Alta Mesa 10Q 2011 Q2 Quarterly report

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, DC 20549

FORM 10-Q

(Mark One)


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

For the quarterly period ended: June 30, 2011


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

For the transition period from to

Commission file number: 333-173751

ALTA MESA HOLDINGS, LP

(Exact name of registrant as specified in its charter)


Texas (State or other jurisdiction of incorporation or organization)		20-3565150 (I.R.S. Employer Identification No.)

15021 Katy Freeway, Suite 400, Houston, Texas (Address of principal executive offices)		77094 (Zip Code)

Registrant’s telephone number, including area code:281-530-0991

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yeso Noþ

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.) Yesþ Noo

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 filero		Accelerated filero		Non-accelerated filerþ(Do not check if a smaller reporting company)		Smaller reporting companyo

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yeso Noþ

Table of Contents


	Page Number
PART I — FINANCIAL INFORMATION

Item 1. Financial Statements

Consolidated Balance Sheets as of June 30, 2011 (unaudited) and December 31, 2010		5

Consolidated Statements of Income (unaudited) for the Three and Six Months Ended June 30, 2011 and 2010		6

Consolidated Statements of Cash Flows (unaudited) for the Six Months Ended June 30, 2011 and 2010		7

Notes to Consolidated Financial Statements (unaudited)		8

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations		26

Item 3. Quantitative and Qualitative Disclosures about Market Risk		38

Item 4. Controls and Procedures		38

PART II — OTHER INFORMATION

Item 1. Legal Proceedings		38

Item 1A. Risk Factors		38

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds		38

Item 3. Defaults Upon Senior Securities		39

Item 4. (Removed and Reserved)		39

Item 5. Other Information		39

Item 6. Exhibits		39

Signatures		40
EX-10.1
EX-10.2
EX-10.3
EX-31.1
EX-31.2
EX-32.1
EX-32.2
EX-101 INSTANCE DOCUMENT
EX-101 SCHEMA DOCUMENT
EX-101 CALCULATION LINKBASE DOCUMENT
EX-101 LABELS LINKBASE DOCUMENT
EX-101 PRESENTATION LINKBASE DOCUMENT

CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS

The information in this report includes “forward-looking statements.” All statements, other than statements of historical fact included in this Quarterly Report on Form 10-Q, regarding our strategy, future operations, financial position, estimated revenues and losses, projected costs, prospects, plans and objectives of management are forward-looking statements. When used in this report, the words “could”, “should”, “will”, “play”, “believe”, “anticipate”, “intend”, “estimate”, “expect”, “project” and similar expressions are intended to identify forward-looking statements, although not all forward-looking statements contain such identifying words. These forward-looking statements are based on our current expectations and assumptions about future events and are based on currently available information as to the outcome and timing of future events. When considering forward-looking statements, you should keep in mind the risk factors and other cautionary statements described under the heading “Risk Factors” included in our Registration Statement on Form S-4 (Commission File No. 333-173751 filed on July 11, 2011, the “Form S-4”) and Part II, Item 1A of this report. These forward-looking statements are based on management’s current belief, based on currently available information, as to the outcome and timing of future events.

Forward-looking statements may include statements about our:

	•		business strategy;

	•		reserves;

	•		financial strategy, liquidity and capital required for our development program;

	•		realized oil and natural gas prices;

	•		timing and amount of future production of oil and natural gas;

	•		hedging strategy and results;

	•		future drilling plans;

	•		competition and government regulations;

	•		marketing of oil and natural gas;

	•		leasehold or business acquisitions;

	•		costs of developing our properties;

	•		liquidity and access to capital;

	•		uncertainty regarding our future operating results; and

	•		plans, objectives, expectations and intentions contained in this report that are not historical.

We caution you that these forward-looking statements are subject to all of the risks and uncertainties, most of which are difficult to predict and many of which are beyond our control, incident to the exploration for and development and production of oil and natural gas. These risks include, but are not limited to volatility of oil and natural gas prices, general economic conditions, credit markets, inflation, the credit rating of U.S. government debt, production timing and volumes, estimates of proved reserves, operating costs and capital expenditures, lack of availability of drilling and production equipment and services, environmental risks, drilling and other operating risks, regulatory changes, the uncertainty inherent in estimating oil and natural gas reserves and in projecting future rates of production, cash flow and access to capital, and the other risks described under “Risk Factors” in our Form S-4.

Reserve engineering is a process of estimating underground accumulations of oil and natural gas that cannot be measured in an exact way. The accuracy of any reserve estimate depends on the quality of available

data, the interpretation of such data and price and cost assumptions made by reservoir engineers. In addition, the results of drilling, testing and production activities may justify revisions of estimates that were made previously. If significant, such revisions would change the schedule of any further production and development drilling. Accordingly, reserve estimates may differ significantly from the quantities of oil and natural gas that are ultimately recovered.

Should one or more of the risks or uncertainties described in the Form S-4 or this report occur, or should underlying assumptions prove incorrect, our actual results and plans could differ materially from those expressed in any forward-looking statements.

All forward-looking statements, expressed or implied, included in this report are expressly qualified in their entirety by this cautionary statement. This cautionary statement should also be considered in connection with any subsequent written or oral forward-looking statements that we or persons acting on our behalf may issue.

Except as otherwise required by applicable law, we disclaim any duty to update any forward-looking statements, all of which are expressly qualified by the statements in this section, to reflect events or circumstances after the date of this Quarterly Report on Form 10-Q.

PART I — FINANCIAL INFORMATION

ITEM 1.Financial Statements

ALTA MESA HOLDINGS, LP AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS
(dollars in thousands)


	June 30,		December 31,
	2011		2010
	(unaudited)
ASSETS
CURRENT ASSETS
Cash and cash equivalents	$	5,523	$	4,836
Accounts receivable, net		41,509		38,081
Other receivables		1,947		6,338
Prepaid expenses and other current assets		4,608		2,292
Derivative financial instruments		11,125		10,436

TOTAL CURRENT ASSETS		64,712		61,983


PROPERTY AND EQUIPMENT
Oil and natural gas properties, successful efforts method, net		527,863		442,880
Other property and equipment, net		15,981		13,384

TOTAL PROPERTY AND EQUIPMENT, NET		543,844		456,264


OTHER ASSETS
Investment in Partnership — cost		9,000		9,000
Deferred financing costs, net		13,447		13,552
Derivative financial instruments		8,668		14,165
Advances to operators		5,980		2,699
Deposits		1,323		576

TOTAL OTHER ASSETS		38,418		39,992


TOTAL ASSETS	$	646,974	$	558,239


LIABILITIES AND PARTNERS’ CAPITAL

CURRENT LIABILITIES
Accounts payable and accrued liabilities	$	74,145	$	87,255
Current portion, asset retirement obligations		1,755		1,617
Derivative financial instruments		3,176		3,092

TOTAL CURRENT LIABILITIES		79,076		91,964


LONG-TERM LIABILITIES
Asset retirement obligations		44,487		41,096
Long-term debt		457,906		371,276
Notes payable to founder		20,309		19,709
Derivative financial instruments		1,704		2,296
Other long-term liabilities		5,440		7,240

TOTAL LONG-TERM LIABILITIES		529,846		441,617


TOTAL LIABILITIES		608,922		533,581

COMMITMENTS AND CONTINGENCIES (NOTE 10)

PARTNERS’ CAPITAL		38,052		24,658


TOTAL LIABILITIES AND PARTNERS’ CAPITAL	$	646,974	$	558,239

See notes to consolidated financial statements.

ALTA MESA HOLDINGS, LP AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF INCOME
(dollars in thousands)
(unaudited)


	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2011			2010			2011			2010
REVENUES
Natural gas	$	38,731		$	30,120		$	74,112		$	57,935
Oil		39,292			16,278			71,489			25,799
Natural gas liquids		2,847			1,214			5,900			1,943
Other revenues		297			386			766			407

		81,167			47,998			152,267			86,084
Unrealized gain (loss) — oil and natural gas derivative contracts		14,377			2,105			(4,808	)		22,908

TOTAL REVENUES		95,544			50,103			147,459			108,992


EXPENSES
Lease and plant operating expense		15,041			9,354			28,372			17,432
Production and ad valorem taxes		4,069			2,785			9,470			4,398
Workover expense		2,352			1,330			3,978			3,289
Exploration expense		5,690			1,651			8,421			4,572
Depreciation, depletion, and amortization		22,963			13,500			42,431			22,122
Impairment expense		4,929			643			10,755			2,093
Accretion expense		476			270			946			415
General and administrative expenses		8,843			4,679			14,593			6,902

TOTAL EXPENSES		64,363			34,212			118,966			61,223


INCOME FROM OPERATIONS		31,181			15,891			28,493			47,769

OTHER INCOME (EXPENSE)
Interest expense		(6,843	)		(4,530	)		(16,323	)		(8,729	)
Interest income		12			5			14			5
Gain on contract settlement		1,285			—			1,285			—

TOTAL OTHER INCOME (EXPENSE)		(5,546	)		(4,525	)		(15,024	)		(8,724	)


INCOME BEFORE STATE INCOME TAXES		25,635			11,366			13,469			39,045

(PROVISION FOR) STATE INCOME TAXES		(75	)		—			(75	)		—


NET INCOME	$	25,560		$	11,366		$	13,394		$	39,045

See notes to consolidated financial statements.

ALTA MESA HOLDINGS, LP AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS
(dollars in thousands)
(unaudited)


	Six Months Ended June 30,
	2011			2010
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$	13,394		$	39,045
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion, and amortization		42,431			22,122
Impairment expense		10,755			2,093
Accretion expense		946			415
Amortization of loan costs		1,694			629
Amortization of debt discount		130			—
Dry hole expense		5,267			219
Unrealized (gain) loss on derivatives		4,300			(23,311	)
(Gain) on contract settlement		(1,285	)		—
Interest converted into debt		600			590
Settlement of asset retirement obligation		(246	)		(463	)
Changes in assets and liabilities:
Accounts receivable		(3,428	)		619
Other receivables		4,391			148
Prepaid expenses and other non-current assets		(6,344	)		(6,331	)
Accounts payable, accrued liabilities, other long-term liabilities		(1,455	)		(19,669	)

NET CASH PROVIDED BY OPERATING ACTIVITIES		71,150			16,106


CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures for property and equipment		(94,139	)		(32,289	)
Acquisitions		(61,235	)		(101,359	)

NET CASH USED IN INVESTING ACTIVITIES		(155,374	)		(133,648	)


CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from long-term debt		86,500			95,000
Repayments of long-term debt		—			(167	)
Additions to deferred financing costs		(1,589	)		(7,164	)
Capital contributions		—			50,000
Capital distributions		—			(55	)

NET CASH PROVIDED BY FINANCING ACTIVITIES		84,911			137,614

NET INCREASE IN CASH		687			20,072

CASH AND CASH EQUIVALENTS, beginning of period		4,836			4,274


CASH AND CASH EQUIVALENTS, end of period	$	5,523		$	24,346


SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION

Cash paid during the period for interest	$	16,484		$	8,234
Cash paid during the period for taxes	$	—		$	—
Change in property asset retirement obligations, net	$	2,829		$	326
Change in accruals or liabilities for capital expenditures	$	(12,170	)	$	14,871

See notes to consolidated financial statements.

