##### 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 March 31, 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. EmployerIdentification 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 May 7, 2010: 24,040,055 units.









---

##### 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 |  | 20  
|Results of Operations                                                                         |  | 23  
|Liquidity and Capital Resources                                                               |  | 26  
|Item 3. Quantitative and Qualitative Disclosures About Market Risk                            |  | 33  
|Item 4. Controls and Procedures                                                               |  | 35  
|                                                                                              | 
|PART IIOther Information                                                                     |  | 36  
|Item 1. Legal Proceedings                                                                     |  | 36  
|Item 1A. Risk Factors                                                                         |  | 36  
|Item 2. Unregistered Sales of Equity Securities and Use of Proceeds                           |  | 38  
|Item 3. Defaults Upon Senior Securities                                                       |  | 38  
|Item 4. Reserved                                                                              |  | 38  
|Item 5. Other Information                                                                     |  | 38  
|Item 6. Exhibits                                                                              |  | 38  
|Signatures                                                                                    |  | 40  



2



---

##### 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 endedMarch 31, |            |   | Three months endedMarch 31, |  
|                                                                         |  | 2010                        |            |   | 2009                        |  
|                                                                         |  | (In 000s except unit data) |           
|Revenues                                                                 |  |                             |            |   |                             |   |            |  
|Oil and gas sales                                                        |  | $                           | 29,237     |   |                             | $ | 32,862     |  
|Gain / (Loss) from mark-to-market activities (see Note 4)                |  |                             | 35,281     |   |                             |   | 19,331     |  
|                                                                         |  |                             |            |   |                             |   |            |  
|Total revenues                                                           |  |                             | 64,518     |   |                             |   | 52,193     |  
|Expenses:                                                                |  |                             |            |   |                             |   |            |  
|Operating expenses:                                                      |  |                             |            |   |                             |   |            |  
|Lease operating expenses                                                 |  |                             | 7,963      |   |                             |   | 8,785      |  
|Cost of sales                                                            |  |                             | 772        |   |                             |   | 832        |  
|Production taxes                                                         |  |                             | 1,125      |   |                             |   | 970        |  
|General and administrative                                               |  |                             | 5,062      |   |                             |   | 5,233      |  
|Exploration costs                                                        |  |                             | 223        |   |                             |   | 103        |  
|(Gain) / Loss on sale of asset                                           |  |                             | (8         | ) |                             |   | 17         |  
|Depreciation, depletion and amortization                                 |  |                             | 27,248     |   |                             |   | 14,434     |  
|Accretion expense                                                        |  |                             | 207        |   |                             |   | 102        |  
|                                                                         |  |                             |            |   |                             |   |            |  
|Total operating expenses                                                 |  |                             | 42,592     |   |                             |   | 30,476     |  
|Other expense / (income)                                                 |  |                             |            |   |                             |   |            |  
|Interest expense                                                         |  |                             | 3,539      |   |                             |   | 2,499      |  
|Interest expense-(Gain)/Loss from mark-to-market activities (see Note 4) |  |                             | 517        |   |                             |   | 344        |  
|Interest (income)                                                        |  |                             |           |   |                             |   | (2         | )
|Other expense (income)                                                   |  |                             | (188       | ) |                             |   | (57        | )
|                                                                         |  |                             |            |   |                             |   |            |  
|Total other expenses / (income)                                          |  |                             | 3,868      |   |                             |   | 2,784      |  
|                                                                         |  |                             |            |   |                             |   |            |  
|Total expenses                                                           |  |                             | 46,460     |   |                             |   | 33,260     |  
|                                                                         |  |                             |            |   |                             |   |            |  
|Net income                                                               |  | $                           | 18,058     |   |                             | $ | 18,933     |  
|Other comprehensive income (loss)                                        |  |                             | (5,286     | ) |                             |   | 7,713      |  
|                                                                         |  |                             |            |   |                             |   |            |  
|Comprehensive income (loss)                                              |  | $                           | 12,772     |   |                             | $ | 26,646     |  
|                                                                         |  |                             |            |   |                             |   |            |  
|                                                                         |  |                            
|Earnings per unit (see Note 1)                                           |  |                             |            |   |                             |   |            |  
|Earnings per unitBasic                                                  |  | $                           | 0.75       |   |                             | $ | 0.85       |  
|Units outstandingBasic                                                  |  |                             | 24,002,372 |   |                             |   | 22,386,063 |  
|Earnings per unitDiluted                                                |  | $                           | 0.75       |   |                             | $ | 0.85       |  
|Units outstandingDiluted                                                |  |                             | 24,002,372 |   |                             |   | 22,386,063 |  
|Distributions declared and paid per unit                                 |  | $                           |           |   |                             | $ | 0.13       |  

See accompanying notes
to consolidated financial statements.



3



---

##### Table of Contents

CONSTELLATION ENERGY PARTNERS LLC and SUBSIDIARIES

Consolidated Balance Sheets

(Unaudited)



|                                                                                                                                             |  |                |          |   |                   |   |          |  
|-------------------------------------------------------------------------------------------------------------------------------------------- |  | -------------- | -------- | - | ----------------- | - | -------- | -
|                                                                                                                                             |  | March 31, 2010 |          |   | December 31, 2009 |  
|                                                                                                                                             |  | (In 000s)     |         
|ASSETS                                                                                                                                       |  |                |          |   |                   |   |          |  
|Current assets                                                                                                                               |  |                |          |   |                   |   |          |  
|Cash and cash equivalents                                                                                                                    |  | $              | 8,443    |   |                   | $ | 11,337   |  
|Accounts receivable                                                                                                                          |  |                | 8,919    |   |                   |   | 8,379    |  
|Prepaid expenses                                                                                                                             |  |                | 1,728    |   |                   |   | 1,298    |  
|Risk management assets (see Note 4)                                                                                                          |  |                | 38,143   |   |                   |   | 24,251   |  
|                                                                                                                                             |  |                |          |   |                   |   |          |  
|Total current assets                                                                                                                         |  |                | 57,233   |   |                   |   | 45,265   |  
|Oil and natural gas properties (See Note 6)                                                                                                  |  |                |          |   |                   |   |          |  
|Oil and natural gas properties, equipment and facilities                                                                                     |  |                | 795,476  |   |                   |   | 794,520  |  
|Material and supplies                                                                                                                        |  |                | 4,389    |   |                   |   | 4,312    |  
|Less accumulated depreciation, depletion and amortization                                                                                    |  |                | (213,171 | ) |                   |   | (186,207 | )
|                                                                                                                                             |  |                |          |   |                   |   |          |  
|Net oil and natural gas properties                                                                                                           |  |                | 586,694  |   |                   |   | 612,625  |  
|Other assets                                                                                                                                 |  |                |          |   |                   |   |          |  
|Debt issue costs (net of accumulated amortization of $3,405 at March 31, 2010 and $2,924 at December 31,
2009)                               |  |                | 5,132    |   |                   |   | 5,590    |  
|Risk management assets (see Note 4)                                                                                                          |  |                | 49,393   |   |                   |   | 33,916   |  
|Other non-current assets                                                                                                                     |  |                | 10,760   |   |                   |   | 10,921   |  
|                                                                                                                                             |  |                |          |   |                   |   |          |  
|Total assets                                                                                                                                 |  | $              | 709,212  |   |                   | $ | 708,317  |  
|                                                                                                                                             |  |                |          |   |                   |   |          |  
|LIABILITIES AND MEMBERS EQUITY                                                                                                              |  |                |          |   |                   |   |          |  
|Liabilities                                                                                                                                  |  |                |          |   |                   |   |          |  
|Current liabilities                                                                                                                          |  |                |          |   |                   |   |          |  
|Accounts payable                                                                                                                             |  | $              | 2,551    |   |                   | $ | 1,102    |  
|Payable to affiliate                                                                                                                         |  |                | 19       |   |                   |   | 201      |  
|Accrued liabilities                                                                                                                          |  |                | 7,390    |   |                   |   | 10,033   |  
|Environmental liabilities                                                                                                                    |  |                | 193      |   |                   |   | 193      |  
|Royalty payable                                                                                                                              |  |                | 4,031    |   |                   |   | 4,747    |  
|Risk management liabilities (see Note 4)                                                                                                     |  |                | 99       |   |                   |   | 208      |  
|                                                                                                                                             |  |                |          |   |                   |   |          |  
|Total current liabilities                                                                                                                    |  |                | 14,283   |   |                   |   | 16,484   |  
|Other liabilities                                                                                                                            |  |                |          |   |                   |   |          |  
|Asset retirement obligation                                                                                                                  |  |                | 12,318   |   |                   |   | 12,129   |  
|Debt                                                                                                                                         |  |                | 185,000  |   |                   |   | 195,000  |  
|                                                                                                                                             |  |                |          |   |                   |   |          |  
|Total other liabilities                                                                                                                      |  |                | 197,318  |   |                   |   | 207,129  |  
|                                                                                                                                             |  |                |          |   |                   |   |          |  
|Total liabilities                                                                                                                            |  |                | 211,601  |   |                   |   | 223,613  |  
|                                                                                                                                             |  |               
|Commitments and contingencies (See Note 8)                                                                                                   |  |                |          |   |                   |   |          |  
|                                                                                                                                             |  |               
|Class D Interests                                                                                                                            |  |                | 6,667    |   |                   |   | 6,667    |  
|                                                                                                                                             |  |               
|Members equity                                                                                                                              |  |                |          |   |                   |   |          |  
|Class A units, 490,613 and 476,950 shares authorized, issued and outstanding, respectively                                                   |  |                | 9,357    |   |                   |   | 8,993    |  
|Class B units, 24,298,763 and 24,298,763 shares authorized, respectively, and 24,040,055 and 23,376,136 issued and outstanding,
respectively |  |                | 458,507  |   |                   |   | 440,677  |  
|Accumulated other comprehensive income                                                                                                       |  |                | 23,080   |   |                   |   | 28,367   |  
|                                                                                                                                             |  |                |          |   |                   |   |          |  
|Total members equity                                                                                                                        |  |                | 490,944  |   |                   |   | 478,037  |  
|                                                                                                                                             |  |                |          |   |                   |   |          |  
|Total liabilities and members equity                                                                                                        |  | $              | 709,212  |   |                   | $ | 708,317  |  
|                                                                                                                                             |  |                |          |   |                   |   |          |  

See accompanying notes to consolidated financial statements.



