Chaparral Energy, Inc. - FORM 10-K

Chaparral Energy, Inc. - FORM 10-K - March 29, 2011

Attached files

Attached files

file	filename
EX-32.2 - SECTION 1350 CERTIFICATION - CFO - Chaparral Energy, Inc.	dex322.htm
EX-21.1 - SUBSIDIARIES OF THE COMPANY - Chaparral Energy, Inc.	dex211.htm
EX-31.1 - CERTIFICATION - CEO - Chaparral Energy, Inc.	dex311.htm
EX-99.2 - REPORT OF RYDER SCOTT COMPANY LP - Chaparral Energy, Inc.	dex992.htm
EX-31.2 - CERTIFICATION - CFO - Chaparral Energy, Inc.	dex312.htm
EX-99.1 - REPORT OF CAWLEY, GILLESPIE & ASSOCIATES - Chaparral Energy, Inc.	dex991.htm
EX-32.1 - SECTION 1350 CERTIFICATION - CEO - Chaparral Energy, Inc.	dex321.htm
EX-10.31 - CARBON DIOXIDE PURCHASE AND SALE AGREEMENT - Chaparral Energy, Inc.	dex1031.htm
EX-10.27 - EMPLOYMENT AGREEMENT - K. EARL REYNOLDS - Chaparral Energy, Inc.	dex1027.htm

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-K

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

For the fiscal year ended December 31, 2010

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

For the transition period from to

Commission file no. 333-134748

Chaparral Energy, Inc.

(Exact name of registrant as specified in its charter)


Delaware		73-1590941
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification No.)

701 Cedar Lake Boulevard Oklahoma City, Oklahoma		73114
(Address of principal executive offices)		(Zip code)

Registrant’s telephone number, including area 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 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 (Section 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 ¨ 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 were privately placed and there is no public market for such shares.

1,410,235 shares of the registrant’s common stock were outstanding as of March 29, 2011.

CHAPARRAL ENERGY, INC.

Index to Form 10-K


Part I

Items 1. and 2.	Business and Properties	8

Item 1A.	Risk Factors	34

Item 1B.	Unresolved Staff Comments	51

Item 2.	Properties	51

Item 3.	Legal Proceedings	51

Item 4.	[Reserved]	51

Part II

Item 5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	52

Item 6.	Selected Financial Data	53

Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	54

Item 7A.	Quantitative and Qualitative Disclosures About Market Risk	79

Item 8.	Financial Statements and Supplementary Data	83

Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	133

Item 9A.	Controls and Procedures	133

Item 9B.	Other Information	134

Part III

Item 10.	Directors, Executive Officers and Corporate Governance	134

Item 11.	Executive Compensation	137

Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	156

Item 13.	Certain Relationships and Related Transactions, and Director Independence	159

Item 14.	Principal Accounting Fees and Services	162

Part IV

Item 15.	Exhibits and Financial Statement Schedules	163

Signatures		166

CAUTIONARY NOTE

REGARDING FORWARD-LOOKING STATEMENTS

This report includes statements that constitute forward-looking statements 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, management’s plans, strategies, goals and objectives for future operations and growth. These forward-looking statements generally are accompanied by words such as “intend,” “anticipate,” “believe,” “estimate,” “expect,” “should,” “seek,” “project,” “plan” or similar expressions. Any statement that is not an historical fact is a forward-looking statement. It should be understood that these forward-looking statements are necessarily estimates reflecting the best judgment of senior management, not guarantees of future performance. They are subject to a number of assumptions, risks and uncertainties that 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:

•

fluctuations in demand or the prices received for oil and natural gas;

•

the amount, nature and timing of capital expenditures;

•

drilling, completion and performance of wells;

•

competition and government regulations;

•

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

•

costs of exploiting and developing properties and conducting other operations, in the aggregate and on a per-unit equivalent basis;

•

increases in proved reserves;

•

operating costs and other expenses;

•

cash flow and anticipated liquidity;

•

estimates of proved reserves;

•

exploitation of property acquisitions; and

•

marketing of oil and natural gas.

These forward-looking statements represent intentions, plans, expectations, assumptions and beliefs about future events and are subject to risks, uncertainties and other factors. Many of those factors are outside of our control and could cause actual results to differ materially from the results expressed or implied by those forward-looking statements. In addition to the risk factors described under the heading “Risk factors,” the factors include:

•

the significant amount of our debt;

•

worldwide supply of and demand for oil and natural gas;

•

volatility and declines in oil and natural gas prices;

•

drilling plans (including scheduled and budgeted wells);

•

the number, timing or results of any wells;

•

changes in wells operated and in reserve estimates;

•

supply of CO₂;

•

future growth and expansion;

•

future exploration;

•

integration of existing and new technologies into operations;

•

future capital expenditures (or funding thereof) and working capital;

•

borrowings and capital resources and liquidity;

•

changes in strategy and business discipline;

•

future tax matters;

•

any loss of key personnel;

•

future seismic data (including timing and results);

•

the plans for timing, interpretation and results of new or existing seismic surveys or seismic data;

•

geopolitical events affecting oil and natural gas prices;

•

outcome, effects or timing of legal proceedings;

•

the effect of litigation and contingencies;

•

the ability to generate additional prospects; and

•

the ability to successfully complete merger, acquisition or divestiture plans, regulatory or other limitations imposed as a result of a merger, acquisition or divestiture, and the success of the business following a merger, acquisition or divestiture.

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 these forward-looking statements. 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 terms

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


Bbl		One stock tank barrel, of 42 U.S. gallons liquid volume, used herein in reference to crude oil, condensate or natural gas liquids.

BBtu		One billion British thermal units.

Bcf		One billion cubic feet of natural gas.

Btu		British thermal unit, which is the heat required to raise the temperature of a one-pound mass of water from 58.5 to 59.5 degrees Fahrenheit.

Basin		A large natural depression on the earth’s surface in which sediments generally brought by water accumulate.

Boe		Barrels of oil equivalent using the ratio of six thousand cubic feet of natural gas to one barrel of oil.

Boe/d		Barrels of oil equivalent per day.

Enhanced oil recovery (EOR)		The use of any improved recovery method, including injection of CO₂ or polymer, to remove additional oil after secondary recovery.

Field		An area consisting of a single reservoir or multiple reservoirs all grouped on, or related to, the same individual geological structural feature or stratigraphic condition. The field name refers to the surface area, although it may refer to both the surface and the underground productive formations.

Horizontal drilling		A drilling technique used in certain formations where a well is drilled vertically to a certain depth and then drilled at a right angle within a specified interval.

Infill wells		Wells drilled into the same pool as known producing wells so that oil or natural gas does not have to travel as far through the formation.


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.

MMcf/d		Millions of cubic feet per day.

NYMEX		The New York Mercantile Exchange.

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.

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 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%.

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		A geological term for 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.


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.

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” 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 an independent oil and natural gas company engaged in the production, exploitation, and acquisition of oil and natural gas properties. Since our inception in 1988, we have increased reserves and production primarily through property acquisitions and development activities. In 2010, we reorganized our oil and natural gas assets into enhanced oil recovery (“EOR”) project areas and non-EOR (“conventional”) productive basins. Our primary areas of operation using conventional recovery methods are the Anadarko Basin Area, Central Oklahoma Area, and the Permian Basin Area. We maintain a portfolio of proved and unproved reserves, development and exploratory drilling opportunities, and EOR projects.

As of December 31, 2010, we had estimated proved reserves of 149.3 MMBoe, including EOR reserves of 30.5 MMBoe, with a PV-10 value of approximately $1.8 billion. Our reserves were 66% proved developed and 63% crude oil. For the year ended December 31, 2010, our average daily production was 22.1 MBoe, our estimated reserve life was approximately 19 years, and our oil and natural gas revenues were $408.6 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.

From 2005 to 2010, our proved reserves and production grew at a compounded annual growth rate of 6% and 11%, 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 typically pursue 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. In 1993, we began acquiring properties with CO₂ EOR potential, and we have initiated CO₂ injection in 11 of these 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 future growth to continue through a combination of developmental drilling, exploitation projects, and acquisitions, complemented by a modest amount of exploration activities.

For the year ended December 31, 2010, we made capital investments in oil and natural gas properties of $327.3 million, including $248.1 million for conventional drilling and development, $37.7 million for EOR drilling and development, and $41.5 million for acquisitions. The majority of our capital investments for conventional drilling in 2010 were allocated to our Anadarko Basin and Permian Basin Areas. The wells we drill in these Areas are primarily infill or single step-out wells, which are characterized as lower-risk.

During 2010, we expended a significant portion of the proceeds from our sale of stock to CCMP (discussed below) for our oil and natural gas properties. We have accordingly reduced our capital expenditure budget for 2011 to $250.0 million. Our 2011 capital budget allocates $157.0 million to conventional oil and gas exploration and production activities. The remaining $93.0 million, or 37%, of the capital budget is allocated to the development of our EOR assets, and represents a substantial increase in capital being directed toward development of EOR assets. The increased focus on EOR reduces near term growth opportunities but enhances longer term growth and is consistent with our strategy of driving near term growth with developmental drilling and long term growth through EOR development.

Recent Capital Transactions

On April 12, 2010, we sold 475,043 shares of 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. Fees and other expenses of the transaction were $11.8 million. In connection with the closing of the sale, we entered into and closed our senior secured revolving credit facility, which had an initial borrowing base of $450.0 million, is collateralized by our oil and natural gas properties, and is scheduled to mature on April 12, 2014. We used the proceeds from the sale of common stock to CCMP, along with proceeds available under our senior secured revolving credit facility, to repay the amounts owing under our prior credit facility.

CCMP Capital Advisors, LLC, is a global private equity firm specializing in buyouts and growth equity investments in companies ranging from $500.0 million to more than $3.0 billion in size. CCMP Capital focuses on four primary industries: Consumer/Retail and Media; Industrial; Energy; and Healthcare. Selected investments under management include: ARAMARK Corporation, Chaparral Energy, Edwards Limited, Francesca’s Collections, Generac Power Systems, Infogroup, Jetro Holdings, LHP Hospital Group, and Warner Chilcott. CCMP Capital’s founders have invested over $13.0 billion since 1984. CCMP Capital’s latest fund, CCMP Capital Investors II, L.P., closed in September 2007 with commitments of approximately $3.4 billion.

CCMP Capital has offices in New York, Houston and London. CCMP Capital’s founders have invested approximately $1.3 billion in energy companies over 20 years in subsectors including: exploration and production, power generation, renewable energy, and services. Christopher Behrens and Karl Kurz lead CCMP Capital’s energy investing efforts. Selected investments include: Chaparral Energy, Northern Border Partners LP, Bill Barrett Corporation, Encore Acquisition Company, Vetco International, Carrizo Oil & Gas, and Latigo Petroleum.

On September 16, 2010, we issued $300.0 million aggregate principal amount of 9.875% Senior Notes maturing on October 1, 2020. We used the net proceeds from the 9.875% Senior Notes to pay down outstanding amounts under our senior secured revolving credit facility and for working capital. As a result of the issuance of our 9.875% Senior Notes, the borrowing base under our senior secured revolving credit facility was reduced from $450.0 million to $375.0 million. As of March 29, 2011, we had $374.1 million of availability under our senior secured revolving credit facility.

On February 22, 2011, we issued $400.0 million aggregate principal amount of 8.25% Senior Notes maturing on September 1, 2021. We used the net proceeds from the 8.25% Senior Notes to consummate a tender offer for all of our 8.5% Senior Notes due 2015, to redeem the 8.5% Senior Notes not purchased in the tender offer, and for general corporate purposes.

Business Strategy

We seek to grow reserves and production profitably through a balanced mix of developmental drilling, enhancements, acquisitions, EOR projects, and a modest number of exploration projects. From 2005 to 2010, we have grown proved reserves and production by a compounded annual growth rate of 6% and 11%, respectively, through a combination of drilling and acquisition success. 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 451% per year from 2005 through 2010. We replaced approximately 247% of our production in 2010.

As part of our strategy to grow reserves and production profitably, 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, 2010, we operated properties comprising approximately 86% of our proved reserves. We also strive to minimize commodity price risk through a conservative financial hedging program. The principal elements of our strategy are described further below.

Continue lower-risk drilling program. During the year ended December 31, 2010, we spent approximately $222.8 million on drilling. A majority of our drilling capital in 2010 was invested in our Anadarko Basin and Permian Basin Areas. The wells we drill in these Areas are generally infill or single step-out wells, which are characterized as lower risk. Our drilling expenditures represented approximately 68% of our total capital expenditures for oil and natural gas properties and approximately 56% of our increase in reserves related to purchases of minerals in place, extensions and discoveries, and improved recoveries for 2010.

Based on SEC pricing for the year ended December 31, 2010, we had an inventory of 1,169 proved undeveloped drilling locations, as shown in the following table:


	Identified proved undeveloped drilling locations
Enhanced Oil Recovery Project Areas		435
Anadarko Basin Area		225
Central Oklahoma Area		287
Permian Basin Area		66
Other		156

Total		1,169

Identified drilling locations represent total gross drilling locations identified by our management as an estimation of our multi-year drilling activities on existing acreage. We currently plan to spend a total of approximately $150.0 million, or approximately 60% of our capital expenditures, on drilling in 2011. 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.

Acquire long-lived properties with enhancement opportunities. We continually evaluate acquisition opportunities and expect that they will continue to play a role in increasing our reserve base and future drilling inventory. We have a dedicated team that 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. During the year ended December 31, 2010, we made approximately $32.5 million of proved reserve acquisitions. These acquisition capital expenditures represented approximately 10% of our total capital expenditures for oil and natural gas properties and approximately 21% of our increase in reserves related to purchases of minerals in place, extensions and discoveries, and improved recoveries for 2010. We have budgeted $5.0 million, or 2% of our total capital expenditures, for acquisitions in 2011 and we continue to consider individual field acquisitions that would complement our existing property base and EOR activities.

Apply technical expertise to enhance mature properties. Once we acquire a property and become the operator, we seek to maximize production and economic value 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 26 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, 2010, our reserve report included 874 shut-in and behind-pipe enhancement projects requiring total estimated capital expenditures of $80.8 million over the life of the reserves.

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. We expect to increase our spending and emphasis on CO₂ EOR projects in upcoming 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 cycles to drive the oil to producing wells. 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 7% of our 2010 production and approximately 20% of our proved reserves at December 31, 2010. Approximately 37% of our 2011 planned capital expenditures are related to our EOR operations. 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; (2) it provides a reasonable rate of return even at relatively low oil prices; 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”), and Central Oklahoma (“Central Oklahoma”). We have also identified and own several high potential projects in the West Texas and Southeast New Mexico area (“Permian Area”), and have a small ownership interest in one outside-operated active EOR property in this area. We currently have a total of 82 properties that we are analyzing in regard to their CO₂ EOR potential. To support our existing CO₂ EOR projects, we have CO₂ supply agreements in place in the Panhandle and Central Oklahoma, and have developed a CO₂ pipeline infrastructure system with ownership interests in 405 miles of CO₂ pipelines, of which more than 325 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. We believe we are one of the few CO₂ EOR producers that uses exclusively anthropogenic CO₂.

As of December 31, 2010, our active EOR projects include 11 units where CO₂ EOR recovery methods are used and one EOR project at our North Burbank Unit where polymer EOR is utilized. We plan to continue the polymer EOR program and introduce CO₂ injection into the North Burbank Unit after acquiring a source of CO₂ in the area. During 2010, we spent $37.7 million, including $16.7 million classified as exploration costs, on the development of our EOR assets, and we have budgeted $93.0 million for development of our EOR assets in 2011.

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 39 years after starting his career at Exxon Mobil Corporation as a petroleum engineer. Joe Evans, our Chief Financial Officer, has over 34 years of experience in the oil and natural gas industry. Earl Reynolds, who became our Chief Operating Officer in February 2011, has 27 years of oil and natural gas production experience. Individuals in our 19-person management team have an average of over 30 years of experience in the oil and natural gas industry.

CCMP Capital is a leading global private equity firm with a 20-year history investing approximately $1.3 billion in energy. As part of the CCMP transaction, CCMP Managing Directors Chris Behrens and Karl Kurz joined our board of directors. Mr. Behrens has worked in private equity for sixteen years and co-leads CCMP Capital’s energy investment activities with Mr. Kurz. Mr. Kurz was chief operating officer of Anadarko Petroleum Corporation where he oversaw the company’s global exploration and production, marketing, midstream, land, technology and services and was a member of the company’s executive committee from 2004 to 2009.

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, for capital investments, and to lock in returns on acquisitions, we enter into commodity price swaps, costless collars, and basis protection swaps. Derivative positions are adjusted in response to changes in prices and market conditions as part of an ongoing dynamic process. As of December 31, 2010, we had derivative contracts in place for approximately 61% and 52%, respectively, of our most recent internally estimated proved developed oil and natural gas production through 2012. For the years ended December 31, 2010 and 2009, we received net derivative settlements of $40.0 million and $157.9 million, respectively, which included proceeds from early derivative monetizations of $7.1 million and $111.9 million, respectively. While our derivative activities protect our cash flows during periods of commodity price declines, we paid net derivative settlements of $51.6 million, after proceeds from early derivative monetizations of $32.6 million, through a period of increasing commodity prices during the year ended December 31, 2008.

Properties

The following table presents our proved reserves and PV-10 value as of December 31, 2010 and average daily production for the year ended December 31, 2010, by our areas of operation. Reserves as of December 31, 2010 were estimated using SEC pricing, which was $79.43 per Bbl of oil and $4.38 per Mcf of gas.


	Proved reserves as of December 31, 2010											Average daily production (MBoe per day) Year ended December 31, 2010
	Oil (MBbls)		Natural gas (MMcf)		Total (MBoe)		Percent of total MBoe			PV-10 value ($MM)
Enhanced Oil Recovery Project Areas		45,242		462		45,319		30.4	%	$	556.6		3.0
Anadarko Basin Area		7,136		156,114		33,155		22.2	%		312.8		6.9
Central Oklahoma Area		24,621		46,770		32,416		21.7	%		474.3		5.3
Permian Basin Area		8,605		66,222		19,642		13.2	%		210.3		4.1
Other		7,808		65,652		18,750		12.5	%		216.1		2.8

Total		93,412		335,220		149,282		100.0	%	$	1,770.1		22.1

Our properties have relatively long reserve lives and highly predictable production profiles. In general, these properties have extensive production histories and production enhancement opportunities. As of December 31, 2010, we owned interests in 8,725 gross (3,000 net) producing wells and we operated wells representing approximately 86% 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.

Enhanced Oil Recovery Project Areas

Our EOR project areas include both EOR activities and ongoing conventional activities, as reflected in the following table:


As of and for the year ended December 31, 2010	EOR		Conventional		Total for EOR Project Areas
Reserves (MBoe)		30,474		14,845		45,319
Production (Boe/d)		1,444		1,513		2,957
Drilling and enhancements (in thousands)	$	37,667	$	7,855	$	45,522

We have been actively implementing and managing CO₂ EOR in the Panhandle Area and in Central Oklahoma since 2001. We have CO₂ supply agreements in place in the Panhandle and Central Oklahoma, and we have built and/or expanded CO₂ pipelines to reach our various field locations in those Areas. Arrangements to secure additional sources of CO₂ for potential future projects are currently in process. The U.S. Department of Energy-Office of Fossil Energy provided a report in February 2006 estimating that significant oil reserves could be economically recovered in 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 are available, projects can be developed on shorter timelines, while a more limited supply dictates a prolonged expansion timeline. 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. Our significant active EOR projects are discussed below.

North Burbank Unit—Burbank Area. As of December 31, 2010, the North Burbank Unit, which is our largest property, accounted for 28.8 MMBoe, or 19% of our proved reserves, including 14.2 MMBoe of proved undeveloped 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 production from this Unit increased by 3% to approximately 1,395 Boe/d in 2010 from 1,350 Boe/d in 2009. As of December 31, 2010, we had 282 producing wells, 216 active service wells, and 463 temporarily abandoned wells in this unit. Upside potential exists in restoring a majority of the temporarily abandoned wells to production and in expanding the polymer injection EOR program that Phillips Petroleum Company instituted during the early 1980’s 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 as a result of the Phillips polymer injection program. 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 pilot area from approximately 90 (78 net) Bbls of oil per day in 2008 to approximately 154 (134 net) Bbls of oil per day during 2010. Our review also indicated that additional oil recovery may be obtained with additional volumes of polymer injected into the Phase I area. We will be implementing this additional injection into the Phase I area as a pilot project during 2011.

