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Table of Contents

 
 
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, DC 20549
FORM 10-Q
(Mark One)
     
þ   QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended: September 30, 2011
OR
     
o   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: 333-173751
ALTA MESA HOLDINGS, LP
(Exact name of registrant as specified in its charter)
     
Texas
(State or other jurisdiction of incorporation or organization)
  20-3565150
(I.R.S. Employer Identification No.)
     
15021 Katy Freeway, Suite 400, Houston, Texas
(Address of principal executive offices)
  77094
(Zip Code)
Registrant’s telephone number, including area code: 281-530-0991
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 þ No o
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 and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files.) Yes þ No o
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 definition of “large accelerated filer,” “accelerated filer,” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one)
             
Large accelerated filer o   Accelerated filer o   Non-accelerated filer þ   Smaller reporting company o
        (Do not check if a smaller reporting company)    
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes o No þ
 
 

 


 

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 EX-10.1
 EX-31.1
 EX-31.2
 EX-32.1
 EX-32.2
 EX-101 INSTANCE DOCUMENT
 EX-101 SCHEMA DOCUMENT
 EX-101 CALCULATION LINKBASE DOCUMENT
 EX-101 LABELS LINKBASE DOCUMENT
 EX-101 PRESENTATION LINKBASE DOCUMENT

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CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS
     The information in this report includes “forward-looking statements.” All statements, other than statements of historical fact included in this Quarterly Report on Form 10-Q, regarding our strategy, future operations, financial position, estimated revenues and losses, projected costs, prospects, plans and objectives of management are forward-looking statements. When used in this report, the words “could”, “should”, “will”, “play”, “believe”, “anticipate”, “intend”, “estimate”, “expect”, “project” and similar expressions are intended to identify forward-looking statements, although not all forward-looking statements contain such identifying words. These forward-looking statements are based on our current expectations and assumptions about future events and are based on currently available information as to the outcome and timing of future events. When considering forward-looking statements, you should keep in mind the risk factors and other cautionary statements described under the heading “Risk Factors” included in our Registration Statement on Form S-4 (Commission File No. 333-173751 filed on July 11, 2011, the “Form S-4”) and Part II, Item 1A of this report. These forward-looking statements are based on management’s current belief, based on currently available information, as to the outcome and timing of future events.
     Forward-looking statements may include statements about our:
    business strategy;
 
    reserves;
 
    financial strategy, liquidity and capital required for our development program;
 
    realized oil and natural gas prices;
 
    timing and amount of future production of oil and natural gas;
 
    hedging strategy and results;
 
    future drilling plans;
 
    competition and government regulations;
 
    marketing of oil and natural gas;
 
    leasehold or business acquisitions;
 
    costs of developing our properties;
 
    liquidity and access to capital;
 
    uncertainty regarding our future operating results; and
 
    plans, objectives, expectations and intentions contained in this report that are not historical.
     We caution you that these forward-looking statements are subject to all of the risks and uncertainties, most of which are difficult to predict and many of which are beyond our control, incident to the exploration for and development and production of oil and natural gas. These risks include, but are not limited to volatility of oil and natural gas prices, general economic conditions, credit markets, inflation, the credit rating of U.S. government debt, production timing and volumes, estimates of proved reserves, operating costs and capital expenditures, lack of availability of drilling and production equipment and services, environmental risks, drilling and other operating risks, regulatory changes, the uncertainty inherent in estimating oil and natural gas reserves and in projecting future rates of production, cash flow and access to capital, and the other risks described under “Risk Factors” in our Form S-4.
     Reserve engineering is a process of estimating underground accumulations of oil and natural gas that cannot be measured in an exact way. The accuracy of any reserve estimate depends on the quality of available data, the interpretation of such data and price and cost assumptions made by reservoir engineers. In addition, the results of drilling, testing and production activities may justify revisions of estimates that were made previously. If significant, such revisions would change the schedule of any further production and development drilling. Accordingly, reserve estimates may differ significantly from the quantities of oil and natural gas that are ultimately recovered.

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     Should one or more of the risks or uncertainties described in the Form S-4 or this report occur, or should underlying assumptions prove incorrect, our actual results and plans could differ materially from those expressed in any forward-looking statements.
     All forward-looking statements, expressed or implied, included in this report are expressly qualified in their entirety by this cautionary statement. This cautionary statement should also be considered in connection with any subsequent written or oral forward-looking statements that we or persons acting on our behalf may issue.
     Except as otherwise required by applicable law, we disclaim any duty to update any forward-looking statements, all of which are expressly qualified by the statements in this section, to reflect events or circumstances after the date of this Quarterly Report on Form 10-Q.

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PART I — FINANCIAL INFORMATION
ITEM 1. Financial Statements
ALTA MESA HOLDINGS, LP AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(dollars in thousands)
                 
    September 30,     December 31,  
    2011     2010  
    (unaudited)          
ASSETS
               
CURRENT ASSETS
               
Cash and cash equivalents
  $ 4,572     $ 4,836  
Accounts receivable, net
    42,888       38,081  
Other receivables
    2,697       6,338  
Prepaid expenses and other current assets
    3,725       2,292  
Derivative financial instruments
    25,787       10,436  
 
           
TOTAL CURRENT ASSETS
    79,669       61,983  
 
           
PROPERTY AND EQUIPMENT
               
Oil and natural gas properties, successful efforts method, net
    555,357       442,880  
Other property and equipment, net
    16,029       13,384  
 
           
TOTAL PROPERTY AND EQUIPMENT, NET
    571,386       456,264  
 
           
OTHER ASSETS
               
Investment in Partnership — cost
    9,000       9,000  
Deferred financing costs, net
    12,898       13,552  
Derivative financial instruments
    24,106       14,165  
Advances to operators
    4,088       2,699  
Deposits
    1,896       576  
 
           
TOTAL OTHER ASSETS
    51,988       39,992  
 
           
TOTAL ASSETS
  $ 703,043     $ 558,239  
 
           
LIABILITIES AND PARTNERS’ CAPITAL
               
CURRENT LIABILITIES
               
Accounts payable and accrued liabilities
  $ 79,318     $ 87,255  
Current portion, asset retirement obligations
    3,418       1,617  
Derivative financial instruments
    1,959       3,092  
 
           
TOTAL CURRENT LIABILITIES
    84,695       91,964  
 
           
LONG-TERM LIABILITIES
               
Asset retirement obligations
    43,275       41,096  
Long-term debt
    471,971       371,276  
Notes payable to founder
    20,606       19,709  
Derivative financial instruments
          2,296  
Other long-term liabilities
    5,052       7,240  
 
           
TOTAL LONG-TERM LIABILITIES
    540,904       441,617  
 
           
TOTAL LIABILITIES
    625,599       533,581  
COMMITMENTS AND CONTINGENCIES (NOTE 10)
               
PARTNERS’ CAPITAL
    77,444       24,658  
 
           
TOTAL LIABILITIES AND PARTNERS’ CAPITAL
  $ 703,043     $ 558,239  
 
           
See notes to consolidated financial statements.

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ALTA MESA HOLDINGS, LP AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME
(dollars in thousands)
(unaudited)
                                 
    Three Months Ended     Nine Months Ended  
    September 30,     September 30,  
    2011     2010     2011     2010  
REVENUES
                               
Natural gas
  $ 40,250     $ 34,153     $ 114,362     $ 92,088  
Oil
    42,213       23,794       113,702       49,593  
Natural gas liquids
    3,000       2,001       8,900       3,944  
Other revenues
    600       380       1,366       787  
 
                       
 
    86,063       60,328       238,330       146,412  
Unrealized gain — oil and natural gas derivative contracts
    30,101       2,712       25,292       25,620  
 
                       
TOTAL REVENUES
    116,164       63,040       263,622       172,032  
 
                       
EXPENSES
                               
Lease and plant operating expense
    16,267       12,149       44,639       29,581  
Production and ad valorem taxes
    5,728       4,015       15,198       8,413  
Workover expense
    4,413       1,569       8,391       4,858  
Exploration expense
    3,889       4,342       12,310       8,914  
Depreciation, depletion, and amortization
    23,756       17,853       66,187       39,975  
Impairment expense
    5,743       416       16,498       2,509  
Accretion expense
    484       517       1,430       932  
Loss on sale of assets
          87             87  
General and administrative expenses
    9,659       6,020       24,251       12,922  
 
                       
TOTAL EXPENSES
    69,939       46,968       188,904       108,191  
 
                       
INCOME FROM OPERATIONS
    46,225       16,072       74,718       63,841  
OTHER INCOME (EXPENSE)
                               
Interest expense
    (6,779 )     (5,946 )     (23,102 )     (14,675 )
Interest income
    21       6       35       11  
Gain on contract settlement
                1,285        
 
                       
TOTAL OTHER INCOME (EXPENSE)
    (6,758 )     (5,940 )     (21,782 )     (14,664 )
 
                       
INCOME BEFORE STATE INCOME TAXES
    39,467       10,132       52,936       49,177  
PROVISION FOR STATE INCOME TAXES
    (75 )     (2 )     (150 )     (2 )
 
                       
NET INCOME
  $ 39,392     $ 10,130     $ 52,786     $ 49,175  
 
                       
See notes to consolidated financial statements.

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ALTA MESA HOLDINGS, LP AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(dollars in thousands)
(unaudited)
                 
    Nine Months Ended September 30,  
    2011     2010  
CASH FLOWS FROM OPERATING ACTIVITIES:
               
Net income
  $ 52,786     $ 49,175  
Adjustments to reconcile net income to net cash provided by operating activities:
               
Depreciation, depletion, and amortization
    66,187       39,975  
Impairment expense
    16,498       2,509  
Accretion expense
    1,430       932  
(Gain) loss on sale of assets
          87  
Amortization of loan costs
    2,243       1,473  
Amortization of debt discount
    195        
Dry hole expense
    6,452       292  
Expired leases
    93        
Unrealized (gain) on derivatives
    (28,721 )     (26,603 )
(Gain) on contract settlement
    (1,285 )      
Interest converted into debt
    897       890  
Settlement of asset retirement obligation
    (702 )     (658 )
Changes in assets and liabilities:
               
Accounts receivable
    (4,807 )     (1,376 )
Other receivables
    3,641       (1,271 )
Prepaid expenses and other non-current assets
    (4,142 )     (7,445 )
Accounts payable, accrued liabilities, and other long-term liabilities
    4,641       (20,830 )
 
           
NET CASH PROVIDED BY OPERATING ACTIVITIES
    115,406       37,150  
 
           
CASH FLOWS FROM INVESTING ACTIVITIES:
               
Capital expenditures for property and equipment
    (147,989 )     (66,307 )
Acquisitions
    (66,592 )     (101,359 )
 
           
NET CASH USED IN INVESTING ACTIVITIES
    (214,581 )     (167,666 )
 
           
CASH FLOWS FROM FINANCING ACTIVITIES:
               
Proceeds from long-term debt
    100,500       256,500  
Repayments of long-term debt
          (162,343 )
Additions to deferred financing costs
    (1,589 )     (7,584 )
Capital contributions
          50,000  
Capital distributions
          (235 )
 
           
NET CASH PROVIDED BY FINANCING ACTIVITIES
    98,911       136,338  
 
           
NET INCREASE (DECREASE) IN CASH
    (264 )     5,822  
CASH AND CASH EQUIVALENTS, beginning of period
    4,836       4,274  
 
           
CASH AND CASH EQUIVALENTS, end of period
  $ 4,572     $ 10,096  
 
           
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION
               
Cash paid during the period for interest
  $ 15,734     $ 14,204  
Cash paid during the period for taxes
  $     $  
Change in property asset retirement obligations, net
  $ 3,252     $ (3 )
Change in accruals or liabilities for capital expenditures
  $ (13,482 )   $ 22,145  
See notes to consolidated financial statements.

