Alta Mesa 10-Q 2012 Q3 Quarterly report

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, DC 20549

FORM 10-Q

(Mark One)

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

For the quarterly period ended: September 30, 2012

OR

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

For the transition period from         to         

Commission file number: 333-173751

ALTA MESA HOLDINGS, LP

(Exact name of registrant as specified in its charter)

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

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

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.    Yes  x    No  ¨

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files.)    Yes  x    No  ¨

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

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

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

Table of Contents

	Page Number
PART I — FINANCIAL INFORMATION
Item 1. Financial Statements
Consolidated Balance Sheets as of September 30, 2012 (unaudited) and December 31, 2011		3
Consolidated Statements of Operations (unaudited) for the Three and Nine Months Ended September  30, 2012 and 2011		4
Consolidated Statements of Cash Flows (unaudited) for the Nine Months Ended September  30, 2012 and 2011		5
Notes to Consolidated Financial Statements (unaudited)		6
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations		18
Item 3. Quantitative and Qualitative Disclosures about Market Risk		27
Item 4. Controls and Procedures		28
PART II — OTHER INFORMATION
Item 1. Legal Proceedings		28
Item 1A. Risk Factors		28
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds		28
Item 3. Defaults Upon Senior Securities		28
Item 4. Mine Safety Disclosures		28
Item 5. Other Information		28
Item 6. Exhibits		29
Signatures		30

2

PART I — FINANCIAL INFORMATION

ITEM 1. Financial Statements

ALTA MESA HOLDINGS, LP AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(dollars in thousands)

	September 30, 2012		December 31, 2011
	(unaudited)
ASSETS
CURRENT ASSETS
Cash and cash equivalents	$	6,022	$	2,630
Accounts receivable, net		38,867		40,807
Other receivables		4,156		2,806
Prepaid expenses and other current assets		7,230		5,394
Derivative financial instruments		16,356		28,582
TOTAL CURRENT ASSETS		72,631		80,219
PROPERTY AND EQUIPMENT
Oil and natural gas properties, successful efforts method, net		627,304		572,816
Other property and equipment, net		16,070		16,351
TOTAL PROPERTY AND EQUIPMENT, NET		643,374		589,167
OTHER ASSETS
Investment in Partnership — cost		9,000		9,000
Deferred financing costs, net		11,204		12,802
Derivative financial instruments		16,570		24,244
Advances to operators		5,464		3,625
Deposits and other assets		1,338		1,026
TOTAL OTHER ASSETS		43,576		50,697
TOTAL ASSETS	$	759,581	$	720,083
LIABILITIES AND PARTNERS’ CAPITAL
CURRENT LIABILITIES
Accounts payable and accrued liabilities	$	98,349	$	70,295
Current portion, asset retirement obligations		1,122		3,030
Derivative financial instruments		101		1,300
TOTAL CURRENT LIABILITIES		99,572		74,625
LONG-TERM LIABILITIES
Asset retirement obligations, net of current portion		46,318		43,066
Long-term debt		545,231		487,036
Notes payable to founder		21,818		20,911
Derivative financial instruments		—		57
Other long-term liabilities		2,605		4,716
TOTAL LONG-TERM LIABILITIES		615,972		555,786
TOTAL LIABILITIES		715,544		630,411
COMMITMENTS AND CONTINGENCIES (NOTE 10)
PARTNERS’ CAPITAL		44,037		89,672
TOTAL LIABILITIES AND PARTNERS’ CAPITAL	$	759,581	$	720,083

See notes to consolidated financial statements.

3

ALTA MESA HOLDINGS, LP AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

(dollars in thousands)

(unaudited)

	Three Months Ended September 30,						Nine Months Ended September 30,
	2012			2011			2012			2011
REVENUES
Natural gas	$	26,758		$	40,250		$	78,638		$	114,362
Oil		57,285			42,213			160,069			113,702
Natural gas liquids		2,877			3,000			10,414			8,900
Other revenues		2,568			600			3,952			1,366
		89,488			86,063			253,073			238,330
Unrealized gain (loss) — oil and natural gas derivative contracts		(37,855	)		30,101			(19,944	)		25,292
TOTAL REVENUES		51,633			116,164			233,129			263,622
EXPENSES
Lease and plant operating expense		17,719			16,267			50,833			44,639
Production and ad valorem taxes		7,232			5,728			19,315			15,198
Workover expense		4,318			4,413			8,254			8,391
Exploration expense		9,480			3,889			13,543			12,310
Depreciation, depletion, and amortization expense		27,147			23,756			76,161			66,187
Impairment expense		46,472			5,743			50,934			16,498
Accretion expense		458			484			1,339			1,430
General and administrative expense		9,812			9,659			30,195			24,251
TOTAL EXPENSES		122,638			69,939			250,574			188,904
INCOME (LOSS) FROM OPERATIONS		(71,005	)		46,225			(17,445	)		74,718
OTHER INCOME (EXPENSE)
Interest expense		(9,922	)		(6,779	)		(29,510	)		(23,102	)
Interest income		30			21			70			35
Litigation settlement		—			—			1,250			—
Gain on contract settlement		—			—			—			1,285
TOTAL OTHER INCOME (EXPENSE)		(9,892	)		(6,758	)		(28,190	)		(21,782	)
INCOME (LOSS) BEFORE STATE INCOME TAXES		(80,897	)		39,467			(45,635	)		52,936
(PROVISION FOR) STATE INCOME TAXES		—			(75	)		—			(150	)
NET INCOME (LOSS)	$	(80,897	)	$	39,392		$	(45,635	)	$	52,786

See notes to consolidated financial statements.

4

ALTA MESA HOLDINGS, LP AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(dollars in thousands)

(unaudited)

	Nine Months Ended September 30,
	2012			2011
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss)	$	(45,635	)	$	52,786
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion, and amortization expense		76,161			66,187
Impairment expense		50,934			16,498
Accretion expense		1,339			1,430
Amortization of loan costs		1,716			2,243
Amortization of debt discount		195			195
Dry hole expense		6,010			6,452
Expired leases		—			93
Unrealized (gain) loss on derivatives		18,644			(28,721	)
(Gain) on contract settlement		—			(1,285	)
Interest converted into debt		907			897
Settlement of asset retirement obligation		(2,003	)		(702	)
Changes in assets and liabilities:
Accounts receivable		1,940			(4,807	)
Other receivables		(1,350	)		3,641
Prepaid expenses and other non-current assets		(3,987	)		(4,142	)
Accounts payable, accrued liabilities, and other long-term liabilities		12,980			4,641
NET CASH PROVIDED BY OPERATING ACTIVITIES		117,851			115,406
CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures for property and equipment		(152,125	)		(147,989	)
Acquisitions		(20,216	)		(66,592	)
NET CASH USED IN INVESTING ACTIVITIES		(172,341	)		(214,581	)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from long-term debt		68,000			100,500
Repayments of long-term debt		(10,000	)		—
Additions to deferred financing costs		(118	)		(1,589	)
NET CASH PROVIDED BY FINANCING ACTIVITIES		57,882			98,911
NET INCREASE (DECREASE) IN CASH		3,392			(264	)
CASH AND CASH EQUIVALENTS, beginning of period		2,630			4,836
CASH AND CASH EQUIVALENTS, end of period	$	6,022		$	4,572
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION
Cash paid during the period for interest	$	20,969		$	15,734
Cash paid during the period for taxes	$	230		$	—
Change in asset retirement obligations	$	1,476		$	445
Asset retirement obligations assumed, purchased properties	$	532		$	2,807
Change in accruals or liabilities for capital expenditures	$	12,963		$	(13,482	)

See notes to consolidated financial statements.

5

ALTA MESA HOLDINGS, LP AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(unaudited)

1. SUMMARY OF ORGANIZATION AND NATURE OF OPERATIONS

The consolidated financial statements reflect the accounts of Alta Mesa Holdings, LP and its subsidiaries (“we,” “us,” “our,” the “Company,” and “Alta Mesa”) after elimination of all significant intercompany transactions and balances. The financial statements should be read in conjunction with the consolidated financial statements and notes thereto included in our annual consolidated financial statements for the year ended December 31, 2011, which were filed with the Securities and Exchange Commission in our Annual Report on Form 10-K (the “2011 Form 10-K”).

The consolidated financial statements included herein as of September 30, 2012, and for the nine month periods ended September 30, 2012 and 2011, are unaudited, and in the opinion of management, the information furnished reflects all material adjustments, consisting of normal recurring adjustments, necessary for a fair presentation of consolidated financial position and of the results of operations for the interim periods presented. The consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the U.S. (“GAAP”) for interim financial information and with the instructions to Form 10-Q and Article 10 of Regulation S-X. Accordingly, they do not include all of the information and footnotes required by GAAP for complete financial statements. Certain minor reclassifications of prior period consolidated financial statements have been made to conform to current reporting practices. The consolidated results of operations for interim periods are not necessarily indicative of results to be expected for a full year.

