10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, DC 20549

FORM 10-Q

(Mark One)

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

For the quarterly period ended: June 30, 2012

OR

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

For the transition period from            to            

Commission file number: 333-173751

ALTA MESA HOLDINGS, LP

(Exact name of registrant as specified in its charter)

Texas	20-3565150
(State or other jurisdiction of incorporation or organization)	(I.R.S. Employer Identification No.)
15021 Katy Freeway, Suite 400, Houston, Texas	77094
(Address of principal executive offices)	(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  x    No  ¨

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted 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  x    No  ¨

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See definition of “large accelerated filer,” “accelerated filer,” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one)

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

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

Table of Contents

	Page Number
PART I — FINANCIAL INFORMATION
Item 1. Financial Statements		3
Consolidated Balance Sheets as of June 30, 2012 (unaudited) and December 31, 2011		3
Consolidated Statements of Income (unaudited) for the Three and Six Months Ended June  30, 2012 and 2011		4
Consolidated Statements of Cash Flows (unaudited) for the Six Months Ended June 30, 2012 and 2011		5
Notes to Consolidated Financial Statements (unaudited)		6
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations		19
Item 3. Quantitative and Qualitative Disclosures about Market Risk		30
Item 4. Controls and Procedures		30
PART II — OTHER INFORMATION
Item 1. Legal Proceedings		30
Item 1A. Risk Factors		30
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds		30
Item 3. Defaults Upon Senior Securities		30
Item 4. Mine Safety Disclosures		30
Item 5. Other Information		30
Item 6. Exhibits		31
Signatures		32

2

PART I — FINANCIAL INFORMATION

ITEM 1. Financial Statements

ALTA MESA HOLDINGS, LP AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(dollars in thousands)

	June 30, 2012		December 31, 2011
	(unaudited)
ASSETS
CURRENT ASSETS
Cash and cash equivalents	$	10,043	$	2,630
Accounts receivable, net		31,343		40,807
Other receivables		3,974		2,806
Prepaid expenses and other current assets		8,578		5,394
Derivative financial instruments		41,289		28,582
TOTAL CURRENT ASSETS		95,227		80,219
PROPERTY AND EQUIPMENT
Oil and natural gas properties, successful efforts method, net		638,029		572,816
Other property and equipment, net		16,297		16,351
TOTAL PROPERTY AND EQUIPMENT, NET		654,326		589,167
OTHER ASSETS
Investment in Partnership — cost		9,000		9,000
Deferred financing costs, net		11,783		12,802
Derivative financial instruments		29,423		24,244
Advances to operators		2,939		3,625
Deposits and other assets		1,089		1,026
TOTAL OTHER ASSETS		54,234		50,697
TOTAL ASSETS	$	803,787	$	720,083
LIABILITIES AND PARTNERS’ CAPITAL
CURRENT LIABILITIES
Accounts payable and accrued liabilities	$	88,676	$	70,295
Current portion, asset retirement obligations		2,201		3,030
Derivative financial instruments		244		1,300
TOTAL CURRENT LIABILITIES		91,121		74,625
LONG-TERM LIABILITIES
Asset retirement obligations, net of current portion		43,941		43,066
Long-term debt		520,166		487,036
Notes payable to founder		21,514		20,911
Derivative financial instruments		—		57
Other long-term liabilities		2,111		4,716
TOTAL LONG-TERM LIABILITIES		587,732		555,786
TOTAL LIABILITIES		678,853		630,411
COMMITMENTS AND CONTINGENCIES (NOTE 10)
PARTNERS’ CAPITAL		124,934		89,672
TOTAL LIABILITIES AND PARTNERS’ CAPITAL	$	803,787	$	720,083

See notes to consolidated financial statements.

3

ALTA MESA HOLDINGS, LP AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF INCOME

(dollars in thousands)

(unaudited)

	Three Months Ended June 30,						Six Months Ended June 30,
	2012			2011			2012			2011
REVENUES
Natural gas	$	26,341		$	38,731		$	51,880		$	74,112
Oil		53,054			39,292			102,784			71,489
Natural gas liquids		4,470			2,847			7,537			5,900
Other revenues		686			297			1,384			766
		84,551			81,167			163,585			152,267
Unrealized gain (loss) — oil and natural gas derivative contracts		24,306			14,377			17,911			(4,808	)
TOTAL REVENUES		108,857			95,544			181,496			147,459
EXPENSES
Lease and plant operating expense		17,196			15,041			33,114			28,372
Production and ad valorem taxes		5,853			4,069			12,083			9,470
Workover expense		2,683			2,352			3,936			3,978
Exploration expense		2,034			5,690			4,063			8,421
Depreciation, depletion, and amortization expense		25,121			22,963			49,014			42,431
Impairment expense		2,710			4,929			4,462			10,755
Accretion expense		441			476			881			946
General and administrative expenses		12,414			8,843			20,383			14,593
TOTAL EXPENSES		68,452			64,363			127,936			118,966
INCOME FROM OPERATIONS		40,405			31,181			53,560			28,493
OTHER INCOME (EXPENSE)
Interest expense		(9,817	)		(6,843	)		(19,588	)		(16,323	)
Interest income		23			12			40			14
Litigation settlement		1,250			—			1,250			—
Gain on contract settlement		—			1,285			—			1,285
TOTAL OTHER INCOME (EXPENSE)		(8,544	)		(5,546	)		(18,298	)		(15,024	)
INCOME BEFORE STATE INCOME TAXES		31,861			25,635			35,262			13,469
(PROVISION FOR) STATE INCOME TAXES		—			(75	)		—			(75	)
NET INCOME	$	31,861		$	25,560		$	35,262		$	13,394

See notes to consolidated financial statements.

4

ALTA MESA HOLDINGS, LP AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(dollars in thousands)

(unaudited)

	Six Months Ended June 30,
	2012			2011
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$	35,262		$	13,394
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion, and amortization expense		49,014			42,431
Impairment expense		4,462			10,755
Accretion expense		881			946
Amortization of loan costs		1,137			1,694
Amortization of debt discount		130			130
Dry hole expense		1,222			5,267
Unrealized (gain) loss on derivatives		(18,999	)		4,300
(Gain) on contract settlement		—			(1,285	)
Interest converted into debt		603			600
Settlement of asset retirement obligation		(1,161	)		(246	)
Changes in assets and liabilities:
Accounts receivable		9,464			(3,428	)
Other receivables		(1,168	)		4,391
Prepaid expenses and other non-current assets		(2,561	)		(6,344	)
Accounts payable, accrued liabilities, and other long-term liabilities		10,203			(1,455	)
NET CASH PROVIDED BY OPERATING ACTIVITIES		88,489			71,150
CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures for property and equipment		(96,072	)		(94,139	)
Acquisitions		(17,886	)		(61,235	)
NET CASH USED IN INVESTING ACTIVITIES		(113,958	)		(155,374	)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from long-term debt		38,000			86,500
Repayments of long-term debt		(5,000	)		—
Additions to deferred financing costs		(118	)		(1,589	)
NET CASH PROVIDED BY FINANCING ACTIVITIES		32,882			84,911
NET INCREASE IN CASH		7,413			687
CASH AND CASH EQUIVALENTS, beginning of period		2,630			4,836
CASH AND CASH EQUIVALENTS, end of period	$	10,043		$	5,523
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION
Cash paid during the period for interest	$	19,070		$	16,484
Cash paid during the period for taxes	$	230		$	—
Change in asset retirement obligations	$	235		$	325
Asset retirement obligations assumed, purchased properties	$	91		$	2,504
Change in accruals or liabilities for capital expenditures	$	5,573		$	(12,170	)

See notes to consolidated financial statements.

5

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, 2011, which were filed with the Securities and Exchange Commission in our Annual Report on Form 10-K (the “2011 Form 10-K”).

The consolidated financial statements included herein as of June 30, 2012, and for the six month periods ended June 30, 2012 and 2011, 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, Alta Mesa Services, LP, AM Idaho LLC, and Alabama Energy Resources LLC, 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 onshore oil and natural gas properties. Our core properties are located primarily in Texas, Louisiana, and Oklahoma.

2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

As of June 30, 2012, our significant accounting policies are consistent with those discussed in Note 2 of the consolidated financial statements for the fiscal year ended December 31, 2011.

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.

6

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 $635,000 and $557,000 at June 30, 2012 and December 31, 2011, 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 June 30, 2012 and 2011, amortization of deferred financing costs included in interest expense amounted to $570,000 and $790,000, respectively. For the six months ended June 30, 2012 and 2011, amortization of deferred financing costs included in interest expense amounted to $1.1 million and $1.7 million, respectively. Deferred financing costs are listed among our long-term assets, net of accumulated amortization of $8.6 million and $7.5 million at June 30, 2012 and December 31, 2011, respectively.

7

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 (“credit facility”) is not considered to be materially different from carrying value due to market rates of interest. The fair value of the notes payable to our founder is not practicable to determine. We have estimated the fair value of our senior notes due 2018 (“senior notes”) at $297 million and $293 million on June 30, 2012 and December 31, 2011, 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 December 2011, the FASB issued ASU No. 2011-11, which increases disclosures about offsetting assets and liabilities. New disclosures are required to enable users of financial statements to understand significant quantitative differences in balance sheets prepared under GAAP and International Financial Reporting Standards (IFRS) related to the offsetting of financial instruments. The existing GAAP guidance allowing balance sheet offsetting, including industry-specific guidance, remains unchanged. The guidance in ASU No. 2011-11 is effective for annual and interim reporting periods beginning on or after January 1, 2013. The disclosures should be applied retrospectively for all prior periods presented. We do not expect the adoption of this amendment to have a material impact on our consolidated financial statements.

We adopted ASU No. 2011-04 to Topic 820, Fair Value Measurements, “Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in U.S. GAAP and IFRS” on January 1, 2012. The ASU changes certain definitions of terms used in its guidance regarding fair value measurements, as well as modifying certain disclosure requirements and other aspects of the guidance. The additional disclosure is included in Note 5.

3. SIGNIFICANT ACQUISITIONS

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). 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.

8

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). 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 preliminary allocations of the purchase prices are as follows (dollars in thousands):

Summary of Consideration:	Sydson		TODD
Cash	$	27,500	$	22,500
Fair value of asset retirement obligations assumed		922		863
Total	$	28,422	$	23,363
Summary of Purchase Price Allocations:
Proved oil and natural gas properties	$	18,330	$	15,223
Unproved oil and natural gas properties		10,092		8,140
Total	$	28,422	$	23,363

The revenue and earnings related to the Sydson and TODD acquisitions are included in our consolidated statement of income for the six months ended June 30, 2012. Revenue and earnings, had the acquisitions occurred on January 1, 2011, 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)
Pro forma results for the combined entity for the six months ended June 30, 2011	$	150,653	$	15,347

9

4. PROPERTY AND EQUIPMENT

Property and equipment consists of the following:

	June 30, 2012			December 31, 2011
	(unaudited)
	(dollars in thousands)
OIL AND NATURAL GAS PROPERTIES
Unproved properties	$	45,571		$	34,797
Accumulated impairment		(7,175	)		(5,427	)
Unproved properties, net		38,396			29,370
Proved oil and natural gas properties		1,032,233			925,578
Accumulated depreciation, depletion, amortization and impairment		(432,600	)		(382,132	)
Proved oil and natural gas properties, net		599,633			543,446
TOTAL OIL AND NATURAL GAS PROPERTIES, net		638,029			572,816
LAND		1,185			1,185
DRILLING RIG		10,500			10,500
Accumulated depreciation		(1,487	)		(1,137	)
TOTAL DRILLING RIG, net		9,013			9,363
OTHER PROPERTY AND EQUIPMENT
Office furniture and equipment, vehicles		8,519			7,313
Accumulated depreciation		(2,420	)		(1,510	)
OTHER PROPERTY AND EQUIPMENT, net		6,099			5,803
TOTAL PROPERTY AND EQUIPMENT, net	$	654,326		$	589,167

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 reliable. 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, which is a Level 1 determination.

Oil and natural gas properties are subject to impairment testing and potential impairment write down. Oil and gas properties with a carrying amount of $12.4 million were written down to their fair value of $7.9 million, resulting in an impairment charge of $4.5 million for the six months ended June 30, 2012. Oil and gas properties with a carrying amount of $24.4 million were written down to their fair value of $13.6 million, resulting in an impairment charge of $10.8 million for the six months ended June 30, 2011. For the three months ended June 30, 2012, oil and gas properties with a carrying amount of $8.9 million were written down to their fair value of $6.2 million, resulting in an impairment charge of $2.7 million, and for the three months ended June 30, 2011, oil and gas properties with a carrying amount of $14.2 million were written down to their fair value of $9.3 million, resulting in an impairment charge of $4.9 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.

10

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.

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 plugging and abandonment of wells and facilities. We recorded $0.3 million and $2.8 million in additions to asset retirement obligations measured at fair value during the six months ended June 30, 2012 and 2011, respectively.

The following table presents information about our financial assets and liabilities measured at fair value on a recurring basis as of June 30, 2012 and December 31, 2011, 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 June 30, 2012 (unaudited):
Financial Assets:
Derivative contracts for oil and natural gas		—	$	117,241		—	$	117,241
Financial Liabilities:
Derivative contracts for oil and natural gas		—	$	46,561		—	$	46,561
Derivative contracts for interest rate		—	$	212		—	$	212
At December 31, 2011:
Financial Assets:
Derivative contracts for oil and natural gas		—	$	109,138		—	$	109,138
Financial Liabilities:
Derivative contracts for oil and natural gas		—	$	56,369		—	$	56,369
Derivative contracts for interest rate		—	$	1,300		—	$	1,300

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 our 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, or in the case of financial basis hedging contracts, based on a designated price differential between various benchmark prices. Cash settlement occurs monthly. 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 income at each reporting date. Realized gains and losses on commodities hedging contracts are included in oil and natural gas revenues.

We have entered into an interest rate swap agreement to mitigate the risk of loss due to changes in interest rates. The interest rate swap is not designated as a cash flow hedge 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 swap contract 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 six month periods ended June 30, 2012 and 2011.

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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 June 30, 2012
	Current asset portion of Derivative financial instruments			Current liability portion of Derivative financial instruments			Long-term asset portion of Derivative financial instruments			Long-term liability portion of Derivative financial instruments
	(unaudited)
	(dollars in thousands)
Fair value of oil and gas commodity contracts, assets	$	65,114		$	—		$	52,127		$	—
Fair value of oil and gas commodity contracts, (liabilities)		(23,825	)		(32	)		(22,704	)		—
Fair value of interest rate contracts, (liabilities)		—			(212	)		—			—
Total net assets, (liabilities)	$	41,289		$	(244	)	$	29,423		$	—

Fair Values of Derivative Contracts

	Balance Sheet Location at December 31, 2011
	Current asset portion of Derivative financial instruments			Current liability portion of Derivative financial instruments			Long-term asset portion of Derivative financial instruments			Long-term liability portion of Derivative financial instruments
	(dollars in thousands)
Fair value of oil and gas commodity contracts, assets	$	56,716		$	—		$	52,422		$	—
Fair value of oil and gas commodity contracts, (liabilities)		(28,134	)		—			(28,178	)		(57	)
Fair value of interest rate contracts, (liabilities)		—			(1,300	)		—			—
Total net assets, (liabilities)	$	28,582		$	(1,300	)	$	24,244		$	(57	)

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 income:

Derivatives not designated as hedging	Location of Gain	Classification of	For the three months ended June 30,				For the six months  ended June 30,
instruments under ASC 815	(Loss)	Gain (Loss)	2012		2011		2012		2011
			(unaudited)				(unaudited)
			(dollars in thousands)
Natural gas commodity contracts	Natural gas revenues	Realized	$	11,089	$	5,120	$	19,629	$	10,911
Oil commodity contracts	Oil revenues	Realized		619		(2,434)		(790)		(3,918)
Interest rate contracts	Interest benefit (expense)	Realized		(564)		2,298		(1,126)		1,928
Total realized gains (losses) from derivatives not designated as hedges			$	11,144	$	4,984	$	17,713	$	8,921
Natural gas commodity contracts	Unrealized gain (loss) — oil and natural gas derivative contracts	Unrealized	$	(13,667)	$	1,659	$	(5,881)	$	(1,299)
Oil commodity contracts	Unrealized gain (loss) — oil and natural gas derivative contracts	Unrealized		37,973		12,718		23,792		(3,509)
Interest rate contracts	Interest benefit (expense)	Unrealized		561		465		1,088		508
Total unrealized gains (losses) from derivatives not designated as hedges			$	24,867	$	14,842	$	18,999	$	(4,300)

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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.