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ALTA MESA HOLDINGS, LP AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(unaudited)
1. SUMMARY OF ORGANIZATION AND NATURE OF OPERATIONS
The consolidated financial statements reflect the accounts of Alta Mesa Holdings, LP and its subsidiaries (we, us, our, the “Company,” and “Alta Mesa”) after elimination of all significant intercompany transactions and balances. The financial statements should be read in conjunction with the consolidated financial statements and notes thereto included in our annual consolidated financial statements for the year ended December 31, 2010, which were filed with the Securities and Exchange Commission in our Registration Statement on Form S-4 (Commission File No. 333-173751).
The consolidated financial statements included herein as of September 30, 2011, and for the nine month periods ended September 30, 2011 and 2010, are unaudited, and in the opinion of management, the information furnished reflects all material adjustments, consisting of normal recurring adjustments, necessary for a fair presentation of consolidated financial position and of the results of operations for the interim periods presented. The consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the U.S. (“GAAP”) for interim financial information and with the instructions to Form 10-Q and Article 10 of Regulation S-X. Accordingly, they do not include all of the information and footnotes required by GAAP for complete financial statements. Certain minor reclassifications of prior period consolidated financial statements have been made to conform to current reporting practices. The consolidated results of operations for interim periods are not necessarily indicative of results to be expected for a full year.
We use accounting policies which reflect industry practices and conform to GAAP. As used herein, the following acronyms have the following meanings: “FASB” means the Financial Accounting Standards Board; the “Codification” refers to the Accounting Standards Codification, the collected accounting and reporting guidance maintained by the FASB; “ASC” means Accounting Standards Codification and is generally followed by a number indicating a particular section of the Codification; and “ASU” means Accounting Standards Update, followed by an identification number, which are the periodic updates made to the Codification by the FASB. “SEC” means the Securities and Exchange Commission.
Organization: The consolidated financial statements presented herein are of Alta Mesa Holdings, LP and its (i) wholly-owned subsidiaries: Alta Mesa Finance Services Corp., Alta Mesa Eagle, LLC, Alta Mesa Acquisition Sub, LLC and its direct and indirect wholly-owned subsidiaries, Alta Mesa Energy, LLC, Aransas Resources, LP and its wholly-owned subsidiary ARI Development, LLC, Brayton Resources II, LP, Buckeye Production Company, LP, Galveston Bay Resources, LP, Louisiana Exploration & Acquisitions, LP and its wholly-owned subsidiary Louisiana Exploration & Acquisition Partnership, LLC, Navasota Resources, Ltd., LLP, Nueces Resources, LP, Oklahoma Energy Acquisitions, LP, Alta Mesa Drilling, LLC, Petro Acquisitions, LP, Petro Operating Company, LP, Texas Energy Acquisitions, LP, Virginia Oil and Gas, LLC and Alta Mesa Services, LP, and (ii) partially-owned subsidiaries: Brayton Resources, LP, and Orion Operating Company, LP.
Nature of Operations: We are engaged primarily in the acquisition, exploration, development, and production of oil and natural gas properties. Our properties are located primarily in Texas, Oklahoma, Louisiana, Florida and the Appalachian Region.
2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
As of September 30, 2011, our significant accounting policies are consistent with those discussed in Note 2 of the consolidated financial statements for the fiscal year ended December 31, 2010.
Use of Estimates: The preparation of consolidated financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the consolidated financial statements and the reported amounts of revenues and expenses during the reporting period.
Reserve estimates significantly impact depreciation, depletion and amortization expense and potential impairments of oil and natural gas properties and are subject to change based on changes in oil and natural gas prices and trends and changes in estimated reserve quantities. We analyze estimates, including those related to oil and natural gas reserves, oil and natural gas revenues, the value of oil and natural gas properties, bad debts, asset retirement obligations, derivative contracts, income taxes and contingencies and litigation. We base our estimates on historical experience and various other assumptions that are believed to be reasonable under the circumstances. Actual results may differ from these estimates.

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Property and Equipment: Oil and natural gas producing activities are accounted for using the successful efforts method of accounting. Under the successful efforts method, lease acquisition costs and all development costs, including unsuccessful development wells, are capitalized.
Unproved Properties — Acquisition costs associated with the acquisition of leases are recorded as unproved leasehold costs and capitalized as incurred. These consist of costs incurred in obtaining a mineral interest or right in a property such as a lease, in addition to options to lease, broker fees, recording fees and other similar costs related to activities in acquiring properties. Leasehold costs are classified as unproved until proved reserves are discovered, at which time related costs are transferred to proved oil and natural gas properties.
Exploration Expense — Exploration expenses, other than exploration drilling costs, are charged to expense as incurred. These costs include seismic expenditures and other geological and geophysical costs, expired leases, and lease rentals. The costs of drilling exploratory wells and exploratory-type stratigraphic wells are initially capitalized pending determination of whether the well has discovered proved commercial reserves. If the exploratory well is determined to be unsuccessful, the cost of the well is transferred to expense. Exploratory well drilling costs may continue to be capitalized if the reserve quantity is sufficient to justify completion as a producing well and sufficient progress in assessing the reserves and the economic and operating viability of the project is being made. Assessments of such capitalized costs are made quarterly.
Proved Oil and Natural Gas Properties — Costs incurred to obtain access to proved reserves and to provide facilities for extracting, treating, gathering, and storing oil and natural gas are capitalized. All costs incurred to drill and equip successful exploratory wells, development wells, development-type stratigraphic test wells, and service wells, including unsuccessful development wells, are capitalized.
Impairment — The capitalized costs of proved oil and natural gas properties are reviewed quarterly for impairment in accordance with ASC 360-10-35, “Property, Plant and Equipment, Subsequent Measurement,” or whenever events or changes in circumstances indicate that the carrying amount of a long-lived asset or asset group exceeds its fair market value and is not recoverable. The determination of recoverability is based on comparing the estimated undiscounted future net cash flows at a producing field level to the carrying value of the assets. If the future undiscounted cash flows, based on estimates of anticipated production from proved reserves and future crude oil and natural gas prices and operating costs, are lower than the carrying cost, the carrying cost of the asset or group of assets is reduced to fair value. For our proved oil and natural gas properties, we estimate fair value by discounting the projected future cash flows at an appropriate risk-adjusted discount rate. Unproved leasehold costs are assessed quarterly to determine whether they have been impaired. Individually significant properties are assessed for impairment on a property-by-property basis, while individually insignificant unproved leasehold costs may be assessed in the aggregate. If unproved leasehold costs are found to be impaired, an impairment allowance is provided and a loss is recognized in the consolidated statement of income.
Depreciation, Depletion, and Amortization — Depreciation, depletion, and amortization (“DD&A”) of capitalized costs of proved oil and natural gas properties is computed using the unit-of-production method based upon estimated proved reserves. Assets are grouped for DD&A on the basis of reasonable aggregation of properties with a common geological structural feature or stratigraphic condition, such as a reservoir or field. The reserve base used to calculate DD&A for leasehold acquisition costs and the cost to acquire proved properties is the sum of proved developed reserves and proved undeveloped reserves. The reserve base used to calculate DD&A for lease and well equipment costs, which include development costs and successful exploration drilling costs, includes only proved developed reserves.
Accounts Receivable, net: Our receivables arise from the sale of oil and natural gas to third parties and joint interest owner receivables for properties in which we serve as the operator. This concentration of customers may impact our overall credit risk, either positively or negatively, in that these entities may be similarly affected by changes in economic or other conditions affecting the oil and gas industry. Accounts receivable are generally not collateralized. Accounts receivable are shown net of an allowance for doubtful accounts of $661,000 and $338,000 at September 30, 2011 and December 31, 2010, respectively.
Deferred Financing Costs: Deferred financing costs and the amount of discount at which notes payable have been issued (debt discount) are amortized using the straight-line method, which approximates the interest method, over the term of the related debt. For the three months ended September 30, 2011 and 2010, amortization of deferred financing costs included in interest expense amounted to $0.5 million and $0.8 million, respectively. For the nine months ended September 30, 2011 and 2010, amortization of deferred financing costs included in interest expense amounted to $2.2 million and $1.5 million, respectively. Deferred financing costs are listed among our long-term assets, net of accumulated amortization of $6.9 million and $4.7 million at September 30, 2011 and

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December 31, 2010, respectively.
Financial Instruments: The fair value of cash, accounts receivable, other current assets, and current liabilities approximate book value due to their short-term nature. The estimate of fair value of long-term debt under our senior secured revolving credit facility is not considered to be materially different from carrying value due to market rates of interest. The fair value of the debt to our founder is not practicable to determine. We have estimated the fair value of our senior notes payable at $273 million and $291 million at September 30, 2011 and December 31, 2010, respectively. See Note 5 for further information on fair values of financial instruments. See Note 8 for information on long-term debt.
Recent Accounting Pronouncements
In September 2011, the FASB issued ASU 2011-08, “Testing Goodwill for Impairment.” ASU 2011-08 amends the guidance for testing goodwill for impairment. Previously, goodwill was required to be tested at least annually, by comparing the fair value of a reporting unit with its carrying value, including goodwill. If the carrying value exceeded the fair value, a second test would be performed to measure the impairment loss, if any. Under the new guidance, testing of goodwill is not prescribed annually, but rather, when events and circumstances make it more likely than not that the carrying value of a reporting unit exceeds its fair value. This is known as a qualitative evaluation. If the qualitative evaluation indicates a possible loss is more likely than not, the two-step test is to be performed. ASU 2011-08 provides new examples of events and circumstances which could affect such a qualitative evaluation. The new guidance is effective for fiscal years beginning after December 15, 2011. Early adoption is permitted. We do not expect adoption of the guidance to have a material impact on our consolidated financial position or results of operations.
3. SIGNIFICANT ACQUISITIONS
Meridian Acquisition
On and effective May 13, 2010, Alta Mesa Acquisition Sub, LLC (“AMAS”), a wholly owned subsidiary of Alta Mesa Holdings, LP, acquired 100% of the shares of and merged with The Meridian Resource Corporation (“Meridian”), with AMAS as the surviving entity. Meridian was a publicly traded company engaged in exploration for and production of oil and natural gas. The oil and natural gas properties of Meridian were similar and in some cases proximate to our areas of operation. Meridian shareholders were paid in cash, funded by proceeds of our credit facility as well as a $50 million equity contribution from our private equity partner Alta Mesa Investment Holdings Inc., an affiliate of Denham Commodities Partners Fund IV LP (“AMIH”). The merger increased the oil portion of our reserves portfolio, improving the balance of our reserves between oil and natural gas, and provided significant additions to our library of 3-D seismic data.
Total cost of the acquisition was $158 million. It was recorded using the acquisition method of accounting. The purchase price was allocated to acquired assets and assumed liabilities based on their estimated fair values at date of acquisition. Acquisition-related costs of approximately $532,000 were recorded in general and administrative expense for the year ended December 31, 2010.
Sydson Acquisition
On April 21, 2011, we purchased from Sydson Energy and certain of its related parties (together, “Sydson” and the “Sydson acquisition”) certain oil and natural gas assets primarily located in Texas and South Louisiana in which we had jointly participated with Sydson. The purchase price was $27.5 million in cash (a total cost of $28.4 million including abandonment liabilities we assumed). Total net proved reserves acquired are estimated to be 800 MBOE (5 Bcfe), 45% of which is oil. By virtue of this acquisition, we increased our after payout net revenue interest in the Eagle Ford Shale by over 50% at the time of the acquisition. Funding for the acquisition was provided through our credit facility. In addition, litigation associated with a portion of the assets purchased was resolved as a result of the transaction.

