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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549





Form 10-Q





(Mark One)

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

For the quarterly period ended September 30, 2009

OR



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

For the transition period from              to
            .

Commission File Number 001-33147





Constellation Energy Partners LLC

(Exact Name of Registrant as Specified in Its Charter)







|                        |  |                                     
|----------------------- |  | ------------------------------------
|Delaware                |  | 11-3742489                          
|(State of organization) |  | (I.R.S. Employer Identification No.)



|                                         |  |           
|---------------------------------------- |  | ----------
|1801 Main, Suite 1300 Houston, TX        |  | 77002     
|(Address of Principal Executive Offices) |  | (Zip Code)

Telephone Number: (832) 308-3700





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

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

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller
reporting company. See the definitions of large accelerated filer, accelerated filer and smaller reporting company in Rule 12b-2 of the Exchange Act.



|                        |  |                                                  |  |                           |  |  
|----------------------- |  | ------------------------------------------------ |  | ------------------------- |  | -
|Large accelerated filer |  |  ̈                                                |  | Accelerated filer         |  | x
|                        |  |                                                  | 
|Non-accelerated filer   |  |  ̈  (Do not check if a smaller reporting company) |  | Smaller reporting company |  |  ̈

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

Indicate the number of shares outstanding of each of the registrants classes of common stock, as of the latest practicable date.

Common Units outstanding on November 6, 2009: 22,265,648 units.









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##### Table of Contents

TABLE OF CONTENTS



|                             |  |                                                                                       |  |     
|---------------------------- |  | ------------------------------------------------------------------------------------- |  | ----
|                             |  |                                                                                       |  | Page
|                             | 
|PART IFinancial Information |  | 3                                                                                    
|Item 1.                      |  | Financial Statements                                                                  |  | 3   
|                             |  | Consolidated Statements of Operations and Comprehensive Income (Loss)                 |  | 3   
|                             |  | Consolidated Balance Sheets                                                           |  | 4   
|                             |  | Consolidated Statements of Cash Flows                                                 |  | 5   
|                             |  | Consolidated Statements of Changes in Members Equity                                 |  | 6   
|                             |  | Notes to Consolidated Financial Statements                                            |  | 7   
|Item 2.                      |  | Managements Discussion and Analysis of Financial Condition and Results of
Operations |  | 26  
|                             |  | Results of Operations                                                                 |  | 30  
|                             |  | Liquidity and Capital Resources                                                       |  | 35  
|Item 3.                      |  | Quantitative and Qualitative Disclosures About Market Risk                            |  | 44  
|Item 4.                      |  | Controls and Procedures                                                               |  | 46  
|                             | 
|PART IIOther Information    |  | 46                                                                                   
|Item 1.                      |  | Legal Proceedings                                                                     |  | 46  
|Item 1A.                     |  | Risk Factors                                                                          |  | 46  
|Item 2.                      |  | Unregistered Sales of Equity Securities and Use of Proceeds                           |  | 49  
|Item 3.                      |  | Defaults Upon Senior Securities                                                       |  | 49  
|Item 4.                      |  | Submission of Matters to a Vote of Security Holders                                   |  | 49  
|Item 5.                      |  | Other Information                                                                     |  | 49  
|Item 6.                      |  | Exhibits                                                                              |  | 49  
|Signature                    |  | 51                                                                                   



2



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PART IFINANCIAL INFORMATION



|Item 1. | Financial Statements
|------- | --------------------

CONSTELLATION ENERGY PARTNERS LLC and SUBSIDIARIES

Consolidated Statements of Operations and Comprehensive Income
(Loss)

(Unaudited)



|                                                          |  |                                 |            |   |                                |   |            |      |  |   |            |   |  |   |            |  
|--------------------------------------------------------- |  | ------------------------------- | ---------- | - | ------------------------------ | - | ---------- | ---- |  | - | ---------- | - |  | - | ---------- | -
|                                                          |  | Three Months EndedSeptember 30, |            |   | Nine Months EndedSeptember 30, |  
|                                                          |  | 2009                            |            |   | 2008                           |   |            | 2009 |  |   | 2008       |  
|                                                          |  | (In 000s except unit data)     |           
|Revenues                                                  |  |                                 |            |   |                                |   |            |      |  |   |            |   |  |   |            |  
|Oil and gas sales                                         |  | $                               | 30,663     |   |                                | $ | 37,674     |      |  | $ | 94,223     |   |  | $ | 108,093    |  
|Gain / (Loss) from mark-to-market activities (see Note 5) |  |                                 | (6,368     | ) |                                |   | 21,976     |      |  |   | 829        |   |  |   | 3,987      |  
|                                                          |  |                                 |            |   |                                |   |            |      |  |   |            |   |  |   |            |  
|Total revenues                                            |  |                                 | 24,295     |   |                                |   | 59,650     |      |  |   | 95,052     |   |  |   | 112,080    |  
|Expenses:                                                 |  |                                 |            |   |                                |   |            |      |  |   |            |   |  |   |            |  
|Operating expenses:                                       |  |                                 |            |   |                                |   |            |      |  |   |            |   |  |   |            |  
|Lease operating expenses                                  |  |                                 | 8,169      |   |                                |   | 9,428      |      |  |   | 25,243     |   |  |   | 27,701     |  
|Cost of sales                                             |  |                                 | 586        |   |                                |   | 2,633      |      |  |   | 2,030      |   |  |   | 6,020      |  
|Production taxes                                          |  |                                 | 715        |   |                                |   | 2,241      |      |  |   | 2,245      |   |  |   | 6,791      |  
|General and administrative                                |  |                                 | 4,844      |   |                                |   | 3,800      |      |  |   | 14,491     |   |  |   | 10,922     |  
|(Gain) / Loss on sale of asset                            |  |                                 |           |   |                                |   | (85        | )    |  |   | 14         |   |  |   | (296       | )
|Depreciation, depletion, and amortization                 |  |                                 | 15,455     |   |                                |   | 11,318     |      |  |   | 48,084     |   |  |   | 32,340     |  
|Accretion expense                                         |  |                                 | 109        |   |                                |   | 105        |      |  |   | 267        |   |  |   | 307        |  
|                                                          |  |                                 |            |   |                                |   |            |      |  |   |            |   |  |   |            |  
|Total operating expenses                                  |  |                                 | 29,878     |   |                                |   | 29,440     |      |  |   | 92,374     |   |  |   | 83,785     |  
|Other expenses (income)                                   |  |                                 |            |   |                                |   |            |      |  |   |            |   |  |   |            |  
|Interest expense                                          |  |                                 | 3,600      |   |                                |   | 3,280      |      |  |   | 9,721      |   |  |   | 8,942      |  
|Interest (income)                                         |  |                                 |           |   |                                |   | (62        | )    |  |   | (2         | ) |  |   | (346       | )
|Other expense (income)                                    |  |                                 | (82        | ) |                                |   | 53         |      |  |   | (129       | ) |  |   | 49         |  
|                                                          |  |                                 |            |   |                                |   |            |      |  |   |            |   |  |   |            |  
|Total other expenses                                      |  |                                 | 3,518      |   |                                |   | 3,271      |      |  |   | 9,590      |   |  |   | 8,645      |  
|                                                          |  |                                 |            |   |                                |   |            |      |  |   |            |   |  |   |            |  
|Total expenses                                            |  |                                 | 33,396     |   |                                |   | 32,711     |      |  |   | 101,964    |   |  |   | 92,430     |  
|                                                          |  |                                 |            |   |                                |   |            |      |  |   |            |   |  |   |            |  
|Net income (Loss)                                         |  | $                               | (9,101     | ) |                                | $ | 26,939     |      |  | $ | (6,912     | ) |  | $ | 19,650     |  
|Other comprehensive Income (Loss)                         |  |                                 | (9,698     | ) |                                |   | 145,935    |      |  |   | (13,339    | ) |  |   | 2,872      |  
|                                                          |  |                                 |            |   |                                |   |            |      |  |   |            |   |  |   |            |  
|Comprehensive Income (Loss)                               |  | $                               | (18,799    | ) |                                | $ | 172,874    |      |  | $ | (20,251    | ) |  | $ | 22,522     |  
|                                                          |  |                                 |            |   |                                |   |            |      |  |   |            |   |  |   |            |  
|Earnings per unit (see Note 1)                            |  |                                 |            |   |                                |   |            |      |  |   |            |   |  |   |            |  
|Earnings per unitBasic                                   |  | $                               | (0.40      | ) |                                | $ | 1.20       |      |  | $ | (0.31      | ) |  | $ | 0.88       |  
|Units outstandingBasic                                   |  |                                 | 22,665,098 |   |                                |   | 22,351,667 |      |  |   | 22,518,284 |   |  |   | 22,370,700 |  
|Earnings per unitDiluted                                 |  | $                               | (0.40      | ) |                                | $ | 1.20       |      |  | $ | (0.31      | ) |  | $ | 0.88       |  
|Units outstandingDiluted                                 |  |                                 | 22,665,098 |   |                                |   | 22,351,667 |      |  |   | 22,518,284 |   |  |   | 22,370,700 |  
|Distributions declared and paid per unit                  |  | $                               |           |   |                                | $ | 0.5625     |      |  | $ | 0.26       |   |  | $ | 1.6875     |  

See accompanying notes to consolidated financial statements.



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CONSTELLATION ENERGY PARTNERS LLC and SUBSIDIARIES

Consolidated Balance Sheets

(Unaudited)



|                                                                                                                                            |  |                    |          |   |                   |   |          |  
|------------------------------------------------------------------------------------------------------------------------------------------- |  | ------------------ | -------- | - | ----------------- | - | -------- | -
|                                                                                                                                            |  | September 30, 2009 |          |   | December 31, 2008 |  
|                                                                                                                                            |  | (In 000s)         |         
|ASSETS                                                                                                                                      |  |                    |          |   |                   |   |          |  
|                                                                                                                                            |  |                   
|Current assets                                                                                                                              |  |                    |          |   |                   |   |          |  
|Cash and cash equivalents                                                                                                                   |  | $                  | 30,787   |   |                   | $ | 6,255    |  
|Accounts receivable                                                                                                                         |  |                    | 5,565    |   |                   |   | 9,363    |  
|Prepaid expenses                                                                                                                            |  |                    | 934      |   |                   |   | 1,026    |  
|Risk management assets (see Note 5)                                                                                                         |  |                    | 27,171   |   |                   |   | 35,587   |  
|                                                                                                                                            |  |                    |          |   |                   |   |          |  
|Total current assets                                                                                                                        |  |                    | 64,457   |   |                   |   | 52,231   |  
|Oil and natural gas properties (See Note 7)                                                                                                 |  |                    |          |   |                   |   |          |  
|Natural gas properties, equipment and facilities                                                                                            |  |                    | 791,174  |   |                   |   | 769,103  |  
|Material and supplies                                                                                                                       |  |                    | 4,837    |   |                   |   | 4,587    |  
|Less accumulated depreciation, depletion and amortization                                                                                   |  |                    | (158,295 | ) |                   |   | (111,171 | )
|                                                                                                                                            |  |                    |          |   |                   |   |          |  
|Net oil and natural gas properties                                                                                                          |  |                    | 637,716  |   |                   |   | 662,519  |  
|Other assets                                                                                                                                |  |                    |          |   |                   |   |          |  
|Debt issue costs (net of accumulated amortization of $2,329 at September 30, 2009 and $1,495 at December 31,
2008)                          |  |                    | 1,227    |   |                   |   | 1,963    |  
|Risk management assets (see Note 5)                                                                                                         |  |                    | 25,570   |   |                   |   | 29,746   |  
|Other non-current assets                                                                                                                    |  |                    | 11,340   |   |                   |   | 12,390   |  
|                                                                                                                                            |  |                    |          |   |                   |   |          |  
|Total assets                                                                                                                                |  | $                  | 740,310  |   |                   | $ | 758,849  |  
|                                                                                                                                            |  |                    |          |   |                   |   |          |  
|                                                                                                                                            |  |                   
|LIABILITIES AND MEMBERS EQUITY                                                                                                             |  |                    |          |   |                   |   |          |  
|                                                                                                                                            |  |                   
|Liabilities                                                                                                                                 |  |                    |          |   |                   |   |          |  
|Current liabilities                                                                                                                         |  |                    |          |   |                   |   |          |  
|Accounts payable                                                                                                                            |  | $                  | 1,178    |   |                   | $ | 2,809    |  
|Payable to affiliate                                                                                                                        |  |                    | 253      |   |                   |   | 1,043    |  
|Accrued liabilities                                                                                                                         |  |                    | 11,411   |   |                   |   | 10,088   |  
|Environmental liabilities                                                                                                                   |  |                    | 310      |   |                   |   | 441      |  
|Royalty payable                                                                                                                             |  |                    | 3,575    |   |                   |   | 5,125    |  
|Risk management liabilities (see note 5)                                                                                                    |  |                    | 301      |   |                   |   |         |  
|                                                                                                                                            |  |                    |          |   |                   |   |          |  
|Total current liabilities                                                                                                                   |  |                    | 17,028   |   |                   |   | 19,506   |  
|Other liabilities                                                                                                                           |  |                    |          |   |                   |   |          |  
|Asset retirement obligation                                                                                                                 |  |                    | 7,137    |   |                   |   | 6,754    |  
|Risk management liabilities (see note 5)                                                                                                    |  |                    | 1,919    |   |                   |   |         |  
|Debt                                                                                                                                        |  |                    | 220,000  |   |                   |   | 212,500  |  
|                                                                                                                                            |  |                    |          |   |                   |   |          |  
|Total other liabilities                                                                                                                     |  |                    | 229,056  |   |                   |   | 219,254  |  
|                                                                                                                                            |  |                    |          |   |                   |   |          |  
|Total liabilities                                                                                                                           |  |                    | 246,084  |   |                   |   | 238,760  |  
|                                                                                                                                            |  |                   
|Commitments and contingencies (See Note 9)                                                                                                  |  |                    |          |   |                   |   |          |  
|                                                                                                                                            |  |                   
|Class D Interests                                                                                                                           |  |                    | 6,667    |   |                   |   | 6,667    |  
|                                                                                                                                            |  |                   
|Members equity                                                                                                                             |  |                    |          |   |                   |   |          |  
|Class A units, 454,401 and 447,721 shares authorized, issued and outstanding, respectively                                                  |  |                    | 9,016    |   |                   |   | 9,266    |  
|Class B units, 22,648,763 and 22,348,763 shares authorized, respectively, and22,265,648 and 21,938,342 issued and
outstanding, respectively |  |                    | 441,755  |   |                   |   | 454,029  |  
|Accumulated other comprehensive income                                                                                                      |  |                    | 36,788   |   |                   |   | 50,127   |  
|                                                                                                                                            |  |                    |          |   |                   |   |          |  
|Total members equity                                                                                                                       |  |                    | 487,559  |   |                   |   | 513,422  |  
|                                                                                                                                            |  |                    |          |   |                   |   |          |  
|Total liabilities and members equity                                                                                                       |  | $                  | 740,310  |   |                   | $ | 758,849  |  
|                                                                                                                                            |  |                    |          |   |                   |   |          |  

See accompanying notes to consolidated financial statements.



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CONSTELLATION ENERGY PARTNERS LLC and SUBSIDIARIES

Consolidated Statements of Cash Flows

(Unaudited)



|                                                                                      |  |                                |         |   |      |   |          |  
|------------------------------------------------------------------------------------- |  | ------------------------------ | ------- | - | ---- | - | -------- | -
|                                                                                      |  | Nine months endedSeptember 30, |        
|                                                                                      |  | 2009                           |         |   | 2008 |  
|                                                                                      |  | (In 000s)                     |        
|Cash flows from operating activities:                                                 |  |                                |         |   |      |   |          |  
|Net income (Loss)                                                                     |  | $                              | (6,912  | ) |      | $ | 19,650   |  
|Adjustments to reconcile net income (loss) to cash provided by operating activities:  |  |                                |         |   |      |   |          |  
|Depreciation, depletion and amortization                                              |  |                                | 48,084  |   |      |   | 32,340   |  
|Amortization of debt issuance costs                                                   |  |                                | 834     |   |      |   | 779      |  
|Accretion of plugging and abandonment liability                                       |  |                                | 267     |   |      |   | 307      |  
|Equity earnings (losses) in affiliate                                                 |  |                                | (129    | ) |      |   | 49       |  
|(Gain) Loss from disposition of property and equipment                                |  |                                | 14      |   |      |   | (296     | )
|Dryhole Costs                                                                         |  |                                | 173     |   |      |   |         |  
|Hedge ineffectiveness                                                                 |  |                                | 267     |   |      |   | (27      | )
|(Gain) Loss from mark-to-market activities on commodity and interest rate derivatives |  |                                | 787     |   |      |   | (3,987   | )
|Unit-based compensation programs                                                      |  |                                | 288     |   |      |   | 273      |  
|Changes in Assets and Liabilities:                                                    |  |                                |         |   |      |   |          |  
|Change in net risk management assets and liabilities                                  |  |                                | 419     |   |      |   | (554     | )
|(Increase) decrease in accounts receivable                                            |  |                                | 3,798   |   |      |   | 5,175    |  
|(Increase) decrease in prepaid expenses                                               |  |                                | 92      |   |      |   | 987      |  
|(Increase) decrease in other assets                                                   |  |                                | 4       |   |      |   | 255      |  
|Increase (decrease) in accounts payable                                               |  |                                | (1,631  | ) |      |   | 1,509    |  
|Increase (decrease) in payable to affiliate                                           |  |                                | (790    | ) |      |   | (1,898   | )
|Increase (decrease) in accrued liabilities                                            |  |                                | 1,594   |   |      |   | (1,442   | )
|Increase (decrease) in royalty payable                                                |  |                                | (1,550  | ) |      |   | 2,879    |  
|                                                                                      |  |                                |         |   |      |   |          |  
|Net cash provided by operating activities                                             |  |                                | 45,609  |   |      |   | 55,999   |  
|                                                                                      |  |                                |         |   |      |   |          |  
|                                                                                      |  |                               
|Cash flows from investing activities:                                                 |  |                                |         |   |      |   |          |  
|Cash paid for acquisitions, net of cash required                                      |  |                                | (170    | ) |      |   | (48,764  | )
|Development of natural gas properties                                                 |  |                                | (22,786 | ) |      |   | (32,330  | )
|Proceeds from sale of equipment                                                       |  |                                | 17      |   |      |   | 594      |  
|Distributions from equity affiliate                                                   |  |                                | 360     |   |      |   | 273      |  
|                                                                                      |  |                                |         |   |      |   |          |  
|Net cash used in investing activities                                                 |  |                                | (22,579 | ) |      |   | (80,227  | )
|                                                                                      |  |                                |         |   |      |   |          |  
|                                                                                      |  |                               
|Cash flows from financing activities:                                                 |  |                                |         |   |      |   |          |  
|Members distributions                                                                |  |                                | (5,820  | ) |      |   | (38,064  | )
|Proceeds from issuance of debt                                                        |  |                                | 34,500  |   |      |   | 226,000  |  
|Repayment of debt                                                                     |  |                                | (27,000 | ) |      |   | (163,000 | )
|Equity issuance costs and costs for shelf registration statement                      |  |                                | (80     | ) |      |   | (340     | )
|Debt issue costs                                                                      |  |                                | (98     | ) |      |   | (1,503   | )
|                                                                                      |  |                                |         |   |      |   |          |  
|Net cash provided by financing activities                                             |  |                                | 1,502   |   |      |   | 23,093   |  
|                                                                                      |  |                                |         |   |      |   |          |  
|Net (decrease) increase in cash                                                       |  |                                | 24,532  |   |      |   | (1,135   | )
|Cash and cash equivalents, beginning of period                                        |  |                                | 6,255   |   |      |   | 18,689   |  
|                                                                                      |  |                                |         |   |      |   |          |  
|Cash and cash equivalents, end of period                                              |  | $                              | 30,787  |   |      | $ | 17,554   |  
|                                                                                      |  |                                |         |   |      |   |          |  
|                                                                                      |  |                               
|Supplemental disclosures of cash flow information:                                    |  |                                |         |   |      |   |          |  
|Increase / (decrease) in accrued capital expenditures                                 |  | $                              | (396    | ) |      | $ | 843      |  
|Cash received during the period for interest                                          |  | $                              | 2       |   |      | $ | 368      |  
|Cash paid during the period for interest                                              |  | $                              | (5,265  | ) |      | $ | (8,054   | )

See accompanying notes to consolidated financial statements.



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CONSTELLATION ENERGY PARTNERS LLC and SUBSIDIARIES

Consolidated Statements of Changes in Members Equity

(Unaudited)



|                                                      |  |                                  |  |        |         |   |       |                                            |        |   |                     |   |  |   |         |   |  |   |         |  
|----------------------------------------------------- |  | -------------------------------- |  | ------ | ------- | - | ----- | ------------------------------------------ | ------ | - | ------------------- | - |  | - | ------- | - |  | - | ------- | -
|                                                      |  | Class A                          |  |        | Class B |   |       | AccumulatedOtherComprehensiveIncome (Loss) |        |   | TotalMembersEquity |  
|                                                      |  | Units                            |  | Amount |         |   | Units |                                            | Amount |   |                     |  
|                                                      |  | ( In 000s, except unit amounts) | 
|Balance, December 31, 2008                            |  | 447,721                          |  | $      | 9,266   |   |       | 21,938,342                                 |        | $ | 454,029             |   |  | $ | 50,127  |   |  | $ | 513,422 |  
|Distributions                                         |  |                                 |  |        | (116    | ) |       |                                           |        |   | (5,704              | ) |  |   |        |   |  |   | (5,820  | )
|Equity Issuance Cost                                  |  |                                 |  |        | (2      | ) |       |                                           |        |   | (78                 | ) |  |   |        |   |  |   | (80     | )
|Change in fair value of commodity and interest hedges |  |                                 |  |        |        |   |       |                                           |        |   |                    |   |  |   | 20,358  |   |  |   | 20,358  |  
|Cash settlement of commodity hedges                   |  |                                 |  |        |        |   |       |                                           |        |   |                    |   |  |   | (36,810 | ) |  |   | (36,810 | )
|Cash settlement of interest rate hedges               |  |                                 |  |        |        |   |       |                                           |        |   |                    |   |  |   | 3,113   |   |  |   | 3,113   |  
|Unit-based compensation programs                      |  | 6,680                            |  |        | 6       |   |       | 327,306                                    |        |   | 282                 |   |  |   |        |   |  |   | 288     |  
|Net income                                            |  |                                 |  |        | (139    | ) |       |                                           |        |   | (6,773              | ) |  |   |        |   |  |   | (6,912  | )
|                                                      |  |                                  |  |        |         |   |       |                                            |        |   |                     |   |  |   |         |   |  |   |         |  
|Balance, September 30, 2009                           |  | 454,401                          |  | $      | 9,015   |   |       | 22,265,648                                 |        | $ | 441,756             |   |  | $ | 36,788  |   |  | $ | 487,559 |  
|                                                      |  |                                  |  |        |         |   |       |                                            |        |   |                     |   |  |   |         |   |  |   |         |  

See accompanying notes to consolidated financial statements.



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CONSTELLATION ENERGY PARTNERS LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

1. ORGANIZATION AND BASIS OF PRESENTATION

The consolidated financial statements as of, and for the period ended September 30, 2009, are unaudited, but in the opinion of
management include all adjustments (consisting only of normal recurring adjustments) necessary for a fair presentation of the results for the interim periods. Certain information and note disclosures normally included in annual financial statements
prepared in accordance with U.S. generally accepted accounting principles (GAAP) have been condensed or omitted under Securities and Exchange Commission (SEC) rules and regulations. The results reported in these unaudited
consolidated financial statements should not necessarily be taken as indicative of results that may be expected for the entire year.

The financial information included herein should be read in conjunction with the financial statements and notes in the Companys Annual Report on Form 10-K for the year ended December 31, 2008.

CBM Equity IV Holdings, LLC was organized as a limited liability company on February 7, 2005, under the laws of the State of Delaware
and had no principal operations prior to the acquisition of our properties in the Black Warrior Basin on June 13, 2005. On May 10, 2006, CBM Equity IV Holdings, LLC changed its name to Constellation Energy Resources LLC. On July 18,
2006, Constellation Energy Resources LLC changed its name to Constellation Energy Partners LLC (CEP or the Company). CEP completed its initial public offering on November 20, 2006, and is traded on the NYSE Arca under
the symbol CEP. CEP is partially-owned by Constellation Energy Commodities Group, Inc. (CCG), which is owned by Constellation Energy Group, Inc. (NYSE: CEG) (Constellation or CEG). As of
September 30, 2009, affiliates of Constellation own all of the Companys Class A units, all of the management incentive interests, approximately 27% of the Companys common units and all of the Companys Class D interests.

The Company is currently focused on the development and acquisition of natural gas properties in the Black Warrior Basin in
Alabama, the Cherokee Basin in Kansas and Oklahoma, and the Woodford Shale in Oklahoma (collectively the Oil and Gas Properties). CEP acquired its interests in the Black Warrior Basin in 2005, its interests in the Cherokee Basin in 2007
and its interests in the Woodford Shale in 2008.

Accounting policies used by CEP conform to accounting principles generally
accepted in the United States of America. The accompanying financial statements include the accounts of CEP and its wholly-owned subsidiaries (collectively, the Entities). All significant intercompany accounts and transactions have been
eliminated in consolidation. CEP operates its oil and natural gas properties as one business segment: the exploration, development and production of natural gas. Management of CEP evaluates performance based on one business segment as there are not
different economic environments within the operation of the oil and natural gas properties. Certain reclassifications have been made to prior years reported amounts in order to conform with the current year presentation. These
reclassifications did not impact net income, members equity or cash flows.

2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

The Companys significant accounting policies are consistent with those discussed in its Annual Report on Form 10-K
for the year ended December 31, 2008.

Earnings per Unit

Basic earnings per unit (EPS) are computed by dividing net earnings attributable to unitholders by the weighted average number of
units outstanding during each period. At September 30, 2009, we had 454,401 Class A units and 22,265,648 Class B units outstanding. Of the Class B units, 345,158 units are unvested restricted common units granted and outstanding.



