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: March 31, 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

 

 

 

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Table of Contents

 

		Page Number
PART I — FINANCIAL INFORMATION
Item 1. Financial Statements			3
Consolidated Balance Sheets as of March 31, 2012 (unaudited) and December 31, 2011			3
Consolidated Statements of Operations (unaudited) for the Three Months Ended March 31, 2012 and 2011			4
Consolidated Statements of Cash Flows (unaudited) for the Three Months Ended March 31, 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			26
Item 4. Controls and Procedures			27
PART II — OTHER INFORMATION			27
Item 1. Legal Proceedings			27
Item 1A. Risk Factors			27
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds			27
Item 3. Defaults Upon Senior Securities			27
Item 4. Mine Safety Disclosures			27
Item 5. Other Information			27
Item 6. Exhibits			28
Signatures			29

 

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PART I — FINANCIAL INFORMATION

ITEM 1. Financial Statements

ALTA MESA HOLDINGS, LP AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(dollars in thousands)

 

		March 31, 2012				December 31, 2011
		(unaudited)
ASSETS
CURRENT ASSETS
Cash and cash equivalents		$	8,836			$	2,630
Accounts receivable, net			35,130				40,807
Other receivables			2,557				2,806
Prepaid expenses and other current assets			6,979				5,394
Derivative financial instruments			28,187				28,582
TOTAL CURRENT ASSETS			81,689				80,219
PROPERTY AND EQUIPMENT
Oil and natural gas properties, successful efforts method, net			602,548				572,816
Other property and equipment, net			16,142				16,351
TOTAL PROPERTY AND EQUIPMENT, NET			618,690				589,167
OTHER ASSETS
Investment in Partnership — cost			9,000				9,000
Deferred financing costs, net			12,234				12,802
Derivative financial instruments			19,485				24,244
Advances to operators			3,197				3,625
Deposits and other assets			1,206				1,026
TOTAL OTHER ASSETS			45,122				50,697
TOTAL ASSETS		$	745,501			$	720,083
LIABILITIES AND PARTNERS’ CAPITAL
CURRENT LIABILITIES
Accounts payable and accrued liabilities		$	73,833			$	70,295
Current portion, asset retirement obligations			3,250				3,030
Derivative financial instruments			773				1,300
TOTAL CURRENT LIABILITIES			77,856				74,625
LONG-TERM LIABILITIES
Asset retirement obligations, net of current portion			43,146				43,066
Long-term debt			505,101				487,036
Notes payable to founder			21,212				20,911
Derivative financial instruments			1,298				57
Other long-term liabilities			3,815				4,716
TOTAL LONG-TERM LIABILITIES			574,572				555,786
TOTAL LIABILITIES			652,428				630,411
COMMITMENTS AND CONTINGENCIES (NOTE 10)
PARTNERS’ CAPITAL			93,073				89,672
TOTAL LIABILITIES AND PARTNERS’ CAPITAL		$	745,501			$	720,083

See notes to consolidated financial statements.

 

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ALTA MESA HOLDINGS, LP AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

(dollars in thousands)

(unaudited)

 

		Three Months Ended March 31,
		2012				2011
REVENUES
Natural gas		$	25,539			$	35,381
Oil			49,730				32,197
Natural gas liquids			3,067				3,053
Other revenues			698				469
			79,034				71,100
Unrealized gain (loss) — oil and natural gas derivative contracts			(6,395	)			(19,184	)
TOTAL REVENUES			72,639				51,916
EXPENSES
Lease and plant operating expense			15,918				13,331
Production and ad valorem taxes			6,230				5,401
Workover expense			1,253				1,626
Exploration expense			2,029				2,731
Depreciation, depletion, and amortization expense			23,893				19,468
Impairment expense			1,752				5,826
Accretion expense			440				470
General and administrative expenses			7,969				5,751
TOTAL EXPENSES			59,484				54,604
INCOME (LOSS) FROM OPERATIONS			13,155				(2,688	)
OTHER INCOME (EXPENSE)
Interest expense			(9,771	)			(9,480	)
Interest income			17				2
TOTAL OTHER INCOME (EXPENSE)			(9,754	)			(9,478	)
INCOME (LOSS) BEFORE STATE INCOME TAXES			3,401				(12,166	)
PROVISION FOR STATE INCOME TAXES			—				—
NET INCOME (LOSS)		$	3,401			$	(12,166	)

See notes to consolidated financial statements.

 

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ALTA MESA HOLDINGS, LP AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(dollars in thousands)

(unaudited)

 