We are continuing to expand this polymer flood from the Phase I area into the Phase II area. Under current plans, this Phase II area will be developed throughout 2011 and 2012, with development of the remaining phases in the following years. Due to the size of the North Burbank Unit and the limitation of available fresh water and third party services, we believe this development program will be an ongoing project. We also plan to introduce CO₂ injection into this Unit, as we believe that this field may have additional upside with the injection of CO₂. To that end, on March 24, 2011, we signed a contract to purchase up to 100% of CO₂ emissions from an existing nitrogen fertilizer plant that produces approximately 40 MMcf/d of CO₂. After construction of compression facilities and an approximately 70-mile pipeline, we expect to begin CO₂ injection into the North Burbank Unit. The contract requires us to begin purchasing CO₂ for injection no later than July 2013.

During 2010, we invested $8.0 million in the North Burbank Unit to drill five service wells, return 24 production and injection wells to service, and complete associated service facilities work. Approximately $35.0 million of our capital expenditures budget for 2011 has been allocated for EOR operations in the Burbank Area.

Camrick Area Units—Panhandle Area. As of December 31, 2010, the Camrick Area Units accounted for 8.8 MMBoe, or 6% of our proved reserves, substantially all of which are considered EOR reserves. Approximately 4.7 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. CO₂ injection has improved production in these units from approximately 153 (74 net) Bbls of oil per day from 18 wells during 2000 to approximately 1,635 (845 net) Bbls of oil per day during 2010. We plan to continue expansion of CO₂ injection operations across all three units. As of December 31, 2010, we had 61 producing wells, 44 active water injection wells, and 46 temporarily abandoned wells in this area. During the third quarter of 2010, we acquired an additional 6% working interest in these three units, thereby increasing our average working interest to 60%. Our net production from this area increased 32% to 902 Boe/d in 2010 compared to 685 Boe/d in 2009.

We have a long-term contract to purchase up to approximately 20 MMcf/d of CO₂ produced at an existing nitrogen fertilizer plant. 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, 2010, we were injecting a combined 24 MMcf/d of purchased and recycled CO₂ in this area.

Our total investment in the Camrick Area Units during 2010, including the acquisition of additional interest, the purchase of CO₂ for injection, the drilling and completion of three production and injection wells, and general well work, was $17.5 million. We have allocated approximately $17.0 million of our capital expenditures budget for 2011 to this area for continued purchase of CO₂, drilling and completions, compression expansion, electrical upgrade, and remedial well work.

Farnsworth Unit—Panhandle Area. The Farnsworth Unit, which lies to the southeast of and is analogous to the Camrick Area Units, accounted for 4.5 MMBoe, or 3% of our proved reserves, at December 31, 2010. All of the reserves in this Unit, which includes 3.7 MMBoe of proved undeveloped reserves, are considered EOR reserves as of December 31, 2010. We acquired a 99% working interest in the Farnsworth Unit in November 2009 and we began CO₂ injection in December 2010. As of December 31, 2010, we had 20 producing wells, 8 active water and CO₂ injection wells, and 50 temporarily abandoned wells in the Unit. Our net production from this Unit, all of which was conventional, was 107 Boe/d in 2010 compared to 13 Boe/d in 2009.

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 nine MMcf/d of CO₂ from this plant as of December 31, 2010. 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. We completed the final tie-in of this extension in the first quarter of 2011. As of December 31, 2010, we were injecting approximately eight MMcf/d of purchased CO₂ in the Farnsworth Unit.

Our total investment in the Farnsworth Unit during 2010, including the construction of the pipeline extensions and general well work, was $4.6 million. We have allocated approximately $27.0 million of our capital expenditures budget for 2011 to this Unit for the continued development of the CO₂ project and related field facilities.

Other EOR Activities. Our EOR operations in the Central Oklahoma Area also include our three East Velma West Block Sand units, which we have been operating since 2001 with an average working interest of 29%, and our NW Velma Hoxbar Unit where we began CO₂ injection in September 2010, and which we operate with a 100% working interest. In the Panhandle Area, we also have an ownership interest in two outside operated units, and in September 2009, we began CO₂ injection into our three Booker area units, which we operate with an average working interest of 99%. We also have a small working interest in an outside operated unit in the Permian area. Our other EOR activities accounted for 3.2 MMBoe, or 2% of our reserves at December 31, 2010, and contributed total production of 553 Boe/d in 2010. Our total capital investment in these projects was $22.9 million in 2010, and we have allocated approximately $14.0 million of our capital expenditures budget for 2011 to these projects.

Anadarko Basin Area

As of December 31, 2010, the Anadarko Basin Area accounted for 33.2 MMBoe, or 22% of our proved reserves. During the year ended December 31, 2010, our net average daily production in the Anadarko Basin Area was approximately 6.9 MBoe per day, or 31% 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.

Granite Wash Play Area—Oklahoma and Texas. The Granite Wash Play area accounted for 4.4 MMBoe, or 3% of our proved reserves as of December 31, 2010. 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 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 Atoka Wash has a higher percentage of carbonate material. 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 and Atoka Wash), resulting in substantially improved recoveries.

In 2009, we participated in the drilling of six Atoka Wash wells that were completed during the first quarter of 2010. Primarily as a result of these new wells, our production in this area increased by 90% to approximately 1,839 Boe/d in 2010 from 970 Boe/d in 2009. Due to the normal decline curve on this type of well, our production in this area had decreased to 1,763 Boe/d as of December 31, 2010. During 2010, our drilling investment in this area was $31.2 million and we drilled or participated in the drilling of nine wells in this area. We have allocated approximately $20.0 million of our 2011 drilling budget to this area.

Cleveland Sand Play Area—Oklahoma and Texas. The Cleveland Sand Play area accounted for 3.6 MMBoe, or 2% of our proved reserves as of December 31, 2010. This area includes the West Shattuck Cleveland Sand Play and the Aledo Bray Cleveland Sand Play, both of which are considered tight gas sand reservoirs. During 2010, our drilling investment in this area was $40.9 million and we drilled or participated in the drilling of 12 wells in this area. Our net production from this area increased 37% to approximately 961 Boe/d in 2010 compared to 701 Boe/d in 2009, primarily due to our drilling activity in the area. We have allocated approximately $18.0 million of our 2011 drilling budget to this area. Our drilling activity for 2011 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 Basin Woodford Shale Play Area—Western Oklahoma. As of December 31, 2010, we own and control approximately 66,150 (22,270 net) acres in the emerging Woodford Shale resource play of western Oklahoma, which primarily are held by production from other formations. 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 with approximately 140 Woodford Shale 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. During 2010, our drilling investment in this area was $2.6 million and we participated in the drilling of five wells in this area. We have allocated approximately $5.0 million of our 2011 drilling budget to this area.

Central Oklahoma Area

As of December 31, 2010, the Central Oklahoma Area accounted for 32.4 MMBoe, or 22% of our proved reserves. During the year ended December 31, 2010, our net average daily production in the Central Oklahoma Area was approximately 5.3 MBoe per day, or 24% of our total net average daily production.

Osage-Creek Area—Osage, Creek, and Kay Counties, Oklahoma. The Osage-Creek area accounted for 14.5 MMBoe, or 10%, of our proved reserves as of December 31, 2010. Our net production from this area increased 17% to an average of 2,376 Boe/d in 2010 from 2,025 Boe/d in 2009. 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. Recently, we have been drilling infill and step-out locations for both the Mississippi Chat and the Burbank Sand. We have a Company-owned drilling rig working full time in this area, and we drilled 52 wells during 2010. Our drilling investment was $23.6 million in 2010, and we have allocated approximately $13.0 million of our 2011 drilling budget to this area.

Northern Oklahoma Mississippi Play—Various Counties, Oklahoma. The Northern Oklahoma Mississippi Play, as currently defined, spans from Woods County, Oklahoma on the west to Osage, Noble, and Payne counties on the east and northward into Kansas. Several companies are devoting large amounts of capital toward leasing and drilling activity in this developing play. Horizontal drilling of the Mississippi formation across the area is yielding encouraging early results. We are currently evaluating our significant acreage position in this area. During 2010, our drilling investment in this area was $2.9 million, and we drilled and/or participated in the drilling of four wells in this area.

Permian Basin Area

As of December 31, 2010, the Permian Basin Area accounted for 19.6 MMBoe, or 13% of our proved reserves. During the year ended December 31, 2010, our net average daily production in the Permian Basin Area was approximately 4.1 MBoe per day, or 19% of our total net average daily production.

Haley Area—Loving County, Texas. The Haley area accounted for 5.7 MMBoe, or 4% of our proved reserves at December 31, 2010. Our net production from this area, which is primarily dry gas, decreased by 20% to approximately 1,905 Boe/d in 2010 compared to 2,381 Boe/d in 2009, primarily due to the decline in production from the Bowdle 47 No. 2 well, which began selling natural gas in late November 2008 and produced an average of 720 net Boe/d in December 2010 compared to an average of 1,236 net Boe/d in December 2009. In April 2010, we completed an offset to the Bowdle 47 No. 2, the Bowdle 47 No. 4 well, which produced an average of 402 net Boe/d in December 2010. Due to prevailing low natural gas prices, we do not plan to invest significant amounts in drilling in this area in 2011.

Tunstill Field Play—Loving and Reeves Counties, Texas. The Tunstill Field Play represented 3.4 MMBoe, or 2% of our proved reserves at December 31, 2010. Our net production from this area increased by 29% to approximately 669 Boe/d in 2010 from 517 Boe/d in 2009, primarily due to our drilling activity. During 2010, our drilling investment was $17.9 million, and we drilled 14 wells. We have allocated approximately $7.0 million of our 2011 drilling budget to this area.

Avalon Shale/Bone Spring Area—West Texas. We own approximately 17,020 (14,540 net) acres in the Avalon/Bone Spring oil play developing in West Texas. Operators have recently begun to switch from vertical to horizontal drilling to improve hydrocarbon recovery from this formation, and approximately 305 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 three 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 are currently developing our geologic mapping and evaluating the drilling activity in the area. Depending on the results of this analysis, we may initiate our drilling program in the second quarter of 2011.

Other Areas

Ark-La-Tex. The Ark-La-Tex area accounted for 8.5 MMBoe, or 6% of our proved reserves as of December 31, 2010. Our net production from this area increased slightly to approximately 1,178 Boe/d in 2010 from 1,166 Boe/d in 2009, primarily due to acquisitions.

Gulf Coast. The Gulf Coast area accounted for 3.6 MMBoe, or 2% of our proved reserves as of December 31, 2010. Our net production from this area decreased by 7% to approximately 763 Boe/d in 2010 compared to 818 Boe/d in 2009. During 2010, our drilling investment in this area was $25.0 million. We drilled two wells in this area, including one exploratory well, during 2010, and the results of these wells are still developing. We currently have limited amounts budgeted for drilling in this area during 2011.

North Texas. The North Texas area accounted for 3.9 MMBoe, or 3% of our proved reserves as of December 31, 2010. Our net production from this area increased by 7% to approximately 515 Boe/d in 2010 from 482 Boe/d in 2009. We drilled eight North Texas wells during the year ended December 31, 2010.

Rocky Mountains. The Rocky Mountains area accounted for 2.8 MMBoe, or 2% of our proved reserves as of December 31, 2010. Our net production from this area decreased slightly to approximately 364 Boe/d in 2010 compared to 381 Boe/d in 2009. We drilled and/or participated in the drilling of 13 Rocky Mountain wells during 2010, including three operated wells late in the year. Production from these wells is expected to come online in the first and second quarters of 2011.

Oil and Natural Gas Reserves

Proved reserves are those 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. 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 engineering group, which is led by our Senior Vice President of Reservoir Engineering and Business Development who is a registered Professional Engineer with 38 years of diversified management and operational and technical engineering experience.

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. Technologies and economic data used include updated production data, well performance, formation logs, geological maps, reservoir pressure tests, and wellbore mechanical integrity information.

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 27 years of petroleum consulting experience. The person responsible for overseeing the preparation of our reserve estimates at Ryder Scott Company, L.P. is a registered Professional Engineer with over 27 years of reservoir engineering experience.

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 Business Development and the Chief Financial Officer, is 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 representative 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 Business Development and our President and Chief Executive Officer.

The table below summarizes our net proved oil and natural gas reserves and PV-10 values at December 31, 2010. Information in the table is derived from reserve reports of estimated proved reserves prepared by Cawley, Gillespie & Associates, Inc. (52% of PV-10 value) and by Ryder Scott Company, L.P. (31% 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 (17% of PV-10 value) at December 31, 2010. 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.


	Net proved reserves as of December 31, 2010
	Oil (MBbls)		Natural gas (MMcf)		Total (MBoe)		PV-10 value (In thousands)
Developed—producing		42,365		211,212		77,567	$	1,130,946
Developed—non-producing		13,242		46,542		20,999		235,447
Undeveloped		37,805		77,466		50,716		403,668

Total proved		93,412		335,220		149,282	$	1,770,061

The following table shows material changes in proved undeveloped reserves that occurred during the year ended December 31, 2010.


Proved undeveloped reserves (MBoe)
Proved undeveloped reserves as of January 1, 2010	48,012
Undeveloped reserves transferred to developed(1)	(6,210	)
Purchases of minerals in place	434
Extensions and discoveries	6,983
Improved recoveries	4,656
Revisions and other	(3,159	)

Proved undeveloped reserves as of December 31, 2010(2)	50,716

(1)	Approximately $87.5 million of developmental drilling costs during the year ended December 31, 2010 related to undeveloped reserves that were transferred to developed.

(2)	Includes 4.7 MMBoe of reserves that have been reported for more than five years that relate specifically to our Camrick area CO₂ EOR projects. Development of these projects is ongoing. See “Properties—Enhanced Oil Recovery Project Areas” for additional discussion of our CO₂ EOR projects.

The following table details our gross and net interest in producing wells in which we have a working interest and the number of wells we operated at December 31, 2010 by area. We also hold royalty interests in units and acreage in addition to the wells in which we have a working interest. Wells are classified as oil or natural gas according to their predominant production stream. Gross wells is the total number of producing wells in which we have a working interest, and net wells is the sum of our working interest in all producing wells.


	Producing Oil Wells				Producing Gas Wells				Total
	Gross		Net		Gross		Net		Gross		Net
Operated Wells:
Enhanced Oil Recovery Project Areas		464		390		—		—		464		390
Anadarko Basin Area		260		217		429		321		689		538
Central Oklahoma Area		988		871		67		53		1,055		924
Permian Basin Area		330		310		62		51		392		361
Other		195		167		136		112		331		279

Total		2,237		1,955		694		537		2,931		2,492

Non-Operated Wells:
Enhanced Oil Recovery Project Areas		252		8		—		—		252		8
Anadarko Basin Area		396		22		1,041		111		1,437		133
Central Oklahoma Area		1,885		237		190		18		2,075		255
Permian Basin Area		1,047		47		91		21		1,138		68
Other		649		24		243		20		892		44

Total		4,229		338		1,565		170		5,794		508

Total Wells:
Enhanced Oil Recovery Project Areas		716		398		—		—		716		398
Anadarko Basin Area		656		239		1,470		432		2,126		671
Central Oklahoma Area		2,873		1,108		257		71		3,130		1,179
Permian Basin Area		1,377		357		153		72		1,530		429
Other		844		191		379		132		1,223		323

Total		6,466		2,293		2,259		707		8,725		3,000

The following table sets forth information with respect to wells drilled during the periods indicated. The information should not be considered indicative of future performance, nor should a correlation be assumed between the number of productive wells drilled, quantities of reserves found, or economic value. Development wells are wells drilled within the proved area of an oil or natural gas reservoir to the depth of a stratigraphic horizon known to be productive. Exploratory wells are wells drilled to find a new field or to find a new reservoir in a field previously found to be productive of oil or natural gas in another reservoir. Productive wells are those that produce commercial quantities of hydrocarbons, exclusive of their capacity to produce at a reasonable rate of return.


	2010						2009						2008
	Gross			Net			Gross			Net			Gross			Net
Development wells
Productive		234.0			100.0			168.0			49.5			319.0			74.9
Dry		5.0			1.9			2.0			1.9			4.0			2.0
Exploratory wells
Productive		18.0			18.0			2.0			1.0			3.0			2.2
Dry		1.0			1.0			0.0			0.0			0.0			0.0
Total wells
Productive		252.0			118.0			170.0			50.5			322.0			77.1
Dry		6.0			2.9			2.0			1.9			4.0			2.0

Total		258.0			120.9			172.0			52.4			326.0			79.1

Percent productive		98	%		98	%		99	%		96	%		99	%		97	%

The following table details our gross and net interest in developed and undeveloped acreage at December 31, 2010 by state. This does not include acreage in which we hold only royalty interests.


	Developed				Undeveloped				Total
	Gross		Net		Gross		Net		Gross		Net
Arkansas		13,257		3,656		—		—		13,257		3,656
Kansas		11,956		9,511		—		—		11,956		9,511
Louisiana		22,659		10,718		1,487		1,144		24,146		11,862
Mississippi		790		36		—		—		790		36
Montana		10,153		3,113		1,650		1,650		11,803		4,763
North Dakota		6,408		4,325		—		—		6,408		4,325
New Mexico		17,057		10,833		240		240		17,297		11,073
Oklahoma		806,904		342,379		44,503		36,306		851,407		378,685
Texas		228,119		144,883		30,214		26,702		258,333		171,585
Utah		40		5		—		—		40		5
Wyoming		23,048		3,568		—		—		23,048		3,568

Total		1,140,391		533,027		78,094		66,042		1,218,485		599,069

The following table summarizes our estimates of net proved oil and natural gas reserves, estimated future net revenues from proved reserves, the PV-10 value, the standardized measure of discounted future net cash flows, and the prices used in projecting those measures over the past three years. Estimates of our net proved oil and natural gas reserves as of December 31, 2010, 2009, and 2008 were prepared by Cawley, Gillespie & Associates, Inc. (52%, 59%, and 68% of PV-10 value, respectively) and Ryder Scott Company, L.P. (31%, 23% and 7% of PV-10 value, respectively). Our internal engineering staff has prepared a report of estimated proved reserves on our remaining smaller value properties (17%, 18%, and 25% of PV-10 value in 2010, 2009, and 2008, respectively).


	As of December 31,
	2010			2009			2008
Estimated proved reserve volumes:
Oil (Mbbls)		93,412			89,469			51,283
Natural gas (MMcf)		335,220			314,430			372,366
Oil equivalent (MBoe)		149,282			141,874			113,344
Proved developed reserve percentage		66	%		66	%		74	%
Estimated proved reserve values (in thousands):
Future net revenue	$	4,110,844		$	3,080,410		$	1,918,270
PV-10 value	$	1,770,061		$	1,323,541		$	932,692
Standardized measure of discounted future net cash flows	$	1,236,026		$	971,364		$	755,013
Oil and natural gas prices:(1)
Oil price (per Bbl)	$	79.43		$	61.18		$	44.60
Natural gas price (per Mcf)	$	4.38		$	3.87		$	5.62
Estimated reserve life in years(2)		18.5			18.6			16.0

(1)

Prices for 2010 and 2009 were based upon the average first day of the month prices for each month during the respective year. The prices for 2008 were based upon the prices in effect on December 31, 2008. In all three years, the prices shown were adjusted for location differentials to reflect the net prices we receive.

(2)	Calculated by dividing net proved reserves by net production volumes for the year indicated.

The following table summarizes our costs incurred for oil and natural gas properties and our reserve replacement ratio for each of the last three years.


	As of December 31,
(dollars in thousands)	2010			2009			2008
Property acquisition costs
Proved properties	$	32,458		$	14,552		$	39,201
Unproved properties		9,062			3,781			6,677

Total acquisition costs		41,520			18,333			45,878
Development costs(1)		251,564			127,640			251,690
Exploration costs(2)		34,180			4,942			5,108

Total	$	327,264		$	150,915		$	302,676

Annual reserve replacement ratio(3)		247	%		243	%		200	%

(1)	Includes $9.8 million, $5.8 million and $17.9 million of costs related to CO₂ support facilities and pipelines in 2010, 2009 and 2008, respectively.

