##### Table of Contents



UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
 Washington, D.C. 20549
 
 FORM 10-Q
 þ
    
    QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
 For the quarterly period ended September 30, 2007
 OR
 o
    
    TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
 Commission File No. 001-33016
 
 EAGLE ROCK ENERGY PARTNERS, L.P.
 (Exact Name of Registrant as Specified in Its Charter)
 Delaware
    
    68-0629883(State or Other Jurisdiction of
    
    (I.R.S. EmployerIncorporation or Organization)
    
    Identification Number)
 16701 Greenspoint Park Drive, Suite 200
Houston, Texas 77060
 (281) 408-1200
 
 þ o
  o o þ
 o þ




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##### 



EAGLE ROCK ENERGY PARTNERS, L.P.
 TABLE OF CONTENTS
 PagePART I. FINANCIAL INFORMATION
    
    
    1Item 1. Financial Statements
    
    
    1Condensed Consolidated Balance Sheets as of September 30, 2007 and December 31, 2006
(unaudited)
    
    
    1Condensed Consolidated Statements of Operations for the three months and nine months ended
September 30, 2007 and 2006 (unaudited)
    
    
    2Condensed Consolidated Statements of Cash Flows for the nine months ended September 30, 2007
and 2006 (unaudited)
    
    
    3Condensed Consolidated Statements of Members Equity for the nine months ended September 30,
2007 (unaudited)
    
    
    4Notes to the Condensed Consolidated Financial Statements (unaudited)
    
    
    5Item 2. Managements Discussion and Analysis of Financial Condition and Results of Operations
    
    
    28Cautionary
Note Regarding Forward-Looking Statements
    
    
    28Item 3. Quantitative and Qualitative Disclosures About Market Risk
    
    
    47Item 4. Controls and Procedures
    
    
    48PART II. OTHER INFORMATION
    
    
    49Item 1. Legal Proceedings
    
    
    49Item 1A. Risk Factors
    
    
    49Item 2. Unregistered Sales of Equity Securities and Use of Proceeds
    
    
    70Item 3. Defaults Upon Senior Securities
    
    
    70Item 4. Submission of Matters to a Vote of Security Holders
    
    
    70Item 5. Other Information
    
    
    70Item 6. Exhibits
    
    
    70Certification Pursuant to Section 302Certification Pursuant to Section 302Certification Pursuant to Section 906Certification Pursuant to Section 906
  i




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##### Table of Contents



PART I. FINANCIAL INFORMATION
 
 Item 1. Financial Statements.
 EAGLE ROCK ENERGY PARTNERS, L.P.
 
 CONDENSED CONSOLIDATED BALANCE SHEETS
(unaudited)
 September 30,
    
    
    December 31,($ in thousands)
    
    2007
    
    
    2006ASSETSCURRENT ASSETS:Cash and cash equivalents
    
    $
    84,557
    
    
    $
    10,581Accounts receivable
    
    
    122,020
    
    
    
    43,567Risk management assets
    
    
    30,213
    
    
    
    13,837Prepayments and other current assets
    
    
    2,139
    
    
    
    2,679Total current assets
    
    
    238,929
    
    
    
    70,664PROPERTY, PLANT AND EQUIPMENT  Net
    
    
    1,249,110
    
    
    
    554,063INTANGIBLE ASSETS  Net
    
    
    151,664
    
    
    
    130,001RISK MANAGEMENT ASSETS
    
    
    9,252
    
    
    
    17,373OTHER ASSETS
    
    
    13,804
    
    
    
    7,800TOTAL
    
    $
    1,662,759
    
    
    $
    779,901LIABILITIES AND MEMBERS EQUITYCURRENT LIABILITIES:Accounts payable
    
    $
    130,591
    
    
    $
    49,558Due to affiliate
    
    
    17,437
    
    
    
    Accrued liabilities
    
    
    20,754
    
    
    
    7,996Risk management liabilities
    
    
    16,974
    
    
    
    1,005Total current liabilities
    
    
    185,756
    
    
    
    58,559LONG-TERM DEBT
    
    
    561,131
    
    
    
    405,731ASSET RETIREMENT OBLIGATIONS
    
    
    9,045
    
    
    
    1,819DEFERRED TAX LIABILITY
    
    
    3,045
    
    
    
    1,229RISK MANAGEMENT LIABILITIES
    
    
    36,320
    
    
    
    20,576OTHER
    
    
    315
    
    
    
    COMMITMENTS AND CONTINGENCIES (Note
11) MEMBERS EQUITY (DEFICIT):Common Unitholders(1)
    
    
    716,942
    
    
    
    116,283Subordinated Unitholders(2)
    
    
    151,749
    
    
    
    176,248General Partner(3)
    
    
    (1,544
    )
    
    
    (544
    )Total members equity
    
    
    867,147
    
    
    
    291,987TOTAL
    
    $
    1,662,759
    
    
    $
    779,901
 
 (1)
    
    50,633,720 common units (exclusive of restricted unvested common units) were issued and
outstanding as of September 30, 2007 and 20,691,495 for December 31, 2006. These numbers do
not include 527,021 units and 122,450 units issued to employees as of September 30, 2007 and
December 31, 2006, respectively, under the 2006 Long-Term Incentive Plan and which are subject
to vesting requirements.(2)
    
    20,691,495 subordinated units were issued and outstanding as of September 30, 2007 and
December 31, 2006.(3)
    
    844,551 general partner units were issued and outstanding as of September 30, 2007 and
December 31, 2006.  1




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EAGLE ROCK ENERGY PARTNERS, L.P.
 
 CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
(unaudited)
 Three Months
    
    
    Nine MonthsEnded September 30,
    
    
    Ended September 30,($ in thousands except per share data)
    
    2007
    
    
    2006
    
    
    2007
    
    
    2006REVENUE:Natural gas, natural gas liquids,
condensate, and oil sales
    
    $
    253,056
    
    
    $
    132,907
    
    
    $
    554,797
    
    
    $
    373,001Gathering, compression and processing fees
    
    
    7,723
    
    
    
    4,549
    
    
    
    19,271
    
    
    
    10,495Minerals and royalty income
    
    
    6,009
    
    
    
    
    
    
    
    9,201
    
    
    
    Gain/(loss) on risk management instruments
    
    
    8,688
    
    
    
    14,031
    
    
    
    (26,209
    )
    
    
    (21,209
    )Other income
    
    
    1,388
    
    
    
    109
    
    
    
    1,007
    
    
    
    436Total revenue
    
    
    276,864
    
    
    
    151,596
    
    
    
    558,067
    
    
    
    362,723COSTS AND EXPENSES:Cost of natural gas and natural gas liquids
    
    
    196,839
    
    
    
    100,723
    
    
    
    451,838
    
    
    
    288,881Operations and maintenance
    
    
    16,883
    
    
    
    9,094
    
    
    
    36,017
    
    
    
    23,892Taxes other than income
    
    
    2,746
    
    
    
    651
    
    
    
    4,364
    
    
    
    1,045Other operating
    
    
    220
    
    
    
    
    
    
    
    1,931
    
    
    
    General and administrative
    
    
    7,196
    
    
    
    2,446
    
    
    
    16,587
    
    
    
    8,063Depreciation, depletion and amortization
    
    
    25,105
    
    
    
    11,244
    
    
    
    50,883
    
    
    
    31,459Total costs and expenses
    
    
    248,989
    
    
    
    124,158
    
    
    
    561,620
    
    
    
    353,340OPERATING INCOME (LOSS)
    
    
    27,875
    
    
    
    27,438
    
    
    
    (3,553
    )
    
    
    9,383OTHER (EXPENSE) INCOME:Interest income
    
    
    231
    
    
    
    217
    
    
    
    2,601
    
    
    
    740Other income
    
    
    767
    
    
    
    
    
    
    
    879
    
    
    
    Interest expense, net
    
    
    (19,152
    )
    
    
    (14,547
    )
    
    
    (32,980
    )
    
    
    (20,993
    )Other expense
    
    
    2
    
    
    
    
    
    
    
    (255
    )
    
    
    Total other (expense) income
    
    
    (18,152
    )
    
    
    (14,330
    )
    
    
    (29,755
    )
    
    
    (20,253
    )INCOME (LOSS) BEFORE INCOME TAXES
    
    
    9,723
    
    
    
    13,108
    
    
    
    (33,308
    )
    
    
    (10,870
    )State income tax provision
    
    
    352
    
    
    
    236
    
    
    
    772
    
    
    
    744NET INCOME (LOSS)
    
    $
    9,371
    
    
    $
    12,872
    
    
    $
    (34,080
    )
    
    $
    (11,614
    )NET INCOME (LOSS) PER COMMON UNIT -

BASIC AND DILUTED:Basic:Net income (loss)Common units
    
    $
    0.25
    
    
    $
    0.44
    
    
    $
    (0.24
    )
    
    $
    (0.42
    )Subordinated units
    
    
    (0.09
    )
    
    
    0.44
    
    
    
    (1.22
    )
    
    
    (0.42
    )General partner units
    
    
    (0.09
    )
    
    
    0.44
    
    
    
    (1.22
    )
    
    
    (0.42
    )Basic (units in thousands)Common units
    
    
    45,954
    
    
    
    4,732
    
    
    
    32,512
    
    
    
    10,850Subordinated units
    
    
    20,691
    
    
    
    24,151
    
    
    
    20,691
    
    
    
    16,631General partner units
    
    
    845
    
    
    
    589
    
    
    
    845
    
    
    
    482Diluted:Net income (loss)Common units
    
    $
    0.25
    
    
    $
    0.44
    
    
    $
    (0.24
    )
    
    $
    (0.42
    )Subordinated units
    
    
    (0.09
    )
    
    
    0.44
    
    
    
    (1.22
    )
    
    
    (0.42
    )General partner units
    
    
    (0.09
    )
    
    
    0.44
    
    
    
    (1.22
    )
    
    
    (0.42
    )Diluted (units in thousands)Common units
    
    
    46,021
    
    
    
    4,732
    
    
    
    32,539
    
    
    
    10,850Subordinated units
    
    
    20,691
    
    
    
    24,151
    
    
    
    20,691
    
    
    
    16,631General partner units
    
    
    845
    
    
    
    589
    
    
    
    845
    
    
    
    482
  2




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EAGLE ROCK ENERGY PARTNERS, L.P.
 
 CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(unaudited)
 Nine MonthsEnded September 30,($ in thousands)
    
    2007
    
    
    2006CASH FLOWS FROM OPERATING ACTIVITIES:Net loss
    
    $
    (34,080
    )
    
    $
    (11,614
    )Adjustments to reconcile net loss to net cash provided by operating activities:Depreciation, depletion and amortization
    
    
    50,883
    
    
    
    31,459Amortization of debt issuance costs
    
    
    416
    
    
    
    718Reclassifying financing derivative settlements
    
    
    (100
    )
    
    
    (514
    )Equity-based compensation expense
    
    
    1,578
    
    
    
    Other
    
    
    (241
    )
    
    
    819Changes in assets and liabilities  net of acquisitions:Accounts receivable
    
    
    (22,437
    )
    
    
    2,683Prepayments and other current assets
    
    
    2,115
    
    
    
    972Risk management activities
    
    
    25,102
    
    
    
    18,692Accounts payable
    
    
    24,516
    
    
    
    (10,470
    )Advances due affiliates
    
    
    17,541
    
    
    
    Accrued liabilities
    
    
    11,018
    
    
    
    6,748Other assets
    
    
    287
    
    
    
    318Net cash provided by operating activities
    
    
    76,598
    
    
    
    39,811CASH FLOWS FROM INVESTING ACTIVITIES:Additions to property, plant and equipment
    
    
    (53,787
    )
    
    
    (21,242
    )Acquisitions
    
    
    (426,960
    )
    
    
    (100,524
    )Cash acquired in acquisitions
    
    
    23,790
    
    
    
    Escrow cash
    
    
    
    
    
    
    7,643Purchase of intangible assets
    
    
    (1,128
    )
    
    
    (2,618
    )Other
    
    
    22
    
    
    
    Net cash used in investing activities
    
    
    (458,063
    )
    
    
    (116,741
    )CASH FLOWS FROM FINANCING ACTIVITIES:Proceeds from long-term debt
    
    
    173,400
    
    
    
    Proceeds from revolver
    
    
    
    
    
    
    3,000Repayment of long-term debt
    
    
    (18,054
    )
    
    
    (2,886
    )Repayment from revolver
    
    
    
    
    
    
    (11,619
    )Payment of debt issuance costs
    
    
    
    
    
    
    (2866
    )Proceeds from derivative contracts
    
    
    100
    
    
    
    514Payment of deferred offering costs
    
    
    
    
    
    
    (2,584
    )Contribution by members
    
    
    
    
    
    
    98,540Proceeds from equity issuance
    
    
    331,500
    
    
    
    Distributions to members and affiliates
    
    
    (31,775
    )
    
    
    7,690Net cash (used in) provided by financing activities
    
    
    455,171
    
    
    
    74,409NET CHANGE IN CASH AND CASH EQUIVALENTS
    
    
    73,706
    
    
    
    (2,521
    )CASH AND CASH EQUIVALENTS  Beginning of period
    
    
    10,851
    
    
    
    19,372CASH AND CASH EQUIVALENTS  End of period
    
    $
    84,557
    
    
    $
    16,851Interest paid  net of amounts capitalized
    
    $
    27,212
    
    
    $
    22,858Investments in property, plant and equipment not paid
    
    $
    2,068
    
    
    $
    1,092Acquisition of assets for equity
    
    $
    307,937
    
    
    $
    
  3




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EAGLE ROCK ENERGY PARTNERS, L.P.
 
 CONDENSED CONSOLIDATED STATEMENTS OF MEMBERS EQUITY
FOR THE NINE MONTH PERIOD ENDED SEPTEMBER 30, 2007
(Unaudited)
 Number of
    
    
    
    
    
    
    Number ofGeneral
    
    
    Common
    
    
    Common
    
    
    Subordinated
    
    
    SubordinatedPartner
    
    
    Units
    
    
    Units
    
    
    Units
    
    
    Units
    
    
    Total($ in thousands, except unit amounts)BALANCE  December 31, 2006
    
    $
    (544
    )
    
    
    20,691,495
    
    
    $
    116,283
    
    
    
    20,691,495
    
    
    $
    176,248
    
    
    $
    291,987Equity issued to
private investors
    
    
    
    
    
    
    16,236,265
    
    
    
    331,500
    
    
    
    
    
    
    
    
    
    
    
    331,500Equity issued in
acquisitions
    
    
    
    
    
    
    13,705,960
    
    
    
    307,937
    
    
    
    
    
    
    
    
    
    
    
    307,937Net loss
    
    
    (1,023
    )
    
    
    
    
    
    
    (7,990
    )
    
    
    
    
    
    
    (25,067
    )
    
    
    (34,080
    )Distributions
    
    
    
    
    
    
    
    
    
    
    (31,775
    )
    
    
    
    
    
    
    
    
    
    
    (31,775
    )Restricted unit
expense
    
    
    23
    
    
    
    
    
    
    
    987
    
    
    
    
    
    
    
    568
    
    
    
    1,578BALANCE 
September 30, 2007
    
    $
    (1,544
    )
    
    
    50,633,720
    
    
    $
    716,942
    
    
    
    20,691,495
    
    
    $
    151,749
    
    
    $
    867,147
  4




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EAGLE ROCK ENERGY PARTNERS, L.P.
 
 NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
 NOTE 1. ORGANIZATION AND DESCRIPTION OF BUSINESS
 Organization
 Initial Public Offering
 Basis of Presentation and Principles of Consolidation
 Description of Business
   5




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NOTE 2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
   Oil and Natural Gas Accounting Policies
  6




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Financial Accounting and Reporting for Oil and Gas Producing
Companies
    Impairment of Oil and Gas Properties
  7




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##### Table of Contents



Property Retirement Obligations
  Other Significant Accounting Policies
 Interim Condensed Disclosures
 Cash and Cash Equivalents
 Concentration and Credit Risk
  Certain Other Concentrations
 Property, Plant, and Equipment
 Pipelines and equipment
    
    20 yearsGas processing and equipment
    
    20 yearsOffice furniture and equipment
    
    5 years
 8




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Producing Oil and Natural Gas Properties 
 Impairment of Long-Lived Assets
 
    
    significant adverse change in legal factors or in the business climate;
    
    a current-period operating or cash flow loss combined with a history of operating or
cash flow losses or a projection or forecast which demonstrates continuing losses
associated with the use of a long-lived asset;
    
    an accumulation of costs significantly in excess of the amount originally expected for
the acquisition or construction of a long-lived asset;
    
    significant adverse changes in the extent or manner in which an asset is used or in its
physical condition;
    
    a significant change in the market value of an asset; or
    
    a current expectation that, more likely than not, an asset will be sold or otherwise
disposed of before the end of its estimated useful life.
  Impairment of Oil and Gas Properties
  Intangible Assets
 September 30,
    
    
    December 31,($ in thousands)
    
    2007
    
    
    2006Rights-of-way and easements  at cost
    
    $
    69,366
    
    
    $
    66,801Less: accumulated amortization
    
    
    (6,073
    )
    
    
    (3,510
    )Contracts
    
    
    112,422
    
    
    
    80,210Less: accumulated amortization
    
    
    (24,051
    )
    
    
    (13,500
    )Net intangible assets
    
    $
    151,664
    
    
    $
    130,001
  Other Assets
 9




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Transportation and Exchange Imbalances
 Revenue Recognition
 
    
    sales of natural gas, NGLs, oil and condensate;
    
    natural gas gathering, processing and transportation, from which Eagle Rock Energy
generates revenues primarily through the compression, gathering, treating, processing and
transportation of natural gas;
    
    NGL transportation from which we generate revenues from transportation fees;
    
    royalties, overriding royalties and lease bonuses.
     Environmental Expenditures
 10




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Income Taxes
 Derivatives Accounting for
Derivative Instruments and Hedging Activities,
 Reclassifications
 NOTE 3. NEW ACCOUNTING PRONOUNCEMENTS
 Accounting for Certain Hybrid Financial Instruments Accounting for Transfers and Servicing of Financial Assets and Extinguishments
of Liabilities,
 Fair Value Measurements.
 11




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The Fair Value Option for Financial Assets and
Financial Liabilities
 Accounting for Purchases and Sales of Inventory with the Same Counterparty
 Accounting for Uncertainty in Income
Taxes  an interpretation of FASB Statement No. 109
 NOTE 4. ACQUISITIONS
 Montierra
 Financial Statements of Oil and Gas Exchange Offers
   12




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($ in thousands)Oil and gas propertiesProved Properties
    
    $
    82,758Unproved Properties
    
    
    49,656Cash
    
    
    936Accounts receivable
    
    
    6,342Accounts payable
    
    
    (1,906
    )Risk management liabilities
    
    
    (717
    )Accrued liabilities
    
    
    (104
    )Equity in earnings of non-affiliate
    
    
    3,459$
    140,424
 Laser
  ($ in thousands)Property, plant and equipment
    
    $
    107,183Intangibles
    
    
    32,210Cash
    
    
    2,885Accounts receivable
    
    
    31,182Other current assets
    
    
    279Accounts payable
    
    
    (30,082
    )Other current liabilities
    
    
    (287
    )$
    143,370
 MacLondon
 EAC Acquisition.
  ($ in thousands)Oil and gas propertiesProved Proved Properties
    
    $
    201,191Unproved Properties
    
    
    19,370Plant and related assets
    
    
    11,560Cash and cash equivalents
    
    
    4,732Accounts receivable
    
    
    17,713Prepaid assets
    
    
    868Risk management assets
    
    
    2,186Other assets
    
    
    1,376Accounts payable
    
    
    (11,440
    )Accrued liabilities
    
    
    (849
    )Asset retirement obligations
    
    
    (3,560
    )Risk management liabilities.
    
    
    (943
    )$
    242,204
 13




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Redman Acquisition.
  ($ in thousands)Oil and gas assetsProved Properties
    
    $
    179,242Cash and cash equivalents
    
    
    15,237Accounts receivable, net
    
    
    6,334Prepaid assets
    
    
    576Derivatives receivable
    
    
    1,119Other assets
    
    
    1,134Accounts payable
    
    
    (11,340
    )Deferred tax payable
    
    
    (1,028
    )Other long-term liabilities
    
    
    (512
    )$
    190,762
  14




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($ in thousands)
    
    September 30, 2007Pro forma earnings data:Revenues(a)
    
    $
    796,679Less: Cost and expenses
    
    
    625,630Income from continuing operations
    
    $
    171,049
 
 (a)
    
    Excludes non-realized revenues risk management loss of $30.5 million. NOTE
5. PROPERTY, PLANT AND EQUIPMENT AND ASSET RETIREMENT OBLIGATIONS
  September 30,
    
    
    December 31,($ in thousands)
    
    2007
    
    
    2006Land
    
    $
    1,064
    
    
    $
    853Plant
    
    
    132,318
    
    
    
    81,485Gathering and pipeline
    
    
    544,409
    
    
    
    433,779Equipment and machinery
    
    
    46,738
    
    
    
    37,185Vehicles and transportation equipment
    
    
    3,627
    
    
    
    2,740Office equipment, furniture, and fixtures
    
    
    1,180
    
    
    
    511Computer equipment
    
    
    4,770
    
    
    
    4,623Corporate
    
    
    126
    
    
    
    126Linefill
    
    
    4,157
    
    
    
    3,923Proved properties
    
    
    475,208
    
    
    
    Unproved properties
    
    
    79,565
    
    
    
    Construction in progress
    
    
    25,428
    
    
    
    19,6771,318,590
    
    
    
    584,902Less: accumulated depreciation, depletion and amortization
    
    
    (69,480
    )
    
    
    (30,839
    )Net fixed assets
    
    $
    1,249,110
    
    
    $
    554,063
  Asset Retirement Obligations Accounting for Conditional Asset Retirement
Obligations, an interpretation of FASB Statement No. 143 Accounting for Asset Retirement
Obligations,
  ($ in thousands)Asset retirement obligations  December 31, 2006
    
