As filed with the Securities and Exchange Commission on April 11, 2013

Registration No.                     

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM S-4

REGISTRATION STATEMENT

UNDER

THE SECURITIES ACT OF 1933

Chaparral Energy, Inc.*

(Exact name of registrant as specified in its charter)

Delaware	1311	73-1590941
(State or other jurisdiction of incorporation or organization)	(Primary Standard Industrial Classification Code Number)	(I.R.S. Employer Identification Number)

701 Cedar Lake Boulevard

Oklahoma City, Oklahoma 73114

(405) 478-8770

(Address, including zip code, and telephone number, including area code, of registrant’s principal executive offices)

David J. Ketelsleger

General Counsel

701 Cedar Lake Boulevard

Oklahoma City, Oklahoma 73114

(405) 478-8770

(Name, address, including zip code, and telephone number, including area code, of agent for service)

Copy to:

Justin L. Jackson, Esq.

Wagner R. Dias da Silva, Esq.

McAfee & Taft A Professional Corporation

Tenth Floor

Two Leadership Square

211 North Robinson

Oklahoma City, Oklahoma 73102

(405) 235-9621

Approximate date of commencement of proposed sale of the securities to the public: As soon as practicable after this registration statement becomes effective.

If the securities being registered on this Form are being offered in connection with the formation of a holding company and there is compliance with General Instruction G, check the following box.  ¨

If this Form is filed to register additional securities for an offering pursuant to Rule 462(b) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering.  ¨

If this Form is a post-effective amendment filed pursuant to Rule 462(d) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering.  ¨

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.

Large accelerated filer	¨	Accelerated filer	¨
Non-accelerated filer	x	Smaller reporting company	¨

If applicable, place an X in the box to designate the appropriate rule provision relied upon in conducting this transaction:

Exchange Act Rule 13e-4(i) (Cross-Border Issuer Tender Offer) ¨

Exchange Act Rule 14-1(d) (Cross-Border Third-Party Tender Offer) ¨

CALCULATION OF REGISTRATION FEE

Title of each class of securities to be registered	Amount to be registered	Proposed maximum offering price per unit	Proposed maximum aggregate offering price	Amount of registration fee
7.625% Senior Notes due 2022	$150,000,000	100%	$150,000,000	$20,460(1)
Guarantees by certain subsidiaries of Chaparral Energy, Inc.*	—	—	—	—        (2)

(1) The registration fee was calculated pursuant to Rule 457(f) under the Securities Act of 1933. For purposes of this calculation, the offering price per note was assumed to be the stated principal amount of each original note that may be received by the registrant in the exchange transaction in which the notes will be offered.

(2) Pursuant to Rule 457(n) under the Securities Act of 1933, no separate fee for the guarantees is payable because the guarantees relate to other securities that are being registered concurrently.

* Includes certain subsidiaries of Chaparral Energy, Inc. identified on the following page.

The registrant hereby amends this registration statement on such date or dates as may be necessary to delay its effective date until the registrant shall file a further amendment which specifically states that this registration statement shall thereafter become effective in accordance with Section 8(a) of the Securities Act of 1933 or until the registration statement shall become effective on such date as the Commission, acting pursuant to said Section 8(a), may determine.

ADDITIONAL SUBSIDIARY GUARANTOR REGISTRANTS

Exact Name of Additional Registrant as Specified in its Charter	State or Other Jurisdiction of Incorporation or Organization	Primary Standard Industrial Classification Code Number
Chaparral Real Estate, L.L.C.(1)	Oklahoma	1311
Chaparral Resources, L.L.C.(1)	Oklahoma	1311
Chaparral CO2, L.L.C.(1)	Oklahoma	1311
Chaparral Energy, L.L.C.(1)	Oklahoma	1311
CEI Acquisition, L.L.C.(1)	Delaware	1311
CEI Pipeline, L.L.C.(1)	Texas	1311
Green Country Supply, Inc.(1)	Oklahoma	1311
Chaparral Exploration, L.L.C.(1)	Delaware	1311
Roadrunner Drilling, L.L.C.(1)	Oklahoma	1311

(1) The address for such Subsidiary Guarantor is 701 Cedar Lake Boulevard, Oklahoma City, Oklahoma 73114.

The information in this prospectus is not complete and may be changed. We may not sell these securities until the registration statement filed with the Securities and Exchange Commission is effective. This prospectus is not an offer to sell these securities and it is not soliciting an offer to buy these securities in any jurisdiction where the offer or sale is not permitted.

Subject to completion, dated April 11, 2013

Prospectus

Offer to Exchange Up to

$150,000,000 of 7.625% Senior Notes Due 2022

that have been registered under the Securities Act of 1933

for

$150,000,000 of 7.625% Senior Notes Due 2022

that have not been registered under the Securities Act of 1933

THE EXCHANGE OFFER WILL EXPIRE AT 5:00 PM, NEW YORK

CITY TIME, ON             , 2013, UNLESS WE EXTEND THE DATE

Terms of the Exchange Offer:

• We are offering to exchange up to $150.0 million aggregate principal amount of registered 7.625% Senior Notes due 2022, which we refer to as the new notes, for any and all of our $150.0 million aggregate principal amount of unregistered 7.625% Senior Notes due 2022, which we refer to as the old notes, that were issued on November 15, 2012.

• We will exchange all outstanding old notes that are validly tendered and not validly withdrawn prior to the expiration of the exchange offer for an equal principal amount of new notes.

• The terms of the new notes are substantially identical to those of the outstanding old notes, except that the transfer restrictions and registration rights relating to the old notes do not apply to the new notes.

• You may withdraw tenders of old notes at any time prior to the expiration of the exchange offer.

• The exchange of new notes for old notes will not be a taxable transaction for U.S. federal income tax purposes.

• We will not receive any cash proceeds from the exchange offer.

• The old notes are, and the new notes will be, guaranteed on a senior unsecured basis by all of our material current and future domestic restricted subsidiaries.

• There is no established trading market for the new notes or the old notes.

• We do not intend to apply for listing of the new notes on any national securities exchange or for quotation through any quotation system.

See “Risk factors” beginning on page 15 for a discussion of certain risks that you should consider prior to tendering your outstanding old notes in the exchange offer.

Neither the Securities and Exchange Commission nor any state securities commission has approved or disapproved of these securities or passed upon the adequacy or accuracy of this prospectus. Any representation to the contrary is a criminal offense.

Each broker-dealer that receives new notes for its own account pursuant to the exchange offer must acknowledge that it will deliver a prospectus in connection with any resale of such new notes. The letter of transmittal states that by so acknowledging and by delivering a prospectus, a broker-dealer will not be deemed to admit that it is an “underwriter” within the meaning of the Securities Act. This prospectus, as it may be amended or supplemented from time to time, may be used by a broker-dealer in connection with resales of new notes received in exchange for old notes where such old notes were acquired by such broker-dealer as a result of market-making activities or other trading activities. We have agreed that, for a period of 180 days after the consummation of the exchange offer, we will make this prospectus available to any broker-dealer for use in connection with any such resale. Please read “Plan of distribution.”             , 2013

Table of contents

	Page
Special cautionary statement regarding forward-looking statements		i
Prospectus summary		1
Risk factors		15
Ratio of earnings to fixed charges		30
Use of proceeds		31
Capitalization		32
Selected historical consolidated financial information		33
Management’s discussion and analysis of financial condition and results of operations		34
Business and properties		57
Management		76
Executive compensation		79
Principal stockholders		91
Certain relationships and related transactions, and director independence		93
Description of certain indebtedness		94
The exchange offer		99
Description of the new notes		108
Certain U.S. federal income tax consequences		151
Certain ERISA considerations		151
Plan of distribution		152
Legal matters		153
Experts		153
Independent petroleum engineers		153
Where you can find more information		153
Glossary of terms		154
Index to financial statements		F-1

This prospectus is part of a registration statement we filed with the Securities and Exchange Commission, referred to in this prospectus as the SEC. In making your decision to participate in the exchange offer, you should rely only on the information contained in this prospectus and in the accompanying letter of transmittal. We have not authorized anyone to provide you with any other information. If you received any unauthorized information, you must not rely on it. We are not making an offer to sell these securities in any state or jurisdiction where the offer is not permitted. You should not assume that the information contained in this prospectus, or any document incorporated by reference into this prospectus, is accurate as of any date other than the date on the front cover of this prospectus or the date of such document incorporated by reference, as the case may be.

THIS PROSPECTUS INCORPORATES IMPORTANT BUSINESS AND FINANCIAL INFORMATION ABOUT OUR COMPANY THAT HAS NOT BEEN INCLUDED IN OR DELIVERED WITH THIS PROSPECTUS. WE WILL PROVIDE WITHOUT CHARGE TO EACH PERSON TO WHOM THIS PROSPECTUS IS DELIVERED, UPON WRITTEN OR ORAL REQUEST, A COPY OF ANY SUCH INFORMATION. REQUESTS FOR SUCH COPIES SHOULD BE DIRECTED TO: CHIEF FINANCIAL OFFICER, CHAPARRAL ENERGY, INC., 701 CEDAR LAKE BOULEVARD, OKLAHOMA CITY, OKLAHOMA 73114; TELEPHONE NUMBER: (405) 478-8770. TO OBTAIN TIMELY DELIVERY, YOU SHOULD REQUEST THE DOCUMENTS AND INFORMATION NO LATER THAN                      , 2013.

Market and industry data

Market data and other statistical information used throughout this prospectus are based on independent industry publications, government publications, reports by market research firms or other published independent sources, including the U.S. Department of Energy. Some data are also based on our good faith estimates. Although we believe these sources are reliable, we have not independently verified the information and cannot guarantee its accuracy and completeness.

SPECIAL CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS

This prospectus includes statements that constitute forward-looking statements within the meaning of the federal securities laws. These statements are subject to risks and uncertainties. These statements may relate to, but are not limited to, information or assumptions about us, our capital and other expenditures, dividends, financing plans, capital structure, cash flow, pending legal and regulatory proceedings and claims, including environmental matters, future economic performance, operating income, cost savings, and management’s plans, strategies, goals and objectives for future operations and growth. These forward-looking statements 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 may relate to the issuance of the new notes and various financial and operational matters, including, among other things:

• benefits, effects or results of the issuance of the new notes;

• operations and results after the issuance of the new notes;

• 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;

• changes 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 in this prospectus under “Risk Factors,” those 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;

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• 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.

Undue reliance should not be placed on forward-looking statements, which speak only as of the date of this prospectus. A description of certain risks relating to us and our business appears under the heading “Risk Factors.”

All subsequent written and oral forward-looking statements attributable to us or any person acting on our behalf are expressly qualified in their entirety by the cautionary statements contained or referred to in this section and any other cautionary statements that may accompany such forward-looking statements. We do not undertake any obligation to release publicly any revisions to these forward-looking statements to reflect events or circumstances after the date of this document or to reflect the occurrence of unanticipated events, unless the federal securities laws require us to do so.

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PROSPECTUS SUMMARY

This summary highlights information contained elsewhere in this prospectus. Because it is a summary, it does not contain all of the information that may be important to you or that you should consider before making a decision to participate in the exchange offer. You should read the entire prospectus carefully, including the section entitled “Risk Factors” and the financial statements and related notes to those financial statements. As used in this prospectus, “Chaparral,” “Company,” “we,” “our,” “ours,” and “us” refer to Chaparral Energy, Inc. and its subsidiaries on a consolidated basis, except where otherwise indicated or the context otherwise requires. Investors who are not familiar with oil and natural gas industry terms used in this prospectus should refer to the “Glossary of Terms” section set forth in this prospectus.

Our Business

We are a growing independent oil and natural gas production and exploitation company. Since our inception in 1988, we have increased reserves and production primarily through property acquisitions and development activities. Our core operations consist of drilling for and production of oil and natural gas from conventional and unconventional reservoirs as well as a focus on tertiary operations through enhanced oil recovery (“EOR”) projects utilizing CO₂ and polymer in the Mid-Continent and Permian Basin areas. We maintain a portfolio of proved and unproved reserves, development and exploratory drilling opportunities, and EOR projects. Starting in 2011, we began to redirect our capital expenditures from the drilling of vertical wells to the drilling of horizontal wells in repeatable resource plays and increased our level of expenditures on EOR projects.

As of December 31, 2012, we had estimated proved reserves of 146.1 MMBoe with a PV-10 value of approximately $2.1 billion. These estimated proved reserves included 29.5 MMBoe of EOR reserves. Our reserves were 65% proved developed and 65% crude oil. For the year ended December 31, 2012, our net average daily production was 25.0 MBoe, our estimated reserve life was approximately 16 years, and our oil and natural gas revenues were $509.5 million . We set forth our definition of PV-10 value (a non-GAAP measure) and a reconciliation of the standardized measure of discounted future net cash flows to PV-10 value elsewhere in this prospectus.

From 2003 to 2012, our proved reserves and production grew at a compounded annual growth rate of 12% and 15%, respectively. During this period, we have grown primarily through a combination of developmental drilling and a disciplined strategy of acquiring proved oil and natural gas reserves, followed by exploitation activities and the acquisition of additional interests in or near these acquired properties. We have typically pursued properties in the second half of their life with stable production, shallow decline rates and with particular producing trends and characteristics indicative of production or reserve enhancement opportunities. Since 2011, we have reduced the amount of costs incurred for proved property acquisitions and spent more on acquisition of leasehold acreage and exploration costs in resource plays with repeatable drilling opportunities. In 1993, we began acquiring properties with CO₂ EOR potential, and we have initiated CO₂ injection in 9 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 long-term growth to come from the development of our CO₂ EOR operations, with our near term growth coming from drilling activities.

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

	Proved reserves as of December 31, 2012											Average daily production (MBoe per day) Year ended December 31, 2012		Average daily production (MBoe per day) Quarter  ended December 31, 2012
	Oil (MBbls)(1)		Natural gas (MMcf)		Total (MBoe)		Percent of total MBoe			PV-10 value ($MM)
Enhanced Oil Recovery Project Areas		44,182		392		44,247		30.3	%	$	705.2		3.7		4.0
Mid-Continent Area		44,788		175,760		74,081		50.7	%		1,043.0		15.6		17.6
Permian Basin Area		8,731		47,040		16,571		11.3	%		185.4		3.3		3.5
Other		5,542		33,923		11,196		7.7	%		135.1		2.4		2.1
Total		103,243		257,115		146,095		100.0	%	$	2,068.7		25.0		27.2

(1) Includes natural gas liquids.

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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, 2012, we owned interests in 8,243 gross (2,843 net) producing wells and we operated wells representing approximately 85% of our proved reserves. The high proportion of reserves in our operated properties allows us to exercise more control over expenses, capital allocations and the timing of development and exploitation activities in our fields.

Business Strategy

We are positioned to grow our reserves and production profitably through our oil focused drilling activities, primarily in our repeatable resource plays, in the near term and through our CO₂ EOR projects in the long term. From 2003 to 2012, we have grown proved reserves and production by a compounded annual growth rate of 12% and 15%, 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 383% per year from 2003 through 2012. We replaced approximately 156% of our production in 2012.

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, 2012, we operated properties comprising approximately 85% of our proved reserves. We also strive to minimize commodity price risk through our financial hedging program. The principal elements of our strategy are described further below.

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

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

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

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

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

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

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

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

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

Hedge production to stabilize cash flow. Our long-lived reserves provide us with relatively predictable production. To protect cash flows that we use for on-going operations and for capital investments, 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.

Based on our year-end proved reserves estimated using SEC pricing as of December 31, 2012, we had derivative contracts in place for approximately 21% and 63%, respectively, of our estimated oil and natural gas liquids and natural gas production through 2014. During 2012, we received $11.8 million and $25.5 million on the net settlement of our derivative oil and natural gas contracts, respectively. During 2011 we paid $57.6 million on the net settlement of our derivative oil contracts and received $34.1 million on the net settlement of our derivative natural gas contracts through a period of increasing oil prices and decreasing natural gas prices. During 2010, we received net derivative settlements of $40.0 million which included proceeds from early derivative monetizations of $7.1 million.

Risk Factors

Our business and our business strategy are subject to a number of material risks described in “Risk factors” beginning on page 15, including:

• the level of consumer demand for oil and natural gas;

• the domestic and foreign supply of oil and natural gas;

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

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

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

• domestic and foreign governmental regulations and taxes;

• the supply of CO₂;

• the price and availability of alternative fuel sources;

• weather conditions;

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• financial and commercial market uncertainty;

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

• worldwide economic conditions.

You should consider carefully these and other risks described in “Risk factors” before deciding to participate in the exchange offer.

Our Company

Chaparral Energy, Inc. is a Delaware corporation. Our principal executive offices are located at 701 Cedar Lake Boulevard, Oklahoma City, OK 73114 and our telephone number at that address is (405) 478-8770. Our web site is located at http://www.chaparralenergy.com. The information on our web site is not part of this prospectus.

Ownership Structure

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Ratio of earnings to fixed charges

The following table sets forth our consolidated ratio of earnings to fixed charges for the periods shown:

	Year ended December 31,
	2012		2011		2010		2009			2008
Ratio of earnings to fixed charges		2.0x		1.8x		1.7x		N/A	(1)		N/A	(1)

(1) For the years ended December 31, 2009 and 2008, fixed charges exceeded earnings by approximately $241.4 million and $92.2 million, respectively.

For purposes of this computation, “earnings” consist of income (loss) from continuing operations before income taxes plus fixed charges (excluding capitalized interest, but including amortization of amounts previously capitalized). “Fixed charges” include interest expensed, capitalized interest, accretion of debt discounts, and amortization of debt issuance costs.

THE EXCHANGE OFFER

On November 15, 2012, we completed a private offering of the old notes. As part of the sale of the old notes, we entered into a registration rights agreement with the initial purchasers of the old notes in which we agreed, among other things, to deliver this prospectus to you and to use our reasonable best efforts to complete the exchange offer within 270 days of the issue date of the old notes. The following is a summary of the exchange offer.

Old Notes	7.625% Senior Notes due November 15, 2022, which were issued on November 15, 2012.
New Notes	7.625% Senior Notes due November 15, 2022. The terms of the new notes are substantially identical to those terms of the outstanding old notes, except that the transfer restrictions and registration rights relating to the old notes do not apply to the new notes.
Exchange Offer	We are offering to exchange up to $150.0 million aggregate principal amount of our new notes that have been registered under the Securities Act for an equal amount of our outstanding old notes that have not been registered under the Securities Act to satisfy our obligations under the registration rights agreement.
	The new notes will evidence the same debt as the old notes and will be issued under and be entitled to the benefits of the same indenture that governs the old notes. Holders of the old notes do not have any appraisal or dissenter rights in connection with the exchange offer. Because the new notes will be registered, the new notes will not be subject to transfer restrictions, and holders of old notes that have tendered and had their old notes accepted in the exchange offer will have no registration rights.
Expiration Date	The exchange offer will expire at 5:00 p.m., New York City time, on             , 2013, unless we decide to extend it.
Conditions to the Exchange Offer	The exchange offer is subject to customary conditions, which we may waive. Please read “The exchange offer—Conditions to the exchange offer” for more information regarding the conditions to the exchange offer.