(2)	Includes $16.7 million of EOR costs in 2010.

(3)

Calculated by dividing the sum of reserve additions (from purchases of minerals in place, extensions and discoveries, and improved recoveries) by the production for the corresponding period. The values for these reserve additions are derived directly from the proved reserves table located in Note 16 of the notes to our consolidated financial statements. In calculating the reserve replacement ratio, we do not use unproved reserve quantities. Management uses the reserve replacement ratio as an indicator of our ability to replenish annual production volumes and grow reserves, thereby providing some information of the sources of future production. It should be noted that the reserve replacement ratio is a statistical indicator that has limitations. As an annual measure, the ratio is limited because it typically varies widely based on the extent and timing of new discoveries and property acquisitions. Its predictive and comparative value is also limited for the same reasons. The reserve replacement ratio is comprised of the following:


	Year ended December 31,
	2010						2009						2008
	Reserves replaced			Percent of total			Reserves replaced			Percent of total			Reserves replaced			Percent of total
Purchases of minerals in place		52	%		21.2	%		9	%		3.5	%		35	%		17.2	%
Extensions and discoveries		138	%		55.7	%		195	%		80.4	%		155	%		77.6	%
Improved recoveries		57	%		23.1	%		39	%		16.1	%		10	%		5.2	%

Total		247	%		100.0	%		243	%		100.0	%		200	%		100.0	%

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


	Year ended December 31,
	2010		2009		2008
Production:(1)
Oil (MBbls)		4,093		3,874		3,773
Natural gas (MMcf)		23,742		22,584		19,795

Combined (MBoe)		8,050		7,638		7,072
Average daily production:
Oil (Bbls)		11,214		10,614		10,309
Natural gas (Mcf)		65,046		61,874		54,085

Combined (Boe)		22,055		20,926		19,323
Average prices (excluding derivative settlements):
Oil (per Bbl)	$	74.53	$	55.04	$	92.47
Natural gas (per Mcf)		4.36		3.51		7.72

Combined (per Boe)	$	50.75	$	38.28	$	70.95
Average costs per Boe:
Lease operating expenses	$	13.18	$	12.32	$	17.04
Production taxes		3.29		2.66		4.78
Depreciation, depletion, and amortization		13.60		13.64		14.29
General and administrative		3.72		3.11		3.16

(1)

The North Burbank Unit is the only field that contained 15% or more of our total proved reserve volumes at December 31, 2010. Production from this Unit, all of which was oil, was 509 MBbls, 492 MBbls, and 454 MBbls of our net production during 2010, 2009, and 2008, respectively.

Non-GAAP Financial Measures and Reconciliations

The PV-10 value is derived from the standardized measure of discounted future net cash flows, which is the most directly comparable financial measure computed using generally accepted accounting principles (“GAAP”). PV-10 value is a computation of the standardized measure of discounted future net cash flows on a pre-tax basis. PV-10 value is equal to the standardized measure of discounted future net cash flows at December 31, 2010 before deducting future income taxes, discounted at 10%. We believe that the presentation of the PV-10 value is relevant and useful to investors because it presents the discounted future net cash flows attributable to our proved reserves prior to taking into account future corporate income taxes, and it is a useful measure of evaluating the relative monetary significance of our oil and natural gas properties. Further, investors may utilize the measure as a basis for comparison of the relative size and value of our reserves to other companies. We use this measure when assessing the potential return on investment related to our oil and natural gas properties. However, PV-10 value is not a substitute for the standardized measure of discounted future net cash flows. Our PV-10 value measure and the standardized measure of discounted future net cash flows do not purport to present the fair value of our oil and natural gas reserves.

The following table provides a reconciliation of PV-10 value to the standardized measure of discounted future net cash flows for the periods shown:


	As of December 31,
(dollars in thousands)	2010			2009			2008
PV-10 value	$	1,770,061		$	1,323,541		$	932,692
Present value of future income tax discounted at 10%		(534,035	)		(352,177	)		(177,679	)

Standardized measure of discounted future net cash flows	$	1,236,026		$	971,364		$	755,013

Management uses adjusted EBITDA as a supplemental financial measurement to evaluate our operational trends. Items excluded generally represent non-cash adjustments, the timing and amount of which cannot be reasonably estimated and are not considered by management when measuring our overall operating performance. In addition, adjusted EBITDA is generally consistent with the Consolidated EBITDAX calculation that is used in the covenant ratio required under our senior secured revolving credit facility described in the Liquidity and Capital Resources section of Management’s Discussion and Analysis of Financial Condition and Results of Operations. We consider compliance with this covenant to be material. Adjusted EBITDA is used as a supplemental financial measurement in the evaluation of our business and should not be considered as an alternative to net income, as an indicator of our operating performance, as an alternative to cash flows from operating activities, or as a measure of liquidity. Adjusted EBITDA is not defined under GAAP and, accordingly, it may not be a comparable measurement to those used by other companies.

We define adjusted EBITDA as net income (loss), adjusted to exclude (1) interest and other financing costs, net of capitalized interest, (2) income taxes, (3) depreciation, depletion and amortization, (4) unrealized (gain) loss on ineffective portion of hedges and reclassification adjustments, (5) non-cash change in fair value of non-hedge derivative instruments, (6) interest income, (7) deferred compensation expense (gain), (8) gain or loss on disposed assets, and (9) impairment charges and other significant, unusual non-cash charges. Through March 31, 2010, our calculation of adjusted EBITDA excluded any cash proceeds received from the monetization of derivatives with a scheduled maturity date more than 12 months following the date of such monetization, in accordance with the terms of our prior credit facility.

In July 2010, we amended the definition of Consolidated EBITDAX in our senior secured revolving credit facility to (1) permit cash proceeds received from the monetization of derivatives to be included in the calculation of Consolidated EBITDAX, to the extent that such monetizations, in any period between scheduled redeterminations, do not exceed 5% of the borrowing base then in effect, and (2) permit the exclusion from the calculation of Consolidated EBITDAX of up to $4.5 million in one-time cash expenses associated with our financing transactions that were incurred and paid during the second quarter of 2010. As a result, beginning with the second quarter of 2010, we have changed our calculation of adjusted EBITDA to include cash proceeds received from the monetization of derivatives with a scheduled maturity date more than 12 months following the date of such monetization, to the extent permitted by our senior secured revolving credit facility. However, we have not changed our calculation of adjusted EBITDA to exclude approximately $2.3 million of one-time cash expenses associated with our financing transactions. As a result of the permitted exclusion of these expenses, our Consolidated EBITDAX as calculated for covenant compliance purposes is higher than our adjusted EBITDA for the year ended December 31, 2010.

The following table provides a reconciliation of net income (loss) to adjusted EBITDA for the specified periods:


	Year Ended December 31,
(dollars in thousands)	2010			2009			2008
Net income (loss)	$	33,713		$	(144,318	)	$	(54,750	)
Interest expense		83,611			90,102			86,038
Income tax expense (benefit)		23,803			(85,936	)		(34,386	)
Depreciation, depletion, and amortization		109,503			104,734			101,973
Unrealized (gain) loss on ineffective portion of hedges and reclassification adjustments		23,889			(21,752	)		(12,549	)
Non-cash change in fair value of non-hedge derivative instruments		(2,523	)		149,106			(89,554	)
Proceeds from monetization of derivatives with a scheduled maturity date more than 12 months from monetization date included in EBITDA		9,418			—			—
Proceeds from monetization of derivatives with a scheduled maturity date more than 12 months from monetization date excluded from EBITDA		—			(102,352	)		—
Interest income		(144	)		(283	)		(409	)
Deferred compensation expense (gain)		2,600			1,145			(306	)
Gain on disposed assets		(184	)		(10,463	)		(177	)
Loss on impairment of oil and natural gas properties		—			240,790			281,393
Other non-cash charges		4,150			2,928			2,900

Adjusted EBITDA	$	287,836		$	223,701		$	280,173

Competition

The oil and natural gas industry is highly competitive. We encounter strong competition from other independent operators and from major oil companies in acquiring properties, contracting for drilling equipment and securing trained personnel. Many of these competitors have financial and technical resources and staffs substantially larger than ours. As a result, our competitors may be able to pay more for desirable leases, or to evaluate, bid for and purchase a greater number of properties or prospects than our financial or personnel resources will permit.

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

Competition is also strong for attractive oil and natural gas producing properties, undeveloped leases and drilling rights, and we cannot assure you that we will be able to compete satisfactorily. Many large oil companies have been actively marketing some of their existing producing properties for sale to independent producers. Although we regularly evaluate acquisition opportunities and submit bids as part of our growth strategy, we do not have any current agreements, understandings or arrangements with respect to any material acquisition.

Markets

The marketing of oil and natural gas we produce will be affected by a number of factors that are beyond our control and whose exact effect cannot be accurately predicted. These factors include:

•

the amount of crude oil and natural gas imports;

•

the availability, proximity and cost of adequate pipeline and other transportation facilities;

•

the success of efforts to market competitive fuels, such as coal and nuclear energy and the growth and/or success of alternative energy sources such as wind power;

•

the effect of federal and state regulation of production, refining, transportation and sales;

•

the laws of foreign jurisdictions and the laws and regulations affecting foreign markets;

•

other matters affecting the availability of a ready market, such as fluctuating supply and demand; and

•

general economic conditions in the United States and around the world.

The supply and demand balance of crude oil and natural gas in world markets has caused significant variations in the prices of these products over recent years. The North American Free Trade Agreement eliminated most trade and investment barriers between the United States, Canada and Mexico, resulting in increased foreign competition for domestic natural gas production. New pipeline projects recently approved by, or presently pending before the Federal Energy Regulatory Commission (FERC), as well as nondiscriminatory access requirements, could further increase the availability of natural gas imports to certain U.S. markets. Such imports could have an adverse effect on both the price and volume of natural gas sales from our wells.

Members of the Organization of Petroleum Exporting Countries establish prices and production quotas from time to time with the intent of reducing the current global oversupply and maintaining, lowering or increasing certain price levels. We are unable to predict what effect, if any, such actions will have on both the price and volume of crude oil sales from our wells.

In several initiatives, FERC has required pipeline transportation companies to develop electronic communication and to provide standardized access via the Internet to information concerning capacity and prices on a nationwide basis, so as to create a national market. Parallel developments toward an electronic marketplace for electric power, mandated by FERC, are serving to create multi-national markets for energy products generally. These systems will allow rapid consummation of natural gas transactions. Although this system may initially lower prices due to increased competition, it is anticipated it will ultimately expand natural gas markets and improve their reliability.

Environmental Matters and Regulation

We believe that our properties and operations are in substantial compliance with applicable environmental laws and regulations, and our operations to date have not resulted in any material environmental liabilities. To reduce our exposure to potential environmental risk, we typically have our field personnel inspect operated properties prior to completing each acquisition.

General

Our operations, like the operations of other companies in our industry, are subject to stringent federal, state and local laws and regulations governing the discharge of materials into the environment or otherwise relating to environmental protection. These laws and regulations may:

•

require the acquisition of various permits before drilling commences;

•

require the installation of expensive emission monitoring and/or pollution control equipment;

•

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

•

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

•

require remedial measures to prevent pollution from former operations, such as pit closure and plugging of abandoned wells;

•

impose substantial liabilities for pollution resulting from our operations; and

•

with respect to operations affecting federal lands or leases, require preparation of a Resource Management Plan, an Environmental Assessment, and/or an Environmental Impact Statement.

These laws, rules and regulations may also restrict the rate of oil and natural gas production below the rate that would otherwise be possible. The regulatory burden on the oil and natural gas industry increases the cost of doing business in the industry and consequently affects profitability. Additionally, Congress and federal and state agencies frequently revise environmental laws and regulations, and any changes that result in more stringent and costly waste handling, disposal and clean-up requirements for the oil and natural gas industry could have a significant impact on our operating costs.

We monitor our properties and operations in an effort to ensure that our properties and operations are, and remain, in substantial compliance with all current applicable environmental laws and regulations. If, at any time, we determine that our properties and/or operations do not substantially comply with all current applicable environmental laws and regulations, we take action to remedy such noncompliance on our own volition and do not delay taking action until ordered to do so by a regulatory authority. We cannot predict how future environmental laws and regulations may affect our properties or operations. For the years ended December 31, 2010 and 2009, we did not incur any material capital expenditures for installation of remediation or pollution control equipment at any of our facilities. As of the date of this report, we are not aware of any other environmental issues or claims that will require material capital expenditures during 2011 or that will otherwise have a material impact on our financial position or results of operations.

Environmental laws and regulations that could have a material impact on the oil and natural gas exploration and production industry include the following:

National Environmental Policy Act

Oil and natural gas exploration and production activities on federal lands are subject to the National Environmental Policy Act (NEPA). NEPA requires federal agencies, including the Department of Interior, to evaluate major agency actions having the potential to significantly impact the environment. In the course of such evaluations, an agency will typically prepare an Environmental Assessment to assess the potential direct, indirect and cumulative impacts of a proposed project and, if necessary, will prepare a more detailed Environmental Impact Statement that may be made available for public review and comment.

All of our current exploration and production activities, as well as proposed exploration and development plans, on federal lands require governmental permits that are subject to the requirements of NEPA. This process has the potential to delay the development of oil and natural gas projects.

Waste Handling

The Resource Conservation and Recovery Act (RCRA), and comparable state statutes, regulate the generation, transportation, treatment, storage, disposal and cleanup of “hazardous wastes” and the disposal of non-hazardous wastes. Under the auspices of the federal Environmental Protection Agency (EPA), individual states administer some or all of the provisions of RCRA, sometimes in conjunction with their own, more stringent requirements. Drilling fluids, produced waters, and most of the other wastes associated with the exploration, development, and production of crude oil, natural gas, or geothermal energy constitute “solid wastes,” which are regulated under the less stringent non-hazardous waste provisions. However, there is no guarantee that the U.S. Congress, EPA or individual states will not adopt more stringent requirements for the handling of non-hazardous wastes or categorize some non-hazardous wastes as hazardous for future regulation.

We believe that we are currently in substantial compliance with the requirements of RCRA and related state and local laws and regulations, and that we hold all necessary and up-to-date permits, registrations and other authorizations to the extent that our operations require them under such laws and regulations. Although we do not believe the current costs of managing our presently classified wastes to be significant, any legislative or regulatory reclassification of oil and natural gas exploration and production wastes could increase our costs to manage and dispose of such wastes.

Comprehensive Environmental Response, Compensation and Liability Act

The Comprehensive Environmental Response, Compensation and Liability Act (CERCLA), also known as the “Superfund” law, imposes strict, and in certain circumstances joint and several liability, on persons who are considered to be responsible for the release of a “hazardous substance” into the environment. Responsible parties include the current, as well as former, owner or operator of the site where the release occurred and persons that disposed or arranged for the disposal of the hazardous substance at the site. Under CERCLA, such persons may be liable for the costs of cleaning up the hazardous substances released into the environment, for damages to natural resources and for the costs of certain health studies. In addition, neighboring landowners and other third parties may file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment.

We currently own, lease, or operate numerous properties that have produced oil and natural gas for many years. Although we believe we have utilized operating and waste disposal practices that were standard in the industry at the time, hazardous substances, wastes, or hydrocarbons may have been released on, under, or from the properties owned or leased by us, or on or under other locations, including off-site locations, where such substances have been taken for disposal. In addition, some of these properties have been operated by third parties or by previous owners or operators whose treatment and disposal of hazardous substances, wastes, or hydrocarbons was not under our control. These properties and the substances disposed or released on them may be subject to CERCLA, RCRA, and analogous state laws. Under such laws, we could be required to remove previously disposed substances and wastes, remediate contaminated property, or perform remedial plugging or pit closure operations to prevent future contamination.

Water Discharges

The Federal Water Pollution Control Act, also known as the Clean Water Act, and analogous state laws impose restrictions and strict controls on the discharge of pollutants, including produced waters and other oil and natural gas wastes, into waters of the United States. The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by EPA or the relevant state. The Clean Water Act also prohibits the discharge of dredge and fill material in regulated waters, including wetlands, unless authorized by a permit issued by the U.S. Army Corps of Engineers. Federal and state regulatory agencies can impose administrative, civil and criminal penalties for non-compliance with discharge permits or other requirements of the federal Clean Water Act and analogous state laws and regulations. We believe we are in substantial compliance with the requirements of the Clean Water Act.

The Safe Drinking Water Act, Groundwater Protection, and the Underground Injection Control Program

The federal Safe Drinking Water Act (SDWA) and the Underground Injection Control (UIC) program promulgated under the SDWA and state programs regulate the drilling and operation of salt water disposal wells. EPA directly administers the UIC program in some states and in others it is delegated to the state for administering. Permits must be obtained before drilling salt water disposal wells, and casing integrity monitoring must be conducted periodically to ensure the casing is not leaking saltwater to groundwater.

Contamination of groundwater by oil and natural gas drilling, production, and related operations may result in fines, penalties, and remediation costs, among other sanctions and liabilities under the SDWA and state laws. In addition, third party claims may be filed by landowners and other parties claiming damages for alternative water supplies, property damages, and bodily injury.

We engage third parties to provide hydraulic fracturing or other well stimulation services to us in connection with many of the wells for which we are the operator. The U.S. Congress has considered legislation that would repeal the exemption for hydraulic fracturing from the SDWA, which would have the effect of allowing the EPA to promulgate regulations requiring permits and implementing potential new requirements of hydraulic fracturing under the SDWA. This could, in turn, require state regulatory agencies in states with programs delegated under the SDWA to impose additional requirements on hydraulic fracturing operations.

Further, in 2010, EPA initiated a Hydraulic Fracturing Research Study to address concerns that hydraulic fracturing may affect the safety of drinking water. As part of that process, EPA requested and received information from the major fracturing service providers regarding the chemical composition of fluids, standard operating procedures, and the sites where they engage in hydraulic fracturing. In February 2011, EPA released its Draft Plan to Study the Potential Impacts of Hydraulic Fracturing on Drinking Water Resources, proposing to study the lifecycle of hydraulic fracturing fluid and providing a comprehensive list of chemicals identified in fracturing fluid and flowback/produced waste. These developments, as well as increased scrutiny of hydraulic fracturing activities by state authorities, municipal location prohibitions and recent Clean Water Act citizen suit litigation activities arising from discharge of recovered wastewater from hydraulic fracturing operations to municipal wastewater treatment works may result in additional levels of regulation or level of complexity with respect to existing regulation at the federal and state levels.

The Clean Air Act

The federal Clean Air Act and comparable state laws regulate emissions of various air pollutants through air emissions permitting programs and the imposition of other requirements. In addition, the EPA has developed and continues to develop stringent regulations governing emissions of toxic air pollutants at specified sources. Federal and state regulatory agencies can impose administrative, civil and criminal penalties for non-compliance with air permits or other requirements of the federal Clean Air Act and associated state laws and regulations. The EPA proposed in a consent decree, which has not been approved by a federal court, that it will issue by January 31, 2011 a proposal to revise its national emissions standards for hazardous air pollution for crude oil and natural gas production, as well as gas transmission and storage and its new source performance standards for oil and natural gas production. The EPA has not issued such a proposal at this time.

Some of our new facilities may be required to obtain permits before work can begin, and existing facilities may be required to incur capital costs in order to comply with new monitoring and reporting requirements and/or emission limitations. In December 2009, the EPA promulgated a finding that serves as the foundation under the Clean Air Act to issue other rules that would result in federal greenhouse gas regulations and emissions limits under the Clean Air Act, even without Congressional action. As part of this array of new regulations, in September 2009, the EPA also promulgated a greenhouse gas monitoring and reporting rule that requires certain parties, including participants in the oil and natural gas industry, to monitor and report their greenhouse gas emissions, including methane and carbon dioxide, to the EPA. In May 2010, EPA promulgated final rules subjecting greenhouse gas to regulation under the Clean Air Act, triggering application of other provisions of the Clean Air Act to major stationary sources of greenhouse gas emissions. In June 2010, EPA promulgated final rules limiting the scope of certain provisions of the Clean Air Act as applied to greenhouse gas emission sources. Additionally, in November 2010, EPA promulgated mandatory greenhouse gas emission reporting rules specifically applying to oil and natural gas exploration and production. These rules are published in the federal register and available on the Internet. These regulations govern our operations to the extent applicable. See “Risk factors—Regulation related to global warming and climate change could have an adverse effect on our operations and demand for oil and natural gas.” These regulations may increase the costs of compliance for some facilities, and federal and state regulatory agencies can impose administrative, civil and criminal penalties for non-compliance. We believe we are in substantial compliance with the current requirements of the Clean Air Act.

