UNITED
STATES


SECURITIES
AND EXCHANGE COMMISSION


Washington,
D.C. 20549





_______________





FORM
10-Q





TQUARTERLY REPORT PURSUANT TO SECTION
13 OR 15(d) OF THE


SECURITIES
EXCHANGE ACT OF 1934





For
the quarterly period ended June 30, 2008





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
            (I.R.S.
      EmployerIncorporation
      or Organization)
            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 bySection 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 R 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  RNon-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 R





The
issuer had 50,824,031 common units outstanding as of August 7,
2008.










EAGLE
ROCK ENERGY PARTNERS, L.P.





TABLE
OF CONTENTS

















PagePART
      I. FINANCIAL INFORMATIONItem
      1.
            Financial
      StatementsUnaudited
      Condensed Consolidated Balance Sheets as of June 30, 2008 andDecember
      31, 2007
            2Unaudited
      Condensed Consolidated Statements of Operations for the three months and
      six months ended June 30, 2008 and 2007
            3Unaudited
      Condensed Consolidated Statements of Cash Flows for the six months ended
      June 30, 2008 and 2007
            4Unaudited
      Condensed Consolidated Statements of Members’ Equity for the six months
      ended June 30, 2008
            5Notes
      to Unaudited Condensed Consolidated Financial Statements
            6Item
      2.
            Management’s
      Discussion and Analysis of Financial Condition and Results of
      Operations
            23Item
      3.
            Quantitative
      and Qualitative Disclosures About Market Risk
            41Item
      4.
            Controls
      and Procedures
            43PART
      II. OTHER INFORMATIONItem
      1.
            Legal
      Proceedings
            46Item
      1A.
            Risk
      Factors
            46Item
      2.
            Unregistered
      Sales of Equity Securities and Use of Proceeds
            46Item
      3.
            Defaults
      Upon Senior Securities
            46Item
      4.
            Submission
      of Matters to a Vote of Security Holders
            46Item
      5.
            Other
      Information
            46Item
      6.
            Exhibits
            47


1


PART
I. FINANCIAL INFORMATION





Item
1. Financial Statements.





EAGLE
ROCK ENERGY PARTNERS, L.P.


UNAUDITED
CONDENSED CONSOLIDATED BALANCE SHEETS


($
in thousands, except unit amounts)





June 30,
              2008
            
            
            December 31,
                2007ASSETSCURRENT
      ASSETS:Cash
      and cash equivalents
            
            $
            64,586
            
            
            $
            68,552Accounts
      Receivable(1)
            
            
            186,182
            
            
            
            135,663Risk
      management assets
            
            
            4,528
            
            
            
            —Prepayments
      and other current assets
            
            
            5,603
            
            
            
            3,962Total
      current assets
            
            
            260,899
            
            
            
            208,177PROPERTY,
      PLANT AND EQUIPMENT — Net
            
            
            1,315,440
            
            
            
            1,207,130INTANGIBLE
      ASSETS — Net
            
            
            145,634
            
            
            
            153,948GOODWILL
            
            
            30,513
            
            
            
            29,527OTHER
      ASSETS
            
            
            12,497
            
            
            
            11,145TOTAL
            
            $
            1,764,983
            
            
            $
            1,609,927LIABILITIES
      AND MEMBERS’ EQUITYCURRENT
      LIABILITIES:Accounts
      payable
            
            $
            203,699
            
            
            $
            132,485Due
      to affiliate
            
            
            21,069
            
            
            
            16,964Accrued
      liabilities
            
            
            16,893
            
            
            
            9,776Income
      taxes payable
            
            
            316
            
            
            
            723Risk
      management liabilities
            
            
            164,006
            
            
            
            33,089Total
      current liabilities
            
            
            405,983
            
            
            
            193,037LONG-TERM
      DEBT
            
            
            623,000
            
            
            
            567,069ASSET
      RETIREMENT OBLIGATIONS
            
            
            16,773
            
            
            
            11,337DEFERRED
      INCOME TAXES
            
            
            43,585
            
            
            
            17,516RISK
      MANAGEMENT LIABILITIES
            
            
            259,985
            
            
            
            94,200COMMITMENTS
      AND CONTINGENCIES (Note 12)MEMBERS’
      EQUITY:Common
      Unitholders(2)
            
            
            398,886
            
            
            
            617,563Subordinated
      Unitholders(3)
            
            
            23,556
            
            
            
            112,360General
      Partner(4)
            
            
            (6,785
            )
            
            
            (3,155
            )Total
      members’ equity
            
            
            415,657
            
            
            
            726,768TOTAL
            
            $
            1,764,983
            
            
            $
            1,609,927








(1)
            Net
      of allowable for bad debt of $7,179 and $1,046 as of June 30, 2008
      and December 31, 2007, respectively.(2)
            50,824,031
      and 50,699,647 units were issued and outstanding as of June 30, 2008 and
      December 31, 2007, respectively.  These amounts do not include
      unvested restricted common units granted under the Partnership’s long-term
      incentive plan of 787,947 and 467,062 as of June 30, 2008 and December 31,
      2007, respectively.(3)
            20,691,495
      units were issued and outstanding as of June 30, 2008 and December 31,
      2007, respectively.(4)
            844,551
      units were issued and outstanding as of June 30, 2008 and December 31,
      2007, respectively.





2


EAGLE
ROCK ENERGY PARTNERS, L.P.


UNAUDITED
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS


($
in thousands, except per unit amounts)





Three
      Months
                Ended
      June 30,
            
            
            Six
      Months
                Ended
      June 30,2008
            
            
            2007
            
            
            2008
            
            
            2007REVENUE:Natural
      gas, natural gas liquids, oil, condensate and sulfur sales
            
            $
            451,769
            
            
            $
            191,621
            
            
            $
            808,788
            
            
            $
            301,742Gathering,
      compression processing fees
            
            
            8,085
            
            
            
            6,883
            
            
            
            15,228
            
            
            
            11,166Mineral
      and royalty income
            
            
            10,255
            
            
            
            3,192
            
            
            
            17,213
            
            
            
            3,192Commodity
      risk management losses
            
            
            (283,973
            )
            
            
            (27,255
            )
            
            
            (329,620
            )
            
            
            (34,897
            )Other
      revenue
            
            
            122
            
            
            
            —
            
            
            
            182
            
            
            
            —Total
      revenue
            
            
            186,258
            
            
            
            174,441
            
            
            
            511,791
            
            
            
            281,203COSTS
      AND EXPENSES:Cost
      of natural gas and natural gas liquids
            
            
            353,558
            
            
            
            164,364
            
            
            
            629,389
            
            
            
            255,000Operations
      and maintenance
            
            
            17,731
            
            
            
            11,396
            
            
            
            33,297
            
            
            
            19,320Taxes
      other than income
            
            
            5,263
            
            
            
            728
            
            
            
            9,610
            
            
            
            1,430General
      and administrative
            
            
            10,026
            
            
            
            5,171
            
            
            
            21,268
            
            
            
            9,391Other
      operating expense
            
            
            6,214
            
            
            
            —
            
            
            
            6,214
            
            
            
            1,711Depreciation,
      depletion and amortization
            
            
            26,457
            
            
            
            14,149
            
            
            
            52,202
            
            
            
            25,779Total
      costs and expenses
            
            
            419,249
            
            
            
            195,808
            
            
            
            751,980
            
            
            
            312,631OPERATING
      LOSS
            
            
            (232,991
            )
            
            
            (21,367
            )
            
            
            (240,189
            )
            
            
            (31,428
            )OTHER
      INCOME (EXPENSE):Interest
      income
            
            
            160
            
            
            
            176
            
            
            
            461
            
            
            
            300Other
      income
            
            
            886
            
            
            
            91
            
            
            
            2,433
            
            
            
            91Interest
      expense, net
            
            
            (6,974
            )
            
            
            (8,519
            )
            
            
            (16,078
            )
            
            
            (16,399
            )Interest
      rate risk management gains (losses)
            
            
            11,245
            
            
            
            6,803
            
            
            
            (2,516
            )
            
            
            5,408Other
      expense
            
            
            (232
            )
            
            
            (711
            )
            
            
            (447
            )
            
            
            (1,003
            )Total
      other (expense) income
            
            
            5,085
            
            
            
            (2,160
            )
            
            
            (16,147
            )
            
            
            (11,603
            )LOSS
      BEFORE INCOME TAXES
            
            
            (227,906
            )
            
            
            (23,527
            )
            
            
            (256,336
            )
            
            
            (43,031
            )INCOME
      TAX (BENEFIT) PROVISION
            
            
            (886
            )
            
            
            256
            
            
            
            (988
            )
            
            
            420NET
      LOSS
            
            $
            (227,020
            )
            
            $
            (23,783
            )
            
            $
            (255,348
            )
            
            $
            (43,451
            )NET
      LOSS PER COMMON UNIT — BASICAND
      DILUTED:Basic
      and diluted net loss:Common
      units
            
            $
            (3.14
            )
            
            $
            (0.28
            )
            
            $
            (3.54
            )
            
            $
            (0.55
            )Subordinated
      units
            
            $
            (3.14
            )
            
            $
            (0.71
            )
            
            $
            (3.54
            )
            
            $
            (1.36
            )General
      partner units
            
            $
            (3.14
            )
            
            $
            (0.71
            )
            
            $
            (3.54
            )
            
            $
            (1.36
            )Basic
      and diluted weighted average number outstanding:Common
      units
            
            
            50,762
            
            
            
            30,613
            
            
            
            50,731
            
            
            
            25,680Subordinated
      units
            
            
            20,691
            
            
            
            20,691
            
            
            
            20,691
            
            
            
            20,691General
      partner units
            
            
            845
            
            
            
            845
            
            
            
            845
            
            
            
            845





See notes
to unaudited condensed consolidated financial statements.


3


EAGLE
ROCK ENERGY PARTNERS, L.P.


UNAUDITED
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS


($
in thousands)





Six Months
              Ended June 30,2008
            
            
            2007CASH
      FLOWS FROM OPERATING ACTIVITIES:Net
      loss
            
            $
            (255,348
            )
            
            $
            (43,451
            )Adjustments
      to reconcile net loss to net cash provided by operating
      activities:Depreciation,
      depletion and amortization
            
            
            52,202
            
            
            
            25,779Amortization
      of debt issuance costs
            
            
            436
            
            
            
            872Reclassifying
      financing derivative settlements
            
            
            9,537
            
            
            
            (100
            )Distribution
      from unconsolidated affiliates – return on investment
            
            
            509
            
            
            
            —Equity
      in earnings of unconsolidated affiliates
            
            
            (2,433
            )
            
            
            —Equity-based
      compensation expense
            
            
            2,718
            
            
            
            792Other
            
            
            (825
            )
            
            
            (855
            )Changes
      in assets and liabilities — net of acquisitions:Accounts
      receivable
            
            
            (48,032
            )
            
            
            (24,943
            )Prepayments
      and other current assets
            
            
            (901
            )
            
            
            223Risk
      management activities
            
            
            289,308
            
            
            
            34,524Accounts
      payable
            
            
            65,571
            
            
            
            28,328Due
      to affiliates
            
            
            4,105
            
            
            
            —Accrued
      liabilities
            
            
            6,021
            
            
            
            6,212Other
      assets and liabilities
            
            
            (224
            )
            
            
            738Net
      cash provided by operating
      activities
            
            
            122,644
            
            
            
            28,119CASH
      FLOWS FROM INVESTING ACTIVITIES:Acquisitions,
      net of cash
      acquired
            
            
            (81,289
            )
            
            
            (114,654
            )Additions
      to property, plant and
      equipment
            
            
            (33,080
            )
            
            
            (37,993
            )Advances
      to
      affiliates
            
            
            —
            
            
            
            (10,665
            )Purchase
      of intangible
      assets
            
            
            (1,011
            )
            
            
            (1,199
            )Other
            
            
            —
            
            
            
            22Net
      cash used in investing
      activities
            
            
            (115,380
            )
            
            
            (164,489
            )CASH
      FLOWS FROM FINANCING ACTIVITIES:Repayment
      of revolving credit
      facility
            
            
            (50,069
            )
            
            
            (18,000
            )Proceeds
      from revolving credit
      facility
            
            
            106,000
            
            
            
            34,400Proceeds
      (payments) on derivative
      contracts
            
            
            (9,537
            )
            
            
            100Proceeds
      from equity
      issuance
            
            
            —
            
            
            
            127,500Distributions
      to members and
      affiliates
            
            
            (57,624
            )
            
            
            (16,185
            )Net
      cash provided by (used in) financing
      activities
            
            
            (11,230
            )
            
            
            127,815NET
      CHANGE IN CASH AND CASH EQUIVALENTS
            
            
            (3,966
            )
            
            
            (8,555
            )CASH
      AND CASH EQUIVALENTS — Beginning of period
            
            
            68,552
            
            
            
            10,581CASH
      AND CASH EQUIVALENTS — End of period
            
            $
            64,586
            
            
            $
            2,026SUPPLEMENTAL
      CASH FLOW DATA:Interest
      paid — net of amounts
      capitalized
            
            $
            12,442
            
            
            $
            7,925Investments
      in property, plant and equipment not
      paid
            
            $
            1,885
            
            
            $
            4,892Acquisition
      of assets for
      equity
            
            $
            —
            
            
            $
            182,291





See notes
to unaudited condensed consolidated financial statements.


4





EAGLE
ROCK ENERGY PARTNERS, L.P.


UNAUDITED
CONDENSED CONSOLIDATED STATEMENT OF MEMBERS’ EQUITY


FOR
THE SIX MONTHS ENDED JUNE 30, 2008


($
in thousands, except unit amounts)





General
                Partner
                Units
            
            
            General
                Partner
            
            
            Number
      of
                Common
                Units
            
            
            Common
                Units
            
            
            Number
      of
                Subordinated
                Units
            
            
            Subordinated
                Units
            
            
            TotalBALANCE
      —December 31, 2007
            
            
            844,551
            
            
            $
            (3,155
            )
            
            
            50,699,647
            
            
            $
            617,563
            
            
            
            20,691,495
            
            
            $
            112,360
            
            
            $
            726,768Net
      loss
            
            
            —
            
            
            
            (2,987
            )
            
            
            —
            
            
            
            (179,172
            )
            
            
            —
            
            
            
            (73,189
            )
            
            
            (255,348
            )Distributions
            
            
            —
            
            
            
            (669
            )
            
            
            —
            
            
            
            (40,557
            )
            
            
            —
            
            
            
            (16,398
            )
            
            
            (57,624
            )Vesting
      of restricted units
            
            
            —
            
            
            
            —
            
            
            
            124,384
            
            
            
            —
            
            
            
            —
            
            
            
            —
            
            
            
            —Distribution
      to affiliates
            
            
            —
            
            
            
            —
            
            
            
            —
            
            
            
            (857
            )
            
            
            —
            
            
            
            —
            
            
            
            (857
            )Restricted
      unit expense
            
            
            —
            
            
            
            26
            
            
            
            —
            
            
            
            1,909
            
            
            
            —
            
            
            
            783
            
            
            
            2,718BALANCE
      —June
      30, 2008
            
            
            844,551
            
            
            $
            (6,785
            )
            
            
            50,824,031
            
            
            $
            398,886
            
            
            
            20,691,495
            
            
            $
            23,556
            
            
            $
            415,657





See notes
to unaudited condensed consolidated financial statements.






5
 EAGLE
ROCK ENERGY PARTNERS, L.P.
 NOTES
TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
 JUNE
30, 2008







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. offered and sold
12,500,000 common units in its initial public offering. In connection with the
initial public offering, Eagle Rock Pipeline, L.P., which was the main operating
subsidiary of Holdings, was merged with and into a newly formed 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, 2007. 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 and six-month periods ending
June 30, 2008 are not necessarily indicative of the results that may be expected
for the year ending December 31, 2008.




Description of Business—The
Partnership is a growth-oriented limited partnership engaged in the business of
(i) gathering, compressing, treating, processing, transporting and selling
natural gas, fractionating and transporting natural gas liquids, or NGLs, which
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 minerals and
royalty interest in producing oil and gas wells located 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 business and the six 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. The Partnership evaluates its estimates and assumptions on a
regular basis.  The Partnership bases its estimates on historical
experience and various other assumptions that are believed to be reasonable
under the circumstances, the results of which form the basis for making
judgments about the carrying values of assets and liabilities that are not
readily apparent from other sources. Actual results could differ from those
estimates and such differences could be material.




The
Partnership has provided a discussion of significant accounting policies in its
annual report on Form 10-K for the year ended December 31,
2007.  Certain items from that discussion are updated
below.




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 operating viability of the
project.




6
 EAGLE
ROCK ENERGY PARTNERS, L.P.
 NOTES
TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
 JUNE
30, 2008




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.




Significant
Accounting Policies




Goodwill—Goodwill acquired in
connection with business combinations represent the excess of consideration over
the fair value of tangible net assets and identifiable intangible assets
acquired. Certain assumptions and estimates are employed in determining the fair
value of assets acquired and liabilities assumed, as well as in determining the
allocation of goodwill to the appropriate reporting unit.




