UNITED
STATES


SECURITIES
AND EXCHANGE COMMISSION


Washington,
D.C. 20549







FORM
10-Q







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




For
the quarterly period ended September 30, 2009




OR




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




Commission
File No. 001-33016







EAGLE
ROCK ENERGY PARTNERS, L.P.


(Exact
Name of Registrant as Specified in Its Charter)








Delaware
            68-0629883(State
      or Other Jurisdiction of
              Incorporation
      or Organization)
            (I.R.S.
      Employer
              Identification
      Number)




16701
Greenspoint Park Drive, Suite 200


Houston,
Texas 77060


(Address
of principal executive offices, including zip code)




(281)
408-1200


(Registrant’s
telephone number, including area code)







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




Indicate
by check mark whether the registrant has submitted electronically and posted on
its corporate website, if any, every Interactive Data File required to be
submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter)
during the preceding 12 months (or for such shorter period than the registrant
was required to submit and post such
files).Yes   ̈    No   ̈




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





Large
      accelerated filer   ̈
            Accelerated
      filer  xNon-accelerated
      filer   ̈
            Smaller
      Reporting Company   ̈(Do
      not check if a smaller reporting
company)




Indicate
by check mark whether the registrant is a shell company (as defined in Rule
12b-2 of the Exchange Act).    Yes   ̈    No  x




The
issuer had 55,277,752 common units outstanding as of November 2,
2009.








EAGLE
ROCK ENERGY PARTNERS, L.P.




TABLE OF CONTENTS










PagePART I. FINANCIAL
      INFORMATIONItem 1.
            Financial StatementsUnaudited Condensed Consolidated Balance Sheets as of September
      30, 2009 and December 31, 2008
            3Unaudited Condensed Consolidated Statements of
      Operations for the three and nine months ended September 30, 2009 and
      2008
            4Unaudited Condensed Consolidated Statements of Cash
      Flows for the nine months ended September 30, 2009 and
      2008
            6Unaudited Condensed Consolidated Statements of Members’
      Equity for the nine months ended September 30, 2009 and
      2008
            7Notes to the Unaudited Condensed Consolidated Financial
      Statements
            8Item 2.
            Management’s Discussion and Analysis of Financial Condition
      and Results of Operations
            33Item 3.
            Quantitative and Qualitative Disclosures About Market
      Risk
            51Item 4.
            Controls and Procedures
            51PART II. OTHER
      INFORMATIONItem 1.
            Legal Proceedings
            52Item 1A.
            Risk Factors
            52Item 2.
            Unregistered Sales of Equity Securities and Use of
      Proceeds
            53Item 3.
            Defaults Upon Senior Securities
            53Item 4.
            Submission of Matters to a Vote of Security
      Holders
            53Item 5.
            Other Information
            54Item 6.
            Exhibits
            54




















2




PART
      1. FINANCIAL INFORMATION




Item 1.
            Financial
      Statements.





EAGLE
ROCK ENERGY PARTNERS, L.P.


UNAUDITED CONDENSED CONSOLIDATED BALANCE SHEETS


($ in thousands)





September
      30,
              2009
            
            
            December 31,
              2008ASSETSCURRENT
      ASSETS:Cash
      and cash equivalents
            
            $
            9,168
            
            
            $
            17,916Accounts
      receivable(1)
            
            
            73,792
            
            
            
            115,932Risk
      management assets
            
            
            26,017
            
            
            
            76,769Prepayments
      and other current assets
            
            
            2,140
            
            
            
            2,607Total
      current assets
            
            
            111,117
            
            
            
            213,224PROPERTY,
      PLANT AND EQUIPMENT — Net
            
            
            1,313,386
            
            
            
            1,357,609INTANGIBLE
      ASSETS — Net
            
            
            139,273
            
            
            
            154,206DEFERRED
      TAX ASSET
            
            
            1,663
            
            
            
            —RISK
      MANAGEMENT ASSETS
            
            
            5,725
            
            
            
            32,451OTHER
      ASSETS
            
            
            19,678
            
            
            
            15,571TOTAL
            
            $
            1,590,842
            
            
            $
            1,773,061LIABILITIES
      AND MEMBERS’ EQUITYCURRENT
      LIABILITIES:Accounts
      payable
            
            $
            65,666
            
            
            $
            116,578Due
      to affiliate
            
            
            10,859
            
            
            
            4,473Accrued
      liabilities
            
            
            11,364
            
            
            
            19,565Taxes
      payable
            
            
            992
            
            
            
            1,559Risk
      management liabilities
            
            
            34,988
            
            
            
            13,763Total
      current liabilities
            
            
            123,869
            
            
            
            155,938LONG-TERM
      DEBT
            
            
            774,383
            
            
            
            799,383ASSET
      RETIREMENT OBLIGATIONS
            
            
            19,728
            
            
            
            19,872DEFERRED
      TAX LIABILITY
            
            
            42,051
            
            
            
            42,349RISK
      MANAGEMENT LIABILITIES
            
            
            31,406
            
            
            
            26,182OTHER
      LONG TERM LIABILITIES
            
            
            568
            
            
            
            1,622COMMITMENTS
      AND CONTINGENCIES (Note 12)MEMBERS’
      EQUITY:Common
      Unitholders(2)
            
            
            533,651
            
            
            
            625,590Subordinated
      Unitholders(3)
            
            
            70,360
            
            
            
            105,839General
      Partner(4)
            
            
            (5,174
            )
            
            
            (3,714
            )Total
      members’ equity
            
            
            598,837
            
            
            
            727,715TOTAL
            
            $
            1,590,842
            
            
            $
            1,773,061





(1)
            Net
      of allowable for bad debt of $12,172 as of September 30, 2009 and $12,080
      as of December 31, 2008, of which $10,699 relates to SemGroup L.P.
      which filed for bankruptcy in July
2008.


(2)
            54,094,219
      and 53,043,767 units were issued and outstanding as of September 30, 2009
      and December 31, 2008, respectively. These amounts do not include
      unvested restricted common units granted under the Partnership’s long-term
      incentive plan of 793,739 and 905,486 as of September 30, 2009 and
      December 31, 2008, respectively.


(3)
            20,691,495
      units were issued and outstanding as of September 30, 2009 and
      December 31, 2008.


(4)
            844,551
      units were issued and outstanding as of September 30, 2009 and
      December 31, 2008.




See
notes to unaudited condensed consolidated financial statements.


3
 Table of Contents




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
      30,2009
            
            
            2008
            
            
            2009
            
            
            2008REVENUE:Natural
      gas, natural gas liquids, oil, condensate and sulfur sales
            
            $
            156,779
            
            
            $
            341,700
            
            
            $
            468,589
            
            
            $
            1,008,891Gathering,
      compression, processing and treating services
            
            
            11,814
            
            
            
            12,513
            
            
            
            35,043
            
            
            
            27,741Minerals
      and royalty income
            
            
            4,050
            
            
            
            17,393
            
            
            
            10,788
            
            
            
            34,606Commodity
      risk management (losses) gains
            
            
            (8,832
            )
            
            
            231,851
            
            
            
            (57,137
            )
            
            
            (97,769
            )Other
      revenue
            
            
            50
            
            
            
            428
            
            
            
            1,770
            
            
            
            610Total
      revenue
            
            
            163,861
            
            
            
            603,885
            
            
            
            459,053
            
            
            
            974,079COSTS
      AND EXPENSES:Cost
      of natural gas and natural gas liquids
            
            
            109,945
            
            
            
            237,742
            
            
            
            358,802
            
            
            
            726,400Operations
      and maintenance (1)
            
            
            16,934
            
            
            
            21,475
            
            
            
            54,624
            
            
            
            54,772Taxes
      other than income
            
            
            2,934
            
            
            
            5,365
            
            
            
            8,790
            
            
            
            14,975General
      and administrative
            
            
            10,449
            
            
            
            9,893
            
            
            
            34,882
            
            
            
            31,161Other
      operating (income) expenses
            
            
            —
            
            
            
            3,920
            
            
            
            (3,552
            )
            
            
            10,134Impairment
            
            
            274
            
            
            
            —
            
            
            
            516
            
            
            
            —Depreciation,
      depletion, and amortization
            
            
            28,586
            
            
            
            28,597
            
            
            
            86,237
            
            
            
            80,799Total
      costs and expenses
            
            
            169,122
            
            
            
            306,992
            
            
            
            540,299
            
            
            
            918,241OPERATING
      (LOSS) INCOME
            
            
            (5,261
            )
            
            
            296,893
            
            
            
            (81,246
            )
            
            
            55,838OTHER
      INCOME (EXPENSE):Interest
      income
            
            
            10
            
            
            
            212
            
            
            
            183
            
            
            
            673Other
      income
            
            
            725
            
            
            
            434
            
            
            
            1,835
            
            
            
            2,867Interest
      expense, net
            
            
            (4,315
            )
            
            
            (7,498
            )
            
            
            (17,282
            )
            
            
            (23,576
            )Interest
      rate risk management losses
            
            
            (10,348
            )
            
            
            (2,859
            )
            
            
            (3,924
            )
            
            
            (5,375
            )Other
      expense
            
            
            (267
            )
            
            
            (205
            )
            
            
            (801
            )
            
            
            (652
            )Total
      other expense
            
            
            (14,195
            )
            
            
            (9,916
            )
            
            
            (19,989
            )
            
            
            (26,063
            )(LOSS)
      INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAX
              BEFORE
      INCOME TAXES
            
            
            (19,456
            )
            
            
            286,977
            
            
            
            (101,235
            )
            
            
            29,775INCOME
      TAX PROVISION (BENEFIT)
            
            
            5,841
            
            
            
            (500
            )
            
            
            1,634
            
            
            
            (1,497
            )(LOSS)
      INCOME FROM CONTINUING OPERATIONS
            
            
            (25,297
            )
            
            
            287,477
            
            
            
            (102,869
            )
            
            
            31,272DISCONTINUED
      OPERATIONS
            
            
            26
            
            
            
            594
            
            
            
            266
            
            
            
            1,451NET
      (LOSS) INCOME
            
            $
            (25,271
            )
            
            $
            288,071
            
            
            $
            (102,603
            )
            
            $
            32,723





(1)
            Includes
      costs to dispose of sulfur in our Upstream segment of $0.3 million and
      $1.5 million for the three and nine months ended September 30, 2009,
      respectively.





See
notes to unaudited condensed consolidated financial statements.





4
 Table of Contents




EAGLE
ROCK ENERGY PARTNERS, L.P.


UNAUDITED
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS


(continued)


(In thousands, except per unit
amounts)








Three
      Months Ended
              September
      30,
            
            
            Nine
      Months Ended
              September
      30,2009
            
            
            2008
            
            
            2009
            
            
            2008NET
      (LOSS) INCOME PER COMMON UNIT — BASIC AND DILUTED:Basic
      (loss) income from continuing operations per unit:Common
      units
            
            $
            (0.33
            )
            
            $
            3.93
            
            
            $
            (1.35
            )
            
            $
            0.43Subordinated
      units
            
            $
            (0.35
            )
            
            $
            3.93
            
            
            $
            (1.43
            )
            
            $
            0.43General
      partner units
            
            $
            (0.33
            )
            
            $
            3.93
            
            
            $
            (1.35
            )
            
            $
            0.43Basic
      discontinued operations per unit:Common
      units
            
            $
            —
            
            
            $
            0.01
            
            
            $
            —
            
            
            $
            0.02Subordinated
      units
            
            $
            —
            
            
            $
            0.01
            
            
            $
            —
            
            
            $
            0.02General
      partner units
            
            $
            —
            
            
            $
            0.01
            
            
            $
            —
            
            
            $
            0.02Basic
      net (loss) income per unit:Common
      units
            
            $
            (0.33
            )
            
            $
            3.94
            
            
            $
            (1.35
            )
            
            $
            0.45Subordinated
      units
            
            $
            (0.35
            )
            
            $
            3.94
            
            
            $
            (1.43
            )
            
            $
            0.45General
      partner units
            
            $
            (0.33
            )
            
            $
            3.94
            
            
            $
            (1.35
            )
            
            $
            0.45Basic
      weighted average units outstanding:Common
      units
            
            
            53,632
            
            
            
            50,824
            
            
            
            53,276
            
            
            
            50,762Subordinated
      units
            
            
            20,691
            
            
            
            20,691
            
            
            
            20,691
            
            
            
            20,691General
      partner units
            
            
            845
            
            
            
            845
            
            
            
            845
            
            
            
            845Diluted
      (loss) income from continuing operations per unit:Common
      units
            
            $
            (0.33
            )
            
            $
            3.93
            
            
            $
            (1.35
            )
            
            $
            0.43Subordinated
      units
            
            $
            (0.35
            )
            
            $
            3.93
            
            
            $
            (1.43
            )
            
            $
            0.43General
      partner units
            
            $
            (0.33
            )
            
            $
            3.93
            
            
            $
            (1.35
            )
            
            $
            0.43Diluted
      discontinued operations per unit:Common
      units
            
            $
            —
            
            
            $
            0.01
            
            
            $
            —
            
            
            $
            0.02Subordinated
      units
            
            $
            —
            
            
            $
            0.01
            
            
            $
            —
            
            
            $
            0.02General
      partner units
            
            $
            —
            
            
            $
            0.01
            
            
            $
            —
            
            
            $
            0.02Diluted
      net (loss) income per unit:Common
      units
            
            $
            (0.33
            )
            
            $
            3.94
            
            
            $
            (1.35
            )
            
            $
            0.45Subordinated
      units
            
            $
            (0.35
            )
            
            $
            3.94
            
            
            $
            (1.43
            )
            
            $
            0.45General
      partner units
            
            $
            (0.33
            )
            
            $
            3.94
            
            
            $
            (1.35
            )
            
            $
            0.45Diluted
      weighted average units outstanding:Common
      units
            
            
            53,632
            
            
            
            50,868
            
            
            
            53,276
            
            
            
            50,900Subordinated
      units
            
            
            20,691
            
            
            
            20,691
            
            
            
            20,691
            
            
            
            20,691General
      partner units
            
            
            845
            
            
            
            845
            
            
            
            845
            
            
            
            845





See
notes to unaudited condensed consolidated financial statements.


5
 Table of Contents




EAGLE
ROCK ENERGY PARTNERS, L.P.


UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF CASH
FLOWS


($ in thousands)





Nine
      Months
              Ended
      September 30,2009
            
            
            2008CASH
      FLOWS FROM OPERATING ACTIVITIES:Net
      (loss) income
            
            $
            (102,603
            )
            
            $
            32,723Adjustments
      to reconcile net (loss) income to net cash provided by operating
      activities:Depreciation,
      depletion and amortization
            
            
            86,237
            
            
            
            80,799Impairment
            
            
            516
            
            
            
            —Amortization
      of debt issuance costs
            
            
            801
            
            
            
            655Reclassifying
      financing derivative settlements
            
            
            (8,330
            )
            
            
            15,462Distribution
      from unconsolidated affiliates – return on
investment
            
            
            247
            
            
            
            1,751Equity
      in earnings of unconsolidated affiliates
            
            
            (988
            )
            
            
            (2,859
            )Equity-based
      compensation expense
            
            
            5,024
            
            
            
            4,147Gain
      from sales of assets
            
            
            (476
            )
            
            
            —Other
      operating income
            
            
            (3,552
            )
            
            
            —Other
            
            
            1,547
            
            
            
            (1,726
            )Changes
      in assets and liabilities — net of acquisitions:Accounts
      receivable
            
            
            41,365
            
            
            
            634Prepayments
      and other current assets
            
            
            478
            
            
            
            17Risk
      management activities
            
            
            103,927
            
            
            
            30,592Accounts
      payable
            
            
            (50,022
            )
            
            
            2,742Due
      to affiliates
            
            
            6,386
            
            
            
            (559
            )Accrued
      liabilities
            
            
            (6,164
            )
            
            
            (1,227
            )Other
      assets and liabilities
            
            
            (1,221
            )
            
            
            420Net
      cash provided by operating activities
            
            
            73,172
            
            
            
            163,571CASH
      FLOWS FROM INVESTING ACTIVITIES:Acquisitions,
      net of cash acquired
            
            
            —
            
            
            
            (81,289
            )Additions
      to property, plant and equipment
            
            
            (29,427
            )
            
            
            (45,337
            )Purchase
      of intangible assets
            
            
            (1,219
            )
            
            
            (1,438
            )Proceeds
      from sale of fixed assets
            
            
            476
            
            
            
            —Investment
      in unconsolidated affiliates
            
            
            (806
            )
            
            
            (3,416
            )Net
      cash used in investing activities
            
            
            (30,976
            )
            
            
            (131,480
            )CASH
      FLOWS FROM FINANCING ACTIVITIES:Repayment
      of revolving credit facility
            
            
            (156,000
            )
            
            
            (145,069
            )Proceeds
      from revolving credit facility
            
            
            131,000
            
            
            
            377,383Proceeds
      (payments) for derivative contracts
            
            
            8,330
            
            
            
            (15,462
            )Payment
      of debt issuance costs
            
            
            —
            
            
            
            (789
            )Repurchase
      of common units
            
            
            (30
            )
            
            
            —Distributions
      to members and affiliates
            
            
            (34,244
            )
            
            
            (87,602
            )Net
      cash (used in) provided by financing activities
            
            
            (50,944
            )
            
            
            128,461NET
      CHANGE IN CASH AND CASH EQUIVALENTS
            
            
            (8,748
            )
            
            
            160,552CASH
      AND CASH EQUIVALENTS — Beginning of period
            
            
            17,916
            
            
            
            68,552CASH
      AND CASH EQUIVALENTS — End of period
            
            $
            9,168
            
            
            $
            229,104SUPPLEMENTAL
      CASH FLOW DATA:Interest
      paid — net of amounts capitalized
            
            $
            21,755
            
            
            $
            26,028Cash
      paid for taxes
            
            $
            1,377
            
            
            $
            705Investments
      in property, plant and equipment not paid
            
            $
            1,720
            
            
            $
            5,534Units
      issued in acquisition from escrow
            
            $
            3,000
            
            
            $
            —







See
notes to unaudited condensed consolidated financial statements.


6
 Table of Contents


EAGLE
ROCK ENERGY PARTNERS, L.P.


UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF MEMBERS’
EQUITY





FOR
THE NINE MONTH PERIOD ENDED SEPTEMBER 30, 2008


($ in thousands, except unit
amounts)





General
              Partner
            
            
            Number
      of
              Common
              Units
            
            
            Common
              Units
            
            
            Number
      of
              Subordinated
              Units
            
            
            Subordinated
              Units
            
            
            TotalBALANCE
      — December 31, 2007
            
            $
            (3,155
            )
            
            
            50,699,647
            
            
            $
            617,563
            
            
            
            20,691,495
            
            
            $
            112,360
            
            
            $
            726,768Net
      income
            
            
            382
            
            
            
            —
            
            
            
            22,976
            
            
            
            —
            
            
            
            9,365
            
            
            
            32,723Distributions
            
            
            (1,016
            )
            
            
            —
            
            
            
            (61,704
            )
            
            
            —
            
            
            
            (24,882
            )
            
            
            (87,602
            )Vesting
      of restricted units
            
            
            —
            
            
            
            124,384
            
            
            
            —
            
            
            
            —
            
            
            
            —
            
            
            
            —Distributions
      to affiliates
            
            
            —
            
            
            
            —
            
            
            
            (857
            )
            
            
            —
            
            
            
            —
            
            
            
            (857
            )Equity
      based compensation
            
            
            40
            
            
            
            —
            
            
            
            2,910
            
            
            
            —
            
            
            
            1,197
            
            
            
            4,147BALANCE
      — September 30, 2008
            
            $
            (3,749
            )
            
            
            50,824,031
            
            
            $
            580,888
            
            
            
            20,691,495
            
            
            $
            98,040
            
            
            $
            675,179











FOR
THE NINE MONTH PERIOD ENDED SEPTEMBER 30, 2009


($ in thousands, except unit
amounts)





General
              Partner
            
            
            Number
      of
              Common
              Units
            
            
            Common
              Units
            
            
            Number
      of
              Subordinated
              Units
            
            
            Subordinated
              Units
            
            
            TotalBALANCE
      — December 31, 2008
            
            $
            (3,714
            )
            
            
            53,043,767
            
            
            $
            625,590
            
            
            
            20,691,495
            
            
            $
            105,839
            
            
            $
            727,715Net
      loss
            
            
            (1,155
            )
            
            
            —
            
            
            
            (73,137
            )
            
            
            —
            
            
            
            (28,311
            )
            
            
            (102,603
            )Distributions
            
            
            (358
            )
            
            
            —
            
            
            
            (25,348
            )
            
            
            —
            
            
            
            (8,538
            )
            
            
            (34,244
            )Vesting
      of restricted units
            
            
            —
            
            
            
            217,503
            
            
            
            —
            
            
            
            —
            
            
            
            —
            
            
            
            —Units
      returned from escrow
            
            
            —
            
            
            
            (7,065
            )
            
            
            (25
            )
            
            
            —
            
            
            
            —
            
            
            
            (25
            )Units
      issued from escrow
            
            
            —
            
            
            
            849,858
            
            
            
            3,000
            
            
            
            —
            
            
            
            —
            
            
            
            3,000Repurchase
      of common units
            
            
            —
            
            
            
            (9,844
            )
            
            
            (30
            )
            
            
            —
            
            
            
            —
            
            
            
            (30
            )Equity
      based compensation
            
            
            53
            
            
            
            —
            
            
            
            3,601
            
            
            
            —
            
            
            
            1,370
            
            
            
            5,024BALANCE
      — September 30, 2009
            
            $
            (5,174
            )
            
            
            54,094,219
            
            
            $
            533,651
            
            
            
            20,691,495
            
            
            $
            70,360
            
            
            $
            598,837













See
notes to unaudited condensed consolidated financial statements.





7
 Table of Contents





EAGLE
ROCK ENERGY PARTNERS, L.P.


NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL
STATEMENTS







NOTE
1. ORGANIZATION AND DESCRIPTION OF BUSINESS




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





Basis of Presentation and Principles of
Consolidation—The accompanying financial
statements include assets, liabilities and the results of operations of the
Partnership. These unaudited condensed consolidated financial statements should
be read in conjunction with the consolidated financial statements presented in
the Partnership’s annual report on Form 10-K for the year ended
December 31, 2008. That report contains a more comprehensive summary of the
Partnership’s major accounting policies. In the opinion of management, the
accompanying unaudited condensed consolidated financial statements contain all
appropriate adjustments, all of which are normally recurring adjustments unless
otherwise noted, considered necessary to present fairly the financial position
of the Partnership and its consolidated subsidiaries and the results of
operations and cash flows for the respective periods. Operating results for the
three and nine-month periods ended September 30, 2009 are not necessarily
indicative of the results that may be expected for the year ending
December 31, 2009.





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




NOTE
2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES




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





The
preparation of financial statements in conformity with accounting principles
generally accepted in the United States of America requires management to make
estimates and assumptions that affect the reported amounts of assets and
liabilities and disclosure of contingent assets and liabilities at the date of
the financial statements and the reported amounts of revenues and expenses
during the reported period. Significant estimates are required for proved oil
and natural gas reserves, which can affect the carrying value of oil and natural
gas properties. We evaluate our estimates and assumptions on a regular basis. We
base our estimates on historical experience and various other assumptions that
are believed to be reasonable under the circumstances, the results of which form
the basis for making judgments about the carrying values of assets and
liabilities that are not readily apparent from other sources. Actual results
could differ from those estimates and such differences could be
material.





The
Partnership has provided a discussion of significant accounting policies in its
annual report on Form 10-K for the year ended December 31, 2008. Certain
items from that discussion are repeated or updated below as necessary to assist
in understanding these financial statements.




Oil
and Natural Gas Accounting Policies





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





Depletion of
proved oil and natural gas properties is recorded based on units of production.
Unit rates are computed for unamortized drilling and development costs using
proved developed reserves and for acquisition costs using all proved
reserves.





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





Unproved
properties that are individually insignificant are
amortized.  Unproved properties that are individually significant are
assessed for impairment on a property-by-property basis.  If
considered impaired, costs are charged to expense when such impairment is deemed
to have occurred.




Impairment
of Oil and Natural Gas Properties





The
Partnership reviews its proved properties at the field level when management
determines that events or circumstances indicate that the recorded carrying
value of the properties may not be recoverable. Such events include a projection
of future oil and natural gas reserves that will be produced from a field, the
timing of this future production, future costs to produce the oil and natural
gas, and future inflation levels. If the carrying amount of an asset exceeds the
sum of the undiscounted estimated future net cash flows, the Partnership
recognizes impairment expense equal to the difference between the carrying value
and the fair value of the asset, which is estimated to be the expected present
value of discounted future net cash flows from proved reserves utilizing the
Partnership’s estimated weighted average cost of capital.  In
connection with the preparation of these financial statements for the nine
months ended September 30, 2009, the Partnership recorded impairment charges of
$0.2 million in its Upstream Segment as a result of a continued decline in
natural gas prices during the period and an impairment of $0.3 million in its
Minerals Segment as a result of a decline in natural gas prices and a slight
reduction in oil reserves based on updated production performance during the
period.  The Upstream Segment impairment charges related specifically
to the three months ended March 31, 2009, and the Minerals Segment impairment
charges related specifically to the three months ended September 30,
2009.  The Partnership did not incur any impairment charges related to
its Upstream or Minerals Segments’ oil and natural gas properties during the
three and nine months ended September 30, 2008.   The Partnership
cannot predict the amount of additional impairment charges that may be recorded
in the future.




Other
Significant Accounting Policies





Transportation and Exchange
Imbalances—In the course of transporting natural gas and natural gas
liquids for others, the Partnership’s Midstream Business may receive for
redelivery different quantities of natural gas or natural gas liquids than the
quantities actually delivered. These transactions result in transportation and
exchange imbalance receivables or payables which, if not subject to cash out
provisions, are recovered or repaid through the receipt or delivery of natural
gas or natural gas liquids in future periods. Imbalance receivables are included
in accounts receivable; imbalance payables are included in accounts payable on
the unaudited condensed consolidated balance sheets and marked-to-market using
current market prices in effect for the reporting period of the outstanding
imbalances. For the Midstream Business, as of September 30, 2009, the
Partnership had imbalance receivables totaling $0.2 million and imbalance
payables totaling $3.1 million, respectively. For the Midstream Business, as of
December 31, 2008, the Partnership had imbalance receivables totaling $0.3
million and imbalance payables totaling $2.8 million, respectively. Changes in
market value and the settlement of any such imbalance at a price greater than or
less than the recorded imbalance results in either an upward or downward
adjustment, as appropriate, to the cost of natural gas and natural gas liquids
sold.




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





Subsequent Events— The Partnership
has evaluated all events subsequent to the balance sheet date of September 30,
2009 through the date of issuance, November 9, 2009.




8
 Table of Contents





NOTE
3. NEW ACCOUNTING PRONOUNCEMENTS





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





In December
2007, the FASB issued authoritative guidance to require 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.  The guidance 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.  The guidance amends previous guidancesuch that adjustments
made to valuation allowances on deferred taxes and acquired tax contingencies
associated with acquisitions that closed prior to the effective date of the
amended guidance would also apply the provisions of such
guidance.  The guidance was effective for the Partnership as of
January 1, 2009 but the impact of the adoption on the Partnership’s consolidated
financial statements will depend on the nature and the extent of business
combinations occurring after January 1, 2009.





In December
2007, the FASB issued authoritative guidance which requires that accounting and
reporting for minority interests will be recharacterized as noncontrolling
interests and classified as a component of equity. The guidance 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 guidance was effective for the Partnership as of January 1,
2009 and did not have a material impact on its consolidated results of
operations or financial position as the Partnership has no noncontrolling
interests.





In February
2008, the FASB issued authoritative guidance that permitted the delayed
application of fair value measurement 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.  Non-financial assets and
liabilities that the Partnership measures at fair value on a non-recurring basis
consists primarily of property, plant and equipment, and intangible assets,
which are subject to fair value adjustments in certain circumstances (for
example, when there is evidence of impairment).





In March
2008, the FASB issued authoritative guidance requiring 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. The guidance was effective for the Partnership as
of January 1, 2009.  See Note 11 for the additional disclosures
required related to the Partnership’s derivative instruments.





In March
2008, the FASB approved authoritative guidance which requires that master
limited partnerships use the two-class method of allocating earnings to
calculate earnings per unit. This guidance is effective for fiscal years
and interim periods beginning after December 15, 2008.  The
guidance was effective for the Partnership as of January 1, 2009 and the
impact on its earnings per unit calculation has been retrospectively applied to
September 30, 2008 (see Note 16).




In April
2008, the FASB issued authoritative guidance which amends the factors that
should be considered in developing renewal or extension assumptions used to
determine the useful life of a recognized intangible asset.  The intent of
guidance is to improve the consistency between the useful life of a recognized
intangible asset and the period of expected cash flows used to measure the fair
value of the asset.  This guidance must be applied prospectively to
intangible assets acquired after the effective date.  The guidance was
effective for the Partnership as of January 1, 2009 but the impact of the
adoption on the Partnership’s consolidated financial statements will depend on
the nature and the extent of business combinations occurring after January 1,
2009.





In June 2008,
the FASB issued authoritative guidance which 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.  This guidance is effective for fiscal years beginning after
December 15, 2008 and earnings-per-unit calculations would need to be adjusted
retroactively.  The guidance was effective for the Partnership as of
January 1, 2009 and the impact on its earnings per unit calculation has been
retrospectively applied to September 30, 2008. (See Note 16).




In December
2008, the SEC released Final Rule, Modernization of Oil and Gas Reporting to
revise the existing Regulation S-K and Regulation S-X reporting requirements to
align with current industry practices and technological advances. The new
disclosure requirements include provisions that permit the use of new
technologies to determine proved reserves if those technologies have been
demonstrated empirically to lead to reliable conclusions about reserve volumes.
In addition, the new disclosure requirements require a company to (a) disclose
its internal control over reserves estimation and report the independence and
qualification of its reserves preparer or auditor, (b) file reports when a third
party is relied upon to prepare reserves estimates or conducts a reserve audit
and (c) report oil and gas reserves using an average price based upon the prior
12-month period rather than period-end prices. The provisions of this final
ruling will become effective for disclosures in the Partnership’s Annual Report
on Form 10-K for the year ending December 31, 2009.  The adoption of
the Final Rule, Modernization of Oil and Gas Reporting revision to Regulation
S-K and Regulations S-X is not expected to have a material impact on the
Partnership’s consolidated financial statements.