4



---

##### Table of Contents

CONSTELLATION ENERGY PARTNERS LLC and SUBSIDIARIES

Consolidated Statements of Cash Flows

(Unaudited)



|                                                                                     |  |                             |         |   |      |   |         |  
|------------------------------------------------------------------------------------ |  | --------------------------- | ------- | - | ---- | - | ------- | -
|                                                                                     |  | Three months endedMarch 31, |        
|                                                                                     |  | 2010                        |         |   | 2009 |  
|                                                                                     |  | (In 000s)                  |        
|Cash flows from operating activities:                                                |  |                             |         |   |      |   |         |  
|Net income                                                                           |  | $                           | 18,058  |   |      | $ | 18,933  |  
|Adjustments to reconcile net income (loss) to cash provided by operating activities: |  |                             |         |   |      |   |         |  
|Depreciation, depletion and amortization                                             |  |                             | 27,248  |   |      |   | 14,434  |  
|Amortization of debt issuance costs                                                  |  |                             | 481     |   |      |   | 264     |  
|Accretion of plugging and abandonment liability                                      |  |                             | 207     |   |      |   | 102     |  
|Equity earnings (losses) in affiliate                                                |  |                             | (188    | ) |      |   | (57     | )
|(Gain) Loss from disposition of property and equipment                               |  |                             | (8      | ) |      |   | 17      |  
|Hedge ineffectiveness                                                                |  |                             |        |   |      |   | 267     |  
|(Gain) Loss from mark-to-market activities                                           |  |                             | (34,764 | ) |      |   | (19,331 | )
|Unit-based compensation programs                                                     |  |                             | 437     |   |      |   | 68      |  
|Changes in Assets and Liabilities:                                                   |  |                             |         |   |      |   |         |  
|Change in net risk management assets and liabilities                                 |  |                             |        |   |      |   | 488     |  
|(Increase) decrease in accounts receivable                                           |  |                             | (540    | ) |      |   | 3,162   |  
|(Increase) decrease in prepaid expenses                                              |  |                             | (429    | ) |      |   | (531    | )
|(Increase) decrease in other assets                                                  |  |                             | (2      | ) |      |   | 42      |  
|Increase (decrease) in accounts payable                                              |  |                             | 1,449   |   |      |   | (1,444  | )
|Increase (decrease) in payable to affiliate                                          |  |                             | (182    | ) |      |   | (179    | )
|Increase (decrease) in accrued liabilities                                           |  |                             | (2,997  | ) |      |   | (349    | )
|Increase (decrease) in royalty payable                                               |  |                             | (716    | ) |      |   | (1,402  | )
|                                                                                     |  |                             |         |   |      |   |         |  
|Net cash provided by operating activities                                            |  |                             | 8,054   |   |      |   | 14,484  |  
|                                                                                     |  |                             |         |   |      |   |         |  
|Cash flows from investing activities:                                                |  |                             |         |   |      |   |         |  
|Cash paid for acquisitions, net of cash required                                     |  |                             | (591    | ) |      |   | 23      |  
|Development of natural gas properties                                                |  |                             | (85     | ) |      |   | (11,480 | )
|Proceeds from sale of equipment                                                      |  |                             | 6       |   |      |   |        |  
|Distributions from equity affiliate                                                  |  |                             | 75      |   |      |   | 80      |  
|                                                                                     |  |                             |         |   |      |   |         |  
|Net cash used in investing activities                                                |  |                             | (595    | ) |      |   | (11,377 | )
|                                                                                     |  |                             |         |   |      |   |         |  
|Cash flows from financing activities:                                                |  |                             |         |   |      |   |         |  
|Members distributions                                                               |  |                             |        |   |      |   | (2,910  | )
|Proceeds from issuance of debt                                                       |  |                             |        |   |      |   | 7,500   |  
|Repayment of debt                                                                    |  |                             | (10,000 | ) |      |   |        |  
|Units tendered by employees                                                          |  |                             | (301    | ) |      |   |        |  
|Equity issue costs                                                                   |  |                             | (2      | ) |      |   |        |  
|Debt issue costs                                                                     |  |                             | (50     | ) |      |   | (36     | )
|                                                                                     |  |                             |         |   |      |   |         |  
|Net cash provided by (used in) financing activities                                  |  |                             | (10,353 | ) |      |   | 4,554   |  
|                                                                                     |  |                             |         |   |      |   |         |  
|Net (decrease) increase in cash                                                      |  |                             | (2,894  | ) |      |   | 7,661   |  
|Cash and cash equivalents, beginning of period                                       |  |                             | 11,337  |   |      |   | 6,255   |  
|                                                                                     |  |                             |         |   |      |   |         |  
|Cash and cash equivalents, end of period                                             |  | $                           | 8,443   |   |      | $ | 13,916  |  
|                                                                                     |  |                             |         |   |      |   |         |  
|Supplemental disclosures of cash flow information:                                   |  |                             |         |   |      |   |         |  
|Change in accrued capital expenditures                                               |  | $                           | 463     |   |      | $ | 3,747   |  
|Cash received during the period for interest                                         |  | $                           |        |   |      | $ | 2       |  
|Cash paid during the period for interest                                             |  | $                           | (1,923  | ) |      | $ | (2,564  | )

See accompanying notes to
consolidated financial statements.



5



---

##### Table of Contents

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 |  
|Distributions                                   |  |                                 |  |        |        |   |       |                                           |        |   |                    |   |  |   |       |   |  |   |        |  
|Units tendered by employees for tax withholding |  |                                 |  |        | (6      | ) |       |                                           |        |   | (295                | ) |  |   |       |   |  |   | (301    | )
|Change in fair value of commodity hedges        |  |                                 |  |        |        |   |       |                                           |        |   |                    |   |  |   | 52     |   |  |   | 52      |  
|Cash settlement of commodity hedges             |  |                                 |  |        |        |   |       |                                           |        |   |                    |   |  |   | (5,728 | ) |  |   | (5,728  | )
|Change in fair value of interest rate hedges    |  |                                 |  |        |        |   |       |                                           |        |   |                    |   |  |   | 389    |   |  |   | 389     |  
|Unit-based compensations programs               |  | 13,663                           |  |        | 9       |   |       | 663,919                                    |        |   | 428                 |   |  |   |       |   |  |   | 437     |  
|Net income                                      |  |                                 |  |        | 361     |   |       |                                           |        |   | 17,697              |   |  |   |       |   |  |   | 18,058  |  
|                                                |  |                                  |  |        |         |   |       |                                            |        |   |                     |   |  |   |        |   |  |   |         |  
|Balance, March 31, 2010                         |  | 490,613                          |  | $      | 9,357   |   |       | 24,040,055                                 |        | $ | 458,507             |   |  | $ | 23,080 |   |  | $ | 490,944 |  
|                                                |  |                                  |  |        |         |   |       |                                            |        |   |                     |   |  |   |        |   |  |   |         |  

See accompanying notes to consolidated financial statements.



6



---

##### Table of Contents

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
March 31, 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 December 31, 2009, 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 March 31, 2010, we had 490,613 Class A units and 24,040,055 Class B units outstanding. Of the Class B units, 1,414,452 units are restricted unvested common units granted and outstanding.



7



---

##### Table of Contents

The following table presents earnings per common unit amounts:



|                                              |  |                             |        |       |            |                |   |     
|--------------------------------------------- |  | --------------------------- | ------ | ----- | ---------- | -------------- | - | ----
|                                              |  | Income                      |        | Units |            | Per UnitAmount
|                                              |  | (In 000s except unit data)
|For the three months ended March 31, 2010     |  |                             |        |       |            |               
|Basic EPS:                                    |  |                             |        |       |            |                |   |     
|Income allocable to unitholders               |  | $                           | 18,058 |       | 24,002,372 |                | $ | 0.75
|Effect of dilutive securities:                |  |                             |        |       |            |                |   |     
|Restricted common unitsTreasury stock method |  |                             |       |       |           |                |   |    
|                                              |  |                             |        |       |            |                |   |     
|Diluted EPS:                                  |  |                             |        |       |            |                |   |     
|Income allocable to common unitholders        |  | $                           | 18,058 |       | 24,002,372 |                | $ | 0.75



|                                              |  |                             |        |       |            |                |   |     
|--------------------------------------------- |  | --------------------------- | ------ | ----- | ---------- | -------------- | - | ----
|                                              |  | Income                      |        | Units |            | Per UnitAmount
|                                              |  | (In 000s except unit data)
|For the three months ended March 31, 2009     |  |                             |        |       |            |               
|Basic EPS:                                    |  |                             |        |       |            |                |   |     
|Income allocable to unitholders               |  | $                           | 18,933 |       | 22,386,063 |                | $ | 0.85
|Effect of dilutive securities:                |  |                             |        |       |            |                |   |     
|Restricted common unitsTreasury stock method |  |                             |       |       |           |                |   |    
|                                              |  |                             |        |       |            |                |   |     
|Diluted EPS:                                  |  |                             |        |       |            |                |   |     
|Income allocable to common unitholders        |  | $                           | 18,933 |       | 22,386,063 |                | $ | 0.85

3. NEW ACCOUNTING PRONOUNCEMENTS

In January 2010, the FASB issued its final guidance on additional supplemental fair value disclosures. Two new disclosures
will be 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 are effective this
quarter 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 March 31, 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.