Other Laws and Regulation

The Kyoto Protocol to the United Nations Framework Convention on Climate Change became effective in February 2005. Under the Protocol, participating nations are required to implement programs to reduce emissions of greenhouse gases that are suspected of contributing to global warming. The United States is not currently a participant in the Protocol, and Congress is considering proposed legislation directed at reducing greenhouse gas emissions. Also, there has been support in various regions of the country for legislation that requires reductions in greenhouse gas emissions, and some states have already adopted legislation addressing greenhouse gas emissions from various sources, primarily power plants. The oil and natural gas industry is a direct source of certain greenhouse gas emissions, namely carbon dioxide and methane, and future restrictions on such emissions could impact our future operations. Our operations are not adversely impacted by current state and local climate change initiatives and, at this time, it is not possible to accurately estimate how potential future laws or regulations limiting or otherwise addressing greenhouse gas emissions would impact our business.

Other Regulation of the Oil and Natural Gas Industry

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

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

Drilling and Production

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

•

the location of wells;

•

the method of drilling and casing wells;

•

the rates of production or “allowables”;

•

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

•

the plugging and abandoning of wells; and

•

notice to surface owners and other third parties.

State laws regulate the size and shape of drilling and spacing units or proration units governing the pooling of oil and natural gas properties. Some states allow forced pooling or integration of tracts to facilitate exploration while other states rely on voluntary pooling of lands and leases. In some instances, forced pooling or unitization may be implemented by third parties and may reduce our interest in the unitized properties. In addition, state conservation laws establish maximum rates of production from oil and natural gas wells, generally prohibit the venting or flaring of natural gas, and impose requirements regarding the ratability of production. These laws and regulations may limit the amount of oil and natural gas we can produce from our wells or limit the number of wells or the locations at which we can drill. Moreover, each state generally imposes a production or severance tax with respect to the production and sale of oil, natural gas, and natural gas liquids within its jurisdiction.

Natural Gas Sales Transportation

Historically, federal legislation and regulatory controls have affected the price of the natural gas we produce and the manner in which we market our production. FERC has jurisdiction over the transportation and sale for resale of natural gas in interstate commerce by natural gas companies under the Natural Gas Act of 1938 and the Natural Gas Policy Act of 1978. Since 1978, various federal laws have been enacted which have resulted in the complete removal of all price and non-price controls for sales of domestic natural gas sold in “first sales,” which include all of our sales of our own production.

FERC also regulates interstate natural gas transportation rates and service conditions, which affects the marketing of natural gas that we produce, as well as the revenues we receive for sales of our natural gas. Commencing in 1985, FERC promulgated a series of orders, regulations and rule makings that significantly fostered competition in the business of transporting and marketing gas. Today, interstate pipeline companies are required to provide nondiscriminatory transportation services to producers, marketers and other shippers, regardless of whether such shippers are affiliated with an interstate pipeline company. FERC’s initiatives have led to the development of a competitive, unregulated, open access market for gas purchases and sales that permits all purchasers of gas to buy gas directly from third-party sellers other than pipelines. However, the natural gas industry historically has been very heavily regulated; therefore, we cannot guarantee that the less stringent regulatory approach recently pursued by FERC and Congress will continue indefinitely into the future nor can we determine what effect, if any, future regulatory changes might have on our natural gas related activities.

Under FERC’s current regulatory regime, transmission services must be provided on an open-access, non-discriminatory basis at cost-based rates or at market-based rates if the transportation market at issue is sufficiently competitive. Gathering service, which occurs upstream of jurisdictional transmission services, is regulated by the states onshore and instate waters. Although its policy is still in flux, FERC recently has reclassified certain jurisdictional transmission facilities as non-jurisdictional gathering facilities, which has the tendency to increase our costs of getting natural gas to point-of-sale locations.

Natural Gas Pipeline Safety

The Department of Transportation, specifically the Pipeline and Hazardous Materials Safety Administration, regulates transportation of natural and other gas by pipeline and imposes minimum federal safety standards pursuant to the pipeline safety laws codified at 49 U.S.C. 60101, et seq. and the hazardous material transportation laws codified at 49 U.S.C. 5101, et seq.

Natural Gas Gathering Regulations

State regulation of natural gas gathering facilities generally includes various safety, environmental and, in some circumstances, nondiscriminatory-take requirements. Although such regulation has not generally been affirmatively applied by state agencies, natural gas gathering is addressed in EPA’s proposed greenhouse gas monitoring and reporting rule and may receive greater regulatory scrutiny in the future.

State Regulation

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

The petroleum industry is also subject to compliance with various other federal, state and local regulations and laws. Some of those laws relate to occupational safety, resource conservation, and equal employment opportunity. We do not believe that compliance with these laws will have a material adverse effect on us.

Seasonality

While our limited operations located in the Gulf Coast and the Rocky Mountains may experience seasonal fluctuations, we do not believe these fluctuations have had, or will have, a material impact on our consolidated results of operations.

Legal proceedings

In the opinion of management, there are no material pending legal proceedings to which we or any of our subsidiaries are a party or of which any of our property is the subject. However, due to the nature of our business, certain legal or administrative proceedings may arise from time to time in the ordinary course of business.

Title to properties

We believe that we have satisfactory title to all of our owned assets. As is customary in the oil and natural gas industry, we initially conduct only a cursory review of the title to undeveloped leasehold acreage rights acquired through oil and natural gas leases or farm-in agreements. Prior to the commencement of drilling operations on undeveloped leasehold, we conduct a title examination and perform curative work with respect to any significant title defects. Prior to completing an acquisition of an interest in significant producing oil and natural gas properties, we conduct due diligence as to title for the specific interest we are acquiring. Our interests in oil and natural gas properties are subject to customary royalty interests, liens for current taxes and other similar burdens and minor easements, restrictions and encumbrances which we believe do not materially detract from the value of these interests either individually or in the aggregate and will not materially interfere with the operation of our business. We will take such steps as we deem necessary to assure that our title to our properties is satisfactory. We are free, however, to exercise our judgment as to reasonable business risks in waiving title requirements.

Employees

As of December 31, 2010, we had 765 full-time employees, including 16 geologists and geophysicists, 36 reservoir, production, and drilling engineers and 15 land professionals. Of these, 328 work in our Oklahoma City office and 437 work in our district and field offices. We also contract for the services of independent consultants involved in land, regulatory, accounting, financial and other disciplines as needed. None of our employees are represented by labor unions or covered by any collective bargaining agreement. We believe that our relations with our employees are satisfactory.

ITEM 1A. RISK FACTORS

The following are some of the important factors that could affect our financial performance or could cause actual results to differ materially from estimates contained in our forward-looking statements. We may encounter risks in addition to those described below. Additional risks and uncertainties not currently known to us, or that we currently deem to be immaterial, may also impair or adversely affect our business, financial condition or results of operation.

Oil and natural gas prices are volatile. A decline in oil and natural gas prices could adversely affect our financial condition, financial results, cash flows, access to capital and ability to grow.

Our future financial condition, revenues, results of operations, rate of growth and the carrying value of our oil and natural gas properties depend primarily upon the prices we receive for our oil and natural gas production. Oil and natural gas prices historically have been volatile and are likely to continue to be volatile in the future, especially given current geopolitical conditions. This price volatility also affects the cash flow we will have available for capital expenditures as well as our ability to borrow money or raise additional capital. The prices for oil and natural gas are subject to a variety of factors that are beyond our control. These factors include, but are not limited to, the following:

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the level of consumer demand for oil and natural gas;

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the domestic and foreign supply of oil and natural gas;

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commodity processing, gathering and transportation availability, and the availability of refining capacity;

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

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

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domestic and foreign governmental regulations and taxes;

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the supply of CO₂;

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the price and availability of alternative fuel sources;

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weather conditions;

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financial and commercial market uncertainty;

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political conditions or hostilities in oil and natural gas producing regions, including the Middle East and South America; and

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worldwide economic conditions.

These factors and the volatility of the energy markets generally make it extremely difficult to predict future oil and natural gas price movements with any certainty. Declines in oil and natural gas prices would not only reduce our revenue, but could reduce the amount of oil and natural gas we can produce economically, and as a result, could have a material adverse effect on our financial condition, results of operations, and reserves. If the oil and natural gas industry experiences significant price declines, we may, among other things, be unable to meet our financial obligations, including payments on our senior secured revolving credit facility and our Senior Notes, or be unable to make planned capital expenditures.

Price declines at the end of 2008 and early 2009 resulted in write downs of the carrying values of our properties, and further price declines could result in additional write downs in the future, which could negatively impact our results of operations.

We utilize the full cost method of accounting for costs related to our oil and natural gas properties. Under this method, all costs incurred for both productive and nonproductive properties are capitalized and amortized on an aggregate basis using the units-of-production method. However, these capitalized costs are subject to a ceiling test which limits such pooled costs to the aggregate of the present value of estimated future net revenues attributable to proved oil and natural gas reserves discounted at 10%, adjusted for derivatives accounted for as cash flow hedges and net of tax considerations, plus the lower of cost or market value of unproved properties. The full cost ceiling is evaluated at the end of each quarter using the SEC prices for oil and natural gas in effect at that date as adjusted for our derivative positions deemed “cash flow hedge positions.” A write-down of oil and natural gas properties does not impact cash flow from operating activities, but does reduce net income. Once incurred, a write-down of oil and natural gas properties is not reversible at a later date.

During the fourth quarter of 2008, our evaluation of our full cost ceiling required a non-cash impairment charge of $281.4 million to the value of our oil and natural gas properties as a result of a decline in oil and natural gas prices at the measurement date. The impairment was calculated based on December 31, 2008 prices of $44.60 per Bbl of oil and $5.62 per Mcf of natural gas. During the first quarter of 2009, natural gas prices declined significantly (as compared to the December 31, 2008 spot price of $5.62 per Mcf), and based on March 31, 2009 spot prices of $49.66 per Bbl of oil and $3.63 per Mcf of natural gas, our reserves declined by 13.5%, as a result of which we recorded a non-cash ceiling test impairment of $240.8 million during the first quarter of 2009. Oil and natural gas prices have remained volatile and this and other factors, without mitigating circumstances, could require us to further write down capitalized costs and incur corresponding non-cash charges to earnings. Any such further write downs could have a material adverse effect on our financial condition, results of operations, and our ability to comply with debt covenants.

The actual quantities and present value of our proved reserves may be lower than we have estimated.

Estimating quantities of proved oil and natural gas reserves is a complex process. It requires interpretations of available technical data and various estimates and assumptions, including estimates based upon assumptions relating to economic factors such as commodity prices, production costs, severance and excise taxes, capital expenditures, workovers, remedial costs, and the assumed effect of governmental regulation. There are numerous uncertainties about when a property may have proved reserves as compared to possible or probable reserves, including with respect to our EOR operations. Reserve estimates are, therefore, inherently imprecise and, although we are reasonably certain of recovering the quantities we disclose as proved reserves, actual results will vary from our estimates. Any significant variations in the interpretations or assumptions underlying our estimates or changes of conditions (e.g. economic growth and/or regulation) could cause the estimated quantities and net present value of our reserves to differ materially. In addition, we may adjust estimates of proved reserves to reflect production history, results of exploration and developmental drilling, prevailing oil and natural gas prices and other factors, many of which are beyond our control. Our properties may also be susceptible to hydrocarbon drainage from production by operators on adjacent properties.

You should not assume that the present values referred to in this report represent the current market value of our estimated oil and natural gas reserves. The timing of production and expenses associated with the development and production of oil and natural gas properties will affect both the timing of actual future net cash flows from our proved reserves and their present value. In accordance with requirements of the SEC, the estimates of present values are based on average prices and costs in effect as of the date of the estimates and exclude escalations based upon future conditions. Actual future prices and costs may be materially higher or lower than the prices and costs as of the date of these estimates. In addition, the effects of derivative instruments are not reflected in these assumed prices. Our December 31, 2010 reserve report used realized prices based on an average price of $4.38 per Mcf for natural gas and an average price of $79.43 per Bbl for oil.

A significant portion of total proved reserves as of December 31, 2010 are undeveloped, and those reserves may not ultimately be developed.

As of December 31, 2010, approximately 34% of our estimated proved reserves were undeveloped. Recovery of undeveloped reserves requires significant capital expenditures and successful drilling and EOR operations. The reserve data assumes that we can and will make these expenditures and conduct these operations successfully. While we are reasonably certain of our ability to make these expenditures and to conduct these operations under existing economic conditions, these assumptions may not prove correct and we may ultimately determine the development of all, or any portion of, such proved but undeveloped reserves is not economically feasible.

Some of our reserves are subject to EOR methods and the failure of these methods may have a material adverse affect on our financial condition, results of operations and reserves.

As of December 31, 2010, approximately 20% of our proved reserves were based on EOR methods including the injection of CO₂ and polymers, a synthetic chemical. Some of these properties have not been injected with CO₂ or with polymers having the identical chemical composition as polymers used in historical production, and recovery factors cannot be estimated with precision. Accordingly, such projects may not result in significant proved reserves or improvements in anticipated production levels.

We do not currently have a supply of CO₂ for all of our unproved properties with CO₂ EOR potential, and we cannot assure you that we will be able to obtain such a supply on commercially reasonable terms. In addition, many of our planned EOR projects will require significant investments in pipeline, compression facilities, and other infrastructure, and we may need to raise additional capital to fund these projects. We cannot assure you that such funding will be available on commercially reasonable terms. The availability of CO₂ supply and financing of CO₂ projects could affect the timing of our planned EOR programs and impact our ability to implement such plans.

Our ability to develop our EOR reserves will depend on whether we can successfully implement our planned EOR programs, and our failure to do so could have a material adverse effect on our financial condition, results of operations and reserves.

The development of the proved undeveloped reserves in our North Burbank Unit, Camrick Area Units, and Farnsworth Unit may take longer and may require higher levels of capital expenditures than we currently anticipate.

As of December 31, 2010, undeveloped reserves comprised 49%, 53%, and 82%, respectively, of the total estimated proved reserves of our North Burbank Unit, Camrick Area Units, and Farnsworth Unit, respectively. As of December 31, 2010, we expect to incur future development costs of $219.0 million over the next six years at our North Burbank Unit, $89.8 million over the next 19 years at our Camrick Area Units, and $118.4 million over the next 12 years at our Farnsworth Unit to fully develop these reserves. Together, these fields encompass 48% of our total estimated future development costs of $882.7 million related to proved undeveloped reserves as of December 31, 2010. Development of these reserves may take longer and require higher levels of capital expenditures than we currently anticipate. In addition, the development of these reserves will require the use of EOR techniques, including water flood and CO₂ injection installations, the success of which is still subject to interpretation and predictability by reservoir engineers. Therefore, ultimate recoveries from these fields may not match current expectations.

The polymer reserves at our North Burbank Unit accounted for 14.2 MMBoe, or approximately 10% of our estimated proved reserves as of December 31, 2010. We and our independent petroleum engineers believe that the polymer EOR flood development plan continues to be sufficient to permit us to include the North Burbank Unit reserves in our proved reserves and, as such, those reserves are included in our total proved reserves as of December 31, 2010. We are continuing to develop our polymer plan while simultaneously instituting a pilot project for enhanced oil recovery from CO₂ injection to determine the best long-term EOR technique. The SEC could determine that our recent increase in focus on our CO₂ operations results in a change in our polymer development plan and could require us to reduce or eliminate all or a portion of the proved reserves attributable to the polymer EOR flood.

Competition in the oil and natural gas industry is intense and many of our competitors have greater financial and other resources than we do.

We operate in the highly competitive areas of oil and natural gas production, acquisition, development, and exploration and face intense competition from both major and other independent oil and natural gas companies:

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seeking to acquire desirable producing properties or new leases for future development or exploration; and

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seeking to acquire the equipment and expertise necessary to operate and develop our properties.

Many of our competitors have financial and other resources substantially greater than ours, and some of them are fully integrated oil companies. These companies may be able to pay more for development prospects and productive oil and natural gas properties and may be able to define, evaluate, bid for and purchase a greater number of properties and prospects than our financial or human resources permit. Our ability to develop our oil and natural gas properties and to acquire additional properties in the future will depend upon our ability to successfully conduct operations, select suitable prospects and consummate transactions in this highly competitive environment.

Significant capital expenditures are required to replace our reserves.

Our development, exploration, and acquisition activities require substantial capital expenditures. Historically, we have funded our capital expenditures through a combination of cash flows from operations, debt financing, and private issuances of common stock. Future cash flows are subject to a number of variables, such as the level of production from existing wells, prices of oil and natural gas, and our success in developing and producing new reserves. If our cash flow from operations is not sufficient to fund our capital expenditure budget, we may not be able to access additional bank debt or other methods of financing on commercially reasonable terms to meet these requirements. If revenue were to decrease as a result of lower oil and natural gas prices or decreased production, and our access to capital were limited, we would have a reduced ability to replace our reserves which may have an adverse effect on our results of operations and financial condition.

If we are not able to replace reserves, we may not be able to sustain production.

Our future success depends largely upon our ability to find, develop, or acquire additional oil and natural gas reserves that are economically recoverable. Unless we replace the reserves we produce through successful development, exploration or acquisition activities, our proved reserves and production will decline over time. In addition, approximately 34% of our total estimated proved reserves (by volume) at December 31, 2010 were undeveloped. By their nature, estimates of undeveloped reserves are less certain. Recovery of such reserves will require significant capital expenditures and successful drilling and EOR operations. Our December 31, 2010 reserve estimates reflect that our production rate on current proved developed producing reserve properties will decline at annual rates of approximately 16%, 12%, and 10% for the next three years. Thus, our future oil and natural gas reserves and production and, therefore, our financial condition, results of operations, and cash flows are highly dependent on our success in efficiently developing our current reserves and economically discovering or acquiring additional recoverable reserves.

Development and exploration drilling may not result in commercially productive reserves.

Drilling activities are subject to many risks, including the risk that commercially productive reservoirs will not be encountered. We cannot assure you that new wells we drill will be productive or that we will recover all or any portion of our investment in such wells. The seismic data and other technologies we use do not allow us to know conclusively prior to drilling a well that oil or natural gas is present or may be economically recovered and/or produced. Drilling for oil and natural gas often involves unprofitable efforts, not only from dry wells but also from wells that are productive but do not produce sufficient net reserves to return a profit at then-realized prices after deducting drilling, operating and other costs. The cost of drilling, completing and operating a well is often uncertain, and cost factors can adversely affect the economics of a project. Further, our drilling operations may be curtailed, delayed or cancelled as a result of numerous factors, including:

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unexpected drilling conditions;

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title problems;

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pressure or lost circulation in formations;

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equipment failures or accidents;

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adverse weather conditions;

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compliance with environmental and other governmental requirements; and

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increases in the cost of, or shortages or delays in the availability of, drilling rigs, equipment and services.

If, for any reason, we are unable to economically recover reserves through our exploration and drilling activities, our results of operations, cash flows, growth, and reserve replenishment may be materially affected.

We are subject to complex laws and regulations, including environmental and safety regulations, which can adversely affect the cost, manner, and feasibility of doing business.

Our operations and facilities are subject to certain federal, state, and local laws and regulations relating to the exploration for, and development, production, and transportation of, oil and natural gas, as well as environmental and safety matters. Although we believe that we are in substantial compliance with all applicable laws and regulations, and are currently evaluating the extent of applicability and preparing to comply to the extent applicable with proposed and newly adopted greenhouse gas reporting and permitting requirements, we cannot be certain that existing laws or regulations, as currently interpreted or reinterpreted in the future, or future laws or regulations will not harm our business, results of operations and financial condition. We may be required to make large and unanticipated capital expenditures to comply with environmental and other governmental regulations such as:

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land use restrictions;

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drilling bonds and other financial responsibility requirements;

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spacing of wells;

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additional reporting or other limitations on emissions of greenhouse gases;

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unitization and pooling of properties;

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habitat and endangered species protection, reclamation and remediation, and other environmental protection;

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well stimulation processes;

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produced water disposal;

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CO₂ pipeline requirements;

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safety precautions;

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operational reporting; and

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taxation.