ALTA MESA HOLDINGS, LP AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(unaudited)

1. SUMMARY OF ORGANIZATION AND NATURE OF OPERATIONS

The consolidated financial statements reflect the accounts of Alta Mesa Holdings, LP and its subsidiaries (we, us, our, the “Company,” and “Alta Mesa”) after elimination of all significant intercompany transactions and balances. The financial statements should be read in conjunction with the consolidated financial statements and notes thereto included in our annual consolidated financial statements for the year ended December 31, 2010, which were filed with the Securities and Exchange Commission in our Registration Statement on Form S-4 (Commission File No. 333-173751).

The consolidated financial statements included herein as of June 30, 2011, and for the six month periods ended June 30, 2011 and 2010, are unaudited, and in the opinion of management, the information furnished reflects all material adjustments, consisting of normal recurring adjustments, necessary for a fair presentation of consolidated financial position and of the results of operations for the interim periods presented. The consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the U.S. (“GAAP”) for interim financial information and with the instructions to Form 10-Q and Article 10 of Regulation S-X. Accordingly, they do not include all of the information and footnotes required by GAAP for complete financial statements. Certain minor reclassifications of prior period consolidated financial statements have been made to conform to current reporting practices. The consolidated results of operations for interim periods are not necessarily indicative of results to be expected for a full year.

We use accounting policies which reflect industry practices and conform to GAAP. As used herein, the following acronyms have the following meanings: “FASB” means the Financial Accounting Standards Board; the “Codification” refers to the Accounting Standards Codification, the collected accounting and reporting guidance maintained by the FASB; “ASC” means Accounting Standards Codification and is generally followed by a number indicating a particular section of the Codification; and “ASU” means Accounting Standards Update, followed by an identification number, which are the periodic updates made to the Codification by the FASB. “SEC” means the Securities and Exchange Commission.

Organization:The consolidated financial statements presented herein are of Alta Mesa Holdings, LP and its (i) wholly-owned subsidiaries: Alta Mesa Finance Services Corp., Alta Mesa Eagle, LLC, Alta Mesa Acquisition Sub, LLC, and its direct and indirect wholly-owned subsidiaries, Alta Mesa Energy, LLC, Aransas Resources, LP and its wholly-owned subsidiary ARI Development, LLC, Brayton Resources II, LP, Buckeye Production Company, LP, Galveston Bay Resources, LP, Louisiana Exploration & Acquisitions, LP and its wholly-owned subsidiary Louisiana Exploration & Acquisition Partnership, LLC, Navasota Resources, Ltd., LLP, Nueces Resources, LP, Oklahoma Energy Acquisitions, LP, Alta Mesa Drilling, LLC, Petro Acquisitions, LP, Petro Operating Company, LP, Texas Energy Acquisitions, LP, Virginia Oil and Gas, LLC and Alta Mesa Services, LP, and (ii) partially-owned subsidiaries: Brayton Resources, LP, and Orion Operating Company, LP.

Nature of Operations: We are engaged primarily in the acquisition, exploration, development, and production of oil and natural gas properties. Our properties are located primarily in Texas, Oklahoma, Louisiana, Florida and the Appalachian Region.

2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

As of June 30, 2011, our significant accounting policies are consistent with those discussed in Note 2 of the consolidated financial statements for the fiscal year ended December 31, 2010.

Use of Estimates:The preparation of consolidated financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the consolidated financial statements and the reported amounts of revenues and expenses during the reporting period.

Reserve estimates significantly impact depreciation, depletion and amortization expense and potential impairments of oil and natural gas properties and are subject to change based on changes in oil and natural gas prices and trends and changes in estimated reserve quantities. We analyze estimates, including those related to oil and natural gas reserves, oil and natural gas revenues, the value of oil and natural gas properties, bad debts, asset retirement obligations, derivative contracts, income taxes and contingencies and litigation. We base our estimates on historical experience and various other assumptions that are believed to be reasonable under the circumstances. Actual results may differ from these estimates.

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 $957,000 and $338,000 at June 30, 2011 and December 31, 2010, respectively.

Deferred Financing Costs:Deferred financing costs and the amount of discount at which notes payable have been issued (debt discount) are amortized using the straight-line method, which approximates the interest method, over the term of the related debt. For the three months ended June 30, 2011 and 2010, amortization of deferred financing costs included in interest expense amounted to $790,000 and $506,000, respectively. For the six months ended June 30, 2011 and 2010, amortization of deferred financing costs included in interest expense amounted to $1.7 million and $629,000, respectively. Deferred financing costs are listed among our long-term assets, net of accumulated amortization of $6.4 million and $4.7 million at June 30, 2011 and December 31, 2010, respectively.

Financial Instruments:The fair value of cash, accounts receivable, other current assets, and current liabilities approximate book value due to their short-term nature. The estimate of fair value of long-term debt under our senior secured revolving credit facility (“credit facility”) is not considered to be materially different from carrying value due to market rates of interest. The fair value of the debt to our founder is not practicable to determine. We have estimated the fair value of our senior notes payable at $299.3 million and $291 million on June 30, 2011 and December 31, 2010, respectively. See Note 5 for further information on fair values of financial instruments. See Note 8 for information on long-term debt.

Recent Accounting Pronouncements

On May 12, 2011, the FASB issued 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.” The ASU changes certain definitions of terms used its guidance regarding fair value measurements, as well as modifying certain disclosure requirements and other aspects of the guidance. We are reviewing the ASU, which is effective for interim and annual periods beginning after December 15, 2011. We do not expect adoption of the guidance to have a material impact on our consolidated financial position or results of operations.

On June 16, 2011, the FASB issued ASU No. 2011-05,Presentation of Comprehensive Income.This standard eliminates the current option to report other comprehensive income and its components in the statement of changes in equity. Two presentation options remain. Changes in comprehensive income

may be reported in a continuous statement of comprehensive income which presents the components of net income as well as the components of comprehensive income. Alternatively, the components of comprehensive income may be reported in a separate statement of comprehensive income, which must immediately follow the statement of net income. The ASU also creates a new requirement that reclassifications from comprehensive income to net income be presented on a gross basis on the face of the financial statements (previously net presentation and footnoting gross information was permitted). The ASU applies to interim and year end reports and is effective for fiscal years beginning after December 15, 2011, and is to be retrospectively applied to all periods presented in such reports. Early adoption is permitted. We do not expect adoption of the guidance to have a material impact on our consolidated financial position or results of operations.

3. SIGNIFICANT ACQUISITIONS

Meridian Acquisition

On and effective May 13, 2010, Alta Mesa Acquisition Sub, LLC (“AMAS”), a wholly owned subsidiary of Alta Mesa Holdings, LP, acquired 100% of the shares of and merged with The Meridian Resource Corporation (“Meridian”), with AMAS as the surviving entity. Meridian was a publicly traded company engaged in exploration for and production of oil and natural gas. The oil and natural gas properties of Meridian are similar and in some cases proximate to our areas of operation. Meridian shareholders were paid in cash, funded by proceeds of our credit facility as well as a $50 million equity contribution from our private equity partner Alta Mesa Investment Holdings Inc., an affiliate of Denham Commodities Partners Fund IV LP (“AMIH”). The merger increased the oil portion of our reserves portfolio, improving the balance of our reserves between oil and natural gas, and provided significant additions to our library of 3-D seismic data.

Total cost of the acquisition was $158 million. It was recorded using the acquisition method of accounting. The purchase price was allocated to acquired assets and assumed liabilities based on their estimated fair values at date of acquisition. Acquisition-related costs of approximately $532,000 were recorded in general and administrative expense for the year ended December 31, 2010.

Sydson Acquisition

On April 21, 2011, we purchased from Sydson Energy and certain of its related parties (together, “Sydson” and the “Sydson acquisition”) certain oil and natural gas assets primarily located in Texas and South Louisiana in which we had jointly participated with Sydson. The purchase price was $27.5 million in cash (a total cost of $28.4 million including abandonment liabilities we assumed). Total net proved reserves acquired are estimated to be 800 MBOE (5 Bcfe), 45% of which is oil. By virtue of this acquisition, we increased our after payout net revenue interest in the Eagle Ford Shale by over 50%. Funding for the acquisition was provided through our credit facility. In addition, litigation associated with a portion of the assets purchased was resolved as a result of the transaction.

TODD Acquisition

On June 17, 2011, we purchased from Texas Oil Distribution & Development, Inc. and Matrix Petroleum LLC and certain other parties (together, “TODD” and the “TODD acquisition”) certain oil and natural gas assets primarily located in Texas and South Louisiana in which we had jointly participated with TODD. The purchase price was $22.5 million in cash (a total cost of $23.4 million including abandonment liabilities we assumed). Total net proved reserves acquired are estimated to be 700 MBOE (4 Bcfe), 36% of which is oil. By virtue of this acquisition, we increased our after payout net revenue interest in the Eagle Ford Shale by an additional 15%. Funding for the acquisition was provided through our credit facility. In addition, litigation associated with TODD was resolved as a result of the transaction.

A summary of the consideration paid and the allocations of the purchase prices (which are preliminary for

the Sydson and TODD acquisitions) are as follows(dollars in thousands):


Summary of Consideration:	Meridian		Sydson		TODD
Cash	$	30,948	$	27,500	$	22,500
Debt retired		82,000		—		—
Debt assumed		5,346		—		—
Working capital deficit⁽¹⁾		753		—		—
Other liabilities assumed		7,971		—		—
Fair value of asset retirement obligations assumed		30,920		922		863

Total	$	157,938	$	28,422	$	23,363


Summary of Purchase Price Allocations:
Proved oil and natural gas properties	$	144,325	$	18,330	$	15,223
Unproved oil and natural gas properties		3,113		10,092		8,140
Other tangible assets		10,500		—		—

Total	$	157,938	$	28,422	$	23,363


⁽¹⁾		Meridian working capital deficit included a cash balance of $11,589,000.

