Final Prospectus

Terms of the New 9⁵/₈% Senior Notes due 2018 Offered in the Exchange Offer:

The old notes were issued as additional notes under the indenture dated October 13, 2010 pursuant to which we previously issued $300,000,000 aggregate principal amount of 9⁵/₈% Senior Notes due 2018 (CUSIP No. 021332 AC5) (the “existing notes”).

See “Risk Factors” beginning on page 14 for a discussion of certain risks that you should consider before participating in the exchange offer.

Neither the Securities and Exchange Commission nor any state securities commission has approved or disapproved of these securities or determined if this prospectus is truthful or complete. Any representation to the contrary is a criminal offense.

This prospectus is part of a registration statement we filed with the Securities and Exchange Commission. In making your investment decision, you should rely only on the information contained in this prospectus and in the accompanying letter of transmittal. We have not authorized anyone to provide you with any other information. We are not making an offer to sell these securities or soliciting an offer to buy these securities in any jurisdiction where an offer or solicitation is not authorized or in which the person making that offer or solicitation is not qualified to do so or to anyone whom it is unlawful to make an offer or solicitation. You should not assume that the information contained in this prospectus is accurate as of any date other than its date.

The information in this prospectus includes “forward-looking statements.” All statements, other than statements of historical fact included in this prospectus, 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 prospectus, 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 this prospectus. 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.

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

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 this prospectus 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 prospectus 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 prospectus.

PROSPECTUS SUMMARY

This summary highlights certain information concerning our business and this prospectus. Because this is a summary, it may not contain all of the information that may be important to you and to your investment decision. The following summary is qualified in its entirety by the more detailed information and financial statements and notes thereto included elsewhere in this prospectus. You should read this prospectus carefully and should consider, among other things, the matters set forth in “Risk Factors” and the other cautionary statements described in this prospectus.

In this prospectus, unless indicated otherwise, references to “Alta Mesa” refer to Alta Mesa Holdings, LP. References to the “Company”, “our company”, “we”, “our” and “us” refer to Alta Mesa and its subsidiaries.

The estimates of our proved reserves as of December 31, 2011 included in this prospectus are based on reserve reports prepared for us by T.J. Smith & Company, Inc., independent petroleum engineers (“T.J. Smith”), and W.D. Von Gonten & Co., independent petroleum engineers (“Von Gonten”), and audited by Netherland, Sewell & Associates, Inc., independent petroleum engineers (“Netherland Sewell”). A copy of the audit report of Netherland Sewell and the summary reports of T.J. Smith and Von Gonten are filed as Exhibits 99.2, 99.3 and 99.4 to the registration statement of which this prospectus forms a part.

For the definitions of certain terms and abbreviations used in the oil and natural gas industry, see “Glossary of Oil and Natural Gas Terms”.

In this prospectus we refer to the notes to be issued in the exchange offer as the “new notes” and the notes issued on October 15, 2012 as the “old notes.” We refer to the notes issued on October 13, 2010 and which were exchanged for registered notes on August 12, 2011 as, together, the “existing notes.” We refer to the new notes, the old notes and the existing notes collectively as the “notes.”

Our Company

We are a privately held company primarily engaged in onshore oil and natural gas acquisition, exploitation, exploration and production whose focus is to maximize the profitability of our assets in a safe and environmentally sound manner. We seek to maintain a portfolio of properties in known resource plays where we identify a large inventory of lower-risk drilling, development, and enhanced recovery and exploitation opportunities. Our core properties are located in Texas, Louisiana, and Oklahoma. We believe our balanced portfolio of assets — principally historically prolific fields in South Louisiana, conventional liquids-rich gas and oil fields of East Texas, shallow long-lived oil fields in Oklahoma, which we believe have additional prospective potential in the Mississippian Lime formation, resource plays in the Deep Bossier (Hilltop field) of East Texas and Eagle Ford Shale in South Texas — has decades of future development potential. We maximize the profitability of our assets by focusing on sound engineering, enhanced geological techniques including 3-D seismic analysis, and proven drilling, stimulation, completion, and production methods.

From December 2008 through December 2011, we have increased production at an annualized compounded rate of approximately 63% through a focused program of drilling and field re-development complemented by strategic acquisitions. As of December 31, 2011, our estimated total proved oil and natural gas reserves were approximately 348 Bcfe, of which 72% were classified as proved developed. Our proved reserve mix is approximately 63% natural gas, 29% oil and 8% natural gas liquids with a reserve life index of 8.4 years for the year ended December 31, 2011. Excluding the Hilltop field and Eagle Ford Shale assets, which include approximately 23% of the PV-10 value of our proved reserves as of December 31, 2011 and where EnCana Oil & Gas (USA), Inc. (“EnCana”) and Murphy Oil Corporation (“Murphy Oil”), respectively, are the principal operators, we maintain operational control of approximately 94% of the PV-10 value of our proved reserves. Of this, we operate 89% directly and the remainder is structured under operating arrangements with minority interest

holders where we contribute significantly to the development of the assets through use of our internal engineering and geologist staffs and we have the ability to control the drilling schedule and remove the operator.

Our areas of focus are typically characterized by multiple hydrocarbon pay zones, and because we are re-developing fields and areas originally discovered and developed by major oil and natural gas companies and other independent producers, our assets are typically served by existing infrastructure. As a result, our business model lowers geological, mechanical, and market-related risks. We focus on properties within our core operating areas that we believe have significant development and exploration opportunities and where we can apply our technical experience and economies of scale to increase production and proved reserves while lowering lease operating and capital costs. Additionally, we have consistently created value through workovers and re-completions of existing wells, infill drilling, operations improvements, secondary recovery and 3-D seismic-driven drilling. We expect to continue production growth in our core areas by exploiting known resources with continued well workovers, development drilling and enhanced recovery programs, and disciplined exploration.

During 2011, we generated $354.2 million of total revenues and $200.5 million of Adjusted EBITDAX. For the nine months ended September 30, 2012, we generated $233.1 million of total revenues and $145.8 million of Adjusted EBITDAX. See “Reconciliation of Non-GAAP Financial Measure”.

Corporate Partner and Structure

We began operations in 1987 and have funded development and operating activities primarily through cash from operations, capital raised from equity contributed by our founder, capital contributed by a private equity partner, borrowings under our bank credit facilities, and proceeds from the issuance of the existing notes and the old notes. Our capital partner, Alta Mesa Investment Holdings Inc. (“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. Since investing in us as a limited partner in 2006, AMIH has contributed $150 million in equity, which includes a $50 million contribution as part of the Meridian acquisition. In October 2010, AMIH received a $50 million distribution from the proceeds of the sale of the existing notes.

As a limited partnership, our operations and activities are managed by the board of directors of our general partner, Alta Mesa Holdings GP, LLC (“Alta Mesa GP”), and the officers of Alta Mesa Services, LP (“Alta Mesa Services”), an entity wholly owned by us. The sole member of Alta Mesa GP is Alta Mesa Resources, LP, an entity owned by Michael E. Ellis, the founder of our company, Chief Operating Officer, and Chairman of the Board of Directors of Alta Mesa GP, and his spouse, Mickey Ellis.

General Corporate Information

Alta Mesa Holdings, LP is a Texas limited partnership founded in 1987 with principal offices at 15021 Katy Freeway, Suite 400, Houston, Texas 77094. We can be reached at (281) 530-0991 and our website address is www.altamesa.net. Information on the website is not part of this prospectus. Alta Mesa Finance Services Corp. is a Delaware corporation and a wholly owned subsidiary of Alta Mesa that has no material assets and was formed for the purpose of co-issuing the existing notes.

EXCHANGE OFFER

On October 15, 2012, we completed a private offering of the old notes. We entered into a registration rights agreement with the initial purchasers in the private offering in which we agreed to deliver to you this prospectus and to use commercially reasonable efforts to complete an exchange offer within 180 days after the date we issued the old notes.

Exchange Offer

We are offering to exchange new notes for old notes. The old notes were issued as additional notes under the indenture pursuant to which, on October 13, 2010, we issued the existing notes.

Expiration Date

The exchange offer will expire at 5:00 p.m., New York City time, on January 31, 2013, unless we decide to extend it.

Condition to the Exchange Offer

The registration rights agreement does not require us to accept old notes for exchange if the exchange offer, or the making of any exchange by a holder of the old notes, would violate any applicable law or interpretation of the staff of the Securities and Exchange Commission. The exchange offer is not conditioned on a minimum aggregate principal amount of old notes being tendered.

Procedures for Tendering Old Notes

To participate in the exchange offer, you must follow the procedures established by The Depository Trust Company, which we call “DTC,” for tendering notes held in book-entry form. These procedures, which we call “ATOP,” require that (i) the exchange agent receive, prior to 5:00 p.m., New York City time, on the expiration date of the exchange offer, a computer generated message known as an “agent’s message” that is transmitted through DTC’s automated tender offer program, and (ii) DTC has received:

•

your instructions to exchange your old notes, and

•

your agreement to be bound by the terms of the letter of transmittal.

For more information on tendering your old notes, please refer to the section in this prospectus entitled “Exchange Offer — Terms of the Exchange Offer,” “— Procedures for Tendering,” and “Description of Notes — Book-Entry; Delivery and Form.”

Guaranteed Delivery Procedures

None.

Withdrawal of Tenders

You may withdraw your tender of old notes at any time prior to the expiration date. To withdraw, you must submit a notice of withdrawal to the exchange agent using ATOP procedures before 5:00 p.m., New York City time, on the expiration date of the exchange offer. Please refer to the section in this prospectus entitled “Exchange Offer — Withdrawal of Tenders.”

Acceptance of Old Notes and Delivery of New Notes

If you fulfill all conditions required for proper acceptance of old notes, we will accept any and all old notes that you properly tender in the exchange offer before 5:00 p.m., New York City time on the

expiration date. We will return any old notes that are late or not properly tendered, and therefore, that we do not accept for exchange to you without expense promptly after the expiration date and acceptance of the old notes for exchange. Please refer to the section in this prospectus entitled “Exchange Offer — Terms of the Exchange Offer.”

Fees and Expenses

We will bear expenses related to the exchange offer. Please refer to the section in this prospectus entitled “Exchange Offer — Fees and Expenses.”

Use of Proceeds

The issuance of the new notes will not provide us with any new proceeds. We are making this exchange offer solely to satisfy our obligations under the registration rights agreement.

Consequences of Failure to Exchange Old Notes

If you do not exchange your old notes in this exchange offer, you will no longer be able to require us to register the old notes under the Securities Act except in limited circumstances provided under the registration rights agreement. In addition, you will not be able to resell, offer to resell or otherwise transfer the old notes unless we have registered the old notes under the Securities Act, or unless you resell, offer to resell or otherwise transfer them under an exemption from the registration requirements of, or in a transaction not subject to, the Securities Act.

U.S. Federal Income Tax Consequences

The exchange of new notes for old notes in the exchange offer will not be a taxable event for U.S. federal income tax purposes. Please read “Certain United States Federal Income Tax Consequences.”

Exchange Agent

We have appointed Wells Fargo Bank, N.A. as exchange agent for the exchange offer. You should direct questions and requests for assistance, requests for additional copies of this prospectus or the letter of transmittal to the exchange agent as follows:

By registered & certified mail:

Wells Fargo Bank, N.A.

Corporate Trust Operations

MAC N9303-121

PO Box 1517 Minneapolis, Minnesota 55480

By regular mail or overnight courier:

Wells Fargo Bank, N.A.

Corporate Trust Operations

MAC N9303-121

Sixth & Marquette Avenue

Minneapolis, Minnesota 55479

TERMS OF THE NEW NOTES

The new notes will be identical to the old notes except that the new notes will be registered under the Securities Act and will not have restrictions on transfer, registration rights or provisions for additional interest. The new notes will evidence the same debt as the old notes, and the same indenture will govern the new notes and the old notes. The old notes do, and the new notes will, constitute the same series of securities as the existing notes for purposes of the indenture.

The following summary contains basic information about the new notes and is not intended to be complete. It does not contain all information that may be important to you. For a more complete understanding of the new notes, please refer to the section entitled “Description of Notes” in this prospectus.

Issuers

Alta Mesa Holdings, LP and Alta Mesa Finance Services Corp. Alta Mesa Finance Services Corp. is our wholly owned direct subsidiary incorporated in Delaware for the purpose of serving as a co-issuer of the notes. Alta Mesa Finance Services Corp. has no material assets and does not conduct any operations.

Securities Offered

$150,000,000 aggregate principal amount of 9⁵/₈% senior notes due 2018. The new notes will have the same cusip number and will be fungible with the existing notes.

Maturity Date

October 15, 2018.

Interest

Interest on the notes will accrue at the rate of 9⁵/₈% per annum.

Interest Payment Dates

April 15 and October 15 of each year, beginning April 15, 2013. Interest on each new note will accrue from the last interest payment date on which interest was paid on the old note tendered in exchange thereof, or, if no interest has been paid on the old note, from the date of the original issue of the old note.

Guarantees

The notes will be guaranteed initially by all of our subsidiaries, other than certain immaterial subsidiaries, and will be guaranteed by our future domestic restricted subsidiaries, other than certain immaterial subsidiaries.

Ranking

The new notes and the related guarantees will be the unsecured senior obligations of us, Alta Mesa Finance Services Corp. and the guarantors. Accordingly, they will rank:

•

equal in right of payment with our existing and future senior indebtedness, including our senior secured revolving credit facility, the existing notes and any old notes that are not exchanged;

•

senior in right of payment to all of our existing and future indebtedness that is expressly subordinated to the notes or the respective guarantees, including certain notes payable to our founder, Michael E. Ellis;

•

effectively subordinated to all of our existing and future secured indebtedness to the extent of the value of the collateral securing

such indebtedness, including amounts outstanding under our senior secured revolving credit facility; and

•

structurally subordinated to all existing and future indebtedness and obligations of any of our subsidiaries that do not guarantee the notes.

As of September 30, 2012, after giving effect to the application of the net proceeds from the offering of the old notes, we had $573.3 million of debt outstanding, $101.5 million of which was secured indebtedness and our non-guarantor subsidiaries had no indebtedness outstanding except that certain non-guarantor subsidiaries have guaranteed obligations under our senior secured revolving credit facility.

Optional Redemption

Beginning on October 15, 2014, we may redeem some or all of the notes at the redemption prices listed under “Description of Notes — Optional Redemption” plus accrued and unpaid interest on the notes to the date of redemption. At any time prior to October 15, 2013 we may redeem up to 35% of the aggregate principal amount of the notes from the proceeds of certain sales of our equity securities at 109.625% of the principal amount, plus accrued and unpaid interest, if any, to the date of redemption. We may make that redemption only if, after the redemption, at least 65% of the aggregate principal amount of the notes remains outstanding and the redemption occurs within 120 days of the closing of the equity offering.

Before October 15, 2014, we may redeem some or all of the notes at the “make-whole” redemption price set forth under “Description of Notes — Optional Redemption” plus accrued and unpaid interest on the notes to the date of redemption.

Change of Control

Upon the occurrence of a change of control (as described under “Description of Notes — Change of Control”), we must offer to repurchase the notes at 101% of their principal amount, plus accrued and unpaid interest to the date of repurchase.

Covenants

The indenture governing the notes contains certain covenants limiting our ability and the ability of our restricted subsidiaries to, under certain circumstances:

•

prepay subordinated indebtedness, pay distributions, redeem stock or make certain restricted investments;

•

incur indebtedness;

•

create liens on our assets to secure debt;

•

restrict dividends, distributions or other payments from subsidiaries to us;

•

enter into transactions with affiliates;

•

designate subsidiaries as unrestricted subsidiaries;

Summary Historical Financial Data

The following table presents our summary consolidated historical financial data as of and for the periods indicated. The information as of December 31, 2011, 2010 and 2009 and for the years ended December 31, 2011, 2010 and 2009 are derived from our historical consolidated financial statements and are included elsewhere in this prospectus. The historical financial data as of September 30, 2012 and for the nine months ended September 30, 2012 and 2011 are derived from our unaudited consolidated statements of operations included elsewhere in this prospectus.

For further information that will help you better understand the summary financial data, you should read this financial data in conjunction with the “Selected Historical Financial and Other Data”, and “Management’s Discussion and Analysis of Financial Condition and Results of Operations” sections included elsewhere in this prospectus and the financial statements and related notes and other financial information included elsewhere in this prospectus. Our historical results of operations are not necessarily indicative of results to be expected for any future periods.


	Nine Months Ended September 30,						Year Ended December 31,
	2012			2011			2011			2010			2009
	(Unaudited)
	(Dollars in thousands)
Statement of Operations Data:
Revenues
Natural gas, oil and natural gas liquids	$	249,121		$	236,964		$	323,911		$	208,537		$	102,263
Other revenue		3,952			1,366			2,127			1,475			1,558

		253,073			238,330			326,038			210,012			103,821
Unrealized gain (loss) — oil and natural gas derivative contracts		(19,944	)		25,292			28,169			10,088			(26,258	)

Total revenues		233,129			263,622			354,207			220,100			77,563
Costs and expenses:
Lease and plant operating expense		50,833			44,639			62,637			41,905			23,871
Production and ad valorem taxes		19,315			15,198			19,357			11,141			4,755
Workover expense		8,254			8,391			11,777			7,409			8,988
Exploration expense		13,543			12,310			15,785			31,037			12,839
Depreciation, depletion, and amortization		76,161			66,187			94,251			59,090			48,659
Impairment expense		50,934			16,498			18,735			8,399			6,165
Accretion expense		1,339			1,430			1,812			1,370			492
General and administrative expense		30,195			24,251			33,087			20,135			8,738
Gain on sale of assets		—			—			—			(1,766	)		(738	)

Total operating expenses		250,574			188,904			257,441			178,720			113,769

Income (loss) from operations		(17,445	)		74,718			96,766			41,380			(36,206	)
Other income (expense):
Interest expense, net		(29,440	)		(23,067	)		(32,644	)		(27,149	)		(13,831	)
Litigation settlement		1,250			—			—			—			—
Gain on contract settlement		—			1,285			1,285			—			—

Other income (expense)		(28,190	)		(21,782	)		(31,359	)		(27,149	)		(13,831	)
Benefit from (provision for) state income taxes		—			(150	)		(228	)		(2	)		750

Net (loss) income		(45,635	)	$	52,786		$	65,179		$	14,229		$	(49,287	)

Other Supplementary Data:
Adjusted EBITDAX(1)	$	145,796		$	147,170		$	200,543		$	131,211		$	58,211
Ratio of senior debt to Adjusted EBITDAX(1)(2)		2.80			2.41			2.43			2.83			3.46

(1)	Adjusted EBITDAX is a non-GAAP financial measure. See “Reconciliation of Non-GAAP Financial Measure” below.

(2)

Senior debt includes all of our debt other than the founder notes. The founder notes are fully subordinated to the notes and our senior secured revolving credit facility. See “Description of Certain Indebtedness”. For all nine month periods, Adjusted EBITDAX is annualized in calculating the ratio of senior debt to Adjusted EBITDAX.


	Nine Months Ended September 30,						Year Ended December 31,
	2012			2011			2011			2010			2009
	(Unaudited)
	(Dollars in thousands)
Statement of Cash Flow Data:
Capital expenditures	$	152,125		$	147,989		$	193,770		$	110,083		$	100,261
Net cash flow provided by operating activities		117,851			115,406			150,655			61,185			34,343
Net cash used in investing activities(1)		(172,341	)		(214,581	)		(266,133	)		(208,412	)		(86,573	)
Net cash provided by financing activities		57,882			98,911			113,272			147,789			51,823
Balance Sheet Data (at period end):
Cash and cash equivalent	$	6,022		$	4,572		$	2,630		$	4,836		$	4,274
Property and equipment, net		643,374			571,386			589,167			456,264			236,196
Total assets		759,581			703,043			720,083			558,239			290,606
Senior debt(2)		545,231			471,971			487,036			371,276			201,500
Total debt		567,049			492,577			507,947			390,985			219,830
Total partners’ capital		44,037			77,444			89,672			24,658			10,664

(1)	Net cash used in investing activities includes $101.4 million for the acquisition of Meridian in the year ended December 31, 2010, and $72.4 million for acquisitions in 2011.

(2)

Senior debt includes all of our debt other than the founder notes. The founder notes are fully subordinated to the notes and our senior secured revolving credit facility. See “Description of Certain Indebtedness”. The existing notes issued in October 2010 are carried on our balance sheet net of a discount of $1.6 million and $1.8 million at September 30, 2012 and December 31, 2011, respectively.

Reconciliation of Non-GAAP Financial Measure

Adjusted EBITDAX is non-GAAP financial measure and as used herein represents net income before interest expense, exploration expense, depletion, depreciation and amortization, impairment of oil and natural gas properties, accretion of asset retirement obligations, deferred tax expense, and unrealized gain/loss on oil and natural gas derivative contracts. We present Adjusted EBITDAX because we believe it is an important supplemental measure of our performance that is frequently used by others in evaluating companies in our industry. Adjusted EBITDAX is not a measurement of our financial performance under GAAP and should not be considered as an alternative to net income, operating income or any other performance measure derived in accordance with GAAP or as an alternative to net cash provided by operating activities as a measure of our profitability or liquidity. Adjusted EBITDAX has significant limitations, including that it does not reflect our cash requirements for capital expenditures, contractual commitments, working capital or debt service. In addition, other companies may calculate Adjusted EBITDAX differently than we do, limiting their usefulness as comparative measures.

The following table sets forth a reconciliation of net income (loss) as determined in accordance with GAAP to Adjusted EBITDAX for the periods indicated:


	Nine Months Ended September 30,						Year Ended December 31,
	2012			2011			2011			2010			2009
	(Unaudited)
	(Dollars in thousands)
Net income (loss)	$	(45,635	)	$	52,786		$	65,179		$	14,229		$	(49,287	)
Interest expense		29,510			23,101			32,722			27,172			13,835
Exploration expense		13,543			12,310			15,785			31,037			12,839
Depreciation, depletion and amortization		76,161			66,187			94,251			59,090			48,659
Impairment of oil and natural gas properties		50,934			16,498			18,735			8,399			6,165
Accretion of asset retirement obligations		1,339			1,430			1,812			1,370			492
Deferred tax (benefit) expense		—			150			228			2			(750	)
Unrealized (gain) loss on oil and natural gas derivative contracts		19,944			(25,292	)		(28,169	)		(10,088	)		26,258

Adjusted EBITDAX	$	145,796		$	147,170		$	200,543		$	131,211		$	58,211

Proved Reserves and Operating Data

Proved Reserves

The table below summarizes our estimated proved reserves as of December 31, 2011.


Estimated Proved Reserves(1):
Natural gas (Bcf)		217.3
Oil (MMBbl)(2)		21.8
Total proved (Bcfe)		347.8
Proved developed producing (Bcfe)		151.3
Proved developed non-producing (Bcfe)		100.6
Proved undeveloped (Bcfe)		95.9
Percent natural gas		62.4	%
Percent proved developed		72.4	%
PV-10 (dollars in millions)(3)	$	1,070.2

(1)

Our proved reserves as of December 31, 2011 were calculated using oil and natural gas price parameters established by current Securities and Exchange Commission (“SEC”) guidelines and accounting rules based on average prices as of the first day of each of the 12 months ended on such date. These average prices were $96.19 per Bbl for oil and $4.118 per MMBtu for natural gas. Pricing was adjusted for basis differentials by field based on our historical realized prices.

(2)	Oil reserves include natural gas liquids.

(3)

PV-10 was calculated using oil and natural gas price parameters established by current SEC guidelines and accounting rules based on average oil and natural gas prices as of the first day of each of the 12 months ended December 31, 2011. Because we are a partnership and, as such, are not subject to income taxes, our PV-10 is the same as our standardized measure of future net cash flows, the most comparable measure under generally accepted accounting principles, which is reduced for the discounted value of estimated future income taxes. Calculation of PV-10 does not give effect to derivatives transactions.

Operating Data

The following table sets forth certain information regarding production volumes, average prices and average production costs associated with our sale of oil and natural gas for the periods indicated.


	Nine Months Ended September 30,				Year Ended December 31,
	2012		2011		2011		2010		2009
	(Unaudited)
Net production:
Natural gas (MMcf)		17,144		23,501		30,750		24,026		10,610
Oil (MBbls)		1,534		1,138		1,580		964		505
Natural gas liquids (MBbls)		228		155		215		147		47
Total (MMcfe)		27,711		31,259		41,518		30,694		13,919
Average sales price per unit before hedging effects:
Natural gas (per Mcf)	$	2.65	$	4.15	$	4.04	$	4.27	$	3.72
Oil (per Bbl)		105.00		103.23		104.73		78.86		59.23
Natural gas liquids (per Bbl)		45.74		57.38		58.75		46.58		36.05
Combined (per Mcfe)		7.83		7.16		7.29		6.05		5.10
Average sales price per unit after hedging effects:
Natural gas (per Mcf)	$	4.59	$	4.87	$	4.86	$	5.24	$	6.25
Oil (per Bbl)		104.38		99.93		102.35		78.63		67.94
Natural gas liquids (per Bbl)		45.74		57.38		58.75		46.58		36.05
Combined (per Mcfe)		8.99		7.58		7.80		6.79		7.35
Average costs per Mcfe:
Lease and plant operating expense	$	1.83	$	1.43	$	1.51	$	1.37	$	1.71
Production and ad-valorem taxes		0.70		0.49		0.47		0.36		0.34
Workover expense		0.30		0.27		0.28		0.24		0.65
Depreciation, depletion and amortization		2.75		2.12		2.27		1.93		3.50
General and administrative expense		1.09		0.78		0.80		0.66		0.63

An investment in the notes involves a significant degree of risk. You should carefully consider each of the risks described below, together with all of the other information contained in this prospectus, before deciding to invest in the new notes and participate in the exchange offer. If any of the following risks develop into actual events, our business, financial condition or results of operations could be materially adversely affected, which in turn could adversely affect our ability to satisfy our obligations under the notes and the guarantees of the notes. Consequently, you may lose all or part of your investment.

If you do not properly tender your old notes, you will continue to hold unregistered old notes and your ability to transfer old notes will remain restricted and may be adversely affected.

The co-issuers will only issue new notes in exchange for old notes that you timely and properly tender. Therefore, you should allow sufficient time to ensure timely delivery of the old notes and you should carefully follow the instructions on how to tender your old notes. Neither we nor the exchange agent is required to tell you of any defects or irregularities with respect to your tender of old notes.

If you do not exchange your old notes for new notes pursuant to the exchange offer, the old notes you hold will continue to be subject to the existing transfer restrictions. In general, you may not offer or sell the old notes except under an exemption from, or in a transaction not subject to, the Securities Act and applicable state securities laws. We do not plan to register old notes under the Securities Act unless our registration rights agreement with the initial purchasers of the old notes requires us to do so. Further, if you continue to hold any old notes after the exchange offer is consummated, you may have trouble selling them because there will be fewer of the old notes outstanding.

The notes and the guarantees are unsecured and effectively subordinated to the rights of our secured indebtedness.

The notes and the guarantees are general unsecured senior obligations ranking effectively junior to all of our, the co-issuer’s and the guarantors’ existing and future secured indebtedness, including obligations under our senior secured revolving credit facility, to the extent of the value of the collateral securing the indebtedness. The notes and the guarantees are also effectively subordinated to any indebtedness of any non-guarantor subsidiaries.

If we were unable to repay such indebtedness under our senior secured revolving credit facility, the lenders under this facility could foreclose on the pledged assets to the exclusion of holders of the notes, even if an event of default exists under the indenture governing the notes at such time. Furthermore, if the lenders foreclose and sell the pledged equity interests in any guarantor in a transaction permitted under the terms of the indenture governing the notes, then such guarantor will be released from its guarantee of the notes automatically and immediately upon such sale. In any such event, because the notes are not secured by any of such assets or by the equity interests in any such guarantor, it is possible that there would be no assets from which your claims could be satisfied or, if any assets existed, they might be insufficient to satisfy your claims in full.

If the co-issuers or any guarantor are declared bankrupt, become insolvent or are liquidated or reorganized, any secured indebtedness will be entitled to be paid in full from its assets or the assets of any guarantor securing that indebtedness before any payment may be made with respect to the notes or the affected guarantees. Holders of the notes will participate ratably in our remaining assets with all holders of any unsecured indebtedness that does not rank junior to the notes, based upon the respective amounts owed to each holder or creditor. In any of the foregoing events, there may not be sufficient assets to pay amounts due on the notes or the guarantees. As a result, holders of the notes would likely receive less, ratably, than holders of secured indebtedness.

As of September 30, 2012, we had total secured indebtedness of approximately $246.8 million outstanding, and $103.2 million of additional borrowing capacity under our senior secured revolving credit facility.

We have a substantial amount of indebtedness, which may adversely affect our cash flows and ability to operate our business, remain in compliance and repay our debt including the notes.

As of September 30, 2012, after giving effect to the sale of the old notes on October 15, 2012 and repayment of certain borrowings under our credit facility, we and the guarantors would have had approximately $573.3 million of total debt outstanding. In addition, the indenture for the notes permits us to incur significant additional debt, some of which may be secured. Our high level of indebtedness could have important consequences to note holders, including the following:

We may not be able to generate sufficient cash flows to meet our debt obligations.

We expect our earnings and cash flows to vary significantly from year to year due to the cyclical nature of the oil and natural gas industry. As a result, the amount of debt that we can manage in some periods may not be appropriate for us in other periods. In addition, our future cash flows may be insufficient to meet our debt obligations and commitments, including the notes. Any insufficiency could negatively impact our business. A range of economic, competitive, business and industry factors will affect our future financial performance, and, as a result, our ability to generate cash flows from operations and to pay our debt, including the notes. Many of these factors, such as oil and natural gas prices, regulatory factors, economic and financial conditions in our industry and the global economy or competitive initiatives of our competitors, are beyond our control. If we do not generate sufficient cash flows from operations to satisfy our debt obligations, we may have to undertake alternative financing plans, such as:

However, any alternative financing plans that we undertake, if necessary, may not allow us to meet our debt obligations. Our inability to generate sufficient cash flows to satisfy our debt obligations, including our obligations under the notes, or to obtain alternative financing, could materially and adversely affect our business, financial condition, results of operations and prospects.

Our ability to restructure or refinance our indebtedness will depend on the condition of the capital markets and our financial condition at such time. Any refinancing of our indebtedness could be at higher interest rates and could require us to comply with more onerous covenants, which could further restrict our business operations. The terms of existing or future debt instruments, including the indenture governing the notes, may restrict us from adopting some of these alternatives. In addition, any failure to make payments of interest or principal on our outstanding indebtedness on a timely basis would likely result in a reduction of our credit rating, which could harm our ability to incur additional indebtedness. In the absence of sufficient cash flows and capital resources, we could face substantial liquidity problems and might be required to dispose of material assets or operations to meet our debt service and other obligations. We may not be able to refinance our indebtedness, sell assets or issue equity, or borrow more funds on terms acceptable to us, if at all.

In addition, if we fail to comply with the covenants or other terms of any agreements governing our debt, our lenders will have the right to accelerate the maturity of that debt and foreclose upon the collateral, if any, securing that debt. Realization of any of these factors could adversely affect our financial condition.

We may be able to incur substantially more indebtedness, including indebtedness ranking equal to the notes and the guarantees. This could increase the risks associated with the notes.

Subject to the restrictions in the indenture governing the notes and in other instruments governing our other outstanding indebtedness (including our senior secured revolving credit facility), we may incur substantial additional indebtedness (including secured indebtedness) in the future. Although the indenture governing the notes and the instruments governing our senior secured revolving credit facility contain restrictions on the incurrence of additional indebtedness, these restrictions are subject to waiver and a number of significant qualifications and exceptions, and indebtedness incurred in compliance with these restrictions could be substantial.

If the co-issuers or any guarantor incurs any additional indebtedness that ranks equally with the notes (or with the guarantee thereof), including trade payables, the holders of that indebtedness will be entitled to share ratably with noteholders in any proceeds distributed in connection with any insolvency, liquidation, reorganization, dissolution or other winding-up of the co-issuers or such guarantor. This may have the effect of reducing the amount of proceeds paid to noteholders in connection with such a distribution.

Claims of holders of the notes will be structurally subordinate to claims of creditors of any of our current and future subsidiaries that do not guarantee the notes.

The notes will not be guaranteed by certain of our subsidiaries. In addition, in the future, we may form unrestricted subsidiaries that will not be subject to any of the covenants of the indenture and will not guarantee the notes. In the event of a bankruptcy, liquidation or dissolution of any current or future subsidiaries that do not guarantee the notes, holders of their indebtedness will generally be entitled to payment on their claims from assets of those subsidiaries before any assets are made available for distribution to us.

Under the terms of the indenture, if we experience certain specific change of control events, we will be required to offer to repurchase all of our outstanding notes at 101% of the principal amount of such notes plus accrued and unpaid interest to the date of repurchase. We may not have available funds sufficient to pay the change of control purchase price for any or all of the notes that might be tendered in the change of control offer.

The definition of change of control in the indenture governing the notes includes a phrase relating to the direct or indirect sale, transfer, conveyance or other disposition of “all or substantially all” of our and our restricted subsidiaries’ assets, taken as a whole. Although there is a limited body of case law interpreting the phrase “substantially all”, there is no precise established definition of the phrase under applicable law. Accordingly, the ability of a holder of notes to require us to repurchase such notes as a result of a sale, transfer, conveyance or other disposition of “less than all of our and our restricted subsidiaries” assets taken as a whole to another person or group may be uncertain. Our limited partnership agreement permits AMIH to cause our general partner to initiate a sale of our company to a third-party, which sale may be deemed to be a change of control. AMIH may exercise this right at a time that we do not have sufficient capital or are otherwise prohibited from repurchasing the notes. In addition, our senior secured revolving credit facility contains, and any future credit agreement likely will contain, restrictions or prohibitions on our ability to repurchase the notes under certain circumstances. If these change of control events occur at a time when we are prohibited from repurchasing the notes, we may seek the consent of our lenders to purchase the notes or could attempt to refinance the borrowings that contain these prohibitions or restrictions. If we do not obtain our lenders’ consent or refinance these borrowings, we will not be able to repurchase the notes. Accordingly, the holders of the notes may not receive the change of control purchase price for their notes in the event of a sale or other change of control, which will give the trustee and the holders of the notes the right to declare an event of default and accelerate the repayment of the notes. See “Description of Notes — Change of Control”.

Your ability to transfer the notes may be limited by the absence of an active trading market, and there is no assurance that any active trading market for the notes will develop or persist.

The old notes have not been registered under the Securities Act, and may not be resold by holders thereof unless the old notes are subsequently registered or an exemption from the registration requirements of the Securities Act is available. However, we cannot assure you that, even following registration or exchange of the old notes for new notes, an active trading market for the old notes or the new notes will exist (or persist, if developed), and we will have no obligation to create such a market. At the time of the private placements of the old notes, each book running manager advised us that they intended to make a market in the old notes and, if issued, the new notes. The book running managers are not obligated, however, to make a market in the old notes or the new notes and any market making may be discontinued at any time at their sole discretion. No assurance can be given as to the liquidity of or trading market for the old notes or the new notes.

The liquidity of any trading market for the notes and the market prices quoted for the notes depend upon the number of holders of the notes, the overall market for high yield securities, our financial performance or prospects or the prospects for companies in our industry generally, the interest of securities dealers in making a market in the notes and other factors.

If the rating agencies that rate the notes reduce their ratings on the notes in the future or indicate that they have their ratings on the notes under surveillance or review with possible negative implications, the value of the notes could decline. In addition, a ratings downgrade could adversely affect our ability to access capital.

Our credit ratings are an assessment by rating agencies of our ability to pay our debts when due. Consequently, real or anticipated changes in our credit ratings will generally affect the market value of the notes. These credit ratings may not reflect the potential impact of risks relating to structure or marketing of the notes.

Agency ratings are not a recommendation to purchase, hold or sell the notes and may be revised or withdrawn at any time by the issuing organization. Each agency’s rating should be evaluated independently of any other agency’s rating.

A financial failure by us or our subsidiaries may result in the assets of any or all of those entities becoming subject to the claims of all creditors of those entities.

A financial failure by us or our subsidiaries could affect payment of the notes if a bankruptcy court were to substantively consolidate us and our subsidiaries. If a bankruptcy court substantively consolidated us and our subsidiaries, the assets of each entity would be subject to the claims of creditors of all entities. This would expose you not only to the usual impairments arising from bankruptcy, but also to potential dilution of the amount ultimately recoverable because of the larger creditor base. Furthermore, forced restructuring of the notes could occur through the cram-down provision of the bankruptcy code. Under this provision, the notes could be restructured over your objections as to their general terms, primarily interest rate and maturity.

If the subsidiary guarantees are deemed fraudulent conveyances or preferential transfers, a court may subordinate or void them.

Under various fraudulent conveyance or fraudulent transfer laws, a court could subordinate or void our subsidiary guarantees. Generally, a United States court may void or subordinate a subsidiary guarantee in favor of the subsidiary’s other obligations if it finds that at the time the subsidiary entered into a subsidiary guarantee it:

The measures of insolvency for purposes of fraudulent transfer laws vary depending upon the governing law. Generally, a guarantor would be considered insolvent if:

In addition, a guarantee may be voided based on the level of benefits that the subsidiary guarantor received compared to the amount of the subsidiary guarantee. If a subsidiary guarantee is voided or held unenforceable, you would not have any claim against that subsidiary and would be creditors solely of us and any subsidiary guarantors whose guarantees are not held unenforceable. After providing for all prior claims, there may not be sufficient assets to satisfy claims of holders of notes relating to any voided portions of any of the subsidiary guarantees. In addition, the court might direct you to repay any amounts that you already received from the subsidiary guarantor.

The amount that can be collected under future subsidiary guarantees, if any, will be limited.

Each subsidiary guarantee entered into after the closing date will contain a provision intended to limit such guarantor’s liability to the maximum amount that it could guarantee without causing the incurrence of the obligations under its guarantee to be a fraudulent transfer. This provision may not be effective to protect subsidiary guarantees from being voided under applicable fraudulent transfer laws or may reduce the guarantor’s obligation to an amount that effectively makes the subsidiary guarantee worthless. In a recent Florida bankruptcy case, this kind of provision was found to be ineffective to protect the guarantees.

In addition, a court could require holders of notes to return amounts received from the subsidiary guarantor during the 90-day (or, in certain cases, one-year) period.

There is no established market for the notes, and we cannot assure you that any active or liquid trading market will develop or persist for these notes. Historically, the market for non-investment grade debt has been subject to disruptions that have caused substantial volatility in the prices of securities similar to the new notes. Any such disruptions could adversely affect the prices at which the notes may be sold. If a market for the notes were to develop, the new notes could trade at prices that may be higher or lower than reflected by their initial offering price, depending on many factors, including, among other things:

Our exploration, exploitation, development and acquisition operations will require substantial capital expenditures. We may be unable to obtain needed capital or financing on satisfactory terms, which could lead to a decline in our production and reserves.

The oil and natural gas industry is capital intensive. We have made and expect to continue to make substantial capital expenditures in our business for the exploration, exploitation, development and acquisition of oil and natural gas reserves. Our capital expenditures for 2011 totaled $249 million including $72 million for acquisitions. Our budgeted capital expenditures for 2012 are currently expected to be approximately $247 million, of which we have spent $185.8 million through September 30, 2012. We have funded development and operating activities primarily through equity capital raised from a private equity partner, through borrowings under our bank credit facilities and through internal operating cash flows. We intend to finance our future capital expenditures predominantly with cash flows from operations. If necessary, we may also access capital through proceeds from potential asset dispositions, borrowings under our senior secured revolving credit facility and the

future issuance of debt and/or equity securities. Our cash flow from operations and access to capital are subject to a number of variables, including:

If our revenues or the borrowing base under our senior secured revolving credit facility decrease as a result of lower commodity prices, operating difficulties, declines in reserves or for any other reason, we may have limited ability to obtain the capital necessary to conduct our operations at expected levels. Our senior secured revolving credit facility may restrict our ability to obtain new debt financing. If additional capital is required, we may not be able to obtain debt and/or equity financing on terms favorable to us, or at all. If cash generated by operations or available under our senior secured revolving credit facility is not sufficient to meet our capital requirements, the failure to obtain additional financing could result in a curtailment of our operations relating to development of our prospects, which in turn could lead to a decline in our reserves and production, and could adversely affect our business, results of operation, financial conditions and ability to make payments on our outstanding indebtedness.

External financing may be required in the future to fund our growth. We may not be able to obtain additional financing, and financing under our senior secured revolving credit facility may not be available in the future. Without additional capital resources, we may be unable to pursue and consummate acquisition opportunities as they become available, and we may be forced to limit or defer our planned oil and natural gas development program, which will adversely affect the recoverability and ultimate value of our oil and natural gas properties, in turn negatively affecting our business, financial condition and results of operations.

Natural gas prices have declined substantially in the last year, and are expected to remain depressed for the foreseeable future. Approximately 74% of our 2011 production on an Mcfe basis was natural gas. Sustained depressed prices of natural gas will adversely affect our assets, development plans, results of operations and financial position, perhaps materially.

Natural gas prices declined significantly during 2011 and 2012, closing at $3.02 for the October 2012 NYMEX Henry Hub Futures contract settled September 28, 2012. The reduction in prices has been caused by many factors, including recent increases in North American natural gas production, warmer than normal winter weather and high levels of natural gas in storage. Prices for oil and natural gas liquids did not significantly decline in 2011 but decreased somewhat in 2012, with the price of NYMEX West Texas Intermediate crude oil averaging $94.56 for the month of September 30, 2012. As of September 30, 2012, we have hedged approximately 90% of our forecasted PDP production through 2017 at prices higher than those currently prevailing. 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.

Oil and natural gas prices are volatile and a decline in prices can significantly affect our financial condition and results of operations.

Our revenue, profitability and cash flow depend upon the prices for oil and natural gas. The prices we receive for oil and natural gas production are volatile and a decrease in prices can significantly affect our financial results and impede our growth, including our ability to maintain or increase our borrowing capacity, to repay current or future indebtedness and to obtain additional capital on attractive terms. Changes in oil and

natural gas prices have a significant impact on the value of our reserves and on our cash flows. Prices for oil and natural gas may fluctuate widely in response to relatively minor changes in supply and demand, market uncertainty and a variety of additional factors that are beyond our control, such as:

Low oil or natural gas prices will decrease our revenues, and may also reduce the volumetric amount of oil or natural gas that we can economically produce. This may result in our having to make substantial downward adjustments to our estimated proved reserves. If this occurs, or if our estimates of development costs increase, production data factors change or drilling results deteriorate, accounting rules may require us to write down, as a non-cash charge to earnings, the carrying value of our oil and natural gas properties for impairments. We are required to perform impairment tests on our assets whenever events or changes in circumstances lead to a reduction of the estimated useful life or estimated future cash flows that would indicate that the carrying amount may not be recoverable or whenever management’s plans change with respect to those assets. We may incur impairment charges in the future, which could have a material adverse effect on our results of operations in the period taken and our ability to borrow funds under our senior secured revolving credit facility.

We will depend on successful exploration, exploitation, development and acquisitions to maintain reserves and revenue in the future.

In general, the volume of production from oil and natural gas properties declines as reserves are depleted, with the rate of decline depending on each reservoir’s characteristics. Except to the extent that we conduct successful exploration and development activities or acquire properties containing proved reserves, or both, our proved reserves will decline as reserves are produced. Our future oil and natural gas production is, therefore, highly dependent on our level of success in finding or acquiring additional reserves. Additionally, the business of exploring for, developing, or acquiring reserves is capital intensive. Recovery of our reserves, particularly undeveloped reserves, will require significant additional capital expenditures and successful drilling operations. To the extent cash flow from operations is reduced and external sources of capital become limited or unavailable, our ability to make the necessary capital investment to maintain or expand our asset base of oil and natural gas reserves would be impaired. In addition, we are dependent on finding partners for our exploratory activity. To the extent that others in the industry do not have the financial resources or choose not to participate in our exploration activities, we may be adversely affected.

Our estimated oil and natural gas reserve quantities and future production rates are based on many assumptions that may prove to be inaccurate. Any material inaccuracies in these reserve estimates or the underlying assumptions will materially affect the quantities and present value of our reserves.

Numerous uncertainties are inherent in estimating quantities of oil and natural gas reserves. Our estimates of our proved reserve quantities are based upon our estimated net proved reserves as of December 31, 2011 contained in the reserve reports prepared by T.J. Smith and Von Gonten. The process of estimating oil and natural gas reserves is complex, requiring significant decisions and assumptions in the evaluation of available geological, engineering and economic data for each reservoir, and these reports rely upon various assumptions, including assumptions regarding future oil and natural gas prices, production levels, and operating and development costs. As a result, estimated quantities of proved reserves and projections of future production rates and the timing of development expenditures may prove to be inaccurate. Over time, we may make material changes to reserve estimates taking into account the results of actual drilling and production. Any significant variance in our assumptions and actual results could greatly affect our estimates of reserves, the economically recoverable quantities of oil and natural gas attributable to any particular group of properties, the classifications of reserves based on risk of recovery, and estimates of the future net cash flows. In addition, changes in future production costs assumptions could have a significant effect on our proved reserve quantities.

The present value of future net revenues from our proved reserves or “PV-10”, will not necessarily be the same as the current market value of our estimated oil and natural gas reserves.

You should not assume that the present value of future net revenues from our proved reserves is the current market value of our estimated oil and natural gas reserves. In accordance with current SEC requirements, we currently base the estimated discounted future net revenues from our proved reserves on the twelve-month unweighted arithmetic average of the first-day-of-the-month price for the preceding twelve months. Actual future net revenues from our oil and natural gas properties will be affected by factors such as:

The timing of both our production and our incurrence of expenses in connection with the development and production of oil and natural gas properties will affect the timing and amount of actual future net revenues from proved reserves, and thus their actual present value. In addition, the 10% discount factor we use when calculating discounted future net revenues may not be the most appropriate discount factor based on interest rates in effect from time to time and risks associated with us or the oil and natural gas industry in general. Actual future prices and costs may differ materially from those used in the present value estimate. If oil and gas prices decline by 10%, then our PV-10 as of December 31, 2011 would decrease approximately $158 million.

Approximately 28% of our total estimated proved reserves at December 31, 2011 were proved undeveloped reserves requiring substantial capital expenditures and may ultimately prove to be less than estimated.

Recovery of proved undeveloped reserves requires significant capital expenditures and successful drilling operations. At December 31, 2011, approximately 96 Bcfe of our total estimated proved reserves were undeveloped. The reserve data included in our reserve reports assumes that substantial capital expenditures will be made to develop non-producing reserves. The calculation of our estimated net proved reserves as of December 31, 2011 assumes that we will spend $184 million to develop our estimated proved undeveloped reserves, including an estimated $127 million in 2012. Although cost and reserve estimates attributable to our natural gas and oil reserves have been prepared in accordance with industry standards, we cannot be sure that the estimated costs are accurate. We may need to raise additional capital in order to develop our estimated proved

undeveloped reserves over the next five years and we cannot be certain that additional financing will be available to us on acceptable terms, if at all. Further, our drilling efforts may be delayed or unsuccessful, and actual reserves may prove to be less than current reserve estimates, which could have a material adverse effect on our financial condition, future cash flows and results of operations.

As part of our exploration and development operations, we have expanded, and expect to further expand, the application of horizontal drilling and multi-stage hydraulic fracture stimulation techniques. The utilization of these techniques requires substantially greater capital expenditures as compared to the completion cost of a vertical well. The incremental capital expenditures are the result of greater measured depths and additional hydraulic fracture stages in horizontal wellbores.

For a more detailed discussion of our current liquidity and projected liquidity immediately following this offering, please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources”.

Future growth may place strains on our resources and cause us to rely more on project partners and independent contractors, possibly negatively affecting our financial condition and results of operations. Our ability to grow will depend on a number of factors, including:

Our use of 2-D and 3-D seismic data is subject to interpretation and may not accurately identify the presence of hydrocarbons, which could adversely affect the results of our drilling operations.

Even when properly used and interpreted, 2-D and 3-D seismic data and visualization techniques are only tools used to assist geoscientists in identifying subsurface structures and hydrocarbon indicators and do not enable geoscientists to know whether hydrocarbons are, in fact, present in those structures and the amount of hydrocarbons. We are employing 3-D seismic technology with respect to certain of our projects. The use of 2-D and 3-D seismic and other advanced technologies requires greater pre-drilling expenditures than traditional drilling strategies, and we could incur greater drilling and testing expenses as a result of such expenditures, which may result in a reduction in our returns or losses. As a result, our drilling activities may not be successful or economical, and our overall drilling success rate or our drilling success rate for activities in a particular area could decline.

We often gather 2-D and 3-D seismic data over large areas. Our interpretation of seismic data delineates those portions of an area that we believe are desirable for drilling. Therefore, we may choose not to acquire option or lease rights prior to acquiring seismic data, and, in many cases, we may identify hydrocarbon indicators before seeking option or lease rights in the location. If we are not able to lease those locations on acceptable terms, we will have made substantial expenditures to acquire and analyze 2-D and 3-D data without having an opportunity to attempt to benefit from those expenditures.

We will rely on drilling to increase our levels of production. If our drilling is unsuccessful, our financial condition will be adversely affected.

The primary focus of our business strategy is to increase production levels by drilling wells. Although we were successful in drilling in the past, we cannot assure you that we will continue to maintain production levels through drilling. Our drilling involves numerous risks, including the risk that we will not encounter commercially productive oil or natural gas reservoirs. We must incur significant expenditures to drill and complete wells. The costs of drilling and completing wells are often uncertain, and it is possible that we will make substantial expenditures on drilling and not discover reserves in commercially viable quantities.

We may be unable to make attractive acquisitions or successfully integrate acquired businesses, and any inability to do so may disrupt our business and hinder our ability to grow.

In the future we may make acquisitions of businesses that complement or expand our current business. We may not be able to identify attractive acquisition opportunities. Even if we do identify attractive acquisition opportunities, we may not be able to complete the acquisition or do so on commercially acceptable terms. No assurance can be given that we will be able to identify additional suitable acquisition opportunities, negotiate acceptable terms, obtain financing for acquisitions on acceptable terms or successfully acquire identified targets.

The success of any completed acquisition will depend on our ability to integrate effectively the acquired business into our existing operations. The process of integrating acquired businesses may involve unforeseen difficulties and may require a disproportionate amount of our managerial and financial resources. Our failure to achieve consolidation savings, to incorporate the acquired businesses and assets into our existing operations successfully or to minimize any unforeseen operational difficulties could have a material adverse effect on our financial condition and results of operations.

In addition, our partnership agreement, our senior secured revolving credit facility and the indenture governing the notes impose certain limitations on our ability to enter into mergers or combination transactions. Our partnership agreement, our senior secured revolving credit facility and the indenture governing the notes also limit our ability to incur certain indebtedness, which could indirectly limit our ability to engage in acquisitions of businesses.

Our business is subject to operational risks that will not be fully insured, which, if they were to occur, could adversely affect our financial condition or results of operations.

In addition, a portion of our natural gas production is processed to extract natural gas liquids at processing plants that are owned by others. If these plants were to cease operations for any reason, we would need to arrange for alternative transportation and processing facilities. These alternative facilities may not be available, which could cause us to shut in our natural gas production. Further, such alternative facilities could be more expensive than the facilities we currently use.

Any of these events could adversely affect our ability to conduct operations or cause substantial losses, including personal injury or loss of life, damage to or destruction of property, natural resources and equipment, pollution or other environmental contamination, loss of wells, regulatory penalties, suspension of operations, and attorney’s fees and other expenses incurred in the prosecution or defense of litigation.

As is customary in the industry, we maintain insurance against some but not all of these risks. Additionally, we may elect not to obtain insurance if we believe that the cost of available insurance is excessive relative to the perceived risks presented. Losses could therefore occur for uninsurable or uninsured risks or in amounts in excess of existing insurance coverage. The occurrence of an event that is not fully covered by insurance could have a material adverse impact on our business activities, financial condition and results of operations.

Our hedging activities could result in financial losses or could reduce our net income.

To achieve more predictable cash flows and to reduce our exposure to fluctuations in the prices of oil and natural gas, we have and may continue to enter into hedging arrangements for a significant portion of our oil and natural gas production. As of September 30, 2012, we hedged approximately 90% of our forecasted PDP production through 2017 at average annual prices ranging from $4.17 per MMBtu to $6.09 per MMBtu and $90.00 per Bbl to $104.75 per Bbl. If we experience a sustained material interruption in our production, we might be forced to satisfy all or a portion of our hedging obligations without the benefit of the cash flows from our sale of the underlying physical commodity, resulting in a substantial diminution of our liquidity. Lastly, an attendant risk exists in hedging activities that the counterparty in any derivative transaction cannot or will not perform under the instrument and that we will not realize the benefit of the hedge.

Our ability to use hedging transactions to protect us from future oil and natural gas price declines will be dependent upon oil and natural gas prices at the time we enter into future hedging transactions and our future levels of hedging, and as a result our future net cash flows may be more sensitive to commodity price changes.

Our policy has been to hedge a significant portion of our near-term estimated oil and natural gas production. However, our price hedging strategy and future hedging transactions will be determined at our discretion. We are not under an obligation to hedge a specific portion of our production. The prices at which we hedge our production in the future will be dependent upon commodities prices at the time we enter into these transactions, which may be substantially higher or lower than current oil and natural gas prices. Accordingly, our price hedging strategy may not protect us from significant declines in oil and natural gas prices received for our future production. Conversely, our hedging strategy may limit our ability to realize cash flows from commodity price increases. It is also possible that a substantially larger percentage of our future production will not be hedged as compared with the next few years, which would result in our oil and natural gas revenues becoming more sensitive to commodity price changes.

Our hedging transactions expose us to risk of financial loss if a counterparty fails to perform under a derivative contract. Disruptions in the financial markets could lead to sudden changes in a counterparty’s liquidity, which could impair their ability to perform under the terms of the derivative contract. We are unable to predict sudden changes in a counterparty’s creditworthiness or ability to perform. Even if we do accurately predict sudden changes, our ability to negate the risk may be limited depending upon market conditions.

During periods of falling commodity prices, such as in late 2008, our hedge receivable positions increase, which increases our exposure. If the creditworthiness of our counterparties deteriorates and results in their nonperformance, we could incur a significant loss.

Current or proposed financial legislation and rulemaking could have an adverse effect on our ability to use derivative instruments to reduce the effect of commodity price, interest rate and other risks associated with our business.

The Dodd-Frank Wall Street Reform and Consumer Protection Act (the “Dodd-Frank Act”), which was signed into law on July 21, 2010, establishes, among other provisions, federal oversight and regulation of the over-the-counter derivatives market and entities that participate in that market. On October 18, 2011, the Commodities Futures Trading Commission (the “CFTC”) approved regulations to set position limits for certain futures and option contracts in the major energy markets, which regulations are presently being challenged in federal court by the Securities Industry Financial Markets Association and the International Swaps and Derivatives Association. On August 13, 2012, the CFTC published the definition of “swap.” As a result, the recordkeeping and reporting requirements under the Dodd-Frank Act will become effective beginning on January 1, 2013 and over the course of the following months. The Dodd-Frank Act may also require us to comply with margin requirements and with certain clearing and trade execution requirements in our derivative activities, subject to certain exceptions, although the application of those provisions to us is uncertain at this time. The schedule for promulgation of final rules has changed repeatedly, but the current schedule published by the CFTC contemplates finishing final regulations in 2012. The financial reform legislation may also require the counterparties to our derivative instruments to spin off some of their derivatives activities to separate entities, which may not be as creditworthy as the current counterparties.

The Dodd-Frank Act and any new regulations could significantly increase the cost of derivative contracts (including through requirements to post collateral, which could adversely affect our available liquidity), materially alter the terms of derivative contracts, reduce the availability of derivatives to protect against risks we encounter, reduce our ability to monetize or restructure our existing derivative contracts, and increase our exposure to less creditworthy counterparties. If we reduce our use of derivatives as a result of the Dodd-Frank Act and regulations, our results of operations may become more volatile and our cash flows may be less predictable, which could adversely affect our ability to plan for and fund capital expenditures. Finally, the Dodd-Frank Act was intended, in part, to reduce the volatility of oil and natural gas prices, which some legislators attributed to speculative trading in derivatives and commodity instruments related to oil and natural gas. Our revenues could therefore be adversely affected if a consequence of the Dodd-Frank Act and regulations is to lower commodity prices. Any of these consequences could have a material adverse effect on our consolidated financial position, results of operations and cash flows.

We may be unable to compete effectively with larger companies, which may adversely affect our ability to generate sufficient revenues.

The oil and natural gas industry is intensely competitive, and we compete with other companies that have greater resources than us. Our ability to acquire additional properties and to discover reserves in the future will be dependent upon our ability to evaluate and select suitable properties to consummate transactions in a highly competitive market. Many of our larger competitors not only drill for and produce oil and natural gas, but also engage in refining operations and market petroleum and other products on a regional, national or worldwide basis. These companies may be able to pay more for oil and natural gas properties, and evaluate, bid for and purchase a greater number of properties than our financial or human resources permit. In addition, these companies may have a greater ability to continue drilling activities during periods of low oil and natural gas prices, to contract for drilling equipment, to secure trained personnel, and to absorb the burden of present and future federal, state, local and other laws and regulations. The oil and natural gas industry has periodically experienced shortages of drilling rigs, equipment, pipe and personnel, which has delayed development drilling and other exploitation activities and has caused significant price increases. Competition has been strong in hiring experienced personnel, particularly in the engineering and technical, accounting and financial reporting, tax and land departments. In addition, competition is strong for attractive oil and natural gas producing properties, oil and natural gas companies, and undeveloped leases and drilling rights. Our inability to compete effectively with larger companies could have a material adverse impact on our business activities, financial condition and results of operations.

The oil and natural gas industry is characterized by rapid and significant technological advancements and introductions of new products and services using new technologies. As others use or develop new technologies, we may be placed at a competitive disadvantage or competitive pressures may force us to implement those new technologies at substantial costs. In addition, other oil and natural gas companies may have greater financial, technical, and personnel resources that allow them to enjoy technological advantages and may in the future allow them to implement new technologies before we can. We may not be able to respond to these competitive pressures and implement new technologies on a timely basis or at an acceptable cost. If one or more of the technologies we use now or in the future were to become obsolete or if we are unable to use the most advanced commercially available technology, our business, financial condition, and results of operations could be materially adversely affected.

Deficiencies of title to our leased interests could significantly affect our financial condition.

If an examination of the title history of a property reveals that an oil or natural gas lease or other developed rights has been purchased in error from a person who is not the owner of the mineral interest desired, our interest would substantially decline in value. In such cases, the amount paid for such oil or natural gas lease or leases or other developed rights would be lost. It is management’s practice, in acquiring oil and natural gas leases or undivided interests in oil and natural gas leases or other developed rights, not to incur the expense of retaining lawyers to examine the title to the mineral interest to be acquired. Rather, we will rely upon the judgment of oil and natural gas lease brokers or landmen who perform the fieldwork in examining records in the appropriate governmental or county clerk’s office before attempting to acquire a lease or other developed rights in a specific mineral interest.

Prior to drilling an oil or natural gas well, however, it is the normal practice in the oil and natural gas industry for the person or company acting as the operator of the well to obtain a preliminary title review of the spacing unit within which the proposed oil or natural gas well is to be drilled to ensure there are no obvious deficiencies in title to the well. Frequently, as a result of such examinations, certain curative work must be done to correct deficiencies in the marketability of the title, such as obtaining affidavits of heirship or causing an estate to be administered. Such curative work entails expense, and it may happen, from time to time, that the operator may elect to proceed with a well despite defects to the title identified in the preliminary title opinion. Our failure to obtain perfect title to our leaseholds may adversely impact our ability in the future to increase production and reserves.

We are vulnerable to risks associated with operating in the inland waters region of South Louisiana.

Our operations and financial results could be significantly impacted by unique conditions in the inland waters region of South Louisiana because we explore and produce in that area. As a result of this activity, we are vulnerable to the risks associated with operating in the inland waters region of South Louisiana, including those relating to:

For example, during Hurricane Isaac in September 2012, our production facilities in the Biloxi Marshland area in Southeast Louisiana sustained damage. Production from these facilities was shut-in in anticipation of the storm and remained shut-in until completion of repairs in November 2012. Production from this area accounted for approximately 3% of our average daily production, or 3 MMcfe per day, at the time the facilities were shut-in. Additionally, in anticipation of the storm, we shut-in production of some of our other Southeast Louisiana properties for several days, and we experienced minor delays in the development of our Weeks Island field. All such shut-in production has been restored to pre-hurricane levels.

Further, production of reserves from reservoirs in the inland waters region of South Louisiana generally decline more rapidly than production of reservoirs from fields in many other producing regions of the world. This results in recovery of a relatively higher percentage of reserves from properties during the initial years of production, and as a result, our reserve replacement needs from new prospects may be greater in the inland waters region of South Louisiana than for our operations elsewhere. Also, our revenues and return on capital will depend significantly on prices prevailing during these relatively short production periods.

Our ability to pursue our business strategies may be adversely affected if we incur costs and liabilities due to a failure to comply with environmental regulations or a release of hazardous substances into the environment.

We may incur significant costs and liabilities as a result of environmental requirements applicable to the operation of our wells, gathering systems and other facilities. These costs and liabilities could arise under a wide range of federal, state and local environmental laws and regulations, including, for example:

Failure to comply with these laws and regulations may trigger a variety of administrative, civil and criminal enforcement measures, including the assessment of monetary penalties, the imposition of remedial requirements, and the issuance of orders enjoining future operations. Certain environmental statutes, including RCRA, CERCLA, the federal OPA and analogous state laws and regulations, impose strict joint and several liability for costs required to clean up and restore sites where hazardous substances or other waste products have been disposed of or otherwise released. More stringent laws and regulations, including any related to climate change, greenhouse gases and hydraulic fracturing, may be adopted in the future. Moreover, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the release of hazardous substances or other waste products into the environment. See “Business — Environmental Matters & Regulation” included elsewhere herein.

The unavailability or high cost of drilling rigs, equipment, supplies, personnel and oil field services could adversely affect our ability to execute development and exploitation plans on a timely basis and within budget, and consequently could adversely affect our anticipated cash flow.

We utilize third-party services to maximize the efficiency of our operation. The cost of oil field services typically fluctuates based on demand for those services. While we currently have excellent relationships with oil field service companies, there is no assurance that we will be able to contract for such services on a timely basis or that the cost of such services will remain at a satisfactory or affordable level. Shortages or the high cost of drilling rigs, equipment, supplies or personnel could delay or adversely affect our development and exploitation operations, which could have a material adverse effect on our business, financial condition or results of operations.

We are subject to complex federal, state, local and other laws and regulations that could adversely affect the cost, manner or feasibility of conducting our operations.

Our oil and natural gas exploration and production operations are subject to complex and stringent laws and regulations. In order to conduct our operations in compliance with these laws and regulations, we must obtain and maintain numerous permits, approvals and certificates from various federal, state and local governmental authorities. Failure or delay in obtaining regulatory approvals or drilling permits could have a material adverse effect on our ability to develop our properties, and receipt of drilling permits with onerous conditions could increase our compliance costs. In addition, regulations regarding conservation practices and the protection of correlative rights affect our operations by limiting the quantity of oil and natural gas we may produce and sell.

We are subject to federal, state and local laws and regulations as interpreted and enforced by governmental authorities possessing jurisdiction over various aspects of the exploration, production and transportation of oil and natural gas. The possibility exists that new laws, regulations or enforcement policies could be more stringent and significantly increase our compliance costs. If we are not able to recover the resulting costs through insurance or increased revenues, our financial position could be adversely affected.

We have limited control over activities on properties we do not operate, which could reduce our production and revenues.

As of December 31, 2011, we maintained operational control of approximately 72% of the PV-10 value of our proved reserves either through operating the properties directly or entering into arrangements with local operators with minority interests in our properties. We have limited control over properties, especially those in Hilltop and Eagle Ford, which we do not operate or do not otherwise control operations. If we do not operate or otherwise control the properties in which we own an interest, we do not have control over normal operating procedures, expenditures or future development of the underlying properties. The failure of an operator of our wells to adequately perform operations or an operator’s breach of the applicable agreements could reduce our production and revenues. The success and timing of our drilling and development activities on properties operated by others, therefore, depends upon a number of factors outside of our control, including the operator’s timing and amount of capital expenditures, expertise and financial resources, inclusion of other participants in drilling wells and use of technology.

AMIH, as our Class B limited partner, has the ability to take actions that conflict with your interests.

AMIH, an affiliate of a private equity fund focused on energy and commodities, is the holder of our Class B limited partner interest. Under our partnership agreement, the Class B limited partner has certain significant rights, including, without limitation:

The interests of the Class B limited partner could conflict with your interests as a holder of the notes. For example, if we encounter financial difficulties or are unable to pay our debts as they mature, the interests of the Class B limited partner may conflict with your interests as a holder of the notes. The Class B limited partner also may have an interest in pursuing acquisitions, divestitures, financings or other transactions that, in its judgment, could enhance its investment, even though such transactions might involve risks to you, as holders of the notes. We can provide no assurance that any such conflicts will be resolved in the favor of the interests of the holders of the notes.

Our private equity partner and its affiliates are not limited in their ability to compete with us for acquisition or drilling opportunities. This could cause conflicts of interest and limit our ability to acquire additional assets or businesses.

Our partnership agreement with our private equity partner does not prohibit it or its affiliates from owning assets or engaging in businesses that compete directly or indirectly with us. For instance, our private equity partner and its affiliates may acquire, develop or dispose of additional oil or natural gas properties or other assets in the future, without any obligation to offer us the opportunity to purchase or develop any of those assets. DCPF IV, an affiliate of our private equity partner, is part of a larger family of funds, which has significantly greater resources than we have, which may make it more difficult for us to compete for acquisition candidates if our private equity partner or its affiliates were to compete against us.

We depend on key personnel, the loss of any of whom could materially adversely affect future operations.

Our success will depend to a large extent upon the efforts and abilities of our executive officers and key operations personnel. The loss of the services of one or more of these key employees could have a material adverse effect on us. We do not maintain key-man life insurance with respect to any of our employees. Our business will also be dependent upon our ability to attract and retain qualified personnel. Acquiring and keeping these personnel could prove more difficult or cost substantially more than estimated. This could cause us to incur greater costs, or prevent us from pursuing our development and exploitation strategy as quickly as we would otherwise wish to do.

We may encounter obstacles to marketing our oil and natural gas, which could adversely impact our revenues.

The marketability of our production will depend in part upon the availability and capacity of natural gas gathering systems, pipelines and other transportation facilities owned by third parties. Transportation space on the gathering systems and pipelines we utilize is occasionally limited or unavailable due to repairs or improvements to facilities or due to space being utilized by other companies that have priority transportation

agreements. Our access to transportation options can also be affected by U.S. federal and state regulation of oil and natural gas production and transportation, general economic conditions and changes in supply and demand. The availability of markets is beyond our control. If market factors dramatically change, the impact on our revenues could be substantial and could adversely affect our ability to produce and market oil and natural gas.

We may experience a temporary decline in revenues and production if we lose one of our significant customers.

Historically, we have been dependent upon a few customers for a significant portion of our revenue. To the extent any significant customer reduces the volume of its oil or natural gas purchases from us, we could experience a temporary interruption in sales of, or a lower price for, our oil and natural gas production and our revenues could decline.

If we fail to maintain an effective system of internal controls, we may not be able to accurately report our financial results or prevent fraud.

Effective internal controls are necessary for us to provide reliable financial reports, prevent fraud and operate successfully. We cannot be certain that our efforts to maintain our internal controls will be successful, that we will be able to maintain adequate controls over our financial processes and reporting in the future. Any failure to maintain effective internal controls, or difficulties encountered in implementing or improving our internal controls, could harm our operating results and affect our ability to timely produce financial results.

Climate change legislation or regulations restricting emissions of greenhouse gases (“GHGs”) could result in increased operating costs and reduced demand for the oil and natural gas we produce.

On December 15, 2009, the EPA officially published its findings that emissions of carbon dioxide, methane and other GHGs present an endangerment to public health and the environment because emissions of such gases are, according to the EPA, contributing to warming of the earth’s atmosphere and other climatic changes. These findings allow the EPA to adopt and implement regulations that would restrict emissions of GHGs under existing provisions of the federal CAA. Accordingly, the EPA has adopted rules regulating GHG emissions from motor vehicles, thus triggering requirements to permit GHG emissions from stationary sources under the Prevention of Significant Deterioration and Title V permitting programs. EPA has adopted the so-called “Tailoring Rule,” requiring that the largest sources first obtain permit for GHG emissions. In addition, on October 30, 2009, the EPA published a final rule requiring the reporting of GHG emissions from specified large GHG emission sources in the United States beginning in 2011 for emissions occurring in 2010. In November 2010, the EPA expanded its GHG reporting rule to include onshore and offshore oil and natural gas production, processing, transmission, storage and distribution facilities. Reporting of GHG emissions from such facilities is required on an annual basis, with reporting beginning in 2012 for emissions occurring in 2011.

Although both houses of Congress, in past sessions, have considered legislation to reduce emissions of GHGs, no comprehensive program has been enacted by Congress. Some members of Congress, however, continue to indicate an intention to promote legislation to curb EPA’s authority to regulate GHGs. In the absence of a comprehensive federal program, many states, either individually or through multistate regional initiatives, are considering or have begun implementing legal measures to reduce emissions of GHGs. The adoption and implementation of any regulations imposing reporting obligations on, or limiting emissions of GHGs from, our equipment and operations could require us to incur costs to reduce emissions of GHGs associated with our operations or could adversely affect demand for the oil and natural gas that we produce.

