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 September 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 55,774,197 common units outstanding as of October 31,
2008.
  
  
  EAGLE
ROCK ENERGY PARTNERS, L.P.
 
 TABLE
OF CONTENTS
 
 
 
 
 
 PagePART
      I. FINANCIAL INFORMATIONItem
      1.
              Financial
      StatementsUnaudited
      Condensed Consolidated Balance Sheets as of September 30, 2008 andDecember
      31, 2007
              1Unaudited
      Condensed Consolidated Statements of Operations for the three months and
      nine months ended September 30, 2008 and 2007
              2Unaudited
      Condensed Consolidated Statements of Cash Flows for the nine months ended
      September 30, 2008 and 2007
              3Unaudited
      Condensed Consolidated Statements of Members’ Equity for the nine months
      ended September 30, 2008
              4Notes
      to Unaudited Condensed Consolidated Financial Statements
              5Item
      2.
              Management’s
      Discussion and Analysis of Financial Condition and Results of
      Operations
              24Item
      3.
              Quantitative
      and Qualitative Disclosures About Market Risk
              45Item
      4.
              Controls
      and Procedures
              47PART
      II. OTHER INFORMATIONItem
      1.
              Legal
      Proceedings
              49Item
      1A.
              Risk
      Factors
              49Item
      2.
              Unregistered
      Sales of Equity Securities and Use of Proceeds
              49Item
      3.
              Defaults
      Upon Senior Securities
              49Item
      4.
              Submission
      of Matters to a Vote of Security Holders
              49Item
      5.
              Other
      Information
              49Item
      6.
              Exhibits
              50
  
  PART
I. FINANCIAL INFORMATION
 
 Item
1. Financial Statements.
 
 EAGLE
ROCK ENERGY PARTNERS, L.P.
 UNAUDITED
CONDENSED CONSOLIDATED BALANCE SHEETS
 ($
in thousands, except unit amounts)
 
 September
      30,
                2008
              
              
              December 31,
                  2007ASSETSCURRENT
      ASSETS:Cash
      and cash equivalents
              
              $
              229,104
              
              
              $
              68,552Accounts
      Receivable(1)
              
              
              138,146
              
              
              
              135,633Risk
      management assets
              
              
              5,239
              
              
              
              —Prepayments
      and other current assets
              
              
              2,344
              
              
              
              3,992Total
      current assets
              
              
              374,833
              
              
              
              208,177PROPERTY,
      PLANT AND EQUIPMENT — Net
              
              
              1,310,422
              
              
              
              1,207,130INTANGIBLE
      ASSETS — Net
              
              
              141,414
              
              
              
              153,948GOODWILL
              
              
              29,890
              
              
              
              29,527RISK
      MANAGEMENT ASSETS
              
              
              2,589
              
              
              
              —OTHER
      ASSETS
              
              
              13,938
              
              
              
              11,145TOTAL
              
              $
              1,873,086
              
              
              $
              1,609,927LIABILITIES
      AND MEMBERS’ EQUITYCURRENT
      LIABILITIES:Accounts
      payable
              
              $
              137,893
              
              
              $
              132,485Due
      to affiliate
              
              
              16,405
              
              
              
              16,964Accrued
      liabilities
              
              
              15,074
              
              
              
              9,776Income
      taxes payable
              
              
              1,009
              
              
              
              723Risk
      management liabilities
              
              
              60,823
              
              
              
              33,089Total
      current liabilities
              
              
              231,204
              
              
              
              193,037LONG-TERM
      DEBT
              
              
              799,383
              
              
              
              567,069ASSET
      RETIREMENT OBLIGATIONS
              
              
              17,062
              
              
              
              11,337DEFERRED
      INCOME TAXES
              
              
              42,508
              
              
              
              17,516RISK
      MANAGEMENT LIABILITIES
              
              
              107,750
              
              
              
              94,200COMMITMENTS
      AND CONTINGENCIES (Note 12)MEMBERS’
      EQUITY:Common
      Unitholders(2)
              
              
              580,888
              
              
              
              617,563Subordinated
      Unitholders(3)
              
              
              98,040
              
              
              
              112,360General
      Partner(4)
              
              
              (3,749
              )
              
              
              (3,155
              )Total
      members’ equity
              
              
              675,179
              
              
              
              726,768TOTAL
              
              $
              1,873,086
              
              
              $
              1,609,927
 
 
 (1)
              Net
      of allowable for bad debt of $11,093 and $1,046 as of September 30,
      2008 and December 31, 2007, respectively.(2)
              50,824,031
      and 50,699,647 units were issued and outstanding as of September 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 748,466 and 467,062 as of September 30, 2008
      and December 31, 2007, respectively.(3)
              20,691,495
      units were issued and outstanding as of September 30, 2008 and December
      31, 2007, respectively.(4)
              844,551
      units were issued and outstanding as of September 30, 2008 and December
      31, 2007, respectively.
 
 See notes
to unaudited condensed consolidated financial statements.
  1
  EAGLE
ROCK ENERGY PARTNERS, L.P.
 UNAUDITED
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
 ($
in thousands, except per unit amounts)
 
 Three
      Months
                  Ended
      September 30,
              
              
              Nine
      Months
                  Ended
      September 30,2008
              
              
              2007
              
              
              2008
              
              
              2007REVENUE:Natural
      gas, natural gas liquids, oil, condensate and sulfur sales
              
              $
              421,346
              
              
              $
              254,084
              
              
              $
              1,230,134
              
              
              $
              555,826Gathering,
      compression, processing and treating fees
              
              
              12,513
              
              
              
              8,103
              
              
              
              27,741
              
              
              
              19,269Mineral
      and royalty income
              
              
              17,393
              
              
              
              6,009
              
              
              
              34,606
              
              
              
              9,201Commodity
      risk management gains (losses)
              
              
              231,851
              
              
              
              8,688
              
              
              
              (97,769
              )
              
              
              (26,209
              )Other
      revenue
              
              
              428
              
              
              
              (20
              )
              
              
              610
              
              
              
              (20
              )Total
      revenue
              
              
              683,531
              
              
              
              276,864
              
              
              
              1,195,322
              
              
              
              558,067COSTS
      AND EXPENSES:Cost
      of natural gas and natural gas liquids
              
              
              316,788
              
              
              
              196,839
              
              
              
              946,177
              
              
              
              451,840Operations
      and maintenance
              
              
              21,475
              
              
              
              16,883
              
              
              
              54,772
              
              
              
              36,015Taxes
      other than income
              
              
              5,365
              
              
              
              2,746
              
              
              
              14,975
              
              
              
              4,364General
      and administrative
              
              
              9,893
              
              
              
              7,196
              
              
              
              31,161
              
              
              
              16,587Other
      operating expense
              
              
              3,920
              
              
              
              220
              
              
              
              10,134
              
              
              
              1,931Depreciation,
      depletion and amortization
              
              
              28,597
              
              
              
              25,105
              
              
              
              80,799
              
              
              
              50,883Total
      costs and expenses
              
              
              386,038
              
              
              
              248,989
              
              
              
              1,138,018
              
              
              
              561,620OPERATING
      INCOME (LOSS)
              
              
              297,493
              
              
              
              27,875
              
              
              
              57,304
              
              
              
              (3,553
              )OTHER
      INCOME (EXPENSE):Interest
      income
              
              
              212
              
              
              
              231
              
              
              
              673
              
              
              
              530Other
      income
              
              
              434
              
              
              
              767
              
              
              
              2,867
              
              
              
              879Interest
      expense, net
              
              
              (7,498
              )
              
              
              (10,633
              )
              
              
              (23,576
              )
              
              
              (27,031
              )Interest
      rate risk management losses
              
              
              (2,859
              )
              
              
              (8,102
              )
              
              
              (5,375
              )
              
              
              (2,588
              )Other
      expense
              
              
              (205
              )
              
              
              (415
              )
              
              
              (652
              )
              
              
              (1,545
              )Total
      other expense
              
              
              (9,916
              )
              
              
              (18,152
              )
              
              
              (26,063
              )
              
              
              (29,755
              )INCOME
      (LOSS) BEFORE INCOME TAXES
              
              
              287,577
              
              
              
              9,723
              
              
              
              31,241
              
              
              
              (33,308
              )INCOME
      TAX (BENEFIT) PROVISION
              
              
              (494
              )
              
              
              352
              
              
              
              (1,482
              )
              
              
              772NET
      INCOME (LOSS)
              
              $
              288,071
              
              
              $
              9,371
              
              
              $
              32,723
              
              
              $
              (34,080
              )NET
      INCOME (LOSS) PER COMMON UNIT — BASIC AND DILUTED:Basic:Net
      Income (Loss)Common
      units
              
              $
              2.31
              
              
              $
              0.25
              
              
              $
              0.45
              
              
              $
              (0.24
              )Subordinated
      units
              
              $
              2.31
              
              
              $
              (0.09
              )
              
              $
              0.45
              
              
              $
              (1.22
              )General
      partner units
              
              $
              2.31
              
              
              $
              (0.09
              )
              
              $
              0.45
              
              
              $
              (1.22
              )Basic
      (units in thousands)Common
      units
              
              
              50,824
              
              
              
              45,954
              
              
              
              50,762
              
              
              
              32,512Subordinated
      units
              
              
              20,691
              
              
              
              20,691
              
              
              
              20,691
              
              
              
              20,691General
      partner units
              
              
              845
              
              
              
              845
              
              
              
              845
              
              
              
              845Diluted:Net
      Income (Loss)Common
      units
              
              $
              2.31
              
              
              $
              0.25
              
              
              $
              0.45
              
              
              $
              (0.24
              )Subordinated
      units
              
              $
              2.31
              
              
              $
              (0.09
              )
              
              $
              0.45
              
              
              $
              (1.22
              )General
      partner units
              
              $
              2.31
              
              
              $
              (0.09
              )
              
              $
              0.45
              
              
              $
              (1.22
              )Diluted
      (units in thousands)Common
      units
              
              
              50,868
              
              
              
              46,021
              
              
              
              50,900
              
              
              
              32,539Subordinated
      units
              
              
              20,691
              
              
              
              20,691
              
              
              
              20,691
              
              
              
              20,691General
      partner units
              
              
              845
              
              
              
              845
              
              
              
              845
              
              
              
              845
 
 See notes
to unaudited condensed consolidated financial statements.
  2
  EAGLE
ROCK ENERGY PARTNERS, L.P.
 UNAUDITED
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
 ($
in thousands)
 
 Nine
      Months
                Ended September 30,2008
              
              
              2007CASH
      FLOWS FROM OPERATING ACTIVITIES:Net
      Income/(Loss)
              
              $
              32,723
              
              
              $
              (34,080
              )Adjustments
      to reconcile net loss to net cash provided by operating
      activities:Depreciation,
      depletion and amortization
              
              
              80,799
              
              
              
              50,883Amortization
      of debt issuance costs
              
              
              655
              
              
              
              416Reclassifying
      financing derivative settlements
              
              
              15,462
              
              
              
              (100
              )Distribution
      from unconsolidated affiliates – return on investment
              
              
              1,751
              
              
              
              —Equity
      in earnings of unconsolidated affiliates
              
              
              (2,859
              )
              
              
              —Equity-based
      compensation expense
              
              
              4,147
              
              
              
              1,578Other
              
              
              (1,726
              )
              
              
              (241
              )Changes
      in assets and liabilities — net of acquisitions:Accounts
      receivable
              
              
              634
              
              
              
              (22,437
              )Prepayments
      and other current assets
              
              
              17
              
              
              
              2,115Risk
      management activities
              
              
              30,592
              
              
              
              25,102Accounts
      payable
              
              
              2,742
              
              
              
              24,516Due
      to affiliates
              
              
              (559
              )
              
              
              17,541Accrued
      liabilities
              
              
              (1,227
              )
              
              
              11,018Other
      assets and liabilities
              
              
              420
              
              
              
              287Net
      cash provided by operating
      activities
              
              
              163,571
              
              
              
              76,598CASH
      FLOWS FROM INVESTING ACTIVITIES:Acquisitions,
      net of cash
      acquired
              
              
              (81,289
              )
              
              
              (403,170
              )Additions
      to property, plant and
      equipment
              
              
              (45,337
              )
              
              
              (53,787
              )Purchase
      of intangible
      assets
              
              
              (1,438
              )
              
              
              (1,128
              )Investment
      in
      partnership
              
              
              (3,416
              )
              
              
              —Other
              
              
              —
              
              
              
              22Net
      cash used in investing
      activities
              
              
              (131,480
              )
              
              
              (458,063
              )CASH
      FLOWS FROM FINANCING ACTIVITIES:Repayment
      of revolving credit
      facility
              
              
              (145,069
              )
              
              
              (18,054
              )Proceeds
      from revolving credit
      facility
              
              
              377,383
              
              
              
              173,400Proceeds
      (payments) on derivative
      contracts
              
              
              (15,462
              )
              
              
              100Payment
      of debt issuance
      costs
              
              
              (789
              )
              
              
              —Proceeds
      from equity
      issuance
              
              
              —
              
              
              
              331,500Distributions
      to members and
      affiliates
              
              
              (87,602
              )
              
              
              (31,775
              )Net
      cash provided by financing
      activities
              
              
              128,461
              
              
              
              455,171NET
      CHANGE IN CASH AND CASH EQUIVALENTS
              
              
              160,552
              
              
              
              73,706CASH
      AND CASH EQUIVALENTS — Beginning of period
              
              
              68,552
              
              
              
              10,851CASH
      AND CASH EQUIVALENTS — End of period
              
              $
              229,104
              
              
              $
              84,557SUPPLEMENTAL
      CASH FLOW DATA:Interest
      paid — net of amounts
      capitalized
              
              $
              26,028
              
              
              $
              27,212Investments
      in property, plant and equipment not
      paid
              
              $
              5,534
              
              
              $
              2,068Acquisition
      of assets for
      equity
              
              $
              —
              
              
              $
              307,937
 
 See notes
to unaudited condensed consolidated financial statements.
  3
  
 EAGLE
ROCK ENERGY PARTNERS, L.P.
 UNAUDITED
CONDENSED CONSOLIDATED STATEMENT OF MEMBERS’ EQUITY
 FOR
THE NINE MONTHS ENDED SEPTEMBER 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
      income
              
              
              —
              
              
              
              382
              
              
              
              —
              
              
              
              22,976
              
              
              
              —
              
              
              
              9,365
              
              
              
              32,723Distributions
              
              
              —
              
              
              
              (1,016
              )
              
              
              —
              
              
              
              (61,704
              )
              
              
              —
              
              
              
              (24,882
              )
              
              
              (87,602
              )Vesting
      of restricted units
              
              
              —
              
              
              
              —
              
              
              
              124,384
              
              
              
              ---
              
              
              
              —
              
              
              
              —
              
              
              
              —Distribution
      to affiliates
              
              
              —
              
              
              
              —
              
              
              
              —
              
              
              