The revenue and earnings related to the Meridian, Sydson, and TODD acquisitions are included in our consolidated statement of income for the six months ended June 30, 2011. The revenue and earnings related to the Meridian acquisition are included in our consolidated statement of income for the six months ended June 30, 2010. Revenue and earnings, had the acquisitions occurred on January 1, 2010, are provided below. This unaudited pro forma information has been derived from historical information and is for illustrative purposes only. The unaudited pro forma financial information does not attempt to predict or suggest future results. It also does not necessarily reflect what the historical results of the combined company would have been had the companies been combined during these periods.


	(Unaudited)
	Revenue		Income
	(dollars in thousands)
Actual results of Meridian included in our statement of income for the six months ended June 30, 2011	$	64,544	$	32,651

Actual results of Sydson included in our statement of income for the period April 21, 2011 through June 30, 2011	$	1,817	$	588

Actual results of TODD included in our statement of income for the period June 17, 2011 through June 30, 2011	$	724	$	193

Pro forma results for the combined entity for the six months ended June 30, 2011	$	150,653	$	15,347

Pro forma results for the combined entity for the six months ended June 30, 2010	$	142,555	$	41,155

4. PROPERTY AND EQUIPMENT

Property and equipment consists of the following:


	June 30,			December 31,
	2011			2010
	(unaudited)
	(dollars in thousands)
OIL AND NATURAL GAS PROPERTIES
Unproved properties	$	35,256		$	12,020
Accumulated impairment		(4,679	)		(2,686	)

Unproved properties, net		30,577			9,334

Proved oil and natural gas properties		821,399			707,364
Accumulated depreciation, depletion, amortization and impairment		(324,113	)		(273,818	)

Proved oil and natural gas properties, net		497,286			433,546

TOTAL OIL AND NATURAL GAS PROPERTIES, net		527,863			442,880


LAND		1,185			1,185


DRILLING RIG		10,500			10,500
Accumulated depreciation		(794	)		(444	)


TOTAL DRILLING RIG, net		9,706			10,056


OTHER PROPERTY AND EQUIPMENT
Office furniture and equipment, vehicles		7,251			3,844
Accumulated depreciation		(2,161	)		(1,701	)


OTHER PROPERTY AND EQUIPMENT, net		5,090			2,143


TOTAL PROPERTY AND EQUIPMENT, net	$	543,844		$	456,264

5. FAIR VALUE DISCLOSURES

We follow the guidance of ASC 820, “Fair Value Measurements and Disclosures,” in the estimation of fair values. ASC 820 provides a hierarchy of fair value measurements, based on the inputs to the fair value estimation process. It requires disclosure of fair values classified according to defined “levels,” which are based on the reliability of the evidence used to determine fair value, with Level 1 being the most reliable and Level 3 the least. Level 1 evidence consists of observable inputs, such as quoted prices in an active market. Level 2 inputs typically correlate the fair value of the asset or liability to a similar, but not identical item which is actively traded. Level 3 inputs include at least some unobservable inputs, such as valuation models developed using the best information available in the circumstances.

We utilize the modified Black-Scholes option pricing model to estimate the fair value of oil and natural gas derivative contracts. Inputs to this model include observable inputs from the New York Mercantile Exchange (“NYMEX”) for futures contracts, and inputs derived from NYMEX observable inputs, such as implied volatility of oil and natural gas prices. We have classified the fair values of all our oil and natural gas derivative contracts as Level 2.

The fair value of our interest rate derivative contracts was calculated using the modified Black-Scholes option pricing model and is also considered a Level 2 fair value.

Oil and natural gas properties are subject to impairment testing and potential impairment write down. 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. Oil and gas properties with a carrying amount of $4.4 million were written down to their fair value of $2.3 million, resulting in an impairment charge of $2.1 million for the six months ended June 30, 2010. 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, and for the three months ended June 30, 2010, oil and gas properties with a carrying amount of $1.2 million were written down to their fair value of $0.6 million, resulting in an impairment charge of $0.6 million. Significant Level 3 assumptions used in the calculation of estimated discounted cash flows in the impairment analysis included our estimate of future oil and natural gas prices, production costs, development expenditures, estimated timing of production of proved reserves, appropriate risk-adjusted discount rates, and other relevant data.

In connection with the Meridian acquisition, we recorded oil and natural gas properties with a fair value of $147.4 million in the second quarter of 2010. In connection with the Sydson and TODD acquisitions, we recorded oil and natural gas properties with a fair value of $28.4 million, and $23.4 million, respectively, in the second quarter of 2011. For information on these acquisitions, see Note 3. Significant Level 3 inputs used were the same as those used in determining impairments based on estimated discounted cash flows for the acquired properties.

New additions to asset retirement obligations result from estimations for new properties, and fair values for them are categorized as Level 3. Such estimations are based on present value techniques which utilize company-specific information for such inputs as cost and timing of plug and abandonment of wells and facilities. We recorded $2.8 million and $34.6 million in additions to asset retirement obligations measured at fair value during the six months ended June 30, 2011 and 2010, respectively. The significant additions in 2010 were the result of the purchase of Meridian.

The following table presents information about our financial assets and liabilities measured at fair value on a recurring basis as of June 30, 2011 and December 31, 2010, and indicates the fair value hierarchy of the valuation techniques we utilized to determine such fair value:


	Level 1		Level 2		Level 3		Total
	(dollars in thousands)
*At June 30, 2011 (unaudited):*
Financial Assets:
Derivative contracts for oil and natural gas	$	—	$	59,898	$	—	$	59,898
Financial Liabilities:
Derivative contracts for oil and natural gas		—		40,105		—		40,105
Derivative contracts for interest rate		—		4,880		—		4,880

*At December 31, 2010:*
Financial Assets:
Derivative contracts for oil and natural gas	$	—	$	61,623	$	—	$	61,623
Financial Liabilities:
Derivative contracts for oil and natural gas		—		37,022		—		37,022
Derivative contracts for interest rate		—		5,388		—		5,388

The amounts above are presented on a gross basis; presentation on our consolidated balance sheets utilizes netting of assets and liabilities with the same counterparty where master netting agreements are in place. For additional information on derivative contracts, see Note 6.

6. DERIVATIVE FINANCIAL INSTRUMENTS

We account for our derivative contracts under the provisions of ASC 815, “Derivatives and Hedging.” We have entered into forward-swap contracts and collar contracts to reduce our exposure to price risk in the spot market for oil and natural gas. We also utilize financial basis swap contracts, which address the price differential between market-wide benchmark prices and other benchmark pricing referenced in certain of our natural gas sales contracts. Substantially all of our hedging agreements are executed by affiliates of the lenders under the credit facility described in Note 8 below, and are collateralized by the security interests of the respective affiliated lenders in certain of our assets under the credit facility. The contracts settle monthly and are scheduled to coincide with either oil production equivalent to barrels (Bbl) per month or gas production equivalent to volumes in millions of British thermal units (MMbtu) per month. The contracts represent agreements between us and the counter-parties to exchange cash based on a designated price. Prices are referenced to the natural gas spot market benchmark price at the Houston Ship Channel or the NYMEX index. Cash settlement occurs monthly based on the specified price benchmark. We have not designated any of our derivative contracts as fair value or cash flow hedges; accordingly we use mark-to-market accounting, recognizing unrealized gains and losses in the statement of operations at each reporting date. Realized gains and losses on commodities hedging contracts are included in oil and natural gas revenues.

We have entered into a series of interest rate swap agreements with several financial institutions to mitigate the risk of loss due to changes in interest rates. The interest rate swaps are not designated as cash flow hedges in accordance with ASC 815. Both realized gains and losses from settlement and unrealized gains and losses from changes in the fair market value of the interest rate swaps are included in interest expense.

The second table below provides information on the location and amounts of realized and unrealized gains and losses on derivatives included in the consolidated statements of income for each of the three month and six month periods ended June 30, 2011 and 2010.

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, 2011
	Current asset			Current liability			Long-term asset			Long-term liability
	portion of			portion of			portion of			portion of
	Derivative			Derivative			Derivative			Derivative
	financial			financial			financial			financial
	instruments			instruments			instruments			instruments
	(unaudited)
	(dollars in thousands)
Fair value of oil and gas commodity contracts, assets	$	25,913		$	—		$	33,985		$	—
Fair value of oil and gas commodity contracts, (liabilities)		(14,788	)		—			(25,317	)		—
Fair value of interest rate contracts, (liabilities)		—			(3,176	)		—			(1,704	)

Total net assets, (liabilities)	$	11,125		$	(3,176	)	$	8,668		$	(1,704	)


Fair Values of Derivative Contracts
	Balance Sheet Location at December 31, 2010
	Current asset			Current liability			Long-term asset			Long-term liability
	portion of			portion of			portion of			portion of
	Derivative			Derivative			Derivative			Derivative
	financial			financial			financial			financial
	instruments			instruments			instruments			instruments
	(dollars in thousands)
Fair value of oil and gas commodity contracts, assets	$	27,118		$	—		$	34,505		$	—
Fair value of oil and gas commodity contracts, (liabilities)		(16,682	)		—			(20,340	)		—
Fair value of interest rate contracts, (liabilities)		—			(3,092	)		—			(2,296	)

Total net assets, (liabilities)	$	10,436		$	(3,092	)	$	14,165		$	(2,296	)

Commodity contracts are subject to master netting arrangements and are presented on a net basis in the consolidated balance sheets. This netting can cause derivative assets to be ultimately presented in a (liability) account on the consolidated balance sheets. Likewise, derivative (liabilities) could be presented in an asset account.