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The following table presents earnings per common unit amounts:



|                                                                                                                                                                                                                                                                                                                                                                                                                                                                                    |  |                             |        |   |       |            |                |   |       |  
|----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------- |  | --------------------------- | ------ | - | ----- | ---------- | -------------- | - | ----- | -
|                                                                                                                                                                                                                                                                                                                                                                                                                                                                                    |  | Income                      |        |   | Units |            | Per UnitAmount |  
|                                                                                                                                                                                                                                                                                                                                                                                                                                                                                    |  | (In 000s except unit data) |       
|For the three months ended September 30, 2009                                                                                                                                                                                                                                                                                                                                                                                                                                       |  |                             |        |   |       |            |                |  
|Basic EPS:                                                                                                                                                                                                                                                                                                                                                                                                                                                                          |  |                             |        |   |       |            |                |   |       |  
|Income allocable to unitholders                                                                                                                                                                                                                                                                                                                                                                                                                                                     |  | $                           | (9,101 | ) |       | 22,265,098 |                | $ | (0.40 | )
|Effect of dilutive securities:                                                                                                                                                                                                                                                                                                                                                                                                                                                      |  |                             |        |   |       |            |                |   |       |  
|Notional common units that earn distributions (a)                                                                                                                                                                                                                                                                                                                                                                                                                                   |  |                             |       |   |       |           |                |   |      |  
|                                                                                                                                                                                                                                                                                                                                                                                                                                                                                    |  |                             |        |   |       |            |                |   |       |  
|Diluted EPS:                                                                                                                                                                                                                                                                                                                                                                                                                                                                        |  |                             |        |   |       |            |                |   |       |  
|Income allocable to common unitholders                                                                                                                                                                                                                                                                                                                                                                                                                                              |  | $                           | (9,101 | ) |       | 22,265,098 |                | $ | (0.40 | )
|                                                                                                                                                                                                                                                                                                                                                                                                                                                                                    |  |                             |       
|                                                                                                                                                                                                                                                                                                                                                                                                                                                                                    |  | Income                      |        |   | Units |            | Per UnitAmount |  
|                                                                                                                                                                                                                                                                                                                                                                                                                                                                                    |  | (In 000s except unit data) |       
|For the nine months ended September 30, 2009                                                                                                                                                                                                                                                                                                                                                                                                                                        |  |                             |        |   |       |            |                |  
|Basic EPS:                                                                                                                                                                                                                                                                                                                                                                                                                                                                          |  |                             |        |   |       |            |                |   |       |  
|Income allocable to unitholders                                                                                                                                                                                                                                                                                                                                                                                                                                                     |  | $                           | (6,912 | ) |       | 22,518,284 |                | $ | (0.31 | )
|Effect of dilutive securities:                                                                                                                                                                                                                                                                                                                                                                                                                                                      |  |                             |        |   |       |            |                |   |       |  
|Notional common units that earn distributions(a)                                                                                                                                                                                                                                                                                                                                                                                                                                    |  |                             |       |   |       |           |                |   |      |  
|                                                                                                                                                                                                                                                                                                                                                                                                                                                                                    |  |                             |        |   |       |            |                |   |       |  
|Diluted EPS:                                                                                                                                                                                                                                                                                                                                                                                                                                                                        |  |                             |        |   |       |            |                |   |       |  
|Income allocable to common unitholders                                                                                                                                                                                                                                                                                                                                                                                                                                              |  | $                           | (6,912 | ) |       | 22,518,284 |                | $ | (0.31 | )
|(a)    We have also issued 1,040,278 notional units that earn distributions under certain circumstances. These notional units will convert into restricted common units upon approval by
our unitholders. Had these units been included in our diluted EPS calculations for the three months and nine months ended September 30, 2009, our total diluted units would not have been different and our EPS would have not been impacted since
we reported a net loss for the periods. | 
|                                                                                                                                                                                                                                                                                                                                                                                                                                                                                    |  |                             |       
|                                                                                                                                                                                                                                                                                                                                                                                                                                                                                    |  | Income                      |        |   | Units |            | Per UnitAmount |  
|                                                                                                                                                                                                                                                                                                                                                                                                                                                                                    |  | (In 000s except unit data) |       
|For the three months ended September 30, 2008                                                                                                                                                                                                                                                                                                                                                                                                                                       |  |                             |        |   |       |            |                |  
|Basic EPS:                                                                                                                                                                                                                                                                                                                                                                                                                                                                          |  |                             |        |   |       |            |                |   |       |  
|Income allocable to unitholders                                                                                                                                                                                                                                                                                                                                                                                                                                                     |  | $                           | 26,939 |   |       | 22,351,667 |                | $ | 1.20  |  
|Effect of dilutive securities:                                                                                                                                                                                                                                                                                                                                                                                                                                                      |  |                             |        |   |       |            |                |   |       |  
|Restricted common unitsTreasury stock method                                                                                                                                                                                                                                                                                                                                                                                                                                       |  |                             |       |   |       |           |                |   |      |  
|                                                                                                                                                                                                                                                                                                                                                                                                                                                                                    |  |                             |        |   |       |            |                |   |       |  
|Diluted EPS:                                                                                                                                                                                                                                                                                                                                                                                                                                                                        |  |                             |        |   |       |            |                |   |       |  
|Income allocable to common unitholders                                                                                                                                                                                                                                                                                                                                                                                                                                              |  | $                           | 26,939 |   |       | 22,351,667 |                | $ | 1.20  |  
|                                                                                                                                                                                                                                                                                                                                                                                                                                                                                    |  |                             |       
|                                                                                                                                                                                                                                                                                                                                                                                                                                                                                    |  | Income                      |        |   | Units |            | Per UnitAmount |  
|                                                                                                                                                                                                                                                                                                                                                                                                                                                                                    |  | (In 000s except unit data) |       
|For the nine months ended September 30, 2008                                                                                                                                                                                                                                                                                                                                                                                                                                        |  |                             |        |   |       |            |                |  
|Basic EPS:                                                                                                                                                                                                                                                                                                                                                                                                                                                                          |  |                             |        |   |       |            |                |   |       |  
|Income allocable to unitholders                                                                                                                                                                                                                                                                                                                                                                                                                                                     |  | $                           | 19,650 |   |       | 22,370,700 |                | $ | 0.88  |  
|Effect of dilutive securities:                                                                                                                                                                                                                                                                                                                                                                                                                                                      |  |                             |        |   |       |            |                |   |       |  
|Restricted common unitsTreasury stock method                                                                                                                                                                                                                                                                                                                                                                                                                                       |  |                             |       |   |       |           |                |   |      |  
|                                                                                                                                                                                                                                                                                                                                                                                                                                                                                    |  |                             |        |   |       |            |                |   |       |  
|Diluted EPS:                                                                                                                                                                                                                                                                                                                                                                                                                                                                        |  |                             |        |   |       |            |                |   |       |  
|Income allocable to common unitholders                                                                                                                                                                                                                                                                                                                                                                                                                                              |  | $                           | 19,650 |   |       | 22,370,700 |                | $ | 0.88  |  



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3. NEW ACCOUNTING PRONOUNCEMENTS

In June 2009, the Financial Accounting Standards Board (FASB) released the final version of its new Accounting Standards
Codification (the Codification) as the single authoritative source for U.S. GAAP. The Codification replaces all previous U.S. GAAP accounting standards as described in SFAS 168, The FASB Accounting Standards Codification and the
Hierarchy of Generally Accepted Accounting Principles. While not intended to change U.S. GAAP, the Codification significantly changes the way in which the accounting literature is organized. It is structured by accounting topic to help
accountants and auditors more quickly identify the guidance that applies to a specific accounting issue. However, because the Codification completely replaces existing standards, it will affect the way U.S. GAAP is referenced by companies in their
financial statements and accounting policies. The Codification is effective for financial statements that cover interim and annual periods ending after September 15, 2009. The adoption of the Codification did not have a material impact on our
financial statements.

In May 2009, the FASB established general standards of accounting for and the disclosures of events
that occur after the balance sheet date but before financial statements are issued or are available to be issued. Although there is new terminology, the standard is based on the same principles as those that currently exist in the auditing
standards. The standard, which includes a new required disclosure of the date through which an entity has evaluated subsequent events, is effective for interim or annual periods ending after June 15, 2009. CEP performs an evaluation of
subsequent events until the issuance date of its document with the SEC so the adoption of the new requirements had no impact on our financial statements. See Note 16 for additional information.

In June 2008, the FASB addressed whether instruments granted in unit-based payment transactions are participating securities prior to
vesting and, therefore, need to be included in the earnings allocation in computing earnings per unit under the two-class method. This affects entities that accrue or pay nonforfeitable cash distributions on unit-based payment awards during
the awards service period. Effective for fiscal years beginning after December 15, 2008, and interim periods within those fiscal years, a retrospective adjustment to all prior period earnings per unit calculations was required. CEP
adopted the guidance on January 1, 2009, and began including all unvested LTIP restricted common units that earn distributions in earnings per unit calculations for all periods presented. The adoption of this guidance did not have a material
impact on our earnings per unit calculations.

In March 2008, the Emerging Issues Task Force reached a consensus on how
current period earnings should be allocated between limited partners and a general partner when the partnership agreement contains incentive distribution rights. Beginning after December 15, 2008, and interim periods within those fiscal years,
this guidance is to be applied retrospectively for all financial statements presented. Earlier application is not permitted. The adoption of this guidance did not have a material impact on our financial statements.

In March 2008, the FASB issued guidance that was effective beginning January 1, 2009 and required entities to provide expanded
disclosures about derivative instruments and hedging activities including (1) the ways in which an entity uses derivatives, (2) the accounting for derivatives and hedging activities, and (3) the impact that derivatives have (or could
have) on an entitys financial position, financial performance, and cash flows. This guidance only required expanded disclosures and did not change the accounting for derivatives. The adoption of this guidance did not have a material impact on
our financial statements. See Note 5 for additional information.

New Accounting Pronouncements Issued But Not Yet Adopted

As of September 30, 2009, there were a number of accounting standards and interpretations that had been issued, but not yet adopted
by us.

In December 2008, the SEC issued the final rule, Modernization of Oil and Gas Reporting (Final
Rule). The Final Rule adopts revisions to the SECs oil and gas reporting disclosure requirements and is effective for annual reports on Forms 10-K for years ending on or after December 31, 2009. The revisions are intended to provide
investors with a more meaningful and comprehensive understanding of oil and gas reserves to help investors evaluate their investments in oil and gas companies. The amendments are also designed to modernize the oil and gas disclosure requirements to
align them with current practices and technological advances. Revised requirements in the Final Rule include, but are not limited to:



| |  |  | Oil and gas reserves must be reported using a 12-month average of the closing prices on the first day of each of such months, rather than a single day
year-end price;
| | - |  | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  |  | Companies will be allowed to report, on a voluntary basis, probable and possible reserves, previously prohibited by SEC rules; and
| | - |  | ----------------------------------------------------------------------------------------------------------------------------------



| |  |  | Easing the standard for the inclusion of proved undeveloped reserves (PUDs) and requiring disclosure of information indicating any progress
toward the development of PUDs.
| | - |  | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------



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We are currently evaluating the potential impact of adopting the Final Rule. The SEC is
discussing the Final Rule with the FASB and IASB staffs to align accounting standards with the Final Rule. These discussions may delay the required compliance date. Absent any change in such date, we will begin complying with the disclosure
requirements in our annual report on Form 10-K for the year ended December 31, 2009. Voluntary early compliance is not permitted.

In September 2009, the FASB issued its proposed updates to oil and gas accounting rules to align the oil and gas reserve estimation and disclosure requirements of Extractive IndustriesOil and Gas (Topic 932) with the requirements in
the SECs final rule, Modernization of the Oil and Gas Reporting Requirements,which was issued on December 31, 2008 and is effective for the year ended December 31, 2009. The public comment period for the FASBs proposed
updates ended October 15, 2009; however, no final guidance has been issued by the FASB. We are evaluating the potential impact of any updates to the oil and gas accounting rules and will comply with any new accounting and disclosure
requirements once they become effective.

4. ACQUISITIONS

CoLa Acquisition

On March 31, 2008, the Company acquired 83
non-operated producing natural gas wells in the Woodford Shale in the Arkoma Basin in Oklahoma from CoLa Resources LLC (CoLa) for $50.2 million, including purchase price adjustments (CoLa Acquisition). CoLa is an affiliate of
CEG, the Companys sponsor. The transaction was reviewed and approved by the Companys conflicts committee. In its review, the Companys conflicts committee considered various economic factors (including historical and estimated
future production, estimated proved reserves, future pricing estimates and operating cost estimates) regarding the transaction, and determined that the acquisition was fair to and in the best interests of the Company. The 83 wells, located in Coal
and Hughes Counties, Oklahoma, have an average gross working interest per well of 11.4% and an average net revenue interest per well of 9.2%. The acquired natural gas reserves associated with the wells are 100% proved developed producing. Our
results of operations include the results of the CoLa wells after the date of acquisition.

To fund the purchase of CoLa, the
Company borrowed $53.0 million under its reserve-based credit facilities (see Note 6).

Upon the announcement of the
acquisition, the Company entered into derivative transactions to hedge a portion of the future expected production associated with these wells (see Note 5).

The total consideration paid was $50.1 million, which consisted of $50.2 million in cash and transaction costs and assumed liabilities of approximately $0.1 million, primarily associated with asset
retirement obligations on the properties. The following table summarizes the allocation of the purchase price to the assets acquired and liabilities assumed at the date of acquisition.





|                               |  |               |      |  
|------------------------------ |  | ------------- | ---- | -
|Acquired March 31, 2008        |  | (in millions) |     
|Oil and Natural Gas Properties |  | $             | 50.2 |  
|                               |  |               |      |  
|Total assets acquired          |  |               | 50.2 |  
|Asset retirement obligations   |  |               | (0.1 | )
|                               |  |               |      |  
|Net assets acquired            |  | $             | 50.1 |  
|                               |  |               |      |  

The purchase price allocation is based on evaluations of estimated proved oil and
natural gas reserves, discounted cash flows, quoted market prices, and other estimates by management.

In July 2009, the
Company received approximately $0.2 million from Cola for post-closing and title adjustments related to the CoLa acquisition. Under the purchase agreement, the Company had the right to assert, and CoLa had the right to attempt to cure, any title
defects to the acquired wells until July 31, 2009. CoLas post-closing payment obligations with respect to title defects and indemnities under the purchase agreement was secured, in part, by a guaranty from CCG delivered at closing. The
maximum amount of the CCG guaranty was limited to (i) 20% of the purchase price, with respect to indemnity obligations, and (ii) with respect to title defect obligations, the amount of such title defects, such amount to be calculated as
provided in the purchase agreement. The amount of CCGs guaranty with respect to title defect obligations has decreased as title curative were received and as CoLa received proceeds of production from the wells as to which payments of
production proceeds had not commenced as of the closing date and which were attributable to periods prior to the effective time of the purchase agreement. No further title adjustments are expected and a guarantee no longer exists with respect to
title defect obligations.

Pro Forma Results

The unaudited pro forma results presented below have been prepared to give effect to the CoLa Acquisition described above on our results of operations as if it had been consummated at the beginning of the
period presented. The unaudited pro forma results do



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not purport to represent what our results of operations actually would have been if this acquisition had been completed on such date or to project our results of operations for any future date or
period.



|                                  |  |                                     |        |                                    |   |        
|--------------------------------- |  | ----------------------------------- | ------ | ---------------------------------- | - | -------
|                                  |  | Three MonthsEnded September 30,2008 |        | Nine MonthsEnded September 30,2008
|                                  |  | (Unaudited)                        
|                                  |  | (In 000s, except per share data)  
|Pro forma financial results:      |  |                                     |        |                                    |   |        
|Revenue                           |  | $                                   | 59,650 |                                    | $ | 115,414
|Income (loss) from operations     |  |                                     | 30,210 |                                    |   | 29,263 
|Net income (loss)                 |  |                                     | 26,939 |                                    |   | 19,856 
|Basic earnings (loss) per share   |  | $                                   | 1.21   |                                    | $ | 0.89   
|Diluted earnings (loss) per share |  | $                                   | 1.21   |                                    | $ | 0.89   

5. DERIVATIVE AND FINANCIAL INSTRUMENTS

Mark-to-Market Activities

The Company has hedged a portion of its expected natural gas sales from currently producing wells through December 2014. All of the Companys swaps, basis swaps and options were accounted for as mark-to-market activities as of
September 30, 2009.

At September 30, 2009, and December 31 2008, the Company had debt outstanding of $220.0
million and $216.0 million, respectively, under its reserve-based credit facilities. The Company has entered into hedging arrangements in the form of interest rate swaps to reduce the impact of volatility stemming from changes in the London
interbank offered rate (LIBOR) on $168.0 million of the outstanding debt through October 2010. All of the Companys interest rate swaps are accounted for as mark-to-market activities as of September 30, 2009. See Note 16 for
additional information.

For the nine months ended September 30, 2009 and 2008, the Company recognized mark-to-market
gains of approximately $0.8 million and $4.0 million, respectively, in connection with its commodity derivatives. For the nine months ended September 30, 2009 and 2008, the Company recognized mark-to-market losses of approximately $1.6 million
and no gains or losses, respectively, in connection with its interest rate derivatives. At September 30, 2009 and December 31, 2008, the fair value of the derivatives accounted for as mark-to-market activities amounted to a net asset of
approximately $50.5 million and a net asset of approximately $20.9 million, respectively.

Accumulated Other Comprehensive Income

Prior to the first quarter of 2009, the Company accounted for certain of its commodity and interest rate derivatives
as hedging activities. The value of the cash flow hedges included in Accumulated other comprehensive income (loss) on the Consolidated Balance Sheets was an unrecognized gain of approximately $36.8 million and an unrecognized gain of $50.1
million at September 30, 2009 and December 31, 2008, respectively. The Company expects that the unrecognized gain will be reclassified from Accumulated other comprehensive income (loss) to the income statement in the following periods:



|                      |  |                      |        |                          |   |        |                     |  |   |            |   |  |   |       
|--------------------- |  | -------------------- | ------ | ------------------------ | - | ------ | ------------------- |  | - | ---------- | - |  | - | ------
|For the Quarter Ended |  | CommodityDerivatives |        | Interest RateDerivatives |   |        | Non-performanceRisk |  |   | Total AOCI
|                      |  |                      |        | ( In 000s)              |   |        |                     |  |   |           
|December 31, 2009     |  |                      | 9,922  |                          |   | (1,222 | )                   |  |   | (93        | ) |  |   | 8,607 
|March 31, 2010        |  |                      | 5,728  |                          |   | (1,149 | )                   |  |   | (52        | ) |  |   | 4,527 
|June 30, 2010         |  |                      | 4,319  |                          |   | (964   | )                   |  |   | (51        | ) |  |   | 3,304 
|September 30, 2010    |  |                      | 3,726  |                          |   | (892   | )                   |  |   | (54        | ) |  |   | 2,780 
|December 31, 2010     |  |                      | 3,568  |                          |   | (326   | )                   |  |   | (62        | ) |  |   | 3,180 
|March 31, 2011        |  |                      | 1,154  |                          |   |       |                     |  |   | (33        | ) |  |   | 1,121 
|June 30, 2011         |  |                      | 2,791  |                          |   |       |                     |  |   | (93        | ) |  |   | 2,698 
|September 30, 2011    |  |                      | 2,494  |                          |   |       |                     |  |   | (93        | ) |  |   | 2,401 
|December 31, 2011     |  |                      | 1,874  |                          |   |       |                     |  |   | (77        | ) |  |   | 1,797 
|March 31, 2012        |  |                      | 845    |                          |   |       |                     |  |   | (26        | ) |  |   | 819   
|June 30, 2012         |  |                      | 2,257  |                          |   |       |                     |  |   | (77        | ) |  |   | 2,180 
|September 30, 2012    |  |                      | 2,016  |                          |   |       |                     |  |   | (74        | ) |  |   | 1,942 
|December 31, 2012     |  |                      | 1,491  |                          |   |       |                     |  |   | (59        | ) |  |   | 1,432 
|                      |  |                      |        |                          |   |        |                     |  |   |            |   |  |   |       
|Total                 |  | $                    | 42,185 |                          | $ | (4,553 | )                   |  | $ | (844       | ) |  | $ | 36,788
|                      |  |                      |        |                          |   |        |                     |  |   |            |   |  |   |       



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Fair Value Measurements

We measure fair value of our financial and non-financial assets and liabilities on a recurring basis. Accounting standards define fair value,
establish a framework for measuring fair value and require certain disclosures about fair value measurements for assets and liabilities measured on a recurring basis. All of CEPs derivative instruments are recorded at fair value in our
financial statements. Fair value is the exit price that we would receive to sell an asset or pay to transfer a liability in an orderly transaction between market participants at the measurement date.

This following hierarchy prioritizes the inputs used to measure fair value. The three levels of the fair value hierarchy are as follows:



| |  |  | Level 1  Quoted prices available in active markets for identical assets or liabilities as of the reporting date.
| | - |  | -----------------------------------------------------------------------------------------------------------------



| |  |  | Level 2  Pricing inputs other than quoted prices in active markets included in Level 1 which are either directly or indirectly observable as of
the reporting date. Level 2 consists primarily of non-exchange traded commodity derivatives.
| | - |  | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  |  | Level 3  Pricing inputs include significant inputs that are generally less observable from objective sources.
| | - |  | --------------------------------------------------------------------------------------------------------------

We classify assets and liabilities within the fair value hierarchy based on the lowest level of input that is significant to the fair value
measurement of each individual asset and liability taken as a whole. Certain of our derivatives are classified as Level 3 because observable market data is not available for all of the time periods for which we have derivative instruments. As
observable market data becomes available for all of the time periods, these derivative positions will be reclassified as Level 2. The income valuation approach, which involves discounting estimated cash flows, is primarily used to determine
recurring fair value measurements of our derivative instruments classified as Level 2 or Level 3. We prioritize the use of the highest level inputs available in determining fair value.

The Companys assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the
classification of assets and liabilities within the fair value hierarchy. Because of the long-term nature of certain assets and liabilities measured at fair value as well as differences in the availability of market prices and market liquidity over
their terms, inputs for some assets and liabilities may fall into any one of the three levels in the fair value hierarchy. While we are required to classify these assets and liabilities in the lowest level in the hierarchy for which inputs are
significant to the fair value measurement, a portion of that measurement may be determined using inputs from a higher level in the hierarchy.

The following tables sets forth by level within the fair value hierarchy the Companys assets and liabilities that were measured at fair value on a recurring basis as of September 30, 2009, and
December 31, 2008.



|                                                                                       |  |            |   |         |   |        |         |  |   |                            |   |                     |   |   |  |   |        |  
|-------------------------------------------------------------------------------------- |  | ---------- | - | ------- | - | ------ | ------- |  | - | -------------------------- | - | ------------------- | - | - |  | - | ------ | -
|At September 30, 2009                                                                  |  | Level 1    |   | Level 2 |   |        | Level 3 |  |   | Netting andCashCollateral* |   | Total Net FairValue |  
|                                                                                       |  | (In 000s) |  
|Risk management assets                                                                 |  | $          |  |         | $ | 58,909 |         |  | $ | (6,168                     | ) |                     | $ |  |  | $ | 52,741 |  
|Risk management liabilities                                                            |  | $          |  |         | $ | (2,220 | )       |  | $ |                           |   |                     | $ |  |  | $ | (2,220 | )
|                                                                                       |  |            |   |         |   |        |         |  |   |                            |   |                     |   |   |  |   |        |  
|Total                                                                                  |  | $          |  |         | $ | 56,689 |         |  | $ | (6,168                     | ) |                     | $ |  |  | $ | 50,521 |  
|                                                                                       |  |            |   |         |   |        |         |  |   |                            |   |                     |   |   |  |   |        |  
|*All of our derivative instruments are secured by our reserve-based credit facilities. | 
|                                                                                       |  |            |   |         |  
|At December 31, 2008                                                                   |  | Level 1    |   | Level 2 |   |        | Level 3 |  |   | Netting andCashCollateral* |   | Total Net FairValue |  
|                                                                                       |  | (In 000s) |  
|Risk management assets                                                                 |  | $          |  |         | $ | 58,581 |         |  | $ | 6,752                      |   |                     | $ |  |  | $ | 65,333 |  
|Risk management liabilities                                                            |  | $          |  |         | $ |       |         |  | $ |                           |   |                     | $ |  |  | $ |       |  
|                                                                                       |  |            |   |         |   |        |         |  |   |                            |   |                     |   |   |  |   |        |  
|Total                                                                                  |  | $          |  |         | $ | 58,581 |         |  | $ | 6,752                      |   |                     | $ |  |  | $ | 65,333 |  
|                                                                                       |  |            |   |         |   |        |         |  |   |                            |   |                     |   |   |  |   |        |  



|* | All of our derivative instruments are secured by our reserve-based credit facilities.
|- | -------------------------------------------------------------------------------------

Risk management assets and liabilities in the table above represent the current fair value of all open derivative positions. We classify all
of our derivative instruments as Risk management assets or Risk management liabilities in our Consolidated Balance Sheets.

We use observable market data or information derived from observable market data in order to determine the fair value amounts presented above. Prior to September 30, 2009, the valuation of our derivatives
was performed by Constellation under a management services agreement (see Note 8). In order to determine the fair value amounts presented above, Constellation utilized various factors, including market data and assumptions that market participants
would use in pricing assets or liabilities as well as assumptions about the risks inherent in the



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inputs to the valuation technique. These factors included not only the credit standing of the counterparties involved and the impact of credit enhancements (such as cash deposits, letters of
credit and parental guarantees), but also the impact of our nonperformance risk on our liabilities. We currently use our reserve-based credit facilities to provide credit support for our derivative transactions. Historically, in connection with
certain of our acquisitions, we have used guarantees from Constellation to provide credit support for our derivative transactions associated with the acquisition volumes. As a result, we do not post cash collateral with our counterparties, nor make
any adjustments for non-performance credit risk on our liabilities with counterparties. We utilize observable market data for credit default swaps to assess the impact of non-performance credit risk when evaluating our assets from counterparties. At
September 30, 2009, the impact of non-performance credit risk on the valuation of our assets from counterparties was $0.5 million, of which $0.4 million was reflected as an increase to our non-cash market-to-market gain and $0.9 million was
reflected as a reduction to our accumulated other comprehensive income.

We use observable market data or information derived
from observable market data to measure the fair value of our derivative instruments. Prior to September 30, 2009, in certain instances, Constellation may have utilized internal models to measure the fair value of our derivative instruments.
Generally, Constellation used similar models to value similar instruments. Valuation models utilized various inputs which included quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or
liabilities in markets that were not active, other observable inputs for the assets or liabilities, and market-corroborated inputs, which were inputs derived principally from or corroborated by observable market data by correlation or other means.

The following table sets forth a reconciliation of changes in the fair value of risk management assets and liabilities
classified as Level 3 in the fair value hierarchy:



|                                                                                       |  |                                               |        |   |                                              |   |        |  
|-------------------------------------------------------------------------------------- |  | --------------------------------------------- | ------ | - | -------------------------------------------- | - | ------ | -
|                                                                                       |  | Three MonthsEndedSeptember 30, 2009(In 000s) |        |   | Nine MonthsEndedSeptember 30, 2009(In 000s) |  
|Balance at beginning of period                                                         |  | $                                             | (266   | ) |                                              | $ | 6,752  |  
|Realized and unrealized gains:                                                         |  |                                               |        |   |                                              |   |        |  
|Included in earnings                                                                   |  |                                               | (2,903 | ) |                                              |   | (9,839 | )
|Included in other comprehensive income                                                 |  |                                               | 0      |   |                                              |   | (1,311 | )
|Purchases, sales, issuances, and settlements                                           |  |                                               | 2,536  |   |                                              |   | 3,765  |  
|Transfers into and out of Level 3(a)                                                   |  |                                               | (5,535 | ) |                                              |   | (5,535 | )
|                                                                                       |  |                                               |        |   |                                              |   |        |  
|Balance as of September 30, 2009                                                       |  | $                                             | (6,168 | ) |                                              | $ | (6,168 | )
|                                                                                       |  |                                               |        |   |                                              |   |        |  
|Change in unrealized gains relating to derivatives still held as of September 30, 2009 |  | $                                             | (2,053 | ) |                                              | $ | (9,309 | )
|                                                                                       |  |                                               |        |   |                                              |   |        |  



|(a) | Reflects transfers of derivatives from Level 3 to Level 2 because observable market data is available for all time periods for which we have derivative instruments.
|--- | --------------------------------------------------------------------------------------------------------------------------------------------------------------------



|                                                                                                |  |                                               |         |   |                                              |   |        |  
|----------------------------------------------------------------------------------------------- |  | --------------------------------------------- | ------- | - | -------------------------------------------- | - | ------ | -
|                                                                                                |  | Three MonthsEndedSeptember 30, 2008(In 000s) |         |   | Nine MonthsEndedSeptember 30, 2008(In 000s) |  
|Balance at beginning of period                                                                  |  | $                                             | (38,426 | ) |                                              | $ | (3,591 | )
|Realized and unrealized gains:                                                                  |  |                                               |         |   |                                              |   |        |  
|Included in earnings                                                                            |  |                                               | 11,170  |   |                                              |   | 2,236  |  
|Included in other comprehensive income                                                          |  |                                               | 27,168  |   |                                              |   | 2,121  |  
|Purchases, sales, issuances, and settlements                                                    |  |                                               | (1,049  | ) |                                              |   | (1,903 | )
|Transfers into and out of Level 3                                                               |  |                                               | 0       |   |                                              |   | 0      |  
|                                                                                                |  |                                               |         |   |                                              |   |        |  
|Balance as of September 30, 2008                                                                |  | $                                             | (1,137  | ) |                                              | $ | (1,137 | )
|                                                                                                |  |                                               |         |   |                                              |   |        |  
|Change in unrealized gains (losses) relating to derivatives still held as of September 30, 2008 |  | $                                             | 36,649  |   |                                              | $ | 1,371  |  
|                                                                                                |  |                                               |         |   |                                              |   |        |  

Credit Support Fee Agreements

In connection with certain of our acquisitions, Constellation entered into credit support agreements with us to provide guarantees to three
banks that required credit support for certain financial derivatives. These guarantees were obtained because we did not own the assets at the time the derivatives were entered into and we could not use our existing reserve-based credit facilities to
provide collateral for the derivative transactions.



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| |  |  | In February 2008, in connection with the CoLa Acquisition, we entered into a credit support fee agreement with Constellation under which Constellation
guaranteed credit support up to $8.5 million for certain financial derivatives that we entered into with BNP Paribas (BNP) and Societe Generale (SocGen). These guarantees have been released.
| | - |  | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

Through September 30, 2008, Constellation charged us $0.1 million for this credit support.

Fair Value of Financial Instruments

At September 30, 2009, the carrying values of cash and cash equivalents, accounts receivable, other current assets and current liabilities on the Consolidated Balance Sheets approximate fair value
because of their short term nature. The Company believes the carrying value of long-term debt approximates its fair value because the interest rates on the debt approximate market interest rates for debt with similar terms, which represents the
amount at which the instrument could be valued in an exchange during a current transaction between willing parties.