              (857
              )
              
              
              —
              
              
              
              —
              
              
              
              (857
              )Restricted
      unit expense
              
              
              —
              
              
              
              40
              
              
              
              —
              
              
              
              2,910
              
              
              
              —
              
              
              
              1,197
              
              
              
              4,147BALANCE
      —September
      30, 2008
              
              
              844,551
              
              
              $
              (3,749
              )
              
              
              50,824,031
              
              
              $
              580,888
              
              
              
              20,691,495
              
              
              $
              98,040
              
              
              $
              675,179
 
 See notes
to unaudited condensed consolidated financial statements.
  4
  EAGLE
ROCK ENERGY PARTNERS, L.P
 NOTES
TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
 SEPTEMBER
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, became a subsidiary of Eagle Rock Energy.
  Basis of Presentation and Principles
of Consolidation—The accompanying financial statements include assets,
liabilities and the results of operations of the Partnership. These unaudited
condensed consolidated financial statements should be read in conjunction with
the consolidated financial statements presented in the Partnership’s Annual
Report on Form 10-K for the year ended December 31, 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 nine-month periods
ending September 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 and transporting of natural
gas; fractionating and transporting natural gas liquids (“NGLs”); and marketing
natural gas, condensate and NGLs, which collectively the Partnership calls its
“Midstream” business, (ii) acquiring, developing and producing interests in oil
and natural gas properties, which the Partnership calls its “Upstream” business;
and (iii) acquiring and managing fee mineral and royalty interests, either
through direct ownership or through investment in other partnerships in
properties in multiple producing trends across the United States, which the
Partnership calls its “Minerals” business.  See Note 13 for a further
description of the Partnership’s three businesses and the 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
   5
   unsuccessful.
The Partnership carries the costs of an exploratory well as an asset if the well
finds a sufficient quantity of reserves to justify its capitalization as a
producing well as long as the Partnership is making sufficient progress towards
assessing the reserves and the economic and operating viability of the
project.
  Depletion of
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 nine months ended September 30, 2008, goodwill increased by $0.4
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, if not subject to cash out
provisions, are recovered or repaid through the receipt or delivery of natural
gas or natural gas liquids in future periods. Imbalance receivables are included
in accounts receivable; imbalance payables are included in accounts payable on
the condensed consolidated balance sheets and marked-to-market using current
market prices in effect for the reporting period of the outstanding imbalances.
For the midstream business, as of September 30, 2008, the Partnership had
imbalance receivables totaling $0.5 million and imbalance payables totaling $4.8
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 to 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. Because the Partnership has not designated any of these derivatives as
hedges, the Partnership recognizes these financial instruments on its
consolidated balance sheets at the instrument’s fair value, and changes in fair
value are reflected in the consolidated statements of operations. The cash flows
from derivatives are reported as cash flows from operating activities unless the
derivative contract is deemed to contain a financing element. Derivatives deemed
to contain a financing element are reported as a financing activity in the
statements of cash
  6
  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.  These reclassifications had no impact on total
operating income (loss) or net income (loss).  Amounts recorded in
"Other Income" within Revenue in the Partnerships Unaudited Condensed
Consolidated Statements of Operations for the three and nine months ended
September 30, 2007 have been reclassified as "Natural gas, natural gas liquids,
oil, condensate and sulfur sales" and as "Gathering, compression, processing and
treating fees" for comparability to the 2008
presentation.  Amounts for "Realized interest rate risk management
gains and (losses)" were presented in "Interest expense, net," in the
Partnership’s Unaudited Condensed Consolidated Statements of Operations for the
three and nine months ended September 30, 2007.  These amounts have
been presented herein as "Interest rate risk management gains (losses)" for
comparability to 2008 presentation.  Amounts recorded in "Interest
income" in the Partnerships Unaudited Condensed Consolidated Statements of
Operations for the three and nine months ended September 30, 2007 have been
reclassified as "Interest expense, net," for comparability to the 2008
presentation.
  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 on its financial
statements, if any, of adopting FSP FAS 157-2.
  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 of minority
interests 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
   7
  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 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 affects entities that accrue
cash dividends on share-based payment awards during the awards’ service period
when dividends do not need to be returned if the employees forfeit the
awards.  FSP EITF 03-6-1 is effective for fiscal years beginning after
December 15, 2008 and earnings-per-unit calculations would need to be adjusted
retroactively.  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
 
 2008
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 borrowings under its existing
credit facility as well as existing cash from operations.  Stanolind
owned and operated oil and natural gas producing properties in the Permian
Basin, primarily in Ward, Crane and Pecos Counties, Texas.
  8
  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
within 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 owning 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 management and the Conflicts
Committee, the Board of Directors approved the transaction.
  2007
Acquisitions
  During
the three months ended September 30, 2008, the Partnership finalized its
purchase price allocations with respect to its acquisition of Escambia Asset
Co., LLC and Escambia Operating Co., LLC (the “EAC Acquisition”) and its
acquisition of Redman Energy Holdings, L.P. and Redman Energy Holdings II, L.P.
(the “Redman Acquisition”).  With respect to the EAC Acquisition,
during the three months ended September 30, 2008, the Partnership increased the
amount assumed for the environmental liability by $2.6 million and finalized the
acquired working capital balances, which resulted in an increase to plant
and related assets of $3.0 million.  With respect to the Redman
Acquisition, during the three months ended September 30, 2008, the Partnership
finalized the acquired working capital balances which resulted in an increase to
goodwill of $0.4 million.
  
  9
   NOTE
5.  FIXED ASSETS AND ASSET RETIREMENT OBLIGATIONS
  Fixed assets
consisted of the following:
  September
      30,
              
              
              December
      31,2008
              
              
              2007($
      in thousands)Land
              
              $
              1,153
              
              
              $
              1,153Plant
              
              
              196,647
              
              
              
              181,689Gathering
      and pipeline
              
              
              552,221
              
              
              
              541,247Equipment
      and machinery
              
              
              15,858
              
              
              
              14,081Vehicles
      and transportation equipment
              
              
              3,949
              
              
              
              3,657Office
      equipment, furniture, and fixtures
              
              
              1,022
              
              
              
              1,023Computer
      equipment
              
              
              4,714
              
              
              
              4,636Corporate
              
              
              126
              
              
              
              126Linefill
              
              
              4,157
              
              
              
              4,157Proved
      properties
              
              
              586,876
              
              
              
              461,884Unproved
      properties
              
              
              73,621
              
              
              
              66,023Construction
      in progress
              
              
              30,295
              
              
              
              20,8841,470,639
              
              
              
              1,300,560Less:
      accumulated depreciation and amortization
              
              
              (160,217
              )
              
              
              (93,430
              )Net
      fixed assets
              
              $
              1,310,422
              
              
              $
              1,207,130
 
 Depreciation
expense for the three and nine months ended September 30, 2008 and for the three
and nine months ended September 30, 2007 was approximately $9.8 million, $31.8
million, $10.9 million and $26.9 million, respectively. Depletion expense for
the three and nine months ended September 30, 2008 and for the three and nine
months ended September 30, 2007 was approximately $14.1 million, $35.0 million,
$9.4 million and $10.9 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 nine months ended September 30, 2008 and 2007, the
Partnership capitalized interest costs of approximately $0.1 million, $0.5
million, $0.3 million and $0.8 million, respectively.
  Asset Retirement
Obligations—The Partnership recognizes asset retirement obligations for
its oil and gas working interests in accordance with FASB Statement
No. 143, Accounting for
Asset Retirement Obligations (“SFAS 143”). SFAS 143 applies to
obligations associated with the retirement of tangible long-lived assets that
result from the acquisition, construction and development of the assets. SFAS
143 requires that the Partnership record the fair value of a liability for an
asset retirement obligation in the period in which it is incurred and a
corresponding increase in the carrying amount of the related long-lived asset.
The Partnership recognizes asset retirement obligations for its midstream assets
in accordance with FASB Interpretation No. 47, Accounting for Conditional Asset
Retirement Obligations, an interpretation of FASB Statement No. 143(“FIN 47”). FIN 47 clarified that the term “conditional asset retirement
obligation”, as used in SFAS No. 143,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
              
              
              751Asset
      retirement obligations—September 30, 2008
              
              $
              17,062
  
   10
   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, $14.0 million,
$4.8 million and $13.1 million for the three and nine months ended September 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:
  September
      30,
              
              
              December
      31,2008
              
              
              2007($
      in thousands)Rights-of-way
      and easements—at cost
              
              $
              81,507
              
              
              $
              80,069Less:
      accumulated amortization
              
              
              (10,315
              )
              
              
              (7,274
              )Customer
      contracts
              
              
              108,772
              
              
              
              108,772Less:
      accumulated amortization
              
              
              (38,550
              )
              
              
              (27,619
              )Net
      intangible assets
              
              $
              141,414
              
              
              $
              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 a weighted average as of September 30,
2008.
  NOTE
7.  LONG-TERM DEBT
  During
the three months ended September 30, 2008, the Partnership exercised $180
million of its $200 million accordion feature under its senior secured revolving
credit facility (“Revolving Credit Facility”), which increased the total
commitments from the Partnership’s lenders to $980 million.  In
connection with exercising the accordion feature of its Revolving Credit
Facility, the Partnership incurred debt issuance costs of $0.8
million.  As of September 30, 2008 and December 31, 2007, the
Partnership had $799.4 million and $567.1 million outstanding, respectively,
under its Revolving Credit Facility.  As of September 30, 2008, the
Partnership was in compliance with the financial covenants under its Revolving
Credit Facility and the unused capacity available to the Partnership under the
Revolving Credit Facility was approximately $175 million (excluding the
commitment from Lehman Brothers), based on the financial covenants.
  NOTE
8.  MEMBERS’ EQUITY
  At
September 30, 2008, there were 50,824,031 common units (not including unvested
restricted common units), 20,691,495 subordinated units (all owned by Holdings)
and 844,551 general partner units outstanding. In addition, there
were 748,466 unvested restricted common units outstanding at September
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 day of any quarter beginning after
September 30, 2009 in respect of which, among other things, the Partnership has
earned and paid at least $1.45 (the minimum quarterly distribution on an
annualized basis) on each outstanding limited partner unit and general partner
unit for each of the three consecutive, non-overlapping four quarter periods
immediately preceding such date.  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 all its unitholders (i.e. common, including unvested restricted
units, general and subordinated) of record as of February 11, 2008. The
distribution amount was $0.3925 per unit, 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 all unitholders of
  11
  record as
of May 9, 2008.
  On July
29, 2008, the Partnership declared a cash distribution of $0.41 per unit, or
approximately $30.0 million, for the second quarter ended June 30,
2008.  The distribution was paid on August 14, 2008, for all
unitholders of record as of August 8, 2008.
  On
October 29, 2008, the Partnership declared a cash distribution of $0.41 per unit
for the third quarter ended September 30, 2008.  The distribution will
be paid on November 14, 2008, for all unitholders of record as of November 7,
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.  In July 2008, the company to which
we sold our natural gas was sold by the affiliate of NGP and thus ceased being a
related party.  For the period that such counterparty was an
affiliate, the Partnership recorded revenues of $0.0 million, $16.0 million,
$6.5 million and $20.4 million for the three and nine months ended September 30,
2008 and 2007, respectively, of which there was a receivable of $5.5
million outstanding at December 31, 2007, respectively.
  In
addition, during the three and nine months ended September 30, 2008 and
September 30, 2007, the Partnership incurred $1.7 million, $4.7 million, $1.1
million and $4.0 million in expenses with related parties, of which there was an
outstanding accounts payable balance of $0.5 million and $0.5 million as of
September 30, 2008 and December 31, 2007.
  Related
to its investments in unconsolidated subsidiaries, during the three and nine
months ended September 30, 2008 and 2007, the Partnership recorded income of
$0.4 million and $2.9 million, respectively, of which there was no outstanding
account receivable balance as of September 30, 2008 and December 31, 2007,
respectively.
  As of
September 30, 2008 and December 31, 2007, Eagle Rock Energy G&P, LLC had
$16.4 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 and nine months ended September 30, 2008, the Partnership incurred
approximately $1.0 million and $1.6 million for services performed by Stanolind
Field Services (“SFS”), which are assets controlled by NGP and certain
individuals, including one employee of Eagle Rock Energy G&P,
LLC.  As of September 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 gives 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,
   12
  volatility
factors and current market and contractual prices for the underlying
instruments, as well as other relevant economic
measures.  Substantially all of these assumptions are observable in
the market place throughout the full term of the instrument, can be derived from
observable data or are supported by observable levels at which transactions are
executed in the marketplace.
 
 Level 3 – Pricing inputs
include significant inputs that are generally less observable from objective
sources.  These inputs may be used with internally developed
methodologies that result in management’s best estimate of fair
value.
  As of
September 30, 2008, the Partnership has recorded its interest rate swaps and
commodity derivative instruments (see Note 11), which includes crude oil,
natural gas and natural gas liquids (“NGLs”), at fair value. The Partnership has
classified the inputs to measure the fair value of its interest rate swap, crude
oil derivatives and natural gas derivatives as Level 2.  Because the NGL
market is considered to be less liquid beyond one year's time, 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. The following table
discloses the fair value of the Partnership’s derivative instruments as of
September 30, 2008:
 
 Level
      1
              
              
              Level
      2
              
              
              Level
      3
              
              
              Total($
      in thousands)Assets:Crude  oil
      derivatives
              
              $
              —
              
              
              $
              7,705
              
              
              $
              —
              
              
              $
              7,705Natural
      gas derivatives
              
              
              —
              
              
              
              123
              
              
              
              —
              
              
              
              123Total
              
              $
              —
              
              
              $
              7,828
              
              
              $
              —
              
              
              $
              7,828Liabilities:Crude oil
    derivatives
              
              $
              —
              
              
              $
              (125,478
              )
              
              $
              —
              
              
              $
              (125,478
              )Natural
      gas derivatives
              
              
              —
              
              
              
              (931
              )
              
              
              —
              
              
              
              (931
              )NGL
      derivatives
              
              
              —
              
              
              
              (15,241
              )
              
              
              (14,223
              )
              
              
              (29,464
              )Interest rate
      derivatives
              
              
              —
              
              
              
              (12,700
              )
              
              
              —
              
              
              
              (12,700
              )Total
              
              $
              —
              
              
              $
              (154,350
              )
              
              $
              (14,223
              )
              
              $
              (168,573
              )
 
 As of
September 30, 2008, risk management current assets in the Condensed Consolidated
Balance Sheet include an investment premium of $5.5 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 September 30, 2008 (in
thousands):
 
 Net
      liability balances as of July 1, 2008
              
              $
              36,856Transfers from Level 3 to
      Level 2
              
              
              (4,931
              )Unrealized
    gains
              
              
              (17,702
              )Net
      liability balances as of September 30, 2008
              
              $
              14,223
 
 The
following table sets forth a reconciliation of changes in the fair value of the
Level 3 NGL derivatives during the nine months ended September 30, 2008 (in
thousands):
 