		Three Months Ended March 31,
		2012				2011
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss)		$	3,401			$	(12,166	)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion, and amortization expense			23,893				19,468
Impairment expense			1,752				5,826
Accretion expense			440				470
Amortization of loan costs			568				904
Amortization of debt discount			65				65
Dry hole expense			893				717
Unrealized (gain) loss on derivatives			5,868				19,141
Interest converted into debt			301				298
Settlement of asset retirement obligation			(373	)			(233	)
Changes in assets and liabilities:
Accounts receivable			5,677				(1,921	)
Other receivables			249				4,158
Prepaid expenses and other non-current assets			(1,337	)			(257	)
Accounts payable, accrued liabilities, and other long-term liabilities			6,351				9,172
NET CASH PROVIDED BY OPERATING ACTIVITIES			47,748				45,642
CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures for property and equipment			(49,596	)			(58,951	)
Acquisitions			(9,946	)			—
NET CASH USED IN INVESTING ACTIVITIES			(59,542	)			(58,951	)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from long-term debt			18,000				14,000
NET CASH PROVIDED BY FINANCING ACTIVITIES			18,000				14,000
NET INCREASE IN CASH			6,206				691
CASH AND CASH EQUIVALENTS, beginning of period			2,630				4,836
CASH AND CASH EQUIVALENTS, end of period		$	8,836			$	5,527
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION
Cash paid during the period for interest		$	2,460			$	2,442
Cash paid during the period for taxes		$	—			$	—
Change in property asset retirement obligations, net		$	233			$	86
Change in accruals or liabilities for capital expenditures		$	(3,714	)		$	(19,976	)

See notes to consolidated financial statements.

 

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ALTA MESA HOLDINGS, LP AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(unaudited)

1. SUMMARY OF ORGANIZATION AND NATURE OF OPERATIONS

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

The consolidated financial statements included herein as of March 31, 2012, and for the three month periods ended March 31, 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 and Alta Mesa Services, LP, AM Idaho LLC, and (ii) partially-owned subsidiaries: Brayton Resources, LP, and Orion Operating Company, LP.

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

2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

As of March 31, 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.

 

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

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

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

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

Impairment — The capitalized costs of proved oil and natural gas properties are reviewed quarterly for impairment in accordance with ASC 360-10-35, “Property, Plant and Equipment, Subsequent Measurement,” or whenever events or changes in circumstances indicate that the carrying amount of a long-lived asset or asset group exceeds its fair market value and is not recoverable. The determination of recoverability is based on comparing the estimated undiscounted future net cash flows at a producing field level to the carrying value of the assets. If the future undiscounted cash flows, based on estimates of anticipated production from proved reserves and future crude oil and natural gas prices and operating costs, are lower than the carrying cost, the carrying cost of the asset or group of assets is reduced to fair value. For our proved oil and natural gas properties, we estimate fair value by discounting the projected future cash flows at an appropriate risk-adjusted discount rate. Unproved leasehold costs are assessed quarterly to determine whether they have been impaired. Individually significant properties are assessed for impairment on a property-by-property basis, while individually insignificant unproved leasehold costs may be assessed in the aggregate. If unproved leasehold costs are found to be impaired, an impairment allowance is provided and a loss is recognized in the consolidated statement of 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 $641,000 and $557,000 at March 31, 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 March 31, 2012 and 2011, amortization of deferred financing costs included in interest expense amounted to $568,000 and $904,000, respectively. Deferred financing costs are listed among our long-term assets, net of accumulated amortization of $8.1 million and $7.5 million at March 31, 2012 and December 31, 2011, respectively.

 

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Financial Instruments: The fair value of cash, accounts receivable, other current assets, and current liabilities approximate book value due to their short-term nature. The estimate of fair value of long-term debt under our senior secured revolving credit facility is not considered to be materially different from carrying value due to market rates of interest. The fair value of the debt to our founder is not practicable to determine. We have estimated the fair value of our $300 million senior notes payable at $303 million at March 31, 2012. See Note 5 for further information on fair values of financial instruments. See Note 8 for information on long-term debt.

Recent Accounting Pronouncements

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

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

3. SIGNIFICANT ACQUISITIONS

Sydson Acquisition

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

TODD Acquisition

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

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

 

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

 

The revenue and earnings related to the Sydson and TODD acquisitions are included in our consolidated statement of operations for the three months ended March 31, 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 (Loss)
		(dollars in thousands)
Pro forma results for the combined entity for the three months ended March 31, 2011		$	54,018			$	(10,987	)

 

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4. PROPERTY AND EQUIPMENT

Property and equipment consists of the following:

 

		March 31, 2012				December 31, 2011
		(unaudited)
		(dollars in thousands)
OIL AND NATURAL GAS PROPERTIES
Unproved properties		$	43,644			$	34,797
Accumulated impairment			(6,653	)			(5,427	)
Unproved properties, net			36,991				29,370
Proved oil and natural gas properties			971,487				925,578
Accumulated depreciation, depletion, amortization and impairment			(405,930	)			(382,132	)
Proved oil and natural gas properties, net			565,557				543,446
TOTAL OIL AND NATURAL GAS PROPERTIES, net			602,548				572,816
LAND			1,185				1,185
DRILLING RIG			10,500				10,500
Accumulated depreciation			(1,312	)			(1,137	)
TOTAL DRILLING RIG, net			9,188				9,363
OTHER PROPERTY AND EQUIPMENT
Office furniture and equipment, vehicles			7,725				7,313
Accumulated depreciation			(1,956	)			(1,510	)
OTHER PROPERTY AND EQUIPMENT, net			5,769				5,803
TOTAL PROPERTY AND EQUIPMENT, net		$	618,690			$	589,167

 

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5. FAIR VALUE DISCLOSURES

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

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

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

Our senior notes are carried at historical cost, net of amortized discount; we estimate the fair value of the senior notes for disclosure purposes (see Note 2). This estimation is based on the most recent trading values of the notes at or near the reporting dates, which is a Level 1 determination.