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

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

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

2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

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

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

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

6

Property and Equipment:Oil and natural gas producing activities are accounted for using the successful efforts method of accounting. Under the successful efforts method, lease acquisition costs and all development costs, including unsuccessful development wells, are capitalized.

Unproved Properties —Acquisition costs associated with the acquisition of leases are recorded as unproved leasehold costs and capitalized as incurred. These consist of costs incurred in obtaining a mineral interest or right in a property such as a lease, in addition to options to lease, broker fees, recording fees and other similar costs related to activities in acquiring properties. Leasehold costs are classified as unproved until proved reserves are discovered, at which time related costs are transferred to proved oil and natural gas properties.

Exploration Expense— Exploration expenses, other than exploration drilling costs, are charged to expense as incurred. These costs include seismic expenditures and other geological and geophysical costs, expired leases, and lease rentals. The costs of drilling exploratory wells and exploratory-type stratigraphic wells are initially capitalized pending determination of whether the well has discovered proved commercial reserves. If the exploratory well is determined to be unsuccessful, the cost of the well is transferred to expense. Exploratory well drilling costs may continue to be capitalized if the reserve quantity is sufficient to justify completion as a producing well and sufficient progress in assessing the reserves and the economic and operating viability of the project is being made. Assessments of such capitalized costs are made quarterly.

Proved Oil and Natural Gas Properties —Costs incurred to obtain access to proved reserves and to provide facilities for extracting, treating, gathering, and storing oil and natural gas are capitalized. All costs incurred to drill and equip successful exploratory wells, development wells, development-type stratigraphic test wells, and service wells, including unsuccessful development wells, are capitalized.

Impairment —The capitalized costs of proved oil and natural gas properties are reviewed quarterly for impairment in accordance with ASC 360-10-35, “Property, Plant and Equipment, Subsequent Measurement,” or whenever events or changes in circumstances indicate that the carrying amount of a long-lived asset or asset group exceeds its fair market value and is not recoverable. The determination of recoverability is based on comparing the estimated undiscounted future net cash flows at a producing field level to the carrying value of the assets. If the future undiscounted cash flows, based on estimates of anticipated production from proved reserves and future crude oil and natural gas prices and operating costs, are lower than the carrying cost, the carrying cost of the asset or group of assets is reduced to fair value. For our proved oil and natural gas properties, we estimate fair value by discounting the projected future cash flows at an appropriate risk-adjusted discount rate. Unproved leasehold costs are assessed quarterly to determine whether they have been impaired. Individually significant properties are assessed for impairment on a property-by-property basis, while individually insignificant unproved leasehold costs may be assessed in the aggregate. If unproved leasehold costs are found to be impaired, an impairment allowance is provided and a loss is recognized in the consolidated statement of operations.

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 $711,000 and $557,000 at September 30, 2012 and December 31, 2011, respectively.

Deferred Financing Costs:Deferred financing costs and the amount of discount at which notes payable have been issued (debt discount) are amortized using the straight-line method, which approximates the interest method, over the term of the related debt. For the three months ended September 30, 2012 and 2011, amortization of deferred financing costs included in interest expense amounted to $0.6 million and $0.5 million, respectively. For the nine months ended September 30, 2012 and 2011, amortization of deferred financing costs included in interest expense amounted to $1.7 million and $2.2 million, respectively. Deferred financing costs are listed among our long-term assets, net of accumulated amortization of $9.2 million and $7.5 million at September 30, 2012 and December 31, 2011, respectively.

Financial Instruments:The fair value of cash, accounts receivable, other current assets, and current liabilities approximate book value due to their short-term nature. The estimate of fair value of long-term debt under our senior secured revolving credit facility is not considered to be materially different from carrying value due to market rates of interest. The fair value of notes payable to our founder is not practicable to determine. We have estimated the fair value of our $300 million senior notes payable due October 15, 2018 (“senior notes”) at $299 million and $293 million at September 30, 2012 and December 31, 2011, respectively. See Note 5 for further information on fair values of financial instruments. See Note 8 for information on long-term debt.

7

Recent Accounting Pronouncements

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

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

3. SIGNIFICANT ACQUISITIONS

Sydson Acquisition

On April 21, 2011, we purchased from Sydson Energy and certain of its related parties (together, “Sydson” and the “Sydson acquisition”) certain oil and natural gas assets primarily located in Texas and South Louisiana in which we had jointly participated with Sydson. The purchase price was $27.5 million in cash (a total cost of $28.4 million including abandonment liabilities we assumed). Funding for the acquisition was provided through our credit facility. In addition, litigation associated with a portion of the assets purchased was resolved as a result of the transaction.

TODD Acquisition

On June 17, 2011, we purchased from Texas Oil Distribution & Development, Inc. and Matrix Petroleum LLC and certain other parties (together, “TODD” and the “TODD acquisition”) certain oil and natural gas assets primarily located in Texas and South Louisiana in which we had jointly participated with TODD. The purchase price was $22.5 million in cash (a total cost of $23.4 million including abandonment liabilities we assumed). Funding for the acquisition was provided through our credit facility. In addition, litigation associated with TODD was resolved as a result of the transaction.

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

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

The revenue and earnings related to the Sydson and TODD acquisitions are included in our consolidated statement of operations for the nine months ended September 30, 2012. Revenue and earnings, had the acquisitions occurred on January 1, 2011, are provided below. This unaudited pro forma information has been derived from historical information and is for illustrative purposes only. The unaudited pro forma financial information does not attempt to predict or suggest future results. It also does not necessarily reflect what the historical results of the combined company would have been had the companies been combined during these periods.

	(Unaudited)
	Revenue		Income
	(dollars in thousands)
Pro forma results for the combined entity for the nine months ended September 30, 2011	$	266,816	$	54,995

8

4. PROPERTY AND EQUIPMENT

Property and equipment consists of the following:

	September 30, 2012			December 31, 2011
	(unaudited)
	(dollars in thousands)
OIL AND NATURAL GAS PROPERTIES
Unproved properties	$	41,845		$	34,797
Accumulated impairment		(5,801	)		(5,427	)
Unproved properties, net		36,044			29,370
Proved oil and natural gas properties		1,092,893			925,578
Accumulated depreciation, depletion, amortization and impairment		(501,633	)		(382,132	)
Proved oil and natural gas properties, net		591,260			543,446
TOTAL OIL AND NATURAL GAS PROPERTIES, net		627,304			572,816
LAND		1,185			1,185
DRILLING RIG		10,500			10,500
Accumulated depreciation		(1,662	)		(1,137	)
TOTAL DRILLING RIG, net		8,838			9,363
OTHER PROPERTY AND EQUIPMENT
Office furniture and equipment, vehicles		8,981			7,313
Accumulated depreciation		(2,934	)		(1,510	)
OTHER PROPERTY AND EQUIPMENT, net		6,047			5,803
TOTAL PROPERTY AND EQUIPMENT, net	$	643,374		$	589,167

9

5. FAIR VALUE DISCLOSURES

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

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

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

Our senior notes are carried at historical cost, net of amortized discount; we estimate the fair value of the senior notes for disclosure purposes (see Note 2). This estimation is based on the most recent trading values of the notes at or near the reporting dates.

Oil and natural gas properties are subject to impairment testing and potential impairment write down. Oil and gas properties with a carrying amount of $198.4 million were written down to their fair value of $147.5 million, resulting in an impairment charge of $50.9 million for the nine months ended September 30, 2012. Oil and gas properties with a carrying amount of $31.8 million were written down to their fair value of $15.3 million, resulting in an impairment charge of $16.5 million for the nine months ended September 30, 2011. For the three months ended September 30, 2012, oil and gas properties with a carrying amount of $186.0 million were written down to their fair value of $139.6 million, resulting in an impairment charge of $46.4 million. For the three months ended September 30, 2011, oil and gas properties with a carrying amount of $7.4 million were written down to their fair value of $1.7 million, resulting in an impairment charge of $5.7 million. Significant Level 3 assumptions used in the calculation of estimated discounted cash flows in the impairment analysis included our estimate of future oil and natural gas prices, production costs, development expenditures, estimated timing of production of proved reserves, appropriate risk-adjusted discount rates, and other relevant data.

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

New additions and revisions to asset retirement obligations result from estimations for new properties or revised estimations for existing 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 $2.0 million and $3.3 million in additions and revisions to asset retirement obligations measured at fair value during the nine months ended September 30, 2012 and 2011, respectively.