 Net
      liability balances as of January 1, 2008
              
              $
              36,695Transfers from Level 3 to
      Level 2
              
              
              (15,661
              )Unrealized
    gains
              
              
              (6,811
              )Net
      liability balances as of September 30, 2008
              
              $
              14,223
 
 The
Partnership values its Level 3 NGL derivatives using forward curves, volatility
curves, volatility skew parameters, interest rate curves and model
parameters.
   13
  Realized
and unrealized losses related to the interest rate derivatives are recorded as
part of interest rate risk management gains and losses in the Condensed
Consolidated Statements of Operations.  Realized and unrealized gains
and losses and 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.
  The
carrying amount of cash equivalents is believed to approximate their fair values
because of the short maturities of these instruments. As of September 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 a portion of 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, demand, 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 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’s derivative
counterparties include BNP Paribas, Wachovia, Barclay’s, Royal Bank of Scotland,
Bank of America, Wells Fargo, J Aron (an affiliate of Goldman Sachs), British
Petroleum and Shell.
  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
      200-
              Gas
              20,000
      MMbtu
              WEST
      TEXAS (WAHA)
              
              $
              7.50
              
              
              $
              8.90
    14
  The
Partnership entered into the following derivative transactions associated with
its Midstream business during the three months ended September 30,
2008.  For the crude oil puts that were acquired, the Partnership paid
premiums totaling $3.3 million.  The natural gas collars were costless
transactions that were entered into in order to reduce the Partnership’s
exposure to potential natural gas increases.  The transactions offset
previous derivative transactions, and were necessary because of change in the
Partnership’s expected net natural gas position.
  Price
                ($
      per MMbtu or $ per Bbl)Period
              Commodity
              Average
      Volumes per Month
              Index
              
              Average
      Floor
              
              
              Average
      CeilingJan-Dec
      2009
              Oil
              7,000
      Bbl
              NYMEX
      WTI
              
              $
              90.00Jan-Dec
      2009
              Oil
              5,000
      Bbl
              NYMEX
      WTI
              
              $
              100.00Jan-Dec
      2010
              Oil
              6,000
      Bbl
              NYMEX
      WTI
              
              $
              90.00Jan-Dec
      2010
              Oil
              5,000
      Bbl
              NYMEX
      WTI
              
              $
              100.00Sep-Oct
      2008
              Gas
              (103,000)
      MMbtu
              NYMEX
      Henry Hub
              
              $
              8.65
              
              
              $
              10.62Nov-Dec
      2008
              Gas
              (103,000)
      MMbtu
              NYMEX
      Henry Hub
              
              $
              8.35
              
              
              $
              13.75Jan-Mar
      2009
              Gas
              (92,700)
      MMbtu
              NYMEX
      Henry Hub
              
              $
              8.80
              
              
              $
              13.75
  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's accruals were approximately
$1.3 million and $1.5 million as of September 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. 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 Partnership's insurance coverage includes (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 director and officer 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)
  15
  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 September 30, 2008 and December 31, 2007, the Partnership had accrued, on an
undiscounted basis, approximately $7.8 million and $2.4 million, respectively,
for environmental matters.
 
 TCEQ Matters—In 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 a second 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.  During the three months ended September 30,
2008, the Partnership executed an Agreed Order resolving with the TCEQ the two
Notice of Enforcement matters. The administrative penalties paid by the
Partnership were, in the aggregate, less than $10,000, and the Partnership
considers these matters concluded at this time.
  In late
September 2008, the TCEQ issued another Notice of Enforcement to a subsidiary of
the Partnership, concerning the environmental compliance of the Partnership’s
Red Deer Gas Plant (the “Site”), TCEQ ID No.: RH 0004-B (the “NOE”).  The
allegations in the NOE are the result of findings made by the TCEQ’s Amarillo
Region Office as a result of a routine inspection of the Site.  In
response, the subsidiary of the Partnership is providing substantial
documentation, some of which is corrective in nature, to the TCEQ and is
contesting certain other allegations.  The TCEQ has great discretion to
assess administrative penalties, in a range of $0 to $10,000 per day, and the
allegations underpinning the NOE involve a time period that runs over one
year.  The TCEQ has not yet made a final determination with respect to
whether 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 gas
prices.  These retained revenue interests do not represent a real
property interest in the hydrocarbons.  The Partnership’s reported
revenues are reduced to account for the retained revenue interests on a monthly
basis.
 
 The
retained revenue interests affect the Partnership’s interest at the Big Escambia
Creek, Flomaton and Fanny Church fields in Escambia County,
Alabama.  With respect to the Partnership’s Flomaton and Fanny Church
fields, the Partnership is currently making payments in satisfaction of the
retained revenue interests, and it expects these payments to continue through
the end of 2009 and possibly 2010.   With respect to the
Partnership’s Big Escambia Creek field, these payments are expected to begin in
2010 and continue through the end of 2019.
  Other Commitments—The
Partnership utilizes assets under operating leases for its corporate office,
certain rights-of way and facilities locations, vehicles and other equipment.
Rental expense, including leases with no continuing commitment, amounted to
approximately $1.2 million, $3.7 million, $0.3 million and $0.5 million for the
three and nine months ended September 30, 2008 and September 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 that is its Upstream Business, one minerals segment that is its
Minerals Business and one functional (corporate) segment:
  16
   (i)      Midstream—Texas Panhandle
Segment:
  gathering,
processing, transportating and marketing of natural gas, condensate and NGLs in
the Texas Panhandle;
  (ii)
              Midstream—South Texas
      Segment:
  gathering,
processing, transportating and marketing of natural gas in South
Texas;
  (iii)
              Midstream—East Texas/Louisiana
      Segment:
  
  (iv)
              Upstream
      Segment:
  crude
oil, natural gas, condensate, and NGLs and sulfur production from operated and
non-operated wells;
  (v)
              Minerals
      Segment:
  fee
minerals and royalties, lease bonus and rental income either through direct
ownership or through investment in other partnerships; and
  (vi)
              Corporate
      Segment:
  risk
management and other corporate activities.
  17
   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 September 30, 2008
              
              Texas
                  Panhandle
                  Segment
              
              
              South
                  Texas
                  Segment
              
              
              East Texas /
                  Louisiana
                  Segment
              
              
              Total
                  Midstream
                  Segments($
      in millions)Sales
      to external customers
              
              $
              182.3
              
              
              $
              115.8
              
              
              $
              80.8
              
              
              $
              378.9Cost
      of natural gas and natural gas liquids
              
              
              138.4
              
              
              
              112.4
              
              
              
              66.0
              
              
              
              316.8Operating
      costs and other expenses
              
              
              9.2
              
              
              
              0.6
              
              
              
              4.2
              
              
              
              14.0Depreciation,
      depletion, and amortization
              
              
              11.0
              
              
              
              0.9
              
              
              
              3.0
              
              
              
              14.9Operating
      income
              
              $
              23.7
              
              
              $
              1.9
              
              
              $
              7.6
              
              
              $
              33.2Capital
      Expenditures
              
              $
              7.2
              
              
              $
              0.2
              
              
              $
              2.6
              
              
              $
              10.0Segment
      Assets
              
              $
              580.6
              
              
              $
              89.6
              
              
              $
              250.9
              
              
              $
              921.1
 
 Three
      Months Ended September 30, 2008
              
              Total
                  Midstream
                  Segments
              
              
              Upstream
                  Segment
              
              
              Minerals
                  Segment
              
              
              Corporate
                  Segment
              
              
              Total
                  Segments($
      in millions)Sales
      to external customers
              
              $
              378.9
              
              
              $
              55.4
              
              
              $
              17.4
              
              
              $
              231.8
              (a)
              
              $
              683.5Cost
      of natural gas and natural gas liquids
              
              
              316.8
              
              
              
              —
              
              
              
              —
              
              
              
              —
              
              
              
              316.8Operating
      costs and other expenses
              
              
              14.0
              
              
              
              12.4
              
              
              
              0.4
              
              
              
              13.8
              
              
              
              40.6Depreciation,
      depletion,  and amortization
              
              
              14.9
              
              
              
              11.2
              
              
              
              2.3
              
              
              
              0.2
              
              
              
              28.6Operating
      income
              
              $
              33.2
              
              
              $
              31.8
              
              
              $
              14.7
              
              
              $
              217.8
              
              
              $
              297.5Capital
      Expenditures
              
              $
              10.0
              
              
              $
              4.5
              
              
              $
              —
              
              
              $
              0.3
              
              
              $
              14.8Segment
      Assets
              
              $
              921.1
              
              
              $
              634.5
              
              
              $
              149.4
              
              
              $
              168.1
              
              
              $
              1,873.1
 
 Midstream
      Segments
                Three
      Months Ended September 30, 2007
              
              Texas
                  Panhandle
                  Segment
              
              
              South
                  Texas
                  Segment
              
              
              East Texas /
                  Louisiana
                  Segment
              
              
              Total
                  Midstream
                  Segments($
      in millions)Sales
      to external customers
              
              $
              130.2
              
              
              $
              64.3
              
              
              $
              48.6
              
              
              $
              243.1Cost
      of natural gas and natural gas liquids
              
              
              96.9
              
              
              
              61.6
              
              
              
              38.4
              
              
              
              196.9Operating
      costs and other expenses
              
              
              9.6
              
              
              
              0.4
              
              
              
              3.6
              
              
              
              13.6Depreciation,
      depletion, and amortization
              
              
              10.4
              
              
              
              0.9
              
              
              
              3.3
              
              
              
              14.6Operating
      income
              
              $
              13.3
              
              
              $
              1.4
              
              
              $
              3.3
              
              
              $
              18.0Capital
      Expenditures
              
              $
              7.2
              
              
              $
              0.8
              
              
              $
              5.7
              
              
              $
              13.7Segment
      Assets
              
              $
              584.0
              
              
              $
              62.3
              
              
              $
              290.6
              
              
              $
              936.9
  Three
      Months Ended September 30, 2007
              
              Total
                  Midstream
                  Segments
              
              
              Upstream
                  Segment
              
              
              Minerals
                  Segment
              
              
              Corporate
                  Segment
              
              
              Total
                  Segments($
      in millions)Sales
      to external customers
              
              $
              243.1
              
              
              $
              19.1
              
              
              $
              6.0
              
              
              $
              8.7
              (a)
              
              $
              276.9Cost
      of natural gas and natural gas liquids
              
              
              196.9
              
              
              
              —
              
              
              
              —
              
              
              
              —
              
              
              
              196.9Operating
      costs and other expenses
              
              
              13.6
              
              
              
              5.8
              
              
              
              0.2
              
              
              
              7.4
              
              
              
              27.0Depreciation,
      depletion, and amortization
              
              
              14.6
              
              
              
              6.9
              
              
              
              3.4
              
              
              
              0.2
              
              
              
              25.1Operating
      income (loss)
              
              $
              18.0
              
              
              $
              6.4
              
              
              $
              2.4
              
              
              $
              1.1
              
              
              $
              27.9Capital
      Expenditures
              
              $
              13.7
              
              
              $
              —
              
              
              $
              —
              
              
              $
              —
              
              
              $
              13.7Segment
      Assets
              
              $
              936.9
              
              
              $
              470.9
              
              
              $
              160.8
              
              
              $
              94.2
              
              
              $
              1,662.8
 ________________________________________
 (a)  Represents
      results of the Partnership’s commodity derivative
    activities.
  18
  
 Midstream
      Segments
                Nine
      months Ended September 30, 2008
              
              Texas
                  Panhandle
                  Segment
              
              
              South
                  Texas
                  Segment
              
              
              East Texas /
                  Louisiana
                  Segment
              
              
              Total
                  Midstream
                  Segments($
      in millions)Sales
      to external customers
              
              $
              522.1
              
              
              $
              346.9
              
              
              $
              249.1
              
              
              $
              1,118.1Cost
      of natural gas and natural gas liquids
              
              
              398.9
              
              
              
              337.4
              
              
              
              209.9
              
              
              
              946.2Operating
      costs and other expenses
              
              
              25.6
              
              
              
              1.8
              
              
              
              11.6
              
              
              
              39.0Depreciation,
      depletion, and amortization
              
              
              32.6
              
              
              
              2.8
              
              
              
              8.8
              
              
              
              44.2Operating
      income
              
              $
              65.0
              
              
              $
              4.9
              
              
              $
              18.8
              
              
              $
              88.7Capital
      Expenditures
              
              $
              20.6
              
              
              $
              0.8
              
              
              $
              8.7
              
              
              $
              30.1Segment
      Assets
              
              $
              580.6
              
              
              $
              89.6
              
              
              $
              250.9
              
              
              $
              921.1
 
 Nine
      months Ended September 30, 2008
              
              Total
                  Midstream
                  Segments
              
              
              Upstream
                  Segment
              
              
              Minerals
                  Segment
              
              
              Corporate
                  Segment
              
              
              Total
                  Segments($
      in millions)Sales
      to external customers
              
              $
              1,118.1
              
              
              $
              140.4
              
              
              $
              34.6
              
              
              $
              (97.8
              )(a)
              
              $
              1,195.3Cost
      of natural gas and natural gas liquids
              
              
              946.2
              
              
              
              —
              
              
              
              —
              
              
              
              —
              
              
              
              946.2Operating
      costs and other expenses
              
              
              39.0
              
              
              
              29.4
              
              
              
              1.4
              
              
              
              41.3
              
              
              
              111.1Depreciation,
      depletion, and amortization
              
              
              44.2
              
              
              
              29.5
              
              
              
              6.4
              
              
              
              0.6
              
              
              
              80.7Operating
      income (loss)
              
              $
              88.7
              
              
              $
              81.5
              
              
              
              26.8
              
              
              $
              (139.7
              )
              
              $
              57.3Capital
      Expenditures
              
              $
              30.1
              
              
              $
              17.7
              
              
              $
              —
              
              
              $
              0.5
              
              
              $
              48.3Segment
      Assets
              
              $
              921.1
              
              
              $
              634.5
              
              
              $
              149.4
              
              
              $
              168.1
              
              
              $
              1,873.1
  Midstream
      Segments
                Nine
      months Ended September 30, 2007
              
              Texas
                  Panhandle
                  Segment
              
              
              South
                  Texas
                  Segment
              
              
              East Texas /
                  Louisiana
                  Segment
              
              
              Total
                  Midstream
                  Segments($
      in millions)Sales
      to external customers
              
              $
              335.2
              
              
              $
              115.1
              
              
              $
              105.7
              
              
              $
              556.0Cost
      of natural gas and natural gas liquids
              
              
              258.5
              
              
              
              110.8
              
              
              
              82.5
              
              
              
              451.8Operating
      costs and other expenses
              
              
              25.6
              
              
              
              0.7
              
              
              
              7.8
              
              
              
              34.1Depreciation,
      depletion, and amortization
              
              
              30.2
              
              
              
