Alta Mesa Holdings, LP - FORM 10-Q

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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, 2013

¨	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)

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

Table of Contents


	Page Number
PART I — FINANCIAL INFORMATION
Item 1. Financial Statements		3
Consolidated Balance Sheets as of March 31, 2013 (unaudited) and December 31, 2012		3
Consolidated Statements of Operations (unaudited) for the Three Months Ended March 31, 2013 and 2012		4
Consolidated Statements of Cash Flows (unaudited) for the Three Months Ended March 31, 2013 and 2012		5
Notes to Consolidated Financial Statements (unaudited)		6
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations		17
Item 3. Quantitative and Qualitative Disclosures about Market Risk		23
Item 4. Controls and Procedures		23
PART II — OTHER INFORMATION		24
Item 1. Legal Proceedings		24
Item 1A. Risk Factors		24
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds		24
Item 3. Defaults Upon Senior Securities		24
Item 4. Mine Safety Disclosures		24
Item 5. Other Information		24
Item 6. Exhibits		25
Signatures		26

PART I — FINANCIAL INFORMATION

ITEM 1. Financial Statements

ALTA MESA HOLDINGS, LP AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(dollars in thousands)


	March 31, 2013			December 31, 2012
	(unaudited)
ASSETS
CURRENT ASSETS
Cash and cash equivalents	$	3,306		$	5,786
Restricted cash		3,305			2,305
Accounts receivable, net		48,732			40,715
Other receivables		2,682			4,415
Prepaid expenses and other current assets		3,381			4,501
Derivative financial instruments		7,343			21,360

TOTAL CURRENT ASSETS		68,749			79,082

PROPERTY AND EQUIPMENT
Oil and natural gas properties, successful efforts method, net		679,691			639,466
Other property and equipment, net		16,070			16,031

TOTAL PROPERTY AND EQUIPMENT, NET		695,761			655,497

OTHER ASSETS
Investment in Partnership — cost		9,000			9,000
Deferred financing costs, net		12,985			13,685
Derivative financial instruments		10,411			14,066
Advances to operators		3,833			9,416
Deposits and other assets		1,695			1,686

TOTAL OTHER ASSETS		37,924			47,853

TOTAL ASSETS	$	802,434		$	782,432

LIABILITIES AND PARTNERS’ CAPITAL (DEFICIT)
CURRENT LIABILITIES
Accounts payable and accrued liabilities	$	112,373		$	112,684
Current portion, asset retirement obligations		1,680			64
Derivative financial instruments		2,721			91

TOTAL CURRENT LIABILITIES		116,774			112,839

LONG-TERM LIABILITIES
Asset retirement obligations, net of current portion		47,512			48,529
Long-term debt		633,986			601,858
Notes payable to founder		22,421			22,123
Derivative financial instruments		—			—
Other long-term liabilities		2,395			3,451

TOTAL LONG-TERM LIABILITIES		706,314			675,961

TOTAL LIABILITIES		823,088			788,800
COMMITMENTS AND CONTINGENCIES (NOTE 9)
PARTNERS’ CAPITAL (DEFICIT)		(20,654	)		(6,368	)

TOTAL LIABILITIES AND PARTNERS’ CAPITAL (DEFICIT)	$	802,434		$	782,432

See notes to consolidated financial statements.

ALTA MESA HOLDINGS, LP AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

(dollars in thousands)

(unaudited)


	Three Months Ended March 31,
	2013			2012
REVENUES
Natural gas	$	25,363		$	25,539
Oil		61,817			49,730
Natural gas liquids		2,118			3,067
Other revenues		652			698

		89,950			79,034
Unrealized (loss) — oil and natural gas derivative contracts		(20,302	)		(6,395	)

TOTAL REVENUES		69,648			72,639

EXPENSES
Lease and plant operating expense		15,583			15,918
Production and ad valorem taxes		5,744			6,230
Workover expense		4,077			1,253
Exploration expense		2,596			2,029
Depreciation, depletion, and amortization expense		24,505			23,893
Impairment expense		7,355			1,752
Accretion expense		443			440
Loss on sale of assets		1,070			—
General and administrative expense		9,341			7,969

TOTAL EXPENSES		70,714			59,484

INCOME (LOSS) FROM OPERATIONS		(1,066	)		13,155
OTHER INCOME (EXPENSE)
Interest expense		(13,290	)		(9,771	)
Interest income		70			17

TOTAL OTHER INCOME (EXPENSE)		(13,220	)		(9,754	)

INCOME (LOSS) BEFORE STATE INCOME TAXES		(14,286	)		3,401
PROVISION FOR STATE INCOME TAXES		—			—

NET INCOME (LOSS)	$	(14,286	)	$	3,401

See notes to consolidated financial statements.