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Procedures for Tendering Old Notes	Unless you comply with the procedures described under the caption “The exchange offer—Procedures for tendering—Guaranteed delivery,” you must do one of the following on or prior to the expiration of the exchange offer to participate in the exchange offer:
	•     tender your old notes by sending the certificates for your old notes, in proper form for transfer, a properly completed and duly executed letter of transmittal, with any required signature guarantees, and all other documents required by the letter of transmittal, to Wells Fargo Bank, National Association, as registrar and exchange agent, at the address listed under the caption “The exchange offer—Exchange agent;” or •     tender your old notes by using the book-entry transfer procedures described below and transmitting a properly completed and duly executed letter of transmittal, with any required signature guarantees, or an agent’s message instead of the letter of transmittal, to the exchange agent. In order for a book-entry transfer to constitute a valid tender of your old notes in the exchange offer, Wells Fargo Bank, National Association, as registrar and exchange agent, must receive a confirmation of book-entry transfer of your old notes into the exchange agent’s account at The Depository Trust Company prior to the expiration of the exchange offer. For more information regarding the use of book-entry transfer procedures, including a description of the required agent’s message, please read the discussion under the caption “The exchange offer—Procedures for tendering—Book-entry transfer.”
Guaranteed Delivery Procedures	If you are a registered holder of the old notes and wish to tender your old notes in the exchange offer, but
	•     the old notes are not immediately available, •     time will not permit your old notes or other required documents to reach the exchange agent before the expiration of the exchange offer, or •     the procedure for book-entry transfer cannot be completed prior to the expiration of the exchange offer,
	then you may tender old notes by following the procedures described under the caption “The exchange offer—Procedures for tendering—Guaranteed delivery.”
Special Procedures for Beneficial Owners	If you are a beneficial owner whose old notes are registered in the name of a broker, dealer, commercial bank, trust company or other nominee and you wish to tender your old notes in the exchange offer, you should promptly contact the person in whose name the old notes are registered and instruct that person to tender on your behalf.
	If you wish to tender in the exchange offer on your own behalf, prior to completing and executing the letter of transmittal and delivering the certificates for your old notes, you must either make appropriate arrangements to register ownership of the old notes in your name or obtain a properly completed bond power from the person in whose name the old notes are registered.
Withdrawal; Non-Acceptance	You may withdraw any old notes tendered in the exchange offer at any time prior to 5:00 p.m., New York City time, on             , 2013. If we decide for any reason not to accept any old notes tendered for exchange, the old notes will be returned to the registered holder at our expense promptly after the expiration or termination of the exchange offer. In the case of old notes tendered by book-entry transfer into the exchange agent’s account at The Depository Trust Company, any withdrawn or unaccepted old notes will be credited to the tendering holder’s account at The Depository Trust Company. For further information regarding the withdrawal of tendered old notes, please read “The exchange offer—Withdrawal rights.”

6

U.S. Federal Income Tax Considerations	We believe the exchange of new notes for old notes in the exchange offer will not be a taxable event for U.S. federal income tax purposes. Please read the discussion under the caption “Certain U.S. federal income tax consequences” for more information regarding the tax consequences to you of the exchange offer.
Use of Proceeds	The issuance of the new notes will not provide us with any new proceeds. We are making this exchange offer solely to satisfy our obligations under the registration rights agreement.
Fees and Expenses	We will pay all of our expenses incident to the exchange offer.
Resales of New Notes	Based on interpretations by the staff of the SEC, as set forth in no-action letters issued to third parties that are not related to us, we believe that the new notes you receive in the exchange offer may be offered for resale, resold or otherwise transferred by you without compliance with the registration and prospectus delivery provisions of the Securities Act so long as:
	•    the new notes are being acquired in the ordinary course of business; •    you are not participating, do not intend to participate, and have no arrangement or understanding with any person to participate in the distribution of the new notes issued to you in the exchange offer; •    you are not our affiliate; and •    you are not a broker-dealer tendering old notes acquired directly from us for your account.
	The SEC has not considered this exchange offer in the context of a no-action letter, and we cannot assure you that the SEC would make similar determinations with respect to this exchange offer. If any of these conditions are not satisfied, or if our belief is not accurate, and you transfer any new notes issued to you in the exchange offer without delivering a resale prospectus meeting the requirements of the Securities Act or without an exemption from registration of your new notes from those requirements, you may incur liability under the Securities Act. We will not assume, nor will we indemnify you against, any such liability. Each broker-dealer that receives new notes for its own account in exchange for old notes, where the old notes were acquired by such broker-dealer as a result of market-making or other trading activities, must acknowledge that it will deliver a prospectus in connection with any resale of such new notes. Please read “Plan of distribution.”
	Please read “The exchange offer—Resales of new notes” for more information regarding resales of the new notes.
Consequences of Not Exchanging Your Old Notes	If you do not exchange your old notes in this exchange offer, you will no longer be able to require us to register your old notes under the Securities Act, except in the limited circumstances provided under the registration rights agreement. In addition, you will not be able to resell, offer to resell or otherwise transfer your old notes unless we have registered the old notes under the Securities Act, or unless you resell, offer to resell or otherwise transfer them under an exemption from the registration requirements of, or in a transaction not subject to, the Securities Act.
	For information regarding the consequences of not tendering your old notes and our obligation to file a registration statement, please read “The exchange offer—Consequences of failure to exchange outstanding securities” and “Description of the new notes.”

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Exchange Agent	Wells Fargo Bank, National Association has been appointed as the exchange agent for the exchange offer. All executed letters of transmittal and any other required documents should be directed to the exchange agent at the address or facsimile number set forth below. Questions and requests for assistance, requests for additional copies of this prospectus or of the letter of transmittal and requests for notices of guaranteed delivery should be directed to the exchange agent addressed as follows:
	WELLS FARGO BANK, NATIONAL ASSOCIATION
	By Facsimile for Eligible Institutions: (612) 667-6282
	By Registered or Certified Mail: Wells Fargo Bank, National Association, Corporate Trust Operations, MAC N9303-121, P.O. Box 1517, Minneapolis, MN 55480
	By Overnight Delivery or Regular Mail: Wells Fargo Bank, National Association, Corporate Trust Operations, Sixth and Marquette, MAC N9303-121, Minneapolis, MN 55479
	By Hand Delivery: Wells Fargo Bank, National Association, 12th Floor—Northstar East Building, Corporate Trust Operations, 608 Second Avenue South, Minneapolis, MN 55402
	Confirm By Telephone or for Information: (800) 344-5128

8

Description of the new notes

The terms of the new notes and those of the outstanding old notes are substantially identical, except that the transfer restrictions and registration rights relating to the old notes do not apply to the new notes. As a result, the new notes will not bear legends restricting their transfer and will not have the benefit of the registration rights and special interest provisions contained in the old notes. The new notes represent the same debt as the old notes for which they are being exchanged. Both the old notes and the new notes are governed by the same indenture.

The following summary contains basic information about the new notes and is not intended to be complete. For a more complete understanding of the new notes, please refer to the section in this prospectus entitled “Description of the new notes.”

Issuer	Chaparral Energy, Inc.
Notes Offered	$150,000,000 aggregate principal amount 7.625% senior notes due 2022 (the “new notes”). The new notes will be issued under the same indenture under which the old notes were issued and under which we previously issued $400,000,000 aggregate principal amount of the 7.625% senior notes due 2022 on May 2, 2012 (the “existing notes”) and together with the old notes and the new notes, the “notes”).
Interest	The new notes will accrue interest from November 15, 2012 at the rate of 7.625% per year. Interest on the new notes will be payable semi-annually in arrears on each May 15 and November 15, commencing on May 15, 2013.
Maturity	November 15, 2022.
Guarantees	Each of our existing and future material restricted domestic subsidiaries will guarantee the new notes on a senior basis.
Ranking	The new notes and the guarantees thereof will be senior unsecured obligations of us and the guarantors, will rank equal in right of payment with all of our existing and future senior obligations, including our senior secured revolving credit facility and our existing senior notes, senior in right of payment to any of our existing and future obligations that are expressly subordinated thereto, will be effectively subordinated to borrowings and other obligations under our senior secured revolving credit facility to the extent of the value of the collateral securing such obligations and structurally subordinated to all existing and future indebtedness and other liabilities of any subsidiary that is not a guarantor of the new notes.
	As of April 11, 2013, we and the guarantors had approximately $1,346.4 million of total debt outstanding on a consolidated basis, of which:
	•     $95.8 million was senior secured indebtedness, and we had committed to borrow an additional $20.0 million under our senior secured revolving credit facility, which will be funded on April 16, 2013; and •     $1,250.6 million of senior unsecured indebtedness, consisting of the notes and the existing senior notes.
Optional Redemption	We may redeem the new notes, in whole or in part, at any time on or after May 15, 2017, at a redemption price equal to 100% of the principal amount thereof, plus a premium declining ratably to par and accrued and unpaid interest to the redemption date. The redemption prices and applicable premium are described under “Description of the New Notes—Optional Redemption.”
	In addition, prior to May 15, 2017, we may redeem all or a portion of the new notes at a redemption price equal to 100% of the principal amount thereof, plus a “make-whole” premium to the redemption price on May 15, 2017 and accrued and unpaid interest to the redemption date.

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	At any time before May 15, 2015, we may redeem up to 35% of the aggregate principal amount of the new notes issued under the indenture governing the new notes with the net cash proceeds of one or more qualified equity offerings at a redemption price equal to 107.625% of the principal amount of the new notes to be redeemed, plus accrued and unpaid interest to the redemption date, provided that:
	•     at least 65% of the aggregate principal amount of the new notes remains outstanding immediately after the occurrence of such redemption; and •     such redemption occurs within 90 days of the date of the closing of any such qualified equity offering.
	If certain transactions that would constitute a change of control occur on or prior to June 1, 2013, we may redeem all, but not less than all, of the new notes at a redemption price equal to 110.000% of the principal amount of the new notes plus accrued and unpaid interest to the redemption date.
Change of Control	Upon a change of control (as defined in the indenture governing the notes), if we do not redeem the new notes, each holder of new notes will be entitled to require us to purchase all or a portion of its new notes at a purchase price equal to 101% of the principal amount thereof, plus accrued and unpaid interest. Our ability to purchase the new notes upon a change of control will be limited by the terms of our debt agreements, including our senior secured revolving credit facility and the indentures governing our existing senior notes. We cannot assure you that we will have the financial resources to purchase the new notes in such circumstances. See “Description of the New Notes—Change of Control.”
Asset Sales	If we sell assets under certain circumstances, we will be required to make an offer to purchase the new notes at their face amount, plus accrued and unpaid interest to the purchase date. See “Description of the New Notes—Certain Covenants—Limitation on Sales of Assets and Subsidiary Stock.”
Certain Covenants	The indenture governing the new notes contains covenants that, among other things, limit our ability and the ability of certain of our subsidiaries to:
	•     incur additional indebtedness; •     pay dividends or repurchase or redeem capital stock; •     make certain investments; •     incur liens; •     enter into certain types of transactions with our affiliates; and •     sell assets or consolidate or merge with or into other companies.
	These and other covenants that are contained in the indenture governing the new notes are subject to important exceptions and qualifications, which are described under “Description of the New Notes—Certain Covenants.”
	Certain of these covenants will be suspended if the new notes are assigned an investment grade rating by both Standard & Poor’s Rating Service and Moody’s Investor Services, Inc. and no default has occurred and is continuing. If either rating on the new notes should subsequently decline to below investment grade, or a default occurs, the suspended covenants will be reinstated. See “Description of the New Notes—Certain Covenants.”
No Prior Market	While the new notes will generally be freely transferable, the new notes are new issues of securities and there is currently no established market for them. Accordingly, there can be no assurance as to the development or liquidity of any market for the new notes. We do not intend to make a trading market in the new notes after the exchange offer.

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SUMMARY HISTORICAL CONSOLIDATED FINANCIAL INFORMATION

You should read the following summary historical consolidated financial information in connection with the financial statements and related notes included in this prospectus, as well as the “Management’s Discussion and Analysis of Financial Condition and Results of Operations” section included in this prospectus. The financial data as of and for each of the five years ended December 31, 2012 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,
(in thousands)	2012			2011			2010			2009			2008
Operating results data:
Revenues
Oil and natural gas sales	$	509,503		$	530,041		$	408,561		$	292,387		$	501,761
Gain (loss) from oil and natural gas hedging activities		46,746			(27,452	)		(29,393	)		19,403			(76,417	)
Other revenues		—			4,070			4,127			2,864			8,735
Total revenues		556,249			506,659			383,295			314,654			434,079
Costs and expenses
Lease operating		130,960			121,420			106,127			94,070			120,487
Production tax		32,003			34,321			26,495			20,341			33,815
Depreciation, depletion and amortization		169,307			146,083			109,503			104,193			101,026
Loss on impairment of oil & natural gas properties		—			—			—			240,790			281,393
Loss on impairment of other assets		2,000			—			4,150			—			2,900
General and administrative		49,812			42,056			29,915			23,741			22,370
Litigation settlement		—			—			—			2,928			—
Other expenses		—			3,448			3,148			1,957			7,150
Total costs and expenses		384,082			347,328			279,338			488,020			569,141
Operating income (loss)		172,167			159,331			103,957			(173,366	)		(135,062	)
Non-operating income (expense)
Interest expense		(98,402	)		(96,720	)		(81,370	)		(90,102	)		(86,038	)
Non-hedge derivative gains		49,685			34,408			38,595			11,169			126,941
Loss on extinguishment of debt		(21,714	)		(20,592	)		(2,241	)		—			—
Financing costs, net of termination fee		—			—			(1,812	)		(2,169	)		2,100
Other income		504			1,545			387			13,921			1,394
Net non-operating income (expense)		(69,927	)		(81,359	)		(46,441	)		(67,181	)		44,397
Income (loss) from continuing operations before income taxes		102,240			77,972			57,516			(240,547	)		(90,665	)
Income tax expense (benefit)		37,837			35,924			23,803			(89,777	)		(34,976	)
Income (loss) from continuing operations		64,403			42,048			33,713			(150,770	)		(55,689	)
Income from discontinued operations, net of related taxes		—			—			—			6,452			939
Net income (loss)	$	64,403		$	42,048		$	33,713		$	(144,318	)	$	(54,750	)
Cash flow data:
Net cash provided by operating activities	$	192,000		$	259,616		$	167,702		$	98,675		$	145,831
Net cash provided by (used in) investing activities		(423,246	)		(324,998	)		(264,172	)		21,904			(262,905	)
Net cash provided by (used in) financing activities		226,476			44,860			78,164			(99,274	)		157,499
Financial position data:
Cash and cash equivalents	$	29,819		$	34,589		$	55,111		$	73,417		$	52,112
Total assets		2,007,552			1,669,733			1,529,292			1,353,920			1,712,836
Total debt		1,293,402			1,034,573			962,087			1,177,007			1,271,589
Retained earnings (accumulated deficit)		17,186			(47,217	)		(89,265	)		(122,978	)		21,340
Accumulated other comprehensive income, net of income taxes		23,223			51,846			34,974			17,618			82,133
Total stockholders’ equity (deficit)		462,857			424,013			363,557			(4,433	)		204,400

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Non-GAAP Financial Measure and Reconciliation—PV-10 Value

PV-10 value is a non-GAAP measure that differs from the standardized measure of discounted future net cash flows in that PV-10 value is a pre-tax number, while the standardized measure of discounted future net cash flows is an after-tax number. 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,
(in thousands)	2012			2011			2010
PV-10 value	$	2,068,620		$	2,309,089		$	1,770,061
Present value of future income tax discounted at 10%		(544,939	)		(711,177	)		(534,035	)
Standardized measure of discounted future net cash flows	$	1,523,681		$	1,597,912		$	1,236,026

Summary Reserve Information

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, 2012, 2011, and 2010 were prepared by Cawley, Gillespie & Associates, Inc. (50%, 50%, and 52% of PV-10 value, respectively) and Ryder Scott Company, L.P. (34%, 34%, and 31% of PV-10 value, respectively). Our internal engineering staff has prepared a report of estimated proved reserves on our remaining smaller value properties (16%, 16%, and 17% of PV-10 value in 2012, 2011, and 2010, respectively).

	As of December 31,
	2012			2011			2010
Estimated proved reserve volumes:
Oil (Mbbls)(1)		103,243			100,380			93,412
Natural gas (MMcf)		257,115			335,280			335,220
Oil equivalent (MBoe)		146,095			156,260			149,282
Proved developed reserve percentage		65	%		64	%		66	%
Estimated proved reserve values (in thousands):
Future net revenue	$	4,780,316		$	5,473,678		$	4,110,844
PV-10 value	$	2,068,620		$	2,309,089		$	1,770,061
Standardized measure of discounted future net cash flows	$	1,523,681		$	1,597,912		$	1,236,026
Oil and natural gas prices:(2)
Oil price (per Bbl)(1)	$	94.71		$	96.19		$	79.43
Natural gas price (per Mcf)	$	2.76		$	4.11		$	4.38
Estimated reserve life in years(3)		16.0			18.1			18.5

(1) Includes natural gas liquids.

(2) Prices were based upon the average first day of the month prices for each month during the respective year.

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

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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,
(in thousands)	2012			2011			2010
Property acquisition costs
Proved properties	$	1,108		$	1,024		$	32,458
Unproved properties		46,895			15,795			9,062
Total acquisition costs		48,003			16,819			41,520
Development costs		409,429			250,182			251,564
Exploration costs(1)		54,432			57,016			34,180
Total	$	511,864		$	324,017		$	327,264
Annual reserve replacement ratio(2)		156	%		169	%		247	%

(1) Includes $52.2 million, $33.0 million, and $16.7 million of EOR costs in 2012, 2011 and 2010, respectively.

(2) 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 15 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,
	2012						2011						2010
	Reserves replaced			Percent of total			Reserves replaced			Percent of total			Reserves replaced			Percent of total
Purchases of minerals in place		1	%		0.1	%		5	%		2.6	%		52	%		21.2	%
Extensions and discoveries		146	%		94.0	%		152	%		90.2	%		138	%		55.7	%
Improved recoveries		9	%		5.9	%		12	%		7.2	%		57	%		23.1	%
Total		156	%		100.0	%		169	%		100.0	%		247	%		100.0	%

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Summary Historical Production and Sales Data

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,
	2012		2011		2010
Production:(1)
Oil (MBbls)(2)		5,812		5,048		4,093
Natural gas (MMcf)		19,834		21,642		23,742
Combined (MBoe)		9,118		8,655		8,050
Average daily production:
Oil (Bbls)(2)		15,880		13,830		11,214
Natural gas (Mcf)		54,191		59,293		65,047
Combined (Boe)		24,912		23,712		22,055
Average prices (excluding derivative settlements):
Oil (per Bbl)(2)	$	78.65	$	87.52	$	74.53
Natural gas (per Mcf)	$	2.64	$	4.08	$	4.36
Combined (per Boe)	$	55.88	$	61.24	$	50.75
Average costs per Boe:
Lease operating expenses	$	14.36	$	14.03	$	13.18
Production taxes	$	3.51	$	3.97	$	3.29
Depreciation, depletion, and amortization	$	18.57	$	16.88	$	13.60
General and administrative	$	5.46	$	4.86	$	3.72

(1) The North Burbank Unit is the only field that contained 15% or more of our total proved reserve volumes at December 31, 2012. Production from this Unit, all of which was oil, was 492 MBbls, 531 MBbls, and 509 MBbls of our net production during 2012, 2011, and 2010, respectively.

(2) Includes natural gas liquids.

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RISK FACTORS

You should carefully consider the risk factors set forth below as well as the other information contained in this prospectus before deciding to participate in the exchange offer. Any of the following risks could materially and adversely affect our business, financial condition or results of operations. The risks described below are not the only risks facing us. Additional risks and uncertainties not currently known to us or those we currently deem to be immaterial may also materially adversely affect our business, financial condition, or results of operations. When we use the term “notes” in this prospectus, unless the context requires otherwise, the term includes the old notes and the new notes.