              1.3
              
              
              
              7.2
              
              
              
              38.7Operating
      income
              
              $
              20.9
              
              
              $
              2.3
              
              
              $
              8.2
              
              
              $
              31.4Capital
      Expenditures
              
              $
              29.7
              
              
              $
              2.1
              
              
              $
              24.1
              
              
              $
              55.9Segment
      Assets
              
              $
              584.0
              
              
              $
              62.3
              
              
              $
              290.6
              
              
              $
              936.9
  Nine
      months Ended September 30, 2007
              
              Total
                  Midstream
                  Segments
              
              
              Upstream
                  Segment
              
              
              Minerals
                  Segment
              
              
              Corporate
                  Segment
              
              
              Total
                  Segments($
      in millions)Sales
      to external customers
              
              $
              556.0
              
              
              $
              19.1
              
              
              $
              9.2
              
              
              $
              (26.2
              )(a)
              
              $
              558.1Cost
      of natural gas and natural gas liquids
              
              
              451.8
              
              
              
              —
              
              
              
              —
              
              
              
              —
              
              
              
              451.8Operating
      costs and other expenses
              
              
              34.1
              
              
              
              5.8
              
              
              
              0.5
              
              
              
              18.5
              
              
              
              58.9Depreciation,
      depletion, and amortization
              
              
              38.7
              
              
              
              6.9
              
              
              
              4.8
              
              
              
              0.6
              
              
              
              51.0Operating
      income (loss)
              
              $
              31.4
              
              
              $
              6.4
              
              
              $
              3.9
              
              
              $
              (45.3
              )
              
              $
              (3.6
              )Capital
      Expenditures
              
              $
              55.9
              
              
              $
              —
              
              
              $
              —
              
              
              $
              0.5
              
              
              $
              56.4Segment
      Assets
              
              $
              936.9
              
              
              $
              470.9
              
              
              $
              160.8
              
              
              $
              94.2
              
              
              $
              1,662.8
 _______________________________________
 (a)
              Represents
      results of the Partnership’s commodity derivative
    activities.
  19
  NOTE
14.  INCOME TAXES
  Provision for Income Taxes –The Partnership’s provision for income taxes relates to (i) state taxes
for the Partnership and (ii) federal taxes for Eagle Rock Energy Acquisition
Co., Inc. (acquiring entity of certain entities acquired in the Redman
acquisition) and Eagle Rock Energy Acquisition Co. II, Inc. (acquiring
entity of certain entities acquired in the Stanolind acquisition) and
their wholly-owned corporations, Eagle Rock Upstream Development Company, Inc.
(successor entity to certain entities acquired in the Redman
acquisition) and Eagle Rock Upstream Development Company II, Inc.
(successor entity to certain entities acquired in the Stanolind acquisition),
which are subject to federal income taxes (the “C Corporations”).
  As a
result of the taxable income from the underlying partnerships owned by the C
Corporations described above, net operating losses of $0.2 million and $0.6
million were used during the three and nine months ended September 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 effective rate for the
three and nine month periods ended September 30, 2008 was (0.2%) and (4.7%),
respectively compared to 100% and 100% for the same periods in
2007.  The changes in effective tax rates are attributable to the
provision amounts for the total of state and federal taxes being applied against
book income for the three months and nine month periods of 2008 whereas they
were applied against book losses for the same period in 2007 which resulted in a
100% effective tax rate for those periods.
  Deferred taxes-As of September 30, 2008,
the net deferred tax liability was $42.5 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 Company II, Inc. our wholly-owned
corporations which are subject to federal income taxes.  Eagle Rock
Upstream Development Company 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 and Redman acquisitions.
  Accounting for Uncertainty in Income
Taxes-In
accordance with FASB Interpretation No. 48, Accounting for Uncertainty in Income
Taxes, the Partnership must recognize the tax effects of any uncertain
tax positions it may adopt, if the position taken by the Partnership is more
likely than not sustainable.  If a tax position meets such criteria,
the tax effect to be recognized by the Partnership would be the largest amount
of benefit with more than a 50% chance of being realized upon
settlement.  This guidance was effective January 1, 2007, and the
Partnership’s adoption of this guidance had and continues to have no material
impact on its financial position, results of operations or cash
flows.
  Texas Franchise Tax -On
May 18, 2006, the State of Texas enacted revisions to the pre-existing
state franchise tax. In general, legal entities that conduct business in Texas
are subject to the Revised Texas Franchise Tax, including previously non-taxable
entities such as limited partnerships and limited liability corporations. The
tax is assessed on Texas sourced taxable margin which is defined as the lesser
of (i) 70% of total revenue or (ii) total revenue less (a) cost
of goods sold or (b) compensation and benefits.
  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
  Eagle
Rock Energy G&P, LLC, the general partner of the general partner for Eagle
Rock Energy Partners, L.P., approved a long-term incentive plan (“LTIP”), as
amended, for its employees, directors and consultants who provide services to
the Partnership and its subsidiaries and affiliates covering an aggregate of
2,000,000 common units to be granted either as options, restricted units or
phantom units.   The Partnership has historically only issued
restricted units under the LTIP.  As to outstanding restricted units,
distributions associated with the restricted units will be distributed directly
to the awardees. No options or phantom units have been issued to
date.
   
   
   20
  A summary of
the restricted common units’ activity for the nine months ended September 30,
2008, is provided below:
  
 Number of
                  Restricted
                  Units
              
              
              Weighted
                  Average
                  Fair Value
      per UnitOutstanding
      at December 31, 2007
              
              
              467,062
              
              
              $
              23.01Granted
              
              
              538,450
              
              
              $
              16.54Vested
              
              
              (124,384
              )
              
              $
              23.27Forfeitures
              
              
              (132,662
              )
              
              $
              18.90Outstanding
      at September 30, 2008
              
              
              748,466
              
              
              $
              19.04
  The total
grant date fair value of restricted units that vested during the nine months
ended September 30, 2008 was $2.9 million.
  For the
three and nine months ended September 30, 2008 and September 30, 2007, non-cash
compensation expense of approximately $1.4 million, $4.1 million, $0.8 million
and $1.6 million respectively, was recorded related to the granted restricted
units.
  As of
September 30, 2008, unrecognized compensation costs related to the outstanding
restricted units under our LTIP totaled approximately $13.3 million. The
remaining expense is to be recognized over a weighted average of 2.1
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), in
accordance with the amount of distributions made for the quarter by each
class, if any. The remaining net income (loss) is allocated to each class
in proportion to the class’ 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
   The
following table presents our calculation of basic and diluted earnings per unit
for the periods indicated:
  
 Three
      Months Ended
                September
      30,
              
              
              Nine
      Months Ended
                  September
      30,2008
              
              
              2007
              
              
              2008
              
              
              2007(in
      thousands, except for per unit amounts)Net
      income (loss)
              
              $
              288,071
              
              
              $
              9,371
              
              
              $
              32,723
              
              
              $
              (34,080
              )Less:
      Incentive Distribution Rights
              
              
              (121,090
              )
              
              
              —
              
              
              
              —
              
              
              
              —Net
      income (loss) to be allocated
              
              $
              166,981
              
              
              $
              9,371
              
              
              $
              32,723
              
              
              $
              (34,080
              )Net
      loss allocated to:Common
      units
              
              $
              117,284
              
              
              $
              6,372
              
              
              $
              22,976
              
              
              $
              (20,448
              )Subordinated
      units
              
              $
              47,749
              
              
              $
              2,905
              
              
              $
              9,365
              
              
              $
              (12,950
              )General
      partner units
              
              $
              1,948
              
              
              $
              94
              
              
              $
              382
              
              
              $
              (682
              )Basic
      weighted average unit outstanding during period:Common
      units
              
              
              50,824
              
              
              
              45,954
              
              
              
              50,762
              
              
              
              32,512Subordinated
      units
              
              
              20,691
              
              
              
              20,691
              
              
              
              20,691
              
              
              
              20,691General
      partner units
              
              
              845
              
              
              
              845
              
              
              
              845
              
              
              
              845Basic Earnings Per
      Unit:Common
      units
              
              $
              2.31
              
              
              $
              0.25
              
              
              $
              0.45
              
              
              $
              (0.24
              )Subordinated
      units
              
              $
              2.31
              
              
              $
              (0.09
              )
              
              $
              0.45
              
              
              $
              (1.22
              )General
      partner units
              
              $
              2.31
              
              
              $
              (0.09
              )
              
              $
              0.45
              
              
              $
              (1.22
              )Diluted
      weighted average unit outstanding during period:Common
      units
              
              
              50,868
              
              
              
              46,021
              
              
              
              50,900
              
              
              
              32,539Subordinated
      units
              
              
              20,691
              
              
              
              20,691
              
              
              
              20,691
              
              
              
              20,691General
      partner units
              
              
              845
              
              
              
              845
              
              
              
              845
              
              
              
              845Diluted Earnings Per
      Unit:Common
      units
              
              $
              2.31
              
              
              $
              0.25
              
              
              $
              0.45
              
              
              $
              (0.24
              )Subordinated
      units
              
              $
              2.31
              
              
              $
              (0.09
              )
              
              $
              0.45
              
              
              $
              (1.22
              )General
      partner units
              
              $
              2.31
              
              
              $
              (0.09
              )
              
              $
              0.45
              
              
              $
              (1.22
              )
   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, through certain subsidiaries, 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 filing, the Partnership recorded a $6.2 million bad debt charge in
the second quarter of 2008, and the Partnership recorded an additional $3.9
million as a bad debt charge during the three months ended September 30,
2008.  The bad debt charges are included in “Other Operating Expense”
in the consolidated statement of operations.  The Partnership stopped
all sales to SemGroup as of August 1, 2008, and as a result, the Partnership
does not anticipate recording any additional bad debt charges in future
periods.  Other operating expenses for the nine months ended September
30, 2008 consisted of the aggregate $10.1 million bad debt charge for the
Partnership’s aggregate outstanding SemGroup receivable, whereas the other
operating expenses for the nine months ended September 30, 2007 consisted of an
arbitration settlement of $1.4 million, a severance payout to a former executive
of $0.3 million and liquidated damages related to the late registration of the
Partnership’s common units for $0.2 million.
  
  22
  NOTE
18. HURRICANES IKE AND GUSTAV
  Hurricane
Ike, which made landfall in Texas on September 13, 2008, caused no material
damage to the Partnership’s offices, facilities or assets; however, the
storm did cause temporary operational disruption to the Partnership's operations
located in East Texas, North Louisiana and South Texas due to third party
downstream infrastructure issues. Operations were either temporarily interrupted
or curtailed during and immediately after the storm due to power disruptions
suffered by third parties causing natural gas and natural gas liquids supply and
market issues. All of the Partnership’s operations returned to pre-hurricane
levels within ten days after the storm.  The Partnership’s assets were
not impacted by Hurricane Gustav.
  NOTE
19. SUBSEQUENT EVENTS
  On October 1,
2008, the Partnership completed the acquisition of 100% of the outstanding units
of Millennium Midstream Partners, L.P. (“MMP”) for an aggregate purchase price
of $225.9 million, comprised of approximately, $181.5 million in cash and
4,000,000 (recorded value of $44.4 million) common units, subject to post
closing purchase price adjustments.  The cash portion of the
consideration was funded through borrowings of $176.4 million under the
Partnership’s Revolving Credit Facility made prior to September 30, 2008 and
cash on hand.  MMP is in the natural gas gathering and processing
business, with assets located in East, Central and West Texas and South
Louisiana.  With respect to the South Louisiana assets acquired in the
Millennium acquisition, the Yscloskey and North Terrebonne facilities were
flooded with three to four feet of water as a result of the storm surges caused
by Hurricanes Ike and/or Gustav.  The Partnership has filed claims
for, and expects to receive payment on its business interruption insurance
coverage related to Hurricane Ike and Gustav’s damage to these two facilities.
The timing of collection of such insurance claims is unknown at this
time.  The expected timing for the facilities to be brought back on
line is currently late November 2008.  The former owners of MMP provided
the Partnership idemnity coverage for Hurricanes Ike and Gustav to the extent
losses are no covered by insurance, and there is an escrow of 2,036,364 common
units and $0.6 million in cash available for the Partnership to recover against
for this purpose.
  On October
31, 2008, the Partnership reset two existing crude oil swap transactions. The
first swap was reset from $73.90 to $100 per barrel on 80,000 barrels per month
for months of November and December, 2008. The second swap was reset from $80.25
to $100 per barrel on 50,000 barrels per month for calendar year 2009. The total
cost of these reset swaps was $15.9 million.  The strike prices of
these swaps were reset to stabilize overall cash flows for the months of
November and December, 2008 and all of 2009 and to provide further assurance of
the Partnership’s ability to maintain its current rate of distribution in the
face of declining commodity prices and industry activity.
  
  23
   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 and transporting of
      natural gas; fractionating and transporting of natural gas liquids
      (“NGLs”); and the marketing of natural gas, condensate and
      NGLs;
  •
              Upstream
      Business—acquiring, developing and producing oil and natural gas property
      interests; and
  •
              Minerals
      Business—acquiring and managing fee mineral and royalty interests, either
      through direct ownership or through investment in other
      partnerships.
  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 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, Shelby, Panola, Ward, Crane,
Pecos and Atascosa Counties, Texas.
 
 We
conduct, evaluate, and report our Minerals Business as one segment.  Our
Minerals Segment consists of fee mineral, royalty and overriding royalty
interests located in multiple producing trends in the United States.  A
significant portion of the mineral interests that we own are managed by a
non-affiliated private partnership (the “Minerals Manager”) that controls the
executive rights associated with the minerals.  We acquired our interest in
these minerals by participating as a co-investor when the Minerals Manager
acquired its interest.  As part of that transaction, we also owned a
minority interest in a partnership (“Ivory Acquisition Partners”) that owned an
interest in the same minerals that we purchased and hold directly.  Ivory
Acquisition Partners is controlled by the Minerals Manager, and it was specified
at the time of the acquisition of these minerals that our interest in Ivory
Acquisition Partners would revert to the Minerals Manager if certain payout
hurdles were reached.  The hurdles have been reached and we no longer have
an interest in Ivory Acquisition Partners.  The impact of this reversion on
the financial statements is discussed under “Corporate Segment – Other Income
and Expenses.”
 
