Alta Mesa Holdings, LP - FORM 10-K

Alta Mesa Holdings, LP - FORM 10-K - March 29, 2012

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EXCEL - IDEA: XBRL DOCUMENT - Alta Mesa Holdings, LP	Financial_Report.xls
EX-23.4 - CONSENT OF W. D. VON GONTEN & CO. - Alta Mesa Holdings, LP	d268408dex234.htm
EX-99.1 - AUDIT REPORT BY NETHERLAND, SEWELL & ASSOCIATES, INC. - Alta Mesa Holdings, LP	d268408dex991.htm
EX-23.1 - CONSENT OF UHY LLP. - Alta Mesa Holdings, LP	d268408dex231.htm
EX-32.2 - CERTIFICATION OF THE COMPANY'S CHIEF FINANCIAL OFFICER PURSUANT TO SECTION 906 - Alta Mesa Holdings, LP	d268408dex322.htm
EX-31.1 - CERTIFICATION OF THE COMPANY'S CHIEF EXECUTIVE OFFICER PURSUANT TO SECTION 302 - Alta Mesa Holdings, LP	d268408dex311.htm
EX-99.3 - RESERVE REPORT BY W. D. VON GONTEN & CO. - Alta Mesa Holdings, LP	d268408dex993.htm
EX-32.1 - CERTIFICATION OF THE COMPANY'S CHIEF EXECUTIVE OFFICER PURSUANT TO SECTION 906 - Alta Mesa Holdings, LP	d268408dex321.htm
EX-23.3 - CONSENT OF T. J. SMITH & COMPANY, INC. - Alta Mesa Holdings, LP	d268408dex233.htm
EX-23.2 - CONSENT OF NETHERLAND, SEWELL & ASSOCIATES, INC. - Alta Mesa Holdings, LP	d268408dex232.htm
EX-21.1 - SUBSIDIARIES - Alta Mesa Holdings, LP	d268408dex211.htm
EX-99.2 - RESERVE REPORT BY T. J. SMITH & COMPANY, INC. - Alta Mesa Holdings, LP	d268408dex992.htm
EX-31.2 - CERTIFICATION OF THE COMPANY'S CHIEF FINANCIAL OFFICER PURSUANT TO SECTION 302 - Alta Mesa Holdings, LP	d268408dex312.htm

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, DC 20549

FORM 10-K

(Mark One)

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

For the annual period ended: December 31, 2011

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

For the transition period from to

Commission file number: 333-173751

ALTA MESA HOLDINGS, LP

(Exact name of registrant as specified in its charter)


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

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

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

Securities registered pursuant to Section 12(b) of the Act:

None

Securities registered pursuant to Section 12(g) of the Act:

None

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act: ¨ Yes x No

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act: ¨ Yes x No

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

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

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (S229.405 of this chapter) is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. x

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

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

TABLE OF CONTENTS


		Page
	PART I
Item 1.	Business		3
Item 1A.	Risk Factors		25
Item 1B.	Unresolved Staff Comments		41
Item 2.	Properties		41
Item 3.	Legal Proceedings		41
Item 4.	Mine Safety Disclosures		42

	PART II

Item 5.	Market For Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities		42
Item 6.	Selected Financial Data		44
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations		45
Item 7A.	Quantitative and Qualitative Disclosures about Market Risk		59
Item 8.	Financial Statements and Supplementary Data		61
Item 9.	Changes in and Disagreements With Accountants on Accounting and Financial Disclosure		61
Item 9A.	Controls and Procedures		61
Item 9B.	Other Information		61
	PART III
Item 10.	Directors, Executive Officers and Corporate Governance		61
Item 11.	Executive Compensation		64
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters		71
Item 13.	Certain Relationships and Related Transactions, and Director Independence		72
Item 14.	Principal Accountant Fees and Services		73
	PART IV
Item 15.	Exhibits and Financial Statement Schedules		74

CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS

The information in this report includes “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended (the “Securities Act”), and Section 21E of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). All statements, other than statements of historical fact included in this report, regarding our strategy, future operations, financial position, estimated revenues and losses, projected costs, prospects, plans and objectives of management are forward-looking statements. When used in this report, the words “could”, “should”, “will”, “play”, “believe”, “anticipate”, “intend”, “estimate”, “expect”, “project” and similar expressions are intended to identify forward-looking statements, although not all forward-looking statements contain such identifying words. These forward-looking statements are based on our current expectations and assumptions about future events and are based on currently available information as to the outcome and timing of future events. When considering forward-looking statements, you should keep in mind the risk factors and other cautionary statements described under the heading “Risk Factors” included in this report. These forward-looking statements are based on management’s current belief, based on currently available information, as to the outcome and timing of future events.

Forward-looking statements may include statements about our:

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business strategy;

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reserves;

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

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realized oil and natural gas prices;

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

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hedging strategy and results;

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future drilling plans;

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competition and government regulations;

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marketing of oil and natural gas;

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leasehold or business acquisitions;

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costs of developing our properties;

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general economic conditions;

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credit markets;

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liquidity and access to capital;

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uncertainty regarding our future operating results; and

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

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

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 report occur, or should underlying assumptions prove incorrect, our actual results and plans could differ materially from those expressed in any forward-looking statements.

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

PART I

Item 1. Business

Our Company

Alta Mesa Holdings, LP (“Alta Mesa,” the “Company,” “us,” “our,” or “we”) is a privately held company engaged primarily 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 lower risk properties in plays with known resources 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 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 scientific staffs and we have the ability to control the drilling schedule and determine 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.

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 in October 2010 of $300 million principal amount of our senior secured notes due October 15, 2018 (“senior 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.

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.

Meridian Acquisition

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 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% and achieved a more balanced portfolio mix by increasing our total proved oil reserves by 69%. We also believe the acquisition affords us significant growth potential by increasing our proved undeveloped reserves and adding 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.

Sydson Acquisition

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

TODD Acquisition

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

Hilltop Field Acquisition

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 Strategy

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.

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Exploit Known Resources in a Repeatable Manner. The majority of our assets are in mature fields previously developed by major oil and natural gas companies or other independent producers, prior to the advent of newer technology that can be applied today. We seek to enhance existing production in these properties by using our engineering and geological expertise to convert PDNP and PUD reserves to the PDP reserve category while creating repeatable efficiencies to lower operating and capital costs. We intend to concentrate our efforts in areas where we can leverage previous experience and knowledge to continually improve our operations and guide our future development and expansion.

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Maximize Development Opportunities with Sound Engineering and Technology. We seek to exploit and redevelop mature properties by using state-of-the-art technology including 2-D and 3-D seismic imaging and advanced seismic modeling. We apply sound engineering and geologic science, including modern well log analysis and advanced fracture stimulation design, to define the appropriate application of various recovery techniques, including recompletions, infill/step out drilling, horizontal drilling, and/or secondary recovery methods to enhance oil and natural gas production. Our geologists, geophysicists, engineers, and petrophysicists systematically integrate reservoir performance data with geologic and geophysical data, an approach that reduces drilling risks, lowers finding costs and provides for more efficient production of oil and natural gas from our properties.

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Create High-Potential, High-Impact Opportunities while Mitigating Exploration Risk. We target high impact prospects that offer an opportunity to significantly grow reserves. We minimize exploration risk by obtaining and synthesizing engineering, geologic, and seismic data to create a robust knowledge of producing zones in and around our prospective areas. We seek multiple targets in a given exploratory well to maximize and prolong the impact of our capital spending, and seek exploration opportunities that will, upon success, lead to multiple development wells. We diversify our risk across a number of prospects and further mitigate risk by typically bringing in industry partners to participate in our exploration prospects.

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Optimize Production Mix Based on Market Conditions. Our diversified asset base enables us to efficiently and rapidly adjust our development activity in response to market prices. Currently, we intend to take advantage of the favorable oil price environment by continuing to exploit oil and natural gas liquids opportunities within our portfolio. Oil and natural gas liquids together represent 26% of our 2011 production, measured on the traditional energy content ratio of 6:1 between natural gas and crude oil. However, 54% of our products revenues came from oil and natural gas liquids for the year ended December 31, 2011. Oil and liquids-rich gas opportunities represented approximately 67% of our 2011 capital budget and represent approximately 92% of our 2012 capital budget. Commodity mix will be a key consideration as we evaluate future drilling and acquisition opportunities.

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Pursue Value-Based Acquisitions that Leverage Current Internal Knowledge. We continually review opportunities to acquire producing properties, leasehold acreage and drilling prospects. We pursue acquisition targets where our own field exploitation methods can be profitably employed, and identify properties that other energy companies may consider lower-valued and/or non-strategic. While we are biased toward acquisitions that leverage our local knowledge and proprietary field exploitation methods to obtain readily executable opportunities, we consider acquisitions that can provide geographic and geological diversity to mitigate market, weather and other risks. While we prefer to control operations, we also engage in partnerships with other capable operators and service providers so we can capitalize on their data, knowledge and access to equipment.

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Mitigate Commodity Price Risk. Due to the volatility of oil and natural gas prices, we periodically enter into derivative transactions for a portion of our oil and natural gas production. This allows us to reduce exposure to low prices and achieve more predictable cash flows. We retain commodity price upside potential through active management of our portfolio of derivative transactions, as well as through future production and reserve growth. As of December 31, 2011, we have hedged approximately 73% of our forecasted PDP production through 2016 at average annual prices ranging from $4.88 per MMBtu to $6.13 per MMBtu and $85.81 per Bbl to $97.96 per Bbl.

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Maintain Financial Flexibility. In order to maintain our financial flexibility, we plan to fund our 2012 capital budget predominantly with cash flow from operations. Our operational control enables us to manage the timing of a substantial portion of our capital investments. At December 31, 2011, under our senior secured revolving credit facility, we had $189 million in borrowings outstanding and $136 million available for borrowing.

Our Strengths

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:

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Proven Track Record of Reserves and Production Growth. 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 and strategic acquisitions largely in our core areas. Based on our long-term historical performance and our business strategy, we believe we have the opportunities, experience and knowledge to continue growing both our reserves and production.

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High Quality Portfolio of Under-Exploited Properties and Multi-Year, Low-Risk Drilling and Wellbore Utilization Inventory. The bulk of our assets are producing properties with significant opportunities for additional exploitation and exploration. We have created and expect to maintain a multi-year drilling inventory and a continuing program of well recompletions, typically to shallower productive zones as deeper formations deplete over time. As of December 31, 2011, our inventory of proved reserve projects consists of 238 PDNP opportunities, 118 of which are recompletions in East Texas, and 108 PUD locations, including 14 PUD locations in Hilltop Field and 24 PUD locations in Eagle Ford Shale. We believe that we have significant additional development opportunities that are not classified as proved reserves. By targeting productive zones in multiple stacked pays we are able to minimize exploration risk and costs.

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Geographically and Geologically Diverse Asset Base. We have a balanced portfolio of low-risk conventional and high-impact resource assets across various historically productive basins. Our core assets are located in the Hilltop field in East Texas, where the Deep Bossier is a prolific natural gas sand formation, and we believe prospective potential exists in the shallower, oil-prone zones including the Woodbine and Austin Chalk; in other East Texas legacy fields with condensate-rich gas; in South Texas, where our Eagle Ford Shale assets are an oil and liquids-rich gas resource; in South Louisiana, where our most significant field is Weeks Island, a large oil field with multiple stacked pay sands; and in Oklahoma, where our assets are predominantly shallow-decline, long-lived oil fields, which we believe have additional prospective potential in the Mississipian Lime formation. Our core properties are located in areas that benefit from an experienced and well-established service sector, efficient state regulation, and readily available midstream infrastructure and services. In addition, based on our reserve report as of December 31, 2011, approximately 71% of our total future net undiscounted revenues are expected to be generated from the production of proved oil and NGL reserves. We believe our geographic and geologic diversification enables us to allocate our capital more profitably, manage market, weather and regulatory risks, and capitalize on technological improvements.