The
Partnership acquired goodwill as part of its acquisition of Redman Energy
Holdings, L.P., and Redman Energy Holdings II, L.P. on July 31, 2007.
During the six months ended June 30, 2008, goodwill increased by $1.0 million
due to adjustments made to the Redman purchase price allocation. The Partnership
will perform an impairment test for goodwill assets annually or earlier if
indicators of potential impairment exist. The Partnership performed its annual
goodwill impairment test in May 2008 and determined no impairment appeared
evident.  The Partnership’s goodwill impairment test involves a
comparison of the fair value of each of its reporting units with their carrying
value. The fair value is determined using discounted cash flows and other
market-related valuation models. Certain estimates and judgments are required in
the application of the fair value models. Since the date of the acquisition, no
event occurred or circumstances changed that would more likely than not reduce
the fair value of a reporting unit below its carrying value. If for any
reason the fair value of the goodwill or that of any of the Partnership’s
reporting units’ declines below the carrying value in the future, the
Partnership may incur charges for the impairment.




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 are recovered or repaid through
the receipt or delivery of natural gas or natural gas liquids in future periods,
if not subject to cash out provisions. Imbalance receivables are included in
accounts receivable and imbalance payables are included in accounts payable on
the 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 June 30, 2008, the Partnership had imbalance
receivables totaling $0.7 million and imbalance payables totaling $5.3 million,
respectively. For the midstream business, as of December 31, 2007, the
Partnership had imbalance receivables totaling $0.2 million and imbalance
payables totaling $2.7 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 measure those instruments at fair value. The Partnership uses
financial instruments such as puts, swaps and other derivatives to mitigate the
risks to cash flows resulting from changes in commodity prices and interest
rates. The Partnership recognizes these financial instruments on its
consolidated balance sheets at the instrument’s fair value with changes in fair
value reflected in the consolidated statements of operations, as the Partnership
has not designated any of these derivative instruments as hedges. The cash flows
from derivatives are reported as cash flows from operating activities unless the
derivative contract is deemed to contain a financing element. Derivatives deemed
to contain a financing element are reported as a financing activity in the
statements of cash flows. See Note 11 for a description of the Partnership’s
risk management activities.




Reclassifications—Certain
prior period amounts have been reclassified to conform to current period
presentation.


7
 EAGLE
ROCK ENERGY PARTNERS, L.P.
 NOTES
TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
 JUNE
30, 2008


NOTE
3.  NEW ACCOUNTING PRONOUNCEMENTS




In
September 2006, the Financial Accounting Standards Board (“FASB”) issued SFAS
No. 157, Fair Value
Measurements. This statement defines fair value, establishes a framework
for measuring fair value, and expands disclosure about fair value measurements.
The statement is effective for financial statements issued for fiscal years
beginning after November 15, 2007. SFAS No. 157, as it relates to financial
assets and financial liabilities, was effective for us on January 1, 2008 and
had no material impact on our consolidated results of operation and 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.  The
Partnership is currently evaluating the potential impact of adopting FSP FAS
157-2, if any, on its financial statements.




In
February 2007, the FASB issued SFAS No. 159, The Fair Value Option for Financial
Assets and Financial Liabilities(“SFAS No. 159”), which permits
entities to choose to measure many financial instruments and certain other items
at fair value. SFAS No. 159 was effective for us as of January 1, 2008
and had no impact, as the Partnership elected not to measure additional
financial assets and liabilities at fair value.




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.  The Partnership is currently evaluating the potential impact,
if any, of the adoption of SFAS 141R on the Partnership’s financial
statements.




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 or 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. The Partnership has not yet determined
the impact, if any, that SFAS No. 160 will have on its financial
statements.




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. The
Partnership has not yet determined the impact, if any, that SFAS No. 161 will
have on its financial statements.




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, 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. The Partnership is evaluating the effect
that EITF Issue No. 07-4 will have on its earnings per unit calculation and
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




8
 EAGLE
ROCK ENERGY PARTNERS, L.P.
 NOTES
TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
 JUNE
30, 2008




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 142-3 is
effective for financial statements issued forfiscal
years beginning after December 15, 2008 and must be applied prospectively to
intangible assets acquired after the effective date.  The Partnership is
currently evaluating the potential impact, if any, of FSP SFAS 142-3 on its
financial statements.




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
Partnership is currently evaluating the potential impact, if any, of the
adoption of SFAS 162 on its 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 effects 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.  The Partnership is currently evaluation the potential
impact, if any of the adoption of FSP EITF 03-6-1 on its financial
statements.




NOTE
4.  ACQUISITIONS





On
April 30, 2008, the Partnership completed the acquisition of all of the
outstanding capital stock of Stanolind Oil and Gas Corp. (“Stanolind”), for an
aggregate purchase price of $81.8 million, subject to working capital and
other purchase price adjustments (the “Stanolind Acquisition”). One or more
Natural Gas Partners’ (“NGP”) private equity funds, which directly or indirectly
owned a majority of the equity interests in Stanolind, is an affiliate of the
Partnership and is the majority owner of the sole owner of Eagle Rock Energy
G&P, LLC (the “Company”), which is the general partner of Eagle Rock Energy
GP, L.P., which is the general partner of the Partnership.  The
Partnership funded the transaction from existing cash from operations as
well as with borrowings under its existing credit facility. Stanolind owned
and operated oil and natural gas producing properties in the Permian Basin,
primarily in Ward, Crane and Pecos Counties, Texas.


9
 EAGLE
ROCK ENERGY PARTNERS, L.P.
 NOTES
TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
 JUNE
30, 2008


The
purchase price was allocated on a preliminary basis to acquired assets and
liabilities assumed based on their respective fair value as determined by
management.  The Partnership recorded the Stanolind acquisition under
the guidance of Staff Accounting Bulletin Topic 2D, Financial Statements of Oil and Gas
Exchange Offers(“Topic 2D”). In accordance with Topic 2D, the
Partnership has recorded the interest attributable to the ownership of NGP in
Stanolind at their carryover basis. Those interests not attributable to NGP have
been recorded at their fair value.  As a result, the Partnership
recorded $0.9 million of the net cash paid in excess of the carryover basis as a
distribution to NGP for the Stanolind acquisition. The preliminary purchase
price allocation is set forth below (in thousands):





Oil
      and gas properties:Proved
      properties
            
            $
            110,691Unproved
      properties
            
            
            7,597Cash
      and cash equivalents
            
            
            537Accounts
      receivable, net
            
            
            2,517Other
      current assets
            
            
            710Other
      assets
            
            
            75Accounts
      payable and accrued liabilities
            
            
            (3,230
            )Risk
      management liabilities
            
            
            (2,865
            )Deferred
      income taxes
            
            
            (27,468
            )Asset
      retirement obligations
            
            
            (4,770
            )Other
      long-term liabilities
            
            
            (2,825
            )Total
      purchase price allocation
            
            
            80,969Distribution
      to NGP
            
            
            857Total
      consideration paid
            
            $
            81,826




The
Partnership commenced recording results of operations on May 1,
2008.  Pro forma income statement results for this acquisition would
not have been materially different from the result presented by the Partnership
with the condensed consolidated statement of operations.




Due to
the potential conflict of interest between the interests of the Company and the
public unitholders of Eagle Rock Energy, as a result of one or more NGP private
equity funds directly or indirectly owned a majority of the equity interests in
Eagle Rock Energy and Stanolind, the Board of Directors authorized the Company’s
Conflicts Committee to review, evaluate, and, if determined appropriate, approve
the Stanolind acquisition. The Conflicts Committee, consisting of independent
Directors of the Company, determined that the Stanolind acquisition was fair and
reasonable to Eagle Rock Energy and its publicunitholders
and recommended to the Board of Directors of theCompany that
the transaction be approved and authorized. In considering the fairness of the
Stanolind acquisition, the Conflicts Committee considered the valuation of the
assets and liabilities involved in the transaction and the cash flow of
Stanolind. Based on the recommendation of the Conflicts Committee, the Board of
Directors approved the transaction.


10
 EAGLE
ROCK ENERGY PARTNERS, L.P.
 NOTES
TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
 JUNE
30, 2008




NOTE
5.  FIXED ASSETS AND ASSET RETIREMENT OBLIGATIONS




Fixed
assets consisted of the following:




June
      30
            
            
            December 
      31,2008
            
            
            2007($
      in thousands)Land
            
            $
            1,154
            
            
            $
            1,153Plant
            
            
            191,588
            
            
            
            181,689Gathering
      and pipeline
            
            
            550,139
            
            
            
            541,247Equipment
      and machinery
            
            
            14,929
            
            
            
            14,081Vehicles
      and transportation equipment
            
            
            3,782
            
            
            
            3,657Office
      equipment, furniture, and fixtures
            
            
            1,023
            
            
            
            1,023Computer
      equipment
            
            
            4,714
            
            
            
            4,636Corporate
            
            
            126
            
            
            
            126Linefill
            
            
            4,157
            
            
            
            4,157Proved
      properties
            
            
            581,842
            
            
            
            461,884Unproved
      properties
            
            
            73,634
            
            
            
            66,023Construction
      in progress
            
            
            24,632
            
            
            
            20,8841,451,720
            
            
            
            1,300,560Less:
      accumulated depreciation and amortization
            
            
            (136,280
            )
            
            
            (93,430
            )Net
      fixed assets
            
            $
            1,315,440
            
            
            $
            1,207,130





Depreciation
expense for the three and six months ended June 30, 2008 and for the three and
six months ended June 30, 2007 was approximately $11.2 million, $22.0 million,
$8.4 million and $16.0 million, respectively. Depletion expense for the three
and six months ended June 30, 2008 and for the three and six months ended June
30, 2007 was approximately $10.6 million and $20.9 million, $1.5 million and
$1.5 million, respectively.




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 and six months ended June 30, 2008 and 2007, the
Partnership capitalized interest costs of approximately $0.2 million, $0.5
million, $0.3 million and $0.4 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 to 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,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 our 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, 2007
            
            $
            11,337Additional
      liability on newly constructed assets
            
            
            204Additional
      liability related to acquisitions
            
            
            4,770Accretion
      expense
            
            
            462Asset
      retirement obligations—June 30, 2008
            
            $
            16,773









11
 EAGLE
ROCK ENERGY PARTNERS, L.P.
 NOTES
TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
 JUNE
30, 2008




NOTE
6.  INTANGIBLE ASSETS




Intangible Assets—Intangible
assets consist of right-of-ways and easements and acquired customer contracts,
which the Partnership amortizes over the term of the agreement or estimated
useful life. Amortization expense was approximately $4.7 million, $9.3 million,
$4.2 million and $8.3 million for the three and six months ended June 30, 2008
and 2007, respectively. Estimated aggregate amortization expense for each of the
five succeeding years is as follows: 2008—$18.0 million; 2009—$18.0 million;
2010—$17.1 million; 2011—$6.3 million; and 2012—$6.3 million. Intangible assets
consisted of the following:




June
      30,
            
            
            December
      31,2008
            
            
            2007($
      in thousands)Rights-of-way
      and easements—at cost
            
            $
            81,080
            
            
            $
            80,069Customer
      contracts
            
            
            108,772
            
            
            
            108,772189,852
            
            
            
            188,841Less:
      accumulated amortization
            
            
            (44,218
            )
            
            
            (34,893
            )Net
      intangible assets
            
            $
            145,634
            
            
            $
            153,948




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 8 years on average as of June 30, 2008.






NOTE
7.  LONG-TERM DEBT




As of
June 30, 2008 and December 31, 2007, the Partnership had $623.0 million and
$567.1 million, respectively, outstanding under its $800 million secured
revolving credit facility (“Revolving Credit Facility”).  As of June
30, 2008, the Partnership was in compliance with the financial covenants under
its Revolving Credit Facility.




Subsequent
to June 30, 2008, the Partnership exercised $100 million of its $200 million
accordion feature under the Revolving Credit Facility, which increased the total
commitment to $900 million.




NOTE
8.  MEMBERS’ EQUITY




At June
30, 2008, there were 50,824,031 common units, 20,619,495 subordinated units (all
subordinated units owned by Holdings) and 844,551 general partner units
outstanding. In addition, there were 787,947 unvested restricted
common units outstanding at June 30, 2008.




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. 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 business day after 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 any three consecutive, non-overlapping four quarter periods on or after
September 30, 2009.  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, which is $2.175 on an
annualized basis) on each outstanding limited partner unit and general partner
unit for any four consecutive quarters ending on or after September 30,
2007.




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.




On
February 6, 2008, the Partnership declared its fourth quarter 2007 cash
distribution to its unitholders of record as of February 11, 2008. The
distribution amount per common unit was $0.3925, or approximately $28.5 million.
The distribution was paid on February 15, 2008.




On April
30, 2008, the Partnership declared a cash distribution of $0.40 per unit, or
approximately $29.1 million, for the first quarter ended March 31, 2008. The
distribution was paid May 15, 2008, for unitholders of record as of May 9,
2008.




On July
29, 2008, the Partnership declared a cash distribution of $0.41 per unit for the
second quarter ended June 30, 2008.  The distribution will be paid on
August 14, 2008, for unitholders of record as of August 8,
2008.


12
 EAGLE
ROCK ENERGY PARTNERS, L.P.
 NOTES
TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
 JUNE
30, 2008




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 NGP, under which the Partnership
sells a portion of its gas supply. The Partnership recorded revenues of $8.3
million, $16.0 million, $8.2 million and $13.9 million for the three and six
months ended June 30, 2008 and 2007, respectively, from the agreement, of which
there was a receivable of $2.2 and $5.5 million outstanding at June 30, 2008 and
December 31, 2007, respectively.  The Partnership has received a
letter of credit as a financial assurance of payment related to this
agreement.




In
addition, during the three and six months ended June 30, 2008 and June 30, 2007,
the Partnership incurred $1.7 million, $3.0 million, $1.6 million and $2.9
million in expenses with related parties, of which there was an outstanding
accounts payable balance of $0.6 million and $0.5 million as of June 30, 2008
and December 31, 2007, respectively.




Related
to its investments in unconsolidated subsidiaries, during the three and six
months ended June 30, 2008, the Partnership recorded income of $0.9 million and
$2.4 million, respectively, of which there was no outstanding account receivable
balance of as of June 30, 2008 and December 31, 2007,
respectively.




As of
June 30, 2008 and December 31, 2007, Eagle Rock Energy G&P, LLC had $21.1
million and $17.0 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.




During
the three months ended June 30, 2008, the Partnership incurred approximately
$0.6 million for services performed by Stanolind Field Services (“SFS”), which
are assets controlled by NGP and certain employees of the
Partnership.  As of June 30, 2008, the Partnership had a payable to
SFS of $0.3 million.




NOTE
10.  FAIR VALUE OF FINANCIAL INSTRUMENTS




Effective
January 1, 2008, the Partnership adopted SFAS No. 157, as discussed in Note 3,
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 give the highest priority to unadjusted quoted
prices in active markets for identical assets or liabilities (level 1
measurement) 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
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.


13
 EAGLE
ROCK ENERGY PARTNERS, L.P.
 NOTES
TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
 JUNE
30, 2008


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
June 30, 2008, the Partnership has fair valued its interest rate swaps and
commodity derivative instruments (see Note 11), which includes crude oil,
natural gas and natural gas liquids (“NGLs”). The Partnership has classified the
inputs to measure the fair value of its interest rate swap, crude oil
derivatives and natural gas derivatives as Level 2. For its NGL derivatives, the
Partnership has classified the inputs related to its NGL derivatives that mature
in less than one year as Level 2, but it has classified the inputs for the NGL
derivatives that mature beyond one year as Level 3 as the NGL market is
considered to be less liquid beyond one year’s time. The following table
discloses the fair value of the Partnership’s derivative instruments as of June
30, 2008:





Level
      1
            
            
            Level
      2
            
            
            Level
      3
            
            
            Total($
      in thousands)Assets:Crude  oil
      derivatives
            
            $
            —
            
            
            $
            4,520
            
            
            $
            —
            
            
            $
            4,520Natural
      gas derivatives
            
            
            —
            
            
            
            8
            
            
            
            —
            
            
            
            8Total
            
            $
            —
            
            
            $
            4,528
            
            
            $
            —
            
            
            $
            4,528Liabilities:Crude  oil
      derivatives
            
            $
            —
            
            
            $
            315,763
            
            
            $
            —
            
            
            $
            315,763Natural
      gas derivatives
            
            
            —
            
            
            
            22,010
            
            
            
            —
            
            
            
            22,010NGL
      derivatives
            
            
            —
            
            
            
            37,163
            
            
            
            36,856
            
            
            
            74,019Interest rate
      derivatives
            
            
            —
            
            
            
            12,199
            
            
            
            —
            
            
            
            12,199Total
            
            $
            —
            
            
            $
            387,135
            
            
            $
            36,856
            
            
            $
            423,991





As of
June 30, 2008, risk management current assets in the Condensed Consolidated
Balance Sheet include an investment premium of $4.5 million, net of
amortization.