Oil and natural gas properties are subject to impairment testing and potential impairment write down. Oil and gas properties with a carrying amount of $3.4 million were written down to their fair value of $1.6 million, resulting in an impairment charge of $1.8 million for the three months ended March 31, 2012. Oil and gas properties with a carrying amount of $10.1 million were written down to their fair value of $4.3 million, resulting in an impairment charge of $5.8 million for the three months ended March 31, 2011. Significant Level 3 assumptions used in the calculation of estimated discounted cash flows in the impairment analysis included our estimate of future oil and natural gas prices, production costs, development expenditures, estimated timing of production of proved reserves, appropriate risk-adjusted discount rates, and other relevant data.

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

New additions to asset retirement obligations result from estimations for new properties, and fair values for them are categorized as Level 3. Such estimations are based on present value techniques which utilize company-specific information for such inputs as cost and timing of plugging and abandonment of wells and facilities. We recorded $233,000 and $86,000 in additions to asset retirement obligations measured at fair value during the three months ended March 31, 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 March 31, 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 March 31,2012 (unaudited):
Financial Assets:
Derivative contracts for oil and natural gas			—			$	121,583				—			$	121,583
Financial Liabilities:
Derivative contracts for oil and natural gas			—			$	75,209				—			$	75,209
Derivative contracts for interest rate			—			$	773				—			$	773
At December 31, 2011:
Financial Assets:
Derivative contracts for oil and natural gas			—			$	109,138				—			$	109,138
Financial Liabilities:
Derivative contracts for oil and natural gas			—			$	56,369				—			$	56,369
Derivative contracts for interest rate			—			$	1,300				—			$	1,300

 

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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. We have not designated any of our derivative contracts as fair value or cash flow hedges; accordingly we use mark-to-market accounting, recognizing unrealized gains and losses in the statement of operations at each reporting date. Realized gains and losses on commodities hedging contracts are included in oil and natural gas revenues.

We have entered into an interest rate swap agreement to mitigate the risk of loss due to changes in interest rates. The interest rate swap is not designated as a cash flow hedge in accordance with ASC 815. Both realized gains and losses from settlement and unrealized gains and losses from changes in the fair market value of the interest rate swap contract are included in interest expense.

The second table below provides information on the location and amounts of realized and unrealized gains and losses on derivatives included in the consolidated statements of operations for each of the three month periods ended March 31, 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 March 31, 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		$	69,745			$	—			$	51,838			$	—
Fair value of oil and gas commodity contracts, (liabilities)			(41,558	)			—				(32,353	)			(1,298	)
Fair value of interest rate contracts, (liabilities)			—				(773	)			—				—
Total net assets, (liabilities)		$	28,187			$	(773	)		$	19,485			$	(1,298	)
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	)

 

11

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

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

 

Derivatives not designated as hedging		Location of		Classification of		For the Three Months Ended March 31,
Instruments under ASC 815		Gain (Loss)		Gain (Loss)		2012				2011
						(unaudited) (dollars in thousands)
Natural gas commodity contracts		Natural gas revenues		Realized		$	8,540			$	5,791
Oil commodity contracts		Oil revenues		Realized			(1,409	)			(1,484	)
Interest rate contracts		Interest benefit (expense)		Realized			(562	)			(370	)
Total realized gains (losses) from derivatives not designated as hedges						$	6,569			$	3,937
Natural gas commodity contracts		Unrealized gain (loss) — oil and natural gas derivative contracts		Unrealized		$	7,786			$	(16,227	)
Oil commodity contracts		Unrealized gain (loss) — oil and natural gas derivative contracts		Unrealized			(14,181	)			(2,957	)
Interest rate contracts		Interest benefit (expense)		Unrealized			527				43
Total unrealized gains (losses) from derivatives not designated as hedges						$	(5,868	)		$	(19,141	)

Although our counterparties provide no collateral, the master derivative agreements with each counterparty effectively allow us, so long as we are not a defaulting party, after a default or the occurrence of a termination event, to set-off an unpaid hedging agreement receivable against the interest of the counterparty in any outstanding balance under the credit facility.

If a counterparty were to default in payment of an obligation under the master derivative agreements, we could be exposed to commodity price fluctuations, and the protection intended by the hedge could be lost. The value of our derivative financial instruments would be impacted.

 

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We had the following open derivative contracts for natural gas at March 31, 2012 (unaudited):

NATURAL GAS DERIVATIVE CONTRACTS

 

				Volume in				Weighted				Range
Period and Type of Contract				MMbtu				Average				High				Low
		2012
Price Swap Contracts					11,452,500			$	4.97			$	8.83			$	3.30
Collar Contracts
Short Call Options					7,390,000				5.53				6.00				4.50
Long Put Options					5,781,250				5.09				6.75				4.00
Long Call Options					4,125,000				4.67				5.00				4.00
Short Put Options					10,446,250				3.61				4.50				3.00
		2013
Price Swap Contracts					19,400,000				4.75				9.15				3.30
Collar Contracts
Short Call Options					1,825,000				5.25				5.25				5.25
Long Put Options					1,500,000				6.09				6.15				6.00
Long Call Options					3,625,000				5.87				7.00				4.75
Short Put Options					17,325,000				3.20				5.00				3.00
		2014
Price Swap Contracts					3,125,000				6.27				7.50				5.60
Collar Contracts
Short Call Options					3,475,000				7.05				9.00				6.00
Long Put Options					1,650,000				6.73				7.00				6.00
Short Put Options					1,200,000				5.50				5.50				5.50
		2015
Price Swap Contracts					1,825,000				5.91				5.91				5.91
		2016
Collar Contracts
Short Call Options					455,000				7.50				7.50				7.50
Long Put Options					455,000				5.50				5.50				5.50
Short Put Options					455,000				4.00				4.00				4.00