We had the following open derivative contracts for natural gas at June 30, 2012 (unaudited):

NATURAL GAS DERIVATIVE CONTRACTS

	Volume in		Weighted		Range
Period and Type of Contract	MMbtu		Average		High		Low
2012
Price Swap Contracts		8,405,000	$	4.79	$	8.83	$	3.06
Collar Contracts
Short Call Options		4,940,000		5.53		6.00		4.50
Long Put Options		3,866,000		5.09		6.75		4.00
Long Call Options		2,760,000		4.67		5.00		4.00
Short Put Options		6,986,000		3.44		4.50		2.50
2013
Price Swap Contracts		19,400,000		4.75		9.15		3.30
Collar Contracts
Short Call Options		1,825,000		5.25		5.25		5.25
Long Put Options		1,500,000		6.09		6.15		6.00
Long Call Options		3,625,000		5.87		7.00		4.75
Short Put Options		18,748,500		3.18		5.00		3.00
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		2,623,500		4.14		5.50		3.00
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

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We had the following open derivative contracts for crude oil at June 30, 2012 (unaudited):

OIL DERIVATIVE CONTRACTS

			Weighted		Range
Period and Type of Contract	Volume in Bbls		Average		High		Low
2012
Price Swap Contracts		266,800	$	114.10	$	121.15	$	80.20
Collar Contracts
Short Call Options		753,398		116.56		132.00		90.00
Long Put Options		736,000		97.53		105.00		65.00
Long Call Options		151,350		99.25		123.50		80.20
Short Put Options		967,100		77.09		85.00		68.75
2013
Price Swap Contracts		392,000		89.75		94.74		77.00
Collar Contracts
Short Call Options		998,660		118.03		134.00		90.00
Long Put Options		1,273,500		108.35		115.00		85.00
Long Call Options		197,475		94.14		127.00		79.00
Short Put Options		1,538,500		80.85		90.00		60.00
2014
Price Swap Contracts		255,050		96.57		105.48		81.00
Collar Contracts
Short Call Options		273,750	$	125.70	$	133.50	$	107.50
Long Put Options		670,950		89.32		100.00		80.00
Short Put Options		777,530		70.78		80.00		60.00
2015
Price Swap Contracts		401,500		99.30		99.30		99.30
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
Price Swap Contracts		292,800		94.95		95.00		94.90
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

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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 natural gas at June 30, 2012 (unaudited):

Volume in MMbtu	Reference Price 1 (1)		Reference Price 2 (1)		Period		Spread ($ per MMbtu)
920,000		NYMEX Henry Hub		Houston Ship Channel		July ’12 —Dec ’12	$	0.1575
1,840,000		NYMEX Henry Hub		Houston Ship Channel		July ’12 —Dec ’12	$	0.1400
3,650,000		NYMEX Henry Hub		Houston Ship Channel		Jan ’13 — Dec ’13	$	0.0625

⁽¹⁾ The spread in these trades limits the differential of the settlement quotation prices for NYMEX Henry Hub over the Houston Ship Channel index published in Inside FERC.

We had the following open financial basis swap contracts for oil at June 30, 2012 (unaudited):

Volume in Bbl	Reference Price 1  (2)		Reference Price 2  (2)		Period		Average Spread ($ per  Bbl)
828,000		Brent IPE		Argus Louisiana Light Sweet		July ’12 —Dec ’12	$	1.92
1,277,500		Brent IPE		Argus Louisiana Light Sweet		Jan ’13 — Dec ’13	$	3.09

⁽²⁾  The spread in these trades limits the differential of the settlement quotation prices for Brent IPE over Argus Louisiana Light Sweet crude.

We had the following open interest rate swap contract at June 30, 2012 (unaudited):

Term	Principal Amount		Interest Rate (3)
	(dollars in thousands)
Floating to Fixed Rate Swap:
July 2012 — August 2012	$	50,000		4.95	%

(3) 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, 2011	$	46,096
Liabilities incurred		235
Liabilities assumed with acquired producing properties		91
Liabilities settled		(1,161	)
Accretion expense		881
Balance, June 30, 2012		46,142
Less: Current portion		2,201
Long term portion	$	43,941

8. LONG-TERM DEBT AND NOTES PAYABLE TO FOUNDER

Long-term debt consists of the following:

	June 30, 2012		December 31, 2011
	(unaudited)
	(dollars in thousands)
Senior Debt — On May 13, 2010, we entered a Sixth Amended and Restated Credit Agreement (as amended, the “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 June 30, 2012, the borrowing base under the facility was $350 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 2.5% as of June 30, 2012 and 2.774% as of December 31, 2011.	$	221,790	$	188,790
Senior Notes due 2018 — On October 13, 2010, we issued senior 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 $1.6 million and $1.8 million at June 30, 2012 and December 31, 2011, respectively.		298,376		298,246
Total long-term debt	$	520,166	$	487,036

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 June 30, 2012, 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 $21.5 million and $20.9 million at June 30, 2012 and December 31, 2011, 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 $603,000 and $600,000 for the six months ended June 30, 2012 and 2011, respectively, and $302,000 and $302,000 for the three months ended June 30, 2012 and 2011, 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:

	June 30, 2012		December 31, 2011
	(unaudited)
	(dollars in thousands)
Capital expenditures	$	28,513	$	19,119
Revenues and royalties payable		7,329		6,742
Operating expenses/taxes		21,794		21,147
Compensation		8,175		3,567
Acquisition costs payable		3,846		2,883
Other		6,445		5,754
Total accrued liabilities		76,102		59,212
Accounts payable		12,574		11,083
Accounts payable and accrued liabilities	$	88,676	$	70,295

10. COMMITMENTS AND CONTINGENCIES

Contingencies

Hilltop Field Litigation: On July 23, 2009, we made a payment of $25.5 million and took assignment of substantially all working interests that Chesapeake Energy Corporation (“Chesapeake”) had acquired from Gastar Exploration Ltd. (“Gastar”) in an approximate 50,000 acre area of Leon and Robertson Counties, Texas known as the Hilltop Field, in which the Deep Bossier formation was the principal focus for development. We had exercised our preferential right to purchase these interests from Gastar in late 2005, but Gastar and Chesapeake had opposed this and Chesapeake took record title at that time. We finally and conclusively prevailed when, 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 review the appeal. As a result, we were able to take assignment of 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 had pursued other claims against Chesapeake and Gastar; Chesapeake claimed an additional $36.3 million of past expenses. The case was set for trial on April 24, 2012. Shortly before the trial was to begin, we reached an agreement in principle to settle with the Chesapeake-related defendants. We also entered into a settlement agreement with Gastar. The effects of these settlements, recorded in the second quarter of 2012, were not material to our financial position or results of operations.

Environmental claims: Management has established a liability for soil contamination in Florida of $1.0 million at June 30, 2012 and $990,000 at December 31, 2011, 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 The Meridian Resource Corporation and its subsidiaries (“Meridian”), which we acquired in 2010, 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 June 30, 2012.

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.

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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 a contingent commitment to pay an amount up to a maximum of approximately $2.9 million for properties acquired in 2008. The additional purchase consideration will be paid if certain product price conditions are met.

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 our capital partner, Alta Mesa Investment Holdings, Inc. (“AMIH”), was admitted to the partnership as the sole Class B limited partner (“Class B Partner”). AMIH is an affiliate of Denham Commodity Partners Fund IV LP (“DCPF IV”). DCPF IV is advised by Denham Capital Management LP, a private equity firm focused on energy and commodities.

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 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.

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 the indenture that governs 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, 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 June 30, 2012, 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 Annual Report on Form 10-K for the year ended December 31, 2011 (“2011 Form 10-K”). The historical financial information discussed below in this Management’s Discussion and Analysis of Financial Condition and Results of Operations represents Alta Mesa’s financial information for the periods indicated, giving effect to 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, including the Hilltop field, Oklahoma, 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

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 were estimated at the date of purchase to be 800 MBOE (5 Bcfe), 45% of which was 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 were estimated at the date of purchase to be 700 MBOE (4 Bcfe), 36% of which was 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

Natural gas prices declined significantly during 2011 and the first half of 2012, closing at $2.77 for the July 2012 NYMEX Henry Hub Futures contract settled June 29, 2012. The reduction in prices has been caused by many factors, including recent increases in North American natural gas production, warmer than normal winter weather and high levels of natural gas in storage. Prices for oil and natural gas liquids did not significantly decline in 2011 but decreased in the second quarter of 2012, with the NYMEX West Texas Intermediate crude oil futures contract for July 2012 closing at $81.80 on June 30, 2012.

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We have hedged approximately 89% of our forecasted PDP production through 2016 at prices higher than those currently prevailing for natural gas. However, if prices for natural gas remain depressed for long periods, we may be required to write down the value of our oil and natural gas properties or revise our development plans, which may cause certain of our undeveloped well locations to no longer be deemed proved. In addition, sustained low prices for natural gas will reduce the amounts we would otherwise have available to pay expenses and service our debt obligations.

If low natural gas prices continue for an extended period of time, we may be unable to hedge additional natural gas production at favorable prices. This could cause us to change our development plans for our natural gas properties and shut–in natural gas production, and may result in an impairment in the value of our natural gas properties, a reduction in the borrowing base under our credit facility and reduce our cash available for distribution and for servicing our indebtedness.

Oil prices decreased during the second quarter of 2012 and remain unstable. We expect oil prices to remain volatile in the future. Factors affecting the price of oil include worldwide economic conditions, including the European credit crisis, geopolitical activities, including developments in the Middle East, worldwide supply disruptions, weather conditions, actions taken by the Organization of Petroleum Exporting Countries and the value of the U.S. dollar in international currency markets.

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, enhanced completions and well recompletions, and other enhanced recovery methods. 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

At Weeks Island, our largest oilfield, we drilled and completed seven successful oil wells in the first half of 2012; of these, four were in production, two were awaiting pipeline tie-in, and one was not yet on production, as of June 30, 2012. We were also in the process of drilling two wells at Weeks Island as of the end of the second quarter having initiated a two-rig drilling program near the end of the second quarter. We expect to continually utilize two drilling rigs and one to two workover rigs in this field through the end of 2012, and at least one drilling rig through mid-2013. Production from Weeks Island was approximately 2,000 BOE per day (net to our interest, 88% oil) for the first half of 2012, and 2,200 BOE per day for the second quarter, as compared to 1,700 BOE per day for the first quarter.

In our Ramos Field, we successfully recompleted the Thibodaux #3 well, and brought it online in late June 2012 and it is producing at a rate of approximately 6.4 Mmcf/day and 300 barrells of natural gas liquids per day.

Total production net to our interest from all of our properties in South Louisiana for the first half of 2012 was 461 MBbl’s (including NGL’s) and 3.3 Bcf of natural gas.

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East Texas/Hilltop

Our Hilltop field in Leon and Robertson Counties continues to produce a significant portion of our gas sales, principally from the Deep Bossier formation, at approximately 33 MMcf per day (net to our interest) for the first half of 2012. We have focused our efforts on liquids-rich targets and chosen to delay further investments in the historically prolific Deep Bossier natural gas play. We continue to develop, test, and evaluate formations other than the Deep Bossier, such as the Buda, Knowles, Woodbine, Eagle Ford and Austin Chalk. During the first half of 2012, we participated with EnCana in the completion of three oil wells in the Woodbine formation. We also completed our first operated well in Hilltop, a successful horizontal oil well in the Austin Chalk formation, and drilled a vertical well which we intend to complete as an oil well in the Lower Woodbine formation.

Our other interests in East Texas are principally in San Jacinto, Montgomery, and Polk Counties and primarily produce from the Yegua, Wilcox, MidCox, Austin Chalk, Eagle Ford, Woodbine, and Edwards formations. We applied significant efforts to debottleneck the Coldspring field during the quarter, having taken over operations of this oil and liquids-rich natural gas field earlier in the year. We intend to continue to pursue opportunities in other prospective and productive formations, such as the Buda, Glen Rose, Pettet, Woodbine, Edwards, and Midway Shale formations, in other East Texas properties. Total production from our East Texas region was 9 Bcfe (87% natural gas) for the first half of 2012, including 6 Bcfe from the Hilltop field.

Oklahoma

We have targeted our Oklahoma properties for further development with increased capital spending in 2012. We expect to improve oil production from these properties by deepening existing wellbores and downspacing to 40 acre units, and by recompleting existing wellbores to other previously unexploited zones. We believe this is a low-cost and low-risk strategy to increase oil production. During the first half of 2012, we deepened or reactivated nine wellbores into the Mississippian Lime formation and are evaluating the fieldwide potential for additional exploitation. Our Oklahoma properties produced 94 MBbl’s of oil and 0.5 Bcf of natural gas net to our interest during the first half of 2012.

Eagle Ford Shale

We are participating with Murphy Oil Corporation (“Murphy”), the operator of our Eagleville field, in what we expect to be at least 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. At the end of the second quarter of 2012, we had working interests in 35 producing wells in the Eagle Ford Shale, and overriding interests in three additional wells. Another thirteen wells had been drilled and were awaiting completion. Through mid-August 2012, four additional wells with working interests have begun production in this field. Murphy is operating three drilling rigs, a fracturing team, and a coil tubing unit in the area. We produced approximately 1,800 BOE per day from the Eagleville field (net to our interest, 94% oil and natural gas liquids) during the first half of 2012.

21

Results of Operations: Three Months Ended June 30, 2012 v. Three Months Ended June 30, 2011

	Three Months Ended June 30,						Increase
	2012			2011			(Decrease)			% Change
	(dollars in thousands, except average sales price and unit costs)
Summary Operating Information:
Net Production:
Natural gas (MMcf)		6,027			7,979			(1,952	)		(24	)%
Oil (MBbls)		505			376			129			34	%
Natural gas liquids (MBbls)		96			50			46			92	%
Total natural gas equivalent (MMcfe)		9,634			10,535			(901	)		(9	)%
Average daily gas production (MMcfe per day)		105.9			115.8			(9.9	)		(9	)%
Average Sales Price:
Natural gas (per Mcf) realized	$	4.37		$	4.85		$	(0.48	)		(10	)%
Natural gas (per Mcf) unhedged		2.53			4.21			(1.68	)		(40	)%
Oil (per Bbl) realized		105.10			104.50			0.60			1	%
Oil (per Bbl) unhedged		103.88			110.97			(7.09	)		(6	)%
Natural gas liquids (per Bbl) realized (1)		46.37			56.87			(10.50	)		(18	)%
Combined (per Mcfe) realized		8.71			7.68			1.03			13	%
Hedging Activities:
Realized natural gas revenue gain	$	11,089		$	5,120		$	5,969			117	%
Realized oil revenue gain (loss)		619			(2,434	)		3,053			125	%
Summary Financial Information
Revenues
Natural gas	$	26,341		$	38,731		$	(12,390	)		(32	)%
Oil		53,054			39,292			13,762			35	%
Natural gas liquids		4,470			2,847			1,623			57	%
Other revenues		686			297			389			131	%
Unrealized gain (loss) — oil and natural gas derivative contracts		24,306			14,377			9,929			69	%
		108,857			95,544			13,313			14	%
Expenses
Lease and plant operating expense		17,196			15,041			2,155			14	%
Production and ad valorem taxes		5,853			4,069			1,784			44	%
Workover expense		2,683			2,352			331			14	%
Exploration expense		2,034			5,690			(3,656	)		(64	)%
Depreciation, depletion, and amortization expense		25,121			22,963			2,158			9	%
Impairment expense		2,710			4,929			(2,219	)		(45	)%
Accretion expense		441			476			(35	)		(7	)%
General and administrative expense		12,414			8,843			3,571			40	%
Interest expense, net		9,794			6,831			2,963			43	%
Litigation settlement		(1,250	)		—			(1,250	)		NA
(Gain) on contract settlement		—			(1,285	)		1,285			NA
Provision for state income taxes		—			75			(75	)		NA
Net income	$	31,861		$	25,560		$	6,301			25	%
Average Unit Costs per Mcfe:
Lease and plant operating expense	$	1.78		$	1.43		$	0.35			24	%
Production and ad valorem tax expense		0.61			0.39			0.22			56	%
Workover expense		0.28			0.22			0.06			27	%
Exploration expense		0.21			0.54			(0.33	)		(61	)%
Depreciation, depletion and amortization expense		2.61			2.18			0.43			20	%
General and administrative expense		1.29			0.84			0.45			54	%

(1) We do not utilize hedges for natural gas liquids.