The
following fair value disclosures are applicable to our financial statements as of September 30, 2009:



|                        |  |                                                  |  |                                                   |         |   |                                     |   |        |  
|----------------------- |  | ------------------------------------------------ |  | ------------------------------------------------- | ------- | - | ----------------------------------- | - | ------ | -
|                        |  |                                                  |  | Fair Value of Asset /(Liability) on Balance Sheet |        
|Derivative Type         |  | Location of Asset / (Liability) on Balance Sheet |  | Nine Months EndedSeptember 30, 2009               |         |   | Year EndedDecember 31, 2008         |  
|Commodity-MTM           |  | Risk management assets                           |  | $                                                 | 72,373  |   |                                     | $ | 26,934 |  
|Commodity-MTM           |  | Risk management assets                           |  |                                                   | (13,464 | ) |                                     |   | (5,987 | )
|Commodity-MTM           |  | Risk management liabilities                      |  |                                                   | (2,220  | ) |                                     |   |       |  
|Interest Rate-MTM       |  | Risk management assets                           |  |                                                   | (6,168  | ) |                                     |   |       |  
|                        |  |                                                  |  |                                                   |         |   |                                     |   |        |  
|                        |  | Total MTM Derivatives                            |  | $                                                 | 50,521  |   |                                     | $ | 20,947 |  
|Commodity-Cash Flow     |  | Risk management assets                           |  | $                                                 |        |   |                                     | $ | 52,232 |  
|Commodity-Cash Flow     |  | Risk management assets                           |  |                                                   |        |   |                                     |   | (182   | )
|Interest Rate-Cash Flow |  | Risk management assets                           |  |                                                   |        |   |                                     |   | (7,665 | )
|                        |  | Total Cash Flow Derivatives                      |  | $                                                 |        |   |                                     | $ | 44,385 |  
|                        |  |                                                  |  |                                                   |         |   |                                     |   |        |  
|                        |  | Total Derivatives                                |  | $                                                 | 50,521  |   |                                     | $ | 65,332 |  
|                        |  |                                                  |  |                                                   |         |   |                                     |   |        |  
|                        |  |                                                 
|                        |  |                                                  |  | Amount of Gain / (Loss)in Income                  |        
|Derivative Type         |  | Location of Gain / (Loss) in Income              |  | Quarter EndedSeptember 30, 2009                   |         |   | Quarter EndedSeptember 30, 2008     |  
|Commodity-MTM           |  | Gain/(Loss) from mark-to-market activities       |  | $                                                 | (6,368  | ) |                                     | $ | 21,976 |  
|Commodity-MTM           |  | Oil and gas sales                                |  | $                                                 | 5,126   |   |                                     | $ | (759   | )
|Interest Rate-MTM       |  | Interest expense                                 |  |                                                   | (2,115  | ) |                                     |   | (573   | )
|                        |  |                                                  |  |                                                   |         |   |                                     |   |        |  
|                        |  | Total MTM Derivatives                            |  | $                                                 | (3,357  | ) |                                     | $ | 20,644 |  
|                        |  |                                                  |  |                                                   |         |   |                                     |   |        |  
|                        |  |                                                 
|                        |  |                                                  |  | Amount of Gain / (Loss)in Income                  |        
|Derivative Type         |  | Location of Gain / (Loss) in Income              |  | Nine Months EndedSeptember 30, 2009               |         |   | Nine Months EndedSeptember 30, 2008 |  
|Commodity-MTM           |  | Gain/(Loss) from mark-to-market activities       |  | $                                                 | 829     |   |                                     | $ | 3,987  |  
|Commodity-MTM           |  | Oil and gas sales                                |  | $                                                 | 11,924  |   |                                     | $ | (1,416 | )
|Interest Rate-MTM       |  | Interest expense                                 |  |                                                   | (4,843  | ) |                                     |   | (996   | )
|                        |  |                                                  |  |                                                   |         |   |                                     |   |        |  
|                        |  | Total MTM Derivatives                            |  | $                                                 | 7,910   |   |                                     | $ | 1,575  |  
|                        |  |                                                  |  |                                                   |         |   |                                     |   |        |  



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|                        |  |                                                                                        |                                   |                                     |                               |                                   |                        |                               |                                   |                               |                                   |   |     |  |   |      
|----------------------- |  | -------------------------------------------------------------------------------------- | --------------------------------- | ----------------------------------- | ----------------------------- | --------------------------------- | ---------------------- | ----------------------------- | --------------------------------- | ----------------------------- | --------------------------------- | - | --- |  | - | -----
|Derivative Type         |  | Location of Gain /(Loss) for Effective and Ineffective Portion of Derivative in Income |                                   | Amount of Gain /(Loss) Reclassified |                               |                                   | Amount of Gain /(Loss)
|                        |  | from AOCI into Income -Effective                                                       |                                   |                                     | in Income - Ineffective      
|                        |  | QuarterEndedSeptember 30,2009                                                          |                                   |                                     | QuarterEndedSeptember 30,2008 |                                   |                        | QuarterEndedSeptember 30,2009 |                                   | QuarterEndedSeptember 30,2008
|Commodity-Cash Flow     |  | Oil and gas sales                                                                      |                                   | $                                   | 11,039                        |                                   |                        | $                             | (4,018                            | )                             |                                   | $ |    |  | $ | 831  
|Interest Rate-Cash Flow |  | Interest expense                                                                       |                                   |                                     | (1,273                        | )                                 |                        |                               | (573                              | )                             |                                   |   |    |  |   |     
|                        |  |                                                                                        |                                   |                                     |                               |                                   |                        |                               |                                   |                               |                                   |   |     |  |   |      
|                        |  | Total Cash Flow                                                                        |                                   | $                                   | 9,766                         |                                   |                        | $                             | (4,591                            | )                             |                                   | $ |    |  | $ | 831  
|                        |  |                                                                                        |                                   |                                     |                               |                                   |                        |                               |                                   |                               |                                   |   |     |  |   |      
|                        |  |                                                                                        |                                  
|                        |  | Location of Gain /(Loss) for Effective and Ineffective Portion of Derivative in Income |                                   | Amount of Gain /(Loss) Reclassified |                               |                                   | Amount of Gain /(Loss)
|                        |  |                                                                                        | from AOCI into Income -Effective  |                                     |                               | in Income - Ineffective          
|Derivative Type         |  |                                                                                        | Nine MonthsEndedSeptember 30,2009 |                                     |                               | Nine MonthsEndedSeptember 30,2008 |                        |                               | Nine MonthsEndedSeptember 30,2009 |                               | Nine MonthsEndedSeptember 30,2008
|Commodity-Cash Flow     |  | Oil and gas sales                                                                      |                                   | $                                   | 36,810                        |                                   |                        | $                             | (9,897                            | )                             |                                   | $ | 267 |  | $ | 1,635
|Interest Rate-Cash Flow |  | Interest expense                                                                       |                                   |                                     | (3,113                        | )                                 |                        |                               | (996                              | )                             |                                   |   |    |  |   |     
|                        |  |                                                                                        |                                   |                                     |                               |                                   |                        |                               |                                   |                               |                                   |   |     |  |   |      
|                        |  | Total Cash Flow                                                                        |                                   | $                                   | 33,697                        |                                   |                        | $                             | (10,893                           | )                             |                                   | $ | 267 |  | $ | 1,635
|                        |  |                                                                                        |                                   |                                     |                               |                                   |                        |                               |                                   |                               |                                   |   |     |  |   |      

As of September 30, 2009, the Company has interest rate swaps on $168.0 million
of its outstanding debt through October 2010, various commodity swaps for 48,920,000 MMbtu of natural gas production through December 2014, various basis swaps for 17,884,000 MMbtu of natural gas production in the Cherokee Basin through December
2012, and a put option for 40,000 MMbtu of natural gas production through December 2009.

6. DEBT

Reserve-Based Credit Facilities

On March 28, 2008, the Company entered into a new credit agreement and an amended and restated credit agreement, each as discussed below. The two agreements contain similar commercial terms with the
same lenders participating in the same applicable percentages. A cross-default feature provides that an event of default under one agreement constitutes an event of default under the other. Each credit agreement is secured by distinct mortgages of
properties as well as guarantees by the Companys subsidiaries.

The current lenders and their percentage commitments in
each of the two credit facilities are: The Royal Bank of Scotland (23.32%), BNP Paribas (22.55%), Wachovia Bank, N.A. (14.55%), Bank of Nova Scotia (17.00%), Calyon (15.05%), and Societe Generale (7.53%).

New Credit Agreement

On March 28, 2008, the Company entered into a new $500.0 million secured credit agreement (Credit Facility) with The Royal Bank of Scotland plc as administrative agent (the
Administrative Agent) and a syndicate of lenders. The amount available for borrowing at any one time is limited to the borrowing base for the Companys properties other than in the State of Alabama. As of September 30, 2009,
the borrowing base under the $500.0 million Credit Facility was $115.0 million. The borrowing base is re-determined semi-annually by the lenders in their sole discretion based on reserve reports as prepared by reserve engineers, together with, among
other things, the oil and natural gas prices at such time. Any increase in each borrowing base must be approved by all of the lenders. The Credit Facility matures on October 31, 2010.

Borrowings under the Credit Facility are available for acquisition, exploration, operation and maintenance of oil and natural gas properties
located in states other than Alabama, payment of expenses incurred in connection with the credit facilities, working capital and general limited liability company purposes. The Credit Facility has a sub-limit of $20.0 million which may be used for
the issuance of letters of credit.

At the Companys election, interest for borrowings under the Credit Facility is
determined by reference to (i) the London interbank rate, or LIBOR, plus an applicable margin between 1.25% and 2.00% per annum based on utilization or (ii) a domestic bank rate plus an applicable margin between 0.25% and
1.00% per annum based on utilization. Interest on borrowings under the Credit Facility is generally payable quarterly for domestic bank rate loans and at the applicable maturity date for LIBOR loans.

The Credit Facility contains various covenants that limit, among other things, the Companys, and certain of the Companys
subsidiaries, ability to incur certain indebtedness, grant certain liens, merge or consolidate, sell all or substantially all of the Companys assets, make certain loans, acquisitions, capital expenditures and investments, and make
distributions other than from available cash.



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In addition, the Company is required to maintain (i) a ratio of debt to Adjusted EBITDA
(defined as, for any period, the sum of consolidated net income for such period plus the following expenses or charges to the extent deducted from consolidated net income in such period: interest expense, depreciation, depletion, amortization,
write-off of deferred financing fees, impairment of long-lived assets, (gain) loss on sale of assets, (gain) loss from equity investment, accretion of asset retirement obligation, unrealized (gain) loss on natural gas derivatives and realized (gain)
loss on cancelled natural gas derivatives, and other similar charges) of not more than 3.50 to 1.00; (ii) Adjusted EBITDA to cash interest expense of not less than 2.5 to 1.0; and (iii) consolidated current assets, including the unused
amount of the total commitments but excluding current non-cash assets, to consolidated current liabilities, excluding non-cash liabilities and current maturities of debt obligations under the credit facilities, of not less than 1.0 to 1.0, all
calculated pursuant to the requirements under SFAS 133 and SFAS 143 (including the current liabilities in respect of the termination of natural gas and interest rate swaps). All financial covenants are calculated using CEPs consolidated
financial information.

The Credit Facility also includes customary events of default, including events of default relating to
non-payment of principal, interest or fees, inaccuracy of representations and warranties in any material respect when made or when deemed made, violation of covenants, cross-defaults, bankruptcy and insolvency events, certain unsatisfied judgments,
guaranties not being valid under the Credit Facility and a change of control. If an event of default occurs under the Credit Facility, the lenders will be able to accelerate the maturity of the Credit Facility and exercise other rights and remedies.

The Credit Facility contains a condition to borrowing and a representation that no material adverse effect (MAE)
has occurred, which includes, among other things, a material adverse change in, or material adverse effect on the business, operations, property, liabilities (actual or contingent) or condition (financial or otherwise) of the Company and its
subsidiaries who are guarantors taken as a whole. If a MAE were to occur, CEP would be prohibited from borrowing under the reserve-based credit facilities and would be in default under the facilities, which could cause all of its existing
indebtedness to become immediately due and payable.

Borrowings under the Credit Facility are secured by various mortgages of
properties that the Company owns in states other than Alabama as well as a security and pledge agreement among the Company and certain of its subsidiaries and the Administrative Agent.

We have the ability to borrow under the Credit Facility to pay distributions to unitholders as long as no event of default exists and
provided that no distributions to unitholders may be made if the borrowings outstanding under the credit facilities exceed 90% of the borrowing base. As of September 30, 2009, the Company is restricted from paying distributions to unitholders
as the borrowings outstanding under its two credit facilities exceed 90% of the borrowing base.

Through September 30,
2009, the Company has borrowed $112.0 million under the Credit Facility.

Amended and Restated Credit Agreement

On March 28, 2008, the Company amended and restated its existing $200.0 million credit facility by entering into an
amended and restated credit agreement with the Administrative Agent and a syndicate of lenders (the Amended and Restated Credit Facility). As of September 30, 2009, the borrowing base under the $200.0 million Amended and Restated
Credit Facility was $110.0 million. The amount available for borrowing at any one time is limited to the borrowing base for the Companys properties in the State of Alabama. The borrowing base is re-determined semi-annually by the lenders in
their sole discretion based on reserve reports as prepared by reserve engineers, together with, among other things, the oil and natural gas prices at such time. Any increase in each borrowing base must be approved by all of the lenders. The Amended
and Restated Credit Facility matures on October 31, 2010.

Borrowings under the Amended and Restated Credit Facility are
available for acquisition, exploration and the operation and maintenance of oil and natural gas properties located in the State of Alabama, payment of expenses incurred in connection with the credit facilities, working capital and general limited
liability company purposes. The Amended and Restated Credit Facility has a sub-limit of $20.0 million which may be used for the issuance of letters of credit.

At the Companys election, interest for borrowings under the Amended and Restated Credit Facility is determined by reference to (i) the London interbank rate, or LIBOR, plus an applicable margin
between 1.25% and 2.00% per annum based on utilization or (ii) a domestic bank rate plus an applicable margin between 0.25% and 1.00% per annum based on utilization. Interest on borrowings under the Amended and Restated Credit
Facility is generally payable quarterly for domestic bank rate loans and at the applicable maturity date for LIBOR loans.

The
Amended and Restated Credit Facility contains various covenants that limit, among other things, the Companys, and certain of the Companys subsidiaries, ability to incur certain indebtedness, grant certain liens, merge or
consolidate, sell all or substantially all of the Companys assets, make certain loans, acquisitions, capital expenditures and investments, and make distributions other than from available cash.

In addition, the Company is required to maintain (i) a ratio of debt to Adjusted EBITDA (defined as, for any period, the sum of
consolidated net income for such period plus the following expenses or charges to the extent deducted from consolidated net income in such period: interest expense, depreciation, depletion, amortization, write-off of deferred financing fees,
impairment of long-lived



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assets, (gain) loss on sale of assets, (gain) loss from equity investment, accretion of asset retirement obligation, unrealized (gain) loss on natural gas derivatives and realized (gain) loss on
cancelled natural gas derivatives, and other similar charges) of not more than 3.50 to 1.00; (ii) Adjusted EBITDA to cash interest expense of not less than 2.5 to 1.0; and (iii) consolidated current assets, including the unused amount of
the total commitments but excluding current non-cash assets, to consolidated current liabilities, excluding non-cash liabilities and current maturities of debt obligations under the credit facilities, of not less than 1.0 to 1.0, all calculated
pursuant to the requirements under SFAS 133 and SFAS 143 (including the current liabilities in respect of the termination of natural gas and interest rate swaps). All financial covenants are calculated using CEPs consolidated financial
information.

The Amended and Restated Credit Facility also includes customary events of default, including events of default
relating to non-payment of principal, interest or fees, inaccuracy of representations and warranties in any material respect when made or when deemed made, violation of covenants, cross-defaults, bankruptcy and insolvency events, certain unsatisfied
judgments, guaranties not being valid under the Amended and Restated Credit Facility and a change of control. If an event of default occurs under the Amended and Restated Credit Facility, the lenders will be able to accelerate the maturity of the
Amended and Restated Credit Facility and exercise other rights and remedies.

The Amended and Restated Credit Facility
contains a condition to borrowing and a representation that no material adverse effect (MAE) has occurred, which includes, among other things, a material adverse change in, or material adverse effect on the business, operations,
property, liabilities (actual or contingent) or condition (financial or otherwise) of the Company and its subsidiaries who are guarantors taken as a whole. If a MAE were to occur, CEP would be prohibited from borrowing under the reserve-based credit
facilities and would be in default under the facilities, which could cause all of its existing indebtedness to become immediately due and payable.

Borrowings under the Amended and Restated Credit Facility are secured by various mortgages of properties the Company owns in Alabama as well as a security and pledge agreement among the Company and
certain of its subsidiaries and the Administrative Agent.

We have the ability to borrow under the Amended and Restated Credit
Facility to pay distributions to unitholders as long as no event of default exists and provided that no distributions to unitholders may be made if the borrowings outstanding under the credit facilities exceed 90% of the borrowing base. As of
September 30, 2009, the Company is restricted from paying distributions to unitholders as the borrowings outstanding under its two credit facilities exceed 90% of the borrowing base.

Through September 30, 2009, the Company has borrowed $108.0 million under the Amended and Restated Credit Facility.

Debt Issue Costs

Total debt issue costs incurred through September 30, 2009, were approximately $3.5 million. These costs are being amortized over the life of the credit facilities.

Funds Available for Borrowing

As of September 30, 2009, the Company had $220.0 million in outstanding debt under its reserve-based credit facilities and $5.0 million in remaining borrowing capacity. As of September 30, 2008,
the Company had $216.0 million in outstanding debt under its reserve-based credit facilities. See Note 16 for additional information.

Compliance with Debt Covenants

Our reserve-based credit facilities mature in October 2010 and, as a result,
amounts due under the facilities became a current liability in October 2009. To date, we have not entered into an agreement to refinance or extend the due date on the reserve-based credit facilities. We may not be able to renew or replace the
facilities at similar borrowing costs, terms, covenants, restrictions, or borrowing base, or with similar debt issue costs. In addition, we do not believe that our forecasted operational cash flow will be sufficient to meet the principal payment
that would be required on our outstanding debt balance as it comes due on October 31, 2010 unless we are able to successfully refinance our outstanding debt, extend the due date on our current credit facilities or sell assets. Our inability to
refinance our outstanding debt would have a material adverse effect on the Company. See Note 16 for additional information.

The reserve-based credit facilities limit the amounts we can borrow to a borrowing base amount, determined by the lenders in their sole discretion. The borrowing base is re-determined semi-annually, and may be re-determined at our request
more frequently and by the lenders in their sole discretion based on reserve reports prepared by reserve engineers, together with, among other things, the oil and natural gas prices existing at the time. The lenders can unilaterally adjust the
borrowing base and the borrowings permitted to be outstanding under the reserve-based credit facilities. Outstanding borrowings in excess of the borrowing base must be repaid immediately, or we must pledge other oil and natural gas properties as
additional collateral. We do not currently have any substantial unpledged properties, and we may not have the financial resources in the future to make any mandatory principal prepayments required under the reserve-based credit facilities. Our
current combined borrowing base under the reserve-based credit facilities is $225.0 million and we expect that the next borrowing base redetermination will occur within the next two months.



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At September 30, 2009, CEP believes that it was in compliance with the debt covenants
contained in its credit facilities. As of September 30, 2009, the actual debt to Adjusted EBITDA ratio was 3.2 to 1.0 as compared with a required ratio of not greater than 3.5 to 1.0, the actual ratio of current assets to current liabilities
was 2.5 to 1.0 as compared with a required ratio of not less than 1.0 to 1.0, and the actual Adjusted EBITDA to cash interest expense ratio was 12.2 to 1.0 as compared with a required ratio of not less than 2.5 to 1.0.

If CEP is unable to remain in compliance with the debt covenants associated with its reserve-based credit facilities or maintain the
required ratios discussed above, CEP could request waivers from the lenders in its bank group. Although the lenders may not provide a waiver, CEP may take additional steps in the event of not meeting the required ratios or in the event of a
reduction in the combined borrowing base below its current level of $225.0 million at the future redetermination by the lenders. If it becomes necessary to pay debt down beyond operating cash flows, CEP could further reduce capital expenditures,
continue to suspend quarterly distributions to unitholders, sell oil and natural gas properties or inventories, liquidate in-the-money derivative positions, reduce operating and administrative costs, or take additional steps to increase liquidity.

7. OIL AND NATURAL GAS PROPERTIES

Natural gas properties consist of the following:



|                                                                                 |  |                   |          |   |                  |   |          |  
|-------------------------------------------------------------------------------- |  | ----------------- | -------- | - | ---------------- | - | -------- | -
|                                                                                 |  | September 30,2009 |          |   | December 31,2008 |  
|                                                                                 |  | (In 000s)        |         
|Oil and natural gas properties and related equipment (successful efforts method) |  |                   |          |   |                  |   |          |  
|Property (acreage) costs                                                         |  |                   |          |   |                  |   |          |  
|Proved property                                                                  |  | $                 | 752,211  |   |                  | $ | 729,898  |  
|Unproved property                                                                |  |                   | 38,052   |   |                  |   | 38,293   |  
|                                                                                 |  |                   |          |   |                  |   |          |  
|Total property costs                                                             |  |                   | 790,263  |   |                  |   | 768,191  |  
|Materials and supplies                                                           |  |                   | 4,837    |   |                  |   | 4,587    |  
|Land                                                                             |  |                   | 911      |   |                  |   | 912      |  
|                                                                                 |  |                   |          |   |                  |   |          |  
|Total                                                                            |  |                   | 796,011  |   |                  |   | 773,690  |  
|Less: Accumulated depreciation, depletion and amortization                       |  |                   | (158,295 | ) |                  |   | (111,171 | )
|                                                                                 |  |                   |          |   |                  |   |          |  
|Natural gas properties and equipment, net                                        |  | $                 | 637,716  |   |                  | $ | 662,519  |  
|                                                                                 |  |                   |          |   |                  |   |          |  

Impairment of Oil and Natural Gas Properties

In the nine months ended September 30, 2009, CEP recorded a charge of approximately $4.2 million to impair the value of certain of its
wells located in the Woodford Shale in Oklahoma and the value of certain obsolete inventory. This charge is included in depreciation, depletion and amortization in the Statement of Operations. This impairment was recorded because the carrying value
of certain of the wells exceeded the fair value of the wells as measured by estimated cash flows reported in a third party reserve report that was based upon future expected oil and natural gas prices. The impairment is primarily caused by the
impact of lower future expected natural gas prices. Cash flow estimates for the impairment testing exclude derivative instruments. As of September 30, 2009, CEP reviewed its other properties for impairment and the estimated undiscounted future
cash flows exceeded the net capitalized costs, thus no impairment was required to be recognized. If oil and natural gas prices continue to significantly decline during 2009, the estimated undiscounted future cash flows for CEPs proved oil and
natural gas properties may not exceed the net capitalized costs for the properties and an impairment may be required to be recognized in future periods.

Asset Sales

In 2009, CEP sold a tractor and other miscellaneous equipment
for less than $0.1 million and recorded a loss of less than $0.1 million on the sales.

In 2008, CEP sold an international
pulling unit, a trencher, and other miscellaneous equipment for approximately $0.2 million and recorded a gain of approximately $0.1 million on the sales.

Involuntary Conversion

In the first quarter 2008, a fire damaged the
Companys field office located in Dewey, Oklahoma. The net book value of the building was $0.2 million. An insurance receivable of $0.4 million and a gain of $0.2 million were recorded for the involuntary conversion. The insurance proceeds of
$0.4 million were collected in April 2008.

Useful Lives

CEPs furniture, fixtures, and equipment are depreciated over a life of one to five years, buildings are depreciated over a life of
twenty years, and pipeline and gathering systems are depreciated over a life of twenty-five to forty years.



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8. RELATED PARTY TRANSACTIONS

Management Services Agreement

In November 2006, CEP entered into a
management services agreement with Constellation Energy Partners Management, LLC (CEPM), a subsidiary of Constellation, to provide certain management, technical and administrative services. These services include legal, accounting and
finance, engineering and technical, risk management, information technology and tax services, as well as acquisition services related to opportunities to acquire oil and natural gas reserves and related midstream assets. CEPM and its affiliates do
not have any obligation to provide acquisition services or other services under the management services agreement, provided that CEPM may receive added compensation for providing CEP with services as a result of the management incentive interests it
holds in CEP. Each quarter, CEPM charges CEP an amount for services provided to CEP. This amount is agreed to annually and includes a portion of the compensation paid by CEPM and its affiliates to personnel who spend time on CEPs business and
affairs. The allocation of compensation expense for the chief executive officer, chief financial officer and chief accounting officer was fixed by agreement between the parties in 2008. As of January 1, 2009, these three officers and CEPs
general counsel became direct employees of the Company. The allocation of compensation expense for other personnel of CEPM and its affiliates is determined based on the percentage of time spent by such personnel on CEPs business and affairs.
The conflicts committee of the Companys board of managers reviews at least annually the services to be provided by CEPM and the costs to be charged to CEP under the management services agreement and reviews the cost allocation quarterly. The
conflicts committee also determines if the amounts to be paid by the Company for the services to be performed are fair to and in the best interests of the Company. During the year, the cost allocation may be adjusted upwards to reflect additional
services provided by CEPM and its affiliates or downwards to reflect the transition of services to CEP employees. These costs totaled approximately $1.2 million and $1.9 million for the nine months ended September 30, 2009 and 2008,
respectively. The costs charged to CEP under the management services agreement may be greater or less than the actual costs CEP would incur if the services were performed by an unaffiliated third party.

In June 2009, CEPM notified the CEP that it will terminate the management services agreement effective December 15, 2009. As a result,
CEP submitted a plan to its lenders for managing its business after the termination of the agreement as required under the terms of its reserve-based credit facilities. The plan has received the requisite approval that was required under the
Companys reserve-based credit facilities.

CEP had payables to Constellation of $0.3 million and $1.0 million as of
September 30, 2009 and December 31, 2008, respectively. This payable balance is included in current liabilities in the accompanying balance sheets.

Credit Support Fee Agreements

As described further in Note 5, CEG
and CEP entered into credit support fee agreement under which CEG guaranteed credit support for certain financial derivatives with three financial institutions. This credit support fee agreement has expired. For the nine months ended
September 30, 2008, CEG charged CEP $0.1 million for the credit support.

Natural Gas Purchases

Through March 31, 2009, CCG purchased natural gas from CEP in the Cherokee Basin. The arrangement was reviewed by the conflicts
committee of CEPs board of managers. The committee found that the arrangement was fair to and in the best interests of CEP. For the nine months ended September 30, 2009, and September 30, 2008, CCG paid CEP $5.7 million and $18.8
million for natural gas purchases, respectively.

In April 2009, Macquarie Cook Energy LLC (Macquarie Cook), a
subsidiary of Sydney, Australia-based Macquarie Group, Ltd. purchased the downstream natural gas trading operations of CEG. This included the CCG entity that purchased natural gas from CEP in the Cherokee Basin. Macquarie Cook will purchase natural
gas from CEP in the Cherokee Basin for May 2009 through October 2009. CEP has received a guarantee from Macquarie Bank Limited for up to $8 million in purchases through December 31, 2011. Macquarie Cook is not a related party to CEP.

Management Incentive Interests

CEPM holds the management incentive interests in the Company. These management incentive interests represent the right to receive 15% of quarterly distributions of available cash from operating surplus
after the Target Distribution (as defined in the Companys limited liability company agreement) has been achieved and certain other tests have been met. For the nine months ended September 30, 2009, none of these applicable tests have been
met, and, as a result, CEPM was not entitled to receive any management incentive interest distributions.

For the third
quarter 2007, the Company increased its quarterly distribution rate to $0.5625 per unit. This increase in the distribution rate commenced a management incentive interest vesting period under the Companys limited liability company agreement.
Through December 31, 2008, a cash reserve of $0.7 million had been established to fund future distributions on the



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management incentive interests. In February 2009, the Company reduced its quarterly distribution rate to $0.13 per unit. This decrease in the distribution rate terminated the initial management
incentive interest vesting period. After the February 13, 2009 distribution was paid, this reserve of $0.7 million was reduced to zero.