Risks Related to the Exchange Offer

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

We will only issue new notes in exchange for old notes that you timely and properly tender. Therefore, you should allow sufficient time to ensure timely delivery of the old notes and you should carefully follow the instructions on how to tender your old notes. Neither we nor the exchange agent is required to tell you of any defects or irregularities with respect to your tender of old notes. Please read “The Exchange Offer—Procedures for Tendering” and “Description of the New Notes.”

If you do not exchange your old notes for new notes in the exchange offer, you will continue to be subject to the restrictions on transfer of your old notes described in the legend on the certificates for your old notes. In general, you may only offer or sell the old notes if they are registered under the Securities Act and applicable state securities laws, or offered and sold under an exemption from these requirements. We do not plan to register any sale of the old notes under the Securities Act. For further information regarding the consequences of tendering your old notes in the exchange offer, please read “The Exchange Offer—Consequences of Failure to Exchange Outstanding Securities.”

You may find it difficult to sell your new notes.

The new notes will not be listed on any securities exchange. Because there is no public market for the new notes, you may not be able to resell them.

We cannot assure you that an active market will exist for the new notes or that any trading market that does develop will be liquid. If an active market does not develop or is not maintained, the market price and liquidity of our new notes may be adversely affected. If a market for the new notes develops, they may trade at a discount from their initial offering price. The trading market for the new notes may be adversely affected by:

• changes in the overall market for non-investment grade securities;

• changes in our financial performance or prospects;

• the financial performance or prospects for companies in our industry generally;

• the number of holders of the notes;

• changes in the credit ratings assigned by independent rating agencies;

• the interest of securities dealers in making a market for the notes; and

• prevailing interest rates and general economic conditions.

Historically, the market for non-investment grade debt has been subject to substantial volatility in prices. The market for the new notes, if any, may be subject to similar volatility. Prospective investors in the new notes should be aware that they may be required to bear the financial risks of such investment for an indefinite period of time.

Some holders who exchange their old notes may be deemed to be underwriters.

If you exchange your old notes in the exchange offer for the purpose of participating in a distribution of the new notes, you may be deemed to have received restricted securities and, if so, will be required to comply with the registration and prospectus delivery requirements of the Securities Act in connection with any resale transaction.

15

Risks Related to Our Business

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:

• the level of consumer demand for oil and natural gas;

• the domestic and foreign supply of oil and natural gas;

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

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

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

• domestic and foreign governmental regulations and taxes;

• the supply of CO₂;

• the price and availability of alternative fuel sources;

• weather conditions;

• financial and commercial market uncertainty;

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

• 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, our existing senior notes and the notes being offered, or be unable to make planned capital expenditures.

Price declines could cause 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 cost of unproved properties not being amortized. 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.

Oil and natural gas prices are 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

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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 prospectus 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 a twelve-month average price, calculated as the unweighted arithmetic average of the first-day-of-the-month price for each month within the twelve-month period prior to the end of the reporting period unless prices are defined by contractual arrangements, excluding 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, 2012 reserve report used prices of $2.76 per Mcf for natural gas and $94.71 per Bbl for oil.

A significant portion of total proved reserves as of December 31, 2012 are undeveloped, and those reserves may not ultimately be developed.

As of December 31, 2012, approximately 35% of our estimated proved reserves (by volume) were undeveloped. These reserve estimates reflect our plans to make significant capital expenditures to convert our proved undeveloped reserves into proved developed reserves including approximately $749 million during the five years ending in 2017. You should be aware that actual development costs may exceed estimates, development may not occur as scheduled and results may not be as estimated. If we choose not to develop our proved undeveloped reserves, or if we are not otherwise able to successfully develop them, we will be required to remove the associated volumes from our reported proved reserves. In addition, under the SEC’s reserve reporting rules, proved undeveloped reserves generally may be booked only if they relate to wells scheduled to be drilled within five years of the date of booking. We may be required to write off any reserves that are not developed within this five-year time frame unless such reported reserves are otherwise exempted from the SEC’s five-year reporting rules.

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

As of December 31, 2012, 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, 2012, undeveloped reserves comprised 49%, 43%, and 55%, respectively, of the total estimated proved reserves of our North Burbank Unit, Camrick Area Units, and Farnsworth Unit, respectively. As of December 31, 2012, we expect to incur future development costs of $229.4 million over the next 11 years at our North Burbank Unit, $123.3 million over the next 15 years at our Camrick Area Units, and $120.7 million over the next 12 years at our Farnsworth Unit to fully develop these reserves. Together, these fields encompass 50.6% of our total estimated future development costs of $934.7 million related to proved undeveloped reserves as of December 31, 2012. 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.

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The polymer reserves at our North Burbank Unit accounted for 14.1 MMBoe, or approximately 10% of our estimated proved reserves as of December 31, 2012. 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, 2012. 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 MMBoe proved reserves attributable to our 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:

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

• 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 35% of our total estimated proved reserves (by volume) at December 31, 2012 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, 2012 reserve estimates reflect that our production rate on current proved developed producing reserve properties will decline at annual rates of approximately 19%, 14%, and 12% 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 canceled as a result of numerous factors, including:

• unexpected drilling conditions;

• title problems;

• pressure or lost circulation in formations;

• equipment failures or accidents;

• adverse weather conditions;

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• compliance with environmental and other governmental requirements; and

• 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:

• land use restrictions;

• drilling bonds and other financial responsibility requirements;

• spacing of wells;

• reporting on emissions of greenhouse gases;

• permitting of emissions of greenhouse gases and other regulated air pollutants;

• unitization and pooling of properties;

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

• well stimulation processes;

• produced water disposal;

• CO₂ pipeline requirements;

• safety precautions;

• operational reporting; and

• taxation.

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

• personal injuries;

• property and natural resource damages;

• oil spills and releases or discharges of hazardous materials;

• well reclamation costs;

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

• other environmental damages; and

• additional reporting permitting or other issues arising from emissions of greenhouse gases and other regulated air pollutants

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 air pollutant 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

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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:

• timing and amount of capital expenditures;

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

• financial resources;

• inclusion of other participants in drilling wells; and

• 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:

• injury or loss of life;

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

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• pollution or other environmental damage;

• clean-up responsibilities;

• regulatory investigations and administrative, civil and criminal penalties; and

• 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:

• the uncertainties in estimating clean up costs;

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

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

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

• 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.

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, 2012, we had entered into swaps for 25,200 BBtu of our natural gas production for 2013 through 2014 at average monthly prices ranging from $3.85 to $4.46 per MMBtu of natural gas. As of December 31, 2012, we had entered into swaps and three way collars for 1,020 MBbls and 5,030 MBbls, respectively, of our crude oil and natural gas liquids production for 2013 through 2014. These swaps had average monthly prices ranging from $96.65 to $96.87 per Bbl of oil, and the three way collars had a weighted average call price, put price, and additional put price of $111.33, $98.00, and $77.37 per Bbl, respectively. As of December 31, 2012, we had basis protection swaps for 30,490 BBtu of our natural gas production for 2013 at monthly prices ranging from $0.20 to $0.23 per MMBtu. The fair value of our oil and natural gas derivative positions outstanding as of December 31, 2012 was an asset of approximately $40.4 million.

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

• our production is less than expected;

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

• 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.

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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:

• our credit ratings;

• interest rates;

• the structured and commercial financial markets;

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

• tax burden due to new tax laws.

Assuming a constant debt level of $500.0 million, equal to our borrowing base at December 31, 2012 (our only variable interest rate facility), 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 $5.0 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 will continue to result primarily from regulatory action by the Environmental Protection Agency (“EPA”) or by the several states that have already taken legal measures to reduce emissions of greenhouse gases.

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Federal regulation. 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”. 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. While these motor vehicle regulations do not directly impact oil and natural gas production operations, they automatically trigger application of the Prevention of Significant Deterioration (“PSD”) and Title V Operating Permit programs for stationary sources of greenhouse gas emissions, potentially including oil and natural gas production operations. 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 to existing sources and 100,000 tons per year CO2e for new sources.

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.

On August 16, 2012, EPA promulgated new CAA regulations addressing criteria pollutants, “Oil and Natural Gas Sector: New Source Performance Standards and National Emission Standards for Hazardous Air Pollutants Reviews.” These new rules are intended to broaden the current scope of EPA’s regulation to include standards governing emissions from most operations associated with oil and natural gas production facilities, natural gas transmission and storage facilities. EPA states that greenhouse gases will be controlled indirectly as a result of these new rules.

Recent caselaw. Beyond legislative and regulatory developments, litigation against energy industry sectors emitting greenhouse gases have arisen based upon common law claims, that may expose us, as potentially an emitter of significant direct and indirect emission sources of greenhouse gases, to similar litigation risk.

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.

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 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, 2010, 2011, and 2012 the administration of President Obama made budget proposals which, if enacted into law by Congress, would potentially increase and accelerate the payment of federal income taxes by independent producers of oil and natural gas. Proposals have included, but have not been limited to, repealing the enhanced oil recovery credit, repealing the credit for oil and gas produced from marginal wells, repealing the expensing of intangible drilling costs, repealing the deduction for the cost of qualified tertiary expenses, repealing the exception to the passive loss limitation for working interests in oil and natural gas properties, 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. In 2009, 2010, and 2011, legislation which would have implemented the proposed changes was introduced but not enacted. It is unclear whether legislation supporting any of the above described 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. However, 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, 2010, 2011 and 2012 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 operations.

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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. 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 is already required by some state agencies governing our operations, 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.

These legislative efforts have halted while EPA studies the issue of hydraulic fracturing. In 2010, EPA initiated a Hydraulic Fracturing Research Study to address concerns that hydraulic fracturing may affect the safety of drinking water, as well as review the application of other environmental statutes to hydraulic fracturing activities, including the RCRA and the Clean Water Act. 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. EPA is scheduled to release its final draft report in late 2014.

These developments, as well as increased scrutiny of hydraulic fracturing activities by state and municipal authorities may result in additional levels of regulation or complexity with respect to existing regulations that 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.

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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 adoption of The Dodd-Frank Wall Street Reform and Consumer Protection 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.

In July of 2010, the U.S. Congress enacted the Dodd-Frank Wall Street Reform and Consumer Protection Act (the “Dodd-Frank Act”), which contains measures aimed at increasing the transparency and stability of the over-the-counter (“OTC”) derivative markets and preventing excessive speculation. Certain companies that use swaps or other derivatives to hedge commercial risk, referred to as end-users, are permitted to continue to use OTC derivatives under newly adopted regulations. We maintain an active price and basis protection hedging program related to the natural gas and oil we produce to manage the risk of low commodity prices and to predict with greater certainty the cash flow from our hedged production. We have used the OTC market exclusively for our natural gas and oil derivative contracts. The Dodd-Frank Act and the rules and regulations promulgated thereunder should permit us, as an end user, to continue to utilize OTC derivatives. However, we may have increased costs or reduced liquidity in the OTC derivatives market due to the current or future regulations. Such changes could materially reduce our hedging opportunities and negatively affect our revenues and cash flow during periods of low commodity prices.

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Risks Related to the New Notes

Our level of indebtedness could adversely affect our financial condition and prevent us from fulfilling our obligations under the notes and our other indebtedness.

As of December 31, 2012, our total long-term indebtedness, including current maturities, was $1.3 billion. As of April 1, 2013, our total long-term indebtedness, including current maturities, was approximately $1.3 billion, and the borrowing base under our senior secured revolving credit facility was $500.0 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:

• it could be more difficult for us to satisfy our obligations with respect to the new notes, including any repurchase obligations that may arise thereunder;

• 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;

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

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

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

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

• 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 obligations under the notes.

Restrictions in our debt instruments limit our ability to take certain actions and breaches thereof could impair our liquidity.

Our existing senior notes, our senior secured revolving credit facility and the indenture governing the notes contain, covenants that restrict our ability to, among other things:

• incur and guarantee indebtedness or issue preferred stock;

• repay subordinated indebtedness prior to its stated maturity;

• pay dividends or make other distributions on or redeem or repurchase our stock;

• issue capital stock of our subsidiaries;

• make certain investments or acquisitions;

• create liens;

• sell certain assets or merge with or into other companies;

• enter into certain transactions with stockholders and affiliates; and

• restrict dividends, distributions or other payments from our subsidiaries.

You should read the discussions under the headings “Description of Other Indebtedness” and “Description of the New Notes—Certain Covenants” for further information about these covenants.

In addition, our senior secured revolving credit facility requires us to comply with financial covenants relating to, among other things, interest coverage and leverage. We may not be able to satisfy these covenants in the future or be able to pursue our strategies within the constraints of these covenants. A breach of a covenant contained in our debt instruments could result in an event of default under one or more of our debt instruments. Such breaches would permit the lenders under our debt instruments to declare the amounts borrowed or otherwise owing thereunder to be due and payable, and the commitments of the lenders under our senior secured revolving credit facility to make further extensions of credit could be terminated. Each of these circumstances could materially and adversely impair our liquidity.

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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 $500.0 million as of April 1, 2013, 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, unless otherwise agreed to by our lenders. 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.

We may not be able to generate sufficient cash to service all of our long-term indebtedness, including the new notes, 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, including the notes.

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, including the notes. 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 existing senior notes, our senior secured revolving credit facility, and the indenture governing the notes restrict our ability to use the proceeds from asset sales. We may not be able to consummate those asset sales to raise capital or 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. See “Description of Other Indebtedness” and “Description of the New Notes.”

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

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

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

• 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

• we could be forced into bankruptcy or liquidation.

Despite our current leverage, we may still be able to incur substantially more debt. This could further exacerbate the risks that we and our subsidiaries face.

We and our subsidiaries may be able to incur substantial additional indebtedness, including additional secured indebtedness, in the future. As of April 11, 2013, we had approximately $79.0 million of loans outstanding under our senior secured revolving credit facility and we had committed to borrow an additional $20.0 million under our senior secured revolving credit facility, which will be funded on April 16, 2013. In addition, the indenture governing the notes allows us to issue additional notes under certain circumstances which will also be guaranteed by the guarantors. The indentures governing our existing senior notes and the indenture governing the notes allow us to incur certain other additional secured debt and will allow our subsidiaries which do not guarantee the notes to incur additional debt, which would be structurally senior to the notes. In addition, the indentures governing the existing senior notes and the notes do not prevent us from incurring other liabilities that do not constitute indebtedness. See “Description of the New Notes.” If new debt or other liabilities are added to our current debt levels, the related risks that we and our subsidiaries now face could intensify.

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Not all of our subsidiaries are guarantors and therefore the notes will be structurally subordinated in right of payment to the indebtedness and other liabilities of our existing and future domestic subsidiaries that do not guarantee the notes. Your right to receive payments on the notes could be adversely affected if any of these non-guarantor subsidiaries declare bankruptcy, liquidate or reorganize.

The notes will not be guaranteed by any of our unrestricted subsidiaries. Accordingly, claims of holders of the notes will be structurally subordinate to the claims of creditors of these non-guarantor subsidiaries, including trade creditors. All obligations of our non-guarantor subsidiaries will have to be satisfied before any of the assets of such subsidiaries would be available for distribution, upon a liquidation or otherwise, to us or a guarantor of the notes. As of the date of this prospectus, our non-guarantor subsidiaries had no operations or liabilities and de minimis assets.

We may not be able to satisfy our obligations to holders of the notes upon a change of control.

Upon the occurrence of a “change of control,” as defined in the indentures governing the notes, each holder of the notes will have the right to require us to purchase the notes at a price equal to 101% of the principal amount thereof. Our failure to purchase, or to give notice of purchase of, the notes would be a default under the indenture governing the notes and any such default could result in a default under certain of our other indebtedness, including our senior secured revolving credit facility and the indentures governing our existing senior notes. In addition, a change of control may constitute an event of default under our senior secured revolving credit facility and the indentures governing our existing senior notes. A default under our senior secured revolving credit facility would result in an event of default under the indenture governing the notes and the indentures governing our existing senior notes if the lenders accelerate the debt under our senior secured revolving credit facility.

Federal and state fraudulent transfer laws may permit a court to void the guarantees, and, if that occurs, you may not receive any payments on the notes.

The issuance of the guarantees may be subject to review under federal and state fraudulent transfer and conveyance statutes. While the relevant laws may vary from state to state, under such laws the incurrence of a guarantee obligation will be a fraudulent conveyance if a guarantor received less than reasonably equivalent value or fair consideration in exchange for issuing such guarantee, and one of the following is also true:

• such guarantor was insolvent or rendered insolvent by reason of the incurrence of the indebtedness;

• the guarantor was left with an unreasonably small amount of capital to carry on the business; or

• the guarantor intended to, or believed that it would, incur debts beyond its ability to pay as they mature.

If a court were to find that the issuance of a guarantee was a fraudulent conveyance, the court could void the payment obligations under such guarantee or subordinate such guarantee to presently existing and future indebtedness of such guarantor, or require the holders of the notes to repay any amounts received with respect to such guarantee. In the event of a finding that a fraudulent conveyance occurred, you may not receive any repayment on the notes.

Generally, an entity would be considered insolvent if, at the time it incurred indebtedness:

• the sum of its debts, including contingent liabilities, was greater than the fair saleable value of all its assets;

• the present fair saleable value of its assets was less than the amount that would be required to pay its probable liability on its existing debts and liabilities, including contingent liabilities, as they become absolute and mature; or

• it could not pay its debts as they become due.

We cannot be certain as to the standards a court would use to determine whether or not a guarantor was solvent at the relevant time, or regardless of the standard that a court uses, that the issuance of the guarantees would not be subordinated to our or a guarantor’s other debt.

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

The market price for the notes may be volatile.

Historically, the market for non-investment grade debt has been subject to disruptions that have caused substantial fluctuations in the price of the securities. Even if a trading market for the notes develops, it may be subject to disruptions and price volatility. Any disruptions may have a negative effect on noteholders, regardless of our prospects and financial performance.

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If a bankruptcy petition were filed by or against us, holders of the notes may receive a lesser amount for their claim than they would have been entitled to receive under the indenture governing the notes.

If a bankruptcy petition were filed by or against us under the United States Bankruptcy Code after the issuance of the notes, the claim by any holder of the notes for the principal amount of the notes may be limited to an amount equal to the sum of the original issue price for the notes and that portion of original issue discount that does not constitute “unmatured interest” for purposes of the United States Bankruptcy Code. Any original issue discount that was not amortized as of the date of the bankruptcy filing would constitute unmatured interest. Accordingly, holders of the notes under these circumstances may receive a lesser amount than they would be entitled to under the terms of the indenture governing the notes, even if sufficient funds are available.

The notes will be unsecured.

The notes will not be secured by any of our or our subsidiaries’ assets. The indenture governing the notes permits us and our subsidiaries to incur secured debt, including pursuant to our senior secured revolving credit facility, purchase money instruments and other forms of secured debt. As a result, the notes and the guarantees thereof will be effectively subordinated to all of our and the guarantors’ secured obligations to the extent of the value of the assets securing such obligations. As of April 11, 2013, we had approximately $95.8 million of secured debt and we had committed to borrow an additional $20.0 million under our senior secured revolving credit facility, which will be funded on April 16, 2013.

If we or the subsidiary guarantors were to become insolvent or otherwise fail to make payment on the notes or the guarantees, holders of any of our and the subsidiary guarantors’ secured obligations would be paid first and would receive payments from the assets securing such obligations before the holders of the notes would receive any payments. Holders of notes may therefore not be fully repaid if we or the subsidiary guarantors become insolvent or otherwise fail to make payment on the notes.

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RATIO OF EARNINGS TO FIXED CHARGES

The following table sets forth our consolidated ratio of earnings to fixed charges for the periods shown:

	Year Ended December 31,
	2012		2011		2010		2009			2008
Ratio of earnings to fixed charges		2.0x		1.8x		1.7x		N/A	(1)		N/A	(1)

(1) For the years ended December 31, 2009 and 2008, fixed charges exceeded earnings by approximately $241.4 million and $92.2 million, respectively.