Significant physical effects of climatic change have the potential to damage our facilities, disrupt our production activities and cause us to incur significant costs in preparing for or responding to those effects.

In an interpretative release on climate change disclosures, the SEC indicates that climate change could have an effect on the severity of weather (including hurricanes and floods), sea levels, the arability of farmland, and water availability and quality. If such effects were to occur, our development and production operations have the

potential to be adversely affected. Potential adverse effects could include damages to our facilities from powerful winds or rising waters in low lying areas, disruption of our production activities either because of climate related damages to our facilities in our costs of operation potentially arising from such climatic effects, less efficient or non-routine operating practices necessitated by climate effects or increased costs for insurance coverage in the aftermath of such effects. Significant physical effects of climate change could also have an indirect effect on our financing and operations by disrupting the transportation or process-related services provided by midstream companies, service companies or suppliers with whom we have a business relationship. We may not be able to recover through insurance some or any of the damages, losses or costs that may result from potential physical effects of climate change.

Federal legislation and state legislative and regulatory initiatives relating to hydraulic fracturing could result in increased costs and additional operating restrictions or delays.

Hydraulic fracturing is used in many of our operations to stimulate production of hydrocarbons, particularly natural gas. Congress has considered legislation to amend the SDWA to remove the exemption currently available to hydraulic fracturing, which would place additional regulatory burdens upon hydraulic fracturing operations including requirements to obtain a permit prior to commencing operations, adhering to certain construction requirements, to establish financial assurance and to require reporting and disclosure of the chemicals used in those operations. This legislation has not passed. The SDWA does not exempt hydraulic fracturing activities using diesel; the EPA has developed draft guidance for permitting of hydraulic fracturing activities using diesel.

The EPA has commenced a study of the potential environmental impacts of hydraulic fracturing activities, with first progress report anticipated to be available by late 2012, and a final draft anticipated in 2014. In addition, in December 2011, the EPA published an unrelated draft report concluding that hydraulic fracturing caused groundwater pollution in a natural gas field in Wyoming; this study remains subject to review and public comment. In March 2012, the EPA agreed to re-sample its Wyoming wells in partnership with the US Geological Survey (“USGS”), the State of Wyoming and various tribes. The comment period on the Wyoming study closes on January 15, 2013.

In addition, some states have adopted, and other states are considering adopting, regulations that could restrict hydraulic fracturing in certain circumstances and that require the disclosure of the chemicals used in hydraulic fracturing operations. Any other new laws or regulations that impose new obligations on, or significantly restrict hydraulic fracturing could make it more difficult or costly for us to perform hydraulic fracturing activities and thereby affect our determination of whether a well is commercially viable and increase our costs of doing business.

The obligations associated with being an SEC reporting company will require significant resources and management attention, which could have a material adverse effect on our business and operating results.

Following the effectiveness of the registration statement of which this prospectus forms a part, we will become subject to certain of the reporting requirements of the Securities Exchange Act of 1934, or the Exchange Act, and the Sarbanes-Oxley Act of 2002, or the Sarbanes-Oxley Act. Under the Exchange Act, we will be required to file annual, quarterly and current reports with respect to our business and financial condition. Under the Sarbanes-Oxley Act, we will be required to, among other things, establish and maintain effective internal controls and procedures for financial reporting. As a result, we may incur significant additional legal, accounting and other expenses that we have not previously incurred. We anticipate that we may need to upgrade our systems, implement additional financial and management controls, reporting systems and procedures, implement an internal audit function, and hire additional accounting and internal audit staff. Furthermore, the need to establish the corporate infrastructure demanded of a reporting company may divert management’s attention from implementing our growth strategy, which could prevent us from improving our business, results of operations and financial condition. We have made, and will continue to make, changes to our internal controls and procedures for financial reporting and accounting systems to meet our reporting obligations as a stand-alone public company. However, the measures we take may not be sufficient to satisfy our obligations as a public company. In addition, we cannot predict or estimate the amount of additional costs we may incur in order to comply with these requirements. We anticipate that these costs will materially increase our general and administrative expenses.

Section 404 of the Sarbanes-Oxley Act requires annual management assessments of the effectiveness of our internal control over financial reporting, starting with the annual report that we would expect to file with the SEC for the year ending December 31, 2012. In connection with the implementation of the necessary procedures and practices related to internal control over financial reporting, we may identify additional deficiencies. We may not be able to remediate any future deficiencies in time to meet the deadline imposed by the Sarbanes-Oxley Act for compliance with the requirements of Section 404. In addition, failure to achieve and maintain an effective internal control environment could have a material adverse effect on our business.

Our debt agreements contain restrictive covenants that may limit our ability to respond to changes in market conditions or pursue business opportunities.

Our senior secured revolving credit facility and the indenture for the notes contain restrictive covenants that limit our ability to, among other things:

In addition, our senior secured revolving credit facility requires us to maintain certain financial ratios and tests. The requirement that we comply with these provisions may materially adversely affect our ability to react to changes in market conditions, take advantage of business opportunities we believe to be desirable, obtain future financing, fund needed capital expenditures or withstand a continuing or future downturn in our business.

If we are unable to comply with the restrictions and covenants in our debt agreements, there could be a default under the terms of such agreements, which could result in an acceleration of repayment which could result in an acceleration of payment of funds that we have borrowed and would impact our ability to make principal and interest payments on the notes.

If we are unable to comply with the restrictions and covenants in the agreements governing our notes or in current or future debt financing agreements, there could be a default under the terms of these agreements. Our ability to comply with these restrictions and covenants, including meeting financial ratios and tests, may be affected by events beyond our control. As a result, we cannot assure that we will be able to comply with these restrictions and covenants or meet such financial ratios and tests. Any default under these agreements governing our indebtedness that is not waived by the required lenders or holders, as the case may be, could prevent us from paying principal, premium, if any, and interest on the notes and substantially decrease the market value of the notes. If we are unable to generate sufficient cash flow and are otherwise unable to obtain funds necessary to meet required payments of principal, premium, if any, and interest on our indebtedness, or if we otherwise fail to comply with the various covenants, including financial and operating covenants in the instruments governing our indebtedness (including covenants in our credit facility and the indenture governing the notes), we could be in default under the terms of the agreements governing such indebtedness. In the event of such a default, the holders of such indebtedness could elect to declare all the funds borrowed thereunder to be due and payable, together with accrued and unpaid interest, the lenders under our credit facility could terminate their commitments to lend, cease making further loans and institute foreclosure proceedings against our assets, and we could be forced into bankruptcy or liquidation.

Borrowings under other debt instruments that contain cross-acceleration or cross-default provisions may also be accelerated and become due and payable. If any of these events occur, our assets might not be sufficient to repay in full all of our outstanding indebtedness and we may be unable to find alternative financing. Even if we could obtain alternative financing, it might not be on terms that are favorable or acceptable to us. Additionally, we may not be able to amend our debt agreements or obtain needed waivers on satisfactory terms.

Our borrowings under our senior secured revolving credit facility expose us to interest rate risk.

Our earnings are exposed to interest rate risk associated with borrowings under our senior secured revolving credit facility. Our senior secured revolving credit facility carries a floating interest rate based upon short-term interest rate indices. If interest rates increase, so will our interest costs, which may have a material adverse effect on our results of operations and financial condition. We use interest rate hedges in an effort to mitigate this risk, but those efforts may not prove successful.

To service our indebtedness, we require a significant amount of cash, and our ability to generate cash will depend on many factors beyond our control.

Our ability to make payments on and to refinance our indebtedness, and to fund planned capital expenditures depends in part on our ability to generate cash in the future. This ability is, to a certain extent, subject to general economic, financial, competitive, legislative, regulatory and other factors that are beyond our control.

We cannot assure you that we will generate sufficient cash flow from operations, that we will realize operating improvements on schedule, or that future borrowings will be available to us in an amount sufficient to enable us to service and repay our indebtedness or to fund our other liquidity needs. If we are unable to satisfy our debt obligations, we may have to undertake alternative financing plans, such as refinancing or restructuring our indebtedness, selling assets, reducing or delaying capital investments or seeking to raise additional capital. We cannot assure you that any refinancing or debt restructuring would be possible, that any assets could be sold or that, if sold, the timing of the sales and the amount of proceeds realized from those sales would be favorable to us or that additional financing could be obtained on acceptable terms. Disruptions in the capital and credit markets, as was experienced during 2008 and 2009, could adversely affect our ability to meet our liquidity needs or to refinance our indebtedness, including our ability to draw on our existing credit facility or enter into new credit facilities.

At the closing of the offering of the old notes, we entered into a registration rights agreement with the initial purchasers pursuant to which we agreed, for the benefit of the holders of the old notes, at our cost, to do the following:

Upon the SEC’s declaring the exchange offer registration statement effective, we agreed to offer the new notes in exchange for surrender of the old notes. We agreed to use commercially reasonable efforts to cause the exchange offer registration statement to be effective continuously, and to keep the exchange offer open for a period of not less than 20 business days.

For each old note surrendered to us pursuant to the exchange offer, the holder of such old note will receive a new note having a principal amount equal to that of the surrendered old note. Interest on each new note will accrue from the last interest payment date on which interest was paid on the surrendered old note. The registration rights agreement also contains agreements to include in the prospectus for the exchange offer certain information necessary to allow a broker-dealer who holds old notes that were acquired for its own account as a result of market-making activities or other ordinary course trading activities (other than old notes acquired directly from us or one of our affiliates) to exchange such old notes pursuant to the exchange offer and to satisfy the prospectus delivery requirements in connection with resales of new notes received by such broker-dealer in the exchange offer. We agreed to use commercially reasonable efforts to maintain the effectiveness of the exchange offer registration statement for these purposes for a period ending on the earlier of (i) one year from the date on which the exchange offer registration statement is declared effective and (ii) the date on which a broker-dealer is no longer required to deliver a prospectus in connection with market-making or other trading activities.

The preceding agreement is needed because any broker-dealer who acquires old notes for its own account as a result of market-making activities or other trading activities is required to deliver a prospectus meeting the requirements of the Securities Act. This prospectus covers the offer and sale of the new notes pursuant to the exchange offer and the resale of new notes received in the exchange offer by any broker-dealer who held old notes acquired for its own account as a result of market-making activities or other trading activities other than old notes acquired directly from us or one of our affiliates.

Based on interpretations by the staff of the SEC set forth in no-action letters issued to third parties, we believe that the new notes issued pursuant to the exchange offer would in general be freely tradable after the exchange offer without further registration under the Securities Act. However, any purchaser of old notes who is an “affiliate” of ours or who intends to participate in the exchange offer for the purpose of distributing the related new notes:

Each holder of the old notes (other than certain specified holders) who desires to exchange old notes for the new notes in the exchange offer will be required to make the representations described below under “— Your Representations to Us.”

We further agreed to file with the SEC a shelf registration statement to register for public resale of old notes held by any holder who provides us with certain information for inclusion in the shelf registration statement if:

We have agreed to use commercially reasonable efforts to keep the shelf registration statement continuously effective until the earlier of one year following its effective date and such time as all notes covered by the shelf registration statement have been sold. We refer to this period as the “shelf effectiveness period.”

The registration rights agreement provides that, in the event that either the exchange offer is not completed or the shelf registration statement, if required, is not declared effective (or does not automatically become effective) on or prior to the 180^th calendar day following the issue date of the old notes, the interest rate on the old notes will be increased by 1.00% per annum until the exchange offer is completed or the shelf registration statement is declared effective (or automatically becomes effective) under the Securities Act, at which time the increased interest shall cease to accrue.

If the shelf registration statement has been declared effective (or automatically becomes effective) and thereafter either ceases to be effective or the prospectus contained therein ceases to be usable for resales of the notes at any time during the shelf effectiveness period, and such failure to remain effective or usable for resales of the notes exists for more than 45 calendar days in any three-month period (whether or not consecutive) or 90 calendar days (whether or not consecutive) in any 12-month period, then the interest rate on the old notes will be increased by 1.00% per annum commencing on the 46^th day or 91^st day, respectively, in such period and ending on such date that the shelf registration statement has again been declared (or automatically becomes) effective or the prospectus again becomes usable, at which time the increased interest shall cease to accrue.

Holders of the old notes will be required to make certain representations to us (as described in the registration rights agreement) in order to participate in the exchange offer and will be required to deliver information to be used in connection with the shelf registration statement and to provide comments on the shelf registration statement within the time periods set forth in the registration rights agreement in order to have their old notes included in the shelf registration statement.

If we effect the registered exchange offer, we will be entitled to close the registered exchange offer 20 business days after its commencement as long as we have accepted all old notes validly tendered in accordance with the terms of the exchange offer and no brokers or dealers continue to hold any old notes.

This summary of the material provisions of the registration rights agreement does not purport to be complete and is subject to, and is qualified in its entirety by reference to, all the provisions of the registration rights agreement, a copy of which is filed as an exhibit to the registration statement which includes this prospectus.

Except as set forth above, after consummation of the exchange offer, holders of old notes which are the subject of the exchange offer have no registration or exchange rights under the registration rights agreement. See “— Consequences of Failure to Exchange.”

Subject to the terms and conditions described in this prospectus and in the letter of transmittal, we will accept for exchange any old notes properly tendered and not withdrawn prior to 5:00 p.m. New York City time on the expiration date. We will issue new notes in principal amount equal to the principal amount of old notes surrendered in the exchange offer. Old notes may be tendered only for new notes and only in minimum denominations of $2,000 and integral multiples of $1,000 in excess thereof.

The exchange offer is not conditioned upon any minimum aggregate principal amount of old notes being tendered for exchange.

As of the date of this prospectus, $150,000,000 in aggregate principal amount of the old notes is outstanding. This prospectus and the letter of transmittal are being sent to all registered holders of old notes. There will be no fixed record date for determining registered holders of old notes entitled to participate in the exchange offer.

We intend to conduct the exchange offer in accordance with the provisions of the registration rights agreement, the applicable requirements of the Securities Act and the Exchange Act and the rules and regulations of the SEC. Old notes that the holders thereof do not tender for exchange in the exchange offer will remain outstanding and continue to accrue interest. These old notes will continue to be entitled to the rights and benefits such holders have under the indenture relating to the notes.

We will be deemed to have accepted for exchange properly tendered old notes when we have given oral or written notice of the acceptance to the exchange agent and complied with the applicable provisions of the registration rights agreement. The exchange agent will act as agent for the tendering holders for the purposes of receiving the new notes from us.

If you tender old notes in the exchange offer, you will not be required to pay brokerage commissions or fees or, subject to the letter of transmittal, transfer taxes with respect to the exchange of old notes. We will pay all charges and expenses, other than certain applicable taxes described below, in connecting with the exchange offer. It is important that you read the section labeled “— Fees and Expenses” for more details regarding fees and expenses incurred in the exchange offer.

We will return any old notes that we do not accept for exchange for any reason without expense to their tendering holder promptly after the expiration or termination of the exchange offer.

The exchange offer will expire at 5:00 p.m., New York City time, on January 31, 2013, unless, in our sole discretion, we extend it.

We expressly reserve the right, at any time or various times, to extend the period of time during which the exchange offer is open. We may delay acceptance of any old notes by giving oral or written notice of such extension to their holders. During any such extensions, all old notes previously tendered will remain subject to the exchange offer, and we may accept them for exchange.

In order to extend the exchange offer, we will notify the exchange agent orally or in writing of any extension. We will notify the registered holders of old notes of the extension no later than 9:00 a.m., New York City time, on the first business day following the previously scheduled expiration date.

If any of the conditions described below under “— Conditions to the Exchange Offer” have not been satisfied, we reserve the right, in our sole discretion:

by giving oral or written notice of such delay, extension or termination to the exchange agent. Subject to the terms of the registration rights agreement, we also reserve the right to amend the terms of the exchange offer in any manner.

Any such delay in acceptance, extension, termination or amendment will be followed promptly by oral or written notice thereof to the registered holders of old notes. If we amend the exchange offer in a manner that we determine to constitute a material change, we will promptly disclose such amendment by means of a prospectus supplement. The supplement will be distributed to the registered holders of the old notes. Depending upon the significance of the amendment and the manner of disclosure to the registered holders, we may extend the exchange offer. In the event of a material change in the exchange offer, including the waiver by us of a material condition, we will extend the exchange offer period if necessary so that at least five business days remain in the exchange offer following notice of the material change.

We will not be required to accept for exchange, or exchange any new notes for, any old notes if the exchange offer, or the making of any exchange by a holder of old notes, would violate applicable law or any applicable interpretation of the staff of the SEC. Similarly, we may terminate the exchange offer as provided in this prospectus before accepting old notes for exchange in the event of such a potential violation.

In addition, we will not be obligated to accept for exchange the old notes of any holder that has not made to us the representations described under “— Purpose and Effect of the Exchange Offer,” “— Your Representations to Us” and “Plan of Distribution” and such other representations as may be reasonably necessary under applicable SEC rules, regulations or interpretations to allow us to use an appropriate form to register the new notes under the Securities Act.

We expressly reserve the right to amend or terminate the exchange offer, and to reject for exchange any old notes not previously accepted for exchange, upon the occurrence of any of the conditions to the exchange offer specified above. We will give prompt oral or written notice of any extension, amendment, non-acceptance or termination to the holders of the old notes as promptly as practicable.

These conditions are for our sole benefit, and we may assert them or waive them in whole or in part at any time or at various times in our sole discretion. If we fail at any time to exercise any of these rights, this failure will not mean that we have waived our rights. Each such right will be deemed an ongoing right that we may assert at any time or at various times.

In addition, we will not accept for exchange any old notes tendered, and will not issue new notes in exchange for any such old notes, if at such time any stop order has been threatened or is in effect with respect to the registration statement of which this prospectus constitutes a part or the qualification of the indenture relating to the notes under the Trust Indenture Act of 1939.

In order to participate in the exchange offer, you must properly tender your old notes to the exchange agent as described below. It is your responsibility to properly tender your notes. We have the right to waive any defects. However, we are not required to waive defects and are not required to notify you of defects in your tender.

If you have any questions or need help in exchanging your notes, please call the exchange agent, whose contact information is set forth in “Prospectus Summary — The Exchange Offer — Exchange Agent.”

All of the old notes were issued in book-entry form, and all of the old notes are currently represented by global certificates held for the account of DTC. We have confirmed with DTC that the old notes may be tendered using the Automated Tender Offer Program (“ATOP”) instituted by DTC. The exchange agent will establish an account with DTC for purposes of the exchange offer promptly after the commencement of the exchange offer and DTC participants may electronically transmit their acceptance of the exchange offer by causing DTC to

transfer their old notes to the exchange agent using the ATOP procedures. In connection with the transfer, DTC will send an “agent’s message” to the exchange agent. The agent’s message will state that DTC has received instructions from the participant to tender old notes and that the participant agrees to be bound by the terms of the letter of transmittal.

By using the ATOP procedures to exchange old notes, you will not be required to deliver a letter of transmittal to the exchange agent. However, you will be bound by its terms just as if you had signed it.

We will determine in our sole discretion all questions as to the validity, form, eligibility, time of receipt, acceptance of tendered old notes and withdrawal of tendered old notes. Our determination will be final and binding. We reserve the absolute right to reject any old notes not properly tendered or any old notes our acceptance of which would, in the opinion of our counsel, be unlawful. We also reserve the right to waive any defect, irregularities or conditions of tender as to particular old notes. Our interpretation of the terms and conditions of the exchange offer, including the instructions in the letter of transmittal, will be final and binding on all parties. Unless waived, all defects or irregularities in connection with tenders of old notes must be cured within such time as we shall determine. Although we intend to notify holders of defects or irregularities with respect to tenders of old notes, neither we, the exchange agent nor any other person will incur any liability for failure to give such notification. Tenders of old notes will not be deemed made until such defects or irregularities have been cured or waived. Any old notes received by the exchange agent that are not properly tendered and as to which the defects or irregularities have not been cured or waived will be returned to the tendering holder, unless otherwise provided in the letter of transmittal, promptly following the expiration date.

In all cases, we will issue new notes for old notes that we have accepted for exchange under the exchange offer only after the exchange agent timely receives:

If we do not accept any tendered old notes for exchange or if old notes are submitted for a greater principal amount than the holder desires to exchange, the unaccepted or non-exchanged old notes will be returned without expense to their tendering holder. Such non-exchanged old notes will be credited to an account maintained with DTC. These actions will occur promptly after the expiration or termination of the exchange offer.

By agreeing to be bound by the letter of transmittal, you will represent to us that, among other things:

Except as otherwise provided in this prospectus, you may withdraw your tender at any time prior to 5:00 p.m. New York City time on the expiration date. For a withdrawal to be effective you must comply with the appropriate procedures of DTC’s ATOP system. Any notice of withdrawal must specify the name and number of the account at DTC to be credited with withdrawn old notes and otherwise comply with the procedures of DTC.

We will determine all questions as to the validity, form, eligibility and time of receipt of notice of withdrawal. Our determination shall be final and binding on all parties. We will deem any old notes so withdrawn not to have been validly tendered for exchange for purposes of the exchange offer.

Any old notes that have been tendered for exchange but are not exchanged for any reason will be credited to an account maintained with DTC for the old notes. This crediting will take place as soon as practicable after withdrawal, rejection of tender or termination of the exchange offer. You may retender properly withdrawn old notes by following the procedures described under “— Procedures for Tendering” above at any time prior to 5:00 p.m., New York City time, on the expiration date.

We will bear the expenses of soliciting tenders. The principal solicitation is being made by mail; however, we may make additional solicitation by facsimile, telephone, electronic mail or in person by our officers and regular employees and those of our affiliates.

We have not retained any dealer-manager in connection with the exchange offer and will not make any payments to broker-dealers or others soliciting acceptances of the exchange offer. We will, however, pay the exchange agent reasonable and customary fees for its services and reimburse it for its related reasonable out-of-pocket expenses.

We will pay the cash expenses to be incurred in connection with the exchange offer. They include:

We will pay all transfer taxes, if any, applicable to the exchange of old notes under the exchange offer. The tendering holder, however, will be required to pay any transfer taxes, whether imposed on the registered holder or any other person, if a transfer tax is imposed for any reason other than the exchange of old notes under the exchange offer.

If you do not exchange new notes for your old notes under the exchange offer, you will remain subject to the existing restrictions on transfer of the old notes. In general, you may not offer or sell the old notes unless the offer or sale is either registered under the Securities Act or exempt from the registration under the Securities Act and applicable state securities laws. Except as required by the registration rights agreement, we do not intend to register resales of the old notes under the Securities Act.

We will record the new notes in our accounting records at the same carrying value as the old notes. This carrying value is the aggregate principal amount of the old notes adjusted for any bond discount or premium, as reflected in our accounting records on the date of exchange. Accordingly, we will not recognize any gain or loss for accounting purposes in connection with the exchange offer.

Participation in the exchange offer is voluntary, and you should carefully consider whether to accept. You are urged to consult your financial and tax advisors in making your own decision on what action to take.

We may in the future seek to acquire untendered old notes in open market or privately negotiated transactions, through subsequent exchange offers or otherwise. We have no present plans to acquire any old notes that are not tendered in the exchange offer or to file a registration statement to permit resales of any untendered old notes.

The exchange offer is intended to satisfy our obligations under the registration rights agreement. We will not receive any proceeds from the issuance of the new notes in the exchange offer. In consideration for issuing the new notes as contemplated by this prospectus, we will receive old notes in a like principal amount. The form and terms of the new notes are identical in all respects to the form and terms of the old notes, except the new notes will be registered under the Securities Act and will not contain restrictions on transfer, registration rights or provisions for additional interest. Old notes surrendered in exchange for the new notes will be retired and cancelled and will not be reissued. Accordingly, the issuance of the new notes will not result in any change in our outstanding indebtedness.

The following table presents our summary historical financial data for the periods indicated, giving effect to the Meridian acquisition from the acquisition date of May 13, 2010 , the Sydson acquisition from April 21, 2011, and the TODD acquisition from June 17, 2011. The data as of and for the years ended December 31, 2011, 2010, 2009, 2008 and 2007 have been derived from our audited consolidated financial statements. The data as of and for the nine months ended September 30, 2012 and 2011 have been derived from our unaudited consolidated financial statements. For further information that will help you better understand the summary data, you should read this financial data in conjunction with “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and the consolidated financial statements and related notes and other financial information included elsewhere in this prospectus.

The following table sets forth our ratios of earnings to fixed charges for the periods presented:

The following discussion and analysis should be read in conjunction with the “Selected Historical Financial and Other Data” and the financial statements and related notes included elsewhere in this prospectus. The following discussion and analysis contains forward-looking statements that reflect our future plans, estimates, beliefs and expected performance. The forward-looking statements are dependent upon events, risks and uncertainties that may be outside our control. Our actual results could differ materially from those discussed in these forward-looking statements. Factors that could cause or contribute to such differences include, but are not limited to, the volatility of oil and natural gas prices, production timing and volumes, estimates of proved reserves, operating costs and capital expenditures, economic and competitive conditions, regulatory changes and other uncertainties, as well as those factors discussed below and elsewhere in this prospectus, particularly in “Risk Factors” and “Cautionary Statement Regarding Forward-Looking Statements”, all of which are difficult to predict. As a result of these risks, uncertainties and assumptions, the forward-looking events discussed may not occur. The historical financial information discussed below in this Management’s Discussion and Analysis of Financial Condition and Results of Operations represents Alta Mesa’s financial information for the periods indicated, giving effect to the Meridian, Sydson and TODD acquisitions from the acquisition dates of May 13, 2010, April 21, 2011 and June 17, 2011, respectively.

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:

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 consolidated results of operations in the future.

On May 13, 2010, we acquired The Meridian Resource Corporation (“Meridian”), a public exploration and production company with properties in or proximate to our other areas of operation, with proved reserves of 75 Bcfe as of December 31, 2009, for approximately $158 million. The acquisition was funded with borrowings under our senior secured revolving credit facility as well as a $50 million equity contribution from our private equity partner, AMIH. As a result of the acquisition, we increased our total proved reserves by approximately 36% as of June 30, 2010, achieved a more balanced portfolio commodity mix with a 69% increase in our proved oil reserves, and increased our proved undeveloped reserves by 51%. We believe the acquisition affords us

significant growth potential with the addition of these proved undeveloped reserves, as well as the addition of a large library of 3-D and 2-D seismic data, much of which we have reprocessed and utilized for the identification and development of new prospects in certain of our operating areas.

On April 21, 2011, we purchased from Sydson Energy and certain of its related parties (together, “Sydson” and the “Sydson acquisition”) certain oil and natural gas assets primarily located in Texas and South Louisiana in which we had jointly participated with Sydson. The purchase price was $27.5 million in cash (a total cost of $28.4 million including abandonment liabilities we assumed). Total net proved reserves acquired were estimated 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 (Eagleville field) 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.

On June 17, 2011, we purchased from Texas Oil Distribution & Development, Inc. and Matrix Petroleum LLC and certain other parties (together, “TODD” and the “TODD acquisition”) certain oil and natural gas assets primarily located in Texas and South Louisiana in which we had jointly participated with TODD. The purchase price was $22.5 million in cash (a total cost of $23.4 million including abandonment liabilities we assumed). Total net proved reserves acquired were estimated 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 Eagleville field 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.

On July 23, 2009, we made a payment of $25.5 million and took assignment of substantially all working interests that Chesapeake Energy Corporation (“Chesapeake”) had acquired from Gastar Exploration Ltd. (“Gastar”) in an approximate 50,000 acre area of Leon and Robertson Counties, Texas known as the Hilltop Field, in which the Deep Bossier formation was the principal focus for development. We exercised our preferential right to purchase these interests from Gastar in late 2005, but Gastar and Chesapeake had opposed this and Chesapeake took record title at that time. We finally and conclusively prevailed when, in 2008, a Texas court of appeals directed that specific performance take place. In early 2009, the Texas Supreme Court denied the defendants’ request to review the appeal. As a result, we were able to take assignment of working interests in over 30 producing wells and participate in further development of the area, primarily with EnCana, but also with Gastar. A subsequent payment to EnCana of $15.2 million plus purchase accounting adjustments of $3.8 million brought the total cost of the acquisition to $44.5 million. While the ownership of these interests has been decided by the courts, we pursued other claims against Chesapeake and Gastar; Chesapeake claimed an additional $36.3 million of past expenses. The case was set for trial on April 24, 2012. Shortly before the trial was to begin, we reached an agreement in principle to settle with the Chesapeake-related defendant and entered into a settlement agreement with Gastar.

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

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

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

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

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

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

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

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

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

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

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

Unrealized gain (loss) — oil and natural gas derivative contracts was a loss of $19.9 million during the nine months ended September 30, 2012 as compared to a gain of $25.3 million during the same period in 2011. The significant fluctuation from period to period is due to the volatility of oil and natural gas prices and changes in our outstanding hedging contracts during these periods.

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

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

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

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

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

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

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

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

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

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

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

Results of Operations: Year Ended December 31, 2011 v. Year Ended December 31, 2010

Natural gas revenues for the year ended December 31, 2011 increased $23.7 million, or 19%, to $149.6 million from $125.9 million in 2010. The increase in natural gas revenue was attributable to increased production volumes, partially offset by a lower average realized price during 2011. Approximately $35.2 million of the increase was due to an increase in production of 6.7 Bcf, or 28%. This increase is primarily due to our Hilltop (formerly referred to as Deep Bossier) field, which produced 18.1 Bcf in 2011, compared to 12.3 Bcf in 2010. The price of natural gas exclusive of hedging decreased 5% in 2011; the overall realized price (including hedging gains and losses), decreased 7% from $5.24 per Mcf in 2010 to $4.86 per Mcf in 2011, resulting in a decrease in natural gas revenues of approximately $11.5 million.

Oil revenues for the year ended December 31, 2011 increased $85.9 million, or 113%, to $161.7 million from $75.8 million in 2010. The increase in revenue was attributable to increased production volumes coupled with a higher average realized price. Approximately $48.5 million of the increase was due to an increase in production of 616 MBbls, or 64%. This increase is primarily due to the full-year effect of the acquisition of Meridian, which produced 985 MBbls in 2011 compared to 472 MBbls in 2010. The price of oil exclusive of hedging increased 33% in 2011; the overall realized price (including hedging gains and losses) increased 30% from $78.63 per Bbl in 2010 to $102.35 per Bbl in 2011, resulting in an increase in oil revenues of approximately $37.4 million.

Natural gas liquids revenues increased during 2011 to $12.6 million from $6.8 million for 2010. The increase was due to an increase in volumes sold, from 147 MBbls to 215 MBbls and an increase in the price, to $58.75 per Bbl in 2011 from $46.58 per Bbl in 2010. The volume increase was due to the full-year effect of the Meridian acquisition.

Other revenues were $2.1 million during 2011 as compared to $1.5 million during 2010. The increase is primarily the result of increased income from our drilling rig, offset by decreased income from investments, which includes distributions from a drilling company we partially own and do not consolidate.

Unrealized gain — oil and natural gas derivative contracts was a gain of $28.2 million for 2011 as compared to a gain of $10.1 million for 2010. The significant fluctuation from period to period is due to the volatility of oil and natural gas prices and changes in our outstanding hedging contracts during these periods.

Lease and plant operating expense increased $20.7 million to $62.6 million in 2011 as compared to $41.9 million in 2010, due primarily to lease operating costs of $7.4 million associated with production from the Meridian acquisition, which occurred in May 2010. The Hilltop field reported an increase of $7.8 million in gas gathering and processing fees, primarily due to increased production, which increased to 18.0 Bcf in 2011 from 12.3 Bcf in 2010. In addition, there were increases in repairs, maintenance, utilities, and well services primarily in our East Texas, South Texas and Florida locations. On a per unit basis, lease and plant operating expense increased to $1.51 from $1.37 per Mcfe for 2011 and 2010, respectively.

Production and ad valorem taxes increased $8.2 million to $19.4 million, or 74%, for 2011, as compared to $11.1 million for 2010. The increase on a percentage basis follows the increase in our revenues from products, which was 55%. On a per unit basis, the expense increased to $0.47 per Mcfe for 2011 from $0.36 per Mcfe for 2010.

Workover expense increased $4.4 million to $11.8 million from $7.4 million for 2011 and 2010, respectively. The increase is primarily due to activities in the East Hennessey and Lincoln North fields in Oklahoma, South Hayes field in South Louisiana, and the Blackjack Creek field in Florida.

Exploration expense includes the costs of our geology departments, costs of geological and geophysical data, delay rentals, expired leases, and dry holes. Exploration expense decreased $15.2 million to $15.8 million for 2011 from $31.0 million for 2010. The decrease is primarily due to a decrease in exploratory dry hole costs of $9.7 million and a decrease in seismic expenditures of $6.7 million, primarily related to seismic license renewals related to the Meridian acquisition recorded in 2010.

Depreciation, depletion and amortization increased $35.2 million to $94.3 million for 2011 as compared to an expense of $59.1 million for 2010. On a per unit basis, this expense increased to $2.27 from $1.93 per Mcfe for 2011 and 2010, respectively. The increase is a function of increased production to reserves and the full year impact of the Meridian acquisition.

Impairment expense increased $10.3 million to $18.7 million in 2011 from $8.4 million in 2010. This expense varies with the results of exploratory drilling, as well as with price declines which may render some projects uneconomic, resulting in impairment. See “Critical Accounting Policies and Estimates — Impairment” below for more details related to 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 $1.8 million and $1.4 million for 2011 and 2010, respectively. The increase was due to the full-year effect of the Meridian acquisition.

General and administrative expense increased $13.0 million to $33.1million in 2011 from $20.1 million in 2010. The increase resulted principally from increased payroll and burden costs of $7.8 million, primarily due to increased headcount and performance and net profit interest bonuses. This increase was partially offset by an increase in engineering and geology allocations to other expense categories. Consulting expenditures such as legal, engineering and other professional services increased $4.1 million, primarily due to on-going litigation, outside services provided by reservoir engineers, accounting, tax and compliance services. In addition, general and administrative costs such as office rent, office relocation and system conversions increased $1.2 million. On a per unit basis, general and administrative expense increased to $0.80 from $0.66 per Mcfe for 2011 and 2010, respectively.

Interest expense, net increased $5.5 million to $32.6 million in 2011 from $27.1 million in 2010, primarily due to new interest from our senior notes payable issued in October 2010 of $23 million. This increase was partially offset by decreased interest on the amount outstanding under our credit facility of $6.5 million, decreased interest rate hedge losses of $8.9 million, and decreased amortization of deferred loan costs $1.4 million. Other interest items decreased a total of $0.7 million year over year, primarily due to a significant prepayment penalty incurred in 2010 when we early retired our subordinate debt.

Results of Operations: Year Ended December 31, 2010 v. Year Ended December 31, 2009

Natural gas revenues for the year ended December 31, 2010 were $125.9 million, compared to $66.3 million for 2009, representing a $59.6 million or 90% increase. The increase in revenue was attributable to increased production volumes, which was partially offset by a lower average realized price during 2010. Approximately $83.8 million of the increase was due to an increase in production of 13.4 Bcf, or 126%. This increase in turn was primarily due to the addition of production from our Meridian acquisition in May 2010, and the full-year effect of the acquisition of our Deep Bossier properties in July 2009. Natural gas production attributable to the acquisition of Meridian for the year was 4.2 Bcf; the Deep Bossier properties produced 12.3 Bcf in 2010, as compared to 4.0 Bcf in 2009. The price of gas we received exclusive of hedging increased 15% in 2010; however, the overall realized price (including hedging gains and losses), decreased 16% from $6.25 per Mcf in 2009 to $5.24 per Mcf in 2010, resulting in a decrease in revenues of approximately $24.2 million.

Oil revenues for the year ended December 31, 2010 increased $41.5 million, or 121%, to $75.8 million from $34.3 million in 2009. The increase in revenue was due to higher production volumes coupled with a higher average realized sales price. Oil production increased to 964 MBbls from 505 MBbls in 2009, an increase of 91%. Of this, 472 MBbls were attributable to the acquisition of Meridian. During 2010, our average realized oil price increased 16% to $78.63 per Bbl from $67.94 per Bbl in 2009, primarily based on market increases to prices before hedging gains and losses. Market oil prices realized exclusive of hedging activities increased 33%, from $59.23 per Bbl to $78.86 per Bbl.

Natural gas liquids revenues increased during 2010 to $6.8 million from $1.7 million for 2009. The increase was primarily due to an increase in volume sold, from 47 MBbls to 147 MBbls; prices also increased between the two periods from $36.05 per Bbl to $46.58 per Bbl.

Other revenues were $1.5 million during 2010 as compared to $1.6 million during 2009. The decrease is primarily the result of decreased income from investments, which includes distributions from a drilling company we partially own and do not consolidate.

Unrealized gain (loss) — oil and natural gas derivative contracts was a gain of $10.1 million for 2010 as compared to a loss of $26.3 million for 2009. 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.

Lease and plant operating expense increased $18.0 million to $41.9 million in 2010 as compared to $23.9 million in 2009, due primarily to lease operating costs of $9.0 million associated with production from the Meridian acquisition, which was acquired in May 2010. In addition, the Deep Bossier properties, acquired in late July 2009, contributed $10.4 million in operating expenses in 2010, as compared to $1.1 million for 2009. The increase at Deep Bossier included approximately $6.8 million in additional gas gathering and marketing expenses, based on a contract which originated in December 2009. Increased production from the Deep Bossier properties, from 4.0 Bcf to 12.3 Bcf, as well as increased production from other non-Meridian properties, also impacted lease operating expense. On a unit basis, lease and plant operating expense decreased from $1.71 per Mcfe to $1.37 per Mcfe.

Production and ad valorem taxes increased $6.3 million to $11.1 million, or 134%, for 2010, as compared to $4.8 million for 2009. The increase on a percentage basis follows the increase in our revenues from products, which was 104%. On a per unit basis, the expense increased to $0.36 for 2010 from $0.34 per Mcfe for 2009.

Workover expense decreased slightly from 2009 to 2010, from $9.0 million to $7.4 million, respectively. This expense varies depending on activities in the field.

Exploration expense includes the costs of our geology departments, costs of geological and geophysical data, delay rentals, expired leases, and dry holes. Exploration expense increased $18.2 million for 2010 to $31.0 million from $12.8 million for 2009. The increase is primarily due to an exploratory dry hole in South Louisiana which cost $4.8 million, two exploratory dry holes in East Texas which cost a combined $10.2 million, and increased seismic expenditures.

Depreciation, depletion and amortization increased $10.4 million to $59.1 million for 2010 as compared to an expense of $48.7 million for 2009. On a per unit basis, this expense declined from $3.50 to $1.93 per Mcfe. This is the result of the acquisition of the Meridian and Deep Bossier properties.

Impairment expense increased $2.2 million to $8.4 million in 2010 from $6.2 million in 2009. This expense varies with the results of exploratory drilling, as well as with price declines which may render some projects uneconomic, resulting in impairment. See “Critical Accounting Policies and Estimates — Impairment” below for more details related to 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 $1.4 million and $0.5 million for 2010 and 2009, respectively. The increase was due to the acquisition of Meridian.

General and administrative expense increased $11.4 million for 2010 to $20.1 million from $8.7 million for 2009. The increase in general and administrative expense resulted principally from increased payroll and burden costs of $8.8 million, which are predominately related to increased headcount due to the Meridian acquisition, the addition of other personnel, and to annual bonuses paid in the third quarter of 2010. The increase in payroll is partially offset by allocations to expense categories. Other general and administrative costs related to the acquisition of Meridian also increased, including office rent, which increased $1.2 million in 2010 as compared to 2009. Consulting expenses such as legal, engineering and other professional services increased a total of $2.0 million, primarily due to increased costs of outside drilling and reservoir engineers, and to services related to accounting and tax work and to acquisition reviews, including the acquisition of Meridian. On a unit basis, general and administrative expense increased to $0.66 per Mcfe for 2010, from $0.63 per Mcfe, for 2009. The increase in total general and administrative expense was largely mitigated on a unit basis by the increase in production.

Interest expense, net increased $13.3 million for 2010 to $27.1 million from $13.8 million for 2009, primarily due to new interest in the fourth quarter of 2010 from our notes payable issued in October 2010 ($6.2 million additional interest), to increases in the amount outstanding under our credit facility (approximately $0.6 million additional interest), to increased amortization of deferred loan costs (approximately $3.5 million), to a prepayment penalty on retirement of our subordinate credit facility ($0.8 million), to increased interest on our notes payable to the founder of the company ($0.2 million) and to increased interest rate hedge losses (approximately $1.5 million).

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

Our 2012 capital budget is primarily focused on the development of existing core areas through exploitation and development. Currently, we plan to spend a total of approximately $247 million during 2012, of which approximately $185.8 million has been expended or accrued through September 30, 2012, including acquisitions. Approximately 75% of our capital budget for the remainder of 2012 is allocated to our properties in Hilltop field,

East Texas, the Eagle Ford Shale in South Texas, Oklahoma, and South Louisiana. Our future drilling plans, plans of our drilling operators and capital budgets are subject to change based upon various factors, some of which are beyond our control, including drilling results, oil and natural gas prices, the availability and cost of capital, drilling and production costs, availability of drilling services and equipment, actions of our operators, gathering system and pipeline transportation constraints and regulatory approvals. Because a large percentage of our acreage is held by production, we have the ability to materially decrease our drilling and recompletion budget in response to market conditions with minimal risk of losing significant acreage.

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

In October 2010, we adjusted our capital structure by issuing $300 million of 9⁵/₈% senior notes due 2018 (the “existing notes”). The existing notes were issued at a discount of $2.1 million, bringing the effective rate to 9³/₄%. The net proceeds from the sale of the existing notes were used to repay in full the $40 million drawn under our $150 million second lien term loan facility with UnionBanCal Equities Inc., as the administrative agent, which was due to mature in March 2013, to repay $199.7 million of the borrowings outstanding under our senior secured revolving credit facility, and to provide a $50 million distribution to AMIH.

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

In connection with the issuance of the existing notes, we entered into a registration agreement with the initial purchasers of the existing notes, pursuant to which we filed a registration statement with the SEC to allow for registration of “exchange notes” with terms substantially identical to the existing notes. The exchange offer was consummated on August 12, 2011, and all of the tendered original senior notes were exchanged.

In October 2012, we issued an additional $150 million of senior notes due 2018 (the “old notes”). The old notes were issued under the same indenture that governs the existing notes and were issued at 99% of par value and bear interest at a rate of 9⁵/₈% . The net proceeds from the sale of the old notes were used to repay a portion of our revolving credit facility.

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

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

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

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

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

Operating activities provided cash of $150.7 million in 2011, as compared to $61.2 million for 2010. The $89.5 million increase in operating cash flows was primarily attributable to our increased earnings. 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 $63.9 million in earnings and a positive impact on cash flow. This was augmented by changes in our working capital accounts, which used $4.6 million of cash flows as compared to having used $30.2 million in cash in 2010. This reversal resulted in a total increase of $25.6 million in cash flow from changes in working capital, which as noted above, augmented the positive effects of increased earnings.

Operating activities provided cash of $61.2 million in 2010, as compared to $34.3 million for 2009. The $26.9 million increase in operating cash flows was primarily attributable to our increase in earnings. 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 $58.5 million in earnings and a positive impact on cash flow. However, partially offsetting these items were changes in our working capital accounts, which used $30.2 million of cash flows as compared to having provided $1.4 million in cash in 2009. This reversal resulted in a total decrease of $31.6 million in cash flow, which as noted above, partially offset the positive effects of increased earnings. Although accounts payable and accrued liabilities increased $54.6 million in 2010, this was primarily due to the acquisition of Meridian, and to an increase in accrued liabilities for capital expenditures, which do not impact operating cash flow. Underlying activity included a net use of cash to meet working capital requirements.

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

Investing activities used cash of $266.1 million for the year ended December 31, 2011 as compared to cash used in investing of $208.4 million for the year ended December 31, 2010. The increase in cash used in investing activities was primarily related to drilling and development expenditures, which increased by $83.7 million. This was partially offset by a decrease in acquisition expenditures of $29.0 million. Acquisitions in 2010 included $101.4 for Meridian, as compared to a total of $72.4 million in 2011, primarily for the Sydson and TODD acquisitions, for which cash expenditures were $50 million.

Investing activities used cash of $208.4 million for the year ended December 31, 2010 as compared to cash used in investing of $86.6 million for the year ended December 31, 2009. The increase in cash used in investing activities was primarily related to the acquisition of Meridian, for which cash expenditures were $101.4 million. Drilling and development expenditures also increased by $9.8 million, and proceeds from sales of properties decreased $10.7 million.

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

Financing activities provided cash of $113.3 million during 2011 as compared to cash provided by financing of $147.8 million during 2010, a decrease of $34.5 million. The decrease in cash flows provided by financing activities was primarily due to higher cash flows from operations of $89.5 million, partially offset by an increase in cash used in investing of $57.7 million. The net increase in cash flow from these activities resulted in decreased borrowing in 2011 as compared to 2010.

Financing activities provided cash of $147.8 million during 2010 as compared to cash provided by financing of $51.8 million during 2009, an increase of $96.0 million. The increase in cash flows provided by financing activities was primarily due to the acquisition of Meridian, which was financed by increased borrowing under our credit facility, as well as a $50 million contribution from our private equity partner, AMIH. The cash and debt retirement paid for the Meridian acquisition was $101.4 million. The proceeds from the issuance of the existing notes were used to retire other debt and to provide a $50 million distribution to AMIH, and had no net effect on cash flows from financing.

Due to the risk of low oil and natural gas prices, we periodically enter into price-risk management transactions (e.g., swaps, collars, puts, calls, and financial basis swap contracts) for a portion of our oil and natural gas production. In certain cases, this allows us to achieve a more predictable cash flow, as well as to reduce exposure from price fluctuations. The commodity derivative instruments apply to only a portion of our production, and provide only partial price protection against declines in oil and natural gas prices, and may partially limit our potential gains from future increases in prices. At December 31, 2011, commodity derivative instruments were in place covering approximately 73% of our projected oil and natural gas production from proved developed properties for 2016. At September 30, 2012, we had hedged approximately 90% of our forecasted PDP production through 2017. See Note 6 to our consolidated financial statements as of December 31, 2011 and September 30, 2012, “Derivative Financial Instruments”, for further information.

The following table summarizes our contractual obligations as of December 31, 2011:

In addition to the items above, we have a contingent commitment to pay an amount up to a maximum of approximately $3.5 million for properties acquired in 2008 and prior years. The additional purchase consideration will be paid if certain product price conditions are met.

As of December 31, 2011, we had no guarantees of third party obligations. Our off-balance sheet arrangements at December 31, 2011 consist of bonds posted in the aggregate amount of $9.2 million, primarily to cover future abandonment costs.

We have no plans to enter into any off-balance sheet arrangements in the foreseeable future.

The discussion and analysis of our financial condition and results of operations are based upon our consolidated financial statements, which have been prepared in accordance with accounting principles generally accepted in the United States (“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.

The preparation of our consolidated financial statements requires us to make estimates and assumptions that affect our reported results of operations and the amount of reported assets, liabilities and proved oil and natural gas reserves. Some accounting policies involve judgments and uncertainties to such an extent that there is reasonable likelihood that materially different amounts could have been reported under different conditions, or if

different assumptions had been used. Actual results may differ from the estimates and assumptions used in the preparation of our consolidated financial statements. Described below are the most significant policies we apply in preparing our consolidated financial statements, some of which are subject to alternative treatments under accounting principles generally accepted in the United States. We also describe the most significant estimates and assumptions we make in applying these policies.

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 and depletion 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, the value of oil and natural gas properties, oil and natural gas revenues, bad debts, derivative contracts, income taxes and contingencies and litigation. We base our estimates on historical experience and various other assumptions that are believed to be reasonable under the circumstances. Actual results may differ from these estimates.

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

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

Exploration Expense. Exploration expenses, other than exploration drilling costs, are charged to expense as incurred. These expenses 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.

Proved Oil and Gas Properties. Costs incurred to obtain access to proved reserves and to provide facilities for extracting, treating, gathering, and storing oil and 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 gas properties are reviewed at least annually for impairment in accordance with ASC 360-10-35, Property, Plant and Equipment, Subsequent Measurement, 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 at least annually 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 statement of operations.

Depreciation, Depletion and Amortization. Depreciation, depletion and amortization (“DD&A”) of capitalized costs of proved oil and 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.

Revenue Recognition. We recognize oil, gas and natural gas liquids revenues when products are delivered at a fixed or determinable price, title has transferred and collectability is reasonably assured (sales method). Oil and natural gas sold is not significantly different from the Company’s share of production. Revenue from drilling rigs has been recorded when services are performed.

Derivative Financial Instruments. We use derivative contracts to hedge the effects of fluctuations in the prices of oil, natural gas and interest rates. We account for such derivative instruments in accordance with ASC 815, Derivatives and Hedging, which establishes accounting and disclosure requirements for derivative instruments and requires them to be measured at fair value and recorded as assets or liabilities in the statements of financial position (see Note 5 of the accompanying Notes to Consolidated Financial Statements for further information on fair value).

Under ASC 815, hedge accounting is used to defer recognition of unrealized changes in the fair value of such financial instruments, for those contracts which qualify as fair value or cash flow hedges, as defined in the guidance. Historically, we have not designated any of our derivative contracts as fair value or cash flow hedges. Accordingly, the unrealized changes in fair value of the contracts are included in net income in the period of the change as “Unrealized gain (loss) — oil and natural gas derivative contracts” for oil and gas contracts, and in interest expense for interest derivative contracts. Realized gains and losses are recorded in income in the period of settlement, and included in the related revenue account or in interest expense. Cash flows from settlements of derivative contracts are classified with the income or expense item to which such settlements directly relate.

Income Taxes. We have elected under the Internal Revenue Code provisions to be treated as individual partnerships for tax purposes. Accordingly, items of income, expense, gains and losses flow through to the partners and are taxed at the partner level. Accordingly, no tax provision for federal income taxes is included in the consolidated financial statements.

We are subject to the Texas margin tax, which is considered a state income tax, and is included in provision for state income tax on the statement of operations. We record state income tax (current and deferred) based on taxable income as defined under the rules for the margin tax.

Acquisitions. Acquisitions are accounted for as purchases and, accordingly, the results of operations are included in our statement of operations from the closing date of the acquisition. Purchase prices are allocated to acquired assets and assumed liabilities based on their estimated fair value at the time of the acquisition.

Asset Retirement Obligations. We estimate the present value of future costs of dismantlement and abandonment of our wells, facilities, and other tangible, long-lived assets, recording them as liabilities in the period incurred. We follow ASC 410, Asset Retirement and Environmental Obligations. ASC 410 requires that an asset retirement obligation (“ARO”) associated with the retirement of a tangible long-lived asset be

recognized as a liability in the period in which it is incurred or becomes determinable (as defined by the standard), with an associated increase in the carrying amount of the related long-lived asset. The cost of the tangible asset, including the initially recognized asset retirement cost, is depreciated over the useful life of the asset and accretion expense is recognized over time as the discounted liability is accreted to its expected settlement value. The fair value of the ARO is measured using expected future cash outflows for abandonment discounted generally at our cost of capital at the time of recognition.

Investment. Our investment consists of a 10% ownership interest in a drilling company, Orion Drilling Company, LP (“Orion”). The investment is accounted for under the cost method. Under this method, our share of earnings or losses of the investment are not included in the statements of operations. Distributions from Orion are recognized in current period earnings as declared.

Deferred Financing Costs. Deferred financing costs are amortized using the straight-line method over the term of the related debt, so long as this approximates the interest rate method.

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 of our unaudited consolidated financial statements as of September 30, 2012.

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 are exposed to certain market risks that are inherent in our consolidated financial statements that arise in the normal course of business. We may enter into derivative instruments to manage or reduce market risk, but do not enter into derivative agreements for speculative purposes.

We do not designate these or future derivative instruments as hedges for accounting purposes. Accordingly, the changes in the fair value of these instruments are recognized currently in earnings.

Our major market risk exposure is to prices for oil, natural gas and natural gas liquids. These prices have historically been volatile. As such, future earnings are subject to change due to changes in these prices. Realized prices are primarily driven by the prevailing worldwide price for oil and regional spot prices for natural gas. We have used, and expect to continue to use, oil and natural gas derivative contracts to reduce our exposure to the risks of changes in the prices of oil and natural gas. Pursuant to our risk management policy, we engage in these activities as a hedging mechanism against price volatility associated with pre-existing or anticipated sales of oil and natural gas.

As of September 30, 2012, we have hedged approximately 90% of our forecasted PDP production through 2017 at average annual prices ranging from $4.17 per MMBtu to $6.09 per MMBtu and $90.00 per Bbl to $104.75 per Bbl. Forecasted production from proved reserves is estimated in our December 2011 reserve report and updated to September 2012 using prices, costs and other assumptions required by SEC rules. Our actual production will vary from the amounts estimated in the reports, perhaps materially. Please read the disclosures under “Our estimated oil and natural gas reserve quantities and future production rates are based on many assumptions that may prove to be inaccurate. Any material inaccuracies in these reserve estimates or the underlying assumptions will materially affect the quantities and present value of our reserves” in “Item 1A. Risk Factors” above.

The fair values of our oil and natural gas derivative contracts and basis swaps were net assets of $33 million and $53 million at September 30, 2012 and December 31, 2011, respectively. 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 fair value (generally correlated to our estimated future net cash flows from such instruments) of our oil and natural gas commodity contracts of approximately $30 million (unrealized loss) or $28 million (unrealized gain), respectively, as of December 31, 2011.

We are subject to interest rate risk on our long-term fixed interest rate debt and variable interest rate borrowings. We use interest rate swaps to mitigate the effect of fluctuating interest rates on interest expense. Floating to fixed rate swaps hedge the variable interest rate under our credit facility. The total fair value of our interest rate swaps at December 31, 2011 was a liability of $1.3 million. These contracts had expired as of September 30, 2012.

On May 13, 2010, we acquired The Meridian Resource Corporation, a public exploration and production company with properties in or proximate to our own areas of operation and proved reserves of 75 Bcfe as of December 31, 2009, for $158 million. The acquisition was funded with borrowings under our senior secured revolving credit facility as well as a $50 million equity contribution from AMIH. As a result of the acquisition, as of June 30, 2010, we increased total proved reserves 36%, achieved a more balanced portfolio mix by increasing our total proved oil reserves by 69%, and increased our proved undeveloped reserves by 51%. We believe the

acquisition gives us significant growth potential with the addition of these proved undeveloped reserves, as well as the addition of a large library of 3-D and 2-D seismic data, much of which we are reprocessing and utilizing for the exploitation of known fields and identification and development of new prospects in certain of our operating areas.

On April 21, 2011, we completed the purchase of certain oil and natural gas assets primarily located in Texas and South Louisiana in which we had shared interests from Sydson Energy and certain of its related parties for $27.5 million. Total net proved reserves acquired were 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 (Eagleville field) 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.

On June 17, 2011, we completed the purchase of certain oil and natural gas assets primarily located in Texas and South Louisiana in which we had shared interests from TODD and certain other parties for $22.5 million. Total net proved reserves acquired were 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 (Eagleville field) by 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.

On July 23, 2009, we made a payment of $25.5 million and took assignment of substantially all working interests that had been held by Chesapeake Energy Corporation (“Chesapeake”) in an approximate 50,000 acre area of Leon and Robertson Counties, Texas known as 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 Exploration Ltd. (“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 Oil and Gas (USA) (“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. The Hilltop properties contribute 85 Bcfe, or 24%, of our proved reserves as of December 31, 2011. The number of wells has increased from 30 at acquisition to 58 as of December 31, 2011.

Our objective is to increase reserves and production by applying sound engineering and geological analyses, combined with safe and cost-effective operations, in areas we have identified as under-developed and over-looked.

We believe that the following strengths provide us with significant competitive advantages and position us to continue to achieve our business objective and execute our strategies:

The following table describes our reserves and production profile as of December 31, 2011:

Our core properties are located in South Louisiana, East Texas, Oklahoma, and the Eagle Ford Shale play in South Texas. The majority of our assets are producing properties located in mature fields characterized by what we believe to be low geologic risk and a large inventory of repeatable development opportunities with multiple pay zones.

We have three major areas of operation in South Louisiana, in fields originally developed by major oil companies, where, as of December 31, 2011, we have working interests in 61 producing wells and 54,725 gross developed and undeveloped acres (31,879 acres, net). These areas have multiple low-risk exploration and development targets, potential for exploiting substantial bypassed and overlooked oil pay zones, and opportunities to increase profitability through facilities de-bottlenecking, production enhancements and drilling. We have identified 34 PDNP opportunities and 13 PUD locations in this area as of December 31, 2011. Hurricane Isaac disrupted our production in South Louisiana during the third quarter of 2012, and all properties have been returned to production. We estimate the total delay of production was approximately 32 MBOE. Total production net to our interest from all of our properties in South Louisiana for the first three quarters of 2012 was 749 MBbl’s (including natural gas liquids) and 4.6 Bcf of natural gas.

Weeks Island Field. Weeks Island, located in Iberia Parish, contains some of our largest developed oil reserves. It is a historically-prolific oil field with 55 potential pay zones that are structurally trapped against a piercement salt dome, which we believe offer significant future opportunities for added production and reserves. The main field pay zones are characterized by high, stable production rates due to the predominant water-drive production mechanism and high-porosity sands. The field was discovered in 1945 by Shell and subsequently developed by Shell and Exxon. We acquired these properties in 2010 with our acquisition of Meridian, which had purchased them in 1998. We operate all of the wells in this field in which we have an interest. Additionally, Weeks Island oil sales prices are based on the Louisiana Light Sweet crude market price index, which has

trended appreciably higher than the West Texas Intermediate index in 2011. As of December 31, 2011, we owned an average 87% working interest in 24 producing wells with 18 PDNP opportunities, and 10 PUD locations, over approximately 5,263 net acres.

South Hayes Field. The South Hayes field is located in Cameron Parish. We produce gas with an average liquid content of 34 barrels per million cubic feet of natural gas from this field. We own and control operations with an average 43% working interest in the South Hayes field as of December 31, 2011. South Hayes is in the center of prolific fields originally developed by Shell, Texaco, and Exxon, most notably the Chalkley and Thornwell fields, and has been the focus of our geologic and geophysical efforts for 15 years, including a proprietary 3-D survey covering 90 square miles integrated with over 300 square miles of previously-existing 3-D data. The field has potential for multiple low-risk targets in historically productive zones, as well as exploratory activity. As of December 31, 2011, we have four producing wells as well as four PDNP opportunities in the field. Additionally, we have invested in fluid gathering and treating infrastructure that will facilitate future field development.

Ramos Field. The Ramos field is a multi-well, multi-zone producing field located in Terrebonne Parish, Louisiana, which produces condensate-rich gas. As of December 31, 2011, we owned and operated an average 81% working interest in six producing wells and have four PDNP recompletions and two PUD locations. We have increased the profitability of Ramos through facilities de-bottlenecking, production well and facility enhancements, and a recompletion since acquiring it with our purchase of Meridian in 2010.

Our operations in this area are low-risk expansions of well-established fields through a consistent, integrated, multi-discipline technical approach to field re-development. Our principal assets in the area are the Urbana and Cold Springs fields, which are adjacent fields with similar geologic formations producing condensate-rich gas principally from the Wilcox formation. These fields were originally discovered in the 1940s and 1950s by major oil companies and were developed based on technology available at the time. The area is served by a robust pipeline and services infrastructure, and established local operators familiar with the fields, wells, and facilities. Wells are typically brought online relatively rapidly, and production is long-lived as we progressively produce from multiple pay zones. We have materially increased reserves and extended the life of these fields by utilizing modern well log and geochemical analyses, modern fracture stimulation techniques, and the integration of 3-D seismic for exploitation as well as exploration. Through Meridian we acquired an interest in over 26,508 net acres in the Austin Chalk and Wilcox formations, and have integrated these field operations with those of the nearby Urbana field. In 2011, we purchased additional acreage, one producing well, and a significant seismic survey with our acquisition of the Raven Forest field. We have interests in 132 producing wells covering 47,130 net developed and undeveloped acres, and have identified 118 PDNP opportunities and 16 PUD locations as of December 31, 2011.

Urbana Field. We are the operator of the Urbana field, located in San Jacinto County, Texas and have an average 97% working interest in 25 producing wells as of December 31, 2011. Urbana is a known structure with multiple pay zones, and as many as 35 productive reservoirs from 7,200 feet to 11,600 feet deep. The liquids/oil to natural gas ratio of approximately 41 barrels per million cubic feet of natural gas (based on 2011 production) from Urbana makes our wells economic even at low natural gas prices.

Cold Springs and Cold Springs West Fields. The Cold Springs and Cold Springs West fields are located west of the Urbana field in San Jacinto County, Texas. We are the largest working interest owner with an average 75% working interest in 47 producing wells as of December 31, 2011. We acquired additional interests in 2011 and became the operator of the Cold Springs field.

The Cold Springs field is a known structure with multiple pay zones, similar to the Urbana field but we believe with larger and greater development and expansion potential. The liquids/oil to natural gas makeup of our production in this field in 2011 was 95 barrels per million cubic feet of natural gas, which makes our wells economic even at low natural gas prices. In 2010 and 2011, we extended Cold Springs with the annex called Cold Springs West, with nine new wells. The area is now contributing higher oil production. We acquired additional seismic data in 2011, which has allowed us to identify opportunities for shallow, relatively inexpensive drilling and recompletion activity.

Our assets in Oklahoma are located in large oil fields with multiple pay zones at depths from less than 2,000 feet to 7,500 feet. The fields are located in the Sooner Trend area of the Anadarko Basin and were initially developed by Conoco, Texaco and Exxon. These assets are predominantly shallow-decline, long-lived oil fields originally drilled on uniform, 80-acre spacing and waterflooded to varying degrees. We own an 84% interest in the Lincoln North Unit which consists of approximately 81 unit producing wells and six non-unit producing wells. We had 12 PDNP opportunities and 19 PUD locations as of December 31, 2011 in Lincoln North. We own an 89% interest in the Lincoln SE Unit, which consists of 34 producing wells, 12 PDNP opportunities and no PUD locations, and we own an 88% interest in the East Hennessey Unit, which consists of 62 producing wells, four PDNP opportunities and four PUD locations. In the aggregate, our Oklahoma properties represent approximately 19% of the PV-10 value of our total proved reserves and 34% of our total proved reserves for oil and natural gas liquids as of December 31, 2011.

Our activity in these fields include adding production from the Mississippian Lime formation by deepening existing wellbores and downspacing to 40 acre units, and by recompleting existing wellbores to other previously unexploited zones. This is a low-cost and low-risk strategy to increase oil production. Augmenting the economics of this strategy, we have already implemented technology for commingling oil production from multiple zones through a single tubing string. In addition, we are continuing to expand waterflooding in the East Hennessey Unit, and to pilot-test waterflooding in both Lincoln North and Lincoln Southeast.

Our Hilltop Field, in Leon and Robertson counties of East Texas, acquired in 2009, is our largest natural gas asset due to the reserves in the Deep Bossier and Knowles formations, at 24% of total reserves as of December 31, 2011. The field has been significantly developed in the Deep Bossier formation, a prolific producer of primarily dry natural gas which occurs at 15,000-20,000 feet. Our interests here, which are operated primarily by EnCana and Gastar, have increased from 30 to 58 producing wells. Although the Deep Bossier has potential for additional development, we, together with other operators, have redirected our near-term focus to other more liquids-rich zones.

We have a large, contiguous acreage position in the Hilltop and adjacent Amoruso fields in Leon and Robertson Counties, Texas, of approximately 50,010 gross developed and undeveloped acres (16,998 acres, net) as of December 31, 2011. EnCana is the primary operator, managing approximately two-thirds of our wells, with Gastar operating the remainder of the wells in production as of December 31, 2011. Our operating agreements with EnCana and Gastar allow us substantial input related to operations and control of our capital expenditures, including provisions that permit us to either propose or non-consent individual wells. We have drilled two additional wells in 2012 which we operate. Our interests in this area include 58 producing wells, nine PDNP opportunities, and 14 PUD locations, as of December 31, 2011.

Our Eagle Ford Shale assets have grown in significance to our operations, and we believe they will continue to be a growing portion of our portfolio in terms of oil production, oil reserves, and investment for several years. As of December 31, 2011, the field contributes 15% of our total proved oil and natural gas liquids reserves. As part of the Meridian transaction in 2010, we acquired interests primarily in an area of Karnes County, Texas

referred to as the Eagleville field. Our acreage position also includes portions of Goliad and DeWitt Counties. The Eagle Ford is a shale typically developed with horizontal wells, which produce a highly desirable mix of oil, natural gas, and natural gas liquids. We have 24 PUD locations identified as of December 31, 2011. As of December 31, 2011, we owned an average 19% working interest in 23 producing wells in the field, in addition to three wells with overriding royalty interests. We are participating with Murphy Oil Corporation (“Murphy”), the operator of our Eagleville field, in what we expect to be at least a five year program that began in 2011 in which we expect to drill at least 200 wells targeting the Eagle Ford Shale in Karnes County, Texas. At the end of the third quarter of 2012, we had working interests in 51 producing wells in the Eagle Ford Shale, and overriding royalty interests in three additional wells. Through mid-November 2012, nine additional wells in which we have working interests have begun production in this area, and Murphy was operating three drilling rigs on our acreage.

In addition to our core areas, we conduct operations in other areas including the Blackjack Creek field in Florida, the Marcellus Shale in West Virginia, and various fields in South Texas and South Louisiana. We have identified a total of 45 PDNP opportunities and three PUD locations in these areas, as of December 31, 2011. We continually evaluate the operations in these areas to determine future development, expansion, acquisition opportunities, and strategic divestiture plans. We own an approximate 96% working interest in Blackjack Creek, where we are operating a waterflood in this shallow-decline field originally developed by Exxon. We have a 1,447 net acre position (3,011 gross acres) in West Virginia where we successfully drilled five wells in the Marcellus Shale in 2011, two vertical wells and three horizontal wells.

The table below summarizes our estimated proved reserves as of December 31, 2011.

The table below summarizes our estimated net proved reserves as of December 31, 2011.

The table above represents estimates only. Reserves estimates are based upon various assumptions, including assumptions required by the SEC relating to oil and natural gas prices, drilling and operating expenses, capital expenditures, taxes and availability of funds. The process of estimating reserves is complex. This process requires significant decisions and assumptions in the evaluation of available geological, geophysical, engineering and economic data for each reservoir. Furthermore, different reserve engineers may make different estimates of reserves and cash flow based on the same available data and these differences may be significant. Therefore,

these estimates are not precise. Actual future production, oil and natural gas prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable oil and natural gas reserves will most likely vary from those estimated. In addition, we may adjust estimates of proved reserves to reflect production history, results of exploration and development, prevailing oil and natural gas prices and other factors, many of which are beyond our control.

The reserve estimation process begins with our internal engineering department, which prepares much of the data used in estimating reserves. Working and net revenue interests are cross-checked and verified by our land department. Cost data are provided by our accounting department on a preliminary basis and reviewed by the engineering department. Our Chief Operating Officer is the technical person primarily responsible for overseeing the preparation of our reserve estimates. His qualifications include the following:

We engaged two third-party engineering firms to prepare 100% of our 2011 reserves estimates, using the data provided by our engineering department, as well as other data. Their methodologies include reviews of production trends, material balance calculations, analogy to comparable properties, and/or volumetric analysis. Performance methods are preferred. Reserve estimates for developed non-producing properties and for undeveloped properties are based primarily on volumetric analysis or analogy to offset production in the same field.

We maintain internal controls including the following to ensure the reliability of reserves estimations:

In addition, a third-party engineering firm audited 100% of our 2011 reserve estimates. The portion of our estimated proved reserves prepared or audited by each of our third-party engineering firms as of December 31, 2011 is presented below.

Copies of the reports issued by the engineering firms are filed with this report as Exhibits 99.1 — 99.3. The qualifications of the technical person at each of these firms primarily responsible for overseeing his firm’s preparation of our reserve estimates are set forth below.

The audit by Netherland, Sewell & Associates, Inc. conformed to the meaning of “reserves audit” as presented in the SEC’s Regulation S-K, Item 1202.

A reserves audit and a financial audit are separate activities with unique and different processes and results. These two activities should not be confused. As currently defined by the SEC within Regulation S-K, Item 1202, a reserves audit is the process of reviewing certain of the pertinent facts interpreted and assumptions underlying a reserves estimate prepared by another party and the rendering of an opinion about the appropriateness of the methodologies employed, the adequacy and quality of the data relied upon, the depth and thoroughness of the reserves estimation process, the classification of reserves appropriate to the relevant definitions used, and the reasonableness of the estimated reserves quantities. A financial audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. A financial audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation.

At December 31, 2011 we had proved undeveloped reserves (“PUDs”) of 96 Bcfe, or approximately 28% of total proved reserves. The PUDs are primarily in our Hilltop field, in South Louisiana, and in Oklahoma, and in our Eagleville field in the Eagle Ford play in South Texas. Total PUDs at December 31, 2010 were 111 Bcfe, or 34% of our total reserves.

In 2011, we converted 17 Bcfe, or 15% of total year end 2010 PUDs, to proved developed reserves. Costs relating to the development of PUDs were approximately $37 million in 2011. Costs of PUD development in 2011 do not represent the total costs of these conversions, as additional costs may have been recorded in previous years. Estimated future development costs relating to the development of 2011 year-end PUDs are $184 million.

All PUDs but three are scheduled to be drilled by 2016; those three are sidetrack developments in producing wells which will be drilled after the current zones are depleted.

Approximately 5.8 Bcfe of our PUDs at December 31, 2011 originated more than five years ago. The most significant of these is a 5.1 Bcfe waterflood expansion project at the East Hennessey Unit in Oklahoma which has been underway for five years and is proceeding in stages. We expect to reach full implementation of the project over the next five years.