The
following table sets forth a reconciliation of changes in the fair value of the
Level 3 NGL derivatives during the three months ended June 30, 2008 (in
thousands):





Net
      liability balances as of April 1, 2008
            
            $
            27,454Transfers from Level 3 to
      Level 2
            
            
            (4,873
            )Unrealized
    gains
            
            
            14,275Net
      liability balances as of June 30, 2008
            
            $
            36,856





The
following table sets forth a reconciliation of changes in the fair value of the
Level 3 NGL derivatives during the six months ended June 30, 2008 (in
thousands):





Net
      liability balances as of January 1, 2008
            
            $
            36,695Transfers from Level 3 to
      Level 2
            
            
            (10,730
            )Unrealized
    gains
            
            
            10,891Net
      liability balances as of June 30, 2008
            
            $
            36,856




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 expense, net in the Condensed Consolidated Statements of
Operations.  Realized and unrealized losses and premium amortization
related to the Partnership’s commodity derivatives are recorded as a component
of revenue in the Condensed Consolidated Statements of Operations.




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.


14
 EAGLE
ROCK ENERGY PARTNERS, L.P.
 NOTES
TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
 JUNE
30, 2008




The
carrying amount of cash equivalents is believed to approximate their fair values
because of the short maturities of these instruments. As of June 30, 2008, the
debt associated with the revolving credit agreement bore interest at floating
rates. As such, carrying amounts of this debt instrument approximates fair
value.




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 the variable-rate interest
obligations into a fixed-rate interest 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.




Commodity Derivative
Instruments—The prices of crude oil, natural gas and NGLs are subject to
fluctuations in response to changes in supply, market uncertainty and a variety
of additional factors which are beyond the Partnership’s control. In order to
manage the risks associated with the future prices of crude oil, natural gas and
NGLs, the Partnership engages in risk management activities that take the form
of commodity derivative instruments. Currently these activities are governed by
the general partner, which today typically 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 entered into any new
derivatives in the second quarter of 2008, other than assuming those derivatives
in the Stanolind acquisition discussed below.




The
counterparties used for all of these transactions have investment grade
ratings.




The
Partnership has not designated either the interest rate or commodity derivative
instruments 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) and changes
in  fair values of the commodity derivative instruments recorded as an
adjustment to the mark-to-market gains (losses) on risk management transactions
within revenue.




As a
result of the Stanolind acquisition, the Partnership assumed the following
derivative transactions (derivatives shown with a floor price only are puts; all
other derivatives are costless collars):







Price
              ($
      per MMbtu or $ per Bbl)Period
            Commodity
            Average
      Volumes per Month
            Index
            Average
      Floor
            Average
      CeilingJul-Dec
      2008
            Oil
            10,000
      Bbl
            NYMEX
      WTI
            60.00Jul-Dec
      2008
            Oil
            11,500
      Bbl
            NYMEX
      WTI
            95.00
            105.20Jan-Dec
      2009
            Oil
            10,000
      Bbl
            NYMEX
      WTI
            93.00
            100.85Jan-Dec
      2010
            Oil
            9,000
      Bbl
            NYMEX
      WTI
            90.00
            99.80Jul-Sept
      2008
            Gas
            20,000
      MMbtu
            WEST
      TEXAS (WAHA)
            8.50
            9.55Oct-Dec
      2008
            Gas
            20,000
      MMbtu
            WEST
      TEXAS (WAHA)
            8.50
            9.45Jan-Mar
      2009
            Gas
            20,000
      MMbtu
            WEST
      TEXAS (WAHA)
            9.00
            9.85Apr-Jun
      2009
            Gas
            20,000
      MMbtu
            WEST
      TEXAS (WAHA)
            7.50
            7.95Jul-Sept
      2009
            Gas
            20,000
      MMbtu
            WEST
      TEXAS (WAHA)
            7.50
            8.60Oct-Dec
      2009
            Gas
            20,000
      MMbtu
            WEST
      TEXAS (WAHA)
            7.50
            8.90







15
 EAGLE
ROCK ENERGY PARTNERS, L.P.
 NOTES
TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
 JUNE
30, 2008




NOTE
12.  COMMITMENTS AND CONTINGENCIES




Litigation—The Partnership is
subject to several lawsuits which arise from time to time in the ordinary course
of business.   The Partnership has accruals of approximately $1.5
million and $1.5 million as of June 30, 2008 and December 31, 2007,
respectively, related to these matters. The Partnership has been indemnified up
to a certain dollar amount for certain of these lawsuits. For the indemnified
lawsuits, the Partnership has not established any accruals as the likelihood of
these suits being successful against them 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 of
the Partnership.




Insurance—The Partnership
carries insurance coverage which covers its assets and operations, which
management believes is consistent with companies engaged in similar operations
and assets. The insurance coverage’s include (1) commercial general
liability insurance for liabilities arising to third parties for bodily injury,
property damage and pollution resulting from Eagle Rock Energy field operations;
(2) workers’ compensation liability coverage to required statutory limits;
(3) automobile liability insurance for all owned, non-owned and hired
vehicles covering liabilities to third parties for bodily injury and property
damage, (4) property insurance covering the replacement value of real and
personal property damage, including damages arising from boiler and machinery
breakdowns, earthquake, flood damage and business interruption/extra expense,
(5) property and reservoir damage insurance for operated and non operated
wells in the upstream segment, and (6) corporate liability policies
including directors and officers coverage and employment practice liability
coverage. All coverages are subject to certain deductibles, terms and conditions
common for companies with similar types of operations and assets.




The
Partnership also maintains excess liability insurance coverage above the
established primary limits for commercial general liability and automobile
liability insurance. Limits, terms, conditions and deductibles are comparable to
those carried by other similarly situated energy companies.




Environmental—The operation
and ownership of (a) midstream assets such as pipelines, plants and other
facilities for gathering, transporting, processing, treating, or storing natural
gas, NGLs and other products and (b) upstream assets such as operated and
non-operated interests in oil and gas properties is subject to stringent and
complex laws and regulations pertaining to health, safety and the environment.
As an owner or operator of these assets, 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 drilling oil and gas wells, 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 June 30, 2008 and December 31, 2007, the Partnership
had accrued, on an undiscounted basis, approximately $5.3 million and $2.4
million, respectively, for environmental matters.




TCEQ Matters—In late June
2008, the Texas Commission on Environmental Quality (“TCEQ”) issued a Notice of
Enforcement  (“NOE”) to a subsidiary of the Partnership, TCEQ ID No.: 
CF-0068-J (the “First NOE”) and an NOE to a subsidiary of the Partnership (TCEQ
ID No.:  CF-0070-W) (the “Second NOE”).  Both the First NOE and the
Second NOE were the result of findings made by the TCEQ’s Amarillo Region Office
during routine investigations of our Cargray facilities in the Texas
Panhandle.  In response, the Partnership took prompt corrective action with
respect to all of the matters addressed in each NOE.  The TCEQ has great
discretion to assess administrative penalties, in a range of $0 to $10,000 per
day, and the allegations underpinning each NOE involve a time period that runs
over one year.  The TCEQ has not yet made a final determination with
respect to whether, in each case, it will assess an administrative penalty (or
the amount of such penalty, if assessed).





Retained Revenue
Interest—Certain assets of the Partnership’s Upstream Segment are subject
to retained revenue interests.  These interests were established under
purchase and sale agreements that were executed by the Partnership’s
predecessors in title.  The terms of these agreements entitle the
owners of the retained revenue interests to a portion of the revenues received
from the sale of the hydrocarbons above specified base oil and
natural


16
 EAGLE
ROCK ENERGY PARTNERS, L.P.
 NOTES
TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
 JUNE
30, 2008




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 the retained revenue interests on a monthly
basis.





The
retained revenue interests affect the Partnership’s interest at the Flomaton and
Fanny Church fields in Escambia County, Alabama, the Partnership is currently
making payments in satisfaction of the retained revenue interests, and it
expects these payments to continue through the end of
2009.   With respect to the Partnership’s Big Escambia Creek
field, these payments are 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 other equipment.
Rental expense, including leases with no continuing commitment, amounted to
approximately $1.2 million $2.5 million, $0.3 million and $0.5 million for the
three and six months ended June 30, 2008 and June 30, 2007, respectively. Rental
expense for leases with escalation clauses is recognized on a straight-line
basis over the initial lease term.




NOTE
13.  SEGMENTS




Based on
the Partnership’s approach to managing its assets, the Partnership believes its
operations consist of three geographic segments in its midstream business, one
upstream segment, one mineral segment and one functional (corporate)
segment:




(i)
            Midstream—Texas Panhandle
      Segment:




gathering,
processing, transportation and marketing of natural gas in the Texas
Panhandle;




(ii)
            Midstream—South Texas
      Segment:




gathering,
processing, transportation 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)
            Upstream
      Segment:




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




(v)
            Minerals
      Segment:




fee
minerals and royalties, lease bonus and rental income and equity in earnings of
unconsolidated non-affiliate; and




(vi)
            Corporate
      Segment:




risk
management and other corporate activities.


17
 EAGLE
ROCK ENERGY PARTNERS, L.P.
 NOTES
TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
 JUNE
30, 2008




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. Summarized financial information concerning
the Partnership’s reportable segments is shown in the following
table:





Midstream
      Segments
              Three
      Months Ended June 30, 2008
            
            Texas
                Panhandle
                Segment
            
            
            South
                Texas
                Segment
            
            
            East Texas /
                Louisiana
                Segment
            
            
            Total
                Midstream
                Segments($
      in millions)Sales
      to external customers
            
            $
            183.5
            
            
            $
            132.7
            
            
            $
            97.8
            
            
            $
            414.0Cost
      of natural gas and natural gas liquids
            
            
            140.3
            
            
            
            129.5
            
            
            
            83.8
            
            
            
            353.6Operating
      costs and other expenses
            
            
            8.7
            
            
            
            0.5
            
            
            
            3.8
            
            
            
            13.0Depreciation,
      depletion, and amortization
            
            
            10.9
            
            
            
            0.9
            
            
            
            3.0
            
            
            
            14.8Operating
      income
            
            $
            23.6
            
            
            $
            1.8
            
            
            $
            7.2
            
            
            $
            32.6Capital
      Expenditures
            
            $
            6.5
            
            
            $
            0.2
            
            
            $
            4.0
            
            
            $
            10.7Segment
      Assets
            
            $
            582.4
            
            
            $
            97.0
            
            
            $
            265.3
            
            
            $
            944.7





Three
      Months Ended June 30, 2008
            
            Total
                Midstream
                Segments
            
            
            Upstream
                Segment
            
            
            Minerals
                Segment
            
            
            Corporate
                Segment
            
            
            Total
                Segments($
      in millions)Sales
      to external customers
            
            $
            414.0
            
            
            $
            45.9
            
            
            $
            10.3
            
            
            $
            (284.0
            )(a)
            
            $
            186.2Cost
      of natural gas and natural gas liquids
            
            
            353.6
            
            
            
            —
            
            
            
            —
            
            
            
            —
            
            
            
            353.6Operating
      costs and other expenses
            
            
            13.0
            
            
            
            9.4
            
            
            
            0.5
            
            
            
            16.2
            
            
            
            39.1Depreciation,
      depletion,  and amortization
            
            
            14.8
            
            
            
            10.0
            
            
            
            1.5
            
            
            
            0.2
            
            
            
            26.5Operating
      income (loss)
            
            $
            32.6
            
            
            $
            26.5
            
            
            $
            8.3
            
            
            $
            (300.4
            )
            
            $
            (233.0
            )Capital
      Expenditures
            
            $
            10.7
            
            
            $
            10.3
            
            
            $
            —
            
            
            $
            0.1
            
            
            $
            21.1Segment
      Assets
            
            $
            944.7
            
            
            $
            588.8
            
            
            $
            148.2
            
            
            $
            83.3
            
            
            $
            1,765.0








Midstream
      Segments
              Three
      Months Ended June 30, 2007
            
            Texas
                Panhandle
                Segment
            
            
            South
                Texas
                Segment
            
            
            East Texas /
                Louisiana
                Segment
            
            
            Total
                Midstream
                Segments($
      in millions)Sales
      to external customers
            
            $
            110.1
            
            
            $
            50.8
            
            
            $
            37.6
            
            
            $
            198.5Cost
      of natural gas and natural gas liquids
            
            
            86.1
            
            
            
            49.2
            
            
            
            29.1
            
            
            
            164.4Operating
      costs and other expenses
            
            
            8.7
            
            
            
            0.2
            
            
            
            2.9
            
            
            
            11.8Depreciation,
      depletion, and amortization
            
            
            10.0
            
            
            
            0.4
            
            
            
            2.0
            
            
            
            12.4Operating
      income
            
            $
            5.3
            
            
            $
            1.0
            
            
            $
            3.6
            
            
            $
            9.9Capital
      Expenditures
            
            $
            12.1
            
            
            $
            0.8
            
            
            $
            3.6
            
            
            $
            16.5Segment
      Assets
            
            $
            581.8
            
            
            $
            75.5
            
            
            $
            277.7
            
            
            $
            935.0





Three
      Months Ended June 30, 2007
            
            Total
                Midstream
                Segments
            
            
            Upstream
                Segment
            
            
            Minerals
                Segment
            
            
            Corporate
                Segment
            
            
            Total
                Segments($
      in millions)Sales
      to external customers
            
            $
            198.5
            
            
            $
            —
            
            
            $
            3.2
            
            
            $
            (27.3
            )(a)
            
            $
            174.4Cost
      of natural gas and natural gas liquids
            
            
            164.4
            
            
            
            —
            
            
            
            —
            
            
            
            —
            
            
            
            164.4Operating
      costs and other expenses
            
            
            11.8
            
            
            
            —
            
            
            
            .3
            
            
            
            5.2
            
            
            
            17.3Depreciation,
      depletion, and amortization
            
            
            12.4
            
            
            
            —
            
            
            
            1.5
            
            
            
            0.2
            
            
            
            14.1Operating
      income (loss)
            
            $
            9.9
            
            
            $
            —
            
            
            $
            1.4
            
            
            $
            (32.7
            )
            
            $
            (21.4
            )Capital
      Expenditures
            
            $
            16.5
            
            
            $
            —
            
            
            $
            —
            
            
            $
            0.1
            
            
            $
            16.6Segment
      Assets
            
            $
            935.0
            
            
            $
            —
            
            
            $
            162.2
            
            
            $
            44.7
            
            
            $
            1,141.9


________________________________________


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


18
 EAGLE
ROCK ENERGY PARTNERS, L.P.
 NOTES
TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
 JUNE
30, 2008





Midstream
      Segments
              Six
      Months Ended June 30, 2008
            
            Texas
                Panhandle
                Segment
            
            
            South
                Texas
                Segment
            
            
            East Texas /
                Louisiana
                Segment
            
            
            Total
                Midstream
                Segments($
      in millions)Sales
      to external customers
            
            $
            339.8
            
            
            $
            231.1
            
            
            $
            168.3
            
            
            $
            739.2Cost
      of natural gas and natural gas liquids
            
            
            260.4
            
            
            
            225.1
            
            
            
            143.9
            
            
            
            629.4Operating
      costs and other expenses
            
            
            16.5
            
            
            
            1.2
            
            
            
            7.3
            
            
            
            25.0Depreciation,
      depletion, and amortization
            
            
            21.6
            
            
            
            1.9
            
            
            
            5.9
            
            
            
            29.4Operating
      income
            
            $
            41.3
            
            
            $
            2.9
            
            
            $
            11.2
            
            
            $
            55.4Capital
      Expenditures
            
            $
            13.4
            
            
            $
            0.6
            
            
            $
            6.1
            
            
            $
            20.1Segment
      Assets
            
            $
            582.4
            
            
            $
            97.0
            
            
            $
            265.3
            
            
            $
            944.7





Six
      Months Ended June 30, 2008
            
            Total
                Midstream
                Segments
            
            
            Upstream
                Segment
            
            
            Minerals
                Segment
            
            
            Corporate
                Segment
            
            
            Total
                Segments($
      in millions)Sales
      to external customers
            
            $
            739.1
            
            
            $
            85.0
            
            
            $
            17.2
            
            
            $
            (329.6
            )(a)
            
            $
            511.8Cost
      of natural gas and natural gas liquids
            
            
            629.4
            
            
            
            —
            
            
            
            —
            
            
            
            —
            
            
            
            629.4Operating
      costs and other expenses
            
            
            25.0
            
            
            
            17.0
            
            
            
            0.9
            
            
            
            27.5
            
            
            
            70.4Depreciation,
      depletion, and amortization
            
            
            29.4
            
            
            
            18.3
            
            
            
            4.1
            
            
            
            0.4
            
            
            
            52.2Operating
      income (loss)
            
            $
            55.4
            
            
            $
            49.7
            
            
            $
            12.2
            
            
            $
            (357.5
            )
            