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Operational Control and Low Cost Structure. We maintain operational control in properties holding approximately 94% of the PV-10 value of our proved reserves, excluding our Hilltop Field and Eagle Ford Shale assets, which include approximately 23% of the PV-10 value of our proved reserves and where EnCana and Murphy Oil, respectively, are the principal operators. This control allows us to more effectively manage

production, control operating costs, allocate capital and control the timing of field development. Where we are not the operator, the Operating Agreements which govern field activity provide us with substantial rights that allow us to protect our interests, including the right to non-consent well proposals and/or make alternate well proposals. We have achieved low average finding and development costs (all sources) of $2.17 per Mcfe for the three years ended December 31, 2011.

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Strong Management Team and Seasoned Technical Expertise. We have an experienced and technically-adept management team, averaging more than 25 years of industry experience among our top eight executives. We have built a strong technical staff of geologists and geophysicists, field operations managers, and engineers in all relevant disciplines. Our engineers and operations staff typically began their careers with major oil companies, large independent producers, or leading service companies, and have direct experience in our areas of operation. We believe our engineers are among the best in their respective fields.

Reserve and Production Overview

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


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

(1)	Computed as a percentage of total reserves of the property.

(2)	Based on unweighted average prices as of the first of each month during the 12 months ended December 31, 2011 of $96.19 per Bbl and $4.118 per MMBtu.

(3)	Includes developed and undeveloped acreage.

(4)	Calculated by dividing total proved reserves as of December 31, 2011 by average daily net production for 2011.

Our Properties

Our core properties are located in South Louisiana, East Texas, Oklahoma, and the Eagle Ford Shale 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.

South Louisiana

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.

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. Since mid-2011 we have continuously employed one drilling rig and one completion rig in Weeks Island to exploit its potential for development through sidetracking, new drilling and recompletions. We expect to continue to actively exploit this field in 2012. 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.

East Texas

Our operations in this area are low-risk expansions of well-established natural gas 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. We completed the first-ever 3-D survey over the Urbana structure in late 2009, which identified a new fault block and an additional horizon for future exploration. We drilled eight successful wells in 2010 and 2011, and plan to extend the field to the north and south as the next step in its development.

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.

Oklahoma

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 pilot-testing waterflooding in both Lincoln North and Lincoln Southeast.

Hilltop Field

Our Hilltop Field, 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. 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. Our highest production (net to our interest) from this field occurred in mid-2011 at approximately 58,000 Mcf per day and decreased to approximately 37,000 Mcf per day by the end of the year. 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. The decrease in production reflects a decrease in continued Deep Bossier drilling as well as natural decline.

During 2012 we will target the Woodbine and Austin Chalk formations for oil exploration using horizontal drilling. These formations are located at a depth of approximately 7,000 feet in the Hilltop area, above the Deep Bossier and Knowles formations. The formations have historically been productive of oil in this area, although at December 31, 2011 we did not have any material proved reserves in the Hilltop Field from the Woodbine or Austin Chalk formations. We are participating with EnCana in three Woodbine wells currently nearing completion. The completions of the Woodbine wells are designed to fracture stimulate the Eagle Ford Shale in which the Woodbine sands exist. We operated our first well in the Hilltop Field when we spudded a horizontal Austin Chalk well in late 2011. This well was completed as a successful well in early 2012.

Other shallower formations in the area that we believe have oil potential include the Pettet, James Lime, Glen Rose, and Buda formations. It is possible that the acreage that we believe is prospective in each of these formations may change, perhaps materially, as additional exploration and discovery efforts are conducted in these areas. Deeper formations that we believe have natural gas potential include the Knowles Lime, Bossier Shale, and Travis Peak.

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, and Alta Mesa operating one new well. We expect to act as operator on new drilling in 2012. 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. Our interests in this area include 58 producing wells, nine PDNP opportunities, and 14 PUD locations, as of December 31, 2011.

South Texas Eagle Ford Shale

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. The wells are primarily operated by Murphy Oil, which has a 120 well development program with the potential of down-spacing and has dedicated up to three drilling rigs, a fully-equipped hydraulic fracturing crew, and a coil tubing unit to the area for the next two years.

Other Assets

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, three vertical wells and two horizontal wells.

Our Oil and Natural Gas Reserves

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


	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

(1)

Our proved reserves as of December 31, 2011 were calculated using oil and natural gas price parameters established by current SEC guidelines and accounting rules based on average prices as of the first day of each of the twelve 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. See “Note 19 — Supplemental Oil and Natural Gas Disclosures” in the accompanying Notes to Consolidated Financial Statements included elsewhere in this report for information concerning proved reserves.

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.

Internal Control and Qualifications

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:

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over 30 years of practical experience in petroleum engineering, including the estimation and evaluation of reserves;

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Bachelor of Science degree in Civil Engineering; and

•

member in good standing of the Society of Petroleum Engineers.

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:

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no employee’s compensation is tied to the amount of reserves booked;

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we follow comprehensive SEC-compliant internal policies to determine and report proved reserves;

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reserve estimates are made by experienced reservoir engineers or under their direct supervision;

•

each quarter, our Chief Operating Officer and Chief Executive Officer review all significant reserves changes and all new proved undeveloped reserves additions.

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.


	% (by Volume)		Principal Properties
Netherland, Sewell & Associates, Inc.		100% audited	All

T. J. Smith & Company, Inc.		97% prepared	All but those prepared by W. D. Von Gonten & Co.

W.D. Von Gonten & Co.		3% prepared	All properties in the Eagle Ford shale play; certain other properties in South Texas; and all properties in the Marcellus Shale.

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.

Netherland, Sewell & Associates, Inc.:

•

over 30 years of practical experience in petroleum engineering and in the estimation and evaluation of reserves

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a Registered Professional Engineer in the state of Texas

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Bachelor of Science Degree in Mechanical Engineering

T. J. Smith & Company, Inc.:

•

over 40 years of practical experience in petroleum engineering, with 35 years in the estimation and evaluation of reserves

•

a Registered Professional Engineer in the states of Texas and Louisiana

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Member of the Society of Petroleum Engineers

•

Bachelor of Science Degree in Petroleum Engineering

W.D. Von Gonten & Co.:

•

over 22 years of practical experience in petroleum geology and in the estimation and evaluation of reserves

•

a Registered Professional Engineer in the state of Texas

•

Member of the Society of Petroleum Engineers

•

Bachelor of Science Degree in Petroleum Engineering

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.

Proved Undeveloped Reserves

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.

Production, Price and Production Cost History

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.


	Year Ended December 31,
	2011		2010		2009
Net production:
Natural gas (MMcf)		30,750		24,026		10,610
Oil (MBbls)		1,580		964		505
Natural gas liquids (MBbls)		215		147		47
Total (Mcfe)		41,518		30,694		13,919
Average sales price per unit before hedging effects:
Natural gas (per Mcf)	$	4.04	$	4.27	$	3.72
Oil (per Bbl)		104.73		78.86		59.23
Natural gas liquids (per Bbl)		58.75		46.58		36.05
Combined (per Mcfe)		7.29		6.05		5.10
Average sales price per unit after hedging effects:
Natural gas (per Mcf)	$	4.86	$	5.24	$	6.25
Oil (per Bbl)		102.35		78.63		67.94
Natural gas liquids (per Bbl)		58.75		46.58		36.05
Combined (per Mcfe)		7.80		6.79		7.35
Average production costs per Mcfe:
Lease and plant operating expense	$	1.51	$	1.37	$	1.71
Production and ad-valorem taxes		0.47		0.36		0.34
Workover expense		0.28		0.24		0.65
Depreciation, depletion and amortization		2.27		1.93		3.50
General and administrative		0.80		0.66		0.63

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:


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

Drilling Activity

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.


	Year Ended December 31,
	2011		2010		2009
Development wells (net):
Productive		28.3		17.69		12.2
Dry		0.2		—		0.6

Total development wells		28.5		17.69		12.8

Exploratory wells (net):
Productive		3.3		3.82		2.7
Dry		1.9		4.30		0.3

Total exploratory wells		5.2		8.12		3.0

Present Activities

As of December 31, 2011, we were drilling 14 gross (5.6 net) wells.

Productive Wells

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:


	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

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

Developed and Undeveloped Acreage Position

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:


	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

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.

Undeveloped Acreage Expirations

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:


	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

Marketing and Customers

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.

Competition

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.

Employees

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 “Item 13. Certain Relationships and Related Party Transactions, and Director Independence — Shared Services and Expenses Agreement.”

Insurance

In accordance with industry practice, we maintain insurance against some, but not all, of the operating risks to which our business is exposed. We currently have insurance policies that include coverage for general liability (includes sudden and accidental pollution), physical damage to our oil and gas properties, control of well, auto liability, marine liability, worker’s compensation and employer’s liability, among other things.

Currently, we have general liability insurance coverage up to $1 million per occurrence, which includes sudden and accidental environmental liability coverage for the effects of pollution on third parties arising from our operations. Our insurance policies contain maximum policy limits and in most cases, deductibles (generally ranging from $25,000 to $1 million) that must be met prior to recovery. These insurance policies are subject to certain customary exclusions and limitations. In addition, we maintain excess liability coverage, which is in addition to and triggered if the general liability per occurrence limit is reached.

Our offshore activities are limited to non-operator positions in five older fields acquired with the Meridian purchase. Our offshore reserves are not a significant portion of our total reserves; the fields are in declining production with no drilling activity. Our consolidated balance sheets include asset retirement liabilities which we believe are sufficient to cover the eventual costs of dismantlement and abandonment. We believe that due to the nature of the operations in these fields, and the limited activity, the risk of environmental damage is not as high as it would be in an actively drilling offshore field. Our insurance program includes property damage, pollution liability, and control of well. The property damage coverage extends to total loss of the equipment (not the reserves) with replacement cost coverage retained on one of the five fields. The pollution coverage, which is applicable to both offshore and onshore events, is $10 million per incident with a $100,000 deductible.

We require all of our third-party contractors, including those that perform hydraulic fracturing operations, to sign master service agreements in which they agree to indemnify us for injuries and deaths of the service provider’s employees as well as contractors and subcontractors hired by the service provider. Similarly, we generally agree to indemnify each third-party contractor against claims made by our employees and other contractors. Additionally, each party generally is responsible for damage to its own property. We do not currently have any insurance policies in effect that are intended to provide coverage for losses solely related to hydraulic fracturing operations.

We re-evaluate the purchase of insurance, coverage limits and deductibles annually. Future insurance coverage for the oil and gas industry could increase in cost and may include higher deductibles or retentions. In addition, some forms of insurance may become unavailable in the future or unavailable on terms that are economically acceptable. No assurance can be given that we will be able to maintain insurance in the future at rates that we consider reasonable and we may elect to self-insure or maintain only catastrophic coverage for certain risks in the future.

Environmental Matters and Regulation

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:

•

require the acquisition of various permits before drilling commences;

•

require the installation of pollution control equipment in connection with operations;

•

place restrictions or regulations upon the use of the material based on our operations and upon the disposal of waste from our operations;

•

restrict the types, quantities and concentrations of various substances that can be released into the environment or used in connection with drilling, production and transportation activities;

•

limit or prohibit drilling activities on lands lying within wilderness, wetlands and other protected areas; and

•

require remedial measures to mitigate pollution from former and ongoing operations, such as site restoration, pit closure and plugging of abandoned wells.

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 increased 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.

Solid and Hazardous Waste Handling

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. 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.

Clean Water Act

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.

Oil Pollution Act

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.

Air Emissions

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.

Safe Drinking Water Act

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 approximately 8 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). 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.

In addition, the EPA has recently been taking activity to assert federal regulatory authority over hydraulic fracturing using diesel under the SDWA’s Underground Injection Control Program. Further, in March 2010, the EPA announced that it would conduct a wide-ranging study on the effects of hydraulic fracturing on drinking water resources. Interim results of the study are expected in 2012, with final results 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. The agency 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 will 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 as a result of these studies, we could incur substantial compliance costs and the requirements could negatively impact our ability to conduct fracturing activities on our assets.

National Environmental Policy Act

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.