ALTA MESA HOLDINGS, LP AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(dollars in thousands)

(unaudited)


	Three Months Ended March 31,
	2013			2012
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss)	$	(14,286	)	$	3,401
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion, and amortization expense		24,505			23,893
Impairment expense		7,355			1,752
Accretion expense		443			440
Amortization of loan costs		700			568
Amortization of debt discount		128			65
Dry hole expense		(150	)		893
Expired leases		222			—
Unrealized loss on derivatives		20,302			5,868
Interest converted into debt		298			301
Loss on sale of assets		1,070			—
Settlement of asset retirement obligation		—			(373	)
Changes in assets and liabilities:
Restricted cash		(1,000	)		—
Accounts receivable		(8,017	)		5,677
Other receivables		1,733			249
Prepaid expenses and other non-current assets		6,694			(1,337	)
Accounts payable, accrued liabilities, and other long-term liabilities		5,636			6,351

NET CASH PROVIDED BY OPERATING ACTIVITIES		45,633			47,748

CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures for property and equipment		(79,705	)		(49,596	)
Acquisitions		(408	)		(9,946	)

NET CASH USED IN INVESTING ACTIVITIES		(80,113	)		(59,542	)

CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from long-term debt		32,000			18,000

NET CASH PROVIDED BY FINANCING ACTIVITIES		32,000			18,000

NET INCREASE (DECREASE) IN CASH		(2,480	)		6,206
CASH AND CASH EQUIVALENTS, beginning of period		5,786			2,630

CASH AND CASH EQUIVALENTS, end of period	$	3,306		$	8,836

SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION
Cash paid during the period for interest	$	521		$	2,460
Cash paid during the period for state taxes	$	(107	)	$	—
Change in property asset retirement obligations, net	$	156		$	233
Change in accruals or liabilities for capital expenditures	$	(7,002	)	$	(3,714	)

See notes to consolidated financial statements.

ALTA MESA HOLDINGS, LP AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(unaudited)

1. SUMMARY OF ORGANIZATION AND NATURE OF OPERATIONS

The consolidated financial statements reflect the accounts of Alta Mesa Holdings, LP and its subsidiaries (“we”, “us”, “our”, the “Company,” and “Alta Mesa”) after elimination of all significant intercompany transactions and balances. The financial statements should be read in conjunction with the consolidated financial statements and notes thereto included in our annual consolidated financial statements for the year ended December 31, 2012, which were filed with the Securities and Exchange Commission in our 2012 Annual Report on Form 10-K.

The consolidated financial statements included herein as of March 31, 2013, and for the three month periods ended March 31, 2013 and 2012, 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 (i) its wholly-owned subsidiaries: Alta Mesa Acquisition Sub, LLC, Alta Mesa Eagle, LLC, Alabama Energy Resources, LLC, Alta Mesa Drilling, LLC, Alta Mesa Energy, LLC, Alta Mesa Finance Services Corp., Alta Mesa GP, LLC, AM Idaho, LLC, AMH Energy New Mexico, LLC, and Virginia Oil and Gas, LLC; (ii) its direct and indirect wholly-owned subsidiaries: Alta Mesa Services, LP, Aransas Resources, LP (and its wholly-owned subsidiary ARI Development, LLC), Brayton Management GP II, LLC, Brayton Resources II, LP, Buckeye Production Company, LP, Cairn Energy USA, LLC, FBB Anadarko, LLC, Galveston Bay Resources, LP, Louisiana Exploration & Acquisitions, LP (and its wholly-owned subsidiary Louisiana Exploration & Acquisition Partnership, LLC), Louisiana Onshore Properties LLC, Navasota Resources, Ltd., LLP, New Exploration Technologies Company, LLC, Nueces Resources, LP, Oklahoma Energy Acquisitions, LP, Petro Acquisitions, LP, Petro Operating Company, LP, Sundance Acquisition, LLC, TE TMR, LLC, Texas Energy Acquisitions, LP, The Meridian Production LLC, The Meridian Resource & Exploration LLC, The Meridian Resource LLC, TMR Drilling, LLC, TMR Equipment, LLC; and (iii) its partially-owned subsidiaries: Brayton Management GP, LLC, Brayton Resources, LP, LEADS Resources, L.L.C., 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, 2013, our significant accounting policies are consistent with those discussed in Note 2 of the consolidated financial statements for the fiscal year ended December 31, 2012.

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

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

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

Unproved Properties — Acquisition costs associated with the acquisition of leases are recorded as unproved properties 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. Unproved properties 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 properties 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 properties may be assessed in the aggregate. If unproved properties 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 $984,000 and $784,000 at March 31, 2013 and December 31, 2012, 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, 2013 and 2012, amortization of deferred financing costs included in interest expense amounted to $700,000 and $568,000, respectively. Deferred financing costs are listed among our long-term assets, net of accumulated amortization of $10.6 million and $9.9 million at March 31, 2013 and December 31, 2012, respectively.

Fair Value of Financial Instruments: The fair value of cash, restricted 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 $450 million senior notes payable at $480.4 million at March 31, 2013. See Note 4 for further information on fair values of financial instruments. See Note 7 for information on long-term debt.

Recent Accounting Pronouncements

In January 2013 we adopted 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 additional disclosures are included in Note 5.