The following table presents information about our financial assets and liabilities measured at fair value on a recurring basis as of September 30, 2012 and December 31, 2011, and indicates the fair value hierarchy of the valuation techniques we utilized to determine such fair value:

	Level 1		Level 2		Level 3		Total
	(dollars in thousands)
At September 30, 2012 (unaudited):
Financial Assets:
Derivative contracts for oil and natural gas	$	—	$	81,447	$	—	$	81,447
Financial Liabilities:
Derivative contracts for oil and natural gas		—		48,622		—		48,622
At December 31, 2011:
Financial Assets:
Derivative contracts for oil and natural gas	$	—	$	109,138	$	—	$	109,138
Financial Liabilities:
Derivative contracts for oil and natural gas		—		56,369		—		56,369
Derivative contracts for interest rate		—		1,300		—		1,300

10

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

6. DERIVATIVE FINANCIAL INSTRUMENTS

We account for our derivative contracts under the provisions of ASC 815, “Derivatives and Hedging.” We have entered into forward-swap contracts and collar contracts to reduce our exposure to price risk in the spot market for oil and natural gas. We also utilize financial basis swap contracts, which address the price differential between market-wide benchmark prices and other benchmark pricing referenced in certain of our crude oil and natural gas sales contracts. Substantially all of our hedging agreements are executed by affiliates of the lenders under our credit facility described in Note 8 below, and are collateralized by the security interests of the respective affiliated lenders in certain of our assets under the credit facility. The contracts settle monthly and are scheduled to coincide with either oil production equivalent to barrels (Bbl) per month or gas production equivalent to volumes in millions of British thermal units (MMbtu) per month. The contracts represent agreements between us and the counter-parties to exchange cash based on a designated price, or in the case of financial basis hedging contracts, based on a designated price differential between various benchmark prices. Cash settlement occurs monthly 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 entered an interest rate swap agreement to mitigate the risk of loss due to changes in interest rates, which expired in the third quarter of 2012. The interest rate swap was not designated as a cash flow hedge in accordance with ASC 815. Both realized gains and losses from settlement and unrealized gains and losses from changes in the fair market value of the interest rate swap contract were 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 operations for each of the three month and nine month periods ended September 30, 2012 and 2011.

The following table summarizes the fair value (see Note 5 for further discussion of fair value) and classification of our derivative instruments, none of which have been designated as hedging instruments under ASC 815:

Fair Values of Derivative Contracts
	Balance Sheet Location at September 30, 2012
	Current asset portion of Derivative financial instruments			Current liability portion of Derivative financial instruments			Long-term asset portion of Derivative financial instruments			Long-term liability portion of Derivative financial instruments
	(unaudited)
	(dollars in thousands)
Fair value of oil and gas commodity contracts, assets	$	38,792		$	—		$	42,655		$	—
Fair value of oil and gas commodity contracts, (liabilities)		(22,436	)		(101	)		(26,085	)		—
Fair value of interest rate contracts, (liabilities)		—			—			—			—
Total net assets, (liabilities)	$	16,356		$	(101	)	$	16,570		$	—

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

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

11

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

Derivatives not designated as hedging instruments under ASC 815	Location of Gain (Loss)	Classification of Gain (Loss)	For the three months ended September 30,					For the nine months  ended September 30,
			2012			2011		2012			2011
			(unaudited) (dollars in thousands)
Natural gas commodity contracts	Natural gas revenues	Realized	$	13,501		$	5,986	$	33,130		$	16,897
Oil commodity contracts	Oil revenues	Realized		(168	)		162		(958	)		(3,756	)
Interest rate contracts	Interest benefit (expense)	Realized		(211	)		76		(1,337	)		2,004
Total realized gains (losses) from derivatives not designated as hedges			$	13,122		$	6,224	$	30,835		$	15,145
Natural gas commodity contracts	Unrealized gain (loss) — oil and natural gas derivative contracts	Unrealized	$	(17,865	)	$	7,724	$	(23,746	)	$	6,425
Oil commodity contracts	Unrealized gain (loss) — oil and natural gas derivative contracts	Unrealized		(19,990	)		22,377		3,802			18,867
Interest rate contracts	Interest benefit (expense)	Unrealized		212			2,921		1,300			3,429
Total unrealized gains (losses) from derivatives not designated as hedges			$	(37,643	)	$	33,022	$	(18,644	)	$	28,721

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.

12

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

NATURAL GAS DERIVATIVE CONTRACTS

	Volume in MMbtu		Weighted Average		Range
Period and Type of Contract					High		Low
October 2012 – December 2012
Price Swap Contracts
Short Swaps		3,440,000	$	4.08	$	5.02	$	3.06
Collar Contracts
Short Call Options		2,470,000		5.53		6.00		4.50
Long Put Options		1,933,000		5.09		6.75		4.00
Long Call Options		1,380,000		4.67		5.00		4.00
Short Put Options		3,493,000		3.44		4.50		2.50
2013
Price Swap Contracts
Short Swaps		19,400,000		4.75		9.15		3.30
Collar Contracts
Short Call Options		1,825,000		5.25		5.25		5.25
Long Put Options		1,500,000		6.09		6.15		6.00
Long Call Options		3,625,000		5.87		7.00		4.75
Short Put Options		18,748,500		3.18		5.00		3.00
2014
Price Swap Contracts
Short Swaps		3,125,000		6.27		7.50		5.60
Collar Contracts
Short Call Options		3,475,000		7.05		9.00		6.00
Long Put Options		1,650,000		6.73		7.00		6.00
Short Put Options		2,623,500		4.14		5.50		3.00
2015
Price Swap Contracts
Short Swaps		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

13

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

OIL DERIVATIVE CONTRACTS

	Volume in Bbls		Weighted Average		Range
Period and Type of Contract					High		Low
October 2012 – December 2012
Price Swap Contracts
Short Swaps		363,400	$	112.06	$	121.15	$	80.20
Collar Contracts
Short Call Options		367,499		117.23		132.00		100.00
Long Put Options		368,000		97.53		105.00		65.00
Long Call Options		66,475		101.89		123.50		90.20
Short Put Options		483,550		77.09		85.00		68.75
2013
Price Swap Contracts
Short Swaps		392,000		89.75		94.74		77.00
Collar Contracts
Short Call Options		1,566,955		116.82		129.00		100.00
Long Put Options		1,273,500		109.15		115.00		85.00
Long Call Options		114,975		105.00		127.00		92.35
Short Put Options		1,456,000		82.04		90.00		65.00
2014
Price Swap Contracts
Short Swaps		255,050		96.57		105.48		81.00
Collar Contracts
Short Call Options		273,750		125.70		133.50		107.50
Long Put Options		1,127,200		91.62		100.00		80.00
Short Put Options		1,233,780		72.34		80.00		60.00
2015
Price Swap Contracts
Short Swaps		401,500		99.30		99.30		99.30
Collar Contracts
Short Call Options		428,850		120.81		135.98		115.00
Long Put Options		501,850		90.27		95.00		85.00
Short Put Options		501,850		69.46		74.00		60.00
2016
Price Swap Contracts
Short Swaps		292,800		94.95		95.00		94.90
Collar Contracts
Short Call Options		256,000		116.28		130.00		114.00
Long Put Options		256,000		90.71		95.00		90.00
Short Put Options		256,000		70.71		75.00		70.00
2017
Collar Contracts
Short Call Options		243,000		114.00		114.00		114.00
Long Put Options		243,000		90.00		90.00		90.00

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

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

Volume in MMbtu	Reference Price 1(1)	Reference Price 2(1)	Period	Spread ($ per MMbtu)
460,000	NYMEX Henry Hub	Houston Ship Channel	Oct ’12 —Dec ’12	$	0.1575
920,000	NYMEX Henry Hub	Houston Ship Channel	Oct ’12 —Dec ’12	$	0.1400
3,650,000	NYMEX Henry Hub	Houston Ship Channel	Jan ’13 — Dec ’13	$	0.0625

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

14

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

Volume in Bbl	Reference Price 1 (2)	Reference Price 2 (2)	Period	Weighted Average Spread ($ per Bbl)
414,000	Brent IPE	Argus Louisiana Light Sweet	Oct ’12 —Dec ’12	$	1.92
1,277,500	Brent IPE	Argus Louisiana Light Sweet	Jan ’13 — Dec ’13	$	3.09

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

7. ASSET RETIREMENT OBLIGATIONS

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

Balance, December 31, 2011	$	46,096
Liabilities incurred		602
Liabilities assumed with acquired producing properties		532
Revisions to previous estimates		874
Liabilities settled		(2,003	)
Accretion expense		1,339
Balance, September 30, 2012		47,440
Less: Current portion		1,122
	$	46,318

8. LONG-TERM DEBT AND NOTES PAYABLE TO FOUNDER

Long-term debt consists of the following:

	September 30, 2012		December 31, 2011
	(unaudited)
	(dollars in thousands)
Credit Facility	$	246,790	$	188,790
Senior Notes		298,441		298,246
Total long-term debt	$	545,231	$	487,036

Credit Facility. On May 13, 2010, we entered into a Sixth Amended and Restated Credit Agreement (as amended, the “credit facility”). The credit facility matures on May 23, 2016 and is secured by substantially all of our oil and gas properties. The credit facility borrowing base is redetermined periodically and, as of September 30, 2012, the borrowing base under the facility was $350 million. The credit facility bears interest at LIBOR plus applicable margins between 2.00% and 2.75% or a “Reference Rate,” which is based on the prime rate of Wells Fargo Bank, N. A., plus a margin ranging from 1.00% to 1.75%, depending on the utilization of our borrowing base. The rate was 2.5% as of September 30, 2012 and 2.774% as of December 31, 2011.

