UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-K

For the fiscal year ended December 31, 20092012

OR

For the transition period fromto

Commission file no.number: 333-134748

Chaparral Energy, Inc.

(Exact name of registrant as specified in its charter)

(405) 478-8770

(Registrant’s telephone number, including area code:code)

(405) 478-8770

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  ¨    No  x

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  ¨    No  x

(Explanatory Note: The registrant is a voluntary filer and is not subject to the filing requirements of the Securities Exchange Act of 1934. However, during the preceding 12 months, the registrant has filed all reports that it would have been required to file by Section 13 or 15(d) of the Securities Exchange Act of 1934 if the registrant was subject to the filing requirements of the Securities Exchange Act of 1934.)

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(§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 (Section 229.405 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 the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.

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

The aggregate market value of common equity held by non-affiliates of the registrant is not determinable as such shares wereare privately placedheld and there is no public market for such shares.

1,401,376Number of shares outstanding of each of the registrant’sissuer’s classes of common stock were outstanding as of April 14, 2010.

CHAPARRAL ENERGY, INC.

Index to Form 10-K1, 2013:

CHAPARRAL ENERGY, INC.

Index to Form 10-K

CAUTIONARY NOTE

REGARDING FORWARD-LOOKING STATEMENTS

TheThis report includes statements contained in this report that are not purely historical are forward-looking statements. Theconstitute forward-looking statements include,within the meaning of the federal securities law. These statements are subject to risks and uncertainties. These statements may relate to, but are not limited to, information or assumptions about us, our capital and other expenditures, dividends, financing plans, capital structure, cash flow, pending legal and regulatory proceedings and claims, including environmental matters, future economic performance, operating income, cost savings, and management’s plans, strategies, goals and objectives for future operations and growth. These forward-looking statements regarding our expectations, hopes, beliefs, intentions or strategies regarding the future. In addition, any statements that refer to projections, forecasts or other characterizations of future events or circumstances, including any underlying assumptions,generally are forward-looking statements. Theaccompanied by words such as “intend,” “anticipate,” “believe,” “continue,” “could,” “estimate,” “expect,” “intend,“should,” “may,” “might,” “plan,” “possible,” “potential,” “predict,“seek,” “project,” “should,” “would” and“plan” or similar expressions may identifyexpressions. Any statement that is not a historical fact is a forward-looking statement. It should be understood that these forward-looking statements butare necessarily estimates reflecting the absencebest judgment of these words doessenior management, not meanguarantees of future performance. They are subject to a number of assumptions, risks and uncertainties that a statement is not forward-looking.could cause actual results to differ materially from those expressed or implied in the forward-looking statements. Forward-looking statements in this report may include, for example, statements about:

The forward-looking statements contained in this report are based on our current expectations and beliefs concerning future developments and their potential effects. There can be no assurance that future developments affecting us will be those that we have anticipated.

These forward-looking statements involve a number ofrepresent intentions, plans, expectations, assumptions and beliefs about future events and are subject to risks, uncertainties (some of which are beyond our control) and other assumptions that mayfactors. Many of those factors are outside of our control and could cause actual results or performance to bediffer materially different from thosethe results expressed or implied by thesethose forward-looking statements. These risks and uncertainties include thoseIn addition to the risk factors described under the heading “Risk Factors.Factors,” Specifically, somethe factors that could cause actual results to differ include:

Should one or more of these risks or uncertainties materialize, or should any of our assumptions prove incorrect, actual results may vary in material respects from those projected in thesethe forward-looking statements.statements contained herein. We undertake no obligation to update or revise any forward-looking statements, whether as a result of new information, future events or otherwise, except as may be required under applicable securities laws. All forward-looking statements included herein are expressly qualified in their entirety by the cautionary statements contained or referred to in this section.

Glossary of termsGLOSSARY OF TERMS

The terms defined in this section are used throughout this annual report on Form 10-K:

MBbls		One thousand barrels of crude oil, condensate, or natural gas liquids.
MBoe		One thousand barrels of crude oil equivalent.
Mcf		One thousand cubic feet of natural gas.
MMBbls		One million barrels of crude oil, condensate, or natural gas liquids.
MMBoe		One million barrels of crude oil equivalent.
MMBtu		One million British thermal units.
MMcf		One million cubic feet of natural gas.
NYMEX MMcf/d		The New York Mercantile Exchange.Millions of cubic feet per day.
Net acres		The percentage of total acres an owner has out of a particular number of acres, or in a specified tract. An owner who has a 50% interest in 100 acres owns 50 net acres.
Net working interest NYMEX		A working interest owner’s gross working interest in production, less the related royalty, overriding royalty, production payment, and net profits interests.The New York Mercantile Exchange.
PDP		Proved developed producing.
Play		A term describing an area of land following the identification by geologists and geophysicists of reservoirs with potential oil and natural gas reserves.
PV-10 value		When used with respect to oil and natural gas reserves, PV-10 value 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, excluding escalations of prices and costs based upon future conditions, 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 Securities and Exchange Commission.
Primary recovery		The period of production in which oil moves from its reservoir through the wellbore under naturally occurring reservoir pressure.
Proved developed reserves		Reserves that can be expected to be recovered through existing wells with existing equipment and operating methods, or in which the cost of the required equipment is relatively minor compared to the cost of a new well.
Proved reserves		The quantities of oil and 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.
Proved undeveloped reserves		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.
Sand PV-10 value		When used with respect to oil and natural gas reserves, PV-10 value means the estimated future gross revenue to be generated from the production of proved reserves, net of estimated production and future development costs, excluding escalations of prices and costs based upon future conditions, before income taxes, and without giving effect to non-property-related expenses, discounted to a present value using an annual discount rate of 10%.
Sandstone		A geological termclastic sedimentary rock composed mainly of cemented sand-sized minerals or rock grains. Most sandstone is composed of quartz or feldspar. It is an important reservoir rock for hydrocarbon production in the earth’s subsurface. It is usually a formation beneath the surface of the earth from which hydrocarbons are produced. Its make-up is sufficiently homogeneous to differentiate it from other formations.more resistant rock than limestone and generally has less lateral variability in porosity.

SEC		The Securities and Exchange Commission.
Secondary recovery		The recovery of oil and natural gas through the injection of liquids or gases into the reservoir, supplementing its natural energy. Secondary recovery methods are often applied when production slows due to depletion of the natural pressure.
Seismic survey		Also known as a seismograph survey, it is a survey of an area by means of an instrument which records the vibrations of the earth. By recording the time interval between the source of the shock wave and the reflected or refracted shock waves from various formations, geophysicists are able to define the underground configurations.
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.
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.
WTI Cushing spot price		The price of West Texas Intermediate grade crude oil, in dollars per barrel, in transactions for immediate delivery at Cushing, Oklahoma.
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 a secondary recovery process.
Wellbore		The hole drilled by the bit that is equipped for oil or 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 oil, natural gas, or other minerals. The working interest owners bear the exploration, development, and operating costs on either a cash, penalty, or carried basis.
Zone		A layer of rock which has distinct characteristics that differ from nearby layers of rock.

PART I

Unless the context requires otherwise, references in this annual report to the “Company”, “we”, “our”, “ours”“Company,” “Chaparral,” “we,” “our,” and “us” refer to Chaparral Energy, Inc. and its subsidiaries on a consolidated basis. We have provided definitions of terms commonly used in the oil and natural gas industry in the “Glossary of terms” at the beginning of this annual report.

ITEMS 1. AND 2. BUSINESS AND PROPERTIES

Overview

We are ana growing independent oil and natural gas company engagedproduction and exploitation company. Since our inception in the1988, we have increased reserves and production exploitation,primarily through property acquisitions and acquisitiondevelopment activities. Our core operations consist of drilling for and production of oil and natural gas properties. Our core areas of operation includefrom conventional and unconventional reservoirs as well as a focus on tertiary operations through enhanced oil recovery (“EOR”) projects utilizing CO₂ and polymer in the Mid-Continent and Permian Basin with additional operations in the Gulf Coast, Ark-La-Tex, North Texas, and the Rocky Mountains.areas. We maintain a portfolio of proved and unproved reserves, development and exploratory drilling opportunities, and enhanced oil recovery (EOR)EOR projects.

On April 12, 2010, Starting in 2011, we sold 475,043 shares ofbegan to redirect our common stock to CCMP Capital investors II (AV-2), L.P., CCMP Energy I LTD., and CCMP Capital Investors (Cayman) II, L.P. (collectively, “CCMP”) for a purchase price of $325.0 million. In connection with the closing of the sale, we entered into and closed an Eighth Restated Credit Agreement, which has an initial borrowing base of $450.0 million, is collateralized by our oil and gas properties, and is scheduled to mature on April 12, 2014. We used the proceedscapital expenditures from the saledrilling of common stockvertical wells to CCMP, along with proceeds available under the Eighth Restated Credit Agreement, to repay the amounts owing underdrilling of horizontal wells in repeatable resource plays and increased our Seventh Restated Credit Agreement. Aslevel of April 14, 2010, we had $275.3 million of availability under our Eight Restated Credit Agreement. See Note 14 to our consolidated financial statements for additional information regarding these transactions.expenditures on EOR projects.

As of December 31, 2009, based on SEC pricing as defined below,2012, we had estimated proved reserves of 141.9146.1 MMBoe with a PV-10 value of approximately $1.3$2.1 billion. These estimated proved reserves included 29.5 MMBoe of EOR reserves. Our reserves were 66%65% proved developed and 63%65% crude oil. For the year ended December 31, 2009,2012, our net average daily production was 20.925.0 MBoe, with anour estimated reserve life of 19was approximately 16 years, and our oil and natural gas revenues were $292.4 million.$509.5 million . We set forth our definition of PV-10 value (a non-GAAP measure) and a reconciliation of the standardized measure of discounted future net cash flows to PV-10 value on page 24.