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 March 31, 2010.

At March 31, 2010 and
December 31 2009, we had debt outstanding of $185.0 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 $151.5 million of the outstanding debt through October 2012. All of our interest rate swaps are accounted for as mark-to-market activities as of
March 31, 2010. Prior to February 2009, they were accounted for as cash flow hedges.

For the three months ended
March 31, 2010 and 2009, we recognized mark-to-market gains of approximately $35.3 million and $19.3 million, respectively, in connection with our commodity derivatives. For the three months ended March 31, 2010 and 2009, we recognized
mark-to-market losses of approximately $0.5 million and $0.3 million, respectively, in connection with our interest rate derivatives. At March 31, 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 $87.4 million and a net asset of approximately $58.0 million, respectively.



8



---

##### Table of Contents

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 $23.1 million and an unrecognized gain of approximately $28.4 million at
March 31, 2010 and December 31, 2009, respectively. We expect that the unrecognized gain will be reclassified from accumulated other comprehensive income (loss) to the income statement in the following periods:



|                      |  |                      |        |                     |   |      |            |  |   |       
|--------------------- |  | -------------------- | ------ | ------------------- | - | ---- | ---------- |  | - | ------
|For the Quarter Ended |  | CommodityDerivatives |        | Non-performanceRisk |   |      | Total AOCI
|June 30, 2010         |  | $                    | 4,319  |                     | $ | (51  | )          |  | $ | 4,268 
|September 30, 2010    |  |                      | 3,726  |                     |   | (54  | )          |  |   | 3,672 
|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                 |  | $                    | 23,697 |                     | $ | (617 | )          |  | $ | 23,080
|                      |  |                      |        |                     |   |      |            |  |   |       

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 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.

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



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



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



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

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

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.



9



---

##### Table of Contents

The following tables sets forth by level within the fair value hierarchy our assets and
liabilities that were measured at fair value on a recurring basis as of March 31, 2010 and December 31, 2009.



|                            |  |            |   |         |              |        |         |                            |   |                     |   |  |   |   |  |   |        |  
|--------------------------- |  | ---------- | - | ------- | ------------ | ------ | ------- | -------------------------- | - | ------------------- | - |  | - | - |  | - | ------ | -
|                            |  | Commodity  |   |         | Interestrate |        |         | Netting andCashCollateral* |   | Total Net FairValue |  
|At March 31, 2010           |  | Level 1    |   | Level 2 |              |        | Level 3 |                            |   |                    
|                            |  | (In 000s) |  
|Risk management assets      |  | $          |  |         | $            | 92,391 |         |                            | $ | (4,855              | ) |  | $ |  |  | $ | 87,536 |  
|Risk management liabilities |  | $          |  |         | $            | (99    | )       |                            | $ |                    |   |  | $ |  |  | $ | (99    | )
|                            |  |            |   |         |              |        |         |                            |   |                     |   |  |   |   |  |   |        |  
|Total                       |  | $          |  |         | $            | 92,292 |         |                            | $ | (4,855              | ) |  | $ |  |  | $ | 87,437 |  
|                            |  |            |   |         |              |        |         |                            |   |                     |   |  |   |   |  |   |        |  



|* | 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, nor make any adjustments for non-performance credit risk on our liabilities with counterparties. We
utilize observable market data for credit default swaps to assess the impact of non-performance credit risk when evaluating our assets from counterparties. At March 31, 2010, the impact of non-performance credit risk on the valuation of our
assets from counterparties was $1.1 million, of which $0.5 million was reflected as a decrease to our non-cash market-to-market gain and $0.6 million was reflected as a reduction to our accumulated other comprehensive income. At March 31, 2009,
the impact of non-performance credit risk on the valuation of our assets from counterparties was $1.8 million, of which $0.9 million was reflected as a decrease to our non-cash market-to-market gain and $0.9 million was reflected as a reduction to
our accumulated other comprehensive income.

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



10



---

##### Table of Contents

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 Months EndedMarch 31, 2010(In 000s) |       
|Balance at beginning of period                                                     |  | $                                          | (4,727 | )
|Realized and unrealized gains:                                                     |  |                                            |        |  
|Included in earnings                                                               |  |                                            | (1,354 | )
|Included in other comprehensive income                                             |  |                                            |       |  
|Purchases, sales, issuances and settlements                                        |  |                                            | 1,226  |  
|Transfers into and out of Level 3                                                  |  |                                            |       |  
|                                                                                   |  |                                            |        |  
|Balance as of March 31, 2010                                                       |  | $                                          | (4,855 | )
|                                                                                   |  |                                            |        |  
|Change in unrealized gains relating to derivatives still held as of March 31, 2010 |  | $                                          | (1,354 | )
|                                                                                   |  |                                            |        |  



|                                                                                   |  |                                            |        |  
|---------------------------------------------------------------------------------- |  | ------------------------------------------ | ------ | -
|                                                                                   |  | Three Months EndedMarch 31, 2009(In 000s) |       
|Balance at beginning of period                                                     |  | $                                          | 6,752  |  
|Realized and unrealized gains:                                                     |  |                                            |        |  
|Included in earnings                                                               |  |                                            | (408   | )
|Included in other comprehensive income                                             |  |                                            | (348   | )
|Purchases, sales, issuances, and settlements                                       |  |                                            | (1,023 | )
|Transfers into and out of Level 3                                                  |  |                                            |       |  
|                                                                                   |  |                                            |        |  
|Balance as of March 31, 2009                                                       |  | $                                          | 4,973  |  
|                                                                                   |  |                                            |        |  
|Change in unrealized gains relating to derivatives still held as of March 31, 2009 |  | $                                          | (962   | )
|                                                                                   |  |                                            |        |  

Fair Value of Financial Instruments

At March 31, 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.

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



|                  |  |                                                  |  |                                                              |                             |   |                             |   |         |  
|----------------- |  | ------------------------------------------------ |  | ------------------------------------------------------------ | --------------------------- | - | --------------------------- | - | ------- | -
|Derivative Type   |  | Location of Asset /
(Liability) on Balance Sheet |  | Fair Value of Asset /(Liability) on Balance Sheets
(in000s) |                            
|                  |  | Quarter EndedMarch 31, 2010                      |  |                                                              | Year EndedDecember 31, 2009 |  
|Commodity-MTM     |  | Risk management assets                           |  | $                                                            | 108,732                     |   |                             | $ | 77,577  |  
|Commodity-MTM     |  | Risk management assets                           |  |                                                              | (16,341                     | ) |                             |   | (14,683 | )
|Commodity-MTM     |  | Risk management liabilities                      |  |                                                              | (99                         | ) |                             |   | (208    | )
|Interest Rate-MTM |  | Risk management assets                           |  |                                                              | (4,855                      | ) |                             |   | (4,727  | )
|                  |  |                                                  |  |                                                              |                             |   |                             |   |         |  
|                  |  | Total Derivatives                                |  | $                                                            | 87,437                      |   |                             | $ | 57,959  |  
|                  |  |                                                  |  |                                                              |                             |   |                             |   |         |  
|                  |  |                                                 
|                  |  |                                                  |  | Amount of Gain / (Loss)in
Income(in 000s)                   |                            
|Derivative Type   |  | Location of Gain / (Loss)
in Income              |  | Quarter EndedMarch 31, 2010                                  |                             |   | Quarter EndedMarch 31, 2009 |  
|Commodity-MTM     |  | Gain/(Loss) from mark-to-market activities       |  | $                                                            | 35,281                      |   |                             | $ | 19,331  |  
|Commodity-MTM     |  | Oil and gas sales                                |  |                                                              | 1,898                       |   |                             |   | 2,003   |  
|Interest Rate-MTM |  | Gain/(Loss) from mark-to-market activities       |  |                                                              | (517                        | ) |                             |   | (344    | )
|Interest Rate-MTM |  | Interest expense                                 |  |                                                              | (837                        | ) |                             |   |        |  
|                  |  |                                                  |  |                                                              |                             |   |                             |   |         |  
|                  |  | Total                                            |  | $                                                            | 35,825                      |   |                             | $ | 20,990  |  
|                  |  |                                                  |  |                                                              |                             |   |                             |   |         |  



11



---

##### Table of Contents

|                        |  |                                                                                         |  |                                     |                            |   |                        |                           |        |                            |  |   |   |  |   |    
|----------------------- |  | --------------------------------------------------------------------------------------- |  | ----------------------------------- | -------------------------- | - | ---------------------- | ------------------------- | ------ | -------------------------- |  | - | - |  | - | ---
|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   
|                        |  | QuarterEndedMarch 
31,2010                                                              |  |                                     | QuarterEndedMarch 
31,2009 |   |                        | QuarterEndedMarch 31,2010 |        | QuarterEndedMarch 
31,2009
|Commodity-MTM           |  | Oil and gas sales                                                                       |  | $                                   | 5,728                      |   |                        | $                         | 13,149 |                            |  | $ |  |  | $ |   
|Commodity-Cash Flow     |  | Oil and gas sales                                                                       |  |                                     |                           |   |                        |                           |       |                            |  |   |  |  |   | 267
|Interest Rate-Cash Flow |  | Interest expense                                                                        |  |                                     | (389                       | ) |                        |                           | (602   | )                          |  |   |  |  |   |   
|                        |  |                                                                                         |  |                                     |                            |   |                        |                           |        |                            |  |   |   |  |   |    
|                        |  | Total                                                                                   |  | $                                   | 5,339                      |   |                        | $                         | 12,547 |                            |  | $ |  |  | $ | 267
|                        |  |                                                                                         |  |                                     |                            |   |                        |                           |        |                            |  |   |   |  |   |    

As of March 31, 2010, we have interest rate swaps
on $151.5 million of our outstanding debt through October 2012, various commodity swaps for 42,325,000 MMbtu of natural gas production through December 2014, and various basis swaps for 15,921,000 MMbtu of natural gas production in the Cherokee
Basin through December 2012.