Climate Change Regulation and Legislation

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. In prior sessions, both houses of Congress have considered legislation to reduce emissions of GHGs (including cap-and-trade style programs), 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. Subsequently, the EPA adopted the Prevention of Significant Deterioration and Title V Greenhouse Gas Tailoring Rule, which phased 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 the 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 July 28, 2011, the EPA proposed a rule to subject oil and gas operations to regulation under the New Source Performance Standards (NSPS) and National Emission Standards for Hazardous Air Pollutants (NESHAP) programs under the Clean Air Act, and to impose new and amended requirements under both programs. Under the proposal, the EPA would, among other things, amend standards applicable to natural gas processing plants and would expand the NSPS to include all oil and gas operations, imposing requirements on those operations. The EPA is also proposing NSPS standards for completions of hydraulically fracturing gas wells. The proposed standards include the reduced emission completion techniques. The NESHAP proposal includes maximum achievable control technology (MACT) standards for certain glycol dehydrators and storage vessels, and revises applicability provisions, alternative test protocols and the availability of the startup, shutdown and maintenance exemption. The EPA is under a court order to finalize the rules, with the current deadline of April 3, 2012. Should these rules become final and applicable to our operations, they could result in increased operating and compliance costs, increased regulatory burdens and delays in our operations.

OSHA and Other Laws and Regulation

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 2012 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.

Other Regulation of the Oil and Natural Gas Industry

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.

Drilling and Production

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:

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the location of wells;

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the method of drilling and casing wells;

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the surface use and restoration of properties upon which wells are drilled; and

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the plugging and abandoning of wells.

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.

Federal Natural Gas Regulation

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.

State Natural Gas Regulation

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.

Other Regulation

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.

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 report.

Item 1A. Risk Factors

Each of the following risk factors could adversely affect our business, operating results and financial condition. It is not possible to foresee or identify all such factors. Investors should not consider this list an exhaustive statement of all

risks and uncertainties. This report also contains forward-looking statements that involve risks and uncertainties. Our actual results may differ from those anticipated in these forward-looking statements as a result of both the risks described below and factors described elsewhere in this report. You should read the section above entitled “Cautionary Statement Regarding Forward-Looking Statements” for further discussion of these matters.

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 $220-240 million. We have funded development and operating activities primarily through equity capital raised from a private equity partner, through borrowings under our bank credit facilities, through the issuance of our senior notes, 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:

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the estimated quantities of our oil and natural gas reserves;

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the amount of oil and natural gas we produce from existing wells;

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the prices at which we sell our production;

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take-away capacity; and

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our ability to acquire, locate and produce new reserves.

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 have declined from $4.22 for the January 2011 NYMEX Henry Hub Futures contract settled December 29, 2010 to $3.08 for the January 2012 Henry Hub Futures contract settled December 28, 2011. The reduction in prices has been caused by many factors, including recent increases in natural gas production from non–conventional (shale) reserves, warmer than normal weather and high levels of natural gas in storage. We have hedged approximately 73% of our forecasted PDP production through 2016 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:

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the domestic and foreign supply of and demand for oil and natural gas;

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the price and quantity of foreign imports of oil and natural gas;

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the level of consumer product demand;

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weather conditions;

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domestic and foreign governmental regulations and taxation;

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overall domestic and global economic conditions, including the European credit crisis;

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the value of the dollar relative to the currencies of other countries;

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political and economic conditions and events in foreign oil and natural gas producing countries, including embargoes, continued hostilities in the Middle East and other sustained military campaigns, conditions in South America, Central America, China and Russia, and acts of terrorism or sabotage;

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the ability of members of the Organization of Petroleum Exporting Countries to agree to and maintain oil price and production controls;

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the proximity and capacity of natural gas pipelines and other transportation facilities to our production;

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technological advances affecting energy consumption;

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the price and availability of alternative fuels; and

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the impact of energy conservation efforts.

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. 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. For the years prior to 2009, we based the estimated discounted future net revenues from our proved reserves on prices and costs in effect on the day of the estimate. In accordance with current SEC requirements, we 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:

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actual prices we receive for crude oil and natural gas;

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actual cost of development and production expenditures;

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the amount and timing of actual production;

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transportation and processing; and

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changes in governmental regulations or taxation.

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 natural 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.

We may experience difficulty in achieving and managing future growth.

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:

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the results of our drilling program;

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hydrocarbon prices;

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our ability to develop existing prospects;

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our ability to obtain leases or options on properties for which we have 3-D seismic data;

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our ability to acquire additional 3-D seismic data;

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our ability to identify and acquire new exploratory prospects;

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our ability to continue to retain and attract skilled personnel;

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our ability to maintain or enter into new relationships with project partners and independent contractors; and

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our access to capital.

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 our senior 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 our senior 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.

Our business activities are subject to operational risks, including:

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damages to equipment caused by adverse weather conditions, including tornadoes, hurricanes and flooding;

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facility or equipment malfunctions;

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pipeline ruptures or spills;

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surface fluid spills and salt water contamination;

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fires, blowouts, craterings and explosions; and

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uncontrollable flows of oil or natural gas or well fluids.

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 December 31, 2011, we have hedged approximately 73% of our forecasted PDP production through 2016 at average annual prices ranging from $4.88 per MMBtu to $6.13 per MMBtu and $85.81 per Bbl to $97.96 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 counterparty credit risk.

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 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. The Commodities Futures Trading Commission (the “CFTC”) is required to implement rules relating to these activities by July 16, 2012. On October 18, 2011, 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. 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, 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.

Certain U.S. federal income tax preferences currently available with respect to oil and natural gas production may be eliminated as a result of future legislation.

In recent years, the Obama Administration’s budget proposals and other proposed legislation have included the elimination of certain key U.S. federal income tax incentives currently available to oil and gas exploration and production. If enacted into law, these proposals would eliminate certain tax preferences applicable to taxpayers engaged in the exploration or production of natural resources. These changes include, but are not limited to (1) the repeal of the percentage depletion allowance for oil and gas properties, (ii) the elimination of current deductions for intangible drilling and development costs, (iii) the elimination of the deduction for U.S. production activities and (iv) the increase in the amortization period from two years to seven years for geophysical costs paid or incurred in connection with the exploration for or development of, oil and gas within the United States. It is unclear whether any such changes will be enacted or how soon any such changes would become effective. The passage of any legislation as a result of these proposals or any other similar changes in U.S. federal income tax laws could negatively affect our financial condition and results of operations.

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:

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adverse weather conditions and natural disasters;

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availability of required performance bonds and insurance;

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oil field service costs and availability;

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compliance with environmental and other laws and regulations;

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matters arising from the 2010 BP Macondo well oil spill including but not limited to new safety requirements, new regulations, increased costs of services and rig mobilizations, slowed issuance of permits for new wells and additional insurance costs and requirements;

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remediation and other costs resulting from oil spills or releases of hazardous materials; and

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failure of equipment or facilities.

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:

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the Clean Air Act (“CAA”) and comparable state laws and regulations that impose obligations related to air emissions;

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the Clean Water Act and Oil Pollution Act (“OPA”) and comparable state laws and regulations that impose obligations related to discharges of pollutants into regulated bodies of water;

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the Resource Conservation and Recovery Act (“RCRA”), and comparable state laws that impose requirements for the handling and disposal of waste from our facilities;

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the Comprehensive Environmental Response, Compensation, and Liability Act (“CERCLA”) and comparable state laws that regulate the cleanup of hazardous substances that may have been released at properties currently or previously owned or operated by us or at locations to which we have sent waste for disposal; and

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the emergency, planning, and 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.

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 and greenhouse natural gases, 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.

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.

We maintain 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 the interests of other investors.

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:

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approval of material sales and acquisitions of properties and assets, the incurrence of debt, the appointment of any successor to our Chief Executive Officer and any other senior officers; the entering into of partnerships and joint ventures; our merger or consolidation with any entity; and the issuance of interests, ownership interests, debentures, bonds and other securities of the company;

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approval of our annual development plan and budget;

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the right to require us to implement measures to mitigate our commodity price risks;

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the right to part of the proceeds of any future debt or equity offering;

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the right to require our general partner to make distributions of “net cash from operations” subject to our compliance with the covenants of any senior debt, including the senior notes, or bank credit facility; “net cash from operations” is defined as the gross cash proceeds from our operations less amounts 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 and agreed reserves (as agreed upon by us and our Class B limited partner);

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the right to cause our general partner to initiate a sale of us to a third party; and

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the right to remove the general partner for cause and replace the general partner in the Class B limited partner’s sole discretion.

The interests of the Class B limited partner could conflict with the interests of our other investors, such as the holders of our senior 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 the interests of the holders of our senior 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 our other investors, including the holders of our senior 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 have actively 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 statutes, 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. The RCRA and comparable state and local programs impose requirements on the management, treatment, storage and disposal of both hazardous and non-hazardous solid wastes. Many of the wastes that we generate are currently exempt from hazardous waste regulation under RCRA, but may be subject to state and local regulation or could in the future lose their RCRA exemption, which would result in more rigorous and costly management and disposal requirements.

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 federal 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, and to require reporting and disclosure of the chemicals used in those operations. This legislation has not passed.

The EPA has commenced a study of the potential environmental impacts of hydraulic fracturing activities, with interim results of the study anticipated to be available by late 2012, and final results 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 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 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.

Congress is currently considering the Fracturing Responsibility and Awareness of Chemicals Act (“FRAC Act”) that would amend the SDWA to repeal an exemption from regulation for hydraulic fracturing. If enacted, the FRAC Act would amend the definition of “underground injection” in the SDWA to encompass hydraulic fracturing activities. If enacted, such a provision could require hydraulic fracturing operations to meet permitting and financial assurance requirements, adhere to certain construction specifications, fulfill monitoring, reporting, and recordkeeping obligations, and meet plugging and abandonment requirements. The FRAC Act also proposes to require the reporting and public disclosure of chemicals used in the fracturing process, which could make it easier for third parties opposing the hydraulic fracturing process to initiate legal proceedings based on allegations that specific chemicals used in the fracturing process could adversely affect groundwater. In addition, the EPA has commenced a study of the potential adverse effects that hydraulic fracturing may have on water quality and public health, and a committee of the U.S. House of Representatives has commenced its own investigation into hydraulic fracturing practices. Additionally, many states and other local regulatory authorities have enacted or are considering regulations on hydraulic fracturing, including regulations requiring disclosure of fracturing chemicals or restricting hydraulic fracturing in certain circumstances. The adoption of any future federal or state laws or implementing regulations imposing reporting obligations on, or otherwise limiting, the hydraulic fracturing process could make it more difficult to complete oil and natural gas wells and increase our costs of compliance and doing business.

The obligations associated with being an SEC reporting company 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 under the registration rights agreement with the holders of our senior notes, we became subject to certain of the reporting requirements of the Exchange Act and the Sarbanes-Oxley Act of 2002. Under the Exchange Act, we are 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 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 senior notes contain restrictive covenants that limit our ability to, among other things:

•

incur or guarantee additional debt;

•

make distributions;

•

repay subordinated debt prior to its maturity;

•

grant additional liens on our assets;

•

enter into transactions with our affiliates;

•

repurchase equity securities;

•

make certain investments or acquisitions of substantially all or a portion of another entity’s business assets; and

•

merge with another entity or dispose of our assets.

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.

If we are unable to comply with the restrictions and covenants in our debt 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. In the event of a default under these agreements, lenders could terminate their commitments to lend or accelerate the loans and declare all amounts borrowed due and payable. 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.

Item 1B. Unresolved Staff Comments.

None.

Item 2. Properties

Information regarding our properties is contained in “Item 1. Business” contained herein.

Item 3. Legal Proceedings

We are party to various litigation matters arising in the ordinary course of business. We do not believe the outcome of such disputes or legal actions will have a material adverse effect on our consolidated financial statements. Accruals for losses associated with litigation are made when losses are deemed probable and can be reasonably estimated.

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 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 consolidated financial statements at December 31, 2011.

Due to the nature of our business, some contamination of the real estate property owned or leased by us is possible. Environmental site assessments of the property would be necessary to adequately determine remediation costs, if any.

Item 4. Mine Safety Disclosures

Not applicable.

PART II

Item 5. Market For Registrant’s Common Equity, Related Stockholder Matters, and Issuer Purchases of Equity Securities

No class of our limited partnership interests has been registered under the Exchange Act, and there is no established public trading market for our equity.

As of March 29, 2012, six holders of our limited partnership interests held 100% of such interests.