Our reserve estimates as of December 31, 2009 were prepared using an average price for oil and natural gas based upon the first day of each month for the prior twelve months as required by the SEC’sModernization of Oil and Gas Reporting. Our reserve estimates prior to December 31, 2009 were prepared using the spot price for oil and gas on the last day of the reporting period. If our reserves had been prepared based on the guidelines in effect prior to December 31, 2009, including spot prices on the last day of the reporting period of $79.36 per Bbl of oil and $5.79 per Mcf of natural gas at December 31, 2009, our estimated proved reserves would have been approximately 160.7 MMBoe with a PV-10 value of approximately $2.2 billion.26.

From 2003 to 2009,2012, our proved reserves and production grew at a compounded annual growth rate of 19%12% and 20%15%, respectively. During this period, we have grown primarily through a combination of developmental drilling and a disciplined strategy of acquiring proved oil and natural gas reserves, followed by exploitation activities and the acquisition of additional interests in or near these acquired properties. We have typically pursuepursued properties in the second half of their life with stable production, shallow decline rates and with particular producing trends and characteristics indicative of production or reserve enhancement opportunities. Since 2011, we have reduced the amount of costs incurred for proved property acquisitions and spent more on acquisition of leasehold acreage and exploration costs in resource plays with repeatable drilling opportunities. In 1993, we began acquiring properties with CO₂ EOR potential. To date, over 72 of these propertiespotential, and we have been acquired andinitiated CO₂ injection operations have been initiated in ten9 of these units.units to date. In 2005 and 2006, we completed two larger acquisitions of $152.9 million and $480.5 million, respectively, of oil and natural gas properties which contained substantial CO₂ EOR potential and complemented our existing property base. We currently expect our futurelong-term growth to continue through a combination of developmental drilling, exploitation projects, and acquisitions, complemented by a modest amount of exploration activities.

Forcome from the year ended December 31, 2009, we made capital expenditures for oil and natural gas properties of $150.9 million, including $77.8 million for developmental drilling and $18.3 million for acquisitions. The majoritydevelopment of our capital expenditures for developmentalCO₂ EOR operations, with our near term growth coming from drilling in 2009 were allocated to our core areas of the Mid-Continent and Permian Basin. The wells we drill in these areas are primarily infill or single stepout wells, which are characterized as lower-risk. We have budgeted $268.0 million for capital expenditures for oil and natural gas properties in 2010.activities.

Business StrengthsStrategy

Consistent track record of reserve additionsWe are positioned to grow our reserves and production growth.profitably through our oil focused drilling activities, primarily in our repeatable resource plays, in the near term and through our CO₂ EOR projects in the long term. From 2003 to 2009,2012, we have grown proved reserves and production by a compounded annual growth rate of 19%12% and 20%15%, respectively. We have achieved thisrespectively, through a combination of drilling and acquisition success. A number of high impact wells that we expect will support our production throughout 2010 are currently being drilled and should be completed and on line during the first and second quarters of 2010. Six of these wells are located in the Texas Panhandle Atoka Wash and one is located in the Haley Area of Loving County, Texas. However, we cannot accurately predict the timing or level of future production.

Our reserve replacement ratio, which reflects our reserve additions from acquisitions, extensions and discoveries, and improved recoveries in a given period stated as a percentage of our production in the same period, has averaged 514%383% per year since 2002.from 2003 through 2012. We replaced approximately 243%, 200%, and 372%156% of our production in 2009, 2008, and 2007, respectively.

Disciplined approach to proved reserve acquisitions. We have a dedicated team that analyzes allAs part of our acquisition opportunities. This team conducts due diligence with reserve engineering on a well-by-well basis to determine whether assets under consideration meet our acquisition criteria. We typically target properties where we can identify enhancements that we believe will increase production rates and extend the producing life of the well. The large number of acquisition opportunities we review allows us to be selective and focus on properties that we believe have the most potential for value enhancement. In 2009, 2008 and 2007, our capital expenditures for acquisitions of proved properties were $14.6 million, $39.2 million, and $41.7 million, respectively. These acquisition capital expenditures represented approximately 10%, 13%, and 18%, respectively, of our total capital expenditures and approximately 4%, 17%, and 13%, respectively, of our increase in reserves related to purchases of minerals in place, extensions and discoveries, and improved recoveries for those periods. We have budgeted $20.0 million, or 7% of our total capital expenditures, for acquisitions in 2010.

Property enhancement expertise. Our ability to enhance acquired properties allows us to increase their production rates and economic value. Our typical enhancements include the repair or replacement of casing and tubing, installation of plunger lifts and pumping units, installation of coiled tubing or siphon strings, compression, workovers and recompletion to new zones. Minimal amounts of investment have significantly enhanced the value of many of our properties.

Inventory of drilling locations. Based on SEC pricing for the year ended December 31, 2009 of $61.18 per Bbl of oil and $3.87 per Mcf of natural gas, we had an inventory of 1,333 proved undeveloped drilling locations.

Identified drilling locations represent total gross drilling locations identified by our management as an estimation of our multi-year drilling activities on existing acreage. As more fully discussed in the section “Risk factors,” our actual drilling activities may change depending on the availability of financing and capital, regulatory approvals, seasonal restrictions, oil and natural gas prices, costs, drilling results and other factors. We have experienced a high historical drilling success rate of approximately 99% on a weighted average basis during 2009, 2008 and 2007. For the year ended December 31, 2009, we spent $82.8 million of developmental drilling and exploration costs to drill 51 (48 net) operated wells and to participate in 121 (4 net) wells operated by others, representing 80% of our additions to reserves. For 2010, we have budgeted $173.0 for developmental and exploratory drilling.

Enhanced oil recovery expertise and asset. Beginning in 2000, we expanded our operations to include CO₂ EOR. CO₂ EOR involves the injection of CO₂, which mixes with the remaining oil in place in the producing reservoir, followed by the injection of water in cycles to drive the hydrocarbons to producing wells. We have a staff of eight engineers that have substantial expertise in CO₂ EOR operations, and we also have specific software for modeling these projects. We own a 29% interest in and operate a large CO₂ EOR unit in southern Oklahoma and have installed and operate a second CO₂ EOR unit with a 54% interest in the Oklahoma and Texas panhandles. We began CO₂ injection in our Perryton Unit in December 2006 and in our Booker Area Units in September 2009, and plan to initiate CO₂ injection in our NW Camrick Unit, our North Farnsworth Unit, and our NW Velma Hoxbar Unit in 2010. At December 31, 2009, our proved reserves included nine units where CO₂ EOR recovery methods are used, representing approximately 7% of our total proved reserves. In addition, we operate a polymer EOR flood in the North Burbank unit. This unit is in the early phases of a polymer EOR flood which was proven up by Phillips Petroleum Company through a pilot program in the early 1980’s before being shut down due to low prevailing oil prices at that time. We initiated polymer injection in this unit in a pilot program in December 2007. In the pilot area, we are seeing production response as production has increased from 90 Bbls of oil per day to 160 Bbls of oil per day. We plan to expand this polymer EOR program and introduce CO₂ injection into this unit after acquiring a source of CO₂ in this area.

Experienced management team. Mark A. Fischer, our Chief Executive Officer and founder, has operated in the oil and natural gas industry for 38 years after starting his career at Exxon Mobil Corporation as a petroleum engineer. Joe Evans, our Chief Financial Officer, has over 30 years of experience in the oil and natural gas industry. Individuals in our 23-person management team have an average of nearly 30 years of experience in the oil and natural gas industry.

Business Strategy

We seekstrategy to grow reserves and production profitably, through a balanced mix of developmental drilling, enhancements, acquisitions, EOR projects, and a modest number of exploration projects. Further, we strive to control our operations and costs and to minimize commodity price risk through a conservative financial hedging program. The principal elements of our strategy include:

Continue lower-risk developmental drilling program. During the year ended December 31, 2009, we spent approximately $77.8 million on development drilling, which represents 52% of our capital expenditures for such period. A majority of these drilling wells are in our core areas of the Mid-Continent and the Permian Basin. The wells we drill in these areas are generally infill or single stepout wells, which are characterized as lower risk. We currently plan to spend a total of approximately $163.0 million, or approximately 61% of our capital expenditures, on developmental drilling in 2010.

Acquire long-lived properties with enhancement opportunities. We continually evaluate acquisition opportunities and expect that they will continue to play a significant role in increasing our reserve base and future drilling inventory. We have traditionally targeted smaller asset acquisitions which allow us to absorb, enhance and exploit the properties without taking on excessive integration risk. During the year ended December 31, 2009, we made approximately $14.6 million of proved reserve acquisitions, or 10% of our total capital expenditures. We have budgeted $20.0 million, or 7% of our total capital expenditures, for acquisitions in 2010.

Apply technical expertise to enhance mature properties. Once we acquire a property and become the operator, we seek to maximize production through enhancement techniques and the reduction of operating costs. We have built our business around a strong engineering team with expertise in the areas where we operate. We believe retaining our own field staff and operating offices close to our properties allows us to maintain tight control over our operations. We have 21 field offices in Oklahoma, Texas and Kansas. Our personnel possess a high degree of expertise in working with lower pressure or depleted reservoirs and, as a result, are able to identify enhancement opportunities with low capital requirements such as installing a plunger lift, pumping unit or compressor, as well as returning inactive wells to production by repairing various mechanical problems. As of December 31, 2009, our reserve report included 840 shut-in and behind-pipe enhancement projects requiring total estimated capital expenditures of $69.6 million over the life of the reserves.