Senior Notes. On October 13, 2010, we issued senior notes due October 15, 2018 with a face value of $300 million, at a discount of $2.1 million. The senior notes carry a face interest rate of 9.625%, with an effective rate of 9.75%; interest is payable semi-annually each April 15th and October 15th. The senior notes are secured by general corporate credit, and effectively rank junior to any of our existing or future secured indebtedness, which includes the credit facility. The senior notes are unconditionally guaranteed on a senior unsecured basis by each of our material subsidiaries. The balance is presented net of unamortized discount of $1.6 million and $1.8 million at September 30, 2012 and December 31, 2011, respectively.

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.

15

The credit facility and senior notes include covenants requiring us to maintain certain financial covenants including a current ratio, leverage ratio, and interest coverage ratio. At September 30, 2012, we were in compliance with the covenants. The terms of the credit facility also restrict our ability to make distributions and investments.

Notes Payable to Founder. We also have notes payable to our founder which bear simple interest at 10% with a balance of $21.8 million and $20.9 million at September 30, 2012 and December 31, 2011, respectively. The notes mature December 31, 2018. Interest and principal are payable at maturity. These founder notes are subordinate to all debt. Interest on the notes payable to our founder amounted to $907,000 and $897,000 for the nine months ended September 30, 2012 and 2011, respectively, and $304,000 and $297,000 for the three months ended September 30, 2012 and 2011, respectively. Such amounts have been added to the balance of the founder notes.

9. ACCOUNTS PAYABLE AND ACCRUED LIABILITIES

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

	September 30, 2012		December 31, 2011
	(unaudited)
	(dollars in thousands)
Capital expenditures	$	29,884	$	19,119
Revenues and royalties payable		6,437		6,742
Operating expenses/taxes		32,747		21,147
Compensation		4,023		3,567
Acquisition costs payable		—		2,883
Other		6,935		5,754
Total accrued liabilities		80,026		59,212
Accounts payable		18,323		11,083
Accounts payable and accrued liabilities	$	98,349	$	70,295

10. COMMITMENTS AND CONTINGENCIES

Contingencies

Hilltop Field Litigation: On July 23, 2009, we made a payment of $25.5 million and took assignment of substantially all working interests that Chesapeake Energy Corporation (“Chesapeake”) had acquired from Gastar Exploration Ltd. (“Gastar”) in an approximate 50,000 acre area of Leon and Robertson Counties, Texas known as the Hilltop field, in which the Deep Bossier formation was the principal focus for development. We exercised our preferential right to purchase these interests from Gastar in late 2005, but Gastar and Chesapeake had opposed this and Chesapeake took record title at that time. We finally and conclusively prevailed when, in 2008, a Texas court of appeals directed that specific performance take place. In early 2009, the Texas Supreme Court denied the defendants’ request to review the appeal. As a result, we were able to take assignment of working interests in over 30 producing wells and participate in further development of the area, primarily with EnCana, but also with Gastar. A subsequent payment to EnCana of $15.2 million plus purchase accounting adjustments of $3.8 million brought the total cost of the acquisition to $44.5 million. While the ownership of these interests has been decided by the courts, we pursued other claims against Chesapeake and Gastar; Chesapeake claimed an additional $36.3 million of past expenses. The case was set for trial on April 24, 2012. Shortly before the trial was to begin, we reached an agreement in principle to settle with the Chesapeake-related defendants and entered into a settlement agreement with Gastar. The effects of these settlements, recorded in the second quarter of 2012, were not material to our financial position or results of operations.

Environmental claims: Management has established a liability for soil contamination in Florida of $1.0 million at September 30, 2012 and December 31, 2011, based on our undiscounted engineering estimates. The obligations are included in other long-term liabilities in the accompanying consolidated balance sheets.

Various landowners have sued The Meridian Resource Corporation and its subsidiaries (“Meridian”), which we acquired in 2010, in lawsuits concerning several fields in which Meridian has had operations. The lawsuits seek injunctive relief and other relief, including unspecified amounts in both actual and punitive damages for alleged breaches of mineral leases and alleged failure to restore the plaintiffs’ lands from alleged contamination and otherwise from Meridian’s oil and natural gas operations. We are unable to express an opinion with respect to the likelihood of an unfavorable outcome of the various environmental claims or to estimate the amount or range of potential loss should the outcome be unfavorable. Therefore, we have not provided any amount for these claims in our financial statements at September 30, 2012.

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

16

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

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

We have a contingent commitment to pay an amount up to a maximum of approximately $2.8 million for properties acquired in 2008. The additional purchase consideration will be paid if certain product price conditions are met.

11. SIGNIFICANT RISKS AND UNCERTAINTIES

Our business makes us vulnerable to changes in wellhead prices of crude oil and natural gas. Such prices have been volatile in the past and can be expected to be volatile in the future. By definition, proved reserves are based on analysis of current oil and natural gas prices. Price declines reduce the estimated value of proved reserves and may increase annual amortization expense (which is based on proved reserves). Price declines may also result in impairments, or non-cash write-downs, of the value of our oil and natural gas properties. We mitigate a portion of this vulnerability by entering into oil and natural gas price derivative contracts. See Note 6.

12. PARTNERS’ CAPITAL

In September 2006, our limited partnership agreement was amended such that the affiliates of Alta Mesa Holdings, LP and certain other parties became Class A limited partners (“Class A Partners”) and our capital partner, Alta Mesa Investment Holdings, Inc. (“AMIH”), was admitted to the partnership as the sole Class B limited partner (“Class B Partner”). AMIH is an affiliate of Denham Commodity Partners Fund IV LP (“DCPF IV”). DCPF IV is advised by Denham Capital Management LP, a private equity firm focused on energy and commodities.

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

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

The Class B Partner may require the General Partner to make distributions; however, any distribution must be permitted under the terms of our credit facility and the indenture that governs our senior notes.

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

13. SUBSIDIARY GUARANTORS

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

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

On October 15, 2012, we issued $150 million in senior notes (“additional senior notes”) due October 15, 2018, substantially identical to the existing senior notes described in Note 8, and governed by the same indenture. The additional senior notes were issued at a discount of $1.5 million and total net proceeds after deducting estimated fees and offering expenses were approximately $145.3 million. All net proceeds were utilized to reduce borrowings outstanding under the credit facility. The additional senior notes carry a face interest rate of 9.625%, with a yield to maturity of 9.85%; interest is payable semi-annually each April 15th and October 15^th. The additional senior notes were issued in a private placement. We entered into a registration rights agreement with the initial purchasers of the additional senior notes, under which we will exchange the notes for notes registered with the SEC within 180 days of the date of issue of the additional senior notes. In connection with the issuance of the additional senior notes, our borrowing base under the credit facility was automatically reduced to $313.7 million.

17

Management has evaluated all events subsequent to the balance sheet date of September 30, 2012, and has determined that no events require disclosure, other than the issuance of additional senior notes described above.

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

The following discussion and analysis should be read in conjunction with the financial statements and related notes included elsewhere in this report. In addition, such analysis should be read in conjunction with the financial statements and the related notes included in our Annual Report on Form 10-K for the year ended December 31, 2011 (“2011 Form 10-K”). The historical financial information discussed below in this Management’s Discussion and Analysis of Financial Condition and Results of Operations represents Alta Mesa’s financial information for the periods indicated, giving effect to the Sydson and TODD asset acquisitions from April 21, 2011 and June 17, 2011, respectively.

Overview

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

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

• the prices at which we will sell our production;

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

• the level of our operating and administrative costs.

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

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

Significant Acquisitions

Sydson Acquisition

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

TODD Acquisition

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

18

Outlook

Natural gas prices declined significantly during 2011 and 2012, slightly rebounding in the third quarter of 2012, closing at $3.02 for the October 2012 NYMEX Henry Hub Futures contract settled September 28, 2012. A low point was reached with the May 2012 NYMEX closing at $2.04 per MMbtu. The reduction in prices has been caused by many factors, including recent increases in North American natural gas production, warmer than normal winter weather and high levels of natural gas in storage.

The decrease in natural gas prices resulted in a significant non-cash write-down of several of our oil and gas properties in the third quarter of 2012. Total impairment expense for the quarter was $46.5 million. Of this, $19.9 million was for our Hilltop field in East Texas, which produces dry gas, and is vulnerable to extremely low prices for natural gas. Other properties written down were also in East Texas, where our natural gas production is most concentrated.