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 (26.83%), 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 March 31, 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 March 31, 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.



12



---

##### Table of Contents

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 March 31, 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, and our borrowings
outstanding, net of available cash, under our reserve-based credit facility exceeded 90% of the borrowing base.

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 March 31, 2010, our unamortized debt issue costs were approximately $5.1 million. These costs are being amortized over the life
of the credit facility through November 2012.



13



---

##### Table of Contents

Funds Available for Borrowing

As of March 31, 2010 and 2009, we had $185.0 million and $220.0 million, respectively, in outstanding debt under our reserve-based
credit facility. As of March 31, 2010, we had $20.0 million in remaining borrowing capacity under the reserve-based credit facility. See Note 15 for additional information.

Compliance with Debt Covenants

At March 31, 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 March 31, 2010, our actual Total Net Debt less Available Cash 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 2.8 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 7.8 to 1.0 as compared with a required
ratio of not less than 2.5 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. 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.

6. OIL AND NATURAL GAS PROPERTIES

Natural gas properties consist of the following:



|                                                                                 |  |               |          |   |                  |   |          |  
|-------------------------------------------------------------------------------- |  | ------------- | -------- | - | ---------------- | - | -------- | -
|                                                                                 |  | March 31,2010 |          |   | December 31,2009 |  
|                                                                                 |  | (In 000s)    |         
|Oil and natural gas properties and related equipment (successful efforts method) |  |               |          |   |                  |   |          |  
|Property (acreage) costs                                                         |  |               |          |   |                  |   |          |  
|Proved property                                                                  |  | $             | 757,549  |   |                  | $ | 756,461  |  
|Unproved property                                                                |  |               | 37,015   |   |                  |   | 37,147   |  
|                                                                                 |  |               |          |   |                  |   |          |  
|                                                                                 |  |              
|Total property costs                                                             |  |               | 794,564  |   |                  |   | 793,608  |  
|Materials and supplies                                                           |  |               | 4,389    |   |                  |   | 4,312    |  
|Land                                                                             |  |               | 912      |   |                  |   | 912      |  
|                                                                                 |  |               |          |   |                  |   |          |  
|                                                                                 |  |              
|Total                                                                            |  |               | 799,865  |   |                  |   | 798,832  |  
|Less: Accumulated depreciation, depletion and amortization                       |  |               | (213,171 | ) |                  |   | (186,207 | )
|                                                                                 |  |               |          |   |                  |   |          |  
|                                                                                 |  |              
|Natural gas properties and equipment, net                                        |  | $             | 586,694  |   |                  | $ | 612,625  |  
|                                                                                 |  |               |          |   |                  |   |          |  

Impairment of Oil and Natural Gas Properties

In the three months ended March 31, 2010 we did not have an impairment to record. For the three months ended March 31, 2009, CEP
recorded a charge of approximately $0.4 million, to impair the value of certain of its wells located in the Woodford Shale in Oklahoma. This charge is included in depreciation, depletion and amortization in the Consolidated Statement of Operations.
This impairment was recorded because the carrying value of certain of the wells exceeded the fair value of the wells as measured by estimated cash flows reported in a third party reserve report that was based upon future expected oil and natural gas
prices, which are based on observable inputs adjusted for basis differentials, which are level two inputs. The impairment is primarily caused by the impact of lower future expected natural gas prices. Cash flow estimates for the impairment testing
exclude derivative instruments. As of March 31, 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 oil and natural gas prices continue to decline during 2010, the estimated undiscounted future cash flows for our proved oil and natural gas properties may not exceed the net capitalized costs for our properties in the Cherokee Basin
or in the Woodford Shale and a non-cash impairment charge may be required to be recognized in future periods.



14



---

##### Table of Contents

Asset Sales

In the three months ended March 31, 2010, we sold miscellaneous equipment and surplus inventory for approximately $0.02 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 $0.2 million and $0.1 million in the three months ended March 31,
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 $0.6 million for the three months ended March 31, 2009.

We had a payable to Constellation of $0.6 million as of March 31, 2009. This payable balance is included in current liabilities in
the accompanying balance sheets.

Natural Gas Purchases

Through March 31, 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 three months ended March 31, 2009, CCG paid CEP $5.5 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 three months ended March 31, 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.

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 March 31, 2010 and March 31, 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.



15



---

##### Table of Contents

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 $2.6 million which represents the distributions that were suspended for the quarterly periods
ended December 31, September 30, June 30, and March, 31, 2009, and December 31, September 30, June 30, and March 31, 2008. The remaining undistributed amount of the Class D interests is $6.7 million. See Note 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:



|                                                        |  |               |        |   |                  |   |        |  
|------------------------------------------------------- |  | ------------- | ------ | - | ---------------- | - | ------ | -
|                                                        |  | March 31,2010 |        |   | December 31,2009 |  
|                                                        |  | (In 000s)    |       
|Asset retirement obligation, beginning balance          |  | $             | 12,129 |   |                  | $ | 6,754  |  
|Liabilities incurred from acquisition of the properties |  |               |       |   |                  |   |       |  
|Liabilities incurred                                    |  |               |       |   |                  |   | 3,873  |  
|Liabilities settled                                     |  |               | (18    | ) |                  |   | (12    | )
|Revisions to prior estimates                            |  |               |       |   |                  |   | 1,108  |  
|                                                        |  |              
|Accretion expense                                       |  |               | 207    |   |                  |   | 406    |  
|                                                        |  |               |        |   |                  |   |        |  
|Asset retirement obligation, ending balance             |  | $             | 12,318 |   |                  | $ | 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 March 31, 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.



16



---

##### Table of Contents

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 three months ended March 31, 2010 and 2009. As a result, no payments were made to the Trust with respect to the NPI for the three months ended March 31, 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.



17



---

##### Table of Contents

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. Trust Venture has also recently 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. That motion was heard by the court on April 30, 2010, but no ruling has yet been rendered. No trial date has been set in the litigation. 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 March 31, 2010 and December 31, 2009, accrued environmental
obligations were $0.2 million and $0.2 million, respectively. These obligations were classified as current liabilities on our Consolidated Balance Sheets.

12. UNIT-BASED COMPENSATION

We recognized approximately $0.4 million and $0.1 million of expense related to our unit-based compensation plans in the three months
ended March 31, 2010, and March 31, 2009, respectively.

2010 Grants

Grants under the 2009 Omnibus Incentive Compensation Plan

In March 2010, we granted approximately 486,981 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 the 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 March 31, 2010

Beginning in June 2009, we have suspended our quarterly distributions to unitholders to remain in compliance with the covenants associated
with our reserve-based credit facility. The distribution must remain suspended until the outstanding debt balance, net of available cash, under our reserve-based credit facility is less than 90% of our borrowing base as determined by our lenders,
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. See Note 15 for additional
information.



18



---

##### Table of Contents

Distributions through March 31, 2009

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 March 31, 2010, we had 490,613 Class A units and 24,040,055 Class B units outstanding, which included 428,273 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 1,330,707 unvested restricted common units under our 2009 Omnibus Incentive
Compensation Plan.

At March 31, 2010, we had granted all common units of the 450,000 common units available under our
Long-Term Incentive Plan. Of these grants, 21,727 have vested.

At March 31, 2010, we had granted 146,552 common units of
the 300,000 common units available under our Executive Inducement Bonus Program. Of these grants, 62,807 have vested.

At
March 31, 2010, we had granted 1,544,740 common units of the 1,650,000 common units available under our 2009 Omnibus Incentive Compensation Plan. Of these grants, 214,033 have vested.

For the three months ended March 31, 2010, 73,660 common units have been tendered by our employees for tax withholding purposes.
These units, costing approximately $0.3 million, have been returned to their respective plan and are available for future grants.

2009 Equity

At March 31, 2009, we had 447,721 Class A units and 21,938,342 Class B units outstanding, which included 23,232 unvested
restricted common units.

At March 31, 2009, we had granted 39,579 units of the 450,000 units available under our
Long-Term Incentive Plan. Of these grants, 16,347 have vested.

15. SUBSEQUENT EVENTS

The following subsequent events have occurred between March 31, 2010, and May 7, 2010:

Distribution

Our
board of managers has suspended the quarterly distribution to our unitholders for the quarter ended March 31, 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 March 31, 2010 and $2.6 million which represents the distributions that were suspended for the
quarterly periods ended December 31, September 30, June 30, and March 31, 2009, and December 31, September 30, June 30, and March 31, 2008. The remaining undistributed amount of the Class D interests is $6.7
million.