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


Derivatives not
designated as hedging			For the three months						For the six months ended
instruments under ASC	Location of Gain	Classification of	ended June 30,						June 30,
815	(Loss)	Gain (Loss)	2011			2010			2011			2010
			(unaudited)
			(dollars in thousands)
Natural gas commodity contracts	Natural gas revenues	Realized	$	5,120		$	6,452		$	10,911		$	9,201
Oil commodity contracts	Oil revenues	Realized		(2,434	)		39			(3,918	)		276

Interest rate contracts	Interest benefit (expense)	Realized		2,298			(1,024	)		1,928			(2,051	)


Total realized gains (losses) from derivatives not designated as hedges			$	4,984		$	5,467		$	8,921		$	7,426


Natural gas commodity contracts	Unrealized gain (loss) — oil and natural gas derivative contracts	Unrealized	$	1,659		$	(5,985	)	$	(1,299	)	$	15,296

Oil commodity contracts	Unrealized gain (loss) — oil and natural gas derivative contracts	Unrealized		12,718			8,090			(3,509	)		7,612

Interest rate contracts	Interest benefit (expense)	Unrealized		465			488			508			403

Total unrealized gains (losses) from derivatives not designated as hedges			$	14,842		$	2,593		$	(4,300	)	$	23,311

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, 2011(unaudited):

NATURAL GAS DERIVATIVE CONTRACTS


	Volume in		Weighted		Range
Period and Type of Contract	MMbtu		Average		High		Low
2011
Price Swap Contracts		6,030,000	$	5.60	$	8.83	$	4.44
Collar Contracts
Short Call Options		6,760,000		5.67		7.05		5.40
Long Put Options		3,060,000		6.05		6.30		5.75

Long Call Options		600,000		7.45		7.45		7.45
Short Put Options		2,950,000		3.86		4.00		3.65

2012
Price Swap Contracts		7,525,000		6.17		8.83		5.00
Collar Contracts
Short Call Options		7,560,000		5.76		6.00		5.50
Long Put Options		4,350,000		5.93		6.75		5.50

Long Call Options		3,660,000		5.00		5.00		5.00
Short Put Options		8,730,000		4.11		4.50		4.00

2013
Price Swap Contracts		4,825,000		6.48		9.15		5.35
Collar Contracts
Short Call Options		1,500,000		8.51		8.80		8.31
Long Put Options		1,500,000		6.09		6.15		6.00

Short Put Options		900,000		5.50		5.50		5.50

2014
Price Swap Contracts		3,125,000		6.27		7.50		5.60
Collar Contracts
Short Call Options		1,650,000		8.21		9.00		7.92
Long Put Options		1,650,000		6.73		7.00		6.00

Short Put Options		1,200,000		5.50		5.50		5.50

2015
Price Swap Contracts		1,825,000		5.91		5.91		5.91

2016
Collar Contracts
Short Call Options		455,000		7.50		7.50		7.50
Long Put Options		455,000		5.50		5.50		5.50

Short Put Options		455,000		4.00		4.00		4.00

We had the following open derivative contracts for crude oil at June 30, 2011(unaudited):

OIL DERIVATIVE CONTRACTS


			Weighted		Range
Period and Type of Contract	Volume in Bbls		Average		High		Low
2011
Price Swap Contracts		230,000	$	83.80	$	103.20	$	67.50
Collar Contracts
Short Call Options		276,000		103.15		110.00		82.25
Long Put Options		317,400		86.67		100.00		75.00

Long Call Options		55,200		75.00		75.00		75.00
Short Put Options		402,592		66.42		89.85		55.00

2012
Price Swap Contracts		228,900		85.69		96.00		67.25
Collar Contracts
Short Call Options		491,172		115.89		123.50		100.00
Long Put Options		522,648		80.75		85.00		80.00

Short Put Options		635,376		62.26		65.00		60.00

2013
Price Swap Contracts		136,500		84.35		94.74		77.00
Collar Contracts
Short Call Options		417,935		110.62		127.00		90.00
Long Put Options		351,500		81.95		90.00		80.00

Long Call Options		82,500		79.00		79.00		79.00
Short Put Options		434,000		61.58		70.00		60.00

2014
Price Swap Contracts		127,300		87.63		91.05		81.00
Collar Contracts
Short Call Options		273,750		125.70		133.50		107.50
Long Put Options		488,450		85.33		90.00		80.00

Short Put Options		488,450		65.33		70.00		60.00

2015
Collar Contracts
Short Call Options		246,350		125.12		135.98		116.40
Long Put Options		319,350		87.57		90.00		85.00

Short Put Options		319,350		66.86		70.00		60.00

2016
Collar Contracts
Short Call Options		36,400		130.00		130.00		130.00
Long Put Options		36,400		95.00		95.00		95.00

Short Put Options		36,400		75.00		75.00		75.00

In those instances where contracts are identical as to time period, volume and strike price, but opposite as to direction (long and short), the volumes and average prices have been netted in the two tables above. In some instances our counterparties in the offsetting contracts are not the same, and may have different credit ratings.

We had the following open financial basis swap contracts at June 30, 2011(unaudited):


Volume in MMbtu	Reference Price	Period	Spread ($ per MMbtu)
1,200,000	Houston Ship Channel	Jul ’11 — Dec ’11		(0.2000	)
1,200,000	Houston Ship Channel	Jul ’11 — Dec ’11		(0.1600	)
460,000	Houston Ship Channel	Jul ’11 — Dec ’11		(0.0850	)
1,380,000	Houston Ship Channel	Jul ’11 — Dec ’11		(0.1550	)
1,830,000	Houston Ship Channel	Jan ’12 — Dec ’12		(0.1575	)
1,840,000	Houston Ship Channel	Jul ’11 — Dec ’11		(0.1150	)
3,660,000	Houston Ship Channel	Jan ’12 — Dec ’12		(0.1400	)

We had the following open interest rate swap contracts at June 30, 2011(unaudited):


Interest Rate Swaps
Term	Principal Amount		Interest Rate (1)
	(dollars in thousands)
Floating to Fixed Rate Swaps:
July 2011 — August 2012	$	50,000		4.95	%
July 2011 — October 2011	$	25,000		3.21	%
Fixed to Floating Rate Swaps:
July 2011 — June 2015	$	150,000		9.625	%


(1)		The floating rate is the three-month LIBOR rate, except the swap for $150 million, which is a fixed to floating rate swap using a floating rate of three-month LIBOR plus 8.06%.

7. ASSET RETIREMENT OBLIGATIONS

A summary of the changes in asset retirement obligations is included in the table below(unaudited, dollars in thousands):


Balance, December 31, 2010	$	42,713
Liabilities incurred		332
Liabilities assumed with acquired producing properties		2,504
Liabilities settled		(246	)
Revisions to previous estimates		(7	)
Accretion expense		946

Balance, June 30, 2011		46,242
Less: Current portion		1,755

Long term portion	$	44,487

8. LONG-TERM DEBT AND NOTES PAYABLE TO FOUNDER

Long-term debt consists of the following:


	June 30,		December 31,
	2011		2010
	(unaudited)
	(dollars in thousands)
Senior Debt — On November 13, 2008, we entered into a Fifth Amended and Restated Credit Agreement with a group of banks, which was replaced by the Sixth Amended and Restated Credit Agreement on May 13, 2010, as amended (“credit facility”). The credit facility matures on May 23, 2016 and is secured by substantially all of our oil and gas properties. The credit facility borrowing base is redetermined periodically and, as of June 30, 2011, the borrowing base under the facility was $260 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 2.519% as of June 30, 2011 and 2.875% as of December 31, 2010	$	159,790	$	73,290

Senior Notes Payable — On October 13, 2010, we issued notes due October 15, 2018 with a face value of $300 million, at a discount of $2.1 million. The senior notes carry a face interest rate of 9 5/8%, with an effective rate of 9 3/4%; interest is payable semi-annually each April 15^th and October 15^th. 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 $1.9 million and $2.0 million at June 30, 2011 and December 31, 2010, respectively.		298,116		297,986


Total long-term debt	$	457,906	$	371,276

The senior notes contain an optional redemption provision beginning in October 2013 allowing us to retire up to 35% of the principal outstanding under the senior notes with the proceeds of an equity offering, at 109.625%. Additional optional redemption provisions allow for retirement at 104.813%, 102.406%, and 100.0% beginning on each of October 15, 2014, 2015, and 2016, respectively.

On October 13, 2010, we entered into a registration rights agreement with the initial purchasers of the senior notes. Pursuant to the registration rights agreement, we filed a registration statement with the SEC to allow for registration of “exchange notes” with terms substantially identical to the senior notes. The exchange offer was consummated on August 12, 2011, with the tendered original senior notes exchanged for the exchange notes.

On May 23, 2011, we amended our $500 million senior secured revolving credit facility to, among other

things, increase the borrowing base limit from $220 million to $260 million and reduce applicable interest rates provided thereunder, extend the maturity date from November 13, 2012 to May 23, 2016, and increase the amount of senior debt securities that we are permitted to issue from $500 million to $700 million. The amended credit facility is currently subject to a $260 million borrowing base limit.

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, 2011, we were in compliance with the covenants. The terms of the credit facility also restrict our ability to make distributions and investments.

In addition, we have notes payable to our founder which bear simple interest at 10% with a balance of $20.3 million and $19.7 million at June 30, 2011 and December 31, 2010, respectively. The notes mature December 31, 2018. Interest and principal are payable at maturity. The notes are subordinate to all debt. Interest on the notes payable to our founder amounted to $600,000 and $590,000 for the six months ended June 30, 2011 and 2010, respectively, and $302,000 and $297,000 for the three months ended June 30, 2011 and 2010, respectively. Such amounts have been added to the balance of the notes.

9. ACCOUNTS PAYABLE AND ACCRUED LIABILITIES

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


	June 30,		December 31,
	2011		2010
	(unaudited)
	(dollars in thousands)
Capital expenditures	$	32,815	$	22,743
Revenues and royalties payable		5,287		5,962
Operating expenses/taxes		23,152		18,220
Compensation		4,057		2,591
Liability related to drilling rig		—		9,785
Other		2,513		1,775

Total accrued liabilities		67,824		61,076
Accounts payable		6,321		26,179

Accounts payable and accrued liabilities	$	74,145	$	87,255

The following provides the detail of other long-term liabilities:


	June 30,		December 31,
	2011		2010
	(unaudited)
	(dollars in thousands)
Acquisition obligation	$	985	$	411
Remediation liability		966		943
Other		3,489		5,886

Total other long-term liabilities	$	5,440	$	7,240

10. COMMITMENTS AND CONTINGENCIES

Contingencies

Deep Bossier litigation: On July 23, 2009, we made a payment of $25.5 million and took assignment of substantially all working interests that had been held by Chesapeake Energy Corporation in an approximate 50,000 acre area of Leon and Robertson Counties, Texas in the Deep Bossier play. We had exercised our preferential right to purchase these interests from Gastar Exploration Ltd. in late 2005, but Gastar and Chesapeake had opposed this and Chesapeake took record title until we finally and conclusively prevailed, and in 2008 a Texas court of appeals directed that specific performance take place. In early 2009, the Texas Supreme Court denied the defendants’ request to hear the appeal. As a result, we were able to take working interests in over 30 producing wells and participate in further development of the area, primarily with EnCana, but also with Gastar. A subsequent payment to EnCana of $15.2 million plus purchase accounting adjustments of $3.8 million brought the total cost of the acquisition to $44.5 million. While the ownership of these interests has been decided by the courts, we are pursuing other claims against Chesapeake; Chesapeake is claiming an additional $36.5 million of past expenses from us. We are unable to express an opinion with respect to the likelihood of an unfavorable outcome of this matter or to estimate the amount or range of potential loss should the outcome be unfavorable. Therefore, we have not provided any amount for this matter in our consolidated financial statements at June 30, 2011.