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TODD Acquisition
On June 17, 2011, we purchased from Texas Oil Distribution & Development, Inc. and Matrix Petroleum LLC and certain other parties (together, “TODD” and the “TODD acquisition”) certain oil and natural gas assets primarily located in Texas and South Louisiana in which we had jointly participated with TODD. The purchase price was $22.5 million in cash (a total cost of $23.4 million including abandonment liabilities we assumed). Total net proved reserves acquired are estimated to be 700 MBOE (4 Bcfe), 36% of which is oil. By virtue of this acquisition, we increased our after payout net revenue interest in the Eagle Ford Shale by an additional 15% at the time of the acquisition. Funding for the acquisition was provided through our credit facility. In addition, litigation associated with TODD was resolved as a result of the transaction.
A summary of the consideration paid and the allocations of the purchase prices (which are preliminary for the Sydson and TODD acquisitions) are as follows (dollars in thousands):
                         
Summary of Consideration:   Meridian     Sydson     TODD  
Cash
  $ 30,948     $ 27,500     $ 22,500  
Debt retired
    82,000              
Debt assumed
    5,346              
Working capital deficit (1)
    753              
Other liabilities assumed
    7,971              
Fair value of asset retirement obligations assumed
    30,920       922       863  
 
                 
Total
  $ 157,938     $ 28,422     $ 23,363  
 
                 
Summary of Purchase Price Allocations:
                       
Proved oil and natural gas properties
  $ 144,325     $ 18,330     $ 15,223  
Unproved oil and natural gas properties
    3,113       10,092       8,140  
Other tangible assets
    10,500              
 
                 
Total
  $ 157,938     $ 28,422     $ 23,363  
 
                 
 
(1)   Meridian working capital deficit included a cash balance of $11,589,000.
The revenue and earnings related to the Meridian, Sydson, and TODD acquisitions are included in our consolidated statement of income for the nine months ended September 30, 2011. The revenue and earnings related to the Meridian acquisition are also included in our consolidated statement of income for the nine months ended September 30, 2010. Revenue and earnings, had the acquisitions occurred on January 1, 2010, are provided below. This unaudited pro forma information has been derived from historical information and is for illustrative purposes only. The unaudited pro forma financial information does not attempt to predict or suggest future results. It also does not necessarily reflect what the historical results of the combined company would have been had the companies been combined during these periods.
                 
    (Unaudited)  
    Revenue     Income  
    (dollars in thousands)  
Actual results of Meridian included in our statement of income for the nine months ended September 30, 2011
  $ 98,949     $ 49,803  
Actual results of Sydson included in our statement of income for the period April 21, 2011 through September 30, 2011
  $ 4,521     $ 1,904  
Actual results of TODD included in our statement of income for the period June 17, 2011 through September 30, 2011
  $ 1,518     $ 119  
Pro forma results for the combined entity for the nine months ended September 30, 2011
  $ 266,816     $ 54,995  
Pro forma results for the combined entity for the nine months ended September 30, 2010
  $ 208,004     $ 52,222  

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4. PROPERTY AND EQUIPMENT
Property and equipment consists of the following:
                 
    September 30,     December 31,  
    2011     2010  
    (unaudited)          
    (dollars in thousands)  
OIL AND NATURAL GAS PROPERTIES
               
Unproved properties
  $ 36,923     $ 12,020  
Accumulated impairment
    (5,246 )     (2,686 )
 
           
Unproved properties, net
    31,677       9,334  
 
           
Proved oil and natural gas properties
    876,286       707,364  
Accumulated depreciation, depletion, amortization and impairment
    (352,606 )     (273,818 )
 
           
Proved oil and natural gas properties, net
    523,680       433,546  
 
           
TOTAL OIL AND NATURAL GAS PROPERTIES, net
    555,357       442,880  
 
           
LAND
    1,185       1,185  
 
           
DRILLING RIG
    10,500       10,500  
Accumulated depreciation
    (969 )     (444 )
 
           
TOTAL DRILLING RIG, net
    9,531       10,056  
 
           
OTHER PROPERTY AND EQUIPMENT
               
Office furniture and equipment, vehicles
    6,393       3,844  
Accumulated depreciation
    (1,080 )     (1,701 )
 
           
OTHER PROPERTY AND EQUIPMENT, net
    5,313       2,143  
 
           
TOTAL PROPERTY AND EQUIPMENT, net
  $ 571,386     $ 456,264  
 
           
5. FAIR VALUE DISCLOSURES
We follow the guidance of ASC 820, “Fair Value Measurements and Disclosures,” in the estimation of fair values. ASC 820 provides a hierarchy of fair value measurements, based on the inputs to the fair value estimation process. It requires disclosure of fair values classified according to defined “levels,” which are based on the reliability of the evidence used to determine fair value, with Level 1 being the most reliable and Level 3 the least. Level 1 evidence consists of observable inputs, such as quoted prices in an active market. Level 2 inputs typically correlate the fair value of the asset or liability to a similar, but not identical item which is actively traded. Level 3 inputs include at least some unobservable inputs, such as valuation models developed using the best information available in the circumstances.
We utilize the modified Black-Scholes option pricing model to estimate the fair value of oil and natural gas derivative contracts. Inputs to this model include observable inputs from the New York Mercantile Exchange (“NYMEX”) for futures contracts, and inputs derived from NYMEX observable inputs, such as implied volatility of oil and natural gas prices. We have classified the fair values of all our oil and natural gas derivative contracts as Level 2.
The fair value of our interest rate derivative contracts was calculated using the modified Black-Scholes option pricing model and is also considered a Level 2 fair value.
Our senior notes are carried at historical cost, net of amortized discount; we estimate the fair value of the senior notes for disclosure purposes (see Note 2). This estimation is based on the most recent trading values of the notes at or near the reporting dates.
Oil and natural gas properties are subject to impairment testing and potential impairment write down. Oil and gas properties with a carrying amount of $31.8 million were written down to their fair value of $15.3 million, resulting in an impairment charge of $16.5 million for the nine months ended September 30, 2011. Oil and gas properties with a carrying amount of $7.3 million were written down to their fair value of $4.8 million, resulting in an impairment charge of $2.5 million for the nine months ended September 30, 2010. For the three months ended September 30, 2011, oil and gas properties with a carrying amount of $7.4 million were written down to their fair value of $1.7 million, resulting in an impairment charge of $5.7 million, and for the three months ended September 30, 2010, oil and gas properties with a carrying amount of $2.9 million were written down to their fair value of $2.5 million, resulting in an impairment charge of $0.4 million. Significant Level 3 assumptions used in the calculation of estimated discounted cash flows in the impairment analysis included our estimate of future oil and natural gas prices, production costs, development expenditures, estimated timing of production of proved reserves, appropriate risk-adjusted discount rates, and other relevant data.
In connection with the Meridian acquisition, we recorded oil and natural gas properties with a fair value of $147.4 million in the second quarter of 2010. In connection with the Sydson and TODD acquisitions, we recorded oil and natural gas properties with a fair value of $28.4 million, and $23.4 million, respectively, in the second quarter of 2011. For information on these acquisitions, see Note 3. Significant Level 3 inputs used were the same as those used in determining impairments based on estimated discounted cash flows for the acquired properties.

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New additions to asset retirement obligations result from estimations for new properties, and fair values for them are categorized as Level 3. Such estimations are based on present value techniques which utilize company-specific information for such inputs as cost and timing of plug and abandonment of wells and facilities. We recorded $3.3 million and $34.6 million in additions to asset retirement obligations measured at fair value during the nine months ended September 30, 2011 and 2010, respectively. The significant additions in 2010 were the result of the purchase of Meridian.
The following table presents information about our financial assets and liabilities measured at fair value on a recurring basis as of September 30, 2011 and December 31, 2010, and indicates the fair value hierarchy of the valuation techniques we utilized to determine such fair value:
                                 
    Level 1     Level 2     Level 3     Total  
    (dollars in thousands)  
At September 30, 2011 (unaudited):
                               
Financial Assets:
                               
Derivative contracts for oil and natural gas
  $     $ 93,586     $     $ 93,586  
Financial Liabilities:
                               
Derivative contracts for oil and natural gas
          43,693             43,693  
Derivative contracts for interest rate
          1,959             1,959  
At December 31, 2010:
                               
Financial Assets:
                               
Derivative contracts for oil and natural gas
  $     $ 61,623     $     $ 61,623  
Financial Liabilities:
                               
Derivative contracts for oil and natural gas
          37,022             37,022  
Derivative contracts for interest rate
          5,388             5,388  
The amounts above are presented on a gross basis; presentation on our consolidated balance sheets utilizes netting of assets and liabilities with the same counterparty where master netting agreements are in place. For additional information on derivative contracts, see Note 6.
6. DERIVATIVE FINANCIAL INSTRUMENTS
We account for our derivative contracts under the provisions of ASC 815, “Derivatives and Hedging.” We have entered into forward-swap contracts and collar contracts to reduce our exposure to price risk in the spot market for oil and natural gas. We also utilize financial basis swap contracts, which address the price differential between market-wide benchmark prices and other benchmark pricing referenced in certain of our crude oil and natural gas sales contracts. Substantially all of our hedging agreements are executed by affiliates of the lenders under the credit facility described in Note 8 below, and are collateralized by the security interests of the respective affiliated lenders in certain of our assets under the credit facility. The contracts settle monthly and are scheduled to coincide with either oil production equivalent to barrels (Bbl) per month or gas production equivalent to volumes in millions of British thermal units (MMbtu) per month. The contracts represent agreements between us and the counter-parties to exchange cash based on a designated price. Prices are referenced to the natural gas spot market benchmark price at the Houston Ship Channel or NYMEX indices. Cash settlement occurs monthly based on the specified price benchmark. We have not designated any of our derivative contracts as fair value or cash flow hedges; accordingly we use mark-to-market accounting, recognizing unrealized gains and losses in the statement of operations at each reporting date. Realized gains and losses on commodities hedging contracts are included in oil and natural gas revenues.
We have entered into a series of interest rate swap agreements with several financial institutions to mitigate the risk of loss due to changes in interest rates. The interest rate swaps are not designated as cash flow hedges in accordance with ASC 815. Both realized gains and losses from settlement and unrealized gains and losses from changes in the fair market value of the interest rate swaps are included in interest expense.
The second table below provides information on the location and amounts of realized and unrealized gains and losses on derivatives included in the consolidated statements of income for each of the three month and nine month periods ended September 30, 2011 and 2010.