In February 2013, the FASB issued ASU No. 2013-04. The guidance requires an entity that is joint and severally liable to measure the obligation as the sum of the amount the entity has agreed with co-obligors to pay and any additional amount it expects to pay on behalf of one or more co-obligors. Required disclosures include a description of the nature of the arrangement, how the liability arose, the relationship with co-obligors and the terms and conditions of the arrangement. ASU No. 2013-04 is effective for annual and interim reporting periods beginning after December 15, 2013. We do not expect the adoption of this pronouncement to have a material impact on our consolidated financial statements.

3. PROPERTY AND EQUIPMENT

Property and equipment consists of the following:


	March 31, 2013			December 31, 2012
	(unaudited)
	(dollars in thousands)
OIL AND NATURAL GAS PROPERTIES
Unproved properties	$	49,534		$	52,501
Accumulated impairment		(1,022	)		(6,040	)

Unproved properties, net		48,512			46,461

Proved oil and natural gas properties		1,239,760			1,171,798
Accumulated depreciation, depletion, amortization and impairment		(608,581	)		(578,793	)

Proved oil and natural gas properties, net		631,179			593,005

TOTAL OIL AND NATURAL GAS PROPERTIES, net		679,691			639,466

LAND		1,185			1,185

DRILLING RIG		10,500			10,500
Accumulated depreciation		(2,012	)		(1,837	)

TOTAL DRILLING RIG, net		8,488			8,663

OTHER PROPERTY AND EQUIPMENT
Office furniture and equipment, vehicles		10,449			9,657
Accumulated depreciation		(4,052	)		(3,474	)

OTHER PROPERTY AND EQUIPMENT, net		6,397			6,183

TOTAL PROPERTY AND EQUIPMENT, net	$	695,761		$	655,497

4. 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.

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 $11.1 million were written down to their fair value of $3.7 million, resulting in an impairment charge of $7.4 million for the three months ended March 31, 2013. 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.

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.

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 $169,000 and $233,000 in additions to asset retirement obligations measured at fair value during the three months ended March 31, 2013 and 2012, respectively.

The following table presents information about our financial assets and liabilities measured at fair value on a recurring basis as of March 31, 2013 and December 31, 2012, 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, 2013 (unaudited):*
Financial Assets:
Derivative contracts for oil and natural gas		—	$	49,097		—	$	49,097
Financial Liabilities:
Derivative contracts for oil and natural gas		—	$	34,064		—	$	34,064
*At December 31, 2012:*
Financial Assets:
Derivative contracts for oil and natural gas		—	$	76,157		—	$	76,157
Financial Liabilities:
Derivative contracts for oil and natural gas		—	$	40,822		—	$	40,822

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 5.

5. 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 7 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 entered into an interest rate swap agreement to mitigate the risk of loss due to changes in interest rates which expired in 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 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, 2013 and 2012.

The following table summarizes the fair value (see Note 4 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, 2013
	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	$	15,697		$	10,391		$	23,009		$	—
Fair value of oil and gas commodity contracts, (liabilities)		(8,354	)		(13,112	)		(12,598	)		—

Total net assets, (liabilities)	$	7,343		$	(2,721	)	$	10,411		$	—


Fair Values of Derivative Contracts
	Balance Sheet Location at December 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
	(dollars in thousands)
Fair value of oil and gas commodity contracts, assets	$	43,074		$	—		$	33,083		$	—
Fair value of oil and gas commodity contracts, (liabilities)		(21,714	)		(91	)		(19,017	)		—

Total net assets, (liabilities)	$	21,360		$	(91	)	$	14,066		$	—

Commodity contracts are subject to master netting arrangements and are presented on a net basis in the consolidated balance sheets. This presentation may 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. We net assets and liabilities with the same counterparty when master netting agreements allow for offsetting of amounts owed.

As of March 31, 2013, a total of $21.0 million in gross derivative assets were offset by the equivalent amount of gross derivative liabilities for presentation on our consolidated balance sheets, and a total of $10.4 million in gross derivative liabilities were offset by an equivalent amount of gross derivative assets for presentation. As of December 31, 2012, a total of $40.7 million in gross derivative assets were offset by the equivalent amount of gross derivative liabilities for presentation on our consolidated balance sheets.

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)	2013			2012
			(unaudited) (dollars in thousands)
Natural gas commodity contracts	Natural gas revenues	Realized	$	10,818		$	8,540
Oil commodity contracts	Oil revenues	Realized		(2,838	)		(1,409	)
Interest rate contracts	Interest expense	Realized		—			(562	)

Total realized gains from derivatives not designated as hedges			$	7,980		$	6,569

Natural gas commodity contracts	Unrealized gain (loss) — oil and natural gas derivative contracts	Unrealized	$	(18,711	)	$	7,786
Oil commodity contracts	Unrealized gain (loss) — oil and natural gas derivative contracts	Unrealized		(1,591	)		(14,181	)
Interest rate contracts	Interest benefit (expense)	Unrealized		—			527

Total unrealized (losses) from derivatives not designated as hedges			$	(20,302	)	$	(5,868	)

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

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

We had the following open derivative contracts for natural gas at March 31, 2013 (unaudited):