 We also
own a minority interest in another non-affiliated partnership (“Ivory Working
Interest Partners”) that is controlled by the Minerals Manager.  Ivory
Working Interest Partners owns non-operating working interests in certain
wells that are drilled on those minerals that are managed by the Minerals
Manager.  Ivory Working Interest Partners owns these non-operated working
interests by virtue of the terms of certain leases negotiated by the Minerals
Manager.  We believe that Ivory Working Interest Partners will continue to
participate in the drilling of new wells as a non-operating working interest
owner.  In general, Ivory Working Interest Partners attempts to fund its
activities from its internal cash flow; however, it has the right to retain cash
derived from the payment of royalties, bonus and delay rentals related to the
mineral interests that it manages to fund its activities of Ivory Working
Interest Partners, to the extent necessary and approved by the
partners.
  Our final
reporting segment is our Corporate Segment, in which we account for
our commodity hedging activity and our general corporate costs.
 24
 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.
  Hurricanes
Ike and Gustav
  Hurricane
Ike, which made landfall in Texas on September 13, 2008, caused no material
damage to our offices, facilities or assets; however, the storm did cause
temporary operational disruption to our operations located in East Texas, North
Louisiana and South Texas due to third party downstream infrastructure issues.
Operations were either temporarily interrupted or curtailed during and
immediately after the storm due to power disruptions suffered by third parties
causing natural gas and natural gas liquids supply and market issues. All of our
operations returned to pre-hurricane levels within ten days after the
storm.  Our assets were not impacted by Hurricane Gustav.
  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”).  One or more Natural Gas Partners private
equity funds owned a majority of the equity interests in
Stanolind.   We funded the transaction from existing cash
from operations, as well as with borrowings under our existing secured
revolving credit facility.  Stanolind operated 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.
  Montierra Acquisition -On
April 30, 2007, we completed the acquisition (by direct acquisition or
acquisition of certain entities) of certain fee minerals, royalties, working
interest properties and certain investments in partnerships 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 Co., 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.
  Recent
Acquisition
  On
October 1, 2008, we completed the acquisition of 100% of the outstanding units
of Millennium Midstream Partners, L.P. (“MMP”), and thereby acquired control of
its operating subsidiaries, for an aggregate purchase price of $225.9
million, comprised of approximately, $181.5 million in cash and 4,000,000
(recorded value of $44.4 million) common units, subject to post-closing purchase
price adjustments.  The cash portion of the consideration was funded
through borrowings of $176.4 million
  25
  under our
secured revolving credit facility made prior to September 30, 2008 and cash on
hand.  MMP is in the natural gas gathering and processing business,
with assets located in East, Central and West Texas and South
Louisiana.  With respect to the South Louisiana assets acquired in the
Millennium acquisition, the Yscloskey and North Terrebonne facilities were
flooded with three to four feet of water as a result of the storm surges caused
by Hurricanes Ike and/or Gustav..  We have filed claims for, and
expect to receive payment on our business interruption insurance coverage
related to Hurricane Ike and Gustav's damage to these two facilities. The timing
of collection of such insurance claims is unknown at this time.  The
expected timing for the facilities to be brought back on line is currently late
November 2008.  The former owners of MMP provided us idemnity coverage for
Hurricane Ike and Gustav, to the extent losses are not covered by insurance, and
there is an escrow of 2,036,364 common units and $0.6 million of cash available
for us to recover against for this purpose.
  Recent
Transactions
  On October
31, 2008, we reset two existing crude oil swap transactions. The first swap was
reset from $73.90 to $100 per barrel on 80,000 barrels per month for the months
of November and December,  2008. The second swap was reset from $80.25 to
$100 per barrel on 50,000 barrels per month for calendar year 2009. The total
cost of these reset swaps was $15.9 million.  The strike prices of
these swaps were reset to stabilize overall cash flows for the balance the
months of November and December,  2008 and all of 2009 and to provide
further assurance of our ability to maintain our current rate of distribution in
the face of declining commodity prices and industry activity.
  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 and operating
expenses on a segment basis 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. More
significantly, recent events impacting the world’s economy and financial
systems, including but not limited to, a generalized stagnation in the world’s
banking system and access to credit markets, precipitous drops in the value of
almost all asset classes including equity, bonds, real estate, and other
investment vehicles, significant drops in commodity prices including the prices
for crude oil, natural gas, NGL's, condensate and sulfur, among others, as
well as the generalized expectation of a prolonged period of recession, will
play an important role in the performance and growth perspectives for our
business. 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.
   26
  Summary
of Consolidated Operating Results
  Below is a
summary table of our consolidated operating results for the three and nine
months ended September 30, 2008 and September 30, 2007,
respectively.  Operating results for our individual operating segments
are presented in tables in this Item 2.
  Three
      Months Ended
                  September
      30,
              
              
              Nine
      Months Ended
                  September
      30,2008
              
              
              2007
              
              
              2008
              
              
              2007($
      in thousands)Revenue:Natural
      gas, natural gas liquids, oil, condensate and sulfur sales
              
              $
              421,346
              
              
              $
              254,084
              
              
              $
              1,230,134
              
              
              $
              555,826Gathering
      compression, processing and treating fees
              
              
              12,513
              
              
              
              8,103
              
              
              
              27,741
              
              
              
              19,269Minerals
      and royalty income
              
              
              17,393
              
              
              
              6,009
              
              
              
              34,606
              
              
              
              9,201Realized
      commodity derivative gains (losses)
              
              
              (24,105
              )
              
              
              (177
              )
              
              
              (64,388
              )
              
              
              4,324Unrealized
      commodity derivative gains (losses) ...
              
              
              255,956
              
              
              
              8,865
              
              
              
              (33,381
              )
              
              
              (30,533
              )Other
              
              
              428
              
              
              
              (20
              )
              
              
              610
              
              
              
              (20
              )Total
      revenue
              
              
              683,531
              
              
              
              276,864
              
              
              
              1,195,322
              
              
              
              558,067Cost
      of natural gas and natural gas liquids
              
              
              316,788
              
              
              
              196,839
              
              
              
              946,177
              
              
              
              451,840Expenses:Operating
      and maintenance
              
              
              21,475
              
              
              
              16,883
              
              
              
              54,772
              
              
              
              36,015Taxes
      other than income
              
              
              5,365
              
              
              
              2,746
              
              
              
              14,975
              
              
              
              4,364General
      and administrative
              
              
              9,893
              
              
              
              7,196
              
              
              
              31,161
              
              
              
              16,587Other
      operating expense
              
              
              3,920
              
              
              
              220
              
              
              
              10,134
              
              
              
              1,931Depreciation,
      depletion, and amortization
              
              
              28,597
              
              
              
              25,105
              
              
              
              80,799
              
              
              
              50,883Total
      costs and expenses
              
              
              386,038
              
              
              
              248,989
              
              
              
              1,138,018
              
              
              
              561,620Operating
      income (loss)
              
              
              297,493
              
              
              
              27,875
              
              
              
              57,304
              
              
              
              (3,553
              )Other
      income (expense):Interest
      income
              
              
              212
              
              
              
              231
              
              
              
              673
              
              
              
              530Other
      income
              
              
              434
              
              
              
              767
              
              
              
              2,867
              
              
              
              879Interest
      expense, net
              
              
              (7,498
              )
              
              
              (10,633
              )
              
              
              (23,576
              )
              
              
              (27,031
              )Unrealized
      interest rate derivatives losses
              
              
              (501
              )
              
              
              (8,429
              )
              
              
              (472
              )
              
              
              (3,555
              )Realized
      interest rate derivative gains (losses)...
              
              
              (2,358
              )
              
              
              327
              
              
              
              (4,903
              )
              
              
              967Other
      expense
              
              
              (205
              )
              
              
              (415
              )
              
              
              (652
              )
              
              
              (1,545
              )Total
      other expense
              
              
              (9,916
              )
              
              
              (18,152
              )
              
              
              (26,063
              )
              
              
              (29,755
              )Income
      (loss) before taxes
              
              
              287,577
              
              
              
              9,723
              
              
              
              31,241
              
              
              
              (33,308
              )Income
      tax (benefit) provision
              
              
              (494
              )
              
              
              352
              
              
              
              (1,482
              )
              
              
              772Net
      income/(loss)
              
              $
              288,071
              
              
              $
              9,371
              
              
              $
              32,723
              
              
              $
              (34,080
              )Adjusted
      EBITDA(a)
              
              $
              75,481
              
              
              $
              45,155
              
              
              $
              185,765
              
              
              $
              81,407
 
 (a)
              See
      "Non-GAAP Financial Measures" and Reconciliation of 'Adjusted EBITDA' to
      net cash flows provided by operating activities and net income
      (loss)" within Item 2. Management’s Discussion and Analysis of
      Financial Condition and Results of Operations for a definition and
      reconciliation to GAAP.
  For the
three months ended September 30, 2008, based on operating income of our
non-Corporate segments, our midstream business comprised approximately 41.6% of
our business (with the Texas Panhandle Segment accounting for 29.7% of our
business, the South Texas Segment accounting for 2.4% of our business, and the
East Texas/Louisiana Segment accounting for 9.5% of our business), our upstream
business comprised approximately 40.0% of our business, and our minerals
business comprised approximately 18.4% of our business. For the nine months
ended September 30, 2008, based on operating income of our non-Corporate
segments, our midstream business comprised approximately 45.0% of our business
(with the Texas Panhandle Segment accounting for 33.0% 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 41.4% of our business, and our minerals
business comprised approximately 13.6% 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.
  27
  Midstream
Business (Three Segments)
  Texas Panhandle
Segment
  Three
      Months Ended
                September
      30,
              
              
              Nine
      Months Ended
                September
      30,2008
              
              
              2007
              
              
              2008
              
              
              2007($
      in thousands, except for price data)Revenue:Sales
      of natural gas, NGLs, oil and condensate
              
              $
              179,608
              
              
              $
              128,008
              
              
              $
              514,450
              
              
              $
              328,672Gathering
      and treating services
              
              
              2,671
              
              
              
              2,234
              
              
              
              7,664
              
              
              
              6,536Other
              
              
              —
              
              
              
              (20
              )
              
              
              —
              
              
              
              (20
              )Total
      revenue
              
              
              182,279
              
              
              
              130,222
              
              
              
              522,114
              
              
              
              335,188Cost
      of natural gas and natural gas liquids
              
              
              138,428
              
              
              
              96,872
              
              
              
              398,828
              
              
              
              258,577Operating
      costs and expenses:Operating
              
              
              9,190
              
              
              
              9,603
              
              
              
              25,653
              
              
              
              25,608Depreciation
      and amortization
              
              
              10,984
              
              
              
              10,466
              
              
              
              32,587
              
              
              
              30,231Total
      operating costs and expenses
              
              
              20,174
              
              
              
              20,069
              
              
              
              58,240
              
              
              
              55,839Operating
      income
              
              $
              23,677
              
              
              $
              13,281
              
              
              $
              65,046
              
              
              $
              20,772Capital
      Expenditures
              
              $
              7,152
              
              
              $
              7,158
              
              
              $
              20,607
              
              
              $
              29,731Realized
      average prices:Oil
      and condensate (per Bbl)
              
              $
              106.43
              
              
              $
              63.41
              
              
              $
              105.03
              
              
              $
              54.62Natural
      gas (per Mcf)
              
              $
              8.81
              
              
              $
              5.45
              
              
              $
              8.85
              
              
              $
              6.02NGLs
      (per Bbl)
              
              $
              66.36
              
              
              $
              53.34
              
              
              $
              67.62
              
              
              $
              48.72Production
      volumes:Gathering
      volumes (Mcf/d)(a)
              
              
              159,254
              
              
              
              164,544
              
              
              
              154,190
              
              
              
              147,523NGLs
      and condensate (net equity gallons)
              
              
              22,752,290
              
              
              
              23,644,648
              
              
              
              64,287,333
              
              
              
              65,278,803Natural
      gas short position (MMbtu/d)(a)
              
              
              (4,150
              )
              
              
              (6,330
              )
              
              
              (5,458
              )
              
              
              (7,389
              )
  __________________
  (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 nine months ended September 30,
2008, the revenues minus cost of natural gas and natural gas liquids for our
Texas Panhandle Segment operations totaled $43.9 million and $123.3 million
compared to $33.4 and $76.6 million for the three and nine months ended
September 30, 2007. There were two primary contributors to this increase:
(i) higher NGL and condensate pricing, as compared to pricing in 2007, and
(ii) a lower natural gas short position as compared to 2007.
  The
higher 2008 gathering volumes during the nine month period compared to 2007 was
primarily due to a full nine months of Red Deer Plant operations in 2008
compared to only three months in 2007 and the colder than normal weather in that
area along with the downtime to repair the Arrington plant during 2007, which
reduced gathering volumes during the three and nine months ended September 30,
2007.  The lower gathering volumes during the three months ended
September 30, 2008 compared to the same period in 2007 are primarily due to the
continued decline of volumes on the West Panhandle system and reduced drilling
activity during the first nine months of 2008 that was not sufficient to replace
the West Panhandle System decline and the natural decline in the East Panhandle
System.
  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 drilling activity in the
  28
  active
Granite Wash drilling play located in Roberts and Hemphill Counties, Texas. The
liquids content of the natural gas is lower in the East 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 nine months ended September 30, 2008 as compared to
the nine months ended September 30, 2007, our equity share of liquids production
would have been less through the nine months ended September 30, 2008 as
compared to the nine months ended September 30, 2007. 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 nine
months ended September 30, 2008 to handle additional volumes of 3 MMcf/d,
bringing total capacity to 23 MMcf/d.  We completed the consolidation
of the Stinnett Plant to the Cargray Plant during the three months ending
September 30, 2008, and we are in the process of relocating the cryogenic
Stinnett Plant to replace the older technology Arringtion Plant which will
result in additional processing capacity on the East Panhandle System and better
NGL recovery from the processed natural gas.
  Operating Expenses.Operating
expenses, including taxes other than income, for three and nine months ended
September 30, 2008 were $9.2 million and $25.7 million compared to $9.6 million
and $25.6 million for the three and nine months ended September 30,
2007.  The three and nine months ended September 30, 2007 included
additional maintenance costs for repairing the Arrington plant. The major items
impacting the $0.1 million increase in operating expense for the nine months
ended September 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 nine months ended
September 30, 2008 were $11.0 million and $32.6 million compared to $10.5
million and $30.2 million for the three and nine months ended September 30,
2007. The major items impacting the $0.5 million and $2.4 million increases was
placing the Red Deer Plant into service and beginning the depreciation expense
associated with the other capital expenditure projects put into
service.
  Capital Expenditures.Capital
expenditures for the three and nine months ended September 30, 2008 were $7.2
million and $20.6 million as compared to $7.2 million and $29.7 million for the
three and nine months ended September 30, 2007.   During the nine
months ended September 30, 2008, of our capital spending in this segment, we
spent $14.2 million on growth capital and $6.4 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 of $9.1 million in capital spending for the nine month period of 2008
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.
   29
  East Texas/Louisiana
Segment
  Three
      Months Ended
                  September
      30,
              
              
              Nine
      Months Ended
                  September
      30,2008
              
              
              2007(b)
              
              
              2008
              
              
              2007(b)($ in thousands, except for
      price data)Revenue:Sales
      of natural gas, NGLs, oil and condensate
              
              $
              71,861
              
              
              $
              44,215
              
              
              $
              231,996
              
              
              $
              95,409Gathering
      and treating services
              
              
              8,908
              
              
              
              4,352
              
              
              
              17,056
              
              
              