Distributions to our partners are determined by the terms of our partnership agreement, described further at Note 15 in the accompanying Notes to Consolidated Financial Statements. See also, “Risk Factors — AMIH, as our Class B

limited partner, has the ability to take actions that conflict with your interests.” We are also currently restricted in our ability to pay dividends under our senior secured revolving credit facility. Historically, limited distributions have been made with the approval of our board of directors. In 2010, a $50 million distribution was made to AMIH, which was offset by an equivalent contribution from that partner earlier the same year.

Item 6. Selected Financial Data

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 the acquisition date of April 21, 2011, the TODD acquisition from the acquisition date of June 17, 2011, and the Hilltop Field acquisition from the acquisition date of July 23, 2009. 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. For further information that will help you better understand the summary data, you should read this financial data in conjunction with “Item 7. 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 report.


	Year Ended December 31,
	2011			2010			2009			2008			2007
	(dollars in thousands)
Statement of Operations Data:
Revenues
Natural gas, oil and natural gas liquids	$	323,911		$	208,537		$	102,263		$	98,983		$	56,746
Other revenues		2,127			1,475			1,558			3,629			12,036

		326,038			210,012			103,821			102,612			68,782
Unrealized gain (loss) — oil and natural gas derivative contracts		28,169			10,088			(26,258	)		60,612			(14,457	)

Total revenues	$	354,207		$	220,100		$	77,563		$	163,224		$	54,325
Costs and expenses:
Lease and plant operating expense		62,637			41,905			23,871			20,658			14,642
Production and ad valorem taxes		19,357			11,141			4,755			6,954			4,406
Workover expense		11,777			7,409			8,988			8,113			7,825
Exploration expense		15,785			31,037			12,839			11,675			9,743
Depreciation, depletion, and amortization		94,251			59,090			48,659			49,219			31,298
Impairment expense		18,735			8,399			6,165			11,487			1,449
Accretion expense		1,812			1,370			492			729			627
General and administrative expense		33,087			20,135			8,738			6,401			5,321
Gain on sale of assets		—			(1,766	)		(738	)		—			—

Total expenses		257,441			178,720			113,769			115,236			75,311
Income (loss) from operations		96,766			41,380			(36,206	)		47,988			(20,986	)

Other income (expense):
Interest expense, net		(32,644	)		(27,149	)		(13,831	)		(14,457	)		(10,792	)
Gain on contract settlement		1,285			—			—			—			—
Gain on extinguishment of debt		—			—			—			3,349			4,302

Total other income (expense)		(31,359	)		(27,149	)		(13,831	)		(11,108	)		(6,490	)
(Provision) benefit for state income taxes		(228	)		(2	)		750			(250	)		(500	)

Net income (loss)	$	65,179		$	14,229		$	(49,287	)	$	36,630		$	(27,976	)

Statement of Cash Flow Data:
Capital expenditures	$	193,770		$	110,083		$	100,261		$	111,096		$	89,604
Net cash flow provided by operating activities		150,655			61,185			34,343			20,300			38,618
Net cash used in investing activities(1)		(266,133	)		(208,412	)		(86,573	)		(111,096	)		(98,604	)
Net cash provided by financing activities		113,272			147,789			51,823			78,771			71,596
Balance Sheet Data (at period end):
Cash and cash equivalents	$	2,630		$	4,836		$	4,274		$	4,681		$	16,706
Property and equipment, net		589,167			456,264			236,196			201,327			132,719
Total assets		720,083			558,239			290,606			277,111			175,157
Total debt, including Notes to Founder		507,947			390,985			219,830			188,228			123,244
Total partners’ capital (deficit)		89,672			24,658			10,664			37,751			(11,661	)

(1)	Net cash used in investing activities includes $72.4 for acquisitions (primarily Sydson and TODD) in 2011, and $101.4 million for the acquisition of Meridian in 2010.

Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations

The following discussion and analysis should be read in conjunction with the “Selected Historical Financial and Other Data” and the consolidated financial statements and related notes included elsewhere in this report. 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 report, 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 consolidated 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 acquisition from the acquisition date of May 13, 2010, the Sydson acquisition from the acquisition date of April 21, 2011, the TODD acquisition from the acquisition date of June 17, 2011, and the Hilltop Field acquisition from the acquisition date of July 23, 2009.

Overview

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

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

•

the prices at which we will sell our production;

•

the amount of oil and natural gas we produce; and

•

the level of our operating and administrative costs.

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

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

Significant Acquisitions

Meridian Acquisition

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.

Sydson Acquisition

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

TODD Acquisition

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

Hilltop Field Acquisition

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’ petition to review the appellate court decision. 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 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. 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 in April 2012.

Outlook

The U.S. and other world economies suffered a severe recession lasting well into 2009 and economic conditions remain uncertain. These uncertain economic conditions reduced demand for oil and natural gas, resulting in a decline in oil and natural gas prices received for our production in 2009 compared with years prior to and including 2008. In response to these lower oil and natural gas prices, we, along with many other oil and natural gas companies, scaled back our drilling programs.

We have hedged approximately 73% of our forecasted PDP production through 2016 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.

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

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

The primary factors affecting our production levels are capital availability, the effectiveness and efficiency of our production operations, the success of our drilling program and our inventory of drilling prospects. We inherently face the challenge of natural production declines since as reservoirs are depleted, pressures decline, and the rate of production from a given well decreases. We attempt to overcome the cumulative effects of these natural declines primarily through developing our existing undeveloped reserves through drilling, 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 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: Year Ended December 31, 2011 v. Year Ended December 31, 2010


	Year Ended December 31,						Increase
	2011			2010			(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	%

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

Revenues

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.

Expenses

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


	Year Ended December 31,						Increase (Decrease)
	2010			2009			Increase (Decrease)			% Change
	($ in thousands, except average sales price and unit costs)

Summary Operating Information:
Net Production:
Natural gas (MMcf)		24,026			10,610			13,416			126	%
Oil (MBbls)		964			505			459			91	%
Natural gas liquids (MBbls)		147			47			100			213	%
Total natural gas equivalent (MMcfe)		30,694			13,919			16,775			121	%
Average daily gas production (MMcfe per day)		84.1			38.1			46.0			121	%
Average Sales Price:
Natural gas (per Mcf) realized	$	5.24		$	6.25		$	(1.01	)		(16	%)
Natural gas (per Mcf) unhedged		4.27			3.72			0.55			15	%
Oil (per Bbl) realized		78.63			67.94			10.69			16	%
Oil (per Bbl) unhedged		78.86			59.23			19.63			33	%
Natural gas liquids (per Bbl) realized(1)		46.58			36.05			10.53			29	%
Combined (per Mcfe) realized		6.79			7.35			(0.56	)		(8	%)
Hedging Activities:
Realized natural gas revenue gain (loss)	$	23,206		$	26,835		$	(3,629	)		(14	%)
Realized oil revenue gain (loss)		(224	)		4,397			(4,621	)		(105	%)
Summary Financial Information:
*Revenues*
Natural gas	$	125,866		$	66,290		$	59,576			90	%
Oil		75,827			34,283			41,544			121	%
Natural gas liquids		6,844			1,690			5,154			305	%
Other revenues		1,475			1,558			(83	)		(5	%)
Unrealized gain (loss) — oil and natural gas derivative contracts		10,088			(26,258	)		36,346			138	%
*Costs and Expenses*
Lease and plant operating expense		41,905			23,871			18,034			76	%
Production and ad valorem taxes		11,141			4,755			6,386			134	%
Workover expense		7,409			8,988			(1,579	)		(18	%)
Exploration expense		31,037			12,839			18,198			142	%
Depreciation, depletion, and amortization		59,090			48,659			10,431			21	%
Impairment expense		8,399			6,165			2,234			36	%
Accretion expense		1,370			492			878			178	%
General and administrative expense		20,135			8,738			11,397			130	%
Gain on sale of assets		(1,766	)		(738	)		(1,028	)		(139	%)
Interest expense, net		27,149			13,831			13,318			96	%
(Benefit) provision for state income taxes		2			(750	)		752			100	%

Net income (loss)	$	14,229		$	(49,287	)	$	63,516			129	%

Average Unit Costs per Mcfe:
Lease and plant operating expense	$	1.37		$	1.71		$	0.34	)		(20	%)
Production and ad valorem taxes		0.36			0.34			0.02			6	%
Workover expense		0.24			0.65			(0.41	)		(63	%)
Exploration expense		1.01			0.92			0.09			10	%
Depreciation, depletion, and amortization		1.93			3.50			(1.57	)		(45	%)
General and administrative expense		0.66			0.63			0.03			5	%

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

Revenues

Natural gas revenues for the year ended December 31, 2010 increased $59.6 million, or 90%, to $125.9 million in 2010 from $66.3 million in 2009. The increase in natural gas 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 Hilltop properties in July 2009. Natural gas production attributable to the acquisition of Meridian for the year was 4.2 Bcf; the Hilltop properties produced 12.3 Bcf in 2010, as compared to 4.0 Bcf in 2009. The price of natural gas 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 natural gas 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 in 2010 from $34.3 million in 2009. The increase in oil revenue was due to increased production volumes coupled with a higher average realized price. Oil production increased to 964 MBbls from 505 MBbls in 2009, or 91%, which increased oil revenues by $31.2 million. Of this, 472 MBbls were attributable to the acquisition of Meridian. The price of oil exclusive of hedging increased 33% in 2010; the overall realized price (including hedging gains and losses), increased 16% to $78.63 per Bbl in 2010 from $67.94 per Bbl in 2009, which increased oil revenues by $10.3 million.

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 and an increase in overall realized price to $46.58 per Bbl in 2010 from $36.05 per Bbl in 2009. The increase in volume was due to the Meridian acquisition.

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.

Expenses

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 occurred in May 2010. In addition, the Hilltop field, 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 Hilltop included approximately $6.8 million in gas gathering and processing expenses, based on a contract which originated in December 2009, primarily due to increased production to 12.3 Bcf in 2010 from 4.0 Bcf in 2009. On a per unit basis, lease and plant operating expense decreased to $1.37 from $1.71 per Mcfe for 2010 and 2009 respectively.

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 per Mcfe for 2010 from $0.34 per Mcfe for 2009.

Workover expense decreased in 2010 to $7.4 million from $9.0 million in 2009. 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 to $31.0 million for 2010 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 Hilltop field.

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 resulted principally from increased payroll and burden costs of $8.8 million, which are predominately related to increased headcount due to the Meridian acquisition and additional personnel, 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 $2.0 million, primarily due to on-going litigation, outside services provided by reservoir engineers and additional accounting, tax and acquisition reviews, including the acquisition of Meridian. In addition, general and administrative costs related to the acquisition of Meridian including office rent, increased $1.2 million in 2010 as compared to 2009. On a per unit basis, general and administrative expense increased to $0.66 per Mcfe for 2010, from $0.63 per Mcfe, for 2009.

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

Liquidity and Capital Resources

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 2011 capital budget was primarily focused on the development of existing core areas through exploitation and development. Currently, we anticipate a capital budget of approximately $220-240 million for 2012. Approximately 78% of our 2012 capital budget is allocated to our properties in Hilltop, East Texas, Eagle Ford, and South Louisiana. Our future drilling plans, plans of our drilling operators and capital budgets are subject to change based upon various factors, some of which are beyond our control, including drilling results, oil and natural gas prices, the availability and cost of capital, drilling and production costs, availability of drilling services and equipment, actions of our operators, gathering system and pipeline transportation constraints and regulatory approvals. Because a large percentage of our acreage is held by production, we have the ability to materially decrease our drilling and recompletion budget in response to market conditions with minimal risk of losing significant acreage.

In October 2010, we adjusted our capital structure by issuing $300 million of 9.625% senior notes due 2018 (“senior notes”). The notes were issued at a discount of $2.1 million, bringing the effective rate to 9.75%. The net proceeds of the senior notes offering 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 senior notes are unsecured senior general corporate obligations, and effectively rank junior to any of our existing or future secured indebtedness, which includes our credit facility. The senior notes are unconditionally guaranteed on a senior unsecured basis by each of our material, wholly owned subsidiaries.

In connection with the issuance of the senior notes, we entered into a registration 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 tendered original senior notes were exchanged for the exchange notes.

