##### Table of Contents





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, 2010

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 Street, Suite 1300 Houston, Texas |  | 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         |  |  ̈
|                        |  |                                                  | 
|Non-accelerated filer   |  | x  (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 5, 2010: 23,975,005 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 Results of Operations |    |      | 21 | 
|                             |  | Liquidity and Capital Resources                                                                             |    |      | 29 | 
|                             |  |                                                                                                            
|Item 3.                      |  | Quantitative and Qualitative Disclosures About Market Risk                                                  |    |      | 37 | 
|                             |  |                                                                                                            
|Item 4.                      |  | Controls and Procedures                                                                                     |    |      | 38 | 
|                             | 
|PART IIOther Information    |  |                                                                                                             | 39 |     
|                             |  |                                                                                                            
|Item 1.                      |  | Legal Proceedings                                                                                           |    |      | 39 | 
|                             |  |                                                                                                            
|Item 1A.                     |  | Risk Factors                                                                                                |    |      | 40 | 
|                             |  |                                                                                                            
|Item 2.                      |  | Unregistered Sales of Equity Securities and Use of Proceeds                                                 |    |      | 42 | 
|                             |  |                                                                                                            
|Item 3.                      |  | Defaults Upon Senior Securities                                                                             |    |      | 42 | 
|                             |  |                                                                                                            
|Item 4.                      |  | Reserved                                                                                                    |    |      | 43 | 
|                             |  |                                                                                                            
|Item 5.                      |  | Other Information                                                                                           |    |      | 43 | 
|                             |  |                                                                                                            
|Item 6.                      |  | Exhibits                                                                                                    |    |      | 43 | 
|                             | 
|Signatures                   |  |                                                                                                             | 44 |     



2



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##### Table of Contents



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, |  
|                                                                         |  | 2010                            |            |   | 2009                           |   |            | 2010 |  |   | 2009       |  
|                                                                         |  | (In 000s except unit data)     |           
|                                                                         |  |                                 |            |  
|Revenues                                                                 |  |                                 |            |   |                                |   |            |      |  |   |            |   |  |   |            |  
|Oil and gas sales                                                        |  | $                               | 26,643     |   |                                | $ | 30,663     |      |  | $ | 82,958     |   |  | $ | 94,223     |  
|Gain / (Loss) from mark-to-market activities (see Note 4)                |  |                                 | 21,100     |   |                                |   | (6,368     | )    |  |   | 51,832     |   |  |   | 829        |  
|                                                                         |  |                                 |            |   |                                |   |            |      |  |   |            |   |  |   |            |  
|Total revenues                                                           |  |                                 | 47,743     |   |                                |   | 24,295     |      |  |   | 134,790    |   |  |   | 95,052     |  
|Expenses:                                                                |  |                                 |            |   |                                |   |            |      |  |   |            |   |  |   |            |  
|Operating expenses:                                                      |  |                                 |            |   |                                |   |            |      |  |   |            |   |  |   |            |  
|Lease operating expenses                                                 |  |                                 | 7,953      |   |                                |   | 8,169      |      |  |   | 23,645     |   |  |   | 25,243     |  
|Cost of sales                                                            |  |                                 | 592        |   |                                |   | 586        |      |  |   | 1,949      |   |  |   | 2,030      |  
|Production taxes                                                         |  |                                 | 647        |   |                                |   | 715        |      |  |   | 2,449      |   |  |   | 2,245      |  
|General and administrative expenses                                      |  |                                 | 5,027      |   |                                |   | 4,568      |      |  |   | 14,277     |   |  |   | 14,009     |  
|Exploration costs                                                        |  |                                 | 284        |   |                                |   | 276        |      |  |   | 731        |   |  |   | 482        |  
|(Gain) / Loss on sale of assets                                          |  |                                 |           |   |                                |   |           |      |  |   | (13        | ) |  |   | 14         |  
|Depreciation, depletion, and amortization                                |  |                                 | 26,175     |   |                                |   | 15,214     |      |  |   | 79,598     |   |  |   | 43,883     |  
|Asset impairments (see Note 6)                                           |  |                                 | 270,408    |   |                                |   | 241        |      |  |   | 270,966    |   |  |   | 4,201      |  
|Accretion expense                                                        |  |                                 | 205        |   |                                |   | 109        |      |  |   | 617        |   |  |   | 267        |  
|                                                                         |  |                                 |            |   |                                |   |            |      |  |   |            |   |  |   |            |  
|Total operating expenses                                                 |  |                                 | 311,291    |   |                                |   | 29,878     |      |  |   | 394,219    |   |  |   | 92,374     |  
|Other expenses (income)                                                  |  |                                 |            |   |                                |   |            |      |  |   |            |   |  |   |            |  
|Interest expense                                                         |  |                                 | 3,151      |   |                                |   | 2,884      |      |  |   | 9,966      |   |  |   | 8,106      |  
|Interest expense (Gain)/Loss from mark-to-market activities (see Note 4) |  |                                 | 545        |   |                                |   | 716        |      |  |   | 1,174      |   |  |   | 1,615      |  
|Interest (income)                                                        |  |                                 | (1         | ) |                                |   |           |      |  |   | (2         | ) |  |   | (2         | )
|Other expense (income)                                                   |  |                                 | (120       | ) |                                |   | (82        | )    |  |   | (410       | ) |  |   | (129       | )
|                                                                         |  |                                 |            |   |                                |   |            |      |  |   |            |   |  |   |            |  
|Total other expenses                                                     |  |                                 | 3,575      |   |                                |   | 3,518      |      |  |   | 10,728     |   |  |   | 9,590      |  
|                                                                         |  |                                 |            |   |                                |   |            |      |  |   |            |   |  |   |            |  
|Total expenses                                                           |  |                                 | 314,866    |   |                                |   | 33,396     |      |  |   | 404,947    |   |  |   | 101,964    |  
|                                                                         |  |                                 |            |   |                                |   |            |      |  |   |            |   |  |   |            |  
|Net income (Loss)                                                        |  | $                               | (267,123   | ) |                                | $ | (9,101     | )    |  | $ | (270,157   | ) |  | $ | (6,912     | )
|Other comprehensive (Loss)                                               |  |                                 | (3,677     | ) |                                |   | (9,698     | )    |  |   | (13,227    | ) |  |   | (13,339    | )
|                                                                         |  |                                 |            |   |                                |   |            |      |  |   |            |   |  |   |            |  
|Comprehensive (Loss)                                                     |  | $                               | (270,800   | ) |                                | $ | (18,799    | )    |  | $ | (283,384   | ) |  | $ | (20,251    | )
|                                                                         |  |                                 |            |   |                                |   |            |      |  |   |            |   |  |   |            |  
|Earnings (loss) per unit (see Note 2)                                    |  |                                 |            |   |                                |   |            |      |  |   |            |   |  |   |            |  
|Earnings (loss) per unitBasic                                           |  | $                               | (10.91     | ) |                                | $ | (0.40      | )    |  | $ | (11.10     | ) |  | $ | (0.31      | )
|Units outstandingBasic                                                  |  |                                 | 24,489,229 |   |                                |   | 22,665,098 |      |  |   | 24,345,034 |   |  |   | 22,518,284 |  
|Earnings (loss) per unitDiluted                                         |  | $                               | (10.91     | ) |                                | $ | (0.40      | )    |  | $ | (11.10     | ) |  | $ | (0.31      | )
|Units outstandingDiluted                                                |  |                                 | 24,489,229 |   |                                |   | 22,665,098 |      |  |   | 24,345,034 |   |  |   | 22,518,284 |  
|Distributions declared and paid per unit                                 |  | $                               | 0. 00      |   |                                | $ | 0. 00      |      |  | $ | 0.00       |   |  | $ | 0.26       |  

See accompanying notes
to consolidated financial statements.



3



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CONSTELLATION ENERGY PARTNERS LLC and SUBSIDIARIES

Consolidated Balance Sheets

(Unaudited)



|                                                                                                                                                                                                                                     |  |                    |          |   |                   |   |          |  
|------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------ |  | ------------------ | -------- | - | ----------------- | - | -------- | -
|                                                                                                                                                                                                                                     |  | September 30, 2010 |          |   | December 31, 2009 |  
|                                                                                                                                                                                                                                     |  | (In 000s)         |         
|ASSETS                                                                                                                                                                                                                               |  |                    |          |   |                   |   |          |  
|Current assets                                                                                                                                                                                                                       |  |                    |          |   |                   |   |          |  
|Cash and cash equivalents                                                                                                                                                                                                            |  | $                  | 13,241   |   |                   | $ | 11,337   |  
|Accounts receivable                                                                                                                                                                                                                  |  |                    | 6,735    |   |                   |   | 8,379    |  
|Prepaid expenses                                                                                                                                                                                                                     |  |                    | 984      |   |                   |   | 1,298    |  
|Risk management assets (see Note 4)                                                                                                                                                                                                  |  |                    | 40,630   |   |                   |   | 24,251   |  
|                                                                                                                                                                                                                                     |  |                    |          |   |                   |   |          |  
|Total current assets                                                                                                                                                                                                                 |  |                    | 61,590   |   |                   |   | 45,265   |  
|Oil and natural gas properties (See Note 6)                                                                                                                                                                                          |  |                    |          |   |                   |   |          |  
|Oil and natural gas properties, equipment and facilities                                                                                                                                                                             |  |                    | 767,092  |   |                   |   | 794,520  |  
|Material and supplies                                                                                                                                                                                                                |  |                    | 2,912    |   |                   |   | 4,312    |  
|Less accumulated depreciation, depletion, amortization, and impairments                                                                                                                                                              |  |                    | (492,557 | ) |                   |   | (186,207 | )
|                                                                                                                                                                                                                                     |  |                    |          |   |                   |   |          |  
|Net oil and natural gas properties                                                                                                                                                                                                   |  |                    | 277,447  |   |                   |   | 612,625  |  
|Other assets                                                                                                                                                                                                                         |  |                    |          |   |                   |   |          |  
|Debt issue costs (net of accumulated amortization of $4,387 at September 30, 2010 and $2,924 at December 31,
2009)                                                                                                                   |  |                    | 4,200    |   |                   |   | 5,590    |  
|Risk management assets (see Note 4)                                                                                                                                                                                                  |  |                    | 54,865   |   |                   |   | 33,916   |  
|Other non-current assets                                                                                                                                                                                                             |  |                    | 3,947    |   |                   |   | 10,921   |  
|                                                                                                                                                                                                                                     |  |                    |          |   |                   |   |          |  
|Total assets                                                                                                                                                                                                                         |  | $                  | 402,049  |   |                   | $ | 708,317  |  
|                                                                                                                                                                                                                                     |  |                    |          |   |                   |   |          |  
|LIABILITIES AND MEMBERS EQUITY                                                                                                                                                                                                      |  |                    |          |   |                   |   |          |  
|Liabilities                                                                                                                                                                                                                          |  |                    |          |   |                   |   |          |  
|Current liabilities                                                                                                                                                                                                                  |  |                    |          |   |                   |   |          |  
|Accounts payable                                                                                                                                                                                                                     |  | $                  | 1,707    |   |                   | $ | 1,102    |  
|Payable to affiliate                                                                                                                                                                                                                 |  |                    |         |   |                   |   | 201      |  
|Accrued liabilities                                                                                                                                                                                                                  |  |                    | 9,552    |   |                   |   | 10,033   |  
|Environmental liabilities                                                                                                                                                                                                            |  |                    |         |   |                   |   | 193      |  
|Royalty payable                                                                                                                                                                                                                      |  |                    | 3,048    |   |                   |   | 4,747    |  
|Risk management liabilities (see Note 4)                                                                                                                                                                                             |  |                    | 106      |   |                   |   | 208      |  
|                                                                                                                                                                                                                                     |  |                    |          |   |                   |   |          |  
|Total current liabilities                                                                                                                                                                                                            |  |                    | 14,413   |   |                   |   | 16,484   |  
|Other liabilities                                                                                                                                                                                                                    |  |                    |          |   |                   |   |          |  
|Asset retirement obligation                                                                                                                                                                                                          |  |                    | 12,783   |   |                   |   | 12,129   |  
|Debt                                                                                                                                                                                                                                 |  |                    | 172,500  |   |                   |   | 195,000  |  
|                                                                                                                                                                                                                                     |  |                    |          |   |                   |   |          |  
|Total other liabilities                                                                                                                                                                                                              |  |                    | 185,283  |   |                   |   | 207,129  |  
|                                                                                                                                                                                                                                     |  |                    |          |   |                   |   |          |  
|Total liabilities                                                                                                                                                                                                                    |  |                    | 199,696  |   |                   |   | 223,613  |  
|                                                                                                                                                                                                                                     |  |                   
|Commitments and contingencies (See Note 8)                                                                                                                                                                                           |  |                    |          |   |                   |   |          |  
|                                                                                                                                                                                                                                     |  |                   
|Class D Interests                                                                                                                                                                                                                    |  |                    | 6,667    |   |                   |   | 6,667    |  
|                                                                                                                                                                                                                                     |  |                   
|Members equity                                                                                                                                                                                                                      |  |                    |          |   |                   |   |          |  
|Class A units, 489,286 and 476,950 shares authorized, issued and outstanding at September 30, 2010 and
December 31, 2009, respectively                                                                                               |  |                    | 3,611    |   |                   |   | 8,993    |  
|Class B units, 24,298,763 and 24,298,763 shares authorized at September 30, 2010 and December 31, 2009, respectively,
and 23,975,005 and 23,376,136 issued and outstanding at September 30, 2010 and December 31, 2009, respectively |  |                    | 176,935  |   |                   |   | 440,677  |  
|Accumulated other comprehensive income                                                                                                                                                                                               |  |                    | 15,140   |   |                   |   | 28,367   |  
|                                                                                                                                                                                                                                     |  |                    |          |   |                   |   |          |  
|Total members equity                                                                                                                                                                                                                |  |                    | 195,686  |   |                   |   | 478,037  |  
|                                                                                                                                                                                                                                     |  |                    |          |   |                   |   |          |  
|Total liabilities and members equity                                                                                                                                                                                                |  | $                  | 402,049  |   |                   | $ | 708,317  |  
|                                                                                                                                                                                                                                     |  |                    |          |   |                   |   |          |  

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, |         
|                                                                                     |  | 2010                           |          |   | 2009 |  
|                                                                                     |  | (In 000s)                     |         
|Cash flows from operating activities:                                                |  |                                |          |   |      |   |         |  
|Net income (loss)                                                                    |  | $                              | (270,157 | ) |      | $ | (6,912  | )
|Adjustments to reconcile net income (loss) to cash provided by operating activities: |  |                                |          |   |      |   |         |  
|Depreciation, depletion and amortization                                             |  |                                | 79,598   |   |      |   | 43,883  |  
|Asset impairments (see Note 6)                                                       |  |                                | 270,966  |   |      |   | 4,201   |  
|Amortization of debt issuance costs                                                  |  |                                | 1,463    |   |      |   | 834     |  
|Accretion of plugging and abandonment liability                                      |  |                                | 617      |   |      |   | 267     |  
|(Equity earnings) losses in affiliates                                               |  |                                | (410     | ) |      |   | (129    | )
|(Gain) Loss from disposition of property and equipment                               |  |                                | (13      | ) |      |   | 14      |  
|Dryhole Costs                                                                        |  |                                | 61       |   |      |   | 173     |  
|Hedge ineffectiveness                                                                |  |                                |         |   |      |   | 267     |  
|(Gain) Loss from mark-to-market activities                                           |  |                                | (50,658  | ) |      |   | 787     |  
|Unit-based compensation programs                                                     |  |                                | 1,405    |   |      |   | 288     |  
|Changes in Assets and Liabilities:                                                   |  |                                |          |   |      |   |         |  
|Change in net risk management assets and liabilities                                 |  |                                |         |   |      |   | 419     |  
|(Increase) decrease in accounts receivable                                           |  |                                | 1,644    |   |      |   | 3,798   |  
|(Increase) decrease in prepaid expenses                                              |  |                                | 316      |   |      |   | 92      |  
|(Increase) decrease in other assets                                                  |  |                                |         |   |      |   | 4       |  
|Increase (decrease) in accounts payable                                              |  |                                | 605      |   |      |   | (1,631  | )
|Increase (decrease) in payable to affiliate                                          |  |                                | (201     | ) |      |   | (790    | )
|Increase (decrease) in accrued liabilities                                           |  |                                | (2,613   | ) |      |   | 1,594   |  
|Increase (decrease) in royalty payable                                               |  |                                | (1,699   | ) |      |   | (1,550  | )
|                                                                                     |  |                                |          |   |      |   |         |  
|Net cash provided by operating activities                                            |  |                                | 30,924   |   |      |   | 45,609  |  
|                                                                                     |  |                                |          |   |      |   |         |  
|Cash flows from investing activities:                                                |  |                                |          |   |      |   |         |  
|Cash (paid) / received for acquisitions, net of cash acquired                        |  |                                | (504     | ) |      |   | (170    | )
|Development of natural gas properties                                                |  |                                | (5,889   | ) |      |   | (22,786 | )
|Proceeds from sale of equipment                                                      |  |                                | 38       |   |      |   | 17      |  
|Distributions from equity affiliate                                                  |  |                                | 310      |   |      |   | 360     |  
|                                                                                     |  |                                |          |   |      |   |         |  
|Net cash used in investing activities                                                |  |                                | (6,045   | ) |      |   | (22,579 | )
|                                                                                     |  |                                |          |   |      |   |         |  
|Cash flows from financing activities:                                                |  |                                |          |   |      |   |         |  
|Members distributions                                                               |  |                                |         |   |      |   | (5,820  | )
|Proceeds from issuance of debt                                                       |  |                                |         |   |      |   | 34,500  |  
|Repayment of debt                                                                    |  |                                | (22,500  | ) |      |   | (27,000 | )
|Units tendered by employees                                                          |  |                                | (372     | ) |      |   |        |  
|Equity issue costs                                                                   |  |                                | (2       | ) |      |   | (80     | )
|Debt issue costs                                                                     |  |                                | (101     | ) |      |   | (98     | )
|                                                                                     |  |                                |          |   |      |   |         |  
|Net cash provided by (used in) financing activities                                  |  |                                | (22,975  | ) |      |   | 1,502   |  
|                                                                                     |  |                                |          |   |      |   |         |  
|Net (decrease) increase in cash                                                      |  |                                | 1,904    |   |      |   | 24,532  |  
|Cash and cash equivalents, beginning of period                                       |  |                                | 11,337   |   |      |   | 6,255   |  
|                                                                                     |  |                                |          |   |      |   |         |  
|Cash and cash equivalents, end of period                                             |  | $                              | 13,241   |   |      | $ | 30,787  |  
|                                                                                     |  |                                |          |   |      |   |         |  
|Supplemental disclosures of cash flow information:                                   |  |                                |          |   |      |   |         |  
|Change in accrued capital expenditures                                               |  | $                              | 1,900    |   |      | $ | (396    | )
|Cash received during the period for interest                                         |  | $                              | 2        |   |      | $ | 2       |  
|Cash paid during the period for interest                                             |  | $                              | (5,842   | ) |      | $ | (5,265  | )

See accompanying notes to
consolidated financial statements.