Expand CO₂ EOR activities. As of December 31, 2009, we have accumulated interests in 72 properties in Oklahoma, Kansas, New Mexico and Texas that meet our criteria for CO₂ EOR operations, and are expanding our CO₂pipeline system to initiate CO₂ injection in certain of these properties. We began CO₂ injection in our Perryton Unit in December 2006 and in our Booker Area Units in September 2009, and plan to initiate CO₂ injection in our NW Camrick Unit, our North Farnsworth Unit, and our NW Velma Hoxbar Unit in 2010. To support our existing CO₂ EOR projects, we currently inject approximately 50 MMcf per day of purchased and recycled CO₂ and have developed a CO₂ pipeline infrastructure system with ownership interests in over 374 miles of CO₂ pipelines. This consists of a 100% ownership interest in our 86-mile Borger CO₂ pipeline, a 29% interest in the 120-mile Enid to Purdy CO₂ pipeline, a 58% interest in the 23-mile Purdy to Velma CO₂ pipeline, which we operate, and a 100% interest in the 126-mile Booker CO2 pipeline. Most of our injected CO₂ is anthropogenic (man-made) CO₂ which we capture from three different sources. We recently installed compression and purification facilities, on which we have applied for a patent, that are currently capturing approximately eight to ten MMcf per day of CO₂ from the Arkalon ethanol plant in Liberal, Kansas. We began injecting CO₂ captured from this plant into the Booker Area fields in the third quarter of 2009. After the completion of additional work, we expect these facilities to capture approximately 15 to 19 MMcf per day of CO₂.

Pursue modest exploration program. During the year ended December 31, 2009, we spent $5.0 million on exploration activities. We have budgeted $10.0 million for exploration activities in 2010.

Control operations and costs. We seek to serve as operator of the wells in which we own a significant interest. As operator, we are better positioned to control the (1) timing and plans for future enhancement and exploitation efforts; (2) costs of enhancing, drilling, completing and producing the wells; and (3) marketing negotiations for our oil and natural gas production to maximize both volumes and wellhead price. As of December 31, 2009,2012, we operated properties comprising approximately 86%85% of our proved reserves. We also strive to minimize commodity price risk through our financial hedging program. The principal elements of our strategy are described further below.

Focus drilling program on repeatable resource plays. During the year ended December 31, 2012, we spent approximately $268.6 million on drilling. We consider our repeatable resource plays to include the Northern Oklahoma Mississippi Play, the Anadarko Granite Wash, the Anadarko Cleveland Sand, the Anadarko Woodford Shale, the Panhandle Marmaton, and the Bone Spring/Avalon Shale. During 2012, we spent $217.7 million of our drilling capital in these plays. Our drilling expenditures represented approximately 52% of our total capital expenditures for oil and natural gas properties and approximately 94% of our increase in reserves related to purchases of minerals in place, extensions and discoveries, and improved recoveries for 2012. In 2013, we currently plan to spend approximately 58% of our capital expenditures, or $234.0 million, on drilling, including $183.0 million in our repeatable resource plays mentioned above. As more fully discussed in the section “Risk factors,” our actual drilling activities may change depending on the availability of financing and capital, regulatory approvals, seasonal restrictions, oil and natural gas prices, costs, drilling results and other factors.

Expand EOR activities. We define EOR activities as activities on properties that have proved EOR reserves, ongoing EOR operations, or that have an approved authorization for expenditure for EOR operations. As of December 31, 2012, we have 11 active EOR projects including nine units where we are actively injecting CO₂ and one project at our North Burbank Unit where polymer is utilized. We plan to continue the polymer program and introduce CO₂ into the North Burbank Unit in 2013. During 2012, we spent $194.0 million, which was an increase from $88.2 million in 2011 and included $52.2 million classified as exploration costs, on the development of our EOR assets. We have budgeted $137.0 million for development of our EOR assets in 2013. In 2014, our EOR capital investments are expected to increase somewhat but remain less than incurred in 2012 and should range between $75.0 million to $150.0 million in subsequent years.

CO₂ used in EOR is an efficient method of producing crude oil. CO₂ EOR involves the injection of CO₂, which mixes with the remaining oil in place in the producing reservoir, followed by the injection of water in alternating cycles to drive the oil to producing wells and control gas processing rates, a process known as water alternating gas (“WAG”). Since we commenced CO₂ injection in the Camrick Unit in 2001, we have gradually increased our emphasis on EOR operations. Beginning in 2010, we have further heightened our focus on this aspect of our business. During the past decade, we have learned a significant amount about the production of CO₂, transportation of CO₂, and EOR operations. Our EOR operations accounted for approximately 9% of our 2012 production and approximately 20% of our proved reserves at December 31, 2012. We believe CO₂-based EOR has many advantages, including: (1) it has a lower risk since we are working in fields that have substantial production histories and other historic data (i.e., known oil); (2) it provides a reasonable rate of return; and (3) we have limited competition for this type of activity in our primary EOR project areas.

Our active EOR projects are located in the Burbank area of northeast Oklahoma (“Burbank”), the Panhandle areas of Oklahoma and Texas (“Panhandle”), Central Oklahoma (“Central Oklahoma”), and the Permian Basin Area in West Texas and Southeast New Mexico (“Permian Basin Area”). In addition to our operated projects, we hold ownership interests in outside-operated CO₂ projects in the Panhandle Area, and have a small ownership interest in one outside-operated active EOR property in the Permian Basin Area. We currently have a total of 74 properties that we are analyzing in regard to their CO₂ EOR potential. To support our operated CO₂ projects, we have CO₂ supply agreements for the Panhandle and Central Oklahoma properties. We have also developed a CO₂ pipeline infrastructure system with ownership interests in 405 miles (245 net) of CO₂ pipelines, of which more than 328 miles are currently active. All of the CO₂ injected in our operated EOR units is anthropogenic (man-made) CO₂ which is captured from three different sources. A fourth source of CO₂ will be added in 2013 as we begin taking CO₂ from a fertilizer plant in Coffeyville, Kansas for injection in our North Burbank Unit. We believe we are the largest and one of only a few CO₂ EOR operators that use exclusively anthropogenic CO₂ from industrial manufacturing.

Acquire properties for future growth. In 2012, we redirected our acquisition expenditures from mature properties with enhancement opportunities to prospect acreage in areas we consider to be repeatable resource plays.

Our total acquisitions during the year ended December 31, 2012 were $48.0 million, including $1.1 million of proved reserve acquisitions, which represented approximately 0.1% of our increase in reserves related to purchases of minerals in place, extensions and discoveries, and improved recoveries for 2012. We have budgeted $25.0 million, or 6% of our total capital expenditures, for acquisitions in 2013. We will continue to consider individual field acquisitions that would complement our oil resource strategy.

Apply technical expertise to enhance mature properties. We seek to maximize the production and economic value of our base of mature properties through enhancement techniques and the reduction of operating costs. We have built our business around a strong engineering team with expertise in the areas where we operate. We believe retaining our own field staff and operating offices close to our properties allows us to maintain tight control over our operations. We have 25 field offices in Oklahoma, Texas, Kansas and Louisiana. Our personnel possess a high degree of expertise in working with lower pressure or depleted reservoirs and, as a result, are able to identify enhancement opportunities with low capital requirements such as installing a plunger lift, pumping unit or compressor, as well as returning inactive wells to production by repairing various mechanical problems. Minimal amounts of investment have significantly enhanced the value of many of our properties. As of December 31, 2012, our proved reserves included 840 shut-in and behind-pipe enhancement projects requiring total estimated capital expenditures of $78.6 million over the life of the reserves.

Maintain an experienced management team and strong investor support. Mark Fischer, our Chief Executive Officer and founder, has operated in the oil and natural gas industry for more than 40 years after starting his career at Exxon Mobil Corporation as a petroleum engineer. Joe Evans, our Chief Financial Officer, has over 35 years of experience in the oil and natural gas industry. Earl Reynolds, who became our Chief Operating Officer in February 2011, has 30 years of oil and natural gas production experience. Individuals in our 23-person management team have an average of 30 years of experience in the oil and natural gas industry.

CCMP Capital is a leading global private equity firm with more than 21years in the energy industry, investing approximately $1.4 billion in energy over its history. CCMP Managing Director Chris Behrens joined our board of directors in 2010. Mr. Behrens has worked in private equity for 18 years and leads CCMP Capital’s energy investment activities.

Hedge production to stabilize cash flow. Our long-lived reserves provide us with relatively predictable production. To protect cash flows that we use for on-going operations and for capital investments, and to lock in returns on acquisitions, we enter into commodity price swaps, costless collars, and basis protection swaps. We consider all these derivative instrumentsDerivative positions are adjusted in response to be economic hedgeschanges in prices and market conditions as part of an ongoing dynamic process.

Based on our year-end proved developed production, regardless of whether hedge accounting is applied. Asreserves estimated using SEC pricing as of December 31, 2009,2012, we had commodity price swaps and costless collarsderivative contracts in place for approximately 77%21% and 73%63%, respectively, of our most recent internally estimated proved developed oil and natural gas liquids and natural gas production forthrough 2014. During 2012, we received $11.8 million and in 2011 we paid $57.6 million on the net settlement of our derivative oil contracts and received $25.5 million and $34.1 million, respectively, on the net settlement of our derivative natural gas contracts through a period of increasing oil prices and decreasing natural gas prices. During 2010, through 2011. For the year ended December 31, 2009, we received net derivative settlements of $157.9 million. While our derivative activities protect our cash flows during periods of commodity price declines, we paid net derivative settlements of $51.6$40.0 million and $20.5 million for the years ended December 31, 2008 and 2007, respectively, through a period of increasing commodity prices.