In April
2009, the FASB issued authoritative guidance amending the other-than-temporary
impairment guidance for debt securities to make the guidance more operational
and to improve the presentation and disclosure of other-than-temporary
impairments in the financial statements. The most significant change is a
revision to the amount of other-than-temporary loss of a debt security recorded
in earnings under certain circumstances.  This guidance was effective
for the Partnership as of June 30, 2009 and did not have a material impact on
its consolidated financial statements.





In April
2009, the FASB issued authoritative guidance which provides additional guidance
for estimating fair value when the volume and level of activity for the asset or
liability have significantly decreased.  The guidance also includes
guidance on identifying circumstances that indicate a transaction is not orderly
and emphasizes that even if there has been a significant decrease in the volume
and level of activity for the asset or liability and regardless of the valuation
technique(s) used, the objective of a fair value measurement remains the same.
Fair value is the price that would be received to sell an asset or paid to
transfer a liability in an orderly transaction (that is, not a forced
liquidation or distressed sale) between market participants at the measurement
date under current market conditions.  This guidance was effective for
the Partnership as of June 30, 2009 and did not have a material impact on its
consolidated financial statements.





In April
2009, the FASB issued authoritative guidance to require disclosures about fair
value of financial instruments for interim reporting periods of publicly traded
companies as well as in annual financial statements.  The guidance
also requires those disclosures in summarized financial information at interim
reporting periods. The guidance was effective for the Partnership as of June 30,
2009.  (See Note 10).




In April
2009, the FASB issued authoritative guidance which amended and clarified
previous guidance with respect to contingencies.  The guidance provides
that an acquirer shall recognize at fair value, at the acquisition date, an
asset acquired or a liability assumed in a business combination that arises from
a contingency if the acquisition-date fair value of that asset or liability can
be determined during the measurement period.  If the acquisition-date fair
value of an asset acquired or a liability assumed in a business combination that
arises from a contingency cannot be determined using the measurement period, the
previous guidance shall apply.”  This guidance was effective for the
Partnership as of January 1, 2009 but the impact of the adoption on the
Partnership’s consolidated financial statements will depend on the nature and
the extent of business combinations occurring after January 1,
2009.





In May 2009,
the FASB issued authoritative guidance which provides guidance on the
Partnership’s assessment of subsequent events. Historically, the Partnership has
relied on U.S. auditing literature for guidance on assessing and disclosing
subsequent events.  The guidance clarifies that the Partnership must
evaluate, as of each reporting period, events or transactions that occur after
the balance sheet date “through the date that the financial statements are
issued or are available to be issued.” The Partnership must perform its
assessment for both interim and annual financial reporting periods
prospectively.  The guidance was effective for the Partnership as of
June 30, 2009 but the impact of the adoption will depend on the nature and the
extent of transactions that occur subsequent to our interim and annual reporting
periods.





9
 Table of Contents





In June 2009,
the FASB issued authoritative guidance which reflects the FASB’s response to
issues entities have encountered when applying previous guidance.  In
addition, this guidance addresses concerns expressed by the SEC, members of the
United States Congress, and financial statement users about the accounting and
disclosures required in the wake of the subprime mortgage crisis and the
deterioration in the global credit markets.  In addition, because this
guidance eliminates the exemption from consolidation for qualified
special-purpose entities (“QSPEs”) a transferor will need to evaluate all
existing QSPEs to determine whether they must be
consolidated.   The guidance is effective for financial asset
transfers occurring after the beginning of an entity’s first fiscal year that
begins after November 15, 2009.  Early adoption of is
prohibited.   The Partnership is currently evaluating the
potential impact, if any, of the adoption of this guidance on its financial
statements.





In June 2009,
the FASB issued authoritative guidance, which amends the consolidation guidance
applicable to variable interest entities (VIEs). The amendments will
significantly affect the overall consolidation analysis.  While the
FASB’s discussions leading up to the issuance of this guidance focused
extensively on structured finance entities, the amendments to the consolidation
guidance affect all entities and enterprises, as well as qualifying
special-purpose entities (QSPEs) that were excluded from previous
guidance.  Accordingly, an enterprise will need to carefully
reconsider its previous conclusions, including (1) whether an entity is a VIE,
(2) whether the enterprise is the VIE’s primary beneficiary, and (3) what type
of financial statement disclosures are required.  This guidance is
effective as of the beginning of the first fiscal year that begins after
November 15, 2009, and early adoption is prohibited.  The Partnership
is currently evaluating the potential impact, if any, of the adoption on its
financial statements.





In June 2009,
the FASB established the FASB Accounting Standards Codification (“ASC”) as the
single source of authoritative U.S. generally accepted accounting principles
(“U.S. GAAP”) recognized by the FASB to be applied by nongovernmental
entities.  Rules and interpretive releases of the United States
Securities and Exchange Commission (“SEC”) under authority of federal securities
laws are also sources of authoritative U.S. GAAP for SEC registrants.  The
Codification did not have a material impact on the Partnership’s consolidated
financial statements upon adoption.  Accordingly, the Partnership’s notes
to consolidated financial statements will explain accounting concepts rather
than cite the topics of specific U.S. GAAP.





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





In September
2009, the FASB issued an amendment to authoritative guidance to address the need
for additional implementation guidance on accounting for uncertainty in income
taxes and to specifically address the following questions, (1) is income tax
paid by the entity attributable to the entity or its owners, (2) what
constitutes a tax position for a pass-through entity or a tax-exempt
not-for-profit entity and (3) how should accounting for uncertainty in income
taxes be applied when a group of related entities comprise both taxable and
nontaxable entities.  This amendment is effective for interim and
annual periods ended after September 15, 2009.  The adoption of this
guidance had no material impact on the Partnership’s financial
statements.




NOTE 4. ACQUISITIONS




2008
Acquisitions





Update on Millennium
Acquisition.   With respect to the South Louisiana assets
acquired in the acquisition of Millennium Midstream Partners, L.P. (“MMP”), the
Yscloskey and North Terrebonne facilities were flooded with three to four feet
of water as a result of the storm surges caused by Hurricanes Gustav and/or Ike
in August and September 2008, respectively. The North Terrebonne facility
came back on-line in November 2008 and the Yscloskey facility came back on-line
in January 2009.  The Partnership received a partial payment for business
interruption caused by Hurricanes Gustav and Ike of approximately $1.6 million,
which was recognized as other revenue during the three months ended June 30,
2009. The former owners of MMP provided the Partnership indemnity coverage for
Hurricanes Gustav and Ike to the extent losses are not covered by insurance and
established an escrow account of 1,818,182 common units and $0.6 million in cash
available for the Partnership to recover against for this purpose and for
settlement of other purchase price adjustments.  As of December 31,
2008, the escrow account held 1,777,302 common units and $0.3 million in
cash.  During the nine months ended September 30, 2009, the
Partnership recovered 534,137 common units, the majority of which was on account
of the purchase price adjustment, and the remaining $0.3 million in cash from
the escrow account.  In addition, during the nine months ended
September 30, 2009, the Partnership received $0.1 million representing the
distribution for the fourth quarter of 2008 that was paid into escrow on 342,609
of those units, per an arrangement with the sellers that the fourth quarter 2008
distribution on certain units cancelled as part of the purchase price adjustment
should be returned to the Partnership upon cancellation.  During the
three months ended September 30, 2009, the 849,858 units were released out of
escrow to the former owners of MMP on account of satisfaction of agreed-upon
conditions for an early-release.  These units were accounted for as
additional purchase price of $3.0 million.  As of September 30, 2009,
the escrow account held 393,307 common units which are available for claims by
the Partnership and will not be available for release to the former owners of
MMP until April 1, 2010.  On October 8, 2009, the Partnership
recovered an additional 2,003 common units from the escrow account.





During the
three months ended September 30, 2009, the Partnership finalized its purchase
price allocations with respect to its Millennium Acquisition.  As of
September 30, 2009, the total purchase price was $210.6 million.  With
respect to the Millennium Acquisition, during the three months ended September
30, 2009, the Partnership decreased the amount assumed for the environmental
liability by $0.5 million and increased the amount of other liabilities assumed
by $0.5 million and decreased accounts receivable by $1.9 million, while it
increased the amount allocated to property, plant and equipment and intangibles
by $4.7 million, $0.7 million and $1.3 million, respectively.





Update on Stanolind Acquisition.During the three months ended June 30, 2009, the Partnership finalized
its purchase price allocations with respect to its acquisition of Stanolind Oil
and Gas Corp. (“Stanolind”).  With respect to the Stanolind
Acquisition, during the three months ended June 30, 2009, the Partnership
decreased the amount assumed for the environmental liability by $1.3 million,
reduced the deferred tax liability by $2.6 million and finalized the acquired
working capital balances, which resulted in a decrease to the amount allocated
to proved properties of $2.8 million and a decrease to the amount allocated to
unproved properties of $0.5 million.




10
 Table of Contents





NOTE
5. FIXED ASSETS AND ASSET RETIREMENT OBLIGATIONS





Fixed assets
consisted of the following:







September
      30,
              2009
            
            
            December
      31,
              2008($
      in thousands)Land
            
            $
            1,241
            
            
            $
            1,211Plant
            
            
            245,289
            
            
            
            232,219Gathering
      and pipeline
            
            
            682,967
            
            
            
            653,016Equipment
      and machinery
            
            
            20,044
            
            
            
            18,672Vehicles
      and transportation equipment
            
            
            4,219
            
            
            
            3,958Office
      equipment, furniture, and fixtures
            
            
            1,248
            
            
            
            1,023Computer
      equipment
            
            
            6,445
            
            
            
            4,714Corporate
            
            
            126
            
            
            
            126Linefill
            
            
            4,269
            
            
            
            4,269Proved
      properties
            
            
            518,164
            
            
            
            515,452Unproved
      properties
            
            
            72,517
            
            
            
            73,622Construction
      in progress
            
            
            16,094
            
            
            
            39,4981,572,623
            
            
            
            1,547,780Less:
      accumulated depreciation, depletion and amortization
            
            
            (259,237
            )
            
            
            (190,171
            )Net
      fixed assets
            
            $
            1,313,386
            
            
            $
            1,357,609




Depreciation
expense for the three and nine months ended September 30, 2009 and 2008 was
approximately $13.5 million, $40.4 million, $9.8 million and $31.8 million,
respectively. Depletion expense for the three and nine months ended September
30, 2009 and 2008 was approximately $9.4 million, $28.5 million, $14.1 million
and $35.0 million, respectively.  In connection with the preparation
of these financial statements for the nine months ended September 30, 2009, the
Partnership recorded impairment charges related to its Upstream Segment’s proved
property assets of $0.2 million during the three months ended March 31, 2009,
and to its Minerals Segment’s proved property assets of $0.3 million during the
three months ended September 30, 2009.  The Partnership did not incur
any impairment charges during the three and nine months ended September 30,
2008. 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, 2009
and 2008, the Partnership capitalized interest costs of less than $0.1 million,
less than $0.1 million, approximately $0.1 million and approximately $0.5
million, respectively.




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




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





Asset
      retirement obligations—December 31, 2008
            
            $
            19,872Liabilities
      settled
            
            
            (1,058
            )Accretion
      expense
            
            
            914Asset
      retirement obligations—September 30, 2009
            
            $
            19,728





11
 Table of Contents





NOTE
6. INTANGIBLE ASSETS




Intangible Assets—Intangible
assets consist of rights-of-way and easements and acquired customer contracts,
which the Partnership amortizes over the term of the agreement or estimated
useful life. Amortization expense was approximately $5.7 million, $17.3 million,
$4.7 million and $14.0 million for the three and nine months ended September 30,
2009 and 2008, respectively. Estimated aggregate amortization expense for 2009
and each of the four succeeding years is as follows: 2009—$22.9 million;
2010—$21.9 million; 2011—$11.2 million; 2012—$11.2 million; and 2013—$10.1
million. Intangible assets consisted of the following:




September
      30,
              2009
            
            
            December 31,
              2008($
      in thousands)Rights-of-way
      and easements—at cost
            
            $
            86,908
            
            
            $
            85,537Less:
      accumulated amortization
            
            
            (14,104
            )
            
            
            (11,437
            )Contracts
            
            
            123,958
            
            
            
            123,409Less:
      accumulated amortization
            
            
            (57,489
            )
            
            
            (43,303
            )Net
      intangible assets
            
            $
            139,273
            
            
            $
            154,206







The
amortization period for rights-of-ways and easements is 20 years. The
amortization period for contracts range from 5 to 20 years, with an average life
of approximately 10 years as of September 30, 2009.




NOTE
7. LONG-TERM DEBT




As of
September 30, 2009 and December 31, 2008, the Partnership had $774.4 million and
$799.4 million outstanding, respectively, under its revolving credit
facility.  In April 2009, due to a regularly scheduled redetermination
of the Upstream Segment’s borrowing base associated with its proved reserves,
the Partnership’s borrowing base was lowered to $135 million, from $206 million,
as a result of declining commodity prices, including sulfur
prices.  The Partnership announced in October 2009 that its existing
borrowing base of $135 million under its revolving credit facility was
reaffirmed by its commercial lenders in the Partnership’s regularly scheduled
semi-annual borrowing base redetermination. The reaffirmation is effective as of
October 1, 2009, with no additional fees or increases in interest rate spread
incurred.





As of
September 30, 2009, the Partnership was in compliance with the financial
covenants under its revolving credit facility, and the unused capacity available
to the Partnership under the revolving credit facility was approximately $34
million (excluding the commitment from Lehman Brothers), based on the
financialcovenants.  The
Partnership’s compliance with the financial covenants under its revolving credit
facility in 2009 has benefited substantially from the Adjusted EBITDA
contributions of its commodity hedging portfolio.  As currently structured,
the Partnership’s commodity hedges will contribute less to its expected 2010
Adjusted EBITDA due to the lower strike prices on its swaps and floors on both
its crude oil and natural gas hedges.  The Partnership’s ability to
comply with the financial covenants over the next five quarters is uncertain and
will depend upon the Partnership’s ability to reduce debt, enhance its commodity
hedge portfolio or otherwise increase its liquidity, or increase its Adjusted
EBITDA due to a rebound in commodity prices and a related increase in drilling
activity by the producers supplying its Midstream facilities’
volumes.


On August
21, 2009, BBVA Compass Bank purchased certain assets and liabilities of Guaranty
Bank, a wholly-owned subsidiary of Guaranty Financial Group Inc. Guaranty Bank
has a commitment under Eagle Rock Energy’s revolving credit facility of $30
million, of which approximately $25 million has been previously
funded.  BBVA Compass has notified the Partnership that it will
continue to honor the Guaranty Bank commitment under Eagle Rock’s revolving
credit facility.







NOTE
8. MEMBERS’ EQUITY




At
September 30, 2009, there were 54,094,219 common units (excluding unvested
restricted common units), 20,691,495 subordinated units (all subordinated units
are owned by Holdings) and 844,551 general partner units outstanding. In
addition, there were 793,739 unvested restricted common units
outstanding.





Subordinated
units represent limited partner interests in the Partnership, and holders of
subordinated units exercise the rights and privileges available to unitholders
under the limited partnership agreement. Subordinated units, during the
subordination period, will generally receive quarterly cash distributions only
when the common units have received a minimum quarterly distribution of
$0.3625 per unit and any outstanding arrearages on the common units have
been paid. Subordinated units will convert into common units on a one-for-one
basis when the subordination period ends.  The subordination period
will end on the first day of any quarter beginning after September 30, 2009 in
respect of which, among other things, the Partnership has earned and paid at
least $1.45 (the minimum quarterly distribution on an annualized basis) on each
outstanding limited partner unit and general partner unit for each of the three
consecutive, non-overlapping four quarter periods immediately preceding such
date and any outstanding arrearages on the common units have been
paid.  Alternatively, the subordination period will end on the first
business day after the Partnership earned and paid at least $0.5438 per quarter
(150% of the minimum quarter distribution, or $2.175 on an annualized basis) on
each outstanding limited partner unit and general partner unit for any four
consecutive quarters ending on or after September 30, 2007 and there are no
outstanding arrearages on the common units.  In addition, the subordination
period will end upon the removal of the Partnership’s general partner other than
for cause if the units held by the Partnership’s general partner and its
affiliates are not voted in favor of such removal, at which point all
outstanding common unit arrearages would be extinguished.  For each of
the three months ended March 31, 2009, June 30, 2009 and September 30, 2009, the
Partnership did not pay the full minimum quarterly distribution
amount.  The third quarter 2009 Common Unit Arrearage is $0.3375 per
common unit.  The Cumulative Common Unit Arrearage is expected to increase
to $1.0125 per common unit with the payment of the third quarter 2009
distribution on November 13, 2009.  Both Common Unit Arrearage and
Cumulative Common Unit Arrearage are terms defined in Eagle Rock Energy’s
partnership agreement.





During the
three months ended June 30, 2009, the Partnership recovered and cancelled 7,065
common units that were being held in an escrow account related to its
acquisition of MacLondon Energy, L.P.





During the
three months ended September 30, 2009, the Partnership released 849,858
common units that were previously held in an escrow account related to its
acquisition of Millennium Midstream Partners, L.P. (“MMP”) to the former owners
of MMP.





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





On April 29,
2009, the Partnership declared its first quarter 2009 cash distribution to its
common unitholders of record as of May 11, 2009.  The distribution
amount was $0.025 per common unit, or approximately $1.4 million.  In
addition, pursuant to the terms of the Partnership’s partnership agreement, the
Partnership’s general partner received a distribution of $0.025 per general
partner unit.  The distribution was paid on May 15, 2009.




On
July 29, 2009, the Partnership declared its second quarter 2009 cash
distribution of $0.025 per unit to its general partner (as to its general
partner units) and its common unitholders of record as of August 10,
2009.  The distribution amount was approximately $1.4
million.  The distribution was paid on August 14,
2009.




On
October 28, 2009, the Partnership declared its third quarter 2009 cash
distribution of $0.025 per unit to its general partner (as to its general
partner units) and its common unitholders of record as of November 9,
2009.  The distribution will be paid November 13, 2009.




12
 Table of Contents





NOTE
9. RELATED PARTY TRANSACTIONS





On
July 1, 2006, the Partnership entered into a month-to-month contract for
the sale of natural gas with an affiliate of Natural Gas Partners, under which
the Partnership sells a portion of its gas supply to such
affiliate.  In July 2008, the company to which the Partnership sold
its natural gas was sold by the affiliate of Natural Gas Partners and thus
ceased being a related party.  For the three and nine months ended
September 30, 2008, during which such counterparty was an affiliate, the
Partnership recorded revenues from such affiliate of less than $0.1 million and
$16.0 million respectively.




In addition,
during the three and nine months ended September 30, 2009 and 2008, the
Partnership incurred $1.9 million, $6.6 million, $1.7 million, and $4.7 million,
respectively, in expenses with related parties, of which there was an
outstanding accounts payable balance of $0.6 million and $0.7 million,
respectively, as of September 30, 2009 and December 31, 2008.




Related to
its investments in unconsolidated subsidiaries, during the three and nine months
ended September 30, 2009 and 2008, the Partnership recorded income of $0.2
million, $1.2 million, $0.4 million and $2.9 million, respectively, of which
there was no outstanding account receivable balances as of September 30, 2009
and December 31, 2008.




During the
three and nine months ended September 30, 2009, the Partnership incurred
approximately $0.3 million and $1.0 million, respectively, for services
performed by Stanolind Field Services (“SFS”), which is an entity controlled by
NGP.  As of September 30, 2009, there were less than $0.1 million
outstanding accounts payable balances.





As of
September 30, 2009 and December 31, 2008, Eagle Rock Energy G&P, LLC had
$10.9 million and $4.5 million, respectively, of outstanding checks paid on
behalf of the Partnership. This amount was recorded as Due to Affiliate on the
Partnership’s balance sheet in current liabilities. As the checks are drawn
against Eagle Rock Energy G&P, LLC’s cash accounts, the Partnership
reimburses Eagle Rock Energy G&P, LLC.





The
Partnership is leasing office space from Montierra Minerals & Production,
L.P. (“Montierra”), which is owned by NGP and certain members of the
Partnership’s senior management, including the Chief Executive
Officer.  During the three and nine months ended September 30, 2009,
the Partnership made rental payments of less than $0.1 million.  In
addition, the Partnership was reimbursed by Montierra for services performed by
its employees on behalf of Montierra of less than $0.1 million for both the
three and nine months ended September 30, 2009.  As of September 30,
2009 and December 31, 2008, the Partnership has an outstanding receivable
balance of less than $0.1 million and $0.3 million, respectively, due from
Montierra and an outstanding payable balance of $0.7 million due to
Montierra.




As of
September 30, 2009 and December 31, 2008, the Partnership had an outstanding
receivable balance of $0.9 million and $1.9 million, respectively, due from an
affiliate of NGP.


On September
18, 2009, the Partnership announced that the Board of Directors of the general
partner of the general partner of the Partnership (the “Board of Directors”)
received a letter from Natural Gas Partners VII, L.P. and Natural Gas Partners
VIII, L.P. (collectively with Natural Gas Partners IX, L.P. and other
affiliates, “NGP”) wherein NGP proposed a series of transactions between NGP and
the Partnership.
 On
October 13, 2009, the Partnership announced that its Board of Directors received
a letter from NGP as a follow-up to NGP’s original proposal which included a
term sheet setting forth revised terms and conditions to NGP’s original
proposal.  The revised proposal contemplated, in exchange for a $32.5
million fee payable to NGP, an equity commitment (including a standby equity
commitment to support a public equity offering by the Partnership), a commitment
to purchase its Minerals Business for $145 million subject to a marketed sales
process, the contribution to the Partnership of all outstanding subordinated
units and incentive distribution rights, and an option to acquire its general
partner. The proposal also contemplated a new incentive plan for its
management team.
 
 On October
17, 2009, the Partnership received a proposal from Black Stone Minerals Company,
L.P. (“Black Stone”), which included, among other terms and conditions, an offer
by Black Stone and certain of its co-investors (collectively, “BSMC”) to
purchase its Minerals Business for $157.5 million and to provide a standby
equity investment commitment in support of a public equity offering by the
Partnership.
 
 On November
7, 2009, the Partnership received a joint proposal from NGP and Black Stone that
revises, and serves as a replacement of, each of their respective most recent
individual proposals to the Partnership (the “Joint Proposal”).  The
Joint Proposal contemplates the following, among other things:
 ·
                  a
      commitment by NGP to participate in a portion of, and provide support for
      (“back-stop”), a rights offering and an equity
  offering;
 
 ·
                  a
      commitment by Black Stone to purchase the Partnership's Minerals
      Business for $170 million;
 
 ·
                  an
      assignment to the Partnership of all the Partnership's incentive
      distribution rights and subordinated
units;
 
 ·
                  an
      option in favor of the Partnership to acquire the Partnership’s 844,551
      outstanding general partner units by acquiring all of the outstanding
      equity of the general partner of our general partner and all of the
      limited partner units of its general partner, in exchange for one million
      newly-issued common units; and
 
 ·
                  the
      payment by the Partnership to NGP of a transaction fee, payable at the
      Partnership’s option as $29 million in cash or as some combination of
      cash, common units and/or warrants.
 At
management’s request to the Conflicts Committee of the Board of Directors
("Conflicts Committee"), the new incentives for the management team that were
included in NGP’s prior proposals were not included in the Joint
Proposal.
  Because a
transaction between NGP and the Partnership would be a related-party
transaction, our Board of Directors previously authorized its Conflicts
Committee to review the prior NGP proposals with the Conflicts Committee’s
financial advisors and legal counsel and negotiate same with NGP on behalf of
the Partnership.  Because the Joint Proposal would be a related-party
transaction, the Conflicts Committee is similarly authorized to review the Joint
Proposal with its financial and legal counsel.  The Conflicts
Committee has not yet determined that the Joint Proposal constitutes an
acceptable framework for negotiation of definitive documents.
 
 The
Partnership caution its unitholders that the joint proposal is not binding at
this time, that neither the Board of Directors nor the Conflicts Committee has
made any decision with respect to the joint proposal, and that there can be no
assurance that any definitive documents will be executed or that any transaction
will be approved or consummated.


13
 Table of Contents





NOTE
10. FAIR VALUE OF FINANCIAL INSTRUMENTS




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




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




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




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




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




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




As of
September 30, 2009, the Partnership has recorded its interest rate swaps and
commodity derivative instruments (see Note 11), which includes crude, natural
gas and natural gas liquids (“NGLs”) at fair value. The Partnership has
classified the inputs to measure the fair value of its interest rate swaps,
crude derivatives and natural gas derivatives as Level 2. Because the NGL market
is considered to be less liquid and thinly traded, the Partnership has
classified the inputs related to its NGL derivatives as Level 3.




The
following table discloses the fair value of the Partnership’s derivative
instruments as of September 30, 2009.







Level 1
            
            
            Level 2
            
            
            Level 3
            
            
            Total($
      in thousands)Assets:Crude
      derivatives
            
            $
            —
            
            
            $
            23,590
            
            
            $
            —
            
            
            $
            23,590Natural
      gas derivatives
            
            
            —
            
            
            
            7,348
            
            
            
            —
            
            
            
            7,348NGL
      derivatives
            
            
            —
            
            
            
            —
            
            
            
            610
            
            
            
            610Interest
      rate swaps
            
            
            —
            
            
            
            194
            
            
            
            —
            
            
            
            194Total
            
            $
            —
            
            
            $
            31,132
            
            
            $
            610
            
            
            $
            31,742Liabilities:Crude
      derivatives
            
            $
            —
            
            
            $
            (30,435
            )
            
            $
            —
            
            
            $
            (30,435
            )Natural
      gas derivatives
            
            
            —
            
            
            
            (1,102
            )
            
            
            —
            
            
            
            (1,102
            )NGL
      derivatives
            
            
            —
            
            
            
            —
            
            
            
            (4,462
            )
            
            
            (4,462
            )Interest
      rate swaps
            
            
            —
            
            
            
            (30,395
            )
            
            
            —
            
            
            
            (30,395
            )Total
            
            $
            —
            
            
            $
            (61,932
            )
            
            $
            (4,462
            )
            
            $
            (66,394
            )







As of
September 30, 2009, risk management current and long-term assets in the
unaudited condensed consolidated balance sheet include put premium and other
derivative costs, net of amortization, of $10.1 million and $1.7 million,
respectively.





The
following table sets forth a reconciliation of changes in the fair value of the
NGL derivatives classified as Level 3 in the fair value hierarchy during the
three months ended September 30, 2009 and 2008 (in thousands):





Three
      Months
              Ended
      September 30,2009
            
            
            2008Net
      liability balances as of July
      1
            
            $
            (520
            )
            
            $
            (36,856
            )Settlements
            
            
            (1,029
            )
            
            
            —Transfers
      from Level 3 to Level 2
            
            
            —
            
            
            
            4,931Total
      gains or losses (realized and unrealized)
            
            
            (2,303
            )
            
            
            17,702Net
      liability balances as of September
      30
            
            $
            (3,852
            )
            
            $
            (14,223
            )





14
 Table of Contents


The
following table sets forth a reconciliation of changes in the fair value of the
NGL derivatives classified as Level 3 in the fair value hierarchy for the nine
months ended September 30, 2009 and 2008 (in thousands):








Nine
      Months
              Ended
      September 30,2009
            
            
            2008Net
      asset (liability) balances as of January
      1
            
            $
            14,016
            
            
            $
            (36,695
            )Settlements
            
            
            (1,939
            )
            
            
            —Transfers
      from Level 3 to Level 2
            
            
            —
            
            
            
            15,661Total
      gains or losses (realized and unrealized)
            
            
            (15,929
            )
            
            
            6,811Net
      liability balances as of September
      30
            
            $
            (3,852
            )
            
            $
            (14,223
            )





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





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





The
Partnership recognized a gain of $3.3 million and $17.9 million,
respectively, in the three and nine months ended September 30, 2009 that
are attributable to the change in unrealized gains or losses related to those
assets and liabilities still held at September 30, 2009 which are included in
the unrealized commodity commodity gains (losses).





The following
table discloses the fair value of the Partnership’s assets measured at fair
value on a nonrecurring basis for the nine months ended September 30, 2009 (in
thousands):







September
      30, 2009
            
            
            Level 1
            
            
            Level 2
            
            
            Level 3
            
            
            Total
              LossesImpaired
      proved properties
            
            $
            355
            
            
            $
            —
            
            
            $
            —
            
            
            $
            355
            
            
            $
            516





In connection
with the preparation of these financial statements for the nine months ended
September 30, 2009, the Partnership wrote down proved properties with a carrying
value of $0.8 million to their fair value of $0.3 million, resulting in an
impairment charge of $0.5 million being included in earnings for the nine month
period.  This impairment charge related specifically to a $0.2 million
charge taken in the three months ended March 31, 2009 in the Upstream Segment
and an additional $0.3 million charge taken in the three months ended September
30, 2009 in the Minerals Segment.  The Partnership calculated the fair
value of the impaired proved properties using its proved reserves, estimated
forward prices and an estimated weighted average cost of capital.





The carrying
amount of cash equivalents is believed to approximate their fair values because
of the short maturities of these instruments.  The fair value of
accounts receivable and accounts payable are not materially different from their
carrying amounts because of the short-term nature of these
instruments.