5



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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, 2009                      |  |                                  | 476,950 |  |         | $ | 8,993  |                                            |  |  | 23,376,136          |  |  | $ | 440,677  |   |  | $ | 28,367  |   |  | $ | 478,037  |  
|Units tendered by employees for tax withholding |  |                                  |        |  |         |   | (7     | )                                          |  |  |                    |  |  |   | (365     | ) |  |   |        |   |  |   | (372     | )
|Change in fair value of commodity hedges        |  |                                  |        |  |         |   |       |                                            |  |  |                    |  |  |   |         |   |  |   | 157     |   |  |   | 157      |  
|Cash settlement of commodity hedges             |  |                                  |        |  |         |   |       |                                            |  |  |                    |  |  |   |         |   |  |   | (13,773 | ) |  |   | (13,773  | )
|Cash settlement of interest rate hedges         |  |                                  |        |  |         |   |       |                                            |  |  |                    |  |  |   |         |   |  |   | 389     |   |  |   | 389      |  
|Unit-based compensation programs                |  |                                  | 12,336  |  |         |   | 28     |                                            |  |  | 598,869             |  |  |   | 1,377    |   |  |   |        |   |  |   | 1,405    |  
|Net income (loss)                               |  |                                  |        |  |         |   | (5,403 | )                                          |  |  |                    |  |  |   | (264,754 | ) |  |   |        |   |  |   | (270,157 | )
|                                                |  |                                  |         |  |         |   |        |                                            |  |  |                     |  |  |   |          |   |  |   |         |   |  |   |          |  
|Balance, September 30, 2010                     |  |                                  | 489,286 |  |         | $ | 3,611  |                                            |  |  | 23,975,005          |  |  | $ | 176,935  |   |  | $ | 15,140  |   |  | $ | 195,686  |  
|                                                |  |                                  |         |  |         |   |        |                                            |  |  |                     |  |  |   |          |   |  |   |         |   |  |   |          |  

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, 2010, 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, 2009.
Certain amounts in the consolidated financial statements and notes thereto have been reclassified to conform to the 2010 financial statement presentation.

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, we, us, our or the Company). We completed our initial public offering on November 20, 2006, and trade on the NYSE Arca under the symbol
CEP. We are 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, 2010,
affiliates of Constellation own all of our Class A units, all of the management incentive interests, approximately 25% of our common units and all of our Class D interests.

We are 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. 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 us conform to accounting principles generally accepted in the United States of America. The accompanying
financial statements include the accounts of us and our wholly-owned subsidiaries. All significant intercompany accounts and transactions have been eliminated in consolidation. We operate our oil and natural gas properties as one business segment:
the exploration, development and production of natural gas. Our management evaluates performance based on one business segment as there are not different economic environments within the operation of our oil and natural gas properties.

2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Our significant accounting policies are consistent with those discussed in our Annual Report on Form 10-K for the year ended December 31, 2009.

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, 2010, we had 489,286 Class A units and 23,975,005 Class B units outstanding. Of the Class B units, 1,725,731 units are restricted unvested common units granted and outstanding.

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, 2010 |  |                             |          |   |       |  |            |                | 
|Basic EPS:                                    |  |                             |          |   |       |  |            |                |  |   |        |  
|Income (loss) allocable to unitholders        |  | $                           | (267,123 | ) |       |  | 24,489,229 |                |  | $ | (10.91 | )
|Effect of dilutive securities:                |  |                             |          |   |       |  |            |                |  |   |        |  
|Restricted common unitsTreasury stock method |  |                             |         |   |       |  |           |                |  |   |       |  
|                                              |  |                             |          |   |       |  |            |                |  |   |        |  



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|                                              |  |                             |          |   |       |  |            |                |  |   |        |  
|--------------------------------------------- |  | --------------------------- | -------- | - | ----- |  | ---------- | -------------- |  | - | ------ | -
|                                              |  | Income                      |          |   | Units |  |            | Per UnitAmount | 
|                                              |  | (In 000s except unit data) |         
|For the three months ended September 30, 2010 |  |                             |          |   |       |  |            |                | 
|Diluted EPS:                                  |  |                             |          |   |       |  |            |                |  |   |        |  
|Income (loss) allocable to common unitholders |  | $                           | (267,123 | ) |       |  | 24,489,229 |                |  | $ | (10.91 | )
|                                              |  |                             |         
|                                              |  | Income                      |          |   | Units |  |            | Per UnitAmount | 
|                                              |  | (In 000s except unit data) |         
|For the nine months ended September 30, 2010  |  |                             |          |   |       |  |            |                | 
|Basic EPS:                                    |  |                             |          |   |       |  |            |                |  |   |        |  
|Income (loss) allocable to unitholders        |  | $                           | (270,157 | ) |       |  | 24,345,034 |                |  | $ | (11.10 | )
|Effect of dilutive securities:                |  |                             |          |   |       |  |            |                |  |   |        |  
|Restricted common unitsTreasury stock method |  |                             |         |   |       |  |           |                |  |   |       |  
|                                              |  |                             |          |   |       |  |            |                |  |   |        |  
|Diluted EPS:                                  |  |                             |          |   |       |  |            |                |  |   |        |  
|Income (loss) allocable to common unitholders |  | $                           | (270,157 | ) |       |  | 24,345,034 |                |  | $ | (11.10 | )
|                                              |  |                             |         
|                                              |  | Income                      |          |   | Units |  |            | Per UnitAmount | 
|                                              |  | (In 000s except unit data) |         
|For the three months ended September 30, 2009 |  |                             |          |   |       |  |            |                | 
|Basic EPS:                                    |  |                             |          |   |       |  |            |                |  |   |        |  
|Income (loss) allocable to unitholders        |  | $                           | (9,101   | ) |       |  | 22,665,098 |                |  | $ | (0.40  | )
|Effect of dilutive securities:                |  |                             |          |   |       |  |            |                |  |   |        |  
|Restricted common unitsTreasury stock method |  |                             |         |   |       |  |           |                |  |   |       |  
|                                              |  |                             |          |   |       |  |            |                |  |   |        |  
|Diluted EPS:                                  |  |                             |          |   |       |  |            |                |  |   |        |  
|Income (loss) allocable to common unitholders |  | $                           | (9,101   | ) |       |  | 22,665,098 |                |  | $ | (0.40  | )
|                                              |  |                             |         
|                                              |  | Income                      |          |   | Units |  |            | Per UnitAmount | 
|                                              |  | (In 000s except unit data) |         
|For the nine months ended September 30, 2009  |  |                             |          |   |       |  |            |                | 
|Basic EPS:                                    |  |                             |          |   |       |  |            |                |  |   |        |  
|Income (loss) allocable to unitholders        |  | $                           | (6,912   | ) |       |  | 22,518,284 |                |  | $ | (0.31  | )
|Effect of dilutive securities:                |  |                             |          |   |       |  |            |                |  |   |        |  
|Restricted common unitsTreasury stock method |  |                             |         |   |       |  |           |                |  |   |       |  
|                                              |  |                             |          |   |       |  |            |                |  |   |        |  
|Diluted EPS:                                  |  |                             |          |   |       |  |            |                |  |   |        |  
|Income (loss) allocable to common unitholders |  | $                           | (6,912   | ) |       |  | 22,518,284 |                |  | $ | (0.31  | )

3. NEW ACCOUNTING PRONOUNCEMENTS

In January 2010, the FASB issued its final guidance on additional supplemental fair value disclosures. Two new disclosures
are required: (1) a gross presentation of activities (purchases, sales, and settlements) within the Level 3 roll forward reconciliation, which will replace the net presentation format, and (2) detailed disclosures
about the transfers between Level 1 and 2 measurements. The guidance also provides several clarifications regarding the level of disaggregation and disclosures about inputs and valuation techniques. The new disclosures became effective for the first
quarter 2010 for calendar year-end companies, except for the Level 3 gross activity disclosures, which will be deferred until the first quarter of 2011. The adoption of this guidance did not have a material impact on our financial
statements or our disclosures.

In February 2010, the FASB amended its guidance on subsequent events. SEC filers are now not
required to disclose the date through which an entity has evaluated subsequent events. The amended guidance was effective upon issuance. The adoption of this guidance did not have an impact on our financial statements or our disclosures.

New Accounting Pronouncements Issued But Not Yet Adopted

As of September 30, 2010, there were a number of accounting standards and interpretations that had been issued, but not yet adopted by us. We are currently reviewing the recently issued standards and
interpretations but none are expected to have a material impact on our financial statements.



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4. DERIVATIVE AND FINANCIAL
INSTRUMENTS

Mark-to-Market Activities

We have hedged a portion of our expected natural gas sales from currently producing wells through December 2014. All of our swaps and basis swaps were accounted for as mark-to-market activities as of
September 30, 2010.

At September 30, 2010 and December 31, 2009, we had debt outstanding of $172.5 million and
$195.0 million, respectively, under our reserve-based credit facility. We have 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 $112.0 million of outstanding debt for various maturities extending through October 2014. All of our interest rate swaps are accounted for as mark-to-market activities as of September 30, 2010. Prior to February 2009,
they were accounted for as cash flow hedges.

For the nine months ended September 30, 2010 and for 2009, we recognized
mark-to-market gains of approximately $51.8 million and $0.8 million, respectively, in connection with our commodity derivatives. For the nine months ended September 30, 2010 and for 2009, we recognized mark-to-market losses of approximately
$1.2 million and $1.6 million, respectively, in connection with our interest rate derivatives. At September 30, 2010 and December 31, 2009, the fair value of the derivatives accounted for as mark-to-market activities amounted to a net
asset of approximately $95.4 million and a net asset of approximately $58.0 million, respectively.

Accumulated Other Comprehensive
Income

Prior to the first quarter of 2009, we accounted for certain of our 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 $15.1 million and an unrecognized gain of approximately
$28.4 million at September 30, 2010 and December 31, 2009, respectively. We expect that the unrecognized gain will be reclassified from accumulated other comprehensive income (loss) (AOCI) to the income statement in the
following periods:



|                      |  |                      |        |  |                     |   |      |            |  |   |        | 
|--------------------- |  | -------------------- | ------ |  | ------------------- | - | ---- | ---------- |  | - | ------ | 
|For the Quarter Ended |  | CommodityDerivatives |        |  | Non-performanceRisk |   |      | Total AOCI | 
|December 31, 2010     |  | $                    | 3,568  |  |                     | $ | (62  | )          |  | $ | 3,506  | 
|March 31, 2011        |  |                      | 922    |  |                     |   | (28  | )          |  |   | 894    | 
|June 30, 2011         |  |                      | 2,147  |  |                     |   | (78  | )          |  |   | 2,069  | 
|September 30, 2011    |  |                      | 1,921  |  |                     |   | (78  | )          |  |   | 1,843  | 
|December 31, 2011     |  |                      | 1,456  |  |                     |   | (65  | )          |  |   | 1,391  | 
|March 31, 2012        |  |                      | 718    |  |                     |   | (22  | )          |  |   | 696    | 
|June 30, 2012         |  |                      | 1,928  |  |                     |   | (66  | )          |  |   | 1,862  | 
|September 30, 2012    |  |                      | 1,721  |  |                     |   | (63  | )          |  |   | 1,658  | 
|December 31, 2012     |  |                      | 1,271  |  |                     |   | (50  | )          |  |   | 1,221  | 
|                      |  |                      |        |  |                     |   |      |            |  |   |        | 
|Total                 |  | $                    | 15,652 |  |                     | $ | (512 | )          |  | $ | 15,140 | 
|                      |  |                      |        |  |                     |   |      |            |  |   |        | 

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 our 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.

The 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.
| | - |  | --------------------------------------------------------------------------------------------------------------



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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.

Our 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 set forth by level within the fair value hierarchy our assets and liabilities that were measured at fair value on a
recurring basis as of September 30, 2010 and December 31, 2009.



|                            |  |            |   |  |              |   |         |                            |  |   |                     |   |  |   |   |  |  |   |        |  
|--------------------------- |  | ---------- | - |  | ------------ | - | ------- | -------------------------- |  | - | ------------------- | - |  | - | - |  |  | - | ------ | -
|                            |  | Commodity  |   |  | Interestrate |   |         | Netting andCashCollateral* |  |   | Total Net FairValue |  
|At September 30, 2010       |  | Level 1    |   |  | Level 2      |   |         | Level 3                    |  |   |                    
|                            |  | (In 000s) |  
|Risk management assets      |  | $          |  |  |              | $ | 101,007 |                            |  | $ | (5,512              | ) |  | $ |  |  |  | $ | 95,495 |  
|Risk management liabilities |  | $          |  |  |              | $ | (106    | )                          |  | $ |                    |   |  | $ |  |  |  | $ | (106   | )
|                            |  |            |   |  |              |   |         |                            |  |   |                     |   |  |   |   |  |  |   |        |  
|Total                       |  | $          |  |  |              | $ | 100,901 |                            |  | $ | (5,512              | ) |  | $ |  |  |  | $ | 95,389 |  
|                            |  |            |   |  |              |   |         |                            |  |   |                     |   |  |   |   |  |  |   |        |  



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



|                            |  |            |   |  |              |   |        |                            |  |   |                     |   |  |   |   |  |  |   |        |  
|--------------------------- |  | ---------- | - |  | ------------ | - | ------ | -------------------------- |  | - | ------------------- | - |  | - | - |  |  | - | ------ | -
|                            |  | Commodity  |   |  | Interestrate |   |        | Netting andCashCollateral* |  |   | Total Net FairValue |  
|At December 31, 2009        |  | Level 1    |   |  | Level 2      |   |        | Level 3                    |  |   |                    
|                            |  | (In 000s) |  
|Risk management assets      |  | $          |  |  |              | $ | 62,894 |                            |  | $ | (4,727              | ) |  | $ |  |  |  | $ | 58,167 |  
|Risk management liabilities |  | $          |  |  |              | $ | (208   | )                          |  | $ |                    |   |  | $ |  |  |  | $ | (208   | )
|                            |  |            |   |  |              |   |        |                            |  |   |                     |   |  |   |   |  |  |   |        |  
|Total                       |  | $          |  |  |              | $ | 62,686 |                            |  | $ | (4,727              | ) |  | $ |  |  |  | $ | 57,959 |  
|                            |  |            |   |  |              |   |        |                            |  |   |                     |   |  |   |   |  |  |   |        |  



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

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 7). 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 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 facility to provide credit support for our
derivative transactions. As a result, we do not post cash collateral with our counterparties, and have minimal 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, 2010, the impact of non-performance credit risk on the valuation of our assets from counterparties was $1.3 million, of which $0.8
million was reflected as a decrease to our non-cash mark-to-market gain and $0.5 million was reflected as a reduction to our accumulated other comprehensive income. 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 mark-to-market gain and $0.9 million was reflected as a reduction to our accumulated other comprehensive income.



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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, 2010(In 000s) |        |   | Nine MonthsEndedSeptember 30, 2010(In 000s) |  
|Balance at beginning of period                                                         |  | $                                             | (4,968 | ) |                                              | $ | (4,727 | )
|Realized and unrealized gain (loss):                                                   |  |                                               |        |   |                                              |   |        |  
|Included in earnings                                                                   |  |                                               | (1,513 | ) |                                              |   | (4,387 | )
|Included in other comprehensive income                                                 |  |                                               |       |   |                                              |   | 389    |  
|Purchases, sales, issuances, and settlements                                           |  |                                               | 969    |   |                                              |   | 3,213  |  
|Transfers into and out of Level 3                                                      |  |                                               |       |   |                                              |   |       |  
|                                                                                       |  |                                               |        |   |                                              |   |        |  
|Balance as of September 30, 2010                                                       |  | $                                             | (5,512 | ) |                                              | $ | (5,512 | )
|                                                                                       |  |                                               |        |   |                                              |   |        |  
|                                                                                       |  |                                              
|Change in unrealized gains relating to derivatives still held as of September 30, 2010 |  | $                                             | (1,513 | ) |                                              | $ | (4,387 | )
|                                                                                       |  |                                               |        |   |                                              |   |        |  
|                                                                                       |  |                                              
|                                                                                       |  | 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 gain (loss):                                                   |  |                                               |        |   |                                              |   |        |  
|Included in earnings                                                                   |  |                                               | (2,903 | ) |                                              |   | (9,839 | )
|Included in other comprehensive income                                                 |  |                                               |       |   |                                              |   | (1,311 | )
|Purchases, sales, issuances, and settlements                                           |  |                                               | 2,536  |   |                                              |   | 3,765  |  
|Transfers into and out of Level 3                                                      |  |                                               | (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 | )
|                                                                                       |  |                                               |        |   |                                              |   |        |  

Fair Value of Financial Instruments

At September 30, 2010, 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. We believe 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.