For purposes of this computation, “earnings” consist of income (loss) from continuing operations before income taxes plus fixed charges (excluding capitalized interest, but including amortization of amounts previously capitalized). “Fixed charges” include interest expensed, capitalized interest, accretion of debt discounts, and amortization of debt issuance costs.

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USE OF PROCEEDS

The exchange offer is intended to satisfy our obligations under the registration rights agreement we entered into in connection with the private offering of the old notes. We will not receive any proceeds from the issuance of the new notes in the exchange offer. In consideration for issuing the new notes as contemplated in this prospectus, we will receive, in exchange, outstanding old notes in like principal amount. We will cancel all old notes surrendered in exchange for new notes in the exchange offer. As a result, the issuance of the new notes will not result in any increase or decrease in our indebtedness.

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CAPITALIZATION

The following table sets forth our capitalization as of December 31, 2012. This table is unaudited and should be read together with our financial statements and the accompanying notes included in this prospectus.

(dollars in thousands)	As of December 31, 2012
Capitalization
Cash and cash equivalents	$	29,819
Long-term debt, including capital leases and current maturities
Senior secured revolving credit facility(1)		25,000
Other installment notes and capital leases		17,740
Total secured debt		42,740
9.875% Senior Notes due 2020, net of discount		294,031
8.25% Senior Notes due 2021		400,000
7.625% Senior Notes due 2022, including premium		556,631
Total debt		1,293,402
Total stockholders’ equity		462,857
Total capitalization	$	1,756,259

(1) As of April 11, 2013, we had $79.0 million of loans outstanding and and we had committed to borrow an additional $20.0 million under our senior secured revolving credit facility, which will be funded on April 16, 2013.

We estimate that our interest expense for the year ended December 31, 2012 would have increased by approximately $8.4 million if the issuance of the old notes had occurred on January 1, 2012.

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SELECTED HISTORICAL CONSOLIDATED FINANCIAL INFORMATION

The following selected historical consolidated financial information as of December 31, 2012 and 2011 and for each of the three years ended December 31, 2012 are derived from our audited financial statements, which are included elsewhere in this prospectus. The following selected historical consolidated financial information as of December 31, 2010, 2009, and 2008 and for the years ended December 31, 2009 and 2008 are derived from our audited financial statements, which are not included in this prospectus. The following table should be read in conjunction with “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and our audited consolidated financial statements and accompanying notes thereto included in this prospectus.

	Year ended December 31,
(in thousands)	2012			2011			2010			2009			2008
Operating results data:
Revenues
Oil and natural gas sales	$	509,503		$	530,041		$	408,561		$	292,387		$	501,761
Gain (loss) from oil and natural gas hedging activities		46,746			(27,452	)		(29,393	)		19,403			(76,417	)
Other revenues		—			4,070			4,127			2,864			8,735
Total revenues		556,249			506,659			383,295			314,654			434,079
Costs and expenses
Lease operating		130,960			121,420			106,127			94,070			120,487
Production tax		32,003			34,321			26,495			20,341			33,815
Depreciation, depletion and amortization		169,307			146,083			109,503			104,193			101,026
Loss on impairment of oil & natural gas properties		—			—			—			240,790			281,393
Loss on impairment of other assets		2,000			—			4,150			—			2,900
General and administrative		49,812			42,056			29,915			23,741			22,370
Litigation settlement		—			—			—			2,928			—
Other expenses		—			3,448			3,148			1,957			7,150
Total costs and expenses		384,082			347,328			279,338			488,020			569,141
Operating income (loss)		172,167			159,331			103,957			(173,366	)		(135,062	)
Non-operating income (expense)
Interest expense		(98,402	)		(96,720	)		(81,370	)		(90,102	)		(86,038	)
Non-hedge derivative gains		49,685			34,408			38,595			11,169			126,941
Loss on extinguishment of debt		(21,714	)		(20,592	)		(2,241	)		—			—
Financing costs, net of termination fee		—			—			(1,812	)		(2,169	)		2,100
Other income		504			1,545			387			13,921			1,394
Net non-operating income (expense)		(69,927	)		(81,359	)		(46,441	)		(67,181	)		44,397
Income (loss) from continuing operations before income taxes		102,240			77,972			57,516			(240,547	)		(90,665	)
Income tax expense (benefit)		37,837			35,924			23,803			(89,777	)		(34,976	)
Income (loss) from continuing operations		64,403			42,048			33,713			(150,770	)		(55,689	)
Income from discontinued operations, net of related taxes		—			—			—			6,452			939
Net income (loss)	$	64,403		$	42,048		$	33,713		$	(144,318	)	$	(54,750	)
Cash flow data:
Net cash provided by operating activities	$	192,000		$	259,616		$	167,702		$	98,675		$	145,831
Net cash provided by (used in) investing activities		(423,246	)		(324,998	)		(264,172	)		21,904			(262,905	)
Net cash provided by (used in) financing activities		226,476			44,860			78,164			(99,274	)		157,499
Financial position data:
Cash and cash equivalents	$	29,819		$	34,589		$	55,111		$	73,417		$	52,112
Total assets		2,007,552			1,669,733			1,529,292			1,353,920			1,712,836
Total debt		1,293,402			1,034,573			962,087			1,177,007			1,271,589
Retained earnings (accumulated deficit)		17,186			(47,217	)		(89,265	)		(122,978	)		21,340
Accumulated other comprehensive income, net of income taxes		23,223			51,846			34,974			17,618			82,133
Total stockholders’ equity (deficit)		462,857			424,013			363,557			(4,433	)		204,400

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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 prospectus. 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 prospectus, particularly in “Risk Factors” and “Special Cautionary Statement Regarding Forward-Looking Statements.”

Overview

We are a growing independent oil and natural gas production and exploitation company. Our core operations consist of drilling for and production of oil and natural gas from conventional and unconventional reservoirs as well as a focus on tertiary operations through enhanced oil recovery (“EOR”) projects utilizing CO₂ and polymer in the Mid-Continent and Permian Basin areas. We maintain a portfolio of proved reserves, development and exploratory drilling opportunities, and EOR projects. Starting in 2011, we began to redirect our capital expenditures from the drilling of vertical wells to the drilling of horizontal wells in repeatable resource plays and increased our level of expenditures on EOR projects. As of December 31, 2012, we had estimated proved reserves of 146.1 MMBoe with a PV-10 value of approximately $2.1 billion. These estimated proved reserves included 29.5 MMBoe of EOR reserves. Our reserves were 65% proved developed and 65% 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, 2012 reserve estimates reflect that our production rate on current proved developed producing reserve properties will decline at annual rates of approximately 19%, 14%, and 12% 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 our liquidity or results of operations, and/or are expected to impact these items in future periods:

• 7.625% Senior Notes due 2022. On May 2, 2012, we issued $400.0 million aggregate principal amount of 7.625% Senior Notes maturing on November 15, 2022. We used the net proceeds from the 7.625% Senior Notes to consummate a tender offer for all of our 8.875% Senior Notes due 2017, to redeem the 8.875% Senior Notes not purchased in the tender offer, and for general corporate purposes. In connection with the issuance of the 7.625% Senior Notes and the repurchase or redemption of our 8.875% Senior Notes due 2017, we capitalized approximately $8.8 million of issuance costs related to underwriting and other fees and we expensed approximately $21.7 million of refinancing costs, including a $5.9 million non-cash write-off of deferred financing costs and unaccreted discount.

• Add-on Note offering. On November 15, 2012, we issued $150.0 million aggregate principal amount of 7.625% Senior Notes due 2022 under the same indenture covering our $400.0 million issuance made on May 2, 2012. The net proceeds from the sale of the Add-on Notes were used to repay all of our outstanding indebtedness under our senior secured revolving credit facility and for general corporate purposes. In connection with the issuance of the November 15, 2012 Add-on Notes, we recorded a premium of $6.8 million and capitalized $3.5 million of issuance costs related to underwriting and other fees.

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• Capital expenditures. Our oil and natural gas property capital expenditure budget for 2013 is set at $401.0 million. During 2012, we increased our focus on the development of our EOR assets and drilling in our repeatable resource plays. Investing in EOR reduces near-term growth opportunities but enhances longer term growth and is consistent with our strategy of driving near-term growth through drilling and long-term growth through EOR development. Our developmental and exploratory expenditures for EOR increased from $88.2 million in 2011 to $194.0 million in 2012, and we have budgeted $137.0 million for the development of our EOR assets in 2013. In 2014, our EOR capital investments are expected to increase somewhat but remain less than incurred in 2012. Future capital investments should then range between $75.0 million and $150.0 million in subsequent years.

• Asset sales. On May 30, 2012, we sold certain mature oil and natural gas properties located in our Velma Area in southern Oklahoma for a cash price of $37.0 million, subject to post-closing adjustments. The properties included in the sale accounted for approximately 1% of our total production prior to the sale and during 2011.

• Stock-based compensation. In the first quarter of 2012, we adopted the Chaparral Energy, Inc. Non-Officer Restricted Stock Unit Plan (the “RSU Plan”), which is intended to replace our existing Phantom Stock Plan. Initial awards under the RSU Plan have an aggregate grant-date fair value of $3.0 million and will vest in equal annual installments over the next three years.

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Results of Operations

Overview

Total production and net income have increased in each year from 2010 to 2012. Oil and natural gas sales and cash flow from operations decreased from 2011 to 2012 after increasing from 2010 to 2011. During 2012, revenue decreased by 4% compared to 2011 as a result of lower oil and natural gas prices, partially offset by increased oil production. Revenue in 2011 increased by 30% compared to 2010 primarily due to higher oil production and prices, partially offset by lower natural gas production and prices. As a result of these and other transactions discussed below, we had net income in 2012, 2011, and 2010 of $64.4 million, $42.0 million, and $33.7 million, respectively.

	Year ended December 31,
	2012		2011		2010
Production (MBoe)		9,118		8,655		8,050
Oil and natural gas sales (in thousands)	$	509,503	$	530,041	$	408,561
Net income (loss) (in thousands)	$	64,403	$	42,048	$	33,713
Cash flow from operations (in thousands)	$	192,000	$	259,616	$	167,702

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
	2012		2011		change			2010		change
Oil and natural gas sales (in thousands)
Oil (1)	$	457,106	$	441,801		3.5	%	$	305,042		44.8	%
Natural gas		52,397		88,240		(40.6	)%		103,519		(14.8	)%
Total	$	509,503	$	530,041		(3.9	)%	$	408,561		29.7	%
Production
Oil (MBbls) (1)		5,812		5,048		15.1	%		4,093		23.3	%
Natural gas (MMcf)		19,834		21,642		(8.4	)%		23,742		(8.8	)%
MBoe		9,118		8,655		5.3	%		8,050		7.5	%
Average sales prices (excluding derivative settlements)
Oil per Bbl (1)	$	78.65	$	87.52		(10.1	)%	$	74.53		17.4	%
Natural gas per Mcf	$	2.64	$	4.08		(35.3	)%	$	4.36		(6.4	)%
Average sales price per Boe	$	55.88	$	61.24		(8.8	)%	$	50.75		20.7	%

(1) Includes natural gas liquids.

Oil and natural gas revenues decreased $20.5 million, or 4%, to $509.5 million during 2012 due to a 9% decrease in the average price per Boe offset in part by a 5% increase in sales volumes. Oil production for 2012 increased compared to 2011 primarily due to our drilling activity, especially in our Cleveland Sand and NOMP Core plays, which together accounted for approximately 18% and 11% of our total oil production during 2012 and 2011, respectively. Natural gas production for 2012 decreased compared to 2011 primarily due to the decline in production in the Permian Basin Area, which accounted for approximately 18% and 20% of total natural gas production during 2012 and 2011, respectively.

Oil and natural gas revenues increased $121.5 million, or 30%, to $530.0 million during 2011 due to a 21% increase in the average price per Boe combined with 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 hedging is shown in the following table:

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	Year ended December 31,
	2012 vs. 2011						2011 vs. 2010
(dollars in thousands)	Sales change			Percentage change in sales			Sales change			Percentage change in sales
Change in oil sales due to:
Prices	$	(51,560	)		(11.6	)%	$	65,585			21.5	%
Production		66,865			15.1	%		71,174			23.3	%
Total change in oil sales	$	15,305			3.5	%	$	136,759			44.8	%
Change in natural gas sales due to:
Prices	$	(28,471	)		(32.2	)%	$	(6,123	)		(6.0	)%
Production		(7,372	)		(8.4	)%		(9,156	)		(8.8	)%
Total change in natural gas sales	$	(35,843	)		(40.6	)%	$	(15,279	)		(14.8	)%

Production volumes by area were as follows (MBoe):

	Year ended December 31,				Percentage			Year ended December 31,		Percentage
	2012		2011		change			2010		change
Enhanced Oil Recovery Project Areas		1,368		1,156		18.3	%		1,079		7.1	%
Mid-Continent Area		5,693		5,037		13.0	%		4,441		13.4	%
Permian Basin Area		1,196		1,315		(9.0	)%		1,500		(12.3	)%
Other		861		1,147		(24.9	)%		1,030		11.4	%
Total		9,118		8,655		5.3	%		8,050		7.5	%

Production has been increasing in our EOR Project Areas due to our drilling and development activities. We acquired a 99% working interest in our Farnsworth Unit in November 2009 and we began CO₂ injection in the Unit in December 2010. We also acquired an additional 6% working interest in our Camrick Area Units during the third quarter of 2010, thereby increasing our average working interest in these units to 60%. Our total capital investment in our EOR Project Areas was $194.4 million in 2012 compared to $91.8 million in 2011, with our primary focus in 2012 on drilling, development and exploitation activities in our North Burbank play.

The increase in production in our Mid-Continent Area is primarily due to our drilling activity. We made significant capital investments in our NOMP, Cleveland Sand and Granite Wash plays during 2012, 2011 and 2010, and these plays accounted for approximately 27%, 20%, and 13% of our total production during 2012, 2011, and 2010, respectively.

Our production in the Permian Basin Area has been decreasing primarily due to the natural decline in production from natural gas wells in the Haley Area, which accounted for approximately 4% of our total production in 2012, compared to 5% in 2011 and 9% in 2010. Due to prevailing low natural gas prices, we reduced our capital expenditures for natural gas projects during 2012 and 2011.

On May 30, 2012, we sold certain mature oil and natural gas properties located in our Velma Area in southern Oklahoma for a cash price of $37,000 subject to post-closing adjustments. Our Velma area, which is included in the line item “Enhanced Oil Recovery Project Areas” in the production table above, accounted for approximately 1% of our total production prior to the sale and in years ended December 31, 2011 and 2010.

On November 28, 2011, we sold certain oil and natural gas properties located in our Rocky Mountains area to Charger Resources, LLC for a cash price of approximately $33.1 million. Our Rocky Mountains area, which is included in the line item “Other” in the production table above, accounted for approximately 2% of our total production in each of the years ended December 31, 2011 and 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.

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Entering into derivative instruments allows us to predict with greater certainty the effective prices we will receive for associated oil and natural gas production. In December 2011, we amended our senior secured revolving credit facility to provide greater flexibility when hedging our anticipated production. The terms of the amendment allow us to protect a portion of our natural gas liquids production from price volatility using crude oil derivatives. 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 early derivative monetizations, on realized prices:

	Year ended December 31,
	2012			2011			2010
Oil (per Bbl): (1)
Before derivative settlements	$	78.65		$	87.52		$	74.53
After derivative settlements	$	80.67		$	76.11		$	71.91
Post-settlement to pre-settlement price		102.6	%		87.0	%		96.5	%
Natural gas (per Mcf):
Before derivative settlements	$	2.64		$	4.08		$	4.36
After derivative settlements	$	3.93		$	5.65		$	6.20
Post-settlement to pre-settlement price		148.9	%		138.5	%		142.2	%

(1) Includes natural gas liquids.

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,
(in thousands)	2012			2011			2010
Derivative assets (liabilities):
Natural gas swaps	$	12,155		$	30,124		$	32,408
Oil swaps		3,618			(5,912	)		(58,200	)
Oil collars		26,231			5,049			1,509
Natural gas basis differential swaps		(1,599	)		(1,268	)		(5,623	)
Net derivative asset (liability)	$	40,405		$	27,993		$	(29,906	)

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 (losses) 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, 2012, accumulated other comprehensive income (“AOCI”) consists of deferred net gains of $37.1 million ($23.2 million net of tax) related to discontinued cash flow hedges that will be recognized as gains from oil and natural gas hedging activities through December 2013 as the hedged production is sold.

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

	Year ended December 31,
	2012						2011						2010
(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	$	46,746		$	—		$	(27,452	)	$	—		$	(25,399	)	$	(5,504	)
Natural gas swaps		—			—			—			—			1,510			—
Gain (loss) from oil and natural gas hedging activities	$	46,746		$	—		$	(27,452	)	$	—		$	(23,889	)	$	(5,504	)
Non-hedge derivative gains (losses):
Oil swaps and collars	$	30,710		$	11,761		$	55,828		$	(57,619	)	$	(8,660	)	$	(5,225	)
Natural gas swaps and collars		(17,968	)		27,184			(2,284	)		42,068			(7,769	)		53,728
Natural gas basis differential contracts		(331	)		(1,671	)		4,355			(7,940	)		9,341			(10,110	)
Derivative monetizations		—			—			—			—			193			7,097
Non-hedge derivative gains (losses)	$	12,411		$	37,274		$	57,899		$	(23,491	)	$	(6,895	)	$	45,490
Total gains (losses) from derivative activities	$	59,157		$	37,274		$	30,447		$	(23,491	)	$	(30,784	)	$	39,986

Our gain (loss) from oil and natural gas hedging activities during 2012, 2011, and 2010 included net gains (losses) of $46.7 million, $(27.5) million, and $(23.9) million, respectively, which were associated with derivatives for which hedge accounting was previously discontinued.

The fluctuation in non-hedge derivative gains from period to period is due primarily to the significant volatility of oil and natural gas prices and basis differentials and to changes in our outstanding derivative contracts during the periods. Non-hedge derivative gains also included proceeds from the early monetization of derivatives. During 2010, we unwound and monetized certain oil and natural gas derivative contracts with original settlement dates from April 2010 through December 2012 for net proceeds of $7.1 million.

Total gains on derivative activities recognized in our statements of operations were $96.4 million, $7.0 million, and $9.2 million in 2012, 2011, and 2010, respectively.

Lease operating expenses

	Year ended December 31,				Percentage			Year ended December 31,		Percentage change
	2012		2011		change			2010
Lease operating expenses (in thousands)	$	130,960	$	121,420		7.9	%	$	106,127		14.4	%
Lease operating expenses per Boe	$	14.36	$	14.03		2.4	%	$	13.18		6.4	%

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 during 2012 increased $9.5 million or 7.8% compared to 2011 primarily due to additional workovers and increased oilfield service costs associated with new wells added during 2012. On a per Boe basis, lease operating expense increased 2.4% to $14.37, reflecting the increased production levels in 2012. Workover and well work costs for operated properties increased to $29.9 million in 2012, as compared to $23.0 million in 2011, largely in our Camrick, Farnsworth, Ark-La-Tex and Permian Basin—Other areas.

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Our lease operating expenses during 2011 were $121.4 million, an increase of $15.3 million or 14% (6.4% on a per Boe basis) compared to 2010. The increase was primarily due to our increased activity combined with the upward pressure on operating and service costs associated with the improvement in oil prices during 2011. Electricity and fuel costs for operated properties increased to $26.9 million in 2011, as compared to $22.8 million in 2010, primarily associated with new wells we added during 2011 and increased activity in our EOR operations. Workover and well work costs for operated properties increased to $23.0 million in 2011, as compared to $19.5 million in 2010, primarily due to a higher number of workovers being conducted in our Gulf Coast, Permian Basin—Other, Tunstill, Golden Trend, Velma, and Sho-Vel-Tum plays.