    $
    1,819Additional liability on newly built assets
    
    
    84Additional liability related to recent acquisitions
    
    
    6,968Accretion expense
    
    
    174Asset retirement obligations  September 30, 2007
    
    $
    9,045
 15




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##### Table of Contents



NOTE 6. LONG-TERM DEBT
  September 30,
    
    
    December 31,($ in thousands)
    
    2007
    
    
    2006Revolver
    
    $
    261,881
    
    
    $
    106,481Term loan
    
    
    299,250
    
    
    
    299,250Total debt
    
    
    561,131
    
    
    
    405,731Less: current portion
    
    
    
    
    
    
    Total long-term debt
    
    $
    561,131
    
    
    $
    405,731
        
    
    Adjusted EBITDA (as defined) to interest expense of not less than 2.5 to 1.0; and
    
    Total consolidated funded debt to Adjusted EBITDA (as defined) of not more than 5.0 to
1.0 and 5.25 to 1.0 for the three quarters following a material acquisition.
  16




---



##### Table of Contents



Principal($ in thousands)
    
    Amount2007
    
    $
    2008
    
    
    2009
    
    
    2010
    
    
    2011
    
    
    561,131$
    561,131
  NOTE 7. MEMBERS EQUITY
   17




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##### Table of Contents



18




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##### Table of Contents



NOTE 8. RELATED PARTY TRANSACTIONS
        19




---



##### Table of Contents



NOTE 9. FAIR VALUE OF FINANCIAL INSTRUMENTS
   NOTE 10. RISK MANAGEMENT ACTIVITIES
  ($ in thousands)Fair ValueRoll Forward
    
    Expiration
    
    Notional
    
    Fixed
    
    September 30,Effective Date
    
    Date
    
    Amount
    
    Rate
    
    200701/03/2006
    
    
    01/03/2011
    
    
    $
    100,000,000
    
    
    
    4.9500
    %
    
    $
    (889
    )01/03/2006
    
    
    01/03/2011
    
    
    
    100,000,000
    
    
    
    4.9625
    
    
    
    (832
    )01/03/2006
    
    
    01/03/2011
    
    
    
    50,000,000
    
    
    
    4.8800
    
    
    
    (309
    )01/03/2006
    
    
    01/03/2011
    
    
    
    50,000,000
    
    
    
    4.8800
    
    
    
    (309
    )09/18/2007
    
    
    12/31/2010
    
    
    
    75,000,000
    
    
    
    4.6600
    
    
    
    (29
    )09/18/2007
    
    
    12/31/2010
    
    
    
    75,000,000
    
    
    
    4.6650
    
    
    
    (41
    )
   20




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##### Table of Contents




    
    NGL puts, costless collar and swap transactions for the sale of Mont Belvieu natural
gas liquids with a combined notional amount of 195,000 Bbls per month, 17,000 Bbls per
month, 57,000 Bbls per month and 54,000 Bbls per month for 2007, 2008, 2009, and 2010,
respectively;
    
    Condensate puts and costless collar transactions for the sale of West Texas
Intermediate crude oil with a combined notional amount of 104,000 Bbls per month, 80,000
Bbls per month, 40,000 Bbls per month and 40,000 Bbls per month for 2007, 2008, 2009, and
2010, respectively;
    
    Natural gas calls for the purchase of Henry Hub natural gas with a notional amount of
100,000 MMBtu per month for 2007;
    
    Fixed swap agreements to hedge WTS-WTI basis differential in amount of 20,000 Bbls per
month for a term of January through December 2007; and
   PriceAverage Monthly
    
    
    
    
    
    ($/mmbtu or $/bbl)Period
    
    Commodity
    
    Volumes
    
    Index
    
    Avg. Floor
    
    Avg. CeilingJan-Dec 2007
    
    Gas
    
    20,000 MMBtu
    
    NYMEX
    
    
    8.00
    
    
    
    12.95Jan-Dec 2007
    
    Gas
    
    15,000 MMBtu
    
    NYMEX
    
    
    7.00
    
    
    
    10.40Jan-Dec 2007
    
    Gas
    
    10,000 MMBtu
    
    NYMEX
    
    
    6.25
    
    
    
    8.00Jan-Dec 2007
    
    Gas
    
    40,000 MMBtu
    
    NYMEX
    
    
    8.00
    
    
    
    12.11Jan-Dec 2007
    
    Gas
    
    20,000 MMBtu
    
    NYMEX
    
    
    7.00Jan-Dec 2007
    
    Gas
    
    40,000 MMBtu
    
    NYMEX
    
    
    7.00Apr-Dec 2007
    
    Gas
    
    123,600 MMBtu
    
    NYMEX
    
    
    7.00
    
    
    
    11.89Jan-Dec 2007
    
    Oil
    
    500 Bbl
    
    NYMEX WTI
    
    
    60.00
    
    
    
    75.00Jan-Dec 2007
    
    Oil
    
    2,500 Bbl
    
    NYMEX WTI
    
    
    60.00
    
    
    
    72.55Jan-Dec 2007
    
    Oil
    
    500 Bbl
    
    NYMEX WTI
    
    
    60.00
    
    
    
    75.00Jan-Dec 2007
    
    Oil
    
    2,500 Bbl
    
    NYMEX WTI
    
    
    60.00
    
    
    
    72.55Jan-Dec 2007
    
    Oil
    
    2,000 Bbl
    
    NYMEX WTI
    
    
    60.00
    
    
    
    75.15Jan-Dec 2007
    
    Oil
    
    32,000 Bbl
    
    NYMEX WTI
    
    
    74.00Jan-Dec 2007
    
    Oil
    
    4,000 Bbl
    
    NYMEX WTI
    
    
    65.00Jan-Dec 2007
    
    Oil
    
    3,000 Bbl
    
    NYMEX WTI
    
    
    65.00Jan-Dec 2007
    
    Oil
    
    5,000 Bbl
    
    NYMEX WTI
    
    
    60.00
    
    
    
    79.95Jul-Dec 2007
    
    Oil
    
    5,000 Bbl
    
    NYMEX WTI
    
    
    65.00
    
    
    
    82.75Jan-Dec 2008
    
    Gas
    
    30,000 MMBtu
    
    NYMEX
    
    
    6.25
    
    
    
    11.15Jan-Dec 2008
    
    Gas
    
    103,000 MMBtu
    
    NYMEX
    
    
    7.00
    
    
    
    13.98Jan-Dec 2008
    
    Gas
    
    30,000 MMBtu
    
    NYMEX
    
    
    7.50
    
    
    
    12.01Jan-Dec 2008
    
    Gas
    
    50,000 MMBtu
    
    NYMEX
    
    
    7.00Jan-Dec 2008
    
    Oil
    
    6,000 Bbl
    
    NYMEX WTI
    
    
    60.00
    
    
    
    71.65Jan-Dec 2008
    
    Oil
    
    29,000 Bbl
    
    NYMEX WTI
    
    
    65.00
    
    
    
    90.00Jan-Dec 2008
    
    Oil
    
    4,000 Bbl
    
    NYMEX WTI
    
    
    60.00
    
    
    
    77.22Jan-Dec 2008
    
    Oil
    
    6,000 Bbl
    
    NYMEX WTI
    
    
    65.00Jan-Dec 2008
    
    Oil
    
    5,000 Bbl
    
    NYMEX WTI
    
    
    60.00
    
    
    
    83.75Jan-Dec 2009
    
    Gas
    
    20,000 MMbtu
    
    NYMEX
    
    
    6.25
    
    
    
    11.20Jan-Mar 2009
    
    Gas
    
    92,700 MMBtu
    
    NYMEX
    
    
    7.50
    
    
    
    13.75Jan-May 2009
    
    Gas
    
    40,000 MMBtu
    
    NYMEX
    
    
    7.00Jan-May 2009
    
    Oil
    
    7,000 Bbl
    
    NYMEX WTI
    
    
    60.00
    
    
    
    80.75Jan-Dec 2009
    
    Oil
    
    6,000 Bbl
    
    NYMEX WTI
    
    
    60.00
    
    
    
    77.00
 21




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##### Table of Contents



Average Monthly
    
    
    
    
    
    PricePeriod
    
    Commodity
    
    Volumes
    
    Index
    
    ($/gal)Jul-Dec 2007
    
    Propane
    
    4,091 Bbl
    
    OPIS MTB TET
    
    
    1.0875Jul-Dec 2007
    
    Propane
    
    5,906 Bbl
    
    OPIS MTB non-TET
    
    
    1.0775Jul-Dec 2007
    
    n-Butane
    
    7,156 Bbl
    
    OPIS MTB non-TET
    
    
    1.2775Jul-Dec 2007
    
    i-Butane
    
    3,600 Bbl
    
    OPIS MTB non-TET
    
    
    1.2950Jan-Dec 2008
    
    Propane
    
    3,272 Bbl
    
    OPIS MTB TET
    
    
    1.0875Jan-Dec 2008
    
    Propane
    
    6,076 Bbl
    
    OPIS MTB non-TET
    
    
    1.0775Jan-Dec 2008
    
    n-Butane
    
    6,691 Bbl
    
    OPIS MTB non-TET
    
    
    1.2775Jan-Dec 2008
    
    i-Butane
    
    3,367 Bbl
    
    OPIS MTB non-TET
    
    
    1.2950Jan-Dec 2009
    
    Propane
    
    2,955 Bbl
    
    OPIS MTB TET
    
    
    1.0875Jan-Dec 2009
    
    Propane
    
    5,486 Bbl
    
    OPIS MTB non-TET
    
    
    1.0775Jan-Dec 2009
    
    n-Butane
    
    6,042 Bbl
    
    OPIS MTB non-TET
    
    
    1.2775Jan-Dec 2009
    
    i-Butane
    
    3,040 Bbl
    
    OPIS MTB non-TET
    
    
    1.2950
   Average Monthly
    
    
    
    
    
    Floor
    
    CapPeriod
    
    Commodity
    
    Volumes
    
    Index
    
    ($/Bbl)
    
    ($/Bbl)Jan-Dec 2008
    
    Crude oil
    
    20,000 Bbl
    
    NYMEX WTI
    
    
    50.00
    
    
    
    65.65Jan-Dec 2008
    
    Crude oil
    
    20,000 Bbl
    
    NYMEX WTI
    
    
    50.00
    
    
    
    65.70Jan-Dec 2008
    
    Crude oil
    
    40,000 Bbl
    
    NYMEX WTI
    
    
    50.00
    
    
    
    69.10
  Average Monthly
    
    
    
    
    
    Swap PricePeriod
    
    Commodity
    
    Volumes
    
    Index
    
    ($/Bbl)Jan-Dec 2008
    
    Crude oil
    
    80,000 Bbl
    
    NYMEX WTI
    
    
    73.90
   Average Monthly
    
    
    
    
    
    Swap PricePeriod
    
    Commodity
    
    Volumes
    
    Index
    
    ($/Bbl)Jan-Dec 2009
    
    Crude oil
    
    25,000 Bbl
    
    NYMEX WTI
    
    
    71.25Jan-Dec 2010
    
    Crude oil
    
    25,000 Bbl
    
    NYMEX WTI
    
    
    70.00
  Average Monthly
    
    
    