22

Revenues

Natural gas revenues for the three months ended June 30, 2012 decreased $12.4 million, or 32%, to $26.3 million from $38.7 million in 2011. The decrease in natural gas revenue was attributable to a lower average realized price during the second quarter of 2012 and to decreased production volumes. The price of natural gas exclusive of hedging decreased 40% in the second quarter of 2012; the overall realized price (including hedging gains and losses) decreased 10% from $4.85 per Mcf in the second quarter of 2011 to $4.37 per Mcf in the second quarter of 2012, resulting in a decrease in natural gas revenues of approximately $2.9 million. Approximately $9.5 million of the decrease in revenues from natural gas was due to a decrease in production of 2.0 Bcf, or 24%. This decline is primarily due to our Hilltop field, which produced 2.8 Bcf in the second quarter of 2012, compared to 4.8 Bcf in the second quarter of 2011.

Oil revenues for the three months ended June 30, 2012 increased $13.8 million, or 35%, to $53.1 million from $39.3 million in 2011. The increase in revenue was attributable to increased production volumes coupled with a higher average realized price. Approximately $13.5 million of the increase was due to an increase in production of 129 MBbls, or 34%. This increase is primarily due to production from our Eagleville field, which increased 81 MBbls in the second quarter of 2012 as compared to the second quarter of 2011, from 52 MBbls to 133 MBbls. The price of oil exclusive of hedging decreased 6% in the second quarter of 2012; the overall realized price (including hedging gains and losses) increased 1% from $104.50 per Bbl in the second quarter of 2011 to $105.10 per Bbl in the second quarter of 2012, resulting in an increase in oil revenues of approximately $0.3 million.

Natural gas liquids revenues increased $1.6 million, or 57%, during the second quarter of 2012 compared to the same period in 2011. A 92% increase in volumes from 50 MBbls to 96 MBbls was offset by a decrease in our average price of 18%, from $56.87 per Bbl to $46.37 per Bbl. The increase in volume is due to a prior period adjustment in the Eagleville field of 39 MBbls.

Other revenues were $0.7 million during the three months ended June 30, 2012 as compared to $0.3 million during the three months ended June 30, 2011. The increase is the result of an increase in rental income from our drilling rig.

Unrealized gain(loss) — oil and natural gas derivative contracts was a gain of $24.3 million during the three months ended June 30, 2012 as compared to a gain of $14.4 million during the same period in 2011. 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. The majority of the gains were related to the decrease in oil prices during the second quarter of 2012, which increased the unrealized value of our open derivative contracts.

Expenses

Lease and plant operating expense increased $2.2 million in the second quarter of 2012 as compared to the second quarter of 2011, from $15.0 million to $17.2 million, due to increased expenses for field services, chemicals and overhead, $1.6 million, compression, $0.4 million, and salt water disposal, $0.3 million. The increases were primarily due to new wells, which were chiefly for oil production. On a unit basis, lease and plant operating expense increased from $1.43 per Mcfe to $1.78 per Mcfe for the three months ended June 30, 2011 and 2012, respectively.

Production and ad valorem taxes increased $1.8 million, or 44%, to $5.9 million for the second quarter of 2012, as compared to $4.1 million for the second quarter of 2011. Ad valorem taxes increased $0.4 million, primarily due to increases in asset values. Production taxes increased $1.4 million, due to a change in our production mix. Production tax as a percentage of product revenues before realized hedging gains and losses was approximately 7% for the quarter ended June 30, 2012 and 4% for the corresponding period in 2011. Reduced production from our Hilltop field, which is subject to certain production tax exemptions, coupled with increased revenues from oil and natural gas liquids, increased the overall tax rate.

Workover expense increased from the second quarter of 2011 to the second quarter of 2012, from $2.4 million to $2.7 million, respectively. This expense varies depending on activities in the field.

Exploration expense includes the costs of our geology department, costs of geological and geophysical data, delay rentals, expired leases, and dry holes. Exploration expense decreased from $5.7 million for the second quarter of 2011 to $2.0 million for the second quarter of 2012, primarily due to dry holes recorded in the second quarter of 2011.

Depreciation, depletion and amortization increased $2.1 million to $25.1 million for the second quarter of 2012 as compared to an expense of $23.0 million for the second quarter of 2011. On a per unit basis, this expense increased from $2.18 to $2.61 per Mcfe. The rate is a function of capitalized costs of proved properties, reserves and production by field.

23

Impairment expense decreased from $4.9 million in the second quarter of 2011 to $2.7 million in the second quarter of 2012. 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 $0.4 million and $0.5 million for the second quarter of 2012 and 2011, respectively.

General and administrative expense increased $3.6 million for the second quarter of 2012 to $12.4 million from $8.8 million for the second quarter of 2011. The increase is principally due to increased salary and benefits expenses of $3.5 million, primarily due to additional accruals for our bonus program and to additional personnel. On a per unit basis, general and administrative expenses increased from $0.84 to $1.29 per Mcfe.

Interest expense, net increased $3.0 million for the second quarter of 2012 to $9.8 million from $6.8 million for the second quarter of 2011. This increase is primarily due to interest rate hedge gains of $2.8 million recorded in the second quarter of 2011, related to certain interest rate hedge contract modifications.

Litigation settlement is related to the settlement of our litigation with Gastar, under which Gastar paid us $1.25 million in damages in the second quarter of 2012.

Gain on contract settlement is related to the settlement of an obligation we assumed with our acquisition of The Meridian Resource Corporation (“Meridian”). The obligation related to underutilization of two contracted drilling rigs. 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.

24

Results of Operations: Six Months Ended June 30, 2012 v. Six Months Ended June 30, 2011

	Six Months Ended June 30,						Increase
	2012			2011			(Decrease)			% Change
	(dollars in thousands, except average sales price and unit costs)
Summary Operating Information:
Net Production:
Natural gas (MMcf)		12,629			15,345			(2,716	)		(18	)%
Oil (MBbls)		965			724			241			33	%
Natural gas liquids (MBbls)		149			108			41			38	%
Total natural gas equivalent (MMcfe)		19,313			20,338			(1,025	)		(5	)%
Average daily gas production (MMcfe per day)		106.1			112.4			(6.3	)		(5	)%
Average Sales Price:
Natural gas (per Mcf) realized	$	4.11		$	4.83		$	(0.72	)		(15	)%
Natural gas (per Mcf) unhedged		2.55			4.12			(1.57	)		(38	)%
Oil (per Bbl) realized		106.50			98.70			7.80			8	%
Oil (per Bbl) unhedged		107.32			104.11			3.21			3	%
Natural gas liquids (per Bbl) realized (1)		50.63			54.73			(4.10	)		(7	)%
Combined (per Mcfe) realized		8.40			7.45			0.95			13	%
Hedging Activities:
Realized natural gas revenue gain	$	19,629		$	10,911		$	8,718			80	%
Realized oil revenue gain (loss)		(790	)		(3,918	)		3,128			80	%
Summary Financial Information
Revenues
Natural gas	$	51,880		$	74,112		$	(22,232	)		(30	)%
Oil		102,784			71,489			31,295			44	%
Natural gas liquids		7,537			5,900			1,637			28	%
Other revenues		1,384			766			618			81	%
Unrealized gain (loss) — oil and natural gas derivative contracts		17,911			(4,808	)		22,719			473	%
		181,496			147,459			34,037			23	%
Expenses
Lease and plant operating expense		33,114			28,372			4,742			17	%
Production and ad valorem tax expense		12,083			9,470			2,613			28	%
Workover expense		3,936			3,978			(42	)		(1	)%
Exploration expense		4,063			8,421			(4,358	)		(52	)%
Depreciation, depletion, and amortization expense		49,014			42,431			6,583			16	%
Impairment expense		4,462			10,755			(6,293	)		(59	)%
Accretion expense		881			946			(65	)		(7	)%
General and administrative expense		20,383			14,593			5,790			40	%
Interest expense, net		19,548			16,309			3,239			20	%
Litigation settlement		(1,250	)		—			(1,250	)		NA
(Gain) on contract settlement		—			(1,285	)		1,285			NA
Provision for state income taxes		—			75			(75	)		NA
Net income	$	35,262		$	13,394		$	21,868			163	%
Average Unit Costs per Mcfe:
Lease and plant operating expense	$	1.71		$	1.40		$	0.31			22	%
Production and ad valorem tax expense		0.63			0.47			0.16			34	%
Workover expense		0.20			0.20			—			0	%
Exploration expense		0.21			0.41			(0.20	)		(49	)%
Depreciation, depletion and amortization expense		2.54			2.09			0.45			22	%
General and administrative expense		1.06			0.72			0.34			47	%

(1) We do not utilize hedges for natural gas liquids.

25

Revenues

Natural gas revenues for the six months ended June 30, 2012 decreased $22.2 million, or 30%, to $51.9 million from $74.1 million in 2011. The decrease in natural gas revenue was attributable to a lower average realized price during the first half of 2012 and to decreased production volumes. The price of natural gas exclusive of hedging decreased 38% in the first half of 2012; the overall realized price (including hedging gains and losses) decreased 15% from $4.83 per Mcf in the first half of 2011 to $4.11 per Mcf in the first half of 2012, resulting in a decrease in natural gas revenues of approximately $9.1 million. Approximately $13.1 million of the decrease in revenues from natural gas was due to a decrease in production of 2.7 Bcf, or 18%. This decline is primarily due to our Hilltop field, which produced 6.0 Bcf in the first half of 2012, compared to 8.9 Bcf in the first half of 2011.

Oil revenues for the six months ended June 30, 2012 increased $31.3 million, or 44%, to $102.8 million from $71.5 million in 2011. The increase in revenue was attributable to increased production volumes coupled with a higher average realized price. Approximately $23.8 million of the increase was due to an increase in production of 241 MBbls, or 33%. This increase is primarily due to production from our Eagleville field, which increased 197 MBbls in the first half of 2012 as compared to the first half of 2011, from 58 MBbls to 255 MBbls. The price of oil exclusive of hedging increased 3% in the first half of 2012; the overall realized price (including hedging gains and losses) increased 8% from $98.70 per Bbl in the first half of 2011 to $106.50 per Bbl in the first half of 2012, resulting in an increase in oil revenues of approximately $7.5 million.

Natural gas liquids revenues increased $1.6 million, or 28%, during the first half of 2012 compared to the same period in 2011. A 38% increase in volumes from 108 MBbls to 149 MBbls was offset by a decrease in our average price of 7%, from $54.73 per Bbl to $50.63 per Bbl. The increase in volume is due to a prior period adjustment in the Eagleville field of 39 MBbls.

Other revenues were $1.4 million during the six months ended June 30, 2012 as compared to $0.8 million during the six months ended June 30, 2011. The increase is primarily the result of an increase in rental income from our drilling rig.

Unrealized gain(loss) — oil and natural gas derivative contracts was a gain of $17.9 million during the six months ended June 30, 2012 as compared to a loss of $4.8 million during the same period in 2011. 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. The majority of the gains were related to the decrease in oil prices during the second quarter of 2012, which increased the unrealized value of our open derivative contracts.

Expenses

Lease and plant operating expense increased $4.7 million in the first half of 2012 as compared to the first half of 2011, from $28.4 million to $33.1 million, due to increased expenses for field services, chemicals and overhead, $3.2 million, compression, $0.6 million, and salt water disposal, $0.7 million. The increases were primarily due to new wells, which were chiefly for oil production. On a unit basis, lease and plant operating expense increased from $1.40 per Mcfe to $1.71 per Mcfe for the six months ended June 30, 2011 and 2012, respectively.

Production and ad valorem taxes increased $2.6 million, or 28%, to $12.1 million for the first half of 2012, as compared to $9.5 million for the first half of 2011. Ad valorem taxes increased $0.8 million, primarily due to increases in asset values. Production taxes increased $1.8 million. Production tax as a percentage of product revenues before realized hedging gains and losses was approximately 7% for the six months ended June 30, 2012 and 5% for the corresponding period in 2011. Reduced production from our Hilltop field, which is subject to certain production tax exemptions, coupled with increased oil revenues, increased the overall tax rate.

Workover expense decreased $0.1 million from the first half of 2011 to the first half of 2012, from $4.0 million to $3.9 million, respectively. This expense varies depending on activities in the field.

Exploration expense includes the costs of our geology department, costs of geological and geophysical data, delay rentals, expired leases, and dry holes. Exploration expense decreased from $8.4 million for the first half of 2011 to $4.1 million for the first half of 2012.

Depreciation, depletion and amortization increased $6.6 million to $49.0 million for the first half of 2012 as compared to an expense of $42.4 million for the first half of 2011. On a per unit basis, this expense increased from $2.09 to $2.54 per Mcfe. The rate is a function of capitalized costs of proved properties, reserves and production by field.

Impairment expense decreased from $10.8 million in the first half of 2011 to $4.5 million in the first half of 2012. 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.

26

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 $0.9 million for each of the six-month periods ending June 30, 2012 and 2011.

General and administrative expense increased $5.8 million for the first half of 2012 to $20.4 million from $14.6 million for the first half of 2011. The increase is principally due to increased salary and benefits expenses of $4.3 million, primarily due to additional accruals for our bonus program and to additional personnel. In addition, expenses for consulting services increased $1.0 million, primarily for fees associated with litigation and engineering services. On a per unit basis, general and administrative expenses increased from $0.72 to $1.06 per Mcfe.

Interest expense, net increased $3.2 million for the first half of 2012 to $19.5 million from $16.3 million for the first half of 2011. This increase is primarily due to interest rate hedge gains of $2.8 million recorded in the first half of 2011, and to increased interest on our credit facility of $1.2 million, due primarily to higher average outstanding balances during the first half of 2012. Partially offsetting this increase was a decrease in amortization of loan costs of $0.6 million, due to the extension of the maturity date of our credit facility which was amended in May 2011.

Litigation settlement is related to the settlement of our litigation with Gastar, under which Gastar paid us $1.25 million in damages in the second quarter of 2012.

Gain on contract settlement is related to the settlement of an obligation we assumed with our acquisition of Meridian. The obligation related to underutilization of two contracted drilling rigs. 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, exploration and 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 2012 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 $220-240 million during 2012, of which approximately $119.6 million has been expended or accrued through June 30, 2012, including acquisitions. Approximately 52% of our capital budget for the second half of 2012 is allocated to our properties in the Eagle Ford Shale in South Texas, and at Weeks Island in South Louisiana, where the emphasis is on oil production. 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 2012 capital budget predominantly with cash flows from operations, supplemented by borrowings under our credit facility. If necessary, we may also access capital through proceeds from potential asset dispositions and the future issuances 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 issued $300 million of 9 5/8% senior notes due 2018 (“senior notes”) at a discount of $2.1 million, with an effective interest rate of 9 3/4%.

27

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.

Credit Facility

We have a senior secured revolving credit facility (“credit facility”) with Wells Fargo Bank, N.A. as the administrative agent. As of June 30, 2012, the credit facility was subject to a $350 million borrowing base limit, and we had $222 million outstanding under the credit facility. Our restricted subsidiaries are guarantors of the credit facility.

The borrowing base is redetermined each May 1 and November 1. In May 2012, the borrowing base was increased to $350 million. As of August 14, 2012, the available unused portion of the borrowing base was $118 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 June 30, 2012 under the credit facility was 2.5%, which was based on the Eurodollar option.

The credit facility and the indenture governing the senior notes include covenants requiring us to maintain certain financial covenants including a current ratio, leverage ratio, and interest coverage ratio. At June 30, 2012, 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 $88.5 million during the six months ended June 30, 2012 as compared to $71.2 million during the comparable period in 2011. The $17.3 million increase in operating cash flows was attributable to changes in working capital accounts, partially offset by a decrease in the cash-based portions of our earnings. Changes in our working capital accounts, provided $15.9 million of cash flows as compared to use of $6.8 million of cash in 2011. The changes in working capital resulted in an increase of $22.7 million in cash flow. 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, decreased approximately $5.4 million, resulting in a negative impact on cash flow.

Cash flow used in investing activities

Investing activities used cash of $114 million during the six months ended June 30, 2012 as compared to cash used in investing of $155.4 million during the comparable period of 2011. A decrease in cash used in acquisition activities of $43.3 million was primarily due to $50 million expended in the first half of 2011 for the Sydson and TODD acquisitions. Investment in property and equipment increased by $1.9 million. On an accrual basis, aside from acquisition expenditures, capital spending generally increased, primarily for expenditures in our Eagleville and Weeks Island fields in South Texas and South Louisiana, respectively, and also in Oklahoma; these increases in spending were partially offset by a decrease in capital spending in our Hilltop field in East Texas, as compared to the first half of 2011.