NATURAL GAS DERIVATIVE CONTRACTS


	Volume in		Weighted		Range
Period and Type of Contract	MMbtu		Average		High		Low
2013
Price Swap Contracts		14,300,000	$	4.47	$	7.03	$	3.30
Collar Contracts
Short Call Options		900,000		4.90		4.90		4.90
Long Put Options		600,000		6.04		6.15		6.00
Long Call Options		3,020,000		7.27		7.92		7.00
Short Put Options		12,016,250		3.11		5.00		3.00
2014
Price Swap Contracts		8,600,000		4.90		7.50		4.01
Collar Contracts
Short Call Options		4,395,000		6.59		9.00		4.83
Long Put Options		2,570,000		5.84		7.00		4.25
Short Put Options		3,543,500		3.98		5.50		3.00
2015
Price Swap Contracts		1,825,000		5.91		5.91		5.91
2016
Collar Contracts
Short Call Options		455,000		7.50		7.50		7.50
Long Put Options		455,000		5.50		5.50		5.50
Short Put Options		455,000		4.00		4.00		4.00

We had the following open derivative contracts for crude oil at March 31, 2013 (unaudited):

OIL DERIVATIVE CONTRACTS


			Weighted		Range
Period and Type of Contract	Volume in Bbls		Average		High		Low
2013
Price Swap Contracts		1,168,750	$	105.40	$	112.39	$	77.00
Collar Contracts
Short Call Options		650,925		117.35		129.00		100.00
Long Put Options		440,000		105.65		113.25		85.00
Long Call Options		86,625		105.00		127.00		92.35
Short Put Options		1,127,500		81.89		90.00		65.00
2014
Price Swap Contracts		620,050		96.23		105.48		81.00
Collar Contracts
Short Call Options		730,000		116.70		133.50		107.50
Long Put Options		762,200		92.39		95.00		85.00
Short Put Options		1,051,280		74.49		80.00		65.00
2015
Price Swap Contracts		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		684,350		71.20		75.00		60.00
2016
Price Swap Contracts		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 gas at March 31, 2013 (unaudited):


Volume in MMbtu	Reference Price 1 ⁽¹⁾	Reference Price 2 ⁽¹⁾	Period	Spread ($ per MMbtu)
2,750,000	NYMEX Henry Hub	Houston Ship Channel	Apr ’13 — Dec ’13	$	0.0625

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

We had the following open financial basis swap contracts for crude oil at March 31, 2013:


Volume in Bbl	Reference Price 1 ⁽²⁾	Reference Price 2 ⁽²⁾	Period	Weighted Average Spread ($ per Bbl)
962,500	Brent IPE	Argus Louisiana Light Sweet	Apr ’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.

6. 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, 2012	$	48,593
Liabilities incurred		169
Liabilities settled		—
Accretion expense		443
Revisions to previous estimates		(13	)

Balance, March 31, 2013		49,192
Less: Current portion		1,680

Long-term portion	$	47,512

7. LONG-TERM DEBT AND NOTES PAYABLE TO FOUNDER

Long-term debt consists of the following:


	March 31, 2013		December 31, 2012
	(unaudited)
	(dollars in thousands)
Credit Facility	$	186,790	$	154,790
Senior Notes		447,196		447,068

Total long-term debt	$	633,986	$	601,858

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 March 31, 2013, the borrowing base under the facility was $313.7 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 2.66% as of March 31, 2013 and 2.33% as of December 31, 2012.

Senior Notes. On October 13, 2010, we issued senior notes due October 15, 2018 (“initial senior notes”) 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. On October 15, 2012 we issued an additional $150 million of senior notes (“additional senior notes”) governed by the same indenture as the original issue of senior notes and carrying the same face interest rate, maturity and interest payment dates. The additional senior notes were issued at a discount of $1.5 million, and proceeds were used to reduce outstanding borrowings under the credit facility. Both the initial senior notes and the additional senior notes (together, “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 $2.8 million and $2.9 million at March 31, 2013 and December 31, 2012, respectively.

The senior notes contain an optional redemption provision available prior to October 2013 allowing us to retire up to 35% of the principal outstanding under the senior notes at 109.625% with the proceeds of an equity offering. 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.

All of the senior notes, which were initially issued in private placements, have been exchanged for substantially identical registered senior notes. The credit facility and senior notes include covenants requiring that the Company maintain certain financial covenants including a current ratio, leverage ratio, and interest coverage ratio. At March 31, 2013, the Company was in compliance with the covenants. The terms of the credit facility also restrict the Company’s 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 $22.4 million and $22.1 million at March 31, 2013 and December 31, 2012, 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 $298,000 and $301,000 for the three months ended March 31, 2013 and 2012, respectively. Such amounts have been added to the balance of the founder notes.