The volatility in prices of both oil and natural gas resulted in a significant unrealized non-cash loss on our derivative contracts, which lost $37.9 million during the third quarter of 2012. However, realized gains from our hedging program were $13.3 million during the same period.

Prices for oil did not significantly decline in 2011 but decreased somewhat in 2012, with a NYMEX West Texas Intermediate crude oil monthly average of $94.56 on September 30, 2012. We expect oil prices to remain volatile in the future. Factors affecting the price of oil include worldwide economic conditions, including the European credit crisis, geopolitical activities, including developments in the Middle East, worldwide supply disruptions, weather conditions, actions taken by the Organization of Petroleum Exporting Countries and the value of the U.S. dollar in international currency markets. Prices for natural gas liquids have declined during 2012 due to increased liquids-targeted drilling and volumes in storage.

We have hedged approximately 90% of our forecasted PDP production through 2017 at prices higher than those currently prevailing for natural gas. However, if prices for natural gas remain depressed for long periods, we may be required to write down the value of our oil and natural gas properties or revise our development plans, which may cause certain of our undeveloped well locations to no longer be deemed proved. In addition, sustained low prices for natural gas will reduce the amounts we would otherwise have available to pay expenses and service our debt obligations.

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

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

Operations Update

South Louisiana

At Weeks Island, our largest oilfield, we drilled and completed eight successful oil wells in the first three quarters of 2012. Three additional wells were completed and began production after September 30, 2012. Finally, in the third quarter of 2012, we spudded two additional wells that will be completed in the fourth quarter of 2012. We initiated a two-rig drilling program near the end of the second quarter. We expect to continually utilize two drilling rigs and one to two workover rigs in this field through the end of 2012, and at least one drilling rig in 2013. Production from Weeks Island was approximately 2,100 BOE per day (net to our interest, 92% oil) for the first three quarters of 2012, and 2,400 BOE per day for the third quarter of 2012, as compared to 1,700 and 2,200 BOE per day for the first and second quarters of 2012, respectively. In the third quarter of 2012, we completed substantial production debottlenecking and facility upgrades at Weeks Island. This work includes the addition of salt water disposal facilities, increased compression capacity and completion of a barge loading facility. We expect these improvements to provide potential opportunities to bring online some wells previously shut in due to higher costs of gas lift and/or salt water disposal, and to increase our sales capacity with higher pipeline and barge throughput capacity.

Hurricane Isaac disrupted our production in South Louisiana during the third quarter of 2012, and all properties have been returned to production. We estimate the total delay of production was approximately 32 MBOE.

19

Total production net to our interest from all of our properties in South Louisiana for the first three quarters of 2012 was 749 MBbl’s (including natural gas liquids) and 4.6 Bcf of natural gas.

East Texas/Hilltop

Our Hilltop field in Leon and Robertson counties continues to produce the largest portion of our gas sales, principally from the Deep Bossier formation, at approximately 29 MMcf per day (net to our interest) for the first three quarters of 2012, declining from approximately 50 MMcf per day for the year 2011. We have chosen to delay further investments in the historically prolific Deep Bossier and Knowles Lime natural gas reservoirs at Hilltop in favor of oil and liquids-rich targets that presently offer higher returns on capital. We continue to develop, test, and evaluate other formations at Hilltop such as the Woodbine, Eagle Ford and Austin Chalk. During the first three quarters of 2012, we participated with EnCana in the completion and testing of three horizontal oil wells in the Woodbine formation; we also have minor carried interests in two Woodbine/Eagle Ford horizontal wells drilled by EnCana on our acreage during the third quarter of 2012. We completed our first operated well in the Hilltop field in 2012, a successful horizontal oil well in the Austin Chalk formation, and drilled a vertical well which is undergoing completion in the fourth quarter of 2012 as an oil well in the Lower Woodbine formation. We plan additional operations in the fourth quarter of 2012 or early 2013, utilizing an existing wellbore to explore a different geological zone.

Our other interests in East Texas are principally in San Jacinto, Montgomery, and Polk counties and primarily produce from the Yegua, Wilcox, and Austin Chalk formations. We continue to pursue opportunities in other prospective and productive formations, such as the MidCox, Buda, Glen Rose, Pettet, Woodbine, Edwards, and Midway Shale formations, in other East Texas properties.

Total production from our East Texas region was 12 Bcfe (86% natural gas) for the first three quarters of 2012, including 8 Bcfe from the Hilltop field.

Oklahoma

We have targeted our Oklahoma properties for further development with increased capital spending in 2012. We expect to increase oil production from these long-lived oil fields by deepening existing wellbores, downspacing with additional drilling, and by recompleting existing wellbores to other previously unexploited zones. We believe this is a low-cost and low-risk strategy to increase oil production. During the first three quarters of 2012, we deepened or reactivated twelve wellbores into the Mississippian Lime formation and are evaluating the fieldwide potential for additional exploitation.

Our Oklahoma properties produced 138 MBbl of oil and 0.8 Bcf of natural gas net to our interest during the first three quarters of 2012.

Eagle Ford Shale

We are participating with Murphy Oil Corporation (“Murphy”), the operator of our Eagleville field, in what we expect to be at least a five year program that began in 2011 in which we expect to drill at least 200 wells targeting the Eagle Ford Shale in Karnes County, Texas. At the end of the third quarter of 2012, we had working interests in 51 producing wells in the Eagle Ford Shale, and overriding royalty interests in three additional wells. Through mid-November 2012, nine additional wells in which we have working interests have begun production in this area, and Murphy was operating three drilling rigs on our acreage.

We produced approximately 1,900 BOE per day from the Eagleville field (net to our interest, 94% oil and natural gas liquids) during the first three quarters of 2012. For the third quarter of 2012, production from the Eagleville field was 2,200 BOE per day net to our interest.

20

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

	Three Months Ended September 30,					Increase (Decrease)			% Change
	2012			2011
	($ in thousands, except average sales price and unit costs)
Summary Operating Information:
Net Production:
Natural gas (MMcf)		4,515			8,156		(3,641	)		(45	)%
Oil (MBbls)		568			414		154			37	%
Natural gas liquids (MBbls)		79			47		32			68	%
Total natural gas equivalent (MMcfe)		8,398			10,921		(2,523	)		(23	)%
Average daily gas production (MMcfe per day)		91.3			118.7		(27.4	)		(23	)%
Average Sales Price:
Natural gas (per Mcf) realized	$	5.93		$	4.94	$	0.99			20	%
Natural gas (per Mcf) unhedged		2.94			4.20		(1.26	)		(30	)%
Oil (per Bbl) realized		100.79			102.08		(1.29	)		(1	)%
Oil (per Bbl) unhedged		101.08			101.69		(0.61	)		(1	)%
Natural gas liquids (per Bbl) realized (1)		36.50			63.43		(26.93	)		(42	)%
Combined (per Mcfe) realized		10.35			7.83		2.52			32	%
Hedging Activities:
Realized natural gas revenue gain	$	13,501		$	5,986	$	7,515			126	%
Realized oil revenue gain (loss)		(168	)		162		(330	)		(204	)%
Summary Financial Information
Revenues
Natural gas	$	26,758		$	40,250	$	(13,492	)		(34	)%
Oil		57,285			42,213		15,072			36	%
Natural gas liquids		2,877			3,000		(123	)		(4	)%
Other revenues		2,568			600		1,968			328	%
Unrealized gain (loss) — oil and natural gas derivative contracts		(37,855	)		30,101		(67,956	)		(226	)%
		51,633			116,164		(64,531	)		(56	)%
Expenses
Lease and plant operating expense		17,719			16,267		1,452			9	%
Production and ad valorem taxes		7,232			5,728		1,504			26	%
Workover expense		4,318			4,413		(95	)		(2	)%
Exploration expense		9,480			3,889		5,591			144	%
Depreciation, depletion, and amortization expense		27,147			23,756		3,391			14	%
Impairment expense		46,472			5,743		40,729			709	%
Accretion expense		458			484		(26	)		(5	)%
General and administrative expense		9,812			9,659		153			2	%
Interest expense, net		9,892			6,758		3,134			46	%
Provision for state income taxes		—			75		(75	)		NA
Net income (loss)	$	(80,897	)	$	39,392	$	(120,289	)		(305	)%
Average Unit Costs per Mcfe:
Lease and plant operating expense	$	2.11		$	1.49	$	0.62			42	%
Production and ad valorem taxes		0.86			0.52		0.34			65	%
Workover expense		0.51			0.40		0.11			28	%
Exploration expense		1.13			0.36		0.77			214	%
Depreciation , depletion and amortization expense		3.23			2.18		1.05			48	%
General and administrative expense		1.17			0.88		0.29			33	%

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

21

Revenues

Natural gas revenuesfor the three months ended September 30, 2012 decreased $13.5 million, or 34%, to $26.8 million from $40.3 million in 2011. Approximately $18 million of the decrease in revenues from natural gas was due to a decrease in production of 3.6 Bcf, or 45%. This decline is primarily due to our Hilltop field, which produced 2.1 Bcf in the third quarter of 2012, compared to 5.2 Bcf in the third quarter of 2011. The price of natural gas exclusive of hedging decreased 30% in the third quarter of 2012; however, our overall realized price (including hedging gains and losses) increased 20% from $4.94 per Mcf in the third quarter of 2011 to $5.93 per Mcf in the third quarter of 2012, resulting in an increase in natural gas revenues of approximately $4.5 million.