              10,284Total
      revenue
              
              
              80,769
              
              
              
              48,567
              
              
              
              249,052
              
              
              
              105,693Cost
      of natural gas and natural gas liquids
              
              
              66,007
              
              
              
              38,397
              
              
              
              209,937
              
              
              
              82,491Operating
      costs and expenses:Operating
              
              
              4,194
              
              
              
              3,619
              
              
              
              11,511
              
              
              
              7,778Depreciation
      and amortization
              
              
              2,989
              
              
              
              3,281
              
              
              
              8,846
              
              
              
              7,213Total
      operating costs and expenses
              
              
              7,183
              
              
              
              6,900
              
              
              
              20,357
              
              
              
              14,991Operating
      income
              
              $
              7,579
              
              
              $
              3,270
              
              
              $
              18,758
              
              
              $
              8,211Capital
      Expenditures
              
              $
              2,591
              
              
              $
              5,696
              
              
              $
              8,686
              
              
              $
              24,056Realized
      average prices:Oil
      and condensate (per Bbl)
              
              $
              125.29
              
              
              $
              75.48
              
              
              $
              117.16
              
              
              $
              66.46Natural
      gas (per Mcf)
              
              $
              9.69
              
              
              $
              5.86
              
              
              $
              10.37
              
              
              $
              6.39NGLs
      (per Bbl)
              
              $
              57.54
              
              
              $
              44.52
              
              
              $
              56.28
              
              
              $
              41.58Production
      volumes:Gathering
      volumes (Mcf/d) (a)
              
              
              173,728
              
              
              
              155,540
              
              
              
              172,434
              
              
              
              125,590NGLs
      and condensate (net equity gallons)
              
              
              6,768,037
              
              
              
              4,742,723
              
              
              
              18,696,086
              
              
              
              12,573,603Natural
      gas short position (MMbtu/d) (a)
              
              
              747
              
              
              
              1,116
              
              
              
              885
              
              
              
              1,485
 _____________
  (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 nine months ended September 30,
2008, revenues minus cost of natural gas and natural gas liquids for our East
Texas/Louisiana Segment totaled $14.7 million and $39.1 million, respectively,
compared to $10.2 million and $23.2 million, respectively, for the three and
nine months ended September 30, 2007.
  We were
positively impacted from higher NGL and condensate pricing during the three and
nine months ended September 30, 2008 as compared to the three and nine months
ended September 30, 2007. We were also positively impacted by an 11.7% growth in
daily gathering volumes during the three months ended September 30, 2008, and a
37.3% growth in daily gathering volumes during the nine months ended September
30, 2008, compared to the comparable period in 2007. Increased volumes were due
to both a full nine months of the Laser Acquisition during 2008 compared to only
a five-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 31% during the three months ended September
30, 2008 compared to the comparable time period in 2007. 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 in the future.
   30
   The Laser
Acquisition positively impacted the East Texas/Louisiana Segment by $4.5 million
and $12.0 million during the three and nine months ended September 30, 2008,
respectively, compared to $3.1 million and $5.3 million during the same time
periods in the prior year.  The Laser Acquisition’s daily gathering
volumes for the three months ended September 30, 2008 compared to the three
months ended September 30, 2007, the time period covering ownership of the Laser
Acquisition, are down due to reduced drilling activity around the Belle Bower
system.
  Operating Expenses.Operating
expenses for the three and nine months ended September 30, 2008 were $4.2
million and $11.5 million, respectively, compared to $3.6 million and $7.8
million for the three and nine months ended September 30, 2007, respectively.
The major items impacting the $0.6 million and $3.7 million increases in
operating expense for the three and nine months ended September 30, 2008 were
(i) the additional 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 additional compression costs due to
increased gathered volumes on the Tyler County Pipeline and Brookeland system,
(iii) preparation costs for Hurricane Ike and Gustav and (iv) higher materials,
supplies and labor costs.
  Depreciation and Amortization.Depreciation and amortization expenses for the three and nine months
ended September 30, 2008 were $3.0 million and $8.8 million compared to $3.3
million and $7.2 million, respectively, for the three and nine months ended
September 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 nine months ended September 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 nine months ended September 30, 2008 were $2.6
million and $8.7 million, respectively, compared to $5.7 million and $24.1
million, respectively, for the three and nine months ended September 30, 2007.
During the nine months ended September 30, 2008 we spent $6.4 million on growth
capital of our capital spending in this segment and $2.3 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 month period of $3.1 was due to the
construction of gathering lines to the significant producer discussed above,
being completed, while the decrease in the nine month period of $15.4 million
was due primarily to the construction and start-up of the Tyler County Pipeline
Extension in March 2007.
   31
  South Texas
Segment
 
 Three
      Months Ended
                  September
      30,
              
              
              Nine
      Months Ended
                  September
      30,2008
              
              
              2007(b)
              
              
              2008
              
              
              2007(b)($
      in thousands, except for price data)Revenue:Sales
      of natural gas, NGLs, oil and condensate
              
              $
              114,899
              
              
              $
              62,792
              
              
              $
              343,932
              
              
              $
              112,676Gathering
      and treating services
              
              
              934
              
              
              
              1,517
              
              
              
              3,021
              
              
              
              2,409Other
              
              
              —
              
              
              
              —
              
              
              
              2
              
              
              
              —Total
      revenue
              
              
              115,833
              
              
              
              64,309
              
              
              
              346,955
              
              
              
              115,085Cost
      of natural gas and natural gas liquids
              
              
              112,353
              
              
              
              61,570
              
              
              
              337,412
              
              
              
              110,772Operating
      costs and expenses:Operating
              
              
              635
              
              
              
              394
              
              
              
              1,862
              
              
              
              688Depreciation
      and amortization
              
              
              939
              
              
              
              910
              
              
              
              2,812
              
              
              
              1,289Total
      operating costs and expenses
              
              
              1,574
              
              
              
              1,304
              
              
              
              4,674
              
              
              
              1,977Operating
      income
              
              $
              1,906
              
              
              $
              1,435
              
              
              $
              4,869
              
              
              $
              2,336Capital
      Expenditures
              
              $
              201
              
              
              $
              766
              
              
              $
              780
              
              
              $
              2,112Realized
      average prices:Oil
      and condensate (per Bbl)
              
              $
              112.20
              
              
              $
              71.76
              
              
              $
              106.54
              
              
              $
              69.88Natural
      gas (per Mcf)
              
              $
              9.42
              
              
              $
              5.99
              
              
              $
              9.58
              
              
              $
              6.62NGLs
      (per Bbl)
              
              $
              83.16
              
              
              $
              63.42
              
              
              $
              77.70
              
              
              $
              63.42Production
      volumes:Gathering
      volumes (Mcf/d) (a)
              
              
              80,097
              
              
              
              99,266
              
              
              
              81,228
              
              
              
              55,853NGLs
      and condensate (net equity gallons)
              
              
              571,615
              
              
              
              162,876
              
              
              
              1,399,183
              
              
              
              162,876Natural
      gas short position (MMbtu/d) (a)
              
              
              500
              
              
              
              500
              
              
              
              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 is a recent area of operations for us
as we entered this segment as a result of the Laser Acquisition, effective May
2007. During the three and nine months ended September 30, 2008 the
South Texas Segment contributed  revenues minus cost of natural gas
and natural gas liquids of  $3.5 million and $9.5 million,
respectively, as compared to $2.7 million and $4.3 million for the three and
nine months ended September 30, 2007.  The increase in revenues during
the three months ended September 30, 2008, were due to increased commodity
prices, but volumes were down due to the impact of Hurricane Ike and reduced
drilling success by producers on the Raymondville system.  The
increase in revenues during the nine months ended September 30, 2008 compared to
the comparable period in 2007 was due to a full nine months of the Laser
Acquisition as compared to only a five month period ending September 30,
2007.
 
 There are
two primary activities in this segment: (i) volumes of natural gas gathered
on our own assets, which represents approximately 84% and 87% of revenues minus
cost of natural gas and natural gas liquids for this segment for the three and
nine months ended September 30, 2008 compared to 87% and 85% for the similar
periods in 2007 and (ii) producer services, providing marketing and
pipeline connection services to small independent producers and to third party
pipeline systems, which accounted for approximately 16% and 13% of revenues
minus cost of natural gas and natural gas liquids for the three and nine months
ended September 30, 2008 as compared to 13% and 15% the same periods in
2007.
  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.
   32
   Operating Expenses.Operating
expenses for the three and nine months ended September 30, 2008 were $0.6
million and $1.9 million, respectively, as compared to $0.4 million and $0.7
million for the three and nine months ended September 30, 2007.Operating expenses are
higher due to (i) a full nine months of the Laser Acquisition in 2008 as
compared to only five months in 2007 and (ii) higher material and labor expenses
when comparing the three months ended September 30, 2008 to the comparable
period in 2007.
  Depreciation and Amortization.Depreciation and amortization expenses for the three and nine months
ended September 30, 2008 were $0.9 million and $2.8 million, respectively, as
compared to $0.9 and $1.3 million for the three and nine months ended September
30, 2007.
  Capital Expenditures.Capital
expenditures for the three and nine months ended September 30, 2008 were $0.2
million and $0.8 million, respectively, as compared to $0.8 and $2.1 million for
the three and nine months ended September 30, 2007.  During the nine
months ended September 30, 2008, of our capital spending in this segment, we
spent $0.6 million on growth capital and $0.2 million on maintenance
capital.
  33
  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
                  September
      30,
              
              
              Nine
      Months Ended
                  September
      30,2008(a)
              
              
              2007
              
              
              2008(a)
              
              
              2007($
      in thousands, except for price data)Revenue:Oil
      and condensate
              
              $
              22,694
              
              
              $
              9,588
              
              
              $
              62,153
              
              
              $
              9,588Natural
      gas
              
              
              11,168
              
              
              
              4,375
              
              
              
              27,725
              
              
              
              4,375NGLs
              
              
              8,059
              
              
              
              4,366
              
              
              
              24,354
              
              
              
              4,366Sulfur
              
              
              13,057
              
              
              
              740
              
              
              
              25,524
              
              
              
              740Other
              
              
              428
              
              
              
              —
              
              
              
              608
              
              
              
              —Total
      revenue
              
              
              55,406
              
              
              
              19,069
              
              
              
              140,364
              
              
              
              19,069Operating
      costs and expenses:Operating
              
              
              12,394
              
              
              
              5,792
              
              
              
              29,369
              
              
              
              5,792Depletion,
      depreciation and amortization
              
              
              11,170
              
              
              
              6,897
              
              
              
              29,509
              
              
              
              6,897Total
      operating costs and expenses
              
              
              23,564
              
              
              
              12,689
              
              
              
              58,878
              
              
              
              12,689Operating
      income
              
              $
              31,842
              
              
              $
              6,380
              
              
              $
              81,486
              
              
              $
              6,380Capital
      Expenditures
              
              $
              4,532
              
              
              $
              —
              
              
              $
              17,716
              
              
              $
              —Realized
      average prices:Oil
      and condensate (per Bbl)
              
              $
              98.36
              
              
              $
              68.10
              
              
              $
              100.79
              
              
              $
              68.10Natural
      gas (per Mcf)
              
              $
              9.05
              
              
              $
              6.57
              
              
              $
              9.41
              
              
              $
              6.57NGLs
      (per Bbl)
              
              $
              67.35
              
              
              $
              49.49
              
              
              $
              66.58
              
              
              $
              49.49Sulfur (per Long
    ton)
              
              $
              505.78
              
              
              $
              59.39
              
              
              $
              355.63
              
              
              $
              59.39Production
      volumes:Oil
      and condensate ( Bbl)
              
              
              230,727
              
              
              
              140,799
              
              
              
              616,643
              
              
              
              140,799Natural
      gas (Mcf)
              
              
              1,233,951
              
              
              
              666,298
              
              
              
              2,949,241
              
              
              
              666,298NGLs
      (Bbl)
              
              
              119,664
              
              
              
              88,228
              
              
              
              365,761
              
              
              
              88,228Total
      (Mcfe)
              
              
              3,336,297
              
              
              
              2,040,460
              
              
              
              8,843,665
              
              
              
              2,040,460Sulfur
      (Long ton)
              
              
              25,816
              
              
              
              12,459
              
              
              
              71,772
              
              
              
              12,459
  __________
   (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.
   34
   Revenue. For
the three and nine months ended September 30, 2008, the Upstream Segment
contributed $55.4 million and $140.4 million of revenue,
respectively,  which includes five months of operations related to the
assets acquired in the Stanolind acquisition, as compared to $19.1 for both the
three and nine month periods ending September 30, 2007.
  During
the three months ending September 30, 2008, production averaged 13.2 MMcfe/d,
2.5 MBO/d, 1.3 MB/d of NGL’s and 281 LT/d of sulfur.   The period
included three months of production from the Stanolind acquisition properties
which averaged 900 BOE/d.  Following the turnaround in the second
quarter 2008, the Big Escambia Creek (“BEC”) treating plant operated continually
during the third quarter of 2008.
  During
the nine month period ending September 30, 2008, revenues were negatively
impacted by shut-in production at the Big Escambia Creek field associated with a
20 day planned turnaround of the BEC treating facility.  In addition
during the nine month period, BEC experienced 31 days and 18 days of partial
curtailment associated with sulfur recovery limitations and facility damage
caused by a lightning strike, respectively.
  Gas
production from Flomaton and Fanny Church fields was restricted from sales for
25 days during the nine months ended September 30, 2008 associated with a third
party’s gas quality issue at the point of sale.  Oil sales from both
Flomaton and Fanny Church fields continued during this period of
curtailment.
  Historically,
sulfur was viewed as a low value by-product in the production of oil and natural
gas.  Currently, primarily due to an increase in demand in the global
fertilizer market, the price per long ton peaked at over $600 at the Tampa,
Florida market (before effects of net-backs); as compared to $40 per long ton 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 9,000 long tons per month, net to
us.  There is no guarantee that these high prices will remain in
effect in the future.  As of September 30, 2008, our sulfur product is
not hedged.  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 $12.4 million and
$29.4 million for the Upstream Segment during the three and nine months ended
September 30, 2008, as compared to $5.8 million for the three and nine month
periods endingSeptember
2007, respectively.  These operating expenses include five 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, including operating expenses
related to the planned turnaround at the BEC treating facility during April
2008.  In addition, during the three months ended September 30, 2008,
we recorded $1.4 million of expense that related to a prior
period.  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 nine months ended September 30, 2008 was $11.2 million and $29.5
million, as compared to $6.9 million for the three and nine month periods ending
September, 2007 respectively.  The increase for the three months ended
September 30, 2008 compared to the comparable period in 2007 is due to an
additional month in 2008 of depletion related to our acquisition of Escambia and
Redman and the depletion expense related to the assets added through the
Stanolind acquisition.
  Capital
Expenditures.  The Upstream Segment’s maintenance capital
expenditures for the three and nine months ended September 30, 2008 total $4.5
million and $17.7 million, respectively.  Growth capital expenditures
during the three and nine months ended September 30, 2008 totaled $3.7 million
and $5.7 million, respectively and were associated with drilling projects
acquired in the Stanolind acquisition.  The maintenance capital
expenditures during the three and nine months ended September 30, 2008 were
associated with the planned turnaround at the BEC treating facility, drilling,
recompletions and workover activities.   In addition, certain
capital facility projects were conducted in each of the asset
areas.
   35
   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
                  September
      30,
              