The following table sets forth certain information regarding the production volumes, average prices received and average production costs associated with our sale of oil and natural gas for the periods indicated below.

The following table provides a summary of our production, average sales prices and average production costs for the Hilltop Field in East Texas, which was the only oil and gas field contributing 15% or more of our total proved reserves as of December 31, 2011:

The following tables sets forth, for each of the three years ended December 31, 2011, the number of net productive and dry exploratory and developmental wells completed, regardless of when drilling was initiated (all wells are located in the United States). The information should not be considered indicative of future performance, nor should it be assumed that there is necessarily any correlation between the number of productive wells drilled, quantities of reserves found or economic value. We own one drilling rig which currently is under contract to a third party.

The following table sets forth information with respect to our ownership interest in productive wells, all of which are located in the United States, as of December 31, 2011:

Of the total well count for 2011, seven wells (6.0 net) are multiple completions.

The following table sets forth information with respect to our gross and net developed and undeveloped oil and natural gas acreage under lease as of December 31, 2011, all of which is located in the United States:

As is customary in the oil and natural gas industry, we can generally retain interest in undeveloped acreage through drilling activity that establishes commercial production sufficient to maintain the leases or by paying delay rentals during the remaining primary term of leases. The oil and natural gas leases in which we have an interest are for varying primary terms and, if production under a lease continues from developed lease acreage beyond the primary term, we are entitled to hold the lease for as long as oil or natural gas is produced. The oil and natural gas properties consist primarily of oil and natural gas wells and interests in leasehold acreage, both developed and undeveloped.

The following table sets forth information with respect to our gross and net undeveloped oil and natural gas acreage under lease as of December 31, 2011, all of which is located in the United States, that will expire over the following three years by region unless production is established within the spacing units covering the acreage prior to the expiration dates:

The market for our oil and natural gas production depends on factors beyond our control, including the extent of domestic production and imports of oil and natural gas, the proximity and capacity of natural gas pipelines and other transportation facilities, the demand for oil and natural gas, the marketing of competitive fuels and the effect of state and federal regulation. The oil and natural gas industry also competes with other industries in supplying the energy and fuel requirements of industrial, commercial and individual consumers. The prices received for oil and natural gas sales are generally tied to monthly or daily indices as quoted in industry publications.

Crude oil and natural gas purchasers vary by area. We market substantially all our oil and natural gas production pursuant to marketing contracts.

For the year ended December 31, 2011, based on revenues excluding hedging activities, two major customers accounted for 10% or more of those revenues individually, with contributions of $67.7 million and $40.8 million. We believe that the loss of such customers would not have a material adverse effect on us because alternative purchasers are readily available.

We encounter intense competition from other oil and natural gas companies in all areas of our operations, including the acquisition of producing properties and undeveloped acreage. Our competitors include major integrated oil and natural gas companies, numerous independent oil and natural gas companies and individuals. Many of our competitors are large, well-established companies with substantially larger operating staffs and greater capital resources and have been engaged in the oil and natural gas business for a much longer time than us. These companies may be able to pay more for productive oil and natural gas properties, exploratory prospects and to define, evaluate, bid for and purchase a greater number of properties and prospects than our financial or human resources permit. Our ability to acquire additional properties and to discover reserves in the future will be dependent upon our ability to evaluate and select suitable properties and to consummate transactions in this highly competitive environment.

We are also affected by competition for drilling rigs and the availability of related equipment. In the past, the oil and natural gas industry has experienced shortages of drilling rigs, equipment, pipe and personnel, which have delayed development, exploitation and exploration activities. We are unable to predict when, or if, such shortages may occur or how they would affect our exploitation and development program.

As of December 31, 2011, we had 145 full-time employees. We are not a party to any collective bargaining agreements and have not experienced any strikes or work stoppages. We believe our relationships with our employees are good. From time to time, we utilize the services of independent contractors to perform various field and other services. See “Certain Relationships and Related Party Transactions — Land Consulting Services.”

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

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

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

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

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

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

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

Our operations are subject to stringent and complex federal, state and local laws and regulations that govern the protection of the environment, as well as the discharge of materials into the environment. These laws and regulations may, among other things:

These laws, rules and regulations may also restrict the rate of oil and natural gas production below the rate that would otherwise be possible. The regulatory burden on the oil and natural gas industry increases the cost of doing business in the industry and consequently affects profitability. Additionally, Congress and federal, state and local agencies frequently revise environmental laws and regulations, and such changes could result in increased costs for environmental compliance, such as waste handling, permitting, or cleanup for the oil and natural gas industry and could have a significant impact on our operating costs. In general, the oil and natural gas industry recently has been the subject of increases legislative attention with respect to environmental matters.

The following is a summary of some of the existing laws, rules and regulations to which our business operations are subject.

The federal Resource Conservation and Recovery Act, or RCRA and comparable state statutes regulate the generation, transportation, treatment, storage, disposal and cleanup of hazardous solid waste. Although oil and natural gas waste generally is exempt from regulations as hazardous waste under RCRA, we generate waste as a routine part of our operations that may be subject to RCRA and not all states similarly exempt oil and gas waste from hazardous waste regulation. Although a substantial amount of the waste generated in our operations are regulated as non-hazardous solid waste rather than hazardous waste, there is no guarantee that the Environmental Protection Agency (“EPA”) or individual states will not adopt more stringent requirements for the handling of non-hazardous waste or categorize some of our waste as hazardous in the future. Any such change could result in an increase in our costs to manage and dispose of waste, which could have a material adverse effect on our results of operations and financial position.

Comprehensive Environmental Response, Compensation, and Liability Act (“CERCLA”)

CERCLA imposes joint and several liability for costs of investigation and remediation and for natural resource damages without regard to fault or legality of the original conduct, on certain classes of persons with respect to the release into the environment of substances designated under CERCLA as hazardous substances (“Hazardous Substances”). These classes of persons, or so-called potentially responsible parties (“PRPs”) include

the current and past owners or operators of a site where the release occurred and anyone who disposed or arranged for the disposal of a hazardous substance found at a site where a release has occurred. CERCLA also authorizes the EPA and, in some instances, third parties to take actions in response to threats to public health or the environment and to seek to recover from the PRPs the costs of such action. Many states have adopted comparable or more stringent state statutes.

Although CERCLA generally exempts “petroleum” from the definition of Hazardous Substance, in the course of our operations, we have generated and will generate wastes that may fall within CERCLA’s definition of Hazardous Substances and may have disposed of these wastes at disposal sites owned and operated by others. Comparable state statutes may not provide a comparable exemption for petroleum. We may also be the owner or operator of sites on which Hazardous Substances have been released. To our knowledge, neither we nor our predecessors have been designated as a PRP by the EPA under CERCLA; we also do not know of any prior owners or operators of our properties that are named as PRPs related to their ownership or operation of such properties. In the event contamination is discovered at a site on which we are or have been an owner or operator or to which we sent Hazardous Substances, we could be liable for the costs of investigation and remediation and natural resources damages.

We currently own, lease, or operate numerous properties that have been used for oil and natural gas exploration and production for many years. Although we believe we have utilized operating and waste disposal practices that were standard in the industry at the time, Hazardous Substances, wastes or hydrocarbons may have been released on or under the properties owned or leased by us, or on or under other locations, including offsite locations, where such materials have been taken for disposal. In addition, some of these properties have been operated by third parties or by previous owners or operators whose treatment and disposal of Hazardous Substances, wastes, or hydrocarbons were not under our control. These properties and the materials disposed or released on them may be subject to CERCLA or RCRA and analogous state laws. In the future, we could be required to remediate property, including groundwater, containing or impacted by previously disposed materials (including wastes disposed or released by prior owners or operators, or property contamination, including groundwater contamination by prior owners or operators) or to perform remedial plugging operations to prevent future or mitigate existing contamination.

The Federal Water Pollution Control Act (the “Clean Water Act”) and analogous state laws impose restrictions and strict controls with respect to the discharge of pollutants, including spills and leaks of produced water and other oil and natural gas wastes, into waters of the United States, a term broadly defined. The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by EPA or an analogous state agency. The Clean Water Act also prohibits the discharge of dredge and fill material in regulated waters, including wetlands, unless authorized by a permit issued by the U.S. Army Corps of Engineers. Federal and state regulatory agencies can impose administrative, civil and criminal penalties, as well as require remedial or mitigation measures, for non-compliance with discharge permits or other requirements of the Clean Water Act and analogous state laws and regulations. In the event of an unauthorized discharge of wastes, we may be liable for penalties and cleanup and response costs.

The primary federal law related to oil spill liability is the Oil Pollution Act (the “OPA”) which amends and augments oil spill provisions of the Clean Water Act and imposes certain duties and liabilities on certain “responsible parties” related to the prevention of oil spills and damages resulting from such spills in or threatening United States waters or adjoining shorelines. A liable “responsible party” includes the owner or operator of a facility, vessel or pipeline that is a source of an oil discharge or that poses the substantial threat of discharge, or in the case of offshore facilities, the lessee or permittee of the area in which a discharging facility is located. OPA assigns joint and several liability, without regard to fault, to each liable party for oil removal costs

and a variety of public and private damages. Although defenses exist to the liability imposed by OPA, they are limited. In the event of an oil discharge or substantial threat of discharge, we may be liable for costs and damages.

Our operations are subject to local, state and federal regulations for the control of emissions from sources of air pollution. Federal and state laws require new and modified sources of air pollutants to obtain permits prior to commencing construction. Major sources of air pollutants are subject to more stringent, federally imposed requirements including additional permits. Federal and state laws designed to control hazardous air pollutants, might require installation of additional controls. Administrative enforcement actions for failure to comply strictly with air pollution regulations or permits are generally resolved by payment of monetary fines and correction of any identified deficiencies. Alternatively, regulatory agencies could bring lawsuits for civil penalties or require us to forego construction, modification or operation of certain air emission sources.

Many of our development projects require hydraulic fracturing procedures to economically develop the formations. Generally, we perform two types of hydraulic fracturing. In our Eagle Ford shale (Eagleville Field, south Texas), Woodbine (Hilltop Field, East Texas), and Marcellus Shale (West Virginia) plays, we perform hydraulic fracturing in horizontally drilled wells. These procedures are more extensive, time-consuming and expensive than hydraulic fracturing of vertical wells. We perform hydraulic fracturing in vertical wells where the target zones are the Wilcox and Frio formations; this is done in various of our East Texas and South Texas fields, including primarily Urbana and Cold Springs (both in East Texas). We also have performed hydraulic fracturing in vertical wells completed in the Deep Bossier formation in our Hilltop field.

During 2011, we participated in the hydraulic fracturing of 24 wells in our Eagle Ford Shale properties, which are operated primarily by Murphy Oil. These horizontal hydraulic fracturing operations cost approximately $3 million each and consume approximately 165,000 barrels of water at depths of 11,000-12,000 feet. The total drilling and completion costs of these wells are approximately $9 million. Our Eagle Ford Shale properties are primarily in Karnes County, Texas. The water table depth there is between 250 and 1,100 feet deep. Our development drilling in this field in 2012 will be significant to us. Murphy Oil has engaged up to three rigs to drill continuously in this area and each well will require hydraulic fracturing. We expect to perform at least another 24 hydraulic fracturing operations in this field in 2012.

Also during 2011, we participated in approximately 15 hydraulic fracturing operations in our Hilltop Field, operated by Gastar and EnCana. These were in the Deep Bossier formation. Hydraulic fracturing operations in the Deep Bossier are vertical and require fewer stages, using approximately 2,000-8,000 barrels of water at a depth of approximately 18,000 feet. The total cost to drill and complete these wells is $9-11 million, of which the hydraulic fracturing operation is typically $1-2 million.

We are expanding development of our Hilltop properties to include the Woodbine formation, where we expect to drill and operate several wells in 2012. Hydraulic fracturing operations for the Woodbine are horizontal and are similar in water usage and costs to those for the Eagle Ford formation; the Woodbine occurs at a depth of about 7,500 feet.

Our Hilltop properties are in Leon and Robertson Counties, Texas. Usable water occurs at various intervals in this area, the deepest being approximately 2,800 feet.

In 2011, we performed five hydraulic fracturing operations in our Marcellus Shale play in West Virginia. Three of these were the more extensive horizontal hydraulic fracturing operations, similar to those performed in the Eagle Ford; two were vertical hydraulic fracturing operations, and used about 10,000 barrels of water each. We plan limited activity in West Virginia in 2012, but future hydraulic fracturing operations there will be the more extensive horizontal hydraulic fracturing operations.

Currently, most hydraulic fracturing activities are regulated at the state level, as the Safe Drinking Water Act (“SDWA”) exempts most hydraulic fracturing (except for hydraulic fracturing activities involving the use of diesel) from the definition of underground injection. The EPA had released draft guidance on permitting of hydraulic fracturing activities using diesel. Congress has periodically considered legislation to amend the federal SDWA to remove the exemption from permitting and regulation provided to injection for hydraulic fracturing and to require the disclosure and reporting of the chemicals used in hydraulic fracturing. This type of legislation if adopted could lead to additional regulation and permitting requirements that could result in operational delays or increased operating costs, making it more difficult to perform hydraulic fracturing and increasing our costs of compliance and operation.

The EPA has commenced a wide-ranging study on the effects of hydraulic fracturing on drinking water resources. A first progress report of the study is expected in late 2012, with a final draft expected in 2014. In addition, in December 2011, the EPA published an unrelated draft report concluding that hydraulic fracturing caused groundwater pollution in a natural gas field in Wyoming; this study remains subject to review and public comment. In March 2012, the EPA agreed to re-sample its Wyoming wells in partnership with the USGS, the State of Wyoming and various tribes. The comment period on the Wyoming study closes on January 15, 2013.

The EPA also announced that one of its enforcement initiatives for 2011 to 2013 would be to focus on environmental compliance by the energy extraction sector. This study and enforcement initiative could result in additional regulatory scrutiny that could make it difficult to perform hydraulic fracturing and increase our costs of compliance and doing business. Consequently, these studies and initiatives could spur further legislative or regulatory action regarding hydraulic fracturing or similar production operations.

Many states and other local regulatory authorities have enacted or are considering regulations on hydraulic fracturing, including disclosure requirements and regulations that could restrict or prohibit hydraulic fracturing in certain circumstances. In compliance with the law enacted in Texas in June 2011 and regulations adopted in December 2011, we have disclosed and will continue to disclose hydraulic fracturing data to the Ground Water Protection Council and the Interstate Oil and Gas Compact Commission chemical registry. This disclosure is required for each chemical ingredient that is subject to the requirements of OSHA regulations, as well as the total volume of water used in the hydraulic fracturing treatment. A copy of the completed form will be submitted to the Railroad Commission of Texas with the completion report for the well. Additionally, a list of all other chemical ingredients not required by the registry will also be provided to the Railroad Commission for disclosure on a publicly accessible website.

We diligently review best practices and industry standards, and comply with all regulatory requirements in the protection of potable water sources. Protective practices include, but are not limited to, setting multiple strings of protection pipe across the potable water sources and cementing these pipes from setting depth to surface, continuously monitoring the hydraulic fracturing process in real time, and disposing of all non-commercially produced fluids in certified disposal wells at depths below the potable water sources. There have not been any incidents, citations or suits related to our hydraulic fracturing activities involving environmental concerns.

If new legislation is enacted or other new requirements or restrictions regarding hydraulic fracturing are adopted, we could incur substantial compliance costs and the requirements could negatively impact our ability to conduct fracturing activities on our assets.

Oil and natural gas exploration and production activities on federal lands (including offshore leasing) may be subject to the National Environmental Policy Act (the “NEPA”), which requires federal agencies, including the Department of Interior, to evaluate major agency actions having the potential to significantly impact the environment. In the course of such evaluations, an agency will prepare an Environmental Assessment that assesses the potential direct, indirect and cumulative impacts of a proposed project and, if necessary, will prepare

a more detailed Environmental Impact Statement that may be made available for public review and comment. All of our current exploration and production activities, as well as proposed exploration and development plans, on federal lands require governmental permits that are subject to the requirements of NEPA. As a result of the events in the Gulf of Mexico, the NEPA process is being reviewed and may become more stringent. This process has the potential to delay or impose additional conditions upon the development of oil and natural gas projects.

More stringent laws and regulations relating to climate change and greenhouse gases (“GHGs”) may be adopted in the future and could cause us to incur material expenses in complying with them. Both houses of Congress have actively considered legislation to reduce emissions of GHGs, but no legislation has yet passed. In the absence of comprehensive federal legislation on GHG emission control, the EPA has been moving forward with rulemaking under the CAA to regulate GHGs as pollutants under the CAA. The EPA has adopted regulations that would require a reduction in emissions of GHGs from motor vehicles, thus triggering permit requirements for GHGs from certain stationary sources. In June 2010, EPA adopted the Prevention of Significant Deterioration and Title V Greenhouse Gas Tailoring Rule, which phases in permitting requirements for stationary sources of GHGs, beginning January 2, 2011. This rule “tailors” these permitting programs to apply to certain stationary sources of GHG emissions in a multi-step process, with the largest sources first subject to permitting. We do not believe our operations currently are subject to subject to these permitting requirements, but if our operations become subject to these or other similar requirements, we could incur significant costs to control our emissions and comply with regulatory requirements. In addition, the EPA has adopted a mandatory GHG emissions reporting program that imposes reporting and monitoring requirements on various types of facilities and industries. In November 2010, the EPA expanded its GHG reporting rule to include onshore and offshore oil and natural gas production, processing, transmission, storage, and distribution facilities, requiring reporting of GHG emissions from such facilities on an annual basis, with reporting beginning in 2012 for emissions occurring in 2011. We do not believe our operations to be subject to GHG reporting requirements, but there is no guarantee that the EPA will not further expand the program to additional sources and facilities. Should we be required to report GHG emissions, it could require us to incur costs to monitor, keep records of, and report emissions of GHGs.

Because of the lack of any comprehensive legislative program addressing GHGs, there is a great deal of uncertainty as to how and when federal regulation of GHGs might take place. Some members of Congress have expressed the intention to promote legislation to curb EPA’s authority to regulation GHGs. In addition to possible federal regulation, a number of states, individually and regionally, also are considering or have implemented GHG regulatory programs. These potential regional and state initiatives may result in so-called cap and trade programs, under which overall GHG emissions are limited and GHG emissions are then allocated and sold, and possibly other regulatory requirements, that could result in our incurring material expenses to comply, e.g., by being required to purchase or to surrender allowances for GHGs resulting from our operations. The federal, regional and local regulatory initiatives also could adversely affect the marketability of the oil and natural gas we produce. The impact of such future programs cannot be predicted, but we do not expect our operations to be affected any differently than other similarly situated domestic competitors.

On April 17, 2012, the EPA issued final rules that subject oil and natural gas production, processing, transmission and storage operations to regulation under the New Source Performance Standards (“NSPS”) and National Emission Standards for Hazardous Air Pollutants (“NESHAP”) programs. The EPA rules include NSPS standards for completions of hydraulically fractured natural gas wells. Before January 1, 2015, these standards require owners/operators to reduce VOC emissions from natural gas not sent to the gathering line during well completion either by flaring using a completion combustion device or by capturing the natural gas using green completions with a completion combustion device. Beginning January 1, 2015, operators must capture the natural gas and make it available for use or sale, which can be done through the use of green completions. The standards are applicable to newly fractured wells and also existing wells that are refractured. Further, the finalized regulations also establish specific new requirements, effective in 2012, for emissions from compressors,

controllers, dehydrators, storage tanks, natural gas processing plants and certain other equipment. These rules may require changes to our operations, including the installation of new equipment to control emissions. We have evaluated the effect these rules will have on our business and are taking steps to ensure compliance.

We are subject to the requirements of the federal Occupational Safety and Health Act (“OSHA”) and comparable state statutes. These laws and the implementing regulations strictly govern the protection of the health and safety of employees. The OSHA hazard communication standard, the EPA community right-to-know regulations under the Title III of CERCLA and similar state statutes require that we organize and/or disclose information about hazardous materials used or produced in our operations. We believe that we are in substantial compliance with these applicable requirements and with other OSHA and comparable requirements.

We believe that we are in substantial compliance with all existing environmental laws and regulations applicable to our current operations and that our continued compliance with existing requirements will not have a material adverse impact on our financial condition and results of operations. We did not incur any material capital expenditures for remediation or pollution control activities for the years ended December 31, 2011, 2010 and 2009. Additionally, we are not aware of any environmental issues or claims that will require material capital expenditures during 2011 or that will otherwise have a material impact on our financial position or results of operations in the future. However, we cannot assure you that the passage of more stringent laws and regulations in the future will not have a negative impact our business activities, financial condition or results of operations.

The oil and natural gas industry is extensively regulated by numerous federal, state and local authorities. Legislation affecting the oil and natural gas industry is under constant review for amendment or expansion, frequently increasing the regulatory burden. Also, numerous departments and agencies, both federal and state, are authorized by statute to issue rules and regulations binding on the oil and natural gas industry and its individual members, some of which carry substantial penalties for failure to comply. Although the regulatory burden on the oil and natural gas industry increases our cost of doing business and, consequently, affects our profitability, these burdens generally do not affect us any differently or to any greater or lesser extent than they affect other companies in the industry with similar types, quantities and locations of production.

Legislation continues to be introduced in Congress and development of regulations continues in the Department of Homeland Security and other agencies concerning the security of industrial facilities, including oil and natural gas facilities. Our operations may be subject to such laws and regulations. Presently, it is not possible to accurately estimate the costs we could incur to comply with any such facility security laws or regulations, but such expenditures could be substantial.

Our operations are subject to various types of regulation at the federal, state and local levels. These types of regulation include requiring permits for the drilling of wells, drilling bonds and reports concerning operations. Most states and some counties and municipalities in which we operate also regulate one or more of the following:

State laws regulate the size and shape of drilling and spacing units or proration units governing the pooling of oil and natural gas properties. Some states allow forced pooling or integration of tracts to facilitate exploitation while other states rely on voluntary pooling of lands and leases. In some instances, forced pooling or unitization

may be implemented by third parties and may reduce our interest in the unitized properties. In addition, state conservation laws establish maximum rates of production from oil and natural gas wells, generally prohibit the venting or flaring of natural gas and impose requirements regarding the ratability of production. These laws and regulations may limit the amount of oil and natural gas we can produce from our wells or limit the number of wells or the locations at which we can drill. Moreover, each state generally imposes a production, ad valorem or severance tax with respect to the production and sale of oil, natural gas and natural gas liquids within its jurisdiction.

In addition, 11 states have enacted surface damage statutes (“SDAs”). These laws are designed to compensate for damage caused by mineral development. Most SDAs contain entry notification and negotiation requirements to facilitate contact between operators and surface owners/users. Most also contain bonding requirements and specific expenses for exploration and producing activities. Costs and delays associated with SDAs could impair operational effectiveness and increase development costs.

We do not control the availability of transportation and processing facilities used in the marketing of our production. For example, we may have to shut-in a productive natural gas well because of a lack of available natural gas gathering or transportation facilities.

If we conduct operations on federal, state or Indian oil and natural gas leases, these operations must comply with numerous regulatory restrictions, including various non-discrimination statutes, royalty and related valuation requirements, and certain of these operations must be conducted pursuant to certain on-site security regulations and other appropriate permits issued by the Bureau of Land Management, Minerals Management Service or other appropriate federal or state agencies.

The availability, terms and cost of transportation significantly affect sales of natural gas. The interstate transportation and sale for resale of natural gas is subject to federal regulation, including regulation of the terms, conditions and rates for interstate transportation, storage and various other matters, primarily by the Federal Energy Regulatory Commission (“FERC”). Federal and state regulations govern the price and terms for access to natural gas pipeline transportation. FERC’s regulations for interstate natural gas transmission in some circumstances may also affect the intrastate transportation of natural gas. FERC regulates the rates, terms and conditions applicable to the interstate transportation of natural gas by pipelines under the Natural Gas Act as well as under Section 311 of the Natural Gas Policy Act.

Since 1985, FERC has implemented regulations intended to increase competition within the natural gas industry by making natural gas transportation more accessible to natural gas buyers and sellers on an open-access, nondiscriminatory basis. FERC has announced several important transportation related policy statements and rule changes, including a statement of policy and final rule issued February 25, 2000, concerning alternatives to its traditional cost-of-service rate-making methodology to establish the rates interstate pipelines may charge for their services. The final rule revises FERC’s pricing policy and current regulatory framework to improve the efficiency of the market and further enhance competition in natural gas markets.

FERC has also issued several other generally pro-competitive policy statements and initiatives affecting rates and other aspects of pipeline transportation of natural gas. On May 31, 2005, FERC generally reaffirmed its policy of allowing interstate pipelines to selectively discount their rates in order to meet competition from other interstate pipelines. On June 15, 2006, the FERC issued an order in which it declined to establish uniform standards for natural gas quality and interchangeability, opting instead for a pipeline-by-pipeline approach. Four days later, on June 19, 2006, in order to facilitate development of new storage capacity, FERC established criteria to allow providers to charge market-based (i.e. negotiated) rates for storage services. On June 19, 2008, the FERC removed the rate ceiling on short-term releases by shippers of interstate pipeline transportation capacity.

Although natural gas prices are currently unregulated, Congress historically has been active in the area of natural gas regulation. We cannot predict whether new legislation to regulate natural gas might be proposed, what proposals, if any, might actually be enacted by Congress or the various state legislatures, and what effect, if any, the proposals might have on the operations of the underlying properties. Sales of condensate and natural gas liquids are not currently regulated and are made at market prices.

Various states regulate the drilling for, and the production, gathering and sale of, natural gas, including imposing severance taxes and requirements for obtaining drilling permits. States also regulate the method of developing new fields, the spacing and operation of wells and the prevention of waste of natural gas resources. States may regulate rates of production and may establish maximum daily production allowables from natural gas wells based on market demand or resource conservation, or both. States do not regulate wellhead prices or engage in other similar direct economic regulation, but there can be no assurance that they will not do so in the future. The effect of these regulations may be to limit the amounts of natural gas that may be produced from our wells and to limit the number of wells or locations we can drill.

In addition to the regulation of oil and natural gas pipeline transportation rates, the oil and natural gas industry generally is subject to compliance with various other federal, state and local regulations and laws. Some of those laws relate to occupational safety, resource conservation and equal employment opportunity.

As is the case with many partnerships, we do not directly employ officers, directors or employees. Our operations and activities are managed by the board of directors of our general partner, Alta Mesa Holdings GP, LLC, and the officers and directors of Alta Mesa Services, LP, an entity wholly owned by us. References to our directors are references to the directors of Alta Mesa GP. References to our officers and employees are references to the officers and employees of Alta Mesa Services.

All of our executive management personnel are employees of Alta Mesa Services and devote all of their time to our business and affairs. We also utilize a significant number of employees of Alta Mesa Services to operate our properties and provide us with certain general and administrative services. Under the shared services and expenses agreement, we reimburse Alta Mesa Services for its operational personnel who perform services for our benefit. See “Certain Relationships and Related Party Transactions — Shared Services and Expenses Agreement.”

Our Chairman is Michael E. Ellis, our Chief Operating Officer and founder of the Company. Our Board of Directors has no policy regarding the separation of the positions of Chief Executive Officer and Chairman. We also do not have a lead independent director.

Like all businesses, we face risks in our business activities. Many of these risks are discussed under the caption “Risk Factors” elsewhere in this prospectus. The board of directors has delegated to management the primary responsibility of risk management, while it has retained oversight of management in that regard.

In addition, our Board of Directors considers our practices regarding risk assessment and risk management, reviews our contingent liabilities, reviews our oil and natural gas reserve estimation practices, as well as major legislative and regulatory developments that could affect us. Our Board reviews and attempts to mitigate risks which may result from our compensation policies.

The following table sets forth the names, ages and offices of our present directors and executive officers as of December 31, 2011. Members of our Board of Directors are elected for one-year terms.

The following is a biographical summary of the business experience of these directors and executive officers:

Harlan H. Chappelle joined Alta Mesa as President and CEO in November 2004, and has led the company in a period of significant growth, building a strong management and technical team, focusing the company on its greatest opportunities, making strategic acquisitions, and restructuring its financing. Mr. Chappelle has over 25 years in field operations, engineering, management, marketing and trading, acquisitions and divestitures, and

field re-development in collaboration with majors including Exxon and Chevron. He has worked for Louisiana Land & Exploration Company, Burlington Resources, Southern Company, and Mirant. Mr. Chappelle retired as a Commander from the U.S. Navy Reserve. He has a Bachelor of Chemical Engineering from Auburn University and a Master of Science in Petroleum Engineering from The University of Texas at Austin.

Michael E. Ellis founded Alta Mesa in 1987 after beginning his career with Amoco, and is our Chairman and Chief Operating Officer, as well as Vice President of Engineering. Mr. Ellis manages all day-to-day engineering and field operations of Alta Mesa. He built the company’s asset base by starting with small earn-in exploitation projects, then progressively growing the company with successive acquisitions of fields from major oil companies, and consistent success in exploration and development drilling. He has over 30 years’ experience in management, engineering, exploration, and acquisitions and divestitures in the Gulf Coast, Midcontinent and West Texas regions. Mr. Ellis holds a Bachelor of Science in Civil Engineering from West Virginia University.

Mickey Ellis has served as a Director since the company’s inception in 1987. Ms. Ellis is actively involved in the leadership of charitable organizations, as a Board Member of Houston Area Respite Care and The Confessing Movement of the United Methodist Church, Treasurer of the National Charity League Star Chapter, Committee Member on several committees within Mission Bend United Methodist Church, and Building Relocation Coordinator for Mission Bend Christian Academy. She is a major fundraiser for the Susan G. Komen Foundation, and an active volunteer for CanCare. Ms. Ellis is the spouse of Michael E. Ellis.

Michael A. McCabe, our Chief Financial Officer, joined Alta Mesa in September 2006. Mr. McCabe has over 25 years of corporate finance experience, with a focus on the energy industry. From 2004 until 2006, Mr. McCabe served as President and sole owner of Bridge Management Group, Inc., a private consulting firm primarily providing advisory services to us and to MultiFuels, Inc., a Houston based developer of natural gas storage facilities. He has served in senior positions with Bank of Tokyo, Bank of New England, and Key Bank. Mr. McCabe holds a Bachelor of Science in Chemistry and Physics from Bridgewater State University, a Masters of Science in Chemical Engineering from Purdue University and a Masters of Business Administration in Financial Management from Pace University.

David Murrell has served as our Vice President, Land and Business Development since 2007. Mr. Murrell has over 25 years of experience in Gulf Coast leasing, exploration and development programs, contract management and acquisitions and divestitures. He created a structured land management system for Alta Mesa, and built a team of lease analysts, landmen, and field representatives that has facilitated our company’s growth. Mr. Murrell earned a Bachelor of Business Administration in Petroleum Land Management from the University of Oklahoma.

Mr. Chappelle’s experience as our Chief Executive Officer since 2004, combined with his significant equity ownership of us, uniquely qualify him to serve as a director of our general partner.

Mr. Ellis is our founder; his experience in that capacity and as one of our executive officers since 1987 provide him intimate knowledge of our operations, finances and strategy and uniquely qualify him to serve as the Chairman of our general partner.

Ms. Ellis’ role in working with us since our inception in 1987 provides her with valuable knowledge of our business and operations.

Because we are a partnership, we do not directly employ any of the persons responsible for managing our business. Our operations and activities are managed by the Board of Directors of our general partner, Alta Mesa Holdings GP, LLC (“Alta Mesa GP”) and the officers of Alta Mesa Services, LP (“Alta Mesa Services”), our wholly owned subsidiary. References to our officers and employees are references to the officers and employees of Alta Mesa Services. We refer to the Board of Directors of Alta Mesa GP as “our Board” or “our Board of Directors.”

Prior to the offering of our senior notes in October 2010, Alta Mesa Services was owned by an affiliate of our general partner and it provided services, including accounting, corporate development, finance, land administration and engineering, to us pursuant to an administrative services agreement. Pursuant to the administrative services agreement, expenses were allocated to us based on the portion of time that the employees allocated to our business. During 2011, all of Alta Mesa Services’ expenses were allocated to us under the above formula.

In connection with the senior note offering, we acquired Alta Mesa Services. All of our executive officers are employees of Alta Mesa Services and devote all of their time to our business and affairs.

Prior to the senior note offering, Alta Mesa Services had the ultimate decision-making authority with respect to our compensation program for our executive officers. The board of Alta Mesa Services was comprised of Michael E. Ellis, our Chief Operating Officer, Mickey Ellis, his wife, and Harlan H. Chappelle, our President and Chief Executive Officer. After the offering, our Board of Directors assumed responsibility for overseeing our executive remuneration programs and the fair and competitive compensation of our executive officers. Our Board consists of Michael E. Ellis, Mickey Ellis and Harlan H. Chappelle and meets each year to review our compensation program and to determine compensation levels for the ensuing fiscal year.

In this Compensation Discussion and Analysis, we discuss our compensation objectives, our decisions and the rationale behind those decisions relating to 2011 compensation for our named executive officers.

Our executive compensation program is intended to motivate our executive officers to achieve strong financial and operating results for us. In addition, our program is designed to achieve the following objectives:

Our strategy is to increase reserves and production by applying advanced engineering analytics and enhanced geological techniques in areas we have identified as under-developed and over-looked. Our compensation program is designed to reward performance that contributes to the achievement of our business strategy. In addition, we reward qualities that we believe help achieve our strategy such as teamwork; individual performance in light of general economic and industry specific conditions; performance that supports our core values; resourcefulness; the ability to manage our existing corporate assets; the ability to explore new avenues to increase oil and natural gas production and reserves; level of job responsibility; and tenure with us.

To accomplish our objectives, our compensation program is comprised of three elements: base salary, cash bonus and benefits. We currently do not offer equity-based compensation.

We pay base salary in order to recognize each executive officer’s unique value and historical contributions to our success in light of salary norms in the industry and the general marketplace; to match competitors for executive talent; to provide executives with sufficient, regularly-paid income; and to reflect an executive’s position and level of responsibility.

We include an annual cash bonus as part of our compensation program because we believe this element of compensation helps to motivate executives to achieve key corporate objectives by providing annual recognition of achievement. The annual cash bonus also allows us to be competitive from a total remuneration standpoint.

We offer benefits such as a 401(k) plan and payment of insurance premiums in order to provide a competitive remuneration package as well as a measure of financial security to our employees.

In determining the elements of compensation, we consider our ability to attract and retain executives as well as various measures of company and industrial performance including debt levels, revenues, cash flow, capital expenditures, reserves of oil and natural gas and costs. We did not retain a consultant with respect to determining 2011 compensation.

Messrs. Ellis, Chappelle, McCabe, and Murrell are parties to employment agreements with Alta Mesa Services. The employment agreements automatically renew annually, subject to prior notice of cancellation by either Alta Mesa Services or the executive. These employment agreements establish set minimum base salaries for each officer of $400,000, $400,000, $300,000, and $190,000 per annum, respectively, which we believe are competitive with other independent oil and natural gas companies with whom we compete for managerial talent. In addition, the employment agreements provide that the executives are each entitled to an annual bonus equal to a percentage of his respective annual base salary if performance criteria set by the board for the applicable period are met. The agreements also provide for benefits such as reimbursement of business expenses, participation in employee benefit plans and key man life insurance.

Base salary. In reviewing base salaries, the board takes into account a combination of subjective factors, primarily relying on their own personal judgment and experience. Subjective factors the board considers include individual achievements, our performance, level of responsibility, experience, leadership abilities, increases or changes in duties and responsibilities and contributions to our performance. Mr. Ellis and Mr. Chappelle participate in and are present during the board’s review and determination of their respective base salaries. For 2011, the Board set the base salaries for Messrs. Ellis, Chappelle and McCabe at $450,000, $450,000 and $350,000, respectively. In addition, the board determined Mr. Murrell’s salary of $300,000 for 2011 was reasonable.

Bonus. A portion of each executive’s total compensation may be paid as bonus compensation. The board takes into consideration our achievements during the year and each executive’s contribution toward such achievements. While performance criteria may be set, the board takes into account subjective factors in determining if these criteria were met. Bonuses for any one year are usually determined and paid in the second or third quarter of the following year. Accordingly, bonus compensation for our executive officers for 2012 has not yet been determined. However, bonuses to our executive officers paid in 2012 for 2011 performance ranged from approximately 73% to 200% of base salary.

Benefits. We provide company benefits or perquisites that we believe are standard in the industry to all of our employees. These benefits consist of a group medical and dental insurance program for employees and their qualified dependents and a 401(k) employee savings and protection plan. The costs of these benefits are paid for

entirely by us. We do not provide employee life insurance amounts surpassing the Internal Revenue Service maximum. We make matching contributions to the 401(k) contribution of each qualified participant. We pay all administrative costs to maintain the plan. In addition, we provide Messrs. Ellis and Chappelle with company automobiles.

Other Compensation. As part of his employment agreement, we reimburse Mr. McCabe for the rental cost of an apartment near our headquarters and pay his commuting expenses to and from his permanent home to Houston. In 2011, these housing and commuting expenses totaled $66,601. We agreed to provide these benefits to Mr. McCabe because our Board believed it was necessary to retain Mr. McCabe’s services despite the fact that his permanent residence is outside of the Houston area. The Board considered the value of this additional compensation in evaluating Mr. McCabe’s total compensation package.

We view the various components of compensation as related but distinct and emphasize “pay for performance” with a portion of total compensation reflecting a risk aspect tied to our financial and strategic goals. We determine the appropriate level for each compensation component based in part, but not exclusively, on our view of internal equity and consistency, and other considerations we deem relevant, such as rewarding extraordinary performance.

Our Board takes risk into account when making compensation decisions and has concluded that the executive compensation program as it is currently structured does not encourage excessive risk or unnecessary risk-taking.

We have structured our compensation program to comply with Internal Revenue Code Section 409A. If an executive is entitled to nonqualified deferred compensation benefits that are subject to Section 409A, and such benefits do not comply with Section 409A, then the benefits are taxable in the first year they are not subject to a substantial risk of forfeiture. In such case, the service provider is subject to regular federal income tax, interest and an additional federal income tax of 20% of the benefit includible in income.

As we do not have a formal compensation committee, our entire Board of Directors serves as our compensation committee. Our Board of Directors has reviewed and discussed the above Compensation Discussion and Analysis with management and, based on such review and discussions, the Board of Directors recommended that the Compensation Discussion and Analysis be included in this prospectus.

The following table summarizes, with respect to our named executive officers, information relating to the compensation earned for services rendered in all capacities during the fiscal year ended December 31, 2011. There was no compensation awarded to, earned by or paid to any of the named executive officers related to option awards or non–equity incentive compensation plans. In addition, none of the named executive officers participate in a defined benefit pension plan.

Mr. Chappelle entered into an employment agreement on August 31, 2006 that provides that he will act as President and Chief Executive Officer until August 31, 2010, subject to automatic one year renewals of the term if neither party submits a notice of termination at least 60 days prior to the end of the then-current term. In accordance with the provisions of the employment agreement, in 2011, the agreement was automatically renewed for an additional one-year term. This agreement may be terminated by either party, at any time, subject to severance obligations in the event Mr. Chappelle is terminated by us without cause or he dies or is disabled.

Mr. Chappelle’s employment agreement provides for a minimum base salary of $400,000 and an annual bonus equal to a percentage of his base salary paid during each such annual period, such percentage to be established by our Board of Directors in the Board’s sole discretion.

Mr. Ellis entered into an employment agreement on August 31, 2006 that provides that he will act as Vice President and Chief Operating Officer until August 31, 2010, subject to automatic one year renewals of the term if neither party submits a notice of termination at least 60 days prior to the end of the then-current term. In accordance with the provisions of the employment agreement, in 2011, the agreement was automatically renewed for an additional one-year term. This agreement may be terminated by either party, at any time, subject to severance obligations in the event Mr. Ellis is terminated by us without cause or he dies or is disabled.

Mr. Ellis’ employment agreement provides for a minimum base salary of $400,000 and an annual bonus equal to a percentage of his base salary paid during each such annual period, such percentage to be established by our Board of Directors in the Board’s sole discretion.

Mr. McCabe entered into an employment agreement on August 31, 2006 that provides that he will act as Vice President and Chief Financial Officer until August 31, 2010, subject to automatic one year renewals of the term if neither party submits a notice of termination at least 60 days prior to the end of the then-current term. In accordance with the provisions of the employment agreement, in 2011, the agreement was automatically renewed for an additional one-year term. This agreement may be terminated by either party, at any time, subject to severance obligations in the event Mr. McCabe is terminated by us without cause or he dies or is disabled.

Mr. McCabe’s employment agreement provides for a minimum base salary of $300,000 and an annual bonus equal to a percentage of his base salary paid during each such annual period, such percentage to be established by our Board of Directors in the Board’s sole discretion.

Mr. McCabe’s employment agreement also provides that he is allowed to work from his residence in Massachusetts as well as in our Houston office so long as he is capable of performing his duties assigned to him. In his employment agreement, we also agree to provide Mr. McCabe with suitable housing (or a housing allowance) and an automobile or reimbursement for the lease of an automobile while he is in Houston.

Mr. Murrell entered into an employment agreement on October 1, 2006 that provides that he will act as Vice President of Land and Business Development until October 1, 2007, subject to automatic one year renewals of the term if neither party submits a notice of termination at least 60 days prior to the end of the then-current term. In accordance with the provisions of the employment agreement, in 2011, the agreement was automatically renewed for an additional one-year term. This agreement may be terminated by either party, at any time, subject to severance obligations in the event Mr. Murrell is terminated by us without cause or he dies or is disabled.

Mr. Murrell’s employment agreement provides for a minimum base salary of $190,000 and an annual bonus equal to 0.5% of the taxable income less federal income tax of Alta Mesa Holdings, subject to a minimum bonus of $50,000 and a maximum bonus such that his combined salary plus bonus does not exceed $1,000,000.

There were no grants of plan-based awards to our named executive officers during the fiscal year ended December 31, 2011.

There were no outstanding equity awards for our named executive officers as of December 31, 2011.

There were no exercises of equity awards and no vesting of equity awards for our named executive officers during fiscal 2011.

We do not have a nonqualified deferred compensation plan and, as such, no compensation has been deferred by our named executive officers.

Messrs. Chappelle, Ellis, McCabe and Murrell are parties to employment agreements which provide them with post-termination benefits in a variety of circumstances. The amount of compensation payable in some cases may vary depending on the nature of the termination, whether as a result of retirement/voluntary termination, involuntary not-for-cause termination, termination following a change of control and in the event of disability or death of the executive. The discussion below describes the varying amounts payable in each of these situations. It assumes, in each case, that the officer’s termination was effective as of December 31, 2010. In presenting this disclosure, we describe amounts earned through December 31, 2010 and, in those cases where the actual amounts to be paid out can only be determined at the time of such executive’s separation from us, our estimates of the amounts which would be paid out to the executives upon their termination.

Under the employment agreements, if the executive’s employment with us terminates, the executive is entitled to unpaid salary for the full month in which the termination date occurred. However, if the executive is terminated for cause, the executive is only entitled to receive accrued but unpaid salary through the termination date. In addition, if the executive’s employment terminates, the executive is entitled to unpaid vacation days for that year which have accrued through the termination date, reimbursement of reasonable business expenses that were incurred but unpaid as of the termination date, a pro rata portion of the annual bonus for that year and COBRA coverage as required by law. Salary and accrued vacation days are payable in cash lump sum less applicable withholdings. Business expenses are reimbursable in accordance with normal procedures.

If the executive’s employment is involuntarily terminated by us (except for cause or due to the death of the executive) or if the executive’s employment is terminated due to disability or retirement or by the executive for good reason, we are obligated to pay as additional compensation an amount in cash equal to two years, except in the case of Mr. Murrell, in which case it is six months, of the executive’s base salary in effect as of the termination date. Under the terms of Mr. Murrell’s employment agreement, upon such involuntary termination, he would also be paid 50% of the annual bonus then in effect. Assuming termination as of December 31, 2011, for both Messrs. Chappelle and Ellis, the termination benefit would have been $900,000; for Mr. McCabe, $700,000; and for Mr. Murrell, $250,000. In addition, the executive is entitled to continued group health plan coverage following the termination date for the executive and the executive’s eligible spouse and dependents for the maximum period for which such qualified beneficiaries are eligible to receive COBRA coverage. The executive shall not be required to pay more for COBRA coverage than officers who are then in active service for us and receiving coverage under the plan. Assuming termination as of December 31, 2011, the total cost to the Company of providing this benefit would have been $29,256 for Mr. Chappelle, $42,976 for Mr. Ellis, $29,256 for Mr. McCabe, and $42,976 for Mr. Murrell.

“Good reason” means the occurrence of any of the following, if not cured and correct by us or our successor, within 60 days after written notice thereof is provided by the executive to us or our successor:

“Retirement” means the termination of the executive’s employment for normal retirement at or after attaining age 70, provided that the executive has been with us for at least five years.

The employment agreements do not separately provide for benefits upon a change of control.

The employee and non-employee members of the Board of Directors do not receive compensation for their services as directors. However, our directors may be reimbursed for their expenses in attending board meetings.

We do not have a formal compensation committee and our full Board serves as our audit committee. Because the registration statement of which this prospectus forms a part registers only debt securities and because we do not have and are not seeking to list any securities on a national securities exchange or on an inter-dealer quotation system, we are not subject to a number of the corporate governance requirements of the SEC or of any national securities exchange or inter-dealer quotation system. For example, we are not required to have a board of directors comprised of a majority of independent directors or to have an audit committee comprised of independent directors. Accordingly, our Board of Directors has not made any determination as to whether any of the members of our Board of Directors or committees thereof would qualify as independent under the listing

standards of any national securities exchange or any inter-dealer quotation system or under any other independence definition. Additionally, for the same reason, we have not yet determined whether any of our directors is an audit committee financial expert.

The Board of Directors has adopted a Code of Ethics for Senior Financial Officers. The Code of Ethics is posted on the investor relations section of our website at www.altamesa.net and is available free of charge upon written request to 15415 Katy Freeway, Suite 800, Houston, Texas 77094.

We do not currently have a compensation committee. None of our executive officers has served as a director or member of the compensation committee of any other entity whose executive officers served as a director or member of our compensation committee.

The following is a summary of the material provisions of our partnership agreement, as amended.

Our partnership was organized in September 2005 and will have a perpetual existence.

Our purpose under the partnership agreement is (a) exploring, developing, operating, investing in, acquiring, expanding, selling, managing and financing, directly or indirectly, oil and gas properties, including those properties held by the partnership as of the effective date and after the effective date and (b) taking all such other actions incidental to any of the foregoing as may be necessary or desirable and for which a Texas limited partnership may legally engage.

Our general partner is authorized in general to perform all acts it determines to be necessary or appropriate to carry out our purposes and to conduct our business.

Our general partner and Class A limited partners have no obligation to make additional capital contributions. Our Class B limited partner is obligated to make additional capital contributions in the amounts set forth in the partnership agreement and contribution agreement, which are referred to as the “Class B Commitment”. In the event the Class B limited partner defaults in making additional capital contributions required under the partnership agreement, the general partner may extinguish certain of the Class B limited partner’s rights under the partnership or withhold distributions to the Class B limited partner.

Our partnership agreement specifies the manner in which we will make cash distributions to our general and limited partners.

Net Cash from Operations. Except for tax distributions and as the general partner and the Class B limited partner otherwise agree, prior to January 1, 2012, net cash from operations is otherwise to be retained by the company to fund the activities of the company and the subsidiaries, including development, exploration and acquisition activities. After January 1, 2012, the Class B limited partner may require the general partner to make distributions of net cash from operations upon notice to the general partner, provided, however, that such distributions are subject to our compliance with the covenants set forth in any senior debt, including the notes, and our bank credit facility. “Net cash from operations” means the gross cash proceeds from operations (including sales and dispositions of properties in the ordinary course of business) less the portion thereof used to pay or fund our costs, expenses, contract operating costs (including operators’ general and administrative expenses), marketing costs, debt payments, capital expenditures, reserve replacements, tax distributions to the partners and Agreed Reserves (as defined below). Subject to the foregoing, net cash from operations is to be distributed:

Net Cash from Liquidity Events. Except as otherwise agreed upon by the general partner and the Class B limited partners, net cash from a liquidity event is to be distributed to the partners, subject to the retention of agreed reserves:

(i) first, 100% to the Class B limited partner until the Class B limited partner receives aggregate distributions equal to the 1x Return Amount;

(ii) second, 85% to the Class B limited partner and 15% to the general partner and the Class A limited partners until the cumulative amount of distributions to the Class B limited partner result in the Class B limited partner achieving a 10% internal rate of return;

(iii) third, 100% to the general partner and the Class A limited partners until the aggregate distributions have been distributed 85% to the Class B limited partner and 15% to the general partner and Class A limited partners;

(iv) fourth, 85% to the Class B limited partner and 15% to the general partner and the Class A limited partners until the cumulative amount of distributions to the Class B limited partner result in the Class B limited partner achieving a 15% internal rate of return;

(v) fifth, 65% to the Class B limited partner and 35% to the general partner and the Class A limited partners until the cumulative amount of distributions to the Class B limited partner result in the Class B limited partner achieving a 27.5% internal rate of return ; and

(vi) thereafter, 25% to the Class B limited partner and 75% to the general partner and the Class A limited partners.

All distributions made to the general partner and the Class A limited partners are pro rata to such partners.

A “liquidity event” is any event in which the company receives cash proceeds outside the ordinary course of the company’s business, including (a) a sale of the company and its subsidiaries, whether structured as a merger or consolidation, share exchange, sale of interests or the equity of the subsidiaries, or a sale of all or substantially all of the assets of the company and the subsidiaries outside the normal course of business, (b) a public or private offering of the interests or other public or private sale of debt or equity securities of the company or a subsidiary; and (c) a financing transaction or leveraged recapitalization of the company or a subsidiary.

“Agreed reserves” are a reserve of cash to pay reasonably anticipated future costs and liabilities of the company, as agreed upon by the general partner and the Class B limited partner.

Amounts due by the company in respect of (i) certain related party subordinated debt and (ii) indemnity obligations under the Contribution Agreement are to be made by the company exclusively from the general partner’s and the Class A limited partners’ allocable share of distributions of net cash from operations and of net cash from a liquidity event.

Distributions for Payment of Taxes. In addition, in each fiscal year, the general partner is to distribute to the partners, to the extent of available cash, in proportion to the taxable income allocated to them, such amount as the general partner reasonably determines is necessary to enable the partners who were allocated taxable income during that fiscal year to pay their income taxes on their distributive shares of the company’s taxable income.

Our business and affairs are managed by our general partner, which has full and exclusive power and authority on our behalf to manage, control, administer and operate our properties, business and affairs. Without the written consent of the Class B limited partner, however, our general partner cannot cause:

(a) any sale of any property or asset of the company or a subsidiary (in a single transaction or a series of related transactions) having a value in each case in excess of $10,000,000 or any sales of properties or assets of the company or its subsidiaries during any 12 month period having an aggregate value in excess of ten percent (10%) of the proved reserves value of the properties as reflected under the most recent engineering report delivered under Section 8.2 (c) of the partnership agreement;

(b) except in connection with the senior credit facility, the incurrence by the company or any subsidiary of indebtedness for borrowed money in excess of amounts drawn under a company credit facility that was approved by the Class B limited partner;

(c) the guaranty by the company or any subsidiary of the payment of money or the performance of any contract or other obligation of any person other than the company or any subsidiary, except in connection with indebtedness permitted under (a) above;

(d) the grant of liens on any assets of the company or its subsidiaries, except in connection with the indebtedness permitted under (a) above or for customary liens contained in joint operating agreements;

(e) the adoption of the development plan and budget pursuant to the terms of the partnership agreement, and making any material amendments to thereto;

(f) the acquisition of properties and other assets (whether in one or in a series of related transactions) having a purchase price or, if not a cash transaction, a fair market value, which exceeds $10,000,000 and which acquisition is not expressly budgeted for in the approved budget;

(g) the appointment of any successor to the Chief Executive Officer or any other senior officer and the payment of any executive compensation to the senior officers;

(i) entering into a partnership or joint venture with any other party for the purpose of carrying on any business other than in the ordinary course of business;

(k) any amalgamation, reconstruction, liquidation, dissolution, commencement of bankruptcy, or similar proceedings with respect to the company or any subsidiary, or compromise with a creditor;

(l) the merger or consolidation of the company with any entity, the conversion of the company into any other organizational form, or the exchange of interests with any other person or entity;

(m) any issuance of interests, ownership interests, debentures, bonds or any other security, including issuances of securities in connection with any employee incentive plan or as consideration in any acquisition (whether by purchase of ownership interests, asset purchase or merger);

(n) any transaction or series of related transactions (not otherwise expressly permitted) between the company or any subsidiary, on the one hand, and any partner or affiliate of any partner, on the other hand;

(o) pursuant to the partnership agreement, any amendment to the partnership agreement, any adoption of or amendment to the partnership agreement, memorandum and articles of association, certificate and articles of incorporation, bylaws, or other organizational documents, of the company or any subsidiary;

(p) except for the exercise of certain warrants, any redemption or other change in the interests or ownership interest, or options or other rights to acquire such interests, in the company or the subsidiaries;

(q) the initiation, compromise or settlement of any lawsuit, administrative matter or other dispute where the amount the company may recover or might be obligated to pay, as applicable, is in excess of $100,000;

(r) the extension of any loans by the company to any third party (including the general partner or any affiliate thereof);

(s) the grant of any approval by the company under Section 6 of the Shared Services Agreement by and among Alta Mesa Services, LP, on the one hand, and the general partner, the company and certain of the subsidiaries of the company, on the other hand, or

(t) the amendment or modification of the terms of certain warrants, the waiver of any material right of the company under the warrants or the making of any material determination or election by the company under the warrants.

Development Plan and Operating Budget. The general partner is to prepare and submit to the Class B limited partner a proposed development plan and budget annually, on or before the 60th day prior to the end of each fiscal year, which shall set forth, for the next following fiscal year, the proposed operations, time schedule for implementing operations, estimated revenues, operating expenditures, and capital expenditures for the company and each of its subsidiaries. All development plans and budgets are subject to the prior written approval of the Class B limited partner.

Price Risk Mitigation. Subject to any restrictions contained in any credit facility or other agreement to which the company or its subsidiaries are parties or any of their respective properties are subject, the Class B limited partner can require the company and its subsidiaries to implement reasonable measures to mitigate commodity price risks.

Initiation of Liquidity Event. Following the earlier of (i) January 1, 2012, and (b) a breach of or default by the company under any representation, warranty, covenant or agreement contained in any loan or credit agreement to which the company is a party or by which its assets are bound, following the expiration of any cure periods, the Class B limited partner can, without consent of any other partner, upon notice to the general partner and Class A partners, request that the general partner take such actions to cause the company and its subsidiaries, or the assets of the company and the subsidiaries to be sold to one or more third parties, subject to a Class A partners’ right of right of first offer to purchase the Class B limited partner’s interests.

Conflicts of Interest. The general partner and its affiliates may transact business with the company and the subsidiaries provided that the terms of such transaction are fair and reasonable to the company and the subsidiaries and no less favorable to the company and the subsidiaries than those the company and the subsidiaries could obtain from unrelated third parties. In connection with any such transaction, the general partner must provide prompt written notice to the Class B limited partner of such transaction.

Meetings of Partners. The Class B limited partner, by notice to the other partners, may call a meeting of partners at such times and places inside the State of Texas as the Class B limited partner may determine upon not less than two business days prior to the date of such meeting.

Business Opportunities. The Class B limited partner has no duty to disclose to the company business opportunities, whether or not competitive with the company’s business whether or not the company might be interested in such business opportunity for itself.

Removal of General Partner. The Class B limited partner may remove our general partner with cause and select a new general partner to operate and carry on our business and affairs. “With cause” includes the commission by the general partner of fraud, willful or intentional misconduct or gross negligence in the performance of its duties hereunder; a default by the general partner in the performance or observation of any material agreement, covenant, term, condition or obligation under the partnership agreement; a false material representation or warranty made by the general partner in the partnership agreement or by the general partner or any of its officers in any writing furnished in connection with or pursuant to the partnership agreement; and the dissolution (or other similar event) of the general partner.

In accordance with Texas law and the provisions of our partnership agreement, we may issue additional partnership securities in the future.

Except as otherwise provided in the partnership agreement, the partnership agreement may be amended, or any provision waived, only with the written consent of each of the general partner, those Class A limited partners holding percentage interests in the aggregate equal to or greater than 66 2/3% of percentage interests held by all Class A limited partners, and the Class B limited partner; provided that no amendment or waiver can materially and adversely affect disproportionately the rights of any limited partner when compared with its effect on any other limited partner without the prior written approval of such disadvantaged limited partner.

We will continue as a limited partnership until terminated under our partnership agreement. We will dissolve upon:

Upon the withdrawal or retirement from the company of the general partner, the business of the company will be continued if within 90 calendar days the Class B limited partner elects by written action to continue the business of the company and designate a replacement general partner. If the Class B limited partner fails to continue the company’s business, the company will be liquidated.

Our partnership agreement requires us to reimburse our general partner for all direct and indirect expenses it incurs or payments it makes on our behalf and all other expenses allocable to us or otherwise incurred by our general partner in connection with operating our business.

We keep books of account and records in accordance with GAAP. Such books and records are maintained at our principal office. The Class B limited partner and any Class A limited partner have the right to audit any and all financial and operational records with respect to the properties, the company and its subsidiaries and their respective operations. The calendar year is the accounting year of the company, and the books of account are maintained on an accrual basis.

The following table sets forth the limited partnership interests in Alta Mesa beneficially owned as of the date of this prospectus by:

Additionally, our general partner, Alta Mesa GP, is owned by Mr. and Ms. Ellis. For further information regarding the manner in which we make cash distributions to our general and limited partners, see “The Partnership Agreement — Cash Distributions”.

Michael E. Ellis, our Chairman and Chief Operating Officer, and his spouse Mickey Ellis, one of our directors, own 84.5% of our Class A interests. Our general partner, Alta Mesa GP, is owned 100% by Alta Mesa Resources, LP, an entity owned by Michael E. Ellis and Mickey Ellis. Our general partner has a 0.1% interest in us.

During 2011, Michael E. Ellis received a capital distribution from us of $165,000.

Through a Shared Services and Expenses Agreement with us, our general partner and our subsidiaries, Alta Mesa Services, LP, an entity owned by us, conducts our business and operations and, in addition to the board of directors of our general partner, makes decisions on our behalf. In addition, Alta Mesa Services agrees to make available its personnel, including our chief operating officer, chief executive officer and chief financial officer, which permits us to carry on our business. Prior to the offering of the notes in October 2010, Alta Mesa Services was owned by Michael E. and Mickey Ellis. During the years ended December 31, 2010, and 2009, we and our subsidiaries reimbursed Alta Mesa Services an aggregate of $14.6 million and $5.9 million, respectively, under the Shared Services and Expenses Agreement. No fees are paid to Alta Mesa Services pursuant to the agreement. Our consolidated financial statements include the activity of Alta Mesa Services for the years ended December 31, 2010, and 2009, respectively. We expect that Alta Mesa Services will continue to provide services to our non-wholly owned subsidiaries.

We were founded in 1987 by Michael E. Ellis and we or our subsidiaries have over time entered into promissory notes to repay Mr. Ellis for contributions of working capital and other amounts. See “Description of Certain Indebtedness — Founder Notes.”

David Murrell, our Vice President, Land and Business Development, is the principal of David Murrell and Associates, which provides land consulting services to us. The primary employee of David Murrell & Associates is his spouse, Brigid Murrell. Services are provided at a pre-negotiated hourly rate based on actual time employed by us. Payments for the years ended December 31, 2011, 2010 and 2009 were approximately $179,000, $146,000 and $131,000 respectively. The contract may be terminated by either party without penalty upon 30 days’ notice.

David McClure, the son-in-law of our CEO, Harlan H. Chappelle, is employed by us as a senior engineer. He received total compensation during 2011 and 2010 of $260,208 and $95,031, respectively. Additionally, his position provides him with the use of a company vehicle, similar to our other engineers whose duties include field oversight.

Our board of directors consists of three members, one of whom is a non-employee director. Because we only have debt securities registered with the SEC under the Exchange Act and because we do not have a class of securities listed on any national securities exchange, national securities association or inter-dealer quotation system, we are not required to have a board of directors comprised of a majority of independent directors under SEC rules or any listing standards. Accordingly, our board of directors has not made any determination as to whether the one non-employee director satisfies any independence requirements applicable to board members under the rules of the SEC or any national securities exchange, inter-dealer quotation system or any other independence definition.

We have a senior secured revolving credit facility with Wells Fargo Bank, N.A. as the administrative agent. As of September 30, 2012, the credit facility was subject to a $350.0 million borrowing base limit and we had $246.8 million outstanding under the credit facility. Each of our material operating subsidiaries is a guarantor of the credit facility. Our credit facility provides that we may not issue senior debt securities in excess of $700.0 million, including the $300.0 million of existing notes issued in October 2010 and exchanged for registered notes in August 2011 and the $150.0 million of old notes issued in October 2012. As a result of the sale of the old notes, the borrowing base under the amended credit facility was automatically reduced by 25 cents per dollar of old notes issued and the adjusted borrowing base is $313.7 million.

The credit facility matures on May 23, 2016, and principal amounts borrowed are payable on the maturity date with such borrowings bearing interest, payable quarterly. We have a choice of borrowing in Eurodollars or at the base rate. Eurodollar loans bear interest at a rate per annum equal to the rate appearing on the Reuters Reference LIBOR1 page as the London Interbank Offered Rate, for deposits in Dollars at 11:00 a.m. (London, England time) for one, three, or six months plus an applicable margin ranging from 200 to 275 basis points, depending on the percentage of our borrowing base utilized. Base rate loans bear interest at a rate per annum equal to the greatest of (i) the agent bank’s reference rate, (ii) the federal funds effective rate plus 50 basis points and (iii) the rate for one month Eurodollar loans plus 1%, plus an applicable margin ranging from 100 to 175 basis points, depending on the percentage of our borrowing base utilized. The borrowing base of $313.7 million was confirmed during the November redetermination. The next redetermination of our borrowing base is scheduled to be on or about May 1, 2013. Following the next scheduled borrowing base redetermination, we may be subject to restrictions on our ability to incur indebtedness or our borrowing base may be reduced. The amount outstanding under the amended credit facility is secured by first priority liens on substantially all of our oil and natural gas properties and associated assets. Our amended credit facility contains restrictive covenants that may limit our ability to, among other things:

The senior secured revolving credit facility also requires us to maintain the following three financial ratios:

We were founded in 1987 by Michael E. Ellis, and we or our subsidiaries have over time entered into promissory notes to repay Mr. Ellis for contributions of working capital and other amounts. These founder notes, which mature on December 31, 2018, bear interest at 10.0% paid-in-kind and are subordinated to the notes. The aggregate amount payable under these founder notes as of September 30, 2012 was $21.8 million. During the years ended December 31, 2011, 2010 and 2009, no amounts were paid in principal or interest. Interest on these founder notes is not compounded and amounted to $1.2 million during 2011, $1.4 million during 2010, and $1.2 million during 2009. Such amounts have been added to the balance of these founder notes.

We will issue the new notes under an indenture dated as of October 13, 2010 (the “Indenture”), among the Issuers, the Subsidiary Guarantors and Wells Fargo Bank, N.A., as trustee (the “Trustee”). The Issuers issued the old notes as additional notes under the Indenture in a private transaction that was not subject to the registration requirements of the Securities Act. The Issuers previously issued $300 million aggregate principal amount of 9⁵/₈% senior notes due 2018 under the Indenture in October 2010 which were exchanged for registered notes on August 12, 2011 (together, the “existing notes”). The old notes are, and the new notes will be, treated as a single class with the existing notes for purposes of the Indenture. However, until the old notes are exchanged for new notes, the existing notes that are registered will have a different CUSIP number than that of the old notes, which may adversely affect the liquidity of the old notes and cause the old notes to trade at different prices than the existing notes. Holders that exchange their old notes in the exchange offer described in this prospectus will receive registered notes having the same CUSIP number as the existing notes that are registered and which will thereafter be fungible with the existing notes that are registered. The terms of the new notes include those expressly set forth in the Indenture and those made part of the Indenture by reference to the Trust Indenture Act of 1939, as amended (the “Trust Indenture Act”).

Under the Indenture, the Issuers may issue an unlimited principal amount of additional notes having identical terms and conditions as the notes. The Issuers will only be permitted to issue such additional notes in compliance with the covenant described under the subheading “— Certain Covenants — Limitation on Indebtedness and Preferred Stock”. Any additional notes, together with any notes we may issue under a Registration Rights Agreement (“Exchange Notes”), will be part of the same series as the existing notes, the old notes and the new notes, will vote on all matters with the holders of the existing notes, the old notes and the new notes, and will be treated as a single class of securities under the Indenture, including, without limitation, with respect to waivers, amendments, redemptions and offers to purchase. Unless the context otherwise requires, for all purposes of the Indenture and this “Description of Notes”, references to the “notes” include the existing notes, new notes, the old notes and any additional notes actually issued. No offering of any such additional notes, however is being or shall in any manner be deemed to be made by this prospectus. In addition, there can be no assurance as to when or whether the Company will issue any such additional notes or as to the aggregate principal amount of any such additional notes.

This “Description of Notes” is intended to be a useful overview of the material provisions of the notes and the Indenture. Since this description is only a summary, you should refer to these documents for a complete description of the obligations of the Issuers and the Subsidiary Guarantors and your rights. A copy of the Indenture has been filed as an exhibit to the registration statement of which the prospectus is a part.

You will find the definitions of capitalized terms used in this description under the heading “— Certain Definitions”. For purposes of this description, references to “the Co-Issuer” refer only to Alta Mesa Finance Services Corp., the co-issuer of the notes, and references to “the Company”, “we”, “our” and “us” refer only to Alta Mesa Holdings, LP and not to any of its subsidiaries. The Co-Issuer and the Company are referred to jointly as the “Issuers”.

The registered holder of a new note will be treated as the owner of it for all purposes. Only registered holders of the notes have rights under the Indenture, and all references to “holders” in this “Description of Notes” are to registered holders of the notes.

If the exchange offer contemplated by this prospectus is consummated, holders of old notes who do not exchange those notes for new notes in the exchange offer will vote together with holders of existing notes and new notes for all relevant purposes under the Indenture. In that regard, the Indenture requires that certain actions by the holders thereunder must be taken, and certain rights must be exercised, by specified minimum percentages of the aggregate principal amount of the outstanding securities issued under the Indenture. In determining whether holders of the requisite percentage in principal amount have given any notice, consent or waiver or taken

any other action permitted under the Indenture, any old notes that remain outstanding after the exchange offer will be aggregated with the existing notes and the new notes, and the holders of such existing notes, old notes and the new notes will vote together as a single class for all such purposes. Accordingly, all references herein to specified percentages in aggregate principal amount of the notes outstanding shall be deemed to mean, at any time after the exchange offer is consummated, such percentages in aggregate principal amount of the existing notes, the old notes and the new notes then outstanding.

Initially, all of the Subsidiaries of the Company (other than the Co-Issuer and certain Immaterial Subsidiaries) will unconditionally guarantee the notes on a senior unsecured basis. In addition, future Domestic Subsidiaries (other than Immaterial Subsidiaries) of the Company will guarantee the Notes. See “— Certain Covenants — Future Subsidiary Guarantors”.

Not all of our Subsidiaries will be Subsidiary Guarantors. The notes and Guarantees will effectively be subordinated to the claims of creditors of any non-Guarantor Subsidiaries to the extent of the value of the assets thereof.

Initially, all of the Subsidiaries of the Company (including the Co-Issuer) were Restricted Subsidiaries, but under the circumstances described below in the definition of “Unrestricted Subsidiary” under the heading “—Certain Definitions”, the Company may designate certain of its Subsidiaries as “Unrestricted Subsidiaries”. Unrestricted Subsidiaries will not guarantee the Notes and will not be subject to the restrictive covenants in the Indenture.

The Issuers will pay interest on any overdue principal of the notes and on any overdue installment of interest at the above rate plus 1.0%, to the extent lawful.

If an interest payment date falls on a day that is not a Business Day, the interest payment to be made on such interest payment date will be made on the next succeeding Business Day with the same force and effect as if made on such interest payment date, and no additional interest will accrue as a result of such delayed payment.

The Issuers will pay principal of, premium, if any, and interest on the notes at the office or agency designated by us in the City and State of New York, except that they may, at their option, pay interest on the notes by check mailed to holders of the notes at their registered address as it appears in the registrar’s books. The Issuers have initially designated the Trustee to act as their paying agent at the corporate trust office of the Trustee in New York, New York, and they have also designated the Trustee to act as registrar at its corporate trust office in Dallas, Texas. The Issuers may, however, change the paying agent or registrar without prior notice to the holders of the notes, and the Company or any of its Restricted Subsidiaries may act as paying agent or registrar.

The Issuers will pay principal of, premium, if any, and interest on, notes in global form registered in the name of Cede & Co., the nominee or The Depository Trust Company, in immediately available funds, directly to The Depository Trust Company.

A holder may transfer or exchange notes in accordance with the Indenture. The registrar and the Trustee may require a holder, among other things, to furnish appropriate endorsements and transfer documents in connection with a transfer of notes. No service charge will be imposed by the Issuers, the Trustee or the registrar for any registration of transfer or exchange of notes, but the Issuers may require a holder to pay a sum sufficient to cover any transfer tax or other governmental taxes and fees required by law or permitted by the Indenture. The Issuers are not required to transfer or exchange any note selected for redemption. Also, the Issuers are not required to transfer or exchange any note for a period of 15 days before a selection of notes to be redeemed.