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The following fair
value disclosures are applicable to our financial statements, as of September 30, 2010 and December 31, 2009:



|                  |  |                                                              |  |                                            |                             |   |                                      |   |        |  
|----------------- |  | ------------------------------------------------------------ |  | ------------------------------------------ | --------------------------- | - | ------------------------------------ | - | ------ | -
|Derivative Type   |  | Location of Asset /
(Liability)                              |  | Fair Value of Asset /(Liability)(in 000s) |                            
|                  |  | Nine Months EndedSeptember 30, 2010                          |  |                                            | Year EndedDecember 31, 2009 |  
|Commodity-MTM     |  | Risk management assets-current                               |  | $                                          | 44,566                      |   |                                      | $ | 30,292 |  
|Commodity-MTM     |  | Risk management assets-non-current                           |  |                                            | 70,559                      |   |                                      |   | 47,285 |  
|Commodity-MTM     |  | Risk management assets-current                               |  |                                            | (3,936                      | ) |                                      |   | (6,041 | )
|Commodity-MTM     |  | Risk management assets-non-current                           |  |                                            | (10,182                     | ) |                                      |   | (8,642 | )
|Commodity-MTM     |  | Risk management liabilities-non-current                      |  |                                            | (106                        | ) |                                      |   | (208   | )
|Interest Rate-MTM |  | Risk management assets-current                               |  |                                            | (5,512                      | ) |                                      |   | (4,727 | )
|                  |  |                                                              |  |                                            |                             |   |                                      |   |        |  
|                  |  | Total Derivatives                                            |  | $                                          | 95,389                      |   |                                      | $ | 57,959 |  
|                  |  |                                                              |  |                                            |                             |   |                                      |   |        |  
|                  |  |                                                             
|                  |  |                                                              |  | Amount of Gain / (Loss)in Income(in 000s) |                            
|Derivative Type   |  | Location of Gain / (Loss)
in Income                          |  | Three Months EndedSeptember 30, 2010       |                             |   | Three Months EndedSeptember 30, 2009 |  
|Commodity-MTM     |  | Gain/(Loss) from mark-to-market activities                   |  | $                                          | 21,100                      |   |                                      | $ | (6,368 | )
|Commodity-MTM     |  | Oil and gas sales                                            |  |                                            | 6,047                       |   |                                      |   | 5,126  |  
|Interest Rate-MTM |  | Interest expense-Gain/(Loss) from mark-to-market activities  |  |                                            | (545                        | ) |                                      |   | (716   | )
|Interest Rate-MTM |  | Interest expense                                             |  |                                            | (969                        | ) |                                      |   | (1,399 | )
|                  |  |                                                              |  |                                            |                             |   |                                      |   |        |  
|                  |  | Total                                                        |  | $                                          | 25,633                      |   |                                      | $ | (3,357 | )
|                  |  |                                                              |  |                                            |                             |   |                                      |   |        |  
|                  |  |                                                             
|                  |  |                                                              |  | Amount of Gain / (Loss)in Income(in 000s) |                            
|Derivative Type   |  | Location of Gain / (Loss)
in Income                          |  | Nine Months EndedSeptember 30, 2010        |                             |   | Nine Months EndedSeptember 30, 2009  |  
|Commodity-MTM     |  | Gain/(Loss) from mark-to-market activities                   |  | $                                          | 51,832                      |   |                                      | $ | 829    |  
|Commodity-MTM     |  | Oil and gas sales                                            |  |                                            | 15,033                      |   |                                      |   | 11,924 |  
|Interest Rate-MTM |  | Interest expense- Gain/(Loss) from mark-to-market activities |  |                                            | (1,174                      | ) |                                      |   | (1,615 | )
|Interest Rate-MTM |  | Interest expense                                             |  |                                            | (2,824                      | ) |                                      |   | (3,228 | )
|                  |  |                                                              |  |                                            |                             |   |                                      |   |        |  
|                  |  | Total                                                        |  | $                                          | 62,867                      |   |                                      | $ | 7,910  |  
|                  |  |                                                              |  |                                            |                             |   |                                      |   |        |  



|                        |  |                                                                                         |  |                                     |                                      |  |                        |                                      |        |   |                                      |   |   |  |  |   |   | 
|----------------------- |  | --------------------------------------------------------------------------------------- |  | ----------------------------------- | ------------------------------------ |  | ---------------------- | ------------------------------------ | ------ | - | ------------------------------------ | - | - |  |  | - | - | 
|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              | 
|                        |  | Three Months EndedSeptember 30, 2010                                                    |  |                                     | Three Months EndedSeptember 30, 2009 |  |                        | Three Months EndedSeptember 30, 2010 |        |   | Three Months EndedSeptember 30, 2009 |  
|Commodity-Cash Flow     |  | Oil and gas sales                                                                       |  | $                                   | 3,726                                |  |                        | $                                    | 11,039 |   |                                      | $ |  |  |  | $ |  | 
|Interest Rate-Cash Flow |  | Interest expense                                                                        |  |                                     |                                     |  |                        |                                      | (1,273 | ) |                                      |   |  |  |  |   |  | 
|                        |  |                                                                                         |  |                                     |                                      |  |                        |                                      |        |   |                                      |   |   |  |  |   |   | 
|                        |  | Total                                                                                   |  | $                                   | 3,726                                |  |                        | $                                    | 9,766  |   |                                      | $ |  |  |  | $ |  | 
|                        |  |                                                                                         |  |                                     |                                      |  |                        |                                      |        |   |                                      |   |   |  |  |   |   | 



|                        |  |                                                                                         |  |                                     |                                     |   |                        |                                     |        |   |                                     |   |   |  |  |   |     | 
|----------------------- |  | --------------------------------------------------------------------------------------- |  | ----------------------------------- | ----------------------------------- | - | ---------------------- | ----------------------------------- | ------ | - | ----------------------------------- | - | - |  |  | - | --- | 
|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             |  
|                        |  | Nine Months EndedSeptember 30, 2010                                                     |  |                                     | Nine Months EndedSeptember 30, 2009 |   |                        | Nine Months EndedSeptember 30, 2010 |        |   | Nine Months EndedSeptember 30, 2009 |  
|Commodity-Cash Flow     |  | Oil and gas sales                                                                       |  | $                                   | 13,774                              |   |                        | $                                   | 36,810 |   |                                     | $ |  |  |  | $ | 267 | 
|Interest Rate-Cash Flow |  | Interest expense                                                                        |  |                                     | (389                                | ) |                        |                                     | (3,113 | ) |                                     |   |  |  |  |   |    | 
|                        |  |                                                                                         |  |                                     |                                     |   |                        |                                     |        |   |                                     |   |   |  |  |   |     | 
|                        |  | Total                                                                                   |  | $                                   | 13,385                              |   |                        | $                                   | 33,697 |   |                                     | $ |  |  |  | $ | 267 | 
|                        |  |                                                                                         |  |                                     |                                     |   |                        |                                     |        |   |                                     |   |   |  |  |   |     | 



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As of
September 30, 2010, we have interest rate swaps on $112.0 million of outstanding debt for various maturities extending through October 2014, various commodity swaps for 36,420,000 MMbtu of natural gas production through December 2014, and
various basis swaps for 23,180,407 MMbtu of natural gas production in the Cherokee Basin through December 2014.

5. DEBT

Reserve-Based Credit Facility

On November 13, 2009, we entered into an amended and restated $350.0 million reserve-based credit facility with The Royal Bank of Scotland plc as administrative agent and a syndicate of lenders. The
reserve-based credit facility amends, extends, and consolidates our previous reserve-based credit facilities and matures on November 13, 2012. Borrowings under the reserve-based credit facility are secured by various mortgages of oil and
natural gas properties that we and certain of our subsidiaries own as well as various security and pledge agreements among us and certain of our subsidiaries and the administrative agent. The current lenders and their percentage commitments in the
reserve-based credit facility are: The Royal Bank of Scotland plc (26.84%), BNP Paribas (21.95%), The Bank of Nova Scotia (21.95%), Wells Fargo Bank, N.A. (14.63%), and Societe Generale (14.63%).

The amount available for borrowing at any one time under the reserve-based credit facility is limited to the borrowing base for our oil
and natural gas properties in Alabama, Kansas, and Oklahoma. As of September 30, 2010, our borrowing base was $205.0 million. The borrowing base is redetermined semi-annually, and may be redetermined at our request more frequently and by the
lenders, in their sole discretion, based on reserve reports as prepared by petroleum engineers, together with, among other things, the oil and natural gas prices prevailing at such time. Outstanding borrowings in excess of our borrowing base must be
repaid or we must pledge other oil and natural gas properties as additional collateral. We may elect to pay any borrowing base deficiency in three equal monthly installments such that the deficiency is eliminated in a period of three months. Any
increase in our borrowing base must be approved by all of the lenders.

Borrowings under the reserve-based credit facility are
available for acquisition, exploration, operation and maintenance of oil and natural gas properties, payment of expenses incurred in connection with the reserve-based credit facility, working capital and general limited liability company purposes.
The reserve-based credit facility has a sub-limit of $20.0 million which may be used for the issuance of letters of credit. As of September 30, 2010, no letters of credit are outstanding.

At our election, interest for borrowings are determined by reference to (i) the London interbank rate, or LIBOR, plus an applicable
margin between 2.50% and 3.50% per annum based on utilization or (ii) a domestic bank rate (ABR) plus an applicable margin between 1.50% and 2.50% per annum based on utilization plus (iii) a commitment fee of
0.50% per annum based on the unutilized borrowing base. Interest on the borrowings for ABR loans and the commitment fee are generally payable quarterly. Interest on the borrowings for LIBOR loans are generally payable at the applicable maturity
date.

The reserve-based credit facility contains various covenants that limit, among other things, our ability and certain of
our subsidiaries ability to incur certain indebtedness, grant certain liens, merge or consolidate, sell all or substantially all of our assets, make certain loans, acquisitions, capital expenditures and investments, and make distributions to
unitholders.

In addition, we are required to maintain (i) a ratio of Total Net Debt (defined as Debt (generally
indebtedness permitted to be incurred by us under the reserve-based credit facility) less Available Cash (generally, cash, cash equivalents, and cash reserves of the Company)) to Adjusted EBITDA (defined as, for any period, the sum of consolidated
net income for such period plus (minus) 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, exploration costs, (gain) loss from equity investment, accretion of asset retirement obligation, unrealized (gain) loss on derivatives and realized (gain) loss on cancelled derivatives, and other
similar charges) of not more than 3.75 to 1.0 through September 30, 2010 and 3.50 to 1.0 thereafter; (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 (to the extent such payments are not past due), 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 our consolidated
financial information.

The reserve-based 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 reserve-based credit facility and a change of control. If an event of default occurs, the lenders will be able to accelerate the maturity of the reserve-based credit facility and exercise
other rights and remedies. The reserve-based 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 us and our subsidiaries who are guarantors taken as a whole. If a MAE were to occur, we would be prohibited
from borrowing under the reserve-based credit facility and would be in default, which could cause all of our existing indebtedness to become immediately due and payable.



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We have the ability to
pay distributions to unitholders from available cash, including cash from borrowings under the reserve-based credit facility, as long as no event of default exists and provided that no distributions to unitholders may be made if the borrowings
outstanding, net of available cash, under the reserve-based credit facility exceed 90% of the borrowing base, after giving effect to the proposed distribution. Our available cash is reduced by any cash reserves established by our board of managers
for the proper conduct of our business and the payment of fees and expenses. As of September 30, 2010, we were restricted from paying distributions to unitholders as we had no available cash (taking into account the cash reserves set by our
board of managers for the proper conduct of our business) from which to make distributions.

The reserve-based credit facility
permits us to hedge our projected monthly production, provided that (a) for the immediately ensuing twelve month period, the volumes of production hedged in any month may not exceed our reasonable business judgment of the production for such
month consistent with the application of petroleum engineering methodologies for estimating proved developed producing reserves based on the then strip pricing (provided that such projection shall not be more than 115% of the proved developed
producing reserves forecast for the same period derived from the most recent reserve report of our petroleum engineers using the then strip pricing), and (b) for the period beyond twelve months, the volumes of production hedged in any month may
not exceed the reasonably anticipated projected production from proved developed producing reserves estimated by our petroleum engineers. The reserve-based credit facility also permits us to hedge the interest rate on up to 90% of the
then-outstanding principal amounts of our indebtedness for borrowed money.

The reserve-based credit facility contains no
covenants related to our relationship with Constellation or Constellations right to appoint all of the Class A managers of our board of managers.

Debt Issue Costs

As of September 30, 2010, our unamortized debt issue
costs were approximately $4.2 million. These costs are being amortized over the life of the reserve-based credit facility through November 2012.

Funds Available for Borrowing

As of September 30, 2010 and
December 31, 2009, we had $172.5 million and $195.0 million, respectively, in outstanding debt under our reserve-based credit facility. As of September 30, 2010, we had $32.5 million in remaining borrowing capacity under the reserve-based
credit facility. See Note 15 for additional information.

Compliance with Debt Covenants

At September 30, 2010, we believe that we were in compliance with the financial covenant ratios contained in our reserve-based credit facility. We
monitor compliance on an ongoing basis. As of September 30, 2010, our actual Total Net Debt to Adjusted EBITDA ratio was 2.7 to 1.0 as compared with a required ratio of not greater than 3.75 to 1.0, our actual ratio of consolidated current
assets to consolidated current liabilities was 3.7 to 1.0 as compared with a required ratio of not less than 1.0 to 1.0, and our actual Adjusted EBITDA to cash interest expense ratio was 6.0 to 1.0 as compared with a required ratio of not less than
2.5 to 1.0. As of December 31, 2010 and thereafter, our required financial covenant ratio of Total Net Debt to Adjusted EBITDA is reduced to not greater than 3.5 to 1.0.

If we are unable to remain in compliance with the financial covenants associated with our reserve-based credit facility or maintain the required ratios discussed above, we could request waivers from the
lenders in our bank group. Although the lenders may not provide a waiver, we could take additional steps in the event of not meeting the required ratios or in the event of a reduction in the borrowing base below its current level of $205.0 million
at one of the future redeterminations by the lenders. During 2010, we intend to use our surplus operating cash flows to reduce our outstanding debt. If it becomes necessary to pay debt down beyond operating cash flows, we could further reduce
capital expenditures, continue to suspend our quarterly distributions to unitholders, sell oil and natural gas properties, liquidate in the money derivative positions, further reduce operating and administrative costs, or take additional steps to
increase liquidity. If we were unable to obtain a waiver and were unsuccessful at reducing our debt to the then necessary level, our debt could become due and payable upon acceleration by the lenders. To the extent that we do not enter into an
agreement to refinance or extend the due date on the reserve-based credit facility, the outstanding debt balance at November 13, 2011, will become a current liability.



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6. OIL AND NATURAL GAS PROPERTIES

Natural gas properties consist of the following:



|                                                                                 |  |                   |          |   |                  |   |          |  
|-------------------------------------------------------------------------------- |  | ----------------- | -------- | - | ---------------- | - | -------- | -
|                                                                                 |  | September 30,2010 |          |   | December 31,2009 |  
|                                                                                 |  | (In 000s)        |         
|Oil and natural gas properties and related equipment (successful efforts method) |  |                   |          |   |                  |   |          |  
|Property (acreage) costs                                                         |  |                   |          |   |                  |   |          |  
|Proved property                                                                  |  | $                 | 766,180  |   |                  | $ | 756,461  |  
|Unproved property                                                                |  |                   |         |   |                  |   | 37,147   |  
|                                                                                 |  |                   |          |   |                  |   |          |  
|                                                                                 |  |                  
|Total property costs                                                             |  |                   | 766,180  |   |                  |   | 793,608  |  
|Materials and supplies                                                           |  |                   | 2,912    |   |                  |   | 4,312    |  
|Land                                                                             |  |                   | 912      |   |                  |   | 912      |  
|                                                                                 |  |                   |          |   |                  |   |          |  
|                                                                                 |  |                  
|Total                                                                            |  |                   | 770,004  |   |                  |   | 798,832  |  
|Less: Accumulated depreciation, depletion, amortization, and impairments         |  |                   | (492,557 | ) |                  |   | (186,207 | )
|                                                                                 |  |                   |          |   |                  |   |          |  
|                                                                                 |  |                  
|Natural gas properties and equipment, net                                        |  | $                 | 277,447  |   |                  | $ | 612,625  |  
|                                                                                 |  |                   |          |   |                  |   |          |  

Depletion, depreciation, amortization and asset impairments consisted of the following:



|                                           |  |                                   |         |  |                                    |   |        |                                   |  |   |                                   |  |  |   |        | 
|------------------------------------------ |  | --------------------------------- | ------- |  | ---------------------------------- | - | ------ | --------------------------------- |  | - | --------------------------------- |  |  | - | ------ | 
|                                           |  |                                   |         | 
|                                           |  | ThreeMonthsEndedSeptember 30,2010 |         |  | ThreeMonthsEndedSeptember 
30,2009 |   |        | NineMonthsEndedSeptember 
30,2010 |  |   | NineMonthsEndedSeptember 
30,2009 | 
|                                           |  | (In 000s)                        |        
|DD&A of oil and natural gas-related assets |  | $                                 | 26,175  |  |                                    | $ | 15,214 |                                   |  | $ | 79,598                            |  |  | $ | 43,883 | 
|Asset impairments                          |  |                                   | 270,408 |  |                                    |   | 241    |                                   |  |   | 270,966                           |  |  |   | 4,201  | 
|                                           |  |                                   |         |  |                                    |   |        |                                   |  |   |                                   |  |  |   |        | 
|Total                                      |  | $                                 | 296,583 |  |                                    | $ | 15,455 |                                   |  | $ | 350,564                           |  |  | $ | 48,084 | 
|                                           |  |                                   |         |  |                                    |   |        |                                   |  |   |                                   |  |  |   |        | 

Impairment of Oil and Natural Gas Properties and Other Non-Current Assets

At September 30, 2010, due to a significant decline in future natural gas price curves across all future production periods, we
performed an interim impairment analysis of our oil and natural gas properties and other non-current assets. For the nine months ended September 30, 2010, we recorded a total non-cash impairment charge of approximately $271.0 million, composed
of $263.4 million to impair the value of our proved and unproved oil and natural gas properties in the Cherokee Basin, $6.3 million to impair our other non-current assets related to our activities in the Cherokee Basin, $0.8 million to impair
certain of our wells in the Woodford Shale, and $0.5 million to impair the value of our casing inventory. These non-cash charges are included in asset impairments in the Consolidated Statement of Operations. This impairment of our proved Cherokee
Basin oil and natural gas properties and the impairment of certain of our wells located in the Woodford Shale was recorded because the net capitalized costs of the properties exceeded the fair value of the properties as measured by estimated cash
flows reported in a third party reserve report. This report was based upon future oil and natural gas prices, which are based on observable inputs adjusted for basis differentials, which are Level 2 inputs. Significant assumptions in valuing the
proved reserves included the reserve quantities, anticipated drilling and operating costs, anticipated production taxes, future expected natural gas prices and basis differentials, anticipated drilling schedules, anticipated production declines, and
an appropriate discount rate commensurate with the risk of the underlying cash flow estimates for the coalbed methane and non-operated shale properties of 10.0%. The impairment was caused by the impact of lower future natural gas prices. During the
third quarter of 2010, future natural gas price curves shifted significantly lower in the Cherokee Basin, especially in the years 5 through 15. Cash flow estimates for the impairment testing exclude derivative instruments used to mitigate the risk
of lower future natural gas prices. Our unproved properties in the Cherokee Basin were impaired based on the drilling locations for the probable and possible reserves becoming uneconomic at the lower future expected natural gas prices, our limited
future capital budgets, and our future expected drilling schedules. Significant assumptions in valuing the unproved reserves included the evaluation of the probable and possible reserves included in the third party reserve report, future expected
natural gas prices and basis



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differentials, and our anticipated drilling schedules and capital availability. The impairment of our other non-current assets was recorded because the net capitalized costs of the intangible
assets exceeded the fair value of the assets as measured by estimated cash flows based on lower observable future expected natural gas prices adjusted for basis differentials, which are Level 2 inputs. These asset impairments have no impact on our
cash flows, liquidity position, or debt covenants.

As of September 30, 2010, we reviewed our 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 expected future long-term oil and natural gas prices continue to decline, the estimated undiscounted
future cash flows for our proved oil and natural gas properties and other assets may not exceed the net capitalized costs related to our properties and further non-cash impairment charges may be required to be recognized. The net capitalized cost
subject to impairment in the Cherokee Basin is approximately $114.8 million, in the Black Warrior Basin is approximately $160.3 million, and in the Woodford Shale is approximately $6.2 million.

For the nine months ended September 30, 2009, we recorded a charge of approximately $4.2 million, to impair the value of certain of
our wells in the Woodford Shale in Oklahoma. The impairment was primarily caused by the impact of lower production volumes than originally estimated, a higher initial production decline rate, and lower future expected natural gas prices. Cash flow
estimates for the impairment testing exclude derivative instruments.

Asset Sales

In the nine months ended September 30, 2010, we sold miscellaneous equipment and surplus inventory for approximately $0.04 million
and recorded a gain of approximately $0.01 million on the sales.

Useful Lives

Our 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.