            $
            (240.2
            )Capital
      Expenditures
            
            $
            20.1
            
            
            $
            13.2
            
            
            $
            —
            
            
            $
            0.2
            
            
            $
            33.5Segment
      Assets
            
            $
            944.7
            
            
            $
            588.8
            
            
            $
            148.2
            
            
            $
            83.3
            
            
            $
            1,765.0





Midstream
      Segments
              Six
      Months Ended June 30, 2007
            
            Texas
                Panhandle
                Segment
            
            
            South
                Texas
                Segment
            
            
            East Texas /
                Louisiana
                Segment
            
            
            Total
                Midstream
                Segments($
      in millions)Sales
      to external customers
            
            $
            205.0
            
            
            $
            50.8
            
            
            $
            57.1
            
            
            $
            312.9Cost
      of natural gas and natural gas liquids
            
            
            161.7
            
            
            
            49.2
            
            
            
            44.1
            
            
            
            255.0Operating
      costs and other expenses
            
            
            16.0
            
            
            
            0.2
            
            
            
            4.2
            
            
            
            20.4Depreciation,
      depletion, and amortization
            
            
            19.8
            
            
            
            0.4
            
            
            
            3.7
            
            
            
            23.9Operating
      income
            
            $
            7.5
            
            
            $
            1.0
            
            
            $
            5.1
            
            
            $
            13.6Capital
      Expenditures
            
            $
            22.5
            
            
            $
            0.8
            
            
            $
            15.9
            
            
            $
            39.2Segment
      Assets
            
            $
            581.8
            
            
            $
            75.5
            
            
            $
            277.7
            
            
            $
            935.0





Six
      Months Ended June 30, 2007
            
            Total
                Midstream
                Segments
            
            
            Upstream
                Segment
            
            
            Minerals
                Segment
            
            
            Corporate
                Segment
            
            
            Total
                Segments($
      in millions)Sales
      to external customers
            
            $
            312.9
            
            
            $
            —
            
            
            $
            3.2
            
            
            $
            (34.9
            )(a)
            
            $
            281.2Cost
      of natural gas and natural gas liquids
            
            
            255.0
            
            
            
            —
            
            
            
            —
            
            
            
            —
            
            
            
            255.0Operating
      costs and other expenses
            
            
            20.4
            
            
            
            —
            
            
            
            0.3
            
            
            
            11.2
            
            
            
            31.9Depreciation,
      depletion, and amortization
            
            
            23.9
            
            
            
            —
            
            
            
            1.5
            
            
            
            0.3
            
            
            
            25.7Operating
      income (loss)
            
            $
            13.6
            
            
            $
            —
            
            
            $
            1.4
            
            
            $
            (46.4
            )
            
            $
            (31.4
            )Capital
      Expenditures
            
            $
            39.2
            
            
            $
            —
            
            
            $
            —
            
            
            $
            0.3
            
            
            $
            39.5Segment
      Assets
            
            $
            935.0
            
            
            $
            —
            
            
            $
            162.2
            
            
            $
            44.7
            
            
            $
            1,141.9


_______________________________________


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


19
 EAGLE
ROCK ENERGY PARTNERS, L.P.
 NOTES
TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
 JUNE
30, 2008


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. (successor entity to certain entities acquired in the Redman
acquisition) and Eagle Rock Energy Acquisition II, Inc. (successor entity to
entities related to the Stanolind acquisition) and their wholly-owned
corporations, Eagle Rock Upstream Development Company, Inc and Eagle Rock
Upstream Development Company II, Inc., 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 losses of $0.3 million and $0.4
million were used during the three and six months ended June 30, 2008,
respectively, which resulted in a partial release of the valuation allowances
established for net operating losses at December 31, 2007.




Effective Rate-The provision for the
first six months of 2008 reflects an estimated annual effective rate of
100%.  The Partnership is organized as a pass-through entity for
income taxes.  As a result, the overall effective rate for federal
taxes is zero.  However, the result of state-based income taxes
applied against book losses is a 100% effective rate for the first and second
quarters of 2008.




Deferred taxes-As of June 30, 2008, the
net deferred tax liability was $43.6 million compared to $17.5 million as of
December 31, 2007 and is primarily attributable to book and tax basis
differences of the entities subject to federal income taxes discussed
above.  The increase during 2008 is mainly due to deferred tax
liabilities related to federal income taxes of Eagle Rock Energy Acquisition Co.
II, Inc. and Eagle Rock Upstream Development II, Inc. our wholly-owned
corporations which are subject to federal income taxes.  Eagle Rock
Upstream Development II, Inc. was formerly known as Stanolind Oil and Gas Corp.
and was acquired in the form of a corporation as part of the Stanolind
acquisition during the second quarter of 2008.  Temporary differences
were created by the Stanolind acquisition.  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 acquisition.




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.




Although
the bill states that the Revised Texas Franchise Tax is not an income tax, it
has the characteristics of an income tax since it is determined by applying a
tax rate to a base that considers both revenues and expenses.




NOTE
15.  EQUITY-BASED COMPENSATION




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 covering an
aggregate of 2,000,000 common units to be granted either as options, restricted
units or phantom units. During the restriction period, distributions associated
with the granted awards will be distributed to the awardees. No options or
phantom units have been issued to date.


20
 EAGLE
ROCK ENERGY PARTNERS, L.P.
 NOTES
TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
 JUNE
30, 2008




A summary
of the restricted common units’ activity for the six months ended June 30, 2008,
is provided below:





Number of
                Restricted
                Units
            
            
            Weighted
                Average
                Fair Value
      per UnitOutstanding
      at December 31, 2007
            
            
            467,062
            
            
            $
            23.01Granted
            
            
            471,250
            
            
            $
            16.79Vested
            
            
            (124,384
            )
            
            $
            23.27Forfeitures
            
            
            (25,981
            )
            
            $
            21.95Outstanding
      at June 30, 2008
            
            
            787,947
            
            
            $
            19.29




The total
grant date fair value of restricted units that vested during the six months
ended June 30, 2008 was $2.9 million.




For the
three and six  months ended June 30, 2008 and June 30, 2007, non-cash
compensation expense of approximately $1.6 million, $2.7 million, $0.2 million
and $0.6 million respectively, was recorded related to the granted restricted
units.




As of
June 30, 2008, unrecognized compensation costs related to the outstanding
restricted units under our LTIP totaled approximately $14.5 million. The
remaining expense is to be recognized over a weighted average of 2.3
years.




NOTE
16.  EARNINGS PER UNIT




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




The
Partnership issued restricted common units at multiple times in its history,
including a number of awards made at the time of the initial public offering,
October 24, 2006. These units vest ratably over the course of approximately
three years and the units, once vested, are treated as common units for all
purposes.  The unvested units (at all periods while unvested) have
been considered in the diluted common unit weighted average number in periods of
net income, but have been excluded in periods of net losses.


21
 EAGLE
ROCK ENERGY PARTNERS, L.P.
 NOTES
TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
 JUNE
30, 2008




The
following table presents our calculation of basic and diluted earnings per unit
for the periods indicated:







Three
      Months Ended
              June
      30,
            
            
            Six
      Months Ended
                June
      30,2008
            
            
            2007
            
            
            2008
            
            
            2007(in
      thousands, except for per unit amounts)Net
      loss
            
            $
            (227,020
            )
            
            $
            (23,783
            )
            
            $
            (255,348
            )
            
            $
            (43,451
            )Net
      loss allocated to:Common
      units
            
            $
            (159,343
            )
            
            $
            (8,580
            )
            
            $
            (179,172
            )
            
            $
            (14,249
            )Subordinated
      units
            
            $
            (65,023
            )
            
            $
            (14,607
            )
            
            $
            (73,189
            )
            
            $
            (28,057
            )General
      partner units
            
            $
            (2,654
            )
            
            $
            (596
            )
            
            $
            (2,987
            )
            
            $
            (1,145
            )Weighted
      average unit outstanding during period:Common
      units
            
            
            50,762
            
            
            
            30,613
            
            
            
            50,731
            
            
            
            25,680Subordinated
      units
            
            
            20,691
            
            
            
            20,691
            
            
            
            20,691
            
            
            
            20,691General
      partner units
            
            
            845
            
            
            
            845
            
            
            
            845
            
            
            
            845Basic and Diluted Earnings Per
      Unit:Common
      units
            
            $
            (3.14
            )
            
            $
            (0.28
            )
            
            $
            (3.54
            )
            
            $
            (0.55
            )Subordinated
      units
            
            $
            (3.14
            )
            
            $
            (0.71
            )
            
            $
            (3.54
            )
            
            $
            (1.36
            )General
      partner units
            
            $
            (3.14
            )
            
            $
            (0.71
            )
            
            $
            (3.54
            )
            
            $
            (1.36
            )




NOTE
17.  OTHER OPERATING EXPENSE




In July
2008, SemGroup, L.P. and certain of its subsidiaries (“SemGroup”) filed
petitions for reorganization under Chapter 11 of the U.S. Bankruptcy
Code.  The Partnership has historically sold portions of its
condensate production from its Texas Panhandle and East Texas midstream systems
to SemGroup.  As a result of the bankruptcy, the Partnership is taking
a $6.2 million bad debt charge in the second quarter of 2008, which is included
in “Other Operating Expense” in the consolidated statement of
operations.  During July 2008, the Partnership sold additional
condensate to SemGroup in the range of approximately $5.0 million to $6.0
million, which it expects to take as a bad debt charge during the three months
ended September 30, 2008.  The Partnership stopped all sales to
SemGroup as of August 1, 2008.  Other operating expenses for the six
months ended June 30, 2007 consisted of an arbitration settlement of $1.4
million and a severance payout to a former executive of $0.3
million.












22




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




The
following management 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, 2007, filed with the Securities and Exchange
Commission.  For a description of oil and natural gas terms, see such
Annual Report.




Overview




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




•
            Midstream
      Business—gathering, compressing, treating, processing, transporting and
      selling natural gas, fractionating and transporting natural gas liquids,
      or NGLs;




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




•
            Minerals
      Business—acquiring and managing fee minerals and royalty
      interests.




We report
on our businesses in six accounting segments (see Note 13).




We
conduct, evaluate and report on our Midstream Business within three distinct
segments—the Texas Panhandle Segment, the East Texas/Louisiana Segment
(previously known prior to the filing of our Annual Report as our Southeast
Texas and North Louisiana Segment), and South Texas 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/Louisiana. Our South Texas Segment consists of gathering systems and
related compression and processing facilities in South Texas.





We
conduct, evaluate and report on our Upstream Business as one segment. Our
Upstream Segment includes operated wells in Escambia County, Alabama and 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 Rains, Van Zandt, Henderson, Ward, Crane, Pecos and
Atascosa Counties, Texas.




We
conduct, evaluate and report on our Minerals Business as one segment. Our
Minerals Segment consists of certain fee minerals, royalties and overriding
royalties located in multiple producing trends across the United
States.




The final
segment that we report is our Corporate Segment, in which we account for our
commodity hedging activity and our general corporate costs.




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.




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 credit
facilities, on terms acceptable to us.




Stanolind Acquisition -On
April 30, 2008, we completed the acquisition of all of the outstanding capital
stock of Stanolind Oil and Gas Corp. (“Stanolind”), for an aggregate purchase
price of $81.8 million, subject to working capital and other purchase price
adjustments (the “Acquisition”).  We funded the transaction from
existing cash from operations, as well as with borrowings under our
existing secured revolving credit facility.  Stanolind operates
crude oil and natural gas producing properties in the Permian Basin of West
Texas, primarily in Ward, Crane and Pecos Counties.




Below is
a summary of the important acquisition transactions we completed during the year
ended December 31, 2007.


23




Montierra Acquisition -On
April 30, 2007, we completed the acquisition of (by direct acquisition or
acquisition of certain entities) certain fee minerals, royalties and working
interest properties from Montierra Minerals & Production, L.P. and
NGP-VII Income Co-Investment Opportunities, L.P. (the “Montierra
Acquisition”).




Laser Acquisition -On
May 3, 2007, we acquired all of the non-corporate interests of Laser
Midstream Energy, LP and certain subsidiaries (the “Laser
Acquisition”).




MacLondon Acquisition -On
June 18, 2007, we completed the acquisition of certain fee mineral and
royalties owned by MacLondon Energy, L.P.




EAC Acquisition -On
July 31, 2007, we completed the acquisition of Escambia Asset Co., LLC and
Escambia Operating Company, LLC (the “EAC Acquisition”).




Redman Acquisition -On
July 31, 2007, we completed the acquisition of Redman Energy Holdings, L.P.
and Redman Energy Holdings II, L.P. (Natural Gas Partners VII, L.P. and Natural
Gas Partners VIII, L.P. portfolio companies, respectively) and certain assets
owned by NGP Income Co-Investment Opportunities Fund II, L.P. (a Natural Gas
Partners affiliate) (the “Redman Acquisition”).




Prior to
the above 2007 acquisitions the Partnership was solely a midstream
company.  The Montierra and MacLondon acquisitions provided the
Partnership’s entry into the minerals business and the EAC and Redman
acquisitions provided the Partnership’s entry into the upstream
business.




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




General
Trends and Outlook




We expect
our business to continue to be affected by the key trends as discussed in our
Annual Report on Form 10-K for the year ended December 31, 2007. 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.




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, 2007, filed with
the Securities and Exchange Commission on April 1, 2008.




24




Summary
of Consolidated Operating Results




Below is
a summary table of our consolidated operating results for the three and six
months ended June 30, 2008 and June 30, 2007, respectively.  Operating
results for our individual operating segments are presented in tables in this
Item 2.




Three
      Months Ended
                June
      30,
            
            
            Six
      Months Ended
                June
      30,2008
            
            
            2007
            
            
            2008
            
            
            2007($
      in thousands)Revenue:Sales
      of natural gas, NGLs, oil, condensate and sulfur
            
            $
            451,769
            
            
            $
            191,621
            
            
            $
            808,788
            
            
            $
            301,742Gathering
      and treating services
            
            
            8,085
            
            
            
            6,883
            
            
            
            15,228
            
            
            
            11,166Minerals
      and royalty income
            
            
            10,255
            
            
            
            3,192
            
            
            
            17,213
            
            
            
            3,192Realized
      commodity derivative gains (losses)
            
            
            (27,708
            )
            
            
            1,502
            
            
            
            (40,283
            )
            
            
            4,501Unrealized
      commodity derivative losses ...
            
            
            (256,265
            )
            
            
            (28,757
            )
            
            
            (289,337
            )
            
            
            (39,398
            )Other
            
            
            122
            
            
            
            —
            
            
            
            182
            
            
            
            —Total
      revenue
            
            
            186,258
            
            
            
            174,441
            
            
            
            511,791
            
            
            
            281,203Cost
      of natural gas and natural gas liquids
            
            
            353,558
            
            
            
            164,364
            
            
            
            629,389
            
            
            
            255,000Expenses:Operating
      and maintenance
            
            
            17,731
            
            
            
            11,396
            
            
            
            33,297
            
            
            
            19,320Taxes
      other than income
            
            
            5,263
            
            
            
            728
            
            
            
            9,610
            
            
            
            1,430General
      and administrative
            
            
            10,026
            
            
            
            5,171
            
            
            
            21,268
            
            
            
            9,391Other
      operating expense
            
            
            6,214
            
            
            
            —
            
            
            
            6,214
            
            
            
            1,711Depreciation,
      depletion, and amortization
            
            
            26,457
            
            
            
            14,149
            
            
            
            52,202
            
            
            
            25,779Total
      costs and expenses
            
            
            419,249
            
            
            
            195,808
            
            
            
            751,980
            
            
            
            312,631Operating
      loss
            
            
            (232,991
            )
            
            
            (21,367
            )
            
            
            (240,189
            )
            
            
            (31,428
            )Other
      income (expense):Interest
      income
            
            
            160
            
            
            
            176
            
            
            
            461
            
            
            
            300Other
      income
            
            
            886
            
            
            
            91
            
            
            
            2,433
            
            
            
            91Interest
      expense, net
            
            
            (6,974
            )
            
            
            (8,519
            )
            
            
            (16,078
            )
            
            
            (16,399
            )Unrealized
      interest rate derivatives gains
            
            
            13,689
            
            
            
            6,485
            
            
            
            29
            
            
            
            4,874Realized
      interest rate derivative gains (losses)...
            
            
            (2,444
            )
            
            
            318
            
            
            
            (2,545
            )
            
            
            534Other
      expense
            
            
            (232
            )
            
            
            (711
            )
            
            
            (447
            )
            
            
            (1,003
            )Total
      other income (expense)
            
            
            5,085
            
            
            
            (2,160
            )
            
            
            (16,147
            )
            
            
            (11,603
            )Loss
      before taxes
            
            
            (227,906
            )
            
            
            (23,527
            )
            
            
            (256,336
            )
            
            
            (43,031
            )Income
      tax (benefit) provision
            
            
            (886
            )
            
            
            256
            
            
            
            (988
            )
            
            
            420Net
      loss
            
            $
            (227,020
            )
            
            $
            (23,783
            )
            
            $
            (255,348
            )
            
            $
            (43,451
            )Adjusted
      EBITDA(a)
            
            $
            57,504
            
            
            $
            22,159
            
            
            $
            110,282
            
            
            $
            36,252







(a)
            See
      Non-GAAP Financial Measures within Item 2. Management’s Discussion and
      Analysis of Financial Condition and Results of Operations for a definition
      and reconciliation to GAAP.