On and after October 15, 2014, the Issuers may redeem all or, from time to time, a part of the notes upon not less than 30 nor more than 60 days’ notice, at the following redemption prices (expressed as a percentage of principal amount of the notes), plus accrued and unpaid interest on the notes, if any, to the applicable redemption date (subject to the right of holders of record on the relevant record date to receive interest due on the relevant interest payment date), if redeemed during the twelve-month period beginning on October 15 of the years indicated below:

Prior to October 15, 2013, the Issuers may, at their option, on any one or more occasions redeem up to 35% of the aggregate principal amount of the notes (including any additional notes) issued under the Indenture with the Net Cash Proceeds of one or more Equity Offerings at a redemption price of 109.625% of the principal amount thereof, plus accrued and unpaid interest, if any, to the redemption date (subject to the right of holders of record on the relevant record date to receive interest due on the relevant interest payment date); provided that

(1) at least 65% of the aggregate principal amount of the notes (including any additional notes) issued under the Indenture remains outstanding after each such redemption; and

(2) the redemption occurs within 120 days after the closing of the related Equity Offering.

In addition, the notes may be redeemed, in whole or in part, at any time prior to October 15, 2014 at the option of the Issuers upon not less than 30 nor more than 60 days’ prior notice mailed by first-class mail to each holder of notes at its registered address, at a redemption price equal to 100% of the principal amount of the notes redeemed plus the Applicable Premium as of, and accrued and unpaid interest to, the applicable redemption date (subject to the right of holders of record on the relevant record date to receive interest due on the relevant interest payment date).

“Applicable Premium” means, with respect to any note on any applicable redemption date, the greater of:

(a) the present value at such redemption date of (i) the redemption price of such note at October 15, 2014 (such redemption price being set forth in the table appearing in the first paragraph of this “Optional Redemption” section) plus (ii) all required interest payments (excluding accrued and unpaid interest to such redemption date) due on such note through October 15, 2014 computed using a discount rate equal to the Treasury Rate as of such redemption date plus 50 basis points; over

“Treasury Rate” means, as of any redemption date, the yield to maturity at the time of computation of United States Treasury securities with a constant maturity (as compiled and published in the most recent Federal Reserve Statistical Release H.15 (519) which has become publicly available at least two Business Days prior to the redemption date (or, if such Statistical Release is no longer published, any publicly available source of similar market data)) most nearly equal to the period from the redemption date to October 15, 2014; provided, however, that if the period from the redemption date to October 15, 2014 is not equal to the constant maturity of a United States Treasury security for which a weekly average yield is given, the Treasury Rate shall be obtained by linear interpolation (calculated to the nearest one-twelfth of a year) from the weekly average yields of United

States Treasury securities for which such yields are given, except that if the period from the redemption date to October 15, 2014 is less than one year, the weekly average yield on actually traded United States Treasury securities adjusted to a constant maturity of one year shall be used. The Company will (a) calculate the Treasury Rate as of the second Business Day preceding the applicable redemption date and (b) prior to such redemption date file with the Trustee an Officers’ Certificate setting forth the Applicable Premium and the Treasury Rate and showing the calculation of each in reasonable detail.

If the Issuers are redeeming less than all of the outstanding notes, the Trustee will select the notes for redemption in compliance with the requirements of the principal national securities exchange, if any, on which the notes are listed or, if the notes are not listed, then on a pro rata basis (or, in the case of notes issued in global form as discussed under the caption “Book-Entry; Delivery and Form”, the Trustee will select the notes for redemption based on DTC’s method that most nearly approximates a pro rata selection), by lot or by such other method as the Trustee in its sole discretion will deem to be fair and appropriate, although no note of $2,000 in original principal amount or less will be redeemed in part. If any note is to be redeemed in part only, the notice of redemption relating to such note will state the portion of the principal amount thereof to be redeemed. A note in principal amount equal to the unredeemed portion thereof will be issued in the name of the holder thereof upon cancellation of the partially redeemed note. On and after the redemption date, interest will cease to accrue on notes or the portion of them called for redemption unless we default in the payment thereof.

We are not required to make mandatory redemption payments or sinking fund payments with respect to the notes. However, under certain circumstances, we may be required to offer to purchase notes as described under the captions “— Change of Control” and “— Certain Covenants — Limitation on Sales of Assets and Subsidiary Stock”.

The Company and its Subsidiaries may acquire notes by means other than a redemption or required repurchase, whether by tender offer, open market purchases, negotiated transactions or otherwise, in accordance with applicable securities laws, so long as such acquisition does not otherwise violate the terms of the Indenture. However, other existing or future agreements of the Company or its Subsidiaries may limit the ability of the Company or its Subsidiaries to purchase notes prior to maturity.

The Subsidiary Guarantors will, jointly and severally, fully and unconditionally guaranteed on a senior unsecured basis our obligations under the notes and all obligations under the Indenture. The obligations of each of the Subsidiary Guarantors under the Subsidiary Guarantees rank equally in right of payment with all other Indebtedness of such Subsidiary Guarantor, except to the extent such other Indebtedness is expressly subordinated in right of payment to the obligations arising under its Subsidiary Guarantee.

Although the Indenture will limit the amount of Indebtedness that the Subsidiary Guarantors may Incur, such Indebtedness may be substantial and such limitation is subject to a number of significant qualifications. Moreover, the Indenture does not impose any limitation on the Incurrence by the Subsidiary Guarantors of liabilities that are not considered Indebtedness under the Indenture. See “— Certain Covenants — Limitation on Indebtedness and Preferred Stock”.

The obligations of each Subsidiary Guarantor under its Subsidiary Guarantee will be limited as necessary to prevent that Subsidiary Guarantee from constituting a fraudulent conveyance or fraudulent transfer under applicable law, although no assurance can be given that a court would give the holder the benefit of such provision. See “Risk Factors — Risks Related to the Exchange Offer and New Notes — If the subsidiary guarantees are deemed fraudulent conveyances or preferential transfers, a court may subordinate or void them”.

Any guarantees of the notes by us or our operating subsidiaries could be deemed fraudulent conveyances under certain circumstances, and a court may subordinate or void the guarantees. If a Subsidiary Guarantee were rendered voidable, it could be subordinated by a court to all other indebtedness (including guarantees and other contingent liabilities) of the applicable Subsidiary Guarantor, and, depending on the amount of such indebtedness, a Subsidiary Guarantor’s liability on its Subsidiary Guarantee could be reduced to zero. If the obligations of a Subsidiary Guarantor under its Subsidiary Guarantee were avoided, holders of Notes would have to look to the assets of any remaining Subsidiary Guarantors for payment. There can be no assurance in that event that such assets would suffice to pay the outstanding principal and interest on the notes.

In the event a Subsidiary Guarantor is sold or disposed of (whether by merger, consolidation, the sale of all of its Capital Stock or the sale of all or substantially all of its assets (other than by lease) and whether or not the Subsidiary Guarantor is the surviving entity in such transaction) to a Person which is not the Company or a Subsidiary of the Company, such Subsidiary Guarantor will be released from its obligations under its Subsidiary Guarantee if the sale or other disposition does not violate the covenants described under “— Certain Covenants — Limitation on Sales of Assets and Subsidiary Stock”.

In addition, a Subsidiary Guarantor will be released from its obligations under its Subsidiary Guarantee, (a) if the Company designates such Subsidiary as an Unrestricted Subsidiary and such designation complies with the other applicable provisions of the Indenture or if such Subsidiary otherwise no longer qualifies as such or (b) in connection with any covenant defeasance, legal defeasance or satisfaction and discharge of the Notes as provided below under the captions “— Defeasance” and “— Satisfaction and Discharge”.

If a Change of Control occurs, unless the Issuers have previously or concurrently exercised their right to redeem all of the notes as described under “— Optional Redemption”, each holder will have the right to require the Company to repurchase all or any part (equal to $2,000 or an integral multiple of $1,000 in excess thereof) of such holder’s notes at a purchase price in cash equal to 101% of the principal amount of the notes plus accrued and unpaid interest, if any, to the date of purchase (subject to the right of holders of record on the relevant record date to receive interest due on the relevant interest payment date).

Within 30 days following any Change of Control, unless the Issuers have previously or concurrently exercised their right to redeem all of the notes as described under “— Optional Redemption”, we will mail a notice (the “Change of Control Offer”) to each holder, with a copy to the Trustee, stating:

(1) that a Change of Control has occurred and that such holder has the right to require us to purchase such holder’s notes at a purchase price in cash equal to 101% of the principal amount of such notes plus accrued and unpaid interest, if any, to the date of purchase (subject to the right of holders of record on a record date to receive interest on the relevant interest payment date) (the “Change of Control Payment”);

(2) the repurchase date (which shall be no earlier than 30 days nor later than 60 days from the date such notice is mailed) (the “Change of Control Payment Date”);

(3) that any note not properly tendered will remain outstanding and continue to accrue interest;

(4) that unless we default in the payment of the Change of Control Payment, all notes accepted for payment pursuant to the Change of Control Offer will cease to accrue interest on the Change of Control Payment Date;

(5) that holders electing to have any notes purchased pursuant to a Change of Control Offer will be required to surrender such notes, with the form entitled “Option of Holder to Elect Purchase” on the reverse of such notes in certificated form completed, to the paying agent specified in the notice at the address specified in the notice prior to the close of business on the third Business Day preceding the Change of Control Payment Date;

(6) that holders will be entitled to withdraw their tendered notes and their election to require us to purchase such notes, provided that the paying agent receives, not later than the close of business on the third Business Day preceding the Change of Control Payment Date, a telegram, telex, facsimile transmission or letter setting forth the name of the holder of the notes, the principal amount of notes tendered for purchase, and a statement that such holder is withdrawing its tendered notes and its election to have such notes purchased;

(7) that if we are repurchasing a portion of the note of any holder, the holder will be issued a new note equal in principal amount to the unpurchased portion of the note surrendered, provided that the unpurchased portion of the note must be equal to a minimum principal amount of $2,000 and an integral multiple of $1,000 in excess thereof; and

(8) the procedures determined by us, consistent with the Indenture, that a holder must follow in order to have its notes repurchased.

(1) accept for payment all notes or portions of notes (in a minimum principal amount of $2,000 and integral multiples of $1,000 in excess thereof) properly tendered pursuant to the Change of Control Offer and not properly withdrawn;

(2) deposit with the paying agent an amount equal to the Change of Control Payment in respect of all notes or portions of notes accepted for payment; and

(3) deliver or cause to be delivered to the Trustee the notes so accepted together with an Officers’ Certificate stating the aggregate principal amount of notes or portions of notes being purchased by the Company.

The paying agent will promptly mail or deliver to each holder of notes accepted for payment the Change of Control Payment for such notes, and the Trustee, upon delivery of a written request from the Company, will promptly authenticate and mail (or cause to be transferred by book entry) to each holder a new note equal in principal amount to any unpurchased portion of the notes surrendered, if any; provided that each such new note will be in a minimum principal amount of $2,000 or an integral multiple of $1,000 in excess thereof.

If the Change of Control Payment Date is on or after an interest record date and on or before the related interest payment date, any accrued and unpaid interest, will be paid to each Person in whose name a note is registered at the close of business on such record date, and no further interest will be payable to holders who tender pursuant to the Change of Control Offer.

The Change of Control provisions described above will be applicable whether or not any other provisions of the Indenture are applicable. Except as described above with respect to a Change of Control, the Indenture will not contain provisions that permit the holders to require that the Company or any Subsidiary repurchase or redeem the notes in the event of a takeover, recapitalization or similar transaction.

We will not be required to make a Change of Control Offer upon a Change of Control if any other Person makes the Change of Control Offer in the manner, at the times and otherwise in compliance with the requirements set forth in the Indenture applicable to a Change of Control Offer made by us and purchases all notes validly tendered and not withdrawn under such Change of Control Offer.

A Change of Control Offer may be made in advance of a Change of Control, and conditioned upon the occurrence of a Change of Control, if a definitive agreement is in place for the Change of Control at the time of making the Change of Control Offer.

We will comply, to the extent applicable, with the requirements of Rule 14e-1 of the Exchange Act and any other securities laws or regulations in connection with the repurchase of notes as a result of a Change of Control.

To the extent that the provisions of any securities laws or regulations conflict with provisions of this covenant, we will comply with the applicable securities laws and regulations and will not be deemed to have breached our obligations under in the Indenture by virtue of our compliance with such securities laws or regulations.

Our ability to repurchase notes pursuant to a Change of Control Offer may be limited by a number of factors. The occurrence of certain of the events that constitute a Change of Control would constitute a default under the Senior Secured Credit Agreement. In addition, certain events that may constitute a change of control under the Senior Secured Credit Agreement and cause a default under that agreement will not constitute a Change of Control under the Indenture. Future Indebtedness of the Company and its Subsidiaries may also contain prohibitions of certain events that would constitute a Change of Control or require such Indebtedness to be repaid upon a Change of Control. Moreover, the exercise by the holders of their right to require us to repurchase the notes could cause a default under other Indebtedness, even if the Change of Control itself does not, due to the financial effect of such repurchase on the Company and its Restricted Subsidiaries. Finally, the Company’s ability to pay cash to the holders upon a repurchase may be limited by the then existing financial resources of the Company and its Restricted Subsidiaries. There can be no assurance that sufficient funds will be available when necessary to make any required repurchases.

Even if sufficient funds were otherwise available, the other Indebtedness of the Company or its Restricted Subsidiaries may prohibit the Company’s repurchase of notes before their scheduled maturity. Consequently, if the Company and its Restricted Subsidiaries are not able to prepay the Indebtedness under the Senior Secured Credit Agreement and any such other Indebtedness containing similar restrictions or obtain requisite consents, the Company will be unable to fulfill its repurchase obligations if holders of notes exercise their repurchase rights following a Change of Control, resulting in a default under the Indenture. A default under the Indenture may result in a cross-default under the Senior Secured Credit Agreement.

The Change of Control provisions described above may deter certain mergers, tender offers and other takeover attempts involving the Company. The Change of Control purchase feature is a result of negotiations between the initial purchasers and the Company. The Company has no present intention to engage in a transaction involving a Change of Control, although it is possible that it could decide to do so in the future. Subject to the limitations discussed below, the Company or its Subsidiaries could, in the future, enter into certain transactions, including acquisitions, refinancings or other recapitalizations, that would not constitute a Change of Control under the Indenture, but that could increase the amount of indebtedness outstanding at such time or otherwise affect our capital structure or credit ratings. Restrictions on the ability of the Company and its Restricted Subsidiaries to incur additional Indebtedness are contained in the covenants described under “—Certain Covenants — Limitation on Indebtedness and Preferred Stock” and “— Certain Covenants — Limitation on Liens”. Such restrictions in the Indenture can be waived only with the consent of the holders of a majority in principal amount of the Notes then outstanding. Except for the limitations contained in such covenants, however, the Indenture will not contain any covenants or provisions that may afford holders of the notes protection in the event of a highly leveraged transaction.

The definition of “Change of Control” includes a disposition of all or substantially all of the assets of the Company and its Restricted Subsidiaries taken as a whole to any Person. Although there is a limited body of case law interpreting the phrase “substantially all”, there is no precise established definition of the phrase under applicable law. Accordingly, in certain circumstances there may be a degree of uncertainty as to whether a particular transaction would involve a disposition of “all or substantially all” of the assets of a Person. As a result, it may be unclear as to whether a Change of Control has occurred and whether a holder of notes may require the Company to make an offer to repurchase the notes as described above.

The provisions under the Indenture relative to our obligation to make an offer to repurchase the notes as a result of a Change of Control may be waived or modified or terminated with the consent of the holders of a majority in principal amount of the notes then outstanding (including consents obtained in connection with a tender offer or exchange offer for the notes), but only if done prior to the occurrence of such Change of Control.

The Company will not, and will not permit any of its Restricted Subsidiaries to, directly or indirectly, Incur any Indebtedness (including Acquired Indebtedness), and the Company will not permit any of its Restricted Subsidiaries to issue Preferred Stock; provided, however, that the Company and any of the Subsidiary Guarantors may Incur Indebtedness and issue Preferred Stock if on the date thereof:

(1) the Consolidated Coverage Ratio for the Company and its Restricted Subsidiaries is at least 2.25 to 1.00, determined on a pro forma basis (including a pro forma application of proceeds); and

(2) no Default would occur as a consequence of, and no Event of Default would be continuing following, Incurring the Indebtedness or its application.

The first paragraph of this covenant will not prohibit the Incurrence of the following:

(1) Indebtedness under one or more Credit Facilities (including the Senior Secured Credit Agreement) Incurred pursuant to this clause (1) by the Issuers or any Subsidiary Guarantor in an aggregate amount outstanding at any one time not to exceed the greater of (i) $300.0 million or (ii) 30.0% of the Company’s Adjusted Consolidated Net Tangible Assets determined as of the date of the Incurrence of such Indebtedness after giving effect to the application of the proceeds therefrom;

(2) guarantees of Indebtedness Incurred in accordance with the provisions of the Indenture; provided that in the event such Indebtedness that is being guaranteed is a Subordinated Obligation or a Guarantor Subordinated Obligation, then the related guarantee shall be subordinated in right of payment to the Notes or the Subsidiary Guarantees to at least the same extent as the Indebtedness being guaranteed, as the case may be;

(3) Indebtedness of the Company owing to and held by any Restricted Subsidiary or Indebtedness of a Restricted Subsidiary owing to and held by the Company or any Restricted Subsidiary; provided, however, that (a)(i) if the Company is the obligor on such Indebtedness and the obligee is not a Subsidiary Guarantor, such Indebtedness must be expressly subordinated to the prior payment in full in cash of all obligations with respect to the Notes and (ii) if a Subsidiary Guarantor is the obligor of such Indebtedness and the obligee is neither the Company nor a Subsidiary Guarantor, such Indebtedness must be expressly subordinated to the prior payment in full in cash of all obligations of such Subsidiary Guarantor with respect to its Subsidiary Guarantee and (b)(i) any subsequent issuance or transfer of Capital Stock or any other event which results in any such Indebtedness being held by a Person other than the Company or a Restricted Subsidiary of the Company and (ii) any sale or other transfer of any such Indebtedness to a Person other than the Company or a Restricted Subsidiary of the Company shall be deemed, in each case, to constitute an Incurrence of such Indebtedness by the Company or such Restricted Subsidiary, as the case may be, that was not permitted by this clause;

(4) Indebtedness represented by (a) the notes issued on the Issue Date and all Subsidiary Guarantees, (b) any Indebtedness (other than the Indebtedness described in clauses (1), (3), 4(a) and (9) of this paragraph) outstanding on the Issue Date, (c) any Exchange Notes and related Subsidiary Guarantees issued pursuant to a Registration Rights Agreement and (d) any Refinancing Indebtedness Incurred in respect of any Indebtedness described in this clause (4) or clause (5) or Incurred pursuant to the first paragraph of this covenant;

(6) Indebtedness Incurred in respect of (a) self-insurance obligations or bid, plugging and abandonment, appeal, reimbursement, performance, surety and similar bonds provided by the Company or a Restricted Subsidiary in the ordinary course of business and any guarantees or letters of credit functioning as or supporting any of such obligations or bonds and (b) obligations represented by letters of credit for the account of the Company or a Restricted Subsidiary in order to provide security for workers’ compensation claims (in the case of both clauses (a) and (b) other than for an obligation for money borrowed);

(7) Indebtedness of the Company or any Subsidiary Guarantor represented by Capitalized Lease Obligations (whether or not incurred pursuant to Sale/Leaseback Transactions) or other Indebtedness incurred or assumed in connection with the acquisition, construction, improvement or development of real or personal, movable or immovable, property, in each case Incurred for the purpose of financing, refinancing, renewing, defeasing or refunding all or any part of the purchase price or cost of acquisition, construction, improvement or development of property used in the business of the Company or the Subsidiary Guarantors; provided that the aggregate principal amount incurred by the Company or any Subsidiary Guarantor pursuant to this clause (7) outstanding at any time shall not exceed the greater of (x) $25.0 million and (y) 2.5% of the Company’s Adjusted Consolidated Net Tangible Assets; and provided further that the principal amount of any Indebtedness permitted under this clause (7) did not in each case at the time of incurrence exceed the Fair Market Value, as determined in accordance with the definition of such term, of the acquired or constructed asset or improvement so financed;

(8) Indebtedness to the extent that the net proceeds thereof are promptly deposited to defease the notes or to satisfy and discharge the Indenture;

(9) in addition to the items referred to in clauses (1) through (8) above, Indebtedness of the Company and its Restricted Subsidiaries in an aggregate outstanding principal amount which, when taken together with the principal amount of all other Indebtedness Incurred pursuant to this clause (9) and then outstanding, will not exceed the greater of (a) $35.0 million, and (b) 5.0% of the Company’s Adjusted Consolidated Net Tangible Assets.

For purposes of determining compliance with, and the outstanding principal amount of any particular Indebtedness Incurred pursuant to and in compliance with, this covenant:

(1) in the event an item of that Indebtedness meets the criteria of more than one of the types of Indebtedness described in the first and second paragraphs of this covenant, the Company, in its sole discretion, will classify such item of Indebtedness on the date of Incurrence and, subject to clause (2) below may later classify, reclassify or redivide all or a portion of such item of Indebtedness, in any manner that complies with this covenant;

(2) any Indebtedness outstanding on the date of the Indenture under the Senior Secured Credit Agreement shall be deemed Incurred on the Issue Date under clause (1) of the second paragraph of this covenant;

(3) guarantees of, or obligations in respect of letters of credit supporting, Indebtedness which is otherwise included in the determination of a particular amount of Indebtedness shall not be included;

(4) the principal amount of any Disqualified Stock of the Company or a Restricted Subsidiary, or Preferred Stock of a Restricted Subsidiary, will be equal to the greater of the maximum mandatory redemption or repurchase price (including, in either case, any redemption or repurchase premium) or the liquidation preference thereof;

(5) Indebtedness permitted by this covenant need not be permitted solely by reference to one provision permitting such Indebtedness but may be permitted in part by one such provision and in part by one or more other provisions of this covenant permitting such Indebtedness; and

(6) the amount of Indebtedness issued at a price that is less than the principal amount thereof will be equal to the amount of the liability in respect thereof determined in accordance with GAAP.

Accrual of interest, accrual of dividends, the amortization of debt discount or the accretion of accreted value and unrealized losses or charges in respect of Hedging Obligations (including those resulting from the application of Statement of Financial Accounting Standard No. 133) will not be deemed to be an Incurrence of Indebtedness for purposes of this covenant.

The Company will not permit any of its Unrestricted Subsidiaries to Incur any Indebtedness other than Non-Recourse Debt. If at any time an Unrestricted Subsidiary becomes a Restricted Subsidiary, any Indebtedness

of such Subsidiary shall be deemed to be Incurred by a Restricted Subsidiary as of such date (and, if such Indebtedness is not permitted to be Incurred as of such date under this “Limitation on Indebtedness and Preferred Stock” covenant, the Company shall be in Default of this covenant).

The Indenture will not treat (1) unsecured Indebtedness as subordinated or junior to secured Indebtedness merely because it is unsecured or (2) senior Indebtedness as subordinated or junior to any other senior Indebtedness merely because it has a junior priority with respect to the same collateral.

The Company will not, and will not permit any of its Restricted Subsidiaries, directly or indirectly, to:

(1) declare or pay any dividend or make any payment or distribution on or in respect of its Capital Stock (including any payment or distribution in connection with any merger or consolidation involving the Company or any of its Restricted Subsidiaries) except:

(a) dividends or distributions by the Company payable solely in Capital Stock of the Company (other than Disqualified Stock); and

(b) dividends or distributions payable to the Company or a Restricted Subsidiary and if such Restricted Subsidiary is not a Wholly Owned Subsidiary, to minority stockholders (or owners of an equivalent interest in the case of a Subsidiary that is an entity other than a corporation) so long as the Company or a Restricted Subsidiary receives at least its pro rata share of such dividend or distribution;

(2) purchase, repurchase, redeem, defease or otherwise acquire or retire for value any Capital Stock of the Company or any direct or indirect parent of the Company held by Persons other than the Company or a Wholly Owned Subsidiary;

(3) purchase, repurchase, redeem, defease or otherwise acquire or retire for value, prior to scheduled maturity, scheduled repayment or scheduled sinking fund payment, any Subordinated Obligations or Guarantor Subordinated Obligations (other than (x) Indebtedness permitted under clause (3) of the second paragraph of the covenant described above under “— Limitation on Indebtedness and Preferred Stock” or (y) the purchase, repurchase, redemption, defeasance or other acquisition or retirement of Subordinated Obligations or Guarantor Subordinated Obligations purchased in anticipation of satisfying a sinking fund obligation, principal installment or final maturity, in each case due within one year of the date of purchase, repurchase, redemption, defeasance or other acquisition or retirement); or

(any such dividend, distribution, purchase, repurchase, redemption, defeasance, other acquisition or retirement or Restricted Investment referred to in clauses (1) through (4) is referred to herein as a “Restricted Payment”), if at the time the Company or such Restricted Subsidiary makes such Restricted Payment:

(b) the Company is not able to Incur an additional $1.00 of Indebtedness pursuant to the first paragraph of the covenant described under “— Limitation on Indebtedness and Preferred Stock” after giving effect, on a pro forma basis, to such Restricted Payment; or

(c) the aggregate amount of such Restricted Payment and all other Restricted Payments declared or made subsequent to the Issue Date (other than under clauses (1), (2), (4), (5), (6), (7), (8), (9), (10), and (11) of the next paragraph) would exceed the sum of (the “Basket Amount”):

(i) 50% of Consolidated Net Income accrued on a cumulative basis for the period (treated as one accounting period) from October 1, 2010 to the end of the most recent fiscal quarter ending prior to the date of such Restricted Payment for which financial statements are in existence (or, in case such Consolidated Net Income is a deficit, minus 100% of such deficit);

(ii) 100% of the aggregate Net Cash Proceeds and the Fair Market Value of any Capital Stock of Persons engaged primarily in the Oil and Gas Business or assets used in the Oil and Gas Business, in each case received by the Company from the issue or sale of its Capital Stock (other than Disqualified Stock) or from cash capital contributions subsequent to the Issue Date (other than Net Cash Proceeds received from an issuance or sale of such Capital Stock to (x) a Subsidiary of the Company or (y) an employee stock ownership plan, option plan or similar trust (to the extent such sale to an employee stock ownership plan, option plan or similar trust is financed by loans from or guaranteed by the Company or any Restricted Subsidiary unless such loans have been repaid with cash on or prior to the date of determination));

(iii) the amount by which Indebtedness of the Company or its Restricted Subsidiaries is reduced on the Company’s balance sheet upon the conversion or exchange (other than by a Subsidiary of the Company) subsequent to the Issue Date of any Indebtedness of the Company or its Restricted Subsidiaries convertible or exchangeable for Capital Stock (other than Disqualified Stock) of the Company (less the amount of any cash, or the Fair Market Value of any other property (other than such Capital Stock), distributed by the Company upon such conversion or exchange), together with the net proceeds, if any, received by the Company or any of its Restricted Subsidiaries upon such conversion or exchange; and

(iv) the amount equal to the aggregate net reduction in Restricted Investments made by the Company or any of its Restricted Subsidiaries in any other Person after the Issue Date resulting from:

(A) repurchases, repayments or redemptions of such Restricted Investments by such Person, proceeds realized upon the sale of such Restricted Investments (other than to a Subsidiary of the Company), or repayments of loans or advances or other transfers of assets (including by way of dividend or distribution) by such Person to the Company or any Restricted Subsidiary; and

(B) the redesignation of Unrestricted Subsidiaries as Restricted Subsidiaries (valued in each case as provided in the definition of “Investment”) not to exceed, in the case of any Unrestricted Subsidiary, the amount of Investments previously made by the Company or any Restricted Subsidiary in such Unrestricted Subsidiary, which amount in each case under this clause (iv) was included in the calculation of the amount of Restricted Payments; provided, however, that no amount will be included under this clause (iv) to the extent it is already included in Consolidated Net Income.

(1) any Restricted Payment made by exchange for, or out of the proceeds of the substantially concurrent sale of, Capital Stock of the Company (other than Disqualified Stock and other than Capital Stock issued or sold to a Subsidiary of the Company or an employee stock ownership plan, option plan or similar trust to the extent such sale to an employee stock ownership plan, option plan or similar trust is financed by loans from or guaranteed by the Company or any Restricted Subsidiary unless such loans have been repaid with cash on or prior to the date of determination) or a substantially concurrent cash capital contribution received by the Company from the owners of its Capital Stock; provided that the Net Cash Proceeds from such sale of Capital Stock or capital contribution will be excluded from clause (c)(ii) of the preceding paragraph;

(2) any purchase, repurchase, redemption, defeasance or other acquisition or retirement of Subordinated Obligations of an Issuer or Guarantor Subordinated Obligations of any Subsidiary Guarantor made by exchange for, or out of the proceeds of the substantially concurrent sale of Refinancing Indebtedness with respect to such Subordinated Obligations or Guarantor Subordinated Obligations permitted to be Incurred pursuant to the covenant described above under “— Limitation on Indebtedness and Preferred Stock”;

(3) dividends paid or distributions made within 60 days after the date of declaration if at such date of declaration such dividend or distribution would have complied with this covenant; provided, however, that

such dividends and distributions will be included in subsequent calculations of the Basket Amount; and provided further, however, that for purposes of clarification, this clause (3) shall not include cash payments in lieu of the issuance of fractional shares included in clause (8) below;

(4) the repurchase or other acquisition of Capital Stock (including options, warrants, equity appreciation rights or other rights to purchase or acquire Capital Stock) of the Company held by any existing or former employees, officers or directors of the Company or the General Partner or any Restricted Subsidiary of the Company or their assigns, estates or heirs, in each case pursuant to the repurchase or other acquisition provisions under employee stock option or stock purchase plans or agreements or other agreements to compensate employees, officers or directors, in each case approved by the Company’s Board of Directors; provided that such repurchases or other acquisitions pursuant to this clause (4) will not exceed $2.0 million in the aggregate during any calendar year; and provided that the proceeds received from any such transaction will be excluded from clause (c)(ii) of the preceding paragraph;

(5) purchases, repurchases, redemptions or other acquisitions or retirements for value of Capital Stock deemed to occur upon the exercise of stock options, warrants, rights to acquire Capital Stock or other convertible securities if such Capital Stock represents a portion of the exercise or exchange price thereof, and any purchases, repurchases, redemptions or other acquisitions or retirements for value of Capital Stock made in lieu of withholding taxes in connection with any exercise or exchange of warrants, options or rights to acquire Capital Stock;

(6) the purchase, repurchase, redemption, defeasance or other acquisition or retirement for value of any Subordinated Obligation (i) at a purchase price not greater than 101% of the principal amount of such Subordinated Obligation in the event of a Change of Control in accordance with provisions similar to the covenant described under “— Change of Control” or (ii) at a purchase price not greater than 100% of the principal amount thereof in accordance with provisions similar to the covenant described under “—Limitation on Sales of Assets and Subsidiary Stock”; provided that, prior to or simultaneously with such purchase, repurchase, redemption, defeasance or other acquisition or retirement, the Company has made the Change of Control Offer or Asset Disposition Offer, as applicable, as provided in such covenant with respect to the notes and has completed the repurchase of all Notes accepted for payment in connection with such Change of Control Offer or Asset Disposition Offer;

(7) so long as no Default has occurred and is continuing, payments or distributions to dissenting equityholders pursuant to applicable law or in connection with the settlement or other satisfaction of legal claims made pursuant to or in connection with a consolidation, merger or transfer of assets;

(9) the declaration and payment of scheduled or accrued dividends to holders of any class of or series of Disqualified Stock of the Company issued after the Issue Date in accordance with the covenant captioned “— Limitation on Indebtedness and Preferred Stock”, to the extent such dividends are included in Consolidated Interest Expense;

(10) so long as the Company is treated for U.S. federal tax purposes as a disregarded entity or partnership, Permitted Tax Distributions;

(11) dividends paid or distributions made by the Company, or purchases, repurchases, redemptions or other acquisitions or retirements for value of Capital Stock of the Company, within 60 days after the Issue Date from proceeds of the issuance of the notes in an aggregate amount not to exceed $50.0 million; and

(12) so long as no Default has occurred and is continuing, Restricted Payments in an amount not to exceed $25.0 million in the aggregate since the Issue Date.

The amount of all Restricted Payments (other than cash) shall be the Fair Market Value on the date of such Restricted Payment of the securities or other assets proposed to be paid, transferred or issued by the Company or such Restricted Subsidiary, as the case may be, pursuant to such Restricted Payment. The Fair Market Value of any cash Restricted Payment shall be its face amount, and the Fair Market Value of any non-cash Restricted

Payment shall be determined in accordance with the definition of that term. Not later than the date of making any Restricted Payment pursuant to clause (c) of the second preceding paragraph or clause (12) of the preceding paragraph, the Company shall deliver to the Trustee an Officers’ Certificate stating that such Restricted Payment is permitted and setting forth the basis upon which the calculations required by this covenant were computed and the Basket Amount after giving effect to such Restricted Payment.

In the event that a Restricted Payment meets the criteria of more than one of the exceptions described in clauses (1) through (12) above or is entitled to be made pursuant to the first paragraph above, the Company shall, in its sole discretion, classify such Restricted Payment and may later re-classify all or a portion of such Restricted Payment.

The Company will not permit any Unrestricted Subsidiary to become a Restricted Subsidiary except pursuant to the last sentence of the definition of “Unrestricted Subsidiary”. For purpose of designating any Restricted Subsidiary as an Unrestricted Subsidiary, all outstanding Investments by the Company and its Restricted Subsidiaries (except to the extent repaid) in the Subsidiary so designated will be deemed to be Restricted Payments in an amount determined as set forth in the last sentence of the definition of “Investment”. Such designation will be permitted only if a Restricted Payment in such amount would be permitted at such time, whether pursuant to the first paragraph of this covenant or under clause (12) of the second paragraph of this covenant, or pursuant to the definition of “Permitted Investments”, and if such Subsidiary otherwise meets the definition of an Unrestricted Subsidiary. Unrestricted Subsidiaries will not guarantee the Notes and will not be subject to any of the restrictive covenants set forth in the Indenture.

The Company will not, and will not permit any of its Restricted Subsidiaries to, directly or indirectly, create, Incur or suffer to exist any Lien (other than Permitted Liens) upon any of its property or assets (including Capital Stock of Restricted Subsidiaries), including any income or profits therefrom, whether owned on the date of the Indenture or acquired after that date, which Lien is securing any Indebtedness, unless contemporaneously with the Incurrence of such Lien effective provision is made to secure the Indebtedness due under the Notes (in the case of the Company) or any Subsidiary Guarantee of such other Restricted Subsidiary, equally and ratably with (or senior in priority to in the case of Liens with respect to Subordinated Obligations or Guarantor Subordinated Obligations, as the case may be) the Indebtedness secured by such Lien for so long as such Indebtedness is so secured.

The Company will not, and will not permit any Restricted Subsidiary (other than the Co-Issuer) to, create or otherwise cause or permit to exist or become effective any consensual encumbrance or consensual restriction on the ability of any such Restricted Subsidiary to:

(1) pay dividends or make any other distributions on its Capital Stock or pay any Indebtedness or other obligations owed to the Company or any other Restricted Subsidiary (it being understood that the priority of any Preferred Stock in receiving dividends or liquidating distributions prior to dividends or liquidating distributions being paid on Common Stock shall not be deemed a restriction on the ability to make distributions on Capital Stock);

(2) make any loans or advances to the Company or any other Restricted Subsidiary (it being understood that the subordination of loans or advances made to the Company or any Restricted Subsidiary to other Indebtedness Incurred by the Company or any Restricted Subsidiary shall not be deemed a restriction on the ability to make loans or advances); or

(3) sell, lease or transfer any of its property or assets to the Company or any other Restricted Subsidiary.

(i) any encumbrance or restriction pursuant to or by reason of an agreement in effect at or entered into on the Issue Date, including the Indenture and the Senior Secured Credit Agreement, each as in effect on such date;

(ii) any encumbrance or restriction with respect to a Person pursuant to or by reason of an agreement relating to any Capital Stock or Indebtedness Incurred by a Person on or before the date on which such Person was acquired by the Company or another Restricted Subsidiary (other than Capital Stock or Indebtedness Incurred as consideration in, or to provide all or any portion of the funds utilized to consummate, the transaction or series of related transactions pursuant to which such Person was acquired by the Company or a Restricted Subsidiary or in contemplation of the transaction) and outstanding on such date; provided that any such encumbrance or restriction shall not extend to any assets or property of the Company or any other Restricted Subsidiary other than the assets and property so acquired;

(iii) any encumbrance or restriction contained in contracts entered into in the ordinary course of business, not relating to any Indebtedness, and that do not, individually or in the aggregate, detract from the value of, or from the ability of the Company and the Restricted Subsidiaries to realize the value of, property or assets of the Company or any Restricted Subsidiary in any manner material to the Company or any Restricted Subsidiary;

(iv) any encumbrance or restriction with respect to a Restricted Subsidiary pursuant to an agreement effecting a refunding, replacement or refinancing of Indebtedness Incurred pursuant to an agreement referred to in clauses (i) and (ii) or clause (ix) of this paragraph or this clause (iv) or contained in any amendment, restatement, modification, renewal, supplemental, refunding, replacement or refinancing of an agreement referred to in clauses (i) and (ii) or clause (ix) of this paragraph or this clause (iv); provided that the encumbrances and restrictions with respect to such Restricted Subsidiary contained in any such agreement taken as a whole are no less favorable in any material respect to the holders of the Notes than the encumbrances and restrictions contained in the agreements governing the Indebtedness being refunded, replaced or refinanced;

(v) in the case of clause (3) of the first paragraph of this covenant, any encumbrance or restriction:

(a) that restricts in a customary manner the subletting, assignment or transfer of any property or asset that is subject to a lease (including leases governing leasehold interests or farm-in agreements or farm-out agreements relating to leasehold interests in Oil and Gas Properties), license or similar contract, or the assignment or transfer of any such lease (including leases governing leasehold interests or farm-in agreements or farm-out agreements relating to leasehold interests in Oil and Gas Properties), license (including licenses of intellectual property) or other contract;

(b) contained in mortgages, pledges or other security agreements permitted under the Indenture securing Indebtedness of the Company or a Restricted Subsidiary to the extent such encumbrances or restrictions restrict the transfer of the property subject to such mortgages, pledges or other security agreements;

(d) pursuant to customary provisions restricting dispositions of real property interests set forth in any reciprocal easement agreements of the Company or any Restricted Subsidiary;

(e) on cash or other deposits imposed by customers under contracts entered into in the ordinary course of business; or

(f) with respect to the disposition or distribution of assets or property in operating agreements, joint venture agreements, development agreements, area of mutual interest agreements and other agreements that are customary in the Oil and Gas Business and entered into in the ordinary course of business;

(vi) any encumbrance or restriction contained in (a) purchase money obligations for property acquired in the ordinary course of business and (b) Capitalized Lease Obligations, in each case that are permitted under the Indenture and that impose encumbrances or restrictions of the nature described in clause (3) of the first paragraph of this covenant on the property or assets so acquired, and any proceeds thereof;

(vii) any encumbrance or restriction with respect to a Restricted Subsidiary (or any of its property or assets) imposed pursuant to an agreement entered into for the direct or indirect sale or other disposition of all or a portion of the Capital Stock or property or assets of such Restricted Subsidiary pending the closing of such sale or other disposition;

(viii) any encumbrance or restriction arising or existing by reason of applicable law or any applicable rule, regulation or order;

(ix) any encumbrance or restriction contained in agreements governing Indebtedness of the Company or any of its Restricted Subsidiaries permitted to be Incurred pursuant to an agreement entered into subsequent to the Issue Date in accordance with the covenant described above under the caption “—Limitation on Indebtedness and Preferred Stock”; provided that the provisions relating to such encumbrance or restriction contained in such Indebtedness, taken as a whole, are not materially less favorable to the Company taken as a whole, as determined by the Board of Directors of the Company in good faith, than the provisions contained in the Senior Secured Credit Agreement and in the Indenture as in effect on the Issue Date; and

(x) any encumbrance or restriction on cash or other deposits or net worth imposed by customers under contracts or required by insurance, surety or bonding companies, in each case entered into or incurred in the ordinary course of business.

The Company will not, and will not permit any of its Restricted Subsidiaries to, make any Asset Disposition unless:

(1) the Company or such Restricted Subsidiary, as the case may be, receives consideration at the time of such Asset Disposition at least equal to the Fair Market Value (such Fair Market Value to be determined on the date of contractually agreeing to such Asset Disposition) of the Capital Stock or other assets subject to such Asset Disposition;

(2) at least 75% of the consideration received by the Company or such Restricted Subsidiary, as the case may be, is in the form of cash or Cash Equivalents or Additional Assets, or any combination thereof; and

(3) except as provided in the next paragraph, an amount equal to 100% of the Net Available Cash from such Asset Disposition is applied, within 360 days from the later of the date of such Asset Disposition or the receipt of such Net Available Cash, by the Company or such Restricted Subsidiary, as the case may be:

(a) to prepay, repay, redeem or purchase Indebtedness (other than intercompany Indebtedness, Subordinated Obligations, Capital Stock or Indebtedness owed to an Affiliate of the Company); provided, however, that, in connection with any prepayment, repayment, redemption or purchase of Indebtedness pursuant to this clause (a), the Company or such Restricted Subsidiary will cause the related commitment to be permanently reduced in an amount equal to the principal amount so prepaid, repaid, redeemed or purchased; or

(b) to invest in Additional Assets or to make capital expenditures in the Oil and Gas Business;

provided that pending the final application of any such Net Available Cash in accordance with clause (a) or clause (b) above, the Company and its Restricted Subsidiaries may temporarily reduce revolving credit Indebtedness or otherwise invest such Net Available Cash in any manner not prohibited by the Indenture.

Any Net Available Cash from Asset Dispositions that is not applied or invested as provided in the preceding paragraph will be deemed to constitute “Excess Proceeds”. Not later than the 360th day from the later of the date of such Asset Disposition or the receipt of such Net Available Cash, if the aggregate amount of Excess Proceeds exceeds $20.0 million, the Company will be required to make an offer (“Asset Disposition Offer”) to all holders of notes and, to the extent required by the terms of other Pari Passu Indebtedness, to all holders of other Pari Passu Indebtedness outstanding with similar provisions requiring the Company to make an offer to purchase such Pari Passu Indebtedness with the proceeds from any Asset Disposition (“Pari Passu Notes”), to purchase the maximum principal amount of notes and any such Pari Passu notes to which the Asset Disposition Offer applies that may be purchased out of the Excess Proceeds, at an offer price in cash in an amount equal to 100% of the principal amount (or, in the event such Pari Passu Indebtedness was issued with original issue discount, 100% of the accreted value thereof) of the notes and Pari Passu notes plus accrued and unpaid interest, if any (or in respect of such Pari Passu notes, such lesser price, if any, as may be provided for by its terms), to the date of purchase (subject to the right of holders of record on the relevant record date to receive interest due on the relevant interest payment date), in accordance with the procedures set forth in the Indenture or the agreements governing the Pari Passu notes, as applicable, in each case in a minimum principal amount of $2,000 and integral multiples of $1,000 in excess thereof. If the aggregate principal amount of notes surrendered by holders thereof and other Pari Passu notes surrendered by holders or lenders, collectively, exceeds the amount of Excess Proceeds, the Trustee shall select the notes to be purchased on a pro rata basis (or, in the case of notes issued in global form as discussed under the caption “Book-Entry; Delivery and Form”, the Trustee will select the notes for purchase based on DTC’s method that most nearly approximates a pro rata selection) on the basis of the aggregate principal amount of tendered notes and Pari Passu notes. To the extent that the aggregate amount of notes and Pari Passu notes so validly tendered and not properly withdrawn pursuant to an Asset Disposition Offer is less than the Excess Proceeds, the Company and its Restricted Subsidiaries may use any remaining Excess Proceeds for general corporate purposes, subject to the other covenants contained in the Indenture. Upon completion of such Asset Disposition Offer, the amount of Excess Proceeds shall be reset at zero.

The Asset Disposition Offer will remain open for a period of 20 Business Days following its commencement, except to the extent that a longer period is required by applicable law (the “Asset Disposition Offer Period”). No later than two Business Days after the termination of the Asset Disposition Offer Period (the “Asset Disposition Purchase Date”), the Company will purchase the principal amount of notes and Pari Passu notes required to be purchased pursuant to this covenant (the “Asset Disposition Offer Amount”) or, if less than the Asset Disposition Offer Amount has been so validly tendered and not properly withdrawn, all notes and Pari Passu notes validly tendered and not properly withdrawn in response to the Asset Disposition Offer.

If the Asset Disposition Purchase Date is on or after an interest record date and on or before the related interest payment date, any accrued and unpaid interest will be paid to each Person in whose name a note is registered at the close of business on such record date, and no further interest will be payable to holders who tender notes pursuant to the Asset Disposition Offer.

On or before the Asset Disposition Purchase Date, the Company will, to the extent lawful, accept for payment, on a pro rata basis to the extent necessary, the Asset Disposition Offer Amount of notes and Pari Passu notes or portions of notes and Pari Passu notes so validly tendered and not properly withdrawn pursuant to the Asset Disposition Offer, or if less than the Asset Disposition Offer Amount has been validly tendered and not properly withdrawn, all notes and Pari Passu notes so validly tendered and not properly withdrawn, in each case in a minimum principal amount of $2,000 and integral multiples of $1,000 in excess thereof. The Company will deliver to the Trustee an Officers’ Certificate stating that such notes or portions thereof were accepted for payment by the Company in accordance with the terms of this covenant and, in addition, the Company will deliver all certificates required, if any, by the agreements governing the Pari Passu notes. On the Asset Disposition Purchase Date, the Company or the paying agent, as the case may be, will mail or deliver to each tendering holder of notes or holder or lender of Pari Passu notes, as the case may be, an amount equal to the purchase price of the notes or Pari Passu notes so validly tendered and not properly withdrawn by such holder or lender, as the case may be, and accepted by the Company for purchase, and the Company will promptly issue a

new note, and the Trustee, upon delivery of a written request from the Company, will authenticate and mail or deliver such new note to such holder, in a principal amount equal to any unpurchased portion of the note surrendered; provided that each such new note will be in a minimum principal amount of $2,000 or an integral multiple of $1,000 in excess thereof. In addition, the Company will take any and all other actions required by the agreements governing the Pari Passu notes. Any note not so accepted will be promptly mailed or delivered by the Issuer to the holder thereof. The Company will publicly announce the results of the Asset Disposition Offer on the Asset Disposition Purchase Date.

The Company will comply, to the extent applicable, with the requirements of Rule 14e-1 of the Exchange Act and any other securities laws or regulations in connection with the repurchase of notes pursuant to an Asset Disposition Offer. To the extent that the provisions of any securities laws or regulations conflict with provisions of this covenant, the Company will comply with the applicable securities laws and regulations and will not be deemed to have breached its obligations under the Indenture by virtue of its compliance with such securities laws or regulations.

For the purposes of clause (2) of the first paragraph of this covenant, the following will be deemed to be cash:

(1) the assumption by the transferee of Indebtedness of the Company or Indebtedness of a Restricted Subsidiary (other than intercompany Indebtedness, Subordinated Obligations, Capital Stock or Indebtedness owed to an Affiliate of the Company) and the release of such Issuer or Restricted Subsidiary from all liability on such Indebtedness in connection with such Asset Disposition; and

(2) securities, notes or other obligations received by the Company or any Restricted Subsidiary from the transferee that are converted by the Company or such Restricted Subsidiary into cash within 30 days after receipt thereof.

The Company will not, and will not permit any Restricted Subsidiary to, engage in any Asset Swaps, unless in the event such Asset Swap involves the transfer by the Company or any Restricted Subsidiary of assets having an aggregate Fair Market Value in excess of $20.0 million, the terms of such Asset Swap have been approved by a majority of the members of the Board of Directors of the Company.

The Company will not, and will not permit any of its Restricted Subsidiaries to, directly or indirectly, enter into, make, amend or conduct any transaction (including making a payment to, the purchase, sale, lease or exchange of any property or the rendering of any service), contract, agreement or understanding with or for the benefit of any Affiliate of the Company (an “Affiliate Transaction”) unless:

(1) the terms of such Affiliate Transaction are no less favorable to the Company or such Restricted Subsidiary, as the case may be, than those that could reasonably be expected to be obtained in a comparable transaction at the time of such transaction in arm’s-length dealings with a Person who is not such an Affiliate;

(2) if such Affiliate Transaction involves an aggregate consideration in excess of $20.0 million, the terms of such transaction have been approved by a majority of the members of the Board of Directors of the Company having no personal stake in such transaction, if any (and such majority determines that such Affiliate Transaction satisfies the criteria in clause (1) above); and

(3) if such Affiliate Transaction involves an aggregate consideration in excess of $50.0 million, the Board of Directors of the Company has received a written opinion from an independent investment banking, accounting, engineering or appraisal firm of nationally recognized standing that such Affiliate Transaction is fair, from a financial standpoint, to the Company or such Restricted Subsidiary or, in the case of non-financial transactions, is not less favorable to the Company or such Restricted Subsidiary than those that could reasonably be expected to be obtained in a comparable transaction at such time on an arm’s-length basis from a Person that is not an Affiliate.

(1) any Restricted Payment permitted to be made pursuant to the covenant described above under “—Limitation on Restricted Payments”;

(2) any issuance of Capital Stock (other than Disqualified Stock), or other payments, awards or grants in cash, Capital Stock (other than Disqualified Stock) or otherwise pursuant to, or the funding of, any employment, consulting, service or severance agreements or other compensation arrangements, options to purchase Capital Stock (other than Disqualified Stock) of the Company, restricted stock plans, long-term incentive plans, stock appreciation rights plans, participation plans or similar employee benefits plans or insurance and indemnification arrangements provided to or for the benefit of directors, officers and employees, in each case in the ordinary course of business and approved by the Board of Directors of the Company;

(3) any merger or other transaction with an Affiliate solely for the purpose of reincorporating or reorganizing the Company or any of its Restricted Subsidiaries in another jurisdiction or creating a holding company for the Company;

(4) advances to or reimbursements of employees for moving, entertainment and travel expenses, drawing accounts and similar expenditures in the ordinary course of business of the Company or any of its Restricted Subsidiaries;

(5) any transaction between the Company and a Restricted Subsidiary or between Restricted Subsidiaries, and guarantees issued by the Company or a Restricted Subsidiary for the benefit of the Company or a Restricted Subsidiary, as the case may be, in accordance with “— Limitation on Indebtedness and Preferred Stock”;

(6) the issuance or sale of any Capital Stock (other than Disqualified Stock) of the Company to, or the receipt by the Company of any capital contribution from, the holders of its Capital Stock;

(7) indemnities of officers, directors and employees of the Company or any of its Restricted Subsidiaries permitted by charter, bylaw or statutory provisions;

(8) the payment of reasonable compensation and fees to officers or directors of the Company or any Restricted Subsidiary;

(9) any transaction with a joint venture or similar entity (other than an Unrestricted Subsidiary) which would constitute an Affiliate Transaction solely because the Company or a Restricted Subsidiary owns, directly or indirectly, an equity interest in or otherwise controls such joint venture or similar entity; and

(10) the performance of obligations of the Company or any of its Restricted Subsidiaries under the terms of any agreement to which the Company or any of its Restricted Subsidiaries is a party as of or on the Issue Date that is disclosed in this prospectus under “Certain Relationships and Related Party Transactions”, as these agreements may be amended, modified, supplemented, extended or renewed from time to time; provided, however, that any future amendment, modification, supplement, extension or renewal entered into after the Issue Date will be permitted only to the extent that its terms are not materially more disadvantageous, taken as a whole, to the holders of the notes than the terms of the agreements in effect on the Issue Date.

The Indenture provides that, whether or not the Company is subject to the reporting requirements of Section 13 or Section 15(d) of the Exchange Act, the Company will make available to the Trustee and the holders of the notes without cost, by posting the same on its website for public availability, the annual reports and the information, documents and other reports that are specified in Sections 13 and 15(d) of the Exchange Act and applicable to a U.S. corporation that would be due after the Issue Date, within the time periods specified therein with respect to a non-accelerated filer. In addition, following the consummation of the exchange offer related to

the existing notes, the Company has been required to file a copy of each of the reports referred to in the preceding sentence with the SEC for public availability within the time periods specified in the rules and regulations applicable to such reports (unless the SEC will not accept such a filing).

This covenant will not impose any duty on the Company under the Sarbanes-Oxley Act of 2002 and the related SEC rules that would not otherwise be applicable.

If the Company has designated any of its Subsidiaries as Unrestricted Subsidiaries, then the financial information required will include a reasonably detailed presentation, either on the face of the financial statements or in the footnotes thereto, and in any accompanying Management’s Discussion and Analysis of Financial Condition and Results of Operations, of the financial condition and results of operations of the Company and its Restricted Subsidiaries separate from the financial condition and results of operations of the Unrestricted Subsidiaries of the Company.

For so long as any notes remain outstanding and constitute “restricted securities” under Rule 144, the Company will furnish to the holders of the notes, and to securities analysts and prospective investors, upon their request, the information required to be delivered pursuant to Rule 144A(d)(4) under the Securities Act.

Neither the Company nor the Co-Issuer will consolidate with or merge with or into or wind up into (whether or not it is the surviving Person), or sell, convey, transfer, lease or otherwise dispose of all or substantially all its assets in one or more related transactions to, any Person, unless:

(1) the resulting, surviving or transferee Person (the “Successor Company”) will be a corporation (in the case of either the Company or the Co-Issuer), or a partnership, trust or limited liability company (but only in the case of the Company), organized and existing under the laws of the United States of America, any State of the United States or the District of Columbia and the Successor Company (if not the Company or the Co-Issuer, as the case may be) will expressly assume, by supplemental indenture, executed and delivered to the Trustee, in form reasonably satisfactory to the Trustee, all the obligations of the Company or the Co-Issuer, as the case may be, under the Indenture, the notes and the applicable Registration Rights Agreement;

(2) immediately after giving effect to such transaction (and treating any Indebtedness that becomes an obligation of the Successor Company or any Subsidiary of the Successor Company as a result of such transaction as having been Incurred by the Successor Company or such Subsidiary at the time of such transaction), no Default or Event of Default shall have occurred and be continuing;

(3) immediately after giving effect to such transaction, the Successor Company would be able to Incur at least an additional $1.00 of Indebtedness pursuant to the first paragraph of the covenant described under “— Limitation on Indebtedness and Preferred Stock”;

(4) if an Issuer is not the Successor Company in any of the transactions referred to above that involve such Issuer, each Subsidiary Guarantor (unless it is the other party to the transactions, in which case clause (1) shall apply) shall have by supplemental indenture confirmed that its Subsidiary Guarantee shall apply to the Successor Company’s obligations in respect of the Indenture and the notes and that its Subsidiary Guarantee shall continue to be in effect; and

(5) the Company or the Co-Issuer, as the case may be, shall have delivered to the Trustee an Officers’ Certificate and an Opinion of Counsel, each stating that such transaction and such supplemental indenture (if any) comply with the Indenture.

For purposes of this covenant, the sale, conveyance, transfer, lease or other disposition of all or substantially all of the assets of one or more Subsidiaries of the Company, which assets, if held by the Company instead of such Subsidiaries, would constitute all or substantially all of the assets of the Company on a consolidated basis, shall be deemed to be the transfer of all or substantially all of the assets of the Company.

The Successor Company will succeed to, and be substituted for, and may exercise every right and power of, the Company or the Co-Issuer, as the case may be, under the Indenture; and its predecessor, except in the case of a lease of all or substantially all its assets, will be released from all obligations under the Indenture Documents.

Although there is a limited body of case law interpreting the phrase “substantially all”, there is no precise established definition of the phrase under applicable law. Accordingly, in certain circumstances there may be a degree of uncertainty as to whether a particular transaction would involve “all or substantially all” of the assets of a Person.

Notwithstanding the preceding clause (3), (x) any Restricted Subsidiary (other than the Co-Issuer) may consolidate with, merge into or transfer all or part of its assets to the Company, and the Company may consolidate with, merge into or transfer all or part of its assets to a Subsidiary Guarantor and (y) the Company may merge with an Affiliate formed solely for the purpose of reorganizing the Company in another jurisdiction.

In addition, the Company will not permit any Subsidiary Guarantor to consolidate with or merge with or into, and will not permit the sale, conveyance, transfer, lease or other disposition of all or substantially all of the assets of any Subsidiary Guarantor to, any Person (other than the Company or another Subsidiary Guarantor) unless:

(i) the resulting, surviving or transferee Person will be a corporation, partnership, trust or limited liability company organized and existing under the laws of the United States of America, any State of the United States or the District of Columbia and such Person (if not such Subsidiary Guarantor) will expressly assume by supplemental indenture, executed and delivered to the Trustee, in form reasonably satisfactory to the Trustee, all the obligations of the Subsidiary Guarantor under the Indenture, the Subsidiary Guarantee and the applicable Registration Rights Agreement and

(ii) immediately after giving effect to such transaction (and treating any Indebtedness that becomes an obligation of the resulting, surviving or transferee Person or any Restricted Subsidiary as a result of such transaction as having been Incurred by such Person or such Restricted Subsidiary at the time of such transaction), no Default shall have occurred and be continuing; or

(b) the transaction results in the release of the Subsidiary Guarantor from its obligations under its Subsidiary Guarantee in compliance with the conditions described in the penultimate paragraph of “—Subsidiary Guarantees”; and

(2) the Company shall have delivered to the Trustee an Officers’ Certificate and an Opinion of Counsel, each stating that such transaction and such supplemental indenture (if any) comply with the Indenture.

The Company will cause (a) each Domestic Subsidiary of the Company formed or acquired after the Issue Date and (b) any other Restricted Subsidiary (except the Co-Issuer) that is not already a Subsidiary Guarantor that guarantees any Indebtedness of the Company or a Subsidiary Guarantor, in each case to execute and deliver to the Trustee within 30 days a supplemental indenture (in the form specified in the Indenture) pursuant to which such Subsidiary will unconditionally guarantee, on a joint and several basis, the full and prompt payment of the principal of, premium, if any, and interest on the notes on a senior basis; provided that (i) any Restricted Subsidiary that constitutes an Immaterial Subsidiary need not become a Subsidiary Guarantor until such time as it ceases to be an Immaterial Subsidiary and (ii) Brayton Resources, L.P., Brayton Resources II, L.P. and Orion Operating Company, LP shall not be required to become Subsidiary Guarantors for so long as they remain Immaterial Subsidiaries and do not guarantee Indebtedness of the Company or any Subsidiary Guarantor other than the Senior Secured Credit Agreement.

Neither the Company nor any of its Restricted Subsidiaries will, directly or indirectly, pay or cause to be paid any consideration, whether by way of interest, fees or otherwise, to any holder of any notes for or as an inducement to any consent, waiver or amendment of any of the terms or provisions of the Indenture or the notes unless such consideration is offered to be paid or is paid to all holders of the notes that consent, waive or agree to amend in the time frame set forth in the solicitation documents relating to such consent, waiver or amendment.

The Company will not, and will not permit any of its Restricted Subsidiaries to, engage in any business other than the Oil and Gas Business, except to such extent as would not be material to the Company and its Restricted Subsidiaries taken as a whole.

The Co-Issuer may not engage in any business not related directly or indirectly to obtaining money or arranging financing for the Company or its Restricted Subsidiaries. The Co-Issuer may not have any Subsidiary, and no Person other than the Company or any of its other Restricted Subsidiaries may own any Capital Stock of the Co-Issuer.

(1) default in any payment of interest on any note when due, continued for 30 days;

(2) default in the payment of principal of or premium, if any, on any note when due at its Stated Maturity, upon optional redemption, upon required repurchase, upon declaration of acceleration or otherwise;

(3) failure by either Issuer or any Subsidiary Guarantor to comply with its obligations under “—Certain Covenants — Merger and Consolidation”;

(4) failure by either Issuer or any Subsidiary Guarantor to comply for 30 days after notice as provided below with any of its obligations under the covenant described under “— Change of Control” above or under the covenants described under “— Certain Covenants” above (in each case, other than a failure to purchase notes which will constitute an Event of Default under clause (2) above and other than a failure to comply with “Certain Covenants — Merger and Consolidation” which is covered by clause (3));

(5) failure by either Issuer or any Subsidiary Guarantor to comply for 60 days after notice as provided below with its other agreements contained in the Indenture;

(6) default under any mortgage, indenture or instrument under which there may be issued or by which there may be secured or evidenced any Indebtedness for money borrowed by the Company or any of its Restricted Subsidiaries (or the payment of which is guaranteed by the Company or any of its Restricted Subsidiaries), other than Indebtedness owed to the Company or a Restricted Subsidiary, whether such Indebtedness or guarantee now exists, or is created after the date of the Indenture, which default:

(a) is caused by a failure to pay principal of, or interest or premium, if any, on such Indebtedness prior to the expiration of the grace period provided in such Indebtedness (and any extensions of any grace period) (“payment default”); or

(b) results in the acceleration of such Indebtedness prior to its Stated Maturity (the “cross acceleration provision”);

and, in each case, the principal amount of any such Indebtedness, together with the principal amount of any other such Indebtedness under which there has been a payment default or the maturity of which has been so accelerated, aggregates $20.0 million or more;

(7) certain events of bankruptcy, insolvency or reorganization of the Company, the Co-Issuer or a Significant Subsidiary or group of Restricted Subsidiaries that, taken together (as of the latest audited consolidated financial statements for the Company and its Restricted Subsidiaries), would constitute a Significant Subsidiary (the “bankruptcy provisions”);

(8) failure by the Company, the Co-Issuer or any Significant Subsidiary or group of Restricted Subsidiaries that, taken together (as of the latest audited consolidated financial statements for the Company and its Restricted Subsidiaries), would constitute a Significant Subsidiary to pay final judgments aggregating in excess of $20.0 million (to the extent not covered by insurance by a reputable and creditworthy insurer as to which the insurer has not disclaimed coverage), which judgments are not paid or discharged, and there shall be any period of 60 consecutive days following entry of such final judgment or decree during which a stay of enforcement of such final judgment or decree, by reason of pending appeal or otherwise, shall not be in effect (the “judgment default provision”); or

(9) any Subsidiary Guarantee of a Significant Subsidiary or group of Restricted Subsidiaries that, taken together (as of the latest audited consolidated financial statements for the Company and its Restricted Subsidiaries) would constitute a Significant Subsidiary, ceases to be in full force and effect (except as contemplated by the terms of the Indenture) or is declared null and void in a judicial proceeding or the Company or any Subsidiary Guarantor that is a Significant Subsidiary or group of Subsidiary Guarantors that, taken together (as of the latest audited consolidated financial statements of the Company and its Restricted Subsidiaries) would constitute a Significant Subsidiary, denies or disaffirms its obligations under the Indenture or its Subsidiary Guarantee.

However, a default under clauses (4) and (5) of this paragraph will not constitute an Event of Default until the Trustee or the holders of at least 25% in principal amount of the outstanding Notes notify the Issuers in writing and, in the case of a notice given by the holders, the Trustee of the default and the Issuers do not cure such default within the time specified in clauses (4) and (5) of this paragraph after receipt of such notice.

If an Event of Default (other than an Event of Default described in clause (7) above) occurs and is continuing, the Trustee by notice to Issuers, or the holders of at least 25% in principal amount of the outstanding notes by notice to the Issuers and the Trustee, may, and the Trustee at the request of such holders shall, declare the principal of, premium, if any, accrued and unpaid interest, if any, on all the notes to be due and payable. If an Event of Default described in clause (7) above occurs and is continuing, the principal of, and premium, if any, and accrued and unpaid interest, if any, on all the notes will become and be immediately due and payable without any declaration or other act on the part of the Trustee or any holders. The holders of a majority in principal amount of the outstanding notes may waive all past defaults (except with respect to nonpayment of principal, premium or interest) and rescind any such acceleration with respect to the notes and its consequences if (1) rescission would not conflict with any judgment or decree of a court of competent jurisdiction and (2) all existing Events of Default, other than the nonpayment of the principal of, premium, if any, and interest on the notes that have become due solely by such declaration of acceleration, have been cured or waived.

Notwithstanding the foregoing, if an Event of Default specified in clause (6) above shall have occurred and be continuing, such Event of Default and any consequential acceleration (to the extent not in violation of any applicable law or in conflict with any judgment or decree of a court of competent jurisdiction) shall be automatically rescinded if (i) the Indebtedness that is the subject of such Event of Default has been repaid or (ii) if the default relating to such Indebtedness is waived by the holders of such Indebtedness or cured and if such Indebtedness has been accelerated, then the holders thereof have rescinded their declaration of acceleration in respect of such Indebtedness, in each case within 20 days after the declaration of acceleration with respect thereto, and (iii) any other existing Events of Default, except nonpayment of principal, premium or interest on the notes that became due solely because of the acceleration of the notes, have been cured or waived.

Subject to the provisions of the Indenture relating to the duties of the Trustee if an Event of Default occurs and is continuing, the Trustee will be under no obligation to exercise any of the rights or powers under the Indenture at the request or direction of any of the holders unless such holders have offered to the Trustee

indemnity or security satisfactory to the Trustee against any loss, liability or expense. Except to enforce the right to receive payment of principal, premium, if any, or interest when due, no holder may pursue any remedy with respect to the Indenture or the notes unless:

(1) such holder has previously given the Trustee notice that an Event of Default is continuing;

(2) holders of at least 25% in principal amount of the outstanding notes have requested the Trustee to pursue the remedy;

(3) such holders have offered the Trustee security or indemnity satisfactory to the Trustee against any loss, liability or expense;

(4) the Trustee has not complied with such request within 60 days after the receipt of the request and the offer of security or indemnity; and

(5) the holders of a majority in principal amount of the outstanding notes have not waived such Event of Default or otherwise given the Trustee a direction that, in the opinion of the Trustee, is inconsistent with such request within such 60-day period.

Subject to the provisions of the Indenture, the holders of a majority in principal amount of the outstanding notes will have the right to direct the time, method and place of conducting any proceeding for any remedy available to the Trustee or of exercising any trust or power conferred on the Trustee. If an Event of Default has occurred and is continuing, the Trustee will be required in the exercise of its powers to use the degree of care that a prudent person would use under the circumstances in the conduct of his own affairs. The Trustee, however, may refuse to follow any direction that conflicts with law or the Indenture or that the Trustee determines is unduly prejudicial to the rights of any other holder or that would involve the Trustee in personal liability. Prior to taking any action under the Indenture, the Trustee will be entitled to indemnification satisfactory to it in its sole discretion against all losses and expenses caused by taking or not taking such action.

If a Default occurs and is continuing and is known to the Trustee, the Trustee must mail to each holder notice of the Default within 90 days after it occurs. Except in the case of a Default in the payment of principal of, premium, if any, or interest on any note, the Trustee may withhold such notice if and so long as a committee of trust officers of the Trustee in good faith determines that withholding notice is in the interests of the holders. In addition, the Issuers are required to deliver to the Trustee, within 120 days after the end of each fiscal year, a certificate indicating whether the signers thereof know of any Default that occurred during the previous year. The Issuers also are required to deliver to the Trustee, within 30 days after the occurrence thereof, written notice of any Defaults, their status and what action the Issuers are taking or proposing to take in respect thereof.

The Indenture and the notes may be amended with the consent of the holders of a majority in principal amount of the notes then outstanding (including consents obtained in connection with a purchase of, or tender offer or exchange offer for, notes) and, subject to certain exceptions, any past default or compliance with any provisions of any Indenture Document may be waived with the consent of the holders of a majority in principal amount of the notes then outstanding (including consents obtained in connection with a purchase of, or tender offer or exchange offer for, notes). However, without the consent of each holder of an outstanding note affected thereby, no amendment or waiver may:

(1) reduce the principal amount of notes whose holders must consent to an amendment or waiver;

(2) reduce the stated rate of or extend the stated time for payment of interest on any note;

(4) reduce the premium payable upon the redemption of any note as described above under “— Optional Redemption”, change the time at which any note may be redeemed as described above under “—Optional Redemption” or make any change relative to our obligation to make an offer to repurchase the notes as a result of a Change of Control as described above under “— Change of Control” after (but not before) the occurrence of such Change of Control;

(6) impair the right of any holder to receive payment of the principal of, premium, if any, and interest on such holder’s notes on or after the due dates therefor or to institute suit for the enforcement of any payment on or with respect to such holder’s notes;

(7) make any change in the amendment provisions which require each holder’s consent or in the waiver provisions;

(8) release any Subsidiary Guarantor from any of its obligations under its Subsidiary Guarantee otherwise than in accordance with the applicable provisions of the Indenture; or

(9) subordinate the notes or any Subsidiary Guarantee in right of payment to any other Indebtedness of either Issuer or any Subsidiary Guarantor.

Notwithstanding the preceding, without the consent of any holder, the Issuers, the Subsidiary Guarantors and the Trustee may amend the Indenture and the notes to:

(2) provide for the assumption by a successor of the obligations of the Company, the Co-Issuer or any Subsidiary Guarantor under the Indenture;

(3) provide for uncertificated notes in addition to or in place of certificated notes (provided that the uncertificated notes are issued in registered form for purposes of Section 163(f) of the Code, or in a manner such that the uncertificated notes are described in Section 163(f)(2)(B) of the Code);

(4) add Subsidiary Guarantors (or any other guarantors) with respect to the notes or release a Subsidiary Guarantor from its Subsidiary Guarantee and terminate such Subsidiary Guarantee; provided that the release and termination is in accordance with the applicable provisions of the Indenture;

(6) add to the covenants of the Company, the Co-Issuer or a Subsidiary Guarantor for the benefit of the holders or surrender any right or power conferred upon the Company, the Co-Issuer or a Subsidiary Guarantor;

(7) make any change that does not adversely affect the legal rights of any holder; provided, however, that any change to conform the Indenture to this “Description of Notes” will not be deemed to adversely affect such legal rights;

(8) comply with any requirement of the SEC in connection with the qualification of the Indenture under the Trust Indenture Act; or

(9) provide for the succession of a successor Trustee, provided that the successor Trustee is otherwise qualified and eligible to act as such under the Indenture.