15
 Table of Contents





NOTE
11. RISK MANAGEMENT ACTIVITIES





Interest Rate
Derivative Instruments




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




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





The table
below summarizes the terms, notional amounts and rates to be paid and the fair
values of the various interest swaps as of September 30, 2009:





Roll
      Forward
              Effective
      Date
            
            Expiration
              Date
            
            Notional
              Amount
            
            
            Fixed
              Rate(a)12/31/2008
            
            12/31/2012
            
            $
            150,000,000
            
            
            
            2.360%
      / 2.560
            %09/30/2008
            
            12/31/2012
            
            
            150,000,000
            
            
            
            4.105%
      / 4.295
            %10/03/2008
            
            12/31/2012
            
            
            300,000,000
            
            
            
            3.895%
      / 4.095
            %





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





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





Commodity
Derivative Instruments




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




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




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




The
Partnership has not designated any of its commodity derivative instruments as
hedges and therefore is marking these derivative contracts to fair
value.  Changes in fair values of the commodity derivative instruments
are recorded as an adjustment to the mark-to-market gains (losses) on risk
management transactions within revenue.




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




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









16
 Table of Contents


The following table, as of September 30,
2009, sets forth certain information regarding our commodity derivatives that
will mature during the year ended December 31, 2009 (excluding transactions
and volumes that settled or were unwound during the nine months ended September
30, 2009):




Underlying
            
            Period
            
            Total
              Notional
              Volumes
              (units)
            
            Type
            
            Floor
              Strike
              Price
              ($/unit)
            
            
            Cap
              Strike
              Price
              ($/unit)Natural
      Gas:IF
      Waha
            
            Oct-Dec
      2009
            
            60,000
      mmbtu
            
            Costless
      Collar
            
            
            7.50
            
            
            
            8.90NYMEX
      Henry Hub
            
            Oct-Dec
      2009
            
            40,000
      mmbtu
            
            Costless
      Collar
            
            
            6.25
            
            
            
            11.20NYMEX
      Henry Hub
            
            Oct-Dec
      2009
            
            170,000
      mmbtu
            
            Costless
      Collar
            
            
            7.85
            
            
            
            9.25NYMEX
      Henry Hub
            
            Oct-Dec
      2009
            
            170,000
      mmbtu
            
            Swap
            
            
            8.35NYMEX
      Henry Hub
            
            Oct-Dec
      2009
            
            140,000
      mmbtu
            
            Swap
            
            
            6.685NYMEX
      Henry Hub
            
            Oct-Dec
      2009
            
            140,000
      mmbtu
            
            Swap
            
            
            6.885Crude
      Oil:NYMEX
      WTI
            
            Oct-Dec
      2009
            
            18,000
      bbls
            
            Costless
      Collar
            
            
            60.00
            
            
            
            77.00NYMEX
      WTI
            
            Oct-Dec
      2009
            
            15,000
      bbls
            
            Costless
      Collar
            
            
            93.00
            
            
            
            100.85NYMEX
      WTI
            
            Oct-Dec
      2009
            
            21,000
      bbls
            
            Put
            
            
            90.00NYMEX
      WTI
            
            Oct-Dec
      2009
            
            15,000
      bbls
            
            Put
            
            
            100.00NYMEX
      WTI
            
            Oct-Dec
      2009
            
            75,000
      bbls
            
            Swap
            
            
            71.25NYMEX
      WTI
            
            Oct-Dec
      2009
            
            150,000
      bbls
            
            Swap
            
            
            100.00NYMEX
      WTI (1)
            
            Oct-Dec
      2009
            
            180,000
      bbls
            
            Swap
            
            
            97.00Natural
      Gas Liquids:OPIS
      Ethane Mt Belv non TET
            
            Oct-Dec
      2009
            
            1,260,000 gallons
            
            Costless
      Collar
            
            
            0.48
            
            
            
            0.58OPIS
      Ethane Mt Belv non TET
            
            Oct-Dec
      2009
            
            1,260,000 gallons
            
            Swap
            
            
            0.53OPIS
      Ethane Mt Belv non TET
            
            Oct-Dec
      2009
            
            3,150,000 gallons
            
            Swap
            
            
            0.6361OPIS
      IsoButane Mt Belv non TET
            
            Oct-Dec
      2009
            
            315,000
      gallons
            
            Costless
      Collar
            
            
            0.935
            
            
            
            1.035OPIS
      IsoButane Mt Belv non TET
            
            Oct-Dec
      2009
            
            315,000
      gallons
            
            Swap
            
            
            0.985OPIS
      IsoButane Mt Belv non TET
            
            Oct-Dec
      2009
            
            368,676
      gallons
            
            Swap
            
            
            1.295OPIS
      NButane Mt Belv non TET
            
            Oct-Dec
      2009
            
            693,000
      gallons
            
            Costless
      Collar
            
            
            0.935
            
            
            
            1.035OPIS
      NButane Mt Belv non TET
            
            Oct-Dec
      2009
            
            693,000
      gallons
            
            Swap
            
            
            0.985OPIS
      NButane Mt Belv non TET
            
            Oct-Dec
      2009
            
            732,732
      gallons
            
            Swap
            
            
            1.2775OPIS
      Propane Mt Belv non TET
            
            Oct-Dec
      2009
            
            1,323,000 gallons
            
            Costless
      Collar
            
            
            0.765
            
            
            
            0.815OPIS
      Propane Mt Belv non TET
            
            Oct-Dec
      2009
            
            1,323,000 gallons
            
            Swap
            
            
            0.815OPIS
      Propane Mt Belv non TET
            
            Oct-Dec
      2009
            
            1,890,000 gallons
            
            Swap
            
            
            1.0925OPIS
      Propane Mt Belv non TET
            
            Oct-Dec
      2009
            
            542,556
      gallons
            
            Swap
            
            
            1.0775OPIS
      Propane Mt Belv non TET
            
            Oct-Dec
      2009
            
            481,194
      gallons
            
            Swap
            
            
            1.0875







(1)
            6,000
      barrels of this “in-the-money” swap were “unwound” as part of the October
      8, 2009 hedge transactions.  Also as part of an October 8, 2009
      hedge transaction, 114,000 barrels were reset from $97.00 to $135.00 for
      the months of November and December of 2009.See
      additional discussion of the October 8, 2009 transaction below.




During the
nine months ended September 30, 2009, the Partnership entered into the following
derivative transactions for the 2010 calendar year: a 125,000 MMBtu per month
Henry Hub natural gas swap at $6.65 per MMBtu on January 19, 2009, a 170,000
MMBtu per month Henry Hub natural gas swap at $6.14 per MMBtu on February 17,
2009, a 45,000 barrel per month WTI crude oil swap at $53.55 per barrel on
February 17, 2009 and a 40,000 barrel per month WTI crude oil swap at $51.40 per
barrel on February 19, 2009.




17
 Table of Contents


The following
table, as of September 30, 2009, sets forth certain information regarding our
commodity derivatives that will mature during the year ended December 31,
2010:





Underlying
            
            Period
            
            Total
              Notional
              Volumes
              (units)
            
            Type
            
            Floor
              Strike
              Price
              ($/unit)
            
            
            Cap
              Strike
              Price
              ($/unit)Natural
      Gas:NYMEX
      Henry Hub
            
            Jan-Dec
      2010
            
            1,320,000
      mmbtu
            
            Costless
      Collar
            
            $
            7.70
            
            
            $
            9.10NYMEX
      Henry Hub
            
            Jan-Dec
      2010
            
            1,500,000 mmbtu
            
            Swap
            
            
            6.65NYMEX
      Henry Hub
            
            Jan-Dec
      2010
            
            2,040,000 mmbtu
            
            Swap
            
            
            6.14Crude
      Oil:NYMEX
      WTI
            
            Jan-Dec
      2010
            
            60,000
      bbls
            
            Costless
      Collar
            
            
            50.00
            
            
            
            67.50NYMEX
      WTI
            
            Jan-Dec
      2010
            
            60,000
      bbls
            
            Costless
      Collar
            
            
            50.00
            
            
            
            68.00NYMEX
      WTI
            
            Jan-Dec
      2010
            
            108,000
      bbls
            
            Costless
      Collar
            
            
            90.00
            
            
            
            99.80NYMEX
      WTI
            
            Jan-Dec
      2010
            
            180,000
      bbls
            
            Costless
      Collar
            
            
            50.00
            
            
            
            67.50NYMEX
      WTI
            
            Jan-Dec
      2010
            
            180,000
      bbls
            
            Costless
      Collar
            
            
            50.00
            
            
            
            68.30NYMEX
      WTI
            
            Jan-Dec
      2010
            
            60,000
      bbls
            
            Put
            
            
            100.00NYMEX
      WTI
            
            Jan-Dec
      2010
            
            72,000
      bbls
            
            Put
            
            
            90.00NYMEX
      WTI
            
            Jan-Dec
      2010
            
            120,000
      bbls
            
            Swap
            
            
            78.35NYMEX
      WTI
            
            Jan-Dec
      2010
            
            300,000
      bbls
            
            Swap
            
            
            70.00NYMEX
      WTI(1)
            
            Jan-Dec
      2010
            
            540,000
      bbls
            
            Swap
            
            
            53.55NYMEX
      WTI
            
            Jan-Dec
      2010
            
            480,000
      bbls
            
            Swap
            
            
            51.40Natural
      Gas Liquids:OPIS
      Ethane Mt Belv non TET
            
            Jan-Dec
      2010
            
            4,536,000 gallons
            
            Costless
      Collar
            
            
            0.43
            
            
            
            0.53OPIS
      Ethane Mt Belv non TET
            
            Jan-Dec
      2010
            
            4,536,000 gallons
            
            Swap
            
            
            0.58OPIS
      IsoButane Mt Belv non TET
            
            Jan-Dec
      2010
            
            2,520,000 gallons
            
            Costless
      Collar
            
            
            0.82
            
            
            
            1.02OPIS
      IsoButane Mt Belv non TET
            
            Jan-Dec
      2010
            
            5,544,000 gallons
            
            Costless
      Collar
            
            
            0.82
            
            
            
            1.02OPIS
      IsoButane Mt Belv non TET
            
            Jan-Dec
      2010
            
            5,040,000 gallons
            
            Costless
      Collar
            
            
            0.705
            
            
            
            0.81OPIS
      IsoButane Mt Belv non TET
            
            Jan-Dec
      2010
            
            5,040,000 gallons
            
            Swap
            
            
            0.755







(1)
            On
      November 2, 2009, 135,000 barrels were reset from $53.55 to $95.00 for the
      months of January, February and March 2010.See
      additional discussion of the November 2, 2009 transaction below.




During the
nine months ended September 30, 2009, the Partnership entered into the following
derivative transactions for its 2011 calendar year: a 30,000 barrel per month
NYMEX WTI swap at $65.60 per barrel on March 31, 2009, a 10,000 barrel per month
NYMEX WTI swap at $65.10 per barrel on April 1, 2009, a 20,000 barrel per month
NYMEX WTI swap at $75.00 per barrel on June 1, 2009, a 20,000 barrel per month
NYMEX WTI swap at $80.05 per barrel on June 9, 2009, a 60,000 MMBtu per month
HENRY HUB swap at $7.085 per MMBtu on June 9, 2009 and a 190,000 MMBtu per month
Henry Hub swap at $6.57 per MMBtu on July 30, 2009.


18
 Table of Contents


The following
table, as of September 30, 2009, sets forth certain information regarding our
commodity derivatives that will mature during the year ended December 31,
2011:





Underlying
            
            Period
            
            Total
              Notional
              Volumes
              (units)
            
            Type
            
            Floor
              Strike
              Price
              ($/unit)
            
            
            Cap
              Strike
              Price
              ($/unit)Natural
      Gas:NYMEX
      Henry Hub
            
            Jan-Dec
      2011
            
            1,200,000 mmbtu
            
            Costless
      Collar
            
            $
            7.50
            
            
            $
            8.85NYMEX
      Henry Hub
            
            Jan-Dec
      2011
            
            720,000
      mmbtu
            
            Swap
            
            
            7.085NYMEX
      Henry Hub
            
            Jan-Dec
      2011
            
            2,280,000
      mmbtu
            
            Swap
            
            
            6.57Crude
      Oil:NYMEX
      WTI(1)
            
            Jan-Dec
      2011
            
            139,152
      bbls
            
            Costless
      Collar
            
            
            75.00
            
            
            
            85.70NYMEX
      WTI(2)
            
            Jan-Dec
      2011
            
            125,256
      bbls
            
            Swap
            
            
            80.00NYMEX
      WTI
            
            Jan-Dec
      2011
            
            360,000
      bbls
            
            Swap
            
            
            65.60NYMEX
      WTI
            
            Jan-Dec
      2011
            
            120,000
      bbls
            
            Swap
            
            
            65.10NYMEX
      WTI
            
            Jan-Dec
      2011
            
            240,000
      bbls
            
            Swap
            
            
            75.00NYMEX
      WTI
            
            Jan-Dec
      2011
            
            240,000
      bbls
            
            Swap
            
            
            80.05





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


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





During the
nine months ended September 30, 2009, the Partnership entered into the following
derivative transactions for its 2012 calendar year: a 20,000 barrel per month
NYMEX WTI swap at $68.30 per barrel on April 1, 2009, a 20,000 barrel per month
NYMEX WTI swap at $76.50 per barrel on June 1, 2009, a 20,000 barrel per month
NYMEX WTI swap at $82.02 per barrel on June 9, 2009 and a 260,000 MMBtu per
month Henry Hub swap at $6.77 per MMBtu on July 30, 2009.




The following table, as of September 30,
2009, sets forth certain information regarding our commodity derivatives that
will mature during the year ended December 31, 2012:




Underlying
            
            Period
            
            Total
              Notional
              Volumes
              (units)
            
            Type
            
            Floor
              Strike
              Price
              ($/unit)
            
            
            Cap
              Strike
              Price
              ($/unit)Natural
      Gas:NYMEX
      Henry Hub
            
            Jan-Dec
      2012
            
            1,080,000
      mmbtu
            
            Costless
      Collar
            
            $
            7.35
            
            
            $
            8.65NYMEX
      Henry Hub
            
            Jan-Dec
      2012
            
            3,120,000 mmbtu
            
            Swap
            
            
            6.77Crude
      Oil:NYMEX
      WTI(1)
            
            Jan-Dec
      2012
            
            135,576
      bbls
            
            Costless
      Collar
            
            
            75.30
            
            
            
            86.30NYMEX
      WTI(2)
            
            Jan-Dec
      2012
            
            108,468
      bbls
            
            Swap
            
            
            68.30NYMEX
      WTI
            
            Jan-Dec
      2012
            
            240,000
      bbls
            
            Swap
            
            
            80.30NYMEX
      WTI
            
            Jan-Dec
      2012
            
            240,000
      bbls
            
            Swap
            
            
            76.50NYMEX
      WTI
            
            Jan-Dec
      2012
            
            240,000
      bbls
            
            Swap
            
            
            82.02





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


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





On October 8,
2009, the Partnership unwound a portion of an “in-the-money” 2009 WTI crude oil
swap and reset the remaining portion.  For the first part of the
transaction, the Partnership bought 3,000 barrels per month for the months of
November and December of 2009, for which the Partnership received $0.1 million
from the counterparty.  For the second part of the transaction, the
Partnership reset, from $97.00 to $135.00, the swap price for the remaining
57,000 barrels a month for the months of November and December of 2009, for
which the Partnership paid the counterparty $4.3 million.




On October
22, 2009, the Partnership entered into a 30,000 barrel per month WTI crude oil
costless collar with a floor of $80.00 and a cap of $92.40 for the 2011 calendar
year and a 30,000 barrel per month WTI crude oil costless collar with a floor of
$80.00 and a cap of $98.50 for the 2012 calendar year.




On November
2, 2009, the Partnership reset a 2010 WTI crude oil swap, from $53.55 to $95.00,
the swap price for 45,000 barrels a month for the months of January, February
and March 2010, for which the Partnership paid the counterparty $5.7
million.




19
 Table of Contents


Fair Value of
Interest Rate and Commodity Derivatives




Fair values
of interest rate and commodity derivative instruments not designated as hedging
instruments in the unaudited condensed consolidated balance sheet as of
September 30, 2009 and December 31, 2008:




Derivative
      Assets
            
            Derivative
      LiabilitiesSeptember
      30, 2009
            
            December
      31, 2008
            
            September
      30, 2009
            
            December
      31, 2008Balance
              Sheet
              Location
            
            Fair
      Value
            
            Balance
              Sheet
              Location
            
            Fair
      Value
            
            Balance
              Sheet
              Location
            
            Fair
      Value
            
            Balance
              Sheet
              Location
            
            Fair
      Value($
      in thousands)Interest
      rate derivatives – assets
            Long-term
      assets
            
            $
            194
            
            
            
            $
            —
            
            
            
            $
            —
            
            
            
            $
            —Interest
      rate derivatives – liabilities
            
            
            
            —
            
            
            
            
            —
            
            Current
      liabilities
            
            
            (16,048
            )
            Current
      liabilities
            
            
            (13,763
            )Interest
      rate derivatives – liabilities
            
            
            
            —
            
            
            
            
            —
            
            Long-term
      liabilities
            
            
            (14,347
            )
            Long-term
      liabilities
            
            
            (26,182
            )Commodity
      derivatives – assets
            Current
      assets
            
            
            26,017
            
            Current
      assets
            
            
            77,603
            
            
            
            
            —
            
            
            
            
            —Commodity
      derivatives – assets
            Long-term
      assets
            
            
            5,531
            
            Long-term
      assets
            
            
            34,088
            
            
            
            
            —
            
            
            
            
            —Commodity
      derivatives – liabilities
            
            
            
            —
            
            Current
      assets
            
            
            (834
            )
            Current
      liabilities
            
            
            (18,940
            )
            
            
            
            —Commodity
      derivatives – liabilities
            
            
            
            —
            
            Long-term
      assets
            
            
            (1,637
            )
            Long-term
      liabilities
            
            
            (17,059
            )
            
            
            
            —Total
      derivatives
            
            
            $
            31,742
            
            
            
            $
            109,220
            
            
            
            $
            (66,394
            )
            
            
            $
            (39,945
            )









The following
table sets forth the location of gains and losses for derivatives not designated
as hedging instruments within the Partnership’s Unaudited Condensed Consolidated
Statement of Operations:




Location
      of Gain or (Loss) Recognized in Income on
Derivatives
            
            Amount
      of Gain or (Loss) Recognized in Income
              on
      DerivativesThree
      Months Ended
              September
      30,
            
            
            Nine
      Months Ended
              September
      30,2009
            
            
            2008
            
            
            2009
            
            
            2008($
      in thousands)Interest
      rate derivatives
            Interest
      rate risk management losses
            
            $
            (10,348
            )
            
            $
            (2,859
            )
            
            $
            (3,924
            )
            
            $
            (5,375
            )Commodity
      derivatives
            Commodity
      risk management (losses) gains
            
            
            (8,832
            )
            
            
            231,851
            
            
            
            (57,137
            )
            
            
            (97,769
            )Total
            
            
            $
            (19,180
            )
            
            $
            228,992
            
            
            $
            (61,061
            )
            
            $
            (103,144
            )


Our hedge
counterparties are participants in our credit agreement, and the collateral for
the outstanding borrowings under our credit agreement is used as collateral for
our hedges.  We do not have rights to collateral from our
counterparties, nor do we have rights of offset against borrowings under our
credit agreement.


20
 Table of Contents


NOTE
12. COMMITMENTS AND CONTINGENT LIABILITIES




Litigation—The Partnership is
subject to lawsuits which arise from time to time in the ordinary course of
business, such as the interpretation and application of contractual terms
related to the calculation of payment for liquids and natural gas proceeds. The
Partnership’s accruals were approximately $0.1 million as of September 30, 2009
and December 31, 2008 related to these matters. The Partnership has been
indemnified up to a certain dollar amount for certain lawsuits that were assumed
as part of prior acquisitions. If there ultimately is a finding against the
Partnership in the indemnified cases, the Partnership would expect to make a
claim against the indemnification up to the limits of the indemnification. For
these indemnified lawsuits, the Partnership has not established any accruals
because the Partnership considers remote the likelihood of these lawsuits being
successful in amounts in excess of the indemnification limits. These matters are
not expected to have a material adverse effect on our financial position,
results of operations or cash flows.




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





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





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




Environmental—The operation of
pipelines, plants and other facilities for gathering, transporting, processing,
treating, or storing natural gas, NGLs and other products is subject to
stringent and complex laws and regulations pertaining to health, safety and the
environment. As an owner or operator of these facilities, the Partnership must
comply with United States laws and regulations at the federal, state and local
levels that relate to air and water quality, hazardous and solid waste
management and disposal and other environmental matters. The cost of planning,
designing, constructing and operating pipelines, plants, and other facilities
must incorporate compliance with environmental laws and regulations and safety
standards. Failure to comply with these laws and regulations may trigger a
variety of administrative, civil and potentially criminal enforcement measures,
including citizen suits, which can include the assessment of monetary penalties,
the imposition of remedial requirements and the issuance of injunctions or
restrictions on operation. Management believes that, based on currently known
information, compliance with these laws and regulations will not have a material
adverse effect on the Partnership’s combined results of operations, financial
position or cash flows. At September 30, 2009 and December 31, 2008, the
Partnership had accrued approximately $4.9 million and $8.6 million,
respectively, for environmental matters.





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





Subsequent to
December 31, 2008, the Partnership received additional Notices of Enforcement
(“NOEs”) and Notices of Violation (“NOVs”) from the TCEQ related to air
compliance matters.  The Partnership expects to receive additional
NOEs or NOVs from the TCEQ from time to time throughout 2009.  Though
the TCEQ has the discretion to adjust penalties and settlements upwards based on
a compliance history containing multiple, successive NOEs, the Partnership does
not expect that the resolution of any existing NOE or any future similar NOE
will vary significantly from the administrative penalties and agreed settlements
experienced by it to date.


21
 Table of Contents


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





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





Other Commitments—The Partnership
utilizes operating leases for its corporate office, certain rights-of way,
facility locations and vehicles. Rental expense, including leases with no
continuing commitment, amounted to approximately, $1.8 million, $6.0 million,
$1.2 million, and $3.7 million for the three and nine months ended September 30,
2009 and September 30, 2008, respectively. Rental expense for leases with
escalation clauses is recognized on a straight-line basis over the initial lease
term.




NOTE
13. SEGMENTS




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




(i)
            Midstream—Texas
      Panhandle Segment:




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





(ii)
            Midstream—South Texas
      Segment:




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




(iii)
            Midstream—East Texas/Louisiana
      Segment:




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




(iv)
            Midstream—Gulf of Mexico
      Segment:




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




(v)
            Upstream
      Segment:




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




(vi)
            Minerals
      Segment:





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




(vii)
            Corporate
      Segment:




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








22
 Table of Contents


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





Midstream
      Business
              Three
      Months Ended September 30, 2009
            
            Texas
              Panhandle
              Segment
            
            
            South
              Texas
              Segment
            
            
            East Texas /
              Louisiana
              Segment
            
            
            Gulf
      of
              Mexico
            
            
            Total
              Midstream
              Business($
      in thousands)Sales
      to external customers
            
            $
            70,263
            
            
            $
            18,672
            
            
            $
            53,620
            
            
            $
            8,618
            
            
            $
            151,173Cost
      of natural gas and natural gas liquids
            
            
            46,540
            
            
            
            16,842
            
            
            
            39,665
            
            
            
            6,898
            
            
            
            109,945Operating
      costs and other expenses
            
            
            8,206
            
            
            
            896
            
            
            
            4,727
            
            
            
            310
            
            
            
            14,139Depreciation,
      depletion, amortization and impairment
            
            
            11,602
            
            
            
            1,287
            
            
            
            4,458
            
            
            
            1,480
            
            
            
            18,827Operating
      income (loss) from continuing operations
            
            $
            3,915
            
            
            $
            (353
            )
            
            $
            4,770
            
            
            $
            (70
            )
            
            $
            8,262Capital
      Expenditures
            
            $
            1,332
            
            
            $
            27
            
            
            $
            2,094
            
            
            $
            165
            
            
            $
            3,618Segment
      Assets
            
            $
            556,963
            
            
            $
            66,758
            
            
            $
            324,893
            
            
            $
            86,789
            
            
            $
            1,035,403





Total
      Segments
              Three
      Months Ended September 30, 2009
            
            Total
              Midstream
              Business
            
            
            Upstream
              Segment
            
            
            Minerals
              Segment
            
            
            Corporate
              Segment
            
            
            Total
              Segments($
      in thousands)Sales
      to external customers
            
            $
            151,173
            
            
            $
            17,470
            
            
            $
            4,050
            
            
            $
            (8,832
            )(a)
            
            $
            163,861Cost
      of natural gas and natural gas liquids
            
            
            109,945
            
            
            
            —
            
            
            
            —
            
            
            
            —
            
            
            
            109,945Operating
      costs and other expenses
            
            
            14,139
            
            
            
            5,526
            
            
            
            203
            
            
            
            10,449
            
            
            
            30,317Depreciation,
      depletion, amortization and impairment
            
            
            18,827
            
            
            
            7,768
            
            
            
            1,928
            
            
            
            337
            
            
            
            28,860Operating
      income (loss) from continuing operations operations
            
            $
            8,262
            
            
            $
            4,176
            
            
            $
            1,919
            
            
            $
            (19,618
            )
            
            $
            (5,261
            )Capital
      Expenditures
            
            $
            3,618
            
            
            $
            2,780
            
            
            $
            —
            
            
            $
            308
            
            
            $
            6,706Segment
      Assets
            
            $
            1,035,403
            
            
            $
            373,172
            
            
            $
            135,844
            
            
            $
            46,423
            
            
            $
            1,590,842





Midstream
      Business
              Three
      Months Ended September 30, 2008
            
            Texas
              Panhandle
              Segment
            
            
            South
              Texas
              Segment
            
            
            East Texas /
              Louisiana
              Segment
            
            
            Total
              Midstream
              Business($
      in thousands)Sales
      to external customers
            
            $
            182,279
            
            
            $
            36,187
            
            
            $
            80,769
            
            
            $
            299,235Cost
      of natural gas and natural gas liquids
            
            
            138,428
            
            
            
            33,307
            
            
            
            66,007
            
            
            
            237,742Operating
      costs and other expenses
            
            
            9,190
            
            
            
            635
            
            
            
            4,194
            
            
            
            14,019Depreciation,
      depletion, and amortization
            
            
            10,984
            
            
            
            939
            
            
            
            2,989
            
            
            
            14,912Operating
      income from continuing operations
            
            $
            23,677
            
            
            $
            1,306
            
            
            $
            7,579
            
            
            $
            32,562Capital
      Expenditures
            
            $
            7,152
            
            
            $
            201
            
            
            $
            2,591
            
            
            $
            9,944Segment
      Assets
            
            $
            580,553
            
            
            $
            89,604
            
            
            $
            250,910
            
            
            $
            921,067





Total
      Segments
              Three
      Months Ended September 30, 2008
            
            Total
              Midstream
              Business
            
            Upstream
              Segment
            
            
            Minerals
              Segment
            
            
            Corporate
              Segment
            
            Total
              Segments($
      in thousands)Sales
      to external customers
            
            $
            299,235
            
            $
            55,406
            
            
            $
            17,393
            
            
            $
            231,851
            (a)
            $
            603,885Cost
      of natural gas and natural gas liquids
            
            
            237,742
            
            
            —
            
            
            
            —
            
            
            
            —
            
            
            237,742Operating
      costs and other expenses
            
            
            14,019
            
            
            12,394
            
            
            
            427
            
            
            
            13,813
            
            
            40,653Depreciation,
      depletion, and amortization
            
            
            14,912
            
            
            11,170
            
            
            
            2,321
            
            
            
            194
            
            
            28,597Operating
      income (loss) from continuing operations operations
            
            $
            32,562
            
            $
            31,842
            
            
            $
            14,645
            
            
            $
            217,844
            
            $
            296,893Capital
      Expenditures
            
            $
            9,944
            
            $
            4,532
            
            
            $
            —
            
            
            $
            —
            
            $
            14,476Segment
      Assets
            
            $
            921,067
            
            $
            634,512
            
            
            $
            149,380
            
            
            $
            68,102
            
            $
            1,773,061





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





23
 Table of Contents





Midstream
      Business
              Nine
      Months Ended September 30, 2009
            
            Texas
              Panhandle
              Segment
            
            
            South
              Texas
              Segment
            
            
            East Texas /
              Louisiana
              Segment
            
            
            Gulf
      of
              Mexico
            
            
            Total
              Midstream
              Business($
      in thousands)Sales
      to external customers
            
            $
            205,000
            
            
            $
            78,077
            
            
            $
            156,900
            
            
            $
            22,668
            
            
            $
            462,645Cost
      of natural gas and natural gas liquids
            
            
            147,894
            
            
            
            71,730
            
            
            
            121,907
            
            
            
            17,271
            
            
            
            358,802Operating
      costs and other expenses
            
            
            24,407
            
            
            
            2,946
            
            
            
            13,887
            
            
            
            1,386
            
            
            
            42,626Depreciation,
      depletion, amortization and impairment
            
            
            33,660
            
            
            
            3,995
            
            
            
            13,469
            
            
            
            4,445
            
            
            
            55,569Operating
      income (loss) from continuing operations
            
            $
            (961
            )
            
            $
            (594
            )
            
            $
            7,637
            
            
            $
            (434
            )
            
            $
            5,648Capital
      Expenditures
            
            $
            5,042
            
            
            $
            41
            
            
            $
            16,172
            
            
            $
            306
            
            
            $
            21,561Segment
      Assets
            
            $
            556,963
            
            
            $
            66,758
            
            
            $
            324,893
            
            
            $
            86,789
            
            
            $
            1,035,403





Total
      Segments
              Nine
      Months Ended September 30, 2009
            
            Total
              Midstream
              Business
            
            
            Upstream
              Segment
            
            
            Minerals
              Segment
            
            
            Corporate
              Segment
            
            
            Total
              Segments($
      in thousands)Sales
      to external customers
            
            $
            462,645
            
            
            $
            42,757
            
            
            $
            10,788
            
            
            $
            (57,137
            )(a)
            
            $
            459,053Cost
      of natural gas and natural gas liquids
            
            
            358,802
            
            
            
            —
            
            
            
            —
            
            
            
            —
            
            
            
            358,802Operating
      costs and other expenses
            
            
            42,626
            
            
            
            16,264
            
            
            
            972
            
            
            
            34,882
            
            
            
            94,744Depreciation,
      depletion, amortization and impairment
            
            
            55,569
            
            
            
            25,361
            
            
            
            5,055
            
            
            
            768
            
            
            
            86,753Operating
      income (loss) from continuing operations operations
            
            $
            5,648
            
            
            $
            1,132
            
            
            $
            4,761
            
            
            $
            (92,787
            )
            
            $
            (81,246
            )Capital
      Expenditures
            
            $
            21,561
            
            
            $
            6,360
            
            
            $
            —
            
            
            $
            1,732
            
            
            $
            29,653Segment
      Assets
            
            $
            1,035,403
            
            
            $
            373,893
            
            
            $
            135,844
            
            
            $
            46,423
            
            
            $
            1,590,842





Midstream
      Business
              Nine
      Months Ended September 30, 2008
            
            Texas
              Panhandle
              Segment
            
            
            South
              Texas
              Segment
            
            
            East Texas /
              Louisiana
              Segment
            
            
            Total
              Midstream
              Business($
      in thousands)Sales
      to external customers
            
            $
            522,114
            
            
            $
            125,712
            
            
            $
            249,052
            
            
            $
            896,878Cost
      of natural gas and natural gas liquids
            
            
            398,828
            
            
            
            117,635
            
            
            
            209,937
            
            
            
            726,400Operating
      costs and other expenses
            
            
            25,653
            
            
            
            1,862
            
            
            
            11,511
            
            
            
            39,026Depreciation,
      depletion, and amortization
            
            
            32,587
            
            
            
            2,812
            
            
            
            8,846
            
            
            
            44,245Operating
      income from continuing operations
            
            $
            65,046
            
            
            $
            3,403
            
            
            $
            18,758
            
            
            $
            87,207Capital
      Expenditures
            
            $
            20,607
            
            
            $
            780
            
            
            $
            8,686
            
            
            $
            30,073Segment
      Assets
            
            $
            580,553
            
            
            $
            89,604
            
            
            $
            250,910
            
            
            $
            921,067





Total
      Segments
              Nine
      Months Ended September 30, 2008
            
            Total
              Midstream
              Business
            
            
            Upstream
              Segment
            
            
            Minerals
              Segment
            
            
            Corporate
              Segment
            
            
            
            Total
              Segments($
      in thousands)Sales
      to external customers
            
            $
            896,878
            
            
            $
            140,364
            
            
            $
            34,606
            
            
            $
            (97,769
            )(a)
            
            
            $
            974,079Cost
      of natural gas and natural gas liquids
            
            
            726,400
            
            
            
            —
            
            
            
            —
            
            
            
            —
            
            
            
            
            726,400Operating
      costs and other expenses
            
            
            39,026
            
            
            
            29,369
            
            
            
            1,352
            
            
            
            41,295
            
            
            
            
            111,042Depreciation,
      depletion, and amortization
            
            
            44,245
            
            
            
            29,509
            
            
            
            6,460
            
            
            
            585
            
            
            
            
            80,799Operating
      income (loss) from continuing operations operations
            
            $
            87,207
            
            
            $
            81,486
            
            
            $
            26,794
            
            
            $
            (139,649
            )
            
            
            $
            55,838Capital
      Expenditures
            
            $
            30,073
            
            
            $
            17,716
            
            
            $
            —
            
            
            $
            —
            
            
            
            $
            47,789Segment
      Assets
            
            $
            921,067
            
            
            $
            634,512
            
            
            $
            149,380
            
            
            $
            68,102
            
            
            
            $
            1,773,061





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


24
 Table of Contents


NOTE
14. INCOME TAXES




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




As a
result of the taxable income from the underlying partnerships owned by the C
Corporations described above, net operating loss carryforwards and statutory
depletion carryforwards of $3.7 million, $6.8 million, $0.2 million, and $0.6
million were used during the three and nine months ended September 30, 2009 and
2008, respectively, which resulted in a release of the valuation allowance
established for the net operating losses as of December 31, 2008.