Our senior secured revolving credit facility (“credit facility”) is subject to a current $325 million borrowing base limit with Wells Fargo Bank, N.A. as the administrative agent. As of December 31, 2011, we had $188.8 million outstanding under the credit facility and $136.2 million in available unused borrowing base. Our restricted subsidiaries are guarantors of the credit facility. The credit facility provides that we may not issue senior unsecured debt securities in excess of $700 million, including the senior notes issued in October 2010.

The 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 weighted average rate on all loans outstanding as of December 31, 2011 under the credit facility was 2.774%, which was based primarily on the Eurodollar option.

The credit facility includes covenants requiring that we maintain certain financial covenants including a current ratio, leverage ratio, and interest coverage ratio. At December 31, 2011, we were in compliance with the covenants. The terms of the credit facility also restrict our ability to make distributions and investments.

We expect to fund our 2012 capital budget predominantly with cash flows from operations. If necessary, we may also access capital through proceeds from potential asset dispositions, borrowings under the credit facility and the future issuance of debt and/or equity securities, subject to the distribution of proceeds therefrom as set forth in our partnership agreement. See Note 15, “Partners’ Capital,” in the accompanying Notes to Consolidated Financial Statements for further information. In addition, we may need to raise additional capital in order to develop our estimated proved undeveloped reserves over the next five years. We strive to maintain financial flexibility and may access capital markets as necessary to maintain substantial borrowing capacity under our 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.

Cash Flow Provided by Operating Activities

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 in 2010 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 Flow Used in Investing Activities

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.

Cash Flow Provided by Financing Activities

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 our senior 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.

Risk Management Activities — Commodity Derivative Instruments

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 90% of our projected oil and natural gas production from proved developed properties for 2012. See Note 6 to our consolidated financial statements as of December 31, 2011, “Derivative Financial Instruments”, for further information.

Contractual Obligations

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


	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

(1)

Interest includes interest on the outstanding balance under our revolving credit agreement maturing in 2016, payable quarterly; on our senior notes due 2018, payable semiannually; and on the debt to our founder, which is payable with principal, at maturity in 2018. Projected obligation amounts are based on the payment schedules for interest, and are not presented on an accrual basis.

(2)

Derivative contract premiums relate to open derivative contracts in place at December 31, 2011 and are due over time as the contracts mature and settle. They are included on our consolidated balance sheet with the related derivative contracts. Amounts presented above are net of $9.9 million for premiums due to us under derivative contracts from the same counterparties.

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.

Off-Balance Sheet Arrangements

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.

Critical Accounting Policies and Estimates

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, oil and natural gas properties, 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 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 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 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 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.

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). Oil and natural gas sold is not significantly different from our 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 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. 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 operations 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 “Benefit from (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.

Recent Accounting Pronouncements

On May 12, 2011, the FASB issued ASU No. 2011-04 to Topic 820, Fair Value Measurements, “Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in U.S. GAAP and IFRS.” The ASU changes certain definitions of terms used its guidance regarding fair value measurements, as well as modifying certain disclosure requirements and other aspects of the guidance. 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.

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 its consolidated financial statements.

Item 7A. Quantitative and Qualitative Disclosures about Market Risk

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.

Commodity Price Risk and Hedges

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 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 December 31, 2011, we have hedged approximately 73% of our forecasted production from proved developed reserves through 2016 at average annual prices ranging from $4.88 per MMBtu to $6.13 per MMBtu and $85.81 per Bbl to $97.96 per Bbl. Forecasted production from proved reserves is estimated in our December 2011 reserve report using prices, costs and other assumptions required by SEC rules. Our actual production will vary from the amounts estimated in the report, 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 value of our oil and natural gas derivative contracts and basis swaps at December 31, 2011 was a net asset of $53 million. A 10% increase or decrease in oil and natural gas prices with all other factors held constant would result in an unrealized loss or gain, respectively, in the 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.

Interest Rates

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. A 1% increase in interest rates (100 LIBOR basis points) would increase the fair value of our interest rate derivatives. However, such an increase in interest rates would also increase interest expense on our variable rate debt.

Item 8. Financial Statements and Supplementary Data

The consolidated financial statements and supplementary financial information required to be filed under this item are presented beginning on page F-1 in Part IV, Item 15 of this annual report and are incorporated herein by reference.

Item 9. Changes in and Disagreements With Accountants on Accounting and Financial Disclosure

None.

Item 9A. Controls and Procedures

Evaluation of Disclosure Controls and Procedures

In accordance with Exchange Act Rule 13a-15 and 15d-15, we carried out an evaluation, under the supervision and with the participation of management, including our Chief Executive Officer and our Chief Financial Officer, of the effectiveness of our disclosure controls and procedures as of the end of the period covered by this report. Based on that evaluation, our Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures were effective as of December 31, 2011 to provide reasonable assurance that information required to be disclosed in our reports filed or submitted under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the Securities and Exchange Commission’s rules and forms. Our disclosure controls and procedures include controls and procedures designed to ensure that information required to be disclosed in reports filed or submitted under the Exchange Act is accumulated and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosure.

Changes in Internal Control Over Financial Reporting

There has been no change in our internal control over financial reporting during the year ended December 31, 2011 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

This annual report does not include a report of management’s assessment regarding internal control over financial reporting or an attestation report of our registered public accounting firm due to a transition period established by the rules of the SEC for newly public companies.

Item 9B. Other Information

None.

PART III

Item 10. Directors, Executive Officers, and Corporate Governance

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 (“Alta Mesa GP”), and the officers and directors of Alta Mesa Services, LP (“Alta Mesa Services”), an entity wholly owned by us. Prior to the offering of the senior notes in October 2010, Alta Mesa Services was owned by Michael E. and Mickey Ellis. 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 “Item 13. Certain Relationships and Related Party Transactions, and Director Independence — Shared Services and Expenses Agreement.”

Board Leadership Structure

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.

Board Oversight of Risk

Like all businesses, we face risks in our business activities. Many of these risks are discussed under the caption “Risk Factors” elsewhere in this report. 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.

Executive Officers and Directors

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.


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

David Murrell		50	—	Vice President, Land and Business Development

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 us in a period of significant growth, building a strong management and technical team, focusing us on our greatest opportunities, making strategic acquisitions, and restructuring our financing. Mr. Chappelle has over 30 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 our 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 our 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.

Qualifications of Directors

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 a knowledge of our business and operations.

Audit and Compensation Committee

We do not have a formal compensation committee and our full Board serves as our audit committee. 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.

Code of Ethics

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 15021 Katy Freeway, Suite 400, Houston, Texas 77094.

Item 11. Executive Compensation

Compensation Discussion and Analysis

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.

Objectives of Our Compensation Program

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:

•

attract and retain talented executive officers by providing reasonable total compensation levels competitive with that of executives holding comparable positions in similarly situated organizations;

•

provide total compensation that is justified by individual performance; and

•

provide performance–based compensation that is tied to both individual and our performance.

What Our Compensation Program is Designed to Reward

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.

Elements of Our Compensation Program and Why We Pay Each Element

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.

How We Determine Each Element of Compensation

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 2011 has not yet been determined. However, bonuses paid in 2011 for 2010 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.

How Elements of Our Compensation Program are Related to Each Other

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.

Assessment of Risk

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.

Accounting and Tax Considerations

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.

Compensation Committee Report

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 Annual Report on Form 10-K.

Harlan H. Chappelle

Michael E. Ellis (Chairman)

Mickey Ellis

Summary Compensation

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.


Name and Principal Position	Year		Salary		Bonus (1)		All Other Compensation			Total
Harlan H. Chappelle President, Chief Executive Officer		2011	$	450,000	$	—	$	29,586	(2)	$	479,586
Harlan H. Chappelle President, Chief Executive Officer		2010	$	450,000	$	900,000	$	18,639	(2)	$	1,368,639

Michael E. Ellis Chief Operating Officer, Vice President of Engineering, and Chairman of the Board		2011	$	450,000	$	—	$	27,989	(3)	$	477,989
		2010	$	450,000	$	500,000	$	26,429	(3)	$	976,429

Michael A. McCabe Vice President, Chief Financial Officer		2011	$	350,000	$	—	$	76,401	(4)	$	426,401
Michael A. McCabe Vice President, Chief Financial Officer		2010	$	350,000	$	500,000	$	88,016	(4)	$	938,016

David Murrell Vice President of Land and Business Development		2011	$	300,000	$	—	$	24,027	(5)	$	324,027
		2010	$	273,750	$	200,000	$	8,250	(5)	$	482,000

(1)	Bonuses for 2011 have not yet been determined. We expect these bonuses will be determined before the end of August 2012.

(2)

Mr. Chappelle’s other compensation for the year ended December 31, 2011 consists of $9,800 in matching funds to his 401(k) account, $17,802 in auto expenses, and $1,984 for club membership. Mr. Chappelle’s other compensation for the year ended December 31, 2010 consists of $8,250 in matching funds to his 401(k) account, and $10,389 in auto expenses.

(3)

Mr. Ellis’ other compensation for the year ended December 31, 2011 consists of $9,800 in matching funds to his 401(k) account and $18,189 in auto expenses. Mr. Ellis’ other compensation for the year ended December 31, 2010 consists of $8,250 in matching funds to his 401(k) account and $18,179 in auto expenses.

(4)

For the year ended December 31, 2011, Mr. McCabe’s other compensation consisted of $9,800 in matching funds to his 401(k) account, and $66,601 in travel and living expenses, which includes $18,764 for an apartment in Houston and $47,837 for travel, which consists primarily of airfare and the cost of a leased car and parking. For the year ended December 31, 2010, Mr. McCabe’s other compensation consisted of $10,417 in matching funds to his 401(k) account, and $77,599 in travel and living expenses, which includes $20,239 for an apartment in Houston and $57,360 for travel, which consists primarily of airfare and the cost of rental cars and parking.

(5)

Mr. Murrell’s other compensation for the year ended December 31, 2011 consists of $9,800 in matching funds to his 401(k) account and $14,227 in auto expenses. Mr. Murrell’s other compensation for the year ended December 31, 2010 consists of $8,250 in matching funds to his 401(k) account. Mr. Murrell’s ending salary for the year 2010 was $275,000, which differs from total salary for that year in the table above as this salary was not in effect for the full year.

Narrative Disclosure to Summary Compensation Table

Mr. Chappelle

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

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

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

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.

Grants of Plan-Based Awards for Fiscal Year 2011

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

Outstanding Equity Awards Value at 2011 Fiscal Year-End

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

Option Exercises and Equity Awards Vested in Fiscal Year 2011

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

Pension Benefits

We do not provide pension benefits for our named executive officers.

Nonqualified Deferred Compensation

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

Termination of Employment and Change–in–Control Provisions

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, 2011. In presenting this disclosure, we describe amounts earned through December 31, 2011 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.

Provisions Under the Employment Agreements

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, for each of Messrs. Chappelle, Ellis, McCabe, and Murrell, this amount would have been $18.00 to each. Our total cost 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.

“Cause” means:

•

the executive’s conviction by a court of competent jurisdiction of a crime involving moral turpitude or a felony, or entering the plea of nolo contendere to such crime by the executive;

•

the commission by the executive of a demonstrable act of fraud, or a misappropriation of funds or property, of or upon us or any affiliate;

•

the engagement by the executive without approval of us and the board of directors in any material activity which directly competes with the business of us or any affiliate or which would directly result in a material injury to the business or reputation of us or any affiliate (including the partners of Alta Mesa); or

•

the breach by the executive of any material provision of the employment agreement, and the executive’s continued failure to cure such breach within a reasonable time period set by us but in no event less than twenty calendar days after the executive’s receipt of such notice.

“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:

•

the demotion or reduction in title or rank of the executive, or the assignment to the executive of duties that are materially inconsistent with the executive’s current positions, duties, responsibilities and status with us, or any removal of the executive from, or any failure to re-elect the executive to, any of such positions (other than a change due to the executive’s disability or as an accommodation under the Americans with Disabilities Act), except for any such demotion, reduction, assignment, removal or failure that occurs in connection with (i) the executive’s termination of employment for cause, disability or death, or (ii) the executive’s prior written consent;

•

the reduction of the executive’s annual base salary or bonus opportunity as effective immediately prior to such reduction without the prior written consent of the executive; or

•

a relocation of the executive’s principal work location to a location in excess of 50 miles from its then current location.