Cash flow provided by financing activities

Financing activities provided cash of $32.9 million during the six months ended June 30, 2012 as compared to cash provided by financing of $84.9 million during the comparable period in 2011. Both periods reflected the effect of drawdowns from our credit facility.

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 Annual Report on Form 10-K for the year ended December 31, 2011 (“2011 Form 10-K”) 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.

28

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;

• general economic conditions;

• credit markets;

• 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, commodity price volatility, low prices for oil and/or natural gas, global economic conditions, inflation, the credit rating of U.S. government debt, 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, the timing of development expenditures, and the other risks described under “Item 1A. Risk Factors” in our 2011 Form 10-K.

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.

Should one or more of the risks or uncertainties described in the 2011 Form 10-K 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.

29

ITEM 3. Quantitative and Qualitative Disclosures about Market Risk

For information regarding our exposure to certain market risks, see “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Risk Management Activities—Commodity Derivative Instruments” and “Item 7A. Quantitative and Qualitative Disclosures about Market Risk” in our 2011 Form 10-K. There have been no material changes to the disclosure regarding market risks. See Part I, Item 1, Note 6 to our consolidated financial statements for a description of our outstanding derivative contracts at the most recent reporting date.

ITEM 4. Controls and Procedures

Evaluation of Disclosure Controls and Procedures

In accordance with Rules 13a-15 and 15d-15 under the Securities Exchange Act of 1934, as amended (“Exchange Act”), 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 June 30, 2012 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 June 30, 2012 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 “Item 1A. Risk Factors” in the 2011 Form 10-K. There have been no material changes with respect to the risk factors disclosed in the 2011 Form 10-K during the quarter ended June 30, 2012.

ITEM 2. Unregistered Sales of Equity Securities and Use of Proceeds

None.

ITEM 3. Defaults Upon Senior Securities

None.

ITEM 4. Mine Safety Disclosures

Not applicable.

ITEM 5. Other Information

None.

30

ITEM 6. Exhibits

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.

31

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
August 14, 2012		general partner
	By:	/s/ Harlan H. Chappelle
		Harlan H. Chappelle
August 14, 2012		President and Chief Executive Officer
	By:	/s/ Michael A. McCabe
		Michael A. McCabe
		Vice President and Chief Financial Officer

32

EX-31.1

Exhibit 31.1

CERTIFICATION OF CHIEF EXECUTIVE OFFICER

I, Harlan H. Chappelle, certify that:

1. I have reviewed this Quarterly Report on Form 10-Q of Alta Mesa Holdings, LP;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of Alta Mesa Holdings, LP as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) for Alta Mesa Holdings, LP and have:

a. Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to Alta Mesa Holdings, LP, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b. [intentionally omitted]

c. Evaluated the effectiveness of Alta Mesa Holdings, LP’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d. Disclosed in this report any change in Alta Mesa Holdings, LP’s internal control over financial reporting that occurred during Alta Mesa Holdings, LP’s most recent fiscal quarter that has materially affected, or is reasonably likely to materially affect, Alta Mesa Holdings, LP’s internal control over financial reporting.

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to Alta Mesa Holdings, LP’s auditors and the audit committee of Alta Mesa Holdings, LP’s board of directors (or persons performing the equivalent functions):

a. All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect Alta Mesa Holdings, LP’s ability to record, process, summarize and report financial information; and

b. Any fraud, whether or not material, that involves management or other employees who have a significant role in Alta Mesa Holdings, LP’s internal control over financial reporting.

Date: August 14, 2012

/s/ Harlan H. Chappelle

Harlan H. Chappelle

President and Chief Executive Officer of Alta Mesa

Holdings GP, LLC, general partner of Alta Mesa Holdings, LP

EX-31.2

Exhibit 31.2

CERTIFICATION OF CHIEF FINANCIAL OFFICER

I, Michael A. McCabe, certify that:

1. I have reviewed this Quarterly Report on Form 10-Q of Alta Mesa Holdings, LP;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of Alta Mesa Holdings, LP as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) for Alta Mesa Holdings, LP and have:

a. Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to Alta Mesa Holdings, LP, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b. [intentionally omitted]

c. Evaluated the effectiveness of Alta Mesa Holdings, LP’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d. Disclosed in this report any change in Alta Mesa Holdings, LP’s internal control over financial reporting that occurred during Alta Mesa Holdings, LP’s most recent fiscal quarter that has materially affected, or is reasonably likely to materially affect, Alta Mesa Holdings, LP’s internal control over financial reporting.

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to Alta Mesa Holdings, LP’s auditors and the audit committee of Alta Mesa Holdings, LP’s board of directors (or persons performing the equivalent functions):

a. All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect Alta Mesa Holdings, LP’s ability to record, process, summarize and report financial information; and

b. Any fraud, whether or not material, that involves management or other employees who have a significant role in Alta Mesa Holdings, LP’s internal control over financial reporting.

Date: August 14, 2012

/s/ Michael A. McCabe

Michael A. McCabe

Vice President and Chief Financial Officer of Alta Mesa

Holdings GP, LLC, general partner of Alta Mesa Holdings, LP

EX-32.1

Exhibit 32.1

CERTIFICATION OF

CHIEF EXECUTIVE OFFICER

OF ALTA MESA HOLDINGS, LP

PURSUANT TO 18 U.S.C. SECTION 1350

In connection with this Quarterly Report on Form 10-Q of Alta Mesa Holdings, LP for the quarter ended June 30, 2012, I, Harlan H. Chappelle, President and Chief Executive Officer of Alta Mesa Holdings, LP, hereby certify pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that:

1. This Quarterly Report Form 10-Q for the quarter ended June 30, 2012 fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

2. The information contained in this Quarterly Report on Form 10-Q for the quarter ended June 30, 2012 fairly presents, in all material respects, the financial condition and results of operations of Alta Mesa Holdings, LP for the periods presented therein.

Date: August 14, 2012

/s/ Harlan H. Chappelle

Harlan H. Chappelle

President and Chief Executive Officer of Alta Mesa

Holdings GP, LLC, general partner of Alta Mesa Holdings, LP

EX-32.2

Exhibit 32.2

CERTIFICATION OF

CHIEF FINANCIAL OFFICER

OF ALTA MESA HOLDINGS, LP

PURSUANT TO 18 U.S.C. SECTION 1350

In connection with this Quarterly Report on Form 10-Q of Alta Mesa Holdings, LP for the quarter ended June 30, 2012, I, Michael A. McCabe, Chief Financial Officer of Alta Mesa Holdings, LP, hereby certify pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that:

1. This Quarterly Report Form 10-Q for the quarter ended June 30, 2012 fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

2. The information contained in this Quarterly Report on Form 10-Q for the quarter ended June 30, 2012 fairly presents, in all material respects, the financial condition and results of operations of Alta Mesa Holdings, LP for the periods presented therein.

Date: August 14, 2012

/s/ Michael A. McCabe

Michael A. McCabe

Vice President and Chief Financial Officer of Alta Mesa

Holdings GP, LLC, general partner of Alta Mesa Holdings, LP

XML

Derivative Financial Instruments (Details 5)	3 Months Ended		6 Months Ended
	Jun. 30, 2012 Reference Price 1 [Member]	Jun. 30, 2012 Reference Price 2 [Member]	Jun. 30, 2012 Financial basis spread contract for oil 1 [Member] Argus Louisiana Light Sweet [Member] Brent IPE [Member] bbl	Jun. 30, 2012 Financial basis spread contract for oil 2 [Member] Argus Louisiana Light Sweet [Member] Brent IPE [Member] bbl
Open financial basis swap contracts for oil
Volume in Bbl			828,000	1,277,500
Derivative, Underlying Basis	Brent IPE	Argus Louisiana Light Sweet
First remaining period of term of derivative contract			Jul. 01, 2012	Jan. 01, 2013
Last Remaining Period of Term of Derivative Contract			Dec. 31, 2012	Dec. 31, 2013
Spread limit under basis spread commodity contract			1.92	3.09

XML

Commitments and Contingencies (Details) (USD $)	6 Months Ended
	Jun. 30, 2012 acre Wells	Dec. 31, 2011	Dec. 31, 2010	Jul. 23, 2009
Commitments and Contingencies (Textual) [Abstract]
Acquisition effective date	Jul. 23, 2009
Payment towards acquisition of all working interests	$ 15,200,000			$ 25,500,000
Area acquired under acquisition	50,000
Period of denial of defendants' appeal by Supreme Court	2009
Number of wells in which an interest was acquired	30
Adjustments to purchase price	3,800,000
Total cost of purchase of oil and natural gas assets purchased			44,500,000
Claim by the defendants' for past expenses	36,300,000
Liability for Environmental claims	1,000,000	990,000
Payment under contingent commitment towards properties acquired	$ 2,900,000

XML

Fair Value Disclosures (Details Textual) (USD $)	3 Months Ended		6 Months Ended
	Jun. 30, 2012	Jun. 30, 2011	Jun. 30, 2012	Jun. 30, 2011	Dec. 31, 2010	Apr. 21, 2011 Sydson [Member]	Jun. 17, 2011 TODD [Member]
Fair Value Disclosures (Textual) [Abstract]
Fair value of oil and gas properties in connection with the acquisitions					$ 44,500,000	$ 28,422,000	$ 23,400,000
Fair Value Disclosures (Additional Textual) [Abstract]
Carrying value of oil and gas properties	8,900,000	14,200,000	12,400,000	24,400,000
Impairment charges to oil and gas properties	2,710,000	4,929,000	4,462,000	10,755,000
Written down fair value of oil and gas properties	6,200,000	9,300,000	7,900,000	13,600,000
Fair value of asset retirement obligations			$ 28,400,000	$ 23,400,000
Asset retirement obligation measured at fair value			0.3	2.8

XML

Long-term Debt and Notes Payable to Founder (Tables)

6 Months Ended

Jun. 30, 2012

Long-term Debt and Notes Payable to Founder [Abstract]

Long-term debt

Long-term debt consists of the following:

	June 30, 2012		December 31, 2011
	(unaudited)
	(dollars in thousands)
Senior Debt — On May 13, 2010, we entered a Sixth Amended and Restated Credit Agreement (as amended, the “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 June 30, 2012, the borrowing base under the facility was $350 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 2.5% as of June 30, 2012 and 2.774% as of December 31, 2011.	$	221,790	$	188,790
Senior Notes due 2018 — On October 13, 2010, we issued senior 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 $1.6 million and $1.8 million at June 30, 2012 and December 31, 2011, respectively.		298,376		298,246
Total long-term debt	$	520,166	$	487,036

XML

Asset Retirement Obligations (Details) (USD $) In Thousands, unless otherwise specified	3 Months Ended		6 Months Ended
	Jun. 30, 2012	Jun. 30, 2011	Jun. 30, 2012	Jun. 30, 2011	Dec. 31, 2011
Summary of changes in asset retirement obligations
Balance, December 31, 2011			$ 46,096
Liabilities incurred			235
Liabilities assumed with acquired producing properties			91
Liabilities settled			(1,161)	(246)
Accretion expense	441	476	881	946
Balance, June 30, 2012	46,142		46,142
Less: Current portion	2,201		2,201		3,030
Long term portion	$ 43,941		$ 43,941		$ 43,066

XML

Derivative Financial Instruments (Details 3) (Oil Derivative Contracts [Member])	Jun. 30, 2012 bbl
Short Call Options [Member] | 2012 [Member]
Oil derivative contracts
Volume in Bbls	753,398
Weighted Average	116.56
Short Call Options [Member] | 2013 [Member]
Oil derivative contracts
Volume in Bbls	998,660
Weighted Average	118.03
Short Call Options [Member] | 2014 [Member]
Oil derivative contracts
Volume in Bbls	273,750
Weighted Average	125.70
Short Call Options [Member] | 2015 [Member]
Oil derivative contracts
Volume in Bbls	246,350
Weighted Average	125.12
Short Call Options [Member] | 2016 [Member]
Oil derivative contracts
Volume in Bbls	36,400
Weighted Average	130.00
Short Call Options [Member] | High [Member] | 2012 [Member]
Oil derivative contracts
Range	132.00
Short Call Options [Member] | High [Member] | 2013 [Member]
Oil derivative contracts
Range	134.00
Short Call Options [Member] | High [Member] | 2014 [Member]
Oil derivative contracts
Range	133.50
Short Call Options [Member] | High [Member] | 2015 [Member]
Oil derivative contracts
Range	135.98
Short Call Options [Member] | High [Member] | 2016 [Member]
Oil derivative contracts
Range	130.00
Short Call Options [Member] | Low [Member] | 2012 [Member]
Oil derivative contracts
Range	90.00
Short Call Options [Member] | Low [Member] | 2013 [Member]
Oil derivative contracts
Range	90.00
Short Call Options [Member] | Low [Member] | 2014 [Member]
Oil derivative contracts
Range	107.50
Short Call Options [Member] | Low [Member] | 2015 [Member]
Oil derivative contracts
Range	116.40
Short Call Options [Member] | Low [Member] | 2016 [Member]
Oil derivative contracts
Range	130.00
Long Put Options [Member] | 2012 [Member]
Oil derivative contracts
Volume in Bbls	736,000
Weighted Average	97.53
Long Put Options [Member] | 2013 [Member]
Oil derivative contracts
Volume in Bbls	1,273,500
Weighted Average	108.35
Long Put Options [Member] | 2014 [Member]
Oil derivative contracts
Volume in Bbls	670,950
Weighted Average	89.32
Long Put Options [Member] | 2015 [Member]
Oil derivative contracts
Volume in Bbls	319,350
Weighted Average	87.57
Long Put Options [Member] | 2016 [Member]
Oil derivative contracts
Volume in Bbls	36,400
Weighted Average	95.00
Long Put Options [Member] | High [Member] | 2012 [Member]
Oil derivative contracts
Range	105.00
Long Put Options [Member] | High [Member] | 2013 [Member]
Oil derivative contracts
Range	115.00
Long Put Options [Member] | High [Member] | 2014 [Member]
Oil derivative contracts
Range	100.00
Long Put Options [Member] | High [Member] | 2015 [Member]
Oil derivative contracts
Range	90.00
Long Put Options [Member] | High [Member] | 2016 [Member]
Oil derivative contracts
Range	95.00
Long Put Options [Member] | Low [Member] | 2012 [Member]
Oil derivative contracts
Range	65.00
Long Put Options [Member] | Low [Member] | 2013 [Member]
Oil derivative contracts
Range	85.00
Long Put Options [Member] | Low [Member] | 2014 [Member]
Oil derivative contracts
Range	80.00
Long Put Options [Member] | Low [Member] | 2015 [Member]
Oil derivative contracts
Range	85.00
Long Put Options [Member] | Low [Member] | 2016 [Member]
Oil derivative contracts
Range	95.00
Long Call Options [Member] | 2012 [Member]
Oil derivative contracts
Volume in Bbls	151,350
Weighted Average	99.25
Long Call Options [Member] | 2013 [Member]
Oil derivative contracts
Volume in Bbls	197,475
Weighted Average	94.14
Long Call Options [Member] | High [Member] | 2012 [Member]
Oil derivative contracts
Range	123.50
Long Call Options [Member] | High [Member] | 2013 [Member]
Oil derivative contracts
Range	127.00
Long Call Options [Member] | Low [Member] | 2012 [Member]
Oil derivative contracts
Range	80.2
Long Call Options [Member] | Low [Member] | 2013 [Member]
Oil derivative contracts
Range	79.00
Short Put Options [Member] | 2012 [Member]
Oil derivative contracts
Volume in Bbls	967,100
Weighted Average	77.09
Short Put Options [Member] | 2013 [Member]
Oil derivative contracts
Volume in Bbls	1,538,500
Weighted Average	80.85
Short Put Options [Member] | 2014 [Member]
Oil derivative contracts
Volume in Bbls	777,530
Weighted Average	70.78
Short Put Options [Member] | 2015 [Member]
Oil derivative contracts
Volume in Bbls	319,350
Weighted Average	66.86
Short Put Options [Member] | 2016 [Member]
Oil derivative contracts
Volume in Bbls	36,400
Weighted Average	75.00
Short Put Options [Member] | High [Member] | 2012 [Member]
Oil derivative contracts
Range	85.00
Short Put Options [Member] | High [Member] | 2013 [Member]
Oil derivative contracts
Range	90.00
Short Put Options [Member] | High [Member] | 2014 [Member]
Oil derivative contracts
Range	80.00
Short Put Options [Member] | High [Member] | 2015 [Member]
Oil derivative contracts
Range	70.00
Short Put Options [Member] | High [Member] | 2016 [Member]
Oil derivative contracts
Range	75.00
Short Put Options [Member] | Low [Member] | 2012 [Member]
Oil derivative contracts
Range	68.75
Short Put Options [Member] | Low [Member] | 2013 [Member]
Oil derivative contracts
Range	60.00
Short Put Options [Member] | Low [Member] | 2014 [Member]
Oil derivative contracts
Range	60.00
Short Put Options [Member] | Low [Member] | 2015 [Member]
Oil derivative contracts
Range	60.00
Short Put Options [Member] | Low [Member] | 2016 [Member]
Oil derivative contracts
Range	75.00
Price Swap Contracts [Member] | 2012 [Member]
Oil derivative contracts
Volume in Bbls	266,800
Weighted Average	114.10
Price Swap Contracts [Member] | 2013 [Member]
Oil derivative contracts
Volume in Bbls	392,000
Weighted Average	89.75
Price Swap Contracts [Member] | 2014 [Member]
Oil derivative contracts
Volume in Bbls	255,050
Weighted Average	96.57
Price Swap Contracts [Member] | 2015 [Member]
Oil derivative contracts
Volume in Bbls	401,500
Weighted Average	99.30
Price Swap Contracts [Member] | 2016 [Member]
Oil derivative contracts
Volume in Bbls	292,800
Weighted Average	94.95
Price Swap Contracts [Member] | High [Member] | 2012 [Member]
Oil derivative contracts
Range	121.15
Price Swap Contracts [Member] | High [Member] | 2013 [Member]
Oil derivative contracts
Range	94.74
Price Swap Contracts [Member] | High [Member] | 2014 [Member]
Oil derivative contracts
Range	105.48
Price Swap Contracts [Member] | High [Member] | 2015 [Member]
Oil derivative contracts
Range	99.30
Price Swap Contracts [Member] | High [Member] | 2016 [Member]
Oil derivative contracts
Range	95.00
Price Swap Contracts [Member] | Low [Member] | 2012 [Member]
Oil derivative contracts
Range	80.20
Price Swap Contracts [Member] | Low [Member] | 2013 [Member]
Oil derivative contracts
Range	77.00
Price Swap Contracts [Member] | Low [Member] | 2014 [Member]
Oil derivative contracts
Range	81.00
Price Swap Contracts [Member] | Low [Member] | 2015 [Member]
Oil derivative contracts
Range	99.30
Price Swap Contracts [Member] | Low [Member] | 2016 [Member]
Oil derivative contracts
Range	94.90