 

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We had the following open derivative contracts for crude oil at March 31, 2012 (unaudited):

OIL DERIVATIVE CONTRACTS

 

								Weighted				Range
Period and Type of Contract				Volume in Bbls				Average				High				Low
		2012
Price Swap Contracts					398,750			$	114.10			$	121.15			$	80.20
Collar Contracts
Short Call Options					1,309,905				118.65				132.00				100.00
Long Put Options					1,089,740				97.82				105.00				65.00
Long Call Options					190,105				102.47				123.50				90.20
Short Put Options					1,089,102				79.45				85.00				60.00
		2013
Price Swap Contracts					392,00				89.75				94.74				77.00
Collar Contracts
Short Call Options					925,660				119.21				134.00				90.00
Long Put Options					1,273,500				108.35				115.00				85.00
Long Call Options					124,475				95.19				127.00				79.00
Short Put Options					1,538,500				80.85				90.00				60.00
		2014
Price Swap Contracts					255,050				96.57				105.48				81.00
Collar Contracts
Short Call Options					273,750				125.70				133.50				107.50
Long Put Options					670,950				89.32				100.00				80.00
Short Put Options					670,950				69.32				80.00				60.00
		2015
Price Swap Contracts					401,500				99.30				99.30				99.30
Collar Contracts
Short Call Options					246,350				125.12				135.98				116.40
Long Put Options					319,350				87.57				90.00				85.00
Short Put Options					319,350				66.86				70.00				60.00
		2016
Price Swap Contracts					292,800				94.95				95.00				94.90
Collar Contracts
Short Call Options					36,400				130.00				130.00				130.00
Long Put Options					36,400				95.00				95.00				95.00
Short Put Options					36,400				75.00				75.00				75.00

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

We had the following open financial basis swap contracts for gas at March 31, 2012 (unaudited):

 

Volume in MMbtu		Reference Price		Period		Spread ($ per MMbtu)
1,375,000		Houston Ship Channel		Apr ’12 — Dec ’12			(0.1575	)
2,750,000		Houston Ship Channel		Apr ’12 — Dec ’12			(0.1400	)
3,650,000		Houston Ship Channel		Jan ’13 — Dec ’13			(0.0625	)

 

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We had the following open interest rate swap contract at March 31, 2012 (unaudited):

Interest Rate Swaps

 

Term		Principal Amount				Interest Rate (1)
		(dollars in thousands)
Floating to Fixed Rate Swap:
April 2012 — August 2012		$	50,000				4.95	%

 

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

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			142
Liabilities assumed with acquired producing properties			91
Liabilities settled			(373	)
Accretion expense			440
Balance, March 31, 2012			46,396
Less: Current portion			3,250
		$	43,146

8. LONG-TERM DEBT AND NOTES PAYABLE TO FOUNDER

Long-term debt consists of the following:

 

		March 31, 2012				December 31, 2011
		(unaudited)
		(dollars in thousands)
Senior Debt — On November 13, 2008, we entered into a Fifth Amended and Restated Credit Agreement with a group of banks, which was replaced by the Sixth Amended and Restated Credit Agreement on May 13, 2010, as amended (“credit facility”). The credit facility matures on May 23, 2016 and is secured by substantially all of our oil and gas properties. The credit facility borrowing base is redetermined periodically and, as of March 31, 2012, the borrowing base under the facility was $325 million. As of May 15, 2012, the borrowing base was increased to $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 March 31, 2012 and 2.774% as of December 31, 2011.		$	206,790			$	188,790
Senior Notes Payable — On October 13, 2010, we issued senior notes due October 15, 2018 with a face value of $300 million, at a discount of $2.1 million. The senior notes carry a face interest rate of 9 5/8%, with an effective rate of 9 3/4%; interest is payable semi-annually each April 15th and October 15th. The senior notes are secured by general corporate credit, and effectively rank junior to any of our existing or future secured indebtedness, which includes the credit facility. The senior notes are unconditionally guaranteed on a senior unsecured basis by each of our material subsidiaries. The balance is presented net of unamortized discount of $1.7 million and $1.8 million at March 31, 2012 and December 31, 2011, respectively.			298,311				298,246
Total long-term debt		$	505,101			$	487,036

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

 

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

The credit facility and senior notes include covenants requiring us to maintain certain financial covenants including a current ratio, leverage ratio, and interest coverage ratio. At March 31, 2012, we were in compliance with the covenants. The terms of the credit facility also restrict our ability to make distributions and investments.

In addition, we have notes payable to our founder which bear simple interest at 10% with a balance of $21.2 million and $20.9 million at March 31, 2012 and December 31, 2011, respectively. The notes mature December 31, 2018. Interest and principal are payable at maturity. The notes are subordinate to all debt. Interest on the notes payable to our founder amounted to $301,000 and $298,000 for the three months ended March 31, 2012 and 2011, respectively. Such amounts have been added to the balance of the notes.