Our lease operating expenses on a BOE basis, increased from $13.18 during 2010 to $14.03 in 2011. This increase of 6% on a BOE basis was primarily the result of the increase in well workover, electricity and fuel expense, as discussed above.

Production taxes (which include ad valorem taxes)

	Year ended December 31,				Percentage			Year ended December 31,		Percentage change
	2012		2011		change			2010
Production taxes (in thousands)	$	32,003	$	34,321		(6.8	)%	$	26,495		29.5	%
Production taxes per Boe	$	3.51	$	3.97		(11.6	)%	$	3.29		20.7	%

Production taxes generally change in proportion to oil and natural gas sales. The 2012 decrease in production taxes from 2011 was primarily due to the 8.7% decrease in average realized prices combined with the 3.9% decrease in oil and natural gas sales. The 2011 increase in production taxes from 2010 was primarily due to the 21% increase in average realized prices combined with an 8% increase in production volumes.

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

	Year ended December 31,				Percentage			Year ended December 31,		Percentage change
	2012		2011		change			2010
DD&A (in thousands):
Oil and natural gas properties	$	154,788	$	132,307		17.0	%	$	96,676		36.9	%
Property and equipment		10,574		10,146		4.2	%		9,567		6.1	%
Accretion of asset retirement obligation		3,945		3,630		8.7	%		3,260		11.3	%
Total DD&A	$	169,307	$	146,083		15.9	%	$	109,503		33.4	%
DD&A per Boe:
Oil and natural gas properties	$	16.98	$	15.29		11.1	%	$	12.01		27.3	%
Other fixed assets	$	1.59	$	1.59		—		$	1.59		—
Total DD&A per Boe	$	18.57	$	16.88		10.0	%	$	13.60		24.1	%

We adjust our DD&A rate on oil and natural gas properties each quarter for significant changes in our estimates of oil and natural gas reserves and costs, and thus our DD&A rate could change significantly in the future. DD&A on oil and natural gas properties increased $22.5 million from 2011 to 2012, of which $15.5 million was due to a higher rate per equivalent unit of production and $7.0 million was due to the increase in production. Our DD&A rate per equivalent unit of production increased $1.69 to $16.98 per Boe primarily due to higher estimated future development costs for proved undeveloped reserves and higher cost reserve additions.

DD&A on oil and natural gas properties increased $35.6 million from 2010 to 2011, of which $28.4 million was due to a higher rate per equivalent unit of production and $7.2 million was due to the increase in production. Our DD&A rate per equivalent unit of production increased $3.28 to $15.29 per Boe primarily due to higher estimated future development costs for proved undeveloped reserves and higher cost reserve additions.

We record the estimated future value of a liability for an asset retirement obligation in the period in which it is incurred, discounted to its present value using our credit adjusted risk-free interest rate, with a corresponding increase in the carrying amount of oil and natural gas properties. The liability is accreted each period, and the capitalized cost is depreciated over the useful life of the related asset.

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Impairment of oil and natural gas properties. In accordance with the full-cost method of accounting, the net capitalized costs of oil and natural gas properties are not to exceed their related estimated future net revenues discounted at 10% (“PV-10 value”), as adjusted for our cash flow hedge positions and net of tax considerations, plus the cost of unproved properties not being amortized.

Our estimates of oil and natural gas reserves as of December 31, 2012, 2011, and 2010 were prepared using an average price for oil and natural gas based upon the first day of each month for the prior twelve months as required by the SEC’s Modernization of Oil and Gas Reporting and the guidance of the Financial Accounting Standard Board (“FASB”) relating to Oil and Gas Reserve Estimation and Disclosures. As of December 31, 2012, the cost center ceiling exceeded the net capitalized cost of our oil and natural gas properties, and no ceiling test impairment was recorded. The PV-10 value of our reserves was estimated based on average prices of $94.71 per Bbl of oil and $2.76 per Mcf of gas for the year ended December 31, 2012.

A decline in oil and natural gas prices subsequent to December 31, 2012 could result in ceiling test write-downs in future periods. The amount of any future impairment is difficult to predict, and will depend on the average oil and gas prices during each period, the incremental proved reserves added during each period, and additional capital spent.

Impairment of other assets. In 2012, we recognized $1.5 million of impairment losses on certain of our owned drilling rigs due to our expectation that these may not sell at a price that will exceed their carrying values. Also in 2012, we recognized $0.5 million of additional impairment losses primarily related to drill pipe.

We owned an interest in the Levelland/Hockley County ethanol plant in Levelland, Texas, and we own a pipeline constructed for the sole purpose of supplying natural gas to the ethanol plant. During the fourth quarter of 2010, we determined that any future cash flows generated by either the ethanol plant or by our pipeline which supplies gas to the ethanol plant would probably not be sufficient to allow us to recover our investment in these assets. We accordingly recorded an impairment charge of $4.2 million, which included our $2.1 million investment in the ethanol plant and the $2.1 million carrying value of our pipeline assets.

General and administrative expenses (“G&A”) and litigation settlement

	Year ended December 31,						Percentage			Year ended December 31,			Percentage change
(dollars in thousands, excluding per Boe amounts)	2012			2011			change			2010
Gross G&A expenses	$	67,176		$	58,745			14.4	%	$	44,575			31.8	%
Capitalized exploration and development costs		(17,364	)		(16,689	)		4.0	%		(14,660	)		13.8	%
Net G&A expenses	$	49,812		$	42,056			18.4	%	$	29,915			40.6	%
Average G&A cost per Boe	$	5.46		$	4.86			12.3	%	$	3.72			30.6	%
Full-time office employees as of December 31		353			337			4.7	%		328			2.7	%

G&A expenses in 2012 increased $7.8 million from 2011, primarily due to compensation and benefit cost increases related to the competitive nature of our market and our growing operations. Expenses for non-recurring professional services for certain projects and initiatives increased approximately $2.2 million compared to 2011. Stock-based compensation expense included in G&A for 2012 was $3.1 million.

G&A expenses in 2011 increased $12.1 million from 2010, primarily due to higher compensation, land, and legal costs caused by our heightened level of activity and our high level of investment in EOR properties. Stock-based compensation expense included in G&A for 2011 was $3.7 million.

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Other income and expenses

Interest expense. The following table presents interest expense for the periods indicated:

	Year ended December 31,
(in thousands)	2012			2011			2010
Senior secured revolving credit facility	$	1,193		$	156		$	10,119
8.5% Senior Notes due 2015		—			4,587			28,489
8.875% Senior Notes due 2017		10,420			29,756			29,675
9.875% Senior Notes due 2020		31,115			30,211			9,119
8.25% Senior Notes due 2021		33,579			28,781			—
7.625% Senior Notes due 2022		21,420			—			—
Bank fees and other interest		5,112			5,608			6,004
Capitalized interest		(4,437	)		(2,379	)		(2,036	)
Total interest expense	$	98,402		$	96,720		$	81,370
Average long-term borrowings	$	1,166,349		$	1,036,541		$	968,114

Total interest expense increased in 2012 by $1.7 million, or 2%, compared to 2011 primarily due to increased levels of borrowing, partially offset by a lower weighted-average interest rate. Total interest expense increased $15.4 million in 2011, or 19%, compared to 2010 primarily due to a higher weighted-average interest rate combined with increased levels of borrowing.

Loss on extinguishment of debt. On May 2, 2012, we issued $400.0 million aggregate principal amount of 7.625% Senior Notes maturing on November 15, 2022. Net proceeds from the 7.625% Senior Notes were used to consummate a tender offer for all of our 8.875% Senior Notes due 2017, to redeem the 8.875% Senior Notes not purchased in the tender offer, and for general corporate purposes. During the second quarter of 2012, we recorded a loss of $21.7 million associated with the refinancing of our 8.875% Senior Notes, including $15.8 million in repurchase or redemption-related fees and a $5.9 million write-off of deferred financing costs and unaccreted discount.

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. During the first quarter of 2011, we recorded a $20.6 million loss associated with the refinancing of our 8.5% Senior Notes due 2015, including $15.1 million in repurchase or redemption-related fees and a $5.5 million write-off of deferred financing costs.

On April 12, 2010, we entered into and closed an Eighth Restated Credit Agreement (our “senior secured revolving credit facility”). We used the proceeds available under our senior secured revolving credit facility to repay the amounts owing under our Seventh Restated Credit Agreement (our “prior credit facility”). During the year ended December 31, 2010, we recorded a loss of $2.2 million related to the write-off of prepaid bank fees associated with our prior credit facility.

Income Taxes

	Year ended December 31,
(dollars in thousands)	2012			2011			2010
Current income tax expense (benefit)	$	118		$	179		$	79
Deferred income tax expense (benefit)		37,719			35,745			23,724
Total income tax expense (benefit)	$	37,837		$	35,924		$	23,803
Effective tax rate		37.0	%		46.1	%		41.4	%
Total net deferred tax asset (liability)	$	(35,773	)	$	(16,178	)	$	30,148

As of December 31, 2012, our federal and state net operating loss carryforwards were approximately $439.0 million and $413.0 million, respectively, and will begin to expire in 2013. As of December 31, 2012, approximately $300.0 million of the state net operating loss carryforwards have been reduced by a valuation allowance based on our assessment that it is more likely than not that a portion will not be realized. No additional adjustment was made to the valuation allowance during 2012.

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Realization of our deferred tax assets is dependent upon generating sufficient future taxable income. Although realization is not assured, we believe it is more likely than not that the deferred tax asset will be realized. The amount of the deferred tax asset considered realizable, however, could be reduced in the near-term if estimates of future taxable income are reduced.

Liquidity and Capital Resources

Historically, our primary sources of liquidity have been cash generated from our operations, debt, and private equity sales. On April 12, 2010, we sold 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”) for proceeds of $313.2 million, net of fees and other expenses of $11.8 million.

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.

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.

On May 2, 2012, we issued $400.0 million aggregate principal amount of 7.625% Senior Notes maturing on November 15, 2022. We used the net proceeds from the 7.625% Senior Notes to consummate a tender offer for all of our 8.875% Senior Notes due 2017, to redeem the 8.875% Senior Notes not purchased in the tender offer, and for general corporate purposes.

On November 15, 2012, we issued $150.0 million aggregate principal amount of 7.625% Senior Notes due 2022 under the same indenture covering our $400.0 million issuance made on May 2, 2012. The net proceeds from the sale of the Add-on Notes were used to repay all of our outstanding indebtedness under our senior secured revolving credit facility and for general corporate purposes.

We maintain a senior revolving credit facility, which has a borrowing base of $500.0 million, that is collateralized by our oil and natural gas properties, and, following an amendment effective November 1, 2012, is scheduled to mature on November 1, 2017. 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. The amount of secured debt permitted under our Senior Notes is set at a minimum of $500.0 million. We have the ability to borrow under our senior secured revolving credit facility, subject to maintaining a Current Ratio, as defined in our senior secured revolving credit facility, of not less than 1.0 to 1.0 and 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 each period of four consecutive fiscal quarters ending on the last day of such applicable fiscal quarter. As of April 1, 2013 our availability under the borrowing base was limited to $245.4 million based on the Consolidated Net Debt to Consolidated EBITDAX ratio.

Sources and Uses of Cash

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

	Year ended December 31,
(in thousands)	2012			2011			2010
Cash flows provided by operating activities	$	192,000		$	259,616		$	167,702
Cash flows provided by (used in) investing activities		(423,246	)		(324,998	)		(264,172	)
Cash flows provided by (used in) financing activities		226,476			44,860			78,164
Net increase (decrease) in cash during the period	$	(4,770	)	$	(20,522	)	$	(18,306	)

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Substantially all of our cash flow from operating activities is from the production and sale of oil and natural gas. Cash inflows from oil and natural gas sales decreased in 2012 compared to 2011 primarily due to lower oil and natural gas prices, partially offset by increased oil production, and increased expenses and interest payments. Cash inflows from oil and natural gas sales and cash outflows for operating expenses both increased significantly from 2010 to 2011 as oil prices rose. Primarily as a result of the above activity, cash flows from operating activities decreased by 26% in 2012 from 2011 and increased by 55% from 2011 to 2010.

We use the net cash provided by operations to partially fund our acquisition, exploration and development activities. For the years ended December 31, 2012, 2011, and 2010, cash flows provided by operating activities were approximately 38%, 76%, and 54%, respectively, of cash used for the purchase of property and equipment and oil and natural gas properties. Our capital expenditures for oil and natural gas properties during 2012 are detailed in the next section. During 2012, cash flows used in investing activities included proceeds of $46.0 million from property dispositions, including approximately $37.0 million from the sale of certain mature oil and natural gas properties located in our Velma Area in southern Oklahoma. During 2011, cash flows used in investing activities included proceeds of $33.1 million from the sale of certain non-strategic oil and natural gas properties located in our Rocky Mountains area, and proceeds of $4.4 million from the sale of the remaining assets of Green Country Supply, Inc., a wholly owned subsidiary.

We received (paid) net derivative settlements totaling $37.3 million, $(23.5) million, and $45.5 million during 2012, 2011 and 2010, respectively. Cash flows used in investing activities in 2010 included proceeds from early derivative monetizations of $7.1 million. Primarily as a result of our net capital investments and derivative settlements, cash flows used in investing activities were $423.2 million, $325.0 million, and $264.2 million during 2012, 2011, and 2010, respectively.

Net cash provided by financing activities was $226.5 million, $44.9 million, and $78.2 million, during 2012, 2011, and 2010, respectively. On May 2, 2012, we issued $400.0 million aggregate principal amount of 7.625% Senior Notes maturing on November 15, 2022. We used the net proceeds from the 7.625% Senior Notes to consummate a tender offer for all of our 8.875% Senior Notes, to redeem the 8.875% Senior Notes not purchased in the tender offer, and for general corporate purposes. In connection with the issuance of the 7.625% Senior Notes and the repurchase or redemption of our 8.875%Senior Notes, we capitalized approximately $8.8 million of issuance costs related to underwriting and other fees and we expensed approximately $21.7 million of refinancing costs, including a $5.9 million non-cash write-off of deferred financing costs and unaccreted discount.

On November 15, 2012, we issued $150.0 million aggregate principal amount of 7.625% Senior Notes (the “Add-on Notes”) under the same indenture covering our $400.0 million issuance made on May 2, 2012. The net proceeds from the sale of the Add-on Notes were used to repay all of our outstanding indebtedness under our senior secured revolving credit facility and for general corporate purposes. In connection with the issuance of the Add-on Notes, we recorded a premium of $6.8 million and capitalized $3.5 million of issuance costs related to underwriting and other fees.

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, 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, we paid approximately $8.8 million of issuance costs related to underwriting and other fees and approximately $15.1 million of repurchase and redemption-related costs.

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 our issuance of the 9.875% Senior Notes, 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. The remaining $80.4 million was used for working capital.

Capital Expenditures

Our oil and natural gas property capital expenditure budget for 2012 was expanded during the third quarter of 2012 from $316.0 million to $443.0 million to accelerate capital investment associated with our North Burbank Unit CO₂ project. Expenditures were expected to occur over the next four years have been accelerated as field-wide communication was higher than anticipated. We have also made significant acquisitions of unproved leasehold acreage in the NOMP and the Panhandle Marmaton play, and participated in incremental outside-operated drilling opportunities in the NOMP, Anadarko Cleveland Sand and Anadarko Granite Wash plays. Investing in EOR reduces near-term growth opportunities but enhances longer-term growth and is consistent with our strategy of

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driving near-term growth through drilling and long-term growth through EOR development. The expanded budget was funded through net cash provided by operations, borrowings under our senior secured revolving credit facility, and sales of non-strategic properties. Expanded budget dollars that were unused in various areas were reallocated to complete our drilling program in the fourth quarter.

Our actual costs incurred for 2012 and our budgeted 2013 capital expenditures for oil and natural gas properties are summarized in the following table:

	2012 Capital Expenditures
(in thousands)	EOR Project Areas		Mid-Continent Area		Permian Basin Area		Other		Total		Budgeted 2013 capital expenditures(1)
Acquisitions	$	314	$	40,530	$	6,778	$	381	$	48,003	$	25,000
Drilling		20,337		229,378		16,866		2,047		268,628		234,000
Enhancements		53,922		9,487		6,674		5,342		75,425		55,000
Pipeline and field infrastructure		109,517		—				—		109,517		67,000
CO2 purchases		10,291		—		—		—		10,291		20,000
Total	$	194,381	$	279,395	$	30,318	$	7,770	$	511,864	$	401,000

(1) Includes $137.0 million allocated to our EOR project areas as follows: drilling of $17.0 million, enhancements of $34.0 million, pipeline and field infrastructure of $66.0 million, and CO₂ purchases of $19.0 million.

In addition to the capital expenditures for oil and natural gas properties, we spent approximately $19.0 million for property and equipment during 2012.

Our actual costs incurred for 2012 and our budgeted capital expenditures for oil and natural gas properties for 2013 are summarized by area in the following table:

(in thousands)	Actual 2012 capital expenditures		Percent of total			Budgeted 2013 capital expenditures		Percent of total
Enhanced Oil Recovery Project Areas	$	194,381		38	%	$	137,000		34	%
Mid-Continent Area		279,395		55	%		180,000		45	%
Permian Basin Area		30,318		6	%		84,000		21	%
Other		7,770		1	%		—		—
Total	$	511,864		100	%	$	401,000		100	%

During 2012, we increased our focus on the development of our EOR assets which is consistent with our strategy of driving near-term growth through drilling and long-term growth through EOR development. Investing in EOR reduces near-term growth opportunities but enhances longer-term growth. Our developmental and exploratory expenditures for EOR increased to $194.0 in 2012 from $88.2 million in 2011 and $37.7 million in 2010. Our oil and natural gas property capital expenditure budget for 2013 is set at $401.0 million, of which $137.0 million, or 34%, is allocated to the development of our EOR assets. In 2014, our EOR capital investments are expected to increase somewhat but remain less than incurred in 2012 and are expected to range between $75.0 million and $150.0 million in subsequent years.

We continually evaluate our capital needs and compare them to our capital resources. Our actual expenditures during 2013 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.

Senior Notes

On May 2, 2012, we issued $400,000 aggregate principal amount of 7.625% Senior Notes maturing on November 15, 2022. We used the net proceeds from the May 2, 2012 7.625% Senior Notes issuance to consummate a tender offer for all of our 8.875% Senior Notes due 2017, to redeem the 8.875% Senior Notes not purchased in the tender offer, and for general corporate purposes.

On November 15, 2012, we issued an additional $150,000 aggregate principal amount of 7.625% Senior Notes under the same indenture covering the issuance on May 2, 2102 (the “Add-on Notes”). The net proceeds from the Add-on Notes were used to repay the outstanding balance of the indebtedness under our senior secured revolving credit facility and for general corporate purposes. In connection with the sale of the Add-on Notes, we entered into a registration rights agreement in which we agree to file a registration

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statement with the SEC related to an offer to exchange the Add-on Notes for an issue of registered notes within 270 days of the closing date (the “Target Registration Date”). If we fail to complete the exchange offer by the Target Registration 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-day period, up to a maximum of 1.0% per annum.

In connection with the issuance of the May 2, 2012 7.625% Senior Notes, we capitalized approximately $8.8 million of issuance costs related to underwriting and other fees that are amortized to interest expense using the effective interest method. In connection with the issuance of the November 15, 2012 Add-on Notes, we recorded a premium of $6.8 million and capitalized $3.5 million of issuance costs related to underwriting and other fees that are amortized to interest expense using the effective interest method.