Oil revenuesfor the three months ended September 30, 2012 increased $15.1 million, or 36%, to $57.3 million from $42.2 million in 2011. The increase in revenue was attributable to increased production volumes, offset slightly by a lower average realized price. Approximately $15.8 million of the increase was due to an increase in production of 154 MBbls, or 37%. This increase is primarily due to production from our Eagleville field, which increased 95 MBbls in the third quarter of 2012 as compared to the third quarter of 2011, from 71 MBbls to 166 MBbls. The price of oil exclusive of hedging decreased 1% in the third quarter of 2012; the overall realized price (including hedging gains and losses) also decreased 1% from $102.08 per Bbl in the third quarter of 2011 to $100.79 per Bbl in the third quarter of 2012, resulting in a decrease in oil revenues of approximately $0.7 million.

Natural gas liquids revenuesdecreased $0.1 million, or 4%, during the third quarter of 2012 compared to the same period in 2011. A 68% increase in volumes from 47 MBbls to 79 MBbls was offset by a decrease in our average price of 42%, from $63.43 per Bbl to $36.50 per Bbl. The increase in volume is primarily due to an increase of 22 MBbls in natural gas liquids from the Eagleville field.

Unrealized gain (loss) — oil and natural gas derivative contractswas a loss of $37.9 million during the three months ended September 30, 2012 as compared to a gain of $30.1 million during the same period in 2011. The significant fluctuation from period to period is due to the volatility of oil and natural gas prices and changes in our outstanding hedging contracts during these periods. The majority of the losses in 2012 were related to the increase in oil and natural gas prices during the third quarter of 2012 as compared to market prices at the end of the second quarter of 2012, which decreased the unrealized value of our open derivative contracts.

Expenses

Lease and plant operating expenseincreased $1.4 million in the third quarter of 2012 as compared to the third quarter of 2011, from $16.3 million to $17.7 million. On a unit basis, lease and plant operating expense increased from $1.49 per Mcfe to $2.11 per Mcfe for the three months ended September 30, 2011 and 2012, respectively, which reflects the decrease in volume while costs increased 9%. In general, lease operating expenses are higher for our oil producing properties. Oil as a percentage of production on an equivalent basis increased from 23% to 41% for the third quarter of 2011 and 2012, respectively. Natural gas as a percentage of total equivalent production during the same periods decreased from 75% to 54%.

Production and ad valorem taxes increased $1.5 million, or 26%, to $7.2 million for the third quarter of 2012, as compared to $5.7 million for the third quarter of 2011. Ad valorem taxes increased $1.2 million, primarily due to increases in asset values. Production taxes increased $0.3 million. Production tax as a percentage of product revenues before realized hedging gains and losses was approximately 8% for the quarter ended September 30, 2012 and 7% for the corresponding period in 2011. Reduced natural gas production from our Hilltop field, which is subject to certain production tax exemptions, coupled with increased revenues from oil and natural gas liquids, increased the overall tax rate.

Workover expensedecreased from the third quarter of 2011 to the third quarter of 2012, from $4.4 million to $4.3 million, respectively. This expense varies depending on activities in the field.

Exploration expenseincludes the costs of our geology department, costs of geological and geophysical data, delay rentals, expired leases, and dry holes. Exploration expense increased $5.6 million from $3.9 million for the third quarter of 2011 to $9.5 million for the third quarter of 2012, primarily due to increased dry hole expense of $4.8 million and seismic expenses in the third quarter of 2012.

22

Depreciation, depletion and amortizationincreased $3.4 million to $27.1 million for the third quarter of 2012 as compared to $23.7 million for the third quarter of 2011. On a per unit basis, this expense increased from $2.18 to $3.23 per Mcfe. The rate is a function of capitalized costs of proved properties, reserves and production by field.

Impairment expenseincreased from $5.7 million in the third quarter of 2011 to $46.4 million in the third quarter of 2012. This expense varies with the results of drilling, as well as with price declines and other factors which may render some projects uneconomic, resulting in impairment. The decreasing trend in natural gas prices resulted in a significant impairment in the third quarter of 2012. Of the $46.4 million total expense, $19.9 million was for our Hilltop field in East Texas, which produces dry gas, and is vulnerable to extremely low prices for natural gas. Other properties written down were also in East Texas, where our natural gas production is most concentrated.

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 $0.5 million for the third quarter of 2012 and 2011, respectively.

General and administrative expenseincreased $0.1 million for the third quarter of 2012 to $9.8 million from $9.7 million for the third quarter of 2011. On a per unit basis, general and administrative expenses increased from $0.88 to $1.17 per Mcfe, which reflects the decrease in volume produced on an Mcfe basis, while total general and administrative expenses remained the same.

Interest expense, netincreased $3.1 million for the third quarter of 2012 to $9.9 million from $6.8 million for the third quarter of 2011. This increase is primarily due to interest rate hedge gains of $2.8 million recorded in the third quarter of 2011.

23

Results of Operations: Nine Months Ended September 30, 2012 v. Nine Months Ended September 30, 2011

	Nine Months Ended September 30,						Increase (Decrease)			% Change
	2012			2011
	($ in thousands, except average sales price and unit costs)
Summary Operating Information:
Net Production:
Natural gas (MMcf)		17,144			23,501			(6,357	)		(27	)%
Oil (MBbls)		1,534			1,138			396			35	%
Natural gas liquids (MBbls)		228			155			73			47	%
Total natural gas equivalent (MMcfe)		27,711			31,259			(3,548	)		(11	)%
Average daily gas production (MMcfe per day)		101.1			114.5			(13.4	)		(11	)%
Average Sales Price:
Natural gas (per Mcf) realized	$	4.59		$	4.87		$	(0.28	)		(6	)%
Natural gas (per Mcf) unhedged		2.65			4.15			(1.50	)		(36	)%
Oil (per Bbl) realized		104.38			99.93			4.45			4	%
Oil (per Bbl) unhedged		105.00			103.23			1.77			2	%
Natural gas liquids (per Bbl) realized (1)		45.74			57.38			(11.64	)		(20	)%
Combined (per Mcfe) realized		8.99			7.58			1.41			19	%
Hedging Activities:
Realized natural gas revenue gain	$	33,130		$	16,897		$	16,233			96	%
Realized oil revenue (loss)		(958	)		(3,756	)		2,798			74	%
Summary Financial Information
Revenues
Natural gas	$	78,638		$	114,362		$	(35,724	)		(31	)%
Oil		160,069			113,702			46,367			41	%
Natural gas liquids		10,414			8,900			1,514			17	%
Other revenues		3,952			1,366			2,586			189	%
Unrealized gain (loss) — oil and natural gas derivative contracts		(19,944	)		25,292			(45,236	)		(179	)%
		233,129			263,622			(30,493	)		(12	)%
Expenses
Lease and plant operating expense		50,833			44,639			6,194			14	%
Production and ad valorem taxes		19,315			15,198			4,117			27	%
Workover expense		8,254			8,391			(137	)		(2	)%
Exploration expense		13,543			12,310			1,233			10	%
Depreciation, depletion, and amortization expense		76,161			66,187			9,974			15	%
Impairment expense		50,934			16,498			34,436			209	%
Accretion expense		1,339			1,430			(91	)		(6	)%
General and administrative expense		30,195			24,251			5,944			25	%
Interest expense, net		29,440			23,067			6,373			28	%
Litigation settlement		(1,250	)		—			(1,250	)		NA
(Gain) on contract settlement		—			(1,285	)		1,285			NA
Provision for state income taxes		—			150			(150	)		NA
Net income (loss)	$	(45,635	)	$	52,786		$	(98,421	)		(186	)%
Average Unit Costs per Mcfe:
Lease and plant operating expense	$	1.83		$	1.43		$	0.40			28	%
Production and ad valorem taxes		0.70			0.49			0.21			43	%
Workover expense		0.30			0.27			0.03			11	%
Exploration expense		0.49			0.39			0.10			26	%
Depreciation , depletion and amortization expense		2.75			2.12			0.63			30	%
General and administrative expense		1.09			0.78			0.31			40	%

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

24

Revenues

Natural gas revenuesfor the nine months ended September 30, 2012 decreased $35.7 million, or 31%, to $78.6 million from $114.3 million in 2011. The decrease in natural gas revenue was attributable to a lower average realized price during the first nine months of 2012 and to decreased production volumes. The price of natural gas exclusive of hedging decreased 36% in the first nine months of 2012; the overall realized price (including hedging gains and losses) decreased 6% from $4.87 per Mcf in the first nine months of 2011 to $4.59 per Mcf in the first nine months of 2012, resulting in a decrease in natural gas revenues of approximately $4.8 million. Approximately $30.9 million of the decrease in revenues from natural gas was due to a decrease in production of 6.4 Bcf, or 27%. This decline is primarily due to our Hilltop field, which produced 7.9 Bcf in the first nine months of 2012, compared to 14.0 Bcf in the first nine months of 2011.