Debt

Funds Available for Borrowing

As of March 31, 2010 we had $185.0 million in outstanding debt under our reserve-based credit facility. As of May 7, 2010, our
banks reaffirmed our borrowing base of $205.0 million and we had $20.0 million in remaining borrowing capacity under our reserve-based credit facility. Our next semi-annual borrowing base redetermination is scheduled for the fourth quarter of 2010.



19



---

##### Table of Contents

|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 March 31, 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).
| | - |  | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



20



---

##### Table of Contents

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

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

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

How We Evaluate our Operations

Non-GAAP Financial MeasureAdjusted EBITDA

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



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



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



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



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



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



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



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



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



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



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



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

Adjusted EBITDA is a significant performance metric used by our management to indicate (prior to the establishment of any cash reserves
by our board of managers) the cash distributions we expect to pay to our unitholders. Specifically, this financial measure indicates to investors whether or not we are generating cash flow at a level that can sustain or support 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.



21



---

##### Table of Contents

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:



|                                                                        |  |                                         |         |   |                                         |   |         |  
|----------------------------------------------------------------------- |  | --------------------------------------- | ------- | - | --------------------------------------- | - | ------- | -
|                                                                        |  | Constellation EnergyPartners LLC        |        
|                                                                        |  | For the threemonths 
endedMarch 31,2010 |         |   | For the threemonths 
endedMarch 31,2009 |  
|                                                                        |  | (In 000s)                              |        
|Reconciliation of Net Income to Adjusted EBITDA:                        |  |                                         |         |   |                                         |   |         |  
|Net income                                                              |  | $                                       | 18,058  |   |                                         | $ | 18,933  |  
|Adjusted by:                                                            |  |                                         |         |   |                                         |   |         |  
|Interest expense/(income),
net                                          |  |                                         | 4,056   |   |                                         |   | 2,841   |  
|Depreciation, depletion and amortization                                |  |                                         | 27,248  |   |                                         |   | 14,434  |  
|Accretion of asset retirement obligation                                |  |                                         | 207     |   |                                         |   | 102     |  
|(Gain)/loss on sale of asset                                            |  |                                         | (8      | ) |                                         |   | 17      |  
|Exploration costs                                                       |  |                                         | 223     |   |                                         |   | 103     |  
|(Gain)/loss on mark-to-market activities                                |  |                                         | (35,281 | ) |                                         |   | (19,331 | )
|Unit-based compensation programs                                        |  |                                         | 437     |   |                                         |   | 68      |  
|Unrealized loss/(gain) on natural gas derivatives/hedge ineffectiveness |  |                                         |        |   |                                         |   | 267     |  
|                                                                        |  |                                         |         |   |                                         |   |         |  
|Adjusted EBITDA                                                         |  | $                                       | 14,940  |   |                                         | $ | 17,434  |  
|                                                                        |  |                                         |         |   |                                         |   |         |  

Significant Operational Factors



| |  |  | Realized Prices.Our average realized price for the three months ended March 31, 2010, including hedges, was $16.71 per Mcfe. This realized
price includes the impact of $35.3 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 three months ended March 31, 2010 was $7.57 per Mcfe.
Further deducting all hedge settlements, average realized prices were $5.60 per Mcfe excluding hedges.
| | - |  | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  |  | Production.Our production for the three months ended March 31, 2010, was approximately 3.9 Bcfe, or an average of 42,889 Mcfe per day.
| | - |  | --------------------------------------------------------------------------------------------------------------------------------------



| |  |  | Capital Expenditures and Drilling Results.During the first quarter of 2010, we spent approximately $0.7 million in cash capital expenditures,
primarily to acquire additional interests in seven wells in the Black Warrior Basin and in the Cherokee Basin. We expect to substantially complete our 2010 drilling program in the Cherokee Basin during the second and third quarters of 2010.
| | - |  | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  |  | Hedging Activities. As of March 31, 2010, all of our swaps and basis swaps are accounted for as mark-to-market derivatives. For the three
months ended March 31, 2010, the unrealized non-cash mark-to-market gain was approximately $35.3 million as compared to an unrealized non-cash mark-to-market gain of $19.3 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 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 29.
| | - |  | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



22



---

##### Table of Contents

Results of Operations

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



|                                                                    |  |                                        |        |   |                                        |   |        |                      |  |   |        |   |  |        |   
|------------------------------------------------------------------- |  | -------------------------------------- | ------ | - | -------------------------------------- | - | ------ | -------------------- |  | - | ------ | - |  | ------ | --
|                                                                    |  | For the threemonths endedMarch 31,2010 |        |   | For the threemonths endedMarch 31,2009 |   |        | 2010 Vs 2009Variance | 
|                                                                    |  |                                        | $      |   |                                        | % |       
|Revenues:                                                           |  |                                        |        |   |                                        |   |        |                      |  |   |        |   |  |        |   
|Oil and gas sales                                                   |  | $                                      | 29,237 |   |                                        | $ | 32,862 |                      |  | $ | (3,625 | ) |  | (11.0  | )%
|Gain (Loss) from mark-to- market activities                         |  |                                        | 35,281 |   |                                        |   | 19,331 |                      |  |   | 15,950 |   |  | 82.5   | % 
|                                                                    |  |                                        |        |   |                                        |   |        |                      |  |   |        |   |  |        |   
|Total revenues                                                      |  |                                        | 64,518 |   |                                        |   | 52,193 |                      |  |   | 12,325 |   |  | 23.6   | % 
|                                                                    |  |                                        |        |   |                                        |   |        |                      |  |   |        |   |  |        |   
|                                                                    |  |                                        |        |  
|Operating expenses:                                                 |  |                                        |        |   |                                        |   |        |                      |  |   |        |   |  |        |   
|Lease operating expenses                                            |  |                                        | 7,963  |   |                                        |   | 8,785  |                      |  |   | (822   | ) |  | (9.4   | )%
|Cost of sales                                                       |  |                                        | 772    |   |                                        |   | 832    |                      |  |   | (60    | ) |  | (7.2   | )%
|Production taxes                                                    |  |                                        | 1,125  |   |                                        |   | 970    |                      |  |   | 155    |   |  | 16.0   | % 
|General and administrative expenses                                 |  |                                        | 5,062  |   |                                        |   | 5,233  |                      |  |   | (171   | ) |  | (3.3   | )%
|Exploration costs                                                   |  |                                        | 223    |   |                                        |   | 103    |                      |  |   | 120    |   |  | 116.5  | % 
|(Gain) loss on sale of asset                                        |  |                                        | (8     | ) |                                        |   | 17     |                      |  |   | (25    | ) |  | (147.1 | )%
|Depreciation, depletion and amortization                            |  |                                        | 27,248 |   |                                        |   | 14,434 |                      |  |   | 12,814 |   |  | 88.8   | % 
|Accretion expenses                                                  |  |                                        | 207    |   |                                        |   | 102    |                      |  |   | 105    |   |  | 102.9  | % 
|                                                                    |  |                                        |        |   |                                        |   |        |                      |  |   |        |   |  |        |   
|Total operating expenses                                            |  |                                        | 42,592 |   |                                        |   | 30,476 |                      |  |   | 12,116 |   |  | 39.8   | % 
|Other expenses (income):                                            |  |                                        |        |   |                                        |   |        |                      |  |   |        |   |  |        |   
|Interest expense                                                    |  |                                        | 3,539  |   |                                        |   | 2,499  |                      |  |   | 1,040  |   |  | 41.6   | % 
|Interest expense-(Gain)/loss from mark-to-market activities         |  |                                        | 517    |   |                                        |   | 344    |                      |  |   | 173    |   |  | 50.3   | % 
|Interest income                                                     |  |                                        |       |   |                                        |   | (2     | )                    |  |   | 2      |   |  | (100.0 | )%
|Other (income) expense                                              |  |                                        | (188   | ) |                                        |   | (57    | )                    |  |   | (131   | ) |  | 229.8  | % 
|                                                                    |  |                                        |        |   |                                        |   |        |                      |  |   |        |   |  |        |   
|Total other expenses (income)                                       |  |                                        | 3,868  |   |                                        |   | 2,784  |                      |  |   | 1,084  |   |  | 38.9   | % 
|                                                                    |  |                                        |        |   |                                        |   |        |                      |  |   |        |   |  |        |   
|Total expenses                                                      |  |                                        | 46,460 |   |                                        |   | 33,260 |                      |  |   | 13,200 |   |  | 39.7   | % 
|                                                                    |  |                                        |        |   |                                        |   |        |                      |  |   |        |   |  |        |   
|Net income                                                          |  | $                                      | 18,058 |   |                                        | $ | 18,933 |                      |  | $ | (875   | ) |  | (4.6   | )%
|                                                                    |  |                                        |        |   |                                        |   |        |                      |  |   |        |   |  |        |   
|                                                                    |  |                                        |        |  
|Net production:                                                     |  |                                        |        |   |                                        |   |        |                      |  |   |        |   |  |        |   
|Total production (MMcfe)                                            |  |                                        | 3,860  |   |                                        |   | 4,364  |                      |  |   | (504   | ) |  | (11.5  | )%
|Average daily production (Mcfe/d)                                   |  |                                        | 42,889 |   |                                        |   | 48,489 |                      |  |   | (5,600 | ) |  | (11.5  | )%
|Average sales prices:                                               |  |                                        |        |   |                                        |   |        |                      |  |   |        |   |  |        |   
|Price per Mcfe including all
hedges(a)                              |  | $                                      | 16.71  |   |                                        | $ | 11.96  |                      |  | $ | 4.75   |   |  | 39.8   | % 
|Price per Mcfe excluding gain (loss) from mark-to-market activities |  | $                                      | 7.57   |   |                                        | $ | 7.53   |                      |  | $ | 0.04   |   |  | 0.53   | % 
|Price per Mcfe excluding all hedges                                 |  | $                                      | 5.60   |   |                                        | $ | 4.15   |                      |  | $ | 1.45   |   |  | 34.9   | % 
|Average unit costs per Mcfe:                                        |  |                                        |        |   |                                        |   |        |                      |  |   |        |   |  |        |   
|Field operating
expenses(b)                                         |  | $                                      | 2.35   |   |                                        | $ | 2.24   |                      |  | $ | 0.11   |   |  | 4.9    | % 
|Lease operating expenses                                            |  | $                                      | 2.06   |   |                                        | $ | 2.01   |                      |  | $ | 0.05   |   |  | 2.5    | % 
|Production taxes                                                    |  | $                                      | 0.29   |   |                                        | $ | 0.22   |                      |  | $ | 0.07   |   |  | 31.8   | % 
|General and administrative expenses                                 |  | $                                      | 1.31   |   |                                        | $ | 1.20   |                      |  | $ | 0.11   |   |  | 9.2    | % 
|General and administrative expenses w/o unit-based compensation     |  | $                                      | 1.21   |   |                                        | $ | 1.19   |                      |  | $ | 0.02   |   |  | 1.7    | % 
|Depreciation, depletion and amortization(c)                         |  | $                                      | 7.06   |   |                                        | $ | 3.31   |                      |  | $ | 3.75   |   |  | 113.3  | % 