Effective Rate -The
effective rate for the three and nine month periods ended September 30, 2009 was
(4.0)% and (1.6)% compared to (0.2)% and (4.7)% for the three and nine month
period ended September 30, 2008, respectively.




Deferred Taxes -As of
September 30, 2009, the net deferred tax liability was $40.4 million compared to
$42.3 million as of December 31, 2008 and is primarily attributable to temporary
book and tax basis differences of the entities subject to federal income taxes
discussed above.  These temporary differences result in a net deferred
tax liability which will be reduced as allocation of depreciation and depletion
in proportion to the assets contributed brings the book and tax basis closer
together over time.  This deferred tax liability was recognized in
conjunction with the purchase accounting for the Stanolind and Redman
acquisitions.




Accounting for Uncertainty in Income
Taxes -The Partnership must recognize the tax effects of any uncertain
tax positions it may adopt, if the position taken by the Partnership is not 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 existing state
franchise tax. In general, legal entities that conduct business in Texas are
subject to the Revised Texas Franchise Tax, including previously non-taxable
entities such as limited partnerships and limited liability corporations. The
tax is assessed on Texas sourced taxable margin which is defined as the lesser
of (i) 70% of total revenue or (ii) total revenue less (a) cost
of goods sold or (b) compensation and benefits.  The Company
makes appropriate accruals for this tax during the reporting
period.






NOTE
15. EQUITY-BASED COMPENSATION




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




A summary
of the LTIP restricted common units’ activity for the three months ended
September 30, 2009, is provided below:





Number of
              Restricted
              Units
            
            
            Weighted
              Average
              Fair ValueNonvested
      at December 31, 2008
            
            
            905,486
            
            
            $
            17.00Granted
            
            
            174,400
            
            
            $
            4.52Vested
            
            
            (217,503
            )
            
            $
            20.07Forfeitures/Cancellations
            
            
            (68,644
            )
            
            $
            15.18Nonvested
      at September 30, 2009
            
            
            793,739
            
            
            $
            13.58





25
 Table of Contents


For the
three and nine months ended September 30, 2009 and 2008, non-cash compensation
expense of approximately $0.9 million, $4.6 million, $1.4 million and $4.1
million, respectively, was recorded related to the granted restricted units
under the LTIP.




As of
September 30, 2009, unrecognized compensation costs related to the outstanding
restricted units under the LTIP totaled approximately $7.6 million. The
remaining expense is to be recognized over a weighted average of 1.5
years.




In
addition to equity awards under the LTIP involving units of the Partnership,
Eagle Rock Holdings, L.P. (“Holdings”), which is controlled by NGP, in the past
has from time to time granted equity in Holdings to certain employees working on
behalf of the Partnership, some of which are named executive
officers.  During the nine month period ended September 30, 2009,
specifically, during the three-month periods ended March 31, 2009, Holdings
granted 160,000 “Tier I” incentive interests to one Eagle Rock Energy
employee.  Under the guidance of U.S. Securities and Exchange
Commission Staff Accounting Bulletin Topic 1.B: “Allocation Of Expenses And Related
Disclosure In Financial Statements Of Subsidiaries, Divisions Or Lesser Business
Components Of Another Entity,” the Partnership recorded a portion of the
value of the incentive units as compensation expense in the Partnership’s
financial statements.  This allocation is based on management’s
estimation of the total value of the incentive unit grant and of the grantee’s
portion of time dedicated to the Partnership.  The Partnership
recorded non-cash compensation expense of $0.4 million based on management’s
estimates related to the Tier I incentive unit grants made by Holdings during
the nine months ended September 30, 2009.  No Tier I incentive unit
grants were made by Holdings during the three months ended September 30,
2009.




Due to
the vesting of certain restricted units during the nine months ended September
30, 2009, 9,844 units were cancelled by the Partnership for less than $0.1
million as consideration for the related employee tax liability paid by the
Partnership.  Pursuant to the terms of the LTIP, these cancelled units
are available for future grants under the LTIP.




NOTE
16.  EARNINGS PER UNIT




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





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





Under the
Partnership’s partnership agreement, for any quarterly period, IDRs participate
in net income only to the extent of the amount of cash distributions actually
declared, thereby excluding the IDRs from participating in undistributed
earnings or losses.  Accordingly, undistributed net income is assumed
to be allocated to the other ownership interests on a pro-rata
basis.  During the three months ended September 30, 2009 and 2008, the
Partnership did not declare a quarterly distribution for the IDRs.





On January 1,
2009, the Partnership also adopted the guidance which provides that share-based
payment awards that contain non-forfeitable rights to dividends or dividend
equivalents meets the definition of a participating security and shall be
included in the computation of earnings-per-unit pursuant to the two-class
method.  The restricted common units granted under the LTIP, as
discussed in Note 15, contain non-forfeitable rights to the distributions
declared by the Partnership.





After
applying the above guidance, net loss per common, subordinated and general
partner unit for the three months ended September 30, 2008 changed to $3.94 from
$2.31 and net loss per common, subordinated and general partner unit for the
nine months ended September 30, 2008 remained at $0.45.  Earnings per
unit has not been separately disclosed for the restricted common units, as the
restricted common units are not considered a separate class of
equity.


26
 Table of Contents


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




Three
      Months Ended
              September
      30,
            
            
            Nine
      Months Ended
              September
      30,2009
            
            
            2008
            
            
            2009
            
            
            2008Basic
      weighted average units outstanding:Common
      units
            
            
            53,632
            
            
            
            50,824
            
            
            
            53,276
            
            
            
            50,762Subordinated
      units
            
            
            20,691
            
            
            
            20,691
            
            
            
            20,691
            
            
            
            20,691General
      partner units
            
            
            845
            
            
            
            845
            
            
            
            845
            
            
            
            845Diluted
      weighted average units outstanding:Common
      units
            
            
            53,632
            
            
            
            50,868
            
            
            
            53,276
            
            
            
            50,900Subordinated
      units
            
            
            20,691
            
            
            
            20,691
            
            
            
            20,691
            
            
            
            20,691General
      partner units
            
            
            845
            
            
            
            845
            
            
            
            845
            
            
            
            845








The following
table presents the Partnership’s basic and diluted loss per unit for the three
months ended September 30, 2009:




Total
            
            
            Common
              Units
            
            
            Restricted
      Common Units
            
            
            Subordinated
      Units
            
            
            General
              Partner
      Units($
      in thousands, except for per unit amounts)Loss
      from continuing operations
            
            $
            (25,297
            )Distributions
      declared
            
            
            1,377
            
            
            $
            1,341
            
            
            $
            15
            
            
            $
            —
            
            
            $
            21Assumed
      loss from continuing operations after distribution to be
      allocated
            
            
            (26,674
            )
            
            
            (19,032
            )
            
            
            —
            
            
            
            (7,342
            )
            
            
            (300
            )Assumed
      allocation of loss from continuing operations
            
            
            (25,297
            )
            
            
            (17,691
            )
            
            
            15
            
            
            
            (7,342
            )
            
            
            (279
            )Discontinued
      operations
            
            
            26
            
            
            
            19
            
            
            
            —
            
            
            
            7
            
            
            
            —Assumed
      net loss to be allocated
            
            $
            (25,271
            )
            
            $
            (17,672
            )
            
            $
            15
            
            
            $
            (7,335
            )
            
            $
            (279
            )Basic
      and diluted loss from continuing operations per unit
            
            
            
            
            
            $
            (0.33
            )
            
            
            
            
            
            $
            (0.35
            )
            
            $
            (0.33
            )Basic
      and diluted discontinued operations per unit
            
            
            
            
            
            $
            —
            
            
            
            
            
            
            $
            —
            
            
            $
            —Basic
      and diluted loss per unit
            
            
            
            
            
            $
            (0.33
            )
            
            
            
            
            
            $
            (0.35
            )
            
            $
            (0.33
            )


The following
table presents the Partnership’s basic and diluted loss per unit for the three
months ended September 30, 2008:




Total
            
            
            Common
      Units
            
            
            Restricted
      Common Units
            
            
            Subordinated
      Units
            
            
            General
              Partner
      Units($
      in thousands, except for per unit amounts)Income
      from continuing operations
            
            $
            287,477Distributions
      declared
            
            
            29,949
            
            
            $
            20,839
            
            
            $
            280
            
            
            $
            8,484
            
            
            $
            346Assumed
      income from continuing operations after distribution to be
      allocated
            
            
            257,528
            
            
            
            179,005
            
            
            
            2,672
            
            
            
            72,876
            
            
            
            2,975Assumed
      allocation of income from continuing operations
            
            
            287,477
            
            
            
            199,844
            
            
            
            2,952
            
            
            
            81,360
            
            
            
            3,321Discontinued
      operations
            
            
            594
            
            
            
            413
            
            
            
            6
            
            
            
            168
            
            
            
            7Assumed
      net income to be allocated
            
            $
            288,071
            
            
            $
            200,257
            
            
            $
            2,958
            
            
            $
            81,528
            
            
            $
            3,328Basic
      and diluted income from continuing operations per unit
            
            
            
            
            
            $
            3.93
            
            
            
            
            
            
            $
            3.93
            
            
            $
            3.93Basic
      and diluted discontinued operations per unit
            
            
            
            
            
            $
            0.01
            
            
            
            
            
            
            $
            0.01
            
            
            $
            0.01Basic
      and diluted income per unit
            
            
            
            
            
            $
            3.94
            
            
            
            
            
            
            $
            3.94
            
            
            $
            3.94





27
 Table of Contents





The following
table presents the Partnership’s basic and diluted loss per unit for the nine
months ended September 30, 2009:







Total
            
            
            Common
              Units
            
            
            Restricted
      Common Units
            
            
            Subordinated
      Units
            
            
            General
              Partner
      Units($
      in thousands, except for per unit amounts)Loss
      from continuing operations
            
            $
            (102,869
            )Distributions
      declared
            
            
            4,110
            
            
            $
            3,996
            
            
            $
            51
            
            
            $
            —
            
            
            $
            63Assumed
      loss from continuing operations after distribution to be
      allocated
            
            
            (106,979
            )
            
            
            (76,184
            )
            
            
            —
            
            
            
            (29,588
            )
            
            
            (1,207
            )Assumed
      allocation of loss from continuing operations
            
            
            (102,869
            )
            
            
            (72,188
            )
            
            
            51
            
            
            
            (29,588
            )
            
            
            (1,144
            )Discontinued
      operations
            
            
            266
            
            
            
            189
            
            
            
            —
            
            
            
            74
            
            
            
            3Assumed
      net loss to be allocated
            
            $
            (102,603
            )
            
            $
            (71,999
            )
            
            $
            51
            
            
            $
            (29,514
            )
            
            $
            (1,141
            )Basic
      and diluted loss from continuing operations per unit
            
            
            
            
            
            $
            (1.35
            )
            
            
            
            
            
            $
            (1.43
            )
            
            $
            (1.35
            )Basic
      and diluted discontinued operations per unit
            
            
            
            
            
            $
            —
            
            
            
            
            
            
            $
            —
            
            
            $
            —Basic
      and diluted loss per unit
            
            
            
            
            
            $
            (1.35
            )
            
            
            
            
            
            $
            (1.43
            )
            
            $
            (1.35
            )





The following
table presents the Partnership’s basic and diluted loss per unit for the nine
months ended September 30, 2008:





Total
            
            
            Common
      Units
            
            
            Restricted
      Common Units
            
            
            Subordinated
      Units
            
            
            General
              Partner
      Units($
      in thousands, except for per unit amounts)Income
      from continuing operations
            
            $
            31,272Distributions
      declared
            
            
            88,899
            
            
            $
            61,930
            
            
            $
            695
            
            
            $
            25,244
            
            
            $
            1,030Assumed
      loss from continuing operations after distribution to be
      allocated
            
            
            (57,627
            )
            
            
            (40,110
            )
            
            
            (501
            )
            
            
            (16,349
            )
            
            
            (667
            )Assumed
      allocation of income from continuing operations
            
            
            31,272
            
            
            
            21,820
            
            
            
            194
            
            
            
            8,895
            
            
            
            363Discontinued
      operations
            
            
            1,451
            
            
            
            1,010
            
            
            
            13
            
            
            
            411
            
            
            
            17Assumed
      net income to be allocated
            
            $
            32,723
            
            
            $
            22,830
            
            
            $
            207
            
            
            $
            9,306
            
            
            $
            380Basic
      and diluted income from continuing operations per unit
            
            
            
            
            
            $
            0.43
            
            
            
            
            
            
            $
            0.43
            
            
            $
            0.43Basic
      and diluted discontinued operations per unit
            
            
            
            
            
            $
            0.02
            
            
            
            
            
            
            $
            0.02
            
            
            $
            0.02Basic
      and diluted income per unit
            
            
            
            
            
            $
            0.45
            
            
            
            
            
            
            $
            0.45
            
            
            $
            0.45








NOTE
17.  DISCONTINUED OPERATIONS





On April 1,
2009, the Partnership sold its producer services business (which was accounted
for in its South Texas Segment) by assigning and novating the contracts under
this business to a third-party purchaser.  The Partnership sold the
producer services business to a third-party purchaser as it was a low-margin
business that was not core to the Partnership’s operations. The Partnership
received an initial payment of $0.1 million for the sale of the
business.  In addition the Partnership received a contingency payment
of $0.1 million in October 2009. The Partnership will also continue to receive a
monthly payment equivalent to $0.01 per MMbtu on the volume of gas that flows
pursuant to the assigned contracts through March 31, 2011.  Producer
services was a business in which the Partnership would negotiate new well
connections on behalf of small producers to pipelines other than its
own.  During
the three and nine months ended September 30, 2009, this business generated
revenues of less than $0.1 million and $19.2 million, respectively, and cost of
natural gas and natural gas liquids of less than $0.1 million and $18.9 million,
respectively.During the three and nine months ended September 30,
2008, this business generated revenues of $79.6 million and $221.3 million,
respectively, and cost of natural gas and natural gas liquids of $79.0 million
and $219.8 million, respectively.  For the three and nine months ended
September 30, 2009, less than $0.1 million and $0.3 million, respectively, of
revenues minus the cost of natural gas and natural gas liquids have been
reported as discontinued operations, as compared to revenues minus the cost of
natural gas and natural gas liquids of $0.6 million and $1.5 million,
respectively, for the three and nine months ended September 30,
2008.





NOTE
18.  OTHER OPERATING (INCOME) EXPENSE





Other
operating (income) expense for the nine months ended September 30, 2009,
includes income of $3.6 million due to the recovery of $2.2 million of assets
previously written off and the release of $1.4 million of liabilities assumed as
part of the Partnership’s purchase price allocation for its acquisitions of
Escambia Asset Co., LLC and Redman Energy Holdings, L.P.  During the
period, the Partnership received additional information about collectability of
these assets and determined that it no longer had any obligation under these
liabilities.





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 historically sold portions of its condensate production from its
Texas Panhandle and East Texas midstream systems to SemGroup.  As a
result of the bankruptcy, the Partnership took a $10.1 million bad debt charge
during the nine months ended September 30, 2008, which is included in “Other
Operating Expense” in the consolidated statement of operations.  In
August 2009, the Partnership sold $3.9 million of its outstanding receivables
from SemGroup, which represented its 20-day administrative claims under
503(b)(9) of the United States Bankruptcy Code, for which it received a payment
of $3.0 million.  Due to certain repurchase obligations under the
assignment agreement, the Partnership recorded the payment as a current
liability within accounts payable as of September 30, 2009 and anticipates
maintaining the balance as a liability until it is clear that the repurchase
obligations can no longer be triggered.


28
 Table of Contents


NOTE
19.  SUBSIDIARY GUARANTORS





The
obligations under the Partnership’s revolving credit facility are secured by
first priority liens on substantially all of the Partnership’s assets, including
a pledge of all of the capital stock of each of its subsidiaries.  All
guarantees are full and unconditional and joint and several guarantees. In
accordance with practices accepted by the SEC, the Partnership has prepared
Unaudited Condensed Consolidating Financial Statements as supplemental
information.  The following Unaudited Condensed Consolidating Balance
Sheets at September 30, 2009 and December 31, 2008, and Unaudited Condensed
Consolidating Statements of Operations for the three and nine months ended
September 30, 2009 and 2008 and Unaudited Condensed Consolidating Statements of
Cash Flows for the nine months ended September 30, 2009 and 2008, present
financial information for Eagle Rock Energy Partners, L.P. as the Parent on a
stand-alone basis (carrying any investments in subsidiaries under the equity
method), financial information for the subsidiary guarantors, which are all
fully owned by the Parent, on a stand-alone basis, and the consolidation
and elimination entries necessary to arrive at the information for the
Partnership on a consolidated basis.  The subsidiary guarantors are
not restricted from making distributions to the Partnership.








Unaudited
      Condensed Consolidating Balance SheetSeptember
      30, 2009(in
      thousands)
            
            Parent
      Issuer
            
            Subsidiary
      Guarantors
            
            Consolidating
      Entries
            
            
            TotalASSETS:Accounts
      receivable – related parties
            
            $
            101,348
            
            $
            —
            
            $
            (101,348
            )
            
            $
            —Other
      current assets
            
            
            13,590
            
            
            97,527
            
            
            —
            
            
            
            111,117Total
      property, plant and equipment, net
            
            
            9
            
            
            1,313,377
            
            
            —
            
            
            
            1,313,386Investment
      in subsidiaries
            
            
            1,300,981
            
            
            —
            
            
            (1,300,981
            )
            
            
            —Total
      other long-term assets
            
            
            6,887
            
            
            159,452
            
            
            —
            
            
            
            166,339Total
      assets
            
            $
            1,422,815
            
            $
            1,570,356
            
            $
            (1,402,329
            )
            
            $
            1,590,842LIABILITIES
      AND EQUITY:Accounts payable – related parties
            
            $
            —
            
            $
            101,348
            
            $
            (101,348
            )
            
            $
            —Other
      current liabilities
            
            
            29,762
            
            
            94,107
            
            
            —
            
            
            
            123,869Other
      long-term liabilities
            
            
            19,833
            
            
            73,920
            
            
            —
            
            
            
            93,753Long-term
      debt
            
            
            774,383
            
            
            —
            
            
            —
            
            
            
            774,383Equity
            
            
            598,837
            
            
            1,300,981
            
            
            (1,300,981
            )
            
            
            598,837Total
      liabilities and equity
            
            $
            1,422,815
            
            $
            1,570,356
            
            $
            (1,402,329
            )
            
            $
            1,590,842








Unaudited
      Condensed Consolidating Balance SheetDecember
      31, 2008(in
      thousands)
            
            Parent
      Issuer
            
            Subsidiary
      Guarantors
            
            Consolidating
      Entries
            
            
            TotalASSETS:Accounts
      receivable – related parties
            
            $
            —
            
            $
            16,880
            
            $
            (16,880
            )
            
            $
            —Other
      current assets
            
            
            37,452
            
            
            175,772
            
            
            —
            
            
            
            213,224Total
      property, plant and equipment, net
            
            
            128
            
            
            1,357,481
            
            
            —
            
            
            
            1,357,609Investment
      in subsidiaries
            
            
            1,520,016
            
            
            —
            
            
            (1,520,016
            )
            
            
            —Total
      other long-term assets
            
            
            7,506
            
            
            194,722
            
            
            —
            
            
            
            202,228Total
      assets
            
            $
            1,565,102
            
            $
            1,744,855
            
            $
            (1,536,896
            )
            
            $
            1,773,061LIABILITIES
      AND EQUITY:Accounts
      payable – related parties
            
            $
            16,880
            
            $
            —
            
            $
            (16,880
            )
            
            $
            —Other
      current liabilities
            
            
            10,596
            
            
            145,342
            
            
            —
            
            
            
            155,938Other
      long-term liabilities
            
            
            10,528
            
            
            79,497
            
            
            —
            
            
            
            90,025Long-term
      debt
            
            
            799,383
            
            
            —
            
            
            —
            
            
            
            799,383Equity
            
            
            727,715
            
            
            1,520,016
            
            
            (1,520,016
            )
            
            
            727,715Total
      liabilities and equity
            
            $
            1,565,102
            
            $
            1,744,855
            
            $
            (1,536,896
            )
            
            $
            1,773,061








29
 Table of Contents
  
 
 Unaudited
      Condensed Consolidating Statement of OperationsFor
      the three months ended September 30, 2009(in
      thousands)
                
                Parent
      Issuer
                
                Subsidiary
      Guarantors
                
                
                Consolidating
      Entries
                
                
                TotalTotal
      revenues
                
                $
                1,348
                
                $
                162,513
                
                
                $
                —
                
                
                $
                163,861Cost
      of natural gas and natural gas liquids
                
                
                —
                
                
                109,945
                
                
                
                —
                
                
                
                109,945Operations
      and maintenance
                
                
                —
                
                
                16,934
                
                
                
                —
                
                
                
                16,934Taxes
      other than income
                
                
                —
                
                
                2,934
                
                
                
                —
                
                
                
                2,934General
      and administrative
                
                
                163
                
                
                10,286
                
                
                
                —
                
                
                
                10,449Depreciation,
      depletion, and impairment
                
                
                —
                
                
                28,860
                
                
                
                —
                
                
                
                28,860Income
      from operations
                
                
                1,185
                
                
                (6,446
                )
                
                
                —
                
                
                
                (5,261
                )Interest
      expense, net
                
                
                (4,315
                )
                
                —
                
                
                
                —
                
                
                
                (4,315
                )Other
      non-operating income
                
                
                1,728
                
                
                1,201
                
                
                
                (2,194
                )
                
                
                735Other
      non-operating expense
                
                
                (4,245
                )
                
                (8,564
                )
                
                
                2,194
                
                
                
                (10,615
                )Income
      (loss) before income taxes
                
                
                (5,647
                )
                
                (13,809
                )
                
                
                —
                
                
                
                (19,456
                )Income
      tax provision
                
                
                697
                
                
                5,144
                
                
                
                —
                
                
                
                5,841Equity
      in earnings of subsidiaries
                
                
                (18,927
                )
                
                —
                
                
                
                18,927
                
                
                
                —Income
      (loss) from continuing operations
                
                
                (25,271
                )
                
                (18,953
                )
                
                
                18,927
                
                
                
                (25,297
                )Discontinued
      operations
                
                
                —
                
                
                26
                
                
                
                —
                
                
                
                26Net
      income (loss)
                
                $
                (25,271
                )
                $
                (18,927
                )
                
                $
                18,927
                
                
                $
                (25,271
                )
 
  
 Unaudited
      Condensed Consolidating Statement of OperationsFor
      the nine months ended September 30, 2009(in
      thousands)
                
                Parent
      Issuer
                
                Subsidiary
      Guarantors
                
                
                Consolidating
      Entries
                
                
                TotalTotal
      revenues
                
                $
                (24,423
                )
                $
                483,476
                
                
                $
                —
                
                
                $
                459,053Cost
      of natural gas and natural gas liquids
                
                
                —
                
                
                358,802
                
                
                
                —
                
                
                
                358,802Operations
      and maintenance
                
                
                —
                
                
                54,624
                
                
                
                —
                
                
                
                54,624Taxes
      other than income
                
                
                —
                
                
                8,790
                
                
                
                —
                
                
                
                8,790General
      and administrative
                
                
                559
                
                
                34,323
                
                
                
                —
                
                
                
                34,882Other
      operating income
                
                
                —
                
                
                (3,552
                )
                
                
                —
                
                
                
                (3,552
                )Depreciation,
      depletion, and impairment
                
                
                —
                
                
                86,753
                
                
                
                —
                
                
                
                86,753Income
      from operations
                
                
                (24,982
                )
                
                (56,264
                )
                
                
                —
                
                
                
                (81,246
                )Interest
      expense, net
                
                
                (17,282
                )
                
                —
                
                
                
                —
                
                
                
                (17,282
                )Other
      non-operating income
                
                
                8,230
                
                
                10,026
                
                
                
                (6,493
                )
                
                
                11,763Other
      non-operating expense
                
                
                (7,024
                )
                
                (13,939
                )
                
                
                6,493
                
                
                
                (14,470
                )Income
      (loss) before income taxes
                
                
                (41,058
                )
                
                (60,177
                )
                
                
                —
                
                
                
                (101,235
                )Income
      tax provision
                
                
                716
                
                
                918
                
                
                
                —
                
                
                
                1,634Equity
      in earnings of subsidiaries
                
                
                (60,829
                )
                
                —
                
                
                
                60,829
                
                
                
                —Income
      (loss) from continuing operations
                
                
                (102,603
                )
                
                (61,095
                )
                
                
                60,829
                
                
                
                (102,869
                )Discontinued
      operations
                
                
                —
                
                
                266
                
                
                
                —
                
                
                
                266Net
      income (loss)
                
                $
                (102,603
                )
                $
                (60,829
                )
                
                $
                60,829
                
                
                $
                (102,603
                )
 
 
 30
 Table of Contents
 Unaudited
      Condensed Consolidating Statement of OperationsFor
      the three months ended September 30, 2008(in
      thousands)
                
                Parent
      Issuer
                
                Subsidiary
      Guarantors
                
                
                Consolidating
      Entries
                
                
                TotalTotal
      revenues
                
                $
                2,181
                
                $
                601,704
                
                
                $
                —
                
                
                $
                603,885Cost
      of natural gas and natural gas liquids
                
                
                —
                
                
                237,742
                
                
                
                —
                
                
                
                237,742Operations
      and maintenance
                
                
                —
                
                
                21,475
                
                
                
                —
                
                
                
                21,475Taxes
      other than income
                
                
                —
                
                
                5,365
                
                
                
                —
                
                
                
                5,365General
      and administrative
                
                
                (24
                )
                
                9,917
                
                
                
                —
                
                
                
                9,893Other
      operating expense
                
                
                —
                
                
                3,920
                
                
                
                —
                
                
                
                3,920Depreciation,
      depletion, and impairment
                
                
                —
                
                
                28,597
                
                
                
                —
                
                
                
                28,597Income
      from operations
                
                
                2,205
                
                
                294,688
                
                
                
                —
                
                
                
                296,893Interest
      expense, net
                
                
                (7,498
                )
                
                —
                
                
                
                —
                
                
                
                (7,498
                )Other
      non-operating income
                
                
                785
                
                
                456
                
                
                
                (595
                )
                
                
                646Other
      non-operating expense
                
                
                (219
                )
                
                (3,440
                )
                