During the fourth quarter of 2008, we monetized oil and natural gas swaps and collars with original settlement dates from January through June of 2009 for proceeds of $32.6 million. During the first quarter of 2009, we monetized additional natural gas swaps with original settlement dates from May through October of 2009 for proceeds of $9.5 million. During the second quarter of 2009, we monetized additional oil swaps and collars with original settlement dates from January 2012 through December 2013 for proceeds of $102.4 million. Thewhich included proceeds from theseearly derivative monetizations are included in the net settlements described above.of $7.1 million.

Properties

The following table presents our proved reserves, and PV-10 value as of December 31, 2009 and2012, average net daily production for the year ended December 31, 2009,2012, and average net daily production for the quarter ended December 31, 2012 , by our areas of operation. Reserves were estimated using a twelve-month average price, calculated as the unweighted arithmetic average of the first-day-of-the-month price for each month within the twelve-month period prior to the end of the reporting period, unless prices were defined by contractual arrangements. Prices used as of December 31, 20092012 were estimated using SEC pricing, which was $61.18$94.71 per Bbl of oil and $3.87$2.76 per Mcf of gas.

Our properties have relatively long reserve lives and highly predictable production profiles. In general, these properties have extensive production histories and production enhancement opportunities. While our portfolio of oil and natural gas properties is geographically diversified, 87% of our 2009 production was concentrated in our two core areas, which allows for substantial economies of scale in production and cost effective application of reservoir management techniques. As of December 31, 2009,2012, we owned interests in 8,1748,243 gross (2,807(2,843 net) producing wells and we operated wells representing approximately 86%85% of our proved reserves. The high proportion of reserves in our operated properties allows us to exercise more control over expenses, capital allocations and the timing of development and exploitation activities in our fields.

Mid-ContinentEnhanced Oil Recovery Project Areas

The Mid-Continent Area is the larger of our two core areasOur EOR Project Areas include both EOR activities and ongoing non-EOR activities, as of December 31, 2009, accounted for 79% of our proved reserves and 79% of our PV-10 value. We own a working interest in 5,392 producing wellsreflected in the Mid-Continent Area, of which we operate 2,100. The Mid-Continent Area has nine of our top ten largest plays in terms of PV-10 value. During the year ended December 31, 2009, our net average daily production in the Mid-Continent Area was approximately 13.7 MBoe per day, or 66% of our total net average daily production. This area is characterized by stable, long-life, shallow decline reserves. We produce and drill in most of the basins in the region and have significant holdings and activity in the areas described below.

North Burbank Unit—Osage County, Oklahoma. The North Burbank Unit is our largest property. The unit was developed in the early 1920’s, is 23,080 acres in size and has cumulative production of approximately 317.1 MMBbls of oil (primary and secondary). The North Burbank Unit accounted for 27.2 MMBoe of our proved reserves and $187.1 million of our PV-10 value as of December 31, 2009, and 566 (492 net) MBoe of our production for the year ended December 31, 2009. The producing zones are the Red Fork and Bartlesville and occur at a depth of 3,000 feet. We own a 99% working interest in and are also the operator of this unit. As of December 31, 2009, the field was producing approximately 1,531 (1,330 net) Bbls of oil per day from 285 producing wells. There are also 201 active service wells and 469 temporarily abandoned wells at December 31, 2009. Upside potential exists in restoring a majority of the temporarily abandoned wells to production and in reinstituting the polymer EOR program that Phillips Petroleum Company instituted in the field from 1980 to 1986 as a project on 1,440 acres called “Block A.” Production increased from 500 Bbls of oil per day to 1,200 Bbls of oil per day in this project area as a result of the polymer injection program. The project was shut down in 1986 due to low oil prices. We reinstituted a polymer flood on 485 acres adjacent to Block A on a 19-well pattern in December 2007. Production has increased in this pilot area from approximately 90 Bbls of oil per day to approximately 160 Bbls of oil per day as of December 31, 2009. Since taking over the field on November 1, 2006, we have returned 99 temporarily abandoned wells to production with initial rates of production as high as 29 Bbls of oil per day. We believe that this field also may have upside with the injection of CO₂.

Osage-Creek Area—Osage and Creek Counties, Oklahoma. The Osage-Creek area accounted for 16.2 MMBoe of our proved reserves and $228.1 million of our PV-10 value at December 31, 2009, and 846 (625 net) MBoe of our production for the year ended December 31, 2009. The majority of our recent activity has been in Osage County, with the largest portion of that being in our South Burbank Unit.

The South Burbank Unit is the southward extension of the “Stanley Stringer” sand development and lies to the south of the North Burbank Unit and covers 2,720 acres. It was discovered in 1934 and unitized in 1935. The South Burbank Unit has produced 56.9 MMBbls of oil from the Burbank Sand from both primary and secondary recovery efforts. The Burbank Sand occurs at a depth of 2,850 feet. Recently, we have been drilling infillactively implementing and stepout locations in the unit area for both the Mississippi Chat, which occurs some 50 feet below the Burbank Sand, and to the Burbank Sand. It is currently estimated that the Mississippi Chat may be productive under a significant portion of the southern half of the South Burbank Unit. Seventeen wells have been drilled in the South Burbank Unit in 2009. Ten wells have been completed in the Burbank Sand with initial potentials ranging between 5 and 150 Bbls of oil per day. Seven wells are completed and produce from the Mississippi Chat with initial potentials as high as 210 Bbls of oil per day and 100 Mcf of gas per day. Any well drilled inside the South Burbank Unit is being developed with a pattern and spacing plan that will maximize any future EOR efforts.

Numerous other properties throughout Osage and Creek Counties are held by production and hold significant upside development potential. Recent new drilling activity outside of the South Burbank Unit has focused on the Mississippi Chat and Burbank reservoirs. We currently have a Company-owned drilling rig working full time in this area. Many of our Osage County units in which we have a large working interest also hold promise for future EOR efforts.

Camrick Area—Beaver and Texas Counties, Oklahoma and Ochiltree County, Texas. The Camrick area accounted for 7.8 MMBoe of our proved reserves and $89.7 million of our PV-10 value at December 31, 2009. This area consists of three unitized fields, the Camrick Unit, which covers 9,168 acres, the NW Camrick Unit, which covers 2,980 acres and the Perryton Unit, which covers 2,508 acres. We currently operate these three units with an average working interest of 54%. Production in the Camrick area is from the Morrow reservoir that occurs between the depths of 6,900 and 7,500 feet. The three units have produced approximately 16.6 MMBbls of primary reserves and approximately 13.6 MMBbls of secondary reserves. There were 55 active producing wells in this area that produced 507 (249 net) MBbls during the year ended December 31, 2009. Currently, CO₂ injection operations are continuing in the Phase I, II and III areas of the Camrick Unit and the Perryton Unit. CO₂ injection has improved the gross production in the Camrick Area from approximately 115 Bbls of oil per day in 2001 from 11 wells to approximately 1,443 (710 net) Bbls of oil per day from 55 producing wells as of December 31, 2009. We plan to continue expansion of CO₂ injection operations across all of the units.

Southwest Antioch Gibson Sand Unit (SWAGSU)—Garvin County, Oklahoma. SWAGSU accounted for 5.5 MMBoe of our proved reserves and $47.4 million of our PV-10 value at December 31, 2009, and 423 (368 net) MBoe of our production for the year ended December 31, 2009. SWAGSU encompasses approximately 9,520 acres with production from the Gibson Sand, which occurs between the depths of 6,500 and 7,200 feet. We currently operate this unit with an average working interest of 99%. The field has produced approximately 40.3 MMBbls of oil and 262.5 Bcf of natural gas since its discovery in 1946. The field was unitized in 1948 and began unitized production as a pressure maintenance operation, utilizing selective production (based on gas/oil ratios) and gas injection. Water injection began in 1952. Gas injection ceased in 1960 without significant blowdown of the injected gas. Field shutdown and plugging activities began in 1965, and all water injection ceased in 1970. A program is currently underway to re-enter abandoned wells and drill new wells to produce the injected gas. We have 37 active producing wells in this unit as of December 31, 2009. We drilled one well in this area in 2009.

Sycamore Unit—Carter County, Oklahoma. The Sycamore Unit, which is 2,120 acres, was discovered in 1950 and unitized in 1973. A three stage development of the Sycamore Unit began in 1975 and was completed in 1992. This unit accounted for 2.8 MMBoe of our proved reserves and $40.9 million of our PV-10 value at December 31, 2009, and 243 (158 net) MBoe of our production for the year ended December 31, 2009. We operate this unit with a working interest of approximately 76%. Producing zones include the Deese and Sycamore, which occur at depths between approximately 2,500 and 4,900 feet. Cumulative production is 11.0 MMBbls of oil and, as of December 31, 2009, the unit has 107 producing wells and 44 active service wells. The unit is currently producing approximately 560 (363 net) Bbls of oil per day.

Cleveland Sand Area—Ellis, Custer, and Dewey Counties, Oklahoma and Lipscomb County, Texas. The Cleveland Sand Area accounted for 4.9 MMBoe of our proved reserves and $38.7 million of our PV-10 value as of December 31, 2009, and 439 (242 net) MBoe of our production for the year ended December 31, 2009. This area includes the West Shattuck Cleveland Sand Play and the Aledo Bray Cleveland Sand Play.

We own approximately 6,864 net acres in the West Shattuck Cleveland Sand Play, which is located in Ellis County, Oklahoma and Lipscomb County, Texas. The Cleveland Sand occurs at depths between 7,900 and 8,300 feet and is considered a tight gas sand reservoir. As of December 31, 2009, we own interests in 27 Cleveland Sand producing wells. We participated in the drilling of one well in 2009. We employed horizontal drilling technology in most of our drilled wells in this area.

We own approximately 2,135 net acres in the Aledo Bray Cleveland Sand Play, which is located in Custer and Dewey Counties, Oklahoma. The Cleveland Sand occurs at 9,700 feet and is considered a tight gas sand reservoir. As of December 31, 2009, we own interests in two Aledo Bray vertical producing wells. We drilled one horizontal well in this play during 2009.