Texas Oil Distribution & Development, Inc. and Matrix Petroleum, LLC v. Alta Mesa Holdings, LP and The Meridian Resource & Exploration, LLC: In November 2010, Texas Oil Distribution & Development, Inc. and Matrix Petroleum LLC (together, “TODD”), filed a petition seeking declaratory relief based on TODD’s employment of Thomas Tourek, a former independent contractor of the Company. TODD subsequently filed an amended petition for declaratory relief, breach of contract and tortious interference related to certain assignments of oil and gas interests and joined Meridian as a defendant. On June 17, 2011, the litigation was settled. See Note 3, “Significant Acquisitions — TODD Acquisition” for further information.

Ted R. Stalder, TRS LP, Richard Hughart, and Richmar Interests, Inc. v. Texas Energy Acquisitions, LP: On May 24, 2011, the plaintiffs brought suit against us for breach of contract, common law fraud, fraud in a real estate transaction, declaratory relief, money had and received, an accounting, and injunctive relief related to two purchase and sales agreements dated December 23, 2008 and a dispute over the interpretation of the payment provisions in those agreements. Anex parte temporary restraining order (“TRO”) was entered against us on May 24, 2011, requiring among other things that we deposit into the registry of the court all payments received from oil, gas and liquids from the properties covered by the agreements. Our motion to dissolve the TRO was denied and the TRO was amended and extended another 14 days on June 2, 2011. We subsequently agreed to amend and extend the TRO until July 8, 2011. On July 7, 2011, during a hearing on the temporary injunction, the court recommended that the parties enter into an agreed temporary injunction. The plaintiffs and us agreed to enter into a temporary injunction whereby, among other things, we would pay directly to the plaintiffs the portion of the payments received from oil, gas, and liquids from the properties covered by the agreements that we contend the plaintiffs are due, less any previous payments. Furthermore, we have agreed to deposit into the registry of the court the amount that the plaintiffs contend they are owed, less any previous payments made to the registry of the court or to the plaintiffs. We are still in the process of negotiating the agreed temporary injunction. On July 28, 2011, we filed a motion for partial summary judgment on the plaintiffs’ fraud claims, which is set for hearing on August 18, 2011. We intend to contest the matter vigorously. We are unable to express an opinion with respect to the likelihood of an unfavorable outcome of this matter or to estimate the amount or range of potential loss should the outcome be unfavorable. Therefore, we have not provided any amount for this matter in our consolidated financial statements at June 30, 2011.

Environmental claims: Management has established a liability for soil contamination in Florida of $966,000 at June 30, 2011 and $943,000 December 31, 2010, based on our undiscounted engineering estimates. The obligations are included in other long-term liabilities in the accompanying consolidated balance sheets.

Various landowners have sued Meridian (along with numerous other oil companies) in lawsuits concerning several fields in which Meridian has had operations. The lawsuits seek injunctive relief and

other relief, including unspecified amounts in both actual and punitive damages for alleged breaches of mineral leases and alleged failure to restore the plaintiffs’ lands from alleged contamination and otherwise from Meridian’s oil and natural gas operations. We are unable to express an opinion with respect to the likelihood of an unfavorable outcome of the various environmental claims or to estimate the amount or range of potential loss should the outcome be unfavorable. Therefore, we have not provided any amount for these claims in our financial statements at June 30, 2011.

Due to the nature of our business, some contamination of the real estate property owned or leased by us is possible. Environmental site assessments of the property would be necessary to adequately determine remediation costs, if any. No accrual has been made other than the balance noted above.

Title/lease disputes: Title and lease disputes may arise in the normal course of our operations. These disputes are usually small but could result in an increase or decrease in reserves once a final resolution to the title dispute is made.

Other contingencies: We are subject to legal proceedings, claims and liabilities arising in the ordinary course of business. The outcome cannot be reasonably estimated; however, in the opinion of management, such litigation and claims will be resolved without material adverse effect on our financial position, results of operations or cash flows. Accruals for losses associated with litigation are made when losses are deemed probable and can be reasonably estimated.

We have contingent commitments to pay an amount up to a maximum of approximately $6.7 million for properties acquired in 2008 and prior years. The additional purchase consideration will be paid only if certain product price conditions are met. We cannot estimate the amounts that will be paid in the future, if any, or the fiscal years in which such amounts could become due.

Drilling rig:Included in our acquisition of Meridian was a contractual obligation for the use of a drilling rig, which expired in February 2011. Meridian and Alta Mesa were not able to fully utilize this rig during the contractual term; however, we were obligated for the dayrate regardless of whether the rig was working or idle. The operator, Orion Drilling, LP (“Orion”), sought other parties to use the rig and agreed to credit Meridian’s and Alta Mesa’s obligation, based on revenues from third parties who utilized the rig when it was not utilized under the contract. We had provided approximately $9.8 million for the liability under this drilling contract and under a similar rig contract which had previously expired and was also underutilized.

On May 19, 2011, we fully settled this liability with a payment of $8.5 million to Orion, and recorded a gain on contact settlement of $1.3 million.

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 gas properties. We mitigate a portion of this vulnerability by entering into oil and natural gas price derivative contracts. See Note 6.

12. PARTNERS’ CAPITAL

In September 2006, our limited partnership agreement was amended such that the affiliates of Alta Mesa Holdings, LP and certain other parties became Class A limited partners (“Class A Partners”) and AMIH was admitted to the partnership as the sole Class B limited partner (“Class B Partner.”)

Management and Control: Our business and affairs are managed by Alta Mesa Holdings GP, LLC, our general partner (“General Partner”). With certain exceptions, the General Partner may not be removed except for the reasons of “cause,” which are defined in the Alta Mesa Holdings, LP Partnership Agreement (“Partnership Agreement”). The Class B limited partner has certain approval rights, generally over capital plans and significant transactions in the areas of finance, acquisition, and divestiture.

Distribution and Income Allocation: Net cash flow from operations may be distributed to the Class A and Class B Partners based on a variable formula as defined in the Partnership Agreement.

After January 1, 2012, the Class B Partner may require the General Partner to make distributions; however, any distribution must be permitted under the terms of our credit facility and our senior notes.

Distribution of net cash flow from a Liquidity Event (as defined below) is distributed to the Class A and Class B Partners according to a variable formula as defined in the Partnership Agreement. A “Liquidity Event” is any event in which we receive cash proceeds outside the ordinary course of our business. Further, after January 1, 2012, the Class B Partner can, without consent of any other partners, request that the General Partner take action to cause us, or our assets, to be sold to one or more third parties.

13. SUBSIDIARY GUARANTORS

All of our material wholly-owned subsidiaries are guarantors under the terms of both our senior notes and our credit facility.

Our consolidated financial statements reflect the combined financial position of these subsidiary guarantors. Our parent company, Alta Mesa Holdings, LP has no independent operations, assets, or liabilities. The guarantees are full and unconditional and joint and several. Those subsidiaries which are not wholly owned and are not guarantors are minor. There are no restrictions on dividends, distributions, loans, or other transfers of funds from the subsidiary guarantors to our parent company.

14. SUBSEQUENT EVENTS

Management has evaluated all events subsequent to the balance sheet date of June 30, 2011 to August 12, 2011, which is the date the consolidated financial statements were issued, and has determined that no events require disclosure.

ITEM 2.Management’s Discussion and Analysis of Financial Condition and Results of Operations

The following discussion and analysis should be read in conjunction with the financial statements and related notes included elsewhere in this report. In addition, such analysis should be read in conjunction with the financial statements and the related notes included in our Registration Statement onForm S-4 (Commission File No. 333-173751 filed on July 11, 2011, the “Form S-4”). The following discussion and analysis contains forward-looking statements that reflect our future plans, estimates, beliefs and expected performance. The forward-looking statements are dependent upon events, risks and uncertainties that may be outside our control. Our actual results could differ materially from those discussed in these forward-looking statements. Factors that could cause or contribute to such differences include, but are not limited to, the volatility of oil and natural gas prices, general economic conditions, credit markets, inflation, the credit rating of U.S. government debt, production timing and volumes, estimates of proved reserves, operating costs and capital expenditures, lack of availability of drilling and production equipment and services, environmental risks, drilling and other operating risks, regulatory changes, the uncertainty inherent in estimating oil and natural gas reserves and in projecting future rates of production, cash flow and access to capital and other uncertainties, as well as those factors discussed below and under “Risk Factors” in ourForm S-4. As a result of these risks, uncertainties and assumptions, the forward-looking events discussed may not occur. The historical financial information discussed below in this Management’s Discussion and Analysis of Financial Conditions and Results of Operations represents Alta Mesa’s financial information for the periods indicated, giving effect to the Meridian acquisition from the acquisition date of May 13, 2010 and the Sydson and TODD asset acquisitions from April 21, 2011 and June 17, 2011, respectively.

Overview

We currently generate significant amounts of our revenue, earnings and cash flow from the production and sale of oil and natural gas from our core properties in the South Louisiana, East Texas, Oklahoma, the Deep Bossier resource play of East Texas and Eagle Ford Shale play in South Texas. We operate in one industry segment, oil and natural gas exploration and development, within one geographical segment, the United States.

The amount of cash we generate from our operations will fluctuate based on, among other things:

	•		the prices at which we will sell our production;

	•		the amount of oil and natural gas we produce; and

	•		the level of our operating and administrative costs.

In order to mitigate the impact of changes in oil and natural gas prices on our cash flows, we are a party to hedging and other price protection contracts, and we intend to enter into such transactions in the future to reduce the effect of oil and natural gas price volatility on our cash flows.

Substantially all of our oil and natural gas activities are conducted jointly with others and, accordingly, amounts presented reflect our proportionate interest in such activities. Inflation has not had a material impact on our results of operations and is not expected to have a material impact on our results of operations in the future.

Significant Acquisitions

Meridian Acquisition

On May 13, 2010, we acquired The Meridian Resource Corporation, a public exploration and production company, with proved reserves of 75 Bcfe as of December 31, 2009, for approximately $158 million. The oil and natural gas properties of Meridian were similar and in some cases proximate to our areas of operation. Meridian shareholders were paid in cash, funded by proceeds of our credit facility as well as a $50 million equity contribution from our private equity partner Alta Mesa Investment Holdings Inc., an affiliate of Denham Commodities Partners Fund IV LP (“AMIH”). The merger increased the oil portion of our reserves portfolio, improving the balance of our reserves between oil and natural gas, and provided significant additions to our library of 3-D seismic data.

Sydson Acquisition

TODD Acquisition

Outlook

The U.S. and other world economies suffered a severe recession lasting well into 2009 and economic conditions remain uncertain. These uncertain economic conditions reduced demand for oil and natural gas, resulting in a decline in oil and natural gas prices received for our production in 2009 compared with years prior to and including 2008. In 2010 and 2011 we have benefitted from increasing prices for oil, but natural gas prices remain at lower levels.