For the
three months ended June 30, 2008, based on operating income of our non-Corporate
segments, our midstream business comprised approximately 48.3% of our business
(with the Texas Panhandle Segment accounting for 35.0% of our business, the
South Texas Segment accounting for 2.7% of our business, and the East
Texas/Louisiana Segment accounting for 10.6% of our business), our upstream
business comprised approximately 39.5% of our business, and our minerals
business comprised approximately 12.2% of our business. For the six months ended
June 30, 2008, based on operating income of our non-Corporate segments, our
midstream business comprised approximately 47.3% of our business (with the Texas
Panhandle Segment accounting for 35.3% of our business, the South Texas Segment
accounting for 2.5% of our business, and the East Texas/Louisiana Segment
accounting for 9.5% of our business), our upstream business comprised
approximately 42.3% of our business, and our minerals business comprised
approximately 10.4% of our business. We intend to acquire and construct
additional assets in both our midstream and upstream businesses, and we intend
to continue to seek attractive acquisitions for our minerals
business.


25


Midstream
Business (Three Segments)




Texas Panhandle
Segment




Three
      Months Ended
              June
      30,
            
            
            Six
      Months Ended
              June
      30,2008
            
            
            2007
            
            
            2008
            
            
            2007($
      in thousands, except for price data)Revenue:Sales
      of natural gas, NGLs, oil and condensate
            
            $
            180,987
            
            
            $
            107,884
            
            
            $
            334,842
            
            
            $
            200,664Gathering
      and treating services
            
            
            2,524
            
            
            
            2,206
            
            
            
            4,993
            
            
            
            4,342Total
      revenue
            
            
            183,511
            
            
            
            110,090
            
            
            
            339,835
            
            
            
            205,006Cost
      of natural gas and natural gas liquids
            
            
            140,282
            
            
            
            86,057
            
            
            
            260,400
            
            
            
            161,704Operating
      costs and expenses:Operating
            
            
            8,715
            
            
            
            8,661
            
            
            
            16,463
            
            
            
            16,005Depreciation
      and amortization
            
            
            10,894
            
            
            
            9,983
            
            
            
            21,603
            
            
            
            19,765Total
      operating costs and expenses
            
            
            19,609
            
            
            
            18,644
            
            
            
            38,066
            
            
            
            35,770Operating
      income
            
            $
            23,620
            
            
            $
            5,389
            
            
            $
            41,369
            
            
            $
            7,532Capital
      Expenditures
            
            $
            6,469
            
            
            $
            12,155
            
            
            $
            13,455
            
            
            $
            22,473Realized
      average prices:Oil
      and condensate (per Bbl)
            
            $
            117.93
            
            
            $
            54.43
            
            
            $
            104.15
            
            
            $
            50.27Natural
      gas (per Mcf)
            
            $
            9.44
            
            
            $
            6.64
            
            
            $
            8.42
            
            
            $
            6.39NGLs
      (per Bbl)
            
            $
            74.76
            
            
            $
            49.98
            
            
            $
            68.46
            
            
            $
            39.06Production
      volumes:Gathering
      volumes (Mcf/d)(a)
            
            
            149,881
            
            
            
            138,032
            
            
            
            152,225
            
            
            
            138,544NGLs
      and condensate (net equity gallons)
            
            
            19,650,791
            
            
            
            21,641,964
            
            
            
            41,535,043
            
            
            
            41,634,155Natural
      gas short position (MMbtu/d)(a)
            
            
            (4,974
            )
            
            
            (9,320
            )
            
            
            (6,112
            )
            
            
            (7,919
            )




__________________




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




Revenue and Cost of Natural Gas and
Natural Gas Liquids.For the three and six months ended June 30, 2008,
the revenues minus cost of natural gas and natural gas liquids for our Texas
Panhandle Segment operations totaled  $43.2 million and $79.4 million
compared to $24.0 and $43.3 million for the three and six months ended June 30,
2007. There were two primary contributors to this increase: (i) higher NGL
and condensate pricing, as compared to pricing in 2007, and (ii) higher
natural gas liquids production as compared to production in 2007.




The
higher 2008 gathering volumes compared to 2007 was primarily due to the colder
than normal weather in that area and the downtime to repair the Arrington plant
which reduced production during the three and six months ended June 30, 2007 and
the start-up of the Red Deer Plant in June 2007, which benefited the gathering
volumes during the three and six months ended June 30, 2008 compared to the same
periods in 2007.




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 amounts of equity
production in the future on the West Panhandle System. The East Panhandle System
continues to experience strong growth in volumes and equity production due to
the active Granite Wash drilling play located in Roberts and Hemphill Counties,
Texas. 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. Due to this difference in
contract mix and liquid content between our West and East Panhandle Systems,
while we have grown aggregate volumes during the three and six months ended June
30, 2008 as compared to the three and six months


26


ended
June 30, 2007, our equity share of liquids production would have been less
through the six months ended June 30, 2008 if 2007 had been a normal winter. Our
current goal is to grow volumes aggressively in the East Panhandle System to
offset the decline in volumes and our share of equity production in the West
Panhandle System. The start-up of the Red Deer Plant in June 2007 provided an
additional 20 MMcf/d of processing capacity in our East Panhandle System that
was immediately utilized by our customers.  We expanded our Red Deer
facility during the six months ended June 30, 2008 to handle additional volumes
of 3 MMcf/d, bringing total capacity to 23 MMcf/d.




Operating Expenses.Operating
expenses, including taxes other than income, for three and six months ended June
30, 2008 were $8.7 million and $16.5 million compared to $8.7 million and $16.0
million for the three and six months ended June 30, 2007.  The three
and six months ended June 30, 2007 included additional maintenance costs for
repairing the Arrington plant. The major items impacting the $0.5 million
increase in operating expense for the six months ended June 30, 2008 were a
combination of the operations of the Red Deer Plant, which was brought on line
in June 2007, and higher materials, supplies and labor costs.




Depreciation and Amortization.Depreciation and amortization expenses for three and six months ended
June 30, 2008 were $10.9 million and $21.6 million compared to $10.0 million and
$19.8 million for the three and six months ended June 30, 2007. The major items
impacting the $0.9 million and $1.8 million increases was placing the Red Deer
Plant into service and beginning the depreciation expense associated with the
capital expenditure.




Capital Expenditures.Capital
expenditures for the three and six months ended June 30, 2008 were $6.5 million
and $13.5 million as compared to $12.2 million and $22.5 million for the three
and six months ended June 30, 2007.   During the six months ended
June 30, 2008, of our capital spending in this segment, we spent $10.6 million
on growth capital and $2.9 million on maintenance capital.  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 decrease in capital
spending for the three and six month periods of 2008 of $5.7 million and $9.0
million was driven by less growth capital due to expenditures in 2007 on the new
Red Deer Plant, which was off set by capital expenditures related to our
Stinnett – Cargray plant consolidation projects during 2008, which were
completed in July 2008.




27


East Texas/Louisiana
Segment




Three
      Months Ended
                June 30,
            
            
            Six
      Months Ended
                June 30,2008
            
            
            2007(b)
            
            
            2008
            
            
            2007(b)($ in thousands, except for
      price data)Revenue:Sales
      of natural gas, NGLs, oil and condensate
            
            $
            93,176
            
            
            $
            33,853
            
            
            $
            160,135
            
            
            $
            51,194Gathering
      and treating services
            
            
            4,700
            
            
            
            3,785
            
            
            
            8,148
            
            
            
            5,932Total
      revenue
            
            
            97,876
            
            
            
            37,638
            
            
            
            168,283
            
            
            
            57,126Cost
      of natural gas and natural gas liquids
            
            
            83,911
            
            
            
            29,105
            
            
            
            143,930
            
            
            
            44,094Operating
      costs and expenses:Operating
            
            
            3,837
            
            
            
            2,877
            
            
            
            7,317
            
            
            
            4,159Depreciation
      and amortization
            
            
            2,988
            
            
            
            2,056
            
            
            
            5,857
            
            
            
            3,731Total
      operating costs and expenses
            
            
            6,825
            
            
            
            4,933
            
            
            
            13,174
            
            
            
            7,890Operating
      income
            
            $
            7,140
            
            
            $
            3,600
            
            
            $
            11,179
            
            
            $
            5,142Capital
      Expenditures
            
            $
            4,044
            
            
            $
            3,576
            
            
            $
            6,095
            
            
            $
            15,893Realized
      average prices:Oil
      and condensate (per Bbl)
            
            $
            116.33
            
            
            $
            72.82
            
            
            $
            111.37
            
            
            $
            62.04Natural
      gas (per Mcf)
            
            $
            12.32
            
            
            $
            7.24
            
            
            $
            10.67
            
            
            $
            7.04NGLs
      (per Bbl)
            
            $
            58.80
            
            
            $
            40.57
            
            
            $
            55.86
            
            
            $
            39.48Production
      volumes:Gathering
      volumes (Mcf/d) (a)
            
            
            179,744
            
            
            
            131,535
            
            
            
            171,824
            
            
            
            111,519NGLs
      and condensate (net equity gallons)
            
            
            6,624,451
            
            
            
            4,823,502
            
            
            
            11,928,049
            
            
            
            7,930,684Natural
      gas short position (MMbtu/d) (a)
            
            
            1,543
            
            
            
            668
            
            
            
            958
            
            
            
            1,664




_____________




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


(b)
Includes operations related to the Laser Acquisition starting on May 3,
2007.




Revenue and Cost of Natural Gas and
Natural Gas Liquids.For the three and six months ended June 30, 2008,
revenues minus cost of natural gas and natural gas liquids for our East
Texas/Louisiana Segment totaled $14.0 million and $24.4 million, respectively,
compared to $8.5 million and $13.0 million ,respectively, for the three and six
months ended June 30, 2007.




We were
positively impacted from higher NGL and condensate pricing during the six months
ended June 30, 2008 as compared to the six months ended June 30, 2007. We were
also positively impacted by a 37% and 54% growth in daily gathering volumes
during the three and six months ended June 30, 2008, respectively, compared to
comparable periods in 2007. Increased volumes were due to both a full six months
of the Laser Acquisition during 2008 compared to only a two-month period in 2007
and continued successful drilling in the Austin Chalk play in Tyler and Jasper
Counties, Texas. Excluding the Laser Acquisition, our gathering volumes
increased by 29%. The Tyler County Pipeline Extension completed in March 2007,
connected the Tyler County Pipeline to our Brookeland gathering system providing
an additional 50 MMcf/d of outlet capacity for the Tyler County
Pipeline.  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.  We have also 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. Depending upon the
continued success of the producer’s drilling activities on this acreage; this
area may continue to provide added volume growth to the segment during
2008.




The Laser
Acquisition positively impacted the East Texas/Louisiana Segment by $4.2 million
and $7.5 million during the three and six months ended June 30, 2008,
respectively, compared to $3.3 million during the same time
periods in the prior year.  The Laser Acquisition’s  daily
gathering volumes for the three months ended June 30, 2008 compared to the two
months ended June 30, 2007, the time period covering ownership of the Laser
Acquisition, are down 9% due to reduced drilling activity around the Belle Bower
system.




28




Operating Expenses.Operating
expenses for the three and six months ended June 30, 2008 were $3.8 million and
$7.3 million, respectively, compared to $2.9 million and $4.2 million for the
three and six months ended June 30, 2007, respectively. The major items
impacting the $0.9 million and $3.1 million increases in operating expense for
the three and six months ended June 30, 2008 were (i) the additional one and
four months that we have owned the assets in 2008 that were a part of the Laser
Acquisition compared to the same time period in the prior year and
(ii) incremental expenses for of additional compression costs due to
increased gathered volumes on the Tyler County Pipeline and (iii) higher
materials, supplies and labor costs.




Depreciation and Amortization.Depreciation and amortization expenses for the three and six months ended
June 30, 2008 were $3.0 million and $5.9 million compared to $2.1 million and
$3.7 million, respectively, for the three and six months ended June 30, 2007.
The major items impacting the increases were (i) the inclusion of one and
four months of additional depreciation and amortization during the three and six
months ended June 30, 2008, as compared to the same period in 2007 due to the
Laser acquisition occurring in May 2007, (ii) a full year and placing the
Tyler County Pipeline Extension into service and beginning the depreciation
expense associated with the capital expenditure.




Capital Expenditures.Capital
expenditures for the three and six months ended June 30, 2008 were $4.0 million
and $6.1 million, respectively, compared to $3.6 million and $15.9 million,
respectively, for the three and six months ended June 30, 2007. During the six
months ended June 30, 2008 we spent $4.4 million on growth capital of our
capital spending in this segment and $1.7 million on maintenance
capital.  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 for the three month period of $0.4 was due to
expansion of the Indian Springs Plant and construction of gathering lines to the
significant producer discussed above, while the decrease in the six month period
of $9.8 million was due primarily to the construction and start-up of the Tyler
County Pipeline Extension in March 2007.




29


South Texas
Segment





Three
      Months Ended
                June 30,
            
            
            Six
      Months Ended
                June 30,2008
            
            
            2007(b)
            
            
            2008
            
            
            2007(b)($
      in thousands, except for price data)Revenue:Sales
      of natural gas, NGLs, oil and condensate
            
            $
            131,794
            
            
            $
            49,884
            
            
            $
            229,033
            
            
            $
            49,884Gathering
      and treating services
            
            
            861
            
            
            
            892
            
            
            
            2,087
            
            
            
            892Other
            
            
            —
            
            
            
            —
            
            
            
            2
            
            
            
            —Total
      revenue
            
            
            132,655
            
            
            
            50,776
            
            
            
            231,122
            
            
            
            50,776Cost
      of natural gas and natural gas liquids
            
            
            129,365
            
            
            
            49,202
            
            
            
            225,059
            
            
            
            49,202Operating
      costs and expenses:Operating
            
            
            574
            
            
            
            294
            
            
            
            1,227
            
            
            
            294Depreciation
      and amortization
            
            
            934
            
            
            
            379
            
            
            
            1,873
            
            
            
            379Total
      operating costs and expenses
            
            
            1,508
            
            
            
            673
            
            
            
            3,100
            
            
            
            673Operating
      income
            
            $
            1,782
            
            
            $
            901
            
            
            $
            2,963
            
            
            $
            901Capital
      Expenditures
            
            $
            218
            
            
            $
            829
            
            
            $
            579
            
            
            $
            829Realized
      average prices:Oil
      and condensate (per Bbl)
            
            $
            123.16
            
            
            $
            62.17
            
            
            $
            105.12
            
            
            $
            62.17Natural
      gas (per Mcf)
            
            $
            10.88
            
            
            $
            6.62
            
            
            $
            9.67
            
            
            $
            6.62NGLs
      (per Bbl)
            
            $
            72.66
            
            
            $
            63.42
            
            
            $
            73.08
            
            
            $
            63.42Production
      volumes:Gathering
      volumes (Mcf/d) (a)
            
            
            84,514
            
            
            
            67,574
            
            
            
            81,312
            
            
            
            33,787NGLs
      and condensate (net equity gallons)
            
            
            377,706
            
            
            
            155,904
            
            
            
            827,568
            
            
            
            155,904Natural
      gas short position (MMbtu/d) (a)
            
            
            500
            
            
            
            333
            
            
            
            500
            
            
            
            167


___________




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


(b)
Includes operations related to the Laser Acquisition starting on May 3,
2007.





Revenue and Cost of Natural Gas and
Natural Gas Liquids.This segment was a new area of operations for us as
we entered this segment as a result of the Laser Acquisition, effective May
2007. During the three and six  months ended June 30, 2008 the South
Texas Segment contributed  revenues minus cost of natural gas and
natural gas liquids of  $3.3 million and $6.1 million, respectively,
as compared to $1.6 million for the three and six months ended June 30,
2007.  The increase in revenues during the three and six months ended
June 30, 2008 compared to the comparable periods in 2007 was due to increases in
volumes on account of inclusion of the Laser Acquisition during the full six
month period in 2008 as compared to only a two month period ending June 30,
2007.  The Laser Acquisition daily gathering volumes for the three
months ended June 30, 2008 compared to the two months ended June 30, 2007, the
time period covering ownership of the Laser Acquisition, are down approximately
17% due to reduced volumes on the Raymondville and McAllen systems.





There are
two primary activities in this segment: (i) volumes of natural gas gathered
on our own assets, which represents approximately 86% of revenues minus cost of
natural gas and natural gas liquids for this segment and (ii) producer
services, providing marketing and pipeline connection services to small
independent producers and to third party pipeline systems, which accounted for
approximately 14% of revenues minus cost of natural gas and natural gas
liquids.