CoLa Acquisition

As further described in Note 4, on March 31, 2008, the Company acquired 83
non-operated producing oil and natural gas wells in the Woodford Shale in the Arkoma Basin in Oklahoma from CoLa for approximately $50.1 million, including purchase price adjustments through September 30, 2009. CoLa is an affiliate of CEG, the
Companys sponsor. The transaction was reviewed and approved by the Companys conflicts committee. In its review, the Companys conflicts committee considered various economic factors (including historical and estimated future
production, estimated proved reserves, future pricing estimates and operating cost estimates) regarding the transaction, and determined that the transaction was fair to and in the best interests of the Company.

9. COMMITMENTS AND CONTINGENCIES

In the course of its normal business affairs, the Company is subject to possible loss contingencies arising from federal, state and local environmental, health and safety laws and regulations and third-party litigation. As of
September 30, 2009 and December 31, 2008, other than the matters discussed below, there were no matters which, in the opinion of management, would have a material adverse effect on the financial position, results of operations or cash
flows of CEP, and its subsidiaries, taken as a whole.

Certain of the Companys wells in the Robinsons Bend Field
are subject to a net profits interest (NPI) held by Torch Energy Royalty Trust (the Trust) (See Note 11). The royalty payment to the Trust is calculated using a sharing arrangement with a pricing formula that has had the
effect of keeping our payments to the Trust lower than if such payments had been calculated based on prevailing market prices. CEP is uncertain of the financial impact of the NPI over the life of the Robinsons Bend Field as it has volumetric
and price risk variables. However, in order to address a portion of the risk of the potential adverse impact on CEPs operating results from a termination of the sharing arrangement, Constellation Holdings, Inc. (CHI) contributed
$8.0 million to CEP in exchange for all of CEPs Class D interests at the closing of its initial public offering in November 2006 for the purpose of partially protecting the distributions to the common unit holders in the event the sharing
arrangement is terminated. This contribution will be returned to CHI in 24 special quarterly distributions as long as the sharing agreement remains in effect for the distribution period. As a result of the initiation of the legal proceedings
discussed in Note 11 and Note 16, the Class D interest special quarterly distributions have been suspended for all quarters commencing on or after January 1, 2008. This suspension includes $1,999,999.65 which represents the distributions that
were suspended for the quarterly periods ended June 30, 2009, March, 31, 2009, and December 31, September 30, June 30, and March 31, 2008. The remaining undistributed amount of the Class D interests is $6.7 million. See
Note 16 for additional information.

10. ASSET RETIREMENT OBLIGATION

We recognize the fair value of a liability for an asset retirement obligation (ARO) in the period in which it is incurred if a
reasonable estimate of fair value can be made. The associated asset retirement cost (ARC) is capitalized as part of the carrying amount of the long-lived asset. Subsequently, the ARC is allocated to expense using a systematic and
rational method over the assets useful life. The AROs recorded by CEP relate to the plugging and abandonment of natural gas wells, and decommissioning of the gas gathering and processing facilities.

Inherent in the fair value calculation of ARO are numerous assumptions and judgments including the ultimate settlement amounts, inflation
factors, credit adjusted discount rates, timing of settlement and changes in the legal, regulatory, environmental and political environments. To the extent future revisions to these assumptions result in adjustments to the recorded fair value of the
existing ARO, a corresponding adjustment is made to the ARC capitalized as part of the gas property balance.

The following
table is a reconciliation of the ARO:



|                                                                 |  |                   |       |                  |   |      
|---------------------------------------------------------------- |  | ----------------- | ----- | ---------------- | - | -----
|                                                                 |  | September 30,2009 |       | December 31,2008
|                                                                 |  | (In 000s)       
|Asset retirement obligation, beginning balance                   |  | $                 | 6,754 |                  | $ | 6,163
|Liabilities incurred from acquisition of the properties (Note 4) |  |                   |      |                  |   | 56   
|Liabilities incurred                                             |  |                   | 116   |                  |   | 124  
|Accretion expense                                                |  |                   | 267   |                  |   | 411  
|                                                                 |  |                   |       |                  |   |      
|Asset retirement obligation, ending balance                      |  | $                 | 7,137 |                  | $ | 6,754
|                                                                 |  |                   |       |                  |   |      



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Additional retirement obligations increase the liability associated with new oil and natural
gas wells and other facilities as these obligations are incurred. Actual expenditures for abandonments of oil and natural gas wells and other facilities reduce the liability for asset retirement obligation. There have been no material expenditures
for abandonments.

At September 30, 2009, and December 31, 2008, there were no assets legally restricted for
purposes of settling existing asset retirement obligations.

11. NET PROFITS INTEREST

Certain of the Companys wells in the Robinsons Bend Field are subject to a non-operating NPI. The holder of the NPI, the Trust,
does not have the right to receive production from the applicable wells in the Robinsons Bend Field. Instead, the Trust only has the right to receive a specified portion of the future natural gas sales revenues from specified wells as defined
by the Net Overriding Royalty Conveyance Agreement. The Company records the NPI as an overriding royalty interest net in revenue in the Consolidated Statements of Operations.

Amounts due to the Trust with respect to NPI are comprised of the sum of the Net Proceeds and the Infill Net Proceeds, which are described
below.

The Net Proceeds equal the lesser of (i) 95% of the net proceeds from 393 producing wells in the Robinsons
Bend Field and (ii) the net proceeds from the sale of 912.5 MMcf of natural gas for the quarter. Net proceeds equal gross proceeds, currently calculated by reference to the gas purchase contract (for a description of the gas purchase contract,
please read Item 1. BusinessNatural Gas DataTorch Royalty NPIThe Gas Purchase Contract in the Companys Annual Report on Form 10-K for the year ended December 31, 2008), less specified costs attributable
to the Robinsons Bend Assets. The specified costs deducted for purposes of calculating net proceeds for purposes of clause (i) of the first sentence of this paragraph (the NPI Net Proceeds Calculation) include: (a) delay rentals,
shut-in royalties and similar payments, (b) property, production, severance and similar taxes and related audit charges, (c) specified refunds, interest or penalties paid to purchasers of hydrocarbons or governmental agencies,
(d) certain liabilities for environmental damage, personal injury and property damage, (e) certain litigation costs, (f) costs of environmental compliance, (g) specified operating costs incurred to produce hydrocarbons,
(h) specified development costs (including costs to increase recoverable reserves or the timing of recovery of such reserves), (i) costs of specified lease renewals and extensions and unitization costs and (j) the unrecovered portion,
if any, of the foregoing costs for preceding time periods plus interest on such unrecovered portion at a rate equal to the base rate (compounded quarterly) as announced from time to time by Citibank, N.A. The specified costs deducted for purposes of
calculating net proceeds for purposes of clause (ii) of the first sentence of this paragraph include: (a) property, production, severance and similar taxes, (b) specified refunds, interest or penalties paid to purchasers of
hydrocarbons or governmental agencies and (c) the unrecovered portion, if any, of the foregoing costs for preceding time periods plus interest on such unrecovered portion at a rate equal to the base rate (compounded quarterly) as announced from
time to time by Citibank, N.A. Net proceeds are calculated quarterly and any negative balance (expenses in excess of revenues) within the net proceeds calculation accumulates and is charged interest as described above.

The cumulative Net NPI Proceeds balance must be greater than $0 before any payments are made to the Trust. The cumulative Net
Proceeds was a deficit for the nine months ended September 30, 2009 and 2008. As a result, no payments were made to the Trust with respect to the NPI for the nine months ended September 30, 2009 and 2008.

The calculation of the Infill Net Proceeds uses the same methodology as the NPI Net Proceeds Calculation described above except that the
proceeds and costs are attributable not to the NPI Net Proceeds Wells, but to the remaining wells in the Robinsons Bend Field that are subject to the NPI and that have been drilled since the Trust was formed and wells that will be drilled
(other than wells drilled to replace damaged or destroyed wells), in each case on leases subject to the NPI. The NPI in the Infill Wells entitles the Trust to receive 20% of the Infill Net Proceeds. There has never been a payout on the Infill Net
Proceeds.

Termination of the Trust and Gas Purchase Contract

On January 29, 2008, the unitholders of the Trust voted to terminate the Trust and the trust agreement and authorized the Trustee to
wind up, liquidate and distribute the assets held by the Trust under the terms of the trust agreement. The gas purchase contract, by its terms, was also terminated on January 29, 2008 as a result of the termination of the Trust.

With the gas purchase contract terminated, we are no longer obligated to sell gas produced from our interest in the Black Warrior Basin
pursuant to the gas purchase contract. Notwithstanding the termination of the gas purchase contract, the NPI will continue to burden the Trust Wells, and it should continue to be calculated as if the gas purchase contract were still in effect,
regardless of what proceeds may actually be received by us as the seller of the gas. Originally, the Trust indicated that it believed that the net profits interest would continue to be calculated as if the gas purchase contract was still in effect.
The Trust, however, subsequently indicated that the documents creating the NPI were not clear as to this point. As a result, on January 25, 2008, Torch Royalty Company (Torch Royalty), Torch E&P Company (Torch
E&P) and CEP (collectively, the Claimants) sent notice of a demand for arbitration before Judicial Arbitration and Mediation Services (JAMS) to Wilmington Trust Company, as Trustee



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(Trustee) for the Trust, and to Capital One, NA, as successor to Hibernia National Bank, as trustee for Torch Energy Louisiana Royalty Trust, pursuant to the operative dispute
resolution provisions of the agreement governing the Trust, the NPI and the Conveyances (as defined below). The Claimants were working interest owners in certain oil and gas fields located in Texas, Louisiana and Alabama. The working interests owned
by the other Claimants are similarly subject to net profit interests (the Other NPIs) that are also based on the gas purchase contract. In the arbitration demand, we and the other Claimants sought a declaratory judgment that the NPI
payments as well as the payments owed in respect of the Other NPIs will continue to be calculated using the sharing arrangement under the gas purchase contract even though the Trust and the gas purchase contract have been terminated. In its response
to the Claimants arbitration demand, the Trustee took the position that the sharing arrangement under the gas purchase contract terminated upon the termination of that contract. On July 18, 2008, the arbitration panel issued its final
award (the Final Award) which, among other things, found and concluded that the sharing arrangement and other pricing terms of the gas purchase contract will continue to control the amount owed to the holder of the NPI.

The Trust and Trust Venture filed a petition to vacate the Final Award (the Petition to Vacate) with the District Court of
Harris County, Texas, 152nd Judicial District (the District Court) on October 16, 2008. The Claimants filed a motion to confirm the Final Award (the Motion to Confirm) with the District Court on November 5, 2008. On
December 10, 2008, the District Court dismissed the Petition to Vacate and granted the Motion to Confirm, thus confirming the Final Award. The Company believes that any timely further appeal or request for other relief by the Trust and Trust
Venture should have been filed by January 9, 2009. The Company is not aware of any filing having been made as of September 30, 2009, and the arbitration and related proceeding thereto appear to have been finalized. See Note 16 for
additional information.

Water Gathering, Separation, and Disposal Costs

On January 8, 2009, the Company was served by Trust Venture, on behalf of the Trust, with a purported derivative action filed in Alabama
state court demanding an audited statement of revenues and expenses associated with the NPI, alleging a breach of contract under the conveyance associated with the NPI and the agreement establishing the Trust and asserting that above market rates
for services were paid, reducing the amounts paid to the Trust in connection with the NPI. The lawsuit seeks unspecified damages and an accounting of the NPI. On February 9, 2009, the Company filed a motion to dismiss the lawsuit and filed an
arbitration proceeding against the Trust relating to the claims alleged in the lawsuit with Judicial Arbitration and Mediation Services (JAMS). On February 12, 2009 Trust Venture requested a stay of the arbitration proceeding. On
February 25, 2009, the Circuit Court of Tuscaloosa County, Alabama denied the Companys motion to dismiss the lawsuit and also denied Trust Ventures motion to stay the arbitration proceeding. On April 1, 2009, the Circuit Court
of Tuscaloosa County, Alabama again denied the Companys motion to stay the litigation in Alabama and again denied Trust Ventures motion to stay the arbitration proceeding. On April 10, 2009, the arbitration panel granted Trust
Ventures motion to stay the arbitration proceeding until the conclusion of the related litigation that was pending in Alabama. On July 24, 2009, the arbitration proceeding was dismissed. As a result, the Alabama litigation is proceeding.
The proceeding is in the discovery phase. Trust Venture and the Trust asserted that discovery from the Trust be produced by the Trust voluntarily as it deems responsive without being subject to the jurisdiction of the Alabama Court. On June 12,
2009, the Company filed a Motion to Compel the Trust or Trust Venture to respond fully to its discovery requests to the Trust. On July 6, 2009, the Alabama Court granted the Companys motion and on August 21, 2009 the Alabama Court
made the Trust a nominal party to the Alabama litigation and confirmed its ruling that the Trust be subject to regular discovery in the litigation. On August 18, 2009, Trust Venture filed an application for preliminary injunction requesting
that the Alabama court enter an injunction requiring the Company to deposit into an escrow account all fees, less expenses, that it receives from water disposal under the water disposal agreement associated with the wells in the Robinsons Bend
field pending judgment in the lawsuit and asserting damages of approximately $11.6 million from June 2005 to May 2009. After hearing, the Alabama court denied Trust Ventures application. The Company intends to defend itself vigorously with
respect to the alleged claims. There can be no assurance as to the outcome or result of the lawsuit or the arbitration proceeding. The Company intends its forward-looking statements relating to the action to speak only as of the time of such
statements and does not plan to update or revise them except to the extent that material information becomes available.

12. ENVIRONMENTAL
LIABILITY

CEP is subject to costs resulting from federal, state and local laws and regulations designed to protect human
health and the environment. These laws and regulations can result in increased capital, operating and other costs as a result of compliance, remediation, containment and monitoring obligations. As of September 30, 2009 and December 31,
2008, accrued environmental obligations were $0.3 million and $0.4 million, respectively. These obligations were classified as current liabilities on CEPs Consolidated Balance Sheet.

13. UNIT-BASED COMPENSATION

The Company recognized approximately $0.3 million and $0.3 million of non-cash expense related to grants made under its Long-term Incentive Plans unit-based compensation and executive inducement bonus program in the nine months ended
September 30, 2009, and September 30, 2008, respectively.



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The Company recognized approximately $0.5 million of cash expense related to grants made
under its omnibus incentive compensation program in the nine months ended September 30, 2009. If the 2009 Omnibus Incentive Compensation Plan is approved by unitholders, this $0.5 million in expense will be recorded as a non-cash expense as the
liability for grants made under the program will be settled in restricted common units as opposed to cash.

Adoption of
the Executive Inducement Bonus Program

An Executive Inducement Bonus Program was adopted and approved by the
Companys Board of Managers on April 28, 2009. The plan was created without unitholder approval in reliance on the exemption provided in the NYSE Arca rules. On May 7, 2009, CEP filed a registration statement with the SEC on Form S-8
for 300,000 common units associated with grants under this program made to the executives of CEP described below. After the initial grants have been made, the only additional common units that can be issued under this program are for distribution
rights in connection with distribution credits as described below.

Adoption of the 2009 Omnibus Incentive Compensation
Plan

A 2009 Omnibus Incentive Compensation Plan containing 1,650,000 common units was adopted and approved by the
Companys Board of Managers on April 28, 2009, subject to approval by the Companys common unitholders. If the common unitholders do not approve the plan, any grants made under the plan, including those discussed below, will be
settled in cash based on the fair market value on the vesting date. Upon approval of the plan by the common unitholders, any outstanding grants will automatically convert into the same number of restricted common units which are settled in common
units and not cash.

The adoption of the 2009 Omnibus Incentive Compensation Plan, if approved by unitholders, will increase
the number of authorized common units of the Company and will be considered when calculating diluted earnings per unit. The 2009 Omnibus Incentive Compensation Plan does not replace or affect the Companys LTIP that was adopted in November 2006
and it does not replace or affect the Executive Inducement Bonus Program discussed above. The 2009 Omnibus Incentive Compensation Plan contains 1,650,000 common units, of which approximately 609,722 units remain available for grants under the plan.
The LTIP contains 450,000 common units, of which approximately 250,599 remain available for grants under the LTIP. The Executive Inducement Bonus Program is not expected to exceed 300,000 common units, of which approximately 132,517 units remain
available for distribution rights in connection with distribution credits to the executives of CEP under the program.

2009 Grants

Grants under the 2009 Omnibus Incentive Compensation Plan

The Company granted approximately 41,408 notional unit awards under the 2009 Omnibus Incentive Compensation Plan on August 1, 2009, to
certain employees of the Company in Texas. These units had a total fair market value of approximately $137,889 based on the closing price of the Companys units on NYSE Arca on August 3, 2009. These service-based restricted units will vest
on a five year ratable schedule beginning on August 1, 2010. If the common unitholders do not approve the 2009 Omnibus Incentive Compensation Plan, the notional units will be settled in cash based on the fair market value on the vesting date.
Upon approval of the 2009 Omnibus Incentive Compensation Plan by the common unitholders, the notional units so granted to the four officers of CEP will automatically convert into restricted common units based on the vesting schedule for the notional
units.

On May 1, 2009, the Company made grants of an aggregate of 748,670 notional units under the 2009 Omnibus
Incentive Compensation Plan to the four officers of CEP, with an approximate aggregate grant-date value of $2,313,390 based on the closing price per unit on May 1, 2009. The units will vest ratably over five years. If the common unitholders do
not approve the 2009 Omnibus Incentive Compensation Plan, the notional units will be settled in cash based on the fair market value on the vesting date. Upon approval of the 2009 Omnibus Incentive Compensation Plan by the common unitholders, the
notional units so granted to the four officers of CEP will automatically convert into restricted common units based on the vesting schedule for the notional units. As of September 30, 2009, a total of 33,625 notional units have been issued as
distribution credits by the Company.

On May 1, 2009, the Company made grants of an aggregate of 140,341 notional units
under the 2009 Omnibus Incentive Compensation Plan to seven new employees of the Companys wholly owned subsidiary, CEP Services Company, Inc (CEP Services), with an approximate aggregate grant-date value of $433,654 based on the
closing price per unit on May 1, 2009. The units will vest ratably over five years. Each of these employees was formerly employed by CCG, an indirectly wholly owned subsidiary of CEG. These employees were involved in the performance of services
to the Company under our management services agreement with CEPM and were hired by CEP Services to directly provide services to the Company and its subsidiaries. If the common unitholders do not approve the 2009 Omnibus Incentive Compensation Plan,
the notional units will be settled in cash based on the fair market value on the vesting date. Upon approval of the 2009 Omnibus Incentive Compensation Plan by the common unitholders, the notional units so granted to the seven employees will
automatically convert into restricted common units based on the vesting schedule for the notional units.

On April 28,
2009, the Companys Board of Managers approved a total grant of 80,937 notional units for the three independent managers currently serving on the Board of Managers, each with an approximate grant-date value of $83,365 based on the closing



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price per unit on May 1, 2009. The grants were made under the 2009 Omnibus Incentive Compensation Plan pursuant to grant agreements, dated May 1, 2009, by and between the Company and
each of Richard H. Bachmann, Richard S. Langdon and John N. Seitz. If the common unitholders do not approve the 2009 Omnibus Incentive Compensation Plan, the notional units will be settled in cash based on the fair market value on the vesting date.
Upon approval of the 2009 Omnibus Incentive Compensation Plan by the common unitholders, the notional units so granted to the independent managers will automatically convert into restricted units. These grants vest on March 1, 2010. As of
September 30, 2009, a total of 2,806 notional units have been issued as distribution credits by the Company.

Prior to
vesting, each notional unit and restricted common unit granted as described above under the 2009 Omnibus Incentive Compensation Plan carries the right to receive distribution credits when any distributions are made by the Company on its common
units. Any distribution credits will accrue under the grants and be settled in cash or common units in the discretion of the Compensation Committee of the Board of Managers on the vesting date for the underlying notional unit or restricted common
unit, as applicable. Upon approval of the 2009 Omnibus Incentive Compensation Plan by the common unitholders, any accrued distribution credits on the notional units will increase the number of restricted common units that are issued upon conversion
of the notional units as described above.

Until any notional units granted under 2009 Omnibus Incentive Compensation Plan are
converted into restricted common units upon unitholder approval, the notional units will be accounted for using the variable plan accounting method. Under the variable method, compensation costs will be measured using the quoted market price of the
Companys common units on each measurement date and multiplying the compensation cost by the percentage of the vesting period served through the measurement date. Increases or decreases in the quoted market price of the common units between the
date of the grant and each measurement date will result in a change in the compensation expense recognized for the notional units.

Grants under the Executive Inducement Bonus Program

On May 1, 2009, the Company made grants of an
aggregate of 161,871 restricted common units under the Executive Inducement Bonus Program to induce four executives to become employed by the Company, with an approximate aggregate grant-date value of $500,181 based on the closing price per unit on
May 1, 2009. The units will vest 50% on January 1, 2010, and 50% on January 1, 2011.

Prior to vesting, these
restricted common units do not have the right to receive cash distributions paid by the Company on its common units. Instead, each such unvested restricted common unit carries the right to receive distribution credits when any distributions are made
by the Company on its common units. Any distribution credits will accrue and be settled in cash or common units, in the discretion of the Compensation Committee of the Companys Board of Managers, upon the vesting of the underlying restricted
common unit. As of September 30, 2009, a total of 5,612 restricted units have been issued as distribution credits by the Company.

Grants under the Long-Term Incentive Program

The Company granted approximately 163,340 restricted common unit
awards under the Long-Term Incentive Plan on August 1, 2009, to certain field employees of the Company in Alabama, Kansas, and Oklahoma. These units had a total fair market value of approximately $529,222 based on the average of the high and
low trading price of the Companys units on NYSE Arca on August 3, 2009. These service-based restricted units will vest on a three year ratable schedule beginning on August 1, 2010.

2008 Grants

Grants under the Long-Term Incentive Program

The Company granted 23,232 restricted common unit awards under
the LTIP on August 1, 2008, to certain field employees of the Company in Alabama and Oklahoma. These units had a total fair market value of approximately $425,000 based on the average of the high and low trading price of the Companys
units on NYSE Arca on the grant date. These service-based restricted units will vest on a three year ratable schedule beginning on August 1, 2009.

The Company granted 11,004 restricted common unit awards under the LTIP on March 1, 2008, to the independent, non-employee members of the Board of Managers. These units had a total fair market value
of approximately $225,000 at the grant date. These service-based restricted units vested in full on March 1, 2009.



24



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2007 Grants

Grants under the Long-Term Incentive Program

The Company granted 5,343 restricted common unit awards under the LTIP on September 14, 2007, to the independent, non-employee members of the Board of Managers. These units had a total fair market
value of approximately $225,000 at the grant date. This amount was recognized over the vesting period. These restricted common units vested in full on March 1, 2008.

14. DISTRIBUTIONS TO UNITHOLDERS

Distributions through
September 30, 2009

The Company has suspended its quarterly distributions to unitholders for the quarters ended
September 30, 2009, and June 30, 2009, to remain in compliance with the covenants associated with its reserve-based credit facilities. The distribution must remain suspended until the outstanding debt balance under its reserve-based credit
facilities is less than 90% of the Companys combined borrowing base as determined by its lenders.

On May 15, 2009,
the Company paid a distribution for the first quarter of 2009 to the unitholders of record at May 8, 2009. The distribution was paid to holders of common units and Class A units at a rate of $0.13 per unit.

On February 13, 2009, the Company paid a distribution for the fourth quarter of 2008 to the unitholders of record at February 6,
2009. The distribution was paid to holders of common units and Class A units at a rate of $0.13 per unit.

Distributions through September 30, 2008

On August 14, 2008, the Company paid a distribution for the
second quarter 2008 to the unitholders of record at August 7, 2008. The distribution was paid to holders of common units and Class A units at a rate of $0.5625 per unit.

On May 15, 2008, the Company paid a distribution for the first quarter of 2008 to the unitholders of record at May 8, 2008. The
distribution was paid to holders of common units and Class A units at a rate of $0.5625 per unit.

On February 14,
2008, the Company paid a distribution for the fourth quarter of 2007 to the unitholders of record at February 7, 2008. The distribution was paid to holders of common units and Class A units at a rate of $0.5625 per unit. A distribution of
$0.3 million was paid to the holder of the Companys Class D interests on February 14, 2008.

15. MEMBERS EQUITY

2009 Equity

At September 30, 2009, we had 454,401 Class A units and 22,265,648 Class B units outstanding, which included 177,674 unvested restricted common units issued under our Long-Term Incentive Plan
and 167,484 unvested restricted common units issued under our Executive Inducement Bonus Program.

At September 30, 2009,
we had granted 199,401 common units of the 450,000 common units available under our Long-term Incentive Plan. Of these grants, 21,727 have vested.

At September 30, 2009, we had granted 167,484 common units of the 300,000 common units available under our Executive Inducement Bonus Program. Of these grants, none have vested.

2008 Equity

At September 30, 2008, we had 447,721 Class A units and 21,938,342 Class B units outstanding, which included 34,236 restricted unvested common units.

At September 30, 2008, we had granted 39,579 units of the 450,000 units available under our Long-term Incentive Plan. Of these grants, 5,343 have vested and 34,236 are unvested.

16. SUBSEQUENT EVENTS

The
following subsequent events have occurred between October 1, 2009, and November 6, 2009:

Class D Interests

In connection with litigation related to the Torch NPI, the Company has suspended all quarterly cash contributions
with respect to the Companys Class D interests. This suspension includes the $333,333.33 quarterly cash distribution for the three months ended September 30, 2009 and $1,999,999.65 which represents the distributions that were suspended
for the quarterly periods ended June 30,



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2009, March, 31, 2009, and December 31, September 30, June 30, and March 31, 2008. The remaining undistributed amount of the Class D interests is $6.7 million.

Debt

Funds Available for Borrowing

As of November 6, 2009, the Company
reduced its outstanding debt under its reserve-based credit facilities from $220.0 million to $200.0 million in outstanding debt and has $25.0 million in remaining borrowing capacity.

As of November 6, 2009, the $200.0 million outstanding balance under our credit facilities is a current liability. We are currently in the
process of negotiating with our lenders to extend the term of our credit facilities. There can be no assurance that we will be able to extend or refinance our current credit facilities. If we were unable to extend or refinance our current credit
facilities and if we were unable to repay the outstanding debt balance when it becomes due on October 31, 2010, it would have a material adverse effect on the Company. The accompanying financial statements do not include any adjustments related to
the recoverability and classification of recorded assets or the amounts and classification of liabilities that might result from the uncertainty associated with Companys ability to meet its obligations as they come due in October 2010.

Distribution

The Board of Managers of the Company has suspended the quarterly distribution to our unitholders for the quarter ended September 30, 2009.



|Item 2. | Managements Discussion and Analysis of Financial Condition and Results of Operations
|------- | -------------------------------------------------------------------------------------

The following discussion and analysis should be read in conjunction with the financial statements and the summary of significant
accounting policies and notes included herein and in the Companys most recent Annual Report on Form 10-K.

Overview

We are a limited liability company formed by Constellation Energy Group, Inc. (Constellation) on
February 7, 2005 to acquire oil and natural gas properties (E&P properties) as well as related midstream assets. Our oil and natural gas reserves are located in the Black Warrior Basin of Alabama, in the Cherokee Basin of Kansas
and Oklahoma, and in the Woodford Shale in Oklahoma. Our primary business objective is to increase unitholder value and to generate stable cash flows allowing us to make quarterly cash distributions to our unitholders. Our strategies for achieving
this objective are to:



| |  |  | organically grow our business by increasing reserves and production through what we believe to be low-risk development drilling that focuses on capital
efficient production growth;
| | - |  | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  |  | make accretive acquisitions of E&P properties characterized by a high percentage of proved developed reserves with long-lived, stable production
and low-risk drilling opportunities, which may include associated midstream assets such as gathering systems, compression, dehydrating and treating facilities and other similar facilities;
| | - |  | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  |  | realize value by opportunistically forming partnerships, participating in farm-out arrangements, joint operating agreements or other capital-efficient
ventures to take advantage of our significant undeveloped acreage positions in the Cherokee Basin; and
| | - |  | -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  |  | reduce the volatility in our revenues resulting from changes in oil and natural gas commodity prices through efficient hedging programs.
| | - |  | ----------------------------------------------------------------------------------------------------------------------------------------

Our future oil and natural gas reserves and production and, therefore, our cash flow and income are highly
dependent on our success in efficiently developing our current reserves and economically finding, developing and acquiring additional recoverable reserves. We may not be able to find, develop or acquire additional reserves to replace our current and
future production at acceptable costs, which could materially adversely affect our business, financial condition and results of operations and our ability to pay quarterly cash distributions to our unitholders.