The consent of the holders is not necessary under the Indenture to approve the particular form of any proposed amendment. It is sufficient if such consent approves the substance of the proposed amendment. After an amendment under the Indenture requiring the consent of the holders becomes effective, the Company will mail to the holders a notice briefly describing such amendment. However, the failure to give such notice to all the holders, or any defect in the notice will not impair or affect the validity of the amendment.

The Issuers at any time may terminate all their obligations under the notes and the Indenture (“legal defeasance”), except for certain obligations specified in the Indenture, including those respecting the defeasance trust and obligations to register the transfer or exchange of the notes, to replace mutilated, destroyed, lost or stolen notes and to maintain a registrar and paying agent in respect of the notes.

The Issuers at any time may terminate their obligations described under “— Change of Control” and under the covenants described under “— Certain Covenants” (other than clauses (1), (2), (4) and (5) of “ — Merger and Consolidation”), the operation of the cross default upon a payment default, cross acceleration provisions, the bankruptcy provisions with respect to Significant Subsidiaries, the judgment default provision, the Subsidiary Guarantee provision described under “— Events of Default” above and the limitations contained in clause (3) under “ — Merger and Consolidation” above (“covenant defeasance”).

If the Issuers exercise their legal defeasance or covenant defeasance option, the Subsidiary Guarantees in effect at such time will terminate.

The Issuers may exercise their legal defeasance option notwithstanding their prior exercise of their covenant defeasance option. If the Issuers exercise their legal defeasance option, payment of the notes may not be accelerated because of an Event of Default with respect to the notes. If the Issuers exercise their covenant defeasance option, payment of the notes may not be accelerated because of an Event of Default specified in clause (4), (5), (6), (7) (with respect only to Significant Subsidiaries), (8) or (9) under “— Events of Default” above or because of the failure of the Company or the Co-Issuer to comply with clause (3) under “— Merger and Consolidation” above.

In order to exercise either defeasance option, an Issuer or a Subsidiary Guarantor must, among other things, irrevocably deposit in trust (the “defeasance trust”) with the Trustee money or U.S. Government Obligations for the payment of principal, premium, if any, and interest on the notes to redemption or Stated Maturity, as the case may be, and must comply with certain other conditions, including delivery to the Trustee of an Opinion of Counsel (subject to customary exceptions and exclusions) to the effect that holders of the notes will not recognize income, gain or loss for federal income tax purposes as a result of such deposit and defeasance and will be subject to federal income tax on the same amount and in the same manner and at the same times as would have been the case if such deposit and defeasance had not occurred. In the case of legal defeasance only, such Opinion of Counsel must be based on a ruling of the Internal Revenue Service or other change in applicable federal income tax law.

The Indenture will be discharged and will cease to be of further effect as to all notes issued thereunder (except as to surviving rights of registration of transfer or exchange of the notes and as otherwise expressly provided for in the Indenture), and all Subsidiary Guarantees will be released, when either:

(1) all notes that have been authenticated (except lost, stolen or destroyed notes that have been replaced or paid and notes for whose payment money has theretofore been deposited in trust or segregated and held in trust by an Issuer and thereafter repaid to such Issuer or discharged from such trust) have been delivered to the Trustee for cancellation, or

(2) all notes that have not been delivered to the Trustee for cancellation have become due and payable or will become due and payable within one year by reason of the giving of a notice of redemption or otherwise and an Issuer or any Subsidiary Guarantor has irrevocably deposited or caused to be irrevocably deposited with the Trustee as trust funds in trust solely for such purpose, cash in U.S. dollars in such amount as will be sufficient without consideration of any reinvestment of interest, to pay and discharge the entire indebtedness on the notes not delivered to the Trustee for cancellation for principal and accrued interest to the date of Stated Maturity or redemption, and in each case certain other procedural requirements set forth in the Indenture are satisfied.

No director, officer, employee, incorporator, stockholder, member, partner or trustee of the Company, the Co-Issuer or any Subsidiary Guarantor, as such, shall have any liability for any obligations of the Company, the Co-Issuer or any Subsidiary Guarantor under the notes, the Indenture or the Subsidiary Guarantees or for any

claim based on, in respect of, or by reason of, such obligations or their creation. Each holder by accepting a note waives and releases all such liability. The waiver and release are part of the consideration for issuance of the notes.

Wells Fargo Bank, N.A. will be the Trustee under the Indenture and has been appointed by the Issuers as registrar and paying agent with regard to the notes.

The Indenture will contain certain limitations on the rights of the Trustee, should it become a creditor of an Issuer or any Subsidiary Guarantor, to obtain payment of claims in certain cases, or to realize on certain property received in respect of any such claim as security or otherwise. The Trustee will be permitted to engage in other transactions; provided, however, that if it acquires any conflicting interest (as defined in the Trust Indenture Act) while any Default exists it must eliminate such conflict within 90 days, apply to the SEC for permission to continue as Trustee with such conflict or resign as Trustee.

The Indenture provides that it and the notes will be governed by, and construed in accordance with, the laws of the State of New York.

The new notes, like the old notes and the existing notes, will be issued in the form of one or more fully registered notes in global form, without interest coupons. Each global note will be deposited with the Trustee, as custodian for The Depository Trust Company (“DTC”), and registered in the name of a nominee of DTC.

Ownership of beneficial interests in each global note will be limited to persons who have accounts with DTC (“DTC participants”) or persons who hold interests through DTC participants. We expect that under procedures established by DTC:

Beneficial interests in the global notes may not be exchanged for notes in physical, certificated form except in the limited circumstances described below.

All interests in the global notes will be subject to the operations and procedures of DTC, including its participants, Euroclear Bank S.A./N.V., as operator of the Euroclear System (“Euroclear”), and Clearstream Banking S.A. (“Clearstream”). We provide the following summaries of those operations and procedures solely for the convenience of investors. The operations and procedures of each settlement system are controlled by that settlement system and may be changed at any time.

DTC was created to hold securities for its participants and to facilitate the clearance and settlement of securities transactions between its participants through electronic book-entry changes to the accounts of its participants. DTC’s participants include securities brokers and dealers, including the initial purchasers, banks and trust companies, clearing corporations, and other organizations. Indirect access to DTC’s system is also available to others such as banks, brokers, dealers, and trust companies. These indirect participants clear through or maintain a custodial relationship with a DTC participant, either directly or indirectly. Investors who are not DTC participants may beneficially own securities held by or on behalf of DTC only through DTC participants or indirect participants in DTC.

So long as DTC’s nominee is the registered owner of a global note, that nominee will be considered the sole owner or holder of the notes represented by that global note for all purposes under the indenture. Except as provided below, owners of beneficial interests in a global note:

As a result, each investor who owns a beneficial interest in a global note must rely on the procedures of DTC to exercise any rights of a holder of notes under the Indenture (and, if the investor is not a participant or an indirect participant in DTC, on the procedures of the DTC participant through which the investor owns its interest).

Payments of principal, premium (if any), and interest with respect to the new notes represented by a global note will be made by the Trustee to DTC’s nominee, as the registered holder of the global note. Neither we nor the Trustee will have any responsibility or liability for the payment of amounts to owners of beneficial interests in a global note, for any aspect of the records relating to or payments made on account of those interests by DTC, or for maintaining, supervising, or reviewing any records of DTC relating to those interests.

Payments by participants and indirect participants in DTC to the owners of beneficial interests in a global note will be governed by standing instructions and customary industry practice and will be the responsibility of those participants or indirect participants and DTC.

Transfers between participants in DTC will be effected under DTC’s procedures and will be settled in same-day funds. Transfers between participants in Euroclear or Clearstream will be effected in the ordinary way under the rules and operating procedures of those systems.

Cross market transfers between DTC participants, on the one hand, and Euroclear or Clearstream participants, on the other hand, will be effected within DTC through the DTC participants that are acting as depositaries for Euroclear and Clearstream. To deliver or receive an interest in a global note held in a Euroclear or Clearstream account, an investor must send transfer instructions to Euroclear or Clearstream, as the case may

be, under the rules and procedures of that system and within the established deadlines of that system. If the transaction meets its settlement requirements, Euroclear or Clearstream, as the case may be, will send instructions to its DTC depositary to take action to effect final settlement by delivering or receiving interests in the relevant global notes in DTC, and making or receiving payment under normal procedures for same-day funds settlement applicable to DTC. Euroclear and Clearstream participants may not deliver instructions directly to the DTC depositaries that are acting for Euroclear or Clearstream.

Because of time zone differences, the securities account of a Euroclear or Clearstream participant that purchases an interest in a global note from a DTC participant will be credited on the business day for Euroclear or Clearstream immediately following the DTC settlement date. Cash received in Euroclear or Clearstream from the sale of an interest in a global note to a DTC participant will be received with value on the DTC settlement date but will be available in the relevant Euroclear or Clearstream cash account as of the business day for Euroclear or Clearstream following the DTC settlement date.

DTC, Euroclear, and Clearstream have agreed to the above procedures to facilitate transfers of interests in the global notes among participants in those settlement systems. However, the settlement systems are not obligated to perform these procedures and may discontinue or change these procedures at any time. Neither we nor the Trustee will have any responsibility for the performance by DTC, Euroclear, or Clearstream, or their participants or indirect participants, of their obligations under the rules and procedures governing their operations.

New notes in physical, certificated form will be issued and delivered to each person that DTC identifies as a beneficial owner of the related notes only if:

Set forth below are certain defined terms used in the Indenture. References to Statements of Financial Accounting Standards of the Financial Accounting Standards Board do not reflect the new nomenclature resulting from the FASB’s codification of such Statements in its ASC 105, Generally Accepted Accounting Principles, issued in June 2009, but are deemed to include the codified Statements under their current nomenclature.

“Acquired Indebtedness” means Indebtedness (i) of a Person or any of its Subsidiaries existing at the time such Person becomes or is merged with and into a Restricted Subsidiary or (ii) assumed in connection with the acquisition of assets from such Person, in each case whether or not Incurred by such Person in connection with, or in anticipation or contemplation of, such Person becoming a Restricted Subsidiary or such acquisition. Acquired Indebtedness shall be deemed to have been Incurred, with respect to clause (i) of the preceding sentence, on the date such Person becomes or is merged with and into a Restricted Subsidiary and, with respect to clause (ii) of the preceding sentence, on the date of consummation of such acquisition of assets.

(1) any properties or assets (other than current assets) to be used by the Company or a Restricted Subsidiary in the Oil and Gas Business; or

(2) the Capital Stock of a Person that is or becomes a Restricted Subsidiary as a result of the acquisition of such Capital Stock by the Company or a Restricted Subsidiary; provided, however, that such Restricted Subsidiary is primarily engaged in the Oil and Gas Business.

“Adjusted Consolidated Net Tangible Assets” of the Company means (without duplication), as of the date of determination, the remainder of:

(i) discounted future net revenues from proved oil and gas reserves of the Company and its Restricted Subsidiaries calculated in accordance with SEC guidelines before any state or federal income taxes, as estimated by the Company in a reserve report prepared as of the end of the Company’s most recently completed fiscal year for which audited financial statements are available, which reserve report is prepared, reviewed or audited by independent petroleum engineers, as increased by, as of the date of determination, the estimated discounted future net revenues from

(A) estimated proved oil and gas reserves acquired since such year end, which reserves were not reflected in such year end reserve report, and

(B) estimated oil and gas reserves attributable to extensions, discoveries and other additions and upward revisions of estimates of proved oil and gas reserves since such year end due to exploration, development or exploitation, production or other activities, which would, in accordance with standard industry practice, cause such revisions (including the impact to proved reserves and future net revenues from estimated development costs incurred and the accretion of discount since such year end),

and decreased by, as of the date of determination, the estimated discounted future net revenues from

(D) estimated oil and gas reserves attributable to downward revisions of estimates of proved oil and gas reserves since such year end due to changes in geological conditions or other factors which would, in accordance with standard industry practice, cause such revisions, in each case calculated on a pre-tax basis and substantially in accordance with SEC guidelines,

in the case of clauses (A) through (D) utilizing prices and costs calculated in accordance with SEC guidelines as if the end of the most recent fiscal quarter preceding the date of determination for which such information is available to the Company were year end; provided, however, that in the case of each of the determinations made pursuant to clauses (A) through (D), such increases and decreases shall be as estimated by the Company’s petroleum engineers;

(ii) the capitalized costs that are attributable to Oil and Gas Properties of the Company and its Restricted Subsidiaries to which no proved oil and gas reserves are attributable, based on the Company’s books and records as of a date no earlier than the date of the Company’s latest available annual or quarterly financial statements;

(iii) the Net Working Capital of the Company and its Restricted Subsidiaries on a date no earlier than the date of the Company’s latest annual or quarterly financial statements; and

(A) the net book value of other tangible assets of the Company and its Restricted Subsidiaries, as of a date no earlier than the date of the Company’s latest annual or quarterly financial statements, and

(B) the appraised value, as estimated by independent appraisers, of other tangible assets of the Company and its Restricted Subsidiaries, as of a date no earlier than the date of the Company’s latest audited financial statements; provided, that, if no such appraisal has been performed the Company shall not be required to obtain such an appraisal and only clause (iv)(A) of this definition shall apply;

(ii) any net gas balancing liabilities of the Company and its Restricted Subsidiaries reflected in the Company’s latest annual or quarterly balance sheet (to the extent not deducted in calculating Net Working Capital of the Company in accordance with clause (a)(iii) above of this definition);

(iii) to the extent included in (a)(i) above, the discounted future net revenues, calculated in accordance with SEC guidelines (but utilizing prices and costs calculated in accordance with SEC guidelines as if the end of the most recent fiscal quarter preceding the date of determination for which such information is available to the Company were year end), attributable to reserves which are required to be delivered to third parties to fully satisfy the obligations of the Company and its Restricted Subsidiaries with respect to Volumetric Production Payments (determined, if applicable, using the schedules specified with respect thereto); and

(iv) the discounted future net revenues, calculated in accordance with SEC guidelines, attributable to reserves subject to Dollar-Denominated Production Payments which, based on the estimates of production and price assumptions included in determining the discounted future net revenues specified in (a)(i) above, would be necessary to fully satisfy the payment obligations of the Company and its Subsidiaries with respect to Dollar-Denominated Production Payments (determined, if applicable, using the schedules specified with respect thereto).

If the Company changes its method of accounting from the successful efforts method of accounting to the full cost or a similar method, “Adjusted Consolidated Net Tangible Assets” will continue to be calculated as if the Company were still using the successful efforts method of accounting.

“Affiliate” of any specified Person means any other Person, directly or indirectly, controlling or controlled by or under direct or indirect common control with such specified Person. For the purposes of this definition, “control” when used with respect to any Person means the power to direct the management and policies of such Person, directly or indirectly, whether through the ownership of voting securities, by contract or otherwise; and the terms “controlling” and “controlled” have meanings correlative to the foregoing.

“Asset Disposition” means any direct or indirect sale, lease (including by means of Production Payments and Reserve Sales and a Sale/Leaseback Transaction but excluding an operating lease entered into in the ordinary course of the Oil and Gas Business), transfer, issuance or other disposition, or a series of related sales, leases, transfers, issuances or dispositions that are part of a common plan, of (A) any Capital Stock of a Restricted Subsidiary (other than directors’ qualifying shares or shares required by applicable law to be held by a Person other than the Company or a Restricted Subsidiary) or (B) any other assets of the Company or any Restricted Subsidiary outside of the ordinary course of business of the Company or such Restricted Subsidiary (each referred to for the purposes of this definition as a “disposition”), in each case by the Company or any of its Restricted Subsidiaries, including any disposition by means of a merger, consolidation or similar transaction.

Notwithstanding the preceding, the following items shall not be deemed to be Asset Dispositions:

(1) a disposition by a Restricted Subsidiary to the Company or by the Company or a Restricted Subsidiary to a Restricted Subsidiary;

(2) a disposition of cash, Cash Equivalents or other financial assets in the ordinary course of business;

(4) a disposition of damaged, unserviceable, obsolete or worn out equipment or equipment that is no longer necessary for the proper conduct of the business of the Company and its Restricted Subsidiaries and that is disposed of in each case in the ordinary course of business;

(5) transactions in accordance with the covenant described under “— Certain Covenants — Merger and Consolidation”;

(6) an issuance of Capital Stock by a Restricted Subsidiary to the Company or to a Restricted Subsidiary;

(7) the making of a Permitted Investment or a Restricted Payment (or a disposition that would constitute a Restricted Payment but for the exclusions from the definition thereof) permitted by the covenant described under “— Certain Covenants — Limitation on Restricted Payments”;

(9) dispositions of assets with a Fair Market Value of less than $10.0 million in any single transaction or series of related transactions;

(11) dispositions of receivables in connection with the compromise, settlement or collection thereof in the ordinary course of business or in bankruptcy or similar proceedings and exclusive of factoring or similar arrangements;

(12) the licensing or sublicensing of intellectual property (including the licensing of seismic data or rights to access and use seismic data libraries);

(13) any Production Payments and Reserve Sales pursuant to incentive compensation programs on terms that are reasonably customary in the Oil and Gas Business for geologists, geophysicists and other providers of technical or management services to the Company or a Restricted Subsidiary;

(14) surrender or waiver of contract rights, oil and gas leases, or the settlement, release or surrender of contract, tort or other claims of any kind; and

(15) the abandonment, assignment, farmout, lease, sublease, forfeiture or other disposition of developed or undeveloped Oil and Gas Properties in the ordinary course of business.

“Asset Swap” means any substantially contemporaneous (and in any event occurring within 180 days of each other) purchase and sale or exchange of any Oil and Gas Assets between the Company or any of its Restricted Subsidiaries and another Person; provided, that any cash received must be applied in accordance with “— Certain Covenants— Limitation on Sales of Assets and Subsidiary Stock” as if the Asset Swap were an Asset Disposition.

“Attributable Debt” in respect of a sale and leaseback transaction means, at the time of determination, the present value of the obligation of the lessee for net rental payments during the remaining term of the lease included in such sale and leaseback transaction including any period for which such lease has been extended or may, at the option of the lessor, be extended. Such present value shall be calculated using a discount rate equal to the rate of interest implicit in such transaction, determined in accordance with GAAP; provided, however, that if such sale and leaseback transaction results in a Capitalized Lease Obligation, the amount of Indebtedness represented thereby will be determined in accordance with the definition of “Capitalized Lease Obligation”.

“Average Life” means, as of the date of determination, with respect to any Indebtedness or Preferred Stock, the quotient obtained by dividing (1) the sum of the products of the numbers of years from the date of determination to the dates of each successive scheduled principal payment of such Indebtedness or redemption or similar payment with respect to such Preferred Stock multiplied by the amount of such payment by (2) the sum of all such payments.

“Beneficial Owner” has the meaning assigned to such term in Rule 13d-3 and Rule 13d-5 under the Exchange Act, except that in calculating the beneficial ownership of any particular “person” (as that term is used in Section 13(d)(3) of the Exchange Act), such “person” will be deemed to have beneficial ownership of all securities that such “person” has the right to acquire by conversion or exercise of other securities, whether such right is currently exercisable or is exercisable only after the passage of time. The terms “Beneficially Owns” and “Beneficially Owned” have a corresponding meaning.

“Board of Directors” means, as to any Person that is a corporation, the board of directors of such Person or any duly authorized committee thereof or as to any Person that is not a corporation, the board of managers or such other individual or group serving a similar function. For so long as the Company is a limited partnership, the board of directors of the General Partner shall be deemed to be the Board of Directors of the Company.

“Business Day” means each day that is not a Saturday, Sunday or other day on which commercial banking institutions in New York, New York are authorized or required by law to close.

“Capital Stock” of any Person means any and all shares, units, interests, rights to purchase, warrants, options, participations or other equivalents of or interests in (however designated) the equity of such Person, including any Preferred Stock, but excluding any debt securities convertible into, or exchangeable for, such equity.

“Capitalized Lease Obligation” means an obligation that is required to be classified and accounted for as a capitalized lease for financial reporting purposes in accordance with GAAP, and the amount of Indebtedness represented by such obligation will be the capitalized amount of such obligation at the time any determination thereof is to be made as determined in accordance with GAAP, and the Stated Maturity thereof will be the date of the last payment of rent or any other amount due under such lease prior to the first date such lease may be terminated without penalty.

(1) securities issued or directly and fully guaranteed or insured by the United States Government or any agency or instrumentality of the United States (provided that the full faith and credit of the United States is pledged in support thereof), having maturities of not more than one year from the date of acquisition;

(2) marketable general obligations issued by any state of the United States of America or any political subdivision of any such state or any public instrumentality thereof maturing within one year from the date of acquisition and, at the time of acquisition, having one of the two highest ratings obtainable from either S&P or Moody’s;

(3) certificates of deposit, time deposits, eurodollar time deposits, overnight bank deposits or bankers’ acceptances having maturities of not more than one year from the date of acquisition thereof issued by any commercial bank the short-term deposit of which is rated at the time of acquisition thereof at least “A-2” or the equivalent thereof by S&P, or “P-2” or the equivalent thereof by Moody’s, and having combined capital and surplus in excess of $500.0 million;

(4) repurchase obligations with a term of not more than seven days for underlying securities of the types described in clauses (1), (2) and (3) entered into with any bank meeting the qualifications specified in clause (3) above;

(5) commercial paper rated at the time of acquisition thereof at least “A-2” by S&P or “P-2” by Moody’s, and in either case maturing within nine months after the date of acquisition thereof; and

(6) interests in any investment company or money market fund which invests 95% or more of its assets in instruments of the type specified in clauses (1) through (5) above.

(1) any “person” or “group” of related persons (as such terms are used in Sections 13(d) and 14(d) of the Exchange Act), other than a Permitted Holder, is or becomes the Beneficial Owner, directly or indirectly, of more than 50% of the total voting power of the Voting Stock of the General Partner (or, following the conversion of the Company into another form as described below, more than 50% of the total voting power of the Voting Stock of the successor entity to the Company);

(2) the first day on which a majority of the members of the Board of Directors of the Company are not Continuing Directors;

(3) the sale, lease, transfer, conveyance or other disposition (other than by way of merger or consolidation), in one or a series of related transactions, of all or substantially all of the assets of the Company and its Restricted Subsidiaries taken as a whole to any “person” (as such term is used in Sections 13(d) and 14(d) of the Exchange Act), other than to the Company, a Restricted Subsidiary or a Permitted Holder; or

(4) the adoption by the members of the General Partner or the partners of the Company (or, following the conversion of the Company into another form as described below, its equity holders) of a plan or proposal for the liquidation or dissolution of the Company.

Notwithstanding the preceding, a conversion (whether by merger, statutory conversion or otherwise) of the Company from a limited partnership to a limited liability company or corporation, or an exchange of all of the outstanding partnership interests in the Company for Capital Stock in a corporation or a limited liability company, shall not constitute a Change of Control, so long as following such conversion or exchange the “persons” (as that term is used in Section 13(d)(3) of the Exchange Act) who Beneficially Owned the Capital Stock of the General Partner and the Company immediately prior to such transactions continue to Beneficially Own in the aggregate sufficient Capital Stock of such successor entity to elect a majority of its directors, managers, trustees or other persons serving in a similar capacity for such successor entity.

“Commodity Agreements” means, in respect of any Person, any forward contract, commodity swap agreement, commodity option agreement or other similar agreement or arrangement in respect of Hydrocarbons used, produced, processed or sold by such Person that is customary in the Oil and Gas Business and designed to protect such Person against fluctuation in Hydrocarbon prices.

“Common Stock” means, with respect to any Person, any and all Capital Stock (however designated and whether voting or nonvoting) of such Person other than any Preferred Stock, whether or not outstanding on the Issue Date, and includes all series and classes of such Capital Stock.

“Consolidated Coverage Ratio” means, for any Person, as of any date of determination, the ratio of (x) the aggregate amount of Consolidated EBITDAX of such Person for the period of the most recent four consecutive fiscal quarters ending prior to the date of such determination for which financial statements are in existence to (y) Consolidated Interest Expense for such four fiscal quarters, provided, however, that:

(a) has Incurred any Indebtedness since the beginning of such period that remains outstanding on such date of determination or if the transaction giving rise to the need to calculate the Consolidated Coverage Ratio is an Incurrence of Indebtedness, Consolidated EBITDAX and Consolidated Interest Expense for such period will be calculated after giving effect on a pro forma basis to the Incurrence of such Indebtedness and the use of proceeds thereof as if such Indebtedness had been Incurred on the first day of such period and such proceeds had been applied as of such date (except that in making such computation, the amount of any revolving credit Indebtedness outstanding on the date of such calculation will be deemed to be (i) the average daily balance of such Indebtedness during such four fiscal quarters or such shorter period during which such Indebtedness was outstanding or (ii) if such revolving credit Indebtedness was Incurred after the end of such four fiscal quarters, the average daily balance of such Indebtedness during the period from the date of Incurrence of such revolving credit Indebtedness to the date of such calculation, in each case, provided that such average daily balance shall take into account any permanent repayment of such revolving credit Indebtedness as provided in clause (b)); or

(b) has repaid, repurchased, defeased or otherwise discharged any Indebtedness since the beginning of the period, including with the proceeds of such new Indebtedness, that is no longer outstanding on such date of determination or if the transaction giving rise to the need to calculate the Consolidated Coverage Ratio involves a discharge of Indebtedness (in each case other than any

revolving credit Indebtedness, unless such revolving credit Indebtedness has been permanently repaid and the related commitment terminated), Consolidated EBITDAX and Consolidated Interest Expense for such period will be calculated after giving effect on a pro forma basis to such discharge of such Indebtedness as if such discharge had occurred on the first day of such period;

(2) if, since the beginning of such period, the Company or any Restricted Subsidiary has made any Asset Disposition or if the transaction giving rise to the need to calculate the Consolidated Coverage Ratio is such an Asset Disposition, the Consolidated EBITDAX for such period will be reduced by an amount equal to the Consolidated EBITDAX (if positive) directly attributable to the assets which are the subject of such Asset Disposition for such period or increased by an amount equal to the Consolidated EBITDAX (if negative) directly attributable thereto for such period and Consolidated Interest Expense for such period shall be reduced by an amount equal to the Consolidated Interest Expense directly attributable to any Indebtedness of the Company or any Restricted Subsidiary repaid, repurchased, defeased or otherwise discharged with respect to the Company and its continuing Restricted Subsidiaries in connection with or with the proceeds from such Asset Disposition for such period (or, if the Capital Stock of any Restricted Subsidiary is sold, the Consolidated Interest Expense for such period directly attributable to the Indebtedness of such Restricted Subsidiary to the extent the Company and its continuing Restricted Subsidiaries are no longer liable for such Indebtedness after such sale);

(3) if, since the beginning of such period, the Company or any Restricted Subsidiary (by merger or otherwise) has made an Investment in any Restricted Subsidiary (or any Person which becomes a Restricted Subsidiary or is merged with or into the Company or a Restricted Subsidiary) or an acquisition (or has received a contribution) of assets, including any acquisition or contribution of assets occurring in connection with a transaction causing a calculation to be made under the Indenture, which constitutes all or substantially all of a Company division, operating unit, segment, business, group of related assets or line of business, Consolidated EBITDAX and Consolidated Interest Expense for such period will be calculated after giving pro forma effect thereto (including the Incurrence of any Indebtedness) as if such Investment or acquisition or contribution had occurred on the first day of such period; and

(4) if, since the beginning of such period, any Person (that subsequently became a Restricted Subsidiary or was merged with or into the Company or any Restricted Subsidiary since the beginning of such period) made any Asset Disposition or any Investment or acquisition of assets that would have required an adjustment pursuant to clause (2) or (3) above if made by the Company or a Restricted Subsidiary during such period, Consolidated EBITDAX and Consolidated Interest Expense for such period will be calculated after giving pro forma effect thereto as if such Asset Disposition or Investment or acquisition of assets had occurred on the first day of such period.

For purposes of this definition, whenever pro forma effect is to be given to any calculation under this definition, the pro forma calculations will be determined on behalf of the Company in good faith by a responsible financial or accounting officer of the Company; provided that such officer may in his or her discretion include any reasonably identifiable and factually supportable pro forma changes to Consolidated EBITDAX, including any pro forma expenses and cost reductions, that have occurred or in the judgment of such officer are reasonably expected to occur within 12 months of the date of the applicable transaction (regardless of whether such expense or cost reduction or any other operating improvements could then be reflected properly in pro forma financial statements prepared in accordance with Regulation S-X under the Securities Act or any other regulation or policy of the SEC). If any Indebtedness bears a floating rate of interest and is being given pro forma effect, the interest expense on such Indebtedness will be calculated as if the average rate in effect from the beginning of such period to the date of determination had been the applicable rate for the entire period (taking into account any Interest Rate Agreement applicable to such Indebtedness, but if the remaining term of such Interest Rate Agreement is less than 12 months, then such Interest Rate Agreement shall only be taken into account for that portion of the period equal to the remaining term thereof). If any Indebtedness that is being given pro forma effect bears an interest rate at the option of the Company or any Restricted Subsidiary, the interest rate shall be calculated by applying such optional rate chosen by the Company or such Restricted Subsidiary. Interest on Indebtedness that may optionally be determined at an interest rate based upon a factor of a prime or similar rate, a eurocurrency

interbank offered rate, or other rate, shall be deemed to have been based upon the rate actually chosen, or, if none, then based upon such optional rate chosen as the Company or the applicable Restricted Subsidiary may designate.

“Consolidated EBITDAX” for any period means, without duplication, the Consolidated Net Income for such period, plus the following, without duplication and to the extent deducted (and not added back) in calculating such Consolidated Net Income:

(3) consolidated depletion and depreciation expense of the Company and its Restricted Subsidiaries;

(4) consolidated amortization expense or impairment charges of the Company and its Restricted Subsidiaries recorded in connection with the application of Statement of Financial Accounting Standard No. 142, “Goodwill and Other Intangibles” and Statement of Financial Accounting Standard No. 144, “Accounting for the Impairment or Disposal of Long Lived Assets”;

(5) other non-cash charges of the Company and its Restricted Subsidiaries (excluding any such non-cash charge to the extent it represents an accrual of or reserve for cash charges in any future period or amortization of a prepaid cash expense that was paid in a prior period not included in the calculation); and

(6) the consolidated exploration and abandonment expense of the Company and its Restricted Subsidiaries,

if applicable for such period; and less, to the extent included in calculating such Consolidated Net Income and in excess of any costs or expenses attributable thereto that were deducted (and not added back) in calculating such Consolidated Net Income, the sum of (x) the amount of deferred revenues that is amortized during such period and is attributable to reserves that are subject to Volumetric Production Payments, (y) amounts recorded in accordance with GAAP as repayments of principal and interest pursuant to Dollar-Denominated Production Payments and (z) other non-cash gains (excluding any non-cash gain to the extent it represents the reversal of an accrual or reserve for a potential cash item that reduced Consolidated EBITDAX in any prior period).

Notwithstanding the preceding sentence, clauses (2) through (6) relating to amounts of a Restricted Subsidiary will be added to Consolidated Net Income to compute Consolidated EBITDAX of the Company only to the extent (and in the same proportion) that the net income (loss) of such Restricted Subsidiary was included in calculating the Consolidated Net Income of the Company and, to the extent the amounts set forth in clauses (2) through (6) are in excess of those necessary to offset a net loss of such Restricted Subsidiary or if such Restricted Subsidiary has net income for such period included in Consolidated Net Income, only if a corresponding amount would be permitted at the date of determination to be dividended to the Company by such Restricted Subsidiary without prior approval (that has not been obtained), pursuant to the terms of its charter and all agreements, instruments, judgments, decrees, orders, statutes, rules and governmental regulations applicable to that Restricted Subsidiary or the holders of its Capital Stock.

“Consolidated Income Tax Expense” means, with respect to any period, the provision for federal, state, local and foreign taxes (including state franchise taxes) based on income of the Company and its Restricted Subsidiaries for such period as determined in accordance with GAAP, or (for any period in which the Company is a partnership) the Tax Amount for such period.

“Consolidated Interest Expense” means, for any period, the total consolidated interest expense (excluding interest income) of the Company and its Restricted Subsidiaries, whether paid or accrued, plus, to the extent not included in such interest expense and without duplication:

(1) interest expense attributable to Capitalized Lease Obligations or Attributable Debt and the interest component of any deferred payment obligations;

(2) amortization of debt discount and debt issuance cost (provided that any amortization of bond premium will be credited to reduce Consolidated Interest Expense unless, pursuant to GAAP, such amortization of bond premium has otherwise reduced Consolidated Interest Expense);

(4) commissions, discounts and other fees and charges owed with respect to letters of credit and bankers’ acceptance financing;

(5) the interest expense on Indebtedness of another Person that is guaranteed by the Company or one of its Restricted Subsidiaries or secured by a Lien on assets of the Company or one of its Restricted Subsidiaries;

(6) cash costs associated with Interest Rate Agreements (including amortization of fees); provided, however, that if Interest Rate Agreements result in net cash benefits rather than costs, such benefits shall be credited to reduce Consolidated Interest Expense unless, pursuant to GAAP, such net benefits are otherwise reflected in Consolidated Net Income;

(7) the consolidated interest expense of the Company and its Restricted Subsidiaries that was capitalized during such period; and

(8) all dividends paid or payable in cash, Cash Equivalents or Indebtedness, or accrued during such period, in each case on any series of Disqualified Stock of the Company or on Preferred Stock of its Restricted Subsidiaries payable to a party other than the Company or a Wholly Owned Subsidiary.

For the purpose of calculating the Consolidated Coverage Ratio in connection with the Incurrence of any Indebtedness described in the final paragraph of the definition of “Indebtedness”, the calculation of Consolidated Interest Expense shall include all interest expense (including any amounts described in clauses (1) through (8) above) relating to any Indebtedness of the Company or any Restricted Subsidiary described in the final paragraph of the definition of “Indebtedness”.

“Consolidated Net Income” means, for any period, the aggregate net income (loss) of the Company and its Subsidiaries determined in accordance with GAAP and before any reduction in respect of Preferred Stock dividends of such Person, less (for any period the Company is a partnership) the Tax Amount for such period; provided, however, that there will not be included (to the extent otherwise included therein) in such Consolidated Net Income:

(1) any net income (loss) of any Person (other than the Company) if such Person is not a Restricted Subsidiary, except that:

(a) subject to the limitations contained in clauses (3) and (4) below, the Company’s equity in the net income of any such Person for such period will be included in such Consolidated Net Income up to the aggregate amount of cash actually distributed by such Person during such period to the Company or a Restricted Subsidiary as a dividend or other distribution (subject, in the case of a dividend or other distribution to a Restricted Subsidiary, to the limitations contained in clause (2) below); and

(b) the Company’s equity in a net loss of any such Person for such period will be included in determining such Consolidated Net Income to the extent such loss has been funded with cash from the Company or a Restricted Subsidiary during such period;

(2) any net income (but not loss) of any Restricted Subsidiary if such Subsidiary is subject to restrictions, directly or indirectly, on the payment of dividends or the making of distributions by such Restricted Subsidiary, directly or indirectly, to the Company, except that:

(a) subject to the limitations contained in clauses (3) and (4) below, the Company’s equity in the net income of any such Restricted Subsidiary for such period will be included in such Consolidated Net Income up to the aggregate amount of cash that could have been distributed by such Restricted Subsidiary during such period to the Company or another Restricted Subsidiary as a dividend or other distribution (subject, in the case of a dividend or other distribution paid to another Restricted Subsidiary, to the limitation contained in this clause); and

(b) the Company’s equity in a net loss of any such Restricted Subsidiary for such period will be included in determining such Consolidated Net Income;

(3) any gain (loss) realized upon the sale or other disposition of any property, plant or equipment of the Company or its Subsidiaries (including pursuant to any Sale/Leaseback Transaction) which is not sold or otherwise disposed of in the ordinary course of business and any gain (loss) realized upon the sale or other disposition of any Capital Stock of any Person;

(4) any extraordinary or nonrecurring gains or losses, together with any related provision for taxes (and, without duplication, any related Permitted Tax Distributions) on such gains or losses and all related fees and expenses;

(6) any asset impairment writedowns on Oil and Gas Properties under GAAP or SEC guidelines;

(7) any unrealized non-cash gains or losses or charges in respect of Hedging Obligations (including those resulting from the application of Statement of Financial Accounting Standard No. 133);

(8) income or loss attributable to discontinued operations (including operations disposed of during such period whether or not such operations were classified as discontinued);

(9) all deferred financing costs written off, and premiums paid, in connection with any early extinguishment of Indebtedness; and

(10) any non-cash compensation charge arising from any grant of stock, stock options or other equity based awards; provided that the proceeds resulting from any such grant will be excluded from clause (4)(c)(ii) of the first paragraph of the covenant described under “— Certain Covenants — Limitation on Restricted Payments”.

“Continuing Directors” means, as of any date of determination, any member of the Board of Directors of the Company who: (1) was a member of such Board of Directors on the date of the Indenture; or (2) was nominated for election or elected to such Board of Directors with the approval of a majority of the Continuing Directors who were members of such Board of Directors at the time of such nomination or election.

“Credit Facility” means, with respect to the Company or any Subsidiary Guarantor, one or more debt facilities (including, without limitation, the Senior Secured Credit Agreement), or commercial paper facilities providing for revolving credit loans, term loans, receivables financing (including through the sale of receivables to lenders or to special purpose entities formed to borrow from such lenders against such receivables) or letters of credit from banks or other institutional lenders, in each case, as amended, restated, modified, renewed, refunded, replaced or refinanced in whole or in part from time to time (and whether or not with the original administrative agent and lenders or another administrative agent or agents or other lenders and whether provided under the original Senior Secured Credit Agreement or any other credit or other agreement or indenture).

“Currency Agreement” means in respect of a Person any foreign exchange contract, currency swap agreement, futures contract, option contract or other similar agreement as to which such Person is a party or a beneficiary.

“Default” means any event which is, or after notice or passage of time or both would be, an Event of Default.

“Disqualified Stock” means, with respect to any Person, any Capital Stock of such Person which by its terms (or by the terms of any security into which it is convertible or for which it is exchangeable) at the option of the holder of the Capital Stock or upon the happening of any event:

(1) matures or is mandatorily redeemable (other than redeemable only for Capital Stock of such Person which is not itself Disqualified Stock) pursuant to a sinking fund obligation or otherwise;

(2) is convertible or exchangeable for Disqualified Stock or other Indebtedness (excluding Capital Stock which is convertible or exchangeable solely at the option of the Company or a Restricted Subsidiary); or

(3) is required to be repurchased by such Person at the option of the holder of the Capital Stock in whole or in part,

in each case on or prior to the date that is 91 days after the earlier of the date (a) of the Stated Maturity of the notes or (b) on which there are no notes outstanding; provided that only the portion of Capital Stock which so matures or is mandatorily redeemable, is so convertible or exchangeable or is so required to be repurchased at the option of the holder thereof prior to such date will be deemed to be Disqualified Stock; provided further, that any Capital Stock that would constitute Disqualified Stock solely because the holders thereof have the right to require the Company or any of its Restricted Subsidiaries to repurchase such Capital Stock upon the occurrence of a change of control or asset sale (each defined in a substantially identical manner to the corresponding definitions in the Indenture) shall not constitute Disqualified Stock if the terms of such Capital Stock (and all such securities into which it is convertible or for which it is exchangeable) provide that (i) the Company and its Restricted Subsidiaries may not repurchase or redeem any such Capital Stock (and all such securities into which it is convertible or for which it is ratable or exchangeable) pursuant to such provision prior to compliance by the Company and its Restricted Subsidiaries with the provisions of the Indenture described under the captions “— Change of Control” and “— Certain Covenants — Limitation on Sales of Assets and Subsidiary Stock” and (ii) such repurchase or redemption will be permitted solely to the extent also permitted in accordance with the provisions of the Indenture described under the caption “— Certain Covenants — Limitation on Restricted Payments”.

“Dollar-Denominated Production Payments” means production payment obligations recorded as liabilities in accordance with GAAP, together with all undertakings and obligations in connection therewith.

“Domestic Subsidiary” means any Restricted Subsidiary that is not a Foreign Subsidiary.

“Equity Offering” means a public or private offering for cash by the Company of its Capital Stock (other than Disqualified Stock).

“Exchange Act” means the Securities Exchange Act of 1934, as amended, and the rules and regulations of the SEC promulgated thereunder.

“Exchange Notes” means notes issued in exchange for old notes or additional notes pursuant to a Registration Rights Agreement.

“Fair Market Value” means, with respect to any asset or property, the sale value that would be obtained in an arm’s-length free market transaction between an informed and willing seller under no compulsion to sell and an informed and willing buyer under no compulsion to buy. Fair Market Value of an asset or property in excess of $20.0 million shall be determined by the Board of Directors of the Company acting in good faith, whose determination shall be conclusive and evidenced by a resolution of such Board of Directors, and any lesser Fair Market Value may be determined by an officer of the Company acting in good faith.

“Foreign Subsidiary” means any Restricted Subsidiary that is not organized under the laws of the United States of America or any state thereof or the District of Columbia and that conducts substantially all of its operations outside the United States of America.

“GAAP” means generally accepted accounting principles in the United States of America as in effect on the Issue Date. All ratios and computations based on GAAP contained in the Indenture will be computed in conformity with GAAP.

“General Partner” means Alta Mesa Holdings GP, LLC, a Texas limited liability company, and its successors as general partner of the Company.

The term “guarantee” means any obligation, contingent or otherwise, of any Person directly or indirectly guaranteeing any Indebtedness of any other Person and any obligation, direct or indirect, contingent or otherwise, of such Person:

(1) to purchase or pay (or advance or supply funds for the purchase or payment of) such Indebtedness of such other Person (whether arising by virtue of partnership arrangements, or by agreement to keep-well, to purchase assets, goods, securities or services, to take-or-pay, or to maintain financial statement conditions or otherwise); or

(2) entered into for purposes of assuring in any other manner the obligee of such Indebtedness of the payment thereof or to protect such obligee against loss in respect thereof (in whole or in part);

provided, however, that the term “guarantee” will not include endorsements for collection or deposit in the ordinary course of business or any obligation to the extent it is payable only in Capital Stock of the guarantor that is not Disqualified Stock. The term “guarantee” used as a verb has a corresponding meaning.

“Guarantor Subordinated Obligation” means, with respect to a Subsidiary Guarantor, any Indebtedness of such Subsidiary Guarantor (whether outstanding on the Issue Date or thereafter Incurred) which is expressly subordinated in right of payment to the obligations of such Subsidiary Guarantor under its Subsidiary Guarantee pursuant to a written agreement.

“Hedging Obligations” of any Person means the obligations of such Person pursuant to any Interest Rate Agreement, Currency Agreement or Commodity Agreement.

The term “holder” means a Person in whose name a note is registered on the registrar’s books.

“Hydrocarbons” means oil, natural gas, casing head gas, drip gasoline, natural gasoline, condensate, distillate, liquid hydrocarbons, gaseous hydrocarbons and all constituents, elements or compounds thereof and products refined or processed therefrom.

“Immaterial Subsidiary” means, as of any date, any Restricted Subsidiary with no Indebtedness in excess of $500,000 (excluding guarantees of Indebtedness under the Senior Secured Credit Agreement by Brayton Resources, L.P., Brayton Resources II, L.P. and Orion Operating Company, LP), and whose total assets, as of the end of the most recent month for which financial statements are available, taken together with those of all other Immaterial Subsidiaries, are less than 1.0% of the Company’s Adjusted Consolidated Net Tangible Assets and whose total revenues, taken together with those of all other Immaterial Subsidiaries, for the most recent 12-month period for which financial statements are available do not exceed 1.0% of the Company’s total consolidated revenues for such period.

“Incur” means issue, create, assume, guarantee, incur or otherwise become directly or indirectly liable for, contingently or otherwise; provided, however, that any Indebtedness or Capital Stock of a Person existing at the time such Person becomes a Restricted Subsidiary (whether by merger, consolidation, acquisition or otherwise) will be deemed to be Incurred by such Restricted Subsidiary at the time it becomes a Restricted Subsidiary; and the terms “Incurred” and “Incurrence” have meanings correlative to the foregoing.

“Indebtedness” means, with respect to any Person on any date of determination (without duplication, whether or not contingent):

(1) the principal of and premium (if any) in respect of indebtedness of such Person for borrowed money;

(2) the principal of and premium (if any) in respect of obligations of such Person evidenced by bonds, debentures, notes or other similar instruments;

(3) the principal component of all obligations of such Person in respect of letters of credit, bankers’ acceptances or other similar instruments (including reimbursement obligations with respect thereto except to the extent such reimbursement obligation relates to a trade payable and except to the extent such letters of credit are not drawn upon or, if and to the extent drawn upon, such obligation is satisfied within five Business Days of payment on the letter of credit);

(4) the principal component of all obligations of such Person to pay the deferred and unpaid purchase price of property, which purchase price is due more than six months after the date of placing such property in service or taking delivery and title thereto to the extent such obligations would appear as liabilities upon the consolidated balance sheet of such Person in accordance with GAAP, as obligor on conditional sales of property or under any title retention agreement;

(6) the principal component or liquidation preference of all obligations of such Person with respect to the redemption, repayment or other repurchase of any Disqualified Stock or, with respect to any Subsidiary of such Person, any Preferred Stock (but excluding, in each case, any accrued dividends);

(7) the principal component of all Indebtedness of other Persons secured by a Lien on any asset of such Person, whether or not such Indebtedness is assumed by such Person; provided, however, that the amount of such Indebtedness will be the lesser of (a) the Fair Market Value of such asset at such date of determination and (b) the amount of such Indebtedness of such other Persons;

(8) the principal component of Indebtedness of other Persons to the extent guaranteed by such Person; and

(9) to the extent not otherwise included in this definition, net obligations of such Person under Commodity Agreements, Currency Agreements and Interest Rate Agreements (the amount of any such obligations to be equal at any time to the termination value of such agreement or arrangement giving rise to such obligation that would be payable by such Person at such time);

provided, however, that any indebtedness which has been defeased in accordance with GAAP or defeased pursuant to the deposit of cash or Cash Equivalents (in an amount sufficient to satisfy all such indebtedness obligations at maturity or redemption, as applicable, and all payments of interest and premium, if any) in a trust or account created or pledged for the sole benefit of the holders of such indebtedness, and subject to no other Liens, shall not constitute “Indebtedness”.

The amount of Indebtedness of any Person at any date will be the outstanding balance at such date of all unconditional obligations as described above and the maximum liability, upon the occurrence of the contingency giving rise to the obligation, of any contingent obligations at such date.

(2) any obligation of a Person in respect of a farm-in agreement or similar arrangement whereby such Person agrees to pay all or a share of the drilling, completion or other expenses of an exploratory or development well (which agreement may be subject to a maximum payment obligation, after which expenses are shared in accordance with the working or participation interest therein or in accordance with the agreement of the parties) or perform the drilling, completion or other operation on such well in exchange for an ownership interest in an Oil and Gas Property;

(3) any obligations under Currency Agreements, Commodity Agreements and Interest Rate Agreements; provided that such Agreements are entered into for bona fide hedging purposes of the Company or its Restricted Subsidiaries (as determined in good faith by the Board of Directors or senior management of the Company, whether or not accounted for as a hedge in accordance with GAAP) and, in the case of Currency Agreements or Commodity Agreements, such Currency Agreements or Commodity

Agreements are related to business transactions of the Company or its Restricted Subsidiaries entered into in the ordinary course of business and, in the case of Interest Rate Agreements, such Interest Rate Agreements substantially correspond in terms of notional amount, duration and interest rates, as applicable, to Indebtedness of the Company or its Restricted Subsidiaries Incurred without violation of the Indenture;

(4) any obligation arising from customary agreements of the Company or a Restricted Subsidiary providing for indemnification, guarantees, adjustment of purchase price, holdbacks, contingency payment obligations or similar obligations, in each case, Incurred or assumed in connection with the acquisition or disposition of any business, assets or Capital Stock of a Restricted Subsidiary, provided that such Indebtedness is not reflected on the face of the balance sheet of the Company or any Restricted Subsidiary;

(5) any obligation arising from the honoring by a bank or other financial institution of a check, draft or similar instrument (including daylight overdrafts) drawn against insufficient funds in the ordinary course of business, provided that such Indebtedness is extinguished within five Business Days of Incurrence;

(6) in-kind obligations relating to net oil or natural gas balancing positions arising in the ordinary course of business; and

(7) accrued expenses and trade payables and other accrued liabilities arising in the ordinary course of business that are not overdue by 90 days or more or are being contested in good faith by appropriate proceedings promptly instituted and diligently conducted.

In addition, “Indebtedness” of any Person shall include Indebtedness described in the first paragraph of this definition of “Indebtedness” whether or not it would appear as a liability on the balance sheet of such Person if:

(1) such Indebtedness is the obligation of a joint venture or partnership that is not a Restricted Subsidiary (a “Joint Venture”);

(2) such Person or a Restricted Subsidiary of such Person is a general partner of the Joint Venture or otherwise liable for all or a portion of the Joint Venture’s liabilities (a “general partner”); and

(3) there is recourse, by contract or operation of law, with respect to the payment of such Indebtedness to property or assets of such Person or a Restricted Subsidiary of such Person;

(a) the lesser of (i) the net assets of the general partner and (ii) the amount of such obligations to the extent that there is recourse, by contract or operation of law, to the property or assets of such Person or a Restricted Subsidiary of such Person; or

(b) if less than the amount determined pursuant to clause (a) immediately above, the actual amount of such Indebtedness that is with recourse to such Person or a Restricted Subsidiary of such Person, if the Indebtedness is evidenced by a writing and is for a determinable amount.

“Interest Rate Agreement” means with respect to any Person any interest rate protection agreement, interest rate future agreement, interest rate option agreement, interest rate swap agreement, interest rate cap agreement, interest rate collar agreement, interest rate hedge agreement or other similar agreement or arrangement as to which such Person is party or a beneficiary.

“Investment” means, with respect to any Person, all investments by such Person in other Persons (including Affiliates) in the form of any direct or indirect advance, loan or other extensions of credit (including by way of guarantee or similar arrangement, but excluding any debt or extension of credit represented by a bank deposit other than a time deposit and advances or extensions of credit to customers in the ordinary course of business) or capital contribution to (by means of any transfer of cash or other property to others or any payment for property or services for the account or use of others), or any purchase or acquisition of Capital Stock, Indebtedness or other similar instruments (excluding any interest in an oil or natural gas leasehold to the extent constituting a security under applicable law) issued by, such other Person and all other items that are or would be classified as investments on a balance sheet prepared in accordance with GAAP; provided that none of the following will be deemed to be an Investment:

(1) Hedging Obligations entered into in the ordinary course of business and in compliance with the Indenture; and

(2) endorsements of negotiable instruments and documents in the ordinary course of business.

The amount of any Investment shall not be adjusted for increases or decreases in value, write-ups, write-downs or write-offs with respect to such Investment.

For purposes of the definition of “Unrestricted Subsidiary” and the covenant described under “— Certain Covenants — Limitation on Restricted Payments”,

(1) “Investment” will include the portion (proportionate to the Company’s equity interest in a Restricted Subsidiary to be designated as an Unrestricted Subsidiary) of the Fair Market Value of the net assets of such Restricted Subsidiary at the time that such Restricted Subsidiary is designated an Unrestricted Subsidiary; provided, however, that upon a redesignation of such Subsidiary as a Restricted Subsidiary, the Company will be deemed to continue to have a permanent “Investment” in an Unrestricted Subsidiary in an amount (if positive) equal to

(a) the Company’s “Investment” in such Subsidiary at the time of such redesignation less (b) the portion (proportionate to the Company’s equity interest in such Subsidiary) of the Fair Market Value of the net assets of such Subsidiary at the time that such Subsidiary is so redesignated a Restricted Subsidiary; and

(2) any property transferred to or from an Unrestricted Subsidiary will be valued at its Fair Market Value at the time of such transfer.

“Issue Date” means the first date on which notes are issued under the Indenture (which was October 13, 2010).

“Lien” means, with respect to any asset, any mortgage, lien (statutory or otherwise), pledge, hypothecation, charge, security interest, preference, priority or encumbrance of any kind in respect of such asset, whether or not filed, recorded or otherwise perfected under applicable law, including any conditional sale or other title retention agreement, any lease in the nature thereof, any option or other agreement to sell or give a security interest in and any filing of or agreement to give any financing statement under the Uniform Commercial Code (or equivalent statutes) of any jurisdiction other than a precautionary financing statement not intended as a security agreement.

“Minority Interest” means the percentage interest represented by any class of Capital Stock of a Restricted Subsidiary that are not owned by the Company or a Restricted Subsidiary.

“Moody’s” means Moody’s Investors Service, Inc., or any successor to the rating agency business thereof.

“Net Available Cash” from an Asset Disposition means cash payments received (including any cash payments received by way of deferred payment of principal pursuant to a note or installment receivable or

otherwise and net proceeds from the sale or other disposition of any securities received as consideration, but only as and when received, but excluding any other consideration received in the form of assumption by the acquiring Person of Indebtedness or other obligations relating to the assets that are the subject of such Asset Disposition or received in any other non-cash form) therefrom, in each case net of:

(1) all legal, accounting, investment banking, title and recording tax expenses, commissions and other fees and expenses Incurred, and all federal, state, provincial, foreign and local taxes (or Permitted Tax Distributions in respect thereof) required to be paid or accrued as a liability under GAAP (after taking into account any available tax credits or deductions and any tax sharing agreements), as a consequence of such Asset Disposition;

(2) all payments made on any Hedging Obligation or other Indebtedness which is secured by any assets subject to such Asset Disposition, in accordance with the terms of any Lien upon such assets, or which must by its terms, or in order to obtain a necessary consent to such Asset Disposition, or by applicable law be repaid out of the proceeds from such Asset Disposition;

(3) all distributions and other payments required to be made to minority interest holders in Subsidiaries or joint ventures or to holders of royalty or similar interests as a result of such Asset Disposition;

(4) the deduction of appropriate amounts to be provided by the seller as a reserve, in accordance with GAAP, against any liabilities associated with the assets disposed of in such Asset Disposition and retained by the Company or any Restricted Subsidiary after such Asset Disposition; and

(5) all relocation expenses incurred as a result thereof and all related severance and associated costs, expenses and charges of personnel related to assets and related operations disposed of;

provided, however, that if any consideration for an Asset Disposition (that would otherwise constitute Net Available Cash) is required to be held in escrow pending determination of whether or not a purchase price adjustment will be made, such consideration (or any portion thereof) shall become Net Available Cash only at such time as it is released to the Company or any of its Restricted Subsidiaries from escrow.

“Net Cash Proceeds”, with respect to any issuance or sale of Capital Stock or any contribution to equity capital, means the cash proceeds of such issuance, sale or contribution net of attorneys’ fees, accountants’ fees, underwriters’ or placement agents’ fees, listing fees, discounts or commissions and brokerage, consultant and other fees and charges actually Incurred in connection with such issuance, sale or contribution and net of taxes paid or payable as a result of such issuance or sale (after taking into account any available tax credit or deductions and any tax sharing arrangements).

“Net Working Capital” means (a) the sum of all current assets of the Company and its Restricted Subsidiaries, except current assets from commodity price risk management activities arising in the ordinary course of the Oil and Gas Business, (other than accounts receivable with respect to any non-contingent periodic settlement payments due thereunder), less (b) all current liabilities of the Company and its Restricted Subsidiaries, except current liabilities (i) associated with asset retirement obligations relating to Oil and Gas Properties, (ii) included in Indebtedness and (iii) any current liabilities of the Company and its Restricted Subsidiaries from commodity price risk management activities arising in the ordinary course of the Oil and Gas Business, (other than accounts payable with respect to any non-contingent periodic settlement payments due thereunder), in each case as set forth in the consolidated financial statements of the Company prepared in accordance with GAAP.

(1) as to which neither the Company nor any Restricted Subsidiary (a) provides any guarantee or credit support of any kind (including any undertaking, guarantee, indemnity, agreement or instrument that would constitute Indebtedness), (b) is directly or indirectly liable (as a guarantor or otherwise) or (c) constitutes the lender;

(2) no default with respect to which (including any rights that the holders thereof may have to take enforcement action against an Unrestricted Subsidiary) would permit (upon notice, lapse of time or both) any holder of any other Indebtedness of the Company or any Restricted Subsidiary to declare a default under such other Indebtedness or cause the payment thereof to be accelerated or payable prior to its Stated Maturity; and

(3) the explicit terms of which provide there is no recourse against any of the assets of the Company or its Restricted Subsidiaries.

“Officer” means the Chairman of the Board, the Chief Executive Officer, the President, the Chief Financial Officer, Chief Accounting Officer, any Vice President, the Treasurer or the Secretary of an Issuer. Officer of any Subsidiary Guarantor has a correlative meaning, and in the case of the Company (so long as it is a limited partnership), Officer means an Officer of its General Partner.

“Officers’ Certificate” means a certificate signed by two Officers of the Company, at least one of whom shall be the Chief Executive Officer, the Chief Financial Officer or the Chief Accounting Officer of the Company.

“Oil and Gas Business” means the business of exploiting, exploring for, developing, acquiring, operating, producing, processing, gathering, marketing, storing, selling, hedging, treating, swapping and transporting (but not refining) Hydrocarbons.

“Oil and Gas Properties” means any and all rights, titles, interests and estates in and to (1) oil or gas leases or (2) other liquid or gaseous Hydrocarbon leases, mineral fee interests, overriding royalty and royalty interests, net profit interests and production payment interests, in each case including any reserved or residual interests of whatever nature.

“Opinion of Counsel” means a written opinion from legal counsel who is acceptable to the Trustee. The counsel may be an employee of or counsel to an Issuer, a Subsidiary Guarantor or the Trustee.

“Pari Passu Indebtedness” means any Indebtedness of either Issuer or any Subsidiary Guarantor that ranks equally in right of payment to the Notes or the Subsidiary Guarantees, as the case may be.

“Permitted Acquisition Indebtedness” means Indebtedness (including Disqualified Stock) of the Company or any of the Restricted Subsidiaries to the extent such Indebtedness was Indebtedness:

(1) of an acquired Person prior to the date on which such Person became a Restricted Subsidiary as a result of having been acquired and not incurred in contemplation of such acquisition; or

(2) of a Person that was merged or consolidated with or into the Company or a Restricted Subsidiary that was not incurred in contemplation of such merger or consolidation,

provided that on the date such Person became a Restricted Subsidiary or the date such Person was merged or consolidated with or into the Company or a Restricted Subsidiary, as applicable, after giving pro forma effect thereto, the Restricted Subsidiary or the Company, as applicable, would be permitted to incur at least $1.00 of additional Indebtedness pursuant to the Consolidated Coverage Ratio test described under “— Certain Covenants — Limitation on Indebtedness and Preferred Stock”.

“Permitted Business Investment” means any Investment made in the ordinary course of, and of a nature that is or shall have become customary in, the Oil and Gas Business including through agreements, transactions, interests or arrangements which permit one to share risks or costs, comply with regulatory requirements regarding local ownership or satisfy other objectives customarily achieved through the conduct of the Oil and Gas Business jointly with third parties including:

(1) ownership interests in oil, natural gas, other Hydrocarbon and mineral properties, processing facilities, gathering systems, storage facilities or related systems or ancillary real property interests;

(2) Investments in the form of or pursuant to operating agreements, working interests, royalty interests, mineral leases, processing agreements, farm-in agreements, farm-out agreements, contracts for the sale, transportation or exchange of oil, natural gas, other Hydrocarbons and minerals, production sharing agreements, participation agreements, development agreements, area of mutual interest agreements, unitization agreements, pooling agreements, joint bidding agreements, service contracts, joint venture agreements, partnership agreements (whether general or limited), subscription agreements, stock purchase agreements, stockholder agreements and other similar agreements (including for limited liability companies) with third parties.

“Permitted Holder” means any of the following (A) (i) Michael E. Ellis, Mickey Ellis and their children, estates, heirs or lineal descendants, (ii) any trust having as its sole beneficiaries one or more of the persons listed in clause (A)(i) above, (iii) any Person a majority of the Voting Stock of which is owned or controlled one or more of the Persons referred to in clauses (A)(i) or (ii); (B) DCPF IV and any of its affiliates (other than any operating company in which it has a portfolio investment) and (C) any group (within the meaning of Section 13(d)(3) or Section 14(d)(2) of the Exchange Act or any successor provision) of which any of the forgoing are members.

“Permitted Investment” means an Investment by the Company or any Restricted Subsidiary in:

(2) another Person whose primary business is the Oil and Gas Business if as a result of such Investment such other Person becomes a Restricted Subsidiary or is merged or consolidated with or into, or transfers or conveys all or substantially all its assets to, the Company or a Restricted Subsidiary; provided, however, that the primary business of such Restricted Subsidiary is the Oil and Gas Business;

(4) receivables owing to the Company or any Restricted Subsidiary created or acquired in the ordinary course of business and payable or dischargeable in accordance with customary trade terms; provided, however, that such trade terms may include such concessionary trade terms as the Company or any such Restricted Subsidiary deems reasonable under the circumstances;

(5) payroll, commission, travel, relocation, expense and similar advances to cover matters that are expected at the time of such advances ultimately to be treated as expenses for accounting purposes and that are made in the ordinary course of business;

(6) loans or advances to employees (other than executive officers or directors) made in the ordinary course of business of the Company or such Restricted Subsidiary;

(7) Capital Stock or other securities received in settlement of debts (x) created in the ordinary course of business and owing to the Company or any Restricted Subsidiary or in satisfaction of judgments or (y) pursuant to any plan of reorganization or similar arrangement in a bankruptcy or insolvency proceeding;

(8) any Person as a result of the receipt of non-cash consideration from an Asset Disposition that was made pursuant to and in compliance with the covenant described under “Certain Covenants — Limitation on Sales of Assets and Subsidiary Stock”;

(10) Commodity Agreements, Currency Agreements, Interest Rate Agreements described in clause (3) of the penultimate paragraph of the definition of “Indebtedness”, and related Hedging Obligations;

(11) guarantees issued in accordance with the covenant described under “— Certain Covenants — Limitation on Indebtedness and Preferred Stock”;

(13) any Person to the extent such Investments consist of prepaid expenses, negotiable instruments held for collection and lease, utility and workers’ compensation, performance and other similar deposits made in the ordinary course of business by the Company or any Restricted Subsidiary;

(14) guarantees of performance or other obligations (other than Indebtedness) arising in the ordinary course of the Oil and Gas Business, including obligations under oil and natural gas exploration, development, joint operating, and related agreements and licenses, concessions or operating leases related to the Oil and Gas Business;

(16) Investments made after the Issue Date in Unrestricted Subsidiaries in an aggregate amount outstanding at any time not to exceed $10.0 million; and

(17) Investments by the Company or any of its Restricted Subsidiaries, together with all other Investments pursuant to this clause (17), in an aggregate amount outstanding at the time of such Investment not to exceed the greater of (i) $25.0 million and (ii) 2.5% of the Company’s Adjusted Consolidated Net Tangible Assets.

(1) Liens securing Indebtedness under a Credit Facility permitted to be Incurred under clause (1) of the second paragraph of the covenant set forth under “— Limitation on Indebtedness and Preferred Stock”;

(2) pledges or deposits by such Person under workers’ compensation laws, unemployment insurance laws, social security or old age pension laws or similar legislation, or good faith deposits in connection with bids, tenders, contracts (other than for the payment of Indebtedness) or leases to which such Person is a party, or deposits (which may be secured by a Lien) to secure public or statutory obligations of such Person including letters of credit and bank guarantees required or requested by the United States, any State thereof or any foreign government or any subdivision, department, agency, organization or instrumentality of any of the foregoing in connection with any contract or statute (including lessee or operator obligations under statutes, governmental regulations, contracts or instruments related to the ownership, exploration and production of oil, natural gas, other hydrocarbons and minerals on state, federal or foreign lands or waters), or deposits of cash or United States government bonds to secure indemnity performance, surety or appeal bonds or other similar bonds to which such Person is a party, or deposits as security for contested taxes or import or customs duties or for the payment of rent, in each case Incurred in the ordinary course of business;

(3) statutory and contractual Liens of landlords and Liens imposed by law, including carriers’, warehousemen’s, mechanics’, materialmen’s and repairmen’s Liens, in each case for sums not yet due or being contested in good faith by appropriate proceedings if a reserve or other appropriate provisions, if any, as shall be required by GAAP shall have been made in respect thereof;

(4) Liens for taxes, assessments or other governmental charges or claims not yet subject to penalties for non-payment or which are being contested in good faith by appropriate proceedings; provided that appropriate reserves, if any, required pursuant to GAAP have been made in respect thereof;

(5) Liens in favor of issuers of surety or performance bonds or bankers’ acceptances issued pursuant to the request of and for the account of such Person in the ordinary course of its business;

(6) survey exceptions, encumbrances, ground leases, easements or reservations of, or rights of others for, licenses, rights of way, sewers, electric lines, telegraph and telephone lines and other similar purposes, or zoning, building codes or other restrictions (including minor defects or irregularities in title and similar encumbrances) as to the use of real properties or Liens incidental to the conduct of the business of such Person or to the ownership of its properties or assets which do not in the aggregate materially adversely affect the value of the properties or assets of such Person and its Restricted Subsidiaries, taken as a whole, or materially impair their use in the operation of the business of such Person;

(7) Liens arising from the deposit of funds or securities in trust for the purpose of decreasing or defeasing Indebtedness so long as such deposit of funds or securities and such decreasing or defeasing of Indebtedness are permitted under the covenant described under “— Certain Covenants — Limitation on Restricted Payments”;

(8) Liens arising from leases, licenses, subleases and sublicenses of any property or assets (including real property and intellectual property rights) entered into in the ordinary course of the Oil and Gas Business;

(9) prejudgment Liens and judgment Liens not giving rise to an Event of Default so long as such Lien is adequately bonded and any appropriate legal proceedings which may have been duly initiated for the review of such judgment have not been finally terminated or the period within which such proceedings may be initiated has not expired;

(10) Liens for the purpose of securing the payment of all or a part of the purchase price of, or Capitalized Lease Obligations, purchase money obligations or other payments Incurred to finance the acquisition, lease, improvement or construction of or repairs or additions to, assets or property acquired or constructed in the ordinary course of business; provided that:

(a) the aggregate principal amount of Indebtedness secured by such Liens is otherwise permitted to be Incurred under the Indenture and does not exceed the cost of the assets or property so acquired or constructed; and

(b) such Liens are created within 180 days of the later of the acquisition, lease, completion of improvements, construction, repairs or additions or commencement of full operation of the assets or property subject to such Lien and do not encumber any other assets or property of the Company or any Restricted Subsidiary other than such assets or property and assets affixed or appurtenant thereto;

(11) Liens arising solely by virtue of any statutory or common law provisions relating to banker’s Liens, rights of set-off or similar rights and remedies as to deposit accounts or other funds maintained with a depositary institution; provided that:

(a) such deposit account is not a dedicated cash collateral account and is not subject to restrictions against access by the Company in excess of those set forth by regulations promulgated by the Federal Reserve Board; and

(b) such deposit account is not intended by the Company or any Restricted Subsidiary to provide collateral to the depository institution;

(12) Liens arising from deposits made in the ordinary course of business to secure any liability to insurance carriers;

(14) Liens on any property or assets of a Person at the time such Person becomes a Subsidiary; provided, however, that such Liens are not created or Incurred in connection with, or in contemplation of, such other Person becoming a Subsidiary; provided further, however, that any such Lien may not extend to any other property or assets owned by the Company or any Restricted Subsidiary (other than any property or assets affixed or appurtenant thereto);

(15) Liens on any property or assets at the time the Company or any of its Subsidiaries acquired the property or assets, including any acquisition by means of a merger or consolidation with or into the Company or any of its Subsidiaries; provided, however, that such Liens are not created or Incurred in connection with, or in contemplation of, such acquisition; provided further, however, that such Liens may not extend to any other property or assets owned by the Company or any Restricted Subsidiary (other than any property or assets affixed or appurtenant thereto);

(16) Liens securing the Notes, the Subsidiary Guarantees and any other Obligations under the Indenture;

(17) Liens securing Refinancing Indebtedness Incurred to refinance Indebtedness described under clauses (10), (13), (14), (15) or this clause (17) that was previously so secured, provided that any such Lien is limited to all or part of the same property or assets that secured (or, under the written arrangements under which the original Lien arose, could secure) the Indebtedness being refinanced or is in respect of property or assets that is the security for a Permitted Lien hereunder;

(19) Liens arising under farm-out agreements, farm-in agreements, division orders, contracts for the sale, purchase, exchange, transportation, gathering or processing of Hydrocarbons, unitizations and pooling designations, declarations, orders and agreements, development agreements, joint venture agreements, partnership agreements, operating agreements, royalties, working interests, net profits interests, joint interest billing arrangements, participation agreements, production sales contracts, area of mutual interest agreements, gas balancing or deferred production agreements, injection, repressuring and recycling agreements, salt water or other disposal agreements, seismic or geophysical permits or agreements, and other agreements that are customary in the Oil and Gas Business; provided, however, in all instances that such Liens are limited to the property or assets that are the subject of the relevant agreement, program, order or contract;

(21) Liens in favor of the Company, the Co-Issuer or any Subsidiary Guarantor; and

(22) Liens securing Indebtedness in an aggregate principal amount outstanding at any one time, added together with all other Indebtedness secured by Liens Incurred pursuant to this clause (22), not to exceed the greater of (a) $10.0 million and (b) 1.0% of the Company’s Adjusted Consolidated Net Tangible Assets.