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, we capitalized approximately $8.8 million of issuance costs related to underwriting and other fees and we expensed approximately 20.6 million refinancing costs, including a $5.5 million non-cash write-off of deferred financing costs.

Senior Notes at December 31, 2012 and 2011 consisted of the following:

	December 31,
(in thousands)	2012			2011
8.875% Senior Notes due 2017		—			325,000
9.875% Senior Notes due 2020		300,000			300,000
8.25% Senior Notes due 2021		400,000			400,000
7.625 % Senior Notes due 2022		550,000			—
Discount on 8.875% Senior Notes due 2017		—			(1,658	)
Discount on 9.875% Senior Notes due 2020		(5,969	)		(6,441	)
Premium on 7.625% Senior Notes due 2022		6,631			—
	$	1,250,662		$	1,016,901

The Senior Notes are our senior unsecured obligations, rank equally in right of payment with all our existing and future senior debt, 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 or after the date that is five years before the maturity 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 date that is five years before the maturity 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 debt;

• make investments;

• incur liens on assets;

• create restrictions on the ability of our restricted subsidiaries to pay dividends, make loans, or transfer property to us;

• engage in transactions with affiliates;

• sell assets, including capital stock of our subsidiaries;

• consolidate, merge or transfer assets; and

• enter into other lines of business.

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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 us their Senior Notes at 101% of the principal amount, plus accrued and unpaid interest.

Senior Secured Revolving Credit Facility

In April 2010, we entered into our senior secured revolving credit facility, which is collateralized by our oil and natural gas properties, and matures on April 1, 2016. The balance outstanding under our senior secured revolving credit facility at December 31, 2012 and 2011 was $25.0 million and $0.0 million, respectively. As of April 11, 2013, we had drawn down $79.0 million under our senior secured revolving credit facility and we had committed to borrow an additional $20.0 million under our senior secured revolving credit facility, which will be funded on April 16, 2013.

During 2012, we had three amendments to our senior secured revolving credit facility. The Eighth Amendment to our senior secured revolving credit facility, effective April 30, 2012, amended our Asset Sale Covenant to permit the sale of certain oil and natural gas properties located in southern Oklahoma and increased our permitted ratio of Consolidated Net Debt to Consolidated EBITDAX. The Ninth Amendment to our senior secured revolving credit facility, effective May 24, 2012, changed the calculation of Consolidated EBITDAX to permit the exclusion of our reasonable and customary fees and expenses related to the refinancing of our 8.875% Senior Notes. The Tenth Amendment to our senior secured revolving credit facility, effective November 1, 2012, increased our borrowing base from $375.0 million to $500.0 million; increased the Aggregate Maximum Credit Amount from $450.0 million to $750.0 million and the maximum Aggregate Maximum Credit Amount (after giving effect to any exercise of the accordion option on the terms and conditions set forth in the senior secured revolving credit facility) to $850.0 million; extended the maturity date to November 1, 2017; reduced the applicable margins added to the Adjusted LIBO Rate for the purposes of determining the interest rate (i) on Eurodollar loans to a margin ranging from 1.50% to 2.50% and (ii) on Alternate Base Rate (“ABR”) loans to a margin ranging from 0.50% to 1.50%, each depending on the utilization percentage of the conforming borrowing base; reduced commitment fees to 0.375% if less than 50% of the borrowing base is utilized; reaffirmed the borrowing base through May 1, 2013 and permitted the offering of the Add-on Notes without triggering the automatic 25% reduction of the borrowing base.

Amounts borrowed under our senior secured revolving credit facility are subject to varying rates of interest based on (1) the total outstanding borrowings in relation to the borrowing base (the “utilization percentage”) and (2) whether we elect to borrow at the Eurodollar rate or the ABR. As of December 31, 2012, the balance outstanding under our senior secured revolving credit facility was $25.0 million, all of which was subject to the Eurodollar rate.

The Eurodollar rate 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 that varies depending on our utilization percentage. During 2012, the margin varied from 1.50% to 2.75%. 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 loans subject to the ABR 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 0.50%, or (3) the Adjusted LIBO Rate, as defined in our senior secured revolving credit facility, plus 1.0%, plus a margin that varies depending on our utilization percentage. During 2012, the margin varied from 0.50% to 1.75%.

Commitment fees of 0.375% to 0.50% accrued on the unused portion of the borrowing base amount based on the utilization percentage 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.

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. Effective November 1, 2012, our borrowing base was increased to $500.0 million through May 1, 2013.

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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, 2012 and 2011, our current ratio as computed using GAAP was 0.84 and 0.74, respectively. After giving effect to the adjustments, our current ratio computed for loan compliance purposes was 3.74 and 3.56, 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:

	December 31,
(in thousands)	2012			2011
Current assets per GAAP	$	163,617		$	124,123
Plus—Availability under senior secured revolving credit facility		474,080			372,080
Less—Short-term derivative instruments		(42,516	)		(12,840	)
Current assets as adjusted	$	595,181		$	483,363
Current liabilities per GAAP	$	194,590		$	167,717
Less—Short term derivative instruments		(436	)		(1,505	)
Less—Short-term asset retirement obligations		(2,900	)		(2,900	)
Less— Deferred tax liability on derivative instruments and asset retirement obligations		(32,051	)		(27,684	)
Current liabilities as adjusted	$	159,203		$	135,628
Current ratio for loan compliance		3.74			3.56

In April 2011, we amended our senior secured revolving credit facility to extend its maturity date from April 12, 2014 to April 1, 2016 and to permit the exclusion of our reasonable and customary fees and expenses related to the refinancing of our 8.5% Senior Notes due 2015 from the calculation of Consolidated EBITDAX.

Our senior secured revolving credit facility, as amended, requires us to maintain 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 each period of four consecutive fiscal quarters ending on the last day of such applicable fiscal quarter.

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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.

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, 2012:

(in thousands)	Less than 1 year		1-3 years		3-5 years		More than 5 years		Total
Debt:
Senior secured revolving credit facility	$	—	$	—	$	25,000	$	—	$	25,000
Senior Notes, including estimated interest		104,563		209,125		209,125		1,656,798		2,179,611
Other long-term notes and capital leases, including estimated interest		4,566		4,874		2,437		12,068		23,945
Commitment fees on senior secured revolving credit facility		1,875		3,750		3,464		—		9,089
Abandonment obligations		2,900		5,800		5,800		34,714		49,214
Derivative obligations		436		2,192		—		—		2,628
CO2 purchase commitments		1,397		6,263		2,578		22,648		32,886
Operating lease obligations		309		273		147		—		729
Other commitments		20,623		—		—		—		20,623
Total	$	136,669	$	232,277	$	248,551	$	1,726,228	$	2,343,725

We have a long-term contract to purchase CO₂ manufactured at an existing ethanol plant. As of December 31, 2012, we were purchasing approximately 14 MMcf/d of CO₂ under this contract, and we expect to purchase an average of approximately 13 MMcf/d over the remainder of the contract term, which expires in May 2024. Purchases under this contract were $1.1 million, $0.5 million, and $0.3 million during 2012, 2011, and 2010, respectively. Pricing is fixed for the remainder of the contract and the contract has renewal language.

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We have rights under two additional contracts with fertilizer plants under which we purchase CO₂ that is restricted, in whole or in part, for use only in EOR projects. Under both contracts, the fertilizer plants retain the right to install additional equipment and use some of the CO₂ to make certain fertilizer products, which could reduce the CO₂ available to us. Under one of these contracts, as of December 31, 2012, we were purchasing an average of approximately 19 MMcf/d and expect our purchases to remain at that level over the remainder of the contract term, which expires in February 2021. Purchases under this contract were $1.5 million, $1.5 million, and $1.0 million during 2012, 2011, and 2010, respectively. Under the second of these contracts, we have elected to purchase 10 MMcf/d of CO₂ through 2014, subject to availability. During 2012, we purchased approximately 1 MMcf/d of CO₂ under this contract. Purchases under this contract, which include transportation charges, were $1.2 million, $3.1 million, and $1.3 million during 2012, 2011, and 2010, respectively. We may terminate or permanently reduce our purchase rate under this contract, which expires in 2016, 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 42 MMcf/d of CO_2. We intend to use these CO₂ volumes 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. 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 23.5 MMcf/d the first year of the contract and 35.3 MMcf/d for the remaining contract years or pay for any deficiencies at the price in effect when the minimum delivery was to have occurred. After the first ten contract years, we may permanently reduce up to 100% of our purchase rate under this contract with six months notice. We expect to purchase an average of approximately 24 MMcf/d of CO₂ under this contract starting in the second quarter of 2013 and continuing for the remainder of 2013.

We have entered into operating lease agreements for the use of office space and equipment. We also rent equipment for use on our oil and natural gas properties. We have leases relating to office space and equipment that have terms of up to five years. As of December 31, 2011, total remaining payments associated with these operating leases were $0.7 million.

Other commitments that are not currently recorded on our balance sheet relate to contracts in place as of December 31, 2012, primarily for the purchase of pipe and other equipment relating to our CO₂ projects, drilling rig services, and other assets. These purchases are generally expected to be finalized within the next several months and are included in our capital expenditures budget for 2013. We generally have the ability to terminate the contracts for purchase of equipment and other assets, in which case our liability would be limited to the cost incurred by the vendor up to that point. Because we do not currently anticipate canceling these contracts, the estimated payments under these contracts have been included in “Other commitments” above.

Critical Accounting Policies

The discussion and analysis of our financial condition and results of operations are based upon our consolidated financial statements. The preparation of these statements requires us to make assumptions and estimates that affect the reported amounts of assets, liabilities, revenues and expenses. We base our estimates on historical experience and other sources that we believe are reasonable at the time. Actual results may differ from the estimates and assumptions we used in preparation of our financial statements. We evaluate our estimates and assumptions on a regular basis. Described below are the most significant policies and the related estimates and assumptions we apply in the preparation of our financial statements. See Note 1 to our consolidated financial statements for an additional discussion of accounting policies and estimates made by management.

Revenue recognition. We derive almost all of our revenue from the sale of crude oil and natural gas produced from our oil and natural gas properties. Revenue is recorded in the month the product is delivered to the purchaser. We receive payment on substantially all of these sales from one to three months after delivery. At the end of each month, we estimate the amount of production delivered to purchasers that month and the price we will receive. Variances between our estimated revenue and actual payment received for all prior months are recorded in the month payment is received.

Derivative instruments. We determine the fair value of our crude oil, natural gas, and basis swaps by reference to forward pricing curves for oil and natural gas futures contracts. The difference between the forward price curve and the contractual fixed price is discounted to the measurement date using a credit risk adjusted discount rate. In certain less liquid markets, forward prices are not as readily available. In these circumstances, swaps are valued using internally developed methodologies that consider historical relationships among various commodities that result in management’s best estimate of fair value. These contracts are classified as Level 3 in accordance with the fair value hierarchy defined by the Financial Accounting Standards Board (“FASB”). We have determined that the fair value methodology described above for the remainder of our swaps is consistent with observable market inputs and have categorized them as Level 2. We determine fair value for our oil and natural gas collars using an option pricing model

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which takes into account market volatility, market prices, contract parameters, and credit risk. Due to unavailability of observable volatility data input for our collars, we have determined that all of our collars’ fair value measurements are categorized as Level 3. Derivative instruments are discounted using a rate that incorporates our nonperformance risk for derivative liabilities, and our counterparties’ credit risk for derivative assets. Our derivative contracts have been executed with the institutions that are parties to our revolving credit facility. We believe the credit risks associated with all of these institutions are acceptable.

Certain of our oil and natural gas derivative contracts have historically been treated as cash flow hedges under GAAP. This policy significantly impacts the timing of revenue or expense recognized from this activity, as our contracts are adjusted to their fair value at the end of each month. The effective portion of the hedge gain or loss, meaning the portion of the change in the fair value of the contract that offsets the change in the expected future cash flows from our forecasted sales of production, is recognized in income when the hedged production is reported as revenue. We reflect this as an adjustment to our revenue in the “Gain (loss) from oil and natural gas hedging activities” line in our consolidated statements of operations. Until hedged production is reported in earnings and the contract settles, the effective portion of change in the fair value of the contract is reported in the “Accumulated other comprehensive income (loss)” line item in stockholders’ equity. The ineffective portion of the hedge gain or loss is reported in the “Gain (loss) from oil and natural gas hedging activities” line item each period. Our derivative contracts that do not qualify for cash flow hedge treatment, or have not been designated as cash flow hedges, are marked to their period end market values and the change in the fair value of the contracts is included in the “Non-hedge derivative gains (losses)” line in our consolidated statements of operations. 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, our reported earnings could include large non-cash fluctuations, particularly in volatile pricing environments.

Oil and natural gas properties.

• Full cost accounting. We use the full cost method of accounting for our oil and natural gas properties. Under this method, all costs incurred in the exploration and development of oil and natural gas properties are capitalized into a cost center. These costs include drilling and equipping productive wells, dry hole costs, seismic costs and delay rentals. Capitalized costs also include salaries, employee benefits, consulting services and other expenses that directly relate to our exploration and development activities.

• Proved oil and natural gas reserves quantities. Proved oil and natural gas reserves are the quantities of crude oil and natural gas which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain. The estimates of proven reserves for a given reservoir may change significantly over time as a result of changing prices, operating cost, additional development activity and the actual operating performance.

Our proved reserve information included in this prospectus is based on estimates prepared by Cawley, Gillespie & Associates, Inc. and Ryder Scott Company, L.P. each independent petroleum engineers, and our engineering staff. The independent petroleum engineers evaluated approximately 85% of the estimated future net revenues of our proved reserves discounted at 10% as of December 31, 2012, and our engineering staff evaluated the remainder. We continually make revisions to reserve estimates throughout the year as additional information becomes available.

• Depreciation, depletion and amortization. The quantities of proved oil and natural gas reserves are a significant component of our calculation of depreciation, depletion and amortization expense, and revisions in such estimates may alter the rate of future expense. The depreciation, depletion and amortization rate is determined using the units-of-production method based on estimates of proved oil and natural gas reserves and production, which are converted to a common unit of measure based on the relative energy content.

• Full cost ceiling limitation. Under the full cost method, the net capitalized costs of oil and natural gas properties recorded on our balance sheet cannot exceed the estimated future net revenues discounted at 10%, adjusted for the impact of derivatives accounted for as cash flow hedges, plus the cost of unproved properties not being amortized. The ceiling calculation requires that prices and costs used to determine the estimated future net revenues exclude escalations based upon future conditions. If oil and natural gas prices decline or if we have downward revisions to our estimated reserve quantities, it is possible that write downs of our oil and natural gas properties could occur in the future.

• Costs not subject to amortization. Costs of unevaluated properties are excluded from our amortization base until we have evaluated the properties. The costs associated with unevaluated leasehold acreage and seismic data, exploratory wells currently drilling, and capitalized interest are initially excluded from our amortization base. Leasehold costs are either transferred to the amortization base with the costs of drilling a well or are assessed quarterly for possible impairment. Our future depreciation, depletion and amortization rate would increase if costs are transferred to the amortization base without any associated reserves.

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• Future development and abandonment costs. Our future development costs include costs to be incurred to obtain access to proved reserves such as drilling costs and the installation of production equipment. Future abandonment costs include costs to plug and abandon our oil and natural gas properties and related facilities. We develop estimates of these costs for each of our properties based on their location, type of facility, market demand for equipment and currently available procedures. Because these costs typically extend many years into the future, estimating these future costs is difficult and requires management to make numerous judgments. These judgments are subject to future revisions from changing technology and regulatory requirements. We review our assumptions and estimates of future development and future abandonment costs on a quarterly basis.

We record a liability for the estimated fair value of an asset retirement obligation in the period in which it is incurred and the corresponding cost is capitalized by increasing the carrying value of the related asset. The liability is accreted to its present value each period and the capitalized cost is depreciated over the useful life of the related asset.

We use the present value of estimated cash flows related to our asset retirement obligation to determine the fair value. Significant assumptions used in estimating such obligations include estimates of the ultimate costs of dismantling and site restoration, inflation factors, credit adjusted discount rates, timing of settlement, and changes in the legal, regulatory, environmental and political environments, all of which are Level 3 inputs in the fair value hierarchy. To the extent future revisions to these assumptions impact the present value of the existing asset retirement obligation liability, a corresponding adjustment will be required for the related asset. We believe the estimates and judgments reflected in our financial statements are reasonable but are necessarily subject to the uncertainties we have just described. Accordingly, any significant variance in any of the above assumptions or factors could materially affect our estimated future cash flows.

Income taxes. Deferred income taxes are provided for the difference between the tax basis of assets and liabilities and the carrying amount in our financial statements. This difference will result in taxable income or deductions in future years when the reported amount of the asset or liability is settled. Since our tax returns are filed after the financial statements are prepared, estimates are required in valuing tax assets and liabilities. We record adjustments to actual in the period we file our tax returns.

Valuation allowance for NOL carryforwards. In computing our income tax expense, we assess the need for a valuation allowance on deferred tax assets, which consist primarily of net operating loss, or NOL, carryforwards. For federal income tax purposes these NOL carryforwards expire 15 to 20 years from the year of origination. We generally assess our ability to fully utilize these carryforwards by estimating expected future taxable income based on the assumption that we will produce our existing reserves, as scheduled for production in our reserve report and by analyzing the expected reversal of existing deferred tax liabilities. These computations are imprecise due to the extensive use of estimates and assumptions. Each quarter we assess our ability to utilize NOL carryforwards. We record a valuation allowance for the amount of net deferred tax assets when, in management’s opinion, it is more likely than not that such asset will not be realized.

Impairment of long-lived assets. Impairment losses are recorded on property and equipment used in operations and other long-lived assets when indicators of impairment are present and the undiscounted cash flows estimated to be generated by those assets are less than the assets’ carrying amounts. Impairment is measured based on the excess of the carrying amount over the fair value of the asset.

Assets Held for Sale. The accounting for assets held for sale is in accordance with ASC 360-10, Property, Plant and Equipment. Under this guidance, the assets are carried on the balance sheet at their carrying value or fair value less cost to sell, whichever is less.

Recent Accounting Pronouncements

In May 2011, the FASB issued authoritative guidance that clarifies the application of fair value measurement and disclosure requirements and changes particular principles or requirements for measuring fair value. This guidance is effective for interim and annual periods beginning after December 15, 2011, and we adopted it on January 1, 2012. There was no significant impact on our consolidated financial statements other than additional disclosures.

In June 2011, the FASB issued new authoritative guidance that requires entities that report other comprehensive income to present the components of net income and comprehensive income in either one continuous financial statement or two consecutive financial statements. It does not change the items that must be reported in other comprehensive income or when an item of other comprehensive income must be reclassified to net income. This guidance is effective for interim and annual periods beginning after December 15, 2011, and we applied it beginning on January 1, 2012. We have elected to present the components of net income and comprehensive income in two consecutive financial statements.

In July 2011, the FASB issued authoritative guidance regarding how health insurers should recognize and classify in their income statements the fees mandated by the Health Care and Education Reconciliation Act (“HCERA”). The HCERA imposes an annual fee upon health insurers for each calendar year beginning on or after January 1, 2014. The annual fee will be allocated to individual entities providing health insurance to employees based on a ratio, as provided for in the HCERA, and is not tax deductible. This guidance specifies that once the entity has provided qualifying health insurance in the calendar year in which the fee is payable,

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the liability for the entity’s fee should be estimated and recorded in full with a corresponding deferred cost that is amortized to expense on a straight line basis, unless another method better allocates the fee over the calendar year that it is payable. This guidance is effective for calendar years beginning after December 15, 2013, once the fee is instituted. We are currently assessing the impact that this fee and the adoption of the related authoritative guidance will have on our financial statements.