We also face the challenge of natural gas production declines. As a given wells initial reservoir pressures are depleted, natural gas
production decreases. We attempt to overcome this natural decline both by drilling on our properties and acquiring additional reserves. We will continue to focus on reducing our costs to add reserves through drilling, well recompletions and
acquisitions, as well as the corresponding costs necessary to produce such reserves. Our ability to add reserves through drilling is dependent on our capital resources and can be limited by many factors, including our ability to timely obtain
drilling permits and regulatory approvals. In accordance with our business plan, we intend to invest the capital necessary to maintain our production and our asset base over the long term. We will seek to maintain or grow our production and our
asset base by pursuing both organic growth opportunities and acquisitions of producing reserves that are suitable for us.

We
completed our initial public offering on November 20, 2006, and our common units, representing Class B limited liability company interests, are listed on the NYSE Arca, Inc. under the symbol CEP.

We have expanded our operations by completing the following acquisitions that we have included in our results of operations and cash flows
beginning with the period of acquisition:



| |  |  | In March 2008, we completed an acquisition of 83 non-operated producing wells located in the Woodford Shale in Oklahoma (the CoLa Assets or
CoLa Acquisition);
| | - |  | ------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  |  | In September 2007, we completed the acquisition of additional coalbed methane properties in the Cherokee Basin of Oklahoma (the Newfield
Assets or Newfield Acquisition);
| | - |  | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------



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| |  |  | In July 2007, we completed an acquisition of additional oil and natural gas properties located in the Cherokee Basin in Oklahoma (the Amvest
Acquisition); and
| | - |  | ----------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  |  | In April 2007, we completed an acquisition of oil and natural gas properties located in the Cherokee Basin in Kansas and Oklahoma (the
EnergyQuest Assets or EnergyQuest Acquisition).
| | - |  | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

These acquisitions have provided us
with the option to pursue organic growth by drilling on proved undeveloped and unproved locations primarily in Osage County, Oklahoma.

Unless the context requires otherwise, any reference in this Quarterly Report on Form 10-Q to Constellation Energy Partners, we, our, us, CEP, the successor company or
the Company means Constellation Energy Partners LLC and its subsidiaries. References in this Quarterly Report on Form 10-Q to Constellation, CCG and CEPM are to Constellation Energy Group, Inc.,
Constellation Energy Commodities Group, Inc. and Constellation Energy Partners Management, LLC, respectively.

How We Evaluate our
Operations

Non-GAAP Financial MeasureAdjusted EBITDA

We define Adjusted EBITDA as net income (loss) adjusted by:



| |  |  | interest (income) expense;
| | - |  | --------------------------



| |  |  | depreciation, depletion and amortization;
| | - |  | -----------------------------------------



| |  |  | write-off of deferred financing fees;
| | - |  | -------------------------------------



| |  |  | impairment of long-lived assets;
| | - |  | --------------------------------



| |  |  | (gain) loss on sale of assets;
| | - |  | ------------------------------



| |  |  | (gain) loss from equity investment;
| | - |  | -----------------------------------



| |  |  | unit-based compensation programs;
| | - |  | ---------------------------------



| |  |  | accretion of asset retirement obligation;
| | - |  | -----------------------------------------



| |  |  | unrealized (gain) loss on natural gas derivatives; and
| | - |  | ------------------------------------------------------



| |  |  | realized loss (gain) on cancelled natural gas derivatives.
| | - |  | ----------------------------------------------------------

Adjusted EBITDA is a significant performance metric used by our management to indicate (prior to the establishment of any cash reserves by
our board of managers) the cash distributions we expect to pay to our unitholders. Specifically, this financial measure indicates to investors whether or not we are generating cash flow at a level that can sustain or support an increase in our
quarterly distribution rates. Adjusted EBITDA is also used as a quantitative standard by our management and by external users of our financial statements such as investors, research analysts and others to assess:



| |  |  | the financial performance of our assets without regard to financing methods, capital structure or historical cost basis;
| | - |  | ------------------------------------------------------------------------------------------------------------------------



| |  |  | the ability of our assets to generate cash sufficient to pay interest costs and support our indebtedness; and
| | - |  | -------------------------------------------------------------------------------------------------------------



| |  |  | our operating performance and return on capital as compared to those of other companies in our industry, without regard to financing or capital
structure.
| | - |  | ----------------------------------------------------------------------------------------------------------------------------------------------------------

Our Adjusted EBITDA should not be considered as a substitute for net income, operating income,
cash flows from operating activities or any other measure of financial performance or liquidity presented in accordance with GAAP. Our Adjusted EBITDA excludes some, but not all, items that affect net income and operating income and these measures
may vary among other companies. Therefore, our Adjusted EBITDA may not be comparable to similarly titled measures of other companies.



27



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The following table presents a reconciliation of net income (loss) to Adjusted EBITDA, our
most directly comparable GAAP performance measure, for each of the periods presented:



|                                                  |  |                            |        |   |                           |   |         |                   |  |   |                   |   |  |   |        |  
|------------------------------------------------- |  | -------------------------- | ------ | - | ------------------------- | - | ------- | ----------------- |  | - | ----------------- | - |  | - | ------ | -
|                                                  |  | For the Three Months Ended |        |   | For the Nine Months Ended |  
|                                                  |  | September 30,2009          |        |   | September 30,2008         |   |         | September 30,2009 |  |   | September 30,2008 |  
|                                                  |  | ( In 000s)                |       
|Reconciliation of Net Income to Adjusted EBITDA:  |  |                            |        |   |                           |   |         |                   |  |   |                   |   |  |   |        |  
|Net income                                        |  | $                          | (9,101 | ) |                           | $ | 26,939  |                   |  | $ | (6,912            | ) |  | $ | 19,650 |  
|Adjusted by:                                      |  |                            |        |   |                           |   |         |                   |  |   |                   |   |  |   |        |  
|Interest expense/(income), net                    |  |                            | 3,600  |   |                           |   | 3,218   |                   |  |   | 9,719             |   |  |   | 8,596  |  
|Depreciation, depletion and amortization          |  |                            | 15,455 |   |                           |   | 11,318  |                   |  |   | 48,084            |   |  |   | 32,340 |  
|Accretion of asset retirement obligation          |  |                            | 109    |   |                           |   | 105     |                   |  |   | 267               |   |  |   | 307    |  
|(Gain)/loss on sale of assets                     |  |                            |       |   |                           |   | (85     | )                 |  |   | 14                |   |  |   | (296   | )
|(Gain)/loss on mark-to-market activities          |  |                            | 6,368  |   |                           |   | (21,976 | )                 |  |   | (829              | ) |  |   | (3,987 | )
|Unit-based compensation programs                  |  |                            | 136    |   |                           |   | 118     |                   |  |   | 288               |   |  |   | 273    |  
|Unrealized loss/(gain) on natural gas derivatives |  |                            |       |   |                           |   | (831    | )                 |  |   | 267               |   |  |   | (27    | )
|                                                  |  |                            |        |   |                           |   |         |                   |  |   |                   |   |  |   |        |  
|Adjusted EBITDA                                   |  | $                          | 16,567 |   |                           | $ | 18,806  |                   |  | $ | 50,898            |   |  | $ | 56,856 |  
|                                                  |  |                            |        |   |                           |   |         |                   |  |   |                   |   |  |   |        |  

Significant Operational Factors



| |  |  | Realized Prices.Our average realized price for the nine months ended September 30, 2009, including hedges, was $7.30 per Mcfe. This
realized price includes the impact of $0.8 million of unrealized gains on mark-to-market derivatives. Excluding the impact of the unrealized mark-to-market gains, the average realized price for the nine months ended September 30, 2009 was $7.24
per Mcfe. Further deducting the cost of sales associated with third party gathering, average realized prices were $7.08 per Mcfe including hedges and $3.39 per Mcfe excluding hedges.
| | - |  | -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  |  | Production.Our production during the first nine months of 2009 was approximately 13.0 Bcfe, or an average of 47,692 Mcfe per day.
| | - |  | ---------------------------------------------------------------------------------------------------------------------------------



| |  |  | Capital Expenditures and Drilling Results.During 2009, we spent approximately $22.8 million in cash capital expenditures primarily for
development activities in the Cherokee Basin. Our development activities were focused on completing the wells associated with our planned 2009 maintenance capital budget of approximately $30.5 million. This maintenance capital spending is intended
to maintain our production rates, reserves, and asset base. Through the first nine months of 2009, our drilling program has successfully replaced production at a rate sufficient to offset the natural decline rate from our existing properties. We now
expect our total capital expenditures for 2009 to be between $23.0 million and $25.0 million, which is below our planned maintenance capital budget of $30.5 million.
| | - |  | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

In the Black Warrior Basin, we have stopped drilling activities due to low natural gas prices and the current costs to drill and complete
wells in the Basin. We have completed 10 drilling locations at a total cost of approximately $1.2 million. These locations will be available to drill when it becomes economically favorable to do so.

In the Cherokee Basin, we drilled and completed 60 net wells and performed 17 net recompletions during the first nine months of 2009. We
drilled 1 horizontal development dry hole. As of September 30, 2009, we have 1 additional net well which requires completion. We do not expect to drill any additional wells during 2009.



| |  |  | Hedging Activities. Our hedging program uses derivatives to reduce the impact of commodity price volatility on our expected cash flows. Our
current intention is to hedge, subject to the terms of our reserve-based credit facilities, up to 80% of our forecasted production for up to a five year period. Our management, however, may modify the hedging percentages and strategies as it deems
appropriate for market conditions, the cost associated with the derivatives and other business strategies. In the first quarter of 2009, we designated all of our commodity and interest rate derivative positions that had been previously accounted for
as hedges and will now account for all of our derivatives as mark-to-market activities.
| | - |  | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

We experience
earnings volatility as a result of using the mark-to-market accounting method for all of our commodity derivatives used to hedge our exposure to changes in natural gas prices or basis differentials. This accounting treatment can cause earnings
volatility as the positions for future natural gas production are marked-to-market. These non-cash unrealized gains or losses are included in our current Statement of Operations until the derivatives are cash settled as the commodities are produced
and sold. We do not enter into speculative trading positions and we only use derivatives to lock in the future sales price for a portion of our expected natural gas production. Increases in the market price of natural gas relative to the fixed
future sales price for our hedges result in unrealized, non-cash mark-to-market losses on those derivatives and lower reported net income. Decreases in the market price of natural gas relative to the fixed future sales price for our hedges result in
unrealized, non-cash mark-to-market gains on those derivatives and higher reported net income. Although these gains and losses are required to be reported immediately in earnings as market prices change, the fair value of the related future physical
natural gas sale is not marked-to-market and therefore is not reflected as Oil and Gas Sales or as an Accounts Receivable in our financial statements. This mismatch impacts our reported Result of Operations and our reported working capital position
until the commodity derivatives are cash settled and the natural gas is produced and sold. Upon cash settlement of the derivatives, the sale of the physical commodity at then-current market prices offsets the previously reported mark-to-market gains
or losses such that the cumulative net cash realized results in a net sale of the physical natural gas production at the fixed future sales price for our hedge. When our derivative positions



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##### Table of Contents

are cash settled as the related commodities are produced and sold, the realized gains and
losses of those derivative positions are included in our Statement of Operations as Oil and Gas Sales. Further detail of our commodity derivative positions and their accounting treatment is outlined starting on page 38.

Significant Market Factors



| |  |  | Events Impacting our Sponsor. Constellation owns all of our outstanding Class A units, approximately 5.9 million Class B Common Units,
all of our Class D interests, and all of the Management Incentive Interests.
| | - |  | -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  |  | In June 2009, Constellation notified CEP that it will terminate the management services agreement effective December 15, 2009. As a result, CEP
submitted a plan to its lenders for managing its business after the termination of the agreement as required under the terms of its reserve-based credit facilities. The plan has received the requisite approval that was required under the
Companys reserve-based credit facilities.
| | - |  | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  |  | Through a series of announcements, Constellation announced that it had impaired the fair value of its investment in CEP due to various factors,
including the possible sale of its investment in CEP.
| | - |  | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  |  | In December 2008, Constellation announced an investment transaction with EDF Group subject to receipt of required regulatory approvals and other
standard closing conditions, which has not yet closed.
| | - |  | -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  |  | In August 2008, Constellation announced its intention to sell its upstream natural gas businesses Constellation subsequently announced that while
certain of its upstream gas properties were sold during 2008, it continues to evaluate the sale of its remaining upstream gas properties while monitoring market conditions to obtain appropriate value for them.
| | - |  | -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

Transition of the Executive Management Team to CEP

In January 2009, our chief executive officer, chief operating officer, and president, chief financial officer and treasurer, and chief accounting officer and controller, were transitioned from being
provided by CEPM under the management services agreement to direct employees of a subsidiary of CEP. In addition, a general counsel was appointed and transitioned from being an employee of CCG. This transition was done to better align our management
team with the interests of our unitholders and to increase their focus on our business operations. Employment letter agreements were executed with these employees and were effective January 1, 2009. The details of the letter agreements for our
chief executive officer, chief operating officer, and president and our chief financial officer and treasurer were filed as exhibits to a Current Report on Form 8-K on January 7, 2009. The details of the letter agreement for our general counsel
were filed as an exhibit to our Annual Report on Form 10-K on February 27, 2009. In May 2009, formal employment agreements were executed and one-time inducement and Long-term Incentive grants were made. The details of the employment agreements
and the inducement and Long-term Incentive grants were filed as exhibits to a Current Report on Form 8-K on May 4, 2009, and a Form 8-K/A filed on May 5, 2009.

As part of this transition, the compensation committee of the Board of Managers retained Hewitt Associates LLC to develop and review proposed compensation structures for the management team. Hewitt
benchmarked compensation and benefits from among the following list:



| |  |  | a peer group of exploration and production companies, consisting of the following: Callon Petroleum Company, Carrizo Oil & Gas Inc., Delta
Petroleum Corp., Edge Petroleum Corp., Goodrich Petroleum Corp., Legacy Reserves LP, McMoRan Exploration Company, Petroquest Energy, Inc., Rosetta Resources, Inc., Venoco, Inc., and Vanguard Natural Resources, LLC.
| | - |  | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

Hewitt proposed a compensation mix that would include a base salary, performance-based bonus awards, long-term incentives consisting of
unit-based compensation, and one-time, inducement sign-on bonuses. It also proposed to target total direct compensation for the team at competitive market median levels with a compensation mix for 2009 heavily weighted to time based compensation,
including restricted units of CEP. The total direct compensation, as approved by the compensation committee includes a base salary and bonus award payouts based on future performance on selected performance measures. The performance targets are
intended to be correlated to the creation of value for CEP unitholders and should balance growth, profitability, and efficient utilization of capital resources. The 2009 performance measures are expected to correspond to the companys 2009
business plan and may include measures that are commonly used at other comparable E&P companies. The payout against the performance targets for 2009 will be made at the discretion of the compensation committee and are intended to include a
threshold level of minimum acceptable performance, a target level of performance, and a maximum level of performance that reflects the achievement of stretch goals. The time based compensation is intended to retain the management team and align it
with the interests of the unitholders. The compensation committee did not require specific unit ownership targets for the executive officers. The overall structure and plan design to be used in 2009 should ensure alignment with our business
strategy.



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##### Table of Contents

Through September 30, 2009, seven employees and certain services have been transitioned
from being provided by CEPM under the management services agreement to CEP. By December 15, 2009, we expect that the remaining employees and services currently being provided by CEPM under the management services agreement will be transitioned
to CEP.

Results of Operations

The following table sets forth the selected financial and operating data for the periods indicated:



|                                            |  |                            |        |     |                           |   |        |          |  |   |                   |   |  |                   |    |  |          |         |     |   |   |         |     |  |   |         |   |  |        |   
|------------------------------------------- |  | -------------------------- | ------ | --- | ------------------------- | - | ------ | -------- |  | - | ----------------- | - |  | ----------------- | -- |  | -------- | ------- | --- | - | - | ------- | --- |  | - | ------- | - |  | ------ | --
|                                            |  | For the Three Months Ended |        |     | For the Nine Months Ended |  
|                                            |  | (Dollars in 000s)         |       
|                                            |  | September 30,2009          |        |     | September 30,2008         |   |        | Variance |  |   | September 30,2009 |   |  | September 30,2008 |    |  | Variance |        
|                                            |  |                            |        |     |                           |   |        | $        |  |   | %                 |   |  |                   |    |  |          |         |     | $ |   |         | %   | 
|Revenues:                                   |  |                            |        |     |                           |   |        |          |  |   |                   |   |  |                   |    |  |          |         |     |   |   |         |     |  |   |         |  
|Oil and gas sales                           |  | $                          | 30,663 |     |                           | $ | 37,674 |          |  | $ | (7,011            | ) |  | (18.6             | )% |  | $        | 94,223  |     |   | $ | 108,093 |     |  | $ | (13,870 | ) |  | (12.8  | )%
|Gain (Loss) from mark-to-market activities  |  |                            | (6,368 | )   |                           |   | 21,976 |          |  |   | (28,344           | ) |  | (129.0            | )% |  |          | 829     |     |   |   | 3,987   |     |  |   | (3,158  | ) |  | (79.2  | )%
|                                            |  |                            |        |     |                           |   |        |          |  |   |                   |   |  |                   |    |  |          |         |     |   |   |         |     |  |   |         |   |  |        |   
|Total revenues                              |  |                            | 24,295 |     |                           |   | 59,650 |          |  |   | (35,355           | ) |  | (59.3             | )% |  |          | 95,052  |     |   |   | 112,080 |     |  |   | (17,028 | ) |  | (15.2  | )%
|                                            |  |                            |        |     |                           |   |        |          |  |   |                   |   |  |                   |    |  |          |         |     |   |   |         |     |  |   |         |   |  |        |   
|Operating expenses:                         |  |                            |        |     |                           |   |        |          |  |   |                   |   |  |                   |    |  |          |         |     |   |   |         |     |  |   |         |  
|Lease operating expenses                    |  |                            | 8,169  |     |                           |   | 9,428  |          |  |   | (1,259            | ) |  | (13.4             | )% |  |          | 25,243  |     |   |   | 27,701  |     |  |   | (2,458  | ) |  | (8.9   | )%
|Cost of sales                               |  |                            | 586    |     |                           |   | 2,633  |          |  |   | (2,047            | ) |  | (77.7             | )% |  |          | 2,030   |     |   |   | 6,020   |     |  |   | (3,990  | ) |  | (66.3  | )%
|Production taxes                            |  |                            | 715    |     |                           |   | 2,241  |          |  |   | (1,526            | ) |  | (68.1             | )% |  |          | 2,245   |     |   |   | 6,791   |     |  |   | (4,546  | ) |  | (66.9  | )%
|General and administrative expenses         |  |                            | 4,844  |     |                           |   | 3,800  |          |  |   | 1,044             |   |  | 27.5              | %  |  |          | 14,491  |     |   |   | 10,922  |     |  |   | 3,569   |   |  | 32.7   | % 
|(Gain) loss on sale of asset                |  |                            |       |     |                           |   | (85    | )        |  |   | 85                |   |  | 100.0             | %  |  |          | 14      |     |   |   | (296    | )   |  |   | 310     |   |  | (104.7 | )%
|Depreciation, depletion and amortization    |  |                            | 15,455 |     |                           |   | 11,318 |          |  |   | 4,137             |   |  | 36.6              | %  |  |          | 48,084  |     |   |   | 32,340  |     |  |   | 15,744  |   |  | 48.7   | % 
|Accretion expenses                          |  |                            | 109    |     |                           |   | 105    |          |  |   | 4                 |   |  | 3.8               | %  |  |          | 267     |     |   |   | 307     |     |  |   | (40     | ) |  | (13.0  | )%
|                                            |  |                            |        |     |                           |   |        |          |  |   |                   |   |  |                   |    |  |          |         |     |   |   |         |     |  |   |         |   |  |        |   
|Total operating expenses                    |  |                            | 29,878 |     |                           |   | 29,440 |          |  |   | 438               |   |  | 1.5               | %  |  |          | 92,374  |     |   |   | 83,785  |     |  |   | 8,589   |   |  | 10.3   | % 
|Other expenses (income):                    |  |                            |        |     |                           |   |        |          |  |   |                   |   |  |                   |    |  |          |         |     |   |   |         |     |  |   |         |  
|Interest expense                            |  |                            | 3,600  |     |                           |   | 3,280  |          |  |   | 320               |   |  | 9.8               | %  |  |          | 9,721   |     |   |   | 8,942   |     |  |   | 779     |   |  | 8.7    | % 
|Interest income                             |  |                            |       |     |                           |   | (62    | )        |  |   | 62                |   |  | (100.0            | )% |  |          | (2      | )   |   |   | (346    | )   |  |   | 344     |   |  | (99.4  | )%
|Other (income) expense                      |  |                            | (82    | )   |                           |   | 53     |          |  |   | (135              | ) |  | (254.7            | )% |  |          | (129    | )   |   |   | 49      |     |  |   | (178    | ) |  | (363.3 | )%
|                                            |  |                            |        |     |                           |   |        |          |  |   |                   |   |  |                   |    |  |          |         |     |   |   |         |     |  |   |         |   |  |        |   
|Total other expenses (income)               |  |                            | 3,518  |     |                           |   | 3,271  |          |  |   | 247               |   |  | 7.6               | %  |  |          | 9,590   |     |   |   | 8,645   |     |  |   | 945     |   |  | 10.9   | % 
|                                            |  |                            |        |     |                           |   |        |          |  |   |                   |   |  |                   |    |  |          |         |     |   |   |         |     |  |   |         |   |  |        |   
|Total expenses                              |  |                            | 33,396 |     |                           |   | 32,711 |          |  |   | 685               |   |  | 2.1               | %  |  |          | 101,964 |     |   |   | 92,430  |     |  |   | 9,534   |   |  | 10.3   | % 
|                                            |  |                            |        |     |                           |   |        |          |  |   |                   |   |  |                   |    |  |          |         |     |   |   |         |     |  |   |         |   |  |        |   
|Net income (loss)                           |  | $                          | (9,101 | )   |                           | $ | 26,939 |          |  | $ | (36,040           | ) |  | (133.8            | )% |  | $        | (6,912  | )   |   | $ | 19,650  |     |  | $ | (26,562 | ) |  | (135.2 | )%
|                                            |  |                            |        |     |                           |   |        |          |  |   |                   |   |  |                   |    |  |          |         |     |   |   |         |     |  |   |         |   |  |        |   
|Net production:                             |  |                            |        |     |                           |   |        |          |  |   |                   |   |  |                   |    |  |          |         |     |   |   |         |     |  |   |         |  
|Total production (MMcfe)                    |  |                            | 4,414  |     |                           |   | 4,477  |          |  |   | (63               | ) |  | (1.4              | )% |  |          | 13,020  |     |   |   | 12,942  |     |  |   | 78      |   |  | 0.6    | % 
|Average daily production (Mcfe/d)           |  |                            | 47,978 |     |                           |   | 48,663 |          |  |   | (685              | ) |  | (1.4              | )% |  |          | 47,692  |     |   |   | 47,234  |     |  |   | 458     |   |  | 1.0    | % 
|Average sales prices:                       |  |                            |        |     |                           |   |        |          |  |   |                   |   |  |                   |    |  |          |         |     |   |   |         |     |  |   |         |  
|Price per Mcfe includinghedges(a)           |  | $                          | 5.50   | (a) |                           | $ | 13.32  | (a)      |  | $ | (7.82             | ) |  | (58.7             | )% |  | $        | 7.30    | (a) |   | $ | 8.66    | (a) |  | $ | (1.36   | ) |  | (15.7  | )%
|Price per Mcfe excluding hedges             |  | $                          | 3.31   |     |                           | $ | 9.32   |          |  | $ | (6.01             | ) |  | (64.5             | )% |  | $        | 3.55    |     |   | $ | 9.26    |     |  | $ | (5.71   | ) |  | (61.7  | )%
|Average unit costs per Mcfe:                |  |                            |        |     |                           |   |        |          |  |   |                   |   |  |                   |    |  |          |         |     |   |   |         |     |  |   |         |  
|Field operating expenses(b)                 |  | $                          | 2.01   |     |                           | $ | 2.61   |          |  | $ | (0.60             | ) |  | (22.9             | )% |  | $        | 2.11    |     |   | $ | 2.67    |     |  | $ | (0.56   | ) |  | (20.9  | )%
|Lease operating expenses                    |  | $                          | 1.85   |     |                           | $ | 2.11   |          |  | $ | (0.26             | ) |  | (12.3             | )% |  | $        | 1.94    |     |   | $ | 2.14    |     |  | $ | (0.20   | ) |  | (9.4   | )%
|Production taxes                            |  | $                          | 0.16   |     |                           | $ | 0.50   |          |  | $ | (0.34             | ) |  | (68.0             | )% |  | $        | 0.17    |     |   | $ | 0.52    |     |  | $ | (0.35   | ) |  | (67.3  | )%
|General and administrative expenses         |  | $                          | 1.10   |     |                           | $ | 0.85   |          |  | $ | 0.25              |   |  | 29.4              | %  |  | $        | 1.11    |     |   | $ | 0.84    |     |  | $ | 0.27    |   |  | 32.1   | % 
|Depreciation, depletion and amortization(c) |  | $                          | 3.50   |     |                           | $ | 2.53   |          |  | $ | 0.97              |   |  | 38.3              | %  |  | $        | 3.69    |     |   | $ | 2.50    |     |  | $ | 1.19    |   |  | 47.6   | % 



|(a) | Price per Mcfe including hedges includes realized and unrealized mark-to-market gains on derivative transactions that did not qualify for hedge
accounting treatment.
|--- | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------

|(b) | Field operating expenses include lease operating expenses and production taxes.
|--- | -------------------------------------------------------------------------------



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|(c) | Depreciation, depletion and amortization includes non-cash impairments of oil and natural gas assets. Excluding impairments, the three months ended
September 30, 2009 cost per Mcfe was $3.45 and $3.37 per Mcfe for the nine months ended September 30, 2009.
|--- | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

Three months ended September 30, 2009 compared to three months September 30, 2008

Oil and
natural gas sales. Oil and natural gas sales decreased $7.0 million, or 18.6%, to $30.7 million for the three months ended September 30, 2009 as compared to $37.7 million for the same period in 2008. Of this decrease, $0.6 million was
attributable to decreased production volumes and $26.5 million was attributable to lower market prices for oil and natural gas, offset by $20.1 million in gains from our hedging program. Production for the three months ended September 30, 2009
was 4.4 Bcfe, which was essentially level with the same period in 2008. Natural declines in production in the Black Warrior Basin and in the Woodford Shale were offset by slightly increased production of less than 0.1 Bcfe due to our drilling
programs in the Cherokee Basin. Our 2008 and 2009 maintenance drilling program has continued to offset the natural decline rate of production associated with our existing wells during the quarter. This offset is not expected to continue as we have
stopped our maintenance capital spending during the second half of 2009. We hedged approximately 75% of our actual production during the third quarter of 2009 and approximately 88% of our actual production during the same period in 2008.

As discussed below, the loss from our unrealized non-cash mark-to-market activities increased $28.3 million for the three months
ended September 30, 2009, as compared to the same period in 2008. Our realized prices before our hedging program decreased from 2009 to 2008 primarily due to significantly lower market prices for oil and natural gas. This was offset by our
hedging program and the mark-to-market gains discussed below.

Hedging and mark-to-market activities. As of
September 30, 2009, all of our swaps, put option, and basis swaps were accounted for as mark-to-market derivatives. For the three months ended September 30, 2009, the unrealized non-cash mark-to-market loss was approximately $6.4 million
as compared to an unrealized non-cash $21.9 million gain for the same period in 2008. This 2009 non-cash loss represents approximately $6.7 million from the impact of higher expected future natural gas prices on these derivative transactions that
are being accounted for as mark-to-market activities offset by a $0.3 million increase for non-performance risk related to our counterparties.

Prior to the first quarter 2009, we entered into cash flow hedges in an effort to reduce our exposure to fluctuations in natural gas prices. For the three months ended September 30, 2008, we
recognized a gain of approximately $0.8 million related to hedge ineffectiveness.

Cash settlements of hedges were received
for our commodity derivatives of approximately $16.0 million for the three months ended September 30, 2009. Cash settlements of hedges were received for our commodity derivatives of approximately $4.9 million for the three months ended
September 30, 2008. This difference is primarily due to significantly lower market prices for natural gas during 2009.

Field operating expenses. Our field operating expenses generally consist of lease operating expenses, labor, vehicle, supervision, transportation, minor maintenance, tools and supplies expenses, as well as production and ad valorem
taxes.