Exploration and Dry
Hole Costs

Our exploration and dry hole costs were $0.7 million and $0.5 million in the nine months ended
September 30, 2010 and 2009, respectively. These costs represent abandonments of drilling locations, dry hole costs, delay rentals, geological and geophysical costs, and the impairment, amortization, and abandonment associated with leases on
our unproved properties.

7. RELATED PARTY TRANSACTIONS

Management Services Agreement

In November 2006, we 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. CEPM terminated the management services
agreement effective December 15, 2009. Each quarter, CEPM charged us an amount for services provided to us. This amount was agreed to annually and included a portion of the compensation paid by CEPM and its affiliates to personnel who spent
time on our business and affairs. The conflicts committee of our board of managers determined that the amounts paid by us for the services performed were fair to and in the best interests of the Company. These costs totaled approximately $1.2
million for the nine months ended September 30, 2009.

We had a payable to Constellation of $0.3 million as of
September 30, 2009. This payable balance is included in current liabilities in the accompanying balance sheet.

Natural Gas
Purchases

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

Management Incentive Interests

CEPM holds the management incentive interests in CEP. 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 our limited liability company agreement) has been achieved and certain other tests have been met. For the nine months ended September 30, 2010, 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, we increased our distribution rate to $0.5625 per unit. This increase in the distribution rate commenced a management incentive interest
vesting period under our operating agreement. Through December 31, 2008, a cash reserve of $0.7 million had been established to fund future distributions on the management incentive interests. In February 2009, we reduced our 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, the reserve was reduced to zero.



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8. COMMITMENTS AND CONTINGENCIES

In the course of its normal business affairs, we are 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, 2010 and September 30, 2009, 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 our 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 10). 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. We are 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 our operating results from a
termination of the sharing arrangement, Constellation Holdings, Inc. (CHI) contributed $8.0 million to us in exchange for all of our 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 10 and Note 15, the Class D interest special quarterly distributions have been suspended for all quarters commencing on or after January 1,
2008. This suspension includes approximately $3.3 million which represents the distributions that were suspended for the quarterly periods ended June 30, and March 31, 2010, and December 31, September 30, June 30, and March,
31, 2009, and December 31, September 30, June 30, and March 31, 2008. Including the suspended distributions, the remaining undistributed amount of the Class D interests is $6.7 million. See Note 15 for additional information.

9. 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. Each period, we
accrete the ARO to its then present value. The associated asset retirement cost (ARC) is capitalized as part of the carrying amount of our natural gas properties equipment and facilities. Subsequently, the ARC is depreciated using a
systematic and rational method over the assets useful life. The AROs recorded by us 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 oil and natural gas property balance.

The following table is a reconciliation of the ARO:



|                                               |  |                   |        |   |                  |   |        |  
|---------------------------------------------- |  | ----------------- | ------ | - | ---------------- | - | ------ | -
|                                               |  | September 30,2010 |        |   | December 31,2009 |  
|                                               |  | (In 000s)        |       
|Asset retirement obligation, beginning balance |  | $                 | 12,129 |   |                  | $ | 6,754  |  
|Liabilities incurred                           |  |                   | 73     |   |                  |   | 3,873  |  
|Liabilities settled                            |  |                   | (36    | ) |                  |   | (12    | )
|Revisions to prior estimates                   |  |                   |       |   |                  |   | 1,108  |  
|Accretion expense                              |  |                   | 617    |   |                  |   | 406    |  
|                                               |  |                   |        |   |                  |   |        |  
|Asset retirement obligation, ending balance    |  | $                 | 12,783 |   |                  | $ | 12,129 |  
|                                               |  |                   |        |   |                  |   |        |  

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.

At September 30, 2010, and December 31, 2009, there were no assets legally restricted for purposes of settling existing asset
retirement obligations.

10. NET PROFITS INTEREST

Certain of our 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. We record the NPI as an
overriding royalty interest net in revenue in the Consolidated Statements of Operations.



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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, 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, 2010 and 2009. As a result, no payments were made to the Trust with respect to the NPI for the nine months ended September 30, 2010 and 2009. 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. As a result of the termination of the Trust, certain water gathering, separation and disposal costs, which are a component of the NPI calculation, increased from $0.53 per barrel to $1.00 per barrel pursuant to the Water Gathering and Disposal
Agreement dated August 9, 1990, as amended; the amounts of the water gathering, separation and disposal costs are set forth in such agreement.

Litigation Related to Trust Termination

On January 25, 2008, Torch
Royalty Company, Torch E&P Company, and CEP (collectively, the Claimants) commenced an arbitration proceeding before Judicial Arbitration and Mediation Services against Wilmington Trust Company, as Trustee (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 were similarly subject to net profit interests (the Other
NPIs) that were also based on the gas purchase contract. The 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 were terminated. The Trustee took the position that the sharing arrangement under the gas purchase contract terminated upon the termination of the gas purchase
contract. Trust Venture Company, LLC (Trust Venture) was permitted to intervene in the proceeding under an agreement whereby Trust Venture and its affiliates agreed to be bound by the formal award in the proceeding. On July 18,
2008, the arbitration panel issued its 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,
and on December 10, 2008, the District Court of Harris County, Texas, 152nd Judicial District, dismissed the appeal of the final award filed by the Trustee and Trust Venture and confirmed the final award.



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On January 8,
2009, we were 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. The Alabama court has made the Trust a nominal party to the Alabama litigation and ruled that the Trust is 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 Gathering and Disposal Agreement
pending judgment in the lawsuit and asserting damages of approximately $11.6 million from June 2005 to May 2009. These alleged damages appear to be calculated based on a water gathering, separation and disposal fee of $0.05 per barrel
notwithstanding the provisions of the Water Gathering and Disposal Agreement. After hearing, the Alabama court denied Trust Ventures application. On February 9, 2010, Trust Venture filed a motion for partial summary judgment seeking a
determination regarding the applicability of a provision in the Conveyance related to the calculation of water handling charges, which motion the court denied on May 28, 2010, with the court ruling that our position with respect to the
Conveyance provision was correct. No trial date has been set in the litigation, although we anticipate a trial date in the first quarter of 2011. We intend to defend ourselves 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. We intend our forward-looking statements relating to the action to speak only as of the time of such statements and do not plan to update or revise them except to the extent
that material information becomes available.

11. ENVIRONMENTAL LIABILITY

We are 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, 2010, we had no accrued environmental obligations. As of
December 31, 2009, accrued environmental obligations were $0.2 million. This obligation was classified as a current liability on our Consolidated Balance Sheet.

12. UNIT-BASED COMPENSATION

We recognized approximately $1.4 million and
$0.3 million of expense related to our unit-based compensation plans in the nine months ended September 30, 2010, and September 30, 2009, respectively.

2010 Grants

Grants under the 2009 Omnibus Incentive Compensation
Plan

In March 2010, we granted approximately 498,000 restricted common unit awards to certain employees in Texas under the
2009 Omnibus Incentive Compensation Plan. These units had a total fair market value of approximately $1.7 million based on the closing price of our common units on NYSE Arca on March 1, 2010. All of these service-based restricted units will
vest on a five year ratable schedule beginning on March 1, 2010.

Grants under the Long-Term Incentive Program

We granted approximately 195,852 restricted common unit awards under the Long-Term Incentive Plan on March 1, 2010,
to certain field employees in Alabama, Kansas, and Oklahoma and to certain employees in Texas. These units had a total fair market value of approximately $0.7 million based on the closing price of our common units on NYSE Arca on March 1, 2010.
These service-based restricted units will vest on a three year ratable schedule beginning on March 1, 2010, except for certain employees in Texas which will vest on a five year ratable schedule beginning on March 1, 2010.

We granted approximately 54,747 restricted common unit awards under the Long-Term Incentive Plan on March 1, 2010, to our three
independent managers. These units had a total fair market value of approximately $0.2 million based on the closing price of our common units on NYSE Arca on March 1, 2010. These awards will vest in full in March 2011.

13. DISTRIBUTIONS TO UNITHOLDERS

Distributions through September 30, 2010

Beginning in June 2009, we
have suspended our quarterly distributions to unitholders. For the quarter ended June 30, 2010, we were restricted from paying distributions to unitholders as we had no available cash (taking into account the cash reserves set by our board of
managers for the proper conduct of our business) from which to make distributions. See Note 15 for additional information.



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Distributions
through September 30, 2009

On May 15, 2009, we 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, we 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.

14. MEMBERS EQUITY

2010 Equity

At September 30, 2010, we had 489,286 Class A units and 23,975,005 Class B units outstanding, which included 337,165 unvested restricted common units issued under our Long-Term Incentive Plan,
83,745 unvested restricted common units issued under our Executive Inducement Bonus Program, and 1,304,821 unvested restricted common units under our 2009 Omnibus Incentive Compensation Plan.

At September 30, 2010, we had granted 401,500 common units of the 450,000 common units available under our Long-Term Incentive Plan.
Of these grants, 64,335 have vested.

At September 30, 2010, we had granted 146,551 common units of the 300,000 common
units available under our Executive Inducement Bonus Program. Of these grants, 62,807 have vested.

At September 30,
2010, we had granted 1,528,190 common units of the 1,650,000 common units available under our 2009 Omnibus Incentive Compensation Plan. Of these grants, 223,369 have vested.

For the nine months ended September 30, 2010, 90,955 common units have been tendered by our employees for tax withholding purposes. These units, costing approximately $0.4 million, have been returned
to their respective plan and are available for future grants.

2009 Equity

At September 30, 2009, we had 454,401 Class A units and 22,265,648 Class B units outstanding, which 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.

15. SUBSEQUENT EVENTS

The following subsequent events have occurred between October 1, 2010, and November 5, 2010:

Distribution

Our
board of managers has suspended the quarterly distribution to our unitholders for the quarter ended September 30, 2010, which continues the suspension we first announced in June 2009.

Class D Interests

In connection with litigation related to the
Torch NPI, we have suspended all quarterly cash contributions with respect to our Class D interests. This suspension, approved by our board of managers, includes the $0.3 million quarterly cash distribution for the three months ended
September 30, 2010 and $3.3 million which represents the distributions that were suspended for the quarterly periods ended June 30, 2010, March 31, 2010, and December 31, September 30, June 30, and March 31, 2009,
and December 31, September 30, June 30, and March 31, 2008. Including the suspended distributions, the remaining undistributed amount of the Class D interests is $6.7 million.



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Debt

Funds Available for Borrowing

As of November 5, 2010, we had $171.5 million in outstanding debt under our reserve-based credit facility and we had $33.5 million in remaining borrowing capacity under the reserve-based credit
facility. Our next semi-annual borrowing base redetermination is scheduled for the fourth quarter of 2010.



|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 our 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 as well as related midstream assets. At September 30, 2010, our oil and natural gas reserves were 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 create long-term value and to generate stable cash flows allowing us to resume making quarterly cash distributions to our unitholders and over time to increase the amount of our future
quarterly distributions. 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;
| | - |  | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



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



| |  |  | make accretive acquisitions of oil and natural gas 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; and
| | - |  | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  |  | 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.
| | - |  | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

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, results of operations and
prospects, 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 in production by drilling additional wells on our proven undeveloped, probable and
possible locations on our existing properties and by acquiring additional reserves when opportunities arise. We will continue to focus on adding 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.

Since our initial public offering, 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 oil and natural gas properties in the Cherokee Basin of Oklahoma (the Newfield
Assets or Newfield Acquisition).
| | - |  | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



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



| |  |  | 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).
| | - |  | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



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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:



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



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



| |  |  | asset impairments;
| | - |  | ------------------



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



| |  |  | accretion expense;
| | - |  | ------------------



| |  |  | exploration costs;
| | - |  | ------------------



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



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



| |  |  | unrealized (gain) loss from mark to market activities;
| | - |  | ------------------------------------------------------



| |  |  | unrealized (gain)/loss on derivatives/hedge ineffectiveness; and
| | - |  | ----------------------------------------------------------------



| |  |  | interest (income) expense, net which includes:
| | - |  | ----------------------------------------------



| | - |  | interest expense
| | - |  | ----------------



| | - |  | interest expense gain/(loss) mark-to-market activities
| | - |  | ------------------------------------------------------



| | - |  | interest (income)
| | - |  | -----------------

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 a quarterly distribution or 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.



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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 30,2010          |          |   | September 30,2009         |   |        | September 30,2010 |  |   | September 30,2009 |  
|                                                            |  | ( In 000s)                |         
|Reconciliation of Net Income (Loss) to Adjusted EBITDA:     |  |                            |          |   |                           |   |        |                   |  |   |                   |   |  |   |        |  
|Net income (loss)                                           |  | $                          | (267,123 | ) |                           | $ | (9,101 | )                 |  | $ | (270,157          | ) |  | $ | (6,912 | )
|Adjusted by:                                                |  |                            |          |   |                           |   |        |                   |  |   |                   |   |  |   |        |  
|Interest (income) expense, net                              |  |                            | 3,695    |   |                           |   | 3,600  |                   |  |   | 11,138            |   |  |   | 9,719  |  
|Depreciation, depletion and amortization                    |  |                            | 26,175   |   |                           |   | 15,214 |                   |  |   | 79,598            |   |  |   | 43,883 |  
|Asset impairments                                           |  |                            | 270,408  |   |                           |   | 241    |                   |  |   | 270,966           |   |  |   | 4,201  |  
|Accretion expense                                           |  |                            | 205      |   |                           |   | 109    |                   |  |   | 617               |   |  |   | 267    |  
|(Gain)/Loss on sale of assets                               |  |                            |         |   |                           |   |       |                   |  |   | (13               | ) |  |   | 14     |  
|Exploration costs                                           |  |                            | 284      |   |                           |   | 276    |                   |  |   | 731               |   |  |   | 482    |  
|(Gain)/Loss on mark-to-market activities                    |  |                            | (21,100  | ) |                           |   | 6,368  |                   |  |   | (51,832           | ) |  |   | (829   | )
|Unit-based compensation programs                            |  |                            | 375      |   |                           |   | 136    |                   |  |   | 1,405             |   |  |   | 288    |  
|Unrealized loss/(gain) on derivatives/hedge ineffectiveness |  |                            |         |   |                           |   |       |                   |  |   |                  |   |  |   | 267    |  
|                                                            |  |                            |          |   |                           |   |        |                   |  |   |                   |   |  |   |        |  
|Adjusted EBITDA                                             |  | $                          | 12,919   |   |                           | $ | 16,843 |                   |  | $ | 42,453            |   |  | $ | 51,380 |  
|                                                            |  |                            |          |   |                           |   |        |                   |  |   |                   |   |  |   |        |  

At September 30, 2010, due to a significant decline in future natural gas price curves across all
future production periods, we performed an interim impairment analysis of our oil and natural gas properties and other non-current assets. As a result of this analysis, we recorded a total non-cash asset impairment charge of $270.4 million for the
three months ended September 30, 2010. The impairment was caused by the impact of lower future expected natural gas prices. This non-cash asset impairment charge lowered our net income to a loss for the year but it does not impact our Adjusted
EBITDA, cash flows, liquidity position, or debt covenants. The impairment is further discussed on pages 15 and 24.

Significant
Operational Factors



| |  |  | Realized Prices.Our average realized price for the nine months ended September 30, 2010, including hedges, was $11.86 per Mcfe. This
realized price includes the impact of $51.8 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, 2010 was
$7.30 per Mcfe. Further deducting all hedge settlements, average realized prices were $4.77 per Mcfe excluding hedges.
| | - |  | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  |  | Production.Our production for the nine months ended September 30, 2010, was approximately 11.4 Bcfe, or an average of 41,623 Mcfe per day.
This production is approximately 1.7 Bcfe, or 12.7%, lower in 2010 than in 2009. This decrease happened because we have reduced capital spending in 2010 and in 2009 below a maintenance level required to offset the natural decline rate associated
with the natural gas production from our existing wells.
| | - |  | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  |  | Capital Expenditures and Drilling Results.During 2010, we spent approximately $6.4 million in cash capital expenditures, primarily associated
with our drilling program in the Cherokee Basin and to acquire additional interests in seven wells in the Black Warrior Basin and in the Cherokee Basin. We have drilled and completed 3 net wells, 7 net recompletions, and 8 net sidetracks in the
Cherokee Basin and we currently have 6 net wells, 7 net recompletions, and 4 net sidetracks in progress. We substantially completed our 2010 drilling program in the Cherokee Basin during the third quarter of 2010 and expect that all of our in
progress activities, except 2 net sidetracks, will be producing in the fourth quarter of 2010. The 2 net sidetracks are expected to be producing in early 2011.
| | - |  | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  |  | Reduction of Outstanding Debt.Through November 5, 2010, we have reduced our outstanding debt from a high of $220.0 million to $171.5
million, or by 22.1%.
| | - |  | ----------------------------------------------------------------------------------------------------------------------------------------------------------



| |  |  | Hedging Activities. As of September 30, 2010, all of our commodity swaps and basis swaps are accounted for as mark-to-market derivatives.
For the nine months ended September 30, 2010, the unrealized non-cash mark-to-market gain included in our revenues was approximately $51.8 million as compared to an unrealized non-cash mark-to-market gain of $0.8 million for the same period in
2009. 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 Results 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
| | - |  | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



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| | 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 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 32.
| | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  |  | Asset Impairments.For the nine months ended September 30, 2010, we recorded a total non-cash impairment charge of approximately
$271.0 million, composed of $263.4 million to impair the value of our oil and natural gas properties in the Cherokee Basin, $6.3 million to impair our other non-current assets related to our activities in the Cherokee Basin, $0.8 million to impair
certain of our wells located in the Woodford Shale, and $0.5 million to impair the value of our casing inventory. These non-cash charges are included in asset impairments in the Consolidated Statement of Operations. These impairments were recorded
because the net capitalized costs of the assets exceeded the fair value of the assets as measured by estimated cash flows based upon future oil and natural gas prices. These impairments were caused by the impact of lower future expected natural gas
prices. During the third quarter of 2010, future natural gas price curves shifted significantly lower, especially in the years 5 through 15. These impairments reflect the price sensitivity and long-term nature of our coalbed methane reserves base.
Cash flow estimates for the impairment testing exclude derivative instruments used to mitigate the risk of lower future natural gas prices. These asset impairments have no impact on our operations, Adjusted EBITDA, cash flows, liquidity position, or
debt covenants.
| | - |  | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  |  | Constellation Announcements.In May 2009, Constellation disclosed that it had recorded an additional impairment charge relating to the fair
value of its investment in us due to various factors, including the possible sale of its investment in us. To date, no transaction has occurred and no further public announcements have been made. We recognize the potential downward pressure on our
unit price when a large unitholder makes an announcement like this. We continue to look for a way to resolve this issue.
| | - |  | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