Oil revenuesfor the nine months ended September 30, 2012 increased $46.4 million, or 41%, to $160.1 million from $113.7 million in 2011. The increase in revenue was attributable to increased production volumes coupled with a higher average realized price. Approximately $39.5 million of the increase was due to an increase in production of 396 MBbls, or 35%. This increase is primarily due to production from our Eagleville field, which increased 273 MBbls in the first nine months of 2012 as compared to the first nine months of 2011, from 148 MBbls to 421 MBbls. The price of oil exclusive of hedging increased 2% in the first nine months of 2012; the overall realized price (including hedging gains and losses) increased 4% from $99.93 per Bbl in the first nine months of 2011 to $104.38 per Bbl in the first nine months of 2012, resulting in an increase in oil revenues of approximately $6.8 million.

Natural gas liquids revenuesincreased $1.5 million, or 17%, during the first nine months of 2012 compared to the same period in 2011. A 47% increase in volumes from 155 MBbls to 228 MBbls was offset by a decrease in our average price of 20%, from $57.38 per Bbl to $45.74 per Bbl. The increase in volume is due to production in the Eagleville field of 71 MBbls, which includes a prior period adjustment of 39 MBbls.

Unrealized gain (loss) — oil and natural gas derivative contractswas a loss of $19.9 million during the nine months ended September 30, 2012 as compared to a gain of $25.3 million during the same period in 2011. The significant fluctuation from period to period is due to the volatility of oil and natural gas prices and changes in our outstanding hedging contracts during these periods. The majority of the losses in 2012 were related to the increase in oil and natural gas prices during the first nine months of 2012 as compared to market prices at the end of 2011, which decreased the unrealized value of our open derivative contracts.

Expenses

Lease and plant operating expenseincreased $6.2 million in the first nine months of 2012 as compared to the first nine months of 2011, from $44.6 million to $50.8 million. On a unit basis, lease and plant operating expense increased from $1.43 per Mcfe to $1.83 per Mcfe for the nine months ended September 30, 2011 and 2012, respectively, which reflects the decrease in volume while costs increased 14%. In general, lease operating expenses are higher for oil producing properties. Oil as a percentage of production on an equivalent basis increased from 22% to 33% for the first nine months of 2011 and 2012, respectively. Natural gas as a percentage of equivalent production during the same periods decreased from 75% to 62%. Expenses for overhead, insurance, marketing and gathering increased $5.5 million due to increased well count. Field operation expenses for services, repairs and maintenance, chemicals, fuel, salt water disposal and compression increased $0.4 million.

Production and ad valorem taxesincreased $4.1 million, or 27%, to $19.3 million for the first nine months of 2012, as compared to $15.2 million for the first nine months of 2011. Ad valorem taxes increased $2.2 million, primarily due to increases in asset values. Production taxes increased $1.9 million. Production tax as a percentage of product revenues before realized hedging gains and losses was approximately 7% for the nine months ended September 30, 2012 and 6% for the corresponding period in 2011. Reduced natural gas production from our Hilltop field, which is subject to certain production tax exemptions, coupled with increased oil revenues, increased the overall tax rate.

Workover expensedecreased $0.1 million from the first nine months of 2011 to the first nine months of 2012, from $8.4 million to $8.3 million, respectively. This expense varies depending on activities in the field.

Exploration expenseincludes the costs of our geology department, costs of geological and geophysical data, delay rentals, expired leases, and dry holes. Exploration expense increased from $12.3 million for the first nine months of 2011 to $13.5 million for the first nine months of 2012, due primarily to seismic expenses.

Depreciation, depletion and amortizationincreased $10 million to $76.2 million for the first nine months of 2012 as compared to $66.2 million for the first nine months of 2011. On a per unit basis, this expense increased from $2.12 to $2.75 per Mcfe. The rate is a function of capitalized costs of proved properties, reserves and production by field.

Impairment expenseincreased from $16.5 million in the first nine months of 2011 to $50.9 million in the first nine months of 2012. This expense varies with the results of drilling, as well as with price declines and other factors which may render some projects uneconomic, resulting in impairment. The decreasing trend in natural gas prices resulted in a significant impairment in the third quarter of 2012. Of the $50.9 million total expense, $19.9 million was for our Hilltop field in East Texas, which produces dry gas, and is vulnerable to extremely low prices for natural gas. Other properties written down were also in East Texas, where our natural gas production is most concentrated.

25

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 $1.3 million and $1.4 million for the nine-month periods ending September 30, 2012 and 2011, respectively.

General and administrative expenseincreased $5.9 million for the first nine months of 2012 to $30.2 million from $24.3 million for the first nine months of 2011. The increase is principally due to increased salary and benefits expenses of $4.6 million, primarily due to additional personnel and bonus accruals. In addition, expenses for consulting services increased $0.5 million, primarily for fees associated with engineering services and litigation. Other employee expenses, primarily related to travel, increased $0.5 million. On a per unit basis, general and administrative expenses increased from $0.78 to $1.09 per Mcfe, which reflects the decrease in volume produced on an Mcfe basis, while costs increased.

Interest expense, netincreased $6.3 million for the first nine months of 2012 to $29.4 million from $23.1 million for the first nine months of 2011. This increase is primarily due to interest rate hedge gains of $5.4 million recorded in the first nine months of 2011, and to increased interest on our credit facility of $1.6 million in the first nine months of 2012, due primarily to higher average outstanding balances during that period. Partially offsetting this increase was a decrease in amortization of loan costs of $0.5 million due to the extension of the maturity date of our credit facility in May 2011.

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

Gain on contract settlementis related to the settlement of an obligation we assumed with our acquisition of Meridian. The obligation related to underutilization of two contracted drilling rigs. We recorded an estimated liability of $9.8 million for the obligation upon purchase of Meridian in 2010. The obligation was subsequently settled in the second quarter of 2011 for $8.5 million, resulting in a gain of $1.3 million.

Liquidity and Capital Resources

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

Our 2012 capital budget is primarily focused on the development of existing core areas through exploitation and development. Currently, we plan to spend a total of approximately $247 million during 2012, of which approximately $185.8 million has been expended or accrued through September 30, 2012, including acquisitions. Approximately 75% of our capital budget for the remainder of 2012 is allocated to our properties in Hilltop field, East Texas, the Eagle Ford Shale in South Texas, Oklahoma, and South Louisiana. Our future drilling plans, plans of our drilling operators and capital budgets are subject to change based upon various factors, some of which are beyond our control, including drilling results, oil and natural gas prices, the availability and cost of capital, drilling and production costs, availability of drilling services and equipment, actions of our operators, gathering system and pipeline transportation constraints and regulatory approvals. Because a large percentage of our acreage is held by production, we have the ability to materially decrease our drilling and recompletion budget in response to market conditions with minimal risk of losing significant acreage.

We expect to fund the remainder of our 2012 capital budget predominantly with cash flows from operations, supplemented by borrowings under our credit facility. If necessary in future years, we may also access capital through proceeds from potential asset dispositions and the future issuances of debt and/or equity securities, subject to the distribution of proceeds therefrom as set forth in our partnership agreement. We strive to maintain financial flexibility and may access capital markets as necessary to maintain substantial borrowing capacity under our senior secured revolving credit facility, facilitate drilling on our large undeveloped acreage position and permit us to selectively expand our acreage position. In the event our cash flows are materially less than anticipated and other sources of capital we historically have utilized are not available on acceptable terms, we may curtail our capital spending.

Senior Notes

In October 2010, we issued $300 million of 9.625% senior notes due 2018 (“senior notes”) at a discount of $2.1 million, with a yield to maturity of 9.75%. On October 15, 2012, we issued an additional $150 million of senior notes (“additional senior notes”) under the same indenture with the same interest rate, date of maturity, and other terms, at a discount of $1.5 million and with a yield to maturity of 9.85%. Net proceeds from the offering were approximately $145.3 million (after deducting estimated fees and offering expenses), which we used to repay existing indebtedness under our credit facility. The additional senior notes were issued in a private placement. We entered into a registration rights agreement with the initial purchasers of the additional senior notes, under which we will exchange the notes for notes registered with the SEC within 180 days of the date of issuance of the additional senior notes. In connection with the issuance of the additional senior notes, the borrowing base under our credit facility was automatically reduced to $313.7 million.