Two
significant items that will continue to add value to this area are (i) a
pipeline extension to connect an active significant producer and other
operator’s production to our Phase 1 20-inch Pipeline and (ii) the
construction of the Kelsey Compressor Station on our Phase 1 20-inch Pipeline
which will provide access to Exxon’s King Ranch processing facility, resulting
in an incremental 24 MMcf/d of capacity. The construction of this station will
enable us to
continue to increase volumes on our Phase 1 20-inch Pipeline provided that
drilling activity and our commercial success to contract for the natural gas
continues in 2008.


30




Operating Expenses.Operating
expenses for the three and six months ended June 30, 2008 were $0.6 million and
$1.2 million, respectively, as compared to $0.3 million for the three and six
months ended June 30, 2007.




Depreciation and Amortization.Depreciation and amortization expenses for the three and six months ended
June 30, 2008 were $0.9 million and $1.9 million, respectively, as compared to
$0.4 million for the three and six months ended June 30, 2007.




Capital Expenditures.Capital
expenditures for the three and six months ended June 30, 2008 were $0.2 million
and $0.6 million, respectively, as compared to $0.8 million for the three and
six months ended June 30, 2007.  During the six months ended June 30,
2008, of our capital spending in this segment, we spent $0.5 million on growth
capital and $0.1 million on maintenance capital.




Upstream
Segment




The
Upstream segment became a new line of business for the Partnership in
2007.  The initial assets were acquired on July 31, 2007.




Three
      Months Ended
                June 30,
            
            
            Six
      Months Ended
                June 30,2008(a)
            
            
            2007
            
            
            2008(a)
            
            
            2007($
      in thousands, except for price data)Revenue:Oil
      and condensate
            
            $
            21,126
            
            
            $
            —
            
            
            $
            39,459
            
            
            $
            —Natural
      gas
            
            
            9,431
            
            
            
            —
            
            
            
            16,557
            
            
            
            —NGLs
            
            
            8,155
            
            
            
            —
            
            
            
            16,295
            
            
            
            —Sulfur
            
            
            7,100
            
            
            
            —
            
            
            
            12,467
            
            
            
            —Other
            
            
            122
            
            
            
            —
            
            
            
            180
            
            
            
            —Total
      revenue
            
            
            45,934
            
            
            
            
            
            
            
            84,958Operating
      costs and expenses:Operating
            
            
            9,386
            
            
            
            —
            
            
            
            16,975
            
            
            
            —Depletion,
      depreciation and amortization
            
            
            9,914
            
            
            
            —
            
            
            
            18,339
            
            
            
            —Total
      operating costs and expenses
            
            
            19,300
            
            
            
            —
            
            
            
            35,314
            
            
            
            —Operating
      income
            
            $
            26,634
            
            
            $
            —
            
            
            $
            49,644
            
            
            $
            —Capital
      Expenditures
            
            $
            10,261
            
            
            $
            —
            
            
            $
            13,184
            
            
            $
            —Realized
      average prices:Oil
      and condensate (per Bbl)
            
            $
            114.50
            
            
            $
            —
            
            
            $
            102.25
            
            
            $
            —Natural
      gas (per Mcf)
            
            $
            10.80
            
            
            $
            —
            
            
            $
            9.65
            
            
            $
            —NGLs
      (per Bbl)
            
            $
            68.74
            
            
            $
            —
            
            
            $
            66.21
            
            
            $
            —Sulfur
      (per Long ton)
            
            $
            359.97
            
            
            $
            —
            
            
            $
            271.28
            
            
            $
            —Production
      volumes:Oil
      and condensate ( Bbl)
            
            
            184,511
            
            
            
            —
            
            
            
            385,916
            
            
            
            —Natural
      gas (Mcf)
            
            
            873,093
            
            
            
            —
            
            
            
            1,715,290
            
            
            
            —NGLs
      (Bbl)
            
            
            118,644
            
            
            
            —
            
            
            
            246,097
            
            
            
            —Total
      (Mcfe)
            
            
            2,692,023
            
            
            
            —
            
            
            
            5,507,368
            
            
            
            —Sulfur
      (Long ton)
            
            
            19,724
            
            
            
            —
            
            
            
            45,956
            
            
            
            —




__________




(a)
Includes operations from the EAC Acquisition and Redman Acquisition beginning on
August 1, 2007 and from the Stanolind Acquisition starting on May 1,
2008.




Revenue. For the three and
six months ended June 30, 2008, the Upstream Segment contributed $45.9 million
and $85.0 million of revenue, respectively,  which includes two months
of operations related to the assets acquir in the
Stanolind acquisition.


31




Production
was negatively impacted by curtailed or shut-in production at Big Escambia Creek
(“BEC”), Flomaton and Fanny Church fields during a portion of both the three
month and six months periods ended June 30, 2008.  In April 2008, the
BEC treating facility was shut-in for 20 days for a planned turnaround, which
shut-in all the production in the BEC field.  In addition, production
was partially curtailed for 18 days during the months of May and June 2008 to
repair damage caused by a lightning strike at the BEC treating
facility.  During this repair period, oil and sulfur sales continued,
but at a restricted rates.




Gas
production from Flomaton and Fanny Church fields was restricted from sales for
25 days during the six months ended June 30, 2008 associated with a third
party’s gas quality issue at the point of sales.  Oil sales from both
Flomaton and Fanny Church fields continued during this period of
curtailment.




During
the first quarter of 2008, the BEC field’s production was partially curtailed
for 31 days due to sulfur recovery limitations ahead of the planned turnaround
that occurred at the Big Escambia Creek treating facility during the month of
April 2008.




In
addition, historically, sulfur was viewed as a low value by-product in the
production of oil and gas.  Currently, primarily due to an increase in
demand in the global fertilizer market, the price per long ton is over $600 at
the Tampa, Florida market (before effects of net-backs); as compared to $40 per
long ton at the Tampa, Florida market as recently as the summer of
2007.  We believe that if our wells and facilities and certain
third-party facilities are at full production we are capable of producing 8,000
to 10,000 long tons per month, net to us.  There is no guarantee that
these high prices will remain in effect for the future.  As of June
30, 2008, our sulfur product is not hedged and we have attempted to identify and
negotiate a long term contract to lock in some of the price upside, but we have
been unable to find a suitable counterparty to this exposure.




Operating Expenses. Operating
expenses, including severance and ad valorem taxes, totaled $9.4 million and
$17.0 million for the Upstream Segment during the three and six months ended
June 30, 2008, respectively.  These operating expenses include two
months of expenses related to the assets acquired in the Stanolind
acquisition.  Excluding severance and ad valorem taxes, the most
significant portion of operating expenses were associated with operating the BEC
and Flomaton treating and processing facilities.  In April 2008, we
incurred additional operating expenses related to the planned turnaround at the
BEC treating facility.  These facilities are required to extract the
hydrogen sulfide and carbon dioxide to achieve pipeline sales quality
specifications, as well as beneficially extracting natural gas liquids and
sulfur for sale. The remaining operating expenses are attributed to base lease
operating expenses and well workovers.




Depletion, Depreciation and
Amortization.Depletion, depreciation and amortization expense for the
three and six months ended June 30, 2008 was $9.9 million and $18.3 million,
respectively.




Capital
Expenditures.  The Upstream Segment’s maintenance capital
expenditures for the three and six months ended June 30, 2008 total $8.3 million
and $11.2 million, respectively.  Growth capital expenditures during
the three and six months ended June 30, 2008 totaled $1.9 million (for both
periods) and were associated with drilling projects acquired in the Stanolind
acquisition.  The maintenance capital expenditures during the three
and six months ended June 30, 2008 were associated with the planned turnaround
at the BEC treating facility and increasing drilling, recompletions and workover
activities.   In addition, certain capital facility projects were
conducted in each of the new asset areas.




32




Minerals
Segment




The
Minerals Segment became a new line of business for the Partnership during
2007.  The first assets were acquired in April 2007.




Three
      Months Ended
                June 30,
            
            
            Six
      Months Ended
                June 30,2008
            
            
            2007(a)
            
            
            2008
            
            
            2007(a)($
      in thousands, except for price data)Revenue:Oil
      and condensate
            
            $
            4,732
            
            
            $
            1,533
            
            
            $
            8,099
            
            
            $
            1,533Natural
      gas
            
            
            3,565
            
            
            
            1,490
            
            
            
            5,774
            
            
            
            1,490NGLs
            
            
            411
            
            
            
            98
            
            
            
            646
            
            
            
            98Lease
      bonus, rentals and other
            
            
            1,547
            
            
            
            71
            
            
            
            2,694
            
            
            
            71Total
      revenue
            
            
            10,255
            
            
            
            3,192
            
            
            
            17,213
            
            
            
            3,192Operating
      costs and expenses:Operating
            
            
            482
            
            
            
            292
            
            
            
            925
            
            
            
            292Depletion
            
            
            1,528
            
            
            
            1,532
            
            
            
            4,139
            
            
            
            1,532Total
      operating costs and expenses
            
            
            2,010
            
            
            
            1,824
            
            
            
            5,064
            
            
            
            1,824Operating
      income
            
            $
            8,245
            
            
            $
            1,368
            
            
            $
            12,149
            
            
            $
            1,368Realized
      average prices:Oil
      and condensate (per Bbl)
            
            $
            115.68
            
            
            $
            62.80
            
            
            $
            102.86
            
            
            $
            62.80Natural
      gas (per Mcf)
            
            $
            10.50
            
            
            $
            8.65
            
            
            $
            8.81
            
            
            $
            8.65NGLs
      (per Bbl)
            
            $
            66.13
            
            
            $
            33.85
            
            
            $
            62.12
            
            
            $
            33.85Production
      volumes:Oil
      and condensate ( Bbl)
            
            
            40,907
            
            
            
            24,412
            
            
            
            78,740
            
            
            
            24,412Natural
      gas (Mcf)
            
            
            339,518
            
            
            
            172,212
            
            
            
            655,474
            
            
            
            172,212NGLs
      (Bbl)
            
            
            6,215
            
            
            
            2,895
            
            
            
            10,400
            
            
            
            2,895Total
      (Mcfe)
            
            
            622,250
            
            
            
            336,054
            
            
            
            1,129,400
            
            
            
            336,054




__________




(a)
Includes operations from the Montierra Acquisition as of May 1, 2007 and from
the MacLondon Acquisition as of July 1, 2007.




Revenue.  For the
three and six months ended June 30, 2008 our revenue was $10.3 million and $17.2
million, respectively, as compared to $3.2 million for the three and six months
ended June 30, 2007.  The increase in revenue was due to increases in
commodity prices and increases in production rates during the three and six
months ended June 30, 2008, which was the result of drilling, recompletion and
workover operations conducted by the various operators of the
properties.




Additionally,
we received approximately $1.5 million and $2.7 million in bonus and delay
rental payments during the three and six months ended June 30, 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. Nevertheless, due to high commodity prices, we expect leasing
activity to remain robust and expect to see similar levels of bonus income in
future periods.




Operating Expenses. Operating
expenses of $0.5 million and $0.9 million, respectively, for the three and six
months ended June 30, 2008 as compared to $0.3 million for the three and six
months ended June 30, 2007 are predominately production and ad valorem taxes.
These taxes are levied by various state and local taxing entities.




Depletion. Under the
successful efforts method of accounting, we calculate depletion using the units
of production method. In the case of our Minerals Segment, we only claim proved
producing reserves because, as a mineral interest owner, we lack sufficient
engineering and geological data to estimate the proved undeveloped and
non-producing reserve quantities, and because we cannot control the occurrence
or the timing of the activities that would cause such reserves to become
productive. Since our units of production depletion and amortization rate are a
function of our proved reserves, we experience a higher depletion and
amortization rate than we would if we


claimed
undeveloped or non-producing reserves. Our depletion during the three and six
months ended June 30, 2008 was $1.5 million and $4.1 million, respectively, as
compared to $1.5 million for the three and six months ended June 30,
2007.




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. 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 we expect that this will continue. We refer
to this phenomenon as “regeneration”. 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 and six
months ended June 30, 2008, as a result of the regeneration phenomenon we
received an initial royalty payment for 92 and 151 new wells,
respectively.




33


Corporate
Segment




Three
      Months Ended
                June 30,
            
            
            Six
      Months Ended
                June 30,2008
            
            
            2007
            
            
            2008
            
            
            2007($
      in thousands)Revenue:Unrealized
      commodity derivative losses
            
            $
            (256,265
            )
            
            $
            (28,757
            )
            
            $
            (289,337
            )
            
            $
            (39,398
            )Realized
      commodity derivative gains (losses)
            
            
            (27,708
            )
            
            
            1,502
            
            
            
            (40,283
            )
            
            
            4,501Total
      revenue
            
            
            (283,973
            )
            
            
            (27,255
            )
            
            
            (329,620
            )
            
            
            (34,897
            )General
      and administrative
            
            
            10,026
            
            
            
            5,171
            
            
            
            21,268
            
            
            
            9,391Other
      operating expense
            
            
            6,214
            
            
            
            —
            
            
            
            6,214
            
            
            
            1,711Depreciation
      and amortization
            
            
            199
            
            
            
            199
            
            
            
            391
            
            
            
            372Total
      costs and expenses
            
            
            16,439
            
            
            
            5,370
            
            
            
            27,873
            
            
            
            11,474Operating
      loss
            
            
            (300,412
            )
            
            
            (32,625
            )
            
            
            (357,493
            )
            
            
            (46,371
            )Other
      income (expense):Interest
      income
            
            
            160
            
            
            
            176
            
            
            
            461
            
            
            
            300Other
      income
            
            
            886
            
            
            
            91
            
            
            
            2,433
            
            
            
            91Interest
      expense, net
            
            
            (6,974
            )
            
            
            (8,519
            )
            
            
            (16,078
            )
            
            
            (16,399
            )Unrealized
      interest rate derivatives gains
            
            
            13,689
            
            
            
            6,485
            
            
            
            29
            
            
            
            4,874Realized
      interest rate derivatives gains (losses)
            
            
            (2,444
            )
            
            
            318
            
            
            
            (2,545
            )
            
            
            534Other
      expense
            
            
            (232
            )
            
            
            (711
            )
            
            
            (447
            )
            
            
            (1,003
            )Total
      other income (expense)
            
            
            5,085
            
            
            
            (2,160
            )
            
            
            (16,147
            )
            
            
            (11,603
            )Loss
      before taxes
            
            
            (295,327
            )
            
            
            (34,785
            )
            
            
            (373,640
            )
            
            
            (57,974
            )Income
      tax (benefit) provision
            
            
            (886
            )
            
            
            256
            
            
            
            (988
            )
            
            
            420Segment
      loss
            
            $
            (294,441
            )
            
            $
            (35,041
            )
            
            $
            (372,652
            )
            
            $
            (58,394
            )




Revenue. As a master limited
partnership, we distribute available cash (as defined in our partnership
agreement) every quarter to our unitholders. The volatility inherent in
commodity prices generates uncertainty in future levels of available cash. We
enter into derivative transactions to reduce our exposure to commodity price
risk and reduce the uncertainty of future cash flows.




Our
Corporate Segment’s revenue, which solely includes our commodity derivatives
activity, decreased to a loss of $284.0 million and $329.6 million for the three
and six months ended June 30, 2008, respectively, from a loss of $27.3 million
and $34.9 for the three and six months ended June 30, 2007, respectively. As a
result of our commodity hedging activities, revenues include total realized
losses of $27.7 million and $40.3 million on risk management activity that was
settled during the three and six months ended June 30, 2008, respectively, and
unrealized mark-to-market losses of $254.0 million and $284.7 million for the
three and six months ended June 30, 2008, respectively, as compared to realized
gains of $1.5 million and $4.5 million and unrealized mark-to-market losses of
$26.8 million and $35.2 million for the three and six months ended June 30,
2007, respectively.   In addition, we recorded amortization of
put premiums of $2.3 million and $4.6 million during the three and six months
ended June 30, 2008, respectively, as compared to $2.0 million and $4.2 million
for the three and six months ended June 30, 2007, respectively.




As the
forward price curves for our hedged commodities shift in relation to the caps,
floors, and swap strike prices the fair value of such instruments
changes.  The unrealized, non-cash, mark-to-market net losses during
the three and six months ended June 30, 2008 reflects overall favorable forward
curve price movements as they relate to our physical volumes sales during the
three and six month periods for commodities underlying the derivative
instruments. The unrealized mark-to-market net losses for the six months ended
June 30, 2008 and 2007 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 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 in future periods 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
and Other Operating Expenses. General and administrative expenses
increased by $4.9 million and $11.9 million to $10.0 million and $21.3 million
for the three and six months ended June 30, 2008, respectively, as compared to
$5.2 million and $9.4 million for the three and six months ended June 30, 2007,
respectively. This growth in general and administrative expenses was mostly
driven by an increase in the number of employees in our corporate office as a
result of our 2007 acquisitions; our expansion into the minerals and upstream
businesses related to the Montierra, Redman, EAC and Stanolind acquisitions; and
to recruiting efforts in accounting, engineering, land and operations. As a
result of the acquisitions and recruiting efforts, corporate-office payroll
expenses increased by $3.7 million and $6.9 million for the three and six months
ended June 30, 2008, respectively.  In addition, other professional
fees, including our public partnership expenses related to audit, tax,
Sarbanes-Oxley compliance and other contract labor increased by $1.1 million and
$3.1 million for the three and six months ended June 30, 2008,
respectively.  We also incurred increased other miscellaneous general
and administrative expenses of $0.1 million and $1.9 million for the three and
six months ended June 30, 2008, respectively.   At the present
time, we do not allocate our general and administrative expenses to our
operational segments. The Corporate Segment bears the entire
amount.