For the three months ended September 30, 2009, lease operating expenses decreased $1.3 million, or 13.4%, to $8.2
million, compared to expenses of $9.4 million for the same period in 2008. This decrease in lease operating expenses is primarily related to $0.7 million in lower total spending in the Cherokee Basin, $0.2 million in lower total spending in the
Black Warrior Basin, and $0.4 million in lower total spending in the Woodford Shale. This total lower spending reflects our focus on reducing expenses and lower overall oilfield service costs. By category, our lease operating expenses were lower in
2009 as compared to 2008 by $1.3 million because of a $0.5 million decrease in well servicing costs, a $0.4 million decrease in costs for our non-operated Woodford Shale properties, a $0.3 million decrease in road and lease maintenance, and a $0.1
million decrease in vehicle expense including gasoline costs.

For the three months ended September 30, 2009, per
unit lease operating expenses were $2.01 per Mcfe compared to $2.61 per Mcfe for the same period in 2008. This decrease is attributable to a decrease in total spending of approximately 13.4% in 2009 as compared the same period in 2008 with
essentially the same level of production in 2009 as compared to the same period in 2008. Our per unit operating costs decreased approximately 13% in the Cherokee Basin from $2.40 per Mcfe in 2008 to $2.10 per Mcfe in 2009 as a result of $0.7 million
in lower total spending and an increase in production volumes of approximately 0.1 Bcfe.

For the three months ended
September 30, 2009, production taxes decreased $1.5 million, or 68.1%, to $0.7 million, compared to expenses of $2.2 million for the same period in 2008. This decrease was primarily the result of significantly lower market prices for oil and
natural gas in 2009 and the impact of production tax credits of approximately $0.3 million.



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Cost of sales.For the three months ended September 30, 2009, cost of sales
decreased by $2.0 million, or 77.7%, to $0.6 million, compared to $2.6 million for the same period in 2008. This represents the cost of purchased natural gas in the Cherokee Basin and was impacted by lower natural gas prices as these costs are tied
to natural gas prices in the Mid-continent region.

General and administrative expenses. General and administrative
expenses include the costs of our employees, related benefits, field office expenses, professional fees, costs billed by CEPM under our management services agreement and other costs not directly associated with field operations.

General and administrative expenses increased $1.0 million, or 27.5%, to $4.8 million for the three months ended September 30, 2009, as
compared to $3.8 million for the same period in 2008. Our general and administrative expenses were higher in 2009 as compared to 2008 because of $1.7 million in labor costs and an additional $0.5 million in administrative costs in Tulsa, offset by
$0.6 million in lower CEPM charges for labor, $0.3 million in legal fees primarily associated with the Torch litigation, $0.4 million in lower professional services and consultants, and $0.1 million in exploration expense. For the three months ended
September 30, 2009 and 2008, CEPM allocated $0.2 million and $0.8 million, respectively, in expenses to us for labor and other charges through the management services agreement.

Our per unit costs were $1.10 per Mcfe for the three months ended September 30, 2009 compared to $0.85 per Mcfe for the same period in
2008. This increase is attributable to an increase in total spending of approximately $1.0 million. This increased level of spending is expected to continue in 2009 as services continue to be transitioned from being provided by CEPM under the
management services agreement to CEP.

Depreciation, depletion and amortization expense. Depreciation, depletion and
amortization expenses include the depreciation, depletion and amortization of acquisition costs and equipment costs. Depletion is calculated using units-of-production. Assuming everything else remains unchanged, as natural gas production changes,
depletion would change in the same direction.

Our depreciation, depletion and amortization expense for the three months ended
September 30, 2009 was $15.4 million, or $3.48 per Mcfe, compared to $11.3 million, or $2.53 per Mcfe, for the same period in 2008. This increase in 2009 depreciation, depletion, and amortization reflects the increased basis in our assets
resulting from the cost of our asset acquisitions in the Woodford Shale, additional capital expenditures for our development drilling programs in the Cherokee Basin, a lower year-end 2008 reserve base primarily due to price-related reserve
revisions, an impairment of $0.1 million for certain of our wells in the Woodford Shale partially offset by a 0.2 Bcfe decrease in production volumes in the Woodford Shale during 2009 as compared to 2008. The impairment was primarily caused by the
impact of lower natural gas prices on estimated future cash flows for the Woodford Shale wells. During 2009, we impaired $0.1 million in obsolete inventory. We calculate depletion using units-of-production under the successful efforts method of
accounting except for our other assets which are depreciated using the straight line basis.

Interest expense. Interest
expense for the three months ended September 30, 2009 increased $0.3 million to $3.6 million as compared to approximately $3.3 million in interest expense for same period in 2008. This increase was primarily due to $0.7 million in non-cash
mark-to-market losses on our interest rate swaps that are accounted for as market-to-market activities. This increase was offset by lower market interest rates of $1.3 million, lower capitalized interest of $0.1 million, and higher swap settlements
of $0.8 million during 2009 as compared to the same period in 2008. Our capitalized interest decreased from 2008 to 2009 due to lower capital spending in 2009. Our borrowings under our reserve-based credit facilities increased in 2009 as compared to
the same period in 2008 to finance capital expenditures and working capital needs. At September 30, 2009, we had an outstanding balance under our credit facilities of $220.0 million as compared to $216.0 million at September 30, 2008.

Interest income. Interest income for the three months ended September 30, 2009 decreased less than $0.1 million
to zero as compared to less than $0.1 million in interest income for same period in 2008. During 2008, we earned interest income by utilizing overnight investments on our excess cash balances. In 2009, we discontinued our overnight investments to
participate in a program sponsored by the FDICs Transaction Account Guarantee Program to provide unlimited insurance coverage for transaction account balances that do not earn interest. This program is currently available until
December 31, 2009.

Accumulated other comprehensive income. Accumulated other comprehensive income, shown on our
consolidated balance sheets, reflects the changes in the fair market value of our open hedge positions. At September 30, 2009, the balance was an unrealized gain of $36.8 million compared to an unrealized gain of $50.1 million at
December 31, 2008. This decrease reflects the settlements during the third quarter of 2009 related to amounts previously included in locked accumulated other comprehensive income associated with our hedging positions previously accounted for as
cash flow hedges. All of our derivative positions are now accounted for as mark-to-market activities and the remaining balance in accumulated other comprehensive income will be amortized to earnings as the positions settle in the future.

The change in Accumulated other comprehensive income (loss) is shown in our consolidated statements of operations and comprehensive
income (loss) as an unrealized loss of $9.7 million for the three months ended September 30, 2009, and as an unrealized gain of $145.9 million for the same period in 2008. This change is primarily due to the impact of the amortization of locked



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accumulated other comprehensive income as we realize an offsetting gain upon the physical sale of natural gas production for which third quarter 2009 hedges have fixed the future sales price.

Nine months ended September 30, 2009 compared to the nine months ended September 30, 2008

Oil and natural gas sales.Oil and natural gas sales decreased $13.9 million, or 12.8%, to $94.2 million for the nine months ended
September 30, 2009 as compared to $108.0 million for the same period in 2008. Of this decrease, $74.3 million in significantly lower market prices for oil and natural gas, was offset by $0.7 million attributable to increased production volumes
and $59.7 million in gains from our hedging program. Production for the nine months ended September 30, 2009 was 13.0 Bcfe, which was 0.1 Bcfe higher than the same period in 2008. This increase is due to our drilling and workover programs in
the Cherokee Basin which increased our production in the basin by 0.2 Bcfe. Our 2008 and 2009 maintenance drilling program has substantially offset the natural decline rate of production associated with our existing wells. Our production in the
Black Warrior Basin decreased 0.1 Bcfe due to natural declines as no new drilling in the field has occurred since 2008. Production in the Woodford Shale was level with last year even though this acquisition closed March 31, 2008. We hedged
approximately 79% of our actual production during the first nine months of 2009 and approximately 91% of our actual production during the same period in 2008.

As discussed below, the loss from our unrealized non-cash mark-to-market activities increased $3.2 million for the nine months ended September 30, 2009, as compared to the same period in 2008.
Our realized prices before our hedging program decreased from 2009 to 2008 primarily due to significantly lower market prices for oil and natural gas. This was offset by our hedging program and the mark-to-market gains discussed below.

Hedging and mark-to-market activities.As of September 30, 2009, all of our swaps, put option, and basis swaps are accounted
for as mark-to-market derivatives. For the nine months ended September 30, 2009, the unrealized non-cash mark-to-market gain was approximately $0.8 million as compared to an unrealized non-cash $4.0 million gain for the same period in 2008.
This 2009 non-cash gain represents approximately $1.2 million from the impact of lower expected future natural gas prices on these derivative transactions that are being accounted for as mark-to-market activities and a $0.4 million increase for
non-performance risk related to our counterparties.

Prior to the first quarter 2009, we entered into cash flow hedges in an
effort to reduce our exposure to fluctuations in natural gas prices. For the nine months ended September 30, 2009, we recognized a loss of approximately $0.3 million related to hedge ineffectiveness. For the nine months ended September 30,
2008, we recognized a gain of less than $0.1 million related to hedge ineffectiveness.

Cash settlements of hedges were
received for our commodity derivatives of approximately $48.3 million for the nine months ended September 30, 2009. Cash settlements of hedges were paid for our commodity derivatives of approximately $11.7 million for the nine months ended
September 30, 2008. This difference is primarily due to significantly lower market prices for natural gas during 2009.

Field operating expenses. Our field operating expenses generally consist of lease operating expenses, labor, vehicle, supervision, transportation, minor maintenance, tools and supplies expenses, as well as production and ad valorem
taxes.

For the nine months ended September 30, 2009, lease operating expenses decreased $2.5 million, or 8.9%, to $25.2
million, compared to expenses of $27.7 million for the nine months ended September 30, 2008. By category, our lease operating expenses were lower in the nine months ended September 30, 2009, as compared to the nine months ended
September 30, 2008, because of a $1.4 million decrease in well servicing costs, $0.7 million decrease in field reorganization expenses in Tulsa, $0.3 million decrease in contract labor, and $0.1 million decrease in incremental expenses
associated with the Dewey office fire.

For the nine months ended September 30, 2009, per unit lease operating
expenses were $1.94 per Mcfe compared to $2.14 per Mcfe for the nine months ended September 30, 2008. Our per unit costs decreased in 2009 as compared to the same period in 2008 because of approximately 0.1 Bcfe of increased production in 2009
and fewer weather-related and specific field office events that occurred in the Cherokee Basin in 2008. During the nine months ended September 30, 2008, the weather-related and specific field office events impacting our lease operating expenses
in the Cherokee Basin were $0.5 million in repair costs to restore production after a significant winter ice storm in Oklahoma, $0.8 million of field reorganization expenses in Tulsa, $0.3 million in costs associated with the final Newfield
settlement under the transition services agreement, and $0.1 million in incremental expenses associated with the Dewey office fire, surface damages, shut-in payments, and environmental costs.

For the nine months ended September 30, 2009, production taxes decreased $4.6 million, or 66.9%, to $2.2 million, compared to expenses
of $6.8 million for the nine months ended September 30, 2008. This decrease was primarily the result of significantly lower market prices for oil and natural gas in 2009, the impact of production tax credits of approximately $0.3 million, and
by the impact of production taxes on approximately 0.1 Bcfe in higher production in Oklahoma.



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Cost of Sales.For the nine months ended September 30, 2009, cost of sales
decreased by $4.0 million, or 66.3%, to $2.0 million, compared to $6.0 million for the same period in 2008. This represents the cost of purchased natural gas in the Cherokee Basin and was impacted by lower natural gas prices as these costs are tied
to natural gas prices in the Mid-continent region.

General and administrative expenses. General and administrative
expenses include the costs of our employees, related benefits, field office expenses, professional fees, costs billed by CEPM under our management services agreement and other costs not directly associated with field operations. General and
administrative expenses increased $3.6 million, or 32.7%, to $14.5 million for the nine months ended September 30, 2009, as compared to $10.9 million for the nine months ended September 30, 2008. This increase was primarily due to costs
associated with transitioning services from CEPM to CEP. Our general and administrative expenses were higher in the nine months ended September 30, 2009, as compared to the nine months ended September 30, 2008, because of $4.9 million in
higher labor, bonus, benefits, and unit-based compensation, $0.3 million in exploration expenses, $0.2 million in insurance, offset by $0.8 million in lower allocations from CEPM, $0.7 million in legal fees, $0.2 million in audit and tax fees, and
$0.1 million in professional services including reservoir engineering. For the nine months ended September 30, 2009 and 2008, CEPM allocated $1.2 million and $1.9 million, respectively, in expenses to us for labor and other charges.

Our per unit costs were $1.11 per Mcfe for the nine months ended September 30, 2009 compared to $0.84 per Mcfe for the nine months
ended September 30, 2008. This increase is attributable to an increase in total spending of approximately $3.6 million offset by 0.1 Bcfe in higher production. This level of spending is expected to continue in 2009 as services continue to be
transitioned from being provided by CEPM under the management services agreement to CEP.

Gain/loss on sale of asset.Our gain/loss on the sale of assets decreased $0.3 million, or 104.7%, to less than a $0.1 million loss for the nine months ended September 30, 2009, as compared to a gain of $0.3 million for the same period in 2008. In 2009, we sold
surplus equipment at loss of less than $0.1 million. In 2008, a fire damaged our field office located in Dewey, Oklahoma. A gain of $0.2 million was recorded for the involuntary conversion as the insurance proceeds of $0.4 million exceeded the $0.2
million book value of the building.

Depreciation, depletion and amortization expense. Depreciation, depletion and
amortization expenses include the depreciation, depletion and amortization of acquisition costs and equipment costs.

Our
depreciation, depletion and amortization expense for the nine months ended September 30, 2009 was $48.0 million, or $3.69 per Mcfe, compared to $32.3 million, or $2.50 per Mcfe, for the same period in 2008. This increase in 2009 depreciation,
depletion, and amortization reflects the increased basis in our assets resulting from the cost of our asset acquisitions in the Woodford Shale, additional capital expenditures for our development drilling programs, a lower year-end 2008 reserve base
primarily due to price-related reserve revisions, an impairment of $4.1 million for certain of our wells in the Woodford Shale, and an impairment of obsolete inventory of $0.1 million, offset by a 0.2 Bcfe increase in production volumes in the
Cherokee Basin during 2009 as compared to 2008. The impairment was primarily caused by the impact of lower natural gas prices on estimated future cash flows for the Woodford Shale wells. We calculate depletion using units-of-production under the
successful efforts method of accounting except for our other assets which are depreciated using the straight line basis.

Interest expense. Interest expense for the nine months ended September 30, 2009 increased $0.8 million to $9.7 million as compared to approximately $8.9 million in interest expense for the nine months ended September 30,
2008. This increase was primarily due to $1.6 million in non-cash mark-to-market losses on our interest rate swaps that are accounted for as market-to-market activities. This increase was offset by lower market interest rates of $3.2 million, higher
swap settlements of $2.2 million, and lower capitalized interest of $0.2 million during 2009 as compared to the same period in 2008. Our borrowings under our reserve-based credit facilities increased in 2009 as compared to the same period in 2008 to
finance capital expenditures and working capital needs. At September 30, 2009, we had an outstanding balance under our credit facilities of $220.0 million as compared to $216.0 million at September 30, 2008. The average interest rate on
our outstanding debt was approximately 5.2% in 2009. Our capitalized interest decreased from 2008 to 2009 due to lower capital spending in 2009.

Interest income.Interest income for the nine months ended September 30, 2009 decreased $0.3 million to less than $0.1 million as compared to approximately $0.3 million in interest income for
same period in 2008. During the nine months ended September 30, 2008, we earned interest income by utilizing overnight investments on our excess cash balances. In 2009, we discontinued our overnight investments to participate in a program
sponsored by the FDICs Transaction Account Guarantee Program to provide unlimited insurance coverage for transaction account balances that do not earn interest. This program is currently available until December 31, 2009. In March 2008,
we received $0.1 million in interest on payment balances from receivables related to the sales of natural gas included in the Torch NPI escrow account. Effective with the termination of the Trust, the escrow account arrangement also terminated and
all payments for natural gas sales were directly received by us.

Accumulated other comprehensive income.
The change in Accumulated other comprehensive income (loss) is shown in our consolidated statements of operations and comprehensive income (loss) as an unrealized loss of $13.3 million for the nine months ended September 30, 2009, and as an
unrealized gain of $2.8 million for the nine months ended September 30, 2008. This change is



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primarily due to the impact of the decrease in expected future market prices for natural gas on our outstanding commodity derivatives accounted for as cash flow hedges and the impact of the
amortization of locked accumulated other comprehensive income as we realize an offsetting gain upon the physical sale of natural gas production for which third quarter 2009 hedges have fixed the future sales price.

Liquidity and Capital Resources

During 2009, we utilized our cash flow from operations as our primary source of capital. Our primary use of capital during 2009 has been for the development of existing oil and natural gas properties in
the Cherokee Basin and the retirement of outstanding debt. As we pursue our business plans, we will be monitoring the capital resources available to us to meet our future financial obligations and planned capital expenditures. Our future success in
growing reserves and production will be highly dependent on the capital resources available to us and our success in drilling for or acquiring additional reserves and managing the costs associated with our operations. Our results will not be fully
impacted by significant increases or decreases in natural gas prices because of our hedging program, which is further discussed on page 38. Based upon our current business plan, we expect to generate operating cash flows in excess of our
working capital needs. We expect no further 2009 maintenance or investment capital expenditures as we have completed our 2009 drilling program. For the immediate future, we intend for our excess cash flow to be used to further reduce our debt
levels.

Our reserve-based credit facilities currently provide only limited availability to finance future maintenance capital
expenditures and other working capital needs. As of November 6, 2009, our total borrowing base under our reserve-based credit facilities was $225.0 million. At November 6, 2009, we had $200.0 million of debt outstanding under the
reserve-based credit facilities and $25.0 million in unused borrowing capacity. Since our outstanding debt balance under our credit facilities exceeded 90% of our borrowing base at September 30, 2009, we were restricted from making cash
distributions to our unitholders. Our credit facilities mature in October 2010. In the first quarter of 2008, we filed a shelf registration statement with the SEC to register up to $1.0 billion of debt or equity securities to fund future expansion
capital expenditures. This registration statement expires January 30, 2010. There is no guarantee that securities can or will be issued under the registration statement. Based on current financial market conditions and market prices for oil and
natural gas, we expect capital markets to remain constrained which will make issuing additional debt or equity securities difficult or not possible at all. Our current credit facilities are also subject to future borrowing base redeterminations and
will have to be renewed or replaced before its maturity in October 2010.

For the remainder of 2009 and for 2010, we expect to
fund our working capital needs and any maintenance capital expenditures with cash flow from operations. Our current expectation is that we will manage our business to operate within the cash flows that are generated. Any available surplus cash may
be used to reduce our debt levels. In response to low natural gas prices, we have stopped all drilling activities in the Black Warrior Basin and have completed all of our 2009 drilling activities in the Cherokee Basin. We expect that the suspension
of our quarterly distribution and the reduction in our total planned capital expenditures will provide additional liquidity to fund our operations and to pay down debt. Through November 6, 2009, we have successfully reduced our outstanding debt
balances from $220.0 million to $200.0 million. Our future quarterly distribution to unitholders cannot be made when our outstanding debt balance is more than 90% of our borrowing base as determined by our lenders. We are subject to additional
future borrowing base redeterminations and cannot forecast at what level our lenders will set our future borrowing base. However, after our outstanding debt balance is less than 90% of our borrowing base as determined by our lenders and at such time
we are able to resume maintenance capital expenditures, we will evaluate the resumption of our quarterly distribution to unitholders. We anticipate that our distribution will remain suspended until our debt levels are reduced and we resume capital
spending at maintenance levels. Any future quarterly distributions must be approved by our Board of Managers.

Reserve-Based Credit
Facilities

On March 28, 2008, we entered into a new $500.0 million secured credit facility with The Royal Bank of
Scotland as administrative agent and a syndicate of lenders. The amount available for borrowing at any one time under the Credit Facility is limited to the borrowing base for our properties other than in the State of Alabama. As of
September 30, 2009, the borrowing base for this Credit Facility is $115.0 million. On March 28, 2008, we also amended and restated our existing $200.0 million credit facility by entering into an amended and restated credit agreement with
The Royal Bank of Scotland as administrative agent and a syndicate of lenders. The amount available for borrowing at any one time under the Amended and Restated Credit Facility is limited to the borrowing base for our properties in the State of
Alabama. As of September 30, 2009, the borrowing base on the Amended and Restated Credit Facility is $110.0 million. Both of our credit facilities will mature on October 31, 2010 and the $200.0 million due under these facilities became a
current liability on October 31, 2009. We will need to renew or replace these credit facilities prior to their maturity date. There is no guarantee that we will be able to renew these facilities. Even if we do renew or replace these facilities,
it may not be possible to do so with similar borrowing costs, terms, or covenants or at the same borrowing base.

As of
November 6, 2009, we had $200.0 million in debt outstanding under these two credit facilities. The amount available for borrowing at any one time is limited to the borrowing base under each facility. The borrowing base is re-determined
semi-annually, and may be re-determined at our request more frequently and by the lenders in their sole discretion based on reserve reports prepared



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by reserve engineers, together with, among other things, the oil and natural gas prices at such time. Any increase in the borrowing base will have to be approved by all of the lenders in the
syndicate and any decrease in the borrowing base will have to be approved by lenders holding at least 662/3% of the commitments. Our aggregate borrowing base of $225.0 million may be redetermined again prior to the maturity of the two credit facilities in October 2010. It is possible that our
borrowing base could decrease because of lower oil and natural gas prices or other factors.

Our reserve-based credit
facilities contain similar commercial terms with the same lenders participating in the same applicable percentages. The current lenders and their percentage commitments in the two facilities are: The Royal Bank of Scotland (23.32%), BNP Paribas
(22.55%), Wachovia Bank, N.A. (14.55%), Bank of Nova Scotia (17.00%), Calyon (15.05%), and Societe Generale (7.53%). A cross-default feature provides that an event of default under one agreement constitutes an event of default under the other. Our
obligations under our credit facilities are secured by mortgages on our natural gas properties, as well as a pledge of all ownership interests in our subsidiaries. We are required to maintain the mortgages on properties representing at least 85% of
our proved producing and proved non-producing reserves. Additionally, the obligations under the credit facilities are guaranteed by all of our operating subsidiaries and any future material subsidiaries.

Borrowings under our credit facilities are available to us for acquisition, exploration, operation and maintenance of oil and natural gas
properties, payment of expenses incurred in connection with the credit facility, working capital and general limited liability company purposes. A sub-limit of $20.0 million of the facility applies for letters of credit.

At our election, interest will be determined by reference to:



| |  |  | LIBOR plus an applicable margin between 1.25% and 2.00% per annum based on utilization; or
| | - |  | ------------------------------------------------------------------------------------------



| |  |  | a domestic bank rate plus an applicable margin between 0.25% and 1.00% per annum based on utilization.
| | - |  | ------------------------------------------------------------------------------------------------------

Interest will generally be payable quarterly for domestic bank rate loans and at the applicable maturity date for LIBOR loans.

Our credit facilities contain various covenants that limit our ability to:



| |  |  | incur indebtedness;
| | - |  | -------------------



| |  |  | grant certain liens;
| | - |  | --------------------



| |  |  | make certain loans, acquisitions, capital expenditures and investments;
| | - |  | -----------------------------------------------------------------------



| |  |  | make distributions other than from available cash;
| | - |  | --------------------------------------------------



| |  |  | merge or consolidate; or
| | - |  | ------------------------



| |  |  | engage in certain asset dispositions, including a sale of all or substantially all of our assets.
| | - |  | -------------------------------------------------------------------------------------------------

Our credit facilities also contain covenants that, among other things, require us to maintain specified ratios or conditions as follows:



| |  |  | debt to Adjusted EBITDA (defined as, for any period, the sum of consolidated net income for such period plus the following expenses or charges to the
extent deducted from consolidated net income in such period: interest expense, depreciation, depletion, amortization, write-off of deferred financing fees, impairment of long-lived assets, (gain) loss on sale of assets, (gain) loss from equity
investment, accretion of asset retirement obligation, unrealized (gain) loss on natural gas derivatives and realized (gain) loss on cancelled natural gas derivatives, and other similar charges) of not greater than 3.5 to 1.0; and
| | - |  | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  |  | Adjusted EBITDA to cash interest expense of not less than 2.5 to 1.0; and
| | - |  | -------------------------------------------------------------------------



| |  |  | consolidated current assets, including the unused amount of the total commitments but excluding current non-cash assets, to consolidated current
liabilities, excluding non-cash liabilities and current maturities of debt obligations under the credit facilities, of not less than 1.0 to 1.0, all calculated pursuant to the requirements under Statement of Financial Accounting Standards
(SFAS) 133 and SFAS 143 (including the current liabilities in respect of the termination of natural gas and interest rate swaps).
| | - |  | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

A failure to maintain the foregoing ratios could result in an acceleration of any indebtedness in excess of $1.0 million and would constitute an event of default that would prohibit us from making
distributions.

We have the ability to borrow under our credit facilities to pay distributions to unitholders as long as there
has not been a default or event of default and if the amount of borrowings outstanding under our credit facilities is less than 90% of the borrowing base. As of September 30, 2009, our amount of borrowings outstanding under our credit
facilities is greater than 90% of the borrowing base so that no cash distributions could be made to our unitholders.



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If an event of default exists under our credit facilities, the lenders will be able to
accelerate the maturity of the credit facility and exercise other customary rights and remedies. Each of the following is an event of default:



| |  |  | failure to pay any principal when due or any interest, fees or other amount within certain grace periods;
| | - |  | ---------------------------------------------------------------------------------------------------------



| |  |  | a representation or warranty made under the loan documents or in any report or other instrument furnished there under is incorrect when made; and
| | - |  | -------------------------------------------------------------------------------------------------------------------------------------------------



| |  |  | failure to perform or otherwise comply with the covenants in the credit facility or other loan documents, subject, in certain instances, to certain
grace periods, which include but are not limited to covenants that:
| | - |  | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  |  | Constellation and its affiliates maintain the right to elect our Class A Managers; and
| | - |  | --------------------------------------------------------------------------------------



| |  |  | we obtain the approval of the administrative agent (such approval not to be unreasonably withheld or delayed) of any management services plan upon the
termination of the management services agreement with CEPM;
| | - |  | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  |  | any event occurs that permits or causes the acceleration of the indebtedness;
| | - |  | -----------------------------------------------------------------------------



| |  |  | bankruptcy or insolvency events involving us or our subsidiaries;
| | - |  | -----------------------------------------------------------------



| |  |  | the entry of, and failure to pay, one or more adverse judgments in excess of $1.0 million or one or more non-monetary judgments that could reasonably
be expected to have a material adverse effect and for which enforcement proceedings are brought or that are not stayed pending appeal;
| | - |  | --------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  |  | specified events relating to our employee benefit plans that could reasonably be expected to result in liabilities in excess of $1.0 million in any
year; and
| | - |  | -------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  |  | a change of control, generally defined as the first date on which both of the following two conditions occur: (i) a decrease by CEPH and CEPM of
their combined ownership of our outstanding membership interests to less than 20%, and (ii) the ownership by any person (other than a wholly-owned subsidiary of Constellation) of more than 35% of our outstanding membership interests.
| | - |  | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

The reserve-based credit facilities contain a condition to borrowing and a representation that no material
adverse effect (MAE) has occurred, which includes, among other things, a material adverse change in, or material adverse effect on the business, operations, property, liabilities (actual or contingent) or condition (financial or
otherwise) of the Company and its subsidiaries who are guarantors taken as a whole. If a MAE were to occur, we would be prohibited from borrowing under the facilities and we would be in default under the facilities, which could cause all of our
existing indebtedness to become immediately due and payable.

Our reserve-based credit facilities mature in October 2010 and,
as a result, amounts due under the facilities became a current liability in October 2009. To date, we have not entered into an agreement to refinance or extend the due date on the reserve-based credit facilities. We may not be able to renew or
replace the facilities at similar borrowing costs, terms, covenants, restrictions, or borrowing base, or with similar debt issue costs. In addition, we do not believe that our forecasted cash flow will be sufficient to meet the principal payment
that would be required on our outstanding debt balance as it comes due on October 31, 2010 unless we are able to successfully refinance our outstanding debt, extend the due date on our current credit facilities or sell assets. Our inability to
refinance our outstanding debt would have a material adverse effect on the Company.

At September 30, 2009, CEP believes
that it was in compliance with the debt covenants contained in its credit facilities. As of September 30, 2009, the actual debt to Adjusted EBITDA ratio was 3.2 to 1.0 as compared with a required ratio of not greater than 3.5 to 1.0, the actual
ratio of current assets to current liabilities was 2.5 to 1.0 as compared with a required ratio of not less than 1.0 to 1.0, and the actual Adjusted EBITDA to cash interest expense ratio was 12.2 to 1.0 as compared with a required ratio of not less
than 2.5 to 1.0.