    
    
    Swap PricePeriod
    
    Commodity
    
    Volumes
    
    Index
    
    ($/gal)Oct-Dec 2007
    
    Ethane
    
    40,000 Bbl
    
    OPIS MTB non-TET
    
    
    0.83375Oct-Dec 2007
    
    Propane
    
    35,000 Bbl
    
    OPIS MTB TET
    
    
    1.2775Oct-Dec 2007
    
    n-Butane
    
    16,000 Bbl
    
    OPIS MTB non-TET
    
    
    1.5275Oct-Dec 2007
    
    i-Butane
    
    8,500 Bbl
    
    OPIS MTB non-TET
    
    
    1.5575
 22




---



##### Table of Contents



Average Monthly
    
    
    
    
    
    Swap PricePeriod
    
    Commodity
    
    Volumes
    
    Index
    
    ($/gal)Jan-Dec 2008
    
    Ethane
    
    25,000 Bbl
    
    OPIS MTB non-TET
    
    
    0.7200Jan-Dec 2008
    
    Propane
    
    35,000 Bbl
    
    OPIS MTB TET
    
    
    1.1900Jan-Dec 2009
    
    Ethane
    
    25,000 Bbl
    
    OPIS MTB non-TET
    
    
    0.6361Jan-Dec 2009
    
    Propane
    
    15,000 Bbl
    
    OPIS MTB TET
    
    
    1.0925
   NOTE 11. COMMITMENTS AND CONTINGENT LIABILITIES
 Litigation
 Insurance
  Regulatory Compliance
 Environmental
 23




---



##### Table of Contents



Other Commitments and Contingencies
 NOTE 12. SEGMENTS
  (i)
    
    Midstream  Texas Panhandle Segment:gathering, processing, transportation and marketing of natural gas in the Texas Panhandle;(ii)
    
    Midstream  South Texas Segment:gathering, processing, transportation and marketing of natural gas in South Texas;(iii)
    
    Midstream  East Texas and Louisiana Segment:gathering, processing and marketing of natural gas and related NGL transportation in East
Texas and Louisiana;(iv)
    
    Upstream Segment:crude oil and natural gas production from operated and non-operated wells;(v)
    
    Minerals Segment:fee minerals, royalties and non-operated working interest ownership, lease bonus and
rental income and equity in earnings of unconsolidated non-affiliate; and(vi)
    
    Corporate Segment:risk management and other corporate activities.
  ($ in millions)
    
    Texas
    
    
    
    
    
    East Texas andThree months ended September 30, 2007
    
    Panhandle
    
    South Texas
    
    Louisiana
    
    Upstream
    
    Minerals
    
    Corporate
    
    TotalSales to external customers
    
    $
    130.3
    
    
    $
    64.3
    
    
    $
    48.5
    
    
    $
    19.1
    
    
    $
    6.0
    
    
    $
    8.7
    (a)
    
    $
    276.9Segment gross profit (loss)(b)
    
    
    33.4
    
    
    
    2.7
    
    
    
    10.1
    
    
    
    19.1
    
    
    
    6.0
    
    
    
    8.7
    
    
    
    80.0Interest expense-net and other
financing costs
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    18.9
    
    
    
    18.9Depreciation, depletion and amortization
    
    
    10.7
    
    
    
    0.9
    
    
    
    3.3
    
    
    
    6.9
    
    
    
    3.3
    
    
    
    
    
    
    
    25.1Capital expenditures
    
    
    7.2
    
    
    
    0.8
    
    
    
    5.7
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    13.7Segment assets
    
    
    584.0
    
    
    
    62.3
    
    
    
    290.6
    
    
    
    470.9
    
    
    
    160.8
    
    
    
    94.2
    
    
    
    1,662.8
 24




---



##### Table of Contents



East Texas($ in millions)
    
    Texas
    
    
    
    
    
    andThree months ended September 30, 2006
    
    Panhandle
    
    South Texas
    
    Louisiana
    
    Upstream
    
    Minerals
    
    Corporate
    
    TotalSales to external customers
    
    $
    112.8
    
    
    $
    
    
    
    $
    24.8
    
    
    $
    
    
    
    $
    
    
    
    $
    14.0
    (a)
    
    $
    151.6Segment gross profit (loss)(b)
    
    
    30.7
    
    
    
    
    
    
    
    6.2
    
    
    
    
    
    
    
    
    
    
    
    13.9
    
    
    
    50.8Depreciation, depletion and amortization
    
    
    8.9
    
    
    
    
    
    
    
    1.6
    
    
    
    
    
    
    
    
    
    
    
    0.8
    
    
    
    11.3Interest expense-net and other
financing costs
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    14.4
    
    
    
    14.4Capital expenditures
    
    
    0.2
    
    
    
    
    
    
    
    7.5
    
    
    
    
    
    
    
    
    
    
    
    0.4
    
    
    
    8.1Segment assets
    
    
    565.6
    
    
    
    
    
    
    
    122.5
    
    
    
    
    
    
    
    
    
    
    
    80.7
    
    
    
    768.8
 ($ in millions)
    
    Texas
    
    
    
    
    
    East Texas andNine months ended September 30, 2007
    
    Panhandle
    
    South Texas
    
    Louisiana
    
    Upstream
    
    Minerals
    
    Corporate
    
    TotalSales to external customers
    
    $
    335.2
    
    
    $
    115.1
    
    
    $
    105.6
    
    
    $
    19.1
    
    
    $
    9.2
    
    
    $
    (26.2
    )(a)
    
    $
    558.0Segment gross profit (loss)(b)
    
    
    76.7
    
    
    
    4.3
    
    
    
    23.1
    
    
    
    19.1
    
    
    
    9.2
    
    
    
    (26.2
    )
    
    
    106.2Depreciation, depletion and amortization
    
    
    30.2
    
    
    
    1.3
    
    
    
    7.0
    
    
    
    6.9
    
    
    
    4.9
    
    
    
    0.6
    
    
    
    50.9Interest expense-net and other
financing costs
    
    
    1.4
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    30.4
    
    
    
    31.8Capital expenditures
    
    
    29.7
    
    
    
    2.1
    
    
    
    24.1
    
    
    
    
    
    
    
    
    
    
    
    0.5
    
    
    
    56.4Segment assets
    
    
    584.0
    
    
    
    62.3
    
    
    
    290.6
    
    
    
    470.9
    
    
    
    160.8
    
    
    
    94.2
    
    
    
    1,662.8
 ($ in millions)
    
    Texas
    
    
    
    
    
    East Texas andNine months ended September 30, 2006
    
    Panhandle
    
    South Texas
    
    Louisiana
    
    Upstream
    
    Minerals
    
    Corporate
    
    TotalSales to external customers
    
    $
    324.9
    
    
    $
    
    
    
    $
    59.0
    
    
    $
    
    
    
    $
    
    
    
    $
    (21.2
    )(a)
    
    $
    362.7Segment gross profit (loss)(b)
    
    
    80.8
    
    
    
    
    
    
    
    14.3
    
    
    
    
    
    
    
    
    
    
    
    (21.3
    )
    
    
    73.8Depreciation, depletion and amortization
    
    
    26.4
    
    
    
    
    
    
    
    4.3
    
    
    
    
    
    
    
    
    
    
    
    0.8
    
    
    
    31.5Interest expense-net and other
financing costs
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    20.3
    
    
    
    20.3Capital expenditures
    
    
    5.6
    
    
    
    
    
    
    
    12.0
    
    
    
    
    
    
    
    
    
    
    
    3.4
    
    
    
    21.0Segment assets
    
    
    565.6
    
    
    
    
    
    
    
    122.5
    
    
    
    
    
    
    
    
    
    
    
    80.7
    
    
    
    768.8
 
 (a)
    
    Represents realized and unrealized revenue risk management activities.(b)
    
    Segment Gross Profit is defined as operating revenues less the purchase of natural gas and
NGLs expense, where applicable.  Three Months
    
    
    Three Months
    
    
    Nine Months
    
    
    Nine MonthsEnded
    
    
    Ended
    
    
    Ended
    
    
    EndedSeptember 30,
    
    
    September 30,
    
    
    September 30,
    
    
    September 30,($ in millions)
    
    2007
    
    
    2006
    
    
    2007
    
    
    2006Total segment gross profit
    
    $
    80.0
    
    
    $
    50.8
    
    
    $
    106.2
    
    
    $
    73.8Operations and maintenance
    
    
    16.9
    
    
    
    9.1
    
    
    
    36.0
    
    
    
    23.9Taxes other than income
    
    
    2.7
    
    
    
    0.7
    
    
    
    4.4
    
    
    
    1.0General and administrative
    
    
    7.2
    
    
    
    2.4
    
    
    
    16.6
    
    
    
    8.1Other operating
    
    
    0.2
    
    
    
    
    
    
    
    1.9
    
    
    
    Depreciation, depletion and amortization
    
    
    25.1
    
    
    
    11.2
    
    
    
    50.9
    
    
    
    31.5Interest and other expense, net
    
    
    18.1
    
    
    
    14.3
    
    
    
    29.6
    
    
    
    20.2State income tax provision
    
    
    0.4
    
    
    
    0.2
    
    
    
    0.8
    
    
    
    0.7Net income (loss)
    
    $
    9.4
    
    
    $
    12.9
    
    
    $
    (34.0
    )
    
    $
    (11.6
    )
 NOTE 13. INCOME TAXES
  25




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NOTE 14. EQUITY-BASED COMPENSATION
   Number ofRestricted
    
    Weighted AverageUnits
    
    FairValueOutstanding at December 31, 2006
    
    
    122,450
    
    
    $
    18.75Granted
    
    
    423,371
    
    
    $
    23.25Vested
    
    
    Forfeitures
    
    
    (18,800
    )
    
    $
    21.90Outstanding at September 30, 2007
    
    
    527,021
    
    
    $
    23.08
  26




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##### Table of Contents



NOTE 15. SUBSEQUENT EVENTS
  Average Monthly
    
    
    
    
    
    PricePeriod
    
    Commodity
    
    Volumes
    
    Index
    
    $/MMBtu or $/BblJan-Dec 2008
    
    Crude oil
    
    30,000 Bbl
    
    NYMEX WTI
    
    
    89.50Jan-Dec 2009
    
    Crude oil
    
    50,000 Bbl
    
    NYMEX WTI
    
    
    80.25Jan-Dec 2010
    
    Crude oil
    
    10,000 Bbl
    
    NYMEX WTI
    
    
    78.35Jan-Dec 2011
    
    Crude oil
    
    45,000 Bbl
    
    NYMEX WTI
    
    
    80.00Jan-Dec 2012
    
    Crude oil
    
    40,000 Bbl
    
    NYMEX WTI
    
    
    80.30Jan-Dec 2008
    
    Natural gas
    
    83,000 MMBtu
    
    NYMEX
    
    
    8.00Jan-Dec 2009
    
    Natural gas
    
    85,000 MMBtu
    
    NYMEX
    
    
    8.35
 Price$/MMBtu or $/BblAverage Monthly
    
    
    