8. ACCOUNTS PAYABLE AND ACCRUED LIABILITIES

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


	March 31, 2013		December 31, 2012
	(unaudited)
	(dollars in thousands)
Capital expenditures	$	26,821	$	37,738
Revenues and royalties payable		10,556		10,788
Operating expenses/taxes		31,829		23,887
Compensation		7,365		5,978
Other		6,853		6,223

Total accrued liabilities		83,424		84,614
Accounts payable		28,949		28,070

Accounts payable and accrued liabilities	$	112,373	$	112,684

9. 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. We entered into settlements with both the Chesapeake-related defendants and Gastar in 2012. 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 $1.1 million and $1.0 million at March 31, 2013 and December 31, 2012, respectively, 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 our wholly owned subsidiary 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, 2013.

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

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

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

We have a contingent commitment to pay an amount up to a maximum of approximately $2.7 million for properties acquired in 2008. The additional purchase consideration will be paid if certain product price conditions are met.

10. 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 5.

11. PARTNERS’ CAPITAL (DEFICIT)

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.

12. 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.

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, 2012 (“2012 Form 10-K”).

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.

Outlook

Natural gas prices declined significantly during 2011 and 2012, reaching a low point with the May 2012 NYMEX closing at $2.04 per MMbtu. Since that date prices have improved to some extent, closing at $3.43 for the March 2013 NYMEX Henry Hub Futures contract settled March 28, 2013. The suppressed prices have been caused by many factors, including increases in North American natural gas production due to intensified drilling activity, warmer than normal winters 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 and fourth quarters of 2012. Total impairment expense for the year 2012 was $96.2 million. Impairment expense for the first quarter of 2013 was $7.4 million. A significant portion of the total in 2012 was for our Hilltop field in East Texas, which produces dry gas, and is vulnerable to extremely low prices for natural gas. Substantially all of the other properties written down were also in East Texas, where our natural gas production is most concentrated.

The unrealized values of our derivative contracts are reported at fair value on our consolidated balance sheets and are highly sensitive to changes in the price of oil and natural gas. Changes in these derivative assets and liabilities are reported in our consolidated statement of operations as unrealized hedging gain or loss, which is a non-cash item. In the first quarter of 2013, we recognized an unrealized loss on our derivative contracts of $20.3 million. Realized cash-based gains from our hedging program were $8.0 million during the quarter, partially offsetting the unrealized losses. The objective of our hedging program is that, over time, the combination of realized hedging gains and losses with ordinary oil and natural gas revenues will produce relative price stability. However, in the short term, both realized and unrealized hedging gains and losses can be significant to our results of operations, and we expect these gains and losses to continue to reflect the unpredictability and volatility of oil and natural gas prices.

We have hedged approximately 68% of our forecasted PDP production through 2017 at average annual prices ranging from $4.52 per MMBtu to $5.91 per MMBtu for natural gas and $90.00 per Bbl to $105.47 per Bbl for oil.

Sustained low oil and natural gas prices may require us to write down the value of our oil and natural gas properties and/or revise our development plans, which may cause certain of our undeveloped well locations to no longer be deemed proved. This could cause a reduction in the borrowing base under our credit facility. Low prices may also reduce our cash available for distribution and for servicing our indebtedness and may make it difficult to hedge production at favorable prices and may cause us to change our development plans.

NYMEX West Texas Intermediate crude oil reflected a monthly average of $92.96 for March 2013. We expect oil prices to remain volatile in the future. Factors affecting the price of oil include worldwide economic conditions, including the European credit crisis, geopolitical activities, including developments in the Middle East, worldwide supply disruptions, weather conditions, actions taken by the Organization of Petroleum Exporting Countries and the value of the U.S. dollar in international currency markets.

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

Operations Update

Eagleville field. We completed ten wells in the Eagle Ford Shale formation in Eagleville field during the first quarter of 2013. An additional twelve wells were in progress at the end of the quarter. As of March 31, 2013, we have 80 producing wells in this field, which are primarily operated by Murphy Oil Corporation (“Murphy”). Our average working interest in these wells is 15%. We produced approximately 3,100 BOE per day from the Eagleville field net to our interest, 90% oil and natural gas liquids, during the first quarter of 2013. For the first quarter of 2012, production from the Eagleville field was 1,600 BOE per day net to our interest. Murphy has operated two to three drilling rigs on our acreage at any given time thus far in 2013.

Weeks Island. We are targeting updip oil reserves and undrained fault blocks in this large oil field. We spudded four wells in the first quarter of 2013 and completed each of them as producers, with two coming on line subsequent to the end of the quarter. Since the beginning of 2013, we also brought on line five wells spudded in 2012 (three were completed during the first quarter of 2013 and two subsequently). Initial rates of production ranged from 100 to 600 BOPD, with one well initially producing primarily natural gas at 1,500 MCFD. As of March 31, 2013, we were drilling two wells. Our plans are to utilize one to two rigs continuously through the end of 2013. We also have two workover rigs operating in this field, primarily for completing new wells and recompleting older wells to new producing zones.

Production from Weeks Island net to our interest was 2,200 BOE per day, 97% oil, for the first quarter of 2013, as compared to 1,700 BOE per day, 85% oil, for the first quarter of 2012.