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The following table summarizes the fair value (see Note 5 for further discussion of fair value) and classification of our derivative instruments, none of which have been designated as hedging instruments under ASC 815:
                                 
Fair Values of Derivative Contracts  
    Balance Sheet Location at September 30, 2011  
    Current asset     Current liability     Long-term asset     Long-term liability  
    portion of     portion of     portion of     portion of  
    Derivative     Derivative     Derivative     Derivative  
    financial     financial     financial     financial  
    instruments     instruments     instruments     instruments  
            (unaudited)          
            (dollars in thousands)          
Fair value of oil and gas commodity contracts, assets
  $ 46,514     $     $ 47,072     $  
Fair value of oil and gas commodity contracts, (liabilities)
    (20,727 )           (22,966 )      
Fair value of interest rate contracts, (liabilities)
          (1,959 )            
 
                       
Total net assets, (liabilities)
  $ 25,787     $ (1,959 )   $ 24,106     $  
 
                       
                                 
Fair Values of Derivative Contracts  
    Balance Sheet Location at December 31, 2010  
    Current asset     Current liability     Long-term asset     Long-term liability  
    portion of     portion of     portion of     portion of  
    Derivative     Derivative     Derivative     Derivative  
    financial     financial     financial     financial  
    instruments     instruments     instruments     instruments  
    (dollars in thousands)  
Fair value of oil and gas commodity contracts, assets
  $ 27,118     $     $ 34,505     $  
Fair value of oil and gas commodity contracts, (liabilities)
    (16,682 )           (20,340 )      
Fair value of interest rate contracts, (liabilities)
          (3,092 )           (2,296 )
 
                       
Total net assets, (liabilities)
  $ 10,436     $ (3,092 )   $ 14,165     $ (2,296 )
 
                       
Commodity contracts are subject to master netting arrangements and are presented on a net basis in the consolidated balance sheets. This netting can cause derivative assets to be ultimately presented in a (liability) account on the consolidated balance sheets. Likewise, derivative (liabilities) could be presented in an asset account.
The following table summarizes the effect of our derivative instruments in the consolidated statements of operations:
                                         
Derivatives not                    
designated as hedging           For the three months ended     For the nine months ended  
instruments under ASC   Location of Gain   Classification of   September 30,     September 30,  
815   (Loss)   Gain (Loss)   2011     2010     2011     2010  
                    (unaudited)          
                    (dollars in thousands)          
Natural gas commodity contracts
  Natural gas revenues   Realized   $ 5,986     $ 7,003     $ 16,897     $ 16,204  
Oil commodity contracts
  Oil revenues   Realized     162       273       (3,756 )     549  
Interest rate contracts
  Interest benefit (expense)   Realized     76       (1,384 )     2,004       (3,436 )
 
                               
Total realized gains (losses) from derivatives not designated as hedges
          $ 6,224     $ 5,892     $ 15,145     $ 13,317  
 
                               
Natural gas commodity contracts
  Unrealized gain (loss) — oil and natural gas derivative contracts   Unrealized   $ 7,724     $ 8,562     $ 6,425     $ 23,858  
Oil commodity contracts
  Unrealized gain (loss) — oil and natural gasderivative contracts   Unrealized     22,377       (5,850 )     18,867       1,762  
Interest rate contracts
  Interest benefit (expense)   Unrealized     2,921       580       3,429       983  
 
                               
Total unrealized gains (losses) from derivatives not designated as hedges
          $ 33,022     $ 3,292     $ 28,721     $ 26,603  
 
                               
Although our counterparties provide no collateral, the master derivative agreements with each counterparty effectively allow us, so long as we are not a defaulting party, after a default or the occurrence of a termination event, to set-off an unpaid hedging agreement receivable against the interest of the counterparty in any outstanding balance under the credit facility.
If a counterparty were to default in payment of an obligation under the master derivative agreements, we could be exposed to commodity price fluctuations, and the protection intended by the hedge could be lost. The value of our derivative financial instruments would be impacted.

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We had the following open derivative contracts for natural gas at September 30, 2011 (unaudited):
NATURAL GAS DERIVATIVE CONTRACTS
                                 
    Volume in     Weighted     Range  
Period and Type of Contract   MMbtu     Average     High     Low  
2011
                               
Price Swap Contracts
    5,815,000     $ 5.63     $ 8.83     $ 4.44  
Collar Contracts
                               
Short Call Options
    6,760,000       5.67       7.05       5.40  
Long Put Options
    3,060,000       6.05       6.30       5.75  
Long Call Options
    600,000       7.45       7.45       7.45  
Short Put Options
    1,480,000       3.86       4.00       3.65  
2012
                               
Price Swap Contracts
    7,525,000       6.17       8.83       5.00  
Collar Contracts
                               
Short Call Options
    7,560,000       5.76       6.00       5.50  
Long Put Options
    4,350,000       5.93       6.75       5.50  
Long Call Options
    3,660,000       5.00       5.00       5.00  
Short Put Options
    9,810,000       4.10       4.50       4.00  
2013
                               
Price Swap Contracts
    6,650,000       6.18       9.15       5.35  
Collar Contracts
                               
Short Call Options
    1,500,000       6.50       6.50       6.50  
Long Put Options
    1,500,000       6.09       6.15       6.00  
Short Put Options
    900,000       5.00       5.00       5.00  
2014
                               
Price Swap Contracts
    3,125,000       6.27       7.50       5.60  
Collar Contracts
                               
Short Call Options
    3,475,000       7.05       9.00       6.00  
Long Put Options
    1,650,000       6.73       7.00       6.00  
Short Put Options
    1,200,000       5.50       5.50       5.50  
2015
                               
Price Swap Contracts
    1,825,000       5.91       5.91       5.91  
2016
                               
Collar Contracts
                               
Short Call Options
    455,000       7.50       7.50       7.50  
Long Put Options
    455,000       5.50       5.50       5.50  
Short Put Options
    455,000       4.00       4.00       4.00  
We had the following open derivative contracts for crude oil at September 30, 2011 (unaudited):
OIL DERIVATIVE CONTRACTS
                                 
            Weighted     Range  
Period and Type of Contract   Volume in Bbls     Average     High     Low  
2011
                               
Price Swap Contracts
    184,000     $ 82.13     $ 103.20     $ 67.50  
Collar Contracts
                               
Short Call Options
    419,900       101.01       110.00       82.25  
Long Put Options
    317,400       86.67       100.00       75.00  
Long Call Options
    162,300       81.60       85.00       75.00  
Short Put Options
    402,592       66.42       89.85       55.00  
2012
                               
Price Swap Contracts
    36,600       80.20       80.20       80.20  
Collar Contracts
                               
Short Call Options
    1,171,008       121.29       132.00       100.00  
Long Put Options
    1,190,618       100.32       105.00       70.00  
Long Call Options
    228,600       103.79       123.50       90.20  
Short Put Options
    1,311,008       79.34       85.00       60.00  

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            Weighted     Range  
Period and Type of Contract   Volume in Bbls     Average     High     Low  
2013
                               
Price Swap Contracts
    136,500       84.35       94.74       77.00  
Collar Contracts
                               
Short Call Options
    527,435       113.38       127.00       90.00  
Long Put Options
    351,500       81.95       90.00       80.00  
Long Call Options
    82,500       79.00       79.00       79.00  
Short Put Options
    434,000       61.58       70.00       60.00  
2014
                               
Price Swap Contracts
    127,300       87.63       91.05       81.00  
Collar Contracts
                               
Short Call Options
    273,750       125.70       133.50       107.50  
Long Put Options
    488,450       85.33       90.00       80.00  
Short Put Options
    488,450       65.33       70.00       60.00  
2015
                               
Collar Contracts
                               
Short Call Options
    246,350       125.12       135.98       116.40  
Long Put Options
    319,350       87.57       90.00       85.00  
Short Put Options
    319,350       66.86       70.00       60.00  
2016
                               
Collar Contracts
                               
Short Call Options
    36,400       130.00       130.00       130.00  
Long Put Options
    36,400       95.00       95.00       95.00  
Short Put Options
    36,400       75.00       75.00       75.00  
In those instances where contracts are identical as to time period, volume and strike price, but opposite as to direction (long and short), the volumes and average prices have been netted in the two tables above. In some instances our counterparties in the offsetting contracts are not the same, and may have different credit ratings.
We had the following open financial basis swap contracts for gas at September 30, 2011 (unaudited):
                         
Volume in MMbtu     Reference Price   Period   Spread ($ per MMbtu)  
600,000    
Houston Ship Channel
  Oct ’11 — Dec ’11     (0.2000)
600,000    
Houston Ship Channel
  Oct ’11 — Dec ’11     (0.1600)
230,000    
Houston Ship Channel
  Oct ’11 — Dec ’11     (0.0850)
690,000    
Houston Ship Channel
  Oct ’11 — Dec ’11     (0.1550)
1,830,000    
Houston Ship Channel
  Jan ’12 — Dec ’12     (0.1575)
920,000    
Houston Ship Channel
  Oct ’11 — Dec ’11     (0.1150)
3,660,000    
Houston Ship Channel
  Jan ’12 — Dec ’12     (0.1400)
We had the following open financial basis swap contract for oil at September 30, 2011 (unaudited):
                         
Volume in BBL     Reference Price   Period     Spread ($ per MMbtu)  
46,000    
Argus Louisiana Light Sweet Crude
  Oct ’11 — Dec ’11     19.40  
We had the following open interest rate swap contracts at September 30, 2011 (unaudited):
Interest Rate Swaps
                 
 
Term   Principal Amount   Interest Rate (1)
    (dollars in thousands)
Floating to Fixed Rate Swaps:
               
October 2011 — August 2012
  $ 50,000       4.95 %
October 2011 — October 2011
  $ 25,000       3.21 %
 
(1)   The floating rate is the three-month LIBOR rate.

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7. ASSET RETIREMENT OBLIGATIONS
A summary of the changes in asset retirement obligations is included in the table below (unaudited, dollars in thousands):
         
Balance, December 31, 2010
  $ 42,713  
Liabilities incurred
    445  
Liabilities assumed with acquired producing properties
    2,807  
Liabilities settled
    (702 )
Accretion expense
    1,430  
 
     
Balance, September 30, 2011
    46,693  
Less: Current portion
    3,418  
 
     
 
  $ 43,275  
 
     
8. LONG-TERM DEBT AND NOTES PAYABLE TO FOUNDER
Long-term debt consists of the following:
                 
    September 30,     December 31,  
    2011     2010  
    (unaudited)          
    (dollars in thousands)  
Senior Debt — On November 13, 2008, we entered into a Fifth Amended and Restated Credit Agreement with a group of banks, which was replaced by the Sixth Amended and Restated Credit Agreement on May 13, 2010, as amended (“credit facility”). The credit facility matures on May 23, 2016 and is secured by substantially all of our oil and gas properties. The credit facility borrowing base is redetermined periodically and, as of September 30, 2011, the borrowing base under the facility was $260 million. As of November 7, 2011, the borrowing base was increased to $325 million. The credit facility bears interest at LIBOR plus applicable margins between 2.00% and 2.75% or a “Reference Rate,” which is based on the prime rate of Wells Fargo Bank, N. A., plus a margin ranging from 1.00% to 1.75%, depending on the utilization of our borrowing base. The rate was 2.615% as of September 30, 2011 and 2.875% as of December 31, 2010.
  $ 173,790     $ 73,290  
Senior Notes Payable — On October 13, 2010, we issued notes due October 15, 2018 with a face value of $300 million, at a discount of $2.1 million. The senior notes carry a face interest rate of 9 5/8%, with an effective rate of 9 3/4%; interest is payable semi-annually each April 15th and October 15th. The senior notes are secured by general corporate credit, and effectively rank junior to any of our existing or future secured indebtedness, which includes the credit facility. The senior notes are unconditionally guaranteed on a senior unsecured basis by each of our material subsidiaries. The balance is presented net of unamortized discount of $1.8 million and $2.0 million at September 30, 2011 and December 31, 2010, respectively.
    298,181       297,986  
 
           
Total long-term debt
  $ 471,971     $ 371,276  
 
           
The senior notes contain an optional redemption provision beginning in October 2013 allowing us to retire up to 35% of the principal outstanding under the senior notes with the proceeds of an equity offering, at 109.625%. Additional optional redemption provisions allow for retirement at 104.813%, 102.406%, and 100.0% beginning on each of October 15, 2014, 2015, and 2016, respectively.
On October 13, 2010, we entered into a registration rights agreement with the initial purchasers of the senior notes. Pursuant to the registration rights agreement, we filed a registration statement with the SEC to allow for registration of “exchange notes” with terms substantially identical to the senior notes. The exchange offer was consummated on August 12, 2011, with the tendered original senior notes exchanged for the exchange notes.
The credit facility and senior notes include covenants requiring us to maintain certain financial covenants including a current ratio, leverage ratio, and interest coverage ratio. At September 30, 2011, we were in compliance with the covenants. The terms of the credit facility also restrict our ability to make distributions and investments.
In addition, we have notes payable to our founder which bear simple interest at 10% with a balance of $20.6 million and $19.7 million at September 30, 2011 and December 31, 2010, respectively. The notes mature December 31, 2018. Interest and principal are payable at maturity. The notes are subordinate to all debt. Interest on the notes payable to our founder amounted to $897,000 and $890,000 for the nine months ended September 30, 2011 and 2010, respectively, and $297,000 and $300,000 for the three months ended September 30, 2011 and 2010, respectively. Such amounts have been added to the balance of the notes.