    
    
    Floor
    
    CapPeriod
    
    Commodity
    
    Volumes
    
    Index
    
    ($/Unit)
    
    ($/Unit)Jan-Dec 2011
    
    Crude oil
    
    50,000 Bbl
    
    NYMEX WTI
    
    
    75.00
    
    
    
    85.70Jan-Dec 2012
    
    Crude oil
    
    50,000 Bbl
    
    NYMEX WTI
    
    
    75.30
    
    
    
    86.00Jan-Dec 2009
    
    Natural gas
    
    85,000 MMBtu
    
    NYMEX
    
    
    7.85
    
    
    
    9.25Jan-Dec 2010
    
    Natural gas
    
    110,000 MMBtu
    
    NYMEX
    
    
    7.70
    
    
    
    9.10Jan-Dec 2011
    
    Natural gas
    
    100,000 MMBtu
    
    NYMEX
    
    
    7.50
    
    
    
    8.85Jan-Dec 2012
    
    Natural gas
    
    90,000 MMBtu
    
    NYMEX
    
    
    7.35
    
    
    
    8.65
   27




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Item 2. Managements Discussion and Analysis of Financial Condition and Results of Operations.
 Overview
      
 Cautionary Note Regarding Forward-Looking Statements
  28




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##### Table of Contents



Our Operations  Midstream Segment
  
    
    Fee-Based Arrangements.  Under these arrangements, we generally are paid a fixed cash
fee per unit volume for performing the gathering and processing service. This fee is
directly related to the volume of natural gas that flows through our systems and is not
directly dependent on commodity prices. A sustained decline, however, in commodity prices
could result in a decline in volumes and, thus, a decrease in our fee revenues. These
arrangements provide stable cash flows, but minimal, if any, upside in higher commodity
price environments. As of September 30, 2007, these arrangements accounted for
approximately 43% of our natural gas volumes.
    
    Percent-of-Proceeds Arrangements.  Under these arrangements, we generally gather raw
natural gas from producers at the wellhead, transport the gas through our gathering system,
process the gas and sell the processed gas and/or NGLs at prices based on published index
prices. These arrangements provide upside in high commodity price environments, but result
in lower margins in low commodity price environments. We regard the margin from this type
of arrangement, that is, the sale proceeds less amounts remitted to the producers, as an
important analytical measure of these arrangements. The price paid to producers is based on
an agreed percentage of one of the following: (1) the actual sale proceeds; (2) the
proceeds based on an index price; or (3) the proceeds from the sale of processed natural
gas or NGLs or both. We refer to contracts in which we share only in specified percentages
of the proceeds from the sale of NGLs and in which the producer receives 100% of the
proceeds from natural gas sales, as percent-of-liquids arrangements. Under
percent-of-proceeds arrangements, our margin correlates directly with the prices of natural
gas and NGLs and under percent-of-liquids arrangements, our margin correlates directly with
the prices of NGLs (although there is often a fee-based component to both of these forms of
contracts in addition to the commodity sensitive component). As of September 30, 2007,
these arrangements accounted for about 29% of our natural gas volumes.
    
    Fixed Recovery Arrangements.Under these arrangements, we generally gather raw natural
gas from producers at the wellhead, transport the natural gas through our gathering system,
process the natural gas and sell the processed natural gas and/or NGLs at prices based on
published index prices. These arrangements provide upside in high commodity price
environments, but result in lower margins in low commodity price environments. We regard
the margin from this type of arrangement, that is, the sale proceeds less amounts remitted
to the producers, as an important analytical measure of these arrangements. The price paid
to the producers is based on an agreed to theoretical product recovery factor to be applied
against the wellhead production and then a percentage of the theoretical proceeds based on
an index or actual sales prices multiplied to the theoretical production. To the extent
that the actual recoveries differ from the theoretical product recovery factor, this will
affect the margin. As of September 30, 2007, these arrangements accounted for approximately
20% of our natural gas volumes.
    
    Keep-Whole Arrangements.  Under these arrangements, we process raw natural gas to
extract NGLs and pay to the producer the full thermal equivalent volume of raw natural gas
received from the producer in the form of either processed natural gas or its cash
equivalent. We are generally entitled to retain the processed NGLs and to sell them for our
account. Accordingly, our margin is a function of the difference between the value of
the NGLs produced and the cost of the processed gas used to replace the thermal equivalent
value of those NGLs. The profitability of these arrangements is subject not only to the
commodity price risk of natural gas
 29




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##### Table of Contents



and NGLs, but also to the price of natural gas relative
to NGL prices. These arrangements can provide improved profit margins in favorable commodity
price environments, but also can be subject to losses if the cost of natural gas exceeds the
value of its thermal equivalent of NGLs. Many of our keep-whole contracts include provisions
that reduce our commodity price exposure, including (1) conditioning floors that require the
keep-whole contract to convert to a fee-based arrangement if the NGLs have a lower value
than their thermal equivalent in natural gas, (2) embedded discounts to the applicable
natural gas index price under which we may reimburse the producer an amount in cash for the
thermal equivalent volume of raw natural gas acquired from the producer, or (3) fixed cash
fees for ancillary services, such as gathering, treating and compressing. As of September
30, 2007, these arrangements accounted for about 8% of our natural gas volumes.
Approximately 73% of these keep-whole arrangements have fee components.
     ONEOK Hydrocarbon.
 Chesapeake Energy Marketing.
 Cimarex Energy.
 30




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##### Table of Contents



Our Operations  Upstream Segment
  Alabama
 East Texas
 South Texas
    31




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##### Table of Contents



Our Operations  Minerals Segment
      How We Evaluate Our Operations
  Midstream Volumes.
 Upstream Volumes.
 Minerals Volumes.
 32




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##### Table of Contents



Segment Gross Profit.
 Risk Management.
 Midstream Operating Expenses.
 Upstream Operating Expenses.
 Minerals Operating Expenses
 Adjusted EBITDA.
 33




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##### Table of Contents



General Trends and Outlook
  Natural Gas Supply, Demand and Outlook.
   Crude Oil Supply, Demand and Outlook.
   Impact of Interest Rates and Inflation.
 34




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##### Table of Contents



Formation and Acquisitions
   Acquisition of certain entities and fee minerals, royalties and working interest properties from
Montierra Minerals & Production, L.P. and NGP-VII Income Co-Investment Opportunities L.P.
  Acquisition of Laser Entities
  Acquisition of fee minerals, royalties and working interest properties from MacLondon Energy, L.P.
  Acquisition of Escambia Entities
  35




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##### Table of Contents



Acquisition of Redman Entities (and certain related assets)
  Critical Accounting Policies and Estimates
   Financial Accounting and Reporting for Oil and Gas Producing
Companies
   Accounting for the Impairment or Disposal of Long-Lived
Assets,
  36




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##### Table of Contents



EAGLE ROCK ENERGY PARTNERS, L.P.
 RESULTS OF OPERATIONS
  Three Months
    
    
    Nine MonthsEnded September 30,
    
    
    Ended September 30,($ in thousands)
    
    2007
    
    
    2006
    
    
    2007
    
    
    2006Sales of natural gas, NGLs, condensate and oil sales
    
    $
    253,056
    
    
    $
    132,907
    
    
    $
    554,797
    
    
    $
    373,001Compression, gathering and processing
    
    
    7,723
    
    
    
    4,549
    
    
    
    19,271
    
    
    
    10,495Minerals and royalty income
    
    
    6,009
    
    
    
    
    
    
    
    9,201
    
    
    
    Gain/(loss) on realized risk management instrument
    
    
    (177
    )
    
    
    (449
    )
    
    
    4,324
    
    
    
    122Gain/(loss) on unrealized risk management instrument
    
    
    8,865
    
    
    
    14,480
    
    
    
    (30,533
    )
    
    
    (21,331
    )Other income
    
    
    1,388
    
    
    
    109
    
    
    
    1,007
    
    
    
    436Total operating revenue
    
    
    276,864
    
    
    
    151,596
    
    
    
    558,067
    
    
    
    362,723Purchase of natural gas and NGLs
    
    
    196,839
    
    
    
    100,723
    
    
    
    451,838
    
    
    
    288,881Total segment gross profit(a)
    
    
    80,025
    
    
    
    50,873
    
    
    
    106,229
    
    
    
    73,842Operating and maintenance expense
    
    
    16,883
    
    
    
    9,094
    
    
    
    36,017
    
    
    
    23,892Taxes other than income
    
    
    2,746
    
    
    
    651
    
    
    
    4,364
    
    
    
    1,045General and administrative expense
    
    
    7,196
    
    
    
    2,446
    
    
    
    16,587
    
    
    
    8,063Other operating expense
    
    
    220
    
    
    
    
    
    
    
    1,931
    
    
    
    Depreciation, depletion and amortization
    
    
    25,105
    
    
    
    11,244
    
    
    
    50,883
    
    
    
    31,459Interest-net, including realized risk management instrument
    
    
    10,490
    
    
    
    7,730
    
    
    
    27,079
    
    
    
    22,892(Gain)/loss on unrealized risk management interest rate
instrument
    
    
    8,429
    
    
    
    6,600
    
    
    
    3,555
    
    
    
    (2,639
    )Other (income)/expense
    
    
    (767
    )
    
    
    
    
    
    
    (879
    )
    
    
    Income tax provision
    
    
    352
    
    
    
    236
    
    
    
    772
    
    
    
    744Net income (loss)
    
    $
    9,371
    
    
    $
    12,872
    
    
    $
    (34,080
    )
    
    $
    (11,614
    )Adjusted EBITDA(b)
    
    $
    45,155
    
    
    $
    24,202
    
    
    $
    81,407
    
    
    $
    62,173
 
 (a)
    
    Defined as operating revenues less the purchase of natural gas and NGLs expense. Operating
revenues include both realized and unrealized revenue risk management activities. 37




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(b)
    
    Defined as net income (loss) plus income tax provision, interest-net (including both realized
and unrealized interest rates risk management activities), depreciation, depletion and
amortization expense, other operating expense, other non-cash operating and general and
administrative expenses (including non-cash compensation related to our equity-based
compensation program) less non-realized revenues risk management instrument gain (loss)
activities and other income/(expense). Other operating expense for 2007 includes legal
arbitration settlement recorded in 2007 that relates to Panhandle Segment assets before the
Partnership owned them, executive separation cost and delay fees related to registration
rights on certain unitholders.  Three Months
    
    
    Nine MonthsEnded September 30,
    
    
    Ended September 30,2007
    
    
    2006
    
    
    2007
    
    
    2006($ in thousands)Total segment gross profit:
    
    $
    80,025
    
    
    $
    50,873
    
    
    $
    106,229
    
    
    $
    73,842Less:Operations and maintenance expense
    
    
    16,883
    
    
    
    9,094
    
    
    
    36,017
    
    
    
    23,892Taxes other than income
    
    
    2,746
    
    
    
    651
    
    
    
    4,364
    
    
    
    1,045General and administrative expense
    
    
    7,196
    
    
    
    2,446
    
    
    