If CEP is unable to remain in compliance with the debt covenants associated with its reserve-based credit
facilities or maintain the required ratios discussed above, CEP could request waivers from the lenders in its bank group. Although the lenders may not provide a waiver, CEP may take additional steps in the event of not meeting the required ratios or
in the event of a reduction in the combined borrowing base below its current level of $225.0 million at the future redetermination by the lenders. If it becomes necessary to pay debt down beyond operating cash flows, CEP could further reduce capital
expenditures, continue to suspend quarterly distributions to unitholders, sell oil and natural gas properties or inventories, liquidate in-the-money derivative positions, reduce operating and administrative costs, or take additional steps to
increase liquidity.

We enter into hedging arrangements to reduce the impact of changes in the LIBOR interest rate on our
interest payments for our reserve-based credit facilities. These positions are outlined on page 45.



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##### Table of Contents

Management Incentive Interests

CEPM holds management incentive interests in us that represent the right to receive 15% of quarterly distributions of available cash from
operating surplus after the Target Distribution (as defined in our limited liability company agreement) has been achieved and certain other tests have been met. Based on our distribution level, beginning in the fourth quarter 2007, we commenced a
management incentive interest vesting period. A cash reserve of $0.7 million was established to fund future distributions on the management incentive interests. In February 2009, the Company reduced its quarterly distribution rate to $0.13 per unit
for the fourth quarter of 2008. This decrease in the distribution rate terminated the initial management incentive interest vesting period. After the February 13, 2009 distribution was paid, the reserve of $0.7 million was reduced to zero.

Cash Flow from Operations

Our net cash flow provided by operating activities for the nine months ended September 30, 2009 was $45.6 million, compared to net cash flow provided by operating activities of $55.9 million for the
same period in 2008. This level of operating cash flow was primarily attributable to higher sales of oil and natural gas as a result of our acquisition in the Woodford Shale and increased production volumes as a result of our drilling program in the
Cherokee Basin. The increase in cash flow due to higher production volumes was offset by the impact of significantly lower market prices for natural gas on our unhedged production volumes. For 2009, our operating cash flows were increased by $45.5
million related to cash hedge settlements for our natural gas commodity and interest rate derivatives. Our change in working capital from December 2008 to September 2009 was impacted by lower accounts receivable of $3.8 million, lower royalties
payable of $1.6 million, lower accounts payable of $1.6 million, lower affiliate payables of $0.8 million offset by an increase in accrued liabilities of $1.6 million. Our receivables balance decreased due to increased collections and lower current
period prices for our current estimated natural gas sales prices in all three of our areas. The royalties payable, which represents the amount of monies owed to the royalty owners in our properties for the monthly oil and natural gas sales,
decreased due to lower market prices for oil and natural gas. The decrease in accounts payable of $1.6 million primarily resulted from the timing of the payment of expenses related to our drilling programs.

Our cash flow from operations is subject to many variables, the most significant of which are the volatility of oil and natural gas prices
and our level of production of oil and natural gas. Oil and natural gas prices are determined primarily by prevailing market conditions, which are dependent on regional and worldwide economic activity, weather and other factors beyond our control.
Our future cash flow from operations will depend on our ability to maintain and increase production through our development programs or completing acquisitions, as well as the market prices of oil and natural gas and our hedging program. For
additional information on our business plan, refer to Outlook on page 42.

We enter into hedging arrangements
to reduce the impact of natural gas price volatility on our operations. By removing the price volatility from a significant portion of our natural gas production, we have mitigated, but not eliminated, the potential effects of changing prices on our
cash flow from operations for those periods. While mitigating negative effects of falling commodity prices, these derivative contracts also limit the benefits we would receive from increases in commodity prices. These derivative contracts also limit
our ability to have additional cash flows to recoup higher severance taxes, which are usually based on market prices for natural gas. Our operating cash flows are also impacted by the cost of oilfield services. In the event of inflation increasing
service costs or administrative expenses, our hedging program will limit our ability to have increased operating cash flows to recoup these higher costs. Increases in the market prices for natural gas may also increase our need for working capital
as our commodity hedging contracts cash settle prior to our receipt of cash from our sales of the related commodities to third parties.

It is our policy to enter into derivative contracts only with counterparties that are creditworthy financial institutions deemed by management as competent and competitive market makers. Each of the
counterparties to our derivative contracts is a lender in our reserve-based credit facilities. We do not post collateral under any of these agreements as they are secured under our reserve-based credit facilities.

The following tables summarize, for the periods indicated, our derivatives currently in place through December 31, 2014. All of these
derivatives are accounted for as mark-to-market activities.



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##### Table of Contents

MTM Fixed Price SwapsNYMEX



|     |  |                                  |  |              |      |          |           |              |   |        |  |              |  |        |      |              |           |        |   |              |  |            |  |   |     
|---- |  | -------------------------------- |  | ------------ | ---- | -------- | --------- | ------------ | - | ------ |  | ------------ |  | ------ | ---- | ------------ | --------- | ------ | - | ------------ |  | ---------- |  | - | ----
|     |  | For the quarter ended (in MMBtu)
|     |  | March 31,                        |  | June 30,     |      | Sept 30, |           | Dec 31,      |   | Total 
|     |  | Volume                           |  | AveragePrice |      | Volume   |           | AveragePrice |   | Volume |  | AveragePrice |  | Volume |      | AveragePrice |           | Volume |   | AveragePrice
|2009 |  |                                  |  |              |      |          |           |              |   |        |  |              |  |        |      |              | 3,235,000 |        | $ | 8.03         |  | 3,235,000  |  | $ | 8.03
|2010 |  | 2,950,000                        |  | $            | 8.31 |          | 2,875,000 |              | $ | 8.23   |  | 2,670,000    |  | $      | 8.13 |              | 2,700,000 |        | $ | 8.15         |  | 11,195,000 |  | $ | 8.21
|2011 |  | 2,400,000                        |  | $            | 8.56 |          | 2,425,000 |              | $ | 8.56   |  | 2,220,000    |  | $      | 8.46 |              | 2,220,000 |        | $ | 8.46         |  | 9,265,000  |  | $ | 8.51
|2012 |  | 2,227,500                        |  | $            | 8.34 |          | 2,227,500 |              | $ | 8.34   |  | 2,250,000    |  | $      | 8.34 |              | 2,250,000 |        | $ | 8.34         |  | 8,955,000  |  | $ | 8.34
|2013 |  | 2,025,000                        |  | $            | 7.33 |          | 2,047,500 |              | $ | 7.33   |  | 2,070,000    |  | $      | 7.33 |              | 2,070,000 |        | $ | 7.33         |  | 8,212,500  |  | $ | 7.33
|2014 |  | 1,575,000                        |  | $            | 7.03 |          | 1,592,500 |              | $ | 7.03   |  | 1,610,000    |  | $      | 7.03 |              | 1,610,000 |        | $ | 7.03         |  | 6,387,500  |  | $ | 7.03
|     |  |                                  |  |              |      |          |           |              |   |        |  |              |  |        |      |              |           |        |   |              |  |            |  |   |     
|     |  |                                  |  |              |      |          |           |              |   |        |  |              |  |        |      |              |           |        |   |              |  | 47,250,000 |  |   |     
|     |  |                                  |  |              |      |          |           |              |   |        |  |              |  |        |      |              |           |        |   |              |  |            |  |   |     



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##### Table of Contents

MTM Fixed Price SwapsCenterPoint Energy Gas Transmission (East)



|     |  |                                  |  |              |      |          |         |              |   |        |  |              |  |        |      |              |         |        |   |              |  |           |  |   |     
|---- |  | -------------------------------- |  | ------------ | ---- | -------- | ------- | ------------ | - | ------ |  | ------------ |  | ------ | ---- | ------------ | ------- | ------ | - | ------------ |  | --------- |  | - | ----
|     |  | For the quarter ended (in MMBtu)
|     |  | March 31,                        |  | June 30,     |      | Sept 30, |         | Dec 31,      |   | Total 
|     |  | Volume                           |  | AveragePrice |      | Volume   |         | AveragePrice |   | Volume |  | AveragePrice |  | Volume |      | AveragePrice |         | Volume |   | AveragePrice
|2009 |  |                                  |  |              |      |          |         |              |   |        |  |              |  |        |      |              | 230,000 |        | $ | 8.11         |  | 230,000   |  | $ | 8.11
|2010 |  | 180,000                          |  | $            | 7.91 |          | 180,000 |              | $ | 7.91   |  | 180,000      |  | $      | 7.91 |              | 180,000 |        | $ | 7.91         |  | 720,000   |  | $ | 7.91
|2011 |  | 180,000                          |  | $            | 7.93 |          | 180,000 |              | $ | 7.93   |  | 180,000      |  | $      | 7.93 |              | 180,000 |        | $ | 7.93         |  | 720,000   |  | $ | 7.93
|     |  |                                  |  |              |      |          |         |              |   |        |  |              |  |        |      |              |         |        |   |              |  |           |  |   |     
|     |  |                                  |  |              |      |          |         |              |   |        |  |              |  |        |      |              |         |        |   |              |  | 1,670,000 |  |   |     
|     |  |                                  |  |              |      |          |         |              |   |        |  |              |  |        |      |              |         |        |   |              |  |           |  |   |     

MTM Fixed Price Basis SwapsCenterPoint Energy Gas Transmission (East),
Natural Gas Pipeline Co. of America (Midcontinent), ONEOK Gas Transportation (Oklahoma), Panhandle Eastern Pipeline (Texas, Oklahoma), or Southern Star Central Gas Pipeline (Texas, Oklahoma, and Kansas)



|     |  |                                  |  |                   |      |          |           |                   |   |        |  |                   |  |        |      |                   |           |        |   |                   |  |            |  |   |     
|---- |  | -------------------------------- |  | ----------------- | ---- | -------- | --------- | ----------------- | - | ------ |  | ----------------- |  | ------ | ---- | ----------------- | --------- | ------ | - | ----------------- |  | ---------- |  | - | ----
|     |  | For the quarter ended (in MMBtu)
|     |  | March 31,                        |  | June 30,          |      | Sept 30, |           | Dec 31,           |   | Total 
|     |  | Volume                           |  | WeightedAverage $ |      | Volume   |           | WeightedAverage $ |   | Volume |  | WeightedAverage $ |  | Volume |      | WeightedAverage $ |           | Volume |   | WeightedAverage $
|2009 |  |                                  |  |                   |      |          |           |                   |   |        |  |                   |  |        |      |                   | 2,041,000 |        | $ | 1.01              |  | 2,041,000  |  | $ | 1.01
|2010 |  | 2,022,000                        |  | $                 | 0.84 |          | 1,579,500 |                   | $ | 0.96   |  | 1,389,000         |  | $      | 0.96 |                   | 1,290,000 |        | $ | 0.96              |  | 6,280,500  |  | $ | 0.92
|2011 |  | 1,335,000                        |  | $                 | 0.77 |          | 1,347,500 |                   | $ | 0.77   |  | 1,130,000         |  | $      | 0.77 |                   | 1,130,000 |        | $ | 0.77              |  | 4,942,500  |  | $ | 0.77
|2012 |  | 1,150,000                        |  | $                 | 0.65 |          | 1,150,000 |                   | $ | 0.65   |  | 1,160,000         |  | $      | 0.65 |                   | 1,160,000 |        | $ | 0.65              |  | 4,620,000  |  | $ | 0.65
|     |  |                                  |  |                   |      |          |           |                   |   |        |  |                   |  |        |      |                   |           |        |   |                   |  |            |  |   |     
|     |  |                                  |  |                   |      |          |           |                   |   |        |  |                   |  |        |      |                   |           |        |   |                   |  | 17,884,000 |  |   |     
|     |  |                                  |  |                   |      |          |           |                   |   |        |  |                   |  |        |      |                   |           |        |   |                   |  |            |  |   |     

Put OptionsNYMEX



|     |  |                                  |  |              |  |          |  |              |  |        |  |              |  |        |  |              |      |        |        |              |   |     
|---- |  | -------------------------------- |  | ------------ |  | -------- |  | ------------ |  | ------ |  | ------------ |  | ------ |  | ------------ | ---- | ------ | ------ | ------------ | - | ----
|     |  | For the quarter ended (in MMBtu)
|     |  | March 31,                        |  | June 30,     |  | Sept 30, |  | Dec 31,      |  | Total 
|     |  | Volume                           |  | AveragePrice |  | Volume   |  | AveragePrice |  | Volume |  | AveragePrice |  | Volume |  | AveragePrice |      | Volume |        | AveragePrice
|2009 |  |                                  |  |              |  |          |  |              |  |        |  |              |  | 40,000 |  | $            | 7.50 |        | 40,000 |              | $ | 7.50
|     |  |                                  |  |              |  |          |  |              |  |        |  |              |  |        |  |              |      |        |        |              |   |     
|     |  |                                  |  |              |  |          |  |              |  |        |  |              |  |        |  |              |      |        | 40,000 |              |   |     
|     |  |                                  |  |              |  |          |  |              |  |        |  |              |  |        |  |              |      |        |        |              |   |     

Investing ActivitiesAcquisitions and Capital Expenditures

Cash used in investing activities was $22.6 million for the nine months ended September 30, 2009, compared to $80.2 million for the same
period in 2008. Our cash capital expenditures were $22.8 million for the nine months ended September 30, 2009, which primarily related to drilling and development of oil and natural gas properties in the Cherokee Basin. Through the third
quarter of 2009, we drilled and completed 60 net wells and 17 net recompletions in the Cherokee Basin. We also prepared 10 drilling locations in the Black Warrior Basin. We also settled post-closing adjustments on our CoLa and Newfield Acquisitions
of $0.2 million.

Our capital expenditures were $81.1 million for the nine months ended September 30, 2008, which
primarily related to $32.3 million for drilling and development of oil and natural gas properties and $50.9 million for the CoLa Acquisition offset by $2.1 million in post-closing adjustments related to our 2007 acquisitions in the Cherokee Basin.
These post-closing adjustments were primarily related to the receipt of revenues between the effective date of the transaction and the closing date and the receipt of $1.0 million in funds related to the Amvest Acquisition. Through the third quarter
of 2008, we drilled and completed 15 net wells in the Black Warrior Basin and 75 net wells and 32 net recompletions in the Cherokee Basin.

In our 2009 business plan, we expected that our total capital budget would be between $28.0 million and $33.0 million for the twelve months ending December 31, 2009. This capital budget primarily
consists of capital for drilling and also includes amounts for infrastructure projects, equipment, and inventory. The 2009 budget was set at a maintenance capital level and has been reduced from our 2008 spending level of approximately $47.9
million. For 2009, we now expect to only spend between $23.0 million and $25.0 million of our total 2009 budget. Substantially all of this spending will occur in the Cherokee Basin. We will continue to monitor the level of oil and natural gas
prices, our liquidity position, our debt level, the results of future borrowing base redeterminations under



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our reserve-based credit facilities, and drilling costs when determining the amount of capital expenditures to make to support our business. To the extent that commodity prices do not
significantly increase or drilling costs decrease further, we would expect to continue to limit our level of capital expenditures during the remainder of 2009 and in 2010. As of September 30, 2009, we have approximately $2.4 million in accrued
capital expenditures and 1 remaining net well in the process of being completed in the Cherokee Basin.

We do not currently
expect to drill any further wells or make any acquisitions in 2009. However, the amount and timing of our capital expenditures is largely discretionary and within our control. We routinely monitor and adjust our capital expenditures in response to
changes in oil and natural gas prices, drilling and acquisition costs, industry and economic conditions, our debt levels, availability of funds under our reserve-based credit facilities, and internally generated cash flow. Our future cash flows are
subject to a number of variables, including the level of natural gas production and prices that we receive for our production. There can be no assurance that our operations and other available capital resources will provide cash in sufficient
amounts to provide for future levels of capital expenditures to maintain our current production rates.

Financing Activities

Our net cash provided by financing activities was $1.5 million for the nine months ended September 30, 2009, compared
to $23.0 million provided by financing activities for the same period in 2008. Through September 30, 2009, we borrowed a net of $7.5 million to finance capital expenditures and for working capital needs. Through November 6, 2009, we used
our excess cash flow to reduce our outstanding debt levels from $220.0 million to $200.0 million.

We also paid distributions
of $5.8 million to our common and Class A unitholders in 2009. We have suspended $2.0 million in quarterly distributions on the Class D interests associated with the periods ended September 30, 2009, June 30, 2009, March 31,
2009, December 31, 2008, September 30, 2008, June 30, 2008, and March 31, 2008. We expect that these quarterly distributions on the Class D interests, and all future quarterly distributions on the Class D interests,
will remain suspended until the litigation surrounding the Torch NPI is finally resolved and such distributions are permitted under our credit and limited liability company agreements. For the nine months ended September 30, 2009, our
distributions to unitholders have been less than our distributable cash flow such that our distribution coverage ratio is greater than 1.0. This coverage ratio compares our distribution rate to our distributable cash flow. Our distributable cash
flow reflects Adjusted EBITDA reduced by estimated maintenance capital expenditures and cash interest expense. Our maintenance capital is the amount of capital spending required to maintain our production rates, reserves, and asset base. We have
suspended our quarterly distributions to unitholders since the quarter ended June 30, 2009, to remain in compliance with the covenants associated with our credit facilities. Assuming that the quarterly distribution rate would have remained at
$0.13 per unit for the third and fourth quarters of 2009, this suspension of the quarterly distribution would provide approximately $5.8 million in cash flow that could be used to reduce our outstanding debt balances under our reserve-based credit
facilities.

Our net cash provided by financing activities was $23.0 million for the nine months ended September 30,
2008. In 2008, we borrowed a total of $63.0 million to fund the CoLa Acquisition, to fund debt issue costs, to finance capital expenditures, and for working capital needs. We also paid distributions of $38.1 million to our common and Class A
unitholders and on the Class D interests in 2008, and incurred $0.3 million in costs associated with our shelf registration statement.

Contractual Obligations

At September 30, 2009, we had the following contractual obligations or commercial
commitments:



|                                   |            |                            |      |  |      |         |      |   |      |  |            |     |       |   |     |  |   |       |  |   |        
|---------------------------------- | ---------- | -------------------------- | ---- |  | ---- | ------- | ---- | - | ---- |  | ---------- | --- | ----- | - | --- |  | - | ----- |  | - | -------
|                                   |            | Payments Due By Year(1)(2)
|                                   | 2009       |                            | 2010 |  | 2011 |         | 2012 |   | 2013 |  | Thereafter |     | Total
|                                   | (In 000s)
|Management Services Agreement(3)   |            | $                          | 185  |  | $    |        |      | $ |     |  | $          |    |       | $ |    |  | $ |      |  | $ | 185    
|Reserve-Based Credit Facilities(4) |            |                            |     |  |      | 220,000 |      |   |     |  |            |    |       |   |    |  |   |      |  |   | 220,000
|Support Services Agreement         |            |                            | 642  |  |      |        |      |   |     |  |            |    |       |   |    |  |   |      |  |   | 642    
|Office Leases                      |            |                            | 103  |  |      | 414     |      |   | 416  |  |            | 424 |       |   | 408 |  |   | 1,174 |  |   | 2,939  
|Purchase Obligation                |            |                            |     |  |      |        |      |   |     |  |            |    |       |   |    |  |   |      |  |   |       
|                                   |            |                            |      |  |      |         |      |   |      |  |            |     |       |   |     |  |   |       |  |   |        
|Total                              |            | $                          | 930  |  | $    | 220,414 |      | $ | 416  |  | $          | 424 |       | $ | 408 |  | $ | 1,174 |  | $ | 223,766
|                                   |            |                            |      |  |      |         |      |   |      |  |            |     |       |   |     |  |   |       |  |   |        



|(1) | This table does not include any liability associated with derivatives.
|--- | ----------------------------------------------------------------------

|(2) | This table does not include interest as interest rates are variable. The average interest rate on our outstanding debt was approximately 5.2% at September 30,
2009.
|--- | --------------------------------------------------------------------------------------------------------------------------------------------------------------------

|(3) | The maximum annual amount for charges under the management services agreement for 2009 approved by the conflicts committee of our board of managers in February 2009 is
$1.7 million.
|--- | -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

|(4) | The value for our reserve-based credit facilities as of November 6, 2009, is $200,000 due in 2010.
|--- | --------------------------------------------------------------------------------------------------



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At September 30, 2009, our asset retirement obligation was approximately
$7.0 million.

Off-Balance Sheet Arrangements

We have no guarantees or off-balance sheet debt to third parties, and we maintain no debt obligations that contain provisions requiring accelerated payment of the related obligations in the event of
specified levels of declines in credit ratings.

Credit Markets and Counterparty Risk

We actively monitor the credit exposure and risks associated with our counterparties. Additionally, we continue to monitor the recent adverse
developments in the global credit markets to limit our potential exposure to credit risk where possible. Our primary credit exposures result from the sale of oil and natural gas and our use of derivatives. Through November 6, 2009, we have not
suffered any losses with our counterparties as a result of nonperformance in the current economic and credit crisis.

Certain
key counterparty relationships are described below:

CCG

Until March 31, 2009, Constellation Energy Commodities Group, Inc. (CCG) purchased a portion of our natural gas production
in Oklahoma and Kansas. As of November 6, 2009, we have no receivables from CCG.

Macquarie Cook Energy LLC

Macquarie Cook Energy LLC (Macquarie Cook), a subsidiary of Sydney, Australia-based Macquarie Group, Ltd.
purchases the majority of our natural gas production in the Cherokee Basin for May 2009 through October 2009. We have received a guarantee from Macquarie Bank Limited for up to $8 million in purchases through December 31, 2011. As of
November 6, 2009, we have no past due receivables from Macquarie Cook.

J.P. Morgan Ventures Energy Corporation

J.P. Morgan Ventures Energy Corporation purchases the majority of our natural gas production in Alabama. The payment for the
purchases is guaranteed by JP Morgan Chase & Company though October 2010. As of November 6, 2009, we have no past due receivables from J.P. Morgan Ventures Energy Corporation.

Derivative Counterparties

As of November 6, 2009, all of our derivatives are with BNP Paribas, The Royal Bank of Scotland, Societe Generale, Calyon and Bank of Nova Scotia. These banks are lenders who participate in our
reserve-based credit facilities. All of our derivatives are collateralized by the assets securing our reserve-based credit facilities. As of November 6, 2009, each of these financial institutions has an investment grade credit rating.

Reserve-Based Credit Facilities

As of November 6, 2009, the banks and their percentage commitments in our two credit facilities are: The Royal Bank of Scotland (23.32%), BNP Paribas (22.55%), Wachovia Bank, N.A. (14.55%), Bank of
Nova Scotia (17.00%), Calyon (15.05%), and Societe Generale (7.53%). As of August 10, 2009, each of these financial institutions has an investment grade credit rating.

Outlook

During the remainder of 2009, we expect that our business will
continue to be affected by the factors described in Part I, Item 1A. Risk Factors of our Annual Report on Form 10-K for December 31, 2008 that was filed on February 27, 2009, as well as the following key industry and
economic trends. Our expectations are based upon key assumptions and information currently available to us. To the extent that our underlying assumptions about or interpretations of available information prove to be incorrect, our actual results may
vary materially from our expected results.

Full Year 2009 Expected Results

Our 2009 business plan and forecast has been focused on maintaining net production levels and promoting financial flexibility by enhancing
our liquidity position. This plan was prepared in conjunction with the ongoing strategic review undertaken with Tudor, Pickering, Holt & Co. Securities, Inc., our strategic advisor, and has been approved by our Board of Managers. Our goal
is to sustain the company through the current business cycle and position our operations for success over the long-term. We expect our full year 2009 results to be impacted by significantly lower natural gas prices in our operating areas, the
limited ability to access our reserve-



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based credit facilities, the economic recession and uncertainty related to our relationship with Constellation. To date, we have substantially achieved all of the objectives set forth in our 2009
business plan.

We currently anticipate:



| |  |  | Our production to be between 17.0 Bcfe and 18.5 Bcfe depending on the level and timing of our capital spending in 2009. Based on the mix of wells
drilled during the first half of 2009 and our lack of capital spending during the second half of 2009, we now anticipate that our full year production will be at the low end of this range.
| | - |  | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  |  | Our operating expenses are expected to be in the range between $57.5 million to $63.5 million.
| | - |  | ----------------------------------------------------------------------------------------------



| |  |  | Our total capital expenditures under our approved 2009 business plan were expected to be between $28.0 million and $33.0 million, which assumed a
decline rate of 13 to 15 percent and a dollar per flowing Mcfe range of $4,400 to $4,600. We now expect our total capital expenditures for 2009 to be between $23.0 million and $25.0 million. For the next three months, we may complete only 1
additional net well in the Cherokee Basin subject to infrastructure availability.
| | - |  | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  |  | Based upon our current business plan, we expect to continue to generate operating cash flows in excess of our remaining 2009 maintenance capital
expenditures and working capital needs. We will use our excess operating cash flows generated during the second half of 2009 to reduce our outstanding debt balances by $20.0 million. We currently intend to use our future available surplus cash
during the remainder of 2009 and during 2010 to further reduce our outstanding debt levels.
| | - |  | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  |  | Our quarterly distribution rate must remain suspended when our outstanding debt balance is less than 90% of our borrowing base as determined by our
lenders. We are subject to additional future borrowing base redeterminations and cannot forecast at what level our lenders will set our future borrowing base. During the remainder of 2009 and during 2010, we anticipate that we will limit our
maintenance capital expenditures and use our excess operating cash flows to further reduce our outstanding debt level. During this time, we anticipate that our distribution will remain suspended. Once we have reduced our outstanding debt balance to
less than 90% of our borrowing base as determined by our lenders and at such time we are able to resume maintenance capital expenditures, we will reevaluate the suspension of our quarterly distribution rate considering our borrowing base, debt
level, the price of natural gas, and our maintenance capital spending needs at that time. Any future quarterly distributions must be approved by our Board of Managers.
| | - |  | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  |  | We are currently working with our lenders to extend or refinance our reserve-based credit facilities that mature in October 2010.
| | - |  | ---------------------------------------------------------------------------------------------------------------------------------



| |  |  | We expect to release our 2010 business plan during our earnings call to be held in February 2010.
| | - |  | -------------------------------------------------------------------------------------------------

Critical Accounting Policies and Estimates

The discussion and analysis of our financial condition and results of operations are based upon our consolidated financial statements, which have been prepared in accordance with accounting principles
generally accepted in the United States of America. The preparation of these financial statements requires us to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses, and related disclosure of
contingent assets and liabilities. Certain accounting policies involve judgments and uncertainties to such an extent that there is reasonable likelihood that materially different amounts could have been reported under different conditions, or if
different assumptions had been used. We evaluate our estimates and assumptions on a regular basis. We base our estimates on historical experience and various other assumptions that are believed to be reasonable under the circumstances, the results
of which form the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. Actual results may differ from these estimates and assumptions used in the preparation of our
financial statements.

As of September 30, 2009, there were no changes with regard to the critical accounting policies
disclosed in our Annual Report on Form 10-K for the year ended December 31, 2008. The policies disclosed included the accounting for natural gas properties, natural gas reserve quantities, net profits interest, revenue recognition and hedging
activities. Please read Note 1 to the consolidated financial statements for a discussion of additional accounting policies and estimates made by management.

New Accounting Pronouncements Adopted

In June 2009, the FASB released the
final version of its new Accounting Standards Codification (the Codification) as the single authoritative source for U.S. GAAP. The Codification replaces all previous U.S. GAAP accounting standards as described in SFAS 168, The FASB
Accounting Standards Codification and the Hierarchy of Generally Accepted Accounting Principles. While not intended to change U.S. GAAP, the Codification significantly changes the way in which the accounting literature is organized. It is
structured by accounting topic to help accountants and auditors more quickly identify the guidance that applies to a specific accounting issue. However, because the Codification completely replaces existing standards, it will affect the way U.S.
GAAP is referenced by companies in their financial statements and accounting policies. The Codification is effective for financial statements that cover interim and annual periods ending after September 15, 2009. The adoption of the
Codification did not have a material impact on our financial statements.

In May 2009, the Financial Accounting Standards
Board established general standards of accounting for and the disclosures of events that occur after the balance sheet date but before financial statements are issued or are available to be issued. Although there is



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new terminology, the standard is based on the same principles as those that currently exist in the auditing standards. The standard, which includes a new required disclosure of the date through
which an entity has evaluated subsequent events, is effective for interim or annual periods ending after June 15, 2009. CEP performs an evaluation of subsequent events until the issuance date of its document with the SEC so the adoption of the
new requirements had no impact on our financial statements. See Note 16 for additional information.