“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.

Compensation of Directors

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.

Compensation Committee Interlocks and Insider Participation

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.

Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters

The following table sets forth the limited partnership interests in Alta Mesa beneficially owned by:

•

all persons who, to the knowledge of our management team, beneficially own more than 5% of our outstanding limited partnership interests;

•

each current director of Alta Mesa GP, our general partner;

•

each principal officer of Alta Mesa GP; and

•

all current directors and principal officers of Alta Mesa GP as a group.


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	%		—

(1)	Unless otherwise indicated, the address for all beneficial owners in this table is at 15021 Katy Freeway, Suite 400, Houston, Texas 77094.

(2)

The address of Alta Mesa Investment Holdings Inc. is c/o Denham Capital Management LP, 600 Travis, Suite 2310, Houston, Texas 77002. For more information on the ability of our Class B Limited Partner to cause a liquidity event, see Note 15 in the accompanying Notes to Consolidated Financial Statements.

(3)	The address of Macquarie Bank Limited is 333 Clay Street, Houston, Texas 77002.

(4)	The address of RBS Equity Corporation is c/o The Royal Bank of Scotland plc, 600 Travis, Suite 6500, Houston, Texas 77002.

(5)	Mr. Ellis does not own directly any partnership interests. Includes limited partner interests held by Alta Mesa Resources, LP, Galveston Bay Resources Holdings, LP, Petro Acquisition Holdings, LP and Petro Operating Company Holdings, Inc., all entities owned and controlled by Mr. Ellis.

(6)	Mickey Ellis is the spouse of Michael E. Ellis. Ms. Ellis may be deemed to be the beneficial owner of the partnership interests owned by Mr. Ellis.

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 Note 15 in the accompanying Notes to Consolidated Financial Statements.

Securities Authorized for Issuance under Equity Compensation Plans

We do not have any equity compensation plans.

Item 13. Certain Relationships and Related Transactions, and Director Independence

We do not have any formal policy with respect to the review and approval of related party transactions.

Ownership in Us and Our General Partner by Founder

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.

Founder Notes

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 Note 9 in the accompanying Notes to Consolidated Financial Statements.

Land Consulting Services

David Murrell, our Vice President, Land and Business Development, is the principal of David Murrell & 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. Payment for the year ended December 31, 2011 was approximately $179,000. The contract may be terminated by either party without penalty upon 30 days’ notice.

Employee

David McClure, one of our senior engineers and the son-in-law of our CEO, Harlan H. Chappelle, received total compensation of $260,208 for the year ended December 31, 2011. Additionally, his position provides him with the use of a company vehicle, similar to our other engineers whose duties include field oversight.

Director Independence

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.

Item 14. Principal Accountant Fees and Services

Our Board of Directors selected UHY LLP, an independent registered public accounting firm, to audit our consolidated financial statements for the fiscal year ended December 31, 2011. Aggregate fees for professional services rendered to us by UHY LLP for the years ended December 31, 2011 and 2010 were as follows:


	2011		2010
Audit Fees	$	508,350	$	166,429

Audit–Related Fees		181,270		345,928

Tax Fees		127,056		46,489

All Other Fees		—		53,605


Total	$	816,676	$	612,451

Audit Fees

The audit fees for the years ended December 31, 2011 and 2010, respectively, were for professional services rendered for the audits of our consolidated financial statements and review of our quarterly financial statements.

Audit-Related Fees

The audit-related fees for the year ended December 31, 2010 were for professional services provided in connection with the private offering of our senior notes. The audit-related fees for the year ended December 31, 2011 were incurred with the follow-on public registration of our exchange bonds which replaced the privately held senior notes; audit related fees for the year 2011 also include fees for the audit of our 401(k) employee savings plan.

Tax Fees

The tax fees for the years ended December 31, 2011 and 2010 were for professional services rendered for tax compliance.

All Other Fees

Other fees for the years ended December 31, 2011 and 2010, respectively, were for services rendered in relation to the Meridian acquisition.

Pre-Approval Policies and Procedures

We currently have no Board committees. Our Board of Directors has adopted policies regarding the pre-approval of auditor services. Specifically, the Board of Directors approves all services provided by the independent public

accountants at its March meeting. All additional services must be pre-approved on a case-by-case basis. Our Board of Directors reviews the actual and budgeted fees for the independent public accountants periodically at regularly scheduled board meetings. All of the services provided by UHY LLP during fiscal 2011 and 2010 were approved by the Board of Directors.

PART IV

Item 15. Exhibits and Financial Statement Schedules

(a)

Documents filed as part of this report:

Financial Statements:

(i)

Independent Registered Public Accounting Firm’s Report

(ii)

Consolidated Statements of Operations for each of the three years in the period ended December 31, 2011

(iii)

Consolidated Balance Sheets as of December 31, 2011 and 2010

(iv)

Consolidated Statements of Cash Flows for each of the three years in the period ended December 31, 2011

(v)

Consolidated Statements of Changes in Partners’ Capital for each of the three years in the period ended December 31, 2011

(vi)

Notes to Consolidated Financial Statements

(vii)

Supplemental Oil and Natural Gas Information (Unaudited)

Financial Statement Schedules:

(i)

All schedules are omitted as they are not applicable, not required or the required information is included in the consolidated financial statements or notes thereto.

Exhibits:


EXHIBIT NUMBER		Description Of Exhibit

3.1		Articles of Organization of Alta Mesa Holdings GP, LLC dated as of September 26, 2005 (incorporated by reference from Exhibit 3.1 to Alta Mesa Holdings, LP’s registration statement on Form S-4 filed with the SEC on April 27, 2011).

3.2		Regulations of Alta Mesa Holdings GP, LLC, dated as of September 26, 2005 (incorporated by reference from Exhibit 3.2 to Alta Mesa Holdings, LP’s registration statement on Form S-4 filed with the SEC on April 27, 2011).

3.3		Certificate of Limited Partnership of Alta Mesa Holdings, LP, dated as of September 26, 2005 (incorporated by reference from Exhibit 3.3 to Alta Mesa Holdings, LP’s registration statement on Form S-4 filed with the SEC on April 27, 2011).

3.4		First Amended and Restated Agreement of Limited Partnership of Alta Mesa Holdings, LP, dated as of September 1, 2006 (incorporated by reference from Exhibit 3.4 to Alta Mesa Holdings, LP’s registration statement on Form S-4 filed with the SEC on April 27, 2011).

3.5		Amendment Number One to the First Amended and Restated Agreement of Limited Partnership of Alta Mesa Holdings, LP, dated as of May 12, 2010 (incorporated by reference from Exhibit 3.5 to Alta Mesa Holdings, LP’s registration statement on Form S-4 filed with the SEC on April 27, 2011).

3.6		Amendment Number Two to the First Amended and Restated Agreement of Limited Partnership of Alta Mesa Holdings, LP, dated as of October 7, 2010 (incorporated by reference from Exhibit 3.6 to Alta Mesa Holdings, LP’s registration statement on Form S-4 filed with the SEC on April 27, 2011).

3.7		Certificate of Incorporation of Alta Mesa Finance Services Corp., dated September 27, 2010 (incorporated by reference from Exhibit 3.7 to Alta Mesa Holdings, LP’s registration statement on Form S-4 filed with the SEC on April 27, 2011).

3.8		Bylaws of Alta Mesa Finance Services Corp., dated as of September 27, 2010 (incorporated by reference from Exhibit 3.8 to Alta Mesa Holdings, LP’s registration statement on Form S-4 filed with the SEC on April 27, 2011).

4.1		Indenture by and among the Issuers, the Subsidiary Guarantors and Wells Fargo Bank, N.A., as Trustee, dated as of October 13, 2010 (incorporated by reference from Exhibit 4.1 to Alta Mesa Holdings, LP’s registration statement on Form S-4 filed with the SEC on April 27, 2011).

4.2		Registration Rights Agreement by and among the Issuers, the Subsidiary Guarantors and Wells Fargo Securities, LLC, as representative of the Initial Purchasers, dated as of October 13, 2010 (incorporated by reference from Exhibit 4.2 to Alta Mesa Holdings, LP’s registration statement on Form S-4 filed with the SEC on April 27, 2011).

10.1		Sixth Amended and Restated Credit Agreement by and among Alta Mesa Holdings, LP, Wells Fargo Bank, N.A., as administrative agent, and the lenders parties thereto from time to time, dated as of May 13, 2010 (incorporated by reference from Exhibit 10.1 to Alta Mesa Holdings, LP’s registration statement on Form S-4 filed with the SEC on April 27, 2011).

10.2		Amendment No. 1 to Sixth Amended and Restated Credit Agreement by and among Alta Mesa Holdings, LP, the guarantors parties thereto, Wells Fargo Bank, N.A., as administrative agent, and the lenders parties thereto from time to time, dated as of September 2, 2010 (incorporated by reference from Exhibit 10.2 to Alta Mesa Holdings, LP’s registration statement on Form S-4 filed with the SEC on April 27, 2011).

10.3		Amendment No. 2 to Sixth Amended and Restated Credit Agreement by and among Alta Mesa Holdings, LP, the guarantors parties thereto, Wells Fargo Bank, N.A., as administrative agent, and the lenders parties thereto from time to time, dated as of December 6, 2010 (incorporated by reference from Exhibit 10.3 to Alta Mesa Holdings, LP’s registration statement on Form S-4 filed with the SEC on April 27, 2011).

10.4		Employment Agreement, dated August 31, 2006, between Alta Mesa Services, LP and Harlan H. Chappelle (incorporated by reference from Exhibit 10.4 to Alta Mesa Holdings, LP’s registration statement on Form S-4 filed with the SEC on April 27, 2011).



10.5		Employment Agreement, dated August 31, 2006, between Alta Mesa Services, LP and Michael E. Ellis (incorporated by reference from Exhibit 10.5 to Alta Mesa Holdings, LP’s registration statement on Form S-4 filed with the SEC on April 27, 2011).

10.6		Employment Agreement, dated August 31, 2006, between Alta Mesa Services, LP and Michael A. McCabe (incorporated by reference from Exhibit 10.6 to Alta Mesa Holdings, LP’s registration statement on Form S-4 filed with the SEC on April 27, 2011).

10.7		Employment Agreement, dated October 1, 2006, between Alta Mesa Services, LP and F. David Murrell (incorporated by reference from Exhibit 10.7 to Alta Mesa Holdings, LP’s registration statement on Form S-4 filed with the SEC on April 27, 2011).

10.8		Agreement and Plan of Merger, dated December 22, 2009, by and among Alta Mesa Holdings, LP, Alta Mesa Acquisition Sub, LLC and The Meridian Resource Corporation (incorporated by reference from Exhibit 10.8 to Alta Mesa Holdings, LP’s registration statement on Form S-4 filed with the SEC on April 27, 2011).

10.9		First Amendment to Agreement and Plan of Merger, dated April 7, 2010, by and among Alta Mesa Holdings, LP, Alta Mesa Acquisition Sub, LLC and The Meridian Resource Corporation (incorporated by reference from Exhibit 10.9 to Alta Mesa Holdings, LP’s registration statement on Form S-4 filed with the SEC on April 27, 2011).

10.10		Amended and Restated Promissory Note, dated June 30, 2010, executed by Galveston Bay Resources, LP in favor of Michael E. Ellis (incorporated by reference from Exhibit 10.10 to Alta Mesa Holdings, LP’s registration statement on Form S-4 filed with the SEC on April 27, 2011).

10.11		Amended and Restated Promissory Note, dated June 30, 2010, executed by Alta Mesa Holdings, LP in favor of Michael E. Ellis (incorporated by reference from Exhibit 10.11 to Alta Mesa Holdings, LP’s registration statement on Form S-4 filed with the SEC on April 27, 2011).

10.12		Amended and Restated Promissory Note, dated June 30, 2010, executed by Petro Acquisitions, LP in favor of Michael E. Ellis (incorporated by reference from Exhibit 10.12 to Alta Mesa Holdings, LP’s registration statement on Form S-4 filed with the SEC on April 27, 2011).