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 30,2010          |         |   | September 30,2009         |   |        | Variance |  |   | September 30,2010 |   |  | September 30,2009 |         |    | Variance |  
|                                                            |  |                            |         |   |                           |   |        | $        |  |   | %                 |   |  |                   |         |    |          |   |         | $ |  |   | %      |  
|Revenues:                                                   |  |                            |         |   |                           |   |        |          |  |   |                   |   |  |                   |         |    |          |   |         |   |  |   |        |   |  |   |         |   |  |  |         |   
|Oil and gas sales                                           |  | $                          | 26,643  |   |                           | $ | 30,663 |          |  | $ | (4,020            | ) |  |                   | (13.1   | )% |          | $ | 82,958  |   |  | $ | 94,223 |   |  | $ | (11,265 | ) |  |  | (12.0   | )%
|Gain (Loss) from mark-to-market activities                  |  |                            | 21,100  |   |                           |   | (6,368 | )        |  |   | 27,468            |   |  |                   | (431.3  | )% |          |   | 51,832  |   |  |   | 829    |   |  |   | 51,003  |   |  |  | 6,152.4 | % 
|                                                            |  |                            |         |   |                           |   |        |          |  |   |                   |   |  |                   |         |    |          |   |         |   |  |   |        |   |  |   |         |   |  |  |         |   
|Total revenues                                              |  |                            | 47,743  |   |                           |   | 24,295 |          |  |   | 23,448            |   |  |                   | 96.5    | %  |          |   | 134,790 |   |  |   | 95,052 |   |  |   | 39,738  |   |  |  | 41.8    | % 
|                                                            |  |                            |         |   |                           |   |        |          |  |   |                   |   |  |                   |         |    |          |   |         |   |  |   |        |   |  |   |         |   |  |  |         |   
|Operating expenses:                                         |  |                            |         |   |                           |   |        |          |  |   |                   |   |  |                   |         |    |          |   |         |   |  |   |        |   |  |   |         |   |  |  |         |   
|Lease operating expenses                                    |  |                            | 7,953   |   |                           |   | 8,169  |          |  |   | (216              | ) |  |                   | (2.6    | )% |          |   | 23,645  |   |  |   | 25,243 |   |  |   | (1,598  | ) |  |  | (6.3    | )%
|Cost of sales                                               |  |                            | 592     |   |                           |   | 586    |          |  |   | 6                 |   |  |                   | 1.0     | %  |          |   | 1,949   |   |  |   | 2,030  |   |  |   | (81     | ) |  |  | (4.0    | )%
|Production taxes                                            |  |                            | 647     |   |                           |   | 715    |          |  |   | (68               | ) |  |                   | (9.5    | )% |          |   | 2,449   |   |  |   | 2,245  |   |  |   | 204     |   |  |  | 9.1     | % 
|General and administrative expenses                         |  |                            | 5,027   |   |                           |   | 4,568  |          |  |   | 459               |   |  |                   | 10.0    | %  |          |   | 14,277  |   |  |   | 14,009 |   |  |   | 268     |   |  |  | 1.9     | % 
|Exploration costs                                           |  |                            | 284     |   |                           |   | 276    |          |  |   | 8                 |   |  |                   | 2.9     | %  |          |   | 731     |   |  |   | 482    |   |  |   | 249     |   |  |  | 51.7    | % 
|(Gain) loss on sale of assets                               |  |                            |        |   |                           |   |       |          |  |   |                  |   |  |                   |        |    |          |   | (13     | ) |  |   | 14     |   |  |   | (27     | ) |  |  | (192.9  | )%
|Depreciation, depletion and amortization                    |  |                            | 26,175  |   |                           |   | 15,214 |          |  |   | 10,961            |   |  |                   | 72.0    | %  |          |   | 79,598  |   |  |   | 43,883 |   |  |   | 35,715  |   |  |  | 81.4    | % 
|Asset impairments                                           |  |                            | 270,408 |   |                           |   | 241    |          |  |   | 270,167           |   |  |                   | 112,103 | %  |          |   | 270,966 |   |  |   | 4,201  |   |  |   | 266,765 |   |  |  | 6,350.0 | % 
|Accretion expenses                                          |  |                            | 205     |   |                           |   | 109    |          |  |   | 96                |   |  |                   | 88.1    | %  |          |   | 617     |   |  |   | 267    |   |  |   | 350     |   |  |  | 131.1   | % 
|                                                            |  |                            |         |   |                           |   |        |          |  |   |                   |   |  |                   |         |    |          |   |         |   |  |   |        |   |  |   |         |   |  |  |         |   
|Total operating expenses                                    |  |                            | 311,291 |   |                           |   | 29,878 |          |  |   | 281,413           |   |  |                   | 941.9   | %  |          |   | 394,219 |   |  |   | 92,374 |   |  |   | 301,845 |   |  |  | 326.8   | % 
|Other expenses (income):                                    |  |                            |         |   |                           |   |        |          |  |   |                   |   |  |                   |         |    |          |   |         |   |  |   |        |   |  |   |         |   |  |  |         |   
|Interest expense                                            |  |                            | 3,151   |   |                           |   | 2,884  |          |  |   | 267               |   |  |                   | 9.3     | %  |          |   | 9,966   |   |  |   | 8,106  |   |  |   | 1,860   |   |  |  | 22.9    | % 
|Interest expense (Gain)/loss from mark-to-market activities |  |                            | 545     |   |                           |   | 716    |          |  |   | (171              | ) |  |                   | (23.9   | )% |          |   | 1,174   |   |  |   | 1,615  |   |  |   | (441    | ) |  |  | (27.3   | )%
|Interest income                                             |  |                            | (1      | ) |                           |   |       |          |  |   | (1                | ) |  |                   | 0       | %  |          |   | (2      | ) |  |   | (2     | ) |  |   |        |   |  |  | 0       | % 
|Other (income) expense                                      |  |                            | (120    | ) |                           |   | (82    | )        |  |   | (38               | ) |  |                   | 46.3    | %  |          |   | (410    | ) |  |   | (129   | ) |  |   | (281    | ) |  |  | 217.8   | % 
|                                                            |  |                            |         |   |                           |   |        |          |  |   |                   |   |  |                   |         |    |          |   |         |   |  |   |        |   |  |   |         |   |  |  |         |   



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|                                                                |  |                            |          |   |                           |   |        |          |  |   |                   |   |  |                   |          |    |          |   |          |   |  |   |         |   |  |   |          |   |  |  |          |   
|--------------------------------------------------------------- |  | -------------------------- | -------- | - | ------------------------- | - | ------ | -------- |  | - | ----------------- | - |  | ----------------- | -------- | -- | -------- | - | -------- | - |  | - | ------- | - |  | - | -------- | - |  |  | -------- | --
|                                                                |  | For the Three Months Ended |          |   | For the Nine Months Ended |  
|                                                                |  | (Dollars in 000s)         |         
|                                                                |  | September 30,2010          |          |   | September 30,2009         |   |        | Variance |  |   | September 30,2010 |   |  | September 30,2009 |          |    | Variance |  
|                                                                |  |                            |          |   |                           |   |        | $        |  |   | %                 |   |  |                   |          |    |          |   |          | $ |  |   | %       |  
|Total other expenses (income)                                   |  |                            | 3,575    |   |                           |   | 3,518  |          |  |   | 57                |   |  |                   | 1.6      | %  |          |   | 10,728   |   |  |   | 9,590   |   |  |   | 1,138    |   |  |  | 11.9     | % 
|                                                                |  |                            |          |   |                           |   |        |          |  |   |                   |   |  |                   |          |    |          |   |          |   |  |   |         |   |  |   |          |   |  |  |          |   
|Total expenses                                                  |  |                            | 314,866  |   |                           |   | 33,396 |          |  |   | 281,470           |   |  |                   | 842.8    | %  |          |   | 404,947  |   |  |   | 101,964 |   |  |   | 302,983  |   |  |  | 297.1    | % 
|                                                                |  |                            |          |   |                           |   |        |          |  |   |                   |   |  |                   |          |    |          |   |          |   |  |   |         |   |  |   |          |   |  |  |          |   
|Net income (loss)                                               |  | $                          | (267,123 | ) |                           | $ | (9,101 | )        |  | $ | (258,022          | ) |  |                   | (2,835.1 | )% |          | $ | (270,157 | ) |  | $ | (6,912  | ) |  | $ | (263,245 | ) |  |  | (3,808.5 | )%
|                                                                |  |                            |          |   |                           |   |        |          |  |   |                   |   |  |                   |          |    |          |   |          |   |  |   |         |   |  |   |          |   |  |  |          |   
|                                                                |  |                            |          |   |                           |   |        |         
|Net production:                                                 |  |                            |          |   |                           |   |        |          |  |   |                   |   |  |                   |          |    |          |   |          |   |  |   |         |   |  |   |          |   |  |  |          |   
|Total production (MMcfe)                                        |  |                            | 3,758    |   |                           |   | 4,414  |          |  |   | (656              | ) |  |                   | (14.9    | )% |          |   | 11,363   |   |  |   | 13,020  |   |  |   | (1,657   | ) |  |  | (12.7    | )%
|Average daily production (Mcfe/d)                               |  |                            | 40,848   |   |                           |   | 47,978 |          |  |   | (7,130            | ) |  |                   | (14.9    | )% |          |   | 41,623   |   |  |   | 47,692  |   |  |   | (6,069   | ) |  |  | (12.7    | )%
|Average sales prices:                                           |  |                            |          |   |                           |   |        |          |  |   |                   |   |  |                   |          |    |          |   |          |   |  |   |         |   |  |   |          |   |  |  |          |   
|Price per Mcfe including hedges(a)                              |  | $                          | 12.70    |   |                           | $ | 5.50   |          |  | $ | 7.20              |   |  |                   | 130.9    | %  |          | $ | 11.86    |   |  | $ | 7.30    |   |  | $ | 4.56     |   |  |  | 62.5     | % 
|Price per Mcfe excluding hedges                                 |  | $                          | 4.49     |   |                           | $ | 3.31   |          |  | $ | 1.18              |   |  |                   | 35.6     | %  |          | $ | 4.77     |   |  | $ | 3.55    |   |  | $ | 1.22     |   |  |  | 34.4     | % 
|Average unit costs per Mcfe:                                    |  |                            |          |   |                           |   |        |          |  |   |                   |   |  |                   |          |    |          |   |          |   |  |   |         |   |  |   |          |   |  |  |          |   
|Field operating expenses(b)                                     |  | $                          | 2.29     |   |                           | $ | 2.01   |          |  | $ | 0.28              |   |  |                   | 13.9     | %  |          | $ | 2.30     |   |  | $ | 2.11    |   |  | $ | 0.19     |   |  |  | 9.0      | % 
|Lease operating expenses                                        |  | $                          | 2.12     |   |                           | $ | 1.85   |          |  | $ | 0.27              |   |  |                   | 14.6     | %  |          | $ | 2.08     |   |  | $ | 1.94    |   |  | $ | 0.14     |   |  |  | 7.2      | % 
|Production taxes                                                |  | $                          | 0.17     |   |                           | $ | 0.16   |          |  | $ | 0.01              |   |  |                   | 6.3      | %  |          | $ | 0.22     |   |  | $ | 0.17    |   |  | $ | 0.05     |   |  |  | 29.4     | % 
|General and administrative expenses                             |  | $                          | 1.34     |   |                           | $ | 1.03   |          |  | $ | 0.31              |   |  |                   | 30.1     | %  |          | $ | 1.26     |   |  | $ | 1.08    |   |  | $ | 0.18     |   |  |  | 16.7     | % 
|General and administrative expenses w/o unit-based compensation |  | $                          | 1.25     |   |                           | $ | 1.01   |          |  | $ | 0.24              |   |  |                   | 23.8     | %  |          | $ | 1.14     |   |  | $ | 1.06    |   |  | $ | 0.08     |   |  |  | 7.5      | % 
|Depreciation, depletion and amortization                        |  | $                          | 6.97     |   |                           | $ | 3.45   |          |  | $ | 3.52              |   |  |                   | 102.0    | %  |          | $ | 7.01     |   |  | $ | 3.37    |   |  | $ | 3.64     |   |  |  | 108.0    | % 



|(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.
|--- | -------------------------------------------------------------------------------

Three months ended September 30, 2010 compared to three months ended September 30, 2009

Oil and natural gas sales. Oil and natural gas sales decreased $4.0 million, or 13.1%, to $26.6 million for the three months ended
September 30, 2010 as compared to $30.7 million for the same period in 2009. Of this decrease, $2.2 million was attributable to decreased production volumes and $6.3 million was attributable to our hedging program, offset by $4.5 million in
higher market prices for oil and natural gas. Production for the three months ended September 30, 2010 was 3.8 Bcfe, which was 0.7 Bcfe lower than the same period in 2009. Of the decrease, 0.6 Bcfe was a reduction of natural gas production due
to our suspension of our drilling programs in the Cherokee Basin starting in June 2009. The remaining decrease in production of 0.1 Bcfe was associated with our properties in the Black Warrior Basin and in the Woodford Shale. Due to the decrease in
the level of our drilling activities, our 2009 and 2010 maintenance drilling programs will not be sufficient to offset the natural decline rate of production associated with our existing wells. We hedged approximately 76% of our actual production
during the third quarter of 2010 and approximately 75% of our actual production during the same period in 2009.

As discussed
below, the gain from our unrealized non-cash mark-to-market activities increased $27.5 million for the three months ended September 30, 2010, as compared to the same period in 2009. Our realized market prices before our hedging program
increased from 2009 to 2010 primarily due to higher market prices for oil and natural gas. This was offset by the impact of our hedging program and the associated mark-to-market gains and losses discussed below.

Hedging and mark-to-market activities. As of September 30, 2010, all of our swaps and basis swaps are accounted for as
mark-to-market derivatives. For the three months ended September 30, 2010, the unrealized non-cash mark-to-market gain was approximately $21.1 million as compared to an unrealized non-cash $6.4 million loss for the same period in 2009. This
2010 non-cash gain represents approximately $21.4 million from the impact of decreased future natural gas prices on these derivative transactions that are being accounted for as mark-to-market activities and by a $0.3 million decrease for
non-performance risk related to our counterparties. This 2009 non-cash loss represents approximately $6.7 million from the impact of increased 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.



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Cash hedge settlements
received for our commodity derivatives were approximately $9.8 million for the three months ended September 30, 2010. Cash hedge settlements received for our commodity derivatives were approximately $16.0 million for the three months ended
September 30, 2009. This difference is primarily due to higher market prices and lower hedged volumes for natural gas during 2010.

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, 2010, lease operating expenses
decreased $0.2 million, or 2.6%, to $8.0 million, compared to expenses of $8.2 million for the same period in 2009. This decrease in lease operating expenses is primarily related to $0.1 million in lower total spending in the Cherokee Basin and $0.1
million in lower expenses associated with the Black Warrior Basin. Our spending in the Woodford Shale properties during 2010 remained level with our spending in 2009. By category, our lease operating expenses were lower in 2010 as compared to 2009
by $0.2 million because of a decrease of $0.4 million in gas compression, $0.2 million in repairs and maintenance, and $0.1 million in workovers offset by an increase of $0.5 million in labor costs.

For the three months ended September 30, 2010, per unit lease operating expenses were $2.12 per Mcfe compared to $1.85 per Mcfe
for the same period in 2009. This increase is attributable to 14.9% lower production in 2010 as compared to the same period in 2009 offset by a decrease in total spending of 2.6% in 2010 as compared to the same period in 2009. Our per unit operating
costs increased in the Cherokee Basin from $2.10 per Mcfe in 2009 to $2.55 per Mcfe in 2010 as a result of 0.6 Bcfe in lower production volumes and lower total spending.

For the three months ended September 30, 2010, production taxes decreased $0.1 million, or 9.5%, to $0.6 million, compared to expenses of $0.7 million for the same period in 2009. This increase was
primarily the result of higher market prices for oil and natural gas in 2010 offset by the impact of production taxes on 0.7 Bcfe in lower production.

Cost of sales.For the three months ended September 30, 2010, cost of sales increased by less than $0.01 million, or 1.0%, to $0.6 million, compared to $0.6 million for the same period in
2009. This represents the cost of purchased natural gas in the Cherokee Basin and was impacted by lower production volumes and higher market prices for natural gas, 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, and other costs not directly associated with field operations.

General
and administrative expenses increased by approximately $0.5 million, or 10.0%, to $5.0 million for the three months ended September 30, 2010, as compared to $4.5 million for the same period in 2009. Our general and administrative expenses were
higher in 2010 as compared to 2009 because of $0.2 million in lower management service fees and $0.2 million in lower legal costs offset by $0.5 million in higher labor costs, $0.2 higher non-cash unit-based compensation expenses, $0.1 higher rent
expenses, and $0.1 million higher insurance costs. For the three months ended September 30, 2009, CEPM allocated $0.2 million in expenses to us for labor and other charges through the management services agreement.

Our per unit costs were $1.34 per Mcfe for the three months ended September 30, 2010 compared to $1.03 per Mcfe for the same period
in 2009. This increase is attributable to an increase in total spending of approximately $0.5 million offset by 0.7 Bcfe in lower production.

Exploration Costs. Exploration costs increased less than $0.01 million, or 2.9%, to $0.3 million for the three months ended September 30, 2010, as compared to $0.3 million for the same period
in 2009. These costs represent abandonments of drilling locations, dry hole costs, delay rentals, geological and geophysical costs, and the impairment, amortization, and abandonment costs associated with leases on our unproved properties. The
increase in 2010 is primarily as the result of the expectation that certain of our lease locations will expire as a result of a lower capital expenditure budget in 2010 and 2011 as compared to prior years.

Depreciation, depletion and amortization expense and Asset impairments. Depreciation, depletion and amortization expenses include
the depreciation, depletion and amortization of acquisition costs and equipment costs and asset impairment expense when the fair value of our assets is less than their historical net book value. 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, 2010 was $26.2 million, or $6.97 per
Mcfe, compared to $15.2 million, or $3.45 per Mcfe, for the same period in 2009. This increase of $11.0 million is composed of higher depletion expense. The increase in 2010 depreciation, depletion, and amortization reflects the impact of a lower
year-end 2009 reserve base primarily due to price-related reserve revisions, capital expenditures for our development drilling



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##### Table of Contents

programs, and a 0.7 Bcfe decrease in production volumes during 2010 as compared to 2009. Our asset impairments for the three months ended September 30, 2010 were $270.4 million, compared to
$0.2 million for the same period in 2009. Our non-cash impairment charges were approximately $263.4 million to impair the value of our oil and natural gas properties in the Cherokee Basin, $6.3 million to impair our other non-current intangible
assets related to our activities the Cherokee Basin, $0.3 million to impair certain of our wells in the Woodford Shale and $0.5 million to impair the value of our casing inventory.

We calculate depletion using units-of-production under the successful efforts method of accounting. Our other assets are depreciated
using the straight line basis. Consistent with our prior practice, we will use our 2009 reserve report to calculate our depletion rate during the first three quarters of 2010. We will use our 2010 reserve report to record our depletion in the fourth
quarter of 2010. If our SEC reserves at year-end 2010 are similar to our third quarter SEC reserve estimates, we would expect a lower depletion rate of approximately $1.50 per Mcfe due to the impairment of our Cherokee Basin assets.