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9. ACCOUNTS PAYABLE AND ACCRUED LIABILITIES
The following provides the detail of accounts payable and accrued liabilities:
                 
    September 30,     December 31,  
    2011     2010  
    (unaudited)          
    (dollars in thousands)  
Capital expenditures
  $ 26,111     $ 22,743  
Revenues and royalties payable
    4,163       5,962  
Operating expenses/taxes
    30,070       18,220  
Compensation
    2,431       2,591  
Liability related to drilling rig
          9,785  
Other
    2,313       1,775  
 
           
Total accrued liabilities
    65,088       61,076  
Accounts payable
    14,230       26,179  
 
           
Accounts payable and accrued liabilities
  $ 79,318     $ 87,255  
 
           
The following provides the detail of other long-term liabilities:
                 
    September 30,     December 31,  
    2011     2010  
    (unaudited)          
    (dollars in thousands)  
Acquisition obligation
  $ 435     $ 411  
Remediation liability
    978       943  
Other
    3,639       5,886  
 
           
Total other long-term liabilities
  $ 5,052     $ 7,240  
 
           
10. COMMITMENTS AND CONTINGENCIES
Contingencies
Deep Bossier litigation: On July 23, 2009, we made a payment of $25.5 million and took assignment of substantially all working interests that had been held by Chesapeake Energy Corporation in an approximate 50,000 acre area of Leon and Robertson Counties, Texas in the Deep Bossier play. We had exercised our preferential right to purchase these interests from Gastar Exploration Ltd. in late 2005, but Gastar and Chesapeake had opposed this and Chesapeake took record title until we finally and conclusively prevailed, and in 2008 a Texas court of appeals directed that specific performance take place. In early 2009, the Texas Supreme Court denied the defendants’ request to hear the appeal. As a result, we were able to take working interests in over 30 producing wells and participate in further development of the area, primarily with EnCana, but also with Gastar. A subsequent payment to EnCana of $15.2 million plus purchase accounting adjustments of $3.8 million brought the total cost of the acquisition to $44.5 million. While the ownership of these interests has been decided by the courts, we are pursuing other claims against Chesapeake; Chesapeake is claiming an additional $36.5 million of past expenses from us. Discovery is ongoing and the case is set for trial on April 24, 2012. We are unable to express an opinion with respect to the likelihood of an unfavorable outcome of this matter or to estimate the amount or range of potential loss should the outcome be unfavorable. Therefore, we have not provided any amount for this matter in our consolidated financial statements at September 30, 2011.
Ted R. Stalder, TRS LP, Richard Hughart, and Richmar Interests, Inc. v. Texas Energy Acquisitions, LP: On May 24, 2011, the plaintiffs brought suit against us for breach of contract, common law fraud, fraud in a real estate transaction, declaratory relief, money had and received, an accounting, and injunctive relief related to the deferred purchase price for oil and gas properties in two purchase and sales agreements dated December 23, 2008. A temporary restraining order (“TRO”) was entered against us on May 24, 2011. At a July 7, 2011 hearing on the temporary injunction, the court recommended that the parties enter into an agreed temporary injunction regarding payment of disputed amounts into the registry of the court.

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The parties are still in the process of negotiating the agreed temporary injunction. On July 28, 2011, we filed a motion for partial summary judgment on the plaintiffs’ fraud claims, which is currently set for hearing on November 17, 2011. We intend to contest the matter vigorously. We are unable to express an opinion with respect to the likelihood of an unfavorable outcome of this matter or to estimate the amount or range of potential loss should the outcome be unfavorable. Therefore, we have not provided any amount for this matter in our consolidated financial statements at September 30, 2011.
Environmental claims: Management has established a liability for soil contamination in Florida of $978,000 at September 30, 2011 and $943,000 at December 31, 2010, based on our undiscounted engineering estimates. The obligations are included in other long-term liabilities in the accompanying consolidated balance sheets.
Various landowners have sued Meridian (along with numerous other oil companies) in lawsuits concerning several fields in which Meridian has had operations. The lawsuits seek injunctive relief and other relief, including unspecified amounts in both actual and punitive damages for alleged breaches of mineral leases and alleged failure to restore the plaintiffs’ lands from alleged contamination and otherwise from Meridian’s oil and natural gas operations. We are unable to express an opinion with respect to the likelihood of an unfavorable outcome of the various environmental claims or to estimate the amount or range of potential loss should the outcome be unfavorable. Therefore, we have not provided any amount for these claims in our financial statements at September 30, 2011.
Due to the nature of our business, some contamination of the real estate property owned or leased by us is possible. Environmental site assessments of the property would be necessary to adequately determine remediation costs, if any. No accrual has been made other than the balance noted above.
Title/lease disputes: Title and lease disputes may arise in the normal course of our operations. These disputes are usually small but could result in an increase or decrease in reserves once a final resolution to the title dispute is made.
Other contingencies: We are subject to legal proceedings, claims and liabilities arising in the ordinary course of business. The outcome cannot be reasonably estimated; however, in the opinion of management, such litigation and claims will be resolved without material adverse effect on our financial position, results of operations or cash flows. Accruals for losses associated with litigation are made when losses are deemed probable and can be reasonably estimated.
We have contingent commitments to pay an amount up to a maximum of approximately $5.9 million for properties acquired in 2008 and prior years. The additional purchase consideration will be paid only if certain product price conditions are met. We cannot estimate the amounts that will be paid in the future, if any, or the fiscal years in which such amounts could become due.
Drilling rig: Included in our acquisition of Meridian was a contractual obligation for the use of a drilling rig, which expired in February 2011. Meridian and Alta Mesa were not able to fully utilize this rig during the contractual term; however, we were obligated for the dayrate regardless of whether the rig was working or idle. The operator, Orion Drilling, LP (“Orion”), sought other parties to use the rig and agreed to credit Meridian’s and Alta Mesa’s obligation, based on revenues from third parties who utilized the rig when it was not utilized under the contract. We had provided approximately $9.8 million for the liability under this drilling contract and under a similar rig contract which had previously expired and was also underutilized.
On May 19, 2011, we fully settled this liability with a payment of $8.5 million to Orion, and recorded a gain on contact settlement of $1.3 million in the second quarter of 2011.
11. SIGNIFICANT RISKS AND UNCERTAINTIES
Our business makes us vulnerable to changes in wellhead prices of crude oil and natural gas. Such prices have been volatile in the past and can be expected to be volatile in the future. By definition, proved reserves are based on analysis of current oil and natural gas prices. Price declines reduce the estimated value of proved reserves and may increase annual amortization expense (which is based on proved reserves). Price declines may also result in impairments, or non-cash write-downs, of the value of our oil and natural gas properties. We mitigate a portion of this vulnerability by entering into oil and natural gas price derivative contracts. See Note 6.
12. PARTNERS’ CAPITAL
In September 2006, our limited partnership agreement was amended such that the affiliates of Alta Mesa Holdings, LP and certain other parties became Class A limited partners (“Class A Partners”) and AMIH was admitted to the partnership as the sole Class B limited partner (“Class B Partner”).

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Management and Control: Our business and affairs are managed by Alta Mesa Holdings GP, LLC, our general partner (“General Partner”). With certain exceptions, the General Partner may not be removed except for the reasons of “cause,” which are defined in the Alta Mesa Holdings, LP Partnership Agreement (“Partnership Agreement”). The Class B limited partner has certain approval rights, generally over capital plans and significant transactions in the areas of finance, acquisition, and divestiture.
Distribution and Income Allocation: Net cash flow from operations may be distributed to the Class A and Class B Partners based on a variable formula as defined in the Partnership Agreement.
After January 1, 2012, the Class B Partner may require the General Partner to make distributions; however, any distribution must be permitted under the terms of our credit facility and our senior notes.
Distribution of net cash flow from a Liquidity Event (as defined below) is distributed to the Class A and Class B Partners according to a variable formula as defined in the Partnership Agreement. A “Liquidity Event” is any event in which we receive cash proceeds outside the ordinary course of our business. Further, after January 1, 2012, the Class B Partner can, without consent of any other partners, request that the General Partner take action to cause us, or our assets, to be sold to one or more third parties.
13. SUBSIDIARY GUARANTORS
All of our material wholly-owned subsidiaries are guarantors under the terms of both our senior notes and our credit facility.
Our consolidated financial statements reflect the combined financial position of these subsidiary guarantors. Our parent company, Alta Mesa Holdings, LP has no independent operations, assets, or liabilities. The guarantees are full and unconditional and joint and several. Those subsidiaries which are not wholly owned and are not guarantors are minor. There are no restrictions on dividends, distributions, loans, or other transfers of funds from the subsidiary guarantors to our parent company.
14. SUBSEQUENT EVENTS
Management has evaluated all events subsequent to the balance sheet date of September 30, 2011, and has determined that no events require disclosure.

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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 related notes included elsewhere in this report. In addition, such analysis should be read in conjunction with the financial statements and the related notes included in our Registration Statement on Form S-4 (Commission File No. 333-173751 filed on July 11, 2011, the “Form S-4”). The following discussion and analysis contains forward-looking statements that reflect our future plans, estimates, beliefs and expected performance. The forward-looking statements are dependent upon events, risks and uncertainties that may be outside our control. Our actual results could differ materially from those discussed in these forward-looking statements. Factors that could cause or contribute to such differences include, but are not limited to, the volatility of oil and natural gas prices, general economic conditions, credit markets, inflation, the credit rating of U.S. government debt, production timing and volumes, estimates of proved reserves, operating costs and capital expenditures, lack of availability of drilling and production equipment and services, environmental risks, drilling and other operating risks, regulatory changes, the uncertainty inherent in estimating oil and natural gas reserves and in projecting future rates of production, cash flow and access to capital and other uncertainties, as well as those factors discussed below and under “Risk Factors” in our Form S-4. As a result of these risks, uncertainties and assumptions, the forward-looking events discussed may not occur. The historical financial information discussed below in this Management’s Discussion and Analysis of Financial Conditions and Results of Operations represents Alta Mesa’s financial information for the periods indicated, giving effect to the Meridian acquisition from the acquisition date of May 13, 2010 and the Sydson and TODD asset acquisitions from April 21, 2011 and June 17, 2011, respectively.
Overview
     We currently generate significant amounts of our revenue, earnings and cash flow from the production and sale of oil and natural gas from our core properties in South Louisiana, East Texas, Oklahoma, the Deep Bossier resource play of East Texas and the Eagle Ford Shale play in South Texas. We operate in one industry segment, oil and natural gas exploration and development, within one geographical segment, the United States.
     The amount of cash we generate from our operations will fluctuate based on, among other things:
    the prices at which we will sell our production;
 
    the amount of oil and natural gas we produce; and
 
    the level of our operating and administrative costs.
     In order to mitigate the impact of changes in oil and natural gas prices on our cash flows, we are a party to hedging and other price protection contracts, and we intend to enter into such transactions in the future to reduce the effect of oil and natural gas price volatility on our cash flows.
     Substantially all of our oil and natural gas activities are conducted jointly with others and, accordingly, amounts presented reflect our proportionate interest in such activities. Inflation has not had a material impact on our results of operations and is not expected to have a material impact on our results of operations in the future.
Significant Acquisitions
Meridian Acquisition
          On May 13, 2010, we acquired The Meridian Resource Corporation, a public exploration and production company, with proved reserves of 75 Bcfe as of December 31, 2009, for approximately $158 million. The oil and natural gas properties of Meridian were similar and in some cases proximate to our areas of operation. Meridian shareholders were paid in cash, funded by proceeds of our credit facility as well as a $50 million equity contribution from our private equity partner, Alta Mesa Investment Holdings Inc., an affiliate of Denham Commodities Partners Fund IV LP (“AMIH”). The merger increased the oil portion of our reserves portfolio, improving the balance of our reserves between oil and natural gas, and provided significant additions to our library of 3-D seismic data.