XML

Fair Value Disclosures

6 Months Ended

Jun. 30, 2012

Fair Value Disclosures [Abstract]

FAIR VALUE DISCLOSURES

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 reliable. 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, which is a Level 1 determination.

Oil and natural gas properties are subject to impairment testing and potential impairment write down. Oil and gas properties with a carrying amount of $12.4 million were written down to their fair value of $7.9 million, resulting in an impairment charge of $4.5 million for the six months ended June 30, 2012. Oil and gas properties with a carrying amount of $24.4 million were written down to their fair value of $13.6 million, resulting in an impairment charge of $10.8 million for the six months ended June 30, 2011. For the three months ended June 30, 2012, oil and gas properties with a carrying amount of $8.9 million were written down to their fair value of $6.2 million, resulting in an impairment charge of $2.7 million, and for the three months ended June 30, 2011, oil and gas properties with a carrying amount of $14.2 million were written down to their fair value of $9.3 million, resulting in an impairment charge of $4.9 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 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.

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 plugging and abandonment of wells and facilities. We recorded $0.3 million and $2.8 million in additions to asset retirement obligations measured at fair value during the six months ended June 30, 2012 and 2011, respectively.

The following table presents information about our financial assets and liabilities measured at fair value on a recurring basis as of June 30, 2012 and December 31, 2011, 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 June 30, 2012 (unaudited):
Financial Assets:
Derivative contracts for oil and natural gas		—	$	117,241		—	$	117,241
Financial Liabilities:
Derivative contracts for oil and natural gas		—	$	46,561		—	$	46,561
Derivative contracts for interest rate		—	$	212		—	$	212
At December 31, 2011:
Financial Assets:
Derivative contracts for oil and natural gas		—	$	109,138		—	$	109,138
Financial Liabilities:
Derivative contracts for oil and natural gas		—	$	56,369		—	$	56,369
Derivative contracts for interest rate		—	$	1,300		—	$	1,300

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.

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Long-term Debt and Notes Payable to Founder (Details) (USD $) In Thousands, unless otherwise specified	Jun. 30, 2012	Dec. 31, 2011
Long-term debt
Senior Debt	$ 221,790	$ 188,790
Senior Notes Payable	298,376	298,246
Total long-term debt	$ 520,166	$ 487,036

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Significant Acquisitions (Details 1) (USD $) In Thousands, unless otherwise specified	6 Months Ended
	Jun. 30, 2011
Pro forma results for the combined entity
Revenue	$ 150,653
Income (Loss)	$ 15,347

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Significant Acquisitions (Details) (USD $) In Thousands, unless otherwise specified	Jun. 30, 2012	Dec. 31, 2010	Jul. 23, 2009	Apr. 21, 2011 Sydson [Member]	Apr. 21, 2011 Sydson [Member] Hilltop [Member]	Jun. 17, 2011 TODD [Member]	Jun. 17, 2011 TODD [Member] Hilltop [Member]
Summary of Consideration:
Cash	$ 15,200		$ 25,500	$ 27,500			$ 22,500
Fair value of asset retirement obligations assumed				922		863
Total		44,500		28,422	28,422	23,400	23,363
Summary of Purchase Price Allocations:
Proved oil and natural gas properties				18,330		15,223
Unproved oil and natural gas properties				10,092		8,140
Total				$ 28,422		$ 23,363

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Long-term Debt and Notes Payable to Founder (Details Textual) (USD $)	3 Months Ended		6 Months Ended
	Jun. 30, 2012	Jun. 30, 2011	Jun. 30, 2012	Jun. 30, 2011	Dec. 31, 2011	Oct. 13, 2010
Long-term Debt and Notes Payable to Founder (Textual) [Abstract]
Maturity Date of Debt			Dec. 31, 2018
Long-term Debt and Notes Payable to Founder (Additional Textual) [Abstract]
Date of sixth amended and restated credit agreement			May 13, 2010
Date of maturity of credit facility			May 23, 2016
Credit facility borrowing base	$ 350,000,000		$ 350,000,000
Credit facility interest rate	2.50%		2.50%		2.774%
Date of issue of senior notes			Oct. 13, 2010
Face value of senior notes issued	300,000,000		300,000,000
Original issue discount						2,100,000
Face interest rate of senior notes	9.625%		9.625%
Effective rate of interest on senior notes	9.75%		9.75%
Remaining unamortized discount	1,600,000		1,600,000		1,800,000
Percentage of senior notes under optional redemption provision			35.00%
Optional redemption provision beginning period			October 2013
Redemption of senior notes under optional redemption provision through proceeds from equity offering at			109.625%
Date of registration rights agreement			Oct. 13, 2010
Notes payable to founder	21,514,000		21,514,000		20,911,000
Rate of interest on notes payable to founder	10.00%		10.00%
Interest on notes payable to founder	$ 302,000	$ 302,000	$ 603,000	$ 600,000
Debt covenants description			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.
Debt covenant compliance description			At June 30, 2012, we were in compliance with the covenants.
Debt restrictive covenants description			The terms of the credit facility also restrict our ability to make distributions and investments.
Senior notes interest payable date			interest is payable semi-annually each April 15th and October 15th
Senior Debt [Member]
Long-term Debt and Notes Payable to Founder (Textual) [Abstract]
Debt instrument collateral			The credit facility matures on May 23, 2016 and is secured by substantially all of our oil and gas properties.
Senior Notes Payable [Member]
Long-term Debt and Notes Payable to Founder (Textual) [Abstract]
Debt instrument collateral			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 subsidaries.
Maturity Date of Debt			Oct. 15, 2018
LIBOR [Member]
Long-term Debt and Notes Payable to Founder (Textual) [Abstract]
Credit facility applicable interest rate, description			LIBOR plus applicable margins between 2.00% and 2.75%
LIBOR [Member] | High [Member]
Long-term Debt and Notes Payable to Founder (Textual) [Abstract]
Margin interest rate	2.75%		2.75%
LIBOR [Member] | Low [Member]
Long-term Debt and Notes Payable to Founder (Textual) [Abstract]
Margin interest rate	2.00%		2.00%
Prime [Member]
Long-term Debt and Notes Payable to Founder (Textual) [Abstract]
Credit facility applicable interest rate, description			prime rate of Wells Fargo Bank, N. A., plus a margin ranging from 1.00% to 1.75%
Prime [Member] | High [Member]
Long-term Debt and Notes Payable to Founder (Textual) [Abstract]
Margin interest rate	1.75%		1.75%
Prime [Member] | Low [Member]
Long-term Debt and Notes Payable to Founder (Textual) [Abstract]
Margin interest rate	1.00%		1.00%
15-Oct-14 [Member]
Long-term Debt and Notes Payable to Founder (Textual) [Abstract]
Retirement of senior notes under additional optional redemption provisions through proceeds from issue of equity at			104.813%
15-Oct-15 [Member]
Long-term Debt and Notes Payable to Founder (Textual) [Abstract]
Retirement of senior notes under additional optional redemption provisions through proceeds from issue of equity at			102.406%
15-Oct-16 [Member]
Long-term Debt and Notes Payable to Founder (Textual) [Abstract]
Retirement of senior notes under additional optional redemption provisions through proceeds from issue of equity at			100.00%

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Significant Acquisitions (Details Textual) (USD $) In Thousands, unless otherwise specified	6 Months Ended			6 Months Ended			6 Months Ended
	Jun. 30, 2012	Dec. 31, 2010	Jul. 23, 2009	Jun. 30, 2012 Sydson [Member]	Apr. 21, 2011 Sydson [Member]	Apr. 21, 2011 Sydson [Member] Hilltop [Member]	Jun. 30, 2012 TODD [Member]	Jun. 17, 2011 TODD [Member]	Jun. 17, 2011 TODD [Member] Hilltop [Member]
Significant Acquisitions (Textual) [Abstract]
Acquisition effective date	Jul. 23, 2009			Apr. 21, 2011			Jun. 17, 2011
Payment towards acquisition of all working interests	$ 15,200		$ 25,500		$ 27,500				$ 22,500
Total cost of purchase of oil and natural gas assets purchased		$ 44,500			$ 28,422	$ 28,422		$ 23,400	$ 23,363

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Property and Equipment (Details) (USD $) In Thousands, unless otherwise specified	Jun. 30, 2012	Dec. 31, 2011
OIL AND NATURAL GAS PROPERTIES
Unproved properties	$ 45,571	$ 34,797
Accumulated impairment	(7,175)	(5,427)
Unproved properties, net	38,396	29,370
Proved oil and natural gas properties	1,032,233	925,578
Accumulated depreciation, depletion, amortization and impairment	(432,600)	(382,132)
Proved oil and natural gas properties, net	599,633	543,446
TOTAL OIL AND NATURAL GAS PROPERTIES, net	638,029	572,816
LAND	1,185	1,185
DRILLING RIG	10,500	10,500
Accumulated depreciation	(1,487)	(1,137)
TOTAL DRILLING RIG, net	9,013	9,363
OTHER PROPERTY AND EQUIPMENT
Office furniture and equipment, vehicles	8,519	7,313
Accumulated depreciation	(2,420)	(1,510)
OTHER PROPERTY AND EQUIPMENT, net	6,099	5,803
TOTAL PROPERTY AND EQUIPMENT, NET	$ 654,326	$ 589,167

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Property and Equipment

6 Months Ended

Jun. 30, 2012

Property and Equipment [Abstract]

PROPERTY AND EQUIPMENT

4. PROPERTY AND EQUIPMENT

Property and equipment consists of the following:

	June 30, 2012			December 31, 2011
	(unaudited)
	(dollars in thousands)
OIL AND NATURAL GAS PROPERTIES
Unproved properties	$	45,571		$	34,797
Accumulated impairment		(7,175	)		(5,427	)
Unproved properties, net		38,396			29,370
Proved oil and natural gas properties		1,032,233			925,578
Accumulated depreciation, depletion, amortization and impairment		(432,600	)		(382,132	)
Proved oil and natural gas properties, net		599,633			543,446
TOTAL OIL AND NATURAL GAS PROPERTIES, net		638,029			572,816
LAND		1,185			1,185
DRILLING RIG		10,500			10,500
Accumulated depreciation		(1,487	)		(1,137	)
TOTAL DRILLING RIG, net		9,013			9,363
OTHER PROPERTY AND EQUIPMENT
Office furniture and equipment, vehicles		8,519			7,313
Accumulated depreciation		(2,420	)		(1,510	)
OTHER PROPERTY AND EQUIPMENT, net		6,099			5,803
TOTAL PROPERTY AND EQUIPMENT, net	$	654,326		$	589,167

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Fair Value Disclosures (Details) (USD $) In Thousands, unless otherwise specified	Jun. 30, 2012	Dec. 31, 2011
Commodity Contract [Member]
Financial Assets
Derivative Contracts for oil and natural gas	$ 117,241	$ 109,138
Financial Liabilities
Derivative contracts, financial liabilities	46,561	56,369
Interest Rate Swap [Member]
Financial Liabilities
Derivative contracts, financial liabilities	212	1,300
Level 1 [Member] | Commodity Contract [Member]
Financial Assets
Derivative Contracts for oil and natural gas
Financial Liabilities
Derivative contracts, financial liabilities
Level 1 [Member] | Interest Rate Swap [Member]
Financial Liabilities
Derivative contracts, financial liabilities
Level 2 [Member] | Commodity Contract [Member]
Financial Assets
Derivative Contracts for oil and natural gas	117,241	109,138
Financial Liabilities
Derivative contracts, financial liabilities	46,561	56,369
Level 2 [Member] | Interest Rate Swap [Member]
Financial Liabilities
Derivative contracts, financial liabilities	212	1,300
Level 3 [Member] | Commodity Contract [Member]
Financial Assets
Derivative Contracts for oil and natural gas
Financial Liabilities
Derivative contracts, financial liabilities
Level 3 [Member] | Interest Rate Swap [Member]
Financial Liabilities
Derivative contracts, financial liabilities

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Derivative Financial Instruments (Details 6) (USD $) In Thousands, unless otherwise specified	Jun. 30, 2012
Floating to Fixed Rate Swap:
Principal Amount	$ 50,000
Interest rate	4.95%

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Consolidated Balance Sheets (USD $) In Thousands, unless otherwise specified	Jun. 30, 2012	Dec. 31, 2011
CURRENT ASSETS
Cash and cash equivalents	$ 10,043	$ 2,630
Accounts receivable, net	31,343	40,807
Other receivables	3,974	2,806
Prepaid expenses and other current assets	8,578	5,394
Derivative financial instruments	41,289	28,582
TOTAL CURRENT ASSETS	95,227	80,219
PROPERTY AND EQUIPMENT
Oil and natural gas properties, successful efforts method, net	638,029	572,816
Other property and equipment, net	16,297	16,351
TOTAL PROPERTY AND EQUIPMENT, NET	654,326	589,167
OTHER ASSETS
Investment in Partnership - cost	9,000	9,000
Deferred financing costs, net	11,783	12,802
Derivative financial instruments	29,423	24,244
Advances to operators	2,939	3,625
Deposits and other assets	1,089	1,026
TOTAL OTHER ASSETS	54,234	50,697
TOTAL ASSETS	803,787	720,083
CURRENT LIABILITIES
Accounts payable and accrued liabilities	88,676	70,295
Current portion, asset retirement obligations	2,201	3,030
Derivative financial instruments	244	1,300
TOTAL CURRENT LIABILITIES	91,121	74,625
LONG-TERM LIABILITIES
Asset retirement obligations, net of current portion	43,941	43,066
Long-term debt	520,166	487,036
Notes payable to founder	21,514	20,911
Derivative financial instruments		57
Other long-term liabilities	2,111	4,716
TOTAL LONG-TERM LIABILITIES	587,732	555,786
TOTAL LIABILITIES	678,853	630,411
COMMITMENTS AND CONTINGENCIES (NOTE 10)
PARTNERS' CAPITAL	124,934	89,672
TOTAL LIABILITIES AND PARTNERS' CAPITAL	$ 803,787	$ 720,083

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Accounts Payable and Accrued Liabilities (Details) (USD $) In Thousands, unless otherwise specified	Jun. 30, 2012	Dec. 31, 2011
Detail of accounts payable and accrued liabilities
Capital expenditures	$ 28,513	$ 19,119
Revenues and royalties payable	7,329	6,742
Operating expenses/taxes	21,794	21,147
Compensation	8,175	3,567
Acquisition costs payable	3,846	2,883
Other	6,445	5,754
Total accrued liabilities	76,102	59,212
Accounts payable	12,574	11,083
Accounts payable and accrued liabilities	$ 88,676	$ 70,295

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Summary of Significant Accounting Policies

6 Months Ended

Jun. 30, 2012

Summary of Significant Accounting Policies [Abstract]

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

As of June 30, 2012, our significant accounting policies are consistent with those discussed in Note 2 of the consolidated financial statements for the fiscal year ended December 31, 2011.