In each case set forth above, notwithstanding any stated limitation on the property or assets that may be subject to such Lien, a Permitted Lien on a specified property or asset or group or type of properties or assets may include Liens on all improvements, additions and accessions thereto and all products and proceeds thereof (including dividends, distributions and increases in respect thereof).

“Permitted Tax Distributions” means for any calendar year or portion thereof of the Company during which it is a pass-through entity for U.S. federal income tax purposes, payments and distributions to the partners of the Company on each estimated payment date as well as each other applicable due date to enable the partners of the Company (or, if any of them are themselves a pass-through entity for US. Federal income tax purposes, their shareholders or partners) to make payments of U.S. federal and state income taxes (including estimates therefor) as a result of the operations of the Company and its Subsidiaries during the current and any previous calendar year, not to exceed an amount equal to the amount of each such partner’s (or, in the case of a pass-through entity, its shareholders’ or partners’) U.S. federal and state income tax liability resulting solely from the pass-through tax treatment of such partner’s interest in the Company and as calculated pursuant to the limited partnership agreement of the Company as in effect on the Issue Date and as it may be amended from time to time thereafter in a manner that is not, considered as a whole, materially adverse to the holders of the Notes.

“Person” means any individual, corporation, partnership, joint venture, association, joint-stock company, trust, unincorporated organization, limited liability company, government or any agency or political subdivision thereof or any other entity.

“Preferred Stock”, as applied to the Capital Stock of any Person, means Capital Stock of any class or classes (however designated) which is preferred as to the payment of dividends, or as to the distribution of assets upon any voluntary or involuntary liquidation or dissolution of such Person, over shares of Capital Stock of any other class of such Person.

“Production Payments and Reserve Sales” means the grant or transfer by the Company or a Restricted Subsidiary to any Person of a royalty, overriding royalty, net profits interest, production payment (whether volumetric or dollar denominated), partnership or other interest in Oil and Gas Properties, reserves or the right to receive all or a portion of the production or the proceeds from the sale of production attributable to such properties where the holder of such interest has recourse solely to such production or proceeds of production, subject to the obligation of the grantor or transferor to operate and maintain, or cause the subject interests to be operated and maintained, in a reasonably prudent manner or other customary standard or subject to the obligation of the grantor or transferor to indemnify for environmental, title or other matters customary in the Oil and Gas

Business, including any such grants or transfers pursuant to incentive compensation programs on terms that are reasonably customary in the Oil and Gas Business for geologists, geophysicists or other providers of technical or management services to the Company or a Restricted Subsidiary.

“Refinancing Indebtedness” means Indebtedness that is Incurred to refund, refinance, replace, exchange, renew, repay, extend, prepay, redeem or retire (including pursuant to any defeasance or discharge mechanism) (collectively, “refinance” and the terms “refinances” and “refinanced” shall have correlative meanings) any Indebtedness (including Indebtedness of the Company that refinances Indebtedness of any Restricted Subsidiary and Indebtedness of any Restricted Subsidiary that refinances Indebtedness of another Restricted Subsidiary, but excluding Indebtedness of a Restricted Subsidiary that refinances Indebtedness of the Company), including Indebtedness that refinances Refinancing Indebtedness, provided, however, that:

(1) (a) if the Stated Maturity of the Indebtedness being refinanced is earlier than the Stated Maturity of the notes, the Refinancing Indebtedness has a Stated Maturity no earlier than the Stated Maturity of the Indebtedness being refinanced or (b) if the Stated Maturity of the Indebtedness being refinanced is later than the Stated Maturity of the notes, the Refinancing Indebtedness has a Stated Maturity at least 91 days later than the Stated Maturity of the notes;

(2) the Refinancing Indebtedness has an Average Life at the time such Refinancing Indebtedness is Incurred that is equal to or greater than the Average Life of the Indebtedness being refinanced;

(3) such Refinancing Indebtedness is Incurred in an aggregate principal amount (or if issued with original issue discount, an aggregate issue price) that is equal to or less than the sum of the aggregate principal amount (or if issued with original issue discount, the aggregate accreted value) then outstanding of the Indebtedness being refinanced (plus, without duplication, any additional Indebtedness Incurred to pay interest, premiums or defeasance costs required by the instruments governing such existing Indebtedness and fees and expenses Incurred in connection therewith); and

(4) if the Indebtedness being refinanced is subordinated in right of payment to the notes or a Subsidiary Guarantee, such Refinancing Indebtedness is subordinated in right of payment to the notes or the Subsidiary Guarantee on terms at least as favorable to the holders as those contained in the documentation governing the Indebtedness being refinanced.

“Registration Rights Agreement” means that certain registration rights agreement dated as of the Issue Date by and among the Issuers, the Subsidiary Guarantors and the initial purchasers set forth therein and, with respect to any additional notes, one or more substantially similar registration rights agreements among the Issuers and the other parties thereto, as any such agreement may be amended from time to time.

“Restricted Investment” means any Investment other than a Permitted Investment.

“Restricted Subsidiary” means any Subsidiary of the Company other than an Unrestricted Subsidiary.

“S&P” means Standard & Poor’s Ratings Services, a division of The McGraw-Hill Companies, Inc., or any successor to the rating agency business thereof.

“Sale/Leaseback Transaction” means an arrangement relating to property now owned or hereafter acquired whereby the Company or a Restricted Subsidiary transfers such property to a Person and the Company or a Restricted Subsidiary leases it from such Person.

“Senior Secured Credit Agreement” means the Sixth Amended and Restated Credit Agreement dated as of May 13, 2010 among the Company, as borrower, Wells Fargo Bank, N.A., as administrative agent and the lenders parties thereto from time to time, including any guarantees, collateral documents, instruments and agreements executed in connection therewith, and any amendments, supplements, modifications, extensions,

renewals, restatements, refundings or refinancings thereof with other revolving credit facilities with banks or other institutional lenders that replace, refund or refinance any part of the loans or commitments thereunder, including any such replacement, refunding or refinancing revolving credit facility that increases the amount borrowable thereunder or alters the maturity thereof.

“Significant Subsidiary” means any Restricted Subsidiary that would be a “Significant Subsidiary” of the Company within the meaning of Rule 1-02 under Regulation S-X promulgated by the SEC, as in effect on the Issue Date.

“Stated Maturity” means, with respect to any security, the date specified in such security as the fixed date on which the payment of principal of such security is due and payable, including pursuant to any mandatory redemption provision, but shall not include any contingent obligations to repay, redeem or repurchase any such principal prior to the date originally scheduled for the payment thereof.

“Subordinated Obligation” means any Indebtedness of either Issuer (whether outstanding on the Issue Date or thereafter Incurred) which is expressly subordinated in right of payment to the Notes pursuant to a written agreement.

“Subsidiary” of any Person means (a) any corporation, association or other business entity (other than a partnership, joint venture, limited liability company or similar entity) of which more than 50% of the Voting Stock or (b) any partnership, joint venture, limited liability company or similar entity of which more than 50% of the capital accounts, distribution rights, total equity and voting interests or general or limited partnership interests, as applicable, is, in the case of clauses (a) and (b), at the time owned or controlled, directly or indirectly, by (1) such Person, (2) such Person and one or more Subsidiaries of such Person or (3) one or more Subsidiaries of such Person. Unless otherwise specified herein, each reference to a Subsidiary (other than in this definition) refers to a Subsidiary of the Company.

“Subsidiary Guarantee” means, individually, any guarantee of payment of the Notes by a Subsidiary Guarantor pursuant to the terms of the Indenture and any supplemental indenture thereto, and, collectively, all such guarantees.

“Subsidiary Guarantor” means any Subsidiary of the Company that is a guarantor of the Notes, including any Person that is required after the Issue Date to guarantee the Notes pursuant to the “Future Subsidiary Guarantors” covenant, in each case until a successor replaces such Person pursuant to the applicable provisions of the Indenture and, thereafter, means such successor; provided, however, that the Co-Issuer shall not be a Subsidiary Guarantor.

“Tax Amount” means, for any period, the combined federal, state and local income taxes, including estimated taxes, that would be payable by the Company if it were a Texas corporation filing separate tax returns with respect to its Taxable Income for such period; provided that in determining the Tax Amount, the effect thereon of any net operating loss carryforwards or other carryforwards or tax attributes, such as alternative minimum tax carryforwards, that would have arisen if the Company were a Texas corporation shall be taken into account; provided, further, that, if there is an adjustment in the amount of the Taxable Income for any period, an appropriate positive or negative adjustment shall be made in the Tax Amount, and if the Tax Amount is negative, then the Tax Amount for succeeding periods shall be reduced to take into account such negative amount until such negative amount is reduced to zero. Notwithstanding anything to the contrary, Tax Amount shall not include taxes resulting from the Company’s reorganization as, or change in the status to, a corporation for tax purposes.

“Taxable Income” means, for any period, the taxable income or loss of the Company for such period for U.S. federal income tax purposes.

(1) any Subsidiary of the Company (other than the Co-Issuer) that at the time of determination shall be designated an Unrestricted Subsidiary by the Board of Directors of the Company in the manner provided below; and

The Board of Directors of the Company may designate any Subsidiary of the Company (including any newly acquired or newly formed Subsidiary or a Person becoming a Subsidiary through merger or consolidation or Investment therein) to be an Unrestricted Subsidiary only if:

(1) such Subsidiary or any of its Subsidiaries does not own any Capital Stock or Indebtedness of or have any Investment in, or own or hold any Lien on any property of, any other Subsidiary of the Company which is not a Subsidiary of the Subsidiary to be so designated or otherwise an Unrestricted Subsidiary;

(2) all the Indebtedness of such Subsidiary and its Subsidiaries shall, at the date of designation, and will at all times thereafter, consist of Non-Recourse Debt;

(3) on the date of such designation, such designation and the Investment of the Company or a Restricted Subsidiary in such Subsidiary complies with “— Certain Covenants — Limitation on Restricted Payments”;

(4) such Subsidiary is a Person with respect to which neither the Company nor any of its Restricted Subsidiaries has any direct or indirect obligation (a) to subscribe for additional Capital Stock of such Person or (b) to maintain or preserve such Person’s financial condition or to cause such Person to achieve any specified levels of operating results;

(5) such Subsidiary, either alone or in the aggregate with all other Unrestricted Subsidiaries, does not operate, directly or indirectly, all or substantially all of the business of the Company and its Subsidiaries; and

(6) such Subsidiary is not a party to any agreement, contract, arrangement or understanding with the Company or any Restricted Subsidiary with terms less favorable to the Company or such Restricted Subsidiary than those that might have been obtained from Persons who are not Affiliates of the Company.

Any such designation by the Board of Directors of the Company shall be evidenced to the Trustee by filing with the Trustee a resolution of the Board of Directors of the Company giving effect to such designation and an Officers’ Certificate certifying that such designation complies with the preceding conditions. If, at any time, any Unrestricted Subsidiary would fail to meet the foregoing requirements as an Unrestricted Subsidiary, it shall thereafter cease to be an Unrestricted Subsidiary for purposes of the Indenture and any Indebtedness of such Subsidiary shall be deemed to be Incurred as of such date.

The Board of Directors of the Company may designate any Unrestricted Subsidiary to be a Restricted Subsidiary; provided that immediately after giving effect to such designation, no Default or Event of Default shall have occurred and be continuing or would occur as a consequence thereof and the Company could Incur at least $1.00 of additional Indebtedness under the first paragraph of the covenant described under “— Certain Covenants — Limitation on Indebtedness and Preferred Stock” on a pro forma basis taking into account such designation.

“U.S. Government Obligations” means securities that are (a) direct obligations of the United States of America for the timely payment of which its full faith and credit is pledged or (b) obligations of a Person controlled or supervised by and acting as an agency or instrumentality of the United States of America the timely payment of which is unconditionally guaranteed as a full faith and credit obligation of the United States of America, which, in either case, are not callable or redeemable at the option of the issuer thereof, and shall also include a depositary receipt issued by a bank (as defined in Section 3(a)(2) of the Securities Act), as custodian with respect to any such U.S. Government Obligations or a specific payment of principal of or interest on any such U.S. Government Obligations held by such custodian for the account of the holder of such depositary receipt; provided that (except as required by law) such custodian is not authorized to make any deduction from the amount payable to the holder of such depositary receipt from any amount received by the custodian in respect of the U.S. Government Obligations or the specific payment of principal of or interest on the U.S. Government Obligations evidenced by such depositary receipt.

“Volumetric Production Payments” means production payment obligations recorded as deferred revenue in accordance with GAAP, together with all undertakings and obligations in connection therewith.

“Voting Stock” of a Person means all classes of Capital Stock of such Person then outstanding and normally entitled to vote in the election of members of such Person’s Board of Directors.

“Wholly Owned Subsidiary” means a Restricted Subsidiary, all of the Capital Stock of which (other than directors’ qualifying shares or other shares required by applicable law to be held by a Person other than the Company or another Wholly Owned Subsidiary) is owned by the Company or another Wholly Owned Subsidiary.

Based on interpretations by the staff of the SEC in no-action letters issued to third parties, we believe you may transfer new notes issued under the exchange offer in exchange for the old notes if:

Each broker-dealer that receives new notes for its own account pursuant to the exchange offer in exchange for old notes that were acquired by such broker-dealer as a result of market-making or other trading activities must acknowledge that it will deliver a prospectus in connection with any resale of such new notes. This prospectus, as it may be amended or supplemented from time to time, may be used by a broker-dealer in connection with resales of new notes received in exchange for old notes where such old notes were acquired as a result of market-making activities or other trading activities.

If you wish to exchange new notes for your old notes in the exchange offer, you will be required to make representations to us as described in “Exchange Offer — Purpose and Effect of the Exchange Offer” and “Exchange Offer — Your Representations to Us” in this prospectus and in the letter of transmittal. In addition, if you are a broker-dealer who receives new notes for your own account in exchange for old notes that were acquired by you as a result of market-making activities or other trading activities, you will be required to acknowledge that you will deliver a prospectus in connection with any resale by you of such new notes.

We will not receive any proceeds from any sale of new notes by broker-dealers. New notes received by broker-dealers for their own account pursuant to the exchange offer may be sold from time to time in one or more transactions in any of the following ways:

Any such resale may be made directly to purchasers or to or through brokers or dealers who may receive compensation in the form of commissions or concessions from any such broker-dealer or the purchasers of any such new notes.

Any broker-dealer that resells new notes that were received by it for its own account pursuant to the exchange offer in exchange for old notes that were acquired by such broker-dealer as a result of market-making or other trading activities may be deemed to be an “underwriter” within the meaning of the Securities Act and profit on any such resale of notes issued in the exchange and any commission or concessions received by any such persons may be deemed to be underwriting compensation under the Securities Act. The letter of transmittal states that by acknowledging that it will deliver and by delivering a prospectus, a broker-dealer will not be deemed to admit that it is an “underwriter” within the meaning of the Securities Act.

For a period of up to one year after the exchange offer registration statement is declared effective, we will promptly send additional copies of this prospectus and any amendment or supplement to this prospectus to any

such broker-dealers that requests such documents. Furthermore, we agreed to amend or supplement this prospectus during such period if so requested in order to expedite or facilitate the disposition of any new notes by broker-dealers.

We have agreed to pay all expenses incident to the exchange offer other than fees and expenses of counsel to the holders and brokerage commissions and transfer taxes payable in respect of any transfer involved in the issuance or delivery of any new note in a name other that that of the holder of the old note in respect of which such new note is being issued, if any, and will indemnify the holders of the old notes (including any broker-dealers) against certain liabilities, including liabilities under the Securities Act.

The following discussion is a summary of the material federal income tax considerations relevant to the exchange of old notes for new notes, but does not purport to be a complete analysis of all potential tax effects. The discussion is based upon the Internal Revenue Code of 1986, as amended (the “Code”), Treasury Regulations, Internal Revenue Service rulings and pronouncements and judicial decisions now in effect, all of which may be subject to change at any time by legislative, judicial or administrative action. These changes may be applied retroactively in a manner that could adversely affect a holder of new notes. Some holders, including financial institutions, insurance companies, regulated investment companies, tax-exempt organizations, dealers in securities or currencies, persons whose functional currency is not the U.S. dollar, or persons who hold the notes as part of a hedge, conversion transaction, straddle or other risk reduction transaction may be subject to special rules not discussed below. We recommend that each holder consult his own tax advisor as to the particular tax consequences of exchanging such holder’s old notes for new notes, including the applicability and effect of any foreign, state, local or other tax laws or estate or gift tax considerations.

We believe that the exchange of old notes for new notes will not be an exchange or otherwise a taxable event to a holder for United States federal income tax purposes. Accordingly, a holder will not recognize gain or loss upon receipt of a new note in exchange for an old note in the exchange, and the holder’s basis and holding period in the new note will be the same as its basis and holding period in the corresponding old note immediately before the exchange.

The validity of the new notes offered in this exchange offer will be passed upon for us by Haynes and Boone, LLP, Houston, Texas.

The Alta Mesa financial statements as of December 31, 2010 and December 31, 2011 and for the three years ended December 31, 2011 included in this prospectus have been audited by UHY LLP, independent auditors, as stated in the report appearing herein. The Statements of Revenue and Direct Operating Expenses for the period January 1, 2011 through March 31, 2011 and for the twelve months ended December 31, 2010 (for the Sydson and TODD acquisitions) have been audited by UHY LLP, independent auditors, as stated in the reports appearing herein. The Meridian financial statements as of December 31, 2009 and 2008 and for the three years ended December 31, 2009 included in this prospectus have been audited by BDO USA, LLP (formerly known as BDO Seidman, LLP), an independent registered public accounting firm, whose report included an explanatory paragraph expressing substantial doubt about Meridian’s ability to continue as a going concern.

Estimates of proved reserves included in this prospectus as of December 31, 2011 using SEC guidelines, were prepared or derived from estimates prepared by T.J. Smith & Company, Inc., independent petroleum engineers, and W.D. Von Gonten & Co., independent petroleum engineers, and audited by Netherland, Sewell & Associates, Inc., independent petroleum engineers. These estimates are included in this prospectus in reliance on the authority of such firm as experts in these matters.

The terms and abbreviations defined in this section are used throughout this prospectus:

“3-D seismic” (Three-Dimensional Seismic Data). Geophysical data that depicts the subsurface strata in three dimensions. 3-D seismic data typically provides a more detailed and accurate interpretation of the subsurface strata than two-dimensional seismic data.

“Bbl”. One stock tank barrel, of 42 U.S. gallons liquid volume, used herein in reference to crude oil, condensate or natural gas liquids.

“Bcfe”. One billion cubic feet of natural gas equivalent with one barrel of oil converted to six thousand cubic feet of natural gas. The ratio of six thousand cubic feet of natural gas to one Bbl of oil or natural gas liquids is commonly used in the oil and natural gas business and represents the approximate energy equivalency of six thousand cubic feet of natural gas to one Bbl of oil or natural gas liquids, and does not represent the sales price equivalency of natural gas to oil or natural gas liquids. Currently, the sales price of one Bbl of oil or natural gas liquids is significantly higher than the sales price of six thousand cubic feet of natural gas.

“BOE”. One barrel of oil equivalent, converting gas to oil at the ratio of 6 Mcf of gas to one Bbl of oil.

“Basin”. A large natural depression on the earth’s surface in which sediments generally brought by water accumulate.

“Btu or British Thermal Unit”. The quantity of heat required to raise the temperature of one pound of water by one degree Fahrenheit.

“Completion”. The process of treating a drilled well followed by the installation of permanent equipment for the production of natural gas or oil, or in the case of a dry hole, the reporting of abandonment to the appropriate agency.

“De-bottlenecking”. The process of increasing production capacity of existing facilities through the modification of existing equipment to remove throughput restrictions.

“Delineation”. The process of placing a number of wells in various parts of a reservoir to determine its boundaries and production characteristics.

“Developed acreage”. The number of acres that are allocated or assignable to productive wells or wells capable of production.

“Developed oil and natural gas reserves”. Developed oil and natural gas reserves are reserves of any category that can be expected to be recovered: (i) through existing wells with existing equipment and operating methods or in which the cost of the related equipment is relatively minor compared to the cost of a new well; and (ii) through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.

“Development well”. A well drilled within the proved area of an oil or natural gas reservoir to the depth of a stratigraphic horizon known to be productive.

“Dry hole”. A well found to be incapable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of such production exceed production expenses and taxes.

“Dry hole costs”. Costs incurred in drilling a well, assuming a well is not successful, including plugging and abandonment costs.

“Enhanced recovery”. The recovery of oil and natural gas through the injection of liquids or gases into the reservoir, supplementing its natural energy. Enhanced recovery methods are often applied when production slows due to depletion of the natural pressure.

“Exploratory well”. A well drilled to find and produce natural gas or oil reserves not classified as proved, to find a new reservoir in a field previously found to be productive of natural gas or oil in another reservoir or to extend a known reservoir.

“Farm-in or farm-out”. An agreement under which the owner of a working interest in an oil and natural gas lease assigns the working interest or a portion of the working interest to another party who desires to drill on the leased acreage. Generally, the assignee is required to drill one or more wells in order to earn its interest in the acreage. The assignor usually retains a royalty or reversionary interest in the lease. The interest received by an assignee is a “farm-in” while the interest transferred by the assignor is a “farm-out”.

“Fault”. A break or planar surface in brittle rock across which there is observable displacement.

“Field”. An area consisting of a single reservoir or multiple reservoirs all grouped on, or related to, the same individual geological structural feature or stratigraphic condition. The field name refers to the surface area, although it may refer to both the surface and the underground productive formations.

“Formation”. A layer of rock which has distinct characteristics that differs from nearby rock.

“Fracing or fracture stimulation technology”. The technique of improving a well’s production or injection rates by pumping a mixture of fluids into the formation and rupturing the rock, creating an artificial channel. As part of this technique, sand or other material may also be injected into the formation to keep the channel open, so that fluids or natural gases may more easily flow through the formation.

“Gross acres or gross wells”. The total acres or wells, as the case may be, in which a working interest is owned.

“Horizontal drilling”. A drilling technique used in certain formations where a well is drilled vertically to a certain depth and then drilled at a right angle within a specified interval.

“Infill wells”. Wells drilled into the same pool as known producing wells so that oil or natural gas does not have to travel as far through the formation.

“Lease operating expenses”. The expenses of lifting oil or natural gas from a producing formation to the surface, constituting part of the current operating expenses of a working interest, and also including labor, superintendence, supplies, repairs, short-lived assets, maintenance, allocated overhead costs, workover, ad valorem taxes, insurance and other expenses incidental to production, but excluding lease acquisition or drilling or completion expenses.

“MBbl”. One thousand barrels of crude oil, condensate or natural gas liquids.

“Mcfe”. One thousand cubic feet equivalent determined using the ratio of six Mcf of natural gas to one barrel of oil, condensate or natural gas liquids.

“MMcfe”. Million cubic feet equivalent, determined using the ratio of six Mcf of natural gas to one Bbl of crude oil, condensate or natural gas liquids. The ratio of six thousand cubic feet of natural gas to one Bbl of oil or natural gas liquids is commonly used in the oil and natural gas business and represents the approximate energy equivalency of six thousand cubic feet of natural gas to one Bbl of oil or natural gas liquids, and does not represent the sales price equivalency of natural gas to oil or natural gas liquids. Currently, the sales price of one Bbl of oil or natural gas liquids is significantly higher than the sales price of six thousand cubic feet of natural gas.

“MMBbl”. One million barrels of crude oil, condensate or natural gas liquids.

“NGLs”. Natural gas liquids. Hydrocarbons found in natural gas which may be extracted as liquefied petroleum gas and natural gasoline.

“Net Acres”. The percentage of total acres an owner has out of a particular number of acres, or a specified tract. An owner who has 50% interest in 100 acres owns 50 net acres.

“Non-operated working interests”. The working interest or fraction thereof in a lease or unit, the owner of which is without operating rights by reason of an operating agreement.

“Pay”. A reservoir or portion of a reservoir that contains economically producible hydrocarbons. The overall interval in which pay sections occur is the gross pay; the smaller portions of the gross pay that meet local criteria for pay (such as a minimum porosity, permeability and hydrocarbon saturation) are net pay.

“Potential drilling locations”. Total gross resource play locations that we may be able to drill on our existing acreage. Our actual drilling activities may change depending on the availability of capital, regulatory approvals, seasonal restrictions, oil and natural gas prices, costs, drilling results and other factors.

“Productive well”. A well that is found to be capable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of the production exceed production expenses and taxes.

“Prospect”. A specific geographic area which, based on supporting geological, geophysical or other data and also preliminary economic analysis using reasonably anticipated prices and costs, is deemed to have potential for the discovery of commercial hydrocarbons.

“Proved reserves”. Proved oil and natural gas reserves are those quantities of oil and natural gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible — from a given date forward from known reservoirs, and under existing economic conditions, operating methods and government regulations — prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.

“Proved undeveloped reserves (“PUD”)”. Proved undeveloped oil and natural gas reserves are reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. Reserves on undrilled acreage are limited to those drilling units offsetting productive units that are reasonably certain of production when drilled. Proved reserves for other undrilled units are claimed only where it can be demonstrated with certainty that there is continuity of production from the existing productive formation. Estimates for proved undeveloped reserves will not be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual tests in the area and in the same reservoir.

“PV-10”. When used with respect to oil and natural gas reserves, PV-10 means the estimated future gross revenue to be generated from the production of proved reserves, net of estimated production and future development and abandonment costs, using prices and costs in effect at the determination date, before income taxes, and without giving effect to non-property related expenses, discounted to a present value using an annual discount rate of 10% in accordance with the guidelines of the SEC. PV-10 is not a financial measure calculated in accordance with generally accepted accounting principles (“GAAP”) and generally differs from Standardized Measure, the most directly comparable GAAP financial measure, because it does not include the effects of income taxes on future net revenues. Neither PV-10 nor Standardized Measure represents an estimate of the fair market value of our oil and natural gas properties. We and others in the industry use PV-10 as a measure to compare the relative size and value of proved reserves held by companies without regard to the specific tax characteristics of such entities. Our PV-10 is the same as our standardized measure for the periods presented in this prospectus.

“Recompletion”. The process of re-entering an existing wellbore that is either producing or not producing and completing new reservoirs in an attempt to establish or increase existing production.

“Reserve life index”. A measure of the productive life of an oil and natural gas property or a group of properties, expressed in years.

“Reservoir”. A porous and permeable underground formation containing a natural accumulation of producible oil and/or natural gas that is confined by impermeable rock or water barriers and is separate from other reservoirs.

“Spacing”. The distance between wells producing from the same reservoir. Spacing is often expressed in terms of acres, e.g., 40-acre spacing, and is often established by regulatory agencies.

“Standardized measure”. Standardized measure is the present value of estimated future net revenues to be generated from the production of proved reserves, determined in accordance with the rules and regulations of the Securities and Exchange Commission, without giving effect to non — property related expenses such as certain general and administrative expenses, debt service and future federal income tax expenses or to depreciation, depletion and amortization and discounted using an annual discount rate of 10%. Our standardized measure includes future obligations under the Texas gross margin tax, but it does not include future federal income tax expenses because we are a partnership and are not subject to federal income taxes. Our standardized measure is the same as our PV-10 for the periods presented in this prospectus.

“Undeveloped acreage”. Lease acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil and natural gas regardless of whether such acreage contains proved reserves.

“Unit”. The joining of all or substantially all interests in a reservoir or field, rather than a single tract, to provide for development and operation without regard to separate property interests. Also, the area covered by a unitization agreement.

“Waterflood”. The injection of water into an oil reservoir to “push” additional oil out of the reservoir rock and into the wellbores of producing wells. Typically an enhanced recovery process.

“Wellbore”. The hole drilled by the bit that is equipped for natural gas production on a completed well. Also called well or borehole.

“Working interest”. The right granted to the lessee of a property to explore for and to produce and own natural gas or other minerals. The working interest owners bear the exploration, development, and operating costs on either a cash, penalty, or carried basis.

We have audited the accompanying consolidated balance sheets of Alta Mesa Holdings, LP and Subsidiaries (the “Company”) as of December 31, 2011 and 2010, and the related consolidated statements of operations, changes in partners’ capital and cash flows for each of the three fiscal years in the period ended December 31, 2011. These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits.

We conducted our audits in accordance with standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audit included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the consolidated financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall consolidated financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the consolidated financial position of the Company as of December 31, 2011 and 2010, and the consolidated results of its operations and its cash flows for each of the three fiscal years in the period ended December 31, 2011, in conformity with accounting principles generally accepted in the United States of America.

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

Nature of Operations. The Company is engaged primarily in the acquisition, exploration, development, and production of oil and natural gas properties. The Company’s properties are located in Texas, Oklahoma, Louisiana, Florida and the Appalachian Region.

Accounting policies used by the Company and its subsidiaries reflect industry practices and conform to accounting principles generally accepted in the U.S. (“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.

Principles of Consolidation. The consolidated financial statements include the accounts of the Company and its wholly owned subsidiaries, after eliminating all significant intercompany transactions. The Company’s interest in oil and natural gas exploration and production ventures and partnerships are proportionately consolidated.

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, the value of oil and natural gas properties, oil and natural gas revenues, 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.

Cash and Cash Equivalents. We consider all highly liquid investments purchased with an original maturity of three months or less to be cash equivalents. The Company maintains cash balances at financial institutions in the United States of America, which at times exceed federally insured amounts. In July 2010, the Federal Deposit Insurance Corporation permanently increased its insurance to $250,000 per depositor. Additionally, coverage for

non-interest bearing accounts, which is temporary, extends through December 31, 2012. This coverage is separate from, and in addition to, the coverage provided for other accounts held at an insured depository institution. We monitor the financial condition of the financial institutions and have experienced no losses associated with these accounts.

Accounts Receivable. The Company’s 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 natural gas industry. Accounts receivable are generally not collateralized.

Allowance for Doubtful Accounts. We routinely assess the recoverability of all material trade and other receivables to determine their collectability. We accrue a reserve when, based on the judgment of management, it is probable that a receivable will not be collected and the amount of the reserve can be reasonably estimated. Accounts receivable are shown net of allowance for doubtful accounts of $557,000 and $338,000 as of December 31, 2011 and 2010, respectively.

Deferred Financing Costs. Deferred financing costs and the amount of discount at which notes payable have been issued (debt discount) are amortized using the straight-line method, which approximates the interest method, over the term of the related debt. For the years ended December 31, 2011, 2010, and 2009, amortization of deferred financing costs included in interest expense amounted to $2.8 million, $4.2 million, and $772,000, respectively. Deferred financing costs are listed among our long-term assets, net of accumulated amortization of $7.5 million and $4.7 million at December 31, 2011 and 2010, respectively.

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 expenses 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.

Our evaluation of the Company’s proved producing properties resulted in impairment expense of $16.9 million, $6.4 million, and $3.1 million for the years ended December 31, 2011, 2010, and 2009, respectively.

In addition, the Company recorded other write-downs and impairment expense of casing and tubing to lower of cost or market, of $162,000, $18,000 and $2.4 million for the years ended December 31, 2011, 2010 and 2009, respectively.

Management evaluates whether the carrying value of all other long-lived assets has been impaired when circumstances indicate the carrying value of those assets may not be recoverable. This evaluation is based on undiscounted cash flow projections. The carrying amount is not recoverable if it exceeds the undiscounted sum of cash flows expected to result from the use and eventual disposition of the assets. Management considers various factors when determining if these assets should be evaluated for impairment.

If the carrying value is not recoverable on an undiscounted basis, the impairment loss is measured as the excess of the asset’s carrying value over its fair value. Management assesses the fair value of long-lived assets using commonly accepted techniques, and may use more than one method, including, but not limited to, recent third party comparable sales, internally developed discounted cash flow analysis and analysis from outside advisors. Significant changes in market conditions resulting from events such as the condition of an asset or a change in management’s intent to utilize the asset would generally require management to reassess the cash flows related to the long-lived assets. For the years ended December 31, 2011, 2010, and 2009, respectively, the Company did not record any impairment expense related to other long-lived assets.

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.

DD&A expense for the years ended December 31, 2011, 2010, and 2009 related to oil and natural gas properties was $92.3 million, $58.2 million, and $47.3 million, respectively.

The Company’s drilling rigs, one of which was sold in December 2009, and the other of which was acquired in connection with the acquisition of The Meridian Resource Corporation (“Meridian”) in May 2010, have been depreciated using the straight-line method of depreciation over a period of approximately fifteen years. Depreciation expense of the rigs for the years ended December 31, 2011, 2010, and 2009 was $693,000, $444,000, and $930,000, respectively.

Leasehold improvements to offices are depreciated using the straight-line method over the life of the lease.

Other property and equipment is depreciated using the straight-line method over periods ranging from three to seven years. Depreciation expense for other property and equipment for the years ended December 31, 2011, 2010, and 2009 was $1.2 million, $494,000, and $468,000 respectively.

Investment. The Company’s investment consists of a 10% ownership interest in a drilling company, Orion Drilling Company, LP (“Orion”). The investment is accounted for under the cost method. Under this method, the Company’s share of earnings or losses of the investment are not included in the statements of operations. Distributions from Orion are recognized in current period earnings as declared. For the years ended December 31, 2011, 2010, and 2009, distributions of zero, $735,000, and $957,000 respectively, were included in “Other revenues” in the Consolidated Statements of Operations.

Asset Retirement Obligations. The Company estimates the present value of future costs of dismantlement and abandonment of its wells, facilities, and other tangible long-lived assets, recording them as liabilities in the period incurred. Asset retirement obligations are calculated using an expected present value technique. Salvage values are excluded from the estimation. We follow ASC 410, “Asset Retirement and Environmental Obligations.” ASC 410 requires that an asset retirement obligation (“ARO”) associated with the retirement of a tangible long-lived asset be recognized as a liability in the period in which it is incurred or becomes determinable (as defined by the ASC), with an associated increase in the carrying amount of the related long-lived asset. The cost of the tangible asset, including the initially recognized asset retirement cost, is depreciated over the useful life of the asset and accretion expense is recognized over time as the discounted liability is accreted to its expected settlement value. The fair value of new ARO’s are measured using expected future cash outflows for abandonment discounted generally at our cost of capital at the time of recognition.

Derivative Financial Instruments. We use derivative contracts to hedge the effects of fluctuations in the prices of oil, natural gas and interest rates. We account for such derivative instruments in accordance with ASC 815, “Derivatives and Hedging,” which establishes accounting and disclosure requirements for derivative instruments and requires them to be measured at fair value and recorded as assets or liabilities in the statements of financial position (see Note 5 for information on fair value).

Under ASC 815, hedge accounting is used to defer recognition of unrealized changes in the fair value of such financial instruments, for those contracts which qualify as fair value or cash flow hedges, as defined in the guidance. Historically, we have not designated any of our derivative contracts as fair value or cash flow hedges. Accordingly, the unrealized changes in fair value of the contracts are included in earnings in the period of the change as “Unrealized gain (loss) — oil and natural gas derivative contracts” for oil and natural gas contracts, and in interest expense for interest derivative contracts. Realized gains and losses are recorded in income in the period of settlement, and included in the related revenue account or in interest expense. Cash flows from settlements of derivative contracts are classified with the income or expense item to which such settlements directly relate.

Income Taxes. The Company has elected under the Internal Revenue Code provisions to be treated as individual partnerships for tax purposes. Accordingly, items of income, expense, gains and losses flow through to the partners and are taxed at the partner level. Accordingly, no tax provision for federal income taxes is included in the consolidated financial statements.

The Company is subject to the Texas margin tax, which is considered a state income tax, and is included in “Benefit from (provision for) state income tax” on the consolidated statements of operations. The Company records state income tax (current and deferred) based on taxable income, as defined under the rules for the margin tax.

We follow guidance issued by the FASB in accounting for uncertainty in income taxes. This guidance clarifies the accounting for income taxes by prescribing the minimum recognition threshold an income tax position is required to meet before being recognized in the consolidated financial statements and applies to all income tax

positions. Each income tax position is assessed using a two step process. A determination is first made as to whether it is more likely than not that the income tax position will be sustained, based upon technical merits, upon examination by the taxing authorities. If the income tax position is expected to meet the more likely than not criteria, the benefit recorded in the consolidated financial statements equals the largest amount that is greater than 50% likely to be realized upon its ultimate settlement.

Management has considered the Company’s exposure under the standard at both the federal and state tax levels. We did not have any uncertain tax positions as of December 31, 2011 and 2010. We record income tax, related interest, and penalties, if any, as a component of income tax expense. We did not incur any interest or penalties for the years ended December 31, 2011, 2010, or 2009.

The Company’s tax returns for the year ended December 31, 2008 forward remain open for examination. None of the Company’s federal or state tax returns are currently under examination by the relevant authorities.

Revenue Recognition. We recognize oil, natural gas and natural gas liquids revenues when products are delivered at a fixed or determinable price, title has transferred and collectability is reasonably assured (sales method). Revenue from drilling rigs has been recorded when services were performed.

Financial Instruments. The fair value of cash, accounts receivable and current liabilities approximate book value due to their short-term nature. The estimate of fair value of long-term debt under our credit facility is not considered to be materially different from carrying value due to market rates of interest. The fair value of the debt to our founder is not practicable to determine. We have estimated the fair value of our senior notes payable at $292.5 million on December 31, 2011. See Note 5 for further information on fair values of financial instruments. See Note 9 for information on long-term debt.

Acquisitions. Acquisitions are accounted for as purchases and, accordingly, the results of operations are included in our consolidated statements of operations from the closing date of the acquisitions. Purchase prices are allocated to acquired assets and assumed liabilities based on their estimated fair value at the time of the acquisition.

Reclassifications. Certain amounts in the 2010 and 2009 consolidated financial statements have been reclassified to conform to the 2011 presentation. The reclassifications had no impact on net income or partners’ capital.

On May 12, 2011, the FASB issued ASU No. 2011-04 to Topic 820, Fair Value Measurements, “Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in U.S. GAAP and IFRS.” The ASU changes certain definitions of terms used its guidance regarding fair value measurements, as well as modifying certain disclosure requirements and other aspects of the guidance. ASU 2011-04 is effective for interim and annual periods beginning after December 15, 2011. We do not expect adoption of the guidance to have a material impact on our consolidated financial position or results of operations.

On June 16, 2011, the FASB issued ASU No. 2011-05, Presentation of Comprehensive Income. This standard eliminates the current option to report other comprehensive income and its components in the statement of changes in equity. Two presentation options remain. Changes in comprehensive income may be reported in a continuous statement of comprehensive income which presents the components of net income as well as the components of comprehensive income. Alternatively, the components of comprehensive income may be reported in a separate statement of comprehensive income, which must immediately follow the statement of net income. The ASU also created a new requirement that reclassifications from comprehensive income to net income be presented on a gross basis on the face of the financial statements (previously net presentation and footnoting gross information was permitted). However, in December 2011, the FASB issued ASU 2011-12, to delay the effectiveness of this new requirement regarding the presentation of such reclassifications; while the FASB

reconsiders those provisions, the previous guidance should be used. ASU 2011-05, with the exception of the provisions regarding certain reclassifications, applies to interim and year end reports and is effective for fiscal years beginning after December 15, 2011, and is to be retrospectively applied to all periods presented in such reports. Early adoption is permitted. We do not expect adoption of the guidance to have a material impact on our consolidated financial position or results of operations.

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

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

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.

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.

In addition to the above, the Company made other insignificant acquisitions during the years ended December 31, 2011 and 2010.

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

The revenue and earnings related to these acquisitions are included in our consolidated statement of operations for the year ended December 31, 2011 from date of acquisition. The revenue and earnings of the combined entity, had the acquisitions occurred at the beginning of each of the periods presented, 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.

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

We utilize the modified Black-Scholes option pricing model to estimate the fair value of oil and natural gas derivative contracts. Inputs to this model include observable inputs from the New York Mercantile Exchange (NYMEX) and other exchanges 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 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 date.

Oil and natural gas properties are subject to impairment testing and potential impairment write down as described in Note 2. Oil and natural gas properties with a carrying amount of $35.2 million were written down to their fair value of $16.5 million, resulting in an impairment charge of $18.7 million for the year ended December 31, 2011. Oil and natural gas properties with a carrying amount of $19.1 million were written down to their fair value of $10.7 million, resulting in an impairment charge of $8.4 million for the year ended December 31, 2010. Oil and natural gas properties with a carrying amount of $8.3 million were written down to their fair value of $4.5 million, resulting in an impairment charge of $3.8 million for the year ended December 31, 2009. The impairment analysis is based on the estimated discounted future cash flows for those properties. Significant Level 3 assumptions used in the calculation of estimated discounted cash flows included our estimate of future oil and natural gas prices, production costs, development expenditures, estimated quantities and timing of production of proved reserves, appropriate risk-adjusted discount rates, and other relevant data.

In addition, other equipment, included in oil and gas properties, was impaired $18,000 and $2.4 million for the years ended December 31, 2010 and 2009, respectively, based on market information for similar products, which is a Level 3 value.

In connection with the Meridian acquisition in 2010, we recorded oil and natural gas properties with a fair value of $147 million. In connection with the Sydson and TODD acquisitions in 2011, we recorded oil and natural gas properties with a fair value of $28 million and $23 million, respectively. Significant Level 3 inputs used were the same as those used in determining impairments based on estimated discounted cash flows for the acquired properties.

New additions to asset retirement obligations result from estimations for new properties, and fair values for them, are categorized as Level 3. Such estimations are based on present value techniques which utilize company-specific information for such inputs as cost and timing of plug and abandonment of wells and facilities. We recorded a total of $3.4 million in additions to asset retirement obligations measured at fair value for the year ended December 31, 2011, of which, $2.8 million was added as a result of the acquisitions of Sydson and TODD and other properties. We recorded a total of $31.6 million in additions to asset retirement obligations measured at fair value for the year ended December 31, 2010, including $30.9 million added as a result of the Meridian acquisition.

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

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.

We account for our derivative contracts under the provisions of ASC 815, “Derivatives and Hedging.” The Company has entered into forward-swap contracts and collar contracts to reduce its exposure to price risk in the spot market for oil and natural gas. The Company also utilizes financial basis swap contracts, which address the price differential between market-wide benchmark prices and other benchmark pricing referenced in certain of our oil and natural gas sales contracts. With very few exceptions, the Company’s hedging agreements are executed by affiliates of the lenders (“Lenders”) under our senior secured revolving credit facility (“Credit Facility”) described in Note 9 below, and are collateralized by the security interests of the respective affiliated Lenders in certain assets of the Company under the Credit Facility. The contracts settle monthly and are scheduled to coincide with either oil production equivalent to barrels (Bbl) per month or natural gas production equivalent to volumes in millions of British thermal units (MMbtu) per month. The contracts represent agreements between the Company and the counter-parties to exchange cash based on a designated price. Prices are referenced to natural gas and crude oil futures contracts traded on the New York Mercantile Exchange (NYMEX) index or the Intercontinental Exchange (ICE). Cash settlement occurs monthly based on the specified price benchmark. The Company has not designated any of its derivative contracts as fair value or cash flow hedges; accordingly we use mark-to-market accounting as described in Note 2, recognizing unrealized gains and losses in the consolidated statement of operations at each reporting date. Realized gains and losses on commodities hedging contracts are included in oil and natural gas revenues.

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

No derivative contracts have been entered into for trading purposes, and the Company typically holds each instrument to maturity.

The second table below provides information on the location and amounts of realized and unrealized gains and losses on derivatives included in the statement of operations for each of the years ended December 31, 2011 and 2010.

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

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 the Company’s derivative instruments in the consolidated statements of operations:

Although the Company’s counterparties provide no collateral, the master derivative agreements with each counterparty effectively allow the Company, so long as it is 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, the Company 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.

In the tables below for natural gas and crude oil derivative positions open as of December 31, 2011, the notional amount is equal to the total net volumetric hedge position of the Company during the periods presented. We have hedged approximately 73% of our forecasted production from proved developed reserves through 2016.

The Company had the following open derivative contracts for natural gas at December 31, 2011:

The Company had the following open derivative contracts for crude oil at December 31, 2011:

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. Prices stated in the table above for oil may settle against either NYMEX or Brent ICE indices or may reflect a mix of positions settling on these two indices.

The Company had the following open financial basis swap contracts for natural gas at December 31, 2011:

The Company had the following open interest rate swap contracts at December 31, 2011:

As discussed in Note 2, the Company follows ASC 410 in accounting for asset retirement obligations. A summary of the changes in asset retirement obligations is included in the table below:

The Company has notes payable to our founder which bear interest at 10% with a balance of $20.9 million and $19.7 million at December 31, 2011 and 2010, respectively. See further information at Note 9.

Alta Mesa Services, LP (“Alta Mesa Services”), one of our wholly owned subsidiaries, conducts our business and operations and, in addition to the board of directors of our general partner, makes decisions on our behalf. Prior to the consummation of the offering of our senior notes in October 2010, Alta Mesa Services was owned by Michael E. Ellis, the founder of the Company, as well as Chief Operating Officer and Chairman of the Board and Mickey Ellis, his spouse.

The consolidated results of operations include the financial activity of Alta Mesa Services for the years ended December 31, 2011, 2010, and 2009, respectively.

During 2011, 2010, and 2009 Michael E. Ellis received capital distributions from the Company of $165,000, $235,000 and $100,000, respectively.

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

On October 13, 2010, in connection with the issuance of the senior notes, the Company entered into a registration rights agreement with the initial purchasers of the senior notes, pursuant to which, 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, and all of the original senior notes were exchanged for the exchange notes.

In addition, the Company has notes payable to our founder which bear simple interest at 10% with a balance of $20.9 million and $19.7 million at December 31, 2011 and 2010, respectively. The notes mature December 31, 2018. Interest and principal are payable at maturity. The notes are subordinate to all debt. Interest on our notes payable to our founder amounted to $1.2 million during 2011, $1.4 million during 2010, and $1.2 million during 2009. Such amounts have been added to the balance of the notes.

Future maturities of long-term debt, including the notes payable to our founder, at December 31, 2011 are as follows (dollars in thousands):

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 December 31, 2011, 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.

Hilltop Field Litigation: On July 23, 2009, we made a payment of $25.5 million and took assignment of substantially all working interests that had been held by Chesapeake in an approximate 50,000 acre area of Leon and Robertson Counties, Texas known as 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 are pursuing other claims against Chesapeake and Gastar; Chesapeake is claiming an additional $36.3 million of past expenses. The case is set for trial on

April 24, 2012. We are unable to express an opinion with respect to the likelihood of an unfavorable outcome of this matter or to estimate the amount or range of potential loss should the outcome be unfavorable. Therefore, we have not provided any amount for this matter in our consolidated financial statements at December 31, 2011.

Ted R. Stalder, TRS LP, Richard Hughart, and Richmar Interests, Inc. v. Texas Energy Acquisitions, LP: On May 24, 2011, the plaintiffs brought suit against us for breach of contract, common law fraud, fraud in a real estate transaction, declaratory relief, money had and received, an accounting, and injunctive relief related to the deferred purchase price for oil and gas properties in two purchase and sales agreements dated December 23, 2008. In March 2012, the parties arrived at a settlement which modified the terms of the two purchase and sale agreements to accelerate the payment of contingent additional consideration to the plaintiffs. Based on the structure of this subsequent settlement, we accrued additional estimated acquisition costs for the related properties in our consolidated financial statements at December 31, 2011.

Environmental Claims: Management has established a liability for soil contamination in Florida of approximately $990,000 and $943,000 at December 31, 2011 and 2010, respectively, based on the Company’s undiscounted engineering estimates. The obligations are included in other long-term liabilities in the accompanying consolidated balance sheets.

Various landowners have sued Meridian (along with numerous other oil companies) in lawsuits concerning several fields in which Meridian has had operations. The lawsuits seek injunctive relief and other relief, including unspecified amounts in both actual and punitive damages for alleged breaches of mineral leases and alleged failure to restore the plaintiffs’ lands from alleged contamination and otherwise from Meridian’s oil and natural gas operations. The Company is 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 consolidated financial statements at December 31, 2011.

Due to the nature of the Company’s business, some contamination of the real estate property owned or leased by the Company is possible. Environmental site assessments of the property would be necessary to adequately determine remediation costs, if any.

Other Contingencies: The Company is 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 the Company’s consolidated 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.

The Company has a contingent commitment to pay an amount up to a maximum of approximately $3.5 million for properties acquired in 2008 and prior years. The additional purchase consideration will be paid if certain product price conditions are met.

Title/lease disputes: Title and lease disputes may arise in the normal course of the Company’s 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.

Office and Equipment Leases: The Company leases office space, as well as certain field equipment such as compressors, under long-term operating lease agreements. The lease for our main office will expire in 2022. Any initial rent-free months are amortized over the life of the lease. Equipment leases are generally for four years or less. Rent expense, including office space and compressors, for the years ended December 31, 2011, 2010, and 2009 amounted to approximately $4.3 million, $2.9 million, and $1.4 million, respectively.

At December 31, 2011, future base rentals for non-cancelable leases are as follows (dollars in thousands):

Additionally, at December 31, 2011, the Company had posted bonds in the aggregate amount of $9.2 million, primarily to cover future abandonment costs.

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

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

The Company markets production on a competitive basis. Natural gas is sold under short-term contracts generally with month-to-month pricing based on published regional indices (typically the market index for delivery at the Houston Ship Channel), with differentials for transportation taken into account. Our oil is primarily sold under short-term contracts, based on local posted prices, adjusted for transportation, location, and quality.

For the year ended December 31, 2011, based on revenues excluding hedging activities, two major customers accounted for 10% or more of those revenues individually, with contributions of $67.7 million and $40.8 million. On the same basis, for the year ended December 31, 2010, one major customer accounted for 10% or more of those revenues individually, with contributions of $38.4 million. On the same basis, for the year ended December 31, 2009, four major customers accounted for 10% or more of those revenues individually, with contributions of $12.2 million, $9.0 million, $8.5 million, and $7.4 million. We believe that the loss of such customers would not have a material adverse effect on us because alternative purchasers are readily available.

Employees of Alta Mesa Services and Petro Operating Company, LP (“POC”) may participate in a 401(k) savings plan, whereby the employees may elect to make contributions pursuant to a salary reduction agreement. Alta Mesa Services and POC make a matching contribution equal to fifty-percent (50%) of an employee’s salary deferral contribution up to a maximum of eight percent (8%) of an employee’s salary. Matching contributions to the plan were approximately $404,000, $393,000, and $128,000 for the years ended December 31, 2011, 2010, and 2009, respectively. Meridian employees entered the plan in 2010, and for vesting purposes, were credited with their years of service with Meridian. Meridian also had a 401(k) plan, the assets and liabilities of which we assumed.

The Company’s business makes it 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 increase annual amortization expense (which is based on proved reserves). The Company mitigates some of this vulnerability by entering into oil and natural gas price derivative contracts. See Note 6.

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

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

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

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

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

During the year ended December 31, 2009, a partner’s interest was redeemed for $5.5 million. During 2010, AMIH contributed $50 million in contributions to the Company for our purchase of Meridian. In conjunction with our subsequent offering of senior notes, AMIH received a distribution of $50 million from the proceeds of the offering.

Management has evaluated all events subsequent to the balance sheet date of December 31, 2011 and has determined that no subsequent events require disclosure.

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.

In December 2008, the SEC published a Final Rule, “Modernization of Oil and Gas Reporting.” The new rule permits the use of new technologies to determine proved reserves if those technologies have been demonstrated to lead to reliable conclusions about reserves volumes. The new requirements also allow companies to disclose their probable and possible reserves to investors. In addition, the new disclosure requirements require companies to: (a) report the independence and qualifications of its reserves preparer or auditor; (b) file reports when a third party is relied upon to prepare reserves estimates or conducts a reserves audit; and (c) report oil and natural gas reserves using an average price based upon the prior 12-month period rather than year-end prices. The use of average prices affects impairment and depletion calculations. The new rule became effective for reserve reports as of December 31, 2009; the FASB incorporated the new guidance into the Codification as Accounting Standards Update 2010-03, effective also on December 31, 2009, ASC Topic 932, “Extractive Activities — Oil and Gas.”

We adopted the new guidance effective December 31, 2009; information about our reserves has been prepared in accordance with the new guidance; management has chosen not to provide information on probable and possible reserves. Our reserves calculations were affected primarily by the use of the average price rather than the year-end price required under the prior rules. Under the new rules issued by the SEC, the estimated future net cash flows as of December 31, 2011 and 2010 were determined using average prices for the most recent twelve months. The average is calculated using the first day of the month price for each of the twelve months that make up the reporting period. As of December 31, 2008, previous rules required that estimated future net cash flows from proved reserves be based on period end prices. The changes resulting from the new rules did not significantly impact our impairment testing, depreciation, depletion and amortization expense, or other results of operations.

Proved reserves and associated cash flows are based on the Company’s combined reserve reports as of December 31, 2011, which were prepared by T. J. Smith & Company, Inc. and W. D. Von Gonten & Co., both of which are independent reservoir engineering firms. Netherland, Sewell & Associates, Inc. audited the combined reserve reports as of December 31, 2011.

For further information on the methods and controls used in the process of estimating reserves, as well as the qualifications of each of the three engineering firms, see “Our Oil and Natural Gas Reserves — Internal Control and Qualifications” included herein.

Oil and natural gas producing activities are conducted onshore within the continental United States and all of our proved reserves are located within the United States.

The reserve and other information presented below is provided as supplemental information in accordance with the provisions of ASC Topic 932-235.

The following table sets forth the net proved reserves of the Company as of December 31, 2011, 2010, and 2009, and the changes therein during the years then ended. Proved oil and natural gas reserves are the estimated quantities of crude oil, natural gas, and natural gas liquids that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions, i.e., prices and costs as of the date the estimate is made.

Costs Incurred in Oil and Natural Gas Acquisition, Exploration and Development Activities

Acquisition costs in the table below include costs incurred to purchase, lease, or otherwise acquire property. Exploration expenses include additions to exploratory wells, including those in progress, and other exploration expenses, such as geological and geophysical costs. Development costs include additions to production facilities and equipment and additions to development wells, including those in progress.

There were no wells in suspense at December 31, 2011, 2010 and 2009, respectively.

The information that follows has been developed pursuant to ASC 932-235 and utilizes reserve and production data prepared by our independent petroleum consultants. Reserve estimates are inherently imprecise and estimates of new discoveries are less precise than those of producing oil and natural gas properties. Accordingly, these estimates are expected to change as future information becomes available.

Future cash inflows as of December 31, 2011 and 2010 were calculated using an unweighted arithmetic average of oil and natural gas prices in effect on the first day of each month in the respective year, except where prices are defined by contractual arrangements. Operating costs, production and ad valorem taxes and future development costs are based on current costs with no escalation.

Actual future prices and costs may be materially higher or lower. Actual future net revenues also will be affected by factors such as actual production, supply and demand for oil and natural gas, curtailments or increases in consumption by natural gas purchasers, changes in governmental regulations or taxation and the impact of inflation on costs.

The following table sets forth the components of the standardized measure of discounted future net cash flows for the years ended December 31, 2011, 2010, and 2009:

The following table sets forth the changes in standardized measure of discounted future net cash flows:

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

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

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

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

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

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

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

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

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

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

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

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

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

Depreciation, Depletion, and Amortization — Depreciation, depletion, and amortization (“DD&A”) of capitalized costs of proved oil and natural gas properties is computed using the unit-of-production method based upon estimated proved reserves. Assets are grouped for DD&A on the basis of reasonable aggregation of properties with a common geological structural feature or stratigraphic condition, such as a reservoir or field. The reserve base used to calculate DD&A for leasehold acquisition costs and the cost to acquire proved properties is

the sum of proved developed reserves and proved undeveloped reserves. The reserve base used to calculate DD&A for lease and well equipment costs, which include development costs and successful exploration drilling costs, includes only proved developed reserves.

Accounts Receivable, net: Our receivables arise from the sale of oil and natural gas to third parties and joint interest owner receivables for properties in which we serve as the operator. This concentration of customers may impact our overall credit risk, either positively or negatively, in that these entities may be similarly affected by changes in economic or other conditions affecting the oil and gas industry. Accounts receivable are generally not collateralized. Accounts receivable are shown net of an allowance for doubtful accounts of $661,000 and $338,000 at September 30, 2011 and December 31, 2010, respectively.

Deferred Financing Costs: Deferred financing costs and the amount of discount at which notes payable have been issued (debt discount) are amortized using the straight-line method, which approximates the interest method, over the term of the related debt. For the three months ended September 30, 2011 and 2010, amortization of deferred financing costs included in interest expense amounted to $0.5 million and $0.8 million, respectively. For the nine months ended September 30, 2011 and 2010, amortization of deferred financing costs included in interest expense amounted to $2.2 million and $1.5 million, respectively. Deferred financing costs are listed among our long-term assets, net of accumulated amortization of $6.9 million and $4.7 million at September 30, 2011 and December 31, 2010, respectively.

Financial Instruments: The fair value of cash, accounts receivable, other current assets, and current liabilities approximate book value due to their short-term nature. The estimate of fair value of long-term debt under our senior secured revolving credit facility is not considered to be materially different from carrying value due to market rates of interest. The fair value of the debt to our founder is not practicable to determine. We have estimated the fair value of our senior notes payable at $273 million and $291 million at September 30, 2011 and December 31, 2010, respectively. See Note 5 for further information on fair values of financial instruments. See Note 8 for information on long-term debt.

In September 2011, the FASB issued ASU 2011-08, “Testing Goodwill for Impairment.” ASU 2011-08 amends the guidance for testing goodwill for impairment. Previously, goodwill was required to be tested at least annually, by comparing the fair value of a reporting unit with its carrying value, including goodwill. If the carrying value exceeded the fair value, a second test would be performed to measure the impairment loss, if any. Under the new guidance, testing of goodwill is not prescribed annually, but rather, when events and circumstances make it more likely than not that the carrying value of a reporting unit exceeds its fair value. This is known as a qualitative evaluation. If the qualitative evaluation indicates a possible loss is more likely than not, the two-step test is to be performed. ASU 2011-08 provides new examples of events and circumstances which could affect such a qualitative evaluation. The new guidance is effective for fiscal years beginning after December 15, 2011. Early adoption is permitted. We do not expect adoption of the guidance to have a material impact on our consolidated financial position or results of operations.

On and effective May 13, 2010, Alta Mesa Acquisition Sub, LLC (“AMAS”), a wholly owned subsidiary of Alta Mesa Holdings, LP, acquired 100% of the shares of and merged with The Meridian Resource Corporation (“Meridian”), with AMAS as the surviving entity. Meridian was a publicly traded company engaged in exploration for and production of oil and natural gas. The oil and natural gas properties of Meridian were similar and in some cases proximate to our areas of operation. Meridian shareholders were paid in cash, funded by proceeds of our credit facility as well as a $50 million equity contribution from our private equity partner Alta

Mesa Investment Holdings Inc., an affiliate of Denham Commodities Partners Fund IV LP (“AMIH”). The merger increased the oil portion of our reserves portfolio, improving the balance of our reserves between oil and natural gas, and provided significant additions to our library of 3-D seismic data.

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.

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 allocations of the purchase prices (which are preliminary for the Sydson and TODD acquisitions) are as follows (dollars in thousands):

The revenue and earnings related to the Meridian, Sydson, and TODD acquisitions are included in our consolidated statement of income for the nine months ended September 30, 2011. The revenue and earnings

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

We follow the guidance of ASC 820, “Fair Value Measurements and Disclosures,” in the estimation of fair values. ASC 820 provides a hierarchy of fair value measurements, based on the inputs to the fair value estimation

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

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

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

Oil and natural gas properties are subject to impairment testing and potential impairment write down. Oil and gas properties with a carrying amount of $31.8 million were written down to their fair value of $15.3 million, resulting in an impairment charge of $16.5 million for the nine months ended September 30, 2011. Oil and gas properties with a carrying amount of $7.3 million were written down to their fair value of $4.8 million, resulting in an impairment charge of $2.5 million for the nine months ended September 30, 2010. For the three months ended September 30, 2011, oil and gas properties with a carrying amount of $7.4 million were written down to their fair value of $1.7 million, resulting in an impairment charge of $5.7 million, and for the three months ended September 30, 2010, oil and gas properties with a carrying amount of $2.9 million were written down to their fair value of $2.5 million, resulting in an impairment charge of $0.4 million. Significant Level 3 assumptions used in the calculation of estimated discounted cash flows in the impairment analysis included our estimate of future oil and natural gas prices, production costs, development expenditures, estimated timing of production of proved reserves, appropriate risk-adjusted discount rates, and other relevant data.

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

New additions to asset retirement obligations result from estimations for new properties, and fair values for them are categorized as Level 3. Such estimations are based on present value techniques which utilize company-specific information for such inputs as cost and timing of plug and abandonment of wells and facilities. We recorded $3.3 million and $34.6 million in additions to asset retirement obligations measured at fair value during the nine months ended September 30, 2011 and 2010, respectively. The significant additions in 2010 were the result of the purchase of Meridian.

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

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.

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 the credit facility described in Note 8 below, and are collateralized by the security interests of the respective affiliated lenders in certain of our assets under the credit facility. The contracts settle monthly and are scheduled to coincide with either oil production equivalent to barrels (Bbl) per month or gas production equivalent to volumes in millions of British thermal units (MMbtu) per month. The contracts represent agreements between us and the counter-parties to exchange cash based on a designated price. Prices are referenced to the natural gas spot market benchmark price at the Houston Ship Channel or NYMEX indices. Cash settlement occurs monthly based on the specified price benchmark. We have not designated any of our derivative contracts as fair value or cash flow hedges; accordingly we use mark-to-market accounting, recognizing unrealized gains and losses in the statement of operations at each reporting date. Realized gains and losses on commodities hedging contracts are included in oil and natural gas revenues.

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

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

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

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:

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 September 30, 2011 (unaudited):

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

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

We had the following open financial basis swap contract for oil at September 30, 2011 (unaudited):

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

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

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

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

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

In addition, we have notes payable to our founder which bear simple interest at 10% with a balance of $20.6 million and $19.7 million at September 30, 2011 and December 31, 2010, respectively. The notes mature December 31, 2018. Interest and principal are payable at maturity. The notes are subordinate to all debt. Interest on the notes payable to our founder amounted to $897,000 and $890,000 for the nine months ended September 30, 2011 and 2010, respectively, and $297,000 and $300,000 for the three months ended September 30, 2011 and 2010, respectively. Such amounts have been added to the balance of the notes.

Deep Bossier litigation: On July 23, 2009, we made a payment of $25.5 million and took assignment of substantially all working interests that had been held by Chesapeake Energy Corporation in an approximate 50,000 acre area of Leon and Robertson Counties, Texas in the Deep Bossier play. We had exercised our preferential right to purchase these interests from Gastar Exploration Ltd. in late 2005, but Gastar and Chesapeake had opposed this and Chesapeake took record title until we finally and conclusively prevailed, and in 2008 a Texas court of appeals directed that specific performance take place. In early 2009, the Texas Supreme Court denied the defendants’ request to hear the appeal. As a result, we were able to take working interests in over 30 producing wells and participate in further development of the area, primarily with EnCana, but also with Gastar. A subsequent payment to EnCana of $15.2 million plus purchase accounting adjustments of $3.8 million brought the total cost of the acquisition to $44.5 million. While the ownership of these interests has been decided by the courts, we are pursuing other claims against Chesapeake; Chesapeake is claiming an additional $36.5 million of past expenses from us. Discovery is ongoing and the case is set for trial on April 24, 2012. We are unable to express an opinion with respect to the likelihood of an unfavorable outcome of this matter or to estimate the amount or range of potential loss should the outcome be unfavorable. Therefore, we have not provided any amount for this matter in our consolidated financial statements at September 30, 2011.

Ted R. Stalder, TRS LP, Richard Hughart, and Richmar Interests, Inc. v. Texas Energy Acquisitions, LP: On May 24, 2011, the plaintiffs brought suit against us for breach of contract, common law fraud, fraud in a real estate transaction, declaratory relief, money had and received, an accounting, and injunctive relief related to the

deferred purchase price for oil and gas properties in two purchase and sales agreements dated December 23, 2008. A temporary restraining order (“TRO”) was entered against us on May 24, 2011. At a July 7, 2011 hearing on the temporary injunction, the court recommended that the parties enter into an agreed temporary injunction regarding payment of disputed amounts into the registry of the court.

The parties are still in the process of negotiating the agreed temporary injunction. On July 28, 2011, we filed a motion for partial summary judgment on the plaintiffs’ fraud claims, which is currently set for hearing on November 17, 2011. We intend to contest the matter vigorously. We are unable to express an opinion with respect to the likelihood of an unfavorable outcome of this matter or to estimate the amount or range of potential loss should the outcome be unfavorable. Therefore, we have not provided any amount for this matter in our consolidated financial statements at September 30, 2011.

Environmental claims: Management has established a liability for soil contamination in Florida of $978,000 at September 30, 2011 and $943,000 at December 31, 2010, based on our undiscounted engineering estimates. The obligations are included in other long-term liabilities in the accompanying consolidated balance sheets.

Various landowners have sued Meridian (along with numerous other oil companies) in lawsuits concerning several fields in which Meridian has had operations. The lawsuits seek injunctive relief and other relief, including unspecified amounts in both actual and punitive damages for alleged breaches of mineral leases and alleged failure to restore the plaintiffs’ lands from alleged contamination and otherwise from Meridian’s oil and natural gas operations. We are unable to express an opinion with respect to the likelihood of an unfavorable outcome of the various environmental claims or to estimate the amount or range of potential loss should the outcome be unfavorable. Therefore, we have not provided any amount for these claims in our financial statements at September 30, 2011.

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

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

We have contingent commitments to pay an amount up to a maximum of approximately $5.9 million for properties acquired in 2008 and prior years. The additional purchase consideration will be paid only if certain product price conditions are met. We cannot estimate the amounts that will be paid in the future, if any, or the fiscal years in which such amounts could become due.

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

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

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.

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.

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

Management has evaluated all events subsequent to the balance sheet date of September 30, 2011, and has determined that no events require disclosure.

We have audited the accompanying consolidated balance sheets of The Meridian Resource Corporation as of December 31, 2009 and 2008 and the related consolidated statements of operations, comprehensive income (loss), stockholders’ equity and cash flows for each of the three years in the period ended December 31, 2009. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States of America). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of The Meridian Resource Corporation at December 31, 2009 and 2008, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2009 in conformity with accounting principles generally accepted in the United States of America.

The accompanying financial statements have been prepared assuming that the Company will continue as a going concern. As discussed in Note 1 to the consolidated financial statements, at December 31, 2009, the Company was in violation of certain debt covenants resulting in the default on its revolving credit and other debt agreements, which raise substantial doubt about the Company’s ability to continue as a going concern. Management’s plans in regard to these matters are also described in Note 1. The financial statements do not include any adjustments that might result from the outcome of this uncertainty.

As discussed in Note 2 to the consolidated financial statements, effective December 31, 2009, the Company changed its reserve estimates and related disclosures as a result of adopting new oil and natural gas reserve estimation and disclosure requirements.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), The Meridian Resource Corporation’s internal control over financial reporting as of December 31, 2009, based on criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) and our report dated April 15, 2010 expressed an unqualified opinion thereon.

The Meridian Resource Corporation and its subsidiaries (the “Company” or “Meridian”) explores for, acquires, develops and produces oil and natural gas reserves, principally located onshore in south Louisiana, Texas and offshore in the Gulf of Mexico. The Company was initially organized in 1985 as a master limited partnership and operated as such until 1990 when it converted into a Texas corporation.

Since December 31, 2008, the Company has been in default of its credit facility, under which borrowings were $87.5 million at December 31, 2009. The credit facility default gave rise to a cross default under the Company’s $6.2 million term loan (“rig note”). As a result, the Company faces substantial economic difficulties. Although operating cash flow has been positive and capital expenditures have been very significantly reduced, the Company continues to be obligated for the expense of drilling rigs it cannot fully utilize and continues to be impacted by prices for oil and natural gas which have exhibited extreme volatility in the recent past. The Company’s default under the debt agreements, which has been mitigated in the short term by certain forbearance agreements, negatively impacts future cash flow and the Company’s access to credit or other forms of capital. If the Company is unable to comply with the terms of the forbearance agreements, it will continue to be in default under the credit facility and the rig note and will be subject to the exercise of remedies by third parties on account of such defaults. The exercise of such remedies, which include acceleration of all principal and interest payments, could potentially result in the Company seeking protection under federal bankruptcy laws. Such relief could materially and adversely affect the Company and its shareholders. Therefore, there is substantial doubt as to the Company’s ability to continue as a going concern for a period longer than the next twelve months. In addition, the accompanying report of the Company’s independent registered public accounting firm includes a “going concern” explanatory paragraph that expresses substantial doubt as to the Company’s ability to continue as a going concern.

For further information regarding bank debt and forbearance agreements, see Note 5. For further information regarding the Company’s drilling rig contracts, and a forbearance agreement with the rig operator, see Note 7.

Proposed Merger. Management has actively pursued many avenues to strengthen the financial position of the Company over the past year. As a result, on December 22, 2009, the Company entered into an Agreement and Plan of Merger (“Merger Agreement”) with Alta Mesa Holdings, LP (“Alta Mesa”) and Alta Mesa Acquisition Sub, LLC, a direct wholly owned subsidiary of Alta Mesa (“Merger Sub”). Under the terms of the Merger Agreement, as amended, shareholders will receive $0.33 per share of common stock, to be paid in cash, and Alta Mesa will assume the Company’s debts and obligations. The Company would be merged into Alta Mesa Acquisition Sub, LLC with the Merger Sub as the surviving entity. The Company’s stock would cease to be publicly traded. The merger is subject to approval by holders of two thirds of the Company’s outstanding shares of common stock; a shareholder meeting and vote are currently scheduled for April 28, 2010. The Company filed a proxy statement regarding the proposed merger on February 8, 2010, in which the Company’s board recommended that shareholders vote in favor of the merger. For further information on the proposed merger, refer to the proxy statement.