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Sydson Acquisition
     On April 21, 2011, we purchased from Sydson Energy and certain of its related parties (together, “Sydson” and the “Sydson acquisition”) certain oil and natural gas assets primarily located in Texas and South Louisiana in which we had jointly participated with Sydson. The purchase price was $27.5 million in cash (a total cost of $28.4 million including abandonment liabilities we assumed). Total net proved reserves acquired are estimated to be 800 MBOE (5 Bcfe), 45% of which is oil. By virtue of this acquisition, we increased our after payout net revenue interest in the Eagle Ford Shale by over 50% at the time of the acquisition. Funding for the acquisition was provided through our credit facility. In addition, litigation associated with a portion of the assets purchased was resolved as a result of the transaction.
     TODD Acquisition
     On June 17, 2011, we purchased from Texas Oil Distribution & Development, Inc. and Matrix Petroleum LLC and certain other parties (together, “TODD” and the “TODD acquisition”) certain oil and natural gas assets primarily located in Texas and South Louisiana in which we had jointly participated with TODD. The purchase price was $22.5 million in cash (a total cost of $23.4 million including abandonment liabilities we assumed). Total net proved reserves acquired are estimated to be 700 MBOE (4 Bcfe), 36% of which is oil. By virtue of this acquisition, we increased our after payout net revenue interest in the Eagle Ford Shale by an additional 15% at the time of the acquisition. Funding for the acquisition was provided through our credit facility. In addition, litigation associated with TODD was resolved as a result of the transaction.
Outlook
     The U.S. and other world economies suffered a severe recession lasting well into 2009 and economic conditions remain uncertain. These uncertain economic conditions reduced demand for oil and natural gas, resulting in a decline in oil and natural gas prices received for our production in 2009 compared with years prior to and including 2008. In 2010 and 2011 we have benefitted from increasing prices for oil, but natural gas prices remain at lower levels.
     We expect oil and natural gas prices to remain volatile in the future. Factors affecting the price of oil include worldwide economic conditions, geopolitical activities, worldwide supply disruptions, weather conditions, actions taken by the Organization of Petroleum Exporting Countries, the credit rating of U.S. government debt and the value of the U.S. dollar in international currency markets. Factors affecting the price of natural gas include U.S. economic conditions, North American weather conditions, industrial and consumer demand for natural gas, storage levels of natural gas, the credit rating of U.S. government debt and the availability and accessibility of natural gas deposits in North America. If the global economic uncertainty continues, commodity prices may be depressed for an extended period of time, which could alter our development plans and adversely affect our growth strategy and our ability to access additional funding in the capital markets.
     We have used, and expect to continue to use, oil and natural gas derivative contracts to reduce our exposure to the risks of changes in the prices of oil and natural gas. Pursuant to our risk management policy, we engage in these activities as a hedging mechanism against price volatility associated with pre-existing or anticipated sales of oil and natural gas. As of September 30, 2011, we have hedged approximately 69% of our forecasted production from proved developed reserves through 2016 at minimum average annual prices ranging from $5.50 per MMBtu to $6.35 per MMBtu and $82.62 per Bbl to $99.72 per Bbl.
     The primary factors affecting our production levels are capital availability, the success of our drilling program and our inventory of drilling prospects. In addition, we face the challenge of natural production declines. As initial reservoir pressures are depleted, production from a given well decreases. We attempt to overcome this natural decline primarily through developing our existing undeveloped reserves. Our future growth will depend on our ability to continue to add reserves in excess of production. Our ability to add reserves through drilling and other development techniques is dependent on our capital resources and can be limited by many factors, including our ability to timely obtain drilling permits and regulatory approvals. Any delays in drilling, completing or connecting our new wells to gathering lines will negatively affect our production, which will have an adverse effect on our revenues and, as a result, cash flow from operations.
Operations Update
South Louisiana
     We have drilled nine wells at Weeks Island, and executed several recompletions in Weeks Island and other South Louisiana fields, in 2011. Production was approximately 1,880 BOE per day (net to our interest) for the third quarter of 2011. We expect to continually utilize one drilling rig and one workover rig in this field through at least mid-2012.

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Eagle Ford Shale
     We are participating with Murphy Oil Corporation (“Murphy”), the operator, in a five year program that began in 2011 in which we expect to drill at least 120 wells targeting the Eagle Ford Shale in Karnes County, Texas. We currently have working interests in 21 wells in the Eagle Ford Shale, and Murphy has dedicated two drilling rigs, a fracturing team, and a coil tubing unit to the area for the next two years. We produced approximately 1,000 BOE per day (net to our interest) during September 2011.
     Drilling costs are trending lower with additional personnel and equipment committed to the area. Lease operating costs, which had been negatively impacted by the use of temporary infrastructure and equipment, are also trending lower as these are upgraded to permanent facilities.
Deep Bossier
     Our Hilltop field continues to produce a significant portion of our gas sales, principally from the Deep Bossier formation, at approximately 55 MMcf per day (net to our interest) for the third quarter of 2011. We continue to drill and recomplete in this field, in which our principal operating partner is EnCana Corporation, and to develop, test, and evaluate formations other than the Deep Bossier, such as the Buda, Knowles, and Austin Chalk. We expect to spend a total in the range of $40-45 million for development in this field in 2011. Capital expenditures for Deep Bossier-directed drilling will be lower in 2012, due to a shift in capital spending to more liquids-rich opportunities.
East Texas
     We have recently focused our efforts in the East Texas area on the Cold Springs field, with several successful recompletions in previously untested Wilcox formation sands. There are approximately 35 distinct pay zones at Cold Springs and our nearby Urbana field. These recompletions are relatively inexpensive and typically produce a high rate of return, in part reflecting the high liquids content in most zones. We have identified an extension of Cold Springs, the West Cold Springs field, and have continued field development and expansion.
     We also completed one new gas and condensate well in the Urbana field. We expect to continue development of the Cold Springs, West Cold Springs, and Urbana fields in 2012.
Results of Operations: Three Months Ended September 30, 2011 v. Three Months Ended September 30, 2010
                                 
    Three Months Ended September 30,     Increase        
    2011     2010     (Decrease)     % Change  
    ($ in thousands, except average sales price and unit costs)  
Summary Operating Information:
                               
Net Production:
                               
Natural gas (MMcf)
    8,156       6,265       1,891       30 %
Oil (MBbls)
    414       311       103       33 %
Natural gas liquids (MBbls)
    47       48       (1 )     (2 )%
Total natural gas equivalent (MMcfe)
    10,921       8,419       2,502       30 %
Average daily gas production (MMcfe per day)
    118.7       91.5       27.2       30 %
Average Sales Price:
                               
Natural gas (per Mcf) realized
  $ 4.94     $ 5.45     $ (0.51 )     (9 )%
Natural gas (per Mcf) unhedged
    4.20       4.33       (0.13 )     (3 )%
Oil (per Bbl) realized
    102.08       76.45       25.63       34 %
Oil (per Bbl) unhedged
    101.69       75.57       26.12       35 %
Natural gas liquids (per Bbl) realized (1)
    63.43       41.89       21.54       51 %
Combined (per Mcfe) realized
    7.83       7.12       .71       10 %
Hedging Activities:
                               
Realized natural gas revenue gain
  $ 5,986     $ 7,003     $ (1,017 )     (15 )%
Realized oil revenue gain
    162       273       (111 )     (41 )%
Summary Financial Information
                               
Revenues
                               
Natural gas
  $ 40,250     $ 34,153     $ 6,097       18 %
Oil
    42,213       23,794       18,419       77 %
Natural gas liquids
    3,000       2,001       999       50 %
Other revenues
    600       380       220       58 %
Unrealized gain — oil and natural gas derivative contracts
    30,101       2,712       27,389       1,010 %
 
                       
 
    116,164       63,040       53,124       84 %
 
                               
Expenses
                               
Lease and plant operating expense
    16,267       12,149       4,118       34 %
Production and ad valorem taxes
    5,728       4,015       1,713       43 %
Workover expense
    4,413       1,569       2,844       181 %
Exploration expense
    3,889       4,342       (453 )     (10 )%
Depreciation, depletion, and amortization
    23,756       17,853       5,903       33 %
Impairment expense
    5,743       416       5,327       1,281 %
Accretion expense
    484       517       (33 )     (6 )%
Loss on sale of assets
          87       (87 )   NA
General and administrative expenses
    9,659       6,020       3,639       60 %
Interest expense, net
    6,758       5,940       818       14 %
Provision for state income taxes
    75       2       73       3,650 %
 
                     
Net income
  $ 39,392     $ 10,130     $ 29,262       289 %
 
                     
Average Unit Costs per Mcfe:
                               
Lease and plant operating expense
  $ 1.49     $ 1.44     $ 0.05       3 %
Production and ad valorem taxes
    0.52       0.48       0.04       8 %
Workover expense
    0.40       0.19       0.21       111 %
Exploration expense
    0.36       0.52       (0.16 )     (31 )%
Depreciation, depletion and amortization
    2.18       2.12       0.06       3 %
General and administrative expenses
    0.88       0.72       0.16       22 %
 
(1)   We do not utilize hedges for natural gas liquids.