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.

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 $635,000 and $557,000 at June 30, 2012 and December 31, 2011, 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 June 30, 2012 and 2011, amortization of deferred financing costs included in interest expense amounted to $570,000 and $790,000, respectively. For the six months ended June 30, 2012 and 2011, amortization of deferred financing costs included in interest expense amounted to $1.1 million and $1.7 million, respectively. Deferred financing costs are listed among our long-term assets, net of accumulated amortization of $8.6 million and $7.5 million at June 30, 2012 and December 31, 2011, 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 (“credit facility”) is not considered to be materially different from carrying value due to market rates of interest. The fair value of the notes payable to our founder is not practicable to determine. We have estimated the fair value of our senior notes due 2018 (“senior notes”) at $297 million and $293 million on June 30, 2012 and December 31, 2011, 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 December 2011, the FASB issued ASU No. 2011-11, which increases disclosures about offsetting assets and liabilities. New disclosures are required to enable users of financial statements to understand significant quantitative differences in balance sheets prepared under GAAP and International Financial Reporting Standards (IFRS) related to the offsetting of financial instruments. The existing GAAP guidance allowing balance sheet offsetting, including industry-specific guidance, remains unchanged. The guidance in ASU No. 2011-11 is effective for annual and interim reporting periods beginning on or after January 1, 2013. The disclosures should be applied retrospectively for all prior periods presented. We do not expect the adoption of this amendment to have a material impact on our consolidated financial statements.

We adopted ASU No. 2011-04 to Topic 820, Fair Value Measurements, “Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in U.S. GAAP and IFRS” on January 1, 2012. The ASU changes certain definitions of terms used in its guidance regarding fair value measurements, as well as modifying certain disclosure requirements and other aspects of the guidance. The additional disclosure is included in Note 5.

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Derivative Financial Instruments (Details 1) (USD $) In Thousands, unless otherwise specified	3 Months Ended		6 Months Ended
	Jun. 30, 2012	Jun. 30, 2011	Jun. 30, 2012	Jun. 30, 2011
Effect of our derivative instruments in the consolidated statements of operations
Interest expense	$ (9,817)	$ (6,843)	$ (19,588)	$ (16,323)
Unrealized gains (losses) from derivatives not designated as hedges	24,306	14,377	17,911	(4,808)
Realized [Member] | Derivatives not designated as hedging Instruments under ASC 815 [Member]
Effect of our derivative instruments in the consolidated statements of operations
Realized gains (losses) from derivatives not designated as hedges	11,144	4,984	17,713	8,921
Realized [Member] | Derivatives not designated as hedging Instruments under ASC 815 [Member] | Natural gas revenues [Member] | Natural gas commodity contracts [Member]
Effect of our derivative instruments in the consolidated statements of operations
Realized gains (losses) from derivatives not designated as hedges	11,089	5,120	19,629	10,911
Realized [Member] | Derivatives not designated as hedging Instruments under ASC 815 [Member] | Oil revenues [Member] | Oil commodity contracts [Member]
Effect of our derivative instruments in the consolidated statements of operations
Realized gains (losses) from derivatives not designated as hedges	619	(2,434)	(790)	(3,918)
Realized [Member] | Derivatives not designated as hedging Instruments under ASC 815 [Member] | Interest benefit (expense) [Member] | Interest rate contracts [Member]
Effect of our derivative instruments in the consolidated statements of operations
Interest expense	(564)	2,298	(1,126)	1,928
Unrealized [Member] | Derivatives not designated as hedging Instruments under ASC 815 [Member]
Effect of our derivative instruments in the consolidated statements of operations
Unrealized gains (losses) from derivatives not designated as hedges	24,867	14,842	18,999	(4,300)
Unrealized [Member] | Derivatives not designated as hedging Instruments under ASC 815 [Member] | Interest benefit (expense) [Member] | Interest rate contracts [Member]
Effect of our derivative instruments in the consolidated statements of operations
Interest expense	561	465	1,088	508
Unrealized [Member] | Derivatives not designated as hedging Instruments under ASC 815 [Member] | Unrealized gain (loss) - oil and natural gas derivative contracts [Member] | Natural gas commodity contracts [Member]
Effect of our derivative instruments in the consolidated statements of operations
Unrealized gains (losses) from derivatives not designated as hedges	(13,667)	1,659	(5,881)	(1,299)
Unrealized [Member] | Derivatives not designated as hedging Instruments under ASC 815 [Member] | Unrealized gain (loss) - oil and natural gas derivative contracts [Member] | Oil commodity contracts [Member]
Effect of our derivative instruments in the consolidated statements of operations
Unrealized gains (losses) from derivatives not designated as hedges	$ 37,973	$ 12,718	$ 23,792	$ (3,509)

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Fair Value Disclosures (Tables)

6 Months Ended

Jun. 30, 2012

Fair Value Disclosures [Abstract]

Measurement of fair value of assets and liabilities on recurring basis

The following table presents information about our financial assets and liabilities measured at fair value on a recurring basis as of June 30, 2012 and December 31, 2011, 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 June 30, 2012 (unaudited):
Financial Assets:
Derivative contracts for oil and natural gas		—	$	117,241		—	$	117,241
Financial Liabilities:
Derivative contracts for oil and natural gas		—	$	46,561		—	$	46,561
Derivative contracts for interest rate		—	$	212		—	$	212
At December 31, 2011:
Financial Assets:
Derivative contracts for oil and natural gas		—	$	109,138		—	$	109,138
Financial Liabilities:
Derivative contracts for oil and natural gas		—	$	56,369		—	$	56,369
Derivative contracts for interest rate		—	$	1,300		—	$	1,300

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Derivative Financial Instruments (Details 2) (Natural Gas Derivative Contracts [Member])	Jun. 30, 2012 MMBTU
Short Call Options [Member] | 2012 [Member]
Natural gas derivative contracts
Volume in MMbtu	4,940,000
Weighted Average	5.53
Short Call Options [Member] | 2013 [Member]
Natural gas derivative contracts
Volume in MMbtu	1,825,000
Weighted Average	5.25
Short Call Options [Member] | 2014 [Member]
Natural gas derivative contracts
Volume in MMbtu	3,475,000
Weighted Average	7.05
Short Call Options [Member] | 2016 [Member]
Natural gas derivative contracts
Volume in MMbtu	455,000
Weighted Average	7.50
Short Call Options [Member] | High [Member] | 2012 [Member]
Natural gas derivative contracts
Range	6.00
Short Call Options [Member] | High [Member] | 2013 [Member]
Natural gas derivative contracts
Range	5.25
Short Call Options [Member] | High [Member] | 2014 [Member]
Natural gas derivative contracts
Range	9.00
Short Call Options [Member] | High [Member] | 2016 [Member]
Natural gas derivative contracts
Range	7.50
Short Call Options [Member] | Low [Member] | 2012 [Member]
Natural gas derivative contracts
Range	4.50
Short Call Options [Member] | Low [Member] | 2013 [Member]
Natural gas derivative contracts
Range	5.25
Short Call Options [Member] | Low [Member] | 2014 [Member]
Natural gas derivative contracts
Range	6.00
Short Call Options [Member] | Low [Member] | 2016 [Member]
Natural gas derivative contracts
Range	7.50
Long Put Options [Member] | 2012 [Member]
Natural gas derivative contracts
Volume in MMbtu	3,866,000
Weighted Average	5.09
Long Put Options [Member] | 2013 [Member]
Natural gas derivative contracts
Volume in MMbtu	1,500,000
Weighted Average	6.09
Long Put Options [Member] | 2014 [Member]
Natural gas derivative contracts
Volume in MMbtu	1,650,000
Weighted Average	6.73
Long Put Options [Member] | 2016 [Member]
Natural gas derivative contracts
Volume in MMbtu	455,000
Weighted Average	5.50
Long Put Options [Member] | High [Member] | 2012 [Member]
Natural gas derivative contracts
Range	6.75
Long Put Options [Member] | High [Member] | 2013 [Member]
Natural gas derivative contracts
Range	6.15
Long Put Options [Member] | High [Member] | 2014 [Member]
Natural gas derivative contracts
Range	7.00
Long Put Options [Member] | High [Member] | 2016 [Member]
Natural gas derivative contracts
Range	5.50
Long Put Options [Member] | Low [Member] | 2012 [Member]
Natural gas derivative contracts
Range	4.00
Long Put Options [Member] | Low [Member] | 2013 [Member]
Natural gas derivative contracts
Range	6.00
Long Put Options [Member] | Low [Member] | 2014 [Member]
Natural gas derivative contracts
Range	6.00
Long Put Options [Member] | Low [Member] | 2016 [Member]
Natural gas derivative contracts
Range	5.50
Long Call Options [Member] | 2012 [Member]
Natural gas derivative contracts
Volume in MMbtu	2,760,000
Weighted Average	4.67
Long Call Options [Member] | 2013 [Member]
Natural gas derivative contracts
Volume in MMbtu	3,625,000
Weighted Average	5.87
Long Call Options [Member] | High [Member] | 2012 [Member]
Natural gas derivative contracts
Range	5.00
Long Call Options [Member] | High [Member] | 2013 [Member]
Natural gas derivative contracts
Range	7.00
Long Call Options [Member] | Low [Member] | 2012 [Member]
Natural gas derivative contracts
Range	4.00
Long Call Options [Member] | Low [Member] | 2013 [Member]
Natural gas derivative contracts
Range	4.75
Short Put Options [Member] | 2012 [Member]
Natural gas derivative contracts
Volume in MMbtu	6,986,000
Weighted Average	3.44
Short Put Options [Member] | 2013 [Member]
Natural gas derivative contracts
Volume in MMbtu	18,748,500
Weighted Average	3.18
Short Put Options [Member] | 2014 [Member]
Natural gas derivative contracts
Volume in MMbtu	2,623,500
Weighted Average	4.14
Short Put Options [Member] | 2016 [Member]
Natural gas derivative contracts
Volume in MMbtu	455,000
Weighted Average	4.00
Short Put Options [Member] | High [Member] | 2012 [Member]
Natural gas derivative contracts
Range	4.50
Short Put Options [Member] | High [Member] | 2013 [Member]
Natural gas derivative contracts
Range	5.00
Short Put Options [Member] | High [Member] | 2014 [Member]
Natural gas derivative contracts
Range	5.50
Short Put Options [Member] | High [Member] | 2016 [Member]
Natural gas derivative contracts
Range	4.00
Short Put Options [Member] | Low [Member] | 2012 [Member]
Natural gas derivative contracts
Range	2.50
Short Put Options [Member] | Low [Member] | 2013 [Member]
Natural gas derivative contracts
Range	3.00
Short Put Options [Member] | Low [Member] | 2014 [Member]
Natural gas derivative contracts
Range	3.00
Short Put Options [Member] | Low [Member] | 2016 [Member]
Natural gas derivative contracts
Range	4.00
Price Swap Contracts [Member] | 2012 [Member]
Natural gas derivative contracts
Volume in MMbtu	8,405,000
Weighted Average	4.79
Price Swap Contracts [Member] | 2013 [Member]
Natural gas derivative contracts
Volume in MMbtu	19,400,000
Weighted Average	4.75
Price Swap Contracts [Member] | 2014 [Member]
Natural gas derivative contracts
Volume in MMbtu	3,125,000
Weighted Average	6.27
Price Swap Contracts [Member] | 2015 [Member]
Natural gas derivative contracts
Volume in MMbtu	1,825,000
Weighted Average	5.91
Price Swap Contracts [Member] | High [Member] | 2012 [Member]
Natural gas derivative contracts
Range	8.83
Price Swap Contracts [Member] | High [Member] | 2013 [Member]
Natural gas derivative contracts
Range	9.15
Price Swap Contracts [Member] | High [Member] | 2014 [Member]
Natural gas derivative contracts
Range	7.50
Price Swap Contracts [Member] | High [Member] | 2015 [Member]
Natural gas derivative contracts
Range	5.91
Price Swap Contracts [Member] | Low [Member] | 2012 [Member]
Natural gas derivative contracts
Range	3.06
Price Swap Contracts [Member] | Low [Member] | 2013 [Member]
Natural gas derivative contracts
Range	3.30
Price Swap Contracts [Member] | Low [Member] | 2014 [Member]
Natural gas derivative contracts
Range	5.60
Price Swap Contracts [Member] | Low [Member] | 2015 [Member]
Natural gas derivative contracts
Range	5.91

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Asset Retirement Obligations (Tables)

6 Months Ended

Jun. 30, 2012

Asset Retirement Obligations [Abstract]

Summary of changes in 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, 2011	$	46,096
Liabilities incurred		235
Liabilities assumed with acquired producing properties		91
Liabilities settled		(1,161	)
Accretion expense		881
Balance, June 30, 2012		46,142
Less: Current portion		2,201
Long term portion	$	43,941

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Significant Acquisitions

6 Months Ended

Jun. 30, 2012

Significant Acquisitions [Abstract]

SIGNIFICANT ACQUISITIONS

3. SIGNIFICANT ACQUISITIONS

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). 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). 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 preliminary allocations of the purchase prices are as follows (dollars in thousands):

Summary of Consideration:	Sydson		TODD
Cash	$	27,500	$	22,500
Fair value of asset retirement obligations assumed		922		863
Total	$	28,422	$	23,363
Summary of Purchase Price Allocations:
Proved oil and natural gas properties	$	18,330	$	15,223
Unproved oil and natural gas properties		10,092		8,140
Total	$	28,422	$	23,363

The revenue and earnings related to the Sydson and TODD acquisitions are included in our consolidated statement of income for the six months ended June 30, 2012. Revenue and earnings, had the acquisitions occurred on January 1, 2011, 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)
Pro forma results for the combined entity for the six months ended June 30, 2011	$	150,653	$	15,347

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Consolidated Statements of Income (Unaudited) (USD $) In Thousands, unless otherwise specified	3 Months Ended		6 Months Ended
	Jun. 30, 2012	Jun. 30, 2011	Jun. 30, 2012	Jun. 30, 2011
REVENUES
Natural gas	$ 26,341	$ 38,731	$ 51,880	$ 74,112
Oil	53,054	39,292	102,784	71,489
Natural gas liquids	4,470	2,847	7,537	5,900
Other revenues	686	297	1,384	766
Total revenues	84,551	81,167	163,585	152,267
Unrealized gain (loss) - oil and natural gas derivative contracts	24,306	14,377	17,911	(4,808)
TOTAL REVENUES	108,857	95,544	181,496	147,459
EXPENSES
Lease and plant operating expense	17,196	15,041	33,114	28,372
Production and ad valorem taxes	5,853	4,069	12,083	9,470
Workover expense	2,683	2,352	3,936	3,978
Exploration expense	2,034	5,690	4,063	8,421
Depreciation, depletion, and amortization expense	25,121	22,963	49,014	42,431
Impairment expense	2,710	4,929	4,462	10,755
Accretion expense	441	476	881	946
General and administrative expenses	12,414	8,843	20,383	14,593
TOTAL EXPENSES	68,452	64,363	127,936	118,966
INCOME FROM OPERATIONS	40,405	31,181	53,560	28,493
OTHER INCOME (EXPENSE)
Interest expense	(9,817)	(6,843)	(19,588)	(16,323)
Interest income	23	12	40	14
Litigation settlement	1,250		1,250
Gain on contract settlement		1,285		1,285
TOTAL OTHER INCOME (EXPENSE)	(8,544)	(5,546)	(18,298)	(15,024)
INCOME BEFORE STATE INCOME TAXES	31,861	25,635	35,262	13,469
(PROVISION FOR) STATE INCOME TAXES		(75)		(75)
NET INCOME	$ 31,861	$ 25,560	$ 35,262	$ 13,394

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Subsidiary Guarantors

6 Months Ended

Jun. 30, 2012

Subsidiary Guarantors [Abstract]

SUBSIDIARY GUARANTORS

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.