9. ACCOUNTS PAYABLE AND ACCRUED LIABILITIES

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

 

		March 31, 2012				December 31, 2011
		(unaudited)
		(dollars in thousands)
Capital expenditures		$	19,526			$	19,119
Revenues and royalties payable			5,582				6,742
Operating expenses/taxes			25,779				21,147
Compensation			4,293				3,567
Acquisition costs payable			1,009				2,883
Other			8,074				5,754
Total accrued liabilities			64,263				59,212
Accounts payable			9,570				11,083
Accounts payable and accrued liabilities		$	73,833			$	70,295

10. COMMITMENTS AND CONTINGENCIES

Contingencies

Hilltop Field Litigation: On July 23, 2009, we made a payment of $25.5 million and took assignment of substantially all working interests that Chesapeake Energy Corporation (“Chesapeake”) had acquired from Gastar Exploration Ltd. (“Gastar”) in an approximate 50,000 acre area of Leon and Robertson Counties, Texas known as the Hilltop Field, in which the Deep Bossier formation was the principal focus for development. We had exercised our preferential right to purchase these interests from Gastar in late 2005, but Gastar and Chesapeake had opposed this and Chesapeake took record title at that time. We finally and conclusively prevailed when, in 2008, a Texas court of appeals directed that specific performance take place. In early 2009, the Texas Supreme Court denied the defendants’ request to review the appeal. As a result, we were able to take assignment of working interests in over 30 producing wells and participate in further development of the area, primarily with EnCana, but also with Gastar. A subsequent payment to EnCana of $15.2 million plus purchase accounting adjustments of $3.8 million brought the total cost of the acquisition to $44.5 million. While the ownership of these interests has been decided by the courts, we have pursued other claims against Chesapeake and Gastar; Chesapeake claimed an additional $36.3 million of past expenses. The case was set for trial on April 24, 2012. Shortly before the trial was to begin, we reached an agreement in principle to settle with the Chesapeake-related defendants. We also entered into a settlement agreement with Gastar. We do not expect the settlements to have a material impact on our financial position or results of operations. We have not provided any amount for these matters in our consolidated financial statements at March 31, 2012.

Environmental claims: Management has established a liability for soil contamination in Florida of $1.0 million at March 31, 2012 and $990,000 at December 31, 2011, based on our undiscounted engineering estimates. The obligations are included in other long-term liabilities in the accompanying consolidated balance sheets.

 

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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 March 31, 2012.

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

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

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

We have a contingent commitment to pay an amount up to a maximum of approximately $3.0 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.

 

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13. SUBSIDIARY GUARANTORS

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

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

14. SUBSEQUENT EVENTS

Management has evaluated all events subsequent to the balance sheet date of March 31, 2012, and has determined that no events require disclosure.

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

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

Overview

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

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

 

•

the prices at which we will sell our production;

 

•

the amount of oil and natural gas we produce; and

 

•

the level of our operating and administrative costs.

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

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

 

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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 are estimated 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 are estimated to be 700 MBOE (4 Bcfe), 36% of which was oil. By virtue of this acquisition, we increased our after payout net revenue interest in the Eagle Ford Shale by an additional 15% at the time of the acquisition. Funding for the acquisition was provided through our credit facility. In addition, litigation associated with TODD was resolved as a result of the transaction.

Outlook

Natural gas prices declined significantly during 2011 and the first quarter of 2012, closing at $2.19 for the April 2012 Henry Hub Futures contract settled March 30, 2012. The reduction in prices has been caused by many factors, including recent increases in North American natural gas production, warmer than normal winter weather and high levels of natural gas in storage. Prices for oil and natural gas liquids, however, have not been similarly depressed.

We have hedged approximately 96% of our forecasted PDP production through 2016 at prices higher than those currently prevailing for natural gas. However, if prices for natural gas remain depressed for long periods, we may be required to write down the value of our oil and natural gas properties or revise our development plans, which may cause certain of our undeveloped well locations to no longer be deemed proved. In addition, sustained low prices for natural gas will reduce the amounts we would otherwise have available to pay expenses and service our debt obligations.

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

While oil prices have strengthened, they remain unstable and we expect them to remain volatile in the future. Factors affecting the price of oil include worldwide economic conditions, including the European credit crisis, geopolitical activities, including activities in Iran, Syria, Libya, Egypt and other countries in the Middle East, worldwide supply disruptions, weather conditions, actions taken by the Organization of Petroleum Exporting Countries and the value of the U.S. dollar in international currency markets.

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

 

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Operations Update

South Louisiana

At Weeks Island, our largest oilfield in South Louisiana, we drilled three successful oil wells in the first quarter of 2012. We expect to continually utilize one drilling rig and one workover rig in this field through at least mid-2012. Production from Weeks Island was approximately 1,700 BOE per day (net to our interest, 85% oil) for the first quarter of 2012. Total production net to our interest from all of our properties in South Louisiana for the first quarter was 211 MBbl’s (including NGL’s) and 1.7 Bcf of natural gas.