Oklahoma. We completed two vertical wells in the first quarter of 2013, as a continuation of our 2012 program to further develop and assess the Mississippian Lime and Hunton Lime formations with vertical well completions. In the first quarter of 2013 we also began the completion of two horizontal Mississippian Lime wells, one of which began drilling in the fourth quarter of 2012, and the other of which was drilled in the first quarter of 2013. We plan to expand our horizontal drilling program targeting primarily the Mississippian Lime in the Lincoln North, Lincoln Southeast, and East Hennessey Units, beginning with one rig in May 2013, a second in June 2013, and additional rigs later in the year. Production from Oklahoma net to our interest was 1,100 BOE per day for the first quarter of 2013, as compared to 1,000 BOE per day for the first quarter of 2012.

Results of Operations: Three Months Ended March 31, 2013 v. Three Months Ended March 31, 2012


	Three Months Ended March 31,						Increase
	2013			2012			(Decrease)			% Change
	(dollars in thousands, except average sales price and unit costs)
Summary Operating Information:
Net Production:
Natural gas (MMcf)		4,224			6,602			(2,378	)		(36	)%
Oil (MBbls)		605			460			145			32	%
Natural gas liquids (MBbls)		59			52			7			13	%
Total natural gas equivalent (MMcfe)		8,209			9,679			(1,470	)		(15	)%
Average daily gas production (MMcfe per day)		91.2			106.4			(15.2	)		(15	)%
Average Sales Price:
Natural gas (per Mcf) realized	$	6.00		$	3.87		$	2.13			55	%
Natural gas (per Mcf) unhedged		3.44			2.57			0.87			34	%
Oil (per Bbl) realized		102.21			108.02			(5.81	)		(5	)%
Oil (per Bbl) unhedged		106.90			111.09			(4.19	)		(4	)%
Natural gas liquids (per Bbl) realized (1)		35.65			58.46			(22.81	)		(39	)%
Combined (per Mcfe) realized		10.88			8.09			2.79			34	%
Hedging Activities:
Realized natural gas revenue gain	$	10,818		$	8,540		$	2,278			27	%
Realized oil revenue gain (loss)		(2,838	)		(1,409	)		(1,429	)		(101	)%
Summary Financial Information
Revenues
Natural gas	$	25,363		$	25,539		$	(176	)		(1	)%
Oil		61,817			49,730			12,087			24	%
Natural gas liquids		2,118			3,067			(949	)		(31	)%
Other revenues		652			698			(46	)		(7	)%
Unrealized (loss) — oil and natural gas derivative contracts		(20,302	)		(6,395	)		(13,907	)		(217	)%

		69,648			72,639			(2,991	)		(4	)%
Expenses
Lease and plant operating expense		15,583			15,918			(335	)		(2	)%
Production and ad valorem tax expense		5,744			6,230			(486	)		(8	)%
Workover expense		4,077			1,253			2,824			225	%
Exploration expense		2,596			2,029			567			28	%
Depreciation, depletion, and amortization expense		24,505			23,893			612			3	%
Impairment expense		7,355			1,752			5,603			320	%
Accretion expense		443			440			3			1	%
Loss on sale of assets		1,070			—			1,070			NA
General and administrative expense		9,341			7,969			1,372			17	%
Interest expense, net		13,220			9,754			3,466			36	%

Net income (loss)	$	(14,286	)	$	3,401		$	(17,687	)		(520	)%

Average Unit Costs per Mcfe:
Lease and plant operating expense	$	1.90		$	1.64		$	0.26			16	%
Production and ad valorem tax expense		0.70			0.64			0.06			9	%
Workover expense		0.50			0.13			0.37			285	%
Exploration expense		0.32			0.21			0.11			52	%
Depreciation, depletion and amortization		2.99			2.47			0.52			21	%
General and administrative expense		1.14			0.82			0.32			39	%

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

Revenues

Natural gas revenues for the three months ended March 31, 2013 decreased $0.2 million, or 1%, to $25.3 million from $25.5 million for the same period in 2012. The decrease in natural gas revenue was attributable to decreased production volumes during the first quarter of 2013, partially offset by an increase in the average price realized. Natural gas revenues declined approximately $9.2 million due to a decrease in production of 2.4 Bcf, or 36%. This decline is primarily due to our Hilltop field, which produced 1.7 Bcf in the first quarter of 2013, compared to 3.2 Bcf in the first quarter of 2012. The realized price of natural gas (including hedging gains and losses, which includes any early termination of derivative contracts) increased 55% from $3.87 per Mcf in the first quarter of 2012 to $6.00 per Mcf in the first quarter of 2013, resulting in an increase in natural gas revenues of approximately $9.0 million. The price of natural gas exclusive of hedging increased 34% in the first quarter of 2013.