While oil and natural gas prices have strengthened, we expect them to remain volatile in the future. Factors affecting the price of oil include worldwide economic conditions, geopolitical activities, worldwide supply disruptions, weather conditions, actions taken by the Organization of Petroleum Exporting Countries, the credit rating of U.S. goverment debt and the value of the U.S. dollar in international currency markets. Factors affecting the price of natural gas include U.S. economic conditions, North American weather conditions, industrial and consumer demand for natural gas, storage levels of natural gas, the credit rating of U.S. goverment debt and the availability and accessibility of natural gas deposits in North America. If the global economic uncertainty continues, commodity prices may be depressed for an extended period of time, which could alter our development plans and adversely affect our growth strategy and our ability to access additional funding in the capital markets.

We have used, and expect to continue to use, oil and natural gas derivative contracts to reduce our exposure to the risks of changes in the prices of oil and natural gas. Pursuant to our risk management

policy, we engage in these activities as a hedging mechanism against price volatility associated with pre-existing or anticipated sales of oil and natural gas. As of June 30, 2011, we have hedged approximately 63% of our forecasted production from proved developed reserves through 2016 at minimum average annual prices ranging from $5.50 per MMBtu to $6.40 per MMBtu and $82.26 per Bbl to $95.00 per Bbl.

The primary factors affecting our production levels are capital availability, the success of our drilling program and our inventory of drilling prospects. In addition, we face the challenge of natural production declines. As initial reservoir pressures are depleted, production from a given well decreases. We attempt to overcome this natural decline primarily through developing our existing undeveloped reserves. Our future growth will depend on our ability to continue to add reserves in excess of production. Our ability to add reserves through drilling and other development techniques is dependent on our capital resources and can be limited by many factors, including our ability to timely obtain drilling permits and regulatory approvals. Any delays in drilling, completing or connecting our new wells to gathering lines will negatively affect our production, which will have an adverse effect on our revenues and, as a result, cash flow from operations.

Operations Update

Deep Bossier:This remains our largest producing area, contributing an average of about 53 MMcf/d (million cubic feet of gas per day). Since the end of the first quarter of 2011 we have participated in drilling five successful wells in this area, with initial production rates ranging from 20 MMcf/d to 1.5 MMcf per day. Additionally, one well was recompleted resulting in a new production rate of approximately 34 MMcf/d. We have a 33% working interest in this EnCana operated well. Currently one well is drilling and one well is waiting on completion in this field.

Eagle Ford Shale:We are participating with our operating partner, Murphy Oil, in a multi-year drilling effort in the liquids window of Karnes County, where we have 21% to 25% working interests in approximately 19,000 gross acres. Currently we have interests in 14 producing wells. Since the end of the first quarter of 2011, we have participated in the drilling of nine wells. Of those nine wells, four wells have been brought online and five wells are waiting to be fracture stimulated or completed. Two wells are currently drilling, and five locations have been prepared for future drilling. The operator has secured a hydraulic fracturing contractor who will be dedicated to our wells in the area for the next two years.

Weeks Island:We began our multi-well drilling program during the second quarter of 2011, drilling two successful wells, one of which is expected to reach approximately 200 Bbls per day and is currently producing at rates between 60 and 150 Bbls per day. The second well was also productive and is under analysis for optimal reservoir exploitation. We also recently finished two recompletions in Weeks Island, with one producing at approximately 180 Bbls per day and the other reflecting an initial rate of 500 Bbls of oil per day, although it is temporarily off-line for a gravel-packing operation.

Cold Springs Field: We took over as operator of the Cold Springs Field in the second quarter, and are continuing development of multiple stacked pays, primarily in the Wilcox sand. During the quarter, we established production in two previously un-tested Wilcox zones. The shallower of these zones tested at an initial production rate of 300 Bbls of oil per day, and is present in several wells in the field. It will be tested in the next recompletion in early August 2011. We believe there are at least 12 wells to drill in the extension area for this field, the first of which is scheduled to be spudded in the third quarter of 2011. We also made a small acquisition in this field in the second quarter of 2011.

Oklahoma: We are continuing with our infill drilling program in the Lincoln North Unit which is designed to further exploit the unitized Oswego and Big Lime formations and will also target other deeper, prospective formations, including the Mississippi Lime formation. The East Hennessey Unit waterflood expansion is now underway with water injection in the initial pilot area for the flood.

Results of Operations: Three Months Ended June 30, 2011 v. Three Months Ended June 30, 2010


	Three Months Ended June 30,					Increase
	2011			2010		(Decrease)			% Change
				($ in thousands, except average sales price and unit costs)
Summary Operating Information:

Net Production:
Natural gas (MMcf)		7,979			5,701		2,278			40	%
Oil (MBbls)		376			213		163			77	%
Natural gas liquids (MBbls)		50			26		24			92	%
Total natural gas equivalent (MMcfe)		10,535			7,135		3,400			48	%
Average daily gas production (MMcfe per day)		115.8			78.4		37.4			48	%

Average Sales Price:
Natural gas (per Mcf) realized	$	4.85		$	5.28	$	(0.43	)		(8	%)
Natural gas (per Mcf) unhedged		4.21			4.15		0.06			1	%
Oil (per Bbl) realized		104.50			76.38		28.12			37	%
Oil (per Bbl) unhedged		110.97			76.20		34.77			46	%
Natural gas liquids (per Bbl) realized⁽¹⁾		56.87			46.73		10.14			22	%
Combined (per Mcfe) realized		7.68			6.67		1.01			15	%

Hedging Activities:
Realized natural gas revenue gain	$	5,120		$	6,452	$	(1,332	)		(21	%)
Realized oil revenue gain (loss)		(2,434	)		39		(2,473	)		(6,341	%)

Summary Financial Information
Revenues
Natural gas	$	38,731		$	30,120	$	8,611			29	%
Oil		39,292			16,278		23,014			141	%
Natural gas liquids		2,847			1,214		1,633			135	%
Other revenues		297			386		(89	)		(23	%)
Unrealized gain (loss) — oil and natural gas derivative contracts		14,377			2,105		12,272			583	%

		95,544			50,103		45,441			91	%
Expenses
Lease and plant operating expense		15,041			9,354		5,687			61	%
Production and ad valorem taxes		4,069			2,785		1,284			46	%
Workover expense		2,352			1,330		1,022			77	%
Exploration expense		5,690			1,651		4,039			245	%
Depreciation, depletion, and amortization		22,963			13,500		9,463			70	%
Impairment expense		4,929			643		4,286			667	%
Accretion expense		476			270		206			76	%
General and administrative expenses		8,843			4,679		4,164			89	%
Interest expense, net		6,831			4,525		2,306			51	%
(Gain) on contract settlement		(1,285	)		—		(1,285	)	NA
Provision for state income taxes		75			—		75		NA


Net income	$	25,560		$	11,366	$	14,194			125	%


Average Unit Costs per Mcfe:
Lease and plant operating expense	$	1.43		$	1.31	$	0.12			9	%
Production and ad valorem taxes		0.39			0.39		—			0	%
Workover expense		0.22			0.19		0.03			16	%
Exploration expense		0.54			0.23		0.31			135	%
Depreciation, depletion and amortization		2.18			1.89		0.29			15	%
General and administrative expenses		0.84			0.66		0.18			27	%


(1)		The Company does not utilize hedges for natural gas liquids.

Revenues

Natural gas revenuesfor the three months ended June 30, 2011 were $38.7 million, compared to $30.1 million for the same period in 2010, representing an $8.6 million or 29% increase. The increase in revenue was attributable to increased production volumes partially offset by lower realized prices during the three months ended June 30, 2011. The increase in production volumes of 2.3 Bcf resulted in increased revenue of approximately $12.0 million primarily related to production from our Meridian acquisition in May 2010 (.7 Bcf) and new production in the Deep Bossier (1.9 Bcf). The decrease in realized prices (including hedge activity) from $5.28 per Mcf in the second quarter of 2010 to $4.85 per Mcf in the second quarter of 2011 resulted in decreased revenue of approximately $3.4 million. The price of gas before hedging increased from $4.15 per Mcf in the second quarter of 2010 to $4.21 per Mcf in the second quarter of 2011.

Oil revenuesfor the three months ended June 30, 2011 increased $23 million, or 141%, to $39.3 million from $16.3 million for the three months ended June 30, 2010. The increase in revenue was due to higher production volumes and higher realized prices. Oil production for the second quarter of 2011 increased to 376 MBbls from 213 MBbls for the same period in 2010, an increase of 77%. The increase is primarily related to the full-quarter effect of production from our Meridian acquisition (105 MBbls higher than the second quarter of 2010) and to new production from our Eagle Ford Shale area (52 MBbls). During the three months ended June 30, 2011, our average realized oil price (including hedge activity) increased from $76.38 per Bbl in the second quarter of 2010 to $104.50 per Bbl in the comparable period of 2011. The price of oil before hedging increased from $76.20 per Bbl to $110.97 per Bbl for the comparative periods.

Natural gas liquids revenuesincreased during the second quarter of 2011 to $2.8 million from $1.2 million for the second quarter of 2010. The increase was due to an increase in volume sold, from 26 MBbls to 50 MBbls, and increased prices, from $46.73 to $56.87 for the three months ended June 30, 2010 and 2011, respectively. The increased production is primarily related to our Meridian acquisition in May 2010.

Other revenues were $297,000 during the three months ended June 30, 2011 as compared to $386,000 during the three months ended June 30, 2010. The decrease is primarily the result of a decrease in income from investments, offset by increased income from rental of our drilling rig.

Unrealized gain (loss) – oil and natural gas derivative contracts was a gain of $14.4 million during the three months ended June 30, 2011 as compared to a gain of $2.1 million during the same period in 2010. The significant fluctuation from period to period is due to the volatility of oil and natural gas prices and changes in our outstanding hedging contracts during these periods.

Expenses

Lease and plant operating expenseincreased $5.7 million in the second quarter of 2011 as compared to the second quarter of 2010, due partially to the full quarter effect of lease operating expenses related to our Meridian acquisition in May 2010, $2.2 million. In addition, expenditures at Deep Bossier increased $3.3 million, primarily due to an increase in the number of producing wells and increased gas marketing fees. On a unit basis, lease and plant operating expense increased from $1.31 per Mcfe to $1.43 per Mcfe for the three months ended June 30, 2010 and 2011, respectively.