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  Revenues
     Natural gas revenues for the three months ended September 30, 2011 were $40.3 million, compared to $34.2 million for the same period in 2010, representing a $6.1 million or 18% increase. The increase in revenue was attributable to increased production volumes partially offset by lower realized prices during the three months ended September 30, 2011. The increase in production volumes of 1.9 Bcf resulted in increased revenue of approximately $10.3 million primarily related to new production in the Deep Bossier play (increased 2.5 Bcf) and production from the Sydson and TODD acquisitions made in the second quarter of 2011 (0.1 Bcf). These increases were offset by decreases in other fields, primarily South Louisiana properties, which decreased 0.4 Bcf. The decrease in realized prices (including hedge activity) from $5.45 per Mcf in the third quarter of 2010 to $4.94 per Mcf in the third quarter of 2011 resulted in decreased revenue of approximately $4.2 million. The price of natural gas before hedging decreased from $4.33 per Mcf in the third quarter of 2010 to $4.20 per Mcf in the third quarter of 2011.
     Oil revenues for the three months ended September 30, 2011 increased $18.4 million, or 77%, to $42.2 million from $23.8 million for the three months ended September 30, 2010. The increase in revenue was due to higher production volumes and higher realized prices. Oil production for the third quarter of 2011 increased to 414 MBbls from 311 MBbls for the same period in 2010, an increase of 33%. The increase is primarily related to new production from our Eagle Ford Shale area (71 MBbls) and to the Sydson and TODD acquisitions (19 MBbls, which excludes 9 MBbls included in the Eagle Ford Shale total mentioned above). During the three months ended September 30, 2011, our average realized oil price (including hedge activity) increased from $76.45 per Bbl in the third quarter of 2010 to $102.08 per Bbl in the comparable period of 2011. The price of oil before hedging increased from $75.57 per Bbl to $101.69 per Bbl for the comparative periods.
     Natural gas liquids revenues increased during the third quarter of 2011 to $3.0 million from $2.0 million for the third quarter of 2010. The increase was due to increased prices from $41.89 to $63.43 for the three months ended September 30, 2010 and 2011, respectively.
     Other revenues were $0.6 million during the three months ended September 30, 2011 as compared to $0.4 million during the three months ended September 30, 2010. The increase is primarily the result of an increase in income from rental of our drilling rig.
     Unrealized gain — oil and natural gas derivative contracts was $30.1 million during the three months ended September 30, 2011 as compared to $2.7 million during the same period in 2010. The significant fluctuation from period to period is due to the volatility of oil and natural gas prices and changes in our outstanding hedging contracts during these periods. In general, the majority of the gains were related to the decline in oil prices during the current quarter, which increased the unrealized value of our open derivative contracts.
Expenses
     Lease and plant operating expense increased $4.1 million in the third quarter of 2011 as compared to the third quarter of 2010, due to increased gas marketing service fees ($0.8 million), salt water disposal and transportation expenses ($0.7 million), and general operating expenditures ($2.2 million), primarily related to additional wells in production. On a unit basis, lease and plant operating expense increased from $1.44 per Mcfe to $1.49 per Mcfe for the three months ended September 30, 2010 and 2011, respectively.
     Production and ad valorem taxes increased $1.7 million, or 43%, to $5.7 million for the third quarter of 2011, as compared to $4.0 million for the third quarter of 2010. Ad valorem taxes increased $0.4 million, due to increases in asset values. The remaining increase of $1.3 million is attributable to production taxes, which increased 36%, following an increase in our revenue from products of 43%. The change in the mix of our sales toward a higher percentage of revenues from oil impacts the variance in this expense. Tax rates on oil are higher than for gas in Louisiana and Texas, where the majority of our oil and gas is produced. Oil as a percentage of product revenues increased from 40% to 49% in the third quarter of 2011 as compared to the same period in 2010.
     Workover expense increased from the third quarter of 2010 as compared to the third quarter of 2011, from $1.6 million to $4.4 million, respectively. This expense varies depending on activities in the field.
     Exploration expense includes the costs of our geology departments, costs of geological and geophysical data, delay rentals, expired leases, and dry holes. Exploration expense decreased slightly from $4.3 million for the third quarter of 2010 to $3.9 million for the third quarter of 2011.
     Depreciation, depletion and amortization increased $5.9 million to $23.8 million for the third quarter of 2011 as compared to an expense of $17.9 million for the third quarter of 2010. On a per unit basis, this expense increased from $2.12 to $2.18 per Mcfe. The rate is a function of capitalized costs of proved properties, reserves and production by field.
     Impairment expense increased from $0.4 million in the third quarter of 2010 to $5.7 million in the third quarter of 2011. This expense varies with the results of drilling, as well as with price declines and other factors which may render some projects uneconomic, resulting in impairment.
     Accretion expense is related to our obligation for retirement of oil and natural gas wells and facilities. We record these liabilities when we place the assets in service, using discounted present values of the estimated future obligation. We then record accretion of the liabilities as they approach maturity. Accretion expense was $0.5 million and $0.5 million for the third quarter of 2011 and 2010, respectively.
     General and administrative expenses increased $3.7 million for the three months ended September 30, 2011 to $9.7 million from $6.0 million for the three months ended September 30, 2010. The increase in general and administrative expenses is principally the result of increased salary and benefits expenses of $1.6 million, due to additional personnel; consulting services increased $1.4 million, primarily for fees associated with litigation, and other consulting services, including risk management and public agency fees. In addition, office expenditures increased $0.5 million, primarily due to a new office lease and annual information system license renewals. On a per unit basis, general and administrative expenses increased from $0.72 to $0.88 per Mcfe.
     Interest expense, net increased $0.8 million for the three months ended September 30, 2011 to $6.7 million from $5.9 million for the three months ended September 30, 2010, primarily due to $7.5 million in interest on our 9 5/8% senior notes issued in October 2010, and increased commitment fees and other interest of $0.4 million. This increase is partially offset by increased interest rate hedge gains of $3.8 million, due partially to a hedge gain of $0.9 million which resulted from the termination of one interest rate swap contract, and to a decline in interest rates. Interest on bank debt decreased $3.0 million due to a decrease in the amount outstanding under our credit facility, to the retirement of our $40 million subordinated debt in October 2010, and to a decline in the floating interest rate under the credit facility. Amortization of deferred loan costs also decreased $0.3 million due to the extension of the maturity date of our credit facility which was amended in May 2011.

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Results of Operations: Nine Months Ended September 30, 2011 v. Nine Months Ended September 30, 2010
                                 
    Nine Months Ended September 30,     Increase        
    2011     2010     (Decrease)     % Change  
    ($ in thousands, except average sales price and unit costs)  
Summary Operating Information:
                               
Net Production:
                               
Natural gas (MMcf)
    23,501       16,936       6,565       39 %
Oil (MBbls)
    1,138       646       492       76 %
Natural gas liquids (MBbls)
    155       87       68       78 %
Total natural gas equivalent (MMcfe)
    31,259       21,338       9,921       46 %
Average daily gas production (MMcfe per day)
    114.5       78.2       36.3       46 %
Average Sales Price:
                               
Natural gas (per Mcf) realized
  $ 4.87     $ 5.44     $ (0.57 )     (10 )%
Natural gas (per Mcf) unhedged
    4.15       4.48       (0.33 )     (7 )%
Oil (per Bbl) realized
    99.93       76.71       23.22       30 %
Oil (per Bbl) unhedged
    103.23       75.87       27.36       36 %
Natural gas liquids (per Bbl) realized (1)
    57.38       45.24       12.14       27 %
Combined (per Mcfe) realized
    7.58       6.83       0.75       11 %
Hedging Activities:
                               
Realized natural gas revenue gain
  $ 16,897     $ 16,204     $ 693       4 %
Realized oil revenue gain (loss)
    (3,756 )     549       (4,305 )     (784 )%
Summary Financial Information
                               
Revenues
                               
Natural gas
  $ 114,362     $ 92,088     $ 22,274       24 %
Oil
    113,702       49,593       64,109       129 %
Natural gas liquids
    8,900       3,944       4,956       126 %
Other revenues
    1,366       787       579       74 %
Unrealized gain — oil and natural gas derivative contracts
    25,292       25,620       (328 )     (1 )%
 
                       
 
    263,622       172,032       91,590       53 %
 
                               
Expenses
                               
Lease and plant operating expense
    44,639       29,581       15,058       51 %
Production and ad valorem taxes
    15,198       8,413       6,785       81 %
Workover expense
    8,391       4,858       3,533       73 %
Exploration expense
    12,310       8,914       3,396       38 %
Depreciation, depletion, and amortization
    66,187       39,975       26,212       66 %
Impairment expense
    16,498       2,509       13,989       558 %
Accretion expense
    1,430       932       498       53 %
Loss on sale of assets
          87       (87 )   NA
General and administrative expenses
    24,251       12,922       11,329       88 %
Interest expense, net
    23,067       14,664       8,403       57 %
(Gain) on contract settlement
    (1,285 )           (1,285 )   NA
Provision for state income taxes
    150       2       148       7,400 %
 
                       
Net income
  $ 52,786     $ 49,175     $ 3,611       7 %
 
                       
Average Unit Costs per Mcfe:
                               
Lease and plant operating expense
  $ 1.43     $ 1.39     $ 0.04       3 %
Production and ad valorem taxes
    0.49       0.39       0.10       26 %
Workover expense
    0.27       0.23       0.04       17 %
Exploration expense
    0.39       0.42       (0.03 )     (7 )%
Depreciation, depletion and amortization
    2.12       1.87       0.25       13 %
General and administrative expenses
    0.78       0.61       0.17       28 %
 
(1)   We do not utilize hedges for natural gas liquids.

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  Revenues
     Natural gas revenues for the nine months ended September 30, 2011 were $114.4 million, compared to $92.1 million for the same period in 2010, representing a $22.3 million or 24% increase. The increase in revenue was attributable to increased production volumes partially offset by lower realized prices during the nine months ended September 30, 2011. The increase in production volumes of 6.6 Bcf resulted in increased revenue of approximately $35.7 million primarily related to new production in the Deep Bossier (5.4 Bcf increase) and to the full-year effect of the Meridian acquisition in the second quarter of 2010 (1.9 Bcf increase). The decrease in realized prices (including hedge activity) from $5.44 per Mcf in the first nine months of 2010 to $4.87 per Mcf in the first nine months of 2011 resulted in decreased revenue of approximately $13.4 million. The price of gas before hedging decreased from $4.48 per Mcf in the first nine months of 2010 to $4.15 per Mcf in the first nine months of 2011.
     Oil revenues for the nine months ended September 30, 2011 increased $64.1 million, or 129%, to $113.7 million from $49.6 million for the nine months ended September 30, 2010. The increase in revenue was due to higher production volumes and higher realized prices. Oil production for the first nine months of 2011 increased to 1,138 MBbls from 646 MBbls for the same period in 2010, an increase of 76%. The increase is primarily related to the full-year effect of production from the Meridian acquisition in May 2010 (435 MBbls higher than the first nine months of 2010) and to the Sydson and TODD acquisitions in the second quarter of 2011, which increased oil production 46 MBbls. Of these increases, approximately 140 MBbls were attributable to new production in the Eagle Ford Shale area. Our average realized oil price (including hedge activity) increased from $76.71 per Bbl in the first nine months of 2010 to $99.93 per Bbl in the first nine months of 2011. The price of oil before hedging increased from $75.87 per Bbl to $103.23 per Bbl for the same comparative periods.
     Natural gas liquids revenues increased during the first nine months of 2011 to $8.9 million from $3.9 million for the first nine months of 2010. The increase was due to an increase in volume sold, from 87 MBbls to 155 MBbls, and increased prices, from $45.24 to $57.38 per Bbl for the nine months ended September 30, 2010 and 2011, respectively. The increased production is primarily related to the full-year effect of our Meridian acquisition in May 2010.
     Other revenues were $1.4 million during the nine months ended September 30, 2011 as compared to $0.8 million during the nine months ended September 30, 2010. The increase is primarily the result of increased income from rental of our drilling rig, and from sales of prospects, offset by a decrease in income from investments.
     Unrealized gain — oil and natural gas derivative contracts was $25.3 million during the nine months ended September 30, 2011 as compared to $25.6 million during the same period in 2010. Fluctuations from period to period are due to the volatility of oil and natural gas prices and changes in our outstanding hedging contracts during these periods.
  Expenses
     Lease and plant operating expense increased $15.1 million in the first nine months of 2011 as compared to the first nine months of 2010. There were increases in gas marketing service fees ($3.7 million), salt water disposal and transportation expense ($1.1 million), labor and contract services ($1.4 million), compression ($0.8 million), fuel, power and water ($0.8 million), and general operating expenditures ($7.3 million), primarily related to the full year effect of the Meridian acquisition in May 2010, as well as new wells coming online in 2011. On a unit basis, lease and plant operating expense increased from $1.39 per Mcfe to $1.43 per Mcfe for the nine months ended September 30, 2010 and 2011, respectively.
     Production and ad valorem taxes increased $6.8 million, or 81%, to $15.2 million for the first nine months of 2011, as compared to $8.4 million for the first nine months of 2010. Ad valorem taxes increased $1.3 million, due to our Meridian acquisition in May 2010 and increased taxable values of our properties. The remaining increase of $5.5 million is attributable to production taxes, which increased 75%, following an increase in our revenue from products of 63%. The change in the mix of our sales toward a higher percentage of revenues from oil impacts the variance in this expense. Tax rates on oil are higher than for gas in Louisiana and Texas, where the majority of our oil is produced. Oil as a percentage of product revenues increased from 34% to 48% in the first nine months of 2011 as compared to 2010.
     Workover expense increased from the first nine months of 2010 as compared to the first nine months of 2011, from $4.9 million to $8.4 million, respectively. This expense varies depending on activities in the field.
     Exploration expense includes the costs of our geology departments, costs of geological and geophysical data, delay rentals, expired leases, and dry holes. Exploration expense increased $3.4 million for the first nine months of 2011 to $12.3 million from $8.9 million