Interest expense. Interest expense for the three months ended September 30, 2010 increased $0.1 million to $3.7 million as
compared to approximately $3.6 million in interest expense for same period in 2009. This increase was primarily due to $0.2 million in lower non-cash mark-to-market losses on our interest rate swaps that are accounted for as mark-to-market
activities, lower interest rate swap settlements of $0.4 million, higher market interest rates of $0.6 million, and higher capitalized interest of $0.1 million during 2010 as compared to the same period in 2009. During 2009 and 2010, we used our
excess operating cash flow to reduce our total debt from a high of $220.0 million to $171.5 million. At September 30, 2010, we had an outstanding balance under our reserve-based credit facility of $172.5 million as compared to $220.0 million at
September 30, 2009. The average interest rate on our outstanding debt was approximately 5.1% at September 30, 2010 compared to 5.2% at September 30, 2009.

Interest income. Interest income for the three months ended September 30, 2010 was less than $0.01 million as compared to zero in interest income for same period in 2009. During 2010, market
rates for overnight investments continued to be at historical lows, resulting in no significant earnings on our 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 was available until December 31, 2009.

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 $3.7 million for the three months ended September 30, 2010, and as an unrealized loss of $9.7 million for the same period in 2009. This decrease reflects the
difference in the hedge settlements during 2010 and 2009, which are 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.

Nine months ended September 30, 2010 compared to nine months ended September 30, 2009

Oil and natural gas sales. Oil and natural gas sales decreased $11.3 million, or 12.0%, to $82.9 million for the nine months ended
September 30, 2010 as compared to $94.2 million for the same period in 2009. Of this decrease, $5.9 million was attributable to decreased production volumes and $19.2 million was attributable to our hedging program, offset by $13.8 million in
higher market prices for oil and natural gas. Production for the nine months ended September 30, 2010 was 11.4 Bcfe, which was 1.7 Bcfe lower than the same period in 2009. Of the decrease, 1.3 Bcfe was a reduction of natural gas production due
to our suspension of our drilling programs in the Cherokee Basin starting in June 2009. The remaining decrease in production of 0.4 Bcfe was associated with our properties in the Black Warrior Basin and in the Woodford Shale. Due to the decrease in
the level of our drilling activities, our 2009 and 2010 maintenance drilling programs will not be sufficient to offset the natural decline rate of production associated with our existing wells. We hedged approximately 80% of our actual production
during 2010 and approximately 79% of our actual production during the same period in 2009.

As discussed below, the gain from
our unrealized non-cash mark-to-market activities increased $51.0 million for the nine months ended September 30, 2010, as compared to the same period in 2009. Our realized market prices before our hedging program increased from 2009 to
2010 primarily due to higher market prices for oil and natural gas. This was offset by the impact of our hedging program and the associated mark-to-market gains and losses discussed below.

Hedging and mark-to-market activities. As of September 30, 2010, all of our swaps and basis swaps are accounted for as
mark-to-market derivatives. For the nine months ended September 30, 2010, the unrealized non-cash mark-to-market gain was approximately $51.8 million as compared to an unrealized non-cash $0.8 million gain for the same period in 2009. This 2010
non-cash gain represents approximately $53.1 million from the impact of decreased future natural gas prices on these derivative transactions that are being accounted for as mark-to-market activities offset by a $1.3 million reduction for
non-performance risk related to our counterparties. This 2009 non-cash gain represents approximately $1.2 million from the impact of decreased 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.



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For the nine months
ended September 30, 2009, we recognized a loss of approximately $0.3 million related to hedge ineffectiveness primarily related to our hedges of production in the Cherokee Basin.

Cash hedge settlements received for our commodity derivatives were approximately $28.8 million for the nine months ended
September 30, 2010. Cash hedge settlements received for our commodity derivatives were approximately $48.3 million for the nine months ended September 30, 2009. This difference is primarily due to higher market prices for natural gas and
lower hedged volumes during 2010.

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, 2010, lease operating expenses decreased $1.6 million, or 6.3%, to $23.6 million, compared to expenses of $25.2 million for the same period in 2009. This
decrease in lease operating expenses is primarily related to $1.1 million in lower total spending in the Cherokee Basin and $0.5 million in lower expenses associated with our Woodford Shale and Black Warrior Basin properties. By category, our lease
operating expenses were lower in 2010 as compared to 2009 by $1.6 million because of a decrease of $1.1 million in gas compression, $0.4 million in repairs and maintenance, $0.4 million in facilities, $0.3 million in power and fuel, $0.1 million in
work over costs offset by $0.7 million higher labor costs. For the nine months ended September 30, 2010, per unit lease operating expenses were $2.08 per Mcfe compared to $1.94 per Mcfe for the same period in 2009. This increase is
attributable to 12.7% lower production in 2010 as compared to the same period in 2009 offset by a decrease in total spending of 6.3% in 2010 as compared to the same period in 2009. Our per unit operating costs increased in the Cherokee Basin from
$2.14 per Mcfe in 2009 to $2.38 per Mcfe in 2010 as a result of 1.3 Bcfe in lower production volumes and lower total spending. Our production declines in the Cherokee Basin are the result of lower maintenance capital expenditures in 2010 and 2009.

For the nine months ended September 30, 2010, production taxes increased $0.2 million, or 9.1%, to $2.4 million,
compared to expenses of $2.2 million for the same period in 2009. This increase was primarily the result of higher market prices for oil and natural gas in 2010 offset by the impact of production taxes on 1.7 Bcfe in lower production.

Cost of sales.For the nine months ended September 30, 2010, cost of sales decreased by approximately $0.1 million, or 4.0%,
to $1.9 million, compared to $2.0 million for the same period in 2009. This represents the cost of purchased natural gas in the Cherokee Basin and was impacted by lower production volumes and higher market prices for natural gas, 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, and other costs not directly associated with field operations.

General and administrative expenses increased $0.3 million, or 1.9%, to $14.3 million for the nine months ended September 30, 2010,
as compared to $14.0 million for the same period in 2009. Our general and administrative expenses were higher in 2010 as compared to 2009 because of $1.2 million in lower management service fees and $0.2 million in legal fees offset by $1.1 million
in higher non-cash unit-based compensation expenses, $0.3 million in higher rent expense, $0.2 million in higher insurance, and $0.1 million in higher printing and production. For the nine months ended September 30, 2009, CEPM allocated
approximately $1.2 million in expenses to us for labor and other charges through the management services agreement.

Our per
unit costs were $1.26 per Mcfe for the nine months ended September 30, 2010 compared to $1.08 per Mcfe for the same period in 2009. This increase is attributable to an increase in total spending of approximately $0.3 million offset by 1.7 Bcfe
in lower production. Approximately 55.6% or $0.10 per Mcfe, of the increase is related to non-cash unit-based compensation costs.

Exploration Costs. Exploration costs increased $0.2 million, or 51.7%, to $0.7 million for the nine months ended September 30, 2010, as compared to $0.5 million for the same period in 2009.
These costs represent abandonments of drilling locations, dry hole costs, delay rentals, geological and geophysical costs, and the impairment, amortization, and abandonment costs associated with leases on our unproved properties. The increase in
2010 is primarily as the result of lease abandonments in Kansas and Oklahoma and the expectation that certain of our lease locations will expire as a result of a lower capital expenditure budget in 2010 and 2011 as compared to prior years.

Gain/loss on sale of assets.Our gain/loss on the sale of assets decreased less than $0.03 million, or 192.9%, to less
than $0.02 million gain for the nine months ended September 30, 2010, as compared to a loss of less than $0.02 million for the same period in 2009. In 2010, we sold surplus equipment at a gain of $0.01 million.

Depreciation, depletion and amortization expense and Asset impairments. Depreciation, depletion and amortization expenses include
the depreciation, depletion and amortization of acquisition costs and equipment costs and asset impairment expense when the fair value of our assets is less than their historical net book value. Depletion is calculated using units-of-production.
Assuming everything else remains unchanged, as natural gas production changes, depletion would change in the same direction.



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Our depreciation,
depletion and amortization expense for the nine months ended September 30, 2010 was $79.6 million, or $7.01 per Mcfe, compared to $43.9 million, or $3.37 per Mcfe, for the same period in 2009. This increase is composed of higher depletion
expense. The increase in 2010 depreciation, depletion, and amortization reflects the impact of a lower year-end 2009 reserve base primarily due to price-related reserve revisions, capital expenditures for our development drilling programs, and a 1.7
Bcfe decrease in production volumes during 2010 as compared to 2009. Our asset impairments for the nine months ended September 30, 2010 were $271.0 million, compared to $4.2 million for the same period in 2009. Our non-cash impairment charges
were approximately $263.4 million to impair the value of our oil and natural gas properties in the Cherokee Basin, $6.3 million to impair our other non-current intangible assets related to our activities the Cherokee Basin, and $0.5 million to
impair the value of our casing inventory offset by $3.4 million lower impairments for certain of our wells in the Woodford Shale.

We calculate depletion using units-of-production under the successful efforts method of accounting. Our other assets are depreciated using the straight line basis. Consistent with our prior practice, we
used our 2009 reserve report to calculate our depletion rate during the first three quarters of 2010. We will use our 2010 reserve report to record our depletion in the fourth quarter of 2010. We will use our 2010 reserve report to record our
depletion in the fourth quarter of 2010. If our SEC reserves at year-end 2010 are similar to our third quarter SEC reserve estimates, we would expect a lower per unit depletion rate of approximately $1.50 per Mcfe due to the impairment of our
Cherokee Basin assets.

Interest expense. Interest expense for the nine months ended September 30, 2010 increased
$1.4 million, or 14.6%, to $11.1 million as compared to approximately $9.7 million in interest expense for same period in 2009. This increase was primarily due to $0.5 million in lower non-cash mark-to-market losses on our interest rate swaps that
are accounted for as market-to-market activities, lower interest rate swap settlements of $0.01 million, higher market interest rates of $1.6 million, and lower capitalized interest of $0.3 million during 2010 as compared to the same period in 2009.
During 2009 and 2010, we used our excess operating cash flow to reduce our total debt from a high of $220.0 million to $171.5 million. At September 30, 2010, we had an outstanding balance under our reserve-based credit facility of $172.5
million as compared to $220.0 million at September 30, 2009. The average interest rate on our outstanding debt was approximately 5.1% at September 30, 2010, compared to 5.2% at September 30, 2009.

Interest income. Interest income for the nine months ended September 30, 2010 was less than $0.02 million as compared to less
than $0.02 million in interest income for same period in 2009. During 2010, market rates for overnight investments continued to be at historical lows, resulting in no significant earnings on our 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 was 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 previously designated cash-flow hedge positions. At September 30, 2010, the balance was an unrealized gain of $15.1 million compared to an unrealized gain of
$28.4 million at December 31, 2009. This decrease reflects the amortization to earnings as the derivative positions that were previously accounted for as cash flow hedges settled during the first and second quarters of 2010.

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 $13.2 million for the nine months ended September 30, 2010, and as an unrealized loss of $13.3 million for the same period in 2009. This decrease reflects the hedge settlements during 2010 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.

Liquidity and Capital Resources

During 2009 and 2010, we utilized our cash flow from operations as our primary source
of capital. Our primary use of capital during this time was for the retirement of outstanding debt. We have successfully reduced our outstanding indebtedness by $48.5 million since we suspended our quarterly distribution to unitholders in June 2009.
Based upon our current business plans for 2010 and 2011, we expect to continue to generate operating cash flows in excess of our working capital needs and planned capital expenditures. We expect to make limited maintenance capital expenditures of
approximately $10.5 million primarily concentrated in the Cherokee Basin during 2010 and approximately $10.0 million to $12.0 million in the Black Warrior Basin and Cherokee Basin during 2011. The primary focus of our business plans in 2010 and 2011
will be to use our excess operating cash flows to further reduce our outstanding debt level.

Our reserve-based credit
facility currently provides a limited availability to finance future maintenance capital expenditures and other working capital needs. As of November 5, 2010, our borrowing base under our reserve-based credit facility was $205.0 million and we
had $171.5 million of debt outstanding under our reserve-based credit facility, leaving us with $33.5 million in unused borrowing capacity. As of September 30, 2010, we were restricted from paying distributions to unitholders as we had no
available cash (taking into account the cash reserves set by our board of managers for the proper conduct of our business) from which to make distributions.



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Our reserve-based
credit facility matures on November 13, 2012. In the first quarter of 2008, we filed a shelf registration statement with the SEC to register up to $1.0 billion of debt and equity securities. This registration statement expires during the first
quarter of 2011. There is no guarantee that securities can or will be issued under the registration statement. If we do not issue any securities under this registration statement prior to its expiration or file a new registration statement, we may
recognize expenses of approximately $0.3 million in our Consolidated Statement of Operations. Our current reserve-based credit facility is also subject to future borrowing base redeterminations and will have to be renewed or replaced before its
maturity in November 2012. We expect our next borrowing base redetermination to be completed in the fourth quarter of 2010.

As we pursue our business plan, we will be monitoring the capital resources available to us to meet our future financial obligations and
planned limited maintenance capital expenditures in 2010 and 2011. 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. For 2011, we forecast total net production of between
13.4 Bcfe and 14.2 Bcfe. We have hedged approximately 72% of the midpoint of this forecast, including hedges on 7.6 Bcfe of our Mid-continent production at an average price, including basis, of $7.87 per Mcfe and an additional 2.4 Bcfe of production
at a NYMEX-only price of $8.51 per Mcfe. This attractive hedge position locks in a significant portion of our expected operating cash flows for 2011. Our hedge program is further discussed on page 32. During 2010 and 2011, 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. During 2010 and 2011, we intend to limit
our capital expenditures and to use any surplus operating cash flows to further reduce our debt level. We expect that the suspension of our quarterly distribution and the reduction in our total planned capital expenditures in 2010 and 2011 will
provide additional liquidity to fund our operations and to pay down debt. Since we began our debt reduction initiative, we have successfully reduced our outstanding debt balances from a high of $220.0 million to $171.5 million. Any future quarterly
distribution to unitholders cannot be made when our borrowings outstanding, net of available cash, under the reserve-based credit facility exceed 90% of the borrowing base, after giving effect to the proposed distribution. Our available cash is
reduced by any cash reserves established by our board of managers for the proper conduct of our business and the payment of fees and expenses. We are subject to additional future borrowing base redeterminations and cannot forecast the level at which
our lenders may set our borrowing base. However, after our outstanding debt balance, net of available cash, 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. This evaluation will consider our outstanding borrowings and cash reserves that are set by our board of managers for the proper conduct of our business. Given our focus on
debt reduction, we anticipate that our distribution will remain suspended through the fourth quarter of 2011. Any future quarterly distributions must be approved by our board of managers.

Reserve-based credit facility

On November 13, 2009, we entered
into an amended and restated $350.0 million reserve-based credit facility with The Royal Bank of Scotland plc as administrative agent and a syndicate of lenders. The reserve-based credit facility amends, extends, and consolidates our previous
reserve-based credit facilities and matures on November 13, 2012. Borrowings under the reserve-based credit facility are secured by various mortgages of oil and natural gas properties that we and certain of our subsidiaries own as well as
various security and pledge agreements among us and certain of our subsidiaries and the administrative agent. The current lenders and their percentage commitments in the reserve-based credit facility are: The Royal Bank of Scotland plc (26.84%), BNP
Paribas (21.95%), The Bank of Nova Scotia (21.95%), Wells Fargo Bank, N.A. (14.63%), and Societe Generale (14.63%).

The
amount available for borrowing at any one time under the reserve-based credit facility is limited to the borrowing base for our oil and natural properties in Alabama, Kansas, and Oklahoma. As of November 5, 2010, our borrowing base was $205.0
million. The borrowing base is redetermined semi-annually, and may be redetermined at our request more frequently and by the lenders, in their sole discretion, based on reserve reports as prepared by petroleum engineers, together with, among other
things, the oil and natural gas prices prevailing at such time. Our next semi-annual borrowing base redetermination is scheduled during the fourth quarter of 2010. Outstanding borrowings in excess of our borrowing base must be repaid or we must
pledge other oil and natural gas properties as additional collateral. We may elect to pay any borrowing base deficiency in three equal monthly installments such that the deficiency is eliminated in a period of three months. Any increase in our
borrowing base must be approved by all of the lenders.

Borrowings under the reserve-based credit facility are available for
acquisition, exploration, operation and maintenance of oil and natural gas properties, payment of expenses incurred in connection with the reserve-based credit facility, working capital and general limited liability company purposes. The
reserve-based credit facility has a sub-limit of $20.0 million which may be used for the issuance of letters of credit. As of September 30, 2010, no letters of credit are outstanding.



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At our election,
interest for borrowings are determined by reference to (i) the London interbank rate, or LIBOR, plus an applicable margin between 2.50% and 3.50% per annum based on utilization or (ii) a domestic bank rate (ABR) plus an
applicable margin between 1.50% and 2.50% per annum based on utilization plus (iii) a commitment fee of 0.50% per annum based on the unutilized borrowing base. Interest on the borrowings for ABR loans and the commitment fee are
generally payable quarterly. Interest on the borrowings for LIBOR loans are generally payable at the applicable maturity date.

The reserve-based credit facility contains various covenants that limit, among other things, our ability and certain of our
subsidiaries ability to incur certain indebtedness, grant certain liens, merge or consolidate, sell all or substantially all of our assets, make certain loans, acquisitions, capital expenditures and investments, and make distributions to
unitholders.

In addition, we are required to maintain (i) a ratio of Total Net Debt (defined as Debt (generally
indebtedness permitted to be incurred by us under the reserve-based credit facility) less Available Cash (generally, cash, cash equivalents, and cash reserves of the Company)) to Adjusted EBITDA (defined as, for any period, the sum of consolidated
net income for such period plus (minus) 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, exploration costs, (gain) loss from equity investment, accretion of asset retirement obligation, unrealized (gain) loss on derivatives and realized (gain) loss on cancelled derivatives, and other
similar charges) of not more than 3.75 to 1.0 through September 30, 2010 and 3.50 to 1.0 thereafter; (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 (to the extent such payments are not past due), 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 our consolidated
financial information.

The reserve-based 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 reserve-based credit facility and a change of control. If an event of default occurs, the lenders will be able to accelerate the maturity of the reserve-based credit facility and exercise
other rights and remedies. The reserve-based 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 us and our subsidiaries who are guarantors taken as a whole. If a MAE were to occur, we would be prohibited
from borrowing under the reserve-based credit facility and would be in default, which could cause all of our existing indebtedness to become immediately due and payable.

We have the ability to pay distributions to unitholders from available cash, including cash from borrowings under the reserve-based credit facility, as long as no event of default exists and provided that
no distributions to unitholders may be made if the borrowings outstanding, net of available cash, under the reserve-based credit facility exceed 90% of the borrowing base, after giving effect to the proposed distribution. Our available cash is
reduced by any cash reserves established by our board of managers for the proper conduct of our business and the payment of fees and expenses. As of November 5, 2010, we were restricted from paying distributions to unitholders as we had no
available cash (taking into account the cash reserves set by our board of managers for the proper conduct of our business) from which to make distributions.