East Texas/Hilltop

Our Hilltop field in East Texas continues to produce a significant portion of our gas sales, principally from the Deep Bossier formation, at approximately 35 MMcf per day (net to our interest) for the first quarter of 2012. We continue to drill and recomplete wells in this field, in which our principal operating partner is EnCana Oil and Gas (USA) (“Encana”), and to develop, test, and evaluate formations other than the Deep Bossier, such as the Buda, Knowles, Woodbine, Eagle Ford and Austin Chalk. During the first quarter of 2012, we participated with EnCana in the completion of three oil wells in the Woodbine formation. We also completed our first operated well in the area, a successful horizontal oil well in the Austin Chalk formation.

We intend to pursue opportunities in other prospective and productive formations, such as the Buda, Glen Rose, and Pettet formations, in other East Texas properties. Total production from our East Texas region was 4.7 Bcfe (88% natural gas) for the first quarter of 2012, including 3.2 Bcfe from the Hilltop field.

Oklahoma

We have targeted our Oklahoma properties for further development with increased capital spending in 2012. We expect to improve oil production from these properties by deepening existing wellbores and downspacing to 40 acre units, and by recompleting existing wellbores to other previously unexploited zones. We believe this is a low-cost and low-risk strategy to increase oil production. During the first quarter of 2012, we deepened five wellbores into the Mississippian Lime formation and are evaluating the results from these wellbores for potential additional exploitation, including horizontal drilling. Our Oklahoma properties produced 48 MBbl’s of oil and 0.3 Bcf of natural gas net to our interest during the first quarter of 2012.

Eagle Ford Shale

We are participating with Murphy Oil Corporation (“Murphy”), the operator of our Eagleville field, in what we expect to be at least a five year program that began in 2011 in which we expect to drill at least 120 wells targeting the Eagle Ford Shale in Karnes County, Texas. At the end of the first quarter of 2012, we had working interests in 27 wells in the Eagle Ford Shale, and overriding interests in three additional wells. Murphy is operating three drilling rigs, a fracturing team, and a coil tubing unit in the area. We produced approximately 1,600 BOE per day from the Eagleville field (net to our interest, 86% oil) during the first quarter of 2012.

 

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Results of Operations: Three Months Ended March 31, 2012 v. Three Months Ended March 31, 2011

 

		Three Months Ended March 31,								Increase
		2012				2011				(Decrease)				% Change
		(dollars in thousands, except average sales price and unit costs)
Summary Operating Information:
Net Production:
Natural gas (MMcf)			6,602				7,366				(764	)			(10	)%
Oil (MBbls)			460				348				112				32	%
Natural gas liquids (MBbls)			52				58				(6	)			(10	)%
Total natural gas equivalent (MMcfe)			9,679				9,803				(124	)			(1	)%
Average daily gas production (MMcfe per day)			106.4				108.9				(2.5	)			(2	)%
Average Sales Price:
Natural gas (per Mcf) realized		$	3.87			$	4.80			$	(0.93	)			(19	)%
Natural gas (per Mcf) unhedged			2.57				4.02				(1.45	)			(36	)%
Oil (per Bbl) realized			108.02				92.44				15.58				17	%
Oil (per Bbl) unhedged			111.09				96.70				14.39				15	%
Natural gas liquids (per Bbl) realized (1)			58.46				52.88				5.58				11	%
Combined (per Mcfe) realized			8.09				7.21				.88				12	%
Hedging Activities:
Realized natural gas revenue gain		$	8,540			$	5,791			$	2,749				47	%
Realized oil revenue gain (loss)			(1,409	)			(1,484	)			75				5	%
Summary Financial Information
Revenues
Natural gas		$	25,539			$	35,381			$	(9,842	)			(28	)%
Oil			49,730				32,197				17,533				54	%
Natural gas liquids			3,067				3,053				14				0	%
Other revenues			698				469				229				49	%
Unrealized (loss) — oil and natural gas derivative contracts			(6,395	)			(19,184	)			12,789				67	%
			72,639				51,916				20,723				40	%
Expenses
Lease and plant operating expense			15,918				13,331				2,587				19	%
Production and ad valorem tax expense			6,230				5,401				829				15	%
Workover expense			1,253				1,626				(373	)			(23	)%
Exploration expense			2,029				2,731				(702	)			(26	)%
Depreciation, depletion, and amortization expense			23,893				19,468				4,425				23	%
Impairment expense			1,752				5,826				(4,074	)			(70	)%
Accretion expense			440				470				(30	)			(6	)%
General and administrative expense			7,969				5,751				2,218				39	%
Interest expense, net			9,754				9,478				276				3	%
Net income (loss)		$	3,401			$	(12,166	)		$	15,567				128	%
Average Unit Costs per Mcfe:
Lease and plant operating expense		$	1.64			$	1.36			$	0.28				21	%
Production and ad valorem tax expense			0.64				0.55				0.09				16	%
Workover expense			0.13				0.17				(0.04	)			(24	)%
Exploration expense			0.21				0.28				(0.07	)			(25	)%
Depreciation , depletion and amortization			2.47				1.99				0.48				24	%
General and administrative expenses			0.82				0.59				0.23				39	%

 

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

 

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Revenues

Natural gas revenues for the three months ended March 31, 2012 decreased $9.8 million, or 28%, to $25.5 million from $35.3 million in 2011. The decrease in natural gas revenue was attributable to a lower average realized price during the first quarter of 2012 and to decreased production volumes. The price of natural gas exclusive of hedging decreased 36% in the first quarter of 2012; the overall realized price (including hedging gains and losses), decreased 19% from $4.80 per Mcf in the first quarter of 2011 to $3.87 per Mcf in the first quarter of 2012, resulting in a decrease in natural gas revenues of approximately $6.1 million. Approximately $3.7 million of the decrease in revenues from natural gas was due to a decrease in production of 0.8 Bcf, or 10%. This decline is primarily due to our Hilltop field, which produced 3.2 Bcf in the first quarter of 2012, compared to 4.1 Bcf in the first quarter of 2011.