In December 2011, the FASB issued authoritative guidance requiring entities to provide enhanced disclosures that will enable users of its financial statements to evaluate the effect or potential effect of netting arrangements on an entity’s financial position. The guidance is effective for interim and annual periods beginning after January 1, 2013. We will adopt the requirements with the preparation of our Form 10-Q for the quarter ending March 31, 2013, which will require additional footnote disclosures for our derivative instruments and are not expected to have a material effect on our consolidated financial statements.

See recently adopted and issued accounting standards in Part II, Item 8. Financial Statements, Note 1, “Nature of operations and summary of significant accounting policies.”

Effects of Inflation and Pricing

While the general level of inflation affects certain of our costs, factors unique to the oil and natural gas industry result in independent price fluctuations. Historically, significant fluctuations have occurred in oil and natural gas prices. In addition, changing prices often cause costs of equipment and supplies to vary as industry activity levels increase and decrease to reflect perceptions of future price levels. Although it is difficult to estimate future prices of oil and natural gas, price fluctuations have had, and will continue to have, a material effect on us.

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Quantitative and Qualitative Disclosures Regarding Market Risks

Oil and natural gas prices. Our financial condition, results of operations 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 due to a variety of factors that are beyond our control. We cannot predict future oil and natural gas prices with any degree of certainty. Sustained declines in oil and natural gas prices may adversely affect our financial condition and results of operations, and may also reduce the amount of net oil and natural gas reserves that we can produce economically. Any reduction in reserves, including reductions due to price fluctuations, can reduce our borrowing base under our senior secured revolving credit facility and adversely affect our liquidity and our ability to obtain capital for our acquisition, exploration, and development activities. Based on our production for the year ended December 31, 2012, our gross revenues from oil and natural gas sales would change approximately $5.8 million for each $1.00 change in oil prices and $2.0 million for each $0.10 change in natural gas prices.

To mitigate a portion of our exposure to fluctuations in commodity prices, we enter into commodity price swaps, costless collars, and basis protection swaps.

Effective April 1, 2010, we elected to de-designate all of our commodity contracts that had previously been designated as cash flow hedges and to discontinue hedge accounting prospectively. Therefore, the changes in fair value and settlement of all our derivative contracts subsequent to March 31, 2010 are recognized as non-hedge derivative gains (losses). This can have a significant impact on our results of operations due to the volatility of the underlying commodity prices.

For commodity price swaps, we receive a fixed price for the hedged commodity and pay a floating market price to the counterparty. The fixed-price payment and the floating-price payment are netted, resulting in a net amount due to or from the counterparty.

Collars contain a fixed floor price (put) and ceiling price (call). If the market price exceeds the call strike price or falls below the put strike price, we receive the fixed price and pay the market price. If the market price is between the call and the put strike price, no payments are due from either party. A three-way collar contract consists of a standard collar contract plus a put option contract sold by us with a price below the floor price of the collar. This additional put option requires us to make a payment to the counterparty if the market price is below the additional put option price. If the market price is greater than the additional put option price, the result is the same as it would have been with a standard collar contract only. By combining the collar contract with the additional put option, we are entitled to a net payment equal to the difference between the floor price of the standard collar and the additional put option price if the market price falls below the additional put option price. This strategy enables us to increase the floor and the ceiling price of the collar beyond the range of a traditional costless collar while defraying the associated cost with the sale of the additional put option.

We use basis protection swaps to reduce basis risk. Basis is the difference between the physical commodity being hedged and the price of the futures contract used for hedging. Basis risk is the risk that an adverse change in the futures market will not be completely offset by an equal and opposite change in the cash price of the commodity being hedged. Basis risk exists in natural gas primarily due to the geographic price differentials between cash market locations and futures contract delivery locations. Natural gas basis protection swaps are arrangements that guarantee a price differential for natural gas from a specified pricing point. We receive a payment from the counterparty if the price differential is greater than the stated terms of the contract and pay the counterparty if the price differential is less than the stated terms of the contract.

Derivative positions are adjusted in response to changes in prices and market conditions as part of an ongoing dynamic process. We review our derivative positions continuously and if future market conditions change, we may execute a cash settlement with our counterparty, restructure the position, or enter into a new swap that effectively reverses the current position (a counter-swap). The factors we consider in closing or restructuring a position before the settlement date are identical to those we reviewed when deciding to enter into the original derivative position.

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Our outstanding oil and natural gas derivative instruments as of December 31, 2012, are summarized below:

	Oil derivatives
	Swaps				Three-way collars
			Weighted average
							Weighted average fixed price per Bbl
	Volume MBbls		fixed price per Bbl		Volume MBbls		Additional put option		Put		Call		Percent of production(1)
1Q 2013		255	$	96.82		930	$	78.06	$	100.10	$	114.41		81.1	%
2Q 2013		255		96.87		950		77.89		99.92		114.06		81.5	%
3Q 2013		255		96.78		930		77.74		99.81		114.11		83.3	%
4Q 2013		255		96.65		900		77.83		99.94		114.49		85.2	%
1Q 2014		—		—		330		75.91		92.54		103.08		24.3	%
2Q 2014		—		—		330		75.91		92.54		103.08		20.7	%
3Q 2014		—		—		330		75.91		92.54		103.08		19.9	%
4Q 2014		—		—		330		75.91		92.54		103.08		19.5	%
		1,020				5,030

	Natural gas swaps							Natural gas basis protection swaps
	Volume BBtu		Weighted average fixed price per Btu		Percent of production(1)			Volume BBtu		Weighted average fixed price per Btu
1Q 2013		4,200	$	4.30		80.1	%		4,050	$	0.20
2Q 2013		4,200		4.19		78.9	%		4,250		0.20
3Q 2013		4,200		4.27		84.8	%		4,050		0.20
4Q 2013		4,200		4.46		91.7	%		4,050		0.20
1Q 2014		2,100		4.00		45.9	%		3,750		0.23
2Q 2014		2,100		3.85		41.4	%		3,620		0.23
3Q 2014		2,100		3.91		40.0	%		3,360		0.23
4Q 2014		2,100		4.05		39.3	%		3,360		0.23
		25,200							30,490

(1) Based on our year-end proved reserves estimated using SEC pricing.

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Subsequent to December 31, 2012, we entered into the following derivative instruments:

	Crude oil enhanced swaps						Crude oil swaps				Crude oil three-way collars											Natural gas swaps
									Weighted															Weighted
			Weighted average						average															average
			fixed price per Bbl						fixed price		Weighted average fixed price per Bbl													fixed price
	Volume MBbls		Additional put option		Swap		Volume MBbls		to be received		Volume MBbls		Additional put option			Put			Call			Volume BBtu		to be received
1Q 2013		—	$	—	$	—		30	$	93.06		—	$		—	$		—	$		—		460	$	3.16
2Q 2013		—		—		—		65		93.68		—		—			—			—			830		3.39
3Q 2013		—		—		—		60		94.00		—		—			—			—			690		3.40
4Q 2013		—		—		—		90		93.73		—		—			—			—			690		3.61
1Q 2014		210		80.00		99.76		120		95.22		270		75.00			94.11			100.55			2,100		4.05
2Q 2014		210		80.00		98.94		120		94.16		270		75.00			94.11			100.55			2,160		3.95
3Q 2014		210		80.00		98.20		120		93.16		270		75.00			94.11			100.55			2,430		4.02
4Q 2014		210		80.00		97.58		120		92.37		270		75.00			94.11			100.55			2,430		4.18
1Q 2015		150		80.00		94.02		—		—		—		—			—			—			2,400		4.36
2Q 2015		150		80.00		94.02		—		—		—		—			—			—			2,400		4.11
3Q 2015		150		80.00		94.02		—		—		—		—			—			—			2,400		4.18
4Q 2015		150		80.00		94.02		—		—		—		—			—			—			2,400		4.33
		1,440						725				1,080											21,390

An enhanced swap contract consists of a standard swap contract plus a put option contract sold by us with a price below the swap. This additional put option requires us to make a payment to the counterparty if the market price is below the additional put option price. If the market price is greater than the additional put option price, the result is the same as it would have been with a standard swap contract only. By combining the swap contract with the additional put option, we are entitled to a net payment equal to the difference between the swap price and the additional put option price if the market price falls below the additional put option price. This strategy enables us to increase the swap price beyond the range of a traditional swap while defraying the associated cost with the sale of the additional put option.

Interest rates. All of the outstanding borrowings under our senior secured revolving facility as of December 31, 2012 are subject to market rates of interest as determined from time to time by the banks. We may designate borrowings under our senior secured revolving credit facility as either ABR loans or Eurodollar loans. ABR loans bear interest at a fluctuating rate that is linked to 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 the 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%. Eurodollar loans bear interest at a fluctuating rate that is linked to LIBOR. Any increases in these rates can have an adverse impact on our results of operations and cash flow. Assuming a constant debt level of $500.0 million, equal to our borrowing base at December 31, 2012, the cash flow impact for a 12-month period resulting from a 100 basis point change in interest rates would be $5.0 million.

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BUSINESS AND PROPERTIES

The following should be read in conjunction with the “Glossary of Terms” section set forth in this prospectus.

Overview

We are a growing independent oil and natural gas production and exploitation company. Since our inception in 1988, we have increased reserves and production primarily through property acquisitions and development activities. Our core operations consist of drilling for and production of oil and natural gas from conventional and unconventional reservoirs as well as a focus on tertiary operations through enhanced oil recovery (“EOR”) projects utilizing CO₂ and polymer in the Mid-Continent and Permian Basin areas. We maintain a portfolio of proved and unproved reserves, development and exploratory drilling opportunities, and EOR projects. Starting in 2011, we began to redirect our capital expenditures from the drilling of vertical wells to the drilling of horizontal wells in repeatable resource plays and increased our level of expenditures on EOR projects.

As of December 31, 2012, we had estimated proved reserves of 146.1 MMBoe with a PV-10 value of approximately $2.1 billion. These estimated proved reserves included 29.5 MMBoe of EOR reserves. Our reserves were 65% proved developed and 65% crude oil. For the year ended December 31, 2012, our net average daily production was 25.0 MBoe, our estimated reserve life was approximately 16 years, and our oil and natural gas revenues were $509.5 million . We set forth our definition of PV-10 value (a non-GAAP measure) and a reconciliation of the standardized measure of discounted future net cash flows to PV-10 value elsewhere in this prospectus.

From 2003 to 2012, our proved reserves and production grew at a compounded annual growth rate of 12% and 15%, respectively. During this period, we have grown primarily through a combination of developmental drilling and a disciplined strategy of acquiring proved oil and natural gas reserves, followed by exploitation activities and the acquisition of additional interests in or near these acquired properties. We have typically pursued properties in the second half of their life with stable production, shallow decline rates and with particular producing trends and characteristics indicative of production or reserve enhancement opportunities. Since 2011, we have reduced the amount of costs incurred for proved property acquisitions and spent more on acquisition of leasehold acreage and exploration costs in resource plays with repeatable drilling opportunities. In 1993, we began acquiring properties with CO₂ EOR potential, and we have initiated CO₂ injection in 9 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 long-term growth to come from the development of our CO₂ EOR operations, with our near term growth coming from drilling activities.

Business Strategy

We are positioned to grow our reserves and production profitably through our oil focused drilling activities, primarily in our repeatable resource plays, in the near term and through our CO₂ EOR projects in the long term. From 2003 to 2012, we have grown proved reserves and production by a compounded annual growth rate of 12% and 15%, 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 383% per year from 2003 through 2012. We replaced approximately 156% of our production in 2012.

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, 2012, we operated properties comprising approximately 85% of our proved reserves. We also strive to minimize commodity price risk through our financial hedging program. The principal elements of our strategy are described further below.

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

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

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

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

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

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

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

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

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

Hedge production to stabilize cash flow. Our long-lived reserves provide us with relatively predictable production. To protect cash flows that we use for on-going operations and for capital investments, 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.

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Based on our year-end proved reserves estimated using SEC pricing as of December 31, 2012, we had derivative contracts in place for approximately 21% and 63%, respectively, of our estimated oil and natural gas liquids and natural gas production through 2014. During 2012, we received $11.8 million and $25.5 million on the net settlement of our derivative oil and natural gas contracts, respectively. During 2011 we paid $57.6 million on the net settlement of our derivative oil contracts and received $34.1 million on the net settlement of our derivative natural gas contracts through a period of increasing oil prices and decreasing natural gas prices. During 2010, we received net derivative settlements of $40.0 million which included proceeds from early derivative monetizations of $7.1 million.

Properties

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

	Proved reserves as of December 31, 2012											Average daily production (MBoe per day) Year ended December 31, 2012		Average daily production (MBoe per day) Quarter  ended December 31, 2012
	Oil (MBbls)(1)		Natural gas (MMcf)		Total (MBoe)		Percent of total MBoe			PV-10 value ($MM)
Enhanced Oil Recovery Project Areas		44,182		392		44,247		30.3	%	$	705.2		3.7		4.0
Mid-Continent Area		44,788		175,760		74,081		50.7	%		1,043.0		15.6		17.6
Permian Basin Area		8,731		47,040		16,571		11.3	%		185.4		3.3		3.5
Other		5,542		33,923		11,196		7.7	%		135.1		2.4		2.1
Total		103,243		257,115		146,095		100.0	%	$	2,068.7		25.0		27.2

(1) Includes natural gas liquids.

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, 2012, we owned interests in 8,243 gross (2,843 net) producing wells and we operated wells representing approximately 85% of our proved reserves. The high proportion of reserves in our operated properties allows us to exercise more control over expenses, capital allocations and the timing of development and exploitation activities in our fields.

Enhanced Oil Recovery Project Areas

Our EOR Project Areas include both EOR activities and ongoing non-EOR activities, as reflected in the following table:

As of and for the year ended December 31, 2012	EOR		Non-EOR		Total for EOR Project Areas
Reserves (MBoe)		29,450		14,797		44,247
Production (Boe/d)		2,246		1,503		3,749
Drilling and enhancements (in thousands)	$	193,959	$	108	$	194,067

We have been actively implementing and managing CO₂ EOR in the Panhandle and Central Oklahoma Areas since 2001. We now have CO₂ supply agreements in place in the Burbank, Panhandle, and Central Oklahoma Areas, and we have built and/or expanded CO₂ pipelines to reach our various field locations in the Panhandle and Central Oklahoma Areas. The CO₂ pipeline reaching the Burbank Area is scheduled for completion near the end of the first quarter of 2013. 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.

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

Burbank Area

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

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

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

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

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

Panhandle Area

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

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

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

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

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

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

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

Permian Basin Area

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

Mid-Continent Area

As of December 31, 2012, the Mid-Continent Area accounted for 74.1 MMBoe, or 51% of our proved reserves. During the year ended December 31, 2012, our net average daily production in the Mid-Continent Area was approximately 15.6 MBoe per day, or 62% of our total net average daily production. This Area is characterized by stable, long-life, shallow decline reserves. We produce and drill in most of the formations in the region and have significant holdings and activity in the areas described below.

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

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

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

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

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

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

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

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

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

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

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

Permian Basin Area

As of December 31, 2012, the Permian Basin Area accounted for 16.6 MMBoe, or 11% of our proved reserves. During the year ended December 31, 2012, our net average daily production in the Permian Basin Area was approximately 3.3 MBoe per day, or 13% of our total net average daily production.

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

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

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

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

Tunstill Field Play—Loving and Reeves Counties, Texas. The Tunstill Field Play represented 2.8 MMBoe, or 1.9% of our proved reserves at December 31, 2012. Our net average daily production from this area decreased 16% to approximately 736 Boe/d in 2012 from 876 Boe/d in 2011, primarily due to a reduction in drilling activity. Net average daily production was 669 Boe/d in 2010. During 2012, our drilling investment was $4.1 million, and we drilled or participated in the drilling of two wells in this area. We have allocated approximately $1.7 million of our 2013 drilling budget to this area.

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Other Areas

Ark-La-Tex. The Ark-La-Tex area accounted for 5.4 MMBoe, or 4% of our proved reserves as of December 31, 2012. Our net production from this area decreased to approximately 1,159 Boe/d in 2012 from 1,306 Boe/d in 2011. The 11% decline was primarily due to normal depletion of the reservoirs. Our total capital investment of $1.6 million during 2012 was primarily for workovers on existing wells. We have not allocated any significant amount of our 2013 drilling budget to this area.

Gulf Coast. The Gulf Coast area accounted for 2.0 MMBoe, or 1% of our proved reserves as of December 31, 2012. Our net average daily production from this area was approximately 753 Boe/d in 2012, 872 Boe/d in 2011, and 763 Boe/d in 2010. The 14% decline in 2012 as compared to 2011 is primarily due to strategic divestitures of properties within the area. Our total capital investment of $2.1 million during 2012 was primarily for workovers on existing wells. We have not allocated any significant amount of our 2013 drilling budget to this area.

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

Rocky Mountains. On November 28, 2011, we sold our non-strategic oil and natural gas properties consisting of 3.4 MMBoe located in the Rocky Mountains area to Charger Resources, LLC for a cash price of approximately $33.1 million. In accordance with the full cost method of accounting, we reduced our full cost pool by the amount of the net proceeds and did not record a gain or loss on the sale. Our Rocky Mountains area accounted for approximately 2% of our production in 2011.

Oil and Natural Gas Reserves

Proved reserves are those quantities of oil and natural gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—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 Corporate Reserves group, which is led by our Associate Vice President of Corporate Reserves who has a Master of Science in Petroleum Engineering and 17 years of industry experience that includes diverse petroleum engineering roles and reserves management for a publicly traded company.

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

This data is 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 more than 30 years of petroleum consulting experience. The person responsible for overseeing the preparation of our reserve estimates at Ryder Scott Company, L.P. is a licensed Professional Engineer with over 30 years of practical experience in the estimation and evaluation of petroleum reserves.

Our reserves are reviewed by senior management, which includes the President and Chief Executive Officer, the Chief Operating Officer, and the Chief Financial Officer, and they are responsible for verifying that the estimate of proved reserves is reasonable, complete, and accurate. Members of senior management may also meet with the key representatives 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 President and Chief Executive Officer, Chief Operating Officer, and Chief Financial Officer.

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Proved Reserves. The table below summarizes our net proved oil and natural gas reserves and PV-10 values at December 31, 2012. Information in the table is derived from reserve reports of estimated proved reserves prepared by Cawley, Gillespie & Associates, Inc. (50% of PV-10 value) and by Ryder Scott Company, L.P. (34% of PV-10 value). Copies of the summary reserve reports prepared by these independent reserve engineers are attached as exhibits to this prospectus. Our internal engineering staff has prepared a report of estimated proved reserves on the remaining smaller value properties (16% of PV-10 value) at December 31, 2012. We set forth our definition of PV-10 value (a non-GAAP measure) and a reconciliation of the standardized measure of discounted future net cash flows to PV-10 value elsewhere in this prospectus.

	Net proved reserves as of December 31, 2012
	Oil (MBbls)(1)		Natural gas (MMcf)		Total (MBoe)		PV-10 value (in thousands)
Developed-producing		54,000		153,413		79,569	$	1,384,128
Developed-non-producing		9,956		32,412		15,361		171,527
Undeveloped		39,287		71,290		51,165		512,965
Total proved		103,243		257,115		146,095	$	2,068,620

(1) Includes natural gas liquids.