Granite Wash and Atoka Wash Areas—Washita County, Oklahoma and Wheeler County, Texas.The Granite Wash and Atoka Wash Areas accounted for 2.9 MMBoe of our proved reserves and $27.4 million of our PV-10 value as of December 31, 2009, and 781 (238 net) MBoe of our production for the year ended December 31, 2009. We have ongoing drilling activity in both these play areas.

The objective target of the Colony Granite Wash Horizontal Play, which is in Washita County, Oklahoma, is the Des Moinesian Granite Wash zones at an average depth of approximately 12,500 feet. To date, this play has encompassed an area approximately three townships in size. The Granite Wash is a quartz rich alluvial wash containing high concentrations of feldspar that results in reducing permeability and therefore reducing ultimate recoveries. Conventional vertical well bores in this area have recovered on average approximately 1.5 Bcfe. The technological advances of horizontal drilling allow maximum exposure of this tight gas filled reservoir to the well bore (most horizontal wells are drilled up to 4,800 feet horizontally in the Granite Wash), resulting in substantially improved recoveries that are currently estimated to be up to three to four times the recoveries of the typical vertical well in this play. We drilled and/or participated in the drilling of seven Colony Granite Wash wells in 2009.

The objective target of the Granite Wash and Atoka Wash Play, which is in Wheeler County, Texas, is the Des Moinesian Granite Wash and Atoka Wash zones at average depths ranging from approximately 12,600 feet to 14,500 feet. To date, this play has encompassed an area approximately two townships in size. The Granite Wash is a quartz rich alluvial wash containing high concentrations of feldspar that results in reducing permeability and therefore reducing ultimate recoveries. Conventional vertical well bores in this area have recovered on average approximately 1.5 Bcfe. The early Atoka Granite Wash is typically a carbonate wash sourced from the carbonates of the Wichita/Amarillo Uplift. The later Atoka Wash as found in the Britt area is an Arkosic wash with quartz with potassium and sodium feldspars. Other minerals present are calcite, dolomite, illite, and chlorite. The Britt Atoka Wash is producing a dryer gas with less condensate then the younger Des Moines Wash. The technological advances of horizontal drilling allow maximum exposure of this tight gas filled reservoir to the well bore (most horizontal wells utilize a lateral drilled up to 4,800 feet horizontally in the Granite Wash and Atoka Wash), resulting in substantially improved recoveries that are currently estimated to be up to three to four times the recoveries of the typical vertical well in this play. We participated in the drilling of six Atoka Wash wells in 2009. All of these wells were completed during the first quarter of 2010 and had initial producing rates of between 15 and 23 MMcf of gas per day.

Anadarko Basin Woodford Shale Play-Western Oklahoma. As of December 31, 2009, we have a significant acreage position in the emerging Woodford Shale Resource Play of western Oklahoma. We own and control approximately 68,780 gross acres and 22,270 net acres, which primarily are held by production from other formations. The Woodford Shale beneath our acreage ranges in thickness from approximately 80 to 280 feet thick at depths from 9,500 feet to 16,000 feet. The horizontal development of this non-conventional resource play began in 2007 in Canadian County and has expanded to include the nearby counties of Blaine, Grady and Caddo with approximately 100 Woodford targeted wells drilled to date. Natural gas in place is estimated to be between 120 to 160 Bcf per section with initial development well density to be four wells per section. The average recovery is expected to be four to six Bcf per well at an average cost of seven to nine million dollars. We participated in the drilling of two wells in this play during 2009, and an additional well in which we own a working interest was completed in the first quarter of 2010. These wells have reported initial daily production rates in the range of one to seven MMcf of natural gas per day per well.

Velma Sims Unit CO₂ Flood—Stephens County, Oklahoma. The EVWB Sims Sand Unit accounted for 1.9 MMBoe of our proved reserves and $16.0 million of our PV-10 value as of December 31, 2009, and 342 (88 net) MBoe of our production for the year ended December 31, 2009. This unit, which covers approximately 1,300 acres, was discovered in 1949 and unitized in 1962. We currently operate this unit with an average working interest of 29%. Hydrocarbon gas injection into the Sims C2 Sand was initiated in the top of the structure in 1962. Waterflood operations began in 1972. Hydrocarbon gas injection ended around 1977 and a miscible CO ₂ injection program was initiated in 1982. This miscible CO₂ injection was first begun in the updip portion of the reservoir and in 1990 expanded into the mid-section area of the Sims C2 reservoir. In 1996, miscible CO₂ injection began in the downdip section of the Sims C2. As of December 31, 2009, we had 43 active producing wells in this unit.

Fox Deese Springer Unit—Carter County, Oklahoma. The Fox Deese Springer Unit, which is 2,335 acres, was discovered in 1915 and unitized in 1977. This unit accounted for 4.7 MMBoe of our proved reserves and $39.8 million of our PV-10 value at December 31, 2009, and 138 (94 net) MBoe of our production for the year ended December 31, 2009. We operate this unit with a working interest of 82%. Producing zones include the Deese, Sims, and Morris, which occur at depths between 3,300 and 5,500 feet. Cumulative production is 12.6 MMBbls of oil and, as of December 31, 2009, the unit has 62 producing wells and 48 active service wells. The unit is currently producing approximately 330 (224 net) Bbls of oil per day.

Sivells Bend Unit—Cooke County, Texas. The Sivells Bend Unit is 3,863 acres in size, produces primarily from the Strawn, which occurs at depths between 6,200 and 7,000 feet, and has recovered 39.4 MMBbls of oil to date. This unit accounted for 2.6 MMBoe of our proved reserves and $35.9 million of our PV-10 value at December 31, 2009, and 83 (48 net) MBoe of our production for the year ended December 31, 2009. There are currently 26 producing wells and 14 active service wells, with production of approximately 218 (126 net) Bbls of oil per day. We operate the field with a working interest of 65%. Upside potential exists in increased density drilling from 80 acres to 40 acres in the Strawn. The only 40-acre increased density well drilled in the unit has recovered over 390 MBbls of oil. Additional potential exists in deeper Ellenburger, as an Ellenburger well tested approximately 193 Bbls of oil per day in 1964 in the adjacent East Sivells Bend Unit, and one well in our unit tested 104 Bbls of oil per day for a short time. 3-D seismic will be required to better define the fault blocks for an Ellenburger test. We own approximately 1,000 acres of fee minerals in this Sivells Bend Unit and own approximately half of the rights below the Strawn, which includes the Ellenburger.

CO₂ EOR—Various counties, Oklahoma, Kansas, New Mexico and Texas. As of December 31, 2009, we have accumulated interests in 72 properties in Oklahoma, Kansas, New Mexico and Texas that meet our criteria formanaging CO₂ EOR operations. Thesein the Panhandle and Central Oklahoma Areas since 2001. We now have CO₂ EOR projects accounted for 6.2 MMBoe ofsupply agreements in place in the Burbank, Panhandle, and Central Oklahoma Areas, and we have built and/or expanded CO₂ pipelines to reach our proved reservesvarious field locations in the Panhandle and $80.2 million of our PV-10 value as of December 31, 2009, and 1,512 (449 net) MBoe of our production for the year ended December 31, 2009. We own a 100% interest in our 86-mile BorgerCentral Oklahoma Areas. The CO₂ pipeline a 29% interest inreaching the 120-mile Enid to Purdy CO₂ pipeline, a 58% interest inBurbank Area is scheduled for completion near the 23-mile Purdy to Velma CO₂ pipeline, which we operate, and a 100% interest in approximately 126 milesend of pipeline that includes a CO₂ pipeline located between Liberal, Kansas and Booker, Texas as well as additional pipeline extensions in the SW Kansas and Texas Panhandle areas. We initiated CO₂ injection in three Booker units in 2009, and plan to expand CO₂ injections into our NW Camrick Unit, our North Farnsworth Unit, and our NW Velma Hoxbar Unit in 2010. As of December 31, 2009, we had in place transportation and supply agreements to provide the necessary CO₂ for these projects. We have installed compression and purification facilities that are currently capturing approximately eight to ten MMcf per day of CO₂ from the Arkalon ethanol plant in Liberal, Kansas. We initiated injection of CO₂ captured from this facility into the Booker area fields in the thirdfirst quarter of 2009. After the completion of additional work, we expect these facilities to capture approximately 15 to 19 MMcf per day of CO₂.

2013. Arrangements to secure additional sources of CO₂ for potential future projects are currently in process. The U.S. Department of Energy-OfficeEnergy–Office of Fossil Energy provided a report in February 2006 estimating that significant oil reserves could be technicallyeconomically recovered in the State of Oklahoma and Texas through CO₂ EOR processes. With our infrastructure, we believe that we will be well positioned to participate in the exploitation of those reserves.

CO₂ miscible flooding is implemented and managed as a closed system consisting of the reservoir and surface piping. The physical material balance of the system means that the CO₂ is produced and recycled many times once it has been injected. Combined with the incoming purchased CO₂ supply, the recycled CO₂ supply allows us to systematically develop additional flood patterns in contiguous acreage to the active patterns. If larger volumes of CO₂ become available, projects can be developed on accelerated timelines, while a more limited supply dictates a prolonged expansion. Due to the size of our EOR projects, the fixed rate of CO₂ availability which is secured for the long-term period, and the limitation of third party services, we expect the development of our EOR projects will extend beyond five years in many cases. Our significant active EOR projects are discussed below.