Under these laws and regulations, we could be liable for:

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personal injuries;

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property and natural resource damages;

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oil spills and releases or discharges of hazardous materials;

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well reclamation costs;

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remediation and clean-up costs and other governmental sanctions, such as fines and penalties;

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other environmental damages; and

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additional reporting permitting or other issues arising from greenhouse gas emissions.

Our operations could be significantly delayed or curtailed and our costs of operations could significantly increase as a result of regulatory requirements or restrictions. Additionally, regulations promulgated pursuant to the Clean Air Act or other mandatory federal legislation requiring monitoring and reporting of greenhouse gas emissions continue to evolve and may impose new restrictions on these emissions resulting in liability for exceeding permitted air pollutant emission rates or other mandatory caps on greenhouse gas emissions. While we are preparing for compliance with newly adopted requirements, at this time we are unable to predict the ultimate cost of compliance with these requirements as they continue to evolve or their effect on our operations.

Properties that we acquire may not produce as projected and we may be unable to accurately predict reserve potential, identify liabilities associated with the properties, or obtain protection from sellers against such liabilities.

Acquisitions of producing and undeveloped properties have been an important part of our historical growth. We expect acquisitions will also contribute to our future growth. Successful acquisitions require an assessment of a number of factors, including recoverable reserves, exploration or development potential, future oil and natural gas prices, operating costs, and potential environmental and other liabilities. We perform an engineering, geological and geophysical review of the acquired properties, which we believe is generally consistent with industry practices, and also endeavor to evaluate environmental risks. However, such assessments are inexact and their accuracy is inherently uncertain for a number of reasons. For instance, in connection with our assessments, such a review may not permit us to become sufficiently familiar with the properties to fully assess their deficiencies and capabilities. We do not physically inspect every well. Even when we inspect a well, we do not always discover structural, subsurface and environmental problems that may exist or arise. Our review prior to signing a definitive purchase agreement may be even more limited. Often we are not entitled to contractual indemnification for pre-closing liabilities, including environmental liabilities associated with acquired properties. Normally, we acquire interests in properties on an “as is” basis with limited remedies for breaches of representations and warranties. Additionally, properties previously acquired have not been subject to greenhouse gas requirements which have just recently been adopted. As a result, significant unknown liabilities, including environmental liabilities, may exist and we may experience losses due to title defects in acquisitions for which we have limited or no contractual remedies or insurance coverage. In addition, we may acquire oil and natural gas properties that contain economically recoverable reserves which are less than predicted. Thus, liabilities and uneconomically feasible oil and natural gas recoveries related to our acquisitions of producing and undeveloped properties may have a material adverse effect on our results of operations and reserve growth.

We cannot control the activities on properties we do not operate and we are unable to ensure the proper operation and profitability of these non-operated properties.

We do not operate all of the properties in which we have an interest. As a result, we have limited ability to exercise influence over, and control the risks associated with, the operation of these properties. The success and timing of drilling and development activities on our partially owned properties operated by others therefore will depend upon a number of factors outside of our control, including the operator’s:

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timing and amount of capital expenditures;

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expertise and diligence in adequately performing operations and complying with applicable agreements;

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financial resources;

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inclusion of other participants in drilling wells; and

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use of technology.

As a result of any of the above or an operator’s failure to act in ways that are in our best interest, our allocated production revenues and results of operations could be adversely affected.

If the third parties we rely on for gathering and distributing our oil and natural gas are unable to meet our needs for such services and facilities, our future exploration and production activities could be adversely affected.

The marketability of our production depends upon the proximity of our reserves to, and the capacity of, third-party facilities and third-party services, including oil and natural gas gathering systems, pipelines, trucking or terminal facilities, and refineries or processing facilities. Such third parties are subject to federal and state regulation of the production and transportation of oil and natural gas. If such third parties are unable to comply with such regulations and we are unable to replace such service and facilities providers, we may be required to shut-in producing wells or delay or discontinue development plans for our properties. A shut-in, delay or discontinuance could adversely affect our financial condition.

The loss of our Chief Executive Officer or other key personnel could adversely affect our business.

We depend, and will continue to depend in the foreseeable future, on the services of Mark A. Fischer, our Chief Executive Officer, and other officers and key employees with extensive experience and expertise in evaluating and analyzing producing oil and natural gas properties and drilling prospects, maximizing production from oil and natural gas properties, marketing oil and natural gas production, and developing and executing financing and hedging strategies. Our ability to retain our officers and key employees, or hire replacements if we should lose one or more, is important to our continued success and growth. The unexpected loss of the services of one or more of these individuals could have a detrimental effect on our business.

Oil and natural gas drilling and production operations can be hazardous and may expose us to environmental or other liabilities.

Oil and natural gas operations are subject to many risks, including well blowouts, cratering, explosions, pipe failure, fires, formations with abnormal pressures, uncontrollable flows of oil, natural gas, brine or well fluids, and other environmental hazards and risks. Our drilling operations involve risks from high pressures and from mechanical difficulties such as stuck pipes, collapsed casings and separated cables. If any of these events occur, we could sustain substantial losses as a result of:

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injury or loss of life;

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severe damage to or destruction of property, natural resources and equipment;

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pollution or other environmental damage;

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clean-up responsibilities;

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regulatory investigations and administrative, civil and criminal penalties; and

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injunctions or other proceedings that suspend, limit or prohibit operations.

Our liability for environmental hazards includes those created on properties prior to the date we acquired or leased them. While we maintain insurance against some, but not all, of the risks described above, our insurance may not be adequate to cover any or all resulting losses or liabilities. Moreover, in the future, we may not be able to obtain any such insurance on commercially reasonable terms. The occurrence of, or failure by us to obtain or maintain adequate insurance coverage for, any of the events listed above could have a material adverse effect on our financial condition and results of operations, as well as our growth, exploration, and employee recruitment activities.

Costs of environmental liabilities could exceed our estimates and adversely affect our operating results.

Our operations are subject to numerous environmental laws and regulations, which obligate us to install and maintain pollution controls and to clean up various sites at which regulated materials may have been disposed of or released. It is not possible for us to estimate reliably the amount and timing of all future expenditures related to environmental matters because of:

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the uncertainties in estimating clean up costs;

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the discovery of additional contamination or contamination more widespread than previously thought;

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the uncertainty in quantifying liability under environmental laws that impose joint and several liability on all potentially responsible parties;

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changes in interpretation and enforcement of existing environmental laws and regulations; and

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future changes to environmental laws and regulations and their enforcement.

Although we believe we have established appropriate reserves for known liabilities, including clean up costs, we could be required to set aside additional reserves in the future due to these uncertainties, incur material clean up costs, other liabilities, and/or expend significant sums to defend ourselves against litigation related to legacy environmental issues, which could have an adverse effect on our operating results.

We may not be able to generate sufficient cash to service all of our long-term indebtedness, and we may be forced to take other actions to satisfy our obligations under our senior secured revolving credit facility, which may not be successful.

Our ability to make scheduled payments on or to refinance our debt obligations depends on our financial and operating performance, which is subject to prevailing economic and competitive conditions and to certain financial, business and other factors beyond our control. We may not be able to maintain a level of cash flow from operating activities sufficient to permit us to pay the principal, premium, if any, and interest on our long-term indebtedness.

If our cash flows and capital resources are insufficient to fund our debt service obligations, we may be forced to reduce or delay capital expenditures, sell assets, seek additional capital or seek to restructure or refinance our indebtedness. These alternative measures may not be successful and may not permit us to meet our scheduled debt service obligations. In the absence of such operating results and resources, we could face substantial liquidity problems and might be required to dispose of material assets or operations to attempt to meet our debt service and other obligations. The indentures governing our Senior Notes and our senior secured revolving credit facility restrict our ability to use the proceeds from asset sales. We may not be able to consummate those asset sales to raise capital or to sell assets at prices that we believe are fair, and proceeds that we do receive may not be adequate to meet any debt service obligations then due.

If we cannot make scheduled payments on our long-term indebtedness, we will be in default and, as a result:

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debt holders could declare all outstanding principal and interest to be due and payable;

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we may be in default under our master (ISDA) derivative contracts and counterparties could demand early termination;

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the lenders under the senior secured revolving credit facility could terminate their commitments to loan us money and foreclose against the assets securing their borrowings; and

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we could be forced into bankruptcy or liquidation.

Our level of indebtedness may adversely affect our operations and limit our growth.

As of December 31, 2010, our total long-term indebtedness, including current maturities, was $962.1 million. As of March 29, 2011, our total long-term indebtedness, including current maturities, was approximately $1.0 billion, and the borrowing base under our senior secured revolving credit facility was $375.0 million. We may incur additional indebtedness, including significant secured indebtedness, in order to make future acquisitions or to develop our properties for production or for other purposes, and we expect to continue to be highly leveraged in the foreseeable future. Covenants set forth in the indentures for our Senior Notes, including the Adjusted Consolidated Net Tangible Asset debt incurrence test (the “ACNTA test”), limit the amount of secured debt we can incur. Certain thresholds set forth in the ACNTA test are principally reliant upon the levels of commodity prices for crude oil and natural gas at specified dates.

Our high level of indebtedness affects our operations in several ways, including the following:

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the restrictions imposed on the operation of our business by the terms of our debt agreements may hinder our ability to take advantage of strategic opportunities to grow our business;

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we must use a substantial portion of our cash flow from operations to pay interest on our Senior Notes and our other indebtedness, which reduces the funds available to us for operations and other purposes;

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we may be at a competitive disadvantage compared to our competitors that may have proportionately less debt;

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our ability to obtain additional financing for working capital, capital expenditures, debt service requirements, restructuring, acquisitions, or general corporate purposes may be impaired, which could be exacerbated by further volatility in the credit markets;

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our flexibility in planning for, or reacting to, changes in our business and the industry in which we operate may be limited;

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we may be more vulnerable to economic downturns and adverse developments in our business; and

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we may be vulnerable to interest rate increases, as our borrowings under our senior secured revolving credit facility are at variable rates.

Any of the foregoing could have a material adverse effect on our business, financial condition, results of operations, prospects, and ability to satisfy our debt obligations.

We may not have sufficient funds to repay bank borrowings if required as a result of a borrowing base redetermination.

Availability under our senior secured revolving credit facility is subject to a borrowing base, which was $375.0 million as of March 29, 2011, and which is set by the banks semi-annually on May 1 and November 1 of each year. In addition, the banks may request a borrowing base redetermination once between each scheduled redetermination and in the event of early termination of our derivative contracts. If we issue Additional Permitted Debt, as defined in our senior secured revolving credit facility, the borrowing base will be automatically reduced by an amount equal to 25% of the aggregate stated principal amount of the debt issued. If the outstanding borrowings under our senior secured revolving credit facility were to exceed the borrowing base as a result of a redetermination, we would be required to eliminate this excess. Within 10 days after receiving notice of the new borrowing base, we would be required to make an election: (1) to repay a portion of our bank borrowings in the amount of the excess either in a lump sum within 30 days or in equal monthly installments over a six-month period, (2) to submit within 30 days additional oil and natural gas properties we own for consideration in connection with the determination of the borrowing base sufficient to eliminate the excess or (3) to eliminate the excess through a combination of repayments and the submission of additional oil and natural gas properties within 30 days. If we are forced to repay a portion of our bank borrowings, we may not have sufficient funds to make such repayments. If we do not have sufficient funds and are otherwise unable to negotiate renewals of our borrowings or arrange new financing, we may have to sell significant assets. Any such sale could have a material adverse effect on our business and financial results.

Our use of derivative instruments could result in financial losses or reduce our income.

To reduce our exposure to the volatility in the price of oil and natural gas and provide stability to cash flows, we enter into derivative positions, some of which we had previously designated as cash flow hedges for accounting purposes. These derivative products include fixed-price swaps, collars, and basis swaps with financial institutions or other similar transactions. As of December 31, 2010, we had entered into swaps for 20,340 BBtu of our natural gas production for 2011 through 2012 at average monthly prices ranging from $4.99 to $6.92 per MMBtu of natural gas. As of December 31, 2010, we had entered into swaps for 4,068 MBbls of our crude oil production for 2011 through 2012 at average monthly prices ranging from $73.71 to $91.37 per Bbl of oil. We also entered into collars for 84 MBbls of our crude oil production for 2011 at a floor of $110.00 per Bbl of oil. As of December 31, 2010, we had basis protection swaps for 23,790 BBtu of our natural gas production for 2011 through 2012 at average monthly prices ranging from $0.30 to $0.73 per MMBtu. The fair value of our oil and natural gas derivative positions outstanding as of December 31, 2010 was a liability of approximately $29.9 million.

Derivative instruments expose us to risk of financial loss in some circumstances, including when:

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our production is less than expected;

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the counterparty to the derivative instruments defaults on its contractual obligations; or

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there is a widening of price differentials between delivery points for our production and the delivery point assumed in the derivative instruments.

Derivatives also expose us to risk of income reduction as derivative instruments may limit the benefit we would receive from increases in the prices for oil and natural gas. Additionally, derivatives that are not hedges must be adjusted to fair value through income. If the derivative qualifies and is designated as a cash flow hedge, the effective portion of changes in the fair value of the derivative is recognized in other comprehensive income (loss) until the hedged item is recognized in income. The ineffective portion of a derivative’s change in fair value, as measured using the dollar offset method, is immediately recognized in gain (loss) from oil and natural gas hedging activities in the statement of operations.

If it is probable the oil or natural gas sales which are hedged will not occur, hedge accounting must be discontinued and the gain or loss reported in accumulated other comprehensive income (loss) is immediately reclassified into income. If a derivative which qualified for cash flow hedge accounting ceases to be highly effective, or is liquidated or sold prior to maturity, hedge accounting must be discontinued. The gain or loss associated with the discontinued hedges remains in accumulated other comprehensive income (loss) and is reclassified into income as the hedged transactions occur.

While the primary purpose of our derivative transactions is to protect ourselves against the volatility in oil and natural gas prices, under certain circumstances, or if hedges are deemed ineffective, discontinued, or terminated for any reason, we may incur substantial losses in closing out our positions, which could have a material adverse effect on our financial condition, results of operations, and cash flows.

Our working capital could be adversely affected if we enter into derivative instruments that require cash collateral.

The use of derivatives may, in some cases, require the posting of cash collateral with counterparties (i.e. margin requirements). Although we currently do not, and do not anticipate that we will in the future, enter into derivative transactions that require an initial deposit of cash collateral, our working capital, and by extension, our growth, could be impacted if we enter into derivative transactions that require cash collateral and if commodity prices move in a manner adverse to us, we may be required to meet margin calls. Future collateral requirements are uncertain and will depend on arrangements with our counterparties and highly volatile oil and natural gas prices.

We are subject to financing and interest rate exposure risks.

Our future success depends on our ability to access capital markets and obtain financing on reasonable terms. Our ability to access financial markets and obtain financing on commercially reasonable terms in the future is dependent on a number of factors, many of which we cannot control, including changes in:

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our credit ratings;

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interest rates;

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the structured and commercial financial markets;

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market perceptions of us or the oil and natural gas exploration and production industry; and

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tax burden due to new tax laws.

Assuming a constant debt level of $375.0 million, equal to our borrowing base at December 31, 2010, the cash flow impact for a 12-month period resulting from a 100 basis point movement in interest rates, regardless of whether the spread widens or tightens, would be $3.75 million. As a result, any increases in our interest rates, or our inability to access the equity markets on reasonable terms, could have an adverse impact on our financial condition, results of operations, and growth prospects.

The concentration of accounts for our oil and natural gas sales, joint interest billings, or hedging with third parties could expose us to credit risk.

Substantially all of our accounts receivable result from oil and natural gas sales or joint interest billings to third parties in the energy industry. The concentration of customers and joint interest owners may impact our overall credit risk in that these entities may be similarly affected by changes in economic and other conditions. Historically, we have not experienced any material credit losses on our receivables. Future concentrations of sales of oil and natural gas to a limited number of customers, combined with decreases in commodity prices could result in adverse effects.

In addition, our oil and natural gas swaps or other hedging contracts expose us to credit risk in the event of non-performance by counterparties. Generally, these contracts are with major investment grade financial institutions and historically we have not experienced any credit losses. We believe that the guarantee of a fixed price for the volume of oil and natural gas hedged reduces volatility in our reported results of operations, financial position and cash flows from period to period and lowers our overall business risk. However, as also discussed along with other risks specific to hedging activities, we may be exposed to greater credit risk in the future.

Regulation related to global warming and climate change could have an adverse effect on our operations and demand for oil and natural gas.

The U.S. Congress has previously considered legislation to reduce emissions of greenhouse gases, including carbon dioxide, methane, and nitrous oxide among others, which some studies have suggested may be contributing to warming of the earth’s atmosphere. However, legislation to reduce greenhouse gases appears less likely in the near term. As a result, regulation of greenhouse gases, if any, will more likely result from regulatory action by EPA or by the several states that have already taken legal measures to reduce emissions of greenhouse gases.

Federal regulation. The Environmental Protection Agency (EPA) has adopted regulations requiring Clean Air Act (CAA) permitting of greenhouse gas emissions from stationary sources. As a result of the U.S. Supreme Court’s decision in Massachusetts, et al. v. EPA finding that greenhouse gases fall within the CAA’s definition of “air pollutant,” the EPA was required to determine whether concentrations of greenhouse gases in the atmosphere “endanger” public health or welfare, and whether emissions of greenhouse gases from motor vehicles may “cause or contribute” to this endangerment. On December 15, 2009, EPA promulgated its final rule, “Endangerment and Cause or Contribute Findings for Greenhouse Gases Under Section 202(a) of the Clean Air Act,” finding that (i) the current and projected emissions of six key well-mixed greenhouse gases, including carbon dioxide and methane, constitute a threat to public health and welfare, and (ii) the combined emissions from motor vehicles cause and contribute to the climate change problem which threatens public health and welfare. These findings did not themselves impose any requirements on industry or other entities, but were a prerequisite to EPA’s adoption of greenhouse gas emission standards for motor vehicles. On May 7, 2010, EPA and the Department of Transportation’s National Highway Traffic and Safety Administration, or NHTSA, promulgated a final action establishing a national program providing new standards for certain motor vehicles to reduce greenhouse gas emissions and improve fuel economy, with EPA adopting the standards under the CAA, and NHTSA adopting the standards as Corporate Average Fuel Economy standards under the Energy Policy and Conservation Act. While these motor vehicle regulations do not directly impact oil and natural gas production operations, the result of these actions are significant in that they automatically trigger application of certain CAA permit programs for stationary greenhouse gas emissions sources, potentially including oil and natural gas production operations. These programs, the Prevention of Significant Deterioration (“PSD”) and Title V Operating Permit programs, have historically applied to sources of air pollutants “subject to regulation” with emissions exceeding 100 and 250 tons per year. To avoid the broad impact of such low permitting thresholds for greenhouse gas emission sources, on June 3, 2010, EPA promulgated its “Prevention of Significant Deterioration and Title V Greenhouse Gas Tailoring Rule,” to add new higher thresholds of 75,000 tons per year carbon dioxide equivalents (“CO₂e”) for modifications and 100,000 tons per year CO₂e for new sources.

Additionally, EPA has promulgated separate regulations requiring greenhouse gas emission reporting from certain industry sectors, including natural gas production. On October 30, 2009, EPA promulgated a final mandatory greenhouse gas reporting rule which will assist EPA in developing policy approaches to greenhouse gas regulation. This reporting rule became effective on December 29, 2009. On November 30, 2010, EPA promulgated additional mandatory greenhouse gas reporting rules that apply specifically to oil and natural gas production for implementation in 2011.

Though under review by the D.C. Circuit, EPA’s rules promulgated thus far have survived petitions for stay, and thus are currently final and effective, and will remain so unless vacated or remanded by the court, or unless Congress adopts legislation preempting EPA’s regulatory authority to address greenhouse gases under the CAA.