                
                595
                
                
                
                (3,064
                )Income
      (loss) before income taxes
                
                
                (4,727
                )
                
                291,704
                
                
                
                —
                
                
                
                286,977Income
      tax provision (benefit)
                
                
                —
                
                
                (500
                )
                
                
                —
                
                
                
                (500
                )Equity
      in earnings of subsidiaries
                
                
                292,798
                
                
                —
                
                
                
                (292,798
                )
                
                
                —Income from
      continuing operations
                
                
                288,071
                
                
                292,204
                
                
                
                (292,798
                )
                
                
                287,477Discontinued
      operations
                
                
                —
                
                
                594
                
                
                
                —
                
                
                
                594Net
      income (loss)
                
                $
                288,071
                
                $
                292,798
                
                
                $
                (292,798
                )
                
                $
                288,071
 
  
 
 Unaudited
      Condensed Consolidating Statement of OperationsFor
      the nine months ended September 30, 2008(in
      thousands)
                
                Parent
      Issuer
                
                Subsidiary
      Guarantors
                
                
                Consolidating
      Entries
                
                
                TotalTotal
      revenues
                
                $
                2,181
                
                $
                971,898
                
                
                $
                —
                
                
                $
                974,079Cost
      of natural gas and natural gas liquids
                
                
                —
                
                
                726,400
                
                
                
                —
                
                
                
                726,400Operations
      and maintenance
                
                
                —
                
                
                54,772
                
                
                
                —
                
                
                
                54,772Taxes
      other than income
                
                
                —
                
                
                14,975
                
                
                
                —
                
                
                
                14,975General
      and administrative
                
                
                4
                
                
                31,157
                
                
                
                —
                
                
                
                31,161Other
      operating expense
                
                
                —
                
                
                10,134
                
                
                
                —
                
                
                
                10,134Depreciation,
      depletion, and impairment
                
                
                —
                
                
                80,799
                
                
                
                —
                
                
                
                80,799Income
      from operations
                
                
                2,177
                
                
                53,661
                
                
                
                —
                
                
                
                55,838Interest
      expense
                
                
                (23,576
                )
                
                —
                
                
                
                —
                
                
                
                (23,576
                )Other
      non-operating income
                
                
                2,520
                
                
                3,127
                
                
                
                (2,107
                )
                
                
                3,540Other
      non-operating expense
                
                
                (654
                )
                
                (7,480
                )
                
                
                2,107
                
                
                
                (6,027
                )Income
      (loss) before income taxes
                
                
                (19,533
                )
                
                49,308
                
                
                
                —
                
                
                
                29,775Income
      tax provision (benefit)
                
                
                —
                
                
                (1,497
                )
                
                
                —
                
                
                
                (1,497
                )Equity
      in earnings of subsidiaries
                
                
                52,256
                
                
                —
                
                
                
                (52,256
                )
                
                
                —Income from
      continuing operations
                
                
                32,723
                
                
                50,805
                
                
                
                (52,256
                )
                
                
                31,272Discontinued
      operations
                
                
                —
                
                
                1,451
                
                
                
                —
                
                
                
                1,451Net
      income (loss)
                
                $
                32,723
                
                $
                52,256
                
                
                $
                (52,256
                )
                
                $
                32,723
 
  31
 Table of Contents


Unaudited
      Condensed Consolidating Statement of Cash FlowsFor
      the nine months ended September 30, 2009(in
      thousands)
            
            Parent
      Issuer
            
            Subsidiary
      Guarantors
            
            
            Consolidating
      Entries
            
            
            TotalNet
      cash flows provided by operating activities
            
            $
            40,548
            
            $
            32,624
            
            
            $
            —
            
            
            $
            73,172CASH
      FLOWS FROM INVESTING ACTIVITIES:Additions
      to property, plant and equipment
            
            
            (9
            )
            
            (29,418
            )
            
            
            —
            
            
            
            (29,427
            )Purchase
      of intangible assets
            
            
            —
            
            
            (1,219
            )
            
            
            —
            
            
            
            (1,219
            )Investment
      in partnerships
            
            
            —
            
            
            (806
            )
            
            
            —
            
            
            
            (806
            )Proceeds
      from sale of asset
            
            
            —
            
            
            476
            
            
            
            —
            
            
            
            476Net
      cash flows provided by (used in) investing activities
            
            
            (9
            )
            
            (30,967
            )
            
            
            —
            
            
            
            (30,976
            )CASH
      FLOWS FROM FINANCING ACTIVITIES:Proceeds
      from long-term debt
            
            
            131,000
            
            
            —
            
            
            
            —
            
            
            
            131,000Repayment
      of long-term debt
            
            
            (156,000
            )
            
            —
            
            
            
            —
            
            
            
            (156,000
            )Proceeds
      from derivative contracts
            
            
            —
            
            
            8,330
            
            
            
            —
            
            
            
            8,330Repurchase
      of common units
            
            
            (30
            )
            
            —
            
            
            
            —
            
            
            
            (30
            )Distributions
      to members and affiliates
            
            
            (34,244
            )
            
            —
            
            
            
            —
            
            
            
            (34,244
            )Net
      cash flows provided by (used in) financing activities
            
            
            (59,274
            )
            
            8,330
            
            
            
            —
            
            
            
            (50,994
            )Net
      (decrease) increase in cash and cash equivalents
            
            
            (18,735
            )
            
            9,987
            
            
            
            —
            
            
            
            (8,748
            )Cash
      and cash equivalents at beginning of year
            
            
            29,272
            
            
            (11,356
            )
            
            
            —
            
            
            
            17,916Cash
      and cash equivalents at end of year
            
            $
            10,537
            
            $
            (1,369
            )
            
            $
            —
            
            
            $
            9,168


Unaudited
      Condensed Consolidating Statement of Cash FlowsFor
      the nine months ended September 30, 2008(in
      thousands)
            
            Parent
      Issuer
            
            Subsidiary
      Guarantors
            
            
            Consolidating
      Entries
            
            
            TotalNet
      cash flows provided by operating activities
            
            $
            108,486
            
            $
            55,085
            
            
            $
            —
            
            
            $
            163,571CASH
      FLOWS FROM INVESTING ACTIVITIES:Additions
      to property, plant and equipment
            
            
            (696
            )
            
            (44,641
            )
            
            
            —
            
            
            
            (45,337
            )Purchase
      of intangible assets
            
            
            —
            
            
            (1,438
            )
            
            
            —
            
            
            
            (1,438
            )Investment
      in partnerships
            
            
            —
            
            
            (3,416
            )
            
            
            —
            
            
            
            (3,416
            )Acquisitions,
      net of cash acquired
            
            
            (857
            )
            
            (80,432
            )
            
            
            —
            
            
            
            (81,289
            )Contributions
      to subsidiaries
            
            
            (80,969
            )
            
            —
            
            
            
            80,969
            
            
            
            —Net
      cash flows provided by (used in) investing activities
            
            
            (85,522
            )
            
            (129,927
            )
            
            
            80,969
            
            
            
            (131,480
            )CASH
      FLOWS FROM FINANCING ACTIVITIES:Proceeds
      from long-term debt
            
            
            377,383
            
            
            —
            
            
            
            —
            
            
            
            377,383Repayment
      of long-term debt
            
            
            (145,069
            )
            
            —
            
            
            
            —
            
            
            
            (145,069
            )Proceeds
      from derivative contracts
            
            
            —
            
            
            (15,462
            )
            
            
            —
            
            
            
            (15,462
            )Payment
      of debt issuance costs
            
            
            —
            
            
            (789
            )
            
            
            —
            
            
            
            (789
            )Contributions
      to subsidiaries
            
            
            —
            
            
            80,969
            
            
            
            (80,969
            )
            
            
            —Distributions
      to members and affiliates
            
            
            (87,602
            )
            
            —
            
            
            
            —
            
            
            
            (87,602
            )Net
      cash flows provided by financing activities
            
            
            144,712
            
            
            64,718
            
            
            
            (80,969
            )
            
            
            128,461Net
      increase (decrease) in cash and cash equivalents
            
            
            170,676
            
            
            (10,124
            )
            
            
            —
            
            
            
            160,552Cash
      and cash equivalents at beginning of year
            
            
            72,286
            
            
            (3,734
            )
            
            
            —
            
            
            
            68,552Cash
      and cash equivalents at end of year
            
            $
            242,962
            
            $
            (13,858
            )
            
            $
            —
            
            
            $
            229,104


NOTE
20.  SUBSEQUENT EVENTS




Subsequent
to September 30, 2009, the Partnership has received various revised proposals
from both NGP and Black Stone.  See further discussion of these
proposals in Note 9.
 32
 Table of Contents





Item2.                      Management’s
Discussion and Analysis of Financial Condition and Results of
Operations.




The
following discussion and analysis of financial condition and results of
operations should be read in conjunction with our unaudited condensed
consolidated financial statements, and the notes thereto, appearing elsewhere in
this report, as well as the Consolidated Financial Statements, Risk Factors and
Management’s Discussion and Analysis of Financial Condition and Results of
Operations presented in our annual report on Form 10-K for the year ended
December 31, 2008, filed with the Securities and Exchange Commission. For a
description of oil and natural gas terms, see our annual report.




Overview





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




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




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




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





We report on
our businesses in seven accounting segments.





We conduct,
evaluate and report on our Midstream Business within four distinct segments—the
Texas Panhandle Segment, the East Texas/Louisiana Segment, the South Texas
Segment and the Gulf of Mexico Segment. Our Texas Panhandle Segment consists of
gathering and processing assets in the Texas Panhandle. Our East Texas/Louisiana
Segment consists of gathering and processing assets in East Texas, Central Texas
and Northern Louisiana. Our South Texas Segment consists of gathering systems
and related compression and processing facilities in South Texas and West
Texas.   Our Gulf of Mexico Segment consists of gathering and
processing assets in Southern Louisiana, the Gulf of Mexico and Galveston Bay,
Texas.  During the three and nine months ended September 30, 2009, our
Midstream Business generated operating income from continuing operations of $8.3
million and $5.6 million, respectively, compared to operating income from
continuing operations of $32.6 million and $87.2 million during the three and
nine months ended September 30, 2008, respectively.





We conduct,
evaluate and report on our Upstream Business as one segment. Our Upstream
Segment includes operated wells in Escambia County, Alabama as well as two
treating facilities, one natural gas processing plant and related gathering
systems that are inextricably intertwined with ownership and operation of the
wells. The Upstream Segment also includes operated and non-operated wells that
are primarily located in West, East and South Texas in Ward, Crane, Pecos,
Henderson, Rains, Van Zandt, Limestone, Freestone and Atascosa Counties,
Texas.  During the three and nine months ended September 30, 2009, our
Upstream Business generated operating income of $4.2 million and $1.1 million,
respectively, compared to operating income of $31.8 million and $81.5 million
during the three and nine months ended September 30, 2008,
respectively.  Of important note, the cost of disposal of sulfur
exceeded the revenue generated by $0.3 million and $1.5 million during the three
and nine months ended September 30, 2009, respectively, compared to revenue of
$13.1 million and $25.5 million generated during the three and nine months ended
September 30, 2008, respectively.





We conduct,
evaluate, and report our Minerals Business as one segment.  Our Minerals
Segment consists of fee mineral, royalty and overriding royalty interests
located in multiple producing trends in the United States.  A significant
portion of the mineral interests that we own are managed by Black Stone Minerals
Company, a non-affiliated private partnership (the “Minerals Manager”) that
controls the executive rights associated with the minerals.  During
the three and nine months ended September 30, 2009, our Minerals Business
generated operating income of $1.9 million and $4.8 million, respectively,
compared to operating income of $14.6 million and $26.8 million during the three
and nine months ended September 30, 2008, respectively.  Included
within these numbers is lease bonus revenue of $0.9 million and $1.8 million
generated during the three and nine months ended September 30, 2009,
respectively, compared to $9.5 million and $12.2 million during the three and
nine months ended September 30, 2008, respectively.





The final
segment that we report on is our Corporate Segment, in which we account for our
commodity derivative/hedging activity and our corporate-level general and
administrative expenses.  During the three and nine months ended
September 30, 2009, our Corporate Segment generated an operating loss of $19.6
million and $92.8 million, respectively, compared to an operating income of
$217.8 million and an operating loss of $139.6 million during the three and nine
months ended September 30, 2008, respectively.  Within these numbers
were losses, realized and unrealized, on commodity derivatives of $8.8 million
and $57.1 million during the three and nine months ended September 30, 2009,
respectively, compared to gains, realized and unrealized, on commodity
derivatives of $231.9 million and losses of $97.8 million during the three and
nine months ended September 30, 2008, respectively.





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





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





Impairment





In connection
with the preparation of our unaudited condensed consolidated financial
statements for the three months ended March 31, 2009, we determined that we
needed to record an impairment charge for certain fields within our proved
properties within our Upstream Segment.  These impairment charges were
necessary due to the continued decline in natural gas prices during the
period.  As a result, we incurred impairment charges of $0.2 million
in our Upstream Segment.  In connection with the preparation of our
unaudited condensed consolidated financial statements for the three months ended
September 30, 2009, we determined that we needed to record an impairment charge
for certain properties within our Minerals Segment.  These impairment
charges resulted from a decline in natural gas prices and a slight reduction in
oil reserves based on updated production performance.  As a result, we
incurred impairment charges of $0.3 million during the three months ended
September 30, 2009 in our Minerals Segment.





Pursuant to
generally accepted accounting principles in the United States, our impairment
analysis does not take into account the value of our commodity derivative
instruments, which generally increase as the estimates of future prices
decline.  Further declines in commodity prices and other factors could
result in additional impairment charges and changes to the fair value of our
derivative instruments.




Acquisitions




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




Below is a
summary of our important acquisition transactions completed since January 1,
2008.




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





Millennium Acquisition -On
October 1, 2008, we completed the acquisition of 100% of the outstanding units
of Millennium Midstream Partners, L.P. (“MMP”).  With the acquisition,
we acquired natural gas gathering and processing assets located in East, Central
and West Texas and South Louisiana.




33
 Table of Contents





Recent
Transactions




On April 1,
2009, we sold our producer services business (which was accounted for in our
South Texas Segment) by assigning and novating the contracts under this business
to a third-party purchaser.  We sold the producer services business to
a third-party purchaser as it was a low-margin business that was not core to our
operations.   We received an initial payment of $0.1 million for
the sale of the business.  In addition we received a contingency
payment of $0.1 million in October 2009.  We will also continue to
receive a monthly payment equivalent to $0.01 per MMbtu on the volume of gas
that flows pursuant to the assigned contracts through March 31,
2011.  The producer services business was a low margin business in
which we would negotiate new well connections on behalf of small producers to
pipelines other than our own.  During
the three and nine months ended September 30, 2009, this business generated
revenues of less than $0.1 million and $19.2 million, respectively, and cost of
natural gas and natural gas liquids of less than $0.1 million and $18.9 million,
respectively.During the three and nine months ended September 30,
2008, this business generated revenues of $79.6 million and $221.3 million,
respectively, and cost of natural gas and natural gas liquids of $79.0 million
and $219.8 million, respectively.  For the three and nine months ended
September 30, 2009, less than $0.1 million and $0.3 million, respectively, of
revenues minus the cost of natural gas and natural gas liquids have been
reported as discontinued operations, as compared to revenues minus the cost of
natural gas of $0.6 million and $1.5 million, respectively, for the three and
nine months ended September 30, 2008.


On September
18, 2009, we announced our Board of Directors received a letter from Natural Gas
Partners VII, L.P. and Natural Gas Partners VIII, L.P. (collectively with
Natural Gas Partners IX, L.P. and other affiliates, “NGP”) wherein NGP proposed
a series of transactions between NGP and the Partnership.
 
 On October
13, 2009, we announced that our Board of Directors received a letter from NGP as
a follow-up to NGP’s original proposal which included a term sheet setting forth
revised terms and conditions to NGP’s original proposal.  The revised
proposal contemplated, in exchange for a $32.5 million fee payable to NGP, an
equity commitment (including a standby equity commitment to support a public
equity offering by us), a commitment to purchase our Minerals Business for $145
million subject to a marketed sales process, the contribution to us of all
outstanding subordinated units and incentive distribution rights, and an option
to acquire our general partner. The proposal also contemplated a new incentive
plan for our management team.
 
 On October
17, 2009, we received a proposal from Black Stone Minerals Company, L.P. (“Black
Stone”), which included, among other terms and conditions, an offer by Black
Stone and certain of its co-investors (collectively, “BSMC”) to purchase our
Minerals Business for $157.5 million and to provide a standby equity investment
commitment in support of a public equity offering by us.
 
 On November
7, 2009, we received a joint proposal from NGP and Black Stone that revises, and
serves as a replacement of, each of their respective most recent individual
proposals to the Partnership (the “Joint Proposal”).  The Joint
Proposal contemplates the following, among other things:
 
 ·
              a
      commitment by NGP to participate in a portion of, and provide support for
      (“back-stop”), a rights offering and an equity
  offering;
 
 ·
              a
      commitment by Black Stone to purchase our Minerals Business for $170
      million;
 
 ·
              an
      assignment to us of all our incentive distribution rights and subordinated
      units;
 
 ·
              an
      option in favor of us to acquire our 844,551 outstanding general partner
      units by acquiring all of the outstanding equity of the general partner of
      our general partner and all of the limited partner units of our general
      partner, in exchange for one million newly-issued common units;
      and
 
 ·
              the
      payment by us to NGP of a transaction fee, payable at our option as $29
      million in cash or as some combination of cash, common units and/or
      warrants.
 
 At
management’s request to the Conflicts Committee of the Board of Directors
("Conflicts Committee"), the new incentives for the management team that were
included in NGP’s prior proposals were not included in the Joint
Proposal.
 We included
the original and revised term sheets received from NGP as exhibits to our Form
8-Ks filed with the Securities and Exchange Commission (“SEC”) on September 18,
2009 and October 13, 2009, respectively.  We included the original
term sheet from Black Stone as an exhibit to our Form 8-K filed with the SEC on
October 19, 2009.  We included the joint term sheet as an exhibit to
our Form 8-K filed with the SEC on November 9, 2009.
 
 Because a
transaction between NGP and us would be a related-party transaction, our Board
of Directors previously authorized our Conflicts Committee to review the prior
NGP proposals with the Conflicts Committee’s financial advisors and legal
counsel and negotiate same with NGP on behalf of the
Partnership.  Because the Joint Proposal would be a related-party
transaction, the Conflicts Committee is similarly authorized to review the Joint
Proposal with its financial and legal counsel.  The Conflicts
Committee has not yet determined that the Joint Proposal constitutes an
acceptable framework for negotiation of definitive documents.
 
 We caution
our unitholders that the joint proposal is not binding at this time, that
neither the Board of Directors nor the Conflicts Committee has made any decision
with respect to the joint proposal, and that there can be no assurance that any
definitive documents will be executed or that any transaction will be approved
or consummated.
  Presentation of Financial
Information


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




How
We Evaluate Our Operations




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




34
 Table of Contents





General
Trends and Outlook




We expect
our business to continue to be affected by the key trends as discussed in our
Annual Report on Form 10-K for the year ended December 31, 2008 and that the
recent events impacting the world’s economy and financial markets will play an
important role in the performance and growth prospects of our
business.  These recent events include but are not limited to:
continued turbulence in the world’s banking system and reduced availability of
credit on attractive terms; precipitous drops in the value of almost all asset
classes including equity, bonds, real estate, and other investment vehicles;
significant volatility in commodity prices including the prices for crude oil,
natural gas, NGLs, condensate, and sulfur, among others; the significant
reaction to the fall in natural gas prices by our producer customers in the
Midstream Business, especially in the form of reduced drilling activity and
curtailment or shutting-in of natural gas production; as well as the possibility
of a prolonged period of economic recession. Our expectations are based on
assumptions made by us and information currently available to us. To the extent
our underlying assumptions about our interpretations of available information
prove to be incorrect, our actual results may vary materially from our expected
results.





On April 29,
2009, we announced that the borrowing base under our revolving credit facility,
which relates to our Upstream Business, was redetermined down to $135 million
from $206 million.  This meaningful reduction in the borrowing base
occurred in connection with a regularly scheduled redetermination in accordance
with our revolving credit facility and is primarily the result of the
deterioration of commodity prices in the oil, natural gas and sulfur
industries.





We announced
in October 2009 that the existing borrowing base of $135 million under our
revolving credit facility was reaffirmed by our commercial lenders as a result
of our regularly scheduled semi-annual borrowing base redetermination. The
reaffirmation is effective as of October 1, 2009, with no additional fees or
increases in interest rate spread incurred. We remain in compliance with the
financial and other covenants in our revolving credit
facility.





In light of
the borrowing base redetermination and the deterioration of commodity prices in
the oil and natural gas industry, which has led to declines in our customers’
drilling activity and hydrocarbon throughput volumes in our gathering and
processing systems, as well as reduced revenues in our Upstream and Minerals
businesses, the Board of Directors has determined it is prudent to create cash
reserves for the proper conduct of our business and to remain in compliance with
financial covenants under our revolving credit facility.  The cash not
distributed to unitholders will be used primarily to reduce our outstanding debt
under our revolving credit facility and to continue the execution of our hedge
strategy to maintain future cash flows.  We anticipate continuing this
strategy until our Board of Directors determines that our leverage ratio is at
an appropriate level for the proper conduct of our business. In making this
determination, we anticipate that our Board of Directors will also focus on
certain aspects of our business which include, but are not limited to,
improvement in commodity prices in the oil and natural gas industry, and
increases in our producer customers’ drilling activity and resulting throughput
volumes in our gathering and processing systems.





On October
28, 2009, we announced that we will pay a quarterly cash distribution of $0.025
per common and general partner unit for the quarter ended September 30, 2009,
which is consistent with the distribution payment for the quarters ended June
30, 2009 and March 31, 2009.  This is consistent with the distribution
paid in the first and second quarters of 2009 but a reduction from the $0.41 per
unit distributed to all unitholders for the quarter ended December 31,
2008.  The distribution will be paid on November 13, 2009 to our
general partner and common unit holders of record as of the close of business on
November 9, 2009.




Cautionary
Note Regarding Forward-Looking Statements





Certain
matters discussed in this report, excluding historical information, include
certain “forward-looking” statements. Statements using words such as
“anticipate,” “believe,” “intend,” “project,” “plan,” “continue,” “estimate,”
“forecast,” “may,” “will,” or similar expressions help identify forward-looking
statements. Although we believe such forward-looking statements are based on
reasonable assumptions and current expectations and projections about future
events, no assurance can be given that these objectives will be reached. In
addition, forward-looking statements speak only as of the date on which such
statements are made.  Actual results may differ materially from any
results projected, forecasted, estimated or expressed in forward-looking
statements because many of the factors which determine these results are subject
to uncertainties and risks, difficult to predict, and beyond management’s
control. We assume no obligation to update any forward-looking statement as of
any future date.  For additional discussion of risks, uncertainties
and assumptions, see our annual report on Form 10-K for the year ended
December 31, 2008, filed with the Securities and Exchange Commission on
March 13, 2009 as well as the risks disclosed in Part II, Item 1A below and in
our previous quarterly reports on Form 10-Q filed during 2009.


35
 Table of Contents




Summary
of Consolidated Operating Results




Below is
a summary table of our consolidated operating results for the three and nine
months ended September 30, 2009 and September 30, 2008, 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
      30,2009
            
            
            2008
            
            
            2009
            
            
            2008($
      in thousands)REVENUE:Natural
      gas, natural gas liquids, oil, condensate and sulfur sales
            
            $
            156,779
            
            
            $
            341,700
            
            
            $
            468,589
            
            
            $
            1,008,891Gathering,
      compression, processing and treating services
            
            
            11,814
            
            
            
            12,513
            
            
            
            35,043
            
            
            
            27,741Minerals
      and royalty income
            
            
            4,050
            
            
            
            17,393
            
            
            
            10,788
            
            
            
            34,606Realized
      commodity derivative gains (losses)
            
            
            17,170
            
            
            
            (24,105
            )
            
            
            70,431
            
            
            
            (64,388
            )Unrealized
      commodity derivative (losses) gains
            
            
            (26,002
            )
            
            
            255,956
            
            
            
            (127,568
            )
            
            
            (33,381
            )Other
      revenue
            
            
            50
            
            
            
            428
            
            
            
            1,770
            
            
            
            610Total
      revenue
            
            
            163,861
            
            
            
            603,885
            
            
            
            458,053
            
            
            
            974,079COSTS
      AND EXPENSES:Cost
      of natural gas and natural gas liquids
            
            
            109,945
            
            
            
            237,742
            
            
            
            358,802
            
            
            
            726,400Operations
      and maintenance (b)
            
            
            16,934
            
            
            
            21,475
            
            
            
            54,624
            
            
            
            54,772Taxes
      other than income
            
            
            2,934
            
            
            
            5,365
            
            
            
            8,790
            
            
            
            14,975General
      and administrative
            
            
            10,449
            
            
            
            9,893
            
            
            
            34,882
            
            
            
            31,161Other
      operating (income) expenses
            
            
            —
            
            
            
            3,920
            
            
            
            (3,552
            )
            
            
            10,134Impairment
            
            
            274
            
            
            
            —
            
            
            
            516
            
            
            
            —Depreciation,
      depletion, and amortization
            
            
            28,586
            
            
            
            28,597
            
            
            
            86,237
            
            
            
            80,799Total
      costs and expenses
            
            
            169,122
            
            
            
            306,992
            
            
            
            540,299
            
            
            
            918,241OPERATING
      (LOSS) GAIN
            
            
            (5,261
            )
            
            
            296,893
            
            
            
            (81,246
            )
            
            
            55,838OTHER
      INCOME (EXPENSE):Interest
      income
            
            
            10
            
            
            
            212
            
            
            
            183
            
            
            
            673Other
      income
            
            
            725
            
            
            
            434
            
            
            
            1,835
            
            
            
            2,867Interest
      expense, net
            
            
            (4,315
            )
            
            
            (7,498
            )
            
            
            (17,282
            )
            
            
            (23,576
            )Realized
      interest rate derivative losses
            
            
            (5,040
            )
            
            
            (2,358
            )
            
            
            (13,669
            )
            
            
            (4,903
            )Unrealized
      interest rate derivative (losses) gains
            
            
            (5,308
            )
            
            
            (501
            )
            
            
            9,745
            
            
            
            (472
            )Other
      expense
            
            
            (267
            )
            
            
            (205
            )
            
            
            (801
            )
            
            
            (652
            )Total
      other income (expense)
            
            
            (14,195
            )
            
            
            (9,916
            )
            
            
            (19,989
            )
            
            
            (26,063
            )(LOSS)
      INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAX
            
            
            (19,456
            )
            
            
            286,977
            
            
            
            (101,235
            )
            
            
            29,775INCOME
      TAX PROVISION (BENEFIT)
            
            
            5,841
            
            
            
            (500
            )
            
            
            1,634
            
            
            
            (1,497
            )(LOSS)
      INCOME  FROM CONTINUING OPERATIONS
            
            
            (25,297
            )
            
            
            287,477
            
            
            
            (102,869
            )
            
            
            31,272DISCONTINUED
      OPERATIONS
            
            
            26
            
            
            
            594
            
            
            
            266
            
            
            
            1,451NET
      (LOSS) INCOME
            
            $
            (25,271
            )
            
            $
            288,071
            
            
            $
            (102,603
            )
            
            $
            32,723ADJUSTED
      EBITDA (a)
            
            $
            51,285
            
            
            $
            74,881
            
            
            $
            137,156
            
            
            $
            184,299





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


(b)
            Includes
      costs to dispose of sulfur in our Upstream Segment of $0.3 million and
      $1.5 million for the three and nine months ended September 30,
      2009.




Adjusted
EBITDA, for the three and nine months ended September 30, 2009 and 2008,
excludes amortization of commodity hedge costs (including, for the three and
nine months ended September 30, 2009, costs of hedge reset transactions) of
$10.6 million, $33.8 million, $2.3 million and $6.8 million,
respectively.  Including these amortization costs, our Adjusted EBITDA
for the three and nine months ended September 30, 2009 and 2008, would have been
$40.7 million, $103.3 million, $72.6 million and $177.5 million,
respectively.


36
 Table of Contents


Midstream
Business (Four Segments)




Texas
Panhandle Segment


Three
      Months Ended
              September
      30,
            
            
            Nine
      Months Ended
              September
      30,2009
            
            
            2008
            
            
            2009
            
            
            2008($
      in thousands)Revenues:Natural
      gas, natural gas liquids, oil, and condensate sales
            
            $
            67,468
            
            
            $
            179,608
            
            
            $
            196,791
            
            
            $
            514,450Gathering
      and treating services
            
            
            2,795
            
            
            
            2,671
            
            
            
            8,209
            
            
            
            7,664Total
      revenues
            
            
            70,263
            
            
            
            182,279
            
            
            
            205,000
            
            
            
            522,114Cost
      of natural gas and natural gas liquids
            
            
            46,540
            
            
            
            138,428
            
            
            
            147,894
            
            
            
            398,828Operating
      costs and expenses:Operations
      and maintenance
            
            
            8,206
            
            
            
            9,190
            
            
            
            24,407
            
            
            
            25,653Depreciation
      and amortization
            
            
            11,602
            
            
            
            10,984
            
            
            
            33,660
            
            
            
            32,587Total
      operating costs and expenses
            
            
            19,808
            
            
            
            20,174
            
            
            
            58,067
            
            
            
            58,240Operating
      income (loss)
            
            $
            3,915
            
            
            $
            23,677
            
            
            $
            (961
            )
            
            $
            65,046Capital
      expenditures
            
            $
            1,332
            
            
            $
            7,152
            
            
            $
            5,042
            
            
            $
            20,607Realized
      average prices:Oil
      and condensate (per Bbl)
            
            $
            65.13
            
            
            $
            106.43
            
            
            $
            57.79
            
            
            $
            105.03Natural
      gas (per Mcf)
            
            $
            2.78
            
            
            $
            8.81
            
            
            $
            2.98
            
            
            $
            8.85NGLs
      (per Bbl)
            
            $
            33.55
            
            
            $
            66.36
            
            
            $
            29.33
            
            
            $
            67.62Production
      volumes:Gathering
      volumes (Mfc/d) (a)
            
            
            134,690
            
            
            
            159,254
            
            
            
            140,725
            
            
            
            154,190NGLs
      (net equity gallons)
            
            
            12,170,309
            
            
            
            12,728,821
            
            
            
            34,620,772
            
            
            
            38,519,981Condensate
      (net equity gallons)
            
            
            9,938,819
            
            
            
            10,023,469
            
            
            
            25,944,824
            
            
            
            25,767,353Natural
      gas short position (MMbtu/d) (a)
            
            
            (4,685
            )
            
            
            (4,150
            )
            
            
            (5,524
            )
            
            
            (5,458
            )





(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.