Production and ad valorem taxes increased $1.3 million, or 46%, to $4.1 million for the second quarter of 2011, as compared to $2.8 million for the second quarter of 2010. Ad valorem taxes increased $0.4 million, due to our Meridian acquisition in May 2010 and increased taxable values of our properties. The remaining increase of $0.9 million is attributable to production taxes, which increased 37%, following an increase in our revenue from products of 70%. The change in the mix of our sales toward a higher percentage of revenues from oil impacts the variance in this expense. Tax rates on oil are higher than for gas in Louisiana, where the majority of our oil is produced. Oil as a percentage of product revenues increased from 34% to 49% in the second quarter of 2011 as compared to the same period in 2010.

Workover expenseincreased from the second quarter of 2010 as compared to the second quarter of 2011, from $1.3 million to $2.4 million, respectively. This expense varies depending on activities in the field.

Exploration expenseincludes the costs of our geology departments, costs of geological and geophysical data, delay rentals, expired leases, and dry holes. Exploration expense increased from $1.7 million for the second quarter of 2010 to $5.7 million for the second quarter of 2011. The increase is primarily due to dry hole expense recorded in the second quarter of 2011 of approximately $4.5 million.

Depreciation, depletion and amortizationincreased $9.5 million to $23 million for the second quarter of 2011 as compared to an expense of $13.5 million for the second quarter of 2010. On a per unit basis, this expense increased from $1.89 to $2.18 per Mcfe. The rate is a function of capitalized costs of proved properties, reserves and production by field.

Impairment expenseincreased from $0.6 million in the second quarter of 2010 to $4.9 million in the second quarter of 2011. This expense varies with the results of exploratory drilling, as well as with price declines which may render some projects uneconomic, resulting in impairment.

Accretion expenseis related to our obligation for retirement of oil and natural gas wells and facilities. We record these liabilities when we place the assets in service, using discounted present values of the estimated future obligation. We then record accretion of the liabilities as they approach maturity. Accretion expense was $0.5 million and $0.3 million for the second quarter of 2011 and 2010, respectively. The increase was due to the acquisition of Meridian.

General and administrative expensesincreased $4.1 million for the three months ended June 30, 2011 to $8.8 million from $4.7 million for the three months ended June 30, 2010. The increase in general and administrative expenses resulted principally from increased payroll and burden costs of $1.1 million, which are predominately related to increased headcount from our Meridian acquisition and additional personnel. Consulting expenses increased $2.2 million, primarily for legal fees, accounting fees (primarily related to the registration of our bonds), and to other consulting services, including risk management (hedging strategy) and expenses assumed with the Meridian acquisition. Office expenditures increased $0.4 million in the second quarter of 2011 as compared to 2010, primarily due to the assumption of Meridian office space in May 2010. On a per unit basis, general and administrative expenses increased from $0.66 to $0.84 per Mcfe.

Interest expense, netincreased $2.3 million for the three months ended June 30, 2011 to $6.8 million from $4.5 million for the three months ended June 30, 2010, primarily due to $7.3 million in interest on our 9 5/8% senior notes issued in October 2010, and increased amortization of deferred loan costs of $0.3 million. This increase is partially offset by decreased interest rate hedge losses of $3.3 million, primarily due to hedge gains of $2.8 million related to interest rate hedge contract modifications and decreased interest on bank debt of $1.9 million due to a decrease in the amount outstanding under our credit facility and to the retirement of our $40 million subordinated debt in October 2010.

Gain on contract settlementis related to the settlement of an obligation the Company assumed upon the purchase of Meridian. The obligation related to underutilization of two contracted drilling rigs, as described in Note 10 of the accompanying notes to our financial statements. We recorded an estimated liability of $9.8 million for the obligation upon purchase of Meridian in 2010. The obligation was subsequently settled in the second quarter of 2011 for $8.5 million, resulting in a gain of $1.3 million.

Results of Operations: Six Months Ended June 30, 2011 v. Six Months Ended June 30, 2010


	Six Months Ended June 30,					Increase
	2011			2010		(Decrease)			% Change
	($ in thousands, except average sales price and unit costs)
Summary Operating Information:

Net Production:
Natural gas (MMcf)		15,345			10,670		4,675			44	%
Oil (MBbls)		724			335		389			116	%
Natural gas liquids (MBbls)		108			39		69			177	%
Total natural gas equivalent (MMcfe)		20,338			12,918		7,420			57	%
Average daily gas production (MMcfe per day)		112.4			71.4		41.0			57	%

Average Sales Price:
Natural gas (per Mcf) realized	$	4.83		$	5.43	$	(0.60	)		(11	%)
Natural gas (per Mcf) unhedged		4.12			4.57		(0.45	)		(10	%)
Oil (per Bbl) realized		98.70			76.96		21.74			28	%
Oil (per Bbl) unhedged		104.11			76.14		27.97			37	%
Natural gas liquids (per Bbl) realized⁽¹⁾		54.73			49.30		5.43			11	%
Combined (per Mcfe) realized		7.45			6.63		0.82			12	%

Hedging Activities:
Realized natural gas revenue gain	$	10,911		$	9,201	$	1,710			19	%
Realized oil revenue gain (loss)		(3,918	)		276		(4,194	)		(1520	%)

Summary Financial Information
Revenues
Natural gas	$	74,112		$	57,935	$	16,177			28	%
Oil		71,489			25,799		45,690			177	%
Natural gas liquids		5,900			1,943		3,957			204	%
Other revenues		766			407		359			88	%
Unrealized gain (loss) — oil and natural gas derivative contracts		(4,808	)		22,908		(27,716	)		(121	%)

		147,459			108,992		38,467			35	%

Expenses
Lease and plant operating expense		28,372			17,432		10,940			63	%
Production and ad valorem taxes		9,470			4,398		5,072			115	%
Workover expense		3,978			3,289		689			21	%
Exploration expense		8,421			4,572		3,849			84	%
Depreciation, depletion, and amortization		42,431			22,122		20,309			92	%
Impairment expense		10,755			2,093		8,662			414	%
Accretion expense		946			415		531			128	%
General and administrative expenses		14,593			6,902		7,691			111	%
Interest expense, net		16,309			8,724		7,585			87	%
(Gain) on contract settlement		(1,285	)		—		(1,285	)	NA
Provision for state income taxes		75			—		75		NA


Net income	$	13,394		$	39,045	$	(25,651	)		(66	%)


Average Unit Costs per Mcfe:
Lease and plant operating expense	$	1.40		$	1.35	$	0.05			4	%
Production and ad valorem taxes		0.47			0.34		0.13			38	%
Workover expense		0.20			0.25		(0.05	)		(20	%)
Exploration expense		0.41			0.35		0.06			17	%
Depreciation, depletion and amortization		2.09			1.71		0.38			22	%
General and administrative expenses		0.72			0.53		0.19			36	%


(1)		The Company does not utilize hedges for natural gas liquids.

Revenues

Natural gas revenuesfor the six months ended June 30, 2011 were $74.1 million, compared to $57.9 million for the same period in 2010, representing a $16.2 million or 28% increase. The increase in revenue was attributable to increased production volumes partially offset by lower realized prices during the six months ended June 30, 2011. The increase in production volumes of 4.7 Bcf resulted in increased revenue of approximately $25.4 million primarily related to production from our Meridian acquisition in May 2010 (2.3 Bcf) and new production in the Deep Bossier (2.9 Bcf). The decrease in realized prices (including hedge activity) from $5.43 per Mcf in the first half of 2010 to $4.83 per Mcf in the first half of 2011 resulted in decreased revenue of approximately $9.2 million. The price of gas before hedging decreased from $4.57 per Mcf in the first half of 2010 to $4.12 per Mcf in the first half of 2011.

Oil revenuesfor the six months ended June 30, 2011 increased $45.7 million, or 177%, to $71.5 million from $25.8 million for the six months ended June 30, 2010. The increase in revenue was due to higher production volumes and higher realized prices. Oil production for the first half of 2011 increased to 724 MBbls from 335 MBbls for the same period in 2010, an increase of 116%. The increase is primarily related to production from our Meridian acquisition in May 2010 (320 MBbls higher than the second quarter of 2010) and to new production from our Eagle Ford Shale area (58 MBbls). During the six months ended June 30, 2011, our average realized oil price (including hedge activity) increased from $76.96 per Bbl in the first half of 2010 to $98.70 per Bbl in the first half of 2011. The price of oil before hedging increased from $76.14 per Bbl to $104.11 per Bbl for the same comparative periods.

Natural gas liquids revenues increased during the first half of 2011 to $5.9 million from $1.9 million for the first half of 2010. The increase was due to an increase in volume sold, from 39 MBbls to 108 MBbls, and increased prices, from $49.30 to $54.73 per Bbl for the six months ended June 30, 2010 and 2011, respectively. The increased production is primarily related to our Meridian acquisition in May 2010.

Other revenueswere $766,000 during the six months ended June 30, 2011 as compared to $407,000 during the six months ended June 30, 2010. The increase is primarily the result of increased income from rental of our drilling rig, and from sales of prospects, offset by a decrease in income from investments.

Unrealized gain (loss) – oil and natural gas derivative contractswas a loss of $4.8 million during the six months ended June 30, 2011 as compared to a gain of $22.9 million during the same period in 2010. The significant fluctuation from period to period is due to the volatility of oil and natural gas prices and changes in our outstanding hedging contracts during these periods.

Expenses

Lease and plant operating expenseincreased $10.9 million in the first half of 2011 as compared to the first half of 2010, due partially to the full six-month effect of lease operating expenses related to our Meridian acquisition in May 2010, $6.3 million. In addition, expenditures in Deep Bossier increased $5.2 million, primarily due to an increase in the number of producing wells and increased gas marketing fees. On a unit basis, lease and plant operating expense increased from $1.35 per Mcfe to $1.40 per Mcfe for the six months ended June 30, 2010 and 2011, respectively.

Production and ad valorem taxesincreased $5.1 million, or 115%, to $9.5 million for the first half of 2011, as compared to $4.4 million for the first half of 2010. Ad valorem taxes increased $1.3 million, due to our Meridian acquisition in May 2010 and increased taxable values of our properties. The remaining increase of $3.8 million is attributable to production taxes, which increased 100%, following an increase in our revenue from products of 77%. The change in the mix of our sales toward a higher percentage of revenues from oil impacts the variance in this expense. Tax rates on oil are higher than for gas in Louisiana, where the majority of our oil is produced. Oil as a percentage of product revenues increased from 30% to 47% in the first half of 2011 as compared to 2010.

Workover expenseincreased from the first half of 2010 as compared to the first half of 2011, from $3.3 million to $4.0 million, respectively. This expense varies depending on activities in the field.

Exploration expenseincludes the costs of our geology departments, costs of geological and geophysical data, delay rentals, expired leases, and dry holes. Exploration expense increased $3.8 million for the first half of 2011 to $8.4 million from $4.6 million for the first half of 2010. The increase is primarily due to dry hole expense recorded in the first half of 2011 of approximately $5.3 million.