Recent caselaw. Beyond legislative and regulatory developments, there have been several court cases impacting this area of risk for significant greenhouse gas emissions sources. In September 2009, the United States Court of Appeals for the Second Circuit issued its decision in Connecticut v. American Electric Power Co. With this case, the Second Circuit reversed a lower court’s dismissal of plaintiff claims that public utility greenhouse gas emissions created a “public nuisance.” In reversing, the Second Circuit rejected the lower court’s reliance on several defenses, including political question, preemption and lack of standing to dismiss. The U.S. Supreme Court is set to review this case in the spring of 2011 to determine whether EPA’s regulation of greenhouse gas under the CAA supplants federal common law public nuisance claims. The Supreme Courts review of this Second Circuit decision is expected to affect another case involving this issue, Native Village of Kivalina v. ExxonMobil Corp. In Native Village of Kivalina v. ExxonMobil Corp. (order granting defendants’ motion to dismiss for lack of subject matter jurisdiction), was appealed to the Ninth Circuit in November, 2009. The decisions in these cases may expose us, as potentially an emitter of significant direct and indirect emission sources of greenhouse gases, to similar litigation risk.

A third case, North Carolina v. Tennessee Valley Authority, also pending review by the Supreme Court, involves state common law claims which may not be affected by the Supreme Court’s decision in Connecticut v. American Electric Power Co.

International treaties. Other nations have already agreed to regulate emissions of greenhouse gases pursuant to the United Nations Framework Convention on Climate Change, also known as the “Kyoto Protocol,” an international treaty pursuant to which participating countries (not including the United States) agreed to reduce their emissions of greenhouse gases to below 1990 levels by 2012. Though the 16th meeting of the Council of the Parties in Mexico in November and December 2010 did not produce a legally binding final agreement, international negotiations continue, with the participation of the United States.

International developments, passage of state or federal climate control legislation or other regulatory initiatives, the adoption of regulations by EPA and analogous state agencies that restrict emissions of greenhouse gases in areas in which we conduct business, or further development of caselaw allowing claims based upon greenhouse gas emissions, could have an adverse effect on our operations and financial condition as a result of material increases in operating and production costs and litigation expense due to expenses associated with monitoring, reporting, permitting and controlling greenhouse gas emissions or litigating claims related to emissions of greenhouse gases, as well as reduced demand for fossil fuels generally.

Potential legislative and regulatory actions could increase our costs, reduce our revenue and cash flow from oil and natural gas sales, reduce our liquidity or otherwise alter the way we conduct our business.

In 2009 and 2010, the administration of President Obama made budget proposals which, if enacted into law by Congress, would have potentially increased and accelerated the payment of federal income taxes by independent producers of oil and natural gas. Proposals included, but were not limited to, repealing the expensing of intangible drilling costs, repealing the percentage depletion allowance, repealing the manufacturing tax deduction for oil and natural gas companies, and increasing the amortization period of geological and geophysical expenses. Legislation which would have implemented the proposed changes was introduced but not enacted. It is unclear whether similar proposals will be forthcoming from the White House in 2011 or subsequent years or whether legislation supporting any such proposals, or designed to accomplish similar objectives, will be introduced or, if introduced, would be enacted into law or, if enacted, how soon resulting changes would become effective. The passage of any legislation designed to implement changes in the U.S. federal income tax laws similar to the changes included in the budget proposals offered by the White House in 2009 and 2010 could eliminate certain tax deductions currently available with respect to oil and gas exploration and development, and any such changes (i) could make it more costly for us to explore for and develop our oil and natural gas resources, and (ii) could negatively affect our financial condition and results of operation.

Certain risks are amplified by the current economic environment.

During 2007, the U.S. and many other countries began to exhibit signs of economic weakness, which continued through 2010. This weakness has had an adverse impact on the global financial system, stressing a number of large financial institutions. Capital constraints coupled with significant energy price volatility have produced pervasive liquidity issues for many companies. Such events have created uncertainty in the economic outlook, and have amplified the potential likelihood of certain risks inherent in our business, such as:

•

increased cost of capital and increased difficulties accessing capital to fund expansion and acquisition activities as well as routine operating requirements;

•

the failure of counterparties to fulfill their delivery or purchase obligations;

•

business failures by vendors, suppliers or customers that result in (i) delays in progress on our capital projects, (ii) nonpayment of receivables or (iii) expensive and protracted court or bankruptcy proceedings; and

•

decreases in domestic consumption or in volumes imported to or produced in the United States and related reductions in transportation, terminalling, or marketing margins.

Competition for experienced technical personnel may negatively impact our operations or financial results.

Our continued drilling success and the success of other activities integral to our operations will depend, in part, on our ability to attract and retain experienced explorationists, engineers and other professionals. Despite the recent decline in commodity prices and lower industry activity levels, competition for these professionals remains strong. We are likely to continue to experience increased costs to attract and retain these professionals.

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

Congress has previously considered legislation to amend the federal Safe Drinking Water Act to require the disclosure of chemicals used by the oil and natural gas industry in the hydraulic fracturing process. Hydraulic fracturing involves the injection of water, sand and chemicals under pressure into rock formations to stimulate natural gas production. Sponsors of bills previously considered before the Senate and House of Representatives have asserted that chemicals used in the fracturing process could adversely affect drinking water supplies. The proposed legislation would require the reporting and public disclosure of chemicals used in the fracturing process, which could make it easier for third parties opposing the hydraulic fracturing process to initiate legal proceedings based on allegations that specific chemicals used in the fracturing process could adversely affect groundwater. In addition, these bills, if adopted, could repeal the exemptions for hydraulic fracturing from the Safe Drinking Water Act.

Further, in 2010, EPA initiated a Hydraulic Fracturing Research Study to address concerns that hydraulic fracturing may affect the safety of drinking water. As part of that process, EPA requested and received information from the major fracturing service providers regarding the chemical composition of fluids, standard operating procedures and the sites where they engage in hydraulic fracturing. In February 2011, EPA released its Draft Plan to Study the Potential Impacts of Hydraulic Fracturing on Drinking Water Resources, proposing to study the lifecycle of hydraulic fracturing fluid and providing a comprehensive list of chemicals identified in fracturing fluid and flowback/produced waste. These developments, as well as increased scrutiny of hydraulic fracturing activities by state authorities, municipal location prohibitions and Clean Water Act citizen suit litigation activities arising from discharge of recovered wastewater from hydraulic fracturing operations to municipal wastewater treatment works may result in additional levels of regulation or level of complexity with respect to existing regulation at the federal and state levels. This additional complexity could lead to operational delays or increased operating costs and could result in additional regulatory burdens that could make it more difficult to perform hydraulic fracturing and increase our costs of compliance and doing business.

We are responsible for the decommissioning, abandonment, and reclamation costs for our facilities, which could decrease funds available for servicing our debt obligations and other operating expenses.

We are responsible for compliance with all applicable laws and regulations regarding the decommissioning, abandonment and reclamation of our facilities at the end of their economic life, the costs of which may be substantial. It is not possible to predict these costs with certainty since they will be a function of regulatory requirements at the time of decommissioning, abandonment and reclamation. We may, in the future, determine it prudent or be required by applicable laws or regulations to establish and fund one or more decommissioning, abandonment and reclamation reserve funds to provide for payment of future decommissioning, abandonment and reclamation costs, which could decrease funds available to service debt obligations. In addition, such reserves, if established, may not be sufficient to satisfy such future decommissioning, abandonment and reclamation costs and we will be responsible for the payment of the balance of such costs.

Unusual weather patterns or natural disasters, whether due to climate change or otherwise, could negatively impact our financial condition.

Our business depends, in part, on normal weather patterns across the United States. Natural gas demand and prices are particularly susceptible to seasonal weather trends. Warmer than usual winters can result in reduced demand and high season-end storage volumes, which can depress prices to unacceptably low levels. In addition, because a majority of our properties are located in Oklahoma, Texas, and Louisiana, our operations are constantly at risk of extreme adverse weather conditions such as tornadoes and hurricanes. Any unusual or prolonged adverse weather patterns in our areas of operations or markets, whether due to climate change or otherwise, could have a material and adverse impact on our business, financial condition and cash flow. In addition, our business, financial condition and cash flow could be adversely affected if the businesses of our key vendors, purchasers, contractors, suppliers or transportation service providers were disrupted due to severe weather, such as hurricanes or floods, whether due to climate change or otherwise.

Climate change and government laws and regulations related to climate change could negatively impact our financial condition.

In addition to other climate-related risks set forth in this “Risk Factors” section, we are and will be, directly and indirectly, subject to the effects of climate change and are, and most likely will continue to be, affected by government laws and regulations related to climate change. We are currently evaluating compliance costs arising from newly adopted mandatory greenhouse gas reporting rules, and potential compliance costs arising from newly promulgated Clean Air Act reporting and permit regulations for greenhouse gas emissions. These new regulations could be preempted by new federal legislation if enacted. However, we cannot predict with any degree of certainty the ultimate effect possible climate change and government laws and regulations related to climate change will have on our operations. While it is difficult to assess the timing and effect of climate change and pending legislation and regulation related to climate change on our business, we believe that climate change and government laws and regulations related to climate change may affect: (i) the cost of the equipment and services we purchase, (ii) our ability to continue to operate as we have in the past, including drilling, completion and operating methods, (iii) the timeliness of delivery of the materials and services we need and the cost of transportation paid by us and our vendors and other providers of services, (iv) insurance premiums, deductibles and the availability of coverage, (v) the cost of utility services, particularly electricity, in connection with the operation of our properties, and (vi) factors arising from new Clean Air Act greenhouse gas permitting and, or, possible greenhouse gas legislation, in addition to previously identified factors. These potential effects depend upon, but are not limited to, the following considerations: whether and to what extent legislation is enacted, the nature of the legislation (such as a cap and trade system or a tax on emissions); the greenhouse gas reductions required pursuant to either existing Clean Air Act regulatory requirements or new greenhouse gas legislation; the cost and availability of required offsets or emissions reductions; the amount and allocation of possible allowances; costs required to improve facilities and equipment to both monitor and reduce emissions in order to comply with regulatory limits or to mitigate the financial consequences of a greenhouse gas emission limitations; changes to profit or loss arising from increased or decreased demand for oil and natural gas we produce arising directly from legislation or regulation, and indirectly from changes in production costs. In addition, climate change may increase the likelihood of property damage and the disruption of our operations, especially in coastal states. As a result, our financial condition could be negatively impacted by significant climate change and related governmental regulation, and that impact could be material.

The recent adoption of The Dodd-Frank Wall Street Reform and Consumer Protection Act (the “Dodd-Frank Act”) could have an adverse effect on our ability to use derivative instruments to reduce the effect of commodity price and other risks associated with our business.

We use derivative instruments to manage our commodity price risk. The United States Congress recently adopted comprehensive financial reform legislation that establishes federal oversight and regulation of the over-the-counter derivatives market and entities that participate in that market. The Dodd-Frank Act requires the Commodities Futures Trading Commission (the “CFTC”) and the SEC to promulgate rules and regulations implementing the new legislation within 360 days from the date of enactment. The CFTC has also proposed regulations to set position limits for certain futures and option contracts in the major energy markets, although it is not possible at this time to predict whether or when the CFTC will adopt those rules or include comparable provisions in its rulemaking under the new legislation. The financial reform legislation may also require us to comply with margin requirements and with certain clearing and trade-execution requirements in connection with our derivative activities, although the application of those provisions to us is uncertain at this time. The financial reform legislation may also require the counterparties to our derivative instruments to spin off some of their derivatives activities to a separate entity, which may not be as creditworthy as the current counterparty. The new legislation and any new regulations could significantly increase the cost of derivative contracts (including through requirements to post collateral which could adversely affect our available liquidity), materially alter the terms of derivative contracts, reduce the availability of derivatives to protect against risks we encounter, reduce our ability to monetize or restructure our existing derivative contracts, and increase our exposure to less creditworthy counterparties. If we reduce our use of derivatives as a result of the legislation and regulations, our results of operations may become more volatile and our cash flows may be less predictable, which could adversely affect our ability to plan for and fund capital expenditures. Finally, the legislation was intended, in part, to reduce the volatility of oil and natural gas prices, which some legislators attributed to speculative trading in derivatives and commodity instruments related to oil and natural gas. Our revenues could therefore be adversely affected if a consequence of the legislation and regulations is to lower commodity prices. Any of these consequences could have a material adverse effect on us, our financial condition and our results of operations.

ITEM 1B. UNRESOLVED STAFF COMMENTS

None.

ITEM 2. PROPERTIES

See Items 1. and 2. Business and Properties—Properties. We also have various operating leases for rental of office space, office and field equipment, and vehicles. See Liquidity and Capital Resources—Contractual Obligations in Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations, and Note 13, “Commitments and Contingencies,” to our consolidated financial statements. Such information is incorporated herein by reference.

ITEM 3. LEGAL PROCEEDINGS

ITEM 4. [RESERVED]

PART II

ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

Our common stock has not been registered under the Securities Exchange Act of 1934, and there is no established public trading market for our common equity.

As of March 29, 2011, we had 1,410,235 shares of common stock outstanding held by 25 record holders.

We have not paid any dividends on our common stock in either of the last two years and we do not currently anticipate paying any cash dividends on our common stock in the foreseeable future. We currently intend to retain all future earnings to fund the development and growth of our business. Any future determination relating to our dividend policy will be at the discretion of our board of directors and will depend on our results of operations, financial condition, capital requirements and other factors deemed relevant by our board. We are also currently restricted in our ability to pay dividends under our senior secured revolving credit facility. See Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources for more information regarding the restrictions on our ability to pay dividends.

ITEM 6. SELECTED FINANCIAL DATA

You should read the following historical financial data in connection with the financial statements and related notes and “Management’s Discussion and Analysis of Financial Condition and Results of Operations” included in this report. The financial data as of and for each of the five years ended December 31, 2010 was derived from our audited financial statements. Our historical results are not necessarily indicative of results to be expected in future periods.


	Year Ended December 31,
(dollars in thousands)	2010			2009			2008			2007			2006
Operating results data:
Revenues
Oil and natural gas sales	$	408,561		$	292,387		$	501,761		$	365,958		$	249,180
Gain (loss) from oil and natural gas hedging activities		(29,393	)		19,403			(76,417	)		(28,140	)		(4,166	)
Other revenues		4,127			2,864			8,735			2,859			—

Total revenues		383,295			314,654			434,079			340,677			245,014

Costs and expenses
Lease operating		106,127			94,070			120,487			104,469			71,663
Production tax		26,495			20,341			33,815			26,216			18,710
Depreciation, depletion and amortization		109,503			104,193			101,026			85,538			52,299
Loss on impairment of oil & natural gas properties		—			240,790			281,393			—			—
Loss on impairment of other assets		4,150			—			2,900			—			—
General and administrative		29,915			23,741			22,370			21,838			14,659
Litigation settlement		—			2,928			—			—			—
Other expenses		3,148			1,957			7,150			2,493			—

Total costs and expenses		279,338			488,020			569,141			240,554			157,331

Operating income (loss)		103,957			(173,366	)		(135,062	)		100,123			87,683

Non-operating income (expense)
Interest expense		(83,611	)		(90,102	)		(86,038	)		(87,656	)		(45,246	)
Non-hedge derivative gains (losses)		38,595			11,169			126,941			(23,781	)		(4,677	)
Financing costs, net of termination fee		(1,812	)		(2,169	)		2,100			—			—
Other income		387			13,921			1,394			2,276			792

Net non-operating income (expense)		(46,441	)		(67,181	)		44,397			(109,161	)		(49,131	)

Income (loss) from continuing operations before income taxes and non-controlling interest		57,516			(240,547	)		(90,665	)		(9,038	)		38,552
Income tax expense (benefit)		23,803			(89,777	)		(34,976	)		(3,292	)		14,817

Income (loss) from continuing operations		33,713			(150,770	)		(55,689	)		(5,746	)		23,735
Income from discontinued operations, net of related taxes		—			6,452			939			953			—

Income (loss) before non-controlling interest in net loss of subsidiaries		33,713			(144,318	)		(54,750	)		(4,793	)		23,735
Net loss attributable to non-controlling interest		—			—			—			—			(71	)

Net income (loss)	$	33,713		$	(144,318	)	$	(54,750	)	$	(4,793	)	$	23,806

Cash flow data:
Net cash provided by operating activities	$	167,702		$	98,675		$	145,831		$	113,070		$	89,154
Net cash provided by (used in) investing activities		(264,172	)		21,904			(262,905	)		(239,069	)		(703,804	)
Net cash provided by (used in) financing activities		78,164			(99,274	)		157,499			128,883			621,855


	As of December 31,
(dollars in thousands)	2010			2009			2008		2007			2006
Financial position data:
Cash and cash equivalents	$	55,111		$	73,417		$	52,112	$	11,687		$	8,803
Total assets		1,529,292			1,353,920			1,712,836		1,530,898			1,331,435
Total debt		962,087			1,177,007			1,271,589		1,114,237			976,272
Retained earnings (accumulated deficit)		(89,265	)		(122,978	)		21,340		76,090			80,883
Accumulated other comprehensive income (loss), net of income taxes		34,974			17,618			82,133		(73,839	)		(3,946	)
Total stockholders’ equity (deficit)		363,557			(4,433	)		204,400		103,178			177,864

ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The following discussion and analysis of our financial condition and results of operations should be read in conjunction with our consolidated financial statements and the accompanying notes included elsewhere in this report. In addition to historical financial information, the following discussion contains forward-looking statements that reflect our plans, estimates, and beliefs. Our actual results could differ materially from those discussed in the forward-looking statements. Factors that could cause or contribute to these differences include those discussed below and elsewhere in this report, particularly in “Risk Factors” and “Cautionary Note Regarding Forward-Looking Statements.”

Overview

We are an independent oil and natural gas company engaged in the production, exploitation and acquisition of oil and natural gas properties. In 2010, we reorganized our oil and natural gas assets into enhanced oil recovery (“EOR”) project areas and non-EOR(“conventional”) productive basins. Our primary areas of operation using conventional recovery methods are the Anadarko Basin Area, Central Oklahoma Area, and the Permian Basin Area. We maintain a portfolio of proved reserves, development and exploratory drilling opportunities, and EOR projects. As of December 31, 2010, we had estimated proved reserves of 149.3 MMBoe, including EOR reserves of 30.5 MMBoe, with a PV-10 value of approximately $1.8 billion. Our reserves were 66% proved developed and 63% crude oil.

Our revenues, profitability and future growth depend substantially on prevailing prices for oil and natural gas and on our ability to find, develop and acquire oil and natural gas reserves that are economically recoverable. The preparation of our financial statements in conformity with generally accepted accounting principles (“GAAP”) requires us to make estimates and assumptions that affect our reported results of operations and the amount of our reported assets, liabilities and proved oil and natural gas reserves. We use the full cost method of accounting for our oil and natural gas activities.

Generally our producing properties have declining production rates. Our December 31, 2010 reserve estimates reflect that our production rate on current proved developed producing reserve properties will decline at annual rates of approximately 16%, 12%, and 10% for the next three years. To grow our production and cash flow we must find, develop and acquire new oil and natural gas reserves to replace those being depleted by production. Substantial capital expenditures are required to find, develop and acquire oil and natural gas reserves.

Oil and natural gas prices fluctuate widely. We generally hedge a substantial portion of our expected future oil and natural gas production to reduce our exposure to commodity price decreases. The prices we receive for our oil and natural gas production affect our:

•

cash flow available for capital expenditures;

•

ability to borrow and raise additional capital;

•

ability to service debt;

•

quantity of oil and natural gas we can produce;

•

quantity of oil and natural gas reserves; and

•

operating results for oil and natural gas activities.

The following are material events that have impacted liquidity or results of operations in 2010 and/or are expected to impact these items in future periods:

•

8.25% Senior Notes due 2021. On February 22, 2011, we issued $400.0 million aggregate principal amount of 8.25% Senior Notes maturing on September 1, 2021. We used the net proceeds from the 8.25% Senior Notes to consummate a tender offer for all of our 8.5% Senior Notes due 2015, to redeem the 8.5% Senior Notes not purchased in the tender offer, and for general corporate purposes. In connection with the issuance of the 8.25% Senior Notes and the repurchase or redemption of our 8.5% Senior Notes due 2015, we capitalized approximately $8.5 million of issuance costs related to underwriting and other fees and we expensed approximately $15.0 million of repurchase- and redemption-related costs.

•

9.875% Senior Notes due 2020. On September 16, 2010, we issued $300.0 million aggregate principal amount of 9.875% Senior Notes maturing on October 1, 2020. The net proceeds from the issuance of the notes were used to pay down outstanding amounts under our senior secured revolving credit facility and for working capital. In connection with the issuance of the 9.875% Senior Notes, we recorded a discount of $7.0 million and capitalized $6.6 million of issuance costs related to underwriting and other fees.