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Document and Entity Information	6 Months Ended
	Jun. 30, 2012
Document and Entity Information [Abstract]
Entity Registrant Name	Alta Mesa Holdings, LP
Entity Central Index Key	0001518403
Document Type	10-Q
Document Period End Date	Jun. 30, 2012
Amendment Flag	false
Document Fiscal Year Focus	2012
Document Fiscal Period Focus	Q2
Current Fiscal Year End Date	--12-31
Entity Filer Category	Non-accelerated Filer
Entity Common Stock, Shares Outstanding	0

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Subsequent Events

6 Months Ended

Jun. 30, 2012

Subsequent Events [Abstract]

SUBSEQUENT EVENTS

14. SUBSEQUENT EVENTS

Management has evaluated all events subsequent to the balance sheet date of June 30, 2012, and has determined that no events require disclosure.

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Consolidated Statements of Cash Flows (Unaudited) (USD $)	6 Months Ended
	Jun. 30, 2012	Jun. 30, 2011
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$ 35,262,000	$ 13,394,000
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion, and amortization expense	49,014,000	42,431,000
Impairment expense	4,462,000	10,755,000
Accretion expense	881,000	946,000
Amortization of loan costs	1,137,000	1,694,000
Amortization of debt discount	130,000	130,000
Dry hole expense	1,222,000	5,267,000
Unrealized (gain) loss on derivatives	(18,999,000)	4,300,000
(Gain) on contract settlement		(1,285,000)
Interest converted into debt	603,000	600,000
Settlement of asset retirement obligation	(1,161,000)	(246,000)
Changes in assets and liabilities:
Accounts receivable	9,464,000	(3,428,000)
Other receivables	(1,168,000)	4,391,000
Prepaid expenses and other non-current assets	(2,561,000)	(6,344,000)
Accounts payable, accrued liabilities, and other long-term liabilities	10,203,000	(1,455,000)
NET CASH PROVIDED BY OPERATING ACTIVITIES	88,489,000	71,150,000
CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures for property and equipment	(96,072,000)	(94,139,000)
Acquisitions	(17,886,000)	(61,235,000)
NET CASH USED IN INVESTING ACTIVITIES	(113,958,000)	(155,374,000)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from long-term debt	38,000,000	86,500,000
Repayments of long-term debt	(5,000,000)
Additions to deferred financing costs	(118,000)	(1,589,000)
NET CASH PROVIDED BY FINANCING ACTIVITIES	32,882,000	84,911,000
NET INCREASE IN CASH	7,413,000	687,000
CASH AND CASH EQUIVALENTS, beginning of period	2,630,000	4,836,000
CASH AND CASH EQUIVALENTS, end of period	10,043,000	5,523,000
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION
Cash paid during the period for interest	19,070,000	16,484,000
Cash paid during the period for taxes	230,000
Change in asset retirement obligations	235,000	325,000
Asset retirement obligations assumed, purchased properties	91,000	2,504,000
Change in accruals or liabilities for capital expenditures	$ 5,573,000	$ (12,170,000)

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Long-term Debt and Notes Payable to Founder

6 Months Ended

Jun. 30, 2012

Long-term Debt and Notes Payable to Founder [Abstract]

LONG-TERM DEBT AND NOTES PAYABLE TO FOUNDER

8. LONG-TERM DEBT AND NOTES PAYABLE TO FOUNDER

Long-term debt consists of the following:

	June 30, 2012		December 31, 2011
	(unaudited)
	(dollars in thousands)
Senior Debt — On May 13, 2010, we entered a Sixth Amended and Restated Credit Agreement (as amended, the “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 June 30, 2012, the borrowing base under the facility was $350 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 2.5% as of June 30, 2012 and 2.774% as of December 31, 2011.	$	221,790	$	188,790
Senior Notes due 2018 — On October 13, 2010, we issued senior 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 $1.6 million and $1.8 million at June 30, 2012 and December 31, 2011, respectively.		298,376		298,246
Total long-term debt	$	520,166	$	487,036

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 June 30, 2012, 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 $21.5 million and $20.9 million at June 30, 2012 and December 31, 2011, 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 $603,000 and $600,000 for the six months ended June 30, 2012 and 2011, respectively, and $302,000 and $302,000 for the three months ended June 30, 2012 and 2011, respectively. Such amounts have been added to the balance of the notes.

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Asset Retirement Obligations

6 Months Ended

Jun. 30, 2012

Asset Retirement Obligations [Abstract]

ASSET RETIREMENT OBLIGATIONS

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, 2011	$	46,096
Liabilities incurred		235
Liabilities assumed with acquired producing properties		91
Liabilities settled		(1,161	)
Accretion expense		881
Balance, June 30, 2012		46,142
Less: Current portion		2,201
Long term portion	$	43,941

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Derivative Financial Instruments (Tables)

6 Months Ended

Jun. 30, 2012

Derivative [Line Items]

Fair Values of Derivative Contracts

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 June 30, 2012
	Current asset portion of Derivative financial instruments			Current liability portion of Derivative financial instruments			Long-term asset portion of Derivative financial instruments			Long-term liability portion of Derivative financial instruments
	(unaudited)
	(dollars in thousands)
Fair value of oil and gas commodity contracts, assets	$	65,114		$	—		$	52,127		$	—
Fair value of oil and gas commodity contracts, (liabilities)		(23,825	)		(32	)		(22,704	)		—
Fair value of interest rate contracts, (liabilities)		—			(212	)		—			—
Total net assets, (liabilities)	$	41,289		$	(244	)	$	29,423		$	—

Fair Values of Derivative Contracts

	Balance Sheet Location at December 31, 2011
	Current asset portion of Derivative financial instruments			Current liability portion of Derivative financial instruments			Long-term asset portion of Derivative financial instruments			Long-term liability portion of Derivative financial instruments
	(dollars in thousands)
Fair value of oil and gas commodity contracts, assets	$	56,716		$	—		$	52,422		$	—
Fair value of oil and gas commodity contracts, (liabilities)		(28,134	)		—			(28,178	)		(57	)
Fair value of interest rate contracts, (liabilities)		—			(1,300	)		—			—
Total net assets, (liabilities)	$	28,582		$	(1,300	)	$	24,244		$	(57	)

Effect of our derivative instruments in the consolidated statements of operations

The following table summarizes the effect of our derivative instruments in the consolidated statements of income:

Derivatives not designated as hedging	Location of Gain	Classification of	For the three months ended June 30,				For the six months  ended June 30,
instruments under ASC 815	(Loss)	Gain (Loss)	2012		2011		2012		2011
			(unaudited)				(unaudited)
			(dollars in thousands)
Natural gas commodity contracts	Natural gas revenues	Realized	$	11,089	$	5,120	$	19,629	$	10,911
Oil commodity contracts	Oil revenues	Realized		619		(2,434)		(790)		(3,918)
Interest rate contracts	Interest benefit (expense)	Realized		(564)		2,298		(1,126)		1,928
Total realized gains (losses) from derivatives not designated as hedges			$	11,144	$	4,984	$	17,713	$	8,921
Natural gas commodity contracts	Unrealized gain (loss) — oil and natural gas derivative contracts	Unrealized	$	(13,667)	$	1,659	$	(5,881)	$	(1,299)
Oil commodity contracts	Unrealized gain (loss) — oil and natural gas derivative contracts	Unrealized		37,973		12,718		23,792		(3,509)
Interest rate contracts	Interest benefit (expense)	Unrealized		561		465		1,088		508
Total unrealized gains (losses) from derivatives not designated as hedges			$	24,867	$	14,842	$	18,999	$	(4,300)

Open financial basis swap contracts for gas

We had the following open financial basis swap contracts for natural gas at June 30, 2012 (unaudited):

Volume in MMbtu	Reference Price 1 (1)		Reference Price 2 (1)		Period		Spread ($ per MMbtu)
920,000		NYMEX Henry Hub		Houston Ship Channel		July ’12 —Dec ’12	$	0.1575
1,840,000		NYMEX Henry Hub		Houston Ship Channel		July ’12 —Dec ’12	$	0.1400
3,650,000		NYMEX Henry Hub		Houston Ship Channel		Jan ’13 — Dec ’13	$	0.0625

⁽¹⁾ The spread in these trades limits the differential of the settlement quotation prices for NYMEX Henry Hub over the Houston Ship Channel index published in Inside FERC.

Open Financial Basis Swap Contracts For Oil

We had the following open financial basis swap contracts for oil at June 30, 2012 (unaudited):

Volume in Bbl	Reference Price 1  (2)		Reference Price 2  (2)		Period		Average Spread ($ per  Bbl)
828,000		Brent IPE		Argus Louisiana Light Sweet		July ’12 —Dec ’12	$	1.92
1,277,500		Brent IPE		Argus Louisiana Light Sweet		Jan ’13 — Dec ’13	$	3.09

⁽²⁾  The spread in these trades limits the differential of the settlement quotation prices for Brent IPE over Argus Louisiana Light Sweet crude.

Interest Rate Swaps

We had the following open interest rate swap contract at June 30, 2012 (unaudited):

Term	Principal Amount		Interest Rate (3)
	(dollars in thousands)
Floating to Fixed Rate Swap:
July 2012 — August 2012	$	50,000		4.95	%

(3) The floating rate is the three-month LIBOR rate.

Natural gas [Member]

Derivative [Line Items]

Derivative contracts

We had the following open derivative contracts for natural gas at June 30, 2012 (unaudited):

NATURAL GAS DERIVATIVE CONTRACTS

	Volume in		Weighted		Range
Period and Type of Contract	MMbtu		Average		High		Low
2012
Price Swap Contracts		8,405,000	$	4.79	$	8.83	$	3.06
Collar Contracts
Short Call Options		4,940,000		5.53		6.00		4.50
Long Put Options		3,866,000		5.09		6.75		4.00
Long Call Options		2,760,000		4.67		5.00		4.00
Short Put Options		6,986,000		3.44		4.50		2.50
2013
Price Swap Contracts		19,400,000		4.75		9.15		3.30
Collar Contracts
Short Call Options		1,825,000		5.25		5.25		5.25
Long Put Options		1,500,000		6.09		6.15		6.00
Long Call Options		3,625,000		5.87		7.00		4.75
Short Put Options		18,748,500		3.18		5.00		3.00
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		2,623,500		4.14		5.50		3.00
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

oil [Member]

Derivative [Line Items]

Derivative contracts

We had the following open derivative contracts for crude oil at June 30, 2012 (unaudited):

OIL DERIVATIVE CONTRACTS

			Weighted		Range
Period and Type of Contract	Volume in Bbls		Average		High		Low
2012
Price Swap Contracts		266,800	$	114.10	$	121.15	$	80.20
Collar Contracts
Short Call Options		753,398		116.56		132.00		90.00
Long Put Options		736,000		97.53		105.00		65.00
Long Call Options		151,350		99.25		123.50		80.20
Short Put Options		967,100		77.09		85.00		68.75
2013
Price Swap Contracts		392,000		89.75		94.74		77.00
Collar Contracts
Short Call Options		998,660		118.03		134.00		90.00
Long Put Options		1,273,500		108.35		115.00		85.00
Long Call Options		197,475		94.14		127.00		79.00
Short Put Options		1,538,500		80.85		90.00		60.00
2014
Price Swap Contracts		255,050		96.57		105.48		81.00
Collar Contracts
Short Call Options		273,750	$	125.70	$	133.50	$	107.50
Long Put Options		670,950		89.32		100.00		80.00
Short Put Options		777,530		70.78		80.00		60.00
2015
Price Swap Contracts		401,500		99.30		99.30		99.30
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
Price Swap Contracts		292,800		94.95		95.00		94.90
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

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Summary of Significant Accounting Policies (Policies)

6 Months Ended

Jun. 30, 2012

Summary of Significant Accounting Policies [Abstract]

Use of Estimates

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.

Property and Equipment

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

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 $635,000 and $557,000 at June 30, 2012 and December 31, 2011, respectively.

Deferred financing costs

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 June 30, 2012 and 2011, amortization of deferred financing costs included in interest expense amounted to $570,000 and $790,000, respectively. For the six months ended June 30, 2012 and 2011, amortization of deferred financing costs included in interest expense amounted to $1.1 million and $1.7 million, respectively. Deferred financing costs are listed among our long-term assets, net of accumulated amortization of $8.6 million and $7.5 million at June 30, 2012 and December 31, 2011, respectively.

Financial Instruments

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 (“credit facility”) is not considered to be materially different from carrying value due to market rates of interest. The fair value of the notes payable to our founder is not practicable to determine. We have estimated the fair value of our senior notes due 2018 (“senior notes”) at $297 million and $293 million on June 30, 2012 and December 31, 2011, 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

Recent Accounting Pronouncements

In December 2011, the FASB issued ASU No. 2011-11, which increases disclosures about offsetting assets and liabilities. New disclosures are required to enable users of financial statements to understand significant quantitative differences in balance sheets prepared under GAAP and International Financial Reporting Standards (IFRS) related to the offsetting of financial instruments. The existing GAAP guidance allowing balance sheet offsetting, including industry-specific guidance, remains unchanged. The guidance in ASU No. 2011-11 is effective for annual and interim reporting periods beginning on or after January 1, 2013. The disclosures should be applied retrospectively for all prior periods presented. We do not expect the adoption of this amendment to have a material impact on our consolidated financial statements.

We adopted ASU No. 2011-04 to Topic 820, Fair Value Measurements, “Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in U.S. GAAP and IFRS” on January 1, 2012. The ASU changes certain definitions of terms used in its guidance regarding fair value measurements, as well as modifying certain disclosure requirements and other aspects of the guidance. The additional disclosure is included in Note 5.

Derivatives and Hedging

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 our 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, or in the case of financial basis hedging contracts, based on a designated price differential between various benchmark prices. Cash settlement occurs monthly. 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 income at each reporting date. Realized gains and losses on commodities hedging contracts are included in oil and natural gas revenues.

We have entered into an interest rate swap agreement to mitigate the risk of loss due to changes in interest rates. The interest rate swap is not designated as a cash flow hedge 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 swap contract are included in interest expense.

Fair Value Measurements and 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 reliable. 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, which is a Level 1 determination.

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Significant Risks and Uncertainties

6 Months Ended

Jun. 30, 2012

Significant Risks and Uncertainties [Abstract]

SIGNIFICANT RISKS AND UNCERTAINTIES

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.

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Accounts Payable and Accrued Liabilities

6 Months Ended

Jun. 30, 2012

Accounts Payable and Accrued Liabilities [Abstract]

ACCOUNTS PAYABLE AND ACCRUED LIABILITIES

9. ACCOUNTS PAYABLE AND ACCRUED LIABILITIES

The following provides the detail of accounts payable and accrued liabilities:

	June 30, 2012		December 31, 2011
	(unaudited)
	(dollars in thousands)
Capital expenditures	$	28,513	$	19,119
Revenues and royalties payable		7,329		6,742
Operating expenses/taxes		21,794		21,147
Compensation		8,175		3,567
Acquisition costs payable		3,846		2,883
Other		6,445		5,754
Total accrued liabilities		76,102		59,212
Accounts payable		12,574		11,083
Accounts payable and accrued liabilities	$	88,676	$	70,295

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Commitments and Contingencies

6 Months Ended

Jun. 30, 2012

Commitments and Contingencies [Abstract]

COMMITMENTS AND CONTINGENCIES

10. COMMITMENTS AND CONTINGENCIES

Contingencies

Hilltop Field Litigation: On July 23, 2009, we made a payment of $25.5 million and took assignment of substantially all working interests that Chesapeake Energy Corporation (“Chesapeake”) had acquired from Gastar Exploration Ltd. (“Gastar”) in an approximate 50,000 acre area of Leon and Robertson Counties, Texas known as the Hilltop Field, in which the Deep Bossier formation was the principal focus for development. We had exercised our preferential right to purchase these interests from Gastar in late 2005, but Gastar and Chesapeake had opposed this and Chesapeake took record title at that time. We finally and conclusively prevailed when, 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 review the appeal. As a result, we were able to take assignment of 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 had pursued other claims against Chesapeake and Gastar; Chesapeake claimed an additional $36.3 million of past expenses. The case was set for trial on April 24, 2012. Shortly before the trial was to begin, we reached an agreement in principle to settle with the Chesapeake-related defendants. We also entered into a settlement agreement with Gastar. The effects of these settlements, recorded in the second quarter of 2012, were not material to our financial position or results of operations.