Depreciation, depletion and amortizationincreased $20.3 million to $42.4 million for the first half of 2011 as compared to an expense of $22.1 million for the first half of 2010. On a per unit basis, this expense increased from $1.71 to $2.09 per Mcfe. The rate is a function of capitalized costs of proved properties, reserves and production by field.

Impairment expenseincreased from $2.1 million in the first half of 2010 to $10.8 million in the first half of 2011. This expense varies with the results of exploratory drilling, as well as with price declines which may render some projects uneconomic, resulting in impairment.

Accretion expenseis 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 and $0.4 million for the first half of 2011 and 2010, respectively. The increase was due to the acquisition of Meridian.

General and administrative expensesincreased $7.7 million for the six months ended June 30, 2011 to $14.6 million from $6.9 million for the six months ended June 30, 2010. The increase in general and administrative expenses resulted principally from increased payroll and burden costs of $3.5 million, which are predominately related to increased headcount from our Meridian acquisition and additional personnel. Other general and administrative costs related to the acquisition of Meridian also increased, including office rent, which increased $0.8 million in the first half of 2011 as compared to 2010. Consulting expenses increased $2.8 million, primarily for legal fees, accounting fees,and other consulting services, including risk management (hedging) and expenses assumed in the acquisition of Meridian. On a unit basis, general and administrative expense increased from $0.53 to $0.72 per Mcfe.

Interest expense, netincreased $7.6 million for the six months ended June 30, 2011 to $16.3 million from $8.7 million for the six months ended June 30, 2010, primarily due to $14.5 million in interest on our 9 5/8% senior notes issued in October 2010, and increased amortization of deferred loan costs of $1.1 million. This increase is partially offset by decreased interest rate hedge losses of $4.1 million, primarily due to hedge gains of $2.8 million recorded in the first half of 2011 related to interest hedge contract modifications. In addition, interest on bank debt decreased $3.9 million due to a decrease in the amount outstanding under our credit facility and to the retirement of our $40 million subordinated debt in October 2010.

Liquidity and Capital Resources

Our principal requirements for capital are to fund our day-to-day operations, development activities, and to satisfy our contractual obligations, primarily for the repayment of debt and any amounts owed during the period related to our hedging positions.

Our 2011 capital budget is primarily focused on the development of existing core areas through exploitation and development. Currently, we plan to spend a total of approximately $180 million during 2011, of which, approximately $80 million has been expended or accrued through June 30, 2011. Approximately 83% of our 2011 capital budget is allocated to our properties in Deep Bossier, East Texas, Eagle Ford, and South Louisiana. Our future drilling plans, plans of our drilling operators and capital budgets are subject to change based upon various factors, some of which are beyond our control, including drilling results, oil and natural gas prices, the availability and cost of capital, drilling and production costs, availability of drilling services and equipment, actions of our operators, gathering system and pipeline transportation constraints and regulatory approvals. Because a large percentage of our acreage is held by production, we have the ability to materially decrease our drilling and recompletion budget in response to market conditions with minimal risk of losing significant acreage.

We expect to fund our 2011 capital budget predominantly with cash flows from operations, supplemented by use of our credit facility. If necessary, we may also access capital through proceeds from potential asset dispositions, and the future issuance of debt and/or equity securities, subject to the distribution of proceeds therefrom as set forth in our partnership agreement. We strive to maintain financial flexibility and may access capital markets as necessary to maintain substantial borrowing capacity under our senior secured revolving credit facility, facilitate drilling on our large undeveloped acreage position and permit us to selectively expand our acreage position. In the event our cash flows are materially less than anticipated and other sources of capital we historically have utilized are not available on acceptable terms, we may curtail our capital spending.

Senior Notes

In October 2010, we adjusted our capital structure by issuing $300 million of 9 5/8% senior notes due 2018 (“senior notes”). The senior notes were issued at a discount of $2.1 million, bringing the effective rate to 9 3/4%.

The senior notes are unsecured senior general corporate obligations, and effectively rank junior to any of our existing or future secured indebtedness, which includes our credit facility. The senior notes are unconditionally guaranteed on a senior unsecured basis by each of our material, wholly owned

subsidiaries. We entered into a registration rights agreement with the purchasers of the senior notes. We filed a registration statement with the SEC to allow for registration of “exchanges notes” substantially identical to the senior notes, which was declared effective by the SEC on July 14, 2011. On August 12, 2011, the exchange notes were exchanged for the original senior notes tendered in connection with the exchange offer.

Credit Facility

We have a senior secured revolving credit facility (“credit facility”) with Wells Fargo Bank, N.A. as the administrative agent. As of June 30, 2011, the credit facility was subject to a $260 million borrowing base limit, and we had $159.8 million outstanding under the credit facility. Our restricted subsidiaries are guarantors of the credit facility.

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, 2011 under the credit facility was 2.519%, which was based on the Eurodollar option.

The credit facility and senior notes include covenants requiring us to maintain certain financial covenants including a current ratio, leverage ratio, and interest coverage ratio. At June 30, 2011, we were in compliance with the covenants. The terms of the credit facility also restrict our ability to make distributions and investments.

Cash flow provided by operating activities

Operating activities provided cash of $71.2 million during the six months ended June 30, 2011 as compared to $16.1 million during the comparable period in 2010. The $55.1 million increase in operating cash flows was attributable to an increase in the cash-based portions of our earnings, as well as changes in working capital accounts. Cash-based items of net income, including revenues (exclusive of unrealized commodity gains or losses), operating expenses and taxes, general and administrative expenses, and the cash portion of our interest expense, provided a net increase of approximately $36.7 million in earnings and a related positive impact on cash flow. Augmenting this were changes in our working capital accounts, which used $6.8 million of cash flows as compared to having used $25.2 million in cash in 2010. This reversal resulted in a total increase of $18.4 million in cash flow, which as noted above, augments the positive effects of increased cash-based earnings.

Cash flow used in investing activities

Investing activities used cash of $155.4 million during the six months ended June 30, 2011 as compared to cash used in investing of $133.6 million during the comparable period of 2010. The decrease in cash used in acquisition activities was due to the $101.4 million invested in the Meridian acquisition in the first half of 2010. Acquisitions in the first half of 2011 were $61.2 million, primarily for the additional interest in legacy Meridian properties acquired from Sydson and TODD. The total cash purchase price of these two acquisitions was approximately $50 million. See Note 3 of the accompanying financial statements for further information. Aside from the acquisitions, investment in property and equipment increased by $61.8 million as compared to the prior year period, primarily related to development activities in our Deep Bossier, Eagle Ford Shale, and East Texas area properties. We also invested in development activities in South Louisiana and Oklahoma.

Cash flow provided by financing activities

Financing activities provided cash of $84.9 million during the six months ended June 30, 2011 as compared to cash provided by financing of $137.6 million during the six months ended June 30, 2010. The decrease is due to the large drawdown of funds under our credit agreement ($95 million) and the capital infusion of $50 million in the first half of 2010, which funded the Meridian acquisition. Cash from financing activities in the first half of 2011 included drawdowns of $86.5 million, of which approximately $50 million was directly used for the Sydson and TODD acquisitions.

ITEM 3.Quantitative and Qualitative Disclosures about Market Risk

For information regarding our exposure to certain market risks, see “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Quantitative and Qualitative Disclosures about Market Risk,” “—Commodity Price Risk and Hedges” and “—Interest Rates” in the Form S-4. There have been no material changes to the disclosure regarding market risks.

ITEM 4.Controls and Procedures

Evaluation of Disclosure Controls and Procedures

In accordance with Exchange Act Rule 13a-15 and 15d-15, we carried out an evaluation, under the supervision and with the participation of management, including our Chief Executive Officer and our Chief Financial Officer, of the effectiveness of our disclosure controls and procedures as of the end of the period covered by this report. Based on that evaluation, our Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures were effective as of June 30, 2011 to provide reasonable assurance that information required to be disclosed in our reports filed or submitted under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the Securities and Exchange Commission’s rules and forms. Our disclosure controls and procedures include controls and procedures designed to ensure that information required to be disclosed in reports filed or submitted under the Exchange Act is accumulated and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosure.

Changes in Internal Control Over Financial Reporting

There has been no change in our internal control over financial reporting during the three months ended June 30, 2011 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

PART II — OTHER INFORMATION

ITEM 1.Legal Proceedings

See Part I, Item 1, Note 10 to our consolidated financial statements entitled “Commitments and Contingencies,” which is incorporated in this item by reference.

ITEM 1A.Risk Factors

We are subject to certain risks and hazards due to the nature of the business activities we conduct. For a discussion of these risks, see “Risk Factors” in the Form S-4. There have been no material changes with respect to the risk factors disclosed in the Form S-4 during the quarter ended June 30, 2011.

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

None.

ITEM 3.Defaults Upon Senior Securities

None.

ITEM 4.(Removed and Reserved)

ITEM 5.Other Information

None.

ITEM 6.Exhibits


10.1		Purchase and Sale Agreement between Michael J. Mayell and Alta Mesa Energy, LLC, dated April 21, 2011.

10.2		Purchase and Sale Agreement between Sydson Energy, Inc. and Alta Mesa Energy, LLC, dated April 21, 2011.

10.3		Purchase and Sale Agreement by and among Texas Oil Distribution & Development, Inc., JAR Resource Holdings, L.P., Joseph A. Reeves, Jr., Dianne S. Reeves and Alta Mesa Energy, LLC, dated June 17, 2011.

31.1		Certification of the Company’s Chief Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 (18 U.S.C. Section 7241).

31.2		Certification of the Company’s Chief Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 (18 U.S.C. Section 7241).

32.1		Certification of the Company’s Chief Executive Officer Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (18 U.S.C. Section 1350).

32.2		Certification of the Company’s Chief Financial Officer Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (18 U.S.C. Section 1350).

*101		Interactive Data Files.


*		Pursuant to Rule 406T of Regulation S-T, these interactive data files are deemed not filed or part of a registration statement or prospectus for purposes of Sections 11 or 12 of the Securities Act of 1933, as amended, or Section 18 of the Securities Exchange Act of 1934, as amended, and otherwise are not subject to liability.

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned hereunto duly authorized.


	ALTA MESA HOLDINGS, LP (Registrant)
	By:	ALTA MESA HOLDINGS GP, LLC, its general partner

August 12, 2011	By:	/s/ Harlan H. Chappelle
		Harlan H. Chappelle
		President and Chief Executive Officer

August 12, 2011	By:	/s/ Michael A. McCabe
		Michael A. McCabe
		Vice President and Chief Financial Officer

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Alta Mesa Inactive 10-Q2011 Q2 Quarterly report

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