              
              Nine
      Months Ended
                  September
      30,2008
              
              
              2007(a)
              
              
              2008
              
              
              2007(a)($
      in thousands, except for price data)Revenue:Oil
      and condensate
              
              $
              4,390
              
              
              $
              3,080
              
              
              $
              12,489
              
              
              $
              4,613Natural
      gas
              
              
              3,044
              
              
              
              1,850
              
              
              
              8,818
              
              
              
              3,340NGLs
              
              
              413
              
              
              
              527
              
              
              
              1,059
              
              
              
              625Lease
      bonus, rentals and other
              
              
              9,546
              
              
              
              552
              
              
              
              12,240
              
              
              
              623Total
      revenue
              
              
              17,393
              
              
              
              6,009
              
              
              
              34,606
              
              
              
              9,201Operating
      costs and expenses:Operating
              
              
              427
              
              
              
              221
              
              
              
              1,352
              
              
              
              513Depletion
              
              
              2,321
              
              
              
              3,358
              
              
              
              6,460
              
              
              
              4,890Total
      operating costs and expenses
              
              
              2,748
              
              
              
              3,579
              
              
              
              7,812
              
              
              
              5,403Operating
      income
              
              $
              14,645
              
              
              $
              2,430
              
              
              $
              26,794
              
              
              $
              3,798Realized
      average prices:Oil
      and condensate (per Bbl)
              
              $
              104.62
              
              
              $
              64.84
              
              
              $
              103.47
              
              
              $
              64.14Natural
      gas (per Mcf)
              
              $
              9.36
              
              
              $
              4.92
              
              
              $
              8.99
              
              
              $
              6.09NGLs
      (per Bbl)
              
              $
              59.16
              
              
              $
              41.40
              
              
              $
              60.92
              
              
              $
              40.00Production
      volumes:Oil
      and condensate (Bbl)
              
              
              42,004
              
              
              
              47,498
              
              
              
              120,744
              
              
              
              71,908Natural
      gas (Mcf)
              
              
              336,060
              
              
              
              376,389
              
              
              
              991,534
              
              
              
              548,600NGLs
      (Bbl)
              
              
              6,981
              
              
              
              12,729
              
              
              
              17,381
              
              
              
              15,624Total
      (Mcfe)
              
              
              629,970
              
              
              
              737,752
              
              
              
              1,820,288
              
              
              
              1,073,793
 __________
  (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 nine months ended September 30, 2008 our revenue was $17.4 million and
$34.6 million, respectively, as compared to $6.0 million and $9.2 million for
the three and nine months ended September 30, 2007.  The increase in
revenue was due to increases in commodity prices and increases in production
rates during the three and nine months ended September 30, 2008, which was the
result of drilling, recompletion and workover operations conducted by the
various operators of the properties.
  Additionally,
we received approximately $9.5 million and $12.2 million in bonus and delay
rental payments during the three and nine months ended September 30, 2008,
respectively. Substantially all of this was derived from our ownership in the
minerals. The majority of this bonus revenue ($8.5 million) was derived from new
leases executed during the third quarter on our behalf by the Minerals Manager
in the emerging Haynesville shale play.  As a result of these leases,
we now have the opportunity to receive future royalty revenues from wells
drilled on approximately 75,000 gross acres in Desoto and Sabine Parishes,
Louisiana and San Augustine and Sabine Counties, Texas.  In addition,
we made a capital contribution to Ivory Working Interest Partners who then used
the funds (along with other funds contributed by the remaining partners) to
purchase a working interest position in approximately 60,000 gross acres in the
Haynesville shale play.  We also own a mineral interest in
approximately 32,000 of these acres.
  The
amount of revenue we receive from bonus and rental payments varies significantly
from month to month; therefore, we do not believe a meaningful set of
conclusions can be drawn by observing changes in leasing activity over small
time periods. Commodity prices may affect the amount of leasing that will occur
on the minerals in future periods, and it is impossible to predict the timing or
amount of future bonus payments.  We do expect to receive some level
of bonus payments in the future, however.
  Operating Expenses. Operating
expenses of $0.4 million and $1.4 million, respectively, for the three and nine
months ended September 30, 2008 as compared to $0.2 million and $0.5 million for
the three and nine months ended September 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 nine months ended September 30,
2008 was $2.3 million and $6.5 million, respectively, as compared to $3.4
million and $4.9 million for the three and nine months ended September 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
nine months ended September 30, 2008, as a result of the regeneration phenomenon
we received an initial royalty payment for 83 and 234 new wells,
respectively.
  36
  Corporate
Segment
  Three
      Months Ended
                  September
      30,
              
              
              Nine
      Months Ended
                  September
      30,2008
              
              
              2007
              
              
              2008
              
              
              2007($
      in thousands)Revenue:Unrealized
      commodity derivative gains (losses)
              
              $
              255,956
              
              
              $
              8,865
              
              
              $
              (33,381
              )
              
              $
              (30,533
              )Realized
      commodity derivative gains (losses)
              
              
              (24,105
              )
              
              
              (177
              )
              
              
              (64,388
              )
              
              
              4,324Total
      revenue
              
              
              231,851
              
              
              
              8,688
              
              
              
              (97,769
              )
              
              
              (26,209
              )General
      and administrative
              
              
              9,893
              
              
              
              7,196
              
              
              
              31,161
              
              
              
              16,587Other
      operating expense
              
              
              3,920
              
              
              
              220
              
              
              
              10,134
              
              
              
              1,931Depreciation
      and amortization
              
              
              194
              
              
              
              193
              
              
              
              585
              
              
              
              564Total
      costs and expenses
              
              
              14,007
              
              
              
              7,609
              
              
              
              41,880
              
              
              
              19,082Operating
      gains (losses)
              
              
              217,844
              
              
              
              1,079
              
              
              
              (139,649
              )
              
              
              (45,291
              )Other
      income (expense):Interest
      income
              
              
              212
              
              
              
              231
              
              
              
              673
              
              
              
              530Other
      income
              
              
              434
              
              
              
              767
              
              
              
              2,867
              
              
              
              879Interest
      expense, net
              
              
              (7,498
              )
              
              
              (10,633
              )
              
              
              (23,576
              )
              
              
              (27,031
              )Unrealized
      interest rate derivatives gains (losses)
              
              
              (501
              )
              
              
              (8,429
              )
              
              
              (472
              )
              
              
              (3,555
              )Realized
      interest rate derivatives gains (losses)
              
              
              (2,358
              )
              
              
              327
              
              
              
              (4,903
              )
              
              
              967Other
      expense
              
              
              (205
              )
              
              
              (415
              )
              
              
              (652
              )
              
              
              (1,545
              )Total
      other expense
              
              
              (9,916
              )
              
              
              (18,152
              )
              
              
              (26,063
              )
              
              
              (29,755
              )Income
      (Loss) before taxes
              
              
              207,928
              
              
              
              (17,073
              )
              
              
              (165,712
              )
              
              
              (75,046
              )Income
      tax (benefit) provision
              
              
              (494
              )
              
              
              352
              
              
              
              (1,428
              )
              
              
              772Segment
      income (loss)
              
              $
              208,422
              
              
              $
              (17,425
              )
              
              $
              (164,284
              )
              
              $
              (75,818
              )
  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, increased to a gain of
$231.9 million and decreased to a loss of $97.8 million for the three and nine
months ended September 30, 2008, respectively, from a gain of $8.7 million and a
loss of $26.2 million for the three and nine months ended September 30, 2007,
respectively. As a result of our commodity hedging activities, revenues include
total realized losses of $24.1 million and $64.4 million on risk management
activity that was settled during the three and nine months ended September 30,
2008, respectively, and unrealized mark-to-market gains of $256.0 million and
losses of $33.4 million for the three and nine months ended September 30, 2008,
respectively, as compared to realized losses of $0.2 million and  gains of
$4.3 million for the three and nine months ended September 30, 2007,
respectively.  In addition, we recorded amortization of put premiums
of $2.3 million and $6.8 million during the three and nine months ended
September 30, 2008, respectively, as compared to $2.0 million and $6.2 million
for the three and nine months ended September 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 results during the
three and nine months ended September 30, 2008 reflects forward curve price
movements during the three and nine month periods for commodities underlying the
derivative instruments. The unrealized mark-to-market results for the nine
months ended September 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. General and administrative expenses were $9.9 million and $31.2
million for the three and nine months ended September 30, 2008, respectively, as
compared to $7.2 million and $16.6 million for the three and nine months ended
September 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 $2.7 million and $9.6 million for
the three and nine months ended September 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 $0.2 million and $3.3 million for the three and nine months ended
September 30, 2008, respectively.  We also experienced lower other
miscellaneous general and administrative expenses of $0.2 million for the three
months ended September 30, 2008 and increased miscellaneous general and
administrative expenses of $1.7 million for the nine months ended September 30,
2008.  At the present time, we do not allocate our general and
administrative expenses to our operational segments. The Corporate Segment bears
the entire amount.
  Other Operating
Expenses.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 recorded a $6.2 million
bad debt charge in the second quarter 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 we recorded an additional bad debt charge of $3.9 million
during the three months ended September 30, 2008.   Although we
sought payment of our $10.1 million receivable for condensate sales as a
critical supplier to SemGroup under its Supplier Protection Program (“SPP”), we
were not successful in being recognized as a critical provider by SemGroup and
thus were not admitted to the SPP.  As of August 1, 2008, we ceased all
deliveries/sales of condensate to SemGroup.
  For the three
and nine months ended September 30, 2007, other operating expenses included a
settlement of arbitration of $1.4 million, severance to a former executive of
$0.3 million and $0.2 million for liquidated damages related to the late
registration of our common units.
  Total other
expense.  Total other expense, which includes both realized and
unrealized gains and losses from our interest rate swaps, decreased to expense
of $9.9 million and $26.1 million for the three and nine months ended September
30, 2008, respectively, as compared to expense of $18.2 million and $29.8
million for the three and nine months ended September 30, 2007,
respectively.  During the three and nine months ended September 30,
2008, we incurred realized losses from our interest rate swaps of $2.4 million
and $4.9 million, respectively, as compared to realized gains of $0.3 million
and $1.0 million during the three and nine months ended September 30, 2007,
respectively.
   37
  We also
incurred unrealized mark-to-market losses of $0.5 million and $0.5 million
during the three and nine months ended September 30, 2008, respectively, as
compared to unrealized mark-to-market losses of $8.4 million and $3.6 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.
  Interest
expense, net, decreased to $7.5 million and $23.6 million for the three and nine
months ended September 30, 2008, respectively, as compared to $10.6 million and
$27.0 million during the same period in the prior year,
respectively.  The decrease in interest expense, net, is due to the
decrease in interest rates from September 30, 2007 to September 30, 2008 as well
as lower interestrate margin
under the new senior revolving credit facility, partially offset by higher debt
balances.
  In
addition, other income includes our equity in earnings of the partnerships
described in the Overview.  During the three and nine months ended
September 30, 2008, we recorded income of $2.5 million and $5.0 million,
respectively.  These income amounts were offset by a loss on the sale
of investments of $2.1 million in one of these partnerships.  As
discussed in the Overview, once certain payout hurdles had been reached, our
interest would revert to the Mineral Manager.  During the three and
nine months ended September 30, 2007, we recorded income of $0.8 million and
$0.9 million, respectively, related to the equity in earnings of the
partnerships.
  Income Tax (Benefit)
Provision. Income tax benefit recorded during the three and nine months
ended September 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 $30.3
million and $104.4 million from $45.2 million and $81.4 million for the three
and nine months ended September 30, 2007, respectively, to $75.5 million and
$185.8 million for the three and nine months ended September 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 $15.8 million and $67.8 million during the
three and nine months ended September 30, 2008, respectively, as compared to the
comparable periods in 2007. The acquisitions which led to our entry into our
Upstream and Mineral Segments contributed an additional $47.7 million and $146.7
million to revenues during the three and nine months ended September 30, 2008,
respectively, as compared to the comparable periods in 2007. Our Corporate
Segment’s realized commodity derivatives loss decreased by $23.9 million and
$68.7 million during the three and nine months ended September 30, 2008,
respectively, as compared to the comparable periods in 2007. This resulted in
$39.6 million and $145.8 million of total incremental revenues minus cost of
natural gas and natural gas liquids during the three and nine months ended
September 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 $14.0 million and $39.0
million for the three and nine months ended September 30, 2008, respectively,
for our Midstream Segment as compared to $13.6 million and $34.1 million to the
three and nine months ended September 30, 2007, respectively, while the
acquisitions which created the Upstream and Minerals Segments contributed
additional Operating Expenses (including taxes other than income) of $6.8
million and $24.4 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 nine month period ending
September 30, 2008 by $2.1 million and $12.0 million, respectively, as compared
to the respective periods ended September 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 nine month
period ending September 30, 2008, as compared to the same periods in 2007
increased by $39.6 million and $145.8 million, respectively, operating expenses
increased by $7.2 million and $18.8 million, respectively, and general and
administrative expenses increased by $2.1 million and $12.0 million,
respectively.  The increases in revenues minus the cost of natural gas
and natural gas liquids, offset by increases in operating costs and general
administrative expenses resulted in an increase to Adjuisted EBITDA during the
three and nine months ended September 30, 2008, as compared to the same periods
in 2007.
   38
  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 operations and borrowings under our
existing credit facility will continue to be sufficient to meet our minimum
quarterly distribution (as defined in our Partnership documents) and our
requirements for short-term working capital and 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
September 30, 2008, working capital was $143.6 million as compared to a $15.1
million balance as of December 31, 2007.
  The net
increase in working capital of $128.5 million from December 31, 2007 to
September 30, 2008, resulted primarily from the following factors:
  •
              risk
      management net working capital deficit balance increased by a net $22.5
      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, increased overall by
      $161.1 million due to the results of operations, timing of expenditure
      payments, and a draw of $176.4 million under our secured revolving credit
      facility on September 29, 2008 in anticipation of the closing of the MMP
      acquisition on October 1, 2008;
  •
              trade
      accounts receivable increased by $2.5 million;
  and
  •
              accounts
      payable and accrued liabilities increased by $10.7 million from
      December 31, 2007 primarily as a result of operating activities and
      timing of payments, including capital
  expenditures.
  Derivative Financial
Exposure.  At September 30, 2008, the fair value of our
financial derivatives was a net liability of $160.7
million.  Substantially all of our counterparties to these derivatives
are participants in our revolving credit facility, and their outstanding debt
commitments and derivative exposure are 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, as long as our derivative counterparties
remain as lenders in our credit facility, we do not have exposure to potential
“margin calls” on our derivative instruments.  To the extent we are in
an asset position, we do not have rights to collateral from our counterparties,
nor do we have rights of offset against the borrowings under our revolving
credit facility.
  Cash
Flows Nine months Ended September 30, 2008 Compared to Nine months Ended
September 30, 2007
  Cash Flow from Operating
Activities. Cash flows provided by operating activities increased by
$87.0 million during the nine months ended September 30, 2008 as compared to the
nine months ended September 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 nine
months ended September 30, 2008, as compared to the nine months ended September
30, 2007, decreased by $326.6 million. The investing activities for the current
period reflect the Stanolind acquisition of $81.3 million compared to the
Laser,  Montierra, Escambia and Redman acquisitions in the prior year
totaling $403.2 million and a lower 2008 capital expenditure level of $46.8
million versus $54.9 million for 2007.
  Cash Flows From Financing
Activities. Cash flows used in financing activities during the nine
months ended September 30, 2008, decreased by $326.7 million, from the cash
flows provided by financing activities of $455.2 million for the nine months
ended September 30, 2007. Key differences between periods include proceeds of
$331.5 from private placement of our units in 2007 offset by increased net
borrowings under our revolving credit facility of
   39
  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 of up
to $800 million.  During the three months ended September 30,
2008, we exercised $180 million of our $200 million accordion feature under the
credit facility, which increased the total commitment to $980
million.  In connection with exercising the accordion feature of our
credit facility, we incurred debt issuance costs of $0.8 million.  We
exercised the accordion feature to provide for adequate funding associated with
our growth strategy.  As of September 30, 2008, unused capacity
available to us under the new credit agreement, based on financial covenants, is
approximately $175 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.
  Given the
current state of the banking industry worldwide, we have endeavored to diversify
our lender group as much as possible. As such, after the upsizing of our credit
facility as described above, our credit facility now counts with the
participation of 21 financial institutions. As of today, all of our banks’
commitments, with the exception of Lehman Brothers’ commitment, remain in place
and have funded in response to our borrowing notices.  A Lehman
Brothers subsidiary has an approximately 2.6% participation in the Partnership’s
credit facility.  We believe that based on the expected positive
effects of the passing of the Emergency Economic Stabilization Act of 2008, and
similar initiatives around the world, credit will continue to be
available.
  Capital
Requirements.
  As we
expand our businesses through acquisitions and organic projects, our need for
capital will increase. We anticipate that as long as the current volatility in
the world’s capital markets continues we will have relatively limited access to
capital to grow, our businesses aside from our existing availability under our
revolving credit facility.  Once stability returns and capital markets
begin to function properly, we anticipate that we will again have sufficient
access to capital to grow.
  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, and draws from our revolving credit facility;
however, we cannot provide assurances that we will be able to obtain additional
capital from equity or debt issuances under terms acceptable to us.
  Our
original 2008 capital budget anticipated that we would spend approximately $48.3
million on our existing assets, of which $24.9 million was for growth and $23.4
million was for maintenance.  This 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 and
Millennium acquisitions) and the actual capital expenditures incurred during the
nine months of 2008, we expect to spend a total of approximately $65.9 million
for 2008 (excludes all acquisition purchase prices), of which $38.0 million will
be fogrowth and $27.9 million 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, which currently has approximately $175 million in
available funds.
  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
  40
   upstream
      business, maintenance capital is defined as capital which is expended to
      maintain our production constant.
  Since our
inception in 2002, we have made substantial growth capital expenditures. We
anticipate we will continue to identify and fund growth capital expenditures
from our revolving credit facility.  We will evaluate future growth
and acquisition projects, subject to capital markets regaining
stability.  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 once capital markets regain
stability, 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
September 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 on our financial statements, if any,
of adopting FSP FAS 157-2.
  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.
  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.
  41
  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 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 (non-recurring), other non-cash operating and
general and administrative expenses (including non-cash compensation related to
our equity-based compensation program), unrealized (gains) losses on commodity
and interest rate risk management 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
  42
  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.
   43
   Reconciliation
of “Adjusted EBITDA” to net cash flows provided by operating activities and net
income (loss)
  Three
      Months Ended
                September
      30,
              