The Company’s various forbearance agreements have been extended to allow for completion of the merger, assuming shareholder approval is obtained. However, the most recent amendment to the bank forbearance agreement also allows the lenders to terminate the forbearance period on or after February 28, 2010, without cause, so long as the decision to terminate is unanimous among the lenders.

The Merger Agreement may be terminated under various conditions, including the occurrence of an event with a material adverse effect on Meridian (“Material Adverse Event,” as defined in the Merger Agreement). Both Meridian and Alta Mesa must adhere to certain customary representations and covenants contained in the

Merger Agreement, including those that restrict Meridian’s conduct of business primarily to current operations, and restrict Meridian from soliciting other offers for the Company, although Meridian is entitled to consider any “superior proposal,” as defined in the Merger Agreement. As a condition of the merger, Meridian was required to enter into a settlement regarding certain indemnification claims, which it has done (see Note 7, “Environmental litigation,” for further information).

The Merger Agreement with Alta Mesa includes a reimbursement clause under which the Company will pay Alta Mesa’s reasonable costs of the merger, not to exceed $1 million, in case of termination of the agreement under various circumstances, including expiration of the term on May 31, 2010 without consummation of the merger, and also including termination of the Merger Agreement due to non-approval in the shareholder vote. In addition to reimbursement of Alta Mesa’s costs, the Company would pay Alta Mesa a $3 million termination fee if, among other reasons, the Company terminates the Alta Mesa agreement and accepts another offer for the Company, so long as the definitive agreement related to the other offer is entered into within nine months after termination of the Merger Agreement with Alta Mesa. The termination fee would be payable no later than two business days after consummation of the transaction which triggered the fee.

Alta Mesa has the right to terminate the Merger Agreement at any time, whether before or after approval by the Company’s shareholders, upon payment of a termination fee of $3 million to the Company. The terms of the Company’s Credit Facility forbearance agreement require any such termination payment received by Meridian to be used to repay any outstanding balance under the Credit Facility.

There can be no assurance that the proposed merger will be completed. Approval by the shareholders is not assured. Litigation was filed by some shareholders claiming the Company’s directors breached their fiduciary duties in approving the merger. To avoid the risk of the litigation delaying or adversely affecting the merger and to minimize the expense of defending the Company against the lawsuit, in March 2010 management agreed to a proposed settlement of the litigation (see Note 7). There can be no assurance the bank forbearance period will not be terminated by the lenders before the proposed merger can be completed. There can be no assurance that cash flow from operations and other sources of liquidity, including asset sales, will be sufficient to meet contractual, operating and capital obligations. The accompanying consolidated financial statements have been prepared in accordance with generally accepted accounting principles applicable to a going concern, which implies that the Company will continue to meet its obligations and continue its operations for the next twelve months. No adjustments relating to the recoverability or classification of recorded amounts have been made, other than to classify all bank debt as current.

The consolidated financial statements include the accounts of the Company and its wholly owned subsidiaries, after eliminating all significant intercompany transactions.

The Company classifies cash balances as restricted cash when cash is restricted as to withdrawal or usage. The restricted cash balance at December 31, 2009, was $35,000 and at December 31, 2008, was $9,971,000. Restricted cash was increased by $9,894,000 in May 2008, when contractual obligations to certain executives were funded by cash placed in a Rabbi Trust account. The obligations and trust are more fully described in Note 12. The funds from the trust were disbursed in 2009. Remaining restricted cash is related to a contractual obligation with respect to royalties payable.

The Company follows the full cost method of accounting for its investments in oil and natural gas properties. All costs incurred in the acquisition, exploration and development of oil and natural gas properties,

including unproductive wells, are capitalized. Through March 2009, capitalized costs included general and administrative costs directly related to acquisition, exploration and development activities. Subsequent to that date, no general and administrative costs have been capitalized, as such activities have significantly decreased. The Company may capitalize general and administrative costs in the future, when costs related directly to the acquisition, exploration, and development of oil and natural gas properties are incurred. Total general and administrative costs capitalized for the years 2009 and 2008 were $2.6 million and $17.4 million, respectively. Proceeds from the sale of oil and natural gas properties are credited to the full cost pool, except in transactions involving a significant quantity of reserves, or where the proceeds received from the sale would significantly alter the relationship between capitalized costs and proved reserves, in which case a gain or loss is recognized. Under the rules of the Securities and Exchange Commission (“SEC”) for the full cost method of accounting, the net carrying value of oil and natural gas properties, less related deferred taxes, is limited to the sum of the present value (10% discount rate) of the estimated future net after-tax cash flows from proved reserves, as adjusted for the Company’s cash flow hedge positions, and on current costs, plus the lower of cost or estimated fair value of unproved properties adjusted for related income tax effects. Under new rules issued by the SEC, the estimated future net cash flows as of December 31, 2009, were determined using average prices for the most recent twelve months. The average is calculated using the first day of the month price for each of the twelve months that make up the reporting period. As of December 31, 2008 and 2007, previous rules required that estimated future net cash flows from proved reserves be based on period end prices. See Note 4.

Capitalized costs of proved oil and natural gas properties are depleted on a units of production method using proved oil and natural gas reserves. Costs subject to depletion include net capitalized costs, and estimated future dismantlement, restoration, and abandonment costs and are reduced by estimated salvage values. Estimated future abandonment, dismantlement and site restoration costs include costs to dismantle, relocate and dispose of the Company’s offshore production platforms, gathering systems, and wells and related structures. Capitalized costs related to unproved oil and natural gas properties are excluded from the full cost pool until proven or impaired in the judgment of management; such costs total $1.6 million and $39.9 million as of December 31, 2009 and 2008, respectively. At December 31, 2009, excluded costs include no exploratory well costs.

Equipment, which includes a drilling rig, computer equipment, computer hardware and software, furniture and fixtures, leasehold improvements and automobiles, is recorded at cost and is generally depreciated on a straight-line basis over the estimated useful lives of the assets, which range in periods of three to seven years. In 2009, gross asset retirements included $940,000 for furniture and equipment retired, with related accumulated depreciation of $911,000.

The Company has a long-term dayrate contract to utilize a drilling rig from an unaffiliated service company, Orion Drilling Company, LLC, (“Orion”). Although capital expenditure plans no longer accommodate full use of this rig, the Company is obligated for the dayrate regardless of whether the rig is working or idle. When the contracted rig is not in use on Meridian-operated wells, Orion may contract it to third parties, or the rig may be idled. The Company is obligated for the difference in dayrates if it is utilized by a third party at a lesser dayrate. The contracted rig was utilized drilling a Meridian-operated well through the end of the first quarter of 2009, and has subsequently been contracted to a third party at a lesser dayrate than the Company’s contracted dayrate. The costs of the rig when it is not providing services to the Company have been included in the consolidated statements of operations as “Rig operations, net.” TMR Drilling Corporation (“TMRD”), a wholly owned subsidiary of the Company, owns a rig which was also intended primarily to drill wells operated by the Company. In April 2008, Orion began leasing the rig from TMRD, and operating it under a dayrate contract with the Company. When the rig drills Company wells, drilling expenditures under the dayrate contract are capitalized as exploration costs and all TMRD profits or losses related to lease of the rig, including any incidental profits related to the share of drilling costs borne by joint interest partners, are offset against the full cost pool. From

April through December of 2008, the rig was utilized almost continuously on Company wells and its profits were accordingly capitalized. For the years ended 2009 and 2008, the rig profits capitalized to the full cost pool were $180,000 and $1.1 million, respectively.

When the rig is used by Orion for work on third party wells in which the Company has no economic or management interest, TMRD’s profit or loss related to the lease of the rig is reflected in the consolidated statements of operations. During 2009, the rig worked on third party wells. The Company is obligated for the difference in dayrates if the rig is utilized by a third party at a lesser dayrate, which has occurred during 2009. This loss on a contractual obligation is included in “Rig Operations, net” in the consolidated statements of operations. The Company’s share of profits on the lease of the rig to Orion partially offsets the loss on the drilling contract and is included in “Rig operations, net” on the consolidated statements of operations. The total lease revenue included in “Rig operations, net” for 2009 was $1.1 million.

Depreciation of the owned rig was $0.9 million and $1.5 million for 2009 and 2008, respectively, of which $0.8 million and zero was included in depletion and depreciation expense on the consolidated statements of operations, and the remainder was capitalized to the full cost pool. In addition, impairment expense includes $6.7 million in 2008 for impairment of the value of the rig.

See Note 7 for additional information on the Company’s plans for potential disposition of the rig and the obligations under the drilling contracts.

For purposes of the statements of cash flows, cash equivalents include time deposits, certificates of deposit and all highly liquid instruments with original maturities of three months or less. The Company made cash payments for interest of $7.9 million, $5.6 million, and $6.0 million in 2009, 2008 and 2007, respectively. Such payments include $1.2 million in forbearance fees in 2009, which have been included in interest expense. Cash payments (refunds) for income taxes (federal and state, net of receipts) were $(505,000), $385,000, and $61,000 for 2009, 2008, and 2007, respectively.

Substantially all of the Company’s receivables are due from oil and natural gas purchasers and other oil and natural gas producing companies located in the United States. Accounts receivable are generally not collateralized. Historically, credit losses incurred on receivables of the Company have not been significant.

The Company maintains its cash in bank deposit accounts which, at times, may exceed federally insured limits. Accounts are guaranteed by the Federal Deposit Insurance Corporation (“FDIC”) up to $250,000 as of December 31, 2009. As of December 31, 2008, the FDIC also provides an unlimited guarantee for balances in non-interest bearing transactional accounts. At December 31, 2009, and December 31, 2008, the Company had approximately $35,000 and $20,696,000, respectively, in excess of FDIC insured limits, including cash in restricted cash accounts. The Company has not experienced any losses in such accounts.

Meridian recognizes oil and natural gas revenue from its interests in producing wells as oil and natural gas is produced and sold from those wells (the sales method). Oil and natural gas sold is not significantly different from the Company’s share of production. Accounts receivable includes accrued oil and natural gas revenue receivables of approximately $10.1 million and $10.2 million as of December 31, 2009 and 2008, respectively.

Accounts receivable includes $1.1 million and $1.6 million in amounts due from joint interest owners as of December 31, 2009 and 2008, respectively. As of December 31, 2008, accounts receivable included $2.4 million for insurance proceeds related to hurricane damage.

The Company maintains an allowance for doubtful accounts for trade receivables equal to amounts estimated to be uncollectible. This estimate is based upon historical collection experience, combined with a specific review of each customer’s outstanding trade receivable balance. Management believes that the allowance for doubtful accounts is adequate; however, actual write-offs may exceed the recorded allowance.

The expense of $1.5 million in 2008 is related to damages incurred from hurricanes Ike and Gustav and is primarily related to the Company’s insurance deductible.

Interest cost is capitalized as part of the historical cost of assets. During 2008 and 2007, respectively, interest of approximately $191,000 and $323,000 was capitalized on the construction of the Company’s drilling rig. The Company’s oil and natural gas properties did not include any individual investments considered significant enough to qualify for interest capitalization under our internal policies. Interest is capitalized using a weighted average interest rate based on the Company’s outstanding borrowings. No interest was capitalized in 2009.

Basic earnings per share amounts are calculated based on the weighted average number of shares of common stock outstanding during each period. Diluted earnings per share is based on the weighted average number of shares of common stock outstanding for the periods, including the dilutive effects of stock options, warrants, and share rights granted. Dilutive options, warrants, and share rights that are issued during a period or that expire or are canceled during a period are reflected in the computations for the time they were outstanding during the periods being reported. Options where the exercise price of the options exceeds the average price for the period are considered antidilutive, and therefore are not included in the calculation of dilutive shares. Shares of Company stock held by the trustee of the Rabbi Trust, although treated as treasury stock for presentation on the Consolidated Balance Sheets, have been included in the computation of basic and diluted earnings per share, as all conditions precedent to their issue, other than passage of time, had been satisfied prior to distribution of the shares in 2009.

The Company follows the guidance in Accounting Standards Codification Topic 718 (“ASC 718”) to account for share-based payment transactions in which the Company receives services in exchange for equity instruments of the Company.

Compensation expense is recorded for stock options and other equity awards over the requisite vesting periods based upon the fair value on the date of the grant.

The Company’s financial instruments consist of cash and cash equivalents, accounts receivable, accounts payable and bank borrowings. The carrying amounts of cash and cash equivalents, accounts receivable, accounts payable, and accrued liabilities approximate fair value due to the highly liquid nature of these short-term instruments. As of December 31, 2009 the Company believes it is not practicable to estimate the fair value of its outstanding debt under its credit facility in light of the payment default. The reduction in credit standing from this default would certainly tend to reduce the fair value of the debt, but it is not practicable to estimate the amount of such reduction. The carrying value of that debt is $87.5 million at December 31, 2009. See Note 5 for further details on the credit facility. The Company also has a smaller bank debt with a fixed rate. The fair value of the rig note at December 31, 2009 is estimated as approximately $4 million; the corresponding carrying value

is $6.2 million. The fair value was estimated based on the fair value of the underlying collateral. The collateral is a drilling rig owned by the Company; see Note 9 for further information on how fair value for the rig was estimated. The Company’s oil and gas price risk hedging contracts are also financial instruments, recorded at fair value; see Note 13.

Notes payable are related to the financing of the Company’s insurance program. The weighted average interest rate on the notes payable was 4.69%, as of December 31, 2008. There were no outstanding notes payable as of December 31, 2009.

The Company amortizes the cost of leasehold improvements over the shorter of the life of the asset or the term of the lease. Rent incentives, such as rent holidays, are also amortized over the life of the lease.

The Company follows the guidance of Accounting Standards Codification Topic 815, “Derivatives and Hedging” (“ASC 815”). The Company enters into derivative contracts to hedge the price risks associated with a portion of anticipated future oil and natural gas production. The Company’s derivative financial instruments have not been entered into for trading purposes and the Company typically has the ability and intent to hold these instruments to maturity. Counterparties to the Company’s derivative agreements are major financial institutions.

All derivatives are recognized on the balance sheet at their fair value. Derivatives are noted as “Assets (or Liabilities) from price risk management activities” and are classified on the Consolidated Balance Sheets as long-term or short-term based on the maturity date of the derivative agreement. On the date the derivative contract is entered into, the Company designates the derivative as either a hedge of the fair value of a recognized asset or liability or of an unrecognized firm commitment (“fair value” hedge) or a hedge of a forecasted transaction or the variability of cash flows to be received or paid related to a recognized asset or liability (“cash flow” hedge). The Company formally documents all relationships between hedging instruments and hedged items, as well as its risk management objective and strategy for undertaking various hedge transactions. This process includes linking all derivatives that are designated as fair-value or cash-flow hedges to specific assets and liabilities on the balance sheet or to specific firm commitments or forecasted transactions. The Company also formally assesses, both at the hedge’s inception and on an ongoing basis, whether the derivatives that are used in hedging transactions are highly effective in offsetting changes in fair values or cash flows of hedged items.

Changes in the fair value of a derivative that is highly effective and that is designated and qualifies as a cash-flow hedge are recorded in other comprehensive income, until earnings are affected by the variability in cash flows of the designated hedged item, whereupon they are recognized in oil or natural gas revenues. The Company recognized a loss of $6,000, a loss of $18,000, and a gain of $21,000 related to hedge ineffectiveness during the years ended December 31, 2009, 2008, and 2007, respectively. Gains and losses from hedge ineffectiveness are presented as “Price risk management activities” in the Consolidated Statements of Operations.

The Company discontinues cash flow hedge accounting prospectively when it is determined that the derivative is no longer effective in offsetting changes in the fair value or cash flows of the hedged item, the derivative expires or is sold, terminated, or exercised, the derivative is redesignated as a hedging instrument because it is unlikely that a forecasted transaction will occur, or management determines that designation of the derivative as a hedging instrument is no longer appropriate.

When cash flow hedge accounting is discontinued because it is probable that a forecasted transaction will not occur, the Company continues to carry the derivative on the balance sheet at its fair value with subsequent changes in fair value included in earnings, and gains and losses that were accumulated in other comprehensive

income are immediately recognized in earnings. In all other situations in which hedge accounting is discontinued, the Company continues to carry the derivative at its fair value on the balance sheet and recognizes any subsequent changes in its fair value in earnings. Gains or losses accumulated in other comprehensive income at the time the hedge relationship is terminated are reclassified into operations in the month in which the related derivative contracts settle.

The Company accounts for federal income taxes using the liability method. Under the liability method, deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between financial statement carrying amounts of existing assets and liabilities and their respective tax bases. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled.

Under the liability method, deferred tax assets and liabilities are recognized for the estimated future tax effects attributable to temporary differences and carryforwards. Ultimately, realization of a deferred tax benefit depends on the existence of sufficient taxable income within the carryback/carryforward period to absorb future deductible temporary differences or a carryforward. In assessing the realizability of deferred tax assets, management considers whether it is more likely than not that some portion or all of the deferred tax assets will not be realized, including such evidence as the scheduled reversal of deferred tax liabilities and projected future taxable income. As a result of the current assessment, in both 2008 and 2009 the Company recorded a valuation allowance equal to the net deferred tax assets.

The Company may from time to time be assessed interest or penalties by major tax jurisdictions, although any such assessments historically have been minimal and immaterial to our financial results. Should the Company determine that any of its tax positions are uncertain, it may record related interest and penalties that may be assessed. Interest recorded, if any, will be charged to interest expense and penalties recorded will be charged to operating expenses in the Company’s Consolidated Statements of Operations.

The Company is subject to extensive federal, state and local environmental laws and regulations. These laws regulate the discharge of materials into the environment and may require the Company to remove or mitigate the environmental effects of the disposal or release of petroleum or chemical substances at various sites. Environmental expenditures are expensed or capitalized depending on their future economic benefit. Expenditures that relate to an existing condition caused by past operations and that have no future economic benefits are expensed. Liabilities for expenditures of a noncapital nature are recorded when environmental assessment and or remediation is probable, and the costs can be reasonably estimated. Such liabilities are generally not estimable unless the timing of cash payments for the liability or component are fixed or reliably determinable.

In July 2009, the Financial Accounting Standards Board (“FASB”) issued revised authoritative guidance regarding the hierarchy of generally accepted accounting principles. Under this revised guidance, the FASB Accounting Standards Codification (“Codification”), the FASB’s new web-based codification of accounting and reporting guidance, along with guidance provided by the SEC, are the only “authoritative” sources of such guidance. All guidance not contained in the Codification, other than SEC guidance, will be considered “non-authoritative.” The Codification is designed to incorporate previously issued guidance from sources such as the FASB, the American Institute of Certified Public Accountants, and the Public Company Accounting Oversight Board, and is not intended to change GAAP for non-governmental entities. The revised guidance on the hierarchy provides additional guidance on the selection, interpretation, and application of accounting principles from the Codification and from non-authoritative sources when necessary. The guidance is effective for financial

statements issued for interim and annual periods ending after September 15, 2009. The Company adopted the revised guidance effective July 1, 2009; the adoption did not have a material impact on financial position or results of operations.

In September 2006, the FASB issued Statement of Financial Accounting Standard (“SFAS”) No. 157, “Fair Value Measurements,” codified in Accounting Standards Codification (“ASC”) Topic 820 (“ASC 820”). ASC 820 defines fair value, establishes a framework for measuring fair value in generally accepted accounting principles and expands disclosure about fair value measurements. In accordance with the effective dates provided in the guidance, the Company adopted the guidance for measurements of the fair values of financial instruments and recurring fair value measurements of non-financial assets and liabilities on January 1, 2008. Effective January 1, 2009, the Company began applying the new guidance to non-recurring measurements of the fair values of non-financial assets and liabilities, such as asset retirement obligations and impairments of long-lived assets other than oil and natural gas properties. The adoptions had no material impact on financial position or results of operations.

In January 2010, the FASB updated Topic 820 with Accounting Standards Update (“ASU”) 2010-06, “Fair Value Measurements and Disclosures (Topic 820) — Improving Disclosures about Fair Value Measurements.” This ASU requires new disclosures and clarifies certain existing disclosure requirements about fair value measurements. ASU 2010-06 requires a reporting entity to disclose significant transfers in and out of Level 1 and Level 2 fair value measurements, to describe the reasons for the transfers and to present separately information about purchases, sales, issuances and settlements for fair value measurements using significant unobservable inputs. ASU 2010-06 is effective for interim and annual reporting periods beginning after December 15, 2009, except for the disclosures about purchases, sales, issuances and settlements in the roll forward of activity in Level 3 fair value measurements, which is effective for interim and annual reporting periods beginning after December 15, 2010; early adoption is permitted. The Company does not expect that the adoption of ASU 2010-06 will have a material impact on financial position, results of operations or cash flows.

In December 2007, the FASB issued SFAS No. 141(R), “Business Combinations,” codified in ASC Topic 805 (“ASC 805”). ASC 805 retains the purchase method of accounting for acquisitions, but requires a number of changes, including changes in the way assets and liabilities are recognized in purchase accounting. It also changes the recognition of assets acquired and liabilities assumed arising from contingencies and requires the expensing of acquisition-related costs as incurred. Generally, ASC 805 is effective on a prospective basis for all business combinations completed on or after January 1, 2009. The Company adopted the revised guidance effective January 1, 2009; the adoption did not have a material impact on financial position or results of operations.

In March 2008, the FASB issued SFAS No. 161, “Disclosures about Derivative Instruments and Hedging Activities,” codified in ASC Topic 815-10-50 (“ASC 815-10-50”). ASC 815-10-50 provides guidance for additional disclosures regarding derivative contracts, including expanded discussions of risk and hedging strategy, as well as new tabular presentations of accounting data related to derivative instruments. The Company adopted the revised guidance effective January 1, 2009; the adoption did not have a material impact on financial position or results of operations. The additional disclosures are included in Note 13.

In June 2008, the FASB Emerging Task Force issued EITF Abstract Issue No. 07-05, “Determining Whether an Instrument (or Embedded Feature) Is Indexed to an Entity’s Own Stock” codified as ASC Topic 815-40-15 (“ASC 815-40-15”). ASC 815-40-15 clarifies the determination of equity instruments which may qualify for an exemption from the other provisions of ASC 815, “Derivatives and Hedging.” Generally, equity instruments which qualify under the guidelines of ASC 815-40-15 may be accounted for in equity accounts; those which do not qualify are subject to derivative accounting. The Company adopted the guidance of ASC 815-40-15 on January 1, 2009. The effects of the adoption included a revision in the carrying value of certain outstanding warrants, and recognition of a related liability of $960,000 on January 1, 2009, as well as recognition of an unrealized gain of $548,000 included in general and administrative expense, due to the change in fair value of those warrants during 2009. See Note 10, “Warrants,” for further information.

In December 2008, the SEC published a Final Rule, “Modernization of Oil and Gas Reporting.” The new rule permits the use of new technologies to determine proved reserves if those technologies have been demonstrated to lead to reliable conclusions about reserves volumes. The new requirements also allow companies to disclose their probable and possible reserves to investors. In addition, the new disclosure requirements require companies to: (a) report the independence and qualifications of its reserves preparer or auditor; (b) file reports when a third party is relied upon to prepare reserves estimates or conducts a reserves audit; and (c) report oil and gas reserves using an average price based upon the prior 12-month period rather than year-end prices. The use of average prices affects impairment and depletion calculations. The new rule became effective for reserve reports as of December 31, 2009; the FASB incorporated the new guidance into the Codification as Accounting Standards Update 2010-03, effective also on December 31, 2009, ASC Topic 932, “Extractive Activities — Oil and Gas.”

The Company adopted the new guidance effective December 31, 2009; information about the company’s reserves has been prepared in accordance with the new guidance and is included in Note 19; management has chosen not to provide information on probable and possible reserves. The Company’s reserves were affected primarily by the use of the average prices rather than the period-end prices required under the prior rules. As a result of adopting the new guidance, we estimate that Meridian’s December 31, 2009 proven reserves decreased approximately 1.4 Bcfe and prices used in the calculation decreased approximately 30%. This change in turn affected the results of the Company’s ceiling test for the fourth quarter of 2009, which was a write-down of $4.0 million. Had the new rule using average pricing not been implemented, the write down in the fourth quarter of 2009 would not have been necessary. The change in total reserves using the new rules had a negligible effect on depletion expense in the fourth quarter of 2009, as total proved reserves are the basis of depletion calculations.

In December 2009, the FASB issued revised authoritative guidance regarding consolidation of variable interest entities (“VIE’s”) in ASU 2009-17, “Improvements to Financial Reporting by Enterprises Involved with Variable Interest Entities,” codified as ASC 810-10-05-08. The ASU (originally issued as SFAS No. 167 in June 2009) amends existing consolidation guidance for variable interest entities. Variable interest entities generally are thinly-capitalized entities which under previous guidance may not have been consolidated. The revised guidance requires a company to perform a qualitative analysis to determine whether to consolidate a VIE, which includes consideration of control issues other than the primarily quantitative considerations utilized prior to this revision. In addition, the revised guidance requires ongoing assessments of whether to consolidate VIE’s, rather than only when specific events occur. The revised guidance also requires additional disclosures about consolidated and unconsolidated VIE’s, including their impact on the company’s risk exposure and its financial statements. The revised guidance will be effective for financial statements for annual and interim periods beginning after November 15, 2009. The Company has not yet determined the impact of adoption on its financial position or results of operations.

In April 2009, the FASB issued new authoritative guidance regarding interim disclosures about the fair value of financial instruments, which enhances consistency in financial reporting by increasing the frequency of fair value disclosures. The guidance is effective for interim and annual periods ending after June 15, 2009, with early adoption permitted for periods ending after March 15, 2009. The Company adopted the new guidance effective April 1, 2009. The adoption did not have a material impact on financial position or results of operations of the Company. The disclosures are included above, “Fair Value of Financial Instruments.”

The preparation of financial statements in accordance with accounting principles generally accepted in the United States of America requires the Company to make estimates and judgments that affect the reported amounts of assets, liabilities, revenues and expenses, and disclosure of contingent assets and liabilities, if any, at the date of the financial statements. Reserve estimates significantly impact depreciation and depletion expense and potential impairments of oil and natural gas properties. The Company analyzes its estimates, including those related to oil and natural gas revenues, bad debts, oil and natural gas properties, derivative contracts, income

taxes and contingencies and litigation. The Company bases its estimates on historical experience and various other assumptions that are believed to be reasonable under the circumstances. Actual results may differ from these estimates.

Certain reclassifications of prior period financial statements have been made to conform to current reporting practices.

The Company estimates the present value of future costs of dismantlement and abandonment of its wells, facilities, and other tangible long-lived assets, recording them as liabilities in the period incurred. Asset retirement obligations are calculated using an expected present value technique. Salvage values are excluded from the estimation.

When the liability is initially recorded, the entity increases the carrying amount of the related long-lived asset. Accretion of the liability is recognized each period, and the capitalized cost is amortized over the useful life of the related asset. Upon settlement of the liability, the Company incurs a gain or loss based upon the difference between the estimated and final liability amounts. The Company records gains or losses from settlements as adjustments to the full cost pool.

Accretion expenses were $2.1 million, $2.1 million and $2.2 million in 2009, 2008 and 2007, respectively.

The following table describes the change in the Company’s asset retirement obligations for the years ended December 31, 2009 and 2008 (thousands of dollars):

Our revisions to estimates represent changes to the expected amount and timing of payments to settle our asset retirement obligations. These changes primarily result from obtaining new information about the timing of our obligations to plug our natural gas and oil wells and the costs to do so.

At the end of each quarter, the unamortized cost of oil and natural gas properties, net of related deferred income taxes, is limited to the sum of the present value (10% discount rate) of the estimated future after-tax net revenues from proved properties after giving effect to cash flow hedge positions, and the lower of cost or fair value of unproved properties adjusted for related income tax effects. Under new rules issued by the SEC, the estimated future net cash flows as of December 31, 2009, were determined using average prices for the most recent twelve months. The average is calculated using the first day of the month price for each of the twelve months that make up the reporting period. As of December 31, 2008 and 2007, previous SEC rules required that estimated future net cash flows from proved reserves be based on period end prices.

The cost of unevaluated oil and natural gas properties not subject to depletion is also assessed quarterly to determine whether such properties have been impaired. In determining impairment, an evaluation is performed on current drilling results, lease expiration dates, current oil and natural gas industry conditions, available geological and geophysical information, and actual exploration and development plans. Any impairment assessed is added to the cost of proved properties being amortized.

In the first quarter of 2009, the Company recognized a non-cash impairment of $59.5 million to oil and natural gas properties, based on March 31, 2009 pricing of $3.76 per Mcf of natural gas and $49.66 per barrel of oil. In the fourth quarter of 2009, the Company recognized a non-cash impairment of $4.0 million to oil and natural gas properties, based on December 31, 2009 pricing of $3.87 per Mcf of natural gas and $61.18 per barrel of oil. The total impairment recorded in 2009 to oil and natural gas properties was $63.5 million.

In the fourth quarter of 2008, the Company recognized non-cash impairment expense of $216.8 million ($203.2 million after tax) to the Company’s oil and natural gas properties under the full cost method of accounting, based on December 31, 2008 pricing of $5.79 per Mcf of natural gas and $44.04 per barrel of oil.

The Company also recorded a non-cash impairment of the value of its drilling rig in 2008, due to uncertainties regarding utilization and dayrates for similar rigs, which decreased significantly after the second quarter of 2008. The value of the rig was based on the present value of estimated cash flows from the asset, using management’s best estimates of utilization and dayrates. The estimated value was $5.5 million as of December 31, 2008. Accordingly, the Company recorded non-cash impairment expense of $6.7 million to write down the net book value of the rig to $5.5 million. Management performs impairment testing of the drilling rig each quarter. No further impairment has been recorded for the rig. At December 31, 2009, the carrying value of the rig exceeded its estimated fair value (based on discounted cash flows) by approximately $0.9 million. However, no impairment was necessary at that date as the undiscounted cash flows exceeded the carrying value. Authoritative accounting guidance provides for impairment only when carrying value exceeds undiscounted cash flows.

Due to the substantial volatility in oil and natural gas prices and their effect on the carrying value of the Company’s proved oil and natural gas reserves, there can be no assurance that future write-downs will not be required as a result of factors that may negatively affect the present value of proved oil and natural gas reserves and the carrying value of oil and natural gas properties, including volatile oil and natural gas prices, downward revisions in estimated proved oil and natural gas reserve quantities and unsuccessful drilling activities. Furthermore, due to the related impact of volatile energy prices on the drilling industry, there can be no assurance that future write-downs will not be required for the drilling rig as well.

Credit Facility. The Company has a credit facility with a group of banks (collectively, the “Lenders,”) with a maturity date of February 21, 2012 (the “Credit Facility.”) The Credit Facility is subject to borrowing base redeterminations and bears a floating interest rate based on LIBOR or the prime rate of Fortis Capital Corp., the administrative agent of the Lenders. The borrowing base and the interest formula have been redetermined or amended multiple times. As of December 31, 2008, the borrowing base was $95 million and was fully drawn. The interest rate formula in effect at that date was LIBOR plus 3.25% or prime plus 2.5%.

Obligations under the Credit Facility are to be secured by pledges of outstanding capital stock of the Company’s subsidiaries and by a first priority lien on not less than 75% (95% in the case of an event of default) of its present value of proved oil and natural gas properties. The Credit Facility also contains other restrictive covenants, including, among other items, maintenance of certain financial ratios, restrictions on cash dividends on common stock and under certain circumstances preferred stock, limitations on the redemption of preferred stock, limitations on repurchases of common stock, restrictions on incurrence of additional debt, and an unqualified audit report on the Company’s consolidated financial statements.

As of December 31, 2008, the Company was in default of two of the covenants under the agreement, including one that requires that the Company maintain a current ratio (as defined in the Credit Facility) of one to one. The current ratio, as defined, was less than the required one to one at December 31, 2008 and continued to be, through December 31, 2009. The Company is also in default of the requirement that the Company’s auditors’ opinion for the current financial statements be without modification. Both the Company’s 2008 and 2009 audit reports from its independent registered public accounting firm included a “going concern” explanatory paragraph that expressed substantial doubt about the Company’s ability to continue as a going concern. As a result of the defaults, the outstanding Credit Facility balances of $95 million at December 31, 2008 and $87.5 million at December 31, 2009 have been classified as current in the accompanying consolidated balance sheets. Also in response to the defaults, the Company provided additional security to the Lenders, such that first priority liens cover in excess of 95% of the present value of proved oil and natural gas properties.

The Credit Facility has been subject to semi-annual borrowing base redeterminations effective on April 30 and October 31 of each year, with limited additional unscheduled redeterminations also available to the Lenders or the Company. The determination of the borrowing base is subject to a number of factors, including quantities of proved oil and natural gas reserves, the banks’ price assumptions related to the price of oil and natural gas and other various factors unique to each member bank. The Lenders can redetermine the borrowing base to a lower level than the current borrowing base if they determine that the Company’s oil and natural gas reserves, at the time of redetermination, are inadequate to support the borrowing base then in effect. In the event the redetermined borrowing base is less than outstanding borrowings under the Credit Facility, the Credit Facility requires repayment of the deficit within a specified period of time.

On April 13, 2009, the Lenders notified the Company that, effective April 30, 2009, the borrowing base was reduced from its then-current and fully drawn $95 million to $60 million. As a result, a $34.5 million payment to the Lenders for the borrowing base deficiency was due July 29, 2009, based on the borrowings outstanding on that date. The Company did not have sufficient cash available to repay the deficiency and, consequently, failed to pay such amount when due. Prior to July 29, 2009, the Company was in covenant default under the terms of the Credit Facility; on and after that date it was in covenant default and payment default as well.

Under the terms of the Credit Facility, the Lenders have various remedies available in the event of a default, including acceleration of payment of all principal and interest.

On September 3, 2009, the Company entered into a forbearance agreement with the Lenders under the Credit Facility (“Bank Forbearance Agreement”). The Bank Forbearance Agreement provided that the Lenders would forbear from exercising any right or remedy arising as a result of certain existing events of default under the Credit Facility until the earlier of December 3, 2009 or the date that any default occurred under the Bank Forbearance Agreement. The terms of the Bank Forbearance Agreement required the Company to consummate a capital transaction such as a capital infusion or a sale or merger of the Company, before October 30, 2009. The deadlines for the capital transaction and the forbearance period were extended several times by amendments to the Bank Forbearance Agreement.

At origination of the Bank Forbearance Agreement, the Company paid the Lenders $2.0 million of principal owed under the Credit Facility. Under the terms of the agreement the Company made a total of $5.0 million in further principal payments through December 31, 2009, bringing the balance at that date to $87.5 million. The Company also paid forbearance fees to the Lenders of $945,000, charged to interest expense in the third quarter of 2009, and incurred an additional $476,000 in forbearance fees, charged to interest expense in the fourth quarter of 2009. In addition, the Company incurred approximately $2.3 million in legal and consulting fees, recorded in general and administrative expense, to originate and amend the Bank Forbearance Agreement and other related agreements.

On December 22, 2009, the Company entered into an Agreement and Plan of Merger (the “Merger Agreement”) with Alta Mesa Holdings, LP (“Alta Mesa”) and Alta Mesa Acquisition Sub, LLC, a direct wholly

owned subsidiary of Alta Mesa. The Eleventh Amendment to Forbearance and Amendment Agreement (“11th Amendment”) provided the Lenders’ consent to the Merger Agreement and extended the date for consummation of a capital transaction, such as the Alta Mesa merger, and the forbearance period, to the earlier of the consummation of the merger with Alta Mesa, the termination of the Merger Agreement, or May 31, 2010. However, the 11th Amendment also allows the Lenders to terminate the forbearance period on or after February 28, 2010, without cause, so long as the decision to terminate is unanimous among the Lenders. The 11th Amendment also requires the Company to repay $1 million in principal to the Lenders per month. As of March 31, 2010, the outstanding balance under the Credit Facility is $83 million.

In accordance with the 11th Amendment, the Company has filed its shareholder proxy statement regarding the merger and called a shareholder meeting currently scheduled for April 28, 2010 to approve the transaction. There can be no assurance that shareholders will approve the transaction or that the merger will be consummated within the time constraints specified in the11th Amendment. Should the forbearance period terminate, the Company will be in default, unprotected from the action of remedies available to the Lenders, which cannot be predicted. Such remedies include acceleration of all outstanding principal and interest.

The Bank Forbearance Agreement placed other restrictions on the Company with respect to capital expenditures, sales of assets, and incurrence and prepayments of other indebtedness and amended the Credit Facility in certain respects. It contains covenants regarding the frequency of reporting of financial and cash flow information to the Lenders, as well as cash account control agreements which provide a secured lien over substantially all of the Company’s cash accounts.

Under the terms of the Bank Forbearance Agreement, as amended, the Credit Facility is amended such that scheduled borrowing base redeterminations will occur quarterly rather than semi-annually, to be effective January 31, April 30, July 31, and October 31 of each year. Outstanding amounts in excess of the borrowing base must be repaid according to certain defined terms. The deficiency could be paid in three equal installments over a maximum period of 100 days after the incurrence of a borrowing base deficiency, or alternatively, the Company could provide additional sufficient collateral to cover the deficiency. However, as the Company has already pledged in excess of 95% of the value of all proved oil and natural gas reserves as security, such an alternative could apply only to a small borrowing base deficiency. The Lenders have provided the Company with a limited waiver postponing the next borrowing base redetermination to the end of the forbearance period. No assurance can be given that further deficiencies will not be incurred at the next redetermination.

The Lenders exercised their right to increase the interest rate on outstanding borrowings by 2% (“default interest,” under the terms of the Credit Facility) as of July 30, 2009. The floating interest rate is based on the prime interest rate, currently 3.25%, plus 2.5%, plus the default increment of 2%, resulting in a total rate of 7.75% at December 31, 2009 and continuing at that rate currently. The additional default interest has been effective as to all outstanding borrowings under the Credit Facility since the July 29, 2009 payment default, and the LIBOR alternative was also eliminated. No interest payments are in arrears.

Rig Note. On May 2, 2008, the Company, through its wholly owned subsidiary TMRD, entered into a financing agreement (“rig note”) with The CIT Group / Equipment Financing, Inc. (“CIT”). Under the terms of the agreement, TMRD borrowed $10.0 million, at a fixed interest rate of 6.625%, which increases in an event of default. The loan is collateralized by the drilling rig, as well as general corporate credit. The term of the loan is five years, expiring on May 2, 2013.

Effective as of December 31, 2008, the Company was in default under the rig note. Under the terms of the rig note, a default under the Credit Facility triggers a cross-default under the rig note. The remedies available to CIT in the event of default include acceleration of all principal and interest payments. Accordingly, all indebtedness under the rig note, $8.8 million at December 31, 2008 and $6.2 million at December 31, 2009, has been classified as current in the accompanying consolidated balance sheets.

On September 3, 2009, the Company also entered into a forbearance agreement with CIT (“CIT Forbearance Agreement.”) The forbearance period under the CIT Forbearance Agreement has been extended several times, most recently by the Fourth Amendment to Forbearance and Amendment Agreement (“4th Amendment”). The forbearance period ends the earlier of the consummation of the merger with Alta Mesa, the termination of the Merger Agreement, May 31, 2010, or the date of any default under either the CIT Forbearance Agreement or the Bank Forbearance Agreement. The 4th Amendment also provides CIT’s consent to the merger with Alta Mesa. CIT retains the right to terminate the forbearance period if, in its sole determination, Alta Mesa experiences changes to its financial condition that would adversely affect its ability to complete the merger with the Company.

At origination of the CIT Forbearance Agreement, the Company prepaid, without penalty, $1.0 million of principal on the rig note and began to pay “default interest” of an additional 4% effective August 1, 2009, as allowed to CIT under the terms of the rig note, bringing the total monthly payment to approximately $220,000. The Company also paid, and recorded in general and administrative expense in the third quarter, a forbearance fee of approximately $50,000. There can be no assurance that the forbearance period under the CIT Forbearance Agreement will provide sufficient time to resolve the cross-default under the rig note.

Scheduled debt maturities for the next five years and thereafter, as of December 31, 2009, including notes payable, are as follows: $93.7 million in 2010 and none thereafter. Absent the assumed acceleration of principal under the Credit Facility and the rig note, scheduled maturities would be: $29.5 million in 2010, $2.2 million in 2011, $62.0 million in 2012, and none thereafter.

In April 2006, the Company negotiated an amendment to its office building lease agreement that extended the Company’s office lease until September 30, 2011. As of December 31, 2009, the remaining base rental payments will be $2.0 million in 2010 and $1.6 million in 2011. The Company also has operating leases for equipment with various terms, none exceeding three years. Rental expense amounted to approximately $1.8 million, $2.0 million, and $2.1 million in 2009, 2008, and 2007, respectively. Future minimum lease payments under all non-cancelable operating leases having initial terms of one year or more are $2.1 million for 2010, $1.6 million for 2011, and none thereafter. In addition, over the next two years, the Company has contractual obligations for the use of two drilling rigs. These obligations are $12.4 million in 2010 and $0.9 million in 2011. See Note 7 for further information.

Additional contractual obligations include: $1 million in 2010 to Shell Oil Company under the settlement contract described in Note 7 below, if the contract is not terminated; and $1.5 million in 2010 and $0.2 million in 2011 to be paid under various settlement contracts. The Shell Oil Company obligation continues through 2014, with a payment of $1 million due each calendar year, for a total of $5 million.

In addition to the obligations described above, the Company has a contingent obligation related to the merger with Alta Mesa. The Merger Agreement with Alta Mesa includes a reimbursement clause under which the Company will pay Alta Mesa’s reasonable costs of the merger, not to exceed $1 million, in case of termination of the agreement under various circumstances, including expiration of the term on May 31, 2010 without consummation of the merger, and also including termination of the Merger Agreement due to non-approval in the shareholder vote. In addition to reimbursement of Alta Mesa’s costs, the Company would pay Alta Mesa a $3 million termination fee if, among other reasons, the Company terminates the Alta Mesa agreement and accepts another offer for the Company, so long as the definitive agreement related to the other offer is entered into within nine months after termination of the Merger Agreement with Alta Mesa. The termination fee would be payable no later than two business days after consummation of the transaction which triggered the fee.

As described in Notes 1 and 5, the Company has been in default under the terms of the Credit Facility and the rig note since December 31, 2008. Although forbearance has been provided by these Lenders under short-term agreements, there can be no assurance that the Company will be able to comply with the terms of the agreements. Among the default remedies available to the Lenders under each of these debt agreements is acceleration of all principal and interest payments. Accordingly, all such debt has been classified as current in the Consolidated Balance Sheets as of December 31, 2009 and 2008. The Company can give no assurance that the transactions contemplated by the Merger Agreement will be completed (see Note 1) and failure to complete the merger will significantly impact the credit defaults as well as the Company’s ability to continue as a going concern; therefore, the Company has not provided for this matter as of December 31, 2009, in its financial statements at December 31, 2009, other than to reclassify all outstanding debt as current at that date and at December 31, 2008.

As described in Note 1, the Company’s board of directors has approved an offer of merger with Alta Mesa, pending a shareholder vote. If the Merger Agreement is terminated by Meridian under various scenarios, including lack of shareholder approval, the Company will be required to reimburse Alta Mesa for their expenses of the merger, not to exceed $1 million. Acceptance of an alternative offer for the Company and consummation of that transaction under certain circumstances could obligate the Company to pay Alta Mesa a termination fee of $3 million (see Note 6 above).

H. L. Hawkins litigation. In December 2004, the estate of H.L. Hawkins filed a claim against Meridian for damages “estimated to exceed several million dollars” for Meridian’s alleged gross negligence, willful misconduct and breach of fiduciary duty under certain agreements concerning certain wells and property in the S.W. Holmwood and E. Lake Charles Prospects in Calcasieu Parish in Louisiana, as a result of Meridian’s satisfying a prior adverse judgment in favor of Amoco Production Company. Mr. James Bond had been added as a defendant by Hawkins claiming Mr. Bond, when he was General Manager of Hawkins, did not have the right to consent, could not consent or breached his fiduciary duty to Hawkins if he did consent to all actions taken by Meridian. Mr. James T. Bond was employed by H.L. Hawkins Jr. and his companies as General Manager until 2002. He served on the Board of Directors of the Company from March 1997 to August 2004. After Mr. Bond’s employment ended with Mr. Hawkins, Jr., and his companies, Mr. Bond was engaged by The Meridian Resource & Exploration LLC as a consultant. This relationship continued until his death. Mr. Bond was also the father-in-law of Michael J. Mayell, the Chief Operating Officer of the Company at the time. A hearing was held before Judge Kay Bates on April 14, 2008. Judge Bates granted Hawkins’ Motion finding that Meridian was estopped from arguing that it did not breach its contract with Hawkins as a result of the United States Fifth Circuit’s decision in the Amoco litigation. Meridian disagrees with Judge Bates’ ruling but the Louisiana First Court of Appeal declined to hear Meridian’s writ requesting the court overturn Judge Bates’ ruling. Meridian filed a motion with Judge Bates asking that the ruling be made a final judgment which would give Meridian the right to appeal immediately; however, the Judge declined to grant the motion, allowing the case to proceed to trial. Management continues to vigorously defend this action on the basis that Mr. Hawkins individually and through his agent, Mr. Bond, agreed to the course of action adopted by Meridian and further that Meridian’s actions were not grossly negligent, but were within the business judgment rule. Since Mr. Bond’s death, a pleading has been filed substituting the proper party for Mr. Bond. The Company is unable to express an opinion with respect to the likelihood of an unfavorable outcome of this matter or to estimate the amount or range of potential loss should the outcome be unfavorable. Therefore, the Company has not provided any amount for this matter in its financial statements at December 31, 2009.

Title/lease disputes. Title and lease disputes may arise in the normal course of the Company’s 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.

Environmental litigation. Various landowners have sued Meridian (along with numerous other oil companies) in lawsuits concerning several fields in which the Company 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 the Company’s oil and natural gas operations. In some of the lawsuits, Shell Oil Company and SWEPI LP (together, “Shell”) have demanded contractual indemnity and defense from Meridian based upon the terms of the two acquisition agreements related to the fields, and in another lawsuit, Exxon Mobil Corporation has demanded contractual indemnity and defense from Meridian on the basis of a purchase and sale agreement related to the field(s) referenced in the lawsuit; Meridian has challenged such demands. In some cases, Meridian has also demanded defense and indemnity from their subsequent purchasers of the fields. On December 9, 2008 Shell sent Meridian a letter reiterating its demand for indemnity and making claims of amounts which were substantial in nature and if adversely determined, would have a material adverse effect on the Company. Shell initiated formal arbitration proceedings on May 11, 2009, seeking relief only for the claimed costs and expenses arising from one of the two acquisition agreements between Shell and Meridian. Meridian denies that it owes any indemnity under either of the two acquisition agreements; however, the Company and Shell entered into a settlement agreement on January 11, 2010. Under the terms of the settlement, the Company will pay Shell $5 million in five equal annual payments beginning in 2010 upon the closing of a sale of the assets or equity interest in the Company to a third party (such as the merger with Alta Mesa described in Note 1), or at an earlier date should Meridian be able. Meridian will also transfer title to certain land the Company owns in Louisiana and an overriding royalty interest of minor value. In return, Shell will release Meridian from any indemnity claim arising from any current or historical claim against Shell, and will release Meridian’s indemnity obligation with respect to any future claim on all but a small subset of the properties acquired pursuant to the acquisition agreements related to the fields. The settlement agreement will terminate on May 1, 2010 if the first payment and the land and overriding royalty interest transfer have not been made, or unless extended at the discretion of Shell. The Company recorded $4.2 million in expense in the fourth quarter of 2009 to recognize the estimated value of the proposed settlement, including the historical cost of the land and discounting the cash payments to present value.

Other than the with regard to the Shell matter, the Company is 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, the Company has not provided any amount for these claims in its financial statements at December 31, 2009.

Litigation involving insurable issues. There are no material legal proceedings involving insurable issues which exceed insurance limits to which Meridian or any of its subsidiaries is a party or to which any of its property is subject, other than ordinary and routine litigation incidental to the business of producing and exploring for crude oil and natural gas.

Property tax litigation. In August, 2009, Gene P. Bonvillain, the tax assessor for Terrebonne Parish, Louisiana, filed a lawsuit against the Company, alleging under-reporting and underpayment of parish property taxes for the years 1998-2008. The claims, which are very similar to thirty other cases filed by Bonvillain against other oil and natural gas companies, allege that certain facilities or other property of the Company were improperly omitted from annual self-reporting tax forms submitted to the parish for the years 1998-2008, and that the properties Meridian did report on such forms were improperly undervalued and mischaracterized. The claims include recovery of delinquent taxes in the amount of $3.5 million, which the claimant advises may be revised upward, and general fraud charges against the Company. All thirty-one similar cases have been consolidated in U.S. District Court for the Eastern District of Louisiana.

Meridian denies the claims and expects to file a motion to dismiss the case, which it considers to be without merit. Meridian asserts that Mr. Bonvillain has no legal basis for filing litigation to collect what are, in essence, additional taxes based on reassessed property values. Furthermore, Meridian asserts that the fraud element of the case is insufficiently supported. Meridian intends to vigorously defend this action. The Company is unable to express an opinion with respect to the likelihood of an unfavorable outcome of this matter or to estimate the amount or range of potential loss should the outcome be unfavorable. Therefore, the Company has not provided any amount for this matter in its financial statements at December 31, 2009.

Shareholder litigation. On January 8, 2010 Mr. Eliezer Leider, a purported Company shareholder, filed a derivative lawsuit filed on behalf of the Company, Leider, derivatively on behalf of The Meridian Resource Corporation v. Ching, et al. in Harris County District Court. Defendants were the Company’s directors, Alta Mesa Holdings, LP, and Alta Mesa Acquisition Sub, LLC. Leider alleged that the Company’s directors breached their fiduciary duties in approving the merger transaction with Alta Mesa and he requested, but was denied, a temporary restraining order against the Company. This lawsuit was consolidated with another, similar one from Mr. Jeremy Rausch, which was a class action lawsuit. Counsel for Leider was appointed lead counsel. On March 23, 2010, the parties agreed in principle to settle the now-consolidated Leider action. The proposed settlement is conditioned on, among other things, approval of the merger by Meridian’s shareholders. Under the terms of the proposed settlement, all claims relating to the Merger Agreement and the merger will be dismissed on behalf of Meridian’s stockholders. As part of the proposed settlement, the defendants have agreed not to oppose plaintiff’s counsel’s request to the court to be paid up to $164,000 for their fees and expenses and up to $1,000 as an incentive award for plaintiff Leider. Any payment of fees, expenses, and incentives is subject to final approval of the settlement and such fees, expenses, and incentives by the court. The proposed settlement will not affect the amount of merger consideration to be paid to Meridian’s shareholders in the merger or change any other terms of the merger or Merger Agreement. Expenses of the proposed settlement are expected to be recorded in the first quarter of 2010.

Ceiling Test. At the end of each quarter, the unamortized cost of oil and natural gas properties, net of related deferred income taxes, is limited to the sum of the estimated future after-tax net revenues from proved properties, after giving effect to cash flow hedge positions, discounted at 10%, and the lower of cost or fair value of unproved properties adjusted for related income tax effects. This limitation is known as the “ceiling test.” Under new rules issued by the SEC, the estimated future net cash flows as of December 31, 2009, were determined using average prices for the most recent twelve months. The average is calculated using the first day of the month price for each of the twelve months that make up the reporting period. As of December 31, 2008 and 2007, previous rules required that estimated future net cash flows from proved reserves be based on period end prices. The Company recorded impairment charges against oil and natural gas properties based on the results of the ceiling test in the fourth quarter of 2008 and again in the first and fourth quarters of 2009.

At December 31, 2009, the Company had no cushion (i.e., the excess of the ceiling over capitalized costs). Thus, any future decrease in the average price to be used for the ceiling test, net of the effect of any hedging positions the Company may have, may necessitate additional impairment charges. Any future impairment would be impacted by changes in the accumulated costs of oil and natural gas properties, which may in turn be affected by sales or acquisitions of properties and additional capital expenditures. Future impairment would also be impacted by changes in estimated future net revenues, which are impacted by additions and revisions to oil and natural gas reserves, as well as by sales and acquisitions of properties. A 10% decrease in prices would have increased our fourth quarter 2009 non-cash impairment expense by approximately $28 million; a 10% increase in prices would have eliminated the need for a write-off.

Due to the its default under lending agreements, should the proposed merger with Alta Mesa (see Note 1) not be completed, the Company would be forced to consider sales of assets to generate cash for repayment of debt. Sales of significant assets would impact future ceiling tests, as their estimated future after-tax

net revenues would be removed from the calculation. Proceeds from sales of properties are generally credited to the full cost pool, reducing the carrying value of oil and gas properties subject to the ceiling test. The Company cannot predict whether significant property sales will cause additional ceiling test impairments, but it is possible that they will.

Drilling rigs. As described in Note 2, “Rig Operations”, the Company has significant contractual obligations for the use of two drilling rigs. The Company’s capital expenditure plans no longer include full use of these rigs; however, the Company is obligated for the dayrate regardless of whether the rigs are working or idle. The operator, Orion, has sought other parties to use the rigs and agreed to credit the Company’s obligation, based on revenues from third parties who utilize the rig(s) when the Company is unable to. Management cannot predict whether utilization of the rigs by third parties will be consistent, nor to what extent it may offset obligations under the dayrate contracts. The Company has not provided any amount for any future losses on these drilling contracts in its financial statements at December 31, 2009. The two drilling contracts will terminate in February 2011 (as to the rig not owned by the Company) and March 2010 (as to the rig owned by the Company and operated by Orion).

The Company entered into a forbearance agreement with Orion which may grant title to the company-owned rig to Orion, the operator under both the dayrate contracts, in exchange for release of all accrued and future liabilities under the rig contracts. This would occur at termination and final payment of the related rig note held by CIT, which is scheduled for 2013, if the Company continues to perform its obligations under the rig note and the rig is free of any significant security interest at title transfer. Both the rig value and the net payable to Orion would be written off at the time of such title transfer, if it were to occur. Alternatively, the terms of the forbearance agreement allow the Company an option to settle all claims with Orion in cash at the end of the term of the rig note, and retain title to the rig. There can be no assurance that the forbearance period under the CIT Forbearance Agreement will provide sufficient time to cure the default under the rig note and ensure performance under the Orion forbearance agreement. All accrued unpaid liabilities for rig expense through December 31, 2009 are classified in the accompanying consolidated balance sheet as current.

At December 31, 2009, the rig is included in equipment at a net book value of $4.6 million, and accounts payable includes a total of $4.3 million in accrued unpaid invoices from Orion for underutilization of both rigs, which is net of a reduction of $1.1 million estimated as the Company’s share of profits on the rig it owns. The Company performs impairment testing of the rig each quarter; see Note 4.

Provisions (benefits) for federal and state income taxes are as follows (thousands of dollars):

Income tax expense (benefit) as reported is reconciled to the federal statutory rate (35%) as follows (thousands of dollars):

Deferred income taxes reflect the net tax effects of net operating losses, depletion carryovers, and temporary differences between the carrying amounts of assets and liabilities for financial reporting purposes and the amounts used for income tax purposes. Significant components of the Company’s deferred tax assets and liabilities are as follows (thousands of dollars):

As of December 31, 2009, the Company had approximately $164.8 million of tax net operating loss carryforwards. The net operating loss carryforwards assume that certain items, primarily intangible drilling costs, have been capitalized and are being amortized under the tax laws for the current year. However, the Company has not made a final determination whether an election will be made to capitalize all or part of these items for tax purposes.

A portion of the net operating loss carryforwards is subject to change in ownership limitations that could restrict the Company’s ability to utilize such losses in the future.

As of December 31, 2009, the Company had net operating loss carryforwards for regular tax and alternative minimum tax (AMT) purposes available to reduce future taxable income. These carryforwards expire as follows (in thousands of dollars):

As of December 31, 2009, the Company had approximately $1.8 million of AMT tax credit carryforwards that do not expire.

Generally Accepted Accounting Principles require a valuation allowance to be recognized if, based on the weight of available evidence, it is more likely than not that some portion or all of the deferred tax asset will not be realized. The Company does not expect to fully realize its deferred tax assets, and therefore recorded a valuation allowance in 2008 and 2009 to the full extent of all net deferred tax assets.

Effective January 1, 2008, the Company adopted new authoritative guidance from the FASB regarding fair value, contained in Accounting Standards Codification Topic 820 (“ASC 820”). ASC 820 provides a hierarchy of fair value measurements, based on the inputs to the fair value estimation process. It requires disclosure of fair values classified according to defined “levels,” which are based on the reliability of the evidence used to determine fair value, with Level 1 being the most reliable and Level 3 the least. Level 1 evidence consists of observable inputs, such as quoted prices in an active market. Level 2 inputs typically correlate the fair value of the asset or liability to a similar, but not identical item which is actively traded. Level 3 inputs include at least some unobservable inputs, such as valuation models developed using the best information available in the circumstances.

The Company adopted the provisions of ASC 820 as it applies to assets and liabilities measured at fair value on a recurring basis on January 1, 2008. This included oil and natural gas derivatives contracts, and as of January 1, 2009, certain outstanding warrants known as the General Partner Warrants (see Notes 2 and 9).

In accordance with the deferred effective date provided by the FASB, on January 1, 2009, the Company adopted the provisions of ASC 820 for non-financial assets and liabilities which are measured at fair value on a non-recurring basis. This includes new additions to asset retirement obligations, and any long-lived assets, other than oil and natural gas properties, for which an impairment write-down is recorded during the period. There have been no such impairments of long-lived assets since adoption. ASC 820 does not apply to oil and natural gas properties accounted for under the full cost method, which are subject to impairment based on SEC rules.

The Company utilizes 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 gas prices. The Company has classified the fair values of all its derivative contracts as Level 2.

The fair value of the Company’s general partner warrants (see Notes 2 and 10) was calculated using the Black-Scholes option pricing model.

As noted above, ASC 820 also applies to new additions to asset retirement obligations, which must be estimated at fair value when added. New additions result from estimations for new obligations 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. The Company recorded $47,000 in additions to asset retirement obligations measured at fair value during the year ended December 31, 2009.

The Company estimates the fair value of its drilling rig quarterly (see Note 4), based on the present value of estimated cash flows from the rig, using management’s best estimates of utilization and dayrates. This is considered a Level 3 fair value.

As described in Note 1, the Company has proposed that it be merged with Alta Mesa, and the board of directors has recommended that shareholders vote in favor of the merger, with the vote currently scheduled for

April 28, 2010. Under the terms of the Merger Agreement, as amended, shareholders will receive $0.33 per share of common stock, to be paid in cash, and shares of the Company would cease to be publicly traded. The Company would be merged into Alta Mesa Acquisition Sub, LLC with the Merger Sub as the surviving entity.

Under the terms of the Merger Agreement, all the Company’s outstanding stock options will become vested and exercisable. As all such options bear exercise prices in excess of the price of $0.33 per share to be received in the merger, the Company expects no additional consideration for the options. Certain outstanding warrants (see below, “Warrants”) are expected to be settled for a total of approximately $431,000 with two members of the Company’s Board of Directors, who are also former officers.

In March 2007, the Company’s Board of Directors authorized a share repurchase program; an amendment to the credit agreement at that time increased the available limit for the Company’s repurchase of its common stock from $1.0 million to $5.0 million annually, so long as the Company was in compliance with certain provisions of the Credit Facility. From March 2007, the inception of the share repurchase program, through December 31, 2009, the Company had repurchased 535,416 common shares at a cost of $1,234,000, of which 501,300 shares have been reissued for 401(k) contributions, for contract services and for compensation, and 34,116 have been retired. The Bank Forbearance Agreement prohibits any further repurchase of Company stock. The Company did not repurchase any shares during 2009 and does not expect to make share repurchases in the foreseeable future.

In 2008, the Company issued shares to certain former executives upon the discontinuation of its deferred compensation plan (see Note 12). Shares sufficient to cover the value of these former executives withholding taxes were withheld from issuance, and the Company made a cash payment for the withholding tax. The total number of shares withheld was 1,001,511, at a value of approximately $3,035,000. In 2009, the Company again withheld shares from a distribution in order to cover the recipients’ personal withholding tax, which was paid in cash by the Company. The total shares withheld in the 2009 transaction were 610,938 shares at a total cost of $195,000. These transactions are considered an indirect repurchase and have been presented in the Consolidated Statements of Cash Flows as a financing item.

As of December 31, 2009, the Company had outstanding warrants (the “General Partner Warrants”) that entitle Joseph A. Reeves, Jr. and Michael J. Mayell to purchase an aggregate of 1,872,998 shares of common stock at an exercise price of $0.10 per share through December 31, 2015. Messrs. Reeves and Mayell, respectively, were the Chief Executive Officer and Chief Operating Officer of the Company for many years. Messrs. Reeves and Mayell both ceased to be employees of the Company on December 29, 2008.

The number of shares of common stock purchasable upon the exercise of the warrants and its corresponding exercise price are subject to customary anti-dilution adjustments. In addition to such customary adjustments, the number of shares of common stock and exercise price per share of the General Partner Warrants are subject to adjustment for any issuance of common stock by the Company such that each warrant will permit the holder to purchase at the same aggregate exercise price, a number of shares of common stock equal to the percentage of outstanding shares of the common stock that the holder could purchase before the issuance. Currently each of these two warrant arrangements permits the holder to purchase approximately 1% of the outstanding shares of the common stock for an aggregate exercise price of $94,303. The General Partner Warrants were issued to Messrs. Reeves and Mayell in conjunction with certain transactions with Messrs. Reeves and Mayell that took place in anticipation of the Company’s consolidation in December 1990 and were a component of the total consideration issued for various interests that Messrs. Reeves and Mayell had as general partners in TMR, Ltd., a predecessor entity of the Company. There are adequate authorized unissued common stock shares that are required to be issued upon conversion of the General Partner Warrants. The Company is not required to redeem the General Partner Warrants in cash.

The Company adopted new authoritative guidance from the FASB with regard to these warrants on January 1, 2009. The provisions of the new guidance, which relate to equity securities indexed to the price of a company’s own stock, were considered in regard to the General Partner Warrants and it was determined that they were not indexed to the price of the Company’s own stock and should therefore be subject to fair value accounting. Accordingly, a charge of $960,000 was recorded on January 1, 2009 to retained earnings to reflect the cumulative effect of recording the 1,884,544 warrants outstanding at that date at fair value, with an offsetting entry to accrued liabilities. Adjustments to fair value have been made on a prospective basis, beginning in 2009. For the year ended December 31, 2009, the Company recorded a gain on the valuation of the warrants of $548,000, which is included in general and administrative expense.

At December 31, 2009, 1,872,998 General Partner Warrants were outstanding and included in accrued liabilities at a total fair value of $412,000. Fair value is based on the Black-Scholes model for option pricing.

Options to purchase the Company’s common stock have been granted to officers, employees, nonemployee directors and certain key individuals, under various stock incentive plans. Options generally become exercisable in 25% cumulative annual increments beginning with the date of grant and expire at the end of ten years. The Company has also made grants of stock shares which vest over time (typically, three years). The Company has also issued rights to shares of common stock under its deferred compensation plan (see additional information for that plan below, “Deferred Compensation.”) The Company typically utilizes newly issued stock shares when options are exercised or shares vest.

Compensation expense is recorded for share-based awards over the requisite vesting periods based upon the fair value of the award on the date of the grant. Share-based compensation expense for grants of options and non-vested shares of approximately $153,000, $193,000, and $294,000 was recorded in the years ended December 31, 2009, 2008, and 2007, respectively and is included in general and administrative expense. In addition, general and administrative expense related to issuance of shares in lieu of cash for services was zero, $144,000, and $1,144,000, for each of the years ended December 31, 2009, 2008, and 2007, respectively. No portion of this expense has been capitalized. At December 31, 2009, 2008, and 2007, 4,140,000, 3,970,000, and 3,850,000 shares, respectively, were available for grant under the plans. Summaries of share-based awards transactions follow:

Fair value of share options was estimated at the date of grant using the Black-Scholes option pricing model. Certain assumptions were used in determining the fair value of share options using this model. The Company calculated the estimated volatility of its stock by averaging the historical daily price intervals for closing prices of the common stock. The risk-free interest rate is based on observed U.S. Treasury rates at date of grant, appropriate for the expected lives of the options. The expected life of options was determined based on the method provided in Staff Accounting Bulletin 107, as we do not have an adequate exercise history to determine the average life for the options with the characteristics of those granted.

Weighted averages of the assumptions used in the Black-Scholes option pricing model were as follows for grants of options in the years ended December 31, 2009, 2008 and 2007, respectively: risk-free interest rates of 1.5%, 3.0% and 4.54%; dividend yield of 0%; volatility factors of the expected market price of the Company’s common stock of 0.58, 0.59, and 0.59; and weighted-average expected lives of three years, four years, and five years. These assumptions resulted in weighted average grant date fair values of $0.25, $1.14 and $1.36 for options granted in 2009, 2008, and 2007, respectively.

The aggregate intrinsic value of share options exercised was zero in each of the years ended December 31, 2009, 2008, and 2007, as no options were exercised. The aggregate intrinsic value of non-vested shares which vested was $14,000, zero, and zero, for each of the years 2009, 2008, and 2007, respectively. No shares vested during 2008 and 2007.

The weighted average remaining contractual life of options outstanding at December 31, 2009, was approximately four years.

The aggregate intrinsic value for all options outstanding and for all exercisable options at December 31, 2009 was zero. The aggregate intrinsic value represents the total pre-tax value (the difference between the Company’s closing stock price on the last trading day of 2009 and the exercise price, multiplied by the number of in-the-money options) that would have been received by the option holders had they exercised their options on December 31, 2009. The amount of aggregate intrinsic value will change based on the fair market value of the Company’s common stock.

As of December 31, 2009, there was approximately $30,000 of total unrecognized compensation expense related to stock-based compensation plans. This compensation expense is expected to be recognized on a straight-line basis over the remaining vesting period of approximately 2 years.

In July 1996, the Company through the Compensation Committee of the Board of Directors offered to Messrs. Reeves and Mayell (at the time, the Company’s Chief Executive Officer and Chief Operating Officer, respectively) the option to accept in lieu of an electable portion of their cash, compensation rights to common stock pursuant to the Company’s Long Term Incentive Plan. Under the terms of this deferred compensation plan, Messrs. Reeves and Mayell each deferred $160,000 for 2008 and $400,000 for 2007. In exchange for and in consideration of their accepting this option to reduce the Company’s cash payments to each of Messrs. Reeves and Mayell, the Company granted to each officer a matching deferral equal to 100% of the amount deferred, subject to a one-year vesting period. Under the terms of the deferred compensation plan, the employee and matching deferrals were allocated to a notional common stock account in which notional shares of common stock were credited to the accounts of the officers based on the number of shares that could be purchased at the market price of the common stock with the deferred and matched funds. For 1997, the price was determined at December 31, 1996, and for all years subsequent to 1997, it was determined on a semi-annual basis at December 31st and June 30th. Compensation costs related to the amounts deferred by the officers and matched by the Company for these equity grants were $968,000 and $1,598,000 for 2008 and 2007, respectively. The costs are reflected in general and administrative expense and in oil and natural gas properties for the years ended December 31, 2008 and 2007, respectively as follows: $484,000 and $799,000 in general and administrative expense, and $484,000 and $799,000 capitalized to oil and natural gas properties.

The Company discontinued the deferred compensation plan provided to these officers, which resulted in the issuance of a total of 1,803,291 shares of new common stock for Messrs. Reeves and Mayell (combined) on July 2, 2008. The shares issued were net of a reduction of 1,001,511 shares withheld in lieu of the executives’ personal withholding tax. The intrinsic value of all these shares on date of issuance, including those withheld, was approximately $8.5 million at $3.03 per share. Also due to termination of the plan, 1,712,114 new shares (856,057 shares for each of the two officers) were issued and placed into a Rabbi Trust on October 2, 2008. The intrinsic value of these shares on date of issuance to the trust was approximately $3.1 million at $1.81 per share. The shares were distributed upon dissolution of the trust on June 26, 2009. The distribution was again issued net of a reduction of shares withheld in lieu of personal withholding tax; the number of shares withheld totaled 610,938. The intrinsic value of the 1,101,176 shares distributed and the 610,938 shares withheld was $352,000 and $195,000, respectively, at $0.32. See Note 12 for further information.

Activity in the notional accounts for the years ended December 31, 2008 and 2007 is as follows:

The shares of common stock which would have been issuable upon distribution of deferrals and matching grants during the time the plan was active (including 2007 and early 2008) have been treated as common stock equivalents in computing earnings per share.

The Company has a 401(k) profit sharing and savings plan (the “Plan”) that covers substantially all employees and entitles them to contribute up to 15% of their annual compensation, subject to maximum limitations imposed by the Internal Revenue Code. The Company matches 100% of each employee’s contribution up to 6.5% of annual compensation subject to certain limitations as outlined in the Plan. In addition, the Company may make discretionary contributions which are allocable to participants in accordance with the Plan. Total expense related to the Company’s 401(k) plan was $382,000, $531,000, and $545,000, in 2009, 2008, and 2007, respectively.