Oil revenues for the three months ended March 31, 2012 increased $17.5 million, or 54%, to $49.7 million from $32.2 million in 2011. The increase in revenue was attributable to increased production volumes coupled with a higher average realized price. Approximately $10.3 million of the increase was due to an increase in production of 112 MBbls, or 32%. This increase is primarily due to production from our Eagleville field, which increased 107 MBbls in the first quarter of 2012 as compared to the first quarter of 2011, from 15 MBbls to 122 MBbls. The price of oil exclusive of hedging increased 15% in the first quarter of 2012; the overall realized price (including hedging gains and losses) increased 17% from $92.44 per Bbl in the first quarter of 2011 to $108.02 per Bbl in the first quarter of 2012, resulting in an increase in oil revenues of approximately $7.2 million.

Natural gas liquids revenues were flat during the first quarter of 2012 compared to the same period in 2011, at $3.1 million. A 10% decrease in volumes from 58 MBbls to 52 MBbls was offset by an increase in our average price of 11%, from $52.88 per Bbl to $58.46 per Bbl.

Other revenues were $0.7 million during the three months ended March 31, 2012 as compared to $0.5 million during the three months ended March 31, 2011. The increase is primarily the result of an increase in rental income from our drilling rig.

Unrealized loss — oil and natural gas derivative contracts was $6.4 million during the three months ended March 31, 2012 as compared to $19.2 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. In general, the majority of the losses were related to the increase in oil prices during each of these periods, which decreased the unrealized value of our open derivative contracts.

Expenses

Lease and plant operating expense increased $2.6 million in the first quarter of 2012 as compared to the first quarter of 2011, due to increased transportation and gathering fees of $1.3 million, field supervision and labor of $1.1 million, repairs and maintenance of $0.6 million, and salt water disposal of $0.4 million. These increases were partially offset by a decrease in field service costs. On a unit basis, lease and plant operating expense increased from $1.36 per Mcfe to $1.64 per Mcfe for the three months ended March 31, 2011 and 2012, respectively.

Production and ad valorem taxes increased $0.8 million, or 15%, to $6.2 million for the first quarter of 2012, as compared to $5.4 million for the first quarter of 2011. Ad valorem taxes increased $0.7 million, primarily due to increases in asset values. Production taxes increased $0.1 million, following an increase in our revenue from products of 11%. Severance tax as a percentage of product revenues before realized hedging gains and losses was approximately 7% for each of the quarters ended March 31, 2012 and 2011.

Workover expense decreased from the first quarter of 2011 to the first quarter of 2012, from $1.6 million to $1.3 million, respectively. This expense varies depending on activities in the field.

Exploration expense includes the costs of our geology department, costs of geological and geophysical data, delay rentals, expired leases, and dry holes. Exploration expense decreased from $2.7 million for the first quarter of 2011 to $2.0 million for the first quarter of 2012.

Depreciation, depletion and amortization increased $4.4 million to $23.9 million for the first quarter of 2012 as compared to an expense of $19.5 million for the first quarter of 2011. On a per unit basis, this expense increased from $1.99 to $2.47 per Mcfe. The rate is a function of capitalized costs of proved properties, reserves and production by field.

 

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Impairment expense decreased from $5.8 million in the first quarter of 2011 to $1.8 million in the first quarter of 2012. This expense varies with the results of drilling, as well as with price declines and other factors which may render some projects uneconomic, resulting in impairment.

Accretion expense is related to our obligation for retirement of oil and natural gas wells and facilities. We record these liabilities when we place the assets in service, using discounted present values of the estimated future obligation. We then record accretion of the liabilities as they approach maturity. Accretion expense was $0.4 million and $0.5 million for the first quarter of 2012 and 2011, respectively.

General and administrative expenses increased $2.2 million for the first quarter of 2012 to $8.0 million from $5.8 million for the first quarter of 2011. The increase in general and administrative expenses is principally due to increased salary and benefits expenses of $0.8 million, primarily due to additional personnel, increased consulting services of $0.8 million, primarily for fees associated with litigation and engineering services, and field management fees of $0.5 million. On a per unit basis, general and administrative expenses increased from $0.59 to $0.82 per Mcfe.

Interest expense, net increased $0.3 million for the first quarter of 2012 to $9.8 million from $9.5 million for the first quarter of 2011, primarily due to $0.9 million higher interest on our credit facility, due primarily to higher average balances during the first quarter of 2012. This increase was partially offset by decreased interest rate hedge losses of $0.3 million, and to a decrease in amortization of deferred loan costs of $0.3 million, due to the extension of the maturity date of our credit facility which was amended in May 2011.