Oil revenues for the three months ended March 31, 2013 increased $12.1 million, or 24%, to $61.8 million from $49.7 million in the same period in 2012. The increase in revenue was attributable to increased production volumes, partially offset by a lower average realized price. Approximately $15.6 million of the increase was due to an increase in production of 145 MBbls, or 32%. This increase is primarily due to production from our Eagleville field, which increased 103 MBbls in the first quarter of 2013 as compared to the first quarter of 2012, from 122 MBbls to 225 MBbls; we also increased production in our Weeks Island field by 62 MBbls, from 132 MBbls in the first quarter of 2012 to 194 MBbls in the first quarter of 2013. The overall realized price of oil (including hedging gains and losses) decreased 5% from $108.02 per Bbl in the first quarter of 2012 to $102.21 per Bbl in the first quarter of 2013, resulting in a decrease in oil revenues of approximately $3.5 million. The price of oil exclusive of hedging decreased 4% in the first quarter of 2013 as compared to the first quarter of 2012.

Natural gas liquids revenues decreased $1.0 million, from $3.1 million during the first quarter of 2012 to $2.1 million for the same period in 2013. A decrease in our average price of 39%, from $58.46 per Bbl to $35.65 per Bbl was partially offset by a 13% increase in volumes from 52 MBbls to 59 MBbls. The decline in prices is primarily due to oversupply of natural gas liquids from increased drilling.

Other revenues were flat at $0.7 million during the three months ended March 31, 2013 and the corresponding period of the prior year. A small decline in rent from our drilling rig was offset by increases in other fees.

Unrealized loss — oil and natural gas derivative contracts was $20.3 million during the three months ended March 31, 2013 as compared to $6.4 million during the same period in 2012. The significant fluctuation from period to period is due to the volatility of oil and natural gas prices and changes in our outstanding hedging contracts during these periods.

Expenses

Lease and plant operating expense decreased $0.3 million in the first quarter of 2013 as compared to the first quarter of 2012, due to decreases in transportation and gathering fees of $1.5 million, salt water disposal fees of $0.4 million, and compression expense of $0.2 million, partially offset by increases in repairs and maintenance of $1.4 million and chemicals expenses of $0.3 million. These expenditures reflect the increased emphasis on production of oil versus dry gas. On a unit basis, lease and plant operating expense increased from $1.64 per Mcfe to $1.90 per Mcfe for the three months ended March 31, 2012 and 2013, respectively.

Production and ad valorem taxes decreased $0.5 million, or 8%, to $5.7 million for the first quarter of 2013, as compared to $6.2 million for the first quarter of 2012. Ad valorem taxes decreased $0.4 million, primarily due to changes in asset values. Production taxes decreased $0.1 million. Severance tax as a percentage of product revenues before realized hedging gains and losses was approximately 6% and 7% for the quarters ending March 31, 2013 and 2012, respectively.

Workover expense increased from $1.3 million in the first quarter of 2012 to $4.1 million in the first quarter of 2013. This expense varies depending on activities in the field.

Exploration expense includes the costs of our geology department, costs of geological and geophysical data, lease rentals, expired leases, and dry holes. Exploration expense increased from $2.0 million for the first quarter of 2012 to $2.6 million for the first quarter of 2013.

Depreciation, depletion and amortization increased $0.6 million to $24.5 million for the first quarter of 2013 as compared to an expense of $23.9 million for the first quarter of 2012. On a per unit basis, this expense increased from $2.47 to $2.99 per Mcfe. The rate is a function of capitalized costs of proved properties, reserves and production by field.

Impairment expense increased from $1.8 million in the first quarter of 2012 to $7.4 million in the first quarter of 2013. 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. Low gas prices reduced the current value of several of our East Texas natural gas fields, resulting in write-downs in the first quarter of 2013.

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 for each of the first quarters of 2013 and 2012.

Loss on sale of assets was $1.1 million in the first quarter of 2013 and zero for the first quarter of 2012. The loss in 2013 was primarily related to the sale of a well.

General and administrative expense increased $1.3 million for the first quarter of 2013 to $9.3 million from $8.0 million for the first quarter of 2012. The increase in general and administrative expenses is principally due to increased salary and benefits expenses of $2.2 million, primarily due to additional personnel, partially offset by decreased consulting services of $0.9 million, primarily for fees associated with litigation and engineering services, and a decrease in corporate insurance expenses of $0.3 million. On a per unit basis, general and administrative expenses increased from $0.82 to $1.14 per Mcfe.

Interest expense, net increased $3.4 million for the first quarter of 2013 to $13.2 million, from $9.8 million for the first quarter of 2012, primarily due to $3.7 million higher interest on our senior notes. In October 2012, we issued an additional $150 million of these notes. This increase was partially offset by decreased interest on borrowings under our credit facility of $0.2 million. We reduced the balance outstanding under the credit facility with proceeds from the tack-on issuance of senior notes. Overall, this increased interest expense, as the interest rate on the notes is higher than for borrowings under the credit facility.

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 2013 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 $250-270 million during 2013, of which approximately $73.2 million has been expended or accrued through March 31, 2013. Approximately 75% of our 2013 capital budget is allocated to our properties in East Texas, Eagle Ford, 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 2013 capital budget predominantly with cash flows from operations, supplemented by borrowings under our credit facility. If necessary, we may also access capital through proceeds from potential asset dispositions and the future issuances of debt and/or equity securities, subject to the distribution of proceeds therefrom as set forth in our partnership agreement. We strive to maintain financial flexibility and may access capital markets as necessary to maintain substantial borrowing capacity under our senior secured revolving credit facility, facilitate drilling on our large undeveloped acreage position and permit us to selectively expand our acreage position. In the event our cash flows are materially less than anticipated and other sources of capital we historically have utilized are not available on acceptable terms, we may curtail our capital spending.