    16,587
    
    
    
    8,063Other operating expense
    
    
    220
    
    
    
    
    
    
    
    1,931
    
    
    
    Depreciation, depletion and amortization
    
    
    25,105
    
    
    
    11,244
    
    
    
    50,883
    
    
    
    31,459Interest-net including realized risk management instrument
    
    
    10,490
    
    
    
    7,730
    
    
    
    27,079
    
    
    
    22,892Gain/(loss) on unrealized risk management interest
related instrument
    
    
    8,429
    
    
    
    6,600
    
    
    
    3,555
    
    
    
    (2,639
    )Other (income)/expense
    
    
    (767
    )
    
    
    
    
    
    
    (879
    )
    
    
    Income tax provision
    
    
    352
    
    
    
    236
    
    
    
    772
    
    
    
    744Net income (loss)
    
    $
    9,371
    
    
    $
    12,872
    
    
    $
    (34,080
    )
    
    $
    (11,614
    )
  Three Months
    
    
    Nine MonthsEnded September 30,
    
    
    Ended September 30,2007
    
    
    2006
    
    
    2007
    
    
    2006($ in thousands)Adjusted EBITDA:
    
    $
    45,155
    
    
    $
    24,202
    
    
    $
    81,407
    
    
    $
    62,173Less:Income tax provision
    
    
    352
    
    
    
    236
    
    
    
    772
    
    
    
    744Other (income)/expense
    
    
    (767
    )
    
    
    
    
    
    
    (879
    )
    
    
    (Gain)/loss on unrealized risk management
interest related instrument
    
    
    8,429
    
    
    
    6,600
    
    
    
    3,555
    
    
    
    (2,639
    )Interest-net including realized risk
management instrument
    
    
    10,490
    
    
    
    7,730
    
    
    
    27,079
    
    
    
    22,892Depreciation, depletion and amortization
    
    
    25,105
    
    
    
    11,244
    
    
    
    50,883
    
    
    
    31,459Other operating expense
    
    
    220
    
    
    
    
    
    
    
    1,931
    
    
    
    Restricted units non-cash amortization expense
    
    
    820
    
    
    
    
    
    
    
    1,613
    
    
    
    Plus:Gain/(loss) revenue risk management
instruments-unrealized
    
    
    8,865
    
    
    
    14,480
    
    
    
    (30,533
    )
    
    
    (21,331
    )Net income (loss)
    
    $
    9,371
    
    
    $
    12,872
    
    
    $
    (34,080
    )
    
    $
    (11,614
    )
 Three Months Ended September 30, 2007 Compared with Three Months Ended September 30, 2006
  38




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39




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##### Table of Contents



Nine Months Ended September 30, 2007 Compared with Nine Months Ended September 30, 2006
        40




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Other Matters
 Wildfires in Texas Panhandle.
 Environmental.
 41




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##### Table of Contents



Liquidity and Capital Resources
    Cash Flows and Capital Expenditures
  
    
    the construction and installation of 1.7 miles of 10-inch diameter and 12.6 miles of
12-inch diameter natural gas pipeline called our Tyler County Pipeline Extension project,
completed in March 2007 at a cost of $24.2 million, plus the expansion of this pipeline
system, called our Tyler County Pipeline Phase II project at an incremental cost of $2.8
million, completed in October 2007;
    
    the acquisition of the Brookeland gathering and processing facility and related assets
on March 31, 2006 and April 7, 2006 for approximately $95.8 million, which we financed
entirely with equity;
    
    the acquisition of all of the partnership interests in Midstream Gas Services, L.P. on
June 2, 2006 , for which the sellers received $4.7 million in cash and 1,125,416 units in
Eagle Rock Pipeline, L.P. (which converted to 809,329 of our common units at the time of
our IPO);
    
    the acquisition of certain fee minerals, royalties and non-operated working interest
properties from Montierra Minerals & Production, L.P., and NGP-VII Income Co-Investment
Opportunities, L.P. on April 30, 2007, for which the sellers received 6,390,400 of our
common units, subject to adjustment, and the extinguishment of $6.0 million of debt;
 42




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##### Table of Contents




    
    the acquisition of Laser Midstream Energy, LP, on May 3, 2007, including its
subsidiaries Laser Quitman Gathering Company, LP, Laser Gathering Company, LP, Hesco
Gathering Company, LLC, and Hesco Pipeline Company, LLC, for which the sellers received
$110.0 million in cash and 1,407,895 of our common units, subject to adjustment;
    
    the acquisition of certain fee minerals, royalties and non-operated working interest
properties from MacLondon Energy, L.P. on June 18, 2007 for 789,474 of our common units,
subject to adjustment;
    
    the private placement of 7,005,495 common units to several institutional purchasers in
a private offering resulting in gross proceeds of $127.5 million, on May 3, 2007. The
proceeds from this offering were used to fully fund the cash portion of the purchase price
of the Laser Acquisition and other general company purposes;
    
    the refurbishment and installation of a 20 MMcf/d processing facility located in
Roberts County, Texas called our Red Deer Processing Plant, at a cost of $17.4 million and
put in service on June 21, 2007.
    
    the acquisition of Escambia Asset Co, LLC and Escambia Operating Co, LLC on July 31,
2007, for which the sellers in the transaction received approximately $224.0 million in
cash and 689,857 in Eagle Rock common units, subject to adjustment;
    
    the acquisition of Redman Energy Holdings, L.P. and Redman Energy Holdings II, L.P. and
certain assets owned by NGP Income Co-Investment Opportunities Fund II, L.P. on July 31,
2007, for which the sellers in the transaction received as consideration a total of
4,428,334 newly-issued Eagle Rock common units and $83.8 million in cash, subject to
adjustment; and
    
    the private placement of 9,230,770 common units among a group of institutional
investors for total cash proceeds of approximately $204.0 million on July 31, 2007. The
proceeds from the private offering were used to partially fund the cash portion of the
purchase price of the EAC and Redman Acquisitions.
     43




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##### Table of Contents



Working Capital.
  
    
    cash balances and marketable securities, net of Due to Affiliate increased overall by
$56.5 million and was impacted primarily from the working capital balances acquired in the
acquisitions during the year, from the results of operations, timing of capital
expenditures payments, financing activities including our debt activities as well as
members equity distributions. The Due to Affiliate liability of $17.4 million as of
September 30, 2007 is owed to Eagle Rock Energy G&P, LLC;
    
    trade accounts receivable increased by $78.4 million primarily from the receivables
activities from the acquisitions completed during the 2007 year;
    
    risk management net working capital balance increased by a
net $0.4 million as a
result of the changes in the mark-to-market unrealized positions and fair value changing of
the option premiums;
    
    accounts payable increased by $81.0 million from December 31, 2006 primarily as a
result of the payables activities from the acquisitions during the current year, activities
and timing of payments, including capital expenditures activities; and
    
    accrued liabilities increase of $12.8 million primarily reflects unbilled expenditures
related primarily to capital expenditures and activities from the acquisitions during the
year.
 Cash Flows Nine Months 2007 Compared to Nine Months 2006
 Cash
Flows from Operating Activities .
 Cash Flows Used in Investing Activities .
 Cash Flows Provided by (Used in) Financing Activities .
 44




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Capital Requirements
     
    
    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, or grow our production in our upstream business; or
    
    maintenance capital expenditures, which are made to replace partially or fully
depreciated assets, to meet regulatory requirements, to maintain the existing operating
capacity of our assets and extend their useful lives, or to connect wells to maintain
existing system volumes and related cash flows; in our upstream business, maintenance
capital is defined as capital which is expended to maintain our production and cash flow
levels in the near future.
   Amended and Restated Credit Agreement
   45




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##### Table of Contents




    
    an interest coverage ratio (the ratio of our consolidated Adjusted EBITDA to our
consolidated interest expense, in each case as defined in the credit agreement) of not less
than 2.5 to 1.0, determined as of the last day of each quarter for the four quarter period
ending on the date of determination; and a leverage ratio (the ratio of our consolidated
indebtedness to our consolidated Adjusted EBITDA, in each case as defined in the credit
agreement) of not more than 5.0 to 1.0 (or, on a temporary basis for not more than three
consecutive quarters following the consummation of certain acquisitions, not more than 5.25
to 1.0).
  Off-Balance Sheet Obligations.
 Debt Covenants.
 Total Contractual Cash Obligations.
 ($ in millions)
    
    Payments Due by PeriodContractual Obligations
    
    Total
    
    
    2007
    
    
    2008
    
    
    2009
    
    
    2010-2011
    
    
    ThereafterLong-term debt (including interest)(1)
    
    $
    760.3
    
    
    $
    38.2
    
    
    $
    43.9
    
    
    $
    43.9
    
    
    $
    634.3
    
    
    $
    0.0Operating leases
    
    
    5.8
    
    
    
    0.9
    
    
    
    0.9
    
    
    
    0.9
    
    
    
    0.7
    
    
    
    2.4Purchase obligations(2)
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    Total contractual obligations
    
    $
    766.1
    
    
    $
    39.1
    
    
    $
    44.8
    
    
    $
    44.8
    
    
    $
    635.0
    
    
    $
    2.4
 
 (1)
    
    Assumes average base interest rate of 4.84%, including impact of
current interest rate swaps, plus the applicable margin under our
Amended and Restated Credit Agreement, which remains constant in all
periods.(2)
    
    Excludes physical and financial purchases of natural gas, NGLs, and
other energy commodities due to the nature of both the price and
volume components of such purchases, which vary on a daily or monthly
basis. Additionally, we do not have contractual commitments for fixed
price and/or fixed quantities of any material amount. 46




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Recent Accounting Pronouncements
 Accounting for Certain Hybrid Financial Instruments Accounting for Transfers and Servicing of Financial Assets and Extinguishment
of Liabilities
 Fair Value Measurements.
 The Fair Value Option for Financial Assets and
Financial Liabilities
 Accounting for Uncertainty in
Income Taxes  an interpretation of FASB Statement No. 109
 
 Item 3. Quantitative and Qualitative Disclosures About Market Risk.
 Risk and Accounting Policies
  47




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Commodity Price Risk
      
 Item 4. Controls and Procedures.
 Disclosure Controls
   48




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Internal Control over Financial Reporting
 13a-14.
  Restatement of Second Quarter Financial Statements
   
 PART II. OTHER INFORMATION
 
 Item 1. Legal Proceedings.
   