Liquidity and Capital Resources

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

Our 2012 capital budget is primarily focused on the development of existing core areas through exploitation and development. Currently, we plan to spend a total of approximately $220-240 million during 2012, of which approximately $55.9 million has been expended or accrued through March 31, 2012, including acquisitions. Approximately 79% of our 2012 capital budget is allocated to our properties in the Hilltop field, other fields in East Texas, the Eagle Ford Shale in South Texas, 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, 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 adjusted our capital structure by issuing $300 million of 9 5/8% senior notes due 2018 (“senior notes”). The senior notes were issued at a discount of $2.1 million, bringing the effective interest rate to 9 3/4%.

The senior notes are unsecured senior general corporate obligations, and effectively rank junior to any of our existing or future secured indebtedness, which includes our credit facility. The senior notes are unconditionally guaranteed on a senior unsecured basis by each of our material, wholly-owned subsidiaries. We entered into a registration rights agreement with the purchasers of the senior notes. We filed a registration statement with the SEC to allow for registration of “exchanges notes” substantially identical to the senior notes. On August 12, 2011, the exchange notes were exchanged for the original senior notes tendered in connection with the exchange offer.

 

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Credit Facility

We have a senior secured revolving credit facility (“credit facility”) with Wells Fargo Bank, N.A. as the administrative agent. As of March 31, 2012, the credit facility was subject to a $325 million borrowing base limit, and we had $206.8 million outstanding under the credit facility. Our restricted subsidiaries are guarantors of the credit facility.

The borrowing base is redetermined each May 1 and November 1. In May 2012, the borrowing base was increased to $350 million. As of May 15, 2012, the available unused portion of the borrowing base was $128.2 million.

Our credit facility provides for two alternative interest rate bases and margins. Eurodollar loans accrue interest generally at the one-month London Interbank Offered Rate plus a margin ranging from 2.00% to 2.75%, depending on the utilization of our borrowing base. “Reference rate” loans accrue interest at the prime rate of Wells Fargo Bank, N.A., plus a margin ranging from 1.00% to 1.75%, depending on the utilization of our borrowing base. The total rate on all loans outstanding as of March 31, 2012 under the credit facility was 2.5%, which was based on the Eurodollar option.

The credit facility and the indenture governing the senior notes include covenants requiring us to maintain certain financial covenants including a current ratio, leverage ratio, and interest coverage ratio. At March 31, 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 $47.7 million during the three months ended March 31, 2012 as compared to $45.6 million during the comparable period in 2011. The $2.1 million increase in operating cash flows was attributable to an increase in the cash-based portions of our earnings, partially offset by changes in working capital accounts. Cash-based items of net income, including revenues (exclusive of unrealized commodity gains or losses), operating expenses and taxes, general and administrative expenses, and the cash portion of our interest expense, provided a net increase of approximately $2.4 million in earnings and a related positive impact on cash flow. Partially offsetting this increase were changes in our working capital accounts, which provided $10.9 million of cash flows as compared to provision of $11.2 million of cash in 2011. The changes in working capital resulted in a decrease of $0.3 million in cash flow.

Cash flow used in investing activities

Investing activities used cash of $59.5 million during the three months ended March 31, 2012 as compared to cash used in investing of $59.0 million during the comparable period of 2011. An increase in cash used in acquisition activities of $9.9 million was primarily due to $6.3 million expended for a group of leasehold properties in South Texas. Investment in property and equipment decreased by $9.4 million, primarily due to a significant paydown of accrued capital expenditures in the first quarter of 2011. On an accrual basis, capital spending was generally increased, primarily for expenditures in our Eagleville and Hayes fields in South Texas and South Louisiana, respectively, and also in Oklahoma; these increases in spending were partially offset by a decrease in capital spending in our Hilltop field in East Texas, as compared to the first quarter of 2011.

Cash flow provided by financing activities

Financing activities provided cash of $18.0 million during the three months ended March 31, 2012 as compared to cash provided by financing of $14.0 million during the comparable period in 2011. Both quarters reflected the effect of drawdowns from our credit facility.

 

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Cautionary Statement Regarding Forward-Looking Statements

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

Forward-looking statements may include statements about our:

 

•

business strategy;

 

•

reserves;

 

•

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

 

•

realized oil and natural gas prices;

 

•

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

 

•

hedging strategy and results;

 

•

future drilling plans;

 

•

competition and government regulations;

 

•

marketing of oil and natural gas;

 

•

leasehold or business acquisitions;

 

•

costs of developing our properties;

 

•

general economic conditions;

 

•

credit markets;

 

•

liquidity and access to capital;

 

•

uncertainty regarding our future operating results; and

 

•

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

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

 

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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.

 

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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 March 31, 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 March 31, 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 our 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 March 31, 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.

 

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ITEM 6. Exhibits

 

10.1		Amendment No. 5 to Sixth Amended and Restated Credit Agreement by and among Alta Mesa Holdings, LP, Wells Fargo Bank, N.A., as administrative agent, and the lenders party thereto from time to time, dated as of May 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.

 

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SIGNATURES

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

 

				ALTA MESA HOLDINGS, LP (Registrant)
				By:		ALTA MESA HOLDINGS GP, LLC,
						its general partner
May 15, 2012				By:		/s/ Harlan H. Chappelle
						Harlan H. Chappelle
						President and Chief Executive Officer
May 15, 2012				By:		/s/ Michael A. McCabe
						Michael A. McCabe
						Vice President and Chief Financial Officer

 

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