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



23



---

##### Table of Contents

|(c) | Depreciation, depletion and amortization includes non-cash impairments of oil and natural gas assets. Excluding impairments, the first quarter 2010 and
2009 cost per Mcfe was $7.06 and $3.22, respectively.
|--- | -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

Three months ended March 31, 2010 compared to three months
ended March 31, 2009

Oil and natural gas sales. Oil and natural gas sales decreased $3.6 million, or 11%,
to $29.2 million for the three months ended March 31, 2010 as compared to $32.8 million for the same period in 2009. Of this decrease, $2.1 million was attributable to decreased production volumes and $7.1 million was attributable to our hedge
program, offset by $5.6 million in higher market prices for oil and natural gas. Production for the three months ended March 31, 2010 was 3.9 Bcfe, which was 0.5 Bcfe lower than the same period in 2009. Of the decrease, 0.4 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
81% of our actual production during 2010 and approximately 84% 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 $16.0 million for the three months ended March 31, 2010, as compared to the same period in 2009. Our realized 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 our hedging program and the mark-to-market gains discussed below.

Hedging and mark-to-market activities. As of March 31, 2010, all of our swaps and basis swaps are accounted for as
mark-to-market derivatives. For the three months ended March 31, 2010, the unrealized non-cash mark-to-market gain was approximately $35.3 million as compared to an unrealized non-cash $19.3 million gain for the same period in 2009. This 2010
non-cash gain represents approximately $35.8 million from the impact of lower than expected future natural gas prices on these derivative transactions that are being accounted for as mark-to-market activities offset by a $0.5 million reduction for
non-performance risk related to our counterparties.

For the three months ended March 31, 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 $7.6 million for the three months ended March 31,
2010. Cash hedge settlements received for our commodity derivatives were approximately $15.0 million for the three months ended March 31, 2009. This difference is primarily due to higher market prices 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 March 31, 2010, lease operating expenses decreased $0.8 million, or 9.4%, to $8.0 million, compared to expenses of $8.8 million for the same period in 2009. This decrease in lease operating expenses is primarily related to $0.6
million in lower total spending in the Cherokee Basin and $0.2 million in lower expenses associated with our Woodford Shale properties. Our spending in the Black Warrior Basin during 2010 remained level with our spending in 2009. By category, our
lease operating expenses were lower in 2010 as compared to 2009 by $0.8 million because of a decrease of $0.5 million in gas compression, $0.4 million in well servicing costs, and $0.1 million in transportation offset by an increase of $0.1 million
in ad valorem taxes and $0.1 million in weather related road and lease maintenance.

For the three months ended March 31,
2010, per unit lease operating expenses were $2.06 per Mcfe compared to $2.01 per Mcfe for the same period in 2009. This increase is attributable to 11.5% lower production in 2010 as compared to the same period in 2009 offset by a decrease in
total spending of 9.4% in 2010 as compared to the same period in 2009. Our per unit operating costs increased in the Cherokee Basin from $2.18 per Mcfe in 2009 to $2.29 per Mcfe in 2010 as a result of 0.4 Bcfe in lower production volumes and lower
total spending.

For the three months ended March 31, 2010, production taxes increased $0.1 million, or 16.0%, to $1.1
million, compared to expenses of $1.0 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 0.5 Bcfe in lower production.

Cost of sales.For the three months ended March 31, 2010, cost of sales decreased by less than $0.1 million, or
7.2%, to $0.8 million, compared to $0.8 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.



24



---

##### Table of Contents

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 decreased $0.2 million, or 3.3%, to $5.0 million for the three months ended March 31, 2010, as
compared to $5.2 million for the same period in 2009. Our general and administrative expenses were lower in 2010 as compared to 2009 because of $0.6 million in lower management service fees and $0.2 million in lower legal fees offset by $0.3 million
in higher non-cash unit-based compensation expenses, $0.2 million in higher labor costs, and $0.1 million in higher rental expense. For the three months ended March 31, 2009, CEPM allocated $0.6 million in expenses to us for labor and other
charges through the management services agreement.

Our per unit costs were $1.31 per Mcfe for the three months ended
March 31, 2010 compared to $1.20 per Mcfe for the same period in 2009. This increase is attributable to a decrease in total spending of approximately $0.2 million offset by 0.5 Bcfe in lower production.

Exploration Costs. Exploration costs increased $0.1 million, or 116.5%, to $0.2 million for the three months ended March 31,
2010, as compared to $0.1 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 associated
with leases on our unproved properties. The increase in 2010 is primarily as the result of lease abandonments in Kansas.

Gain/loss on sale of asset.Our gain/loss on the sale of assets decreased $0.02 million, or 147.1%, to less than a $0.01 million
loss for the three months ended March 31, 2010, as compared to a loss of $0.01 million for the same period in 2009. In 2010, we sold surplus equipment at a loss of less than $0.01 million.

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

Our depreciation, depletion and amortization expense for the three months ended March 31, 2010 was $27.3 million, or
$7.06 per Mcfe, compared to $14.4 million, or $3.31 per Mcfe, for the same period in 2009. This increase in 2010 depreciation, depletion, and amortization reflects the increased basis in our assets resulting from a lower year-end 2009 reserve base
primarily due to price-related reserve revisions, capital expenditures for our development drilling programs, and a 0.5 Bcfe decrease in production volumes during 2010 as compared to 2009. 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 expect our depletion rate during the first three quarters of 2010 to be approximately $7.08 per Mcfe. We will continue to use our 2010 reserve report to record our depletion in the fourth quarter of 2010.

Interest expense. Interest expense for the three months ended March 31, 2010 increased $1.2 million to $4.1 million as
compared to approximately $2.9 million in interest expense for same period in 2009. This increase was primarily due to $0.2 million in higher non-cash mark-to-market losses on our interest rate swaps that are accounted for as market-to-market
activities, higher interest rate swap settlements of $0.6 million, higher amortization of debt issues costs of $0.2 million, higher market interest rates of $0.1 million, and lower 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 $185.0 million. At March 31, 2010, we had an outstanding balance under our reserve-based credit facility
of $185.0 million as compared to $220.0 million at March 31, 2009. The average interest rate on our outstanding debt was approximately 5.9% in 2010 compared to 5.1% in 2009. Our capitalized interest decreased from 2009 to 2010 due to no
significant capital spending in 2010.

Interest income. Interest income for the three months ended March 31, 2010
was zero as compared to less than $0.01 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 March 31, 2010, the balance was an unrealized gain of $23.1 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 quarter of 2010.



25



---

##### Table of Contents

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 $5.3 million for the three months ended March 31, 2010, and as an unrealized gain of $7.7 million for the same period in 2009. This decrease reflects the
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 $35.0 million since we suspended our quarterly distribution to unitholders in June 2009. Based upon our current business plan for 2010, 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 $10.0 million to $12.0 million primarily
concentrated in the Cherokee Basin during the second and third quarters of 2010. The primary focus of our business plan in 2010 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 March 31, 2010, our borrowing base under our reserve-based credit facility was $205.0 million and we had $185.0 million of debt outstanding under our reserve-based credit facility, leaving us with $20.0 million in
unused borrowing capacity. As of March 31, 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, and our borrowings outstanding, net of available cash, under our reserve-based credit facility exceeded 90% of the borrowing base.

Our reserve-based credit facility matures in November 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 January 30, 2011. There is no guarantee that securities can or will be issued under the registration statement. 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.

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. Our future success in growing reserves and production will be highly dependent on the capital resources available to us and our success in drilling for or acquiring additional reserves and
managing the costs associated with our operations. Our results will not be fully impacted by significant increases or decreases in natural gas prices because of our hedging program, which is further discussed on page 29. 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, we
intend to limit our capital expenditures and to use any available surplus cash to further reduce our debt level. We expect to complete substantially all of our 2010 drilling activities in the Cherokee Basin during the second and third quarters of
2010. We expect that the suspension of our quarterly distribution and the reduction in our total planned capital expenditures will provide additional liquidity to fund our operations and to pay down debt. During 2009 and 2010, we have successfully
reduced our outstanding debt balances from a high of $220.0 million to $185.0 million. Any future quarterly distribution to unitholders cannot be made when our outstanding debt balance, net of available cash, is more than 90% of our borrowing base
as determined by our lenders, 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 2010 and we currently expect to
resume capital spending at maintenance levels in 2011. Any future quarterly distributions must be approved by our board of managers.