In July
2008, SemGroup, L.P. and certain of its subsidiaries (“SemGroup”) filed
petitions for reorganization under Chapter 11 of the U.S. Bankruptcy
Code.  We historically sold portions of our condensate production from
our Texas Panhandle and East Texas midstream systems to SemGroup.  As
a result of the bankruptcy we are taking a $6.2 million bad debt charge in the
second quarter of 2008, which is included in “Other Operating Expense” in the
consolidated statement of operations.  During July 2008, we sold
pre-bankruptcy, and continued to sell, post-bankruptcy, condensate to SemGroup,
for which our financial exposure is approximately $5 million to $6
million.  We are seeking payment of our $6.2 million receivable as a
critical supplier to SemGroup and placement in the Supplier Protection Program
(“SPP”).  The intent of the SPP is for SemGroup to pay certain
critical suppliers their pre-bankruptcy claims in full and continue to pay such
suppliers in exchange for their willingness to continue
performance.  It is premature at this time to predict the timing of
payments, if any, under the SPP or otherwise.  As of August 1, 2008,
we have stopped sales of condensate to SemGroup until we have more clarity
around the SPP program and treatment in the bankruptcy proceedings.




Total other income
(expense).  Total other income (expense), which includes both
realized and unrealized gains and losses from our interest rate swaps, increased
to income of $5.1 million for the three months ended June 30, 2008 and decreased
to expense of $16.1 million for the six months ended June 30, 2008, as compared
to expense of $2.2 million and $11.6 million for the three and six months ended
June 30, 2007.  During the three and six months ended June 30, 2008,
we incurred realized losses from our interest rate swaps of $2.4 million and
$2.5 million, respectively, as compared to realized gains of $0.3 million and
$0.5 million during the three and six months ended June 30, 2007,
respectively.  We also incurred unrealized mark-to-market gains of
$13.7 million and $0 million during the three and six months ended June 30,
2008, respectively, as compared to unrealized mark-to-market gains of $6.5
million and $4.9 million for the same periods in 2007.  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.




In
addition, interest expense, (net) decreased to $7.0 million and $16.1 million
for the three and six months ended June 30, 2008, respectively, as compared to
$8.5 million and $16.4 million during the same period in the prior year,
respectively.  The decrease in interest expense is due to the decrease
in interest rates from June 30, 2007 to June 30, 2008 as well as lower
interestrate margin
under the new senior revolving credit facility, partially offset by higher debt
balances.




34




Income Tax (Benefit)
Provision. Income tax benefit recorded during the three and six months
ended June 30, 2008 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 federal income taxes associated with the
Redman and Stanolind acquisitions (See Note 14 for additional
detail).




Adjusted EBITDA.




Adjusted
EBITDA, as defined under “Non-GAAP Financial Measures”, increased by $35.3
million and $74.0 million from $22.2 million and $36.2 million for the three and
six months ended June 30, 2007, respectively, to $57.5 million and $110.3
million for the three and six months ended June 30, 2008,
respectively.




As
described above, revenues minus cost of natural gas and natural gas liquids for
the Midstream Segment (including the Texas Panhandle, East Texas / Louisiana and
the South Texas Segment) grew by $26.3 million and $51.8 million during the
three and six months ended June 30, 2008, respectively, as compared to the
comparable periods in 2007. The acquisitions which lead to our entry into our
Upstream and Mineral Segments contributed an additional $53.0 million and $99.0
million to revenues during the three and six months ended June 30, 2008,
respectively, as compared to the comparable periods in 2007. Our Corporate
Segment’s realized commodity derivatives loss decreased by $29.2 million and
$44.8 million during the three and six months ended June 30, 2008, respectively,
as compared to the comparable periods in 2007. This resulted in $50.1 million
and $106.1 million of total incremental revenues minus cost of natural gas and
natural gas liquids during the three and six months ended June 30, 2008,
respectively, as compared to the comparable periods in 2007.  The
incremental revenue amounts are adjusted to exclude the impact of unrealized
commodity derivatives not included in the calculation of Adjusted
EBITDA.




Operating
expenses (including taxes other than income), were $13.0 million and $24.9
million for the three and six months ended June 30, 2008, respectively, for our
Midstream Segment as compared to $11.8 million and $20.4 million to the three
and six months ended June 30, 2007, respectively, while the acquisitions which
created the Upstream and Minerals Segments contributed additional Operating
Expenses (including taxes other than income) of $9.6 million and $17.7 million,
respectively, as compared to the comparable periods in 2007.




General
and administrative expense, excluding the impact of non-cash compensation
charges related to our long-term incentive program (“LTIP”) and captured within
our Corporate Segment, increased during the three and six month period ending
June 30, 2008 by $3.9 million and $9.9 million, respectively, as compared to the
respective periods ended June 30, 2007.




As a
result, revenues (excluding the impact of unrealized commodity derivative
activity) minus cost of natural gas and natural gas liquids for the three and
six month period ending June 30, 2008, as compared to the same periods in 2007
increased by $50.1 million and $106.1 million, respectively, operating expenses
increased by $10.9 million and $22.2 million, respectively, and general and
administrative expenses increased by $3.9 million and $9.9 million,
respectively.  The increases in revenues minus the cost of natural gas
and natural gas liquids, offset by increases in operating costs and general and
administrative expenses resulted in an increase to Adjusted EBITDA during the
three and six months ended June 30, 2008, as compared to the same periods in
2007.




Liquidity
and Capital Resources.




Historically,
our sources of liquidity have included cash generated from operations, equity
issuances and borrowings under our existing credit facilities.  We
believe that the cash generated from these sources will continue to be
sufficient to meet our minimum quarterly cash distributions and our requirements
for short-term working capital and long-term capital expenditures for at least
the next twelve months.




In the
event that we acquire additional assets that exceed our existing capital
resources, we expect that we will finance those acquisitions with a combination
of expanded or new debt facilities and, if necessary, new equity issuances. The
ratio of debt and equity issued will be determined by our management and our
board of directors.




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 June
30, 2008, working capital was a deficit of $145.1 million as compared to a $15.1
million balance as of December 31, 2007.




35




The net
decrease in working capital of $160.2 million from December 31, 2007 to
June 30, 2008, resulted primarily from the following factors:




•
            risk
      management net working capital deficit balance increased by a net $126.4
      million, primarily, as a result of increases in commodity prices since
      December 31, 2007, which caused increases in the unrealized losses
      associated with our derivative
instruments;




•
            cash
      and cash equivalents, net of due to affiliates, decreased overall by $8.1
      million due to the results of operations, timing of expenditure payments,
      and financing activities including our debt
  activities;




•
            trade
      accounts receivable increased by $50.5 million primarily from the impact
      of higher commodity prices; and




•
            accounts
      payable and accrued liabilities increased by $78.3 million from
      December 31, 2007 primarily as a result of operating activities and
      timing of payments, including capital
  expenditures.




Derivative Financial
Exposure.  At June 30, 2008, the fair value of our financial
derivatives was a net liability of $419.5 million.  Substantially all
of our counterparties to these derivatives are part of our revolving credit
facility and have their outstanding debt commitments and derivative exposure
collateralized pursuant to our credit facility.  The Partnership has
crude oil put options with two counterparties that are not in our revolving
credit facility; however, due to the nature of the put options we have no
“margin call” exposure on these instruments.  Accordingly, we do not
have exposure to potential “margin calls” on our derivative instruments which
could cause us to have a significant liquidity event.




Cash
Flows Six Months Ended June 30, 2008 Compared to Six Months Ended June 30,
2007




Cash Flow from Operating
Activities. Cash flows provided by operating activities increased by
$94.5 million during the six months ended June 30, 2008 as compared to the six
months ended June 30, 2007 as a result of the contribution from acquired assets
and growth projects, as well as higher commodity prices.




Cash Flows From Investing
Activities. Cash flows used in investing activities for the six
months ended June 30, 2008, as compared to the six months ended June 30, 2007,
decreased by $49.1 million. The investing activities for the current period
reflect the Stanolind acquisition of $81.3 million compared to the Laser and
Montierra acquisitions in the prior year totaling $114.7 and a lower 2008
capital expenditure level of $33.1 million versus $38.0 million for
2007.




Cash Flows From Financing
Activities. Cash flows used in financing activities during the six
months ended June 30, 2008, decreased by $139.0 million, compared to the cash
flows provided by financing activities of $127.8 million for the six months
ended June 30, 2007. Key differences between periods include proceeds of $127.5
from a private placement of our units in 2007 offset by increased net borrowings
under our revolving credit facility of $39.5 million.  Distributions
to unitholders represented a cash outflow of $57.6 million during the six months
ended June 30, 2008, as compared to $16.2 million during the six months ended
June 30, 2007.




Revolving
Credit Facility




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 up to
$800 million.  The new credit agreement provides terms and
pricing options which are more favorable than those in the prior credit
agreement. Availability as of June 30, 2008 under the new credit agreement,
based on financial covenants, is $800 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 up to $1 billion. The credit agreement
is scheduled to mature on December 13, 2012.




Subsequent
to June 30, 2008, we exercised $100 million of our $200 million accordion
feature under the credit facility, which increased the total commitment to $900
million.  We have partially exercised the accordion feature to provide
for adequate funding associated with our growth strategy.




Capital
Requirements.




As we
expand our businesses through acquisitions and organic projects, our need for
capital will increase. We anticipate that we will have sufficient access to
capital to grow, maintain and commercially exploit our businesses.




36




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
original 2008 capital budget anticipated that we would spend approximately $54
million on our existing assets, of which $30 million was for growth and $24
million was for maintenance.  The budget includes capital expenditures
for growth, maintenance and well connect projects in both our Midstream and
Upstream segments.  After updating our view of the remainder of 2008
(which includes expenditures on the recent Stanolind acquisition) and the actual
capital expenditures incurred during the first half of 2008 we expect to spend
approximately $70 million for 2008 (excludes all acquisitions), of which $40
million was for growth and $30 million was for maintenance.  We intend
to finance our maintenance capital expenditures (including well connect costs)
with internally generated cash flow and our growth capital expenditures
utilizing our revolving credit facility.




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




•
            growth
      capital expenditures, which are made to acquire new assets; to expand and
      upgrade existing systems and facilities; or to construct or acquire
      similar systems or 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 upstream business, maintenance capital is defined
      as capital which is expended to maintain our
  production.




Since our
inception in 2002, we have made substantial growth capital expenditures. We
anticipate we will continue to make significant growth capital expenditures and
acquisitions. Consequently, our ability to develop and maintain sources of funds
to meet our capital requirements is critical to our ability to meet our growth
objectives.




We
continually review opportunities for both organic growth projects and
acquisitions which would enhance our financial performance. Because we will
distribute most of our available cash to our unitholders, we will depend on
borrowings under our Revolving Credit Facility and the issuance of debt and
equity securities to finance any future growth capital expenditures or
acquisitions.




Off-Balance Sheet
Obligations.




We have
no off-balance sheet transactions or obligations.




Debt
Covenants.




At June
30, 2008, we were in compliance with the covenants of our credit
facilities.




Recent
Accounting Pronouncements.




In
September 2006, the FASB issued SFAS No. 157, Fair Value Measurements. This
statement defines fair value, establishes a framework for measuring fair value,
and expands disclosure about fair value measurements. The statement is effective
for financial statements issued for fiscal years beginning after
November 15, 2007. SFAS No. 157, as it relates to financial assets and
liabilities, was effective for us on January 1, 2008 and had no impact on our
consolidated results of operations and 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 non financial 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.  We are
currently evaluating the potential impact of adopting FSP FAS 157-2, if any, on
our financial statements.




In
February 2007, the FASB issued SFAS No. 159, The Fair Value Option for Financial
Assets and Financial Liabilities(“SFAS No. 159”), which permits
entities to choose to measure many financial instruments and certain other items
at fair value. SFAS No. 159 was effective for us as of January 1, 2008
and had no impact as we have elected not to measure additional financial assets
and liabilities at fair value.




37




In
December 2007, the FASB issued SFAS No. 141 (revised 2007), Business Combinations (“SFAS
No. 141R”), which replaces SFAS No. 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.  We are currently evaluating the potential impact, if any, of
the adoption of SFAS No. 141R on our financial statements.




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. This
Statement is effective as of the beginning of an entity’s first fiscal year
beginning after December 15, 2008. We have not yet determined the impact,
if any, that SFAS No. 160 will have on our financial statements.




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 is
effective for financial statements issued for fiscal years and interim periods
beginning after November 15, 2008, with early application encouraged. We have
not yet determined the impact, if any, that SFAS No. 161 will have on our
financial statements.




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, 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. We are evaluating the effect that EITF
Issue No. 07-4 will have on our earnings per unit calculation and 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 142-3 is
effective for financial statements issued forfiscal years
beginning after December 15, 2008 and must be applied prospectively to
intangible assets acquired after the effective date.  We are currently
evaluating the potential impact, if any, of FSP SFAS 142-3 on our consolidated
financial statements.





In May
2008, 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.  We are
currently evaluating the potential impact, if any, of the adoption of SFAS 162
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


38


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.  We are currently evaluating the potential impact, if
any, of the adoption of FSP EITF 03-6-1 on our 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 (minus) income tax provision
(benefit), interest-net (including realized interest rate risk management
instruments and other expense), depreciation, depletion, and amortization
expense, other operating expense, 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 instrument and other (income). Adjusted EBITDA is
useful in determining our ability to sustain or increase distributions. By
excluding unrealized derivative gains (losses), a non-cash charge which
represents the change in fair market value of our executed derivative
instruments and is independent of our assets’ performance or cash flow
generating ability, we believe Adjusted EBITDA reflects more accurately our
ability to generate cash sufficient to pay interest costs, support our level of
indebtedness, make cash distributions to our unitholders and general partner and
finance our maintenance capital expenditures. We further believe that Adjusted
EBITDA also describes more accurately the underlying performance of our
operating assets by isolating the performance of our operating assets from the
impact of an unrealized, non-cash measure designed to describe the fluctuating
inherent value of a financial asset. Similarly, by excluding the impact of
non-recurring discontinued operations, Adjusted EBITDA provide 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.




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 earnings determined under
GAAP, as well as Adjusted EBITDA, to evaluate our liquidity. Our Adjusted EBITDA
excludes some, but not all, items that affect net income and operating income
and these measures may vary among companies. Therefore, our Adjusted EBITDA may
not be comparable to similarly titled measures of other companies.




39




Reconciliation
of “Adjusted EBITDA” to net cash flows provided by operating activities and net
loss




Three
      Months Ended
              June
      30,
            
            
            Six
      Months Ended
                June
      30,2008
            
            
            2007
            
            
            2008
            
            
            2007($
      in thousands)Net
      cash flows provided by operating activities
            
            $
            89,499
            
            
            $
            13,938
            
            
            $
            122,644
            
            
            $
            28,119Add
      (deduct):Depreciation,
      depletion and amortization
            
            
            (26,457
            )
            
            
            (14,149
            )
            
            
            (52,202
            )
            
            
            (25,779
            )Amortization
      of debt issuance costs
            
            
            (219
            )
            
            
            —
            
            
            
            (436
            )
            
            
            (872
            )Risk
      management portfolio value changes
            
            
            (242,576
            )
            
            
            (22,272
            )
            
            
            (289,308
            )
            
            
            (34,524
            )Net
      realized (loss) gain on financing derivative settlements
            
            
            (7,259
            )
            
            
            —
            
            
            
            (9,537
            )
            
            
            100Other
            
            
            (111
            )
            
            
            (250
            )
            
            
            31
            
            
            
            63Accounts
      receivables and other current assets
            
            
            18,719
            
            
            
            24,277
            
            
            
            48,933
            
            
            
            24,720Accounts
      payable, due to affiliates and accrued liabilities
            
            
            (58,006
            )
            
            
            (24,665
            )
            
            
            (75,697
            )
            
            
            (34,540
            )Other
      assets and liabilities
            
            
            (610
            )
            
            
            (662
            )
            
            
            224
            
            
            
            (738
            )Net
      loss
            
            
            (227,020
            )
            
            
            (23,783
            )
            
            
            (255,348
            )
            
            
            (43,451
            )Add
      (deduct):Interest
      (income) expense, net (1)
            
            
            9,490
            
            
            
            8,025
            
            
            
            18,609
            
            
            
            16,568Depreciation,
      depletion and amortization
            
            
            26,457
            
            
            
            14,149
            
            
            
            52,202
            
            
            
            25,779Income
      tax (benefit) provision
            
            
            (886
            )
            
            
            256
            
            
            
            (988
            )
            
            
            420EBITDA
            
            
            (191,959
            )
            
            
            (1,353
            )
            
            
            (185,525
            )
            
            
            (684
            )Add
      (deduct):Risk
      management portfolio value changes
            
            
            242,576
            
            
            
            22,272
            
            
            
            289,308
            
            
            
            34,524Restricted
      unit compensation expense
            
            
            1,559
            
            
            
            620
            
            
            
            2,718
            
            
            
            792Other
      income
            
            
            (886
            )
            
            
            620
            
            
            
            (2,433
            )
            
            
            (91
            )Other
      operating expenses (2)
            
            
            6,214
            
            
            
            —
            
            
            
            6,214
            
            
            
            1,711ADJUSTED
      EBITDA
            
            $
            57,504
            
            
            $
            22,159
            
            
            $
            110,282
            
            
            $
            36,252




__________




(1)
            Includes
      realized interest rate derivative gains and losses and other
      expenses.