Burbank Area

North Burbank Unit. As of December 31, 2012, the North Burbank Unit, which is our largest property, accounted for 28.7 MMBoe, or 20% of our proved reserves, including 14.1 MMBoe of proved undeveloped polymer EOR reserves. The producing zones are the Red Fork and Bartlesville formations and occur at a depth of approximately 3,000 feet. We own a 99% working interest in and are also the operator of this Unit. Our net average daily production from this Unit decreased by 7% from 1,455 Boe/d in 2011 to approximately 1,347 Boe/d in 2012, of which 46% or 49 Boe/d was due to a scheduled shut-in while we raised pressure in the Phase I Area, the northwestern sector of the field. As of December 31, 2012, we had 296 (294 net) producing wells, 243 active injection wells, and 471 shut-in and temporarily abandoned wells in this Unit. Upside potential exists in restoring a majority of the temporarily abandoned wells to production, expanding the polymer injection EOR program, and initiating CO₂ EOR operations. Due to the size of the North Burbank Unit, there is insufficient fresh water and third party services available to complete the development of the North Burbank Unit within five years, and as a result the development of the North Burbank Unit will be an ongoing project.

Phillips Petroleum Company instituted a polymer flood in their “Block A” polymer project that originally covered 1,440 acres. Production increased from 500 Bbls of oil per day to 1,200 Bbls of oil per day in this original project area. The Phillips project was shut down in 1986 due to low oil prices.

In December 2007, we expanded a polymer flood into the Phase I area of the North Burbank Unit, which consists of 485 acres adjacent to Block A on a 19-well pattern. During 2010, we completed a review of this project, and the results of this review confirm that injection of polymer is successful in recovering commercial quantities of tertiary oil from the North Burbank Unit. Production has increased in this area from approximately 90 (78 net) Bbls of oil per day in 2008 to approximately 152 (132 net) Bbls of oil per day during 2012. Our review also indicated that additional oil recovery may be obtained with additional volumes of polymer injected into the Phase I area. We implemented this additional injection into the Phase I area in 2011 and continued injection during 2012.

We have scheduled expansion of the polymer project from the Phase I area into Phase II during 2014 with development of remaining phases to follow in future years as a sufficient volume of fresh water becomes available. We are also developing a Phase I CO₂ flood as we believe the field to have additional upside with the injection of CO₂. On March 24, 2011, we signed a 20-year contract with renewal options to purchase up to 100% of CO₂ emissions from an existing nitrogen fertilizer plant in Coffeyville, Kansas that produces approximately 42 MMcf/d of CO₂. In early 2013, we expect completion of gathering and compression facilities at Coffeyville and a 68-mile pipeline to transport the CO₂ to the Burbank field. Beginning no later than July 2013, and assuming the fertilizer plant produces and delivers a specified quality of CO₂, we will be obligated to purchase an average of approximately 24 MMcf/d the first year of the contract and 35 MMcf/d for the remaining contract years or pay for any deficiencies at the price in effect when the minimum delivery was to have occurred. After the first ten contract years, we may permanently reduce up to 100% of our purchase rate under this contract with six months’ notice. We expect to purchase an average of approximately 24 MMcf/d of CO₂ under this contract starting in the second quarter of 2013 for injection into our North Burbank Unit. As a result of our success with polymer and additional technical analysis of the same, we are evaluating augmentation of our developing CO₂-EOR project to include polymer during periods of water injection within WAG cycles.

Our total investment in the North Burbank Unit during 2012, including expenditures associated with construction of the CO₂ compression facilities and pipeline, drilling two service wells, and reactivating 33 wells, was $141.0 million. Approximately $87.3 million of our capital expenditures budget for 2013 has been allocated for EOR operations in the North Burbank Unit.

Panhandle Area

Camrick Area Units. As of December 31, 2012, the Camrick Area Units accounted for 6.0 MMBoe, or 4% of our proved reserves, substantially all of which are considered EOR reserves. Approximately 2.8 MMBoe of the proved reserves in this area are undeveloped. The Camrick Area Units consist of three units, which we operate: the Camrick Unit, where we began CO₂ injection in 2001; the North Perryton Unit, where we began CO₂ injection in 2006; and the NW Camrick Unit, which will be initiated as recycled CO₂ volumes become available from the other two Units. Currently, CO₂ injection operations are continuing in the Phase I and II areas of the Camrick Unit and within the North Perryton Unit. As of December 31, 2012, we had 62 (37 net) producing wells, 47 active water injection wells, and 41 temporarily abandoned wells in this area. During the third quarter of 2010, we acquired an additional 6% working interest in these reserves.three Units, thereby increasing our average working interest to 60%. Our net average daily production from this area increased 4% to 1,006 Boe/d in 2012 compared to 966 Boe/d in 2011, which was a 7% increase compared to 902 Boe/d in 2010.

We have a long-term contract to purchase up to approximately 20 MMcf/d of CO₂ produced at an existing nitrogen fertilizer plant in Borger, Texas. The fertilizer plant reserves the right to install additional equipment and use some of the CO₂ to make certain fertilizer products, which could reduce our CO₂ purchases. We own 100% of and operate the 74-mile Borger CO₂ Pipeline, which transports CO₂ from the fertilizer plant to the Camrick Area Units. As of December 31, 2012, we were injecting a combined 18 MMcf/d of purchased and recycled CO₂ in this area.

Our total investment in the Camrick Area Units during 2012, including the purchase of CO₂ for injection, the drilling and completion of three wells, and general well work, was $12.0 million. We have allocated approximately $8.8 million of our capital expenditures budget for 2013 to this area for continued purchase of CO₂, drilling and completions, compression expansion, electrical upgrades, and remedial well work.

Farnsworth Unit. The Farnsworth Unit, which lies to the southeast of and is analogous to the Camrick Area Units, accounted for 6.4 MMBoe, or 4% of our proved reserves, at December 31, 2012. All of the reserves in this Unit, which includes 3.5 MMBoe of proved undeveloped reserves, are considered EOR reserves as of December 31, 2012. We acquired a 99% working interest in the Farnsworth Unit in November 2009 and we began CO₂ injection in December 2010. CO₂ injection has improved production in the Unit from approximately 394 (314 net) Bbls of oil per day in December 2011 to approximately 1,093 (870 net) Bbls of oil per day in December 2012. As of December 31, 2012, we had 23 producing wells, 18 active water and CO₂ injection wells, and 44 shut-in and temporarily abandoned wells in the Unit. Our net average daily production from this Unit increased 184% to 475 Boe/d in 2012 compared to 167 Boe/d in 2011, which was a 56% increase compared to 107 Boe/d in 2010.

We have a long-term contract to purchase up to approximately 15 MMcf/d of CO₂ produced at the Arkalon ethanol plant near Liberal, Kansas. We have installed compression and purification facilities that are capturing approximately 14 MMcf/d of CO₂ from this plant as of December 31, 2012. We own 100% of and operate the 95-mile TexOk CO₂ Pipeline that includes a CO₂ pipeline located between Liberal, Kansas and Spearman, Texas. During 2010, we built a 14-mile pipeline extension through the Farnsworth Unit, connecting the TexOk CO₂ Pipeline and the Borger CO₂ Pipeline to allow flexibility in delivering CO₂ to the Farnsworth Unit and future projects. We completed the final tie-in of this extension in the first quarter of 2011. As of December 31, 2012, we were injecting approximately 12 MMcf/d of purchased and recycled CO₂ in the Farnsworth Unit.

During 2012, we invested $21.6 million in the Farnsworth Unit to drill two wells, return four production and injection wells to service, complete associated field facilities work, and completed modifications at Arkalon. We have allocated approximately $23.6 million of our capital expenditures budget for 2013 to this Unit for the continued development of the CO₂ project and related field facilities.

Booker Area Units. As of December 31, 2012, the Booker Area Units accounted for 0.9 MMBoe of our proved reserves, all of which are developed. In September 2009, we began CO₂ injection into our three Booker Area Units, which we operate with an average working interest of 99%. As of December 31, 2012, we had 12 producing wells, six active water and CO₂ injection wells, and three shut-in and temporarily abandoned wells in the Unit. Our net average daily production from this area increased 473% to 402 Boe/d in 2012 compared to 70 Boe/d in 2011, which was a 55% increase compared to 45 Boe/d in 2010. Our total investment in the Booker Area Units during 2012 was $9.9 million, primarily spent on CO₂ purchases. We have allocated approximately $9.6 million of our capital expenditures budget for 2013 to this area.

Permian Basin Area

We have identified and own several potential projects in the West Texas and Southeast New Mexico area. Currently, we do not have active operated CO₂ EOR projects, and have a small ownership interest in one outside-operated active EOR property, the Adair San Andres Unit in this area.

Permian BasinMid-Continent Area

The Permian Basin Area is the second of our two core areas and, asAs of December 31, 2009,2012, the Mid-Continent Area accounted for 11%74.1 MMBoe, or 51% of our proved reserves and 11% of our PV-10 value. We own a working interest in 1,693 producing wells in the Permian Basin, of which we operate 318. The Permian Basin Area has one of our top ten plays in terms of PV-10 value.reserves. During the year ended December 31, 2009,2012, our net average daily production in the Mid-Continent Area was approximately 15.6 MBoe per day, or 62% of our total net average daily production. This Area is characterized by stable, long-life, shallow decline reserves. We produce and drill in most of the formations in the region and have significant holdings and activity in the areas described below.

Northern Oklahoma Mississippi Play (“NOMP”)—Various Counties, Oklahoma. The Northern Oklahoma Mississippi Play, as currently defined, spans from Woodward and Harper, Oklahoma counties on the west to Washington, Tulsa and Okmulgee, Oklahoma counties on the east and northward into Kansas.

We refer to the western portion of Osage County and the other counties of Northern Oklahoma as NOMP Core. This area has a long history of production from vertical wells and a well-developed infrastructure system to support further development. Several companies in the industry are devoting large amounts of capital toward leasing and horizontal drilling activities in further developing this shallow, cost-effective play. Leasing in the NOMP Core has become increasingly competitive as the play continues to yield positive results. During 2012, we spent $11.1 million on leasehold acquisitions, increasing our acreage position to approximately 117,000 acres for the NOMP Core portion of the play.