Revenues and Cost of Natural Gas and
Natural Gas Liquids.For the three and nine months ended September 30,
2009, revenues minus cost of natural gas and natural gas liquids for our Texas
Panhandle Segment operations totaled $23.7 million and $57.1 million,
respectively, compared to $43.9 million and $123.3 million, respectively, for
the three and nine months ended September 30, 2008. There were two primary
contributors to this decrease: (i) lower NGL and condensate pricing, as
compared to pricing in 2008, and (ii) lower NGL equity production as
compared to production in 2008.  The lower NGL equity production was
primarily due to approximately 4% lower gathered volumes in 2009 as compared to
2008 and due to operating certain plants in ethane rejection mode for much of
the first two months of 2009.  Ethane rejection operations occur when
we elect to not recover the ethane component in the natural gas stream in our
plants and instead choose to leave the ethane component in the residue gas
stream sold at the tailgates of our plants. Ethane rejection operations result
in a lower volume of equity NGLs with a correspondingly smaller natural gas
short position.  We operate in this manner when the value of ethane is
worth more in the gas stream than as a separate product.




The lower
gathering volumes during the three and nine months ended September 30, 2009
compared to the same period in the prior year were due to natural declines in
the underlying existing wells in addition to reduced drilling activity during
2009.   The dramatic fall in commodity prices experienced in the
latter part of 2008 and lasting into early 2009 has resulted in many of our
producer customers significantly reducing drilling activity in the Texas
Panhandle, presumably not to be resumed until commodity prices rise to levels
which justify drilling.   While oil prices have recovered from
the lows seen in the three months ended March 31, 2009, natural gas prices have
remained suppressed during the third quarter of 2009 because of an excess supply
of natural gas experienced in many regions of the country.





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





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





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





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




Operating Expenses.Operating
expenses, including taxes other than income, for the three and nine months ended
September 30, 2009 were $8.2 million and $24.4 million, respectively, compared
to $9.2 million and $25.7 million, respectively, for the three and nine months
ended September 30, 2008. The $1.0 million and $1.3 million decrease in
operating expenses during the three and nine months ended September 30, 2009,
respectively, as compared to the same periods in 2008, was primarily due to
overall cost reduction initiatives implemented by the Partnership across the
segment.





Depreciation and
Amortization. Depreciation and amortization expenses for the three and
nine months ended September 30, 2009 were $11.6 million and $33.7 million,
respectively, compared to $11.0 million and $32.6 million, respectively, for the
three and nine months ended September 30, 2008.  The major item
impacting the $0.6 million and $1.1 million increases, respectively, was
depreciation expense associated with the capital expenditures placed into
service during the period.




Capital Expenditures.Capital
expenditures for the three and nine months ended September 30, 2009 were $1.3
million and $5.0 million, respectively, compared to $7.2 million and $20.6
million, respectively, for the three and nine months ended September 30, 2008.
We classify capital expenditures as either maintenance capital (which represents
routine well connects and capitalized maintenance activities) or as growth
capital (which represents organic growth projects). In the three and nine months
ended September 30, 2009, growth capital represented 8% and 56% of our capital
expenditures as compared to 51% and 69%, respectively, in the three and nine
months ended September 30, 2008. The decrease in capital expenditures of $5.8
million and $15.6 million, respectively, was driven by reduced maintenance
capital associated with fewer new well connects due to the lower drilling
activity and by less growth capital due to expenditures related to our Stinnett
– Cargray plant consolidation project having occurred in the three and nine
months ended September 30, 2008.







37
 Table of Contents


East
Texas/Louisiana Segment


Three
      Months Ended
              September
      30,
            
            
            Nine
      Months Ended
              September
      30,2009(b)
            
            
            2008
            
            
            2009(b)
            
            
            2008($
      in thousands)Revenues:Natural
      gas, natural gas liquids, oil, and condensate sales
            
            $
            46,253
            
            
            $
            71,861
            
            
            $
            134,949
            
            
            $
            231,996Gathering
      and treating services
            
            
            7,367
            
            
            
            8,908
            
            
            
            21,951
            
            
            
            17,056Total
      revenues
            
            
            53,620
            
            
            
            80,769
            
            
            
            156,900
            
            
            
            249,052Cost
      of natural gas and natural gas liquids
            
            
            39,665
            
            
            
            66,007
            
            
            
            121,907
            
            
            
            209,937Operating
      costs and expenses:Operations
      and maintenance
            
            
            4,727
            
            
            
            4,194
            
            
            
            13,887
            
            
            
            11,511Depreciation
      and amortization
            
            
            4,458
            
            
            
            2,989
            
            
            
            13,469
            
            
            
            8,846Total
      operating costs and expenses
            
            
            9,185
            
            
            
            7,183
            
            
            
            27,356
            
            
            
            20,357Operating
      income
            
            $
            4,770
            
            
            $
            7,579
            
            
            $
            7,637
            
            
            $
            18,758Capital
      expenditures
            
            $
            2,094
            
            
            $
            2,591
            
            
            $
            16,172
            
            
            $
            8,686Realized
      average prices:Oil
      and condensate (per Bbl)
            
            $
            65.49
            
            
            $
            125.29
            
            
            $
            59.35
            
            
            $
            117.16Natural
      gas (per Mcf)
            
            $
            3.42
            
            
            $
            9.69
            
            
            $
            3.74
            
            
            $
            10.37NGLs
      (per Bbl)
            
            $
            41.37
            
            
            $
            57.54
            
            
            $
            30.63
            
            
            $
            56.28Production
      volumes:Gathering
      volumes (Mfc/d) (a)
            
            
            236,561
            
            
            
            173,728
            
            
            
            257,957
            
            
            
            172,434NGLs
      (net equity gallons)
            
            
            5,830,042
            
            
            
            6,387,873
            
            
            
            14,672,928
            
            
            
            17,321,951Condensate
      (net equity gallons) (c)
            
            
            218,552
            
            
            
            628,824
            
            
            
            1,603,175
            
            
            
            1,851,850Natural
      gas long position (MMbtu/d) (a)
            
            
            2,295
            
            
            
            747
            
            
            
            2,790
            
            
            
            885





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


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


(c)
            All
      prior periods have been updated to reflect the intrasystem movement of
      certain condensate net equity gallons previously unreported.  For the
      three months ended September 30, 2009, the net equity condensate gallons
      reflect the impact of a negative entry of 257,192 gallons resulting from a
      correction in our estimation model for net equity condensate gallons
      at the Brookeland Plant.  Revenues and cost of natural gas and
      natural gas liquids were not impacted by these statistical
      corrections.


Revenues and Cost of Natural Gas and
Natural Gas Liquids. For the three and nine months ended September 30,
2009, revenues minus cost of natural gas and natural gas liquids for our East
Texas/Louisiana Segment totaled $14.0 million and $35.0 million, respectively,
compared to $14.8 million and $39.1 million, respectively, for the three and
nine months ended September 30, 2008.  The Millennium Acquisition
positively impacted the East Texas/Louisiana Segment’s revenue minus cost of
natural gas and natural gas liquids by $3.1 million and $8.6 million,
respectively, during the three and nine months ended September 30,
2009.  Our lower NGL equity gallons for the nine months ended
September 30, 2009 were primarily due to operating the facilities in ethane
rejection mode during much of the first two months of 2009. Ethane rejection
mode is when we elect to not recover the ethane component in the natural gas
stream in our plants and instead choose to leave the ethane component in the
residue gas stream sold at the tailgates of our plants.  We operate in
this manner when the value of ethane is worth more in the gas stream than as a
separate product.




We were
negatively impacted by lower NGL and condensate pricing during the three and
nine months ended September 30, 2009 as compared to the three and nine months
ended September 30, 2008. We were positively impacted by 38% growth in gathering
volume during the nine months ended September 30, 2009 compared to the nine
months ended September 30, 2008 due to the Millennium
Acquisition.  Other East Texas/Louisiana Segment gathering systems
realized a reduction in volumes. Excluding the Millennium Acquisition, our
gathering volumes decreased by 11%. The offsetting reduction in higher margin
gas volumes is being replaced with lower margin, fixed fee volumes from the
Millennium Acquisition.  The gas volumes from the Millennium
Acquisition are comprised primarily of dry gas that does not require processing
to remove NGLs prior to delivery to the interstate pipelines in order to meet
the pipelines’ gas quality tariff requirements.  The lower margin gas,
though contributing to a significant increase in overall gathered volumes, has
not offset the lower revenues and margins due to the lower NGL, condensate and
natural gas prices during the first nine months of 2009 as compared to the same
time period in 2008.  During the last three months of 2008 and
continuing into the first nine months of 2009, we saw a significant reduction in
our customer’s drilling activity due to lower commodity values.




During
the month of September 2009, two producers curtailed their gas production due to
low natural gas prices by a total of approximately 17,500 Mcf/d for the month
delivered to the Brookeland Plant and Tyler County gathering
system.  As of October 1, 2009, approximately 4,000 Mcf/d remained
curtailed due to natural gas prices.





Operating Expenses.Operating
expenses for the three and nine months ended September 30, 2009 were $4.7
million and $13.9 million, respectively, compared to $4.2 million and $11.5
million, respectively, for the three and nine months ended September 30, 2008.
The major items impacting the $0.5 million and $2.4 million increases in
operating expense for the three and nine months, respectively, was due to
expenses associated with operating the assets acquired as part of the Millennium
Acquisition.  Excluding operating expenses related to the assets
acquired as part of the Millennium Acquisition, operating expenses were
relatively flat for the three and nine months ended September 30, 2009 as
compared to the same periods in 2008.





Depreciation and Amortization.Depreciation and amortization expenses for the three and nine months
ended September 30, 2009 were $4.5 million and $13.5 million, respectively,
compared to $3.0 million and $8.8 million, respectively, for the three and nine
months ended September 30, 2008. The major items impacting the $1.5 million and
$4.6 million increases were (i) three and nine months of depreciation and
amortization of the assets acquired as part of Millennium Acquisition and
(ii) depreciation expense associated with the capital expenditures placed
into service.These
increases were offset by an adjustment of $0.9 million recorded during the three
months ended June 30, 2009 to correct an overstatement of depreciation expense
in a prior period.




Capital Expenditures.Capital
expenditures for the three and nine months ended September 30, 2009 were $2.1
million and $16.2 million, respectively, compared to $2.6 million and $8.7
million, respectively, for the three and nine months ended September 30, 2008.
We classify capital expenditures as either maintenance capital (which represents
routine well connects and capitalized maintenance activities) or as growth
capital (which represents organic growth projects). Our increase in capital
spending of $7.5 million for the nine months ended September 30, 2009 is due
primarily to the construction of gathering lines to producers in the Brookeland
and Tyler County gathering systems.







38
 Table of Contents


South Texas
Segment


Three
      Months Ended
              September
      30,
            
            
            Nine
      Months Ended
              September
      30,2009(b)
            
            
            2008
            
            
            2009(b)
            
            
            2008($
      in thousands)Revenues:Natural
      gas, natural gas liquids, oil, and condensate sales
            
            $
            17,324
            
            
            $
            35,253
            
            
            $
            73,863
            
            
            $
            122,689Gathering
      and treating services
            
            
            1,348
            
            
            
            934
            
            
            
            4,211
            
            
            
            3,021Other
            
            
            —
            
            
            
            —
            
            
            
            3
            
            
            
            2Total
      revenues
            
            
            18,672
            
            
            
            36,187
            
            
            
            78,077
            
            
            
            125,712Cost
      of natural gas and natural gas liquids
            
            
            16,842
            
            
            
            33,307
            
            
            
            71,730
            
            
            
            117,635Operating
      costs and expenses:Operations
      and maintenance
            
            
            896
            
            
            
            635
            
            
            
            2,946
            
            
            
            1,862Depreciation
      and amortization
            
            
            1,287
            
            
            
            939
            
            
            
            3,995
            
            
            
            2,812Total
      operating costs and expenses
            
            
            2,183
            
            
            
            1,574
            
            
            
            6,941
            
            
            
            4,674Operating
      (loss) income from continuing operations
            
            
            (353
            )
            
            
            1,306
            
            
            
            (594
            )
            
            
            3,403Discontinued
      operations
            
            
            26
            
            
            
            601
            
            
            
            266
            
            
            
            1,436Operating
      (loss) income
            
            $
            (327
            )
            
            $
            1,907
            
            
            $
            (328
            )
            
            $
            4,839Capital
      expenditures
            
            $
            27
            
            
            $
            201
            
            
            $
            41
            
            
            $
            780Realized
      average prices:Oil
      and condensate (per Bbl)
            
            $
            58.06
            
            
            $
            112.20
            
            
            $
            45.02
            
            
            $
            106.54Natural
      gas (per Mcf)
            
            $
            3.06
            
            
            $
            9.42
            
            
            $
            3.66
            
            
            $
            9.58NGLs
      (per Bbl)
            
            $
            30.71
            
            
            $
            83.16
            
            
            $
            28.74
            
            
            $
            77.70Production
      volumes:Gathering
      volumes (Mfc/d) (a)
            
            
            66,680
            
            
            
            80,097
            
            
            
            85,496
            
            
            
            81,228NGLs
      (net equity gallons)
            
            
            252,005
            
            
            
            —
            
            
            
            929,452
            
            
            
            —Condensate
      (net equity gallons)
            
            
            210,984
            
            
            
            571,615
            
            
            
            1,167,630
            
            
            
            1,399,183Natural
      gas long position (MMbtu/d) (a)
            
            
            1,784
            
            
            
            500
            
            
            
            928
            
            
            
            1,500





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


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




Revenues and Cost of Natural Gas and
Natural Gas Liquids.During the three and nine months ended September 30,
2009, the South Texas Segment contributed $1.8 million and $6.3 million,
respectively, in revenues minus cost of natural gas and natural gas liquids as
compared to $2.9 million and $8.1 million, respectively, for the three and nine
months ended September 30, 2008.  We were negatively impacted by lower
NGL, natural gas and condensate pricing during the three and nine months ended
September 30, 2009 as compared to the same periods in
2008.   This decline was partially offset by the impact of the
assets acquired as part of the Millennium Acquisition which contributed revenue
minus cost of natural gas and natural gas liquids of $0.9 million and $2.5
million, respectively, during the three and nine months ended September 30,
2009.





Operating Expenses.Operating
expenses for the three and nine months ended September 30, 2009 were $0.9
million and $2.9 million, respectively, compared to $0.6 million and $1.9
million, respectively, for the three and nine months ended September 30,
2008.  The major item impacting the $0.3 million and $1.1 million
increases in operating expense, for the three and nine months, respectively, was
the additional expenses associated with operating the assets acquired as part of
the Millennium Acquisition.




Depreciation and Amortization.Depreciation and amortization expenses for the three and nine months
ended September 30, 2009 were $1.3 million and $4.0 million, respectively,
compared to $0.9 million and $2.8 million, respectively, for the three and nine
months ended September 30, 2008.  The major item impacting the $0.3
million and $1.2 million increases, for the three and nine months, respectively,
was the additional depreciation and amortization of the assets acquired as part
of the Millennium Acquisition.





Capital Expenditures.Capital
expenditures for the three and nine months ended September 30, 2009 were less
than $0.1 million compared to $0.2 million and $0.8 million, respectively, for
the three and nine months ended September 30, 2008. We classify capital
expenditures as either maintenance capital (which represents routine well
connects and capitalized maintenance activities) or as growth capital (which
represents organic growth projects).





Discontinued
Operations.On April 1, 2009, we sold our producer services
line of business and thus have classified its revenues minus cost of natural gas
and natural gas liquids as discontinued operations.  During the nine
months ended September 30, 2009, our producer services business generated
revenues of $19.2 million and cost of natural gas and natural gas liquids of
$18.9 million, as compared to revenues of $221.3 million and cost of natural gas
and natural gas liquids of $219.8 million during the nine months ended September
30, 2008.





39
 Table of Contents
 
 Gulf of
Mexico Segment


Three
      Months Ended
              September
      30,
            
            
            Nine
      Months Ended
              September
      30,2009(b)
            
            
            2008
            
            
            2009(b)
            
            
            2008($
      in thousands)Revenues:Natural
      gas, natural gas liquids, oil, and condensate sales
            
            $
            8,314
            
            
            $
            —
            
            
            $
            20,380
            
            
            $
            —Gathering
      and treating services
            
            
            304
            
            
            
            —
            
            
            
            672
            
            
            
            —Other
      revenue
            
            
            —
            
            
            
            —
            
            
            
            1,616
            
            
            
            —Total
      revenues
            
            
            8,618
            
            
            
            —
            
            
            
            22,668
            
            
            
            —Cost
      of natural gas and natural gas liquids
            
            
            6,898
            
            
            
            —
            
            
            
            17,271
            
            
            
            —Operating
      costs and expenses:Operations
      and maintenance
            
            
            310
            
            
            
            —
            
            
            
            1,386
            
            
            
            —Depreciation
      and amortization
            
            
            1,480
            
            
            
            —
            
            
            
            4,445
            
            
            
            —Total
      operating costs and expenses
            
            
            1,790
            
            
            
            —
            
            
            
            5,831
            
            
            
            —Operating
      loss
            
            $
            (70
            )
            
            $
            —
            
            
            $
            (434
            )
            
            $
            —Capital
      expenditures
            
            $
            165
            
            
            $
            —
            
            
            $
            306
            
            
            $
            —Realized
      average prices:Oil
      and condensate (per Bbl)
            
            $
            65.67
            
            
            $
            —
            
            
            $
            54.50
            
            
            $
            —Natural
      gas (per Mcf)
            
            $
            3.46
            
            
            $
            —
            
            
            $
            4.64
            
            
            $
            —NGLs
      (per Bbl)
            
            $
            37.70
            
            
            $
            —
            
            
            $
            31.79
            
            
            $
            —Production
      volumes:Gathering
      volumes (Mfc/d) (a)
            
            
            131,527
            
            
            
            —
            
            
            
            115,591
            
            
            
            —NGLs
      (net equity gallons)
            
            
            1,376,512
            
            
            
            —
            
            
            
            4,280,670
            
            
            
            —





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


(b)
            This
      segment was created upon closing of the Millennium Acquisition on October
      1, 2008.





Revenues and Cost of Natural Gas and
Natural Gas Liquids.We entered into this segment as a result of the
Millennium Acquisition, effective October 1, 2008.During the three and
nine months ended September 30, 2009, the Gulf of Mexico Segment contributed
$1.7 million and $5.4 million, respectively, in revenues minus cost of natural
gas and natural gas liquids.  As a result of damage inflicted by
Hurricanes Gustav and Ike in August 2008 and September 2008, respectively, the
Yscloskey plant did not come back online until mid-January 2009 and the North
Terrebonne plant did not come back online until mid-November 2008. We received a
partial payment of approximately $1.6 million for business interruption caused
by Hurricanes Gustav and Ike which we recognized as other revenue during the
three months ended June 30, 2009.





Operating
Expenses.Operating expenses for the three and nine months
ended September 30, 2009 were $0.3 million and $1.4 million,
respectively.  We continued to incur operating expenses associated
with the Yscloskey and North Terrebonne plants while the plants were undergoing
repair for the hurricane damage.  We also incurred costs for the
repair of the two plants.  Such costs were recovered from the escrow
account established pursuant to the Millennium Acquisition purchase and sale
agreement.  As a result and pursuant to the agreement, any insurance
proceeds received for repair costs will be deposited into the escrow
account.  During the nine months ended September 30, 2009, we received
payment from the Millennium Acquisition escrow in the amount of $0.3 million in
cash and began canceling common units held in escrow to satisfy additional
claims.





Depreciation and Amortization.Depreciation and amortization expenses for the three and nine months
ended September 30, 2009 were $1.5 million and $4.4 million,
respectively.





Capital
Expenditures.Capital expenditures for the three and nine
month periods ended September 30, 2009 for the Gulf of Mexico Segment were $0.2
million and $0.3 million, respectively.







40
 Table of Contents




Upstream
Business (One segment)


Three
      Months Ended
              September
      30,
            
            
            Nine
      Months Ended
              September
      30,2009
            
            
            2008(a)
            
            
            2009
            
            
            2008(a)($
      in thousands)Revenues:Oil
      and condensate sales (b)
            
            $
            10,817
            
            
            $
            22,694
            
            
            $
            25,373
            
            
            $
            62,153Natural
      gas sales (c)
            
            
            2,221
            
            
            
            11,168
            
            
            
            7,081
            
            
            
            27,725Natural
      gas liquids sales (d)
            
            
            4,382
            
            
            
            8,059
            
            
            
            10,152
            
            
            
            24,354Sulfur
      sales
            
            
            —
            
            
            
            13,057
            
            
            
            —
            
            
            
            25,524Other
            
            
            50
            
            
            
            428
            
            
            
            151
            
            
            
            608Total
      revenues
            
            
            17,470
            
            
            
            55,406
            
            
            
            42,757
            
            
            
            140,364Operating
      costs and expenses:Operations
      and maintenance
            
            
            5,178
            
            
            
            12,394
            
            
            
            18,311
            
            
            
            29,369Sulfur
      disposal costs
            
            
            348
            
            
            
            —
            
            
            
            1,505
            
            
            
            —Impairment
            
            
            —
            
            
            
            —
            
            
            
            242
            
            
            
            —Other
      operating income
            
            
            —
            
            
            
            —
            
            
            
            (3,552
            )
            
            
            —Depreciation
      and amortization
            
            
            7,768
            
            
            
            11,170
            
            
            
            25,119
            
            
            
            29,509Total
      operating costs and expenses
            
            
            13,294
            
            
            
            23,564
            
            
            
            41,625
            
            
            
            58,878Operating
      income
            
            $
            4,176
            
            
            $
            31,842
            
            
            $
            1,132
            
            
            $
            81,486Capital
      expenditures
            
            $
            2,780
            
            
            $
            4,532
            
            
            $
            6,360
            
            
            $
            17,716Realized
      average prices (e):Oil
      and condensate (per Bbl)
            
            $
            50.78
            
            
            $
            98.36
            
            
            $
            40.79
            
            
            $
            100.79Natural
      gas (per Mcf)
            
            $
            3.25
            
            
            $
            9.05
            
            
            $
            3.47
            
            
            $
            9.41NGLs
      (per Bbl)
            
            $
            34.67
            
            
            $
            67.35
            
            
            $
            27.07
            
            
            $
            66.58Sulfur
      (per Long ton)
            
            $
            —
            
            
            $
            505.77
            
            
            $
            —
            
            
            $
            355.63Production
      volumes:Oil
      and condensate (Bbl)
            
            
            213,351
            
            
            
            230,727
            
            
            
            628,527
            
            
            
            616,643Natural
      gas (Mcf)
            
            
            991,827
            
            
            
            1,233,951
            
            
            
            2,792,316
            
            
            
            2,949,241NGLs
      (Bbl)
            
            
            128,379
            
            
            
            119,664
            
            
            
            375,215
            
            
            
            365,761Total
      (Mcfe)
            
            
            3,042,207
            
            
            
            3,336,297
            
            
            
            8,814,768
            
            
            
            8,843,665Sulfur
      (Long ton)
            
            
            27,634
            
            
            
            25,816
            
            
            
            96,063
            
            
            
            71,772





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


(b)
            Revenues
      include a change in the value of product imbalances of $0 and $(260) for
      the three and nine months ended September 30, 2009,
      respectively.  No changes in the value of the product imbalances
      were recognized during the three and nine months ended September 30,
      2008.


(c)
            Revenues
      include a change in the value of product imbalances of $(780) and $(2,377)
      for the three and nine months ended September 30, 2009,
      respectively.  No changes in the value of the product imbalances
      were recognized during three and nine months ended September 30,
      2008.


(d)
            Revenues
      include a change in the value of product imbalances of $0 and $28 for the
      three and nine months ended September 30, 2009,
      respectively.  No changes in the value of the product imbalances
      were recognized during the three and nine months ended September 30,
      2008.


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




Revenue. For the three and
nine months ended September 30, 2009 and 2008, the Upstream Segment contributed
$17.5 million, $42.8 million, $55.4 million and $140.4 million of revenue,
respectively.  The decrease in revenue was due to substantially lower
realized prices for oil, natural gas, NGLs and sulfur and the non-cash
mark-to-market of product imbalances, partially offset by an additional one
month and four months, respectively, of operations related to the assets
acquired in the Stanolind Acquisition.  During the three and nine
months ended September 30, 2009, production averaged 10.8 MMcf/d and 10.3 MMcf/d
of natural gas, respectively, 2.3 MBO/d and 2.3 MBO/d of oil and condensate,
respectively, 1.4 MB/d of NGL’s and 1.4 MB/d of NGL’s, respectively and 300 LT/d
of sulfur and 353 LT/d of sulfur, respectively.  The period included
three and nine months of production from the assets acquired in the Stanolind
Acquisition which averaged 746 Boe/d and 803 Boe/d,
respectively.  During the three and nine months ended September 30,
2009, the Big Escambia Creek (BEC) plant experienced reduced oil, residue gas
and NGL sales due to unanticipated repairs and overhauls to the plant’s residue
gas compressors.  Sales of oil, residue gas and NGLs from BEC, Flomaton and
Fanny Church fields were curtailed for 44 and 60 days, during the three and nine
months ended September 30, 2009, respectively, associated with the compressors’
downtime.  The reduced production during these periods negatively impacted
Upstream revenues by approximately $1.1 million and $2.6 million,
respectively.




During
the three and nine months ended September 30, 2009, the cost to dispose of
sulfur exceeded the sales price by $0.3 million and $1.5 million, respectively,
compared to revenue of $13.1 million and $25.5 million, respectively, during the
three and nine months ended September 30, 2008.  Historically, sulfur
was viewed as a low value by-product in the production of oil and natural
gas.  Due to an increase in demand in the global fertilizer market
during the first nine months of 2008, the price per long ton (before effects of
net-backs) peaked at over $600 at the Tampa, Florida market in September,
2008.  Deterioration in the sulfur market during the nine months ended
September 30, 2009 has caused the price at the Tampa, Florida market to decline
to $5 per long ton, and we are incurring costs to dispose of our sulfur at this
time.   We expect this to be an ongoing issue until sulfur demand
improves.




Operating Expenses. Operating
expenses, including severance and ad valorem taxes, totaled $5.2 million and
$18.3 million, respectively, for the Upstream Segment during the three and nine
months ended September 30, 2009, as compared to $12.4 million and $29.4 million,
respectively, for the three and nine months ended September 30,
2008.  The operating expenses include nine months of expenses related
to the assets acquired in the Stanolind Acquisition during 2009 compared to only
five months for the same period in 2008.  The decrease in operating
expense can be attributed to lower well workover expense incurred during the
three and nine months ended September 30, 2009 as compared to the same period in
the prior year and additional expenses being incurred during the three and nine
months ended September 30, 2008 due to the turnaround at the BEC treating
facility in April 2008.  The decrease during the three and nine months
ended September 30, 2009 is also due to a reversal of $1.6 million in
environmental reserves determined to no longer be necessary as well as a credit
of $0.7 million for overbilling related to a non-operated asset .




Depreciation, Depletion and
Amortization.Depreciation, depletion and amortization expense for the
three and nine months ended September 30, 2009 was $7.8 million and $25.1
million, respectively, as compared to $11.2 million and $29.5 million,
respectively for the three and nine month periods ended September 30, 2008,
respectively.  The decrease for the nine months ended September 30,
2009 compared to the comparable period in 2008 is due to the decrease in our
depletable base as a result of the impairment charges we incurred during the
last three months of fiscal year 2008.  This decrease was partially
offset by the depletion expense related to the assets added through the
Stanolind Acquisition for the first nine months of 2009 compared to only five
months during the same period in 2008 and the curtailed production during the
nine months ended September 30, 2008 due to the turnaround at the BEC treating
facility in April 2008.





Impairment.During the
nine months ended September 30, 2009 specifically, during the three months ended
March 31, 2009, we incurred impairment charges related to certain fields within
our Upstream Segment of $0.2 million due to the continued decline of natural gas
prices during the period.  No impairment charges were incurred during
the nine months ended September 30, 2008.




Other Operating
Income.Other operating income for the nine months ended
September 30, 2009, includes income of $3.6 million due to the recovery of $2.2
million of assets previously written off and the release of $1.4 million of
liabilities assumed as part of our purchase price allocation for our
acquisitions of Escambia Asset Co. LLC and Redman Energy Holdings,
L.P.  During the period, we received additional information about
collectability of these assets and determined that we no longer had any
obligation under these liabilities.




Capital
Expenditures.  The Upstream Segment’s maintenance capital
expenditures for the three and nine months ended September 30, 2009 and 2008 was
$2.8 million, $6.4 million, $4.5 million and $17.7 million,
respectively.  Growth capital expenditures during the three and nine
months ended September 30, 2009 totaled $2.2 million and $3.1 million,
respectively, and were associated with the completion of drilling projects
associated with properties acquired in the Stanolind Acquisition.  We
did not incur any growth capital expenditures during the three and nine months
ended September 30, 2008.  The maintenance capital expenditures during
the three and nine months ended September 30, 2009 were associated with
compressor overhauls at the BEC and Flomaton treating facilities and well
completions, recompletions, workovers, equipping and leasing activities. 
The
higher maintenance capital expenditures in the nine months ended September 30,
2009 were related primarily to a planned turnaround at our Big Escambia Creek
(“BEC”) facility.