The reserve-based credit facility permits us to hedge our projected monthly production, provided that (a) for the immediately ensuing twelve month period, the volumes of production hedged in any
month may not exceed our reasonable business judgment of the production for such month consistent with the application of petroleum engineering methodologies for estimating proved developed producing reserves based on the then strip pricing
(provided that such projection shall not be more than 115% of the proved developed producing reserves forecast for the same period derived from the most recent reserve report of our petroleum engineers using the then strip pricing), and (b) for
the period beyond twelve months, the volumes of production hedged in any month may not exceed the reasonably anticipated projected production from proved developed producing reserves estimated by our petroleum engineers. The reserve-based credit
facility also permits us to hedge the interest rate on up to 90% of the then-outstanding principal amounts of our indebtedness for borrowed money.

The reserve-based credit facility contains no covenants related to our relationship with Constellation or Constellations right to appoint all of the Class A managers of our board of managers.

At September 30, 2010, we believe that we were in compliance with the financial covenant ratios contained in our
reserve-based credit facility. We monitor compliance on an ongoing basis. As of September 30, 2010, our actual Total Net Debt to Adjusted EBITDA ratio was 2.7 to 1.0 as compared with a required ratio of not greater than 3.75 to 1.0, our actual
ratio of consolidated current assets to consolidated current liabilities was 3.7 to 1.0 as compared with a required ratio of not less than 1.0 to 1.0, and our actual Adjusted EBITDA to cash interest expense ratio was 6.0 to 1.0 as compared with a
required ratio of not less than 2.5 to 1.0. As of December 31, 2010 and thereafter, our required financial covenant ratio of Total Net Debt to Adjusted EBITDA is reduced to not greater than 3.5 to 1.0.



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If we are unable to
remain in compliance with the debt covenants associated with our reserve-based credit facility or maintain the required ratios discussed above, we could request waivers from the lenders in our bank group. Although the lenders may not provide a
waiver, we could take additional steps in the event of not meeting the required ratios or in the event of a reduction in the borrowing base below its current level of $205.0 million at one of the future redeterminations by the lenders. During 2010,
we intend to use our surplus operating cash flows to reduce our outstanding debt. If it becomes necessary to pay debt down beyond operating cash flows, we could further reduce capital expenditures, continue to suspend our quarterly distributions to
unitholders, sell oil and natural gas properties, liquidate in the money derivative positions, further reduce operating and administrative costs, or take additional steps to increase liquidity. If we were unable to obtain a waiver and were
unsuccessful at reducing our debt to the necessary level, our debt could become due and payable upon acceleration by the lenders. To the extent that we do not enter into an agreement to refinance or extend the due date on the reserve-based credit
facility, the outstanding debt balance at November 13, 2011, will become a current liability.

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 facility. These positions are outlined on page 33.

Cash Flow from Operations

Our net cash flow provided by operating
activities for the nine months ended September 30, 2010 was $30.9 million, compared to net cash flow provided by operating activities of $45.6 million for the same period in 2009. This decrease in operating cash flow was primarily attributable
to lower oil and natural gas sales of $11.3 million as the result of 1.7 Bcfe in lower natural gas production in 2010. For 2010, our operating cash flows were increased by $25.6 million related to cash hedge settlements for our natural gas commodity
and interest rate derivatives. Our change in working capital from 2009 to 2010 was impacted by lower accrued liabilities of $2.6 million, lower royalties payable of $1.7 million, lower accounts receivable of $1.6 million, higher accounts payable of
$0.6 million, and lower payables to Constellation of $0.2 million. Our accrued liabilities decreased with the payments associated with our 2009 incentive compensation programs. Our accounts payable increased due to timing of invoice payments to
vendors associated with our 2010 capital program. Our accounts receivable balance decreased due to lower volumes of natural gas sold in 2010 offset by higher current period prices for our current estimated natural gas sales. The royalties payable,
which represents the amount of monies owed to the royalty owners in our properties for our monthly oil and natural gas sales, decreased due to lower production of natural gas reducing the amount of royalties owed. The decrease in payables to
Constellation was impacted by the termination of the management services agreement in December 2009.

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 toOutlook on page 35.

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 the negative effects of falling
commodity prices, these derivative contracts also limit the benefits we would receive from increases in commodity prices. To the extent market prices exceed our hedge 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 will 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 facility. We currently do not post collateral under any of these agreements as they are secured under our reserve-based credit facility. This is significant since we are able to lock in attractive sales prices on a
substantial amount of our expected future production without posting cash collateral based on price changes prior to the hedges being cash settled.

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



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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 |  
|2010 |  |                                  |           |  |              |   |      |          |  |  |              |  |  |        |      |  |              |  |           |        |  |   |              |  |  |        | 2,700,000 |  |              | $ | 8.15 |  |  |  | 2,700,000  |  |  | $ | 8.15 | 
|2011 |  |                                  | 2,400,000 |  |              | $ | 8.55 |          |  |  | 2,425,000    |  |  | $      | 8.55 |  |              |  | 2,220,000 |        |  | $ | 8.45         |  |  |        | 2,220,000 |  |              | $ | 8.45 |  |  |  | 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 |          |  |  | 2,079,500    |  |  | $      | 7.32 |  |              |  | 2,070,000 |        |  | $ | 7.33         |  |  |        | 2,038,000 |  |              | $ | 7.34 |  |  |  | 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 | 
|     |  |                                  |           |  |              |   |      |          |  |  |              |  |  |        |      |  |              |  |           |        |  |   |              |  |  |        |           |  |              |   |      |  |  |  |            |  |  |   |      | 
|     |  |                                  |           |  |              |   |      |          |  |  |              |  |  |        |      |  |              |  |           |        |  |   |              |  |  |        |           |  |              |   |      |  |  |  | 35,520,000 |  |  |   |      | 
|     |  |                                  |           |  |              |   |      |          |  |  |              |  |  |        |      |  |              |  |           |        |  |   |              |  |  |        |           |  |              |   |      |  |  |  |            |  |  |   |      | 

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 |  
|2010 |  |                                  |         |  |              |   |      |          |  |  |              |  |  |        |      |  |              |  |         |        |  |   |              |  |  |        | 180,000 |  |              | $ | 7.91 |  |  |  | 180,000 |  |  | $ | 7.91 | 
|2011 |  |                                  | 180,000 |  |              | $ | 7.93 |          |  |  | 180,000      |  |  | $      | 7.93 |  |              |  | 180,000 |        |  | $ | 7.93         |  |  |        | 180,000 |  |              | $ | 7.93 |  |  |  | 720,000 |  |  | $ | 7.93 | 
|     |  |                                  |         |  |              |   |      |          |  |  |              |  |  |        |      |  |              |  |         |        |  |   |              |  |  |        |         |  |              |   |      |  |  |  |         |  |  |   |      | 
|     |  |                                  |         |  |              |   |      |          |  |  |              |  |  |        |      |  |              |  |         |        |  |   |              |  |  |        |         |  |              |   |      |  |  |  | 900,000 |  |  |   |      | 
|     |  |                                  |         |  |              |   |      |          |  |  |              |  |  |        |      |  |              |  |         |        |  |   |              |  |  |        |         |  |              |   |      |  |  |  |         |  |  |   |      | 

MTM Fixed Price Basis Swaps CenterPoint Energy Gas Transmission (East), 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 $ |  
|2010 |  |                                  |           |  |                   |   |      |          |  |  |                   |  |  |        |      |  |                   |  |           |        |  |   |                   |  |  |        | 2,070,895 |  |                   | $ | 0.72 |  |  |  | 2,070,895  |  |  | $ | 0.72 | 
|2011 |  |                                  | 1,947,352 |  |                   | $ | 0.63 |          |  |  | 1,823,324         |  |  | $      | 0.65 |  |                   |  | 1,703,467 |        |  | $ | 0.62              |  |  |        | 1,393,700 |  |                   | $ | 0.68 |  |  |  | 6,867,843  |  |  | $ | 0.64 | 
|2012 |  |                                  | 1,502,800 |  |                   | $ | 0.58 |          |  |  | 1,427,100         |  |  | $      | 0.59 |  |                   |  | 1,352,900 |        |  | $ | 0.61              |  |  |        | 1,295,900 |  |                   | $ | 0.62 |  |  |  | 5,578,700  |  |  | $ | 0.60 | 
|2013 |  |                                  | 1,245,400 |  |                   | $ | 0.40 |          |  |  | 1,192,900         |  |  | $      | 0.40 |  |                   |  | 1,145,700 |        |  | $ | 0.40              |  |  |        | 1,104,400 |  |                   | $ | 0.40 |  |  |  | 4,688,400  |  |  | $ | 0.40 | 
|2014 |  |                                  | 1,053,465 |  |                   | $ | 0.40 |          |  |  | 1,010,529         |  |  | $      | 0.40 |  |                   |  | 971,508   |        |  | $ | 0.40              |  |  |        | 939,067   |  |                   | $ | 0.40 |  |  |  | 3,974,569  |  |  | $ | 0.40 | 
|     |  |                                  |           |  |                   |   |      |          |  |  |                   |  |  |        |      |  |                   |  |           |        |  |   |                   |  |  |        |           |  |                   |   |      |  |  |  |            |  |  |   |      | 
|     |  |                                  |           |  |                   |   |      |          |  |  |                   |  |  |        |      |  |                   |  |           |        |  |   |                   |  |  |        |           |  |                   |   |      |  |  |  | 23,180,407 |  |  |   |      | 
|     |  |                                  |           |  |                   |   |      |          |  |  |                   |  |  |        |      |  |                   |  |           |        |  |   |                   |  |  |        |           |  |                   |   |      |  |  |  |            |  |  |   |      | 

Investing ActivitiesAcquisitions and Capital Expenditures

Cash used in investing activities was $6.0 million for the nine months ended September 30, 2010, compared to $22.6 million for the
same period in 2009. Our cash capital expenditures were $6.4 million in 2010, of which $5.9 million related to drilling expenditures for our 2010 capital program in the Cherokee Basin and $0.5 million related to the acquisition of additional
interests in seven natural gas wells in the Cherokee Basin and in the Black Warrior Basin. We have drilled and completed 3 net wells, 7 net recompletions, and 8 net sidetracks in the Cherokee Basin and we currently have 6 net wells, 7 net
recompletions, and 4 net sidetracks in progress. All of these in progress wells, except 2 sidetracks, are expected to be producing in the fourth quarter of 2010. The 2 sidetracks are expected to be producing in early 2011. We have used $1.4 million
of our materials and supplies inventory in our current drilling and workover programs and expect to use an additional $0.2 million in inventory during the fourth quarter. We do not plan on restocking the inventory items that we use. We do not
currently plan on any additional material capital spending during 2010.

Our 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 September 30, 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.

We currently anticipate our 2010 capital spending will be approximately $10.5 million, of which we have spent $6.4 million. We currently
anticipate our total capital budget for 2011 will be between $10.0 million and $12.0 million. This 2011 capital budget primarily consists of capital for drilling wells and recompletions and also includes amounts for infrastructure projects,
equipment, and inventory. The 2011 budget is set below our 2010 estimated maintenance capital level of $25.3 million and is set at a similar level to our 2010 actual capital spending. Our capital spending in 2010 was reduced from our 2009 spending
level of $22.9 million and our 2008 spending level of $47.9 million. We expect that our current and future capital expenditures will be funded using our cash flow



33



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from operations. This decreased level of maintenance capital spending will result in lower production volumes in future periods. Because we have reduced capital spending in 2010 and in 2009 below
a maintenance level, we anticipate lower production in 2010 and 2011 which we expect to reduce our operating cash flows. Once market conditions warrant, we expect to evaluate the resumption of capital spending at a level sufficient to maintain our
then current production rate. We believe that natural gas prices in excess of $6.00 per Mcfe produce rates of return that generally support capital spending at maintenance levels. The amount and timing of our capital expenditures is largely
discretionary and within our control. If natural gas prices decline further, and the total borrowing base under our reserve-based credit facility is further reduced, or drilling costs escalate, we could choose to defer a portion of any planned
capital expenditures until later periods. We routinely monitor and adjust our capital expenditures in response to changes in oil and natural gas prices, drilling and acquisition costs, industry conditions, availability of funds under our
reserve-based credit facility, and internally generated cash flow. Matters outside our control that could affect the timing of our capital expenditures include obtaining required permits and approvals in a timely manner and the availability of rigs
and crews. Based upon current natural gas price expectations and expected production levels, we anticipate that our cash flow from operations will meet our planned capital expenditures and other cash requirements for the remainder of 2010 and for
the twelve months ending December 31, 2011. In 2010 and 2011, we expect that our excess operating cash flows will be used to reduce our outstanding debt level, which may provide us with additional liquidity from the available borrowing base
under our reserve-based credit facility. However, future cash flows and our borrowing capacity are subject to a number of variables, including the level of natural gas production and prices. There can be no assurance that operations and other
capital resources will provide cash in sufficient amounts to maintain planned levels of capital expenditures. Our capital expenditures are also impacted by drilling and service costs. In the event of inflation increasing drilling and service costs,
our hedging program will limit our ability to have increased revenues recoup the higher costs, which could further impact our planned capital spending.

Financing Activities

Our net cash used in financing activities was $23.0
million for the nine months ended September 30, 2010, compared to $1.5 million provided by financing activities for the same period in 2009. During 2010, we used $23.5 million in operating cash flows to reduce our outstanding debt level from
$195.0 million to $171.5 million or by 12.1%. In November 2009, we entered into an amended and restated credit facility that matures in November 2012. At September 30, 2010, we have approximately $4.2 million in debt issue costs remaining to be
amortized through November 2012.

We have suspended $3.3 million in quarterly distributions on the Class D interests
associated with each of the quarterly periods since 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 reserve-based credit facility and limited liability company agreement. We have suspended our $0.13 per unit quarterly distributions to
unitholders since the quarter ended June 30, 2009, to reduce our outstanding indebtedness. Given our current focus on debt reduction, we anticipate that our distribution will remain suspended through the fourth quarter of 2011. For additional
information, refer toOutlook on page 35.

Our net cash provided by financing activities was $1.5 million for the
nine months ended September 30, 2009. In 2009, we borrowed a net of $7.5 million to finance capital expenditures and for working capital needs. We also paid distributions of $5.8 million to our common and Class A unitholders in 2009.

Contractual Obligations

At September 30, 2010, we had the following contractual obligations or commercial commitments:



|                              |                |                            |       |      |  |   |      |  |  |      |         |  |      |   |     |            |  |   |       |  |  |   |     |  |  |   |         | 
|----------------------------- | -------------- | -------------------------- | ----- | ---- |  | - | ---- |  |  | ---- | ------- |  | ---- | - | --- | ---------- |  | - | ----- |  |  | - | --- |  |  | - | ------- | 
|                              |                | Payments Due By
Year(1)(2) |      
|                              | 2010           |                            |       | 2011 |  |   | 2012 |  |  | 2013 |         |  | 2014 |   |     | Thereafter |  |   | Total | 
|                              | (In thousands) |                           
|Reserve-based credit facility |                | $                          |      |      |  | $ |     |  |  | $    | 172,500 |  |      | $ |    |            |  | $ |      |  |  | $ |    |  |  | $ | 172,500 | 
|Support Services Agreements   |                |                            | 1,265 |      |  |   |     |  |  |      |        |  |      |   |    |            |  |   |      |  |  |   |    |  |  |   | 1,265   | 
|Offices Leases                |                |                            | 414   |      |  |   | 416  |  |  |      | 424     |  |      |   | 408 |            |  |   | 422   |  |  |   | 752 |  |  |   | 2,836   | 
|                              |                |                            |       |      |  |   |      |  |  |      |         |  |      |   |     |            |  |   |       |  |  |   |     |  |  |   |         | 
|Total                         |                | $                          | 1,679 |      |  | $ | 416  |  |  | $    | 172,924 |  |      | $ | 408 |            |  | $ | 422   |  |  | $ | 752 |  |  | $ | 176,601 | 
|                              |                |                            |       |      |  |   |      |  |  |      |         |  |      |   |     |            |  |   |       |  |  |   |     |  |  |   |         | 



|(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 5.1% at September 30,
2010.
|--- | --------------------------------------------------------------------------------------------------------------------------------------------------------------------

At September 30, 2010, our asset retirement obligation was approximately $12.8 million.



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Off-Balance Sheet Arrangements

We have no off-balance sheet debt to any third parties or related 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

Our internal risk committee actively monitors 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 5, 2010, we have not suffered any losses with our
counterparties as a result of nonperformance.

Certain key counterparty relationships are described below:

Macquarie Energy LLC

Macquarie Energy LLC (Macquarie), a subsidiary of Sydney, Australia-based Macquarie Group Limited, purchases a portion of our natural gas production in the Cherokee Basin. We have received a
guarantee from Macquarie Bank Limited for up to $8.0 million in purchases through December 31, 2011. As of November 5, 2010, we have no past due receivables from Macquarie.

Scissortail Energy, LLC

Scissortail Energy, LLC (Scissortail), a subsidiary of Copano Energy, L.L.C., purchases a portion of our natural gas production in Oklahoma and Kansas. As of November 5, 2010, we have no
past due receivables from Scissortail.

ONEOK Energy Services Company, L.P.

ONEOK Energy Services Company, L.P. (ONEOK), a subsidiary of ONEOK, Inc., purchases a portion of our natural gas production in
Oklahoma and Kansas. As of November 5, 2010, we have no past due receivables from ONEOK.

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 through June 30, 2014. As of November 5, 2010, we have no past due receivables from J.P. Morgan Ventures Energy Corporation.

Derivative Counterparties

As of November 5, 2010, all of our derivatives are with BNP Paribas, The Royal Bank of Scotland plc, Societe Generale, Wells Fargo Bank, N.A. and The Bank of Nova Scotia. These banks are lenders who
participate in our reserve-based credit facility. All of our derivatives are collateralized by the assets securing our reserve-based credit facility and therefore currently do not require the posting of cash collateral. As of November 5, 2010,
each of these financial institutions has an investment grade credit rating.

Reserve-Based Credit Facility

As of November 5, 2010, the banks and their percentage commitments in our reserve-based credit facility are: The Royal Bank of
Scotland plc (26.84%), BNP Paribas (21.95%), The Bank of Nova Scotia (21.95%), Wells Fargo Bank, N.A. (14.63%), and Societe Generale (14.63%). As of November 5, 2010, each of these financial institutions has an investment grade credit rating.

Outlook

During the remainder of 2010 and throughout 2011, we expect that our business will continue to be affected by the factors described in
Part II, Item 1A. Risk Factors, and the other risk factors described in our annual report on Form 10-K for the year ended December 31, 2009, as well as the following key industry and economic trends. Our expectation is 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 2010 Expected Results

Our 2010 business plan and forecast was focused on reducing our outstanding debt level and promoting financial flexibility by further enhancing our liquidity position. This plan resulted in limited
maintenance capital expenditures and the continued suspension of our quarterly distribution through the fourth quarter of 2010. During 2010, our expected results have been impacted by weak economic activity muting the demand and prices for oil and
natural gas in our market areas, further declines in expected future prices of natural gas, a decline in our natural gas production, and a continued limited ability to access our reserve-based credit facility. Our actual operating and financial
results through September 30, 2010, are consistent with or exceed the expectations that have been outlined in our 2010 business plan and forecast.