(2)
            Includes
      the SemGroup bad debt expense for the three and six months ended June 30,
      2008 and a settlement of arbitration for $1.4 million and severance to a
      former executive of $0.3 million for the six months ended June 30,
      2007.




40


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
puts, calls, 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,
and 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.




Pursuant
to our policies and practices we do not speculate in the buying and selling of
commodity or interest rate derivates.  Speculation includes, but is
not limited to, buying and selling commodity or financial instruments that are
not necessary for meeting forecasted production (i.e. physical production),
consumption or outstanding debt service.  In no event shall
transactions be entered into to speculate on market conditions.




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.




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 June 30,
2008, the Partnership recorded a loss on risk management instruments of $284.0
million representing a fair value (unrealized) loss of $254.0 million,
amortization of put premiums of $2.3 million and net (realized) settlement
losses of $27.7 million.  For the six months ended June 30, 2008, the
Partnership recorded a loss on risk management instruments of $329.6 million
representing a fair value (unrealized) loss of $284.7 million, amortization of
put premiums of $4.6 million and net (realized) settlement losses of $40.3
million.  As of June 30, 2008, the fair value liability of these
commodity contracts, including put premiums, totaled approximately $407.3
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 June 30, 2008, the Partnership
recorded a fair value (unrealized) gain of $13.7 million and a realized loss of
$2.4 million.  For the six months ended June 30, 2008, the Partnership
recorded a fair value (unrealized) gain of $0.1 million and a realized loss of
$2.5 million.  As of June 30, 2008, the fair value liability of these
interest rate contracts totaled approximately $12.2 million.


41




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. In the sale of our NGLs and condensates, our principle
customers are large natural gas liquids purchasers, fractionators and marketers
and large condensate aggregators that also in turn 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, but we
believe that our credit risk monitoring substantially mitigates the exposure to
significant credit risk.




In July
2008, SemGroup, L.P. and certain of its subsidiaries (“SemGroup”) filed
petitions for reorganization under Chapter 11 of the U.S. Bankruptcy
Code.    We historically sold portions of our condensate
production from our Texas Panhandle and East Texas midstream systems to
SemGroup.  The abrupt bankruptcy of SemGroup has caught us, the energy
business and the financial community by surprise.  We are not aware of
any other measures that we could have taken to identify this risk at an earlier
time.  During the three and six months ended June 30, 2008, we
recorded a bad debt provision of $6.2 million related to our outstanding
receivables from SemGroup.


42




Item
4. Controls and Procedures.




Evaluation
of Disclosure Controls and Procedures




Management
has conducted an evaluation of the effectiveness of the our disclosure controls
and procedures, as defined in Rules 13a-15(e) and 15d-15(e) under the Securities
Exchange Act of 1934, as amended, as of the end of the period covered by this
report. Disclosure controls and procedures are designed to ensure that
information required to be disclosed in reports filed or submitted under the
Securities Exchange Act of 1934, as amended, is recorded, processed, summarized
and reported within the time periods specified by the SEC rules and forms and
that such information is accumulated and communicated to management, including
our principal executive officer and principal financial officer, to ensure
timely decisions regarding required disclosures. During the evaluation of
disclosure controls and procedures and our internal control over financial
reporting as of December 31, 2007 conducted during the preparation of our
financial statements, which were included in our Annul Report on Form 10-K for
the year ended December 31, 2007, our management identified material weaknesses
in internal control over financial reporting relating to our (a) Internal
Control Environment, (b) Period End Financial Reporting, and (c) Midstream Cost
of Natural Gas and Natural Gas Liquids. As a result, our principal executive
officer and principal financial officer concluded that, as of December 31, 2007,
our disclosure controls and procedures were ineffective. Upon identification of
the material weaknesses and under the direction of our principal executive
officer and principal financial officer, we developed a comprehensive plan to
remediate the material weaknesses.




As of
June 30, 2008, and as described under Status of Remediation of Material Weakness
in Internal Control Over Financial Reporting below, all of the material
weaknesses were not fully remediated. As a result, our principal executive
officer and principal financial officer concluded that, as of June 30, 2008, our
disclosure controls and procedures were not effective. Notwithstanding the
aforementioned material weaknesses and failure of disclosure controls, our
management has taken additional steps to assure there is appropriate disclosure
in this report and has concluded that the financial statements included in this
report fairly present, in all material respects, our financial condition for the
periods presented in conformity with generally accepted accounting
principles.




Status
of Remediation of Material Weakness in Internal Control Over Financial
Reporting




We have
been and are actively engaged in the implementation of remediation efforts to
address the material weaknesses in our internal control over financial reporting
as of December 31, 2007 and any other subsequently identified significant
deficiencies or material weaknesses.  These remediation efforts
outlined below are specifically designed to address the material weaknesses
identified by our management relating to our Internal Control Environment,
Period End Financial Reporting Process and Midstream Cost of Natural Gas and
Natural Gas Liquids.




In our
management’s analysis, we determined that the material weaknesses were caused as
follows:




Internal
Control Environment




·
            We
      lacked training programs and job descriptions to communicate clearly
      management’s and employees’ roles and responsibilities in internal control
      over financial reporting and a sufficient number of accounting and finance
      professional to perform supervisory reviews and monitoring activities over
      financial reporting matters and
controls.




Period
End Financial Reporting Process




·
            We
      did not have adequate internal controls relating to non-routine
      transactions and unusual journal entries, closing of accounting periods,
      account reconciliations and variance analyses, and recording hedging
      transactions including validation of monthly settlements and recording
      unrealized and realized
gains/losses.




Midstream
Cost of Natural Gas and Natural Gas Liquids




·
            We
      did not have adequate internal controls relating to pricing, including
      controls over loading and maintenance of monthly index pricing in the
      revenue system associated with our Midstream
  Segment.




43


Remediated
Material Weaknesses




As of the
filing of this Quarterly Report on Form 10-Q, our management has completed the
implementation of our remediation efforts related to the material weaknesses
over the Internal Control Environment and Midstream Cost of Natural Gas and
Natural Gas Liquids which included the following:




Internal
Control Environment




·
            Developed
      and delivered Internal Controls (“COSO”) training to Executives, other
      management and finance/accounting resources. The training included a
      review of management’s and individual roles and responsibilities related
      to internal controls;


·
            Hired
      additional finance and accounting resources who possess public company
      accounting and reporting technical expertise. This includes five Certified
      Public Accounting resources. A portion of their job responsibilities is to
      perform reviews, reconciliations and other financial reporting monitoring
      controls;


·
            Created
      a Compliance Office within the Risk and Compliance Department. The
      Compliance Office is focused on working with management to educate and
      inform staff on their internal control responsibilities, evaluate and
      assess the adequacy and operating effectiveness of internal controls and
      to assist management with identifying and remediating control
      deficiencies; and


·
            Completed
      an Enterprise Risk Assessment covering all of the partnership’s segments.
      The results and our management’s action plans were reported to and
      discussed with the Audit Committee during the review of the June 30, 2008
      Quarterly Report on Form 10-Q.




Midstream
Cost of Natural Gas and Natural Gas Liquids




·
            Management
      implemented new monitoring controls related to reviewing the accuracy of
      prices which are uploaded into the midstream revenue
      systems.  These controls were independently tested by management
      and were determined to be operating
effectively.




Management
has completed its remediation efforts as of the date of this filing for these
material weaknesses. Accordingly, management deems these material weaknesses
remediated as of the date of the filing of this Quarterly Report on Form
10-Q.




Un-remediated
Material Weakness




Management
continues to devote significant planning and execution efforts toward
remediation of the remaining material weakness related to period end financial
reporting which is specific tocontrols related to the
close process, including controls over:


·
            Non-routine
      transactions and unusual journal
entries;


·
            Closing
      of accounting periods;


·
            Account
      reconciliations and variance analyses;
and


·
            Recording
      hedging transactions including validation of monthly settlements and
      recording of unrealized and realized
  gains/losses





As of the
filing of this Quarterly Report on Form 10-Q, our management has completed the
following toward remediation of this material weakness:


·
            Implemented
      a monthly balance sheet account reconciliation process and controls across
      all segments and is in the process of testing the operating effectiveness
      of the controls within the midstream and corporate
      segments.  The controls within the Minerals segment have been
      tested and deemed to be operating effectively. Testing of the upstream
      segment controls are scheduled to begin in thethird
      quarter of 2008;


·
            Implemented
      a monthly variance fluctuation analysis across all
      segments.  This control is also used to validate material,
      non-routine and unusual journal entries.  Testing of this
      control is in progress; and


·
            Implemented
      financial hedging procedures and controls to ensure the completeness and
      accuracy of recorded mark-to-market realized and unrealized gains and
      losses and also new monitoring controls to ensure that new transactions
      and changes to existing transactions are authorized and
      valid.   Controls related to the completeness and accuracy
      of recording realized and unrealized gains and losses have been tested and
      the conclusion is that the controls were operating
      effectively.





Management
is also in the process of implementing the following:


·
            Controls
      to detect un-posted journal
entries;


·
            Procedures
      to ensure that accounting periods are closed for all segments in a timely
      manner and access to open and close; accounting periods is adequately
      restricted;


44


·
            Controls
      to support the accuracy of material accruals including those accruals that
      are highly judgmental in nature;
and


·
            Continued
      hiring of well qualified personnel to insure that the proper accounting
      staff is in place to perform the necessary period end
      controls.





Management
believes that the new procedures and controls discussed above will provide an
appropriate remediation of the material weakness; however, the effectiveness of
the controls have not been fully tested by management.





Due to
the nature of the remediation process and the need to allow adequate time after
implementation to evaluate and test the effectiveness of the controls, no
assurance can be given as to the timing of achievement of remediation. The
material weaknesses will be fully remediated when, in the opinion of our
management, the revised control processes have been operating for a sufficient
period of time and independently validated by management.





The
remediation and ultimate resolution of each of the Partnership's material
weaknesses will be reviewed with the Audit Committee of the Partnership's Board
of Directors.




Changes
in Internal Control Over Financial Reporting




During
thesecond
quarter of 2008, we completed an acquisition of Stanolind Oil and Gas
Company.  Because of the timing of the acquisition, management
anticipates that it will not include the internal control processes for this
entity in its 2008 internal controls assessment to be included in our Annual
Report for the year ending December 31, 2008.   The acquisition
is excluded from the certifications required under Section 302 of the
Sarbanes-Oxley Act of 2002.  We will include all aspects of internal
controls over financial reporting for this acquisition, including changes to our
internal controls over financial reporting based on this acquisition, in our
2009 assessment.




All other
changes in the Partnership's internal controls over financial reporting during
the quarter ended June 30, 2008 that have been materially affected, or are
reasonably likely to materially affect, our internal control over financial
reporting have been described above.







45




PART II. OTHER INFORMATION






Item
1. Legal Proceedings.




Our
operations are subject to a variety of risks and disputes normally incident to
our business. As a result, we are and may, at any given time, be a defendant in
various legal proceedings and litigation arising in the ordinary course of
business. However, we are not currently a party to any material litigation. We
maintain insurance policies with insurers in amounts and with coverage and
deductibles that we, with the advice of our insurance advisors and brokers,
believe are reasonable and prudent. We cannot, however, assure you that this
insurance will be adequate to protect us from all material expenses related to
potential future claims for personal and property damage or that these levels of
insurance will be available in the future at economical prices.




On June
20th
of 2008, the Texas Commission on Environmental Quality (“TCEQ”) issued a Notice
of Enforcement  (“NOE”) to one of our subsidiaries, TCEQ ID No.: 
CF-0068-J (the “First NOE”), and on June 25th of
2008, the TCEQ issued a NOE one of our subsidiaries (TCEQ ID No.: 
CF-0070-W) (the “Second NOE”).  Both the First NOE and the Second NOE were
the result of findings made by the TCEQ’s Amarillo Region Office during routine
investigations of our Cargray facilities in the Texas Panhandle.  The First
NOE primarily relates to allegations of emissions in excess of those permitted,
and the Second NOE primarily relates to allegations of operation of an engine in
excess of the maximum hours of operation represented to the TCEQ.  Both the
First NOE and the Second NOE allege that the resulting emissions levels at each
site result in the site being a “major source” for both nitrogen oxides and
carbon monoxide, necessitating the site to have been permitted with a Title V
permit, which it was not.  We took prompt corrective action, by placing
controls on the engine in question in the First NOE and by completely
discontinuing operation of the engine in question in the Second NOE, and as a
result, we believe that the sites are now in compliance and have all necessary
permits with TCEQ.  We anticipate that our first-time offender status and
our prompt corrective actions will limit the amount of any administrative
penalty to be assessed by the TCEQ.  The TCEQ has great discretion to
assess administrative penalties, in a range of $0 to $10,000 per day, and the
allegations underpinning each of the First NOE and the Second NOE involve a time
period that runs over one year.




Item
1A. Risk Factors.




There
have not been any material changes from risk factors as previously disclosed in
our annual report on Form 10-K for the year ended December 31,
2007.




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.




We have
reported on Form 8-K during the quarter covered by this report all information
required to be reported on Form 8-K.




46




Item
6. Exhibits.




2.1
            Stock
      Purchase Agreement dated April 2, 2008 among Eagle Rock Energy Partners,
      L.P., Stanolind Holdings, L.P. and Stanolind Oil and Gas Corp.
      (incorporated by reference to Exhibit 2.8 of the Form 8-K filed with the
      Commission on April 4, 2008)31.1
            Certification
      by Joseph A. Mills pursuant to Section 302 of the Sarbanes-Oxley Act of
      2002 and 18 U.S.C. Section 7241.31.2
            Certification
      by Darin G. Holderness pursuant to Section 302 of the Sarbanes-Oxley Act
      of 2002 and 18 U.S.C. Section 7241.32.1
            Certification
      by Joseph A. Mills pursuant to Section 906 of the Sarbanes-Oxley Act of
      2002 and 18 U.S.C. Section 1350.32.2
            Certification
      by Darin G. Holderness pursuant to Section 906 of the Sarbanes-Oxley Act
      of 2002 and 18 U.S.C. Section 1350.





47


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:
      August 8, 2008
            EAGLE
      ROCK ENERGY PARTNERS, L.P.
              
              By:
      EAGLE ROCK ENERGY GP, L.P., its general
              partner
              
              By:
      EAGLE ROCK ENERGY G&P, LLC, its
              general
      partner
              
              By:                           /s/ Darin G.
      Holderness
              Darin
      G. Holderness
              Senior
      Vice President and
              Chief
      Financial Officer of Eagle Rock
              Energy
      G&P, LLC, General Partner of Eagle Rock
              Energy
      GP, L.P., General Partner of Eagle Rock
              Energy
      Partners, L.P.
              (Duly
      Authorized and Principal Financial
Officer)





48


EAGLE
ROCK ENERGY PARTNERS, L.P.


EXHIBIT
INDEX





2.1
            Stock
      Purchase Agreement dated April 2, 2008 among Eagle Rock Energy Partners,
      L.P., Stanolind Holdings, L.P. and Stanolind Oil and Gas Corp.
      (incorporated by reference to Exhibit 2.8 of the Form 8-K filed with the
      Commission on April 4, 2008)31.1
            Certification
      by Joseph A. Mills pursuant to Section 302 of the Sarbanes-Oxley Act of
      2002 and 18 U.S.C. Section 7241.31.2
            Certification
      by Darin G. Holderness pursuant to Section 302 of the Sarbanes-Oxley Act
      of 2002 and 18 U.S.C. Section 7241.32.1
            Certification
      by Joseph A. Mills pursuant to Section 906 of the Sarbanes-Oxley Act of
      2002 and 18 U.S.C. Section 1350.32.2
            Certification
      by Darin G. Holderness pursuant to Section 906 of the Sarbanes-Oxley Act
      of 2002 and 18 U.S.C. Section 1350.





49