•

Stock purchase agreement. On April 12, 2010, we closed the sale of an aggregate of 475,043 shares of 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”). Proceeds from the sale were $313.2 million, net of fees and other expenses of $11.8 million, and were used to repay amounts owing under our prior credit facility. See Note 10 to our consolidated financial statements for additional information regarding this transaction.

•

Senior secured revolving credit facility. In connection with the closing of the sale of our common stock to CCMP, we entered into and closed our Eighth Restated Credit Agreement (our “senior secured revolving credit facility”), which had an initial borrowing base of $450.0 million, is collateralized by our oil and natural gas properties, and is scheduled to mature on April 12, 2014. We used the proceeds from the sale of common stock to CCMP, along with proceeds available under the senior secured revolving credit facility, to repay the amounts owing under our Seventh Restated Credit Agreement (our “prior credit facility”). During the second quarter of 2010, we recorded expenses for derivative novation and break fees and the write off of prepaid bank fees associated with our prior credit facility of $3.1 million, and we recorded deferred financing costs associated with the closing of our senior secured revolving credit facility of $10.9 million. As a result of the issuance of our 9.875% Senior Notes due 2020, our borrowing base was reduced from $450.0 million to $375.0 million, effective September 16, 2010. The borrowing base of $375.0 million was reaffirmed effective November 23, 2010.

•

2010 Equity Incentive Plan. We adopted the Chaparral Energy, Inc. 2010 Long-Term Incentive Plan (the “2010 Plan”) on April 12, 2010. The 2010 Plan reserves a total of 86,301 shares of our class A common stock for awards issued under the 2010 Plan. All of our or our affiliates’ employees, officers, directors, and consultants, as defined in the 2010 Plan, are eligible to participate in the 2010 Plan. Our Board of Directors has approved awards of restricted stock under the 2010 Plan totaling 51,346 shares of our class A common stock. These initial awards are subject to performance, service, and market vesting conditions. During 2010, we recorded stock-based compensation expense of $2.4 million associated with these awards. See Note 11 to our consolidated financial statements for additional information regarding stock-based compensation.

•

Capital expenditure budget. During 2010, we expended a significant portion of the proceeds from our sale of stock to CCMP for our oil and natural gas properties. We have accordingly reduced our capital expenditure budget for 2011 to $250.0 million. Our 2011 capital budget allocates $157.0 million to conventional oil and natural gas exploration and production activities. The remaining $93.0 million, or 37%, of the capital budget is allocated to the development of our EOR assets, and represents a substantial increase in capital being directed toward development of our EOR assets. The increased focus on EOR reduces near term growth opportunities but enhances longer term growth and is consistent with our strategy of driving near term growth with developmental drilling and long term growth through EOR development.

Liquidity and capital resources

Historically, our primary sources of liquidity have been cash generated from our operations and debt. On April 12, 2010, we sold an aggregate of 475,043 shares of our common stock to CCMP for proceeds of $313.2 million, net of fees and other expenses of $11.8 million. In connection with our sale of common stock to CCMP, we entered into and closed our senior secured revolving credit facility, which had an initial borrowing base of $450.0 million, is collateralized by our oil and natural gas properties, and is scheduled to mature on April 12, 2014. We used the proceeds from the sale of common stock to CCMP, along with proceeds available under our senior secured revolving credit facility, to repay the amounts owing under our prior credit facility.

On September 16, 2010, we issued $300.0 million aggregate principal amount of 9.875% Senior Notes maturing on October 1, 2020. We used the proceeds from the 9.875% Senior Notes due 2020 to pay down outstanding amounts under our senior secured revolving credit facility and for working capital. As a result of our issuance of the 9.875% Senior Notes due 2020, the borrowing base under our senior secured revolving credit facility was reduced from $450.0 million to $375.0 million.

We pledge our producing oil and natural gas properties to secure our senior secured revolving credit facility. The banks establish a borrowing base by making an estimate of the collateral value of our oil and natural gas properties. We have the capacity to utilize the available funds to supplement our operating cash flows as a financing source for our capital expenditures. If oil and natural gas prices decrease from the amounts used in estimating the collateral value of our oil and natural gas properties, the borrowing base may be reduced, thus reducing funds available under the borrowing base. We mitigate a potential reduction in our borrowing base caused by a decrease in oil and natural gas prices through the use of commodity derivatives.

Covenants set forth in the indentures for our Senior Notes, including the ACNTA test, limit the amount of secured debt we can incur. Certain thresholds set forth in the ACNTA test are principally reliant upon the levels of commodity prices for crude oil and natural gas at specified dates.

Sources and uses of cash

Our net increase (decrease) in cash is summarized as follows:


	Year ended December 31,
(dollars in thousands)	2010			2009			2008
Cash flows provided by operating activities	$	167,702		$	98,675		$	145,831
Cash flows provided by (used in) investing activities		(264,172	)		21,904			(262,905	)
Cash flows provided by (used in) financing activities		78,164			(99,274	)		157,499

Net increase (decrease) in cash during the period	$	(18,306	)	$	21,305		$	40,425

Substantially all of our cash flow from operating activities is from the production and sale of oil and natural gas, reduced or increased by associated hedging activities. Cash inflows from oil and natural gas sales net of hedging settlements and cash outflows for operating expenses both increased significantly from 2009 to 2010 as commodity prices rose, after having decreased sharply from 2008 to 2009 due to the decline in commodity prices. Operating cash flows also include production tax credits of $0, $13.7 million, and $1.0 million for the years ended December 31, 2010, 2009, and 2008, respectively. This source of cash received will not be available in future periods. Primarily as a result of the above activity, cash flows from operating activities increased by 70% from 2009 to 2010 after having decreased by 32% from 2008 to 2009.

We use the net cash provided by operations to partially fund our acquisition, exploration and development activities. For the years ended December 31, 2010, 2009, and 2008, cash flows provided by operating activities were approximately 54%, 55%, and 48%, respectively, of cash used for the purchase of property and equipment and oil and natural gas properties.

During 2010, 2009, and 2008, the early monetization of derivatives provided investing cash inflows of $7.1 million, $111.9 million, and $32.6 million, respectively, and the return of our prepaid production tax credits provided investing cash inflows of $0, $13.5 million, and $1.1 million, respectively. Cash flows provided by investing activities for the year ended December 31, 2009 also included proceeds of $25.3 million from the sale of the Electric Submersible Pumps (“ESP”) and Chemicals divisions of Green Country Supply, Inc. (“GCS”), a wholly owned subsidiary.

In February 2008, loss of well control occurred at the Bowdle 47 No. 2 well in Loving County, Texas. Total costs attributable to the loss of well control were approximately $10.6 million. Our insurance policy has covered 100% of these costs, with the $0.6 million insurance retention and deductible being payable by us. We received insurance proceeds of $1.9 million and $8.1 million in 2009 and 2008, respectively, and no further receipts are expected. Insurance proceeds received are recorded as a reduction of oil and natural gas properties on the balance sheet and in the statement of cash flows.

Net cash provided by (used in) financing activities was $78.2 million, $(99.3) million, and $157.5 million, during 2010, 2009, and 2008, respectively. On April 12, 2010, we sold an aggregate of 475,043 shares of our common stock to CCMP for proceeds of $313.2 million, net of fees and other expenses of $11.8 million, and we entered into and closed our senior secured revolving credit facility. We used the proceeds from the sale of common stock to CCMP, along with proceeds available under our senior secured revolving credit facility, to repay the amounts owing under our prior credit facility. On September 16, 2010, we issued $300.0 million aggregate principal amount of 9.875% Senior Notes maturing on October 1, 2020, for net proceeds of $293.0 million, less fees and other expenses of $6.6 million. As a result of the issuance of our 9.875% Senior Notes due 2020, the borrowing base under our senior secured revolving credit facility was reduced from $450.0 million to $375.0 million, and proceeds from the issuance of $206.0 million were used to pay down outstanding amounts under the facility. The remaining $80.4 million was used for working capital.

As a result of our early monetization of derivatives in the second quarter of 2009, the borrowing base under our prior credit facility was reduced from $600.0 million to $513.0 million, and proceeds from the monetization of $87.0 million were paid to the banks. Borrowings under our prior credit facility were $147.0 million in 2008, and were used to finance our capital expenditures.

Capital expenditures

During the second quarter of 2010, we expanded our oil and natural gas property capital expenditure budget for 2010 from $268.0 million to $310.0 million in order to accelerate our development program. Our actual costs incurred for the year ended December 31, 2010 and our budgeted 2011 capital expenditures for oil and natural gas properties are summarized by area in the following table:


	Year ended December 31, 2010
(dollars in thousands)	Acquisitions		Drilling		Enhancements		Total(1)		Percent of total			Budgeted 2011 capital expenditures		Percent of total
Enhanced Oil Recovery Project Areas(2)	$	7,451	$	16,730	$	28,792	$	52,973		16	%	$	93,000		37	%
Anadarko Basin Area		6,147		86,997		6,360		99,504		31	%		71,000		29	%
Central Oklahoma		2,676		25,964		8,193		36,833		11	%		35,000		14	%
Permian Basin Area		5,884		45,796		7,599		59,279		18	%		21,000		8	%
Other		19,362		47,270		12,043		78,675		24	%		30,000		12	%

Total	$	41,520	$	222,757	$	62,987	$	327,264		100	%	$	250,000		100	%

(1)	Includes $1.5 million of additions relating to increases in our asset retirement obligations.

(2)	Drilling and enhancements include $7.9 million of additions relating to conventional assets located in our EOR project areas and $9.8 million for CO₂ support facilities and pipelines.

In addition to our capital expenditures for oil and natural gas properties, we spent approximately $16.6 million for property and equipment during 2010.

During 2010, we expended a significant portion of the proceeds from our sale of stock to CCMP for our oil and natural gas properties. We have accordingly reduced our capital expenditure budget for 2011 to $250.0 million. Despite this reduction, we expect production for 2011 to increase compared to 2010. We are currently drilling a number of wells that we expect will support our production throughout 2011, and these wells are expected to be completed and on line during the first and second quarters of 2011. However, we cannot accurately predict the timing or level of future production.

Our budgeted capital expenditures for oil and natural gas properties for the year ended December 31, 2011 are summarized by area in the following table:


(dollars in thousands)	Budgeted 2011 capital expenditures
Enhanced Oil Recovery	$	93,000
Acquisitions		5,000
Conventional drilling		126,000
Enhancements		26,000

Total	$	250,000

Our 2011 capital budget reflects a substantial increase in capital being directed toward development of EOR assets. The increased focus on EOR reduces near-term growth opportunities but enhances longer-term growth, and is consistent with our strategy of driving near-term growth with developmental drilling and long-term growth through EOR development. The EOR capital budget of $93.0 million includes approximately $42.0 million for project infrastructure, including CO₂ transmission lines and compression facilities, $27.0 million for enhancements and CO₂ purchases, and $24.0 million for drilling.

We continually evaluate our capital needs and compare them to our capital resources. Our actual expenditures during 2011 may be higher or lower than our budgeted amounts. Our level of exploration and development expenditures is largely discretionary, and the amount of funds devoted to any particular activity may increase or decrease significantly depending on available opportunities, commodity prices, cash flows and development results, among other factors.

As of December 31, 2010, we had cash and cash equivalents of $55.1 million and long-term debt obligations of $962.1 million.

Credit Agreements

As of December 31, 2009, we were party to our prior credit facility, which was scheduled to mature on October 31, 2010, and was collateralized by our oil and natural gas properties.

On April 12, 2010, in connection with the closing of our stock purchase agreement with CCMP, we entered into and closed our senior secured revolving credit facility, which had an initial borrowing base of $450.0 million, is collateralized by our oil and natural gas properties, and matures on April 12, 2014. We used the proceeds from the sale of common stock to CCMP, along with proceeds available under our senior secured revolving credit facility, to repay the amounts owing under our prior credit facility. During the second quarter of 2010, we recorded expenses for derivative novation and break fees and the write off of prepaid bank fees associated with our prior credit facility of $3.1 million and we recorded deferred financing costs associated with the closing of our senior secured revolving credit facility of $10.9 million.

The terms of our senior secured revolving credit facility are described below. The terms of our prior credit facility were substantially similar to those contained in our senior secured revolving credit facility. All discussions of interest rates and ratios as of dates prior to April 12, 2010 relate to our prior credit facility.

Availability under our senior secured revolving credit facility is subject to a borrowing base which is set by the banks semi-annually on May 1 and November 1 of each year. In addition, the lenders may request a borrowing base redetermination once between each scheduled redetermination and in the event of early termination of our derivative contracts. As a result of the issuance of our 9.875% Senior Notes due 2020, the borrowing base was reduced from $450.0 million to $375.0 million effective September 16, 2010. Effective November 23, 2010, the borrowing base was reaffirmed at $375.0 million.

Borrowings under our senior secured revolving credit facility are made, at our option, as either Eurodollar loans or Alternate Base Rate (“ABR”) loans.

Interest on Eurodollar loans is computed at the Adjusted LIBO Rate, defined as the rate applicable to dollar deposits in the London interbank market with a maturity comparable to the interest period (one, two, three or six months, selected by us) times a Statutory Reserve Rate multiplier, as defined in our senior secured revolving credit facility, plus a margin where the margin varies from 2.50% to 3.50% depending on the utilization percentage of the conforming borrowing base. From April 12, 2010 until October 12, 2010, the margin was fixed at 3.00%. Interest payments on Eurodollar borrowings are due the last day of the interest period, if shorter than three months or every three months.

Interest on ABR loans is computed as the greater of (1) the Prime Rate, as defined in our senior secured revolving credit facility, (2) the Federal Funds Effective Rate, as defined in our senior secured revolving credit facility, plus 1/2 of 1%, or (3) the Adjusted LIBO Rate, as defined in our senior secured revolving credit facility, plus 1%; plus a margin where the margin varies from 1.625% to 2.625%, depending on the utilization percentage of the borrowing base.

Commitment fees of 0.50% accrue on the unused portion of the borrowing base amount and are included as a component of interest expense. We have the right to make prepayments of the borrowings at any time without penalty or premium.

Our senior secured revolving credit facility contains restrictive covenants that may limit our ability, among other things, to:

•

incur additional indebtedness;

•

create or incur additional liens on our oil and natural gas properties;

•

pay dividends in cash or other property, redeem our capital stock or prepay certain indebtedness;

•

make investments in or loans to others;

•

change our line of business;

•

enter into operating leases;

•

merge or consolidate with another person, or lease or sell all or substantially all of our assets;

•

sell, farm-out or otherwise transfer property containing proved reserves;

•

enter into transactions with affiliates;

•

issue preferred stock;

•

enter into negative pledge agreements or agreements restricting the ability of our subsidiaries to pay dividends;

•

enter into or terminate certain swap agreements;

•

amend our organizational documents; and

•

amend, modify or waive under our permitted bond documents (i) any covenants that would make the terms materially more onerous to us or (ii) certain other provisions.

Our senior secured revolving credit facility requires us to maintain a current ratio, as defined in our senior secured revolving credit facility, of not less than 1.0 to 1.0. The definition of current assets and current liabilities used for determination of the current ratio computed for loan compliance purposes differs from current assets and current liabilities determined in compliance with GAAP. Since compliance with financial covenants is a material requirement under our senior secured revolving credit facility, we consider the current ratio calculated under our senior secured revolving credit facility to be a useful measure of our liquidity because it includes the funds available to us under our senior secured revolving credit facility and is not affected by the volatility in working capital caused by changes in the fair value of derivatives. At December 31, 2010 and 2009, our current ratio as computed using GAAP was 0.87 and 1.38, respectively. After giving effect to the adjustments, our current ratio computed for loan compliance purposes was 3.78 and 1.51, respectively. The following table reconciles our current assets and current liabilities using GAAP to the same items for purposes of calculating the current ratio for our loan compliance:


(dollars in thousands)	December 31, 2010			December 31, 2009
Current assets per GAAP	$	142,348		$	161,682
Plus—Availability under senior secured revolving credit facility		374,080			3,145
Less—Short-term derivative instruments		(1,429	)		(18,226	)
Less—Deferred tax asset on derivative instruments and asset retirement obligations		(9,655	)		(1,079	)

Current assets as adjusted	$	505,344		$	145,522

Current liabilities per GAAP	$	163,347		$	117,529
Less—Short term derivative instruments		(28,853	)		(20,677	)
Less—Short-term asset retirement obligation		(690	)		(300	)

Current liabilities as adjusted	$	133,804		$	96,552

Current ratio for loan compliance		3.78			1.51

Our senior secured revolving credit facility also requires us to maintain, to the extent borrowings are outstanding, a Consolidated Total Debt to Consolidated EBITDAX ratio, or to the extent no borrowings are outstanding, a Consolidated Net Debt to Consolidated EBITDAX ratio, as defined in our senior secured revolving credit facility, of not greater than:

•

4.50 to 1.0 for the annualized periods commencing on April 1, 2010 and ending on the last day of the fiscal quarter ending on June 30, 2010, September 30, 2010, and December 31, 2010;

•

4.25 to 1.0 for the four consecutive fiscal quarters ending on March 31, 2011, June 30, 2011, and September 30, 2011; and

•

4.00 to 1.0 for the four consecutive fiscal quarters ending on December 31, 2011 and for each period of four consecutive fiscal quarters ending on the last day of such applicable fiscal quarters thereafter.

In July 2010, we amended the definition of Consolidated EBITDAX in our senior secured revolving credit facility to (1) permit cash proceeds received from the early monetization of derivatives to be included in the calculation of Consolidated EBITDAX, to the extent that such monetizations, in any period between scheduled redeterminations, do not exceed 5% of the borrowing base then in effect, and (2) permit the exclusion from the calculation of Consolidated EBITDAX of up to $4.5 million in one-time cash expenses associated with our financing transactions that were incurred and paid during the second quarter of 2010.

Our senior secured revolving credit facility also specifies events of default, including:

•

our failure to pay principal or interest under our senior secured revolving credit facility when due and payable;

•

our representations or warranties proving to be incorrect, in any material respect, when made or deemed made;

•

our failure to observe or perform certain covenants, conditions or agreements under our senior secured revolving credit facility;

•

our failure to make payments on certain other material indebtedness when due and payable;

•

the occurrence of any event or condition that requires the redemption or repayment of, or an offer to redeem or repay, certain other material indebtedness prior to its scheduled maturity;

•

the commencement of a voluntary or involuntary proceeding seeking liquidation, reorganization or other relief, or the appointment of a receiver, trustee, custodian or other similar official for us or our subsidiaries, and the proceeding or petition continues undismissed for 60 days or an order approving the foregoing is entered;

•

our inability, admission or failure generally to pay our debts as they become due;

•

the entry of a final, non-appealable judgment for the payment of money in excess of $5.0 million that remains undischarged for a period of 60 consecutive days;

•

a Change of Control (as defined in our senior secured revolving credit facility); and

•

the occurrence of a default under any permitted bond document, which such default continues unremedied or is not waived prior to the expiration of any applicable grace or cure under any permitted bond document.

If the outstanding borrowings under our senior secured revolving credit facility were to exceed the borrowing base as a result of a redetermination, we would be required to eliminate this excess. Within 10 days after receiving notice of the new borrowing base, we would be required to make an election: (1) to repay a portion of our bank borrowings in the amount of the excess either in a lump sum within 30 days or in equal monthly installments over a six-month period, (2) to submit within 30 days additional oil and natural gas properties we own for consideration in connection with the determination of the borrowing base sufficient to eliminate the excess or (3) to eliminate the excess through a combination of repayments and the submission of additional oil and natural gas properties within 30 days.

Senior Notes

Senior Notes at December 31, 2010 and December 31, 2009 consisted of the following:


	December 31,
(dollars in thousands)	2010			2009
8.5% Senior Notes due 2015	$	325,000		$	325,000
8.875% Senior Notes due 2017(1)		325,000			325,000
9.875% Senior Notes due 2020(2)		300,000			—
Discount on Senior Notes due 2017		(1,901	)		(2,123	)
Discount on Senior Notes due 2020		(6,865	)		—

	$	941,234		$	647,877

(1)

As part of the indenture, we entered into a registration rights agreement in which we agreed to file a registration statement with the Securities and Exchange Commission related to an offer to exchange the notes for an issue of registered notes within 270 days of the closing date. The exchange offer was not completed within the 270-day period ending October 15, 2007 as required by the registration rights agreement. As a result, we accrued liquidated damages of $0.3 million during the year ended December 31, 2007. On February 29, 2008, we completed the exchange offer, and liquidated damages ceased to accrue as of that date. Total liquidated damages paid in 2008 were $0.4 million.