10.13		The Meridian Resource & Exploration LLC Change in Control Severance Plan and Summary Plan Description (As Amended and Restated Effective as of May 14, 2010), dated as of May 14, 2010 (incorporated by reference from Exhibit 10.13 to Alta Mesa Holdings, LP’s registration statement on Form S-4 filed with the SEC on April 27, 2011).

10.14		The Meridian Resource Corporation Management Well Bonus Plan, dated as of November 5, 1997 (incorporated by reference from Exhibit 10.14 to Alta Mesa Holdings, LP’s registration statement on Form S-4 filed with the SEC on April 27, 2011).

10.15		Amendment to The Meridian Resource Corporation Management Well Bonus Plan, dated as of May 13, 2010 (incorporated by reference from Exhibit 10.15 to Alta Mesa Holdings, LP’s registration statement on Form S-4 filed with the SEC on April 27, 2011).

10.16		The Meridian Resource Corporation Geoscientist Well Bonus Plan, dated as of November 5, 1997 (incorporated by reference from Exhibit 10.16 to Alta Mesa Holdings, LP’s registration statement on Form S-4 filed with the SEC on April 27, 2011).

10.17		Amendment to The Meridian Resource Corporation Geoscientist Well Bonus Plan, dated as of May 13, 2010 (incorporated by reference from Exhibit 10.17 to Alta Mesa Holdings, LP’s registration statement on Form S-4 filed with the SEC on April 27, 2011).

10.18		The Meridian Resource Corporation TMR Employees Trust Well Bonus Plan, dated as of November 5, 1997 (incorporated by reference from Exhibit 10.18 to Alta Mesa Holdings, LP’s registration statement on Form S-4 filed with the SEC on April 27, 2011).

10.19		Amendment to The Meridian Resource Corporation TMR Employees Trust Well Bonus Plan, dated as of May 13, 2010 (incorporated by reference from Exhibit 10.19 to Alta Mesa Holdings, LP’s registration statement on Form S-4 filed with the SEC on April 27, 2011).

10.20		Amendment No. 3 to Sixth Amended and Restated Credit Agreement by and among Alta Mesa Holdings, LP, Wells Fargo Bank, N.A., as administrative agent, and the lenders party thereto from time to time, dated as of May 23, 2011 (incorporated by reference from Exhibit 10.20 to Alta Mesa Holdings, LP’s registration statement on Form S-4/A filed with the SEC on July 11, 2011).



10.21		First Amendment to The Meridian Resource & Exploration LLC Change in Control Severance Plan and Summary Plan Description (As Amended and Restated Effective as of May 14, 2010), dated as of July 6, 2011 (incorporated by reference from Exhibit 10.21 to Alta Mesa Holdings, LP’s registration statement on Form S-4/A filed with the SEC on July 11, 2011).

10.22		Purchase and Sale Agreement between Michael J. Mayell and Alta Mesa Energy, LLC, dated April 21, 2011 (incorporated by reference from Exhibit 10.1 to Alta Mesa Holdings, LP’s quarterly report on Form 10-Q filed with the SEC on August 12, 2011).

10.23		Purchase and Sale Agreement between Sydson Energy, Inc. and Alta Mesa Energy, LLC, dated April 21, 2011 (incorporated by reference from Exhibit 10.2 to Alta Mesa Holdings, LP’s quarterly report on Form 10-Q filed with the SEC on August 12, 2011).

10.24		Purchase and Sale Agreement by and among Texas Oil Distribution & Development, Inc., JAR Resource Holdings, L.P., Joseph A. Reeves, Jr., Dianne S. Reeves and Alta Mesa Energy, LLC, dated June 17, 2011 (incorporated by reference from Exhibit 10.3 to Alta Mesa Holdings, LP’s quarterly report on Form 10-Q filed with the SEC on August 12, 2011).

10.25		Amendment No. 4 to Sixth Amended and Restated Credit Agreement by and among Alta Mesa Holdings, LP, Wells Fargo Bank, N.A., as administrative agent, and the lenders party thereto from time to time, dated as of November 7, 2011 (incorporated by reference from Exhibit 10.1 to Alta Mesa Holdings, LP’s quarterly report on Form 10-Q filed with the SEC on November 14, 2011).

21.1*		Subsidiaries of the Company.

23.1*		Consent of UHY LLP.

23.2*		Consent of Netherland, Sewell & Associates, Inc.

23.3*		Consent of T. J. Smith & Company, Inc.

23.4*		Consent of W. D. Von Gonten & Co.

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

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

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

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

99.1*		Audit Report by Netherland, Sewell & Associates, Inc. dated as of March 23, 2012.

99.2*		Reserve Report by T. J. Smith & Company, Inc. dated as of February 24, 2012.

99.3*		Reserve Report by W. D. Von Gonten & Co., dated as of February 28, 2012.

101+		Interactive Data Files.

*	Filed herewith.

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

GLOSSARY OF CERTAIN OIL AND NATURAL GAS TERMS

The definitions set forth below apply to the indicated terms as used in this Annual Report on Form 10-K. All volumes of natural gas referred to are stated at the legal pressure base of the state or area where the reserves exist and at 60 degrees Fahrenheit and in most instances are rounded to the nearest major multiple.

“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.

“Bcf”. One billion cubic feet of natural gas.

“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.

“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.

“DD&A”. Depreciation, depletion and amortization.

“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, fracture stimulation technology, hydraulic fracturing”. 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.

“Mcf”. One thousand cubic feet of natural gas.

“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. The ratio of six Mcf 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 Mcf 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 Mcf of natural gas.

“Mcfe/d”. Mcfe per day.

“MMBtu”. One million British thermal units.

“MMcf”. One million cubic feet of natural gas.

“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.

“MMcfe/d”. MMcfe per day.

“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.

“NYMEX”. The New York Mercantile Exchange.

“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.

“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.

“PDNP”. Proved developed non-producing reserves.

“PDP”. Proved developed producing reserves.

“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.

INDEX TO FINANCIAL STATEMENTS

Below is an index to the financial statements and notes contained in Financial Statements and Supplementary Data.


	Page
Audited Financial Statements
Report of Independent Registered Public Accounting Firm		F-1
Consolidated Balance Sheets		F-2
Consolidated Statements of Operations		F-3
Consolidated Statements of Changes in Partners’ Capital		F-4
Consolidated Statements of Cash Flows		F-5
Notes to Consolidated Financial Statements		F-6

Independent Auditors’ Report

To the Partners of

Alta Mesa Holdings, LP and Subsidiaries

Houston, Texas

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.

/S/ UHY LLP

Houston, Texas

March 29, 2012

F-1

ALTA MESA HOLDINGS, LP AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS


	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

See notes to consolidated financial statements.

F-2

ALTA MESA HOLDINGS, LP AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS


	Year Ended December 31,
	2011			2010			2009
	(dollars in thousands)
REVENUES
Natural gas	$	149,580		$	125,866		$	66,290
Oil		161,726			75,827			34,283
Natural gas liquids		12,605			6,844			1,690
Sale of oil and natural gas prospects		467			666			364
Other revenues		1,660			809			1,194

		326,038			210,012			103,821
Unrealized gain (loss) — oil and natural gas derivative contracts		28,169			10,088			(26,258	)

TOTAL REVENUES		354,207			220,100			77,563


EXPENSES
Lease and plant operating expense		62,637			41,905			23,871
Production and ad valorem taxes		19,357			11,141			4,755
Workover expense		11,777			7,409			8,988
Exploration expense		15,785			31,037			12,839
Depreciation, depletion, and amortization expense		94,251			59,090			48,659
Impairment expense		18,735			8,399			6,165
Accretion expense		1,812			1,370			492
General and administrative expense		33,087			20,135			8,738
(Gain) on sale of assets		—			(1,766	)		(738	)

TOTAL EXPENSES		257,441			178,720			113,769


INCOME (LOSS) FROM OPERATIONS		96,766			41,380			(36,206	)

OTHER INCOME (EXPENSE)
Interest expense		(32,722	)		(27,172	)		(13,835	)
Interest income		78			23			4
Gain on contract settlement		1,285			—			—

TOTAL OTHER INCOME (EXPENSE)		(31,359	)		(27,149	)		(13,831	)


INCOME (LOSS) BEFORE STATE INCOME TAXES		65,407			14,231			(50,037	)

BENEFIT FROM (PROVISION FOR) STATE INCOME TAXES		(228	)		(2	)		750

NET INCOME (LOSS)	$	65,179		$	14,229		$	(49,287	)

See notes to consolidated financial statements.

F-3

ALTA MESA HOLDINGS, LP AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CHANGES IN PARTNERS’ CAPITAL

YEARS ENDED DECEMBER 31, 2011, 2010, AND 2009

(dollars in thousands)


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

See notes to consolidated financial statements.

F-4

ALTA MESA HOLDINGS, LP AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS


	Year Ended December 31,
	2011			2010			2009
	(dollars in thousands)
CASH FLOWS FROM OPERATING ACTIVITIES
Net income (loss)	$	65,179		$	14,229		$	(49,287	)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization expense		94,251			59,090			48,659
Impairment expense		18,735			8,399			6,165
Accretion expense		1,812			1,370			492
(Gain) on sale of assets		—			(1,766	)		(738	)
Dry hole expense		6,064			15,834			244
Expired leases		96			—			918
Amortization of loan costs		2,813			4,240			772
Amortization of debt discount		260			65			—
Unrealized (gain) loss on derivatives		(32,256	)		(10,974	)		25,308
(Gain) on contract settlement		(1,285	)		—			—
Interest converted into debt		1,202			1,379			1,191
Settlement of asset retirement obligation		(1,823	)		(453	)		(97	)
Deferred state tax provision (benefit)		228			—			(750	)
Changes in operating assets and liabilities:
Accounts receivable		(2,726	)		(9,255	)		(7,416	)
Other receivables		3,532			(4,612	)		1,192
Prepaid expenses and other non-current assets		(4,478	)		(3,305	)		2,738
Accounts payable, accrued liabilities and other long-term liabilities		(949	)		(13,056	)		4,952

NET CASH PROVIDED BY OPERATING ACTIVITIES		150,655			61,185			34,343

CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures for property and equipment		(193,770	)		(110,083	)		(100,261	)
Acquisitions		(72,363	)		(101,359	)		—
Proceeds from sale of assets		—			3,030			13,688

NET CASH USED IN INVESTING ACTIVITIES		(266,133	)		(208,412	)		(86,573	)

CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from long-term debt		130,500			584,421			37,380
Repayments of long-term debt		(15,000	)		(420,056	)		(6,969	)
Proceeds from short-term debt		—			—			8,000
Repayments of short-term debt		—			—			(8,000	)
Additions to deferred financing costs		(2,063	)		(16,341	)		(788	)
Capital contributions		—			50,000			27,800
Redemption of partnership interest		—			—			(5,500	)
Capital distributions		(165	)		(50,235	)		(100	)

NET CASH PROVIDED BY FINANCING ACTIVITIES		113,272			147,789			51,823

NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS		(2,206	)		562			(407	)
CASH AND CASH EQUIVALENTS, beginning of year		4,836			4,274			4,681

CASH AND CASH EQUIVALENTS, end of year	$	2,630		$	4,836		$	4,274

SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION
Cash paid during the year for interest	$	32,069		$	21,537		$	9,064

Cash paid during the year for taxes	$	—		$	—		$	—

Increase in property asset retirement obligations, net	$	587		$	609		$	162

Change in accruals or liabilities for capital expenditures	$	(17,478	)	$	36,025		$	3,382

See notes to consolidated financial statements.

F-5

ALTA MESA HOLDINGS, LP AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

YEARS ENDED DECEMBER 31, 2011, 2010 AND 2009

NOTE 1 — SUMMARY OF ORGANIZATION AND NATURE OF OPERATIONS

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.

NOTE 2 — SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

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,

F-6

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.

F-7

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

F-8

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.

F-9

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.

Recent Accounting Pronouncements

F-10

NOTE 3 — SIGNIFICANT ACQUISITIONS

Meridian Acquisition

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.

Sydson Acquisition

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

TODD Acquisition

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

In addition to the above, the Company made other insignificant acquisitions during the years ended December 31, 2011 and 2010.