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We currently
anticipate that for 2010:



| |  |  | Our production to be approximately 14.5 Bcfe to 15.5 Bcfe.
| | - |  | ----------------------------------------------------------



| |  |  | Our operating expenses to be at the lower end of the range of $52.0 million to $56.0 million.
| | - |  | ---------------------------------------------------------------------------------------------



| |  |  | Our total capital expenditures to be approximately $10.5 million. This capital budget was reduced to a level below our estimated maintenance level of
capital expenditures of approximately $25.3 million for 2010. We expect to drill and complete approximately 30 to 35 net wells, sidetracks, and recompletions, all in the Cherokee Basin.
| | - |  | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  |  | Our total operating cash flow to exceed our business plan targets allowing for a total reduction of our outstanding debt level to approximately $165.0
million at December 31, 2010, down from a high of $220.0 million, or a reduction of 25.0%.
| | - |  | -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

2011
Business Plan and Forecast

Our 2011 business plan and forecast is focused on further reducing our outstanding debt level
and promoting financial flexibility by limiting maintenance capital expenditures and an anticipated continued suspension of our quarterly distribution through the fourth quarter of 2011. We currently expect our operating environment to be
characterized by continued low natural gas prices and increasing cost pressures, including higher service costs and healthcare costs.

We currently anticipate that for 2011:



| |  |  | Our production to be between 13.4 Bcfe and 14.2 Bcfe, approximately 72% of which is currently hedged at a level above current market prices.
| | - |  | --------------------------------------------------------------------------------------------------------------------------------------------



| |  |  | Our operating expenses to be actively managed, resulting in a range of $48.0 million to $52.0 million.
| | - |  | ------------------------------------------------------------------------------------------------------



| |  |  | Our total capital expenditures to be between $10.0 million and $12.0 million, which assumes a decline rate of 15 percent and a dollar per flowing Mcfe
range of $3,200 to $3,800. This capital budget has been held steady with our 2010 budgeted capital expenditures, which was reduced to a level below our estimated maintenance level of capital expenditures of approximately $25.3 million for 2010. We
expect to drill and complete approximately 30 to 35 net wells, sidetracks, and recompletions, both in the Black Warrior Basin and in the Cherokee Basin. We have very limited amounts of lease expirations during 2011 and 2012, which generally allows
us to reduce our drilling activities without losing our undeveloped locations. We expect to actively review our drilling and recompletion opportunities and anticipate allocating capital to the highest value-added projects across all of our available
opportunities.
| | - |  | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  |  | We anticipate that our operating cash flows may allow for a total reduction of our outstanding debt level at December 31, 2011, by an additional
$25.0 million to $30.0 million below our expected $165.0 million balance at December 31, 2010.
| | - |  | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  |  | We anticipate that our quarterly distributions to our unitholders will remain suspended through the fourth quarter of 2011. All future quarterly
distributions must be approved by our board of managers.
| | - |  | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

Impact of 2010 and 2011 Plans

Our 2010 and 2011 operating plans are intended to further reduce our outstanding debt by continuing our reduction of maintenance capital
expenditures and continuing the suspension of our quarterly distribution to unitholders. We expect that these plans will result in lower production levels in 2010 and in 2011. This limited level of maintenance capital spending would likely result in
lower production levels continuing into future periods. We do not believe, however, that during this potential extended period of limited maintenance capital expenditures, we would lose any significant leased acreage. These plans are expected to
reduce our leverage, continue to improve our liquidity position, and reduce future cash interest expenses on our outstanding unhedged debt. When we forecast over the next five years, we currently expect that our existing asset base and hedge
portfolio will allow us to substantially reduce our debt while funding a limited capital program.

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.



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As of
September 30, 2010, 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, 2009. 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

In January 2010, the FASB issued its final guidance on additional supplemental fair value disclosures. Two new disclosures are required: (1) a gross presentation of activities (purchases,
sales, and settlements) within the Level 3 roll forward reconciliation, which will replace the net presentation format, and (2) detailed disclosures about the transfers between Level 1 and 2 measurements. The guidance also provides
several clarifications regarding the level of disaggregation and disclosures about inputs and valuation techniques. The new disclosures became effective for the first quarter 2010 for calendar year-end companies, except for the Level 3
gross activity disclosures, which will be deferred until the first quarter of 2011. The adoption of this guidance did not have a material impact on our financial statements or our disclosures.

In February 2010, the FASB amended its guidance on subsequent events. SEC filers are now not required to disclose the date through which
an entity has evaluated subsequent events. The amended guidance was effective upon issuance. The adoption of this guidance did not have a material impact on our financial statements or our disclosures.

New Accounting Pronouncements Issued But Not Yet Adopted

As of September 30, 2010, there were a number of accounting standards and interpretations that had been issued, but not yet adopted by us. We are currently reviewing the recently issued standards and
interpretations but none are expected to have a material impact on our financial statements.



|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 oil and 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 2010, the U.S. economy has improved but the level of improvement has been insufficient to materially increase the demand for oil and natural gas. Concurrently, production from shale gas plays has
increased the supply of natural gas in the U.S. As a result, future expected prices for natural gas have significantly declined since December 31, 2009.

We expect that our ability to issue debt and equity may be limited over the next year, that the borrowing base of our reserve-based credit facility could potentially be further reduced, particularly if
future expected market prices for natural gas decline further. We also may have difficulty in accessing credit should we have the need to. In response to the credit crisis and the decline in the market prices for oil and natural gas, we have
suspended our cash distribution since June 2009 and lowered our maintenance capital spending in 2009, 2010, and 2011. We expect that if market prices for natural gas remains depressed, our future cash flows from operations will be reduced for our
unhedged production. We continue to monitor the financial and energy markets to determine if we should further revise the timing and scope of our future drilling programs, financing activities, and acquisition activities to determine the impact of
these activities on 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, 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 reducing 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 available for sale in the market.



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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 our derivative transactions with counterparties that are lenders in our reserve-based credit facility. 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, 2010 |  | $          | 100,901    |  |                     | $          | 84,222 |                     |            | $ | (16,679 | )        |  | $ | 117,580 |  |  | $ | 16,679 | 

Interest Rate Risk

At September 30, 2010, the one-month LIBOR rate was 0.256%, the three-month LIBOR rate was 0.290%, and our
applicable margin on LIBOR borrowings was 3.25%. At September 30, 2010, the ABR rate was 3.25%, and our applicable margin on ABR borrowings was 2.25%. At September 30, 2010, we had debt outstanding of $172.5 million. Of this amount, $116.5
million incurred interest at a rate of a three-month LIBOR rate plus an applicable margin of 3.25% based on utilization and $56.0 million incurred interest at a rate of a one-month LIBOR rate plus an applicable margin of 3.25% based on utilization.
We had no debt outstanding at the ABR rate. At September 30, 2010, the carrying value and fair value of our debt is $172.5 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, 2010 |  | $          | (5,512     | ) |                     | $        | (4,714 | )                   |            | $ | 798 |            |  | $ | (6,310 | ) |  | $ | (798 | )

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, 2010, we have the following outstanding interest rate swaps that fix our LIBOR rate:



|                   |  |                   |        |  |                  |  |      |  
|------------------ |  | ----------------- | ------ |  | ---------------- |  | ---- | -
|Maturity Date      |  | Total Debt Hedged |        |  | LIBOR Fixed Rate | 
|                   |  | (in 000s)        |        |  |                  | 
|                   |  |                  
|October 22, 2010   |  | $                 | 19,000 |  |                  |  | 2.91 | %
|August 20, 2014    |  | $                 | 11,000 |  |                  |  | 2.37 | %
|September 20, 2014 |  | $                 | 45,000 |  |                  |  | 2.52 | %
|October 19, 2014   |  | $                 | 29,500 |  |                  |  | 2.68 | %
|October 22, 2014   |  | $                 | 7,500  |  |                  |  | 2.61 | %



|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.



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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 the three months ended September 30, 2010, 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.

In July 2010, the Dodd-Frank Wall Street Reform and Consumer Protection Act (Dodd-Frank Act), was enacted into law. The
Dodd-Frank Act provides non-accelerated filers with a permanent exemption from the requirement to obtain an external audit on the effectiveness of internal financial reporting controls provided in Section 404(b) of the Sarbanes-Oxley Act. CEP
is a non-accelerated filer and will utilize this exemption under the Dodd-Frank Act for the year ending December 31, 2010. CEP will still disclose managements assessment of the effectiveness of internal control over financial reporting as
required in Section 404(a) of the Sarbanes-Oxley Act. The amendment to the Sarbanes-Oxley Act was effective immediately and is intended to reduce compliance costs for smaller companies. The use of this exemption was reviewed and approved by
CEPs audit committee.

Part IIOther Information



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

Litigation Related to Trust Termination

On January 25, 2008, Torch Royalty Company, Torch E&P Company, and CEP (collectively, the Claimants) commenced an arbitration proceeding before Judicial Arbitration and Mediation
Services against Wilmington Trust Company, as Trustee (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 were similarly subject to net profit interests (the Other NPIs) that were also based on the gas purchase contract. The 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 were terminated. The Trustee took the position that the sharing arrangement
under the gas purchase contract terminated upon the termination of the gas purchase contract. Trust Venture Company, LLC (Trust Venture) was permitted to intervene in the proceeding under an agreement whereby Trust Venture and its
affiliates agreed to be bound by the formal award in the proceeding. On July 18, 2008, the arbitration panel issued its 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, and on December 10, 2008, the District Court of Harris County, Texas, 152nd Judicial District, dismissed the appeal of the final award filed by the Trustee and
Trust Venture and confirmed the final award.

On January 8, 2009, we were 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. The Alabama court has made
the Trust a nominal party to the Alabama litigation and ruled that the Trust is 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 Gathering and Disposal Agreement pending judgment in the lawsuit and asserting damages of
approximately $11.6 million from June 2005 to May 2009. These alleged damages appear to be calculated based on a water gathering, separation and disposal fee of $0.05 per barrel notwithstanding the provisions of the Water Gathering and Disposal
Agreement. After hearing, the Alabama court denied Trust Ventures application. On February 9, 2010, Trust Venture filed a motion for partial summary judgment seeking a determination regarding the applicability of a provision in the
Conveyance related to the calculation of water handling charges, which motion the court denied on May 28, 2010, with the court ruling that our position with respect to the Conveyance provision was correct. No trial date has been set in the
litigation, although we anticipate a trial date in the first quarter of 2011. We intend to defend ourselves 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. We intend our forward-looking statements relating to the action to speak only as of the time of such statements and do not plan to update or revise them except to the extent that material information becomes available.



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|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 the year ended December 31, 2009 that was filed on February 25, 2010. 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 2009 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.

Risks Related to Financing and Credit Environment

Government regulations regarding derivatives could adversely impact our ability to engage in commodity price risk management activities.

We use derivative instruments to manage our commodity price and interest rate risk. The Dodd-Frank Act, which was signed into law in July
2010, contains measures aimed at increasing the transparency and stability of the over-the-counter, or OTC, derivative markets and preventing excessive speculation. The Dodd-Frank Act could restrict, among other things, trading positions in the
energy futures markets, require different collateral or settlement positions, or increase regulatory reporting over derivative positions. Based on the provisions included in the Dodd-Frank Act and the implementation of regulations yet to be
developed, these changes could, among other things, impact our ability to hedge commodity price and interest rate risk or increase the costs associated with our hedging programs, and such impact could be material to our revenues and operating cash
flows.

Tax Risks to Unitholders

The value of an investment in our units could be affected by recent and potential federal tax increases.

Absent new legislation extending the current rates, in taxable years beginning after December 31, 2010, the highest marginal United States federal income tax rate applicable to ordinary income and
long-term capital gains of individuals will increase to 39.6% and 20%, respectively. These rates are subject to change by new legislation at any time.

The recently enacted Health Care and Education Reconciliation Act of 2010 includes a provision that, in taxable years beginning after December 31, 2012, subjects certain individuals, estates and
trusts to an Unearned Income Medicare Contribution tax of 3.8% on certain income. In the case of an individual having a modified adjusted gross income in excess of $200,000 (or $250,000 for married taxpayers filing joint returns), the provision
imposes a tax equal to 3.8% of the lesser of such excess and the individuals net investment income, which will include net income and gain from the ownership or disposition of our units.

These recent federal tax increases, and any other future potential federal tax increases, could negatively impact the value of an
investment in our common units.

Certain U.S. federal income tax deductions currently available with respect to oil and gas exploration
and development may be eliminated as a result of future legislation.

Substantive changes to the existing federal
income tax laws have been proposed that, if adopted, would affect, among other things, the ability to take certain operations-related deductions, including deductions for intangible drilling costs and percentage depletion and deductions for United
States production activities. Other proposed changes may affect our ability to remain taxable as a partnership for federal income tax purposes. We are unable to predict whether any changes, or other proposals to such laws, ultimately will be
enacted. Any such changes could negatively impact the value of an investment in our common units.

Unitholders may be required to pay
taxes on income from us, including their share of ordinary income and any capital gains on dispositions of properties by us, even if they do not receive any cash distributions from us.

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. For example, we may sell a portion of our properties and use the proceeds to pay down debt or acquire other properties rather than distributing the
proceeds to our unitholders. Our unitholders may be allocated substantial taxable income with respect to that sale.

Based on
our 2010 and 2011 business plans and forecasts, we do not currently anticipate resuming a cash distribution in 2010 or in 2011 and we anticipate making limited maintenance capital expenditures. If we generate taxable income for the 2010 or 2011 tax
years, our unitholders will not receive cash distributions from us during 2010 or 2011 in an amount sufficient to pay any actual tax liability that results from their share of such 2010 or 2011 taxable income.



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A unitholders share of our
taxable income, gain, loss and deduction, or specific items thereof, may be substantially different than the unitholders interest in our economic profits.

A unitholders share of our taxable income and gain (or specific items thereof) may be substantially greater than, or our tax losses and deductions (or specific items thereof) may be substantially
less than, the unitholders interest in our economic profits. This may occur, for example, in the case of a unitholder who purchases units at a time when the value of our units or of one or more of our properties is relatively low or a
unitholder who acquires units directly from us in exchange for property whose fair market value exceeds its tax basis at the time of the exchange.

The tax treatment of publicly traded partnerships or an investment in our common units could be subject to potential legislative, judicial or administrative changes and differing interpretations,
possibly on a retroactive basis.

The present U.S. federal income tax treatment of publicly traded partnerships,
including us, or an investment in our common units may be modified by administrative, legislative or judicial interpretation at any time. For example, members of Congress are considering substantive changes to the definition of qualifying
income under Section 7704 of the Internal Revenue Code and changing the treatment of certain types of income earned from profits or carried interests. It is possible that these legislative efforts could result in changes to the
existing U.S. tax laws that affect publicly traded partnerships, including us. Any modification to the U.S. federal income tax laws and interpretations thereof could make it more difficult or impossible to (i) meet the exception, which we
refer to as the qualifying income exception, for us to be treated as a partnership for U.S. federal income tax purposes that is not taxable as a corporation, (ii) affect or cause us to change our business activities, (iii) affect the tax
considerations of an investment in us, (iv) change the character or treatment of portions of our income or (v) adversely affect an investment in our common units. Any modification to the federal income tax laws and interpretations
thereof may or may not be applied retroactively. Any such changes could negatively impact the value of an investment in our common units.

We will be considered to have terminated for tax purposes due to a sale or exchange of 50% or more of our interests within a twelve-month period.

We will be considered to have terminated for tax purposes if there is a sale or exchange of 50% or more of the total
interests in our capital and profits within a twelve-month period. For purposes of determining whether the 50% threshold has been met, multiple sales of the same interest will be counted only once. A constructive termination results in the closing
of our taxable year for all unitholders, which would result in us filing two tax returns for one fiscal year, the cost of which would be borne by our unitholders, and could result in a deferral of depreciation deductions allowable in computing our
taxable income. We technically terminated for tax purposes for the 2009 tax year and incurred additional costs as a result of the termination. We are not able to control or to predict if or when we may technically terminate for tax purposes in the
future.

In the case of a unitholder reporting on a taxable year other than a fiscal year ending December 31, the closing
of our taxable year may result in more than 12 months of our taxable income or loss being includable in his taxable income for the year of termination. Our termination currently would not affect our classification as a partnership for federal income
tax purposes, but instead, we would be treated as a new partnership for tax purposes. When treated as a new partnership, we must make new tax elections and could be subject to penalties if we are unable to determine that a termination occurred.

Unitholders may be subject to state and local taxes and return filing requirements.

We currently do business and own assets in Alabama, Kansas, and Oklahoma. We are registered to do business in Texas. Each of these
states, except Texas, imposes an income tax on individuals. Most of these states also impose an income tax on corporations and other entities. As we make acquisitions or expand our business, we may do business or own assets in other states in the
future.

Some of the states may require us, or we may elect, to withhold a percentage of income from amounts to be distributed
to a common unitholder who is not a resident of the state. Withholding, the amount of which may be greater or less than a particular common unitholders income tax liability to the state, generally does not relieve a nonresident common
unitholder from the obligation to file an income tax return. Amounts withheld may be treated as if distributed to common unitholders for purposes of determining the amounts distributed by us.

It is the sole responsibility of each unitholder to file all United States federal, foreign, state and local tax returns that may be
required of such unitholder.

Forward-Looking Statements

This Quarterly Report on Form 10-Q contains forward-looking statements as defined by the SEC 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;
| | - |  | ------------------------------------------------------



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| |  |  | 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 facility;
| | - |  | ---------------------------------------------------------------------



| |  |  | the level of our borrowing base under our reserve-based credit facility;
| | - |  | ------------------------------------------------------------------------



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



| |  |  | the impact from any termination of the NPI sharing arrangement or any change in the calculation of the NPI;
| | - |  | -----------------------------------------------------------------------------------------------------------



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



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



| |  |  | our lease operating expenses, general and administrative costs, depletion rates 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 and economic environment;
| | - |  | -----------------------------------------------------------------



| |  |  | 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, including environmental regulation, and taxation of the oil and natural gas industry;
| | - |  | --------------------------------------------------------------------------------------------------------------



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



| |  |  | support from our former sponsor or a change in any 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. 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 and our Annual Report on Form 10-K and 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.



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

None.



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

None.



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|Item 4. | Reserved
|------- | --------



|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, 2010 and September 30, 2009 and nine months ended September 30, 2010 and September 30, 2009

Consolidated Balance Sheets  Constellation Energy Partners LLC at September 30, 2010 and December 31, 2009

Consolidated Statements of Cash Flows  Constellation Energy Partners LLC for the nine months ended September 30, 2010 and
September 30, 2009

Consolidated Statements of Changes in Members Equity and Comprehensive Income 
Constellation Energy Partners LLC for the nine months ended September 30, 2010

Notes to Consolidated Financial Statements

EXHIBIT INDEX



|               |  |                                                                                                                                                                                                                               
|-------------- |  | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|Exhibit Number |  | Description                                                                                                                                                                                                                   
|               | 
|*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 5, 2010 |  | By                                |  | /s/ MICHAEL B. HINEY                                    
|                       |  |                                   |  | Michael B. Hiney Chief
Accounting Officer and Controller



44