26

The senior notes and additional 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 and the additional senior notes are unconditionally guaranteed on a senior unsecured basis by each of our material, wholly-owned subsidiaries.

Credit Facility

We have a senior secured revolving credit facility (“credit facility”) with Wells Fargo Bank, N.A. as the administrative agent. As of September 30, 2012, the credit facility was subject to a $350 million borrowing base limit, and we had $247 million outstanding under the credit facility, which was subsequently reduced using proceeds from our issuance of the additional senior notes, as described above. Our restricted subsidiaries are guarantors of the credit facility.

The borrowing base is redetermined each May 1 and November 1. In May 2012, the borrowing base was increased to $350 million. On October 15, 2012, as a result of the issuance of the additional senior notes and in accordance with the terms of the credit facility, the borrowing base was automatically reduced to $313.7 million. The borrowing base was confirmed during the November redetermination. As of November 13, 2012, outstanding borrowing under the credit facility was $128.3 million, and the available unused portion of the borrowing base was $185.4 million.

Our credit facility provides for two alternative interest rate bases and margins. Eurodollar loans accrue interest generally at the one-month London Interbank Offered Rate plus a margin ranging from 2.00% to 2.75%, depending on the utilization of our borrowing base. “Reference rate” loans accrue interest at the prime rate of Wells Fargo Bank, N.A., plus a margin ranging from 1.00% to 1.75%, depending on the utilization of our borrowing base. The total rate on all loans outstanding as of September 30, 2012 under the credit facility was 2.5%, which was based on the Eurodollar option.

The credit facility and the indenture governing the senior notes and additional senior notes include covenants requiring us to maintain certain financial covenants including a current ratio, leverage ratio, and interest coverage ratio. At September 30, 2012, we were in compliance with the covenants. The terms of the credit facility also restrict our ability to make distributions and investments.

Cash flow provided by operating activities

Operating activities provided cash of $117.9 million during the nine months ended September 30, 2012 as compared to $115.4 million during the comparable period in 2011. The $2.5 million increase in operating cash flows was attributable to changes in working capital accounts, partially offset by a decrease in the cash-based portions of our earnings. Changes in our working capital accounts provided $9.5 million of cash flows as compared to a use of $0.7 million of cash in 2011. The changes in working capital resulted in an increase of $10.2 million in cash flow. Cash-based items of net income, including revenues (exclusive of unrealized commodity gains or losses), operating expenses and taxes, general and administrative expenses, and the cash portion of our interest expense, decreased approximately $7.7 million, resulting in a negative impact on cash flow.

Cash flow used in investing activities

Cash used in investing activities was $172.3 million during the nine months ended September 30, 2012 as compared to $214.6 million during the comparable period of 2011. A decrease in cash used in acquisition activities of $46.3 million was primarily due to $50 million expended in the first nine months of 2011 for the Sydson and TODD acquisitions. Investment in property and equipment increased by $4.1 million. Our capital spending for the first nine months of 2012 has been primarily for expenditures in our Eagleville and Weeks Island fields in South Texas and South Louisiana, respectively. We also made expenditures for our properties in Southeast Texas, Hilltop field, and Oklahoma.

Cash flow provided by financing activities

Financing activities provided cash of $57.9 million during the nine months ended September 30, 2012 as compared to $98.9 million during the comparable period in 2011. Both periods reflected the effect of drawdowns from our credit facility. The larger cash flows in the first nine months of 2011 were due to the $50 million cash purchase price of Sydson and TODD.

Cautionary Statement Regarding Forward-Looking Statements

The information in this report includes “forward-looking statements.” All statements, other than statements of historical fact included in this Quarterly Report on Form 10-Q, regarding our strategy, future operations, financial position, estimated revenues and losses, projected costs, prospects, plans and objectives of management are forward-looking statements. When used in this report, the words “could”, “should”, “will”, “play”, “believe”, “anticipate”, “intend”, “estimate”, “expect”, “project” and similar expressions are intended to identify forward-looking statements, although not all forward-looking statements contain such identifying words. These forward-looking statements are based on our current expectations and assumptions about future events and are based on currently available information as to the outcome and timing of future events. When considering forward-looking statements, you should keep in mind the risk factors and other cautionary statements described under the heading “Risk Factors” included in our Annual Report on Form 10-K for the year ended December 31, 2011 (“2011 Form 10-K”) and Part II, Item 1A of this report. These forward-looking statements are based on management’s current belief, based on currently available information, as to the outcome and timing of future events.

27

Forward-looking statements may include statements about our:

• business strategy;

• reserves;

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

• realized oil and natural gas prices;

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

• hedging strategy and results;

• future drilling plans;

• competition and government regulations;

• marketing of oil and natural gas;

• leasehold or business acquisitions;

• costs of developing our properties;

• general economic conditions;

• credit markets;

• liquidity and access to capital;

• uncertainty regarding our future operating results; and

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

We caution you that these forward-looking statements are subject to all of the risks and uncertainties, most of which are difficult to predict and many of which are beyond our control, incident to the exploration for and development and production of oil and natural gas. These risks include, but are not limited to, commodity price volatility, inflation, lack of availability of drilling and production equipment and services, environmental risks, weather risks, drilling and other operating risks, regulatory changes, the uncertainty inherent in estimating oil and natural gas reserves and in projecting future rates of production, cash flow and access to capital, the timing of development expenditures, and the other risks described under “Item 1A. Risk Factors” in our 2011 Form 10-K.

Reserve engineering is a process of estimating underground accumulations of oil and natural gas that cannot be measured in an exact way. The accuracy of any reserve estimate depends on the quality of available data, the interpretation of such data and price and cost assumptions made by reservoir engineers. In addition, the results of drilling, testing and production activities may justify revisions of estimates that were made previously. If significant, such revisions would change the schedule of any further production and development drilling. Accordingly, reserve estimates may differ significantly from the quantities of oil and natural gas that are ultimately recovered.

Should one or more of the risks or uncertainties described in the 2011 Form 10-K or this report occur, or should underlying assumptions prove incorrect, our actual results and plans could differ materially from those expressed in any forward-looking statements.

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

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

ITEM 3. Quantitative and Qualitative Disclosures about Market Risk

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

28

ITEM 4. Controls and Procedures

Evaluation of Disclosure Controls and Procedures

In accordance with Rules 13a-15 and 15d-15 under the Securities Exchange Act of 1934, as amended (“Exchange Act”), we carried out an evaluation, under the supervision and with the participation of management, including our Chief Executive Officer and our Chief Financial Officer, of the effectiveness of our disclosure controls and procedures as of the end of the period covered by this report. Based on that evaluation, our Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures were effective as of September 30, 2012 to provide reasonable assurance that information required to be disclosed in our reports filed or submitted under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the Securities and Exchange Commission’s rules and forms. Our disclosure controls and procedures include controls and procedures designed to ensure that information required to be disclosed in reports filed or submitted under the Exchange Act is accumulated and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosure.

Changes in Internal Control Over Financial Reporting

There has been no change in our internal control over financial reporting during the three months ended September 30, 2012 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

PART II — OTHER INFORMATION

ITEM 1. Legal Proceedings

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

ITEM 1A. Risk Factors

We are subject to certain risks and hazards due to the nature of the business activities we conduct. For a discussion of these risks, see “Item 1A. Risk Factors” in the 2011 Form 10-K. There have been no material changes with respect to the risk factors disclosed in the 2011 Form 10-K during the quarter ended September 30, 2012.

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

None.

ITEM 3. Defaults Upon Senior Securities

None.

ITEM 4. Mine Safety Disclosures

Not applicable.

ITEM 5. Other Information

None.

29

ITEM 6. Exhibits

1.1	Purchase Agreement dated October 3, 2012 by and among Alta Mesa Holdings, LP, Alta Mesa Finance Services Corp., the Guarantors named therein and the Initial Purchasers named therein (incorporated by reference from Exhibit 10.1 to Alta Mesa Holdings, LP’s current report on Form 8-K filed with the SEC on October 4, 2012).
4.1	Registration Rights Agreement dated October 15, 2012 by and among Alta Mesa Holdings, LP, Alta Mesa Finance Services Corp., the Guarantors named therein and the Initial Purchasers named therein (incorporated by reference from Exhibit 4.2 to Alta Mesa Holdings, LP’s current report on Form 8-K filed with the SEC on October 15, 2012).
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.

30

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
November 13, 2012		general partner
	By:	/s/ Harlan H. Chappelle
		Harlan H. Chappelle
November 13, 2012		President and Chief Executive Officer
	By:	/s/ Michael A. McCabe
		Michael A. McCabe
		Vice President and Chief Financial Officer

31