26



---

##### Table of Contents

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 (26.83%), 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 May 7, 2010, our borrowing base was reaffirmed by our banks at $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 December 31, 2009, 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 (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.



27



---

##### Table of Contents

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. As of May 7, 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, and our borrowings
outstanding, net of available cash, under our reserve-based credit facility exceeded 90% of the borrowing base.

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 March 31, 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 March 31, 2010, our actual Total Net Debt less Available Cash 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 2.8 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 7.8 to 1.0 as compared with a required
ratio of not less than 2.5 to 1.0.

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. 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 35.

Cash Flow from Operations

Our net cash flow provided by operating activities for the three months ended March 31, 2010 was $8.0 million, compared to net cash
flow provided by operating activities of $14.5 million for the same period in 2009. This decrease in operating cash flow was primarily attributable to lower oil and natural gas sales of $3.6 million as the result of 0.5 Bcfe in lower natural gas
production in 2010. For 2010, our operating cash flows were increased by $6.4 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 $3.1 million, higher accounts payable of $1.4 million, lower royalties payable of $0.7 million, higher accounts receivable of $0.5 million and higher prepaid expenses of $0.4 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. Our receivables balance increased due to higher current period prices for our current estimated natural gas
sales prices. 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 increase in prepaid expenses of $0.4 million primarily resulted from the timing of the payment for insurance expenses.



28



---

##### Table of Contents

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 32.

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 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.

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 |  |                                  |  |              |      |          | 2,875,000 |              | $ | 8.23   |  | 2,670,000    |  | $      | 8.13 |              | 2,700,000 |        | $ | 8.15         |  | 8,245,000  |  | $ | 8.17
|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
|     |  |                                  |  |              |      |          |           |              |   |        |  |              |  |        |      |              |           |        |   |              |  |            |  |   |     
|     |  |                                  |  |              |      |          |           |              |   |        |  |              |  |        |      |              |           |        |   |              |  | 41,065,000 |  |   |     
|     |  |                                  |  |              |      |          |           |              |   |        |  |              |  |        |      |              |           |        |   |              |  |            |  |   |     

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 |              | 180,000 |        | $ | 7.91         |  | 540,000   |  | $ | 7.91
|2011 |  | 180,000                          |  | $            | 7.93 |          | 180,000 |              | $ | 7.93   |  | 180,000      |  | $      | 7.93 |              | 180,000 |        | $ | 7.93         |  | 720,000   |  | $ | 7.93
|     |  |                                  |  |              |      |          |         |              |   |        |  |              |  |        |      |              |         |        |   |              |  |           |  |   |     
|     |  |                                  |  |              |      |          |         |              |   |        |  |              |  |        |      |              |         |        |   |              |  | 1,260,000 |  |   |     
|     |  |                                  |  |              |      |          |         |              |   |        |  |              |  |        |      |              |         |        |   |              |  |           |  |   |     

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)



29



---

##### Table of Contents

|     |  |                                  |  |                   |      |          |           |                   |   |        |  |                   |  |        |      |                   |           |        |   |                   |  |            |  |   |     
|---- |  | -------------------------------- |  | ----------------- | ---- | -------- | --------- | ----------------- | - | ------ |  | ----------------- |  | ------ | ---- | ----------------- | --------- | ------ | - | ----------------- |  | ---------- |  | - | ----
|     |  | 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 |  |                                  |  |                   |      |          | 2,249,500 |                   | $ | 0.77   |  | 2,114,000         |  | $      | 0.74 |                   | 1,995,000 |        | $ | 0.73              |  | 6,358,500  |  | $ | 0.75
|2011 |  | 1,335,000                        |  | $                 | 0.77 |          | 1,347,500 |                   | $ | 0.77   |  | 1,130,000         |  | $      | 0.77 |                   | 1,130,000 |        | $ | 0.77              |  | 4,942,500  |  | $ | 0.77
|2012 |  | 1,150,000                        |  | $                 | 0.65 |          | 1,150,000 |                   | $ | 0.65   |  | 1,160,000         |  | $      | 0.65 |                   | 1,160,000 |        | $ | 0.65              |  | 4,620,000  |  | $ | 0.65
|     |  |                                  |  |                   |      |          |           |                   |   |        |  |                   |  |        |      |                   |           |        |   |                   |  |            |  |   |     
|     |  |                                  |  |                   |      |          |           |                   |   |        |  |                   |  |        |      |                   |           |        |   |                   |  | 15,921,000 |  |   |     
|     |  |                                  |  |                   |      |          |           |                   |   |        |  |                   |  |        |      |                   |           |        |   |                   |  |            |  |   |     

Investing ActivitiesAcquisitions and Capital Expenditures

Cash used in investing activities was $0.6 million for the three months ended March 31, 2010, compared to $11.4 million for the same
period in 2009. Our cash capital expenditures were $0.7 million in 2010, which primarily related to the acquisition of additional interests in seven natural gas wells in the Cherokee Basin and in the Black Warrior Basin. In 2010, we have not drilled
and completed any net wells or any net recompletions in the Cherokee Basin. We expect to begin our drilling activities in the Cherokee Basin during the second quarter of 2010. We do not plan to resume drilling in the Black Warrior Basin during 2010.

Our capital expenditures were $11.4 million for the three months ended March 31, 2009, which primarily related to
drilling and development of oil and natural gas properties in the Cherokee Basin. Through March 31, 2009, we drilled and completed 30 net wells and 16 net recompletions in the Cherokee Basin. We also prepared 10 drilling locations in the Black
Warrior Basin.

We currently anticipate our total capital budget will be between $10.0 million and $12.0 million for the
twelve months ending December 31, 2010. This capital budget primarily consists of capital for drilling wells and recompletions and also includes amounts for infrastructure projects, equipment, and inventory. The 2010 budget is set below our
2010 estimated maintenance capital level of $25.3 million. Our capital spending in 2010 has been reduced from our 2009 spending level of $22.9 million and our 2008 spending level of $47.9 million. We expect to spend substantially the entire capital
budget in the Cherokee Basin during the second and third quarters of 2010 and have not planned for any investment capital expenditures. Because we have reduced capital spending in 2010 and in 2009 below a maintenance level, we anticipate lower
production in 2010 which may reduce our operating cash flows. We currently expect that we will resume capital spending at a level to maintain our production in 2011.

The amount and timing of our capital expenditures is largely discretionary and within our control. If natural gas prices decline to
levels below acceptable levels, 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 these 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 and available borrowing capacity under our reserve-based credit facility will meet our planned capital expenditures and other cash requirements for the
twelve months ending December 31, 2010. In 2010, we expect that our excess operating cash flows will be used to reduce our outstanding debt level. However, future cash flows 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 by financing activities was $10.4 million for the three months ended March 31, 2010, compared to $4.5 million
provided by financing activities for the same period in 2009. During 2010, we used $10.0 million in operating cash flows to reduce our outstanding debt level. During the first quarter of 2010, we reduced our outstanding debt from $195.0 million to
$185.0 million or by 5%. In November 2009, we also entered into a new reserve-based credit facility that matures in November 2012. At March 31, 2010, we have approximately $5.1 million in debt issue costs remaining to be amortized through
November 2012.



30



---

##### Table of Contents

We have suspended $2.6 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 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 2010. Assuming that the quarterly
distribution rate would have remained at $0.13 per unit for each quarter in 2010, this suspension of the quarterly distribution would provide approximately $12.8 million in cash flow during 2010 that could be used to reduce our outstanding debt
balance under our reserve-based credit facility. For additional information, refer toOutlook on page 32.

Our net cash
provided by financing activities was $4.5 million for the three months ended March 31, 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 $2.9 million to
our common and Class A unitholders in 2009.

Contractual Obligations

At March 31, 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 |                | $                          |      |  | $    |    |      | $ | 185,000 |  | $          |    |       | $ |    |  | $ |    |  | $ | 185,000
|Support Services Agreement    |                |                            | 1,265 |  |      |    |      |   |        |  |            |    |       |   |    |  |   |    |  |   | 1,265  
|Offices Leases                |                |                            | 414   |  |      | 416 |      |   | 424     |  |            | 408 |       |   | 422 |  |   | 752 |  |   | 2,836  
|                              |                |                            |       |  |      |     |      |   |         |  |            |     |       |   |     |  |   |     |  |   |        
|Total                         |                | $                          | 1,679 |  | $    | 416 |      | $ | 185,424 |  | $          | 408 |       | $ | 422 |  | $ | 752 |  | $ | 189,101
|                              |                |                            |       |  |      |     |      |   |         |  |            |     |       |   |     |  |   |     |  |   |        



|(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 5.9% at March 31, 2010.
|--- | ----------------------------------------------------------------------------------------------------------------------------------------------------------------

At March 31, 2010, our asset retirement obligation was approximately $12.3 million.

Off-Balance Sheet Arrangements

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

Credit Markets and Counterparty Risk

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 May 7, 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, Ltd., 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 million in purchases through December 31, 2011. As of May 7, 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 May 7, 2010, we have no past due receivables from Scissortail.



31



---

##### Table of Contents

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 May 7, 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 though October 2010. As of May 7, 2010, we have no past due receivables from J.P. Morgan Ventures Energy Corporation.