 Item 1A. Risk Factors.
 Limited partner interests are inherently different from capital stock of a corporation,
although many of the business risks to which we are subject are similar to those that would be
faced by a corporation engaged in similar businesses.
 If any of the following risks were actually to occur, our business, financial condition or
results of operations could be materially adversely affected. In that case, we might not be able to
pay the minimum quarterly distribution on our common units, the trading price of our common units
could decline and you could lose all or part of your investment.
 Certain risks apply to both our midstream business and our upstream business. To the extent
any risk applies to one or the other, we have indicated the specific risk in the appropriate risk
factor.
 Risks Related to Our Business
 Because of the natural decline in production from existing wells, our success depends on our
ability to obtain new sources of production and supplies of oil, natural gas and NGLs, which are
dependent on certain factors beyond our control. Our success is also dependent on developing
current reserves. Any decrease in production or supplies of oil, natural gas or NGLs could
adversely affect our business and operating results.
  49




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##### Table of Contents



Natural gas, NGLs, Crude Oil and other commodity prices are volatile, and a reduction in these
prices could adversely affect our cash flow and our ability to make distributions.
  
    
    the impact of weather or force majeure events on the demand for oil and natural gas;
    
    the level of domestic oil and natural gas production and demand;
    
    the level of imported oil and natural gas availability and demand;
    
    the level of consumer product demand;
    
    political and economic conditions and events in, as well as actions taken by foreign
oil and natural gas producing nations;
    
    overall domestic and global economic conditions;
    
    the availability of local, intrastate and interstate transportation systems including
natural gas pipelines and other transportation facilities to our production;
    
    the availability and marketing of competitive fuels;
    
    delays or cancellations of crude oil and natural gas drilling and production
activities;
 50




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##### Table of Contents




    
    the impact of energy conservation efforts, including technological advances affecting
energy consumption; and
    
    the extent of governmental regulation and taxation.
   Our hedging activities may have a material adverse effect on our earnings, profitability, cash
flows and financial condition.
  51




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Our estimated oil and natural gas reserve quantities and future production rates are based on many
assumptions that may prove to be inaccurate. Any material inaccuracies in these reserve estimates
or the underlying assumptions will materially affect the quantities and present value of our
reserves.
    52




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Our operations will require substantial capital expenditures, which will reduce our cash
available for distribution. We may be unable to obtain needed capital or financing on
satisfactory terms, which could lead to a decline in our cash flows.
  
    
    volume throughput through our pipelines and processing facilities;
    
    the estimated quantities of our oil and natural gas reserves;
    
    the amount of oil and natural gas produced from existing wells;
    
    the prices at which we sell our production or that of our midstream customers; and
    
    our ability to acquire, locate and produce new reserves.
  We typically do not obtain independent evaluations of other producers natural gas reserves
dedicated to our gathering and pipeline systems; therefore, volumes of natural gas on our systems
in the future could be less than we anticipate.
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The loss of any of our significant customers could result in a decline in our volumes, revenues
and cash available for distribution.
 Midstream.
 Upstream.
 We may not successfully balance our purchases and sales of natural gas, which would increase our
exposure to commodity price risks.
  If third-party pipelines and other facilities interconnected to our systems become unavailable to
transport or produce natural gas and NGLs, our revenues and cash available for distribution could
be adversely affected.
  Our access to transportation options may affect our revenues and cash available for distribution.
  Our industry is highly competitive, and increased competitive pressure could adversely affect our
business and operating results.
  Midstream.
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Upstream.
  A change in the jurisdictional characterization of some of our assets by federal, state or local
regulatory agencies or a change in policy by those agencies may result in increased regulation of
our assets, which may cause our revenues to decline and operating expenses to increase.
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We
are subject to compliance with stringent environmental laws and
regulations that may expose us to significant costs and
liabilities.
    
    
    the federal Clean Air Act and comparable state laws and regulations that impose
obligations related to air emissions;
    
    the federal Clean Water Act and comparable state laws and regulations that impose
obligations related to discharges of pollutants into regulated bodies of water;
    
    the federal Resource Conservation and Recovery Act, or RCRA, and comparable state laws
that impose requirements for the handling and disposal of waste from our facilities; and
    
    the Comprehensive Environmental Response, Compensation and Liability Act of 1980, or
CERCLA, also known as Superfund, and comparable state laws that regulate the cleanup of
hazardous substances that may have been released at properties currently or previously
owned or operated by us or at locations to which we have sent waste for disposal.
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Our construction of new assets may not result in revenue increases and is subject to regulatory,
environmental, political, legal and economic risks, which could adversely affect our results of
operations and financial condition.
  If we do not make acquisitions on economically acceptable terms, our future growth will be
limited.
    
    
    mistaken assumptions about future prices, volumes, revenues and costs of oil and
natural gas, including synergies and estimates of the oil and natural gas reserves
attributable to a property we acquire;
    
    an inability to integrate successfully the businesses we acquire;
    
    inadequate expertise for new geographic areas, operations or products and services;
    
    the assumption of unknown liabilities;
    
    limitations on rights to indemnity from the seller;
    
    mistaken assumptions about the overall costs of equity or debt;
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
    
    the diversion of managements and employees attention from other business concerns;
    
    unforeseen difficulties operating in new product areas or new geographic areas;
    
    customer or key employee losses at the acquired businesses; and
    
    establishment of internal controls and procedures that we are required to maintain
under the Sarbanes-Oxley Act of 2002.
  Our ability to derive benefits from our acquisitions will depend on our ability to integrate
operations to achieve the benefits of the acquisitions.
  
    
    geographically separated organizations and possible differences in corporate cultures
and management philosophies;
    
    significant demands on management resources, which may distract managements attention
from day-to-day business;
    
    differences in the disclosure systems, accounting systems, and accounting controls and
procedures of the two companies, which may interfere with our ability to make timely and
accurate public disclosure; and
    
    the demands of managing new lines of business acquired.
  We do not own all of the land on which our pipelines and facilities are located, which could
disrupt our operations.
  Our business involves many hazards and operational risks, some of which may not be fully covered
by insurance. If a significant accident or event occurs that is not fully insured or interrupts
normal operations, our operations and financial results could be adversely affected.
  
    
    damage to production equipment, pipelines and plants, related equipment and surrounding
properties caused by hurricanes, tornadoes, floods, fires and other natural disasters and
acts of terrorism;
    
    inadvertent damage from construction, farm and utility equipment;
    
    leaks of natural gas, NGLs and other hydrocarbons or losses of natural gas or NGLs as a
result of the malfunction of pipeline, equipment or facilities;
    
    fires and explosions; and
    
    other hazards that could also result in personal injury and loss of life, pollution and
suspension of operations, such as the uncontrollable flow of oil or natural gas or well
fluids.
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Our current debt levels may limit our flexibility in obtaining additional financing and in
pursuing other business opportunities. In addition, we may incur substantial debt in the future to
enable us to maintain or increase our reserve and production levels and to otherwise pursue our
business plan. This debt may restrict our ability to make distributions.
  
    
    our ability to obtain additional financing, if necessary, for working capital, capital
expenditures, acquisitions or other purposes may be impaired or such financing may not be
available on favorable terms;
    
    we will need a portion of our cash flow to make interest payments on our debt, reducing
the funds that would otherwise be available for operations, future business opportunities
and distributions to unitholders;
    
    our debt level will make us more vulnerable to competitive pressures or a downturn in
our business or the economy generally; and
    
    our debt level may limit our flexibility in responding to changing business and
economic conditions.
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Shortages of drilling rigs, equipment and crews could delay our operations and reduce our cash
available for distribution.
  Our and other operators drilling operations may be curtailed, delayed or cancelled as a result of
a variety of factors.
  
    
    unexpected drilling conditions;
    
    drilling, production or transportation facility or equipment failure or accidents;
    
    shortages or delays in the availability of drilling rigs and other services and
equipment;
    
    adverse weather conditions;
    
    compliance with environmental and governmental requirements;
    
    title problems;
    
    unusual or unexpected geological formations;
    
    pipeline ruptures;
    
    fires, blowouts, craterings and explosions; and
    
    uncontrollable flows of oil or natural gas or well fluids.
   Restrictions in our amended and restated credit facility limit our ability to make distributions
and limit our ability to capitalize on acquisitions and other business opportunities.
  Increases in interest rates, which have recently experienced record lows, could adversely impact
our unit price and our ability to issue additional equity, to incur debt to make acquisitions or
for other purposes or to make cash distributions at our intended levels.
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Due to our limited industry and geographic diversification in our midstream operations and in our
upstream operated properties, adverse developments in our operations or operating areas would
reduce our ability to make distributions to our unitholders.
  We are exposed to the credit risks of our key producer customers, and any material nonpayment or
nonperformance by our key producer customers could reduce our ability to make distributions to our
unitholders.
  Terrorist attacks, and the threat of terrorist attacks, have resulted in increased costs to our
business. Continued hostilities in the Middle East or other sustained military campaigns may
adversely impact our results of operations.
   If we fail to develop or maintain an effective system of internal controls, we may not be able to
report our financial results accurately or prevent fraud.
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Risks Inherent in an Investment in Us
 We may not have sufficient cash from operations following the establishment of cash reserves and
payment of fees and expenses, including cost reimbursements to our general partner, to enable us
to make cash distributions to holders of our common units and subordinated units at the initial
distribution rate under our cash distribution policy.
  
    
    the fees we charge and the margins we realize for our services;
    
    the prices and level of production of and demand for, oil, natural gas, NGLs and
condensate that we and others produce;
    
    the volume of natural gas we gather, treat, compress, process, transport and sell, the
volume of NGLs we transport and sell, and the volume of oil and natural gas we and others
produce;
    
    our operators and other producers drilling activities and success of such programs;
    
    the level of competition from other upstream and midstream energy companies;
    
    the level of our operating and maintenance and general and administrative costs;
    
    the relationship between oil, natural gas and NGL prices; and
    
    prevailing economic conditions.
  
    
    the level of capital expenditures we make;
    
    the cost of acquisitions;
    
    our debt service requirements and other liabilities;
    
    fluctuations in our working capital needs;
    
    our ability to borrow funds and access capital markets;
    
    restrictions contained in our debt agreements; and
    
    the amount of cash reserves established by our general partner.
 The amount of cash we have available for distribution to holders of our common units and
subordinated units depends primarily on our cash flow and not solely on profitability.
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Eagle Rock Holdings, L.P., owns and controls our general partner, which has sole responsibility for
conducting our business and managing our operations. Our general partner has conflicts of interest,
which may permit it to favor its own interests.
  
    
    neither our partnership agreement nor any other agreement requires the NGP Investors to
pursue a business strategy that favors us;
    
    our general partner is allowed to take into account the interests of parties other than
us in resolving conflicts of interest;
    
    the NGP Investors and its affiliates are not limited in their ability to compete with
us;
    
    our general partner has limited its liability and reduced its fiduciary duties, and has
also restricted the remedies available to our unitholders for actions that, without the
limitations, might constitute breaches of fiduciary duty;
    
    our general partner determines the amount and timing of asset purchases and sales,
borrowings, issuance of additional partnership securities and reserves, each of which can
affect the amount of cash that is distributed to unitholders;
    
    our general partner determines the amount and timing of any capital expenditures and
whether a capital expenditure is a maintenance capital expenditure, which reduces operating
surplus, or an expansion capital expenditure, which does not reduce operating surplus. This
determination can affect the amount of cash that is distributed to our unitholders and the
ability of the subordinated units to convert to common units;
    
    our general partner determines which costs incurred by it and its affiliates are
reimbursable by us;
    
    our partnership agreement does not restrict our general partner from causing us to pay
it or its affiliates for any services rendered to us or entering into additional
contractual arrangements with any of these entities on our behalf;
    
    our general partner intends to limit its liability regarding our contractual and other
obligations and, in some circumstances, is entitled to be indemnified by us;
    
    our general partner may exercise its limited right to call and purchase common units if
it and its affiliates own more than 80% of the common units;
    
    our general partner controls the enforcement of obligations owed to us by our general
partner and its affiliates; and
    
    our general partner decides whether to retain separate counsel, accountants or others
to perform services for us.
 Affiliates of our general partner are not limited in their ability to compete with us, which could
cause conflicts of interest and limit our ability to acquire additional assets, drilling
opportunities or businesses which in turn could adversely affect our results of operations and
cash available for distribution to our unitholders.
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Cost reimbursements due to our general partner and its affiliates for services provided, which
will be determined by our general partner, will be substantial and will reduce our cash available
for distribution.
  Our general partner intends to limit its liability regarding our obligations.
  Our partnership agreement requires that we distribute all of our available cash, which could limit
our ability to grow and make acquisitions.
   Our partnership agreement limits our general partners fiduciary duties to holders of our common
units and subordinated units.
  