              
              Nine
      Months Ended
                  September
      30,2008
              
              
              2007
              
              
              2008
              
              
              2007($
      in thousands)Net
      cash flows provided by operating activities
              
              $
              40,927
              
              
              $
              48,479
              
              
              $
              163,571
              
              
              $
              76,598Add
      (deduct):Depreciation,
      depletion and amortization
              
              
              (28,597
              )
              
              
              (25,104
              )
              
              
              (80,799
              )
              
              
              (50,883
              )Amortization
      of debt issuance costs
              
              
              (219
              )
              
              
              456
              
              
              
              (655
              )
              
              
              (416
              )Risk
      management portfolio value changes
              
              
              258,716
              
              
              
              9,422
              
              
              
              (30,592
              )
              
              
              (25,102
              )Net
      realized (loss) gain on financing derivative settlements
              
              
              (5,925
              )
              
              
              —
              
              
              
              (15,462
              )
              
              
              100Other
              
              
              (1,344
              )
              
              
              (1,400
              )
              
              
              (1,313
              )
              
              
              (1,337
              )Accounts
      receivables and other current assets
              
              
              (49,584
              )
              
              
              (4,398
              )
              
              
              (651
              )
              
              
              20,322Accounts
      payable, due to affiliates and accrued liabilities
              
              
              74,741
              
              
              
              (18,535
              )
              
              
              (956
              )
              
              
              (53,075
              )Other
      assets and liabilities
              
              
              (644
              )
              
              
              451
              
              
              
              (420
              )
              
              
              (287
              )Net
      income (loss)
              
              
              288,071
              
              
              
              9,371
              
              
              
              32,723
              
              
              
              (34,080
              )Add
      (deduct):Interest
      expense, net (1)
              
              
              9,849
              
              
              
              10,490
              
              
              
              28,458
              
              
              
              27,079Depreciation,
      depletion and amortization
              
              
              28,597
              
              
              
              25,104
              
              
              
              80,799
              
              
              
              50,883Income
      tax (benefit) provision
              
              
              (494
              )
              
              
              352
              
              
              
              (1,482
              )
              
              
              772EBITDA
              
              
              326,023
              
              
              
              45,317
              
              
              
              140,498
              
              
              
              44,654Add
      (deduct):Risk
      management portfolio value changes
              
              
              (255,455
              )
              
              
              (436
              )
              
              
              33,853
              
              
              
              34,088Restricted
      unit compensation expense
              
              
              1,427
              
              
              
              821
              
              
              
              4,147
              
              
              
              1,613Other
      income
              
              
              (434
              )
              
              
              (767
              )
              
              
              (2,867
              )
              
              
              (879
              )Other
      operating expenses (2)
              
              
              3,920
              
              
              
              220
              
              
              
              10,134
              
              
              
              1,931ADJUSTED
      EBITDA
              
              $
              75,481
              
              
              $
              45,155
              
              
              $
              185,765
              
              
              $
              81,407
 ________
  (1)
              Includes
      realized interest rate derivative gains and losses and other
      expenses.
 (2)
              Includes
      the SemGroup bad debt expense of $3.9 million and $6.2 million for the
      three and nine months ended September 30, 2008, respectively, a settlement
      of arbitration for $1.4 million and severance to a former executive of
      $0.3 million for the nine months ended September 30, 2007 and $0.2 million
      for liquidated damages related to the late registration of our common
      units during the three and nine months ended September 30,
      2007.
   44
  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 but today these correlations
have widened significantly and may or may not continue to maintain this
correlation into the future.
  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 September 30,
2008, the Partnership recorded a gain on risk management instruments of $231.9
million representing a fair value (unrealized) gain of $258.3 million,
amortization of put premiums of $2.3 million and net (realized) settlement
losses of $24.1 million.  For the nine months ended September 30,
2008, the Partnership recorded a loss on risk management instruments of $97.8
million representing a fair value (unrealized) loss of $26.6 million,
amortization of put premiums of $6.8 million and net (realized) settlement
losses of $64.4 million.  As of September 30, 2008, the fair value
liability of these commodity contracts, including put premiums, totalled
approximately $148.0 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 September 30, 2008, the
Partnership recorded a fair value (unrealized) gain of $0.5 million and a
realized loss of $2.4 million.  For the nine months ended September
30, 2008, the Partnership recorded a fair value (unrealized) loss of $0.5
million and a realized loss of $4.9 million.  As of September 30,
2008, the fair value liability of these interest rate contracts totaled
approximately $12.7 million.
  45
   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 principal
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 nine months ended September 30, 2008, we
recorded a bad debt provision of $3.9 million and $10.1 million,
respectively, related to our outstanding receivables from SemGroup. 
We discontinued all sales to SemGroup as of August 1, 2008, and as a result, we
do not anticipate recording any additional bad debt charges in future
periods.
  Our
derivative counterparties include BNP Paribas, Wachovia, Barclay’s, Royal Bank
of Scotland, Bank of America, Wells Fargo, J Aron (an affiliate of Goldman
Sachs), British Petroleum and Shell.
  46
   Item
4. Controls and Procedures.
  Evaluation
of Disclosure Controls and Procedures
  Management
has conducted an evaluation of the effectiveness of the Partnership's 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
the Partnership's principal executive officer and principal financial officer,
to ensure timely decisions regarding required disclosures. As part of the
evaluation of disclosure controls and procedures conducted during the
preparation of our financial statements as of December 31, 2007, which were
included in our Annul Report on Form 10-K for the year ended December 31, 2007,
material weaknesses in internal control over financial reporting were identified
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
directions of our principal executive officer and principal financial officer,
we developed a comprehensive plan to remediate the material weaknesses, the
status of which is described below.
  As of
September 30, 2008, and as described under Status of Remediation of Material
Weakness in Internal Control Over Financial Reporting below, all of the
aforementioned identified material weaknesses were not fully remediated. As a
result, our principal executive officer and principal financial officer
concluded that, as of September 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.
  47
  Remediated Material
Weaknesses
  As of the
filing of the June 30, 2008 Quarterly Report on Form 10-Q, our management had
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 four 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.
  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
completed its remediation efforts and deemed these material weaknesses
remediated as of the filing of the June 30, 2008 Quarterly Report on Form
10-Q.
  During
the three months ended September 30, 2008 our Chief Financial Officer
resigned.  We are actively engaged in a search for a permanent
replacement.  Management also assessed the impact of the resignation
on the Internal Control Environment and has concluded that, based on the other
remediation actions completed and described above, and the oversight
provided by our Interim Chief Financial Officer, the resignation did not have a
material impact on the Internal Control Environment.  Therefore, the
material weakness related to Internal Control Environment, which was identified
in our Annual Report on Form 10-K for the year ended December 31, 2007 is still
remediated as of the filing of the September 30, 2008 Quarterly Report on Form
10-Q.
  Un-remediated
Material Weakness
  Period
End Financial Reporting Process
  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. Management concluded that the controls are operating
      effectively across all segments.
 ·
              Implemented
      and tested controls to ensure that access to open and close accounting
      periods is adequately restricted.  Management concluded that the
      controls are operating effectively.
 ·
              Implemented
      and tested controls related to material and highly subjective accruals.
      Management concluded that the controls are operating
      effectively.·
              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 are operating
      effectively.
  ·
              Continued
      to implement and refine 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.
 ·
              Implemented
      controls to detect un-posted journal entries. Testing of this control is
      in progress.
 
 Management
believes that the new procedures and controls discussed above will provide an
appropriate remediation of this material weakness; however, the effectiveness of
all of the controls has 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. This
material weakness will be fully remediated when, in the opinion of management,
the revised control processes have been operating for a sufficient period of
time and independently validated by internal audit testing.
 
 The
remediation and ultimate resolution of this material weakness will be reviewed
with the Audit Committee of our Board of Directors.
  Changes
in Internal Control Over Financial Reporting
  During
thefourth
quarter of 2008, the partnership completed the acquisition of Millennium
Midstream Partners, L.P., thereby acquiring control of its many subsidiary
operating entities and their assets and operation which the Partnership
subsequently restructured in order to integrate them into our existing
structure.  Because of the timing of the acquisition, management will
not include the internal control processes for these entities, and their assets
and operations, in its 2008 Internal Controls
Assessment.  Additionally, the acquisition is excluded from the
certifications required under Section 302 of the Sarbanes-Oxley Act of
2002.  Management will include all aspects of internal controls for
this acquisition in its 2009 assessment.
  Except for
the changes and events described above, as of the quarter ended September 30,
2008, management has not identified any other events or changes which are
reasonably likely to materially affect our internal controls over financial
reporting.
   48
   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.
  In June 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 a second NOE to our subsidiary 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.  During the three months ended September 30, 2008, we
executed an Agreed Order resolving with the TCEQ the two Notice of Enforcement
matters. The administrative penalties paid by us were, in the aggregate, less
than $10,000, and we consider these matters concluded at this time.
  In late
September 2008, the TCEQ issued another Notice of Enforcement to one of our
subsidiaries, concerning the environmental compliance of our Red Deer Gas Plant
(the “Site”), TCEQ ID No.: RH 0004-B (the “NOE”).  The allegations in the
NOE are the result of findings made by the TCEQ’s Amarillo Region Office as a
result of a routine inspection of the Site.  In response, our subsidiary is
providing substantial documentation, some of which is corrective in nature, to
the TCEQ and we are contesting certain other allegations.  The TCEQ has
great discretion to assess administrative penalties, in a range of $0 to $10,000
per day, and the allegations underpinning the NOE involve a time period that
runs over one year.  The TCEQ has not yet made a final determination
with respect to whether it will assess an administrative penalty (or the amount
of such penalty, if assessed).
  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.
   49
  Item
6. Exhibits.
  2.1
              Partnership
      Interests Purchase Agreement dated September 11, 2008, as amended, among
      Eagle Rock Energy Partners, L.P. and Millennium Midstream Partners,
      L.P.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 Alfredo Garcia 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 Alfredo Garcia pursuant to Section 906 of the Sarbanes-Oxley Act of
      2002 and 18 U.S.C. Section 1350.
 
  50
  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:
      November 10, 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/
      Alfredo Garcia
                Alfredo
      Garcia
                Senior
      Vice President, Corporate Development and Interim
                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.
 
  51
  EAGLE
ROCK ENERGY PARTNERS, L.P.
 EXHIBIT
INDEX
 
 2.1
              Partnership
      Interests Purchase Agreement dated September 11, 2008, as amended, among
      Eagle Rock Energy Partners, L.P. and Millennium Midstream Partners,
      L.P.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 Alfredo Garcia 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 Alfredo Garcia pursuant to Section 906 of the Sarbanes-Oxley Act of
      2002 and 18 U.S.C. Section 1350.
 
  52