41
 Table of Contents


Minerals
Business (One segment)




Three
      Months Ended
              September
      30,
            
            
            Nine
      Months Ended
              September
      30,2009
            
            
            2008
            
            
            2009
            
            
            2008($
      in thousands)Revenues:Oil
      and condensate sales
            
            $
            2,228
            
            
            $
            4,390
            
            
            $
            6,136
            
            
            $
            12,489Natural
      gas sales
            
            
            749
            
            
            
            3,044
            
            
            
            2,454
            
            
            
            8,818Natural
      gas liquids sales
            
            
            169
            
            
            
            413
            
            
            
            367
            
            
            
            1,059Lease
      bonus, rentals and other
            
            
            904
            
            
            
            9,546
            
            
            
            1,831
            
            
            
            12,240Total
      revenues
            
            
            4,050
            
            
            
            17,393
            
            
            
            10,788
            
            
            
            34,606Operating
      costs and expenses:Operations
      and maintenance
            
            
            203
            
            
            
            427
            
            
            
            972
            
            
            
            1,352Impairment
            
            
            274
            
            
            
            —
            
            
            
            274
            
            
            
            —Depletion
            
            
            1,654
            
            
            
            2,321
            
            
            
            4,781
            
            
            
            6,460Total
      operating costs and expenses
            
            
            2,131
            
            
            
            2,748
            
            
            
            6,027
            
            
            
            7,812Operating
      income
            
            $
            1,919
            
            
            $
            14,645
            
            
            $
            4,761
            
            
            $
            26,794Realized
      average prices:Oil
      and condensate (per Bbl)
            
            $
            63.96
            
            
            $
            104.62
            
            
            $
            52.87
            
            
            $
            103.47Natural
      gas (per Mcf)
            
            $
            2.31
            
            
            $
            9.36
            
            
            $
            2.76
            
            
            $
            8.99NGLs
      (per Bbl)
            
            $
            29.44
            
            
            $
            59.16
            
            
            $
            23.62
            
            
            $
            60.92Production
      volumes:Oil
      and condensate (Bbl)
            
            
            34,841
            
            
            
            42,004
            
            
            
            117,979
            
            
            
            120,744Natural
      gas (Mcf)
            
            
            264,082
            
            
            
            336,060
            
            
            
            853,571
            
            
            
            991,534NGLs
      (Bbl)
            
            
            5,739
            
            
            
            6,981
            
            
            
            15,110
            
            
            
            17,381Total
      (Mcfe)
            
            
            507,562
            
            
            
            629,970
            
            
            
            1,652,106
            
            
            
            1,820,288




Revenue.  For the
three and nine months ended September 30, 2009 our revenue was $4.1 million and
$10.8 million, respectively, as compared to $17.4 million and $34.6 million for
the three and nine months ended September 30, 2008, respectively.  The
decrease in revenue was due to decreases in commodity prices and lower
production volumes as well as much lower bonus income due to the reduced leasing
activity in the three and nine months ended September 30, 2009 as compared to
the three and nine months ended September 30, 2008.  In addition,
during the three and nine months ended September 30, 2009, our natural gas
production volumes and related revenues were negatively impacted by
approximately 37,000 Mcf due to a correction by an operator of  the
Fruitland Coal field, in which we hold mineral interests.




One of the
distinctive characteristics of our large, diversified mineral position is that
operators are continually conducting exploration and development drilling,
recompletion, and workover operations on our interests; in our minerals segment,
we refer to this phenomenon as “regeneration.” We do not pay for these
operations, but we do receive a share of the production they generate. This mode
of operation has resulted in relatively constant production rates from our
mineral interests in the past, and while we expect that regeneration will
continue, we are uncertain if it will continue at rates sufficient to maintain
or grow the segment’s production rate so long as commodity prices remain at
their current levels. We have observed rapid and significant reductions in the
active drilling rig count in virtually every producing basin of the United
States, except for the Haynesville (North Louisiana and East Texas) and
Marcellus (Appalachian region) shale plays. The new sources of production that
we expect will materialize due to regeneration will also be the source of future
extensions and discoveries and positive revisions to our reserve estimates,
which may effect out future depletion rates.  During the three and
nine months ended September 30, 2009, as a result of regeneration we received an
initial royalty payment for 15 and 150 new wells, respectively.





Additionally,
we received approximately $0.9 million and $1.8 million in bonus and delay
rental payments during the three and nine months ended September 30, 2009,
respectively, and $9.5 million and $12.2 million in the three and nine months
ended September 30, 2008, respectively. The amount of revenue we receive from
bonus and rental payments varies significantly from month to month; therefore,
we do not believe a meaningful set of conclusions can be drawn by observing
changes in leasing activity over small time periods. Commodity prices may affect
the amount of leasing that will occur on the minerals in future periods, and it
is impossible to predict the timing or amount of future bonus
payments.  However, we do expect to receive some level of bonus
payments in the future.




Operating Expenses. Operating
expenses of $0.2 million and $1.0 million for the three and nine months ended
September 30, 2009, respectively as compared to $0.4 million and $1.4 million
for the three and nine months ended September 30, 2008, respectively, are
predominately production and ad valorem taxes. These taxes are levied by various
state and local taxing entities.





Impairment.During the
three and nine months ended September 30, 2009, we incurred impairment charges
related to certain fields within our Minerals Segment of $0.3 million due to a
decline in natural gas prices and a slight reduction in oil reserves based on
updated production performance during the period.  No impairment
charges were incurred during the three and nine months ended September 30,
2008.




Depletion.  Our
depletion during the three and nine months ended September 30, 2009 was $1.7
million and $4.8 million, respectively, as compared to $2.3 million and $6.5
million for the three and nine months ended September 30, 2008,
respectively.  The decrease in depletion expense for the nine months
ended September 30, 2009, as compared to the same period in the prior year, is
due to lower production and an incorrect rate being used to calculate depletion
causing an overstatement of depletion during the first three months in
2008.  An adjustment of $0.7 million was recorded during the three
months ended September 30, 2008 to correct this overstatement.




42
 
 Corporate
Segment




Three
      Months Ended
              September
      30,
            
            
            Nine
      Months Ended
              September
      30,2009
            
            
            2008
            
            
            2009
            
            
            2008($
      in thousands)Revenues:Unrealized
      commodity derivative (losses) gains
            
            $
            (26,002
            )
            
            $
            255,956
            
            
            $
            (127,568
            )
            
            $
            (33,381
            )Realized
      commodity derivative gains (losses)
            
            
            17,170
            
            
            
            (24,105
            )
            
            
            70,431
            
            
            
            (64,388
            )Total
      revenue
            
            
            (8,832
            )
            
            
            231,851
            
            
            
            (57,137
            )
            
            
            (97,769
            )Costs
      and expenses:General
      and administrative
            
            
            10,449
            
            
            
            9,893
            
            
            
            34,882
            
            
            
            31,161Other
      operating expenses
            
            
            —
            
            
            
            3,920
            
            
            
            —
            
            
            
            10,134Depreciation,
      depletion, and amortization
            
            
            337
            
            
            
            194
            
            
            
            768
            
            
            
            585Total
      costs and expenses
            
            
            10,786
            
            
            
            14,007
            
            
            
            35,650
            
            
            
            41,880Segment
      operating (loss) income
            
            
            (19,618
            )
            
            
            217,844
            
            
            
            (92,787
            )
            
            
            (139.649
            )Other
      income (expense):Interest
      income
            
            
            10
            
            
            
            212
            
            
            
            183
            
            
            
            673Other
      income
            
            
            725
            
            
            
            434
            
            
            
            1,835
            
            
            
            2,867Interest
      expense, net
            
            
            (4,315
            )
            
            
            (7,498
            )
            
            
            (17,282
            )
            
            
            (23,576
            )Realized
      interest rate derivative losses
            
            
            (5,040
            )
            
            
            (2,358
            )
            
            
            (13,669
            )
            
            
            (4,903
            )Unrealized
      interest rate derivative (losses) gains
            
            
            (5,308
            )
            
            
            (501
            )
            
            
            9,745
            
            
            
            (472
            )Other
      expense
            
            
            (267
            )
            
            
            (205
            )
            
            
            (801
            )
            
            
            (652
            )Total
      other income (expense)
            
            
            (14,195
            )
            
            
            (9,916
            )
            
            
            (19,989
            )
            
            
            (26,063
            )(Loss)
      income from continuing operations before taxes
            
            
            (33,813
            )
            
            
            207,928
            
            
            
            (112,776
            )
            
            
            (165,712
            )Income
      tax provision (benefit)
            
            
            5,841
            
            
            
            (494
            )
            
            
            1,634
            
            
            
            (1,428
            )(Loss)
      income from continuing operations
            
            
            (39,654
            )
            
            
            208,422
            
            
            
            (114,410
            )
            
            
            (164,284
            )Discontinued
      operations
            
            
            —
            
            
            
            (7
            )
            
            
            —
            
            
            
            15Net
      (loss) income
            
            $
            (39,654
            )
            
            $
            208,415
            
            
            $
            (114,410
            )
            
            $
            (164,269
            )




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




Our
Corporate Segment’s revenues, which consist solely of our commodity derivatives
activity, decreased to a loss of $8.8 million and $57.1 million, respectively,
for the three and nine months ended September 30, 2009, from a gain of $231.9
million and a loss of $97.8 million, respectively, for the three and nine months
ended September 30, 2008.  As a result of our commodity hedging
activities, revenues include realized gains of $17.2 million and $70.4 million
on risk management activity that was settled during the three and nine months
ended September 30, 2009, respectively, and unrealized mark-to-market losses of
$26.0 million and $127.6 million for the three and nine months ended September
30, 2009, respectively, as compared to 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.  Included with
our unrealized commodity derivative gains (losses) is the amortization of put
premiums and other derivative costs of $10.6 million, $33.8 million, $2.3
million and $6.8 million during the three and nine months ended September 30,
2009 and 2008, respectively.




As the
forward price curves for our hedged commodities shift in relation to the various
strike prices of our commodity derivatives, the fair value of those instruments
changes.  The unrealized, non-cash, mark-to-market results during the
three and nine months ended September 30, 2009 reflects forward curve price
movements from the beginning to the end of the three-month and nine-month period
for commodities underlying the derivative instruments.  The unrealized
mark-to-market results for the three and nine months ended September 30, 2009
and 2008 had no impact on cash activities for those periods and are excluded
from our calculation of Adjusted EBITDA.




Given the
uncertainty surrounding future commodity prices, and the general inability to
predict these as they relate to the caps, floors, swaps and strike prices at
which we have hedged our exposure, it is difficult to predict the magnitude and
impact that marking our hedges to market will have on our income from operations
in future periods.




General and Administrative
Expenses. General and administrative expenses increased by $0.5 million
and $3.7 million to $10.4 million and $34.9 million for the three and nine
months ended September 30, 2009, respectively, as compared to $9.9 million and
$31.2 million for the three and nine months ended September 30, 2008,
respectively. This growth in general and administrative expenses was primarily
driven by increased headcount in our corporate office as a result of our 2008
acquisitions but was also impacted by our recruiting efforts in accounting,
back-office, engineering, land and operations-related corporate personnel
associated with being a public partnership.  Corporate-office payroll
expenses decreased by less than $0.1 million and increased $4.4 million for the
three and nine months ended September 30, 2009, respectively, as a result of the
increased headcount.  Included within the increased corporate-office
payroll expenses was an decrease of $0.5 million and a decrease of $0.9 million
for the three and nine months ended September 30, 2009, respectively, related to
equity-based compensation, of which the nine months ended September 30, 2009
includes $0.4 million related to the allocation of expense from Eagle Rock
Holdings, L.P. due to its issuance of Tier I units to one of our
executives.  Also included in the nine months ended September 30, 2009
was a one time charge of $0.1 million for severance payments due to a reduction
in workforce.  As a result of the increase in our expenses for
corporate-office headcount, contract labor and other outside professional
services decreased by $0.1 million and $0.2 million during the three and nine
months ended September 30, 2009, respectively, as compared to the same periods
in 2008.  In addition, the three and nine months ended September 30,
2009, included legal and other professional advisory fees $0.4 million and $0.6
million, respectively, incurred related to strategic discussions regarding our
capital structure and proposals received regarding the sale of the Minerals
Segment.




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





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.  We historically sold portions of its condensate production from
its Texas Panhandle and East Texas midstream systems to SemGroup.  As
a result of the bankruptcy we took a $10.1 million bad debt charge during the
nine months ended September 30, 2008, which is included in “Other Operating
Expense” in the consolidated statement of operations.  In August 2009,
we sold $3.9 million of our outstanding receivables from SemGroup, which
represented our 20-day administrative claims under 503(b)(9) of the United
States Bankruptcy Code, for which we received a payment of $3.0
million.  Due to certain repurchase obligations under the assignment
agreement, we recorded the payment as a current liability within accounts
payable as of September 30, 2009 and anticipate maintaining the balance as a
liability until it is clear that the repurchase obligations can no longer be
triggered.





Amounts
included within other operating (income) expense are excluded from our
calculation of Adjusted EBITDA.





Total Other Income (Expense).
Total other income (expense) includes both realized and unrealized gains and
losses from our interest rate swaps. We incurred expense of $14.2 million and
$20.0 million for the three and nine months ended September 30, 2009,
respectively, as compared to $9.9 million and $26.1 million for the three and
nine months ended September 30, 2008, respectively.  During the three
and nine months ended September 30, 2009, we incurred realized losses from our
interest rate swaps of $5.0 million and $13.7 million, respectively, as compared
to realized losses of $2.4 million and $4.9 million during the three and nine
months ended September 30, 2008, respectively. We also incurred unrealized
mark-to-market losses of $5.3 million and gains of $9.7 million during the three
and nine months ended September 30, 2009, respectively, as compared to
unrealized mark-to-market losses of $0.5 million and $0.4 million during the
three and nine months ended September 30, 2009, respectively.  These
unrealized mark-to-market gains did not have any impact on cash activities for
the period, and are excluded by definition from our calculation of Adjusted
EBITDA.





Interest
expense, net, decreased to $4.3 million and $17.3 million for the three and nine
months ended September 30, 2009, respectively, as compared to $7.5 million and
$23.6 million, respectively, during the three and nine months ended September
30, 2008, respectively.  Interest expense, net is shown before the impact
of our interest rate derivatives, which convert a portion of our outstanding
debt from variable-rate interest obligations to fixed-rate interest
obligations.  All of our outstanding debt consists of borrowings under our
revolving credit facility, which bears interest primarily based on a LIBOR rate
plus the applicable margin.  The decrease in interest expense, net is due
to lower LIBOR rates during the three and nine months ended September 30, 2009,
as compared to the same period in 2008, partially offset by higher debt balances
in the 2009 period as a result of our acquisitions made in 2008.





Income Tax Provision (Benefit) –Income
tax provision for the three and nine months ended September 30, 2009 and 2008
relates to (i) state taxes due by us and (ii) federal taxes due by Eagle Rock
Energy Acquisition Co., Inc. (acquiring entity of certain entities acquired
in the acquisition of Redman Energy Corporation “Redman Acquisition” in 2007)
and Eagle Rock Energy Acquisition Co. II, Inc. (acquiring entity of
certain entities acquired in the Stanolind Acquisition) and their
wholly-owned corporations, Eagle Rock Upstream Development Company, Inc.
(successor entity to certain entities acquired in the Redman
acquisition) and Eagle Rock Upstream Development Company II, Inc.
(successor entity to certain entities acquired in the Stanolind acquisition),
which are subject to federal income taxes (the “C
Corporations”).  During the three and nine months ended September 30,
2009, our tax provision increased by $6.3 million and $3.1 million,
respectively, as compared to the same periods in the prior
year.  These increases were the result of 2009 income
projected for the C Corporations resulting from utilization of
our remaining net operating loss carryforwards, adjustments to the true-up
of the results of 2008 tax returns and our 2008 tax provision, as well as
changes in estimates used in our tax provision calculation in prior
periods.


43
 Table of Contents


Adjusted
EBITDA




Adjusted
EBITDA, as defined under “Non-GAAP Financial Measures,” decreased by $23.6
million and $47.1 million from $74.9 million and $184.3 million for the three
and nine months ended September 30, 2008, respectively, to $51.3 million and
$137.2 million for the three and nine months ended September 30, 2009,
respectively.




As
described above, for the three and nine months ended September 30, 2009,
revenues minus cost of natural gas and natural gas liquids for the Midstream
Business (including the Texas Panhandle, East Texas/Louisiana, South Texas and
the Gulf of Mexico Segment) declined by $20.3 million and $66.6 million as
compared to the three and nine months ended September 30, 2008. For the three
and nine months ended September 30, 2009, revenues for our Upstream and Mineral
Segments declined by $51.3 million and $121.4 million, respectively, as compared
to the same period in the prior year.  Our Corporate Segment’s
realized commodity derivatives gain increased by $41.3 million and $134.8
million as compared to the three and nine months ended September 30, 2008,
respectively. This resulted in a decline of $30.3 million and $53.2 million of
total incremental revenues minus cost of natural gas and natural gas liquids,
adjusted to exclude the impact of unrealized commodity derivatives not included
in the calculation of Adjusted EBITDA, as compared to the three and nine months
ended September 30, 2008.




Operating
expenses (including taxes other than income), increased by $0.1 million and $3.6
million for our Midstream Business with respect to the three and nine months
ended September 30, 2009, respectively, primarily due to the addition of the
Millennium Midstream acquisition properties, while operating expenses for our
Upstream and Minerals Segments decreased by $7.1 million and $13.5 million, as
compared to the three and nine months ended September 30, 2008,
respectively.




General
and administrative expense, captured in the Corporate Segment, increased by $1.1
million and $6.4 million, as compared to the same periods in the prior
year.  These amounts are adjusted to exclude non-cash compensation
charges related to our LTIP program and other operating expenses.




As a
result, revenues (excluding the impact of unrealized commodity derivative
activity and non-cash mark-to-market of Upstream product imbalances) minus cost
of natural gas and natural gas liquids decreased by $30.3 million and $53.2
million, operating expenses decreased by $7.0 million and $9.9 million and
general and administrative expenses increased by $1.1 million and $6.4 million,
resulting in the decrease to Adjusted EBITDA during the three and nine months
ended September 30, 2009, as compared to the three and nine months ended
September 30, 2008.









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




44
 Table of Contents





Liquidity
and Capital Resources




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




We
believe that the cash generated from these sources will continue to be
sufficient to meet our expected quarterly cash distributions (which we have
reduced in the first three quarters of 2009 to below the minimum quarterly
distribution amount described in our partnership agreement) and our requirements
for short-term working capital and long-term capital
expenditures.  The actual distributions we will declare will be
subject to our operating performance, prevailing market conditions (including
forward oil, natural gas and sulfur commodity prices), the impact of unforeseen
events and the approval of our Board of Directors and will be done pursuant to
our distribution policy.




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




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




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




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





In connection
with making the distribution decision for the first, second and third quarters
of 2009, our Board of Directors determined to reduce the quarterly distribution
in each quarter to $0.025 per common unit, as compared to $0.41 per common,
subordinated and general partner unit paid for the fourth quarter of 2008, to
establish cash reserves (as against available cash) for the proper conduct of
our business and to enhance our ability to remain in compliance with financial
covenants under our revolving credit facility in future periods.  The
cash not distributed has been used to reduce our outstanding debt under our
revolving credit facility, to continue the execution of our hedge strategy
to maintain future cash flows and/or to fund growth capital
expenditures.




Under the
terms of the agreements governing our revolving credit facility, we are
prohibited from declaring or paying any distribution to unitholders if a default
or event of default (as defined in such agreements) exists.Our goal is to reduce our
ratio of outstanding debt to Adjusted EBITDA, or “leverage ratio,” with respect
to our Midstream and Minerals Businesses, which as of September 30, 2009 was
4.75, to approximately 3.0 to 3.5, including without limitation, by reducing
outstanding indebtedness.  We believe this leverage ratio range to be
appropriate in light of these more turbulent economic conditions and more
in-line with historical midstream industry standards.  Our leverage
ratio has been negatively impacted in the nine months ended September 30, 2009
by the effect of lower commodity prices on our Adjusted EBITDA.  In
response, we have taken steps to reduce our outstanding indebtedness under our
revolving credit facility and to improve our Adjusted EBITDA position through
prudent management of our hedging portfolio, including by hedge reset
transactions.  During the three months ended September 30, 2009, we
reduced our outstanding debt under the revolving credit facility by $30.0
million from $804.4 million to $774.4 million.  Based primarily on our
current expectations of continued depressed commodity prices and decreased
drilling activity, we do not expect to be able to maintain the same level of
debt reduction achieved during the third quarter of 2009 for the fourth
quarter of 2009 or for 2010.  The actual amount and timing of further
debt repayment will depend on a number of factors, including but not limited to,
changes in commodity prices, our producer customers’ drilling plans,
availability of external capital, and the potential consummation of asset
acquisitions or divestitures, as well as future determinations of the borrowing
base under our revolving credit facility.  If we are unable to
continue reducing our outstanding debt, we must increase our Adjusted EBITDA to
further reduce our leverage ratio.  For a detailed description of our
revolving credit facility, see the description under Item 7. Management’s
Discussion and Analysis of Financial Condition and Results of Operations –
Liquidity and Capital Resources – Debt Covenants included in our annual report
on Form 10-K for the year ended December 31, 2008 and below under “Revolving
Credit Facility and Debt Covenants.”




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




Working Capital.Working
capital is the amount by which current assets exceed current liabilities and is
a measure of our ability to pay our liabilities as they become due. As of
September 30, 2009, working capital was $(12.8) million as compared to $57.3
million as of December 31, 2008.




The net
decrease in working capital of $70.1 million from December 31, 2008 to
September 30, 2009, resulted primarily from the following factors:




•
            cash
      balances and marketable securities, net of due to affiliates, decreased
      overall by $15.1 million and was impacted primarily by the distributions
      paid on February 15, 2009 with respect to the fourth quarter of 2008
      financial results, the results of operations, timing of capital
      expenditures payments, and financing activities including our debt
      activities (the due to affiliate liability of $10.9 million as of
      September 30, 2009 is owed to Eagle Rock Energy G&P,
    LLC);




•
            trade
      accounts receivable decreased by $42.1 million primarily from the impact
      of lower commodity prices on our consolidated
  revenue;




•
            risk
      management net working capital balance decreased by a net $72.0 million as
      a result of the changes in current portion of the mark-to-market
      unrealized positions, increased other derivative costs, which includes the
      unwinding of long-term positions to purchase current positions (see
      Hedging Strategy), and amortization of the put premiums and other
      derivative costs;




•
            accounts
      payable decreased by $50.9 million from December 31, 2008 primarily
      as a result of activities and timing of payments, including capital
      expenditures activities and lower commodity prices;
  and




•
            accrued
      liabilities decreased by $8.2 million primarily reflecting payment of
      employee benefit accruals, lower interest payments and the timing of
      payment of unbilled expenditures related primarily to capital
      expenditures.




45
 Table of Contents





Cash Flows
for the Nine Months Ended September 30, 2009 Compared to the Nine Months Ended
September 30, 2008




Cash Flow from Operating
Activities.Cash flows from operating
activities decreased $90.4 million during the nine months ended September 30,
2009 as compared to the nine months ended September 30, 2008 as a result of
lower commodity prices across our three businesses and reduced NGL equity
volumes in the Midstream Business.  These lower commodity prices
resulted in lower cash flows from the sale of our equity crude oil, natural gas
and natural gas liquids volumes.  The lower commodity prices also had
a direct result in the decrease in our working capital.  Specifically
contributing to the decrease in cash flows from operating activities was the
$50.9 million decrease in accounts payable, as discussed above.  Lower
commodity prices also resulted in us realizing settlement gains during the nine
months ended September 30, 2009, of which $8.3 million of cash received was
reclassified to cash from financing activities, compared to $15.5 million of
payments being reclassified during the nine months ended September 30,
2008.  In addition, our cash flows from operating activities for the nine
months ended September 30, 2009, includes a payment of $13.9 million to reset
certain derivative contracts, as discussed within “Hedging Strategy”
below.
  Cash Flows from Investing
Activities.Cash flows used for investing
activities for the nine months ended September 30, 2009, as compared to the nine
months ended September 30, 2008, decreased by $100.5 million due to acquisitions
completed in 2008.  During the nine months ended September 30, 2008,
we paid $81.3 million, net of cash acquired, for our acquisition of
Stanolind.  During the nine months ended September 30, 2009, we did
not make any acquisitions. The investing activities for the current period
reflect additions to property, plant and equipment expenditures of $29.4 million
versus $45.3 million for the prior year period.  This decrease is
attributable to lower well-connect activity in our Midstream Business resulting
from the reduced drilling activity of our producer customers, as well as lower
capital spending associated with the maintenance of our Big Escambia Creek
(“BEC”) facility, for which we performed a scheduled turnaround during the nine
months ended September 30, 2008.
  Cash Flows from Financing Activities.Cash flows used for financing activities during the
nine months ended September 30, 2009, were $50.9 million versus cash flows
provided by financing activities of $128.5 during the nine months ended
September 30, 2008. Key differences between periods include net payments to our
revolving credit facility of $25.0 million during the nine months ended
September 30, 2009, as compared to net proceeds of $232.3 million from our
revolving credit facility during the nine months ended September 30,
2008.  The net proceeds received during the nine months ended
September 30, 2008, were used for our acquisition of Stanolind and our
acquisition of MMP, which closed on October 1, 2008.  Distributions to
members decreased to cash outflows of $34.2 million during the nine months ended
September 30, 2009, as compared to $87.6 million during the nine months ended
September 30, 2008 as a result of reducing our quarterly distribution to $0.025
from $0.41 as discussed above.
  Hedging
Strategy





We use a
variety of hedging instruments to accomplish our risk management objectives.
 At times our hedging strategy may involve entering into hedges with strike
prices above current futures prices or resetting existing hedges to higher price
levels in order to meet our cash flow requirements, stay in compliance with our
revolving credit facility covenants and continue to execute on our distribution
objectives.  In addition, we may also terminate or unwind hedges or
portions of hedges when the expected future volumes do not support the level of
hedges.  Hedge transactions such as these impact our liquidity in that
we are required to pay the present value of the difference between the hedged
price and the current futures price.  These transactions also increase our
exposure to the counterparties through which we execute the
hedges.  During the nine months ended September 30, 2009, as part of
this strategy, we executed a series of hedging transactions that involved the
unwinding of a portion of existing “in-the-money” 2011 and 2012 WTI crude oil
swaps and collars, and the unwinding of two “in-the-money” 2009 WTI crude oil
collars.  With these transactions, and an additional $13.9 million of
cash, we purchased a 2009 WTI crude oil swap on 60,000 barrels per month
beginning January 1, 2009 at $97 per barrel.





On October 8,
2009, we unwound a portion of an “in-the-money” 2009 WTI crude oil swap and
reset the remaining portion.  For the first part of the transaction,
we bought 3,000 barrels per month for the months of November and December of
2009, for which we received $0.1 million for the counterparty.  For
the second part of the transaction, we reset from $97.00 to $135.00 the
remaining 57,000 barrels a month for the months of November and December of
2009, for which we paid the counterparty $4.3 million.  On October 22,
2009, we entered into a 30,000 barrel per month WTI crude oil costless collar
with a floor of $80.00 and a cap of $92.40 for the 2011 calendar year and a
30,000 barrel per month WTI crude oil costless collar with a floor of $80.00 and
a cap of $98.50 for the 2012 calendar year.  On November 2, 2009, the
Partnership reset a 2010 WTI crude oil swap, from $53.55 to $95.00, the swap
price for 45,000 barrels a month for the months of January, February and March
2010, for which the Partnership paid the counterparty $5.7 million.




Revolving
Credit Facility and Debt Covenants





On
December 13, 2007, we entered into a credit agreement with Wachovia Bank,
National Association, as administrative agent and swing line lender, Bank of
America, N.A., as syndication agent; HSH Nordbank AG, New York Branch; the Royal
Bank of Scotland, plc; and BNP Paribas, as co-documentation agents, and the
other lenders who are parties to the agreement with aggregate commitments of up
to $800 million.  During the year ended December 31, 2008, we
exercised $180 million of our $200 million accordion feature under the revolving
credit facility, which increased the total commitment to $980
million.  Pursuant to the revolving credit facility, we may, at our
request and subject to the terms and conditions of the revolving credit
facility, increase our commitments by an additional $20 million to an aggregate
of $1 billion.  As a result of Lehman Brothers’ bankruptcy
filing, the amount of available commitments was reduced by the unfunded portion
of Lehman Brothers’ commitment in an amount of approximately $9.1
million.   As of September 30, 2009, unused capacity available to
us under the new credit agreement, based on outstanding debt and compliance with
financial covenants as of that date, was approximately $34
million.  The credit agreement is scheduled to mature on
December 13, 2012.





Given the
current state of the banking industry worldwide, we are pleased with the degree
of diversification within our lender group.  Our revolving credit
facility includes the participation of 19 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 our revolving credit facility.  On August 21, 2009,
BBVA Compass Bank purchased certain assets and liabilities of Guaranty Bank, a
wholly owned subsidiary of Guaranty Financial Group Inc.  Guaranty
Bank had a commitment under Eagle Rock Energy’s revolving credit facility of $30
million, of which approximately $25 million has been funded.  BBVA
Compass has purchased Guaranty Bank’s commitment and has informed us it will
continue to honor such commitment.




We
announced in October 2009 that its existing borrowing base of $135 million under
our revolving credit facility was reaffirmed by our commercial lenders as a
result of our regularly scheduled semi-annual borrowing base redetermination.
The reaffirmation is effective as of October 1, 2009, with no additional fees or
increases in interest rate spread incurred.