Derivative Counterparties

As of May 7, 2010, all of our derivatives are with BNP Paribas, The Royal Bank of Scotland, Societe Generale, Wells Fargo and 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 do not require the posting of cash
collateral. As of May 7, 2010, each of these financial institutions has an investment grade credit rating.

Reserve-Based Credit Facility

As of May 7, 2010, the banks and their percentage commitments in our reserve-based credit facility are: The Royal Bank of Scotland
plc (26.83%), 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 May 7, 2010, each of these financial institutions has an investment grade credit rating.

Outlook

During 2010, we
expect that our business will continue to be affected by the factors described in Part II, Item 1A. Risk Factors, 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 is focused on reducing our outstanding debt level and promoting financial flexibility by further
enhancing our liquidity position. This plan will result in limited maintenance capital expenditures and the continued suspension of our quarterly distribution through the fourth quarter of 2010. Our current goal is to sustain the company through the
current business cycle and to further reduce our debt level so that we can resume maintenance capital expenditures. Ultimately we intend to position our operations to create long-term value. We expect to resume full maintenance capital expenditures
as part of our 2011 business plan. We also intend to evaluate the possibility of a resumption of a limited quarterly distribution for the first quarter of 2011. We expect our full year 2010 results to be impacted by declining production of natural
gas, further commodity price volatility, continued limited ability to access our reserve-based credit facility, and weak economic activity muting the demand and prices for oil and natural gas in our market areas.

We currently anticipate:



| |  |  | Our production to be between 14.5 Bcfe and 15.5 Bcfe.
| | - |  | -----------------------------------------------------



| |  |  | Our operating expenses to be relatively flat with our 2009 operating expenses, resulting in a range of $52.0 million to $56.0 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 $4,400 to $4,700. This capital budget has been reduced to a level below our estimated maintenance level of capital expenditures of approximately $25.3 million. We expect to drill and complete approximately 25 net wells and recompletions,
primarily in the Cherokee Basin. We will 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 any possible future distribution levels in 2011 will be set at a sustainable rate based on our operating results, the market prices
for oil and natural gas and our projected business plan being achieved. All future quarterly distributions must be approved by our board of managers.
| | - |  | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



32



---

##### Table of Contents

Impact of 2010 Plan

We currently prepare a five-year plan to manage our business. Our goal is to maintain production rates and operating cash flows at a
steady level by developing our proved undeveloped reserve locations each year. Although during 2010, the focus of our business plan is to further reduce our outstanding debt by reducing maintenance capital expenditures and continuing the suspension
of our quarterly distribution to unitholders. We expect that this will position us to resume maintenance capital expenditures in 2011 through 2014. We expect that this plan will likely result in lower production levels in 2010. If we resume
maintenance capital expenditures in 2011 as we currently anticipate, it will likely result in production levels at or near our 2010 production run rates in 2011 through 2014. This plan is expected to reduce our leverage, improve our liquidity
position, and reduce future cash interest expenses on our outstanding unhedged debt.

Critical Accounting Policies and Estimates

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

As of March 31, 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 will be
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 are effective this quarter 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 March 31, 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 2009 and 2008, there was unprecedented volatility in the global financial and energy markets. Additionally, the economic recession
reduced the demand for oil and natural gas, which negatively impacted market prices for these products.



33



---

##### Table of Contents

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 reduced if future expected market prices for natural gas decline further, and that the cost of capital may increase during this time. We also may have difficulty in
accessing credit should we have the need to. 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
and 2010. 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, and the Inside FERC price for the CenterPoint Energy Gas Transmission (East) for our properties in the Woodford Shale, and the spot market prices applicable to all of our natural gas production. Historically, pricing for natural gas
production has been volatile and unpredictable and we expect this volatility to continue in the future. We are currently operating in an environment characterized by low natural gas prices which will lower our revenues that we realize on our
unhedged natural gas production and limit the amount of operating cash flows available for maintenance capital expenditures, distributions to unitholders, or 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 for sale in the market.

We have entered into hedging arrangements with respect to a portion of our projected natural gas production through various derivatives
that hedge the future prices received. These hedging activities are intended to support natural gas prices at targeted levels and to manage our exposure to natural gas price fluctuations. We do not hold or issue derivative instruments for
speculative trading purposes. The use of hedging transactions also involves the risk that the counterparties will be unable to meet the financial terms of the transactions. We attempt to minimize this risk by entering into 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 March 31, 2010 |            | $          | 92,292 |                     | $ | 70,799 |                     | $ | (21,493  | ) |  | $ | 113,785 |  | $ | 21,493

Interest Rate Risk

At March 31, 2010, the one-month LIBOR rate was 0.249%, the three-month LIBOR rate was 0.292%, and our applicable margin
on LIBOR borrowings was 3.5%. At March 31, 2010, the ABR rate was 3.25%, and our applicable margin on ABR borrowings was 2.5%. At March 31, 2010, we had debt outstanding of $185.0 million. This entire amount incurred interest at a rate of
a three-month LIBOR rate plus an applicable margin of 3.5% based on utilization. We had no debt outstanding at the one-month LIBOR rate or at the ABR rate. At March 31, 2010, the carrying value and fair value of our debt is $185.0 million.

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



|                                                                                     |  |            |            |   |                     |          |                     |            |  |   |            |  |   |        |   |  |   |      |  
|------------------------------------------------------------------------------------ |  | ---------- | ---------- | - | ------------------- | -------- | ------------------- | ---------- |  | - | ---------- |  | - | ------ | - |  | - | ---- | -
|                                                                                     |  | Fair Value |            |   | 10 Percent Increase |          | 10 Percent Decrease |           
|                                                                                     |  |            | Fair Value |   |                     | Increase |                     | Fair Value |  |   | (Decrease) | 
|                                                                                     |  | (in 000s) |           
|Impact of changes in LIBOR on derivative interest rate instruments at March 31, 2010 |  | $          | (4,855     | ) |                     | $        | (4,423              | )          |  | $ | 432        |  | $ | (5,287 | ) |  | $ | (432 | )



34



---

##### Table of Contents

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 March 31, 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)        |        |                  |     
|August 21, 2010    |  | $                 | 28,500 |                  | 2.74 | %
|September 21, 2010 |  | $                 | 11,000 |                  | 2.66 | %
|October 22, 2010   |  | $                 | 19,000 |                  | 2.91 | %
|August 20, 2012    |  | $                 | 11,000 |                  | 2.75 | %
|September 20, 2012 |  | $                 | 45,000 |                  | 3.03 | %
|October 19, 2012   |  | $                 | 29,500 |                  | 3.21 | %
|October 22, 2012   |  | $                 | 7,500  |                  | 3.06 | %



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

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

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

Evaluation of Disclosure Controls and Procedures

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

Changes in Internal Control over Financial Reporting

During the three months ended March 31, 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.



35



---

##### Table of Contents

Part IIOther Information



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

Termination of the
Trust and Related Litigation

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. Trust Venture has also recently 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. That
motion was heard by the court on April 30, 2010, but no ruling has yet been rendered. No trial date has been set in the litigation. 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.



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

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.

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;
| | - |  | ------------------------------------------------------



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



36



---

##### Table of Contents

| |  |  | 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 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. These forward-looking statements may be found in Item 1. Business; Item 1A. Risk Factors; Item 7. Managements Discussion and Analysis of Financial Condition and Results
of Operations and other items within this Quarterly Report on Form 10-Q. In some cases, forward-looking statements can be identified by terminology such as may, could, should, expect,
plan, project, intend, anticipate, believe, estimate, predict, potential, pursue, target, continue, the negative of
such terms or other comparable terminology.



37



---

##### Table of Contents

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



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

None.



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

None.



|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
March 31, 2010 and March 31, 2009

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

Consolidated Statements of Cash Flows  Constellation Energy Partners LLC
for the three months ended March 31, 2010 and March 31, 2009

Consolidated Statements of Changes in Members
Equity and Comprehensive Income  Constellation Energy Partners LLC for the three months ended March 31, 2010

Notes
to Consolidated Financial Statements



38



---

##### Table of Contents

EXHIBIT INDEX



|               |  |                                                                                                                                                                                                                                                                                           |  | 
|-------------- |  | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------- |  | 
|Exhibit
Number |  | Description                                                                                                                                                                                                                                                                              
|               | 
|10.31         |  | Form of Grant Agreement Relating to Restricted UnitsExecutive Officers under the 2009 Omnibus Incentive Compensation Plan (incorporated by reference to Exhibit 10.9 to the
Current Report on Form 8-K filed by Constellation Energy Partners LLC on March 3, 2010, File No. 001-33147).
|               | 
|*31.1.        |  | Certification of Chief Executive Officer, Chief Operating Officer and President of Constellation Energy Partners LLC pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.                                                                                                          
|               | 
|*31.2.        |  | Certification of Chief Financial Officer and Treasurer of Constellation Energy Partners LLC pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.                                                                                                                                   
|               | 
|*32.1.        |  | Certification of Chief Executive Officer, Chief Operating Officer and President of Constellation Energy Partners LLC pursuant to 18 U.S.C. Section 1350, as adopted pursuant to
Section 906 of the Sarbanes-Oxley Act of 2002.                                                           
|               | 
|*32.2.        |  | Certification of Chief Financial Officer and Treasurer of Constellation Energy Partners LLC pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the
Sarbanes-Oxley Act of 2002.                                                                                    



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



39



---

##### Table of Contents

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: May 7, 2010 |  | By |  | /s/ MICHAEL B. HINEY                                    
|                  |  |    |  | Michael B. Hiney Chief
Accounting Officer and Controller



40