Environmental claims: Management has established a liability for soil contamination in Florida of $1.0 million at June 30, 2012 and $990,000 at December 31, 2011, 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 The Meridian Resource Corporation and its subsidiaries (“Meridian”), which we acquired in 2010, 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 June 30, 2012.

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 a contingent commitment to pay an amount up to a maximum of approximately $2.9 million for properties acquired in 2008. The additional purchase consideration will be paid if certain product price conditions are met.

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Partners' Capital

6 Months Ended

Jun. 30, 2012

Partners' Capital [Abstract]

PARTNERS' CAPITAL

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 our capital partner, Alta Mesa Investment Holdings, Inc. (“AMIH”), was admitted to the partnership as the sole Class B limited partner (“Class B Partner”). AMIH is an affiliate of Denham Commodity Partners Fund IV LP (“DCPF IV”). DCPF IV is advised by Denham Capital Management LP, a private equity firm focused on energy and commodities.

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 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.

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 the indenture that governs 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, 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.

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Derivative Financial Instruments (Details) (USD $) In Thousands, unless otherwise specified	Jun. 30, 2012	Dec. 31, 2011
Fair Values of Derivative Contracts
Current asset portion of Derivative financial instruments	$ 41,289	$ 28,582
Derivative financial instruments	(244)	(1,300)
Long-term asset portion of Derivative financial instruments	29,423	24,244
Long-term liability portion of Derivative financial instruments		(57)
Fair value of oil and gas commodity contracts, assets [Member]
Fair Values of Derivative Contracts
Current asset portion of Derivative financial instruments	65,114	56,716
Derivative financial instruments
Long-term asset portion of Derivative financial instruments	52,127	52,422
Long-term liability portion of Derivative financial instruments
Fair value of oil and gas commodity contracts, (liabilities) [Member]
Fair Values of Derivative Contracts
Current asset portion of Derivative financial instruments	(23,825)	(28,134)
Derivative financial instruments	(32)
Long-term asset portion of Derivative financial instruments	(22,704)	(28,178)
Long-term liability portion of Derivative financial instruments		(57)
Fair value of interest rate contracts, (liabilities) [Member]
Fair Values of Derivative Contracts
Current asset portion of Derivative financial instruments
Derivative financial instruments	(212)	(1,300)
Long-term asset portion of Derivative financial instruments
Long-term liability portion of Derivative financial instruments

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Property and Equipment (Tables)

6 Months Ended

Jun. 30, 2012

Property and Equipment [Abstract]

Property and equipment

Property and equipment consists of the following:

	June 30, 2012			December 31, 2011
	(unaudited)
	(dollars in thousands)
OIL AND NATURAL GAS PROPERTIES
Unproved properties	$	45,571		$	34,797
Accumulated impairment		(7,175	)		(5,427	)
Unproved properties, net		38,396			29,370
Proved oil and natural gas properties		1,032,233			925,578
Accumulated depreciation, depletion, amortization and impairment		(432,600	)		(382,132	)
Proved oil and natural gas properties, net		599,633			543,446
TOTAL OIL AND NATURAL GAS PROPERTIES, net		638,029			572,816
LAND		1,185			1,185
DRILLING RIG		10,500			10,500
Accumulated depreciation		(1,487	)		(1,137	)
TOTAL DRILLING RIG, net		9,013			9,363
OTHER PROPERTY AND EQUIPMENT
Office furniture and equipment, vehicles		8,519			7,313
Accumulated depreciation		(2,420	)		(1,510	)
OTHER PROPERTY AND EQUIPMENT, net		6,099			5,803
TOTAL PROPERTY AND EQUIPMENT, net	$	654,326		$	589,167

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Accounts Payable and Accrued Liabilities (Tables)

6 Months Ended

Jun. 30, 2012

Accounts Payable and Accrued Liabilities [Abstract]

Detail of accounts payable and accrued liabilities

The following provides the detail of accounts payable and accrued liabilities:

	June 30, 2012		December 31, 2011
	(unaudited)
	(dollars in thousands)
Capital expenditures	$	28,513	$	19,119
Revenues and royalties payable		7,329		6,742
Operating expenses/taxes		21,794		21,147
Compensation		8,175		3,567
Acquisition costs payable		3,846		2,883
Other		6,445		5,754
Total accrued liabilities		76,102		59,212
Accounts payable		12,574		11,083
Accounts payable and accrued liabilities	$	88,676	$	70,295

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Derivative Financial Instruments (Details Textual)	3 Months Ended	6 Months Ended
	Jun. 30, 2012	Jun. 30, 2012
Derivative Financial Instruments (Textual) [Abstract]
LIBOR floating rate period		3 months
Derivative instruments not designated as hedging instruments, description of terms	Commodity contracts are subject to master netting arrangements and are presented on a net basis in the consolidated balance sheets

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Summary of Organization and Nature of Operations

6 Months Ended

Jun. 30, 2012

Summary of Organization and Nature of Operations [Abstract]

SUMMARY OF ORGANIZATION AND NATURE OF OPERATIONS

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, 2011, which were filed with the Securities and Exchange Commission in our Annual Report on Form 10-K (the “2011 Form 10-K”).

The consolidated financial statements included herein as of June 30, 2012, and for the six month periods ended June 30, 2012 and 2011, 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, Alta Mesa Services, LP, AM Idaho LLC, and Alabama Energy Resources LLC, 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 onshore oil and natural gas properties. Our core properties are located primarily in Texas, Louisiana, and Oklahoma.

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Derivative Financial Instruments

6 Months Ended

Jun. 30, 2012

Derivative Financial Instruments [Abstract]

DERIVATIVE FINANCIAL INSTRUMENTS

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 our 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, or in the case of financial basis hedging contracts, based on a designated price differential between various benchmark prices. Cash settlement occurs monthly. 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 income at each reporting date. Realized gains and losses on commodities hedging contracts are included in oil and natural gas revenues.

We have entered into an interest rate swap agreement to mitigate the risk of loss due to changes in interest rates. The interest rate swap is not designated as a cash flow hedge 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 swap contract 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 six month periods ended June 30, 2012 and 2011.

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 June 30, 2012
	Current asset portion of Derivative financial instruments			Current liability portion of Derivative financial instruments			Long-term asset portion of Derivative financial instruments			Long-term liability portion of Derivative financial instruments
	(unaudited)
	(dollars in thousands)
Fair value of oil and gas commodity contracts, assets	$	65,114		$	—		$	52,127		$	—
Fair value of oil and gas commodity contracts, (liabilities)		(23,825	)		(32	)		(22,704	)		—
Fair value of interest rate contracts, (liabilities)		—			(212	)		—			—
Total net assets, (liabilities)	$	41,289		$	(244	)	$	29,423		$	—

Fair Values of Derivative Contracts

	Balance Sheet Location at December 31, 2011
	Current asset portion of Derivative financial instruments			Current liability portion of Derivative financial instruments			Long-term asset portion of Derivative financial instruments			Long-term liability portion of Derivative financial instruments
	(dollars in thousands)
Fair value of oil and gas commodity contracts, assets	$	56,716		$	—		$	52,422		$	—
Fair value of oil and gas commodity contracts, (liabilities)		(28,134	)		—			(28,178	)		(57	)
Fair value of interest rate contracts, (liabilities)		—			(1,300	)		—			—
Total net assets, (liabilities)	$	28,582		$	(1,300	)	$	24,244		$	(57	)

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 income:

Derivatives not designated as hedging	Location of Gain	Classification of	For the three months ended June 30,				For the six months  ended June 30,
instruments under ASC 815	(Loss)	Gain (Loss)	2012		2011		2012		2011
			(unaudited)				(unaudited)
			(dollars in thousands)
Natural gas commodity contracts	Natural gas revenues	Realized	$	11,089	$	5,120	$	19,629	$	10,911
Oil commodity contracts	Oil revenues	Realized		619		(2,434)		(790)		(3,918)
Interest rate contracts	Interest benefit (expense)	Realized		(564)		2,298		(1,126)		1,928
Total realized gains (losses) from derivatives not designated as hedges			$	11,144	$	4,984	$	17,713	$	8,921
Natural gas commodity contracts	Unrealized gain (loss) — oil and natural gas derivative contracts	Unrealized	$	(13,667)	$	1,659	$	(5,881)	$	(1,299)
Oil commodity contracts	Unrealized gain (loss) — oil and natural gas derivative contracts	Unrealized		37,973		12,718		23,792		(3,509)
Interest rate contracts	Interest benefit (expense)	Unrealized		561		465		1,088		508
Total unrealized gains (losses) from derivatives not designated as hedges			$	24,867	$	14,842	$	18,999	$	(4,300)

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.

We had the following open derivative contracts for natural gas at June 30, 2012 (unaudited):

NATURAL GAS DERIVATIVE CONTRACTS

	Volume in		Weighted		Range
Period and Type of Contract	MMbtu		Average		High		Low
2012
Price Swap Contracts		8,405,000	$	4.79	$	8.83	$	3.06
Collar Contracts
Short Call Options		4,940,000		5.53		6.00		4.50
Long Put Options		3,866,000		5.09		6.75		4.00
Long Call Options		2,760,000		4.67		5.00		4.00
Short Put Options		6,986,000		3.44		4.50		2.50
2013
Price Swap Contracts		19,400,000		4.75		9.15		3.30
Collar Contracts
Short Call Options		1,825,000		5.25		5.25		5.25
Long Put Options		1,500,000		6.09		6.15		6.00
Long Call Options		3,625,000		5.87		7.00		4.75
Short Put Options		18,748,500		3.18		5.00		3.00
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		2,623,500		4.14		5.50		3.00
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 June 30, 2012 (unaudited):

OIL DERIVATIVE CONTRACTS

			Weighted		Range
Period and Type of Contract	Volume in Bbls		Average		High		Low
2012
Price Swap Contracts		266,800	$	114.10	$	121.15	$	80.20
Collar Contracts
Short Call Options		753,398		116.56		132.00		90.00
Long Put Options		736,000		97.53		105.00		65.00
Long Call Options		151,350		99.25		123.50		80.20
Short Put Options		967,100		77.09		85.00		68.75
2013
Price Swap Contracts		392,000		89.75		94.74		77.00
Collar Contracts
Short Call Options		998,660		118.03		134.00		90.00
Long Put Options		1,273,500		108.35		115.00		85.00
Long Call Options		197,475		94.14		127.00		79.00
Short Put Options		1,538,500		80.85		90.00		60.00
2014
Price Swap Contracts		255,050		96.57		105.48		81.00
Collar Contracts
Short Call Options		273,750	$	125.70	$	133.50	$	107.50
Long Put Options		670,950		89.32		100.00		80.00
Short Put Options		777,530		70.78		80.00		60.00
2015
Price Swap Contracts		401,500		99.30		99.30		99.30
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
Price Swap Contracts		292,800		94.95		95.00		94.90
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 natural gas at June 30, 2012 (unaudited):

Volume in MMbtu	Reference Price 1 (1)		Reference Price 2 (1)		Period		Spread ($ per MMbtu)
920,000		NYMEX Henry Hub		Houston Ship Channel		July ’12 —Dec ’12	$	0.1575
1,840,000		NYMEX Henry Hub		Houston Ship Channel		July ’12 —Dec ’12	$	0.1400
3,650,000		NYMEX Henry Hub		Houston Ship Channel		Jan ’13 — Dec ’13	$	0.0625

⁽¹⁾ The spread in these trades limits the differential of the settlement quotation prices for NYMEX Henry Hub over the Houston Ship Channel index published in Inside FERC.

We had the following open financial basis swap contracts for oil at June 30, 2012 (unaudited):

Volume in Bbl	Reference Price 1  (2)		Reference Price 2  (2)		Period		Average Spread ($ per  Bbl)
828,000		Brent IPE		Argus Louisiana Light Sweet		July ’12 —Dec ’12	$	1.92
1,277,500		Brent IPE		Argus Louisiana Light Sweet		Jan ’13 — Dec ’13	$	3.09

⁽²⁾  The spread in these trades limits the differential of the settlement quotation prices for Brent IPE over Argus Louisiana Light Sweet crude.

We had the following open interest rate swap contract at June 30, 2012 (unaudited):

Term	Principal Amount		Interest Rate (3)
	(dollars in thousands)
Floating to Fixed Rate Swap:
July 2012 — August 2012	$	50,000		4.95	%

(3) The floating rate is the three-month LIBOR rate.

XML

Summary of Significant Accounting Policies (Details) (USD $)	3 Months Ended		6 Months Ended
	Jun. 30, 2012	Jun. 30, 2011	Jun. 30, 2012	Jun. 30, 2011	Dec. 31, 2011
Summary of Significant Accounting Policies (Textual) [Abstract]
Accounts receivable net of allowance for doubtful accounts	$ 635,000		$ 635,000		$ 557,000
Amortization of loan costs	570,000	790,000	1,137,000	1,694,000
Accumulated amortization, deferred financing costs	8,600,000		8,600,000		7,500,000
Fair value of senior notes payable	$ 297,000,000		$ 297,000,000		$ 293,000,000

XML

Derivative Financial Instruments (Details 4)	3 Months Ended				6 Months Ended	3 Months Ended		6 Months Ended	3 Months Ended		6 Months Ended
	Jun. 30, 2012 Reference Price 1 [Member]	Jun. 30, 2012 Reference Price 2 [Member]	Jun. 30, 2012 Financial basis spread contract for gas 1 [Member] Reference Price 1 [Member]	Jun. 30, 2012 Financial basis spread contract for gas 1 [Member] Reference Price 2 [Member]	Jun. 30, 2012 Financial basis spread contract for gas 1 [Member] Houston Ship Channel [Member] NYMEX Henry Hub [Member] MMBTU	Jun. 30, 2012 Financial basis spread contract for gas 2 [Member] Reference Price 1 [Member]	Jun. 30, 2012 Financial basis spread contract for gas 2 [Member] Reference Price 2 [Member]	Jun. 30, 2012 Financial basis spread contract for gas 2 [Member] Houston Ship Channel [Member] NYMEX Henry Hub [Member] MMBTU	Jun. 30, 2012 Financial basis spread contract for gas 3 [Member] Reference Price 1 [Member]	Jun. 30, 2012 Financial basis spread contract for gas 3 [Member] Reference Price 2 [Member]	Jun. 30, 2012 Financial basis spread contract for gas 3 [Member] Houston Ship Channel [Member] NYMEX Henry Hub [Member] MMBTU
Open financial basis swap contracts for gas
Volume in MMbtu					920,000			1,840,000			3,650,000
Derivative, Underlying Basis	Brent IPE	Argus Louisiana Light Sweet	NYMEX Henry Hub	Houston Ship Channel		NYMEX Henry Hub	Houston Ship Channel		NYMEX Henry Hub	Houston Ship Channel
First remaining period of term of derivative contract					Jul. 01, 2012			Jul. 01, 2012			Jan. 01, 2013
Last Remaining Period of Term of Derivative Contract					Dec. 31, 2012			Dec. 31, 2012			Dec. 31, 2013
Spread limit under basis spread commodity contract					0.1575			0.1400			0.0625

XML

Significant Acquisitions (Tables)

6 Months Ended

Jun. 30, 2012

Significant Acquisitions [Abstract]

Summary of consideration paid and preliminary allocations of purchase prices

A summary of the consideration paid and the preliminary allocations of the purchase prices are as follows (dollars in thousands):

Summary of Consideration:	Sydson		TODD
Cash	$	27,500	$	22,500
Fair value of asset retirement obligations assumed		922		863
Total	$	28,422	$	23,363
Summary of Purchase Price Allocations:
Proved oil and natural gas properties	$	18,330	$	15,223
Unproved oil and natural gas properties		10,092		8,140
Total	$	28,422	$	23,363

Pro forma results for the combined entity

	(Unaudited)
	Revenue		Income
	(dollars in thousands)
Pro forma results for the combined entity for the six months ended June 30, 2011	$	150,653	$	15,347