Our
revolving credit facility accommodates, through the use of a borrowing base for
our Upstream Business and traditional cash-flow based covenants for our
Midstream and Minerals Businesses, the allocation of indebtedness to either our
Upstream Business (to be measured against the borrowing base) or to our
Midstream and Minerals Businesses (to be measured against the cash-flow based
covenant).  At September 30, 2009, we were in compliance with our
covenants under the revolving credit facility. Our interest coverage ratio, as
defined in the credit agreement (i.e., Consolidated EBITDA divided by
Consolidated Interest Expense), was 4.93 as compared to a minimum interest
coverage covenant of 2.5, and our leverage ratio, as defined in the credit
agreement (i.e., Total Funded Indebtedness divided by Adjusted Consolidated
EBITDA), was 4.75 as compared to a maximum leverage ratio of
5.0.  Primarily as a result of lower expected future commodity prices,
our borrowing base was re-determined in April 2009 to $135 million (which
resulted in a higher allocation of indebtedness to our Midstream and Minerals
Businesses).  The reduction in borrowing base was a contributing
factor to the decrease in our quarterly distribution (as discussed
above).  It also contributed to our taking steps to reduce our
leverage.  The $135 million borrowing base was reaffirmed effective
October 1, 2009.  At this time, we believe that we will remain in
covenant compliance for the remainder of 2009.  Our covenant
compliance throughout 2009 has benefited substantially from the contributions of
our hedging portfolio.  Absent any changes to the current hedge
positions in place for 2010, we anticipate a lower contribution from our hedges
in 2010, which, among other factors, could result in us exceeding the allowable
covenant levels in the revolving credit facility.  Management is
evaluating several alternatives to address this concern, including but not
limited to asset sales and additional adjustments to our hedging portfolio,
including buying-up exisiting hedges to more favorable price
levels.  In addition, the Partnership has received proposals from NGP
and BSMC which would, among other items, involve the sale of our Minerals
Business and the potential issuance of new equity.  These proposals
are currently being evaluated by the Conflicts Committee of our Board. We
caution our unitholders that the proposals are not binding at this time, that
neither the Board of Directors nor the Conflicts Committee has made any decision
with respect to our response to the proposals and that there can be no assurance
that any agreement will be executed or that any transaction will be approved or
consummated.




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 Table of Contents





Capital
Requirements




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




Our 2009
capital budget anticipates that we will spend approximately $40.0 million in
total for the year on our existing assets.  Our 2009 capital budget
anticipated that we would spend approximately $30.4 million in the nine months
ended September 30, 2009 on our existing assets. We actually spent approximately
$29.7 million in total during that period.




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




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




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




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





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




Off-Balance
Sheet Obligations




We have
no off-balance sheet transactions or obligations.


Recent
Accounting Pronouncements





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





In December
2007, the FASB issued authoritative guidance to require 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.  The guidance 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.  The guidance amends previous guidancesuch that adjustments
made to valuation allowances on deferred taxes and acquired tax contingencies
associated with acquisitions that closed prior to the effective date of the
amended guidance would also apply the provisions of such
guidance.  The guidance was effective for us as of January 1, 2009 but
the impact of the adoption on our consolidated financial statements will depend
on the nature and the extent of business combinations occurring after January 1,
2009.




In
December 2007, the FASB issued authoritative guidance which requires that
accounting and reporting for minority interests will be recharacterized as
noncontrolling interests and classified as a component of equity. The guidance
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 guidance was effective for us as of January 1, 2009 and did
not have a material impact on its consolidated results of operations or
financial position as we have no noncontrolling interests.




In
February 2008, the FASB issued authoritative guidance that permitted the delayed
application of fair value measurement 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.  Non-financial assets and
liabilities that we measure at fair value on a non-recurring basis consists
primarily of property, plant and equipment, and intangible assets, which are
subject to fair value adjustments in certain circumstances (for example, when
there is evidence of impairment).




In March
2008, the FASB issued authoritative guidance requiring 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. The guidance was effective for us as of January 1,
2009.  See Note 11 for the additional disclosures required related to
our derivative instruments.




In March
2008 the FASB approved authoritative guidance which requires that master limited
partnerships use the two-class method of allocating earnings to calculate
earnings per unit. This guidance is effective for fiscal years and interim
periods beginning after December 15, 2008.  The guidance was
effective for us as of January 1, 2009 and the impact on its earnings per
unit calculation has been retrospectively applied to September 30, 2008 (see
Note 16).





In April
2008, the FASB issued authoritative guidance which amends the factors that
should be considered in developing renewal or extension assumptions used to
determine the useful life of a recognized intangible asset.  The intent of
guidance is to improve the consistency between the useful life of a recognized
intangible asset and the period of expected cash flows used to measure the fair
value of the asset.  This guidance must be applied prospectively to
intangible assets acquired after the effective date.  The guidance was
effective for us as of January 1, 2009 but the impact of the adoption on our
consolidated financial statements will depend on the nature and the extent of
business combinations occurring after January 1, 2009.




47
 Table of Contents





In June 2008,
the FASB issued authoritative guidance which 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.  This guidance is effective for fiscal years beginning after
December 15, 2008 and earnings-per-unit calculations would need to be adjusted
retroactively.  The guidance was effective for us as of January 1,
2009 and the impact on its earnings per unit calculation has been
retrospectively applied to September 30, 2008. (See Note 16).





In December
2008, the SEC released Final Rule, Modernization of Oil and Gas Reporting to
revise the existing Regulation S-K and Regulation S-X reporting requirements to
align with current industry practices and technological advances. The new
disclosure requirements include provisions that permit the use of new
technologies to determine proved reserves if those technologies have been
demonstrated empirically to lead to reliable conclusions about reserve volumes.
In addition, the new disclosure requirements require a company to (a) disclose
its internal control over reserves estimation and report the independence and
qualification of its reserves preparer or auditor, (b) file reports when a third
party is relied upon to prepare reserves estimates or conducts a reserve audit
and (c) report oil and gas reserves using an average price based upon the prior
12-month period rather than period-end prices. The provisions of this final
ruling will become effective for disclosures in our Annual Report on Form 10-K
for the year ending December 31, 2009.  The adoption of the Final
Rule, Modernization of Oil and Gas Reporting revision to Regulation S-K and
Regulations S-X is not expected to have a material impact on our consolidated
financial statements.





In April
2009, the FASB issued authoritative guidance amending the other-than-temporary
impairment guidance for debt securities to make the guidance more operational
and to improve the presentation and disclosure of other-than-temporary
impairments in the financial statements. The most significant change is a
revision to the amount of other-than-temporary loss of a debt security recorded
in earnings under certain circumstances. This guidance was effective for us as
of June 30, 2009 and did not have a material impact on its consolidated
financial statements.





In April
2009, the FASB issued authoritative guidance which provides additional guidance
for estimating fair value when the volume and level of activity for the asset or
liability have significantly decreased.  The guidance also includes
guidance on identifying circumstances that indicate a transaction is not orderly
and emphasizes that even if there has been a significant decrease in the volume
and level of activity for the asset or liability and regardless of the valuation
technique(s) used, the objective of a fair value measurement remains the same.
Fair value is the price that would be received to sell an asset or paid to
transfer a liability in an orderly transaction (that is, not a forced
liquidation or distressed sale) between market participants at the measurement
date under current market conditions.  This guidance was effective for
us as of June 30, 2009 and did not have a material impact on its consolidated
financial statements.





In April
2009, the FASB issued authoritative guidance to require disclosures about fair
value of financial instruments for interim reporting periods of publicly traded
companies as well as in annual financial statements.  The guidance
also requires those disclosures in summarized financial information at interim
reporting periods. The guidance was effective for us as of June 30,
2009.  (See Note 10).





In April
2009, the FASB issued authoritative guidance which amended and clarified
previous guidance with respect to contingencies.  The guidance provides
that an acquirer shall recognize at fair value, at the acquisition date, an
asset acquired or a liability assumed in a business combination that arises from
a contingency if the acquisition-date fair value of that asset or liability can
be determined during the measurement period.  If the acquisition-date fair
value of an asset acquired or a liability assumed in a business combination that
arises from a contingency cannot be determined using the measurement period, the
previous guidance shall apply.”  This guidance was effective for us as
of January 1, 2009 but the impact of the adoption on our consolidated financial
statements will depend on the nature and the extent of business combinations
occurring after January 1, 2009.





In May 2009,
the FASB issued authoritative guidance which provides guidance on our
assessment of subsequent events. Historically, we have relied on U.S. auditing
literature for guidance on assessing and disclosing subsequent
events.  The guidance clarifies that we must evaluate, as of each
reporting period, events or transactions that occur after the balance sheet date
“through the date that the financial statements are issued or are available to
be issued.” We must perform its assessment for both interim and annual financial
reporting periods prospectively.  The guidance was effective for us as
of June 30, 2009 but the impact of the adoption will depend on the nature and
the extent of transactions that occur subsequent to our interim and annual
reporting periods.





In June 2009,
the FASB issued authoritative guidance which reflects the FASB’s response to
issues entities have encountered when applying previous guidance.  In
addition, this guidance addresses concerns expressed by the SEC, members of the
United States Congress, and financial statement users about the accounting and
disclosures required in the wake of the subprime mortgage crisis and the
deterioration in the global credit markets.  In addition, because this
guidance eliminates the exemption from consolidation for qualified
special-purpose entities (“QSPEs”) a transferor will need to evaluate all
existing QSPEs to determine whether they must be
consolidated.   The guidance is effective for financial asset
transfers occurring after the beginning of an entity’s first fiscal year that
begins after November 15, 2009.  Early adoption of is
prohibited.   We are currently evaluating the potential impact,
if any, of the adoption of this guidance on its financial
statements.





In June 2009,
the FASB issued authoritative guidance, which amends the consolidation guidance
applicable to variable interest entities (VIEs). The amendments will
significantly affect the overall consolidation analysis.  While the
FASB’s discussions leading up to the issuance of this guidance focused
extensively on structured finance entities, the amendments to the consolidation
guidance affect all entities and enterprises, as well as qualifying
special-purpose entities (QSPEs) that were excluded from previous
guidance.  Accordingly, an enterprise will need to carefully
reconsider its previous conclusions, including (1) whether an entity is a VIE,
(2) whether the enterprise is the VIE’s primary beneficiary, and (3) what type
of financial statement disclosures are required.  This guidance is
effective as of the beginning of the first fiscal year that begins after
November 15, 2009, and early adoption is prohibited.  We are currently
evaluating the potential impact, if any, of the adoption on its financial
statements.





In June 2009,
the FASB established the FASB Accounting Standards Codification (“ASC”) as the
single source of authoritative U.S. generally accepted accounting principles
(“U.S. GAAP”) recognized by the FASB to be applied by nongovernmental
entities.  Rules and interpretive releases of the United States
Securities and Exchange Commission (“SEC”) under authority of federal securities
laws are also sources of authoritative U.S. GAAP for SEC registrants.  The
Codification did not have a material impact on the Partnership’s consolidated
financial statements upon adoption.  Accordingly, our notes to consolidated
financial statements will explain accounting concepts rather than cite the
topics of specific U.S. GAAP.





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





In September
2009, the FASB issued an amendment to authoritative guidance to address the need
for additional implementation guidance on accounting for uncertainty in income
taxes and to specifically address the following questions, (1) is income tax
paid by the entity attributable to the entity or its owners, (2) what
constitutes a tax position for a pass-through entity or a tax-exempt
not-for-profit entity and (3) how should accounting for uncertainty in income
taxes be applied when a group of related entities comprise both taxable and
nontaxable entities.  This amendment is effective for interim and
annual periods ended after September 15, 2009.  The adoption of this
guidance had no material impact on our financial statements.


.


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 Table of Contents


Non-GAAP
Financial Measures




We
include in this filing the following non-GAAP financial measure, Adjusted
EBITDA. We provide reconciliations of this non-GAAP financial measure to its
most directly comparable financial measures as calculated and presented in
accordance with GAAP.




We define
Adjusted EBITDA as net income (loss) plus or (minus) income tax provision
(benefit); interest-net, including realized interest rate risk management
instruments and other expense; depreciation, depletion and amortization expense,
impairment expense; other operating expense, non-recurring; other non-cash
operating and general and administrative expenses, including non-cash
compensation related to our equity-based compensation program; unrealized
(gains) losses on commodity and interest rate risk management related
instruments; (gains) losses on discontinued operations and other (income)
expense. We use Adjusted EBITDA as a measure of our core profitability to assess
the financial performance of our assets.  Adjusted EBITDA is used as a
supplemental financial measure by external users of our financial statements
such as investors, commercial banks and research analysts. For example, our
lenders under our revolving credit facility use a variant of our Adjusted EBITDA
in a compliance covenant designed to measure the viability of us and our ability
to perform under the terms of the revolving credit facility; we, therefore, use
Adjusted EBITDA to measure our compliance with our revolving credit facility. We
believe that investors benefit from having access to the same financial measures
that our management uses in evaluating performance.  Adjusted EBITDA
is useful in determining our ability to sustain or increase distributions. By
excluding unrealized derivative gains (losses), a non-cash, mark-to-market
benefit (charge) which represents the change in fair market value of our
executed derivative instruments and is independent of our assets’ performance or
cash flow generating ability, we believe Adjusted EBITDA reflects more
accurately our ability to generate cash sufficient to pay interest costs,
support our level of indebtedness, make cash distributions to our unitholders
and general partner and finance our maintenance capital expenditures. We further
believe that Adjusted EBITDA describes more accurately the underlying
performance of our operating assets by isolating the performance of our
operating assets from the impact of an unrealized, non-cash measure designed to
describe the fluctuating inherent value of a financial asset. Similarly, by
excluding the impact of non-recurring discontinued operations, Adjusted EBITDA
provides users of our financial statements a more accurate picture of our
current assets’ cash generation ability, independently from that of assets which
are no longer a part of our operations. Our Adjusted EBITDA definition may not
be comparable to Adjusted EBITDA or similarly titled measures of other entities,
as other entities may not calculate Adjusted EBITDA in the same manner as us.
For example, we include in Adjusted EBITDA the actual settlement revenue created
from our commodity hedges by virtue of transactions undertaken by us to reset
commodity hedges to higher prices or purchase puts or other similar floors
despite the fact that we exclude from Adjusted EBITDA any charge for
amortization of the cost of such commodity hedge reset transactions or
puts.  For a reconciliation of Adjusted EBITDA to its most directly
comparable financial measures calculated and presented in accordance with GAAP
(accounting principles generally accepted in the United States) see the table
below.




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





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


49
 Table of Contents


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







Three
      Months Ended
              September
      30,
            
            
            Nine
      Months Ended
              September
      30,2009
            
            
            2008
            
            
            2009
            
            
            2008Net
      cash flows provided by operating activities
            
            $
            40,893
            
            
            $
            40,927
            
            
            $
            73,172
            
            
            $
            163,571Add
      (deduct):Depreciation,
      depletion, amortization and impairment
            
            
            (28,860
            )
            
            
            (28,597
            )
            
            
            (86,753
            )
            
            
            (80,799
            )Amortization
      of debt issuance costs
            
            
            (267
            )
            
            
            (219
            )
            
            
            (801
            )
            
            
            (655
            )Risk
      management portfolio value changes
            
            
            (31,314
            )
            
            
            258,716
            
            
            
            (103,927
            )
            
            
            (30,592
            )Reclassifying
      financing derivative settlements
            
            
            1,556
            
            
            
            (5,925
            )
            
            
            8,330
            
            
            
            (15,462
            )Other
            
            
            (5,894
            )
            
            
            (1,344
            )
            
            
            (1,802
            )
            
            
            (1,313
            )Accounts
      receivables and other current assets
            
            
            (6,917
            )
            
            
            (49,584
            )
            
            
            (41,843
            )
            
            
            (651
            )Accounts
      payable, due to affiliates and accrued liabilities
            
            
            5,965
            
            
            
            74,741
            
            
            
            49,800
            
            
            
            (956
            )Other
      assets and liabilities
            
            
            (433
            )
            
            
            (644
            )
            
            
            1,221
            
            
            
            (420
            )Net
      (loss) income
            
            
            (25,271
            )
            
            
            288,071
            
            
            
            (102,603
            )
            
            
            32,723Add
      (deduct):Interest
      (income) expense, net
            
            
            9,612
            
            
            
            9,849
            
            
            
            31,569
            
            
            
            28,458Depreciation,
      depletion, amortization and impairment
            
            
            28,860
            
            
            
            28,597
            
            
            
            86,753
            
            
            
            80,799Income
      tax provision (benefit)
            
            
            5,841
            
            
            
            (500
            )
            
            
            1,634
            
            
            
            (1,497
            )EBITDA
            
            
            19,042
            
            
            
            326,017
            
            
            
            17,353
            
            
            
            140,483Add
      (deduct):Unrealized
      risk management losses
            
            
            31,310
            
            
            
            (255,455
            )
            
            
            117,823
            
            
            
            33,853Equity-based
      compensation expense
            
            
            904
            
            
            
            1,427
            
            
            
            5,024
            
            
            
            4,147Non-cash
      mark-to-market of Upstream imbalances
            
            
            780
            
            
            
            —
            
            
            
            2,609
            
            
            
            —Other
      income
            
            
            (725
            )
            
            
            (434
            )
            
            
            (1,835
            )
            
            
            (2,867
            )Discontinued
      operations
            
            
            (26
            )
            
            
            (594
            )
            
            
            (266
            )
            
            
            (1,451
            )Other
      operating expenses
            
            
            —
            
            
            
            3,920
            
            
            
            (3,552
            )
            
            
            10,134ADJUSTED
      EBITDA
            
            $
            51,285
            
            
            $
            74,881
            
            
            $
            137,156
            
            
            $
            184,299







Three
      Months Ended
                September
      30,
              
              
              Nine
      Months Ended
                September
      30,2009
              
              
              2008
              
              
              2009
              
              
              2008Amortization
      of commodity derivative costs
              
              $
              10,590
              
              
              $
              2,260
              
              
              $
              33,886
              
              
              $
              6,780





50
 Table of Contents


Item 3.                      Quantitative
and Qualitative Disclosures About Market Risk.




Risk
and Accounting Policies




We are
exposed to market risks associated with adverse changes in commodity prices,
interest rates and counterparty credit. We may use financial instruments such as
put and call options, swaps and other derivatives to mitigate the effects of the
identified risks. Adverse effects on our cash flow from changes in crude oil,
natural gas, NGL product prices or interest rates could adversely impact our
ability to make distributions to our unitholders, meet debt service obligations,
fund required capital expenditures and other similar requirements. Our
management has established a comprehensive review of our market risks and has
developed risk management policies and procedures to monitor and manage these
market risks. Our general partner is responsible for the overall approval of
market risk management policies, delegation of transaction authority levels, and
for the establishment of a Risk Management Committee. The Risk Management
Committee is composed of officers (including, on an ex officio basis, our chief
executive officer) who receive regular briefings on positions and exposures,
credit exposures and overall risk management in the context of market
activities. The Risk Management Committee is responsible for the overall
management of commodity price risk, interest rate risk and credit risk,
including monitoring exposure limits.




Commodity
Price Risk




We are
exposed to the impact of market fluctuations in the prices of crude oil, natural
gas, NGLs, sulfur and other commodities as a result of our gathering,
processing, producing and marketing activities, which produce a naturally long
position in crude oil, NGLs, sulfur and natural gas. Both our profitability and
our cash flow are affected by volatility in prevailing prices for these
commodities. These prices are impacted by changes in the supply and demand for
these commodities, as well as market uncertainty and other factors beyond our
control. Historically, changes in the prices of NGLs, such as natural gasoline,
have generally correlated with changes in the price of crude oil but those
correlations may change in the future.




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




We have
not designated our derivative contracts as accounting hedges. As a result, we
mark our derivatives to fair value with the resulting change in fair value
included in our statement of operations.  For the three months ended
September 30, 2009, we recorded a loss on risk management instruments of $8.8
million representing a fair value (unrealized) loss of $15.4 million,
amortization of put premiums and other derivative costs of $10.6 million and net
(realized) settlement gain of $17.2 million.  For the nine months
ended September 30, 2009, we recorded a loss on risk management instruments of
$57.1 million representing a fair value (unrealized) loss of $93.7 million,
amortization of put premiums and other derivative costs of $33.9 million and net
(realized) settlement gains of $70.4 million.  As of September 30,
2009, the fair value net liability of these commodity contracts, including put
premiums and other derivative costs, totaled approximately $4.5
million.




We
continually monitor our hedging and contract portfolio and expect to continue to
adjust our hedge position as conditions warrant.




Interest
Rate Risk




We are
exposed to variable interest rate risk as a result of borrowings under our
existing revolving credit agreement. To mitigate its interest rate risk, we have
entered into various interest rate swaps. These swaps convert the variable-rate
term loan into a fixed-rate obligation. The purpose of entering into 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. 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,
2009, the Partnership recorded a fair value (unrealized) loss of $5.3 million
and a realized loss of $5.0 million.  For the nine months ended
September 30, 2009, we recorded a fair value (unrealized) gain of $9.7 million
and a realized loss of $13.7 million.  As of September 30, 2009, the
fair value liability of these interest rate contracts totaled approximately
$30.2 million.




Credit
Risk





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





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





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




Item 4.
            Controls
      and Procedures.




Evaluation
of Disclosure Controls and Procedures





Based on the
evaluation of our disclosure controls and procedures (as defined in the
Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934, as
amended (the “Exchange Act”)) required by Exchange Act Rules 13a-15(b) or
15d-15(b), our principal executive officer and principal financial officer have
concluded that as of the end of the period covered by this report, our
disclosure controls and procedures were effective at the reasonable assurance
level to ensure that information we are required to disclose in reports that we
file or submit under the Exchange Act is recorded, processed, summarized and
reported within the time periods specified in Securities and Exchange Commission
rules and forms, and include controls and procedures designed to ensure that
information required to be disclosed by us in such reports is accumulated and
communicated to our management, including the principal executive officer and
principal financial officer, as appropriate to allow timely decisions regarding
required disclosure.





Changes
in Internal Control Over Financial Reporting




There
were no changes in our internal control over financial reporting that occurred
during the Partnership’s most recent fiscal quarter that have materially
affected, or are reasonably likely to materially affect, our internal control
over financial reporting.






51
 Table of Contents




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.




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




Subsequent
to December 31, 2008, we received additional Notices of Enforcement (“NOEs”)
and Notices of Violation (“NOVs”) from the TCEQ related to air compliance
matters.  We expect to receive additional NOEs or NOVs from the TCEQ
from time to time throughout 2009.  Though the TCEQ has the discretion
to adjust penalties and settlements upwards based on a compliance history
containing multiple, successive NOEs, we do not expect that the resolution of
any existing NOE or any future similar NOE will vary significantly from the
administrative penalties and agreed settlements experienced by us to
date.









Item 1A.                      Risk
Factors.




Set forth
below is a material update to the risk factors discussed in our annual report on
Form 10-K for the year ended December 31, 2008 and our previous quarterly
reports on Form 10-Q filed during 2009.




Potential
legislation related to “over-the-counter” derivatives could adversely impact our
ability to execute our hedging stratedy.




In response
to the role that “over-the-counter” derivatives are perceived to have played in
the global financial crisis that began in 2008, various committees of the United
States Congress are currently drafting legislation to increase the regulation of
the markets for these instruments.  These efforts may result, among
other things, in legislation that would require us to clear our commodity
derivatives through clearinghouses, and post cash collateral when market prices
rise above the strike prices of our derivatives.  If this or similar
legislation is promulgated, the cost of executing our hedging strategy could
increase significantly, potentially to a level that would lead us to hedge a
much lower level of our forecasted production than we otherwise would
desire.  Increases in hedging costs and the need to post cash
collateral would have an adverse effect on our business as a result of reduced
cash flow and reduced liquidity.  Additionally, in the event that we
hedge lower quantities in response to higher hedging costs and increased margin
requirements, our exposure to changes in commodity prices would increase and
this could result in lower cash flows to the Partnership.  Ultimately,
increased regulation of “over-the-counter” derivatives has the potential to
reduce our cash flows and thereby reduce our ability to make distributions,
reduce debt, and fund maintenance and growth activities.





Climate
change legislation, regulatory initiatives and litigation may adversely affect
our operations, our cost structure, or the demand for oil and natural
gas.





On April 17,
2009, the U.S. Environmental Protection Agency, or “EPA,” issued a notice of its
proposed finding and determination that emissions of carbon dioxide, methane,
and other greenhouse gases, or “GHGs,” presented an endangerment to human health
and the environment because emissions of such gases are, according to EPA,
contributing to warming of the earth’s atmosphere.  Once finalized,
EPA’s finding and determination would allow it to begin regulating emissions of
GHGs under existing provisions of the federal Clean Air Act.  In
addition, on June 26, 2009, the U.S. House of Representatives passed the
“American Clean Energy and Security Act of 2009”, also known as the
“Waxman-Markey legislation,” which would establish an economy-wide cap-and-trade
program to reduce emissions of carbon dioxide and other GHGs in the United
States and would require an overall reduction in GHG emissions of 17% (from 2005
levels) by 2020, and by over 80% by 2050.  President Obama is
encouraging the Senate to consider climate change legislation during the fall of
2009.  Further, on September 21, 2009 a U.S. Federal appellate court
reinstated a lawsuit filed by several state attorneys general and others against
five of the largest U.S. electric utility companies alleging that those
companies have created a public nuisance due to their emissions of carbon
dioxide.  Although it is not possible at this time to predict if and
when the Senate may act on climate change legislation, how any bill passed by
the Senate would be reconciled with the Waxman-Markey legislation or what
effect, if any, the recent decision permitting a nuisance lawsuit to proceed
against certain utilities may have on the oil and natural gas industry, any
future federal laws or implementing regulations that may be adopted to address
greenhouse gas emissions, as well as future climate change litigation against us
or our customers for GHG emissions, could result in increased compliance costs
or additional operating restrictions, and could have an adverse effect on demand
for the oil and natural gas we produce and distribute.




We
have significant indebtedness under our revolving credit facility.  We may
have difficulty complying with the leverage ratio covenant set forth in our
revolving credit facility over the next five quarters. 
 As
of September 30, 2009, total borrowings under our revolving credit facility were
approximately $775 million,
and our leverage ratio (amount of outstanding debt over Adjusted EBITDA, as
defined in the credit agreement) was approximately 4.75 versus a maximum
allowable ratio level of 5.0.  Our ability to comply with the leverage
ratio covenant over the next five quarters is uncertain and may depend on our
ability to reduce debt, enhance our hedging portfolio (including through hedge
reset transactions), execute on a strategic proposal (which may include a
variety or combination of one or more of the proposals we have received to date)
or otherwise increase our liquidity.  Other factors beyond our control that
may contribute to our ability to comply with the leverage ratio covenant
include, but are not limited to, commodity prices and drilling activity by our
producer customers.  If we breach the leverage ratio covenant, an event of
default would occur under our revolving credit facility.  An event of
default could cause an acceleration of our repayment of the outstanding
amounts under our revolving credit facility or, if waived, incurrence of a
waiver fee and/or an increase in the applicable interest-rate margins in our
revolving credit facility.


52
 Table of Contents




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





The sale or
exchange of 50% or more of our capital and profits interests during any
twelve-month period would result in the technical termination of our partnership
for federal income tax purposes.




We will be
considered to have terminated our partnership for federal income tax purposes if
there is a sale or exchange of 50% or more of the total interests in our capital
and profits within a twelve-month period. During the nine months ended September
30, 2009, we experienced a high volume of trading in our common units. We cannot
at this time determine whether there has been a sale or exchange of 50% or more
of the total interests in our capital and profits as such determination requires
analyzing historic brokerage trading data as it becomes available to us.  A
technical termination would not affect our consolidated financial statements nor
does it affect our classification as a partnership or otherwise affect the
nature or extent of our “qualifying income” for U.S. federal income tax
purposes.  A technical termination would, among other things, result in the
closing of our taxable year for all unitholders (which, most likely, results in
unitholders who were unitholders before and after such technical termination
receiving an additional K-1 on account of the termination) and would result in a
deferral of depreciation deductions allowable in computing our taxable
income.  A deferral of depreciation deductions would result in increased
taxable income or reduced taxable loss to certain unitholders, although the
exact increase or reduction for each unitholder cannot be estimated at this
time.




Except as
disclosed above, the risks previously disclosed in our annual report on
Form 10-K for the year ended December 31, 2008 and our previous
quarterly reports on Form 10-Q filed during 2009 have not changed in any
material respect.






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




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




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




Item 3.
            Defaults
      Upon Senior Securities.




None.




Item 4.
            Submission
      of Matters to a Vote of Security
Holders.




None.


53
 Table of Contents




Item 5.              Other
Information.




None.




Item 6.
            Exhibits.





31.1
            Certification
      by Joseph A. Mills pursuant to Section 302 of the Sarbanes-Oxley Act of
      2002.31.2
            Certification
      by Jeffrey P. Wood pursuant to Section 302 of the Sarbanes-Oxley Act of
      2002.32.1
            Certification
      by Joseph A. Mills pursuant to Section 906 of the Sarbanes-Oxley Act of
      2002 and 18 U.S.C. Section 1350.32.2
            Certification
      by Jeffrey P. Wood pursuant to Section 906 of the Sarbanes-Oxley Act of
      2002 and 18 U.S.C. Section 1350.








54


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 9, 2009
            EAGLE
      ROCK ENERGY PARTNERS, L.P.By:
            EAGLE
      ROCK ENERGY GP, L.P., its general partnerBy:
            EAGLE
      ROCK ENERGY G&P, LLC, its general partnerBy:
            /s/
      Jeffrey P. WoodJeffrey
      P. WoodSenior
      Vice President,Chief
      Financial Officer and Treasurer of Eagle RockEnergy
      G&P, LLC, General Partner of Eagle RockEnergy
      GP, L.P., General Partner of Eagle RockEnergy
      Partners, L.P.









































55





EAGLE
ROCK ENERGY PARTNERS, L.P.





EXHIBIT
INDEX








31.1
            Certification
      by Joseph A. Mills pursuant to Section 302 of the Sarbanes-Oxley Act of
      200231.2
            Certification
      by Jeffrey P. Wood pursuant to Section 302 of the Sarbanes-Oxley Act of
      200232.1
            Certification
      by Joseph A. Mills pursuant to Section 906 of the Sarbanes-Oxley Act of
      2002 and 18 U.S.C. Section 135032.2
            Certification
      by Jeffrey P. Wood pursuant to Section 906 of the Sarbanes-Oxley Act of
      2002 and 18 U.S.C. Section 1350