    
    its limited call right;
    
    its voting rights with respect to the units it owns;
    
    its registration rights; and
    
    and its determination whether or not to consent to any merger or consolidation of the
partnership or amendment to the partnership agreement.
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Our partnership agreement restricts the remedies available to holders of our common units and
subordinated units for actions taken by our general partner that might otherwise constitute
breaches of fiduciary duty.
  
    
    provides that whenever our general partner makes a determination or takes, or declines
to take, any other action in its capacity as our general partner, our general partner is
required to make such determination, or take or decline to take such other action in good
faith, and our general partner will not be subject to any other or different standard
imposed by our partnership agreement, Delaware law or any other law, rule or regulation or
at equity;
    
    provides that our general partner will not have any liability to us or our unitholders
for decisions made in its capacity as a general partner so long as it acted in good faith,
and our partnership agreement specifies that the satisfaction of this standard requires
that our general partner must believe that the decision is in the best interests of our
partnership;
    
    provides that our general partner and its officers and directors will not be liable for
monetary damages to us, our limited partners or assignees for any acts or omissions unless
there has been a final and non-appealable judgment entered by a court of competent
jurisdiction determining that the general partner or those other persons acted in bad faith
or engaged in fraud or willful misconduct or, in the case of a criminal matter, acted with
knowledge that the conduct was criminal; and
    
    provides that our general partner will not be in breach of its obligations under the
partnership agreement or its fiduciary duties to us or our unitholders if the resolution of
a conflict is:
    
    approved by the conflicts committee of our general partner, although our general
partner is not obligated to seek such approval;
    
    approved by the vote of a majority of the outstanding common units, excluding any
common units owned by our general partner or any of its affiliates;
    
    on terms no less favorable to us than those generally being provided to or available
from unrelated third parties; or
    
    fair and reasonable to us, taking into account the totality of the relationships among
the parties involved, including other transactions that may be particularly favorable or
advantageous to us.
  Holders of our common units have limited voting rights and are not entitled to elect our general
partner or its directors.
  Our partnership agreement restricts the voting rights of unitholders owning 20% or more of our
common units.
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Control of our general partner may be transferred to a third party without unitholder consent.
  We may issue additional units without limited partner approval, which would dilute ownership
interests.
  
    
    our unitholders proportionate ownership interest in us will decrease;
    
    the amount of cash available for distribution on each unit may decrease;
    
    because a lower percentage of total outstanding units will be subordinated units, the
risk that a shortfall in the payment of the minimum quarterly distribution will be borne by
our common unitholders will increase;
    
    the ratio of taxable income to distributions may increase;
    
    the relative voting strength of each previously outstanding unit may be diminished; and
    
    the market price of the common units may decline.
 Affiliates of our general partner, certain private investors and employees, may sell common units
in the public markets, which sales could have an adverse impact on the trading price of the common
units.
  Our general partner has a limited call right that may require limited partners to sell their units
at an undesirable time or price.
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Liability of a limited partner may not be limited if a court finds that unitholder action
constitutes control of our business.
  
    
    a court or government agency determined that we were conducting business in a state but
had not complied with that particular states partnership statute; or
    
    the right to act with other unitholders to remove or replace the general partner, to
approve some amendments to our partnership agreement or to take other actions under our
partnership agreement constitute control of our business.
 Unitholders may have liability to repay distributions that were wrongfully distributed to them.
  The price of our common units may fluctuate significantly.
   
    
    our quarterly distributions;
    
    our quarterly or annual earnings or those of other companies in our industry;
    
    loss of a large customer;
    
    announcements by us or our competitors of significant contracts or acquisitions or
change in management;
    
    changes in accounting standards, policies, guidance, interpretations or principles;
    
    general economic conditions;
    
    the failure of securities analysts to cover our common units or changes in financial
estimates by analysts;
    
    future sales of our common units; and
    
    other factors described in these Risk Factors.
 We will incur increased costs as a result of being a publicly traded partnership.
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Tax Risks to Common Unitholders
 The tax efficiency of our partnership structure depends on our status as a partnership for federal
income tax purposes, as well as our not being subject to a material amount of entity-level
taxation by individual states. If the Internal Revenue Service were to treat us as a corporation
or if we become subject to a material amount of entity-level taxation for state tax purposes, it
would reduce the amount of cash available for distribution.
    If the IRS contests the federal income tax positions we take, the market for our common units may
be adversely impacted and the cost of any IRS contest will reduce our cash available for
distribution.
  Limited partners may be required to pay taxes on their share of our income even if they do not
receive any cash distributions from us.
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Tax gain or loss on disposition of our common units could be more or less than expected.
  Tax-exempt entities and foreign persons face unique tax issues from owning common units that may
result in adverse tax consequences to them.
  We will treat each purchaser of our common units as having the same tax benefits without regard to
the actual common units purchased. The IRS may challenge this treatment, which could adversely
affect the value of the common units.
  The sale or exchange of 50% or more of our capital and profits interests during any twelve-month
period will result in the termination of our partnership for federal income tax purposes.
  Limited partners will likely be subject to state and local taxes and return filing requirements in
states where they do not live as a result of investing in our common units.
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Item 2. Unregistered Sales of Equity Securities and Use of Proceeds.
   
 Item 3. Defaults Upon Senior Securities.
  
 Item 4. Submission of Matters to a Vote of Security Holders.
  
 Item 5. Other Information.
  
 Item 6. Exhibits.
 2.1
    
    Contribution and Sale Agreement By and Among Eagle Rock Energy Partners, L.P., Redman
Energy Holdings, L.P. and Certain Other Parties Named Therein, dated July 11, 2007
(incorporated by reference to Exhibit 2.4 of the registrants registration statement on
Form S-1 (File No. 333-144938)).2.2
    
    Contribution and Sale Agreement By and Among Eagle Rock Energy Partners, L.P., Redman
Energy Holdings II, L.P. and Certain Other Parties Named Therein, dated July 11, 2007
(incorporated by reference to Exhibit 2.5 of the registrants registration statement on
Form S-1 (File No. 333-144938)).2.3
    
    Asset Contribution Agreement By and Among NGP Co-Investment Opportunities Fund II, L.P.
and Eagle Rock Energy Partners, L.P., dated July 11, 2007 (incorporated by reference to
Exhibit 2.6 of the registrants registration statement on Form S-1 (File No. 333-144938)).2.4
    
    Purchase, Sale and Contribution Agreement Between AmGu
Holdings LLC, as seller, and Eagle
Rock Energy Partners, L.P., as purchaser, dated July 11, 2007 (incorporated by reference
to Exhibit 2.7 of the registrants registration statement on Form S-1 (File No.
333-144938)).4.1
    
    Registration Rights Agreement dated July 31, 2007, among Eagle Rock Energy Partners, L.P.
and the purchasers listed thereto (incorporated by reference to Exhibit 4.6 of the
registrants registration statement on Form S-1 (File No. 333-144938)).10.1
    
    Common Unit Purchase Agreement By and Among Eagle Rock Energy Partners, L.P. and The
Purchasers Named Therein, dated July 11, 2007 (incorporated by reference to Exhibit 10.15
of the registrants registration statement on Form S-1 (File No. 333-144938)).10.2
    
    Severance Agreement with former executive officer (incorporated by reference to Exhibit
10.16 of the registrants registration statement on Form S-1 (File No. 333-144938)).31.1
    
    Certification by Joseph A. Mills pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.31.2
    
    Certification by Richard W. FitzGerald pursuant to Section 302 of the Sarbanes-Oxley Act
of 2002.
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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 Richard W. FitzGerald pursuant to Section 906 of the Sarbanes-Oxley Act
of 2002 and 18 U.S.C. Section 1350.
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SIGNATURES
   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/ Richard W. FitzGerald

Richard W. FitzGerald

Senior Vice President, 
Chief Financial Officer
and Treasurer(Duly Authorized and Principal Financial Officer)
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EAGLE ROCK ENERGY PARTNERS, L.P.
 
 EXHIBIT INDEX
 2.1
    
    Contribution and Sale Agreement By and Among Eagle Rock Energy Partners, L.P., Redman
Energy Holdings, L.P. and Certain Other Parties Named Therein, dated July 11, 2007
(incorporated by reference to Exhibit 2.4 of the registrants registration statement on
Form S-1 (File No. 333-144938)).2.2
    
    Contribution and Sale Agreement By and Among Eagle Rock Energy Partners, L.P., Redman
Energy Holdings II, L.P. and Certain Other Parties Named Therein, dated July 11, 2007
(incorporated by reference to Exhibit 2.5 of the registrants registration statement on
Form S-1 (File No. 333-144938)).2.3
    
    Asset Contribution Agreement By and Among NGP Co-Investment Opportunities Fund II, L.P.
and Eagle Rock Energy Partners, L.P., dated July 11, 2007 (incorporated by reference to
Exhibit 2.6 of the registrants registration statement on Form S-1 (File No. 333-144938)).2.4
    
    Purchase, Sale and Contribution Agreement Between AmGu
Holdings LLC, as seller, and Eagle
Rock Energy Partners, L.P., as purchaser, dated July 11, 2007 (incorporated by reference
to Exhibit 2.7 of the registrants registration statement on Form S-1 (File No.
333-144938)).4.1
    
    Registration Rights Agreement dated July 31, 2007, among Eagle Rock Energy Partners, L.P.
and the purchasers listed thereto (incorporated by reference to Exhibit 4.6 of the
registrants registration statement on Form S-1 (File No. 333-144938)).10.1
    
    Common Unit Purchase Agreement By and Among Eagle Rock Energy Partners, L.P. and The
Purchasers Named Therein, dated July 11, 2007 (incorporated by reference to Exhibit 10.15
of the registrants registration statement on Form S-1 (File No. 333-144938)).10.2
    
    Severance Agreement with former executive officer (incorporated by reference to Exhibit
10.16 of the registrants registration statement on Form S-1 (File No. 333-144938)).31.1
    
    Certification by Joseph A. Mills pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.31.2
    
    Certification by Richard W. FitzGerald 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 Richard W. FitzGerald pursuant to Section 906 of the Sarbanes-Oxley Act
of 2002 and 18 U.S.C. Section 1350.