Senior Notes

In October 2010, we issued $300 million of 9.625% senior notes due 2018 (“initial 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. In connection with the issuance of the additional senior notes, the borrowing base under our credit facility was automatically reduced to $313.7 million. Both the initial senior notes and the additional senior notes (together, “senior notes”) were issued in private placements but were exchanged for substantially identical registered notes.

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

Credit Facility

We have a senior secured revolving credit facility (“credit facility”) with Wells Fargo Bank, N.A. as the administrative agent. As of March 31, 2013, the credit facility was subject to a $313.7 million borrowing base limit, and we had $186.8 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. As of May 14, 2013, the available unused portion of the borrowing base was $77.4 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 March 31, 2013 under the credit facility was 2.66%, which was based primarily 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, 2013, 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 $45.6 million during the three months ended March 31, 2013 as compared to $47.7 million during the comparable period in 2012. The $2.1 million decrease in operating cash flows was attributable to changes in working capital accounts, partially offset by an increase in the cash-based portions of our earnings. Our working capital accounts provided $5.0 million of cash flows as compared to provision of $10.9 million of cash in 2012. The changes in working capital resulted in a decrease of $5.9 million in cash flow. Partially offsetting this, 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 $3.8 million in earnings and a related positive impact on cash flow.

Cash flow used in investing activities

Investing activities used cash of $80.1 million during the three months ended March 31, 2013 as compared to cash used in investing of $59.5 million during the comparable period of 2012. Investment in property and equipment increased by $30.1 million, due primarily to increased drilling and development. A decrease in cash used in acquisition activities of $9.5 million was primarily due to $6.3 million expended for a group of leasehold properties in South Texas in the first quarter of 2012, whereas in the first quarter of 2013 there were no significant property acquisitions. On an accrual basis, capital spending was generally increased, primarily for expenditures in our Eagle Ford Shale play, South Louisiana (Weeks Island), Oklahoma, and South Texas.

Cash flow provided by financing activities

Financing activities provided cash of $32.0 million during the three months ended March 31, 2013 as compared to cash provided by financing of $18.0 million during the comparable period in 2012. Both quarters reflected the effect of drawdowns from our credit facility.

Cautionary Statement Regarding Forward-Looking Statements

The information in this report includes “forward-looking statements.” All statements, other than statements of historical fact included in this Quarterly Report on Form 10-Q, regarding our strategy, future operations, financial position, estimated revenues and losses, projected costs, prospects, plans and objectives of management are forward-looking statements. When used in this report, the words “could”, “should”, “will”, “play”, “believe”, “anticipate”, “intend”, “estimate”, “expect”, “project” and similar expressions are intended to identify forward-looking statements, although not all forward-looking statements contain such identifying words. These forward-looking statements are based on our current expectations and assumptions about future events and are based on currently available information as to the outcome and timing of future events. When considering forward-looking statements, you should keep in mind the risk factors and other cautionary statements described under the heading “Risk Factors” included in our Annual Report on Form 10-K for the year ended December 31, 2012 (“2012 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 2012 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 2012 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 2012 Form 10-K. There have been no material changes to the disclosure regarding market risks other than as noted below. See Part I, Item 1, Note 5 to our consolidated financial statements for a description of our outstanding derivative contracts at the most recent reporting date.

The fair value of our oil and natural gas derivative contracts and basis swaps at March 31, 2013 was a net asset of $15.0 million. A 10% increase or decrease in oil and natural gas prices with all other factors held constant would result in an unrealized loss or gain, respectively, in the estimated fair value (generally correlated to our estimated future net cash flows from such instruments) of our oil and natural gas commodity contracts of approximately $47.4 million (net unrealized loss) or $45.8 million (net unrealized gain), respectively, as of March 31, 2013.

We are subject to interest rate risk on our variable interest rate borrowings. Although in the past we have used interest rate swaps to mitigate the effect of fluctuating interest rates on interest expense, we currently have no open interest rate derivative contracts. A 1% increase in interest rates would increase annual interest expense on our variable rate debt by approximately $1.9 million, based on the balance outstanding as of March 31, 2013.

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, 2013 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, 2013 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 9 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 2012 Form 10-K. There have been no material changes with respect to the risk factors disclosed in the 2012 Form 10-K during the quarter ended March 31, 2013.

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.

ITEM 6. Exhibits


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

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

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

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

*101		Interactive Data Files.

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

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 14, 2013	By:	/s/ Harlan H. Chappelle
		Harlan H. Chappelle
		President and Chief Executive Officer

May 14, 2013	By:	/s/ Michael A. McCabe
		Michael A. McCabe
		Vice President and Chief Financial Officer

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