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for the first nine months of 2010. The increase is primarily due to an increase in dry hole expense of $5.9 million, offset by a decrease in geological expense of $3.7 million. Dry hole costs in the first nine months of 2011 included four wells with costs ranging from $1 million to $2 million each. Geological expenses decreased in the first nine months of 2011 as compared to the same period in 2010 due to the timing of purchases of seismic data.
     Depreciation, depletion and amortization increased $26.2 million to $66.2 million for the first nine months of 2011 as compared to an expense of $40.0 million for the first nine months of 2010. On a per unit basis, this expense increased from $1.87 to $2.12 per Mcfe. The rate is a function of capitalized costs of proved properties, reserves and production by field.
     Impairment expense increased from $2.5 million in the first nine months of 2010 to $16.5 million in the first nine months of 2011. This expense varies with the results of drilling, as well as with price declines which may render some projects uneconomic, resulting in impairment.
     Accretion expense is related to our obligation for retirement of oil and natural gas wells and facilities. We record these liabilities when we place the assets in service, using discounted present values of the estimated future obligation. We then record accretion of the liabilities as they approach maturity. Accretion expense was $1.4 million and $0.9 million for the first nine months of 2011 and 2010, respectively. The increase was due to the acquisition of Meridian.
     General and administrative expenses increased $11.4 million for the nine months ended September 30, 2011 to $24.3 million from $12.9 million for the nine months ended September 30, 2010. The increase in general and administrative expenses is principally the result of increased salary and benefits expenses of $5.6 million, due to additional personnel; consulting services increased $4.1 million, primarily for fees associated with litigation, and other consulting services, including risk management services. In addition, office expenditures increased $1.5 primarily due to the assumption of the Meridian office space and a new office lease and annual information system license renewals. On a unit basis, general and administrative expense increased from $0.61 to $0.78 per Mcfe.
     Interest expense, net increased $8.4 million for the nine months ended September 30, 2011 to $23.1 million from $14.7 million for the nine months ended September 30, 2010, primarily due to $22 million in interest on our 9 5/8% senior notes issued in October 2010, increased amortization of deferred loan costs of $0.7 million, and an increase of $0.7 million in commitment fees and other interest. These increases are partially offset by increased interest rate hedge gains of $7.9 million, primarily due to hedge gains of $3.7 million recorded in the first nine months of 2011 related to interest hedge contract modifications and termination of one interest rate swap contract. In addition, interest on bank debt decreased $7.1 million due to a decrease in the amount outstanding under our credit facility and to the retirement of our $40 million subordinated debt in October 2010.
     Gain on contract settlement is related to the settlement of an obligation we assumed upon the purchase of Meridian. The obligation related to underutilization of two contracted drilling rigs, as described in Note 10 of the accompanying notes to our financial statements. We recorded an estimated liability of $9.8 million for the obligation upon purchase of Meridian in 2010. The obligation was subsequently settled in the second quarter of 2011 for $8.5 million, resulting in a gain of $1.3 million.
Liquidity and Capital Resources
     Our principal requirements for capital are to fund our day-to-day operations, development activities, and to satisfy our contractual obligations, primarily for the repayment of debt and any amounts owed during the period related to our hedging positions.
     Our 2011 capital budget is primarily focused on the development of existing core areas through exploitation and development. Currently, we plan to spend a total of approximately $180 million during 2011, of which, approximately $133 million has been expended or accrued through September 30, 2011. Approximately 83% of our 2011 capital budget is allocated to our properties in Deep Bossier, East Texas, the Eagle Ford Shale, and South Louisiana. Our future drilling plans, plans of our drilling operators and capital budgets are subject to change based upon various factors, some of which are beyond our control, including drilling results, oil and natural gas prices, the availability and cost of capital, drilling and production costs, availability of drilling services and equipment, actions of our operators, gathering system and pipeline transportation constraints and regulatory approvals. Because a large percentage of our acreage is held by production, we have the ability to materially decrease our drilling and recompletion budget in response to market conditions with minimal risk of losing significant acreage.
     We expect to fund the remainder of our 2011 capital budget predominantly with cash flows from operations, supplemented by use of our credit facility. If necessary, we may also access capital through proceeds from potential asset dispositions, and the future

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issuance of debt and/or equity securities, subject to the distribution of proceeds therefrom as set forth in our partnership agreement. We strive to maintain financial flexibility and may access capital markets as necessary to maintain substantial borrowing capacity under our senior secured revolving credit facility, facilitate drilling on our large undeveloped acreage position and permit us to selectively expand our acreage position. In the event our cash flows are materially less than anticipated and other sources of capital we historically have utilized are not available on acceptable terms, we may curtail our capital spending.
     Senior Notes
     In October 2010, we adjusted our capital structure by issuing $300 million of 9 5/8% senior notes due 2018 (“senior notes”). The senior notes were issued at a discount of $2.1 million, bringing the effective rate to 9 3/4%.
     The senior notes are unsecured senior general corporate obligations, and effectively rank junior to any of our existing or future secured indebtedness, which includes our credit facility. The senior notes are unconditionally guaranteed on a senior unsecured basis by each of our material, wholly owned subsidiaries. We entered into a registration rights agreement with the purchasers of the senior notes. We filed a registration statement with the SEC to allow for registration of “exchanges notes” substantially identical to the senior notes. On August 12, 2011, the exchange notes were exchanged for the original senior notes tendered in connection with the exchange offer.
Credit Facility
     We have a senior secured revolving credit facility (“credit facility”) with Wells Fargo Bank, N.A. as the administrative agent. As of September 30, 2011, the credit facility was subject to a $260 million borrowing base limit, and we had $173.8 million outstanding under the credit facility. Our restricted subsidiaries are guarantors of the credit facility.
     In November 2011, the borrowing base was increased to $325 million. The borrowing base is redetermined each May 1 and November 1. As of November 14, 2011, the available unused portion of the borrowing base is $136.2 million.
     Our credit facility provides for two alternative interest rate bases and margins. Eurodollar loans accrue interest generally at the one-month London Interbank Offered Rate plus a margin ranging from 2.00% to 2.75%, depending on the utilization of our borrowing base. “Reference rate” loans accrue interest at the prime rate of Wells Fargo Bank, N.A., plus a margin ranging from 1.00% to 1.75%, depending on the utilization of our borrowing base. The total rate on all loans outstanding as of September 30, 2011 under the credit facility was 2.615%, which was based on the Eurodollar option.
     The credit facility and senior notes include covenants requiring us to maintain certain financial covenants including a current ratio, leverage ratio, and interest coverage ratio. At September 30, 2011, we were in compliance with the covenants. The terms of the credit facility also restrict our ability to make distributions and investments.
Cash flow provided by operating activities
     Operating activities provided cash of $115.4 million during the nine months ended September 30, 2011 as compared to $37.2 million during the comparable period in 2010. The $78.2 million increase in operating cash flows was attributable to an increase in the cash-based portions of our earnings, as well as changes in working capital accounts. Cash-based items of net income, including revenues (exclusive of unrealized commodity gains or losses), operating expenses and taxes, general and administrative expenses, and the cash portion of our interest expense, provided a net increase of approximately $48 million in earnings and a related positive impact on cash flow. Augmenting this were changes in our working capital accounts, which used $0.7 million of cash flows as compared to having used $30.9 million of cash in 2010. This reversal resulted in a total increase of $30.2 million in cash flow, which as noted above, augments the positive effects of increased cash-based earnings.
Cash flow used in investing activities
     Investing activities used cash of $214.6 million during the nine months ended September 30, 2011 as compared to cash used in investing of $167.7 million during the comparable period of 2010. A decrease in cash used in acquisition activities of $34.8 million was due to the $101.4 million invested in the Meridian acquisition in the second quarter of 2010. Acquisitions in the first nine months of 2011 were $66.6 million, primarily for the additional interests in legacy Meridian properties acquired from Sydson and TODD. The total cash purchase price of these two acquisitions was approximately $50 million. See Note 3 of the accompanying financial statements for further information. Aside from the acquisitions, investment in property and equipment increased by $81.7 million as compared to the prior year period, primarily related to development activities in our Deep Bossier, Eagle Ford Shale, South Louisiana, and East Texas area properties.

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Cash flow provided by financing activities
     Financing activities provided cash of $98.9 million during the nine months ended September 30, 2011 as compared to cash provided by financing of $136.3 million during the nine months ended September 30, 2010. The decrease is due primarily to the capital infusion of $50 million in the first half of 2010 provided by our private equity partner, which partially funded the Meridian acquisition. Cash from financing activities in the first nine months of 2011 included drawdowns on our credit facility of $101 million, of which approximately $50 million was directly used for the Sydson and TODD acquisitions.
ITEM 3. Quantitative and Qualitative Disclosures about Market Risk
     For information regarding our exposure to certain market risks, see “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Quantitative and Qualitative Disclosures about Market Risk,” “—Commodity Price Risk and Hedges” and “—Interest Rates” in the Form S-4. There have been no material changes to the disclosure regarding market risks.
ITEM 4. Controls and Procedures
Evaluation of Disclosure Controls and Procedures
     In accordance with Exchange Act Rule 13a-15 and 15d-15, we carried out an evaluation, under the supervision and with the participation of management, including our Chief Executive Officer and our Chief Financial Officer, of the effectiveness of our disclosure controls and procedures as of the end of the period covered by this report. Based on that evaluation, our Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures were effective as of September 30, 2011 to provide reasonable assurance that information required to be disclosed in our reports filed or submitted under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the Securities and Exchange Commission’s rules and forms. Our disclosure controls and procedures include controls and procedures designed to ensure that information required to be disclosed in reports filed or submitted under the Exchange Act is accumulated and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosure.
Changes in Internal Control Over Financial Reporting
     There has been no change in our internal control over financial reporting during the three months ended September 30, 2011 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.
PART II — OTHER INFORMATION
ITEM 1. Legal Proceedings
     See Part I, Item 1, Note 10 to our consolidated financial statements entitled “Commitments and Contingencies,” which is incorporated in this item by reference.
ITEM 1A. Risk Factors
     We are subject to certain risks and hazards due to the nature of the business activities we conduct. For a discussion of these risks, see “Risk Factors” in the Form S-4. There have been no material changes with respect to the risk factors disclosed in the Form S-4 during the quarter ended September 30, 2011.
ITEM 2. Unregistered Sales of Equity Securities and Use of Proceeds
     None.
ITEM 3. Defaults Upon Senior Securities
     None.
ITEM 4. (Removed and Reserved)
ITEM 5. Other Information
     None.

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ITEM 6. Exhibits
         
  10.1    
Amendment No. 4 to Sixth Amended and Restated Credit Agreement by and among Alta Mesa Holdings, LP, Wells Fargo Bank, N.A., as administrative agent, and the lenders party thereto from time to time, dated as of November 7, 2011.
 
  31.1    
Certification of the Company’s Chief Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 (18 U.S.C. Section 7241).
       
 
  31.2    
Certification of the Company’s Chief Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 (18 U.S.C. Section 7241).
       
 
  32.1    
Certification of the Company’s Chief Executive Officer Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (18 U.S.C. Section 1350).
       
 
  32.2    
Certification of the Company’s Chief Financial Officer Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (18 U.S.C. Section 1350).
       
 
  *101    
Interactive Data Files.
 
*   Pursuant to Rule 406T of Regulation S-T, these interactive data files are deemed not filed or part of a registration statement or prospectus for purposes of Sections 11 or 12 of the Securities Act of 1933, as amended, or Section 18 of the Securities Exchange Act of 1934, as amended, and otherwise are not subject to liability.

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SIGNATURES
     Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned hereunto duly authorized.
             
    ALTA MESA HOLDINGS, LP    
    (Registrant)    
 
           
 
  By:   ALTA MESA HOLDINGS GP, LLC, its    
 
      general partner    
 
           
November 14, 2011
  By:   /s/ Harlan H. Chappelle
 
   
 
      Harlan H. Chappelle    
 
      President and Chief Executive Officer    
 
           
November 14, 2011
  By:   /s/ Michael A. McCabe
 
   
 
      Michael A. McCabe    
 
      Vice President and Chief Financial Officer    

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