The NOMP Core accounted for 7.2 MMBoe, or 5% of our proved reserves as of December 31, 2012. Primarily as a result of our drilling activity, our net average daily production from this area has increased significantly to approximately 1,409 Boe/d in 2012 compared to 307 Boe/d in 2011. During 2012, we spent $85.8 million on developmental and exploratory activities in the NOMP Core. We drilled and/or participated in the drilling of 32 (16 net) horizontal wells that were completed during 2012. Our drilling activity for 2013 will continue to focus on the NOMP Core area with plans to drill and/or participate in the drilling of 25 wells. We have allocated approximately $78.3 million of our 2013 drilling budget to this portion of the play.

We consider the eastern portion of Osage County as NOMP Emerging. During the third quarter of 2011, we paid $1.5 million for an exclusive Concession Agreement with the Osage Minerals Council to lease and potentially develop oil and natural gas rights on 217,000 acres in Osage County, Oklahoma through June 30, 2014. This includes approximately 138,000 acres currently available to us, of which 16,112 acres are under active leases. The Concession Agreement provides for a 20% royalty payment to the Osage Indian Nation and a drilling commitment by us to drill a minimum number of wells in each of the three years covered by the Concession Agreement, for a total of 61 wells. During 2012, by virtue of our exclusive Concession Agreement we spent $1.8 million on lease acquisitions increasing our leased acreage from 2,400 acres in 2011 to 16,112 acres in NOMP Emerging. Our acreage position in NOMP Emerging outside the Concession Agreement is approximately 40,000 acres.

NOMP Emerging accounted for 0.5 MMBoe, or 0.4% of our proved reserves as of December 31, 2012. During 2012, we spent $23.5 million on developmental and exploratory activities in NOMP Emerging, which includes the area covered by the Concession Agreement. We drilled five horizontal wells that were completed during 2012.

Osage-Creek Area—Osage, Creek, and Kay Counties, Oklahoma. The Osage-Creek area accounted for 14.4 MMBoe, or 10%, of our proved reserves as of December 31, 2012. Our net average daily production from this area decreased by 6% to approximately 2,155 Boe/d in 2012 compared to 2,302 Boe/d in 2011 and 2,376 Boe/d in 2010, primarily due to normal production decline. The majority of our recent activity has been in Osage County, with the largest portion of that being in our South Burbank Unit, which is the southward extension of the “Stanley Stringer” sand development and lies to the south of the North Burbank Unit. Any well drilled inside the South Burbank Unit is being developed with a pattern and spacing plan that will maximize any future EOR efforts. Numerous other properties throughout Osage and Creek Counties are held by production and hold significant upside development potential. Many of our Osage County units in which we have a large working interest also hold promise for future EOR efforts. Our drilling investment was $3.7 million and we drilled three wells in this area during 2012. We have not allocated any significant amount of our 2013 drilling budget to this area.

Anadarko Granite Wash Play Area—Oklahoma and Texas.The Granite Wash Play area accounted for 6.4 MMBoe, or 4% of our proved reserves as of December 31, 2012. Objective targets in this area include the Des Moinesian Granite Wash and Atoka Wash zones at average depths ranging from approximately 12,500 feet to 14,500 feet. The technological advances of horizontal drilling allow maximum exposure of this low permeability reservoir to the well bore (most horizontal wells are drilled up to 4,800 feet horizontally in the Granite Wash and Atoka Wash), resulting in substantially improved recoveries.

We drilled and/or participated in the drilling of 10 (two net) Granite Wash horizontal wells that were completed during 2012. Our net average daily production from this area decreased by 2% to approximately 2,291 Boe/d in 2012 from 2,329 in 2011, which was 27% higher than 1,839 Boe/d in 2010, primarily due to the normal decline curve on this type of well. During 2012, our drilling investment in this area was $24.2 million and we have allocated approximately $7.7 million of our 2013 drilling budget to this area.

Anadarko Hogshooter Wash Play Area-Oklahoma and Texas. The Hogshooter Wash Play area was identified during 2012 and is located in the Anadarko Basin of the Texas Panhandle and western Oklahoma. The Hogshooter Wash Play accounted for 0.3 MMBoe, or 0.2% of our proved reserves as December 31, 2012. We drilled and/or participated in drilling four (one net) Hogshooter Wash horizontal wells that were completed during 2012. Production was 446 Boe/d as of December 31, 2012 and approximately 238 Boe/d for the 2012 average. Our drilling investment in this area was $7.0 million and we have not allocated any significant amount of our 2013 drilling budget to this area.

Anadarko Cleveland Sand Play Area—Oklahoma and Texas.The Cleveland Sand Play area accounted for 6.6 MMBoe, or 4.5% of our proved reserves as of December 31, 2012. This area includes the West Shattuck Cleveland Sand Play and the Aledo Bray Cleveland Sand Play, both of which are considered tight liquids rich sand reservoirs. We drilled and/or participated in the drilling of 12 (seven net) Cleveland Sand horizontal wells that were completed during 2012. Primarily as a result of these new wells, our production in this area increased 38% to approximately 2,955 Boe/d in 2012 compared to 2,134 Boe/d in 2011 and 961 Boe/d in 2010. Our production in the Cleveland Sand Play area was 3,476 Boe/d as of December 31, 2012. During 2012, our drilling investment was $54.3 million and we have allocated approximately $20.6 million of our 2013 drilling budget to this area. Our drilling activity for 2013 will focus on the West Shattuck Cleveland Sand Play that trends from Hansford County in the Texas Panhandle across our acreage position to eastern Ellis County in Oklahoma. It is characterized by a tight, shaley sand sequence that lends itself to the benefits of horizontal drilling.

Anadarko Woodford Shale Play Area—Western Oklahoma. The Anadarko Basin Woodford Shale Play area accounted for 2.5 MMBoe, or 2%, of our proved reserves as of December 31, 2012. The horizontal development of this non-conventional resource play began in 2007 in Canadian County and has expanded to include the nearby counties of Blaine, Dewey, Grady, and Caddo. Our production in this area increased 23% to approximately 190 Boe/d in 2012 compared to 154 Boe/d in 2011 and 133 Boe/d in 2010. Our drilling investment was $1.5 million and we participated in the drilling of three (zero net) wells in this area during 2012. We have not allocated any significant amount of our 2013 drilling budget to this area.

Permian Basin Area

As of December 31, 2012, the Permian Basin Area accounted for 16.6 MMBoe, or 11% of our proved reserves. During the year ended December 31, 2012, our net average daily production in the Permian Basin Area was approximately 4.43.3 MBoe per day, or 21%13% of our total net average daily production. Similar

Bone Spring/Avalon Shale Play—West Texas/New Mexico. We own approximately 19,590 (17,216 net) acres in the Bone Spring/Avalon oil play developing in West Texas and southeast New Mexico. Operators have switched from vertical to horizontal drilling to improve hydrocarbon recovery from this formation, and approximately 300 horizontal wells have been drilled to date. The average recovery is expected to be 200 to 550 MBoe per well at an average cost of five to six million dollars. Our acreage is attractively located on trend within the play, with active horizontal drilling recently offsetting us in two directions. Recent Avalon/Bone Spring production has been established immediately adjacent to our acreage block, and industry activity, which is drilling towards our acreage position from both directions, is continuing to prove up the value of our position. We have drilled and/or participated in the drilling of five (one net) wells in the Bone Spring/ Avalon Shale Play during 2012. Based on early results, we entered into a joint venture to satisfy our continuous drilling obligation for lease extension and created a significant cost advantage that allows us to reduce future capital spending. Our drilling investment in this Area was $12.6 million in 2012, and we have not allocated any significant amount of our 2013 drilling budget to this play.

Panhandle Marmaton Play—Texas and Oklahoma Panhandles. We currently own approximately 56,600 (44,500 net) acres in this emerging play. The horizontal play began in the fourth quarter of 2008 with a few wells drilled in Beaver, County, OK. In 2010, the play accelerated with 26 wells drilled and has expanded into Ochiltree, County, TX. The horizontal play has included infill drilling on the vertical Marmaton fields and has extended the play off the structures into lower energy facies and structurally lower areas. The multi-stage fracture stimulation jobs performed are a critical component for establishing economical production in the play. Their success has opened up the play into the tighter facies of the Marmaton. The average ultimate recovery is estimated to be 150 MBoe at an average completed well cost of approximately $3.5 million.

The Marmaton Play accounted for 0.5 MMBoe, or 0.4% of our proved reserves as of December 31, 2012. We drilled or participated in the drilling of five (two net) horizontal wells that were completed during 2012. Initial net average daily production in late 2012 resulted in 103 Boe/d. Our drilling investment in this area was $16.5 million in 2012 and we have allocated approximately $41.3 million of our 2013 drilling budget to the Mid-Continent Area, the Permian Basin AreaMarmaton Play.

Haley Area—Loving County, Texas. The Haley area accounted for 3.7 MMBoe, or 3% of our proved reserves at December 31, 2012. Our net production from this area, which is characterizedprimarily dry gas, decreased by stable, long-life, shallow decline reserves.28% to approximately 902 Boe/d in 2012 compared to 1,257 Boe/d in 2011 primarily due to compression facility upgrades and significant shut-in time by gas purchasers. Due to prevailing low natural gas prices, we did not invest any significant amounts to drilling in this area in 2012, and we have not allocated any significant amount of our 2013 drilling budget to this area.