New Accounting Pronouncements Issued
But Not Adopted

As of September 30, 2009, there were a number of accounting standards and interpretations that had
been issued, but not yet adopted by us.

On December 31, 2008, the SEC issued the final rule, Modernization of Oil
and Gas Reporting (Final Rule). The Final Rule adopts revisions to the SECs oil and gas reporting disclosure requirements and is effective for annual reports on Forms 10-K for years ending on or after December 31, 2009.
The revisions are intended to provide investors with a more meaningful and comprehensive understanding of oil and gas reserves to help investors evaluate their investments in oil and gas companies. The amendments are also designed to modernize the
oil and gas disclosure requirements to align them with current practices and technological advances. Revised requirements in the Final Rule include, but are not limited to:



| |  |  | Oil and gas reserves must be reported using a 12-month average of the closing prices on the first day of each of such months, rather than a single day
year-end price;
| | - |  | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  |  | Companies will be allowed to report, on a voluntary basis, probable and possible reserves, previously prohibited by SEC rules; and
| | - |  | ----------------------------------------------------------------------------------------------------------------------------------



| |  |  | Easing the standard for the inclusion of proved undeveloped reserves (PUDs) and requiring disclosure of information indicating any progress toward the
development of PUDs.
| | - |  | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------

We are currently evaluating the potential impact of adopting the Final Rule. The SEC
is discussing the Final Rule with the FASB and IASB staffs to align accounting standards with the Final Rule. These discussions may delay the required compliance date. Absent any change in such date, we will begin complying with the disclosure
requirements in our annual report on Form 10-K for the year ended December 31, 2009. Voluntary early compliance is not permitted.

In September 2009, the FASB issued its proposed updates to oil and gas accounting rules to align the oil and gas reserve estimation and disclosure requirements of Extractive IndustriesOil and Gas (Topic 932) with the requirements in
the SECs final rule, Modernization of the Oil and Gas Reporting Requirements,which was issued on December 31, 2008 and is effective for the year ended December 31, 2009. The public comment period for the FASBs proposed
updates ended October 15, 2009; however, no final guidance has been issued by the FASB. We are evaluating the potential impact of any updates to the oil and gas accounting rules and will comply with any new accounting and disclosure
requirements once they become effective.



|Item 3. | Quantitative and Qualitative Disclosures about Market Risk
|------- | ----------------------------------------------------------

The primary objective of the following information is to provide forward-looking quantitative and qualitative information about our potential exposure to market risks. The term market risk
refers to the risk of loss arising from adverse changes in natural gas prices and interest rates. The disclosures are not meant to be precise indicators of expected future losses, but rather indicators of reasonably possible losses. This
forward-looking information provides indicators of how we view and manage our ongoing market risk exposures. All of our market risk sensitive instruments were entered into for purposes other than speculative trading.

Global Financial and Energy Markets

During 2008 and 2009, there has been unprecedented volatility in global financial and energy markets. The failures of financial institutions have effectively restricted current liquidity within global
financial markets. Despite world-wide governmental efforts to provide liquidity to the financial sector, capital and credit markets currently remain constrained. We expect that our ability to issue debt and equity will be limited over the next year
should capital markets remain in crisis and that the cost of capital may increase during this time. We also may have difficulty in accessing credit should we have the need to. Additionally, the market prices for oil and natural gas have
significantly declined since June 2008. This decline may result in further decreases in our total $225.0 million borrowing base under our reserve-based credit facilities at future redeterminations prior to the facilities maturing in October 2010.
The equity valuations for energy-related companies, and E&P master limited partnerships in particular, have fallen dramatically. In response to the credit crisis and the decline in the market prices for oil and natural gas, many energy companies
have reduced their planned capital expenditures or have shut-in production. In response, we have suspended our cash distribution and lowered our capital expenditure budget for 2009 as compared to 2008. We expect that if market prices for oil and
natural gas remain depressed, our future cash flows from operations will be reduced for our unhedged production. We will continue to monitor the financial and energy



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markets to determine if we should revise the timing and scope of our future drilling programs, financing activities, acquisition activities, or resume cash distributions to our unitholders.

Commodity Price Risk

Our major market risk exposure is in the pricing applicable to our natural gas production. Realized pricing is primarily driven by the Inside FERC prices for Southern Natural Gas Company (Louisiana) with
respect to our properties in the Black Warrior Basin and the Inside FERC prices for CenterPoint Energy Gas Transmission (East), Natural Gas Pipeline Company of America (Midcontinent), the CenterPoint Energy Gas Transmission (East), ONEOK Gas
Transportation (Oklahoma), Panhandle Eastern Pipeline (Texas, Oklahoma) and Southern Star Central Gas Pipeline (Texas, Oklahoma, Kansas) with respect to our properties in the Cherokee Basin, and the Inside FERC price for the CenterPoint Energy Gas
Transmission (East) for our properties in the Woodford Shale, and the spot market prices applicable to all of our natural gas production. Historically, pricing for natural gas production has been volatile and unpredictable and we expect this
volatility to continue in the future. We are currently operating in an environment characterized by low natural gas prices which will lower our revenues that we realize on our unhedged natural gas production and limit the amount of operating cash
flows available for maintenance capital expenditures, distributions to unitholders, or to reduce our outstanding debt level. The prices we receive for production depend on many factors outside our control, including weather, economic conditions, and
the total supply of oil and natural gas for sale in the market.

We have entered into hedging arrangements with respect to a
portion of our projected natural gas production through various derivatives that hedge the future prices received. These hedging activities are intended to support natural gas prices at targeted levels and to manage our exposure to natural gas price
fluctuations. We do not hold or issue derivative instruments for speculative trading purposes. The use of hedging transactions also involves the risk that the counterparties will be unable to meet the financial terms of the transactions. We attempt
to minimize this risk by entering into all of our derivative transactions with counterparties that are lenders in our reserve-based credit facilities. The table below presents the hypothetical changes in fair values arising from potential changes in
the quoted market prices of the commodity underlying the derivative instruments used to mitigate these market risks. Any gain or loss on these derivative commodity instruments would be substantially offset by a corresponding gain or loss on the sale
of the hedged natural gas production, which are not included in the table. These derivatives do not hedge all of our commodity price risk related to our forecasted sales of natural gas production and as a result, we are subject to commodity price
risks on our remaining unhedged natural gas production.





|                                                                                                |            |            |        |                     |   |        |                     |   |          |   |  |   |        |  |   |       
|----------------------------------------------------------------------------------------------- | ---------- | ---------- | ------ | ------------------- | - | ------ | ------------------- | - | -------- | - |  | - | ------ |  | - | ------
|                                                                                                |            | Fair Value |        | 10 Percent Increase |   |        | 10 Percent Decrease
|                                                                                                |            | Fair Value |        | (Decrease)          |   |        | Fair Value          |   | Increase
|                                                                                                | (in 000s)
|Impact of changes in commodity prices on derivative commodity instruments at September 30, 2009 |            | $          | 56,689 |                     | $ | 27,039 |                     | $ | (29,650  | ) |  | $ | 86,341 |  | $ | 29,652

Interest Rate Risk

At September 30, 2009, we had debt outstanding of $220.0 million. This entire amount incurred interest at a rate of a one-month LIBOR
rate plus an applicable margin of 2.00% based on utilization. At September 30, 2009, the one-month LIBOR rate was 0.246% and the three-month LIBOR rate was 0.287%, and our applicable margin was 2.00%. At September 30, 2009, the ABR rate
was 3.25%, and our applicable margin was 1.00%. We had no debt outstanding at the three-month LIBOR rate or at the ABR rate. At September 30, 2009, the carrying value and fair value of our debt is $220.0 million.

The table below presents the hypothetical changes in fair values arising from potential changes in the quoted interest rate underlying the
derivative instruments used to mitigate these market risks.





|                                                                                         |            |            |        |   |                     |   |                     |   |  |            |     |  |   |        |   |  |   |      |  
|---------------------------------------------------------------------------------------- | ---------- | ---------- | ------ | - | ------------------- | - | ------------------- | - |  | ---------- | --- |  | - | ------ | - |  | - | ---- | -
|                                                                                         |            | Fair Value |        |   | 10 Percent Increase |   | 10 Percent Decrease |  
|                                                                                         |            | Fair Value |        |   | Increase            |   | Fair Value          |   |  | (Decrease) |    
|                                                                                         | (in 000s) |           
|Impact of changes in LIBOR on derivative interest rate instruments at September 30, 2009 |            | $          | (6,168 | ) |                     | $ | (5,991              | ) |  | $          | 177 |  | $ | (6,345 | ) |  | $ | (177 | )



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We enter into hedging arrangements to reduce the impact of volatility of changes in the
LIBOR interest rate on our interest payments for our debt. At September 30, 2009, we have the following outstanding interest rate swaps that fix our LIBOR rate:



|                   |  |                   |        |                  |      |  
|------------------ |  | ----------------- | ------ | ---------------- | ---- | -
|Maturity Date      |  | Total Debt Hedged |        | LIBOR Fixed Rate |     
|                   |  | (in 000s)        |        |                  |     
|February 20, 2010  |  | $                 | 16,500 |                  | 4.74 | %
|August 20, 2010    |  | $                 | 11,000 |                  | 4.58 | %
|August 21, 2010    |  | $                 | 28,500 |                  | 2.74 | %
|September 20, 2010 |  | $                 | 45,000 |                  | 4.96 | %
|September 21, 2010 |  | $                 | 11,000 |                  | 2.66 | %
|October 19, 2010   |  | $                 | 29,500 |                  | 4.81 | %
|October 22, 2010   |  | $                 | 7,500  |                  | 4.56 | %
|October 22, 2010   |  | $                 | 19,000 |                  | 2.91 | %



|Item 4. | Controls and Procedures
|------- | -----------------------

A control system, no matter how well conceived and operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met. Because of the inherent limitations in all control systems, no evaluation
of controls can provide absolute assurance that all control issues and instances of fraud, if any, with CEP have been detected. These inherent limitations include error by personnel in executing controls due to faulty judgment or simple mistakes,
which could occur in situations such as when personnel performing controls are new to a job function or when inadequate resources are applied to a process. Additionally, controls can be circumvented by the individual acts of some persons or by
collusion of two or more people.

The design of any system of controls also is based in part upon certain assumptions about
the likelihood of future events, and there can be no absolute assurance that any design will succeed in achieving its stated goals under all potential future conditions; over time, controls may become inadequate because of changes in conditions or
personnel, or the degree of compliance with the policies or procedures may deteriorate. Because of the inherent limitations in a cost-effective control system, misstatements due to error or fraud may occur and not be detected.

Evaluation of Disclosure Controls and Procedures. The Chief Executive Officer and the Chief Financial Officer of CEP have evaluated
the effectiveness of the disclosure controls and procedures (as such term is defined in rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934, as amended (the Exchange Act)) as of the end of the fiscal quarter covered
by this quarterly report (the Evaluation Date). Based on such evaluation, the Chief Executive Officer and the Chief Financial Officer have concluded that, as of the Evaluation Date, CEPs disclosure controls and procedures are
effective.

Changes in Internal Control over Financial Reporting. During 2009, we have transitioned certain processes
and employees from being provided by Constellation under the management services agreement to CEP. This transition has been substantially completed as of September 30, 2009. The management services agreement with Constellation will be
terminated on December 15, 2009. The transfer of the processes and employees did not materially impact CEPs internal control over financial reporting. During the nine months ended September 30, 2009, there were no changes in
CEPs internal control over financial reporting (as such term is defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act) that have materially affected, or are reasonably likely to materially affect, CEPs internal control over
financial reporting.

Part IIOther Information



|Item 1. | Legal Proceedings
|------- | -----------------

Termination of the
Trust and Related Litigation

On January 29, 2008, the unitholders of the Torch Energy Royalty Trust voted to
terminate the Trust and authorized the Trustee to wind up, liquidate, and distribute the assets held by the Trust under the terms of the trust agreement. As discussed beginning on page 21 in Note 11, we are involved in litigation related to the
calculation of the NPI held by the Trust in the Robinsons Bend Field in Alabama.

Although we may, from time to time, be
involved in litigation and claims arising out of our operations in the normal course of business, we are not currently a party to any other material legal proceedings. In addition, we are not aware of any legal or governmental proceedings against
us, or contemplated to be brought against us, under various environmental protection statutes or other regulations to which we are subject.



|Item 1A. | Risk Factors
|-------- | ------------

Except as
identified below, there have been no material changes to the risk factors previously disclosed in Item 1A. to Part I of our Annual Report on Form 10-K for December 31, 2008 that was filed on February 27, 2009. An investment in our
common units involves various risks. When considering an investment in us, careful consideration should be given to the risk factors described in our 2008 Form 10-K. These risks and uncertainties are not the only ones facing us and there may be
additional matters that are not known to us or that we currently consider immaterial. All of these risks and uncertainties could adversely affect our business, financial condition or future results and, thus, the value of an investment in us.

Tax Risks to Unitholders

Unitholders may be required to pay taxes on income from us even if they do not receive any cash distributions from us.



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Unitholders are required to pay federal income taxes and, in some cases, state and local
income taxes, on their share of our taxable income, whether or not they receive cash distributions from us. Generally, should we generate taxable income for a particular tax year and not pay any cash distributions, our unitholders will be required
to pay the actual tax liability that results from their share of such taxable income even though they received no cash distributions from us.

On May 15, 2009, we paid a cash distribution of $0.13 on each common unit (or Class B) and Class A unit. If we generate taxable income for the 2009 tax year and do not resume cash distributions
in 2009, our unitholders who received that cash distribution and any unitholders who purchase or purchased common units after the record date for such distribution may not receive cash distributions from us during 2009 sufficient to pay the actual
tax liability that results from their share of such 2009 taxable income.

Risks Related to Our Distribution to Unitholders

We may not have sufficient available cash from operations to resume our quarterly cash distributions to unitholders following the reduction of
outstanding debt balances and the establishment of cash reserves and the payment of fees and expenses.

Our quarterly
distribution rate has been suspended in order to remain in compliance with the covenants associated with our reserve-based credit facilities. Before we can resume our quarterly cash distributions, we must reduce our outstanding debt balances to less
than 90% of our borrowing base as determined by our lenders. We are subject to additional future borrowing base redeterminations before our reserve-based credit facilities matures in October 2010 and cannot forecast at what level our lenders will
set our future borrowing base. If our lenders further reduce our borrowing base because of any of the numerous factors generally described in this caption Risk Factors and the Risk Factors in our 2008 Form 10-K, our
outstanding debt balances may remain at more than 90% of our borrowing base as determined by our lenders and we may be unable to resume our quarterly cash distributions or may again have to suspend our quarterly cash distributions. If we do not
achieve our expected operational results and do not continue to reduce our outstanding debt levels, we may not be able to resume quarterly cash distributions, in which event the market price of our common units may decline substantially.

In addition, we may not have sufficient available cash or future cash flow from operations each quarter to pay cash distributions to our
unitholders following establishment of cash reserves by our board of managers for the proper conduct of our business and the payment of fees and expenses. The amount of available cash from which we may pay distributions is defined in both our
reserve-based credit facilities and our limited liability company agreement. The amount of available cash we distribute is subject to the definition of operating surplus in our limited liability company agreement. Ultimately, the amount of available
cash that we may distribute to our unitholders principally depends upon the amount of cash we generate from our operations, which will fluctuate from quarter to quarter based on numerous factors generally described in this caption Risk
Factors and the Risk Factors in our 2008 Form 10-K, including, among other things: the amount of oil and natural gas we produce; the demand for and the price at which we are able to sell our oil and natural gas production; the
results of our hedging activity; the level of our operating costs, including reimbursements to CEPM under the management services agreement; the costs we incur to acquire E&P properties; whether we are able to continue our development activities
at economically attractive costs; the level of our interest expense, which depends on the amount of our indebtedness and the interest payable thereon; the amount of working capital required to operate our business; and the level of our maintenance
capital expenditures.

The amount of available cash that we will have to distribute to our unitholders also depends on other
factors, some of which are beyond our control, including: the borrowing base under our reserve-based credit facilities; our ability to make working capital borrowings under our reserve-based credit facilities to pay distributions; our debt service
requirements and covenants and restrictions on distributions contained in our reserve-based credit facilities; fluctuations in our working capital needs; the timing and collectability of receivables; prevailing economic conditions; the amount of our
estimated maintenance capital expenditures; and the amount of cash reserves established by our board of managers for the proper conduct of our business, including the maintenance of our asset base and the payment of future cash distributions on our
Class A and common units, any management incentive interests and Class D interests. As a result of these factors, we may not have sufficient available cash to resume our quarterly distributions. Even if we were able to resume a quarterly cash
distribution because we have reduced our outstanding debt balances to a level that complies with our debt covenants, the amount of available cash that we could distribute from our operating surplus in any quarter to our unitholders may fluctuate
significantly from quarter to quarter and may be significantly less than the quarterly distribution amount of $0.13 per unit that we paid for the first quarter 2009. If we do not have sufficient available cash or future cash flow from operations to
resume quarterly cash distributions, the market price of our common units may decline substantially.

Risks Related to Our Business

Potential regulatory actions could increase our operating or capital costs and delay our operations or otherwise alter the way we
conduct our business.

Exploration and development activities and the production and sale of oil and natural gas are
subject to extensive federal, state, local and tribal regulations. Changes to existing regulations or new regulations may unfavorably impact us, our suppliers or our customers. In the United States, legislation that directly impacts the
oil and gas industry has been recently proposed covering areas such as emission reporting and reductions, hydraulic fracturing of wells, the repeal of certain oil and natural gas tax incentives and tax



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deductions, and the regulation of commodity derivatives. These and other potential regulations could increase our costs, reduce our liquidity, impact our ability to hedge our future oil and
natural gas sales, delay our operations or otherwise alter the way we conduct our business, negatively impacting our financial condition, results of operations and cash flows.

Risks Related to Financing and Credit Environment

Amounts borrowed under our credit
facilities will become due in October 2010 unless we are able to refinance that debt.

Our credit facilities mature on
October 31, 2010. As a result, the $200.0 million outstanding balance under our credit facilities as of November 6, 2009 has become a current liability. We are currently working to extend or refinance our credit facilities. If we were unable to
extend or refinance our current credit facilities and if we were unable to repay the then outstanding debt balance thereunder when it becomes due on October 31, 2010, it would have a material adverse effect on the Company.

Forward-Looking Statements

This Quarterly Report on Form 10-Q contains forward-looking statements that are subject to a number of risks and uncertainties, many of which are beyond our control, which may include statements about:



| |  |  | the volatility of realized oil and natural gas prices;
| | - |  | ------------------------------------------------------



| |  |  | the conditions of the capital markets, inflation, interest rates, availability of credit facilities to support business requirements, liquidity, and
general economic conditions;
| | - |  | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  |  | the discovery, estimation, development and replacement of oil and natural gas reserves;
| | - |  | ---------------------------------------------------------------------------------------



| |  |  | our business, financial, and operational strategy;
| | - |  | --------------------------------------------------



| |  |  | our drilling locations;
| | - |  | -----------------------



| |  |  | technology;
| | - |  | -----------



| |  |  | our cash flow, liquidity and financial position;
| | - |  | ------------------------------------------------



| |  |  | the ability to extend or refinance our reserve-based credit facilities;
| | - |  | -----------------------------------------------------------------------



| |  |  | the resumption or amount of our cash distribution;
| | - |  | --------------------------------------------------



| |  |  | the impact from any termination of the Robinsons Bend sharing arrangement;
| | - |  | ---------------------------------------------------------------------------



| |  |  | our hedging program and our derivative positions;
| | - |  | -------------------------------------------------



| |  |  | our production volumes;
| | - |  | -----------------------



| |  |  | our lease operating expenses, general and administrative costs and finding and development costs;
| | - |  | -------------------------------------------------------------------------------------------------



| |  |  | the availability of drilling and production equipment, labor and other services;
| | - |  | --------------------------------------------------------------------------------



| |  |  | our future operating results;
| | - |  | -----------------------------



| |  |  | our prospect development and property acquisitions;
| | - |  | ---------------------------------------------------



| |  |  | the marketing of oil and natural gas;
| | - |  | -------------------------------------



| |  |  | competition in the oil and natural gas industry;
| | - |  | ------------------------------------------------



| |  |  | the impact of the current global credit crisis and economic recession;
| | - |  | ----------------------------------------------------------------------



| |  |  | the impact of weather and the occurrence of natural disasters such as fires, floods, hurricanes, tornados, earthquakes, snow and ice storms and other
catastrophic events and natural disasters;
| | - |  | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  |  | governmental regulation and taxation of the oil and natural gas industry;
| | - |  | -------------------------------------------------------------------------



| |  |  | developments in oil-producing and natural gas producing countries;
| | - |  | ------------------------------------------------------------------



| |  |  | support from our sponsor or a change in our sponsor; and
| | - |  | --------------------------------------------------------



| |  |  | our strategic plans, objectives, expectations, forecasts, budgets, estimates and intentions for future operations.
| | - |  | ------------------------------------------------------------------------------------------------------------------

All of these types of statements, other than statements of historical fact included in this Quarterly Report on Form 10-Q, are
forward-looking statements. These forward-looking statements may be found in Part I, Item 2. Managements Discussion and Analysis of Financial Condition and Results of Operations Part II, Item 1A. Risk Factors; and
other items within this Quarterly Report on Form 10-Q. In some cases, forward-looking statements can be identified by terminology such as may, could, should, expect, plan,
project, intend, anticipate, believe, estimate, predict, potential, pursue, target, continue, the negative of such terms or other
comparable terminology.

The forward-looking statements contained in this Quarterly Report on Form 10-Q are largely based on
our expectations, which reflect estimates and assumptions made by our management. These estimates and assumptions reflect our best judgment based on currently known market conditions and other factors. Although we believe such estimates and
assumptions to be reasonable, they are inherently uncertain and involve a number of risks and uncertainties that are beyond our control. In addition, managements assumptions about future events may prove to be inaccurate. Management cautions
all readers that the forward-looking statements contained in this Quarterly Report on Form 10-Q are not guarantees of future performance, and we cannot assure any reader that such statements will be realized or the forward-looking events and
circumstances will occur. Actual results may differ materially from those anticipated or implied in the forward-looking statements due to factors listed in the Risk Factors section and elsewhere in this Quarterly Report on Form 10-Q. We
do not intend to publicly update or revise any forward-looking statements as a result of new information, future events or otherwise. These cautionary statements qualify all forward-looking statements attributable to us or persons acting on our
behalf.



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##### Table of Contents

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

None.



|Item 3. | Defaults Upon Senior Securities
|------- | -------------------------------

None.



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

None.



|Item 5. | Other Information
|------- | -----------------

None.



|Item 6. | Exhibits
|------- | --------



| | (a) | The following documents are filed as a part of this Quarterly Report on Form 10-Q:
| | --- | ----------------------------------------------------------------------------------



| | 1. | Financial Statements:
| | -- | ---------------------

Consolidated Statements of Operations and Comprehensive Income/(Loss)  Constellation Energy Partners LLC for the three months ended September 30, 2009 and September 30, 2008 and for the nine months ended September 30,
2009 and September 30, 2008

Consolidated Balance Sheets  Constellation Energy Partners LLC at September 30,
2009 and December 31, 2008

Consolidated Statements of Cash Flows  Constellation Energy Partners LLC for the nine
months ended September 30, 2009 and September 30, 2008

Consolidated Statements of Changes in Members Equity
and Comprehensive Income  Constellation Energy Partners LLC for the nine months ended September 30, 2009

Notes to
Consolidated Financial Statements



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EXHIBIT INDEX



|               |  |             |  |                                                                                                                                                                                                                                                                                
|-------------- |  | ----------- |  | -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|Exhibit Number |  | Description
|3.1            |  |            |  | Certificate of Formation of Constellation Energy Partners LLC, as amended (incorporated herein by reference to Exhibit 3.1 to the Annual Report on Form 10-K filed by
Constellation Energy Partners LLC on March 12, 2007)                                                     
|               |  |            
|3.2            |  |            |  | Second Amended and Restated Operating Agreement of Constellation Energy Partners LLC (incorporated herein by reference to Exhibit 3.1 to the Current Report on Form 8-K filed by
Constellation Energy Partners LLC on November 28, 2006)                                       
|               |  |            
|3.3            |  |            |  | Amendment No. 1 to Second Amended and Restated Operating Agreement of Constellation Energy Partners LLC (incorporated herein by reference to Exhibit 3.1 to the Current Report on
Form 8-K filed by Constellation Energy Partners LLC on April 24, 2007)                       
|               |  |            
|3.4            |  |            |  | Amendment No. 2 to Second Amended and Restated Operating Agreement of Constellation Energy Partners LLC dated July 25, 2007. (incorporated herein by reference to Exhibit 3.1 to
the Current Report on Form 8-K filed by Constellation Energy Partners LLC on July 26, 2007).  
|               |  |            
|3.5            |  |            |  | Amendment No. 3 to Second Amended and Restated Operating Agreement of Constellation Energy Partners LLC dated September 21, 2007 (incorporated by reference to Exhibit 3.5 to the
Current Report on Form 8-K filed by Constellation Energy Partners LLC on September 26, 2007).
|               |  |            
|3.6            |  |            |  | Amendment No. 4 to Second Amended and Restated Operating Agreement of Constellation Energy Partners LLC dated December 28, 2007 (incorporated by reference to Exhibit 3.1 to the
Current Report on Form 8-K filed by Constellation Energy Partners LLC on December 28, 2007).  
|               |  |            
|10.1           |  |            |  | Employment Agreement, dated May 1, 2009, by and between CEP Services Company, Inc. and Stephen R. Brunner (incorporated by reference to Exhibit 10.1 to the Current Report on Form
8-K/A filed by Constellation Energy Partners LLC on May 5, 2009, File No. 001-33147).       
|               |  |            
|*10.2          |  |            |  | Employment Agreement, dated May 1, 2009, by and between CEP Services Company, Inc. and Charles C. Ward (corrected version filed herewith reflecting corrections of typographical
errors).                                                                                      
|               |  |            
|*10.3          |  |            |  | Employment Agreement, dated May 1, 2009, by and between CEP Services Company, Inc. and Lisa J. Mellencamp (corrected version filed herewith reflecting corrections of
typographical errors).                                                                                   
|               |  |            
|*10.4          |  |            |  | Employment Agreement, dated May 1, 2009, by and between CEP Services Company, Inc. and Michael B. Hiney (corrected version filed herewith reflecting corrections of typographical
errors).                                                                                     
|               |  |            
|10.9           |  |            |  | Form of Grant Agreement for Executive Officers (incorporated by reference to Exhibit 10.9 to the Current Report on Form 8-K filed by Constellation Energy Partners LLC on
May 4, 2009, File No. 001-33147).                                                                    
|               |  |            
|10.10          |  |            |  | Form of Grant Agreement for Independent Managers (incorporated by reference to Exhibit 10.10 to the Current Report on Form 8-K filed by Constellation Energy Partners LLC on May
4, 2009, File No. 001-33147).                                                                 
|               |  |            
|*31.1.         |  |            |  | Certification of Chief Executive Officer, Chief Operating Officer and President of Constellation Energy Partners LLC pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.                                                                                                
|               |  |            
|*31.2.         |  |            |  | Certification of Chief Financial Officer and Treasurer of Constellation Energy Partners LLC pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.                                                                                                                         
|               |  |            
|*32.1.         |  |            |  | Certification of Chief Executive Officer, Chief Operating Officer and President of Constellation Energy Partners LLC pursuant to 18 U.S.C. Section 1350, as adopted pursuant to
Section 906 of the Sarbanes-Oxley Act of 2002.                                                 
|               |  |            
|*32.2.         |  |            |  | Certification of Chief Financial Officer and Treasurer of Constellation Energy Partners LLC pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the
Sarbanes-Oxley Act of 2002.                                                                          



|* | Filed herewith
|- | --------------



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SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, Constellation Energy Partners LLC, the Registrant, has duly caused this
report to be signed on its behalf by the undersigned, thereunto duly authorized.



|                       |  |                                   |  |                                                         
|---------------------- |  | --------------------------------- |  | --------------------------------------------------------
|                       |  | CONSTELLATION ENERGY PARTNERS LLC
|                       |  | (REGISTRANT)                     
|                       |  |                                  
|Date: November 6, 2009 |  | By                                |  | /s/ MICHAEL B. HINEY                                    
|                       |  |                                   |  | Michael B. Hiney Chief
Accounting Officer and Controller



51