During 1998, the Company implemented a net profits program that was adopted effective as of November 1997. All employees participate in this program. Pursuant to this program, the Company adopted three separate well bonus plans: (i) The Meridian Resource Corporation Geoscientist Well Bonus Plan (the “Geoscientist Plan”); (ii) The Meridian Resource Corporation TMR Employees Trust Well Bonus Plan (the “Trust Plan”) and (iii) The Meridian Resource Corporation Management Well Bonus Plan (the “Management Plan,” together with the Trust Plan and the Geoscientist Plan, the “Well Bonus Plans”). Payments under the plans are calculated based on revenues from production on previously discovered reserves, as realized by the Company at current commodity prices, less operating expenses. Total compensation related to these plans was $2.3 million, $5.0 million, and $4.7 million, in 2009, 2008, and 2007, respectively. A portion of these amounts was capitalized with regard to personnel engaged in activities associated with exploratory projects. The Executive Committee of the Board of Directors, which was comprised of Messrs. Reeves and Mayell, administers each of the Well Bonus Plans. The participants in each of the Well Bonus Plans are designated by the Executive Committee in its sole discretion. Participants in the Management Plan are limited to executive officers of the Company and other key management personnel designated by the Executive Committee. Neither Messrs. Reeves nor Mayell participated in the Management Plan. The participants in the Trust Plan generally will be employees of the Company that do not participate in one of the other Well Bonus Plans. Effective March 2001, the participants in the Geoscientist Plan were notified that no additional future wells would be placed into the Geoscientist Plan. During 2002, the Executive Committee decided to modify this position and for certain key geoscientists the Geoscientist Plan will include new wells.

Pursuant to the Well Bonus Plans, the Executive Committee designates, in its sole discretion, the individuals and wells that will participate in each of the Well Bonus Plans. The Executive Committee also determines the percentage bonus that will be paid under each well and the individuals that will participate thereunder. The Well Bonus Plans cover all properties on which the Company expends funds during each participant’s employment with the Company, with the percentage bonus generally ranging from less than 0.1% to 0.5%, depending on the level of the employee. It is intended that these well bonuses function similar to actual net profit interests, except that the employee will not have a real property interest and will be subject to the general credit of the Company. For certain employees covered under the Management Well Bonus Plan and the Geoscientist Well Bonus Plan, payments under vested bonus rights will continue to be made after an employee leaves the employment of the Company based on their adherence to the obligations required in their non-compete agreement upon termination. The Company has the option to make payments in whole, or in part, utilizing shares of common stock. The determination whether to pay cash or issue common stock is based upon a variety of factors, including the

Company’s current liquidity position and the fair market value of the common stock at the time of issuance. In practice, most payments have been made in cash, with some payments to ex-employees made in common stock.

In connection with the execution of their employment contracts in 1994, both Messrs. Reeves and Mayell were granted a 2% net profit interest in the oil and natural gas production from the Company’s properties to the extent the Company acquires a mineral interest therein. The net profits interest for Messrs. Reeves and Mayell applies to all properties on which the Company expended funds during their employment with the Company. Each grant of a net profits interest is reflected at a value based on a third party appraisal of the interest granted. For the years ended December 31, 2009, 2008, and 2007, compensation expense in the amounts of zero, $137,350, and $78,054 were recorded for each Messrs. Reeves and Mayell. Grants made in 2009 were negligible. The net profit interests represent real property rights not subject to vesting or continued employment with the Company. Messrs. Reeves and Mayell did not participate in the Well Bonus Plans. The net profits interest plan for Messrs. Reeves and Mayell was discontinued in April, 2008 as to new properties, but continues to apply to all properties on which the Company had expended funds prior to discontinuation. See Note 12 for further information.

12. CONTRACT SETTLEMENTS, RABBI TRUST, EMPLOYEE RETENTION, AND INDEMNIFICATION SETTLEMENT

In April 2008 the Company made significant changes in the structure of the compensation of two executives, Mr. Joseph A. Reeves and Mr. Michael J. Mayell, former Chief Executive Officer and former Chief Operating Officer. Effective April 29, 2008, the employment contracts for Messrs. Reeves and Mayell were replaced with new agreements. In addition, certain other agreements that governed other elements of their compensation packages were also settled. As a result of the agreements, the Company recorded $9.9 million in contract settlement expense in the second quarter of 2008, and placed that amount of cash in a Rabbi Trust for the former officers. In June 2009, pursuant to the contractual terms, the cash was distributed from the trust to the former officers. Also in the third quarter of 2008, the Company recorded a $1.2 million non-cash expense due to write-down of the deferred tax asset related to the stock rights; the write-down was the result of the difference between the market value of the stock when the rights were issued and expensed, and the market value at conversion of the rights into shares.

In addition, the Company discontinued the deferred compensation plan provided to these officers, which resulted in the issuance of a total of 1,803,291 shares of new common stock for Messrs. Reeves and Mayell (combined) on July 2, 2008. The shares issued were net of a reduction of 1,001,511 shares withheld from issuance in lieu of the former executives’ personal withholding tax. An additional 1,712,114 new shares (856,057 shares to each of the two former officers) were placed in the Rabbi Trust in the third quarter of 2008, and distributed to the former officers in June 2009. The shares were again issued net of shares withheld for personal withholding tax (a total of 610,938 shares were withheld from distribution and retired). The total net shares distributed to the two officers was 1,101,176 (550,588 each). Substantially all of the compensation expense related to these shares had been recognized historically, when the rights to such future shares were granted.

Prior to distribution, the cash in the Rabbi Trust was included on the Consolidated Balance Sheets under “Restricted Cash,” and the shares in the trust were accounted for as treasury shares, assigned a value based on the closing market price on the date they were issued, October 2, 2008. Until distribution, the assets of the trust belonged to the Company, but were effectively restricted due to the obligation to the former officers.

On July 29, 2008, the Company reached an agreement with a former employee to terminate a compensation agreement. Under the terms of the termination agreement, the Company paid the former employee $825,000 and repurchased from him, 34,116 shares of Company stock, which had been issued to him in lieu of cash compensation. The total cost of repurchasing the shares was approximately $75,000. The Company has no further obligation to this former employee. The termination payment was recorded as general and administrative expense in the third quarter of 2008.

On July 3, 2008, the Company initiated the Meridian Resource & Exploration LLC Retention Incentive Compensation Plan, and under the terms of the plan, distributed a total of $1.6 million in bonuses to its employees. The purpose of the plan was to encourage the retention of valued employees for the immediate term. The employment market for experienced personnel in the oil and gas industry had been very strong for some time when the plan was initiated. Management’s intention for the incentive program was to help equalize its employees’ compensation with current market conditions and motivate them to continue their careers with Meridian. The terms of the plan included a second, final bonus to those employees who continued their employment with the Company through March 31, 2009. The second payment, issued April 3, 2009, totaled approximately $2.9 million; the expense was accrued ratably over the time period July 2008 through March 2009. The Company recognized $1.7 million in general and administrative expense, net of capitalization of a portion to the full cost pool, through December 31, 2008, and approximately $0.5 million in general and administrative expense for the retention bonus plan in 2009, net of capitalization.

As described in Note 7, in the fourth quarter of 2009 the Company recorded $4.2 million in expense for a settlement with Shell regarding indemnification of environmental claims.

The Company’s operating environment includes two primary financial risks which could be addressed through derivatives and similar financial instruments: the risk of movement in oil and natural gas commodity prices, which impacts revenue, and the risk of interest rate movements, which impacts interest expense from floating rate debt.

The Company currently does not utilize derivative contracts or any other form of hedging against interest rate risk.

The Company utilizes derivative contracts to address the risk of adverse oil and natural gas commodity price fluctuations. While the use of derivative contracts limits the downside risk of adverse price movements, it may also limit future gains from favorable movements. No derivative contracts have been entered into for trading purposes, and the Company generally holds each remaining instrument to maturity. The Company’s commodity derivative contracts are considered cash flow hedges under generally accepted accounting principles.

The Company has historically utilized derivative contracts to hedge the sale of a portion of its future production. The Company’s objective is to reduce the impact of commodity price fluctuations on both income and cash flow, as well as to protect future revenues from adverse price movements. Management considers some exposure to market pricing to be desirable, due to the potential for favorable price movements, but prefers to achieve a measure of stability and predictability over revenues and cash flows by hedging some portion of production. All the Company’s hedging agreements expired in December 2009. All of the Company’s hedging agreements are executed by affiliates of the Lenders under the Credit Facility and are collateralized by the security interest the Lenders have in the oil and natural gas assets of the Company. Due to the default under the Credit Facility, the Lenders have not allowed the Company to enter into any additional hedging agreements. As a result, the Company’s oil and natural gas sales for periods beyond December 2009 will more closely resemble prevailing market prices.

The Company accounts for its derivative contracts under the provisions of ASC 815, “Derivatives and Hedging.” Under ASC 815, the Company’s commodity derivatives are designated as cash-flow hedges and are stated at fair value on the Consolidated Balance Sheets. See Note 9, “Fair Value Measurements” for further

information on how fair values of derivative instruments are determined. Changes in the fair value of the contracts, which occur due to commodity price movements, are offset in Accumulated Other Comprehensive Income. When the derivative contract or a portion of it matures, the gain or loss is settled in cash and reclassified from Accumulated Other Comprehensive Income to Revenues from Oil and Natural Gas. Net settlements under hedging agreements increased (decreased) oil and natural gas revenues by $11.7 million, ($4.7 million) and $3.3 million for the years ended December 31, 2009, 2008 and 2007, respectively. A gain or loss may be recorded to earnings prior to contract maturity if a portion of the cash flow hedge becomes “ineffective” under the guidelines provided under generally accepted accounting principles, or if the forecasted transaction is no longer expected to occur. Although the Company periodically records gains or losses from hedge ineffectiveness, there have been no losses recorded due to changes in expectations regarding occurrence of the hedged transactions. The following two tables provide information regarding assets, liabilities, gains, and losses related to derivative contracts, and where these amounts are reflected within the Company’s financial statements (in thousands):

Effect of Derivative Contracts on the Consolidated Balance Sheets and the Consolidated Statements of Operations.

As of December 31, 2009 and 2008, the Company had unrealized gains of zero and $8.1 million (pre-tax and net of tax) deferred in Accumulated Other Comprehensive Income, respectively. All of the Company’s derivative agreements expired December 31, 2009.

Major customers for the years ended December 31, 2009, 2008, and 2007, were as follows (based on sales exceeding 10% of total oil and natural gas revenues):

Messrs. Joseph A. Reeves, Jr. and Michael J. Mayell, each of whom was an officer of the Company until December 29, 2008 and is a current Director of Meridian, are working interest partners of the Company. Historically since 1994, affiliates of Meridian have been permitted to hold interests in projects of the Company. With the approval of the Board of Directors, Texas Oil Distribution and Development, Inc. (“TODD”) and JAR Resources LLC (“JAR”), entities controlled by Joseph A. Reeves, Jr. and Sydson Energy, Inc. (“Sydson”), an entity controlled by Michael J. Mayell, have each invested in Meridian drilling locations, where applicable, at a 1.5% to 4% working interest basis. The maximum total percentage at which either officer was allowed to participate in any prospect was a 4% working interest. The right to participate in “new oil and gas projects” was terminated as of December 29, 2008, under the settlement agreements with Messrs. Reeves and Mayell described immediately below and in Note 12. On a collective basis, TODD, JAR and Sydson invested $997,000, $4,321,000, and $9,871,000, for the years ended December 31, 2009, 2008, and 2007, respectively, in oil and natural gas drilling activities. The former officers continued to be offered participation in new wells in 2009, from prospects initiated prior to December 29, 2008. Net amounts due to (from) TODD, JAR, Matrix Petroleum LLC (see below) and Mr. Reeves were approximately $76,000 and ($1,981,000) as of December 31, 2009 and 2008, respectively. Net amounts due to Sydson and Mr. Mayell were approximately $466,000 and $232,000 as of December 31, 2009 and 2008, respectively.

Messrs. Reeves and Mayell each entered into consulting agreements with the Company, commencing December 30, 2008. Each provided professional services to the Company for a monthly fee; the agreements terminated on April 30, 2009, with a total of $217,000 paid to or on behalf of each of the two former officers during 2009. During 2008, the Company settled certain compensation-related contracts with Messrs. Reeves and Mayell, accruing a total of $9,894,000 for obligations under the settlements, included in “Due to affiliates” in the accompanying Consolidated Balance Sheet for December 31, 2008. See Note 12 for further details. As a result of this settlement, during the second quarter of 2009, the Company paid $4,954,000 and $4,940,000 to Messrs. Reeves and Mayell, respectively. Funds for the payments were provided from those previously set aside in the related Rabbi Trust. In addition to the cash payment, each of the former officers received 550,588 shares of Company stock distributed from the Rabbi Trust. Under the terms of other employment contracts entered into in 2008, Messrs. Reeves and Mayell also continued to receive such employee benefits as medical insurance throughout 2009, as well as other fringe benefits, primarily the maintenance of certain club memberships on their behalf. The Company is obligated to continue these benefits to each of these two former officers through October 2010.

Also under the terms of the 2008 settlement with Messrs. Reeves and Mayell, in 2009 the Company transferred to them the furniture, equipment, and artwork from their Meridian executive offices.

During 2009, Matrix Petroleum LLC (“Matrix”), an entity controlled by Mr. Reeves, entered into a lease of office space from Meridian. The Company has invoiced Matrix a total of $77,000 for rent and minor charges for use of Meridian office support staff.

As described in Note 11, Messrs. Reeves and Mayell are entitled to certain grants of net profits interests in properties initiated for development during their term of employment. As properties develop from geological studies to executed mineral leases, Messrs. Reeves and Mayell receive interests in the mineral leases. Such grants were valued by third party appraisal at $137,350 and $78,054 for the years 2008 and 2007, respectively. Grants made in 2009 were negligible.

In December 2009, the Company reached a settlement agreement with Mr. Reeves, TODD, and JAR (collectively, the “Reeves Parties”) regarding amounts the Reeves Parties claimed were owed to them by the Company under various agreements, all of which involve the Company’s and the Reeves Parties’ ownership interests in various oil and natural gas properties. In settlement of these claims: 1) the Company agreed to credit by $600,000 the balance owed by the Reeves Parties to the Company as joint interest partners; 2) the Reeves Parties paid the Company $400,000 against their joint interest accounts in December 2009 and agreed to bring their account balances current by May 2010; 3) the Company indemnified the Reeves Parties against claims arising prior to the settlement date of December 22, 2009 in regard to the properties in which the Reeves Parties share an interest with the Company; and 4) the Reeves Parties’ ownership in each property was clarified and listed, including those potential properties included in areas of study performed during Mr. Reeves’ tenure as an officer. Together with credits for the Reeves Parties’ share of fourth quarter revenues on the properties, these transactions brought the balance between the Company and Reeves Parties to the amount cited above, $76,000 owed by the Company to Reeves.

The Company also entered a settlement contract with Mr. Mayell and Sydson (together, “Mayell Parties”) on December 17, 2009, clarifying and listing the Mayell Parties’ ownership in each oil and natural gas property, including those potential properties included in areas of study performed during Mr. Mayell’s tenure as an officer. The Company provided the Mayell Parties with indemnifications as to claims arising before the date of settlement, with regard to the properties in which the Mayell Parties share an interest with the Company.

Mr. Joe Kares, a former Director of Meridian, is a partner in the public accounting firm of Kares & Cihlar, which provided the Company with accounting services for the years ended December 31, 2009, 2008, and 2007 and received fees of approximately $150,000, $216,000, and $231,000, respectively. Such fees exceeded 5% of the gross revenues of Kares & Cihlar for those respective years. Mr. Kares also participated in the Management Plan described in Note 11 above, pursuant to which he was paid approximately $101,000 during 2009, $335,000 during 2008, and $275,000 during 2007. Mr. Kares resigned from the Board of Directors effective October 13, 2009.

Mr. Gary A. Messersmith, a former Director of Meridian, is currently a member of the law firm of Looper, Reed & McGraw P.C. in Houston, Texas, which provided legal services for the Company for the years ended December 31, 2009, 2008, and 2007, and received fees of approximately $137,000, $118,000, and $73,000, respectively. In addition, during 2007, the Company paid Gary A. Messersmith, P.C. $8,333 per month relating to his services provided to the Company. The retainer was paid through March, 2008, then discontinued. Mr. Messersmith also participated in the Management Plan described in Note 11 above, pursuant to which he was paid approximately $159,000 during 2009, $527,000 during 2008, and $441,000 during 2007. Mr. Messersmith resigned from the Board of Directors effective October 13, 2009.

During 2008, both Mr. Kares and Mr. Messersmith requested the Company discontinue their participation in the Management Well Bonus Plan as to new wells drilled after mid-April 2008. Their participation as to wells previously drilled is unchanged.

Mr. G. M. Larberg, a former Director of Meridian, is a petroleum industry consultant that provided the Company with services for the years ended December 31, 2009, 2008, and 2007, and received consulting fees of approximately $44,000, $210,000, and $223,000, respectively. Mr. Larberg resigned from the Board of Directors effective October 13, 2009.

Mr. J. Drew Reeves, the son of Mr. Joseph A. Reeves, Jr., is a staff member in the Land Department. Mr. Drew Reeves was paid $218,000, $227,000, and $168,000, for the years 2009, 2008, and 2007, respectively. Mr. Jeff Robinson is the son-in-law of Joseph A. Reeves, Jr. and is employed as the Manager of the Company’s Information Technology Department and has been paid $198,000, $193,000, and $164,000, for the years 2009, 2008, and 2007, respectively. Mr. J. Todd Reeves, the son of Joseph A. Reeves, Jr., is a partner in the law firm of J. Todd Reeves and Associates, which provides legal services to the Company and received fees of approximately $63,000 in 2009, $197,000 in 2008, and $371,000 in 2007. Such fees exceeded 5% of the gross revenues for the firm for those respective years.

Mr. Michael W. Mayell, the son of Mr. Michael J. Mayell, an officer until December 29, 2008 and a current Director of Meridian, is a staff member in the Production Department, and was paid $174,000, $169,000, and $129,000 for the years 2009, 2008, and 2007, respectively. Mr. James T. Bond, former Director of Meridian, was the father-in-law of Mr. Michael J. Mayell; he provided consulting services to the Company and received fees in the amount of $48,000 for the year 2007.

Earnings during 2008 and 2009 noted above for related party employees include the impact of the Retention Incentive Compensation Plan described in Note 12.

The following table sets forth the computation of basic and diluted earnings (loss) per share:

Warrants and stock options for which the exercise prices were greater than the average market price of the Company’s common stock are excluded from the computation of diluted earnings per share. Stock rights issued under the Company’s deferred compensation plan, which was discontinued in 2008, had no exercise price and are included in diluted earnings per share in all years during which they were outstanding, unless there is a loss. All potentially dilutive shares, whether from options, warrants, or rights, are excluded when there is an operating loss, because inclusion of such shares would be anti-dilutive.

(a) The number of warrants excluded totaled approximately 1.9 million, 3.3 million, and 1.4 million, in 2009, 2008, and 2007, respectively.

(b) The number of stock options excluded totaled approximately 0.4 million, 0.5 million, and 3.6 million, in 2009, 2008, and 2007, respectively.

Below is the detail of accrued liabilities on the Company’s balance sheets as of December 31 (thousands of dollars):

The total Shell settlement obligation is $4,223,000, of which $3,220,000 is classified as “Other Liabilities” in the long-term section of the accompanying Consolidated Balance Sheets at December 31, 2009. See Note 7 for further information. The balance is to be paid over a five year period.

Results of operations by quarter for the year ended December 31, 2009 were (thousands of dollars, except per share):

Results of operations by quarter for the year ended December 31, 2008 were (thousands of dollars, except per share):

In December 2008, the SEC published a Final Rule, “Modernization of Oil and Gas Reporting.” The new rule permits the use of new technologies to determine proved reserves if those technologies have been demonstrated to lead to reliable conclusions about reserves volumes. The new requirements also allow companies to disclose their probable and possible reserves to investors. In addition, the new disclosure requirements require companies to: (a) report the independence and qualifications of its reserves preparer or auditor; (b) file reports when a third party is relied upon to prepare reserves estimates or conducts a reserves audit; and (c) report oil and gas reserves using an average price based upon the prior 12-month period rather than year-end prices. The use of average prices affects impairment and depletion calculations. The new rule became effective for reserve reports as of December 31, 2009; the FASB incorporated the new guidance into the Codification as Accounting Standards Update 2010-03, effective also on December 31, 2009, ASC Topic 932, “Extractive Activities — Oil and Gas.”

The Company adopted the new guidance effective December 31, 2009; information about the Company’s reserves has been prepared in accordance with the new guidance; management has chosen not to provide information on probable and possible reserves. The Company’s reserves were affected primarily by the use of the average price rather than the year-end price required under the prior rules. Under the new rules issued by the SEC, the estimated future net cash flows as of December 31, 2009, were determined using average prices for the most recent twelve months. The average is calculated using the first day of the month price for each of the twelve months that make up the reporting period. As of December 31, 2008 and 2007, previous rules required that estimated future net cash flows from proved reserves be based on period end prices. As a result of adopting the new guidance, we estimate that Meridian’s December 31, 2009 proven reserves decreased approximately 1.4 Bcfe and prices used in the calculation decreased approximately 30%. These changes in turn affected the results of the Company’s ceiling test for the fourth quarter, which was a write-down of $4.0 million. Had the new rule using average pricing not been implemented, the write-down in the fourth quarter of 2009 would not have been necessary. The change in total reserves had only a negligible effect on depletion expense in the fourth quarter of 2009; total proved reserves are the basis of depletion calculations.

The reserve volumes and associated cash flows were prepared by T. J. Smith & Company, Inc., independent reservoir engineers. For further information on Mr. Smith’s qualifications and on the methods and controls used in the process of estimating reserves, please see Part I, Item 1, Business, Oil and Natural Gas Reserves.

The reserve information presented below is provided as supplemental information in accordance with the provisions of ASC Topic 932-235.

Costs Incurred in Oil and Natural Gas Acquisition, Exploration and Development Activities

At December 31, 2009 and 2008, unevaluated costs of $1,647,000 and $39,927,000, respectively, were excluded from the depletion base. The costs excluded in 2009 are expected to be evaluated within the next three years. These costs consist primarily of acreage acquisition costs at December 31, 2009, and acreage acquisition costs and related geological and geophysical costs at December 31, 2008.

The following table sets forth a summary of oil and natural gas property costs not being amortized at December 31, 2009, by the year in which such costs were incurred. All the costs not being amortized relate to one property, a group of leaseholds in south Texas under exploration with another operator, and include no exploratory well costs.

The following table sets forth the net proved reserves of the Company as of December 31, 2009, 2008, and 2007, and the changes therein during the years then ended. Proved oil and natural gas reserves are the estimated quantities of crude oil, natural gas, and natural gas liquids that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions, i.e., prices and costs as of the date the estimate is made. The reserve information was prepared by T. J. Smith & Company, Inc., independent reservoir engineers, for 2009, 2008, and 2007. Mr. T. J. Smith is the person primarily responsible for overseeing the preparation of our annual reserve estimates. Mr. Smith is a graduate of Mississippi State University with a Bachelor of Science degree in Petroleum Engineering. He has over 40 years’ experience with approximately 35 years focused on reserve evaluation. He is a member of the Society of Petroleum Engineers and is a Registered Professional Engineer in the states of Texas and Louisiana. All of the Company’s oil and natural gas producing activities are located in the United States.

The total of the Company’s proved undeveloped reserves (“PUD’s”) is 27 Bcfe, or approximately 36% of total proved reserves at December 31, 2009. The undeveloped properties are primarily in our East Texas area and in two of our mature fields in Louisiana and are the same or similar properties to those reported in 2008, which totaled 29 Bcfe. Reductions in PUD’s from the prior year include a decrease of 5.6 Bcfe at the outside operated East Cameron 331/332 field offshore. We have eliminated these non-operated reserves as there is substantial uncertainty as to their development as the field has undergone numerous operator changes (again in 2009) and we have no firm plans to develop them at this time. Other changes in PUD’s include a reduction of 3.7 Bcfe for several oil wells that had been candidates for updip oil development; however, there is no certainty that these updip locations will be oil. We have, for reserve purposes, estimated that the section will be natural gas, and hence, the reserves are uneconomic and have been eliminated.

Increases to PUD’s were due primarily to upward revisions of estimates and the addition of several new locations in East Texas totaling 5.8 Bcfe, based on new drilling and production information for that area. Progress toward development of our portfolio of proved undeveloped reserves was necessarily minimal during 2009, as we minimized capital spending due to our Credit Facility defaults.

Approximately 11.5 Bcfe of our PUD’s at December 31, 2009 originated more than five years ago. Certain PUD’s in our mature fields in Louisiana have been included for more than five years, because they have been planned as sidetracks and cannot be developed until the current producing well bores have been depleted and abandoned. We have been exploring and developing our East Texas acreage since 2005, and now have a total of 14 producing wells in that area.

The estimated discounted future net cash flows from estimated proved reserves are based on historical prices and costs as of the date of the estimate unless such prices or costs are contractually determined at such date. Actual future prices and costs may be materially higher or lower. Actual future net revenues also will be affected by factors such as actual production, supply and demand for oil and natural gas, curtailments or increases in consumption by natural gas purchasers, changes in governmental regulations or taxation and the impact of inflation on costs. Future income tax expense has been reduced for the effect of available net operating loss carryforwards.

The following table sets forth the components of the standardized measure of discounted future net cash flows for the years ended December 31, 2009, 2008, and 2007 (thousands of dollars):

The average expected realized price for natural gas in the above computations was $3.97, $5.79, and $6.66 per Mcf at December 31, 2009, 2008, and 2007, respectively. The average expected realized price used for crude oil in the above computations was $59.94, $44.04, and $95.54, per Bbl at December 31, 2009, 2008, and 2007, respectively. No consideration was been given to the Company’s hedged transactions.

The following table sets forth the changes in standardized measure of discounted future net cash flows for the years ended December 31, 2009, 2008, and 2007 (thousands of dollars):

We have audited the accompanying statements of revenues and direct operating expenses of the oil and gas properties purchased by Alta Mesa Holdings, LP and Subsidiaries, from Sydson Energy, Inc. and affiliates (“Sydson”) for the period January 1, 2011 through March 31, 2011 and for the fiscal twelve month period ended December 31, 2010. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the financial statements referred to above present fairly, in all material respects, the statements of revenues and direct operating expenses of the oil and gas properties purchased by Alta Mesa Holdings, LP and Subsidiaries from Sydson for the period January 1, 2011 through March 31, 2011 and for the fiscal twelve month period ended December 31, 2010, in conformity with accounting principles generally accepted in the United States of America.

See accompanying Notes to the Statements of Revenues and Direct Operating Expenses

NOTES TO STATEMENTS OF REVENUES AND DIRECT OPERATING EXPENSES OF THE OIL AND GAS PROPERTIES PURCHASED BY ALTA MESA HOLDINGS, LP AND SUBSIDIARIES FROM SYDSON ENERGY, INC. AND AFFILIATES (In thousands)

On April 21, 2011, Alta Mesa Holdings, LP and Subsidiaries (the “Company”) acquired interests in oil and gas properties (the “Properties”) from Sydson Energy, Inc. and affiliates (“Sydson”) for a purchase price of $27.5 million. The accompanying statements of revenues and direct operating expenses relate to the operations of the oil and gas properties acquired by the Company.

The statements of revenues and direct operating expenses associated with the properties were derived from the accounting records of the Company, the operator of the properties. During the periods presented, the Properties were not accounted for or operated as a consolidating entity or as a separate division by Sydson. Revenues and direct operating expenses for the Properties included in the accompanying statements represent the net collective working and revenue interests to be acquired by the Company on the accrual basis of accounting. The revenues and direct operating expenses presented herein relate only to the interests in the producing oil and natural gas properties which were acquired and do not represent all of the oil and natural gas operations of Sydson, other owners, or third party working interest owners. Direct operating expenses include lease operating expenses and production and other related taxes. General and administrative expenses, depreciation, depletion and amortization (“DD&A”) of oil and gas properties and federal and state taxes have been excluded from direct operating expenses in the accompanying statements of revenues and direct operating expenses because the allocation of certain expenses would be arbitrary and would not be indicative of what such costs would have been had the Properties been operated as a stand alone entity. Full separate financial statements prepared in accordance with accounting principles generally accepted in the United States of America do not exist for the Properties and are not practicable to prepare in these circumstances. The statements of revenues and direct operating expenses presented are not indicative of the results of operations of the Properties on a go forward basis due to the changes in the business and omission of various operating expenses.

Use of estimates: The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.

Revenue recognition: The Company records revenues when its products are delivered at a fixed or determinable price, title has transferred and collectability is reasonably assured.

The following estimates of the net proved oil and natural gas reserves of the properties, which are located entirely within the United States of America, are based on evaluations prepared by third-party reservoir engineers. Reserves were estimated in accordance with guidelines established by the Securities and Exchange Commission (“SEC”) and the Financial Accounting Standards Board (“FASB”), which require that reserve estimates be prepared under existing economic and operating conditions with no provisions for price and cost changes except by contractual arrangements. Reserve estimates are inherently imprecise and estimates of new discoveries are more imprecise than those of producing oil and gas properties. Accordingly, reserve estimates are expected to change as additional performance data becomes available.

Estimated quantities of proved reserves and changes in quantities of proved developed and undeveloped reserves were as follows:

A summary of the discounted future net cash flows relating to proved reserves is shown below. Future net cash flows are computed with guidelines established by the SEC and FASB, using commodity prices and costs that relate to the properties’ existing proved reserves.

The discounted future net cash flows related to proved reserves are as follows (in thousands):

A summary of the changes in the discounted future net cash flows applicable to proved reserves follows (in thousands):

We have audited the accompanying statements of revenues and direct operating expenses of the oil and gas properties purchased by Alta Mesa Holdings, LP and Subsidiaries, from Texas Oil Distribution and Development, Inc. and affiliates (“TODD”) for the period January 1, 2011 through March 31, 2011 and for the fiscal twelve month period ended December 31, 2010. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

In our opinion, the financial statements referred to above present fairly, in all material respects, the statements of revenues and direct operating expenses of the oil and gas properties purchased by Alta Mesa Holdings, LP and Subsidiaries from TODD for the period January 1, 2011 through March 31, 2011 and for the fiscal twelve month period ended December 31, 2010, in conformity with accounting principles generally accepted in the United States of America.

SUBSIDIARIES FROM TEXAS OIL DISTRIBUTION AND DEVELOPMENT, INC. AND AFFILIATES

See accompanying Notes to the Statements of Revenues and Direct Operating Expenses

On June 17, 2011, Alta Mesa Holdings, LP and Subsidiaries (the Company) acquired interests in oil and gas properties (the “Properties”) from Texas Oil Distribution and Development, Inc. and affiliates (“TODD”) for a purchase price of $22.5 million. The accompanying statements of revenues and direct operating expenses relate to the operations of the oil and gas properties acquired by the Company.

The statements of revenues and direct operating expenses associated with the properties were derived from the accounting records of the Company, the operator of the Properties. During the periods presented, the Properties were not accounted for or operated as a consolidating entity or as a separate division by TODD. Revenues and direct operating expenses for the Properties included in the accompanying statements represent the net collective working and revenue interests to be acquired by the Company on the accrual basis of accounting. The revenues and direct operating expenses presented herein relate only to the interests in the producing oil and natural gas properties which were acquired and do not represent all of the oil and natural gas operations of TODD, other owners, or third party working interest owners. Direct operating expenses include lease operating expenses and production and other related taxes. General and administrative expenses, depreciation, depletion and amortization (“DD&A”) of oil and gas properties and federal and state taxes have been excluded from direct operating expenses in the accompanying statements of revenues and direct operating expenses because the allocation of certain expenses would be arbitrary and would not be indicative of what such costs would have been had the Properties been operated as a stand alone entity. Full separate financial statements prepared in accordance with accounting principles generally accepted in the United States of America do not exist for the Properties and are not practicable to prepare in these circumstances. The statements of revenues and direct operating expenses presented are not indicative of the results of operations of the Properties on a go forward basis due to the changes in the business and omission of various operating expenses.

Revenue recognition: The Company records revenues when its products are delivered at a fixed or determinable price, title has transferred and collectability is reasonably assured.

Estimated quantities of proved reserves and changes in quantities of proved developed and undeveloped reserves were as follows:

The discounted future net cash flows related to proved reserves are as follows (in thousands):

A summary of the changes in the discounted future net cash flows applicable to proved reserves follows (in thousands):

THE EXCHANGE OFFER AND WITHDRAWAL RIGHTS WILL EXPIRE AT 5:00 P.M., NEW YORK CITY TIME, ON JANUARY 31, 2013 (THE “EXPIRATION DATE”), UNLESS THE EXCHANGE OFFER IS EXTENDED BY THE ISSUERS.

The Exchange Agent for the Exchange Offer is Wells Fargo Bank, N.A. and its contact information is as follows:

If you wish to exchange your issued and outstanding 9 5/8% Senior Notes due 2018, Series A (“old notes”) for an equal aggregate principal amount of 9 5/8% Senior Notes due 2018, Series B (“new notes”) pursuant to the exchange offer, you must validly tender (and not withdraw) old notes to the Exchange Agent prior to the Expiration Date.

We refer you to the Prospectus, dated December 28, 2012 (the “Prospectus”), of Alta Mesa Holdings, LP (the “Company”) and Alta Mesa Finance Services Corp. (the “Co-Issuer”, and together with the Company, the “Issuers”), and this Letter of Transmittal (the “Letter of Transmittal”), which together describe the Issuers’ offer (the “Exchange Offer”) to exchange their new notes that have been registered under the Securities Act of 1933, as amended (the “Securities Act”), for a like principal amount of their issued and outstanding old notes. Capitalized terms used but not defined herein have the respective meaning given to them in the Prospectus.

The Issuers reserve the right, at any time or from time to time, to extend the Exchange Offer at their discretion, in which event the term “Expiration Date” shall mean the latest date to which the Exchange Offer is extended. The Issuers shall notify the Exchange Agent and each registered holder of the old notes of any extension by oral or written notice prior to 9:00 a.m., New York City time, on the next business day after the previously scheduled Expiration Date.

This Letter of Transmittal is to be used by holders of the old notes. Tender of old notes is to be made according to the Automated Tender Offer Program (“ATOP”) of The Depository Trust Company (“DTC”) pursuant to the procedures set forth in the Prospectus under the caption “Exchange Offer—Procedures for Tendering.” DTC participants that are accepting the Exchange Offer must transmit their acceptance to DTC, which will verify the acceptance and execute a book-entry delivery to the Exchange Agent’s DTC account. DTC will then send a computer generated message known as an “agent’s message” to the Exchange Agent for its acceptance. For you to validly tender your old notes in the Exchange Offer the Exchange Agent must receive, prior to the Expiration Date, an agent’s message under the ATOP procedures that confirms that:

BY USING THE ATOP PROCEDURES TO TENDER OLD NOTES, YOU WILL NOT BE REQUIRED TO DELIVER THIS LETTER OF TRANSMITTAL TO THE EXCHANGE AGENT. HOWEVER, YOU WILL BE BOUND BY ITS TERMS, AND YOU WILL BE DEEMED TO HAVE MADE THE ACKNOWLEDGMENTS AND THE REPRESENTATIONS AND WARRANTIES IT CONTAINS, JUST AS IF YOU HAD SIGNED IT.

1. By tendering old notes in the Exchange Offer, you acknowledge receipt of the Prospectus and this Letter of Transmittal.

2. By tendering old notes in the Exchange Offer, you represent and warrant that you have full authority to tender the old notes described above and will, upon request, execute and deliver any additional documents deemed by the Issuers to be necessary or desirable to complete the tender of old notes.

3. You understand that the tender of the old notes pursuant to all of the procedures set forth in the Prospectus will constitute an agreement between you and the Issuers as to the terms and conditions set forth in the Prospectus.

4. By tendering old notes in the Exchange Offer, you acknowledge that the Exchange Offer is being made in reliance upon interpretations contained in no-action letters issued to third parties by the staff of the Securities and Exchange Commission (the “SEC”), including Exxon Capital Holdings Corp., SEC No-Action Letter (available April 13, 1989), Morgan Stanley & Co., Inc., SEC No-Action Letter (available June 5, 1991) and Shearman & Sterling, SEC No-Action Letter (available July 2, 1993), that the new notes issued in exchange for the old notes pursuant to the Exchange Offer may be offered for resale, resold and otherwise transferred by holders thereof without compliance with the registration and prospectus delivery provisions of the Securities Act (other than a broker-dealer who purchased old notes exchanged for such new notes directly from the Issuers to resell pursuant to Rule 144A or any other available exemption under the Securities Act and any such holder that is an “affiliate” of the Issuers within the meaning of Rule 405 under the Securities Act), provided that such new notes are acquired in the ordinary course of such holders’ business and such holders are not participating in, and have no arrangement with any other person to participate in, the distribution of such new notes.

5. By tendering old notes in the Exchange Offer, you hereby represent and warrant that:

(a) the new notes acquired pursuant to the Exchange Offer are being obtained in the ordinary course of business of you, whether or not you are the holder;

(b) you are not engaging and do not intend to engage in the distribution of new notes within the meaning of the Securities Act;

(c) you are not an “affiliate,” as such term is defined under Rule 405 promulgated under the Securities Act, of the Issuers; and

(d) if you are a broker-dealer, that you will receive the new notes for your own account in exchange for old notes that were acquired as a result of market-making activities or other trading activities and that you acknowledge that you will deliver a prospectus (or, to the extent permitted by law, make available a prospectus) in connection with any resale of such new notes.

You may, if you are unable to make all of the representations and warranties contained in Item 5 above and as otherwise permitted in the Registration Rights Agreement (as defined below), elect to have your old notes registered in the shelf registration statement described in the Registration Rights Agreement, dated as of October 15, 2012 (the “Registration Rights Agreement”), by and among the Issuers, the several guarantors named therein, and Wells Fargo Securities, LLC, as representative of the Initial Purchasers (as defined therein). Such election may be made by notifying the Issuers in writing at 15021 Katy Freeway, Suite 400, Houston, Texas 77094, Attention: Corporate Secretary. By making such election, you agree, as a holder of old notes participating in a shelf registration, to indemnify and hold harmless the Issuers, each of the directors of the Issuers, each of the officers of the Issuers who sign such shelf registration statement, each person who controls the Issuers within the meaning of either the Securities Act or the Securities Exchange Act of 1934, as amended (the “Exchange Act”), and each other holder of old notes, from and against any and all losses, claims, damages or liabilities caused by any untrue statement or alleged untrue statement of a material fact contained in any shelf registration statement or prospectus, or in any supplement thereto or amendment thereof, or caused by the omission or alleged omission to state therein a material fact required to be stated therein or necessary to make the statements therein, in the light of the circumstances under which they were made, not misleading; but only with respect to information relating to you furnished in writing by or on behalf of you expressly for use in a shelf registration statement, a prospectus or any amendments or supplements thereto. Any such indemnification shall be governed by the terms and subject to the conditions set forth in the Registration Rights Agreement, including, without limitation, the provisions regarding notice, retention of counsel, contribution and payment of expenses set forth therein. The above summary of the indemnification provision of the Registration Rights Agreement is not intended to be exhaustive and is qualified in its entirety by the Registration Rights Agreement.

6. If you are a broker-dealer that will receive new notes for your own account in exchange for old notes that were acquired as a result of market-making activities or other trading activities, you acknowledge by tendering old notes in the Exchange Offer, that you will deliver a prospectus in connection with any resale of such new notes; however, by so acknowledging and by delivering a prospectus, you will not be deemed to admit that you are an “underwriter” within the meaning of the Securities Act.

7. If you are a broker-dealer and old notes held for your own account were not acquired as a result of market-making or other trading activities, such old notes cannot be exchanged pursuant to the Exchange Offer.

8. Any of your obligations hereunder shall be binding upon your successors, assigns, executors, administrators, trustees in bankruptcy and legal and personal representatives.

IMPORTANT: BY USING THE ATOP PROCEDURES TO TENDER OLD NOTES, YOU WILL NOT BE REQUIRED TO DELIVER THIS LETTER OF TRANSMITTAL TO THE EXCHANGE AGENT. HOWEVER, YOU WILL BE BOUND BY ITS TERMS, AND YOU WILL BE DEEMED TO HAVE MADE THE ACKNOWLEDGMENTS AND THE REPRESENTATIONS AND WARRANTIES IT CONTAINS, JUST AS IF YOU HAD SIGNED IT.


	Page
CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS		ii
PROSPECTUS SUMMARY		1
RISK FACTORS		14
EXCHANGE OFFER		35
USE OF PROCEEDS		42
SELECTED HISTORICAL FINANCIAL AND OTHER DATA		43
RATIOS OF EARNINGS TO FIXED CHARGES		44
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS		45
BUSINESS		65
MANAGEMENT		88
THE PARTNERSHIP AGREEMENT		98
SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT		104
CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS		104
DESCRIPTION OF CERTAIN INDEBTEDNESS		106
DESCRIPTION OF NOTES		108
PLAN OF DISTRIBUTION		161
CERTAIN UNITED STATES FEDERAL INCOME TAX CONSIDERATIONS		163
LEGAL MATTERS		163
EXPERTS		163
GLOSSARY OF OIL AND NATURAL GAS TERMS		164
INDEX TO FINANCIAL STATEMENTS		F-1
ANNEX A: LETTER OF TRANSMITTAL		A-1


	Year Ended December 31,
	Total		2012		2013-2014		2015-2016		Thereafter
	(dollars in thousands)
Debt(1)	$	509,701	$	—	$	—	$	188,790	$	320,911

Interest(1)		233,599		34,112		68,224		65,053		66,210
Operating leases		19,706		2,884		4,723		3,206		8,893
Settlement obligations		3,000		1,000		2,000		—		—
Derivative contract premiums(2)		4,312		2,275		1,446		591		—
Abandonment liabilities		46,096		3,030		11,421		2,060		29,585

Total	$	816,414	$	43,301	$	87,814	$	259,700	$	425,599


Property	Total Proved Reserves (Bcfe)		% Proved Developed(1)			Oil and NGLs as % of Total Proved Reserves(1)			PV-10 ($ in (millions)(2)		Net Acreage(3)		Net Producing Wells		Average Daily Net Production (MMcfe/d)		Reserve Life Index (Years)(4)
South Louisiana		73.2		70.0	%		33.2	%	$	289.9		31,879		42.3		30.8		6.5
East Texas		67.8		87.6	%		30.1	%		203.4		47,130		70.0		16.1		11.5
Oklahoma		59.7		70.0	%		73.9	%		207.5		36,179		173.1		5.7		28.8
Hilltop (formerly called Deep Bossier)		85.2		72.5	%		1.1	%		112.3		16,998		15.2		49.4		4.7
Eagle Ford		21.3		44.8	%		91.0	%		130.9		2,933		4.5		4.7		12.3
Other		40.6		69.5	%		52.9	%		126.2		33,657		46.1		7.0		15.8

All Properties		347.8		72.4	%		37.6	%	$	1,070.2		168,776		351.2		113.7		8.4


	As of December 31, 2011
	Oil and NGLs (MMBbls)		Natural Gas (Bcf)
Proved Reserves(1)
Developed		15.1		161.4
Undeveloped		6.7		55.9

Total Proved		21.8		217.3


	% (by Volume)	Principal Properties
Netherland, Sewell & Associates, Inc.	100% audited	All

T. J. Smith & Company, Inc.	93% prepared	All but those prepared by W. D. Von Gonten & Co.

W.D. Von Gonten & Co.	7% prepared	All properties in the Eagle Ford shale play; certain other properties in South Texas; and all properties in the Marcellus Shale.


	Nine Months Ended September 30,						Year Ended December 31,
	2012			2011			2011			2010			2009			2008			2007
	(Unaudited)						(Dollars in thousands)
Statement of Operations Data:
Revenues
Natural gas, oil and natural gas liquids	$	249,121		$	236,964		$	323,911		$	208,537		$	102,263		$	98,983		$	56,746
Other revenues		3,952			1,366			2,127			1,475			1,558			3,629			12,036

		253,073			238,330			326,038			210,012			103,821			102,612			68,782
Unrealized gain (loss) — oil and natural gas derivative contracts		(19,944	)		25,292			28,169			10,088			(26,258	)		60,612			(14,457	)

Total revenues	$	233,129		$	263,622		$	354,207		$	220,100		$	77,563		$	163,224		$	54,325
Costs and expenses:
Lease and plant operating expense		50,833			44,639			62,637			41,905			23,871			20,658			14,642
Production and ad valorem taxes		19,315			15,198			19,357			11,141			4,755			6,954			4,406
Workover expense		8,254			8,391			11,777			7,409			8,988			8,113			7,825
Exploration expense		13,543			12,310			15,785			31,037			12,839			11,675			9,743
Depreciation, depletion, and amortization		76,161			66,187			94,251			59,090			48,659			49,219			31,298
Impairment expense		50,934			16,498			18,735			8,399			6,165			11,487			1,449
Accretion expense		1,339			1,430			1,812			1,370			492			729			627
General and administrative expense		30,195			24,251			33,087			20,135			8,738			6,401			5,321
Gain on sale of assets		—			—			—			(1,766	)		(738	)		—			—

Total expenses		250,574			188,904			257,441			178,720			113,769			115,236			75,311
Income (loss) from operations		(17,445	)		74,718			96,766			41,380			(36,206	)		47,988			(20,986	)

Other income (expense):
Interest expense, net		(29,440	)		(23,067	)		(32,644	)		(27,149	)		(13,831	)		(14,457	)		(10,792	)
Gain on contract settlement		—			—			1,285			—			—			—			—
Litigation settlement		1,250			—			—			—			—			—			—
Gain on extinguishment of debt		—			1,285			—			—			—			3,349			4,302

Total other income (expense)		(28,190	)		(21,782	)		(31,359	)		(27,149	)		(13,831	)		(11,108	)		(6,490	)
(Provision) benefit for state income taxes		—			(150	)		(228	)		(2	)		750			(250	)		(500	)

Net income (loss)	$	(45,635	)	$	52,786		$	65,179		$	14,229		$	(49,287	)	$	36,630		$	(27,976	)

Statement of Cash Flow Data:
Capital expenditures	$	152,125		$	147,989		$	193,770		$	110,083		$	100,261		$	111,096		$	89,604
Net cash flow provided by operating activities		117,851			115,406			150,655			61,185			34,343			20,300			38,618
Net cash used in investing activities(1)		(172,341	)		(214,581	)		(266,133	)		(208,412	)		(86,573	)		(111,096	)		(98,604	)
Net cash provided by financing activities		57,882			98,911			113,272			147,789			51,823			78,771			71,596
Balance Sheet Data (at period end):
Cash and cash equivalents	$	6,022		$	4,572		$	2,630		$	4,836		$	4,274		$	4,681		$	16,706
Property and equipment, net		643,374			571,386			589,167			456,264			236,196			201,327			132,719
Total assets		759,581			703,043			720,083			558,239			290,606			277,111			175,157
Total debt, including Notes to Founder		567,049			492,577			507,947			390,985			219,830			188,228			123,244
Total partners’ capital (deficit)		44,037			77,444			89,672			24,658			10,664			37,751			(11,661	)


	Nine Months Ended September 30, 2012		Year Ended December 31,
			Year Ended December 31,
			2011		2010		2009		2008		2007
Ratio of earnings to fixed charges(1)		—		2.70		1.59		—		5.00		—


	Nine Months Ended September 30,						Increase (Decrease)			% Change
	2012			2011			Increase (Decrease)			% Change
	($ in thousands, except average sales price and unit costs)
Summary Operating Information:
Net Production:
Natural gas (MMcf)		17,144			23,501			(6,357	)		(27	)%
Oil (MBbls)		1,534			1,138			396			35	%
Natural gas liquids (MBbls)		228			155			73			47	%
Total natural gas equivalent (MMcfe)		27,711			31,259			(3,548	)		(11	)%
Average daily gas production (MMcfe per day)		101.1			114.5			(13.4	)		(11	)%
Average Sales Price:
Natural gas (per Mcf) realized	$	4.59		$	4.87		$	(0.28	)		(6	)%
Natural gas (per Mcf) unhedged		2.65			4.15			(1.50	)		(36	)%
Oil (per Bbl) realized		104.38			99.93			4.45			4	%
Oil (per Bbl) unhedged		105.00			103.23			1.77			2	%
Natural gas liquids (per Bbl) realized(1)		45.74			57.38			(11.64	)		(20	)%
Combined (per Mcfe) realized		8.99			7.58			1.41			19	%
Hedging Activities:
Realized natural gas revenue gain	$	33,130		$	16,897		$	16,233			96	%
Realized oil revenue (loss)		(958	)		(3,756	)		2,798			74	%
Summary Financial Information
Revenues
Natural gas	$	78,638		$	114,362		$	(35,724	)		(31	)%
Oil		160,069			113,702			46,367			41	%
Natural gas liquids		10,414			8,900			1,514			17	%
Other revenues		3,952			1,366			2,586			189	%
Unrealized gain (loss) — oil and natural gas derivative contracts		(19,944	)		25,292			(45,236	)		(179	)%

		233,129			263,622			(30,493	)		(12	)%
Expenses
Lease and plant operating expense		50,833			44,639			6,194			14	%
Production and ad valorem taxes		19,315			15,198			4,117			27	%
Workover expense		8,254			8,391			(137	)		(2	)%
Exploration expense		13,543			12,310			1,233			10	%
Depreciation, depletion, and amortization expense		76,161			66,187			9,974			15	%
Impairment expense		50,934			16,498			34,436			209	%
Accretion expense		1,339			1,430			(91	)		(6	)%
General and administrative expense		30,195			24,251			5,944			25	%
Interest expense, net		29,440			23,067			6,373			28	%
Litigation settlement		(1,250	)		—			(1,250	)		NA
(Gain) on contract settlement		—			(1,285	)		1,285			NA
Provision for state income taxes		—			150			(150	)		NA

Net income (loss)	$	(45,635	)	$	52,786		$	(98,421	)		(186	)%

Average Unit Costs per Mcfe:
Lease and plant operating expense	$	1.83		$	1.43		$	0.40			28	%
Production and ad valorem taxes		0.70			0.49			0.21			43	%
Workover expense		0.30			0.27			0.03			11	%
Exploration expense		0.49			0.39			0.10			26	%
Depreciation, depletion and amortization expense		2.75			2.12			0.63			30	%
General and administrative expense		1.09			0.78			0.31			40	%


	Year Ended December 31,						Increase (Decrease)			% Change
	2011			2010			Increase (Decrease)			% Change
	($ in thousands, except average sales price and unit costs)
Summary Operating Information:
Net Production:
Natural gas (MMcf)		30,750			24,026			6,724			28	%
Oil (MBbls)		1,580			964			616			64	%
Natural gas liquids (MBbls)		215			147			68			46	%
Total natural gas equivalent (MMcfe)		41,518			30,694			10,824			35	%
Average daily gas production (MMcfe per day)		113.7			84.1			29.6			35	%
Average Sales Price:
Natural gas (per Mcf) realized	$	4.86		$	5.24		$	(0.38	)		(7	)%
Natural gas (per Mcf) unhedged		4.04			4.27			(0.23	)		(5	)%
Oil (per Bbl) realized		102.35			78.63			23.72			30	%
Oil (per Bbl) unhedged		104.73			78.86			25.87			33	%
Natural gas liquids (per Bbl) realized(1)		58.75			46.58			12.17			26	%
Combined (per Mcfe) realized		7.80			6.79			1.01			15	%
Hedging Activities:
Realized natural gas revenue gain	$	25,208		$	23,206		$	2,002			9	%
Realized oil revenue (loss)		(3,756	)		(224	)		(3,532	)		(1577	)%
Summary Financial Information:
*Revenues*
Natural gas	$	149,580		$	125,866		$	23,714			19	%
Oil		161,726			75,827			85,899			113	%
Natural gas liquids		12,605			6,844			5,761			84	%
Other revenues		2,127			1,475			652			44	%
Unrealized gain — oil and natural gas derivative contracts		28,169			10,088			18,081			179	%
*Costs and Expenses*
Lease and plant operating expense		62,637			41,905			20,732			49	%
Production and ad valorem taxes		19,357			11,141			8,216			74	%
Workover expense		11,777			7,409			4,368			59	%
Exploration expense		15,785			31,037			(15,252	)		(49	)%
Depreciation, depletion, and amortization		94,251			59,090			35,161			60	%
Impairment expense		18,735			8,399			10,336			123	%
Accretion expense		1,812			1,370			442			32	%
General and administrative expense		33,087			20,135			12,952			64	%
(Gain) on sale of assets		—			(1,766	)		1,766			100	%
Interest expense, net		32,644			27,149			5,495			20	%
(Gain) on contract settlement		(1,285	)		—			(1,285	)		NA
Provision for state income taxes		228			2			226			11300	%

Net income	$	65,179		$	14,229		$	50,950			358	%

Average Unit Costs per Mcfe:
Lease and plant operating expense	$	1.51		$	1.37		$	0.14			10	%
Production and ad valorem taxes		0.47			0.36			0.11			31	%
Workover expense		0.28			0.24			0.04			17	%
Exploration expense		0.38			1.01			(0.63	)		(62	)%
Depreciation, depletion, and amortization		2.27			1.93			0.34			18	%
General and administrative expense		0.80			0.66			0.14			21	%


Hilltop Field	Year Ended December 31,
	2011		2010		2009
Net production:
Natural gas (MMcf)		18,043		12,263		3,950
Oil (MBbls)		—		—		—
Natural gas liquids (MBbls)		—		—		—
Total (Mcfe)		18,043		12,263		3,950
Average sales price per unit after hedging effects:
Natural gas (per Mcf)	$	3.78	$	4.01	$	3.08
Average production costs per Mcfe:
Lease and plant operating expense	$	0.91	$	0.85	$	0.27
Production and ad-valorem taxes		0.08		0.13		0.11
Depreciation, depletion and amortization		1.54		1.11		1.08


	December 31, 2011
	Gross		Net
Oil wells:
South Louisiana		31		23.2
East Texas		32		8.6
Oklahoma		228		171.1
Hilltop (formerly called Deep Bossier)		—		—
Eagle Ford		22		4.4
Other		29		18.8

All properties		342		226.1

Natural gas wells:
South Louisiana		30		19.1
East Texas		100		61.4
Oklahoma		7		2.0
Hilltop (formerly called Deep Bossier)		58		15.2
Eagle Ford		1		0.1
Other		74		27.3

All properties		270		125.1


	Developed Acres				Undeveloped Acres				Total Acres
Property:	Gross		Net		Gross		Net		Gross		Net
South Louisiana		28,325		20,498		26,400		11,381		54,725		31,879
East Texas		38,284		22,455		41,302		24,675		79,586		47,130
Oklahoma		55,312		36,179		—		—		55,312		36,179
Hilltop (formerly called Deep Bossier)		16,450		5,445		33,560		11,553		50,010		16,998
Eagle Ford		4,863		880		11,348		2,053		16,211		2,933
Other		55,484		18,670		48,070		14,987		103,554		33,657

All properties		198,718		104,127		160,680		64,649		359,398		168,776


	2012				2013				2014
Property:	Gross		Net		Gross		Net		Gross		Net
South Louisiana		8,812		3,804		5,690		2,402		3,986		1,651
East Texas		10,543		5,189		8,411		5,030		4,225		1,934
Oklahoma		—		—		—		—		—		—
Hilltop (formerly called Deep Bossier)		11,186		3,851		7,458		2,567		4,972		1,712
Eagle Ford		3,782		684		2,522		456		1,681		304
Other		12,089		2,873		8,146		2,002		6,059		1,962

All properties		46,412		16,401		32,227		12,457		20,923		7,563


Name	Age		Director Since		Position
Harlan H. Chappelle		55		2005	President, Chief Executive Officer and Director
Michael E. Ellis		55		1987	Founder, Chairman, Vice President of Engineering and Chief Operating Officer
Mickey Ellis		53		1987	Director
Michael A. McCabe		56		—	Vice President and Chief Financial Officer
F. David Murrell		50		—	Vice President, Land and Business Development


Name and Principal Position	Year		Salary		Bonus(1)		All Other Compensation			Total
Harlan H. Chappelle		2011	$	450,000	$	900,000	$	29,586	(2)	$	1,379,586
President, Chief Executive Officer		2010	$	450,000	$	900,000	$	18,639	(2)	$	1,368,639

Michael E. Ellis		2011	$	450,000	$	500,000	$	27,989	(3)	$	977,989
Chief Operating Officer, Vice President of Engineering, and Chairman of the Board		2010	$	450,000	$	500,000	$	26,429	(3)	$	976,429

Michael A. McCabe		2011	$	350,000	$	500,000	$	76,401	(4)	$	926,401
Vice President, Chief Financial Officer		2010	$	350,000	$	500,000	$	88,016	(4)	$	938,016

David Murrell		2011	$	300,000	$	225,000	$	24,027	(5)	$	549,027
Vice President of Land and Business Development		2010	$	273,750	$	200,000	$	8,250	(5)	$	482,000


Name of Beneficial Owner(1)	Percentage of Class A Limited Partnership Interests Beneficially Owned			Percentage of Class B Limited Partnership Interests Beneficially Owned
Alta Mesa Investment Holdings Inc.(2)		—			100.0	%
Macquarie Bank Limited(3)		5.0	%		—
RBS Equity Corporation(4)		5.0	%		—
Michael E. Ellis(5)		84.5	%		—
Mickey Ellis(6)		—			—
Harlan H. Chappelle		5.0	%		—
Michael A. McCabe		—			—
David Murrell		—			—
Directors and principal officers as a group (5 persons)		89.5	%		—


Year	Percentage
2014		104.813	%
2015		102.406	%
2016 and thereafter		100.000	%


	Page
Audited Financial Statements
Report of Independent Registered Public Accounting Firm		F-2
Consolidated Balance Sheets		F-3
Consolidated Statements of Operations		F-4
Consolidated Statements of Changes in Partners’ Capital		F-5
Consolidated Statements of Cash Flows		F-6
Notes to Consolidated Financial Statements		F-7

Unaudited Financial Statements
Consolidated Balance Sheets		F-31
Consolidated Statements of Income		F-32
Consolidated Statements of Cash Flows		F-33
Notes to Consolidated Financial Statements		F-34

Audited Financial Statements (Meridian)
Report of Independent Registered Public Accounting Firm		F-49
Consolidated Statements of Operations		F-50
Consolidated Balance Sheets		F-51
Consolidated Statements of Cash Flows		F-52
Consolidated Statements of Stockholders’ Equity		F-53
Consolidated Statements of Comprehensive Income (Loss)		F-54
Notes to Consolidated Financial Statements		F-55

Audited Financial Statements (Sydson Acquisition)
Independent Auditors’ Report		F-94
Statements of Revenues and Direct Operating Expenses		F-95
Notes to Statements of Revenues and Direct Operating Expenses		F-96

Audited Financial Statements (TODD Acquisition)
Independent Auditors’ Report		F-99
Statements of Revenues and Direct Operating Expenses		F-100
Notes to Statements of Revenues and Direct Operating Expenses		F-101


	December 31,
	2011		2010
	(dollars in thousands)
ASSETS
CURRENT ASSETS
Cash and cash equivalents	$	2,630	$	4,836
Accounts receivable, net		40,807		38,081
Other receivables		2,806		6,338
Prepaid expenses and other current assets		5,394		2,292
Derivative financial instruments		28,582		10,436

TOTAL CURRENT ASSETS		80,219		61,983

PROPERTY AND EQUIPMENT
Oil and natural gas properties, successful efforts method, net		572,816		442,880
Other property and equipment, net		16,351		13,384

TOTAL PROPERTY AND EQUIPMENT, NET		589,167		456,264

OTHER ASSETS
Investment in Partnership — cost		9,000		9,000
Deferred financing costs, net		12,802		13,552
Derivative financial instruments		24,244		14,165
Advances to operators		3,625		2,699
Deposits and other assets		1,026		576

TOTAL OTHER ASSETS		50,697		39,992

TOTAL ASSETS	$	720,083	$	558,239

LIABILITIES AND PARTNERS’ CAPITAL
CURRENT LIABILITIES
Accounts payable and accrued liabilities	$	70,295	$	87,255
Current portion, asset retirement obligations		3,030		1,617
Derivative financial instruments		1,300		3,092

TOTAL CURRENT LIABILITIES		74,625		91,964

LONG-TERM LIABILITIES
Asset retirement obligations, net of current portion		43,066		41,096
Long-term debt		487,036		371,276
Notes payable to founder		20,911		19,709
Derivative financial instruments		57		2,296
Other long-term liabilities		4,716		7,240

TOTAL LONG-TERM LIABILITIES		555,786		441,617

TOTAL LIABILITIES		630,411		533,581
COMMITMENTS AND CONTINGENCIES (NOTE 11)

PARTNERS’ CAPITAL		89,672		24,658

TOTAL LIABILITIES AND PARTNERS’ CAPITAL	$	720,083	$	558,239


BALANCE, DECEMBER 31, 2008	$	37,751
CONTRIBUTIONS		27,800
DISTRIBUTIONS		(100	)
REDEMPTION OF PARTNERSHIP INTEREST		(5,500	)
NET LOSS		(49,287	)

BALANCE, DECEMBER 31, 2009		10,664
CONTRIBUTIONS		50,000
DISTRIBUTIONS		(50,235	)
NET INCOME		14,229

BALANCE, DECEMBER 31, 2010		24,658
DISTRIBUTIONS		(165	)
NET INCOME		65,179

BALANCE, DECEMBER 31, 2011	$	89,672


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

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


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

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


	(Unaudited)
	Revenue		Income (Loss)
	(dollars in thousands)
Actual results of Meridian included in our statement of operations for the year ended December 31, 2011	$	135,670	$	54,515
Actual results of Sydson included in our statement of operations for the period April 21, 2011 through December 31, 2011	$	7,698	$	2,656
Actual results of TODD included in our statement of operations for the period June 17, 2011 through December 31, 2011	$	2,909	$	159
Pro forma results for the combined entity for the year ended December 31, 2011	$	357,401	$	67,132
Pro forma results for the combined entity for the year ended December 31, 2010	$	258,008	$	17,693


	Level 1		Level 2		Level 3		Total
	(dollars in thousands)
*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
*At December 31, 2010:*
Financial Assets:
Derivative contracts for oil and natural gas		—	$	61,623		—	$	61,623
Financial Liabilities:
Derivative contracts for oil and natural gas		—	$	37,022		—	$	37,022
Derivative contracts for interest rate		—	$	5,388		—	$	5,388


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 natural gas commodity contracts, assets	$	56,716		$	—		$	52,422		$	—
Fair value of oil and natural 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	)


	Location of Gain (Loss)	Classification of Gain (Loss)	Years Ended December 31,
Derivatives not designated as hedging instruments under ASC 815	Location of Gain (Loss)	Classification of Gain (Loss)	2011			2010			2009
			(dollars in thousands)
Natural gas commodity contracts	Natural gas revenues	Realized	$	25,208		$	23,206		$	26,835
Oil commodity contracts	Oil revenues	Realized		(3,756	)		(224	)		4,397
Interest rate contracts	Interest expense	Realized		1,363			(4,380	)		(2,967	)

Total realized gains (losses) from derivatives not designated as hedges			$	22,815		$	18,602		$	28,265

Natural gas commodity contracts	Unrealized gain (loss) — oil and natural gas derivative contracts	Unrealized	$	21,937		$	17,066		$	(3,579	)
Oil commodity contracts	Unrealized gain (loss) — oil and natural gas derivative contracts	Unrealized		6,232			(6,978	)		(22,679	)
Interest rate contracts	Interest expense	Unrealized		4,088			886			950

Total unrealized gains (losses) from derivatives not designated as hedges			$	32,257		$	10,974		$	(25,308	)


	Volume in MMbtu		Weighted Average		Range
Period and Type of Contract	Volume in MMbtu		Weighted Average		High		Low
2012
Price Swap Contracts		13,930,000	$	5.20	$	8.83	$	3.99
Collar Contracts
Short Call Options		8,935,000		5.56		6.00		4.50
Long Put Options		4,350,000		5.93		6.75		5.50

Long Call Options		5,035,000		4.73		5.00		4.00
Short Put Options		11,185,000		4.03		4.50		3.55

2013
Price Swap Contracts		14,862,500		5.14		9.15		3.99
Collar Contracts
Short Call Options		3,325,000		5.81		6.50		5.25
Long Put Options		1,500,000		6.09		6.15		6.00

Long Call Options		1,825,000		4.75		4.75		4.75
Short Put Options		2,725,000		4.30		5.00		3.95

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


	Volume in Bbls		Weighted Average		Range
Period and Type of Contract	Volume in Bbls		Weighted Average		High		Low
2012
Price Swap Contracts		36,600	$	80.20	$	80.20	$	80.20
Collar Contracts
Short Call Options		1,719,496		118.91		132.00		100.00
Long Put Options		1,422,618		98.42		105.00		65.00

Long Call Options		229,144		103.78		123.50		90.20
Short Put Options		1,494,008		78.81		85.00		60.00

2013
Price Swap Contracts		392,000		89.75		94.74		77.00
Collar Contracts
Short Call Options		496,410		111.83		123.90		90.00
Long Put Options		388,000		91.65		95.00		85.00

Long Call Options		124,475		95.19		127.00		79.00
Short Put Options		653,000		69.71		75.00		60.00

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

Short Put Options		488,450		65.33		70.00		60.00

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

Short Put Options		319,350		66.86		70.00		60.00

2016
Price Swap Contracts
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


Volume in MMbtu	Reference Price		Period		Spread ($ per MMbtu)
1,830,000		Houston Ship Channel		Jan’12 — Dec’12		(0.1575	)
3,660,000		Houston Ship Channel		Jan’12 — Dec’12		(0.1400	)


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


Year Ending December 31,
2012		—
2013		—
2014		—
2015		—
2016	$	188,790
Thereafter		320,911

	$	509,701


	Quarter Ended
2011	March 31			June 30		Sept. 30		Dec. 31
	(dollars in thousands)
Revenues	$	51,916		$	95,544	$	116,164	$	90,583
Results of operations from exploration and production activities(1)		22,247			25,647		25,783		28,007
Net income (loss)	$	(12,166	)	$	25,560	$	39,392	$	12,393


	Oil (MBbls)			Gas (MMcf)			NGL (MBbls)(1)
Total Proved Reserves:
Balance at December 31, 2008		5,674			87,186			—
Production during 2009		(552	)		(10,610	)		—
Purchases in place(2)		1			85,786			—
Discoveries and extensions		462			26,292			—
Revisions of previous quantity estimates and other		2,910			(5,549	)		—

Balance at December 31, 2009		8,495			183,105			—
Production during 2010		(964	)		(24,026	)		(147	)
Purchases in place(3)		5,301			49,217			660
Discoveries and extensions		3,306			24,022			207
Revisions of previous quantity estimates and other		(3,951	)		9,135			1,015

Balance at December 31, 2010		12,187			241,453			1,735
Production during 2011		(1,580	)		(30,750	)		(215	)
Purchases in place(4)		674			10,385			100
Discoveries and extensions		4,436			24,142			544
Revisions of previous quantity estimates and other		1,216			(27,964	)		2,681

Balance at December 31, 2011		16,933			217,266			4,845

Proved Developed Reserves:
Balance at December 31, 2008		4,453			64,870			—
Balance at December 31, 2009		6,978			101,082			—
Balance at December 31, 2010		7,867			159,226			1,301
Balance at December 31, 2011		11,484			161,395			3,616


	At December 31,
	2011			2010			2009
	(dollars in thousands)
Future cash flows	$	2,850,381		$	2,060,794		$	1,154,974
Future production costs		(803,290	)		(618,319	)		(360,639	)
Future development costs		(297,375	)		(255,128	)		(148,097	)
Future taxes on income		—			—			—

Future net cash flows		1,749,716			1,187,347			646,238
Discount to present value at 10 percent per annum		(679,520	)		(482,165	)		(307,941	)

Standardized measure of discounted future net cash flows	$	1,070,196		$	705,182		$	338,297

Base price for natural gas, per Mcf, in the above computations was:	$	4.12		$	4.38		$	3.87
Base price for crude oil, per Bbl, in the above computations was:	$	96.19		$	79.43		$	61.18


	September 30, 2011		December 31, 2010
	(unaudited)
ASSETS
CURRENT ASSETS
Cash and cash equivalents	$	4,572	$	4,836
Accounts receivable, net		42,888		38,081
Other receivables		2,697		6,338
Prepaid expenses and other current assets		3,725		2,292
Derivative financial instruments		25,787		10,436

TOTAL CURRENT ASSETS		79,669		61,983

PROPERTY AND EQUIPMENT
Oil and natural gas properties, successful efforts method, net		555,357		442,880
Other property and equipment, net		16,029		13,384

TOTAL PROPERTY AND EQUIPMENT, NET		571,386		456,264

OTHER ASSETS
Investment in Partnership — cost		9,000		9,000
Deferred financing costs, net		12,898		13,552
Derivative financial instruments		24,106		14,165
Advances to operators		4,088		2,699
Deposits		1,896		576

TOTAL OTHER ASSETS		51,988		39,992

TOTAL ASSETS	$	703,043	$	558,239

LIABILITIES AND PARTNERS’ CAPITAL
CURRENT LIABILITIES
Accounts payable and accrued liabilities	$	79,318	$	87,255
Current portion, asset retirement obligations		3,418		1,617
Derivative financial instruments		1,959		3,092

TOTAL CURRENT LIABILITIES		84,695		91,964

LONG-TERM LIABILITIES
Asset retirement obligations		43,275		41,096
Long-term debt		471,971		371,276
Notes payable to founder		20,606		19,709
Derivative financial instruments		—		2,296
Other long-term liabilities		5,052		7,240

TOTAL LONG-TERM LIABILITIES		540,904		441,617

TOTAL LIABILITIES		625,599		533,581
COMMITMENTS AND CONTINGENCIES (NOTE 10)
PARTNERS’ CAPITAL		77,444		24,658

TOTAL LIABILITIES AND PARTNERS’ CAPITAL	$	703,043	$	558,239