Tunstill Field Play—Loving and Reeves Counties, Texas. Our Tunstill Field Play covers approximately 20,440 acres. We operate 86 producing wells in this play with an average working interest of 99%, and own a working interest in 120 producing wells operated by others. The Tunstill Field Play represented 2.72.8 MMBoe, or 1.9% of our proved reserves and $33.6 million of our PV-10 value at December 31, 2009, and 252 (179 net) MBoe of our production for the year ended December 31, 2009. Primary objectives in this play are the Bell Canyon Sands that occur at depths from 3,200 to 4,200 feet and the Cherry Canyon Sands that occur at depths from 4,200 to 5,400 feet. Older wells produce from the shallower Bell Canyon Sands including the Ramsey and Olds, while more recent wells have established2012. Our net average daily production from the deeper Cherry Canyon Sands as well as the shallower sands. We drilled three wells in this play during the year ended December 31, 2009.

Haley Area Play—Loving County, Texas. The Haley Area—Bone Springs, Strawn, Atoka, and Morrow play encompasses 3,840 gross acres. We own interests in and operate ten producing wells in this play. The Haley Area accounted for 4.7 MMBoe of our proved reserves and $27.7 million of our PV-10 value at December 31, 2009, and 1,163 (805 net) MBoe of our production for the year ended December 31, 2009. Production has been established from four main intervals: (1) the Bone Springs at a depth of approximately 9,800 to 11,500 feet; (2) the Strawn at a depth of approximately 15,000 feet; (3) the Atoka at a depth of approximately 15,300 feet; and (4) the Morrow at a depth of approximately 17,500 feet. Recent activity in the area, on all four sides of our acreage, has established significant producing wells from the Strawn/Atoka/Morrow commingled interval with some initial potentials of 3 to 5 MBoe per day. The Bowdle 47 No. 2 began selling natural gas in late November 2008, and is currently producing at approximately 12.0 (8.7 net) MMcf per day. We are currently drilling an offset to the Bowdle 47 No. 2 well, the Bowdle 47 No. 4, which is expected to be completed in the second quarter of 2010.

Gulf Coast

The Gulf Coast Area is the most active of our four growth areas and accounted for 5% of our proved reserves and 4% of our PV-10 value as of December 31, 2009, and 6% of our production for the year ended December 31, 2009. We own an interest in 200 wells in the Gulf Coast Area, of which we operate 128. Unlike our core areas, the Gulf Coast Area is characterized by shorter-life and high initial potential production. We believe a balance of this type of production complements our long-life reserves and adds a dimension for increasing our near-term cash flow.

Mustang Island & Mesquite Bay—Aransas and Nueces Counties, TX. We own interests in approximately 1,700 net producing acres and 10,650 net non-producing acres. Multiple producing sand intervals are found from depths of 6,500 feet to 11,500 feet. We operate seven active producing wells in this area. As of December 31, 2009, this area accounted for 1.3 MMBoe ofdecreased 16% to approximately 736 Boe/d in 2012 from 876 Boe/d in 2011, primarily due to a reduction in drilling activity. Net average daily production was 669 Boe/d in 2010. During 2012, our proved reservesdrilling investment was $4.1 million, and $14.2 million of our PV-10 value. We recorded a 58-square mile proprietary 3-D seismic survey over parts of this area where we have entered into an area of mutual interest with a 50% ownership in an attempt to find bypassed reservesdrilled or other potential reservoirs. We drilled one Mustang Island well in 2009.

Ark-La-Tex

The Ark-La-Tex Area accounted for 2% of our proved reserves and 2% of our PV-10 value as of December 31, 2009, and 3% of our production for the year ended December 31, 2009. We own an interest in 120 wells in the Ark-La-Tex Area, of which we operate 53. These reserves are characterized by shorter life and higher initial potential. We participated in the drilling of one Ark-La-Tex welltwo wells in 2009.this area. We have allocated approximately $1.7 million of our 2013 drilling budget to this area.

North TexasOther Areas

Ark-La-Tex. The North Texas AreaArk-La-Tex area accounted for 2%5.4 MMBoe, or 4% of our proved reserves and 2% of our PV-10 value as of December 31, 2009, and 2%2012. Our net production from this area decreased to approximately 1,159 Boe/d in 2012 from 1,306 Boe/d in 2011. The 11% decline was primarily due to normal depletion of the reservoirs. Our total capital investment of $1.6 million during 2012 was primarily for workovers on existing wells. We have not allocated any significant amount of our production2013 drilling budget to this area.

Gulf Coast. The Gulf Coast area accounted for the year ended December 31, 2009. We own an interest in 588 wells in the North Texas Area, of which we operate 107. We participated in the drilling of 81 North Texas wells in 2009.

Rocky Mountains

The Rocky Mountains Area accounted for2.0 MMBoe, or 1% of our proved reserves and 2% of our PV-10 value as of December 31, 2009,2012. Our net average daily production from this area was approximately 753 Boe/d in 2012, 872 Boe/d in 2011, and 763 Boe/d in 2010. The 14% decline in 2012 as compared to 2011 is primarily due to strategic divestitures of properties within the area. Our total capital investment of $2.1 million during 2012 was primarily for workovers on existing wells. We have not allocated any significant amount of our 2013 drilling budget to this area.

North Texas. The North Texas area accounted for 3.8 MMBoe, or 3% of our proved reserves as of December 31, 2012. Our net average daily production from this area was approximately 438 Boe/d in 2012, 545 Boe/d in 2011, and 515 Boe/d in 2010. The 20% decrease in 2012 as compared to 2011 was primarily due to an extended shut-in time for lease repairs and the well’s normal decline. Our total capital investment was $4.0 million and we drilled 32 (one net) wells in this area during 2012. We have not allocated any significant amount of our 2013 drilling budget to this area.

Rocky Mountains. On November 28, 2011, we sold our non-strategic oil and natural gas properties consisting of 3.4 MMBoe located in the Rocky Mountains area to Charger Resources, LLC for a cash price of approximately $33.1 million. In accordance with the full cost method of accounting, we reduced our full cost pool by the amount of the net proceeds and did not record a gain or loss on the sale. Our Rocky Mountains area accounted for approximately 2% of our production for the year ended December 31, 2009. We own an interest in 181 wells in the Rocky Mountains Area, of which we operate 39. We participated in the drilling of five Rocky Mountains wells in 2009.2011.

Oil and Natural Gas Reserves

Proved 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—producible—from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations—regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain. Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined, and exclude escalations based upon future conditions.

Our policies regarding internal controls over the recording of reserves are structured to objectively estimate our oil and natural gas reserve quantities and values in compliance with SEC regulations. Users of this information should be aware that the process of estimating quantities of crude oil and natural gas reserves is very complex, requiring significant subjective decisions in the evaluation of all available geological, engineering, and economic data for each reservoir. The data for a given reservoir may also change substantially over time as a result of numerous factors, including additional development activity, evolving production history, and continual reassessment of the viability of production under varying economic conditions. Consequently, material revisions to existing reserve estimates occur from time to time. Responsibility for preparation of our reserve estimates is delegated to our reservoir engineeringCorporate Reserves group, which is led by our SeniorAssociate Vice President of ReservoirCorporate Reserves who has a Master of Science in Petroleum Engineering and Acquisitions who is a registered Professional Engineer with 3717 years of diversifiedindustry experience that includes diverse petroleum engineering roles and reserves management and operational and technical engineering experience.for a publicly traded company.

Technical reviews are performed throughout the year by our geologic and engineering staff who evaluate pertinent geological and engineering data. This data, in conjunction with economic data and ownership information, is used in making a determination of proved reserve quantities. We have internal auditing guidelines and controls in place to monitor the reservoir data and reporting parameters used in preparing the year-end reserves. TechnologiesTechnical and economic data used include updated production data, well performance, formation logs, geological maps, reservoir pressure tests, and wellbore mechanical integrity information. We have also added an analysis and reporting software system designed specifically for reserves management.

This data is then provided to the independent petroleum engineering firms of Cawley, Gillespie & Associates, Inc. and Ryder Scott Company, L.P. who prepare reserve estimates for the majority of our properties using their own engineering assumptions and the economic data which we provide. The person responsible for overseeing the preparation of our reserve estimates at Cawley, Gillespie & Associates, Inc. is a registered Professional Engineer with 26more than 30 years of petroleum consulting experience. The person responsible for overseeing the preparation of our reserve estimates at Ryder Scott Company, L.P. is a registeredlicensed Professional Engineer with over 2730 years of reservoir engineering experience.practical experience in the estimation and evaluation of petroleum reserves.

Our reserves are reviewed by senior management. Senior management, which includes the President and Chief Executive Officer, the Senior Vice President of Reservoir Engineering and AcquisitionsChief Operating Officer, and the Chief Financial Officer, isand they are responsible for reviewing and verifying that the estimate of proved reserves is reasonable, complete, and accurate. Members of senior management may also meet with the key representativerepresentatives from Cawley, Gillespie & Associates, Inc. and Ryder Scott Company, L.P. to discuss their process and findings. Final approval of the reserves is required by our Senior Vice President of Reservoir Engineering and Acquisitions and our President and Chief Executive Officer, Chief Operating Officer, and Chief Financial Officer.

Proved Reserves. The table below summarizes our net proved oil and natural gas reserves and PV-10 values at December 31, 2009.2012. Information in the table is derived from reserve reports of estimated proved reserves prepared by Cawley, Gillespie & Associates, Inc. (59%(50% of PV-10 value) and by Ryder Scott Company, L.P. (23%(34% of PV-10 value). Copies of the summary reserve reports prepared by these independent reserve engineers are attached as exhibits to this annual report. Our internal engineering staff has prepared a report of estimated proved reserves on the remaining smaller value properties (18%(16% of PV-10 value) at December 31, 2009.2012. We set forth our definition of PV-10 value (a non-GAAP measure) and a reconciliation of the standardized measure of discounted future net cash flows to PV-10 value on page 24.