F-11

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):


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

⁽¹⁾	Working capital deficit included a cash balance of $11,589.

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.


	(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

F-12

NOTE 4 — PROPERTY AND EQUIPMENT

Property and equipment consists of the following:


	December 31,
	2011			2010
	(dollars in thousands)
OIL AND NATURAL GAS PROPERTIES
Unproved properties	$	34,797		$	12,020
Accumulated impairment		(5,427	)		(2,686	)

Unproved properties, net		29,370			9,334

Proved oil and natural gas properties		925,578			707,364
Accumulated depreciation, depletion, amortization and impairment		(382,132	)		(273,818	)

Proved oil and natural gas properties, net		543,446			433,546


TOTAL OIL AND NATURAL GAS PROPERTIES, net		572,816			442,880

LAND		1,185			1,185

DRILLING RIG		10,500			10,500
Accumulated depreciation		(1,137	)		(444	)

TOTAL DRILLING RIG, net		9,363			10,056

OTHER PROPERTY AND EQUIPMENT
Office furniture and equipment, software, vehicles		7,313			3,844
Accumulated depreciation		(1,510	)		(1,701	)

OTHER PROPERTY AND EQUIPMENT, net		5,803			2,143

TOTAL PROPERTY AND EQUIPMENT, net	$	589,167		$	456,264

NOTE 5 — FAIR VALUE DISCLOSURES

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

F-13

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:


	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

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.

F-14

NOTE 6 — DERIVATIVE FINANCIAL INSTRUMENTS

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:


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	)

F-15


Fair Values of Derivative Contracts
	Balance Sheet Location at December 31, 2010
	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	$	27,118		$	—		$	34,505		$	—
Fair value of oil and natural gas commodity contracts, (liabilities)		(16,682	)		—			(20,340	)		—
Fair value of interest rate contracts, (liabilities)		—			(3,092	)		—			(2,296	)

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

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

The following table summarizes the effect of the Company’s derivative instruments in the consolidated statements of operations:


	Location of Gain	Classification of	Years Ended December 31,
Derivatives not designated as hedging instruments under ASC 815	(Loss)	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	)

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.

F-16

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:

NATURAL GAS DERIVATIVE CONTRACTS


	Volume in		Weighted		Range
Period and Type of Contract	MMbtu		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

F-17

The Company had the following open derivative contracts for crude oil at December 31, 2011:

OIL DERIVATIVE CONTRACTS


			Weighted		Range
Period and Type of Contract	Volume in Bbls		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

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.

F-18

The Company had the following open financial basis swap contracts for natural gas at December 31, 2011:


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	)

The Company had the following open interest rate swap contracts at December 31, 2011:


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	%

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

NOTE 7 — ASSET RETIREMENT OBLIGATIONS

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:


	Year Ended December 31,
	2011			2010			2009
	(dollars in thousands)
Balance, beginning of year	$	42,713		$	10,267		$	9,710
Liabilities incurred		608			702			748
Liabilities assumed with acquired producing properties		2,807			30,920			—
Liabilities settled		(1,823	)		(453	)		(97	)
Revisions to previous estimates		(21	)		(93	)		(586	)
Accretion expense		1,812			1,370			492

Balance, end of year		46,096			42,713			10,267
Less: Current portion		3,030			1,617			—

Long-term portion	$	43,066		$	41,096		$	10,267

NOTE 8 — RELATED PARTY TRANSACTIONS

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.

F-19

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.

NOTE 9 — LONG TERM DEBT

Long-term debt consists of the following:


	December 31,
	2011		2010
	(dollars in thousands)
Senior Debt — On November 13, 2008, we entered into a Fifth Amended and Restated Credit Agreement with a group of banks, which was replaced by the Sixth Amended and Restated Credit Agreement on May 13, 2010, as amended (“credit facility”). The credit facility matures on May 23, 2016 and is secured by substantially all of our oil and gas properties. The credit facility borrowing base is redetermined periodically and, as of December 31, 2011, the borrowing base under the facility was $325 million. The credit facility bears interest at LIBOR plus applicable margins between 2.00% and 2.75% or a “Reference Rate,” which is based on the prime rate of Wells Fargo Bank, N. A., plus a margin ranging from 1.00% to 1.75%, depending on the utilization of our borrowing base. The rate was 2.774% as of December 31, 2011 and 2.875% as of December 31, 2010.	$	188,790	$	73,290

Senior Notes Payable — On October 13, 2010, the Company issued notes due October 15, 2018 with a face value of $300 million, at a discount of $2.1 million. The senior notes carry a face interest rate of 9.625%, with an effective rate of 9.75%; interest is payable semi-annually each April 15^th and October 15^th. The senior notes are secured by general corporate credit, and effectively rank junior to any existing or future secured indebtedness of the Company, which includes the credit facility. The senior notes are unconditionally guaranteed on a senior unsecured basis by each material subsidiary of the Company. The balance is presented net of unamortized discount of $1.8 million and $2.0 million at December 31, 2011 and 2010, respectively.		298,246		297,986


Total long-term debt	$	487,036	$	371,276

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.

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Future maturities of long-term debt, including the notes payable to our founder, at December 31, 2011 are as follows (dollars in thousands):


Year Ending December 31,
2012		—
2013		—
2014		—
2015		—
2016	$	188,790
Thereafter		320,911

	$	509,701

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.

NOTE 10 — ACCOUNTS PAYABLE AND ACCRUED LIABILITIES

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


	December 31,
	2011		2010
	(dollars in thousands)
Capital expenditures	$	19,119	$	22,743
Revenues and royalties payable		6,742		5,962
Operating expenses/taxes		21,147		18,220
Compensation		3,567		2,591
Acquisition costs payable		2,883		—
Liability related to drilling rig		—		9,785
Other		5,754		1,775

Total accrued liabilities		59,212		61,076
Accounts payable		11,083		26,179

Accounts payable and accrued liabilities	$	70,295	$	87,255

NOTE 11 — COMMITMENTS AND CONTINGENCIES

Contingencies

F-21

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.

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.

Commitments

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.

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At December 31, 2011, future base rentals for non-cancelable leases are as follows (dollars in thousands):


Year Ending December 31,
2012	$	2,884
2013		2,759
2014		1,964
2015		1,606
2016		1,600
Thereafter		8,893

	$	19,706

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.

NOTE 12 — MAJOR CUSTOMERS

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.

NOTE 13 — 401(k) SAVINGS PLAN

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.

F-23

NOTE 14 — SIGNIFICANT RISKS AND UNCERTAINTIES

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.

NOTE 15 — PARTNERS’ CAPITAL

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

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

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

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

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

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.

F-24

NOTE 16 — SUBSEQUENT EVENTS

Management has evaluated all events subsequent to the balance sheet date of December 31, 2011 and has determined that no subsequent events require disclosure.

NOTE 17 — SUBSIDIARY GUARANTORS

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

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

NOTE 18 — QUARTERLY RESULTS OF OPERATIONS (Unaudited)

Results of operations by quarter for the year ended December 31, 2011 were:


	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

Results of operations by quarter for the year ended December 31, 2010 were:


	Quarter Ended
2010	March 31		June 30		Sept. 30		Dec. 31
	(dollars in thousands)
Revenues	$	58,889	$	50,103	$	63,040	$	48,068
Results of operations from exploration and production activities (1)		13,298		18,465		19,467		(1,569	)
Net income (loss)	$	27,679	$	11,366	$	10,130	$	(34,946	)

(1)

Results of operations from exploration and production activities, which approximate gross profit, are computed as revenues, exclusive of unrealized gain/loss on oil and natural gas derivative contracts, less expenses for lease operating, severance and ad valorem taxes, workovers, exploration, depletion and depreciation, impairment, and accretion.

NOTE 19 — SUPPLEMENTAL OIL AND NATURAL GAS DISCLOSURES (UNAUDITED)

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

F-25

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.

F-26

Estimated Quantities of Proved Reserves

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.


	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

(1)	Natural gas liquids were not tracked in our reserve reports prior to 2010.

(2)	Primarily the purchase of producing properties in the Hilltop field (Deep Bossier trend) in 2009.

(3)	Purchase of Meridian in 2010.

(4)	Primarily the purchases of Sydson and TODD in 2011.

Proved Undeveloped Reserves

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Capitalized Costs Relating to Oil and Natural Gas Producing Activities


	December 31,
	2011			2010
	(dollars in thousands)
Capitalized costs:
Proved properties	$	925,578		$	707,364
Unproved properties		34,797			12,020

Total		960,375			719,384
Accumulated depreciation, depletion and amortization		(387,559	)		(276,504	)

Net capitalized costs	$	572,816		$	442,880

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.


	Year Ended December 31,
	2011		2010		2009
	(dollars in thousands)
Costs incurred during the year:
Property acquisition costs
Unproved	$	37,152	$	3,018	$	2,383
Proved(1)		53,601		148,518		47,415
Exploration		24,079		57,830		17,636
Development(2)		142,212		98,053		46,480

	$	257,044	$	307,419	$	113,914

(1)

Property acquisition costs for proved properties in 2011 include primarily the purchase of Sydson ($28.4 million) and TODD ($23.4 million). Property acquisition costs for proved properties in 2010 include the purchase of Meridian for $147.4 million and an adjustment to the purchase price of the Hilltop (Deep Bossier) properties of $1.0 million. Property acquisition costs for proved properties in 2009 include acquisition of a group of producing wells in Hilltop field, $43.5 million.

(2)	Includes asset retirement costs of $587,000, $609,000, and $162,000, for the years ended December 31, 2011, 2010, and 2009, respectively.

Suspended Well Costs

There were no wells in suspense at December 31, 2011, 2010 and 2009, respectively.

F-28

Results of Operations from Oil and Natural Gas Producing Activities


	Year Ended December 31,
	2011		2010			2009
	(dollars in thousands)
Operating revenues:
Natural gas	$	149,580	$	125,866		$	66,290
Oil		161,726		75,827			34,283
Natural gas liquids		12,605		6,844			1,690
Other revenue		2,127		1,475			1,558

		326,038		210,012			103,821

Less:
Lease and plant operating expense		62,637		41,905			23,871
Production and ad valorem taxes		19,357		11,141			4,755
Workover expense		11,777		7,409			8,988
Exploration expense		15,785		31,037			12,839
Depreciation, depletion and amortization expense (1)		92,321		58,152			47,261
Impairment expense		18,735		8,399			6,165
Accretion expense		1,812		1,370			492
Gain on sale of assets		—		(1,766	)		(738	)
(Benefit from) provision for state income taxes		228		2			(750	)

		222,652		157,649			102,883

Results of operations from oil and natural gas producing activities	$	103,386	$	52,363		$	938

Depletion and amortization expense per Mcfe (1)	$	2.22	$	1.89		$	3.40

(1)	Excludes depreciation of non-oil and gas assets of $1.9 million, $0.9 million, and $1.4 million in 2011, 2010, and 2009, respectively.

Standardized Measure of Discounted Future Net Cash Flows

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.

F-29

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:


	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

No consideration was given to the Company’s hedged transactions.

Changes in Standardized Measure of Discounted Future Net Cash Flows

The following table sets forth the changes in standardized measure of discounted future net cash flows:


	Year Ended December 31,
	2011			2010			2009
	(dollars in thousands)

Balance at beginning of year	$	705,182		$	338,297		$	277,358
Sales of oil and natural gas, net of production costs		(230,140	)		(148,082	)		(64,649	)
Changes in sales and transfer prices, net of production costs		219,797			27,025			(124,417	)
Revisions of previous quantity estimates		(15,217	)		(15,189	)		16,223
Purchases of reserves-in-place		47,680			250,996			177,581
Sales of reserves-in-place		—			—			—
Current year discoveries and extensions		228,041			131,492			48,744
Changes in estimated future development costs		(5,987	)		5,998			(9,740	)
Development costs incurred during the year		47,402			29,413			27,917
Accretion of discount		70,518			33,830			27,736
Net change in income taxes		—			—			—
Change in production rate (timing) and other		2,920			51,402			(38,456	)


Net change		365,014			366,885			60,939


Balance at end of year	$	1,070,196		$	705,182		$	338,297

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Large accelerated filer

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