(2)

As part of the indenture, we entered into a registration rights agreement in which we agreed to file a registration statement with the Securities and Exchange Commission related to an offer to exchange the notes for an issue of registered notes within 270 days of the closing date. If we fail to complete the exchange offer within 270 days after the closing date, we will be required to pay liquidated damages equal to 0.25% per annum of the principal amount of the notes for the first 90 days after the target registration date. After the first 90 days, the rate increases an additional 0.25% for each additional 90 days, up to a total of 1.0%.

The Senior Notes are our senior unsecured obligations, rank equally in right of payment with all of our existing and future senior indebtedness, and rank senior to all of our existing and future subordinated debt. The payment of the principal, interest and premium on the Senior Notes is fully and unconditionally guaranteed on a senior unsecured basis by our material existing and future domestic restricted subsidiaries, as defined in the indentures.

On and after the fifth anniversary of the issue date, we may redeem some or all of the Senior Notes at any time at redemption prices specified in the indentures, plus accrued and unpaid interest to the date of redemption.

Prior to the fifth anniversary of the issue date, the Senior Notes may be redeemed in whole or in part at a redemption price equal to the principal amount of the notes plus accrued and unpaid interest to the date of redemption plus an applicable premium specified in the indentures.

We and our restricted subsidiaries are subject to certain negative and financial covenants under the indentures governing the Senior Notes. The provisions of the indentures limit our and our restricted subsidiaries’ ability to, among other things:

•

incur or guarantee additional indebtedness, or issue preferred stock;

•

pay dividends on our capital stock or redeem, repurchase or retire our capital stock or subordinated indebtedness;

•

make investments;

•

incur liens;

•

create any consensual limitation on the ability of our restricted subsidiaries to pay dividends, make loans or transfer property to us;

•

engage in transactions with our affiliates;

•

sell assets, including capital stock of our subsidiaries;

•

consolidate, merge or transfer assets; and

•

enter into other lines of business.

If we experience a change of control (as defined in the indentures governing the Senior Notes), including making certain asset sales, subject to certain conditions, we must give holders of the Senior Notes the opportunity to sell to us their Senior Notes at 101% of the principal amount, plus accrued and unpaid interest.

Alternative capital resources

We have historically used cash flow from operations, debt financing, and private issuances of common stock as our primary sources of capital. In the future, we may use additional sources such as asset sales, additional public or private issuances of common or preferred stock, or project financing. While we believe we would be able to obtain funds through one or more of these alternative sources, if needed, we cannot provide assurance that these resources would be available on terms acceptable to us.

Contractual obligations

The following table summarizes our contractual obligations and commitments as of December 31, 2010:


(dollars in thousands)	Less than 1 year		1-3 years		3-5 years		More than 5 years		Total
Debt:(1)
Commitment fees on senior secured revolving credit facility	$	1,875	$	3,750	$	531	$	—	$	6,156
Senior Notes, including estimated interest(2)		86,094		172,188		494,885		796,966		1,550,133
Other long-term notes, including estimated interest		5,118		5,875		3,238		14,515		28,746
Capital leases, including estimated interest		124		10		—		—		134
Abandonment obligations		690		1,380		1,380		38,245		41,695
Derivative obligations		28,853		2,482		—		—		31,335
Purchase commitments		6,911		3,641		—		—		10,552

Total	$	129,665	$	189,326	$	500,034	$	849,726	$	1,668,751

(1)	As of December 31, 2010, we had no off-balance sheet arrangements.

(2)

We have open purchase orders for inventory totaling $3.3 million at December 31, 2010.

We have a long-term contract to purchase CO₂ manufactured at an existing ethanol plant. We are currently purchasing approximately nine MMcf/d of CO₂ under this contract, and we expect to purchase an average of approximately 12 MMcf/d over the fifteen-year contract term, which began on May 1, 2009. Purchases under this contract were $0.3 million, $0.1 million and $0 during 2010, 2009, and 2008, respectively. Pricing under the contract is variable over time and the contract has renewal language.

We have rights under two additional contracts that require us to purchase CO₂ for EOR projects. Under one of these contracts, we are currently purchasing an average of approximately 16 MMcf/d and expect our purchases to remain at that level over the remaining contract term, which expires in February 2021. Purchases under this contract were $1.0 million, $0.6 million, and $0.7 million during 2010, 2009, and 2008, respectively. Under the second of these contracts, we as unit operator have nominated to purchase 10 MMcf/d of CO₂ through 2012, and are currently purchasing approximately nine MMcf/d of CO₂ under this contract. Purchases under this contract, which include transportation charges, were $1.5 million, $3.2 million, and $3.2 million during 2010, 2009, and 2008, respectively. The contract expires in 2016. We may terminate or permanently reduce our purchase rate under this contract at the end of any calendar year with 13 months notice. Pricing under both of these contracts is dependent on certain variable factors, including the price of oil.

On March 24, 2011, we signed a long-term contract to purchase up to 100% of CO₂ emissions from an existing nitrogen fertilizer plant that produces approximately 40 MMcf/d of CO₂ for injection into our North Burbank Unit. The initial term of the contract is 20 years from commencement of operations of the compression facilities and pipeline, and the contract has renewal language. Pricing under the contract is fixed for the first five contract years and variable thereafter. The contract will terminate automatically unless we begin construction of compression facilities by December 2011. 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 32 MMcf/d over the first ten contract years or pay for any deficiencies at the price in effect when the minimum delivery was to have occurred. Based on current prices, we estimate our minimum purchase obligation under the contract to be approximately $28.0 million over the first ten contract years. After the first ten contract years, we may permanently reduce up to 100% of our purchase rate under this contract with six months notice.

Results of operations

Overview

Production has increased in each of the last three years. However, oil and natural gas price volatility has had a significant impact on our revenues and cash flows from operations. Average sales prices and oil and natural gas sales increased by 33% and 40%, respectively, from 2009 to 2010 after having decreased by 46% and 42%, respectively, from 2008 to 2009. In addition, we recorded non-cash pre-tax ceiling test impairments of our oil and natural gas properties of $0, $240.8 million, and $281.4 million in 2010, 2009, and 2008, respectively. As a result of these and other transactions discussed below, we had net income of $33.7 million in 2010 compared to a net loss of $144.3 million and $54.8 million in 2009 and 2008, respectively.


	Year ended December 31,
	2010		2009			2008
Production (MBoe)		8,050		7,638			7,072

Oil and natural gas sales (in thousands)	$	408,561	$	292,387		$	501,761
Net income (loss) (in thousands)	$	33,713	$	(144,318	)	$	(54,750	)

Cash flow from operations (in thousands)	$	167,702	$	98,675		$	145,831

Revenues and production

The following table presents information about our oil and natural gas sales before the effects of commodity derivative settlements:


	Year ended December 31,				Percentage			Year ended December 31,		Percentage
	2010		2009		change			2008		change
Oil and natural gas sales (dollars in thousands)
Oil	$	305,042	$	213,207		43.1	%	$	348,907		(38.9	)%
Natural gas		103,519		79,180		30.7	%		152,854		(48.2	)%

Total	$	408,561	$	292,387		39.7	%	$	501,761		(41.7	)%


Production
Oil (MBbls)		4,093		3,874		5.7	%		3,773		2.7	%
Natural gas (MMcf)		23,742		22,584		5.1	%		19,795		14.1	%

MBoe		8,050		7,638		5.4	%		7,072		8.0	%

Average sales prices (excluding derivative settlements)
Oil per Bbl	$	74.53	$	55.04		35.4	%	$	92.47		(40.5	)%
Natural gas per Mcf	$	4.36	$	3.51		24.2	%	$	7.72		(54.5	)%

Average price per Boe	$	50.75	$	38.28		32.6	%	$	70.95		(46.0	)%

Oil and natural gas revenues increased $116.2 million, or 40%, to $408.6 million during 2010 due to a 33% increase in the average price per Boe, combined with a 5% increase in sales volumes. Oil and natural gas revenues decreased $209.4 million, or 42%, to $292.4 million during 2009 due to a 46% decrease in the average price per Boe, partially offset by an 8% increase in sales volumes.

The relative impact of changes in commodity prices and sales volumes on our oil and natural gas sales before the effects of derivative settlements is shown in the following table:


	Year ended December 31,
	2010 vs. 2009					2009 vs. 2008
(dollars in thousands)	Sales increase		Percentage change in sales			Sales increase (decrease)			Percentage change in sales
Change in oil sales due to:
Prices	$	79,782		37.4	%	$	(145,040	)		(41.6	)%
Production		12,053		5.7	%		9,340			2.7	%

Total increase (decrease) in oil sales	$	91,835		43.1	%	$	(135,700	)		(38.9	)%


Change in natural gas sales due to:
Prices	$	20,279		25.6	%	$	(95,210	)		(62.3	)%
Production		4,060		5.1	%		21,536			14.1	%

Total increase (decrease) in natural gas sales	$	24,339		30.7	%	$	(73,674	)		(48.2	)%

Production volumes by area were as follows (MBoe):


	Year ended December 31,				Percentage			Year ended December 31,		Percentage
	2010		2009		change			2008		change
Enhanced Oil Recovery Project Areas		1,079		920		17.3	%		875		5.1	%
Anadarko Basin Area		2,506		2,152		16.4	%		2,019		6.6	%
Central Oklahoma		1,935		1,902		1.7	%		1,836		3.6	%
Permian Basin Area		1,500		1,625		(7.7	)%		1,116		45.6	%
Other		1,030		1,039		(0.9	)%		1,226		(15.3	)%

Total		8,050		7,638		5.4	%		7,072		8.0	%

Production increased in our EOR project areas due to acquisition and development activities. The increase in production in the Anadarko Basin Area is primarily due to our participation in six Atoka Wash wells, which came online during the first quarter of 2010 and accounted for approximately 4% of our total production during 2010. We also drilled two Cleveland Sand horizontal wells that came online during the first and second quarters of 2010 and accounted for approximately 1% of our total production during 2010.

The decrease in production in the Permian Basin Area during 2010 is primarily due to the decline in production from the Bowdle 47 No. 2, which began selling natural gas in late November 2008 and accounted for approximately 5% and 9% of total production in 2010 and 2009, respectively. We have drilled and completed an offset, the Bowdle 47 No. 4, which came online in late April of 2010 and accounted for approximately 2% of our total production during 2010.

Derivative activities

Our results of operations, financial condition and capital resources are highly dependent upon the prevailing market prices of, and demand for, oil and natural gas. These commodity prices are subject to wide fluctuations and market uncertainties. To mitigate a portion of this exposure, we enter into commodity price swaps, costless collars, and basis protection swaps. Certain commodity price swaps qualified and were designated as cash flow hedges.

Entering into derivative instruments allows us to predict with greater certainty the effective prices we will receive for associated oil and natural gas production. We closely monitor the fair value of our derivative contracts and may elect to settle a contract prior to its scheduled maturity date in order to lock in a gain or loss. Our derivative activities are dynamic to allow us to respond to the volatile commodity markets.

Our realized prices are impacted by realized gains and losses resulting from commodity derivatives contracts. The following table presents information about the effects of derivative settlements, excluding derivative monetizations, on realized prices:


	Year ended December 31,
	2010			2009			2008
Oil (per Bbl):
Before derivative settlements	$	74.53		$	55.04		$	92.47
After derivative settlements	$	71.91		$	56.36		$	71.95
Post-settlement to pre-settlement price		96.5	%		102.4	%		77.8	%

Natural gas (per Mcf):
Before derivative settlements	$	4.36		$	3.51		$	7.72
After derivative settlements	$	6.20		$	5.32		$	7.38
Post-settlement to pre-settlement price		142.2	%		151.6	%		95.6	%

The estimated fair values of our oil and natural gas derivative instruments are provided below. The associated carrying values of these instruments are equal to the estimated fair values.


	As of December 31,
(dollars in thousands)	2010			2009			2008
Derivative assets (liabilities):
Natural gas swaps	$	32,408		$	30,340		$	13,312
Oil swaps		(58,200	)		(68,551	)		111,416
Natural gas collars		—			14,065			21,682
Oil collars		1,509			12,290			57,716
Natural gas basis differential swaps		(5,623	)		(14,964	)		1,618

Net derivative asset (liability)	$	(29,906	)	$	(26,820	)	$	205,744

Effective April 1, 2010, we elected to de-designate all of our commodity derivative contracts that had previously been designated as cash flow hedges and to discontinue hedge accounting prospectively. As a result, all gains and losses from changes in the fair value of our derivative contracts subsequent to March 31, 2010 are recognized immediately in non-hedge derivative gains in the consolidated statement of operations. This can have a significant impact on our results of operations due to the volatility of the underlying commodity prices. Prior to March 31, 2010, a portion of the change in fair value was deferred through other comprehensive income. As of December 31, 2010, accumulated other comprehensive income (loss) (“AOCI”) consists of deferred net gains of $56.4 million ($35.0 million net of tax) related to discontinued cash flow hedges that will be recognized as gains (losses) from oil and natural gas hedging activities through December 2013 as the hedged production is sold.

The effects of derivative activities on our results of operations and cash flows were as follows:


	Year ended December 31,
	2010						2009						2008
(dollars in thousands)	Non-cash fair value adjustment			Cash receipts (payments)			Non-cash fair value adjustment			Cash receipts (payments)			Non-cash fair value adjustment			Cash receipts (payments)
Gain (loss) from oil and natural gas hedging activities:
Oil swaps	$	(25,399	)	$	(5,504	)	$	14,114		$	(2,349	)	$	7,770		$	(73,170	)
Natural gas swaps		1,510			—			7,638			—			4,779			(15,796	)

Gain (loss) from oil and natural gas hedging activities	$	(23,889	)	$	(5,504	)	$	21,752		$	(2,349	)	$	12,549		$	(88,966	)


Non-hedge derivative gains (losses):
Oil swaps and collars	$	(8,660	)	$	(5,225	)	$	(30,791	)	$	7,490		$	80,297		$	(4,258	)
Natural gas swaps and collars		(7,769	)		53,728			9,455			46,100			24,144			3,086
Natural gas basis differential contracts		9,341			(10,110	)		(16,582	)		(5,189	)		1,079			5,970
Derivative monetizations		193			7,097			(111,188	)		111,874			(15,966	)		32,589

Non-hedge derivative gains (losses)	$	(6,895	)	$	45,490		$	(149,106	)	$	160,275		$	89,554		$	37,387

Total gains (losses) from derivative activities	$	(30,784	)	$	39,986		$	(127,354	)	$	157,926		$	102,103		$	(51,579	)

We reclassified into earnings $25.4 million in losses associated with oil derivatives for which hedge accounting has been discontinued, and we made payments on oil hedges of $5.5 million in 2010. In addition, due primarily to an increase in average NYMEX forward strip oil prices as of December 31, 2010 compared to December 31, 2009, combined with high oil prices prevalent during the period, we recognized a non-hedge loss on oil derivatives of $13.9 million in 2010.

Due to the low oil prices prevalent during 2009, we received proceeds from oil derivatives of $5.1 million; however, we recognized non-cash losses on oil derivatives of $16.7 million in 2009 primarily due to the significant improvement in average NYMEX forward strip oil prices as of December 31, 2009 compared to December 31, 2008. This included gains of $14.5 million reclassified into earnings that were associated with derivatives for which hedge accounting was discontinued in 2008.

Due primarily to low natural gas prices prevalent during the periods, we recognized non-hedge gains on natural gas derivatives of $46.0 million and $55.6 million during 2010 and 2009, respectively. In addition, we reclassified into earnings gains of $1.5 million and $7.6 million in 2010 and 2009, respectively, which were associated with derivatives for which hedge accounting was discontinued in 2008.

Due primarily to the high commodity prices prevalent during the first nine months of 2008, we made payments on oil and natural gas derivatives of $77.4 million and $12.7 million, respectively. However, these losses were offset by non-cash gains on oil and natural gas derivatives of $88.1 million and $28.9 million, respectively, which resulted from the decline in the NYMEX forward strip oil and natural gas prices as of December 31, 2008 compared to December 31, 2007.

During 2010, losses on natural gas basis differential contracts were $0.8 million, primarily due to low basis differentials prevalent during the period, partially offset by lower average contractual prices and higher differentials indicated by the forward commodity price curves as of December 31, 2010 compared to December 31, 2009. During 2009, losses on natural gas basis differential contracts were $21.8 million, primarily due to lower differentials indicated by the forward commodity price curves as of December 31, 2009 compared to December 31, 2008. Gains on natural gas basis differential swaps were $7.0 million in 2008, primarily due to high differentials during 2008.

During 2010, we unwound and monetized oil swaps and collars and natural gas collars with original settlement dates from April 2010 through December 2012 for net proceeds of $7.1 million, and we recognized gains of $7.3 million associated with these transactions. During 2009, we monetized natural gas swaps with original settlement dates from May through October of 2009 and oil swaps and collars with original settlement dates from January 2012 through December 2013 for total net proceeds of $111.9 million. As a result of these transactions, gains of $0.7 million were recognized in earnings during 2009, and gains of $81.9 million were deferred through AOCI. During 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. As a result of this monetization, gains of $16.6 million were recognized in earnings, and gains of $17.9 million were deferred through AOCI.

Primarily as a result of the above transactions, total gains on derivative activities recognized in our statements of operations were $9.2 million, $30.6 million and $50.5 million in 2010, 2009 and 2008, respectively.

Lease operating expenses


	Year ended							Year ended
	December 31,				Percentage			December 31,		Percentage
	2010		2009		change			2008		change
Lease operating expenses (in thousands)	$	106,127	$	94,070		12.8	%	$	120,487		(21.9	)%

Lease operating expenses per Boe	$	13.18	$	12.32		7.0	%	$	17.04		(27.7	)%

Lease operating costs are sensitive to changes in demand for field equipment, services, and qualified operational personnel, which is driven by demand for oil and natural gas. However, the timing of changes in operating costs may lag behind changes in commodity prices. Our lease operating expenses increased by 13% from 2009 to 2010 after having decreased by 22% from 2008 to 2009, which is consistent, though not commensurate, with the changes in commodity prices during the same periods.

During 2010, lease operating expenses increased $12.1 million, or $0.86 per Boe, compared to 2009, primarily due to our increased activity combined with the upward pressure on operating and service costs associated with the improvement in commodity prices during 2010. Electricity and fuel costs and workover costs increased by $3.8 million and $1.1 million, respectively, for operated properties from 2009 to 2010.

Due primarily to higher production mostly associated with the Bowdle 47 No. 2 well, the shut-in of uneconomic wells, and our efforts to reduce production costs, lease operating expenses for 2009 decreased by $26.4 million, or $4.72 per Boe, compared to 2008. Per unit expenses were lower for all categories of lease operating expenses due to downward pressure on service costs, labor, and materials resulting from the low commodity prices prevalent throughout 2009. Electricity and fuel costs and workover costs decreased by $4.4 million and $8.3 million, respectively, for operated properties from 2008 to 2009.

Production taxes (which include ad valorem taxes)


	Year ended							Year ended
	December 31,				Percentage			December 31,		Percentage
	2010		2009		change			2008		change
Production taxes (in thousands)	$	26,495	$	20,341		30.3	%	$	33,815		(39.8	)%

Production taxes per Boe	$	3.29	$	2.66		23.7	%	$	4.78		(44.4	)%

Production taxes generally change in proportion to oil and natural gas sales. The increase in production taxes from 2009 to 2010 was primarily due to the 33% increase in average realized prices, combined with a 5% increase in production volumes. The decrease in production taxes from 2008 to 2009 was due primarily to the 46% decrease in average realized prices, partially offset by an 8% increase in production volumes.

Depreciation, depletion and amortization (“DD&A”) and losses on impairment

Year ended

December 31,

Percentage

December 31,

Percentage

2010

2009

change

2008

change

DD&A (in thousands):

Large Accelerated Filer

Accelerated Filer

Non-Accelerated Filer

Smaller Reporting Company