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, 2012, 2011, and 2010 were prepared by Cawley, Gillespie & Associates, Inc. (50%, 50%, and 52% of PV-10 value, respectively) and Ryder Scott Company, L.P. (34%, 34%, and 31% of PV-10 value, respectively). Our internal engineering staff has prepared a report of estimated proved reserves on our remaining smaller value properties (16%, 16%, and 17% of PV-10 value in 2012, 2011, and 2010, respectively).

	As of December 31,
	2012			2011			2010
Estimated proved reserve volumes:
Oil (Mbbls)(1)		103,243			100,380			93,412
Natural gas (MMcf)		257,115			335,280			335,220
Oil equivalent (MBoe)		146,095			156,260			149,282
Proved developed reserve percentage		65	%		64	%		66	%
Estimated proved reserve values (in thousands):
Future net revenue	$	4,780,316		$	5,473,678		$	4,110,844
PV-10 value	$	2,068,620		$	2,309,089		$	1,770,061
Standardized measure of discounted future net cash flows	$	1,523,681		$	1,597,912		$	1,236,026
Oil and natural gas prices:(2)
Oil price (per Bbl)(1)	$	94.71		$	96.19		$	79.43
Natural gas price (per Mcf)	$	2.76		$	4.11		$	4.38
Estimated reserve life in years(3)		16.0			18.1			18.5

(1) Includes natural gas liquids.

(2) Prices were based upon the average first day of the month prices for each month during the respective year.

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

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Proved Undeveloped Reserves. The following table shows material changes in proved undeveloped reserves that occurred during the year ended December 31, 2012.

	MBoe
Proved undeveloped reserves as of January 1, 2012		56,142
Undeveloped reserves transferred to developed(1)		(3,351	)
Sales of minerals in place, net of purchases		(970	)
Extensions and discoveries		7,527
Improved recoveries		281
Revisions and other		(8,464	)
Proved undeveloped reserves as of December 31, 2012(2)		51,165

(1) Approximately $61.7 million of developmental costs incurred during 2012 related to undeveloped reserves that were transferred to developed.

(2) Includes 2.9 MMBoe and 14.1 MMBoe, respectively, of reserves that have been reported for more than five years that relate specifically to our Camrick area CO₂ EOR projects and our North Burbank polymer EOR projects. Development of these projects is ongoing. See “Properties—Enhanced Oil Recovery Project Areas” for additional discussion of our CO₂ EOR projects.

Productive Wells

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, 2012 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 natural gas wells				Total
	Gross		Net		Gross		Net		Gross		Net
Operated Wells:
Enhanced Oil Recovery Project Areas		419		392		—		—		419		392
Mid-Continent Area		1,229		1,086		438		326		1,667		1,412
Permian Basin Area		313		294		53		43		366		337
Other		146		126		104		84		250		210
Total		2,107		1,898		595		453		2,702		2,351
Non-Operated Wells:
Enhanced Oil Recovery Project Areas		254		8		—		—		254		8
Mid-Continent Area		2,161		262		1,144		123		3,305		385
Permian Basin Area		1,061		48		86		20		1,147		68
Other		718		21		117		10		835		31
Total		4,194		339		1,347		153		5,541		492
Total Wells:
Enhanced Oil Recovery Project Areas		673		400		—		—		673		400
Mid-Continent Area		3,390		1,348		1,582		449		4,972		1,797
Permian Basin Area		1,374		342		139		63		1,513		405
Other		864		147		221		94		1,085		241
Total		6,301		2,237		1,942		606		8,243		2,843

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Drilling Activity

The following table sets forth information with respect to wells drilled during the periods indicated. 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.

	2012						2011						2010
	Gross			Net			Gross			Net			Gross			Net
Development wells
Productive		134.0			43.0			279.0			65.9			234.0			100.0
Dry		1.0			1.0			7.0			4.1			5.0			1.9
Exploratory wells
Productive		29.0			14.0			7.0			5.1			18.0			18.0
Dry		—			—			—			—			1.0			1.0
Total wells
Productive		163.0			57.0			286.0			71.0			252.0			118.0
Dry		1.0			1.0			7.0			4.1			6.0			2.9
Total		164.0			58.0			293.0			75.1			258.0			120.9
Percent productive		99	%		98	%		98	%		95	%		98	%		98	%

Developed and Undeveloped Acreage

The following table details our gross and net interest in developed and undeveloped acreage at December 31, 2012 by state. This does not include acreage in which we hold only royalty interests.

	Developed				Undeveloped(1)				Total
	Gross		Net		Gross		Net		Gross		Net
Arkansas		1,895		1,041		—		—		1,895		1,041
Kansas		11,322		8,533		160		160		11,482		8,693
Louisiana		14,430		5,217		480		231		14,910		5,448
Mississippi		790		36		—		—		790		36
New Mexico		22,018		10,591		2,546		1,407		24,564		11,998
Oklahoma		799,840		343,725		113,652		82,120		913,492		425,845
Texas		211,611		135,814		60,004		39,779		271,615		175,593
Total		1,061,906		504,957		176,842		123,697		1,238,748		628,654

(1) Approximately 10%, 21%, and 38% of our net undeveloped acres will expire in 2013, 2014 and 2015, respectively, if not successfully developed or renewed.

Property Acquisition, Development and Exploration Costs

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,
(in thousands)	2012			2011			2010
Property acquisition costs
Proved properties	$	1,108		$	1,024		$	32,458
Unproved properties		46,895			15,795			9,062
Total acquisition costs		48,003			16,819			41,520
Development costs		409,429			250,182			251,564
Exploration costs(1)		54,432			57,016			34,180
Total	$	511,864		$	324,017		$	327,264
Annual reserve replacement ratio(2)		156	%		169	%		247	%

(1) Includes $52.2 million, $33.0 million, and $16.7 million of EOR costs in 2012, 2011 and 2010, respectively.

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(2) 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 15 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,
	2012						2011						2010
	Reserves replaced			Percent of total			Reserves replaced			Percent of total			Reserves replaced			Percent of total
Purchases of minerals in place		1	%		0.1	%		5	%		2.6	%		52	%		21.2	%
Extensions and discoveries		146	%		94.0	%		152	%		90.2	%		138	%		55.7	%
Improved recoveries		9	%		5.9	%		12	%		7.2	%		57	%		23.1	%
Total		156	%		100.0	%		169	%		100.0	%		247	%		100.0	%

Production and Price History

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,
	2012		2011		2010
Production:(1)
Oil (MBbls)(2)		5,812		5,048		4,093
Natural gas (MMcf)		19,834		21,642		23,742
Combined (MBoe)		9,118		8,655		8,050
Average daily production:
Oil (Bbls)(2)		15,880		13,830		11,214
Natural gas (Mcf)		54,191		59,293		65,047
Combined (Boe)		24,912		23,712		22,055
Average prices (excluding derivative settlements):
Oil (per Bbl)(2)	$	78.65	$	87.52	$	74.53
Natural gas (per Mcf)	$	2.64	$	4.08	$	4.36
Combined (per Boe)	$	55.88	$	61.24	$	50.75
Average costs per Boe:
Lease operating expenses	$	14.36	$	14.03	$	13.18
Production taxes	$	3.51	$	3.97	$	3.29
Depreciation, depletion, and amortization	$	18.57	$	16.88	$	13.60
General and administrative	$	5.46	$	4.86	$	3.72

(1) The North Burbank Unit is the only field that contained 15% or more of our total proved reserve volumes at December 31, 2012. Production from this Unit, all of which was oil, was 492 MBbls, 531 MBbls, and 509 MBbls of our net production during 2012, 2011, and 2010, respectively.

(2) Includes natural gas liquids.

Competition

The oil and natural gas industry is highly competitive. We encounter strong competition from other independent operators and from major oil and natural gas 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.

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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 Bureau of Indian Affairs and other 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 managing the global supply 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;

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• 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, 2012, 2011 and 2010, 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 prospectus, we are not aware of any other environmental issues or claims that will require material capital expenditures during 2013 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.

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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. Congress has previously considered legislation to amend the federal Safe Drinking Water Act to require the disclosure of chemicals used by the oil and 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 proposed 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 is already required by some state agencies governing our operations, 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.

These legislative efforts have halted while EPA studies the issue of hydraulic fracturing. In 2010, EPA initiated a Hydraulic Fracturing Research Study to address concerns that hydraulic fracturing may affect the safety of drinking water, as well as review the application of other environmental statutes to hydraulic fracturing activities, including RCRA and the Clean Water Act. 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 water. EPA is scheduled to release its final draft report in late 2014.

These developments, as well as increased scrutiny of hydraulic fracturing activities by state and municipal authorities, may result in additional levels of regulation or level of complexity with respect to existing regulations that 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.

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The Clean Air Act

The federal Clean Air Act (“CAA”) 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 CAA and associated state laws and regulations. On August 16, 2012, EPA promulgated new CAA regulations addressing criteria pollutants, “Oil and Natural Gas Sector: New Source Performance Standards and National Emission Standards for Hazardous Air Pollutants Reviews.” These new rules are intended to broaden the current scope of EPA’s regulation to include standards governing emissions from most operations associated with oil and natural gas production facilities, natural gas transmission and storage facilities. EPA states that greenhouse gases will be controlled indirectly as a result of these new rules.

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 CAA to issue other rules that would result in federal greenhouse gas regulations and emissions limits under the CAA, 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 CAA, triggering application of other provisions of the CAA to major stationary sources of greenhouse gas emissions. In June 2010, EPA promulgated final rules limiting the scope of certain provisions of the CAA 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. On April 17, 2012, EPA adopted new CAA regulations imposing new emissions standards for the oil and natural gas sector, including sources not previously regulated. 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 CAA.

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.

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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, is subject to air permitting requirements where applicable, and may receive greater regulatory scrutiny in the future.

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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 may experience seasonal fluctuations, we do not believe these fluctuations have had, or will have, a material impact on our consolidated results of operations.

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Legal Proceedings

Naylor Farms, Inc. v. Chaparral Energy, L.L.C. On June 7, 2011, Naylor Farms, Inc. (the “Plaintiff”), filed a complaint against us, alleging claims on behalf of itself and non-governmental royalty interest owners in oil and natural gas wells we operate in Oklahoma. The Plaintiff asserts class claims seeking recovery for underpayment of royalties, alleging damages in excess of $5.0 million. The Plaintiff also requests allowable interest, punitive damages, cancellation of leases, other equitable relief, and an award of attorney fees and costs. We have denied liability on the claims and raised arguments and defenses that, if accepted by the Court, will result in no loss to us. The matter is currently stayed pending resolution of unrelated cases currently on appeal with the U.S. Court of Appeals for the Tenth Circuit. These cases are expected to influence the ruling on class certification in the Plaintiff’s case. At the time that the matter was stayed no class had been certified and discovery was ongoing. As such, we are not yet able to estimate a possible loss, or range of possible loss, if any.

In our opinion, there are no other material pending legal proceedings to which we 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. While the outcome of these legal matters cannot be predicted with certainty, we do not expect them to have a material adverse effect on our financial condition, results of operations or cash flows.

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 ensure 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, 2012, we had 746 full-time employees, including 24 geologists and geophysicists, 60 reservoir, production, and drilling engineers and 25 land professionals. Of these, 351 work in our Oklahoma City office and 395 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.

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MANAGEMENT

Executive Officers and Directors

The following table provides information regarding our executive officers and directors. Our board of directors currently consists of five members: Mark A. Fischer, Charles A. Fischer, Jr., Domenic J. Dell’Osso, Christopher Behrens, and Kyle Vann. Mark A. Fischer is a full-time employee.

Name	Age		Position
Mark A. Fischer		63	Chairman, Chief Executive Officer and President
K. Earl Reynolds		52	Chief Operating Officer and Executive Vice President
Joseph O. Evans		58	Chief Financial Officer and Executive Vice President
David J. Ketelsleger		48	Senior Vice President and General Counsel
Jeffrey M. Gutman		47	Senior Vice President—Chief Corporate Development Officer
G. Don Culpepper, Jr.		54	Senior Vice President—Corporate Drilling Manager
James M. Miller		50	Senior Vice President—Mid-Continent Region Manager
Scott C. Wehner		55	Senior Vice President—EOR Business Unit Manager
Jeffery D. Dahlberg		55	Senior Vice President—Southern Region Manager
Charles A. Fischer, Jr.		64	Director
Domenic J. Dell’Osso		36	Director
Christopher Behrens		52	Director
Kyle Vann		65	Director

Mark A. Fischer, Chairman, Chief Executive Officer, President and Co-Founder, co-founded Chaparral in 1988 and has served as its President and Chairman of the Board since its inception. Mr. Fischer began his career with Exxon Company USA in 1972 in the Permian Basin of West Texas where he held various positions as production engineer, reservoir engineer, field superintendent and finally supervising production engineer. From 1977 until 1980, Mr. Fischer served as the drilling and production manager for the West Texas and then Mid-Continent Division of TXO Production Corp. Prior to founding Chaparral, he served as division operations manager for Slawson Exploration Company from 1980 to 1988, focusing on the Mid-Continent and Panhandle Divisions. He is a member of the Society of Petroleum Engineers and the American Petroleum Institute. Mr. Fischer served as a director of the API from 1984 to 1986. Mr. Fischer graduated from Texas A&M University in 1972 with an honors degree in aerospace engineering. Mark A. Fischer and Charles A. Fischer, Jr. are brothers. Mr. Fischer is the board designee of the holders of our class B common stock.

K. Earl Reynolds, Chief Operating Officer and Executive Vice President, joined the Company in February 2011. From 2000 through 2010, Mr. Reynolds was actively involved in international operations and strategic planning for Devon Energy, most recently serving as Senior Vice President—Strategic Development, and was responsible for tactical planning, budgeting, coordination of acquisitions and divestitures, and oversight of the company’s assessment of oil and natural gas reserves. Prior to Devon Energy, Mr. Reynolds’ career included several key leadership roles in domestic and international operations with companies such as Burlington Resources and Mobil Oil. Mr. Reynolds is registered as a Professional Engineer and a member of the Society of Petroleum Engineers. He has served on the board of directors for several non-profit organizations in Houston and Oklahoma City. Mr. Reynolds holds a Master of Science degree in Petroleum Engineering from the University of Houston and a Bachelor of Science degree in Petroleum Engineering from Mississippi State University.

Joseph O. Evans, Chief Financial Officer & Executive Vice President, joined Chaparral in July of 2005 as Chief Financial Officer. From 1998 to June 2005, Mr. Evans was a consultant and practiced public accounting with the firm of Evans Gaither & Assoc. From 1997 to 1998, he served as Senior Vice President and Financial Advisor, Energy Lending, for First National Bank of Commerce in New Orleans. From 1976 until 1997, Mr. Evans worked in the Oklahoma practice of Deloitte & Touche where he became an Audit Partner. While at Deloitte he was a member of the energy industry group and was responsible for services on numerous SEC filings for clients. Mr. Evans has instructed numerous continuing professional education courses focused on compliance with the Sarbanes-Oxley Act. He is a Certified Public Accountant and an Accredited Petroleum Accountant. Mr. Evans is a graduate of the University of Central Oklahoma with a Bachelor of Science degree in Accounting.

David J. Ketelsleger, Sr. Vice President and General Counsel, joined Chaparral in November, 2012 and oversees the Legal, Human Resources, Land Administration, Acquisitions & Divestitures, Marketing, and Environmental Health and Safety functions. Prior to joining the Company, Mr. Ketelsleger was a partner at the law firm of McAfee & Taft A Professional Corporation specializing in public and private finance, securities and business transactions. Mr. Ketelsleger joined McAfee & Taft in 1990 and is listed in The Best Lawyers in America (corporate compliance law; corporate governance law; corporate law; mergers and acquisitions law; securities/capital markets law) and Chambers USA Guide to America’s Leading Lawyers for Business. Mr. Ketelsleger has been a Certified Public Accountant since 1986 and worked at Touche Ross & Co. prior to attending law school. He earned his Bachelor of Arts degree, summa cum laude, in Accounting from the University of Montana and his Juris Doctorate, with highest honors, from the University of Oklahoma.

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Jeffrey M. Gutman, Sr. Vice President—Chief Corporate Development Officer, joined the Company in February 2013. Prior to joining the Company, Mr. Gutman had been at Oxford Resource Partners, LP (Oxford), a producer of surface-mined steam coal based in Columbus, Ohio. Mr. Gutman served as Oxford’s Senior Vice President and Chief Financial Officer since 2008, and led Oxford’s initial public offering as an MLP in 2010. Prior to his joining Oxford, Mr. Gutman was with The Williams Companies, Inc. in Tulsa, Oklahoma for 17 years where he served in several leadership positions including Business Development and Mergers and Acquisitions, Chief Financial Officer of Gulf Liquids, Structured Finance and Capital Services. Prior to joining Williams, Mr. Gutman was with Deloitte & Touche, LLC in their Tulsa office. Mr. Gutman is a Certified Public Accountant in Oklahoma and holds a Bachelors degree in Accounting from Oklahoma State University.

G. Don Culpepper, Jr., Sr. Vice President—Corporate Drilling Manager, joined the Company in June 2011. From 2004 to May 2011, Mr. Culpepper was actively involved in domestic drilling operations for Devon Energy, most recently serving as Director—Category Management & Analysis, and was responsible for leading activities in building a new organizational capability to identify strategic categories of spend in order to more efficiently leverage the corporation’s capital budget relative to supply chain needs in the United States and Canada. Prior to Devon Energy, Mr. Culpepper’s career included key roles of responsibility in domestic and international operations with companies such as EOG Resources and Texaco. He is a graduate of the University of North Texas and has completed several post graduate certificate programs from The Johnson Graduate School of Management at Cornell University.

James M. Miller, Sr. Vice President—Mid-Continent Region Manager, joined the Company in 1996, as Operations Engineer. Since joining the Company, Mr. Miller has been promoted to positions of increasing responsibility and currently oversees production operations in the Mid-Continent Region. Mr. Miller has gained particular expertise in the area of operating secondary and tertiary recovery units. Prior to joining Chaparral, Mr. Miller worked for KEPCO Operating Inc. for one year as a petroleum engineer. From 1987 to 1995, he was employed by Robert A. Mason Production Co., as a petroleum engineer, and later as Vice President of Production. He is a member of the Society of Petroleum Engineers and the American Petroleum Institute. Mr. Miller attended the University of Oklahoma and received a Bachelor of Science degree in Petroleum Engineering in 1986.

Scott C. Wehner, Sr. Vice President—EOR Business Unit Manager, joined Chaparral in 2010 as the Vice President of the EOR-CO₂ Unit. Prior to joining Chaparral, Mr. Wehner worked for Whiting O&G Corp. where he assisted with the capitalization of assets with CO₂ potential. Prior to Whiting, he left Texaco after 20 years to help Kinder Morgan open its CO₂ EOR operations office in Midland, Texas to exploit the acquisition of the SACROC Unit. With 31 years industry experience, his past 26 years have been associated with the evaluation, design, implementation and management of CO₂ projects in West Texas, Southeast New Mexico, Oklahoma and Wyoming. He has published and presented various CO₂-related papers and has a US Patent involving the CO₂ process. He is a member and past Director of the International Society of Petroleum Engineers and sits on the RCP Advisory Board of the Colorado School of Mines. Mr. Wehner graduated from the University of Missouri—Rolla in 1980 with a Bachelor of Science in Geological Engineering and received UMR’s Distinguished Young Alumnus Award in 1997. He is a recipient of a 2003 Engineer of the Year Award from the Texas Society of Professional Engineers and is a member of the American Petroleum Institute.

Jeffery D. Dahlberg, Sr. Vice President—Southern Region Manager, joined Chaparral in 2007 as District Manager of the Mid-Continent West Division. From 2003 through 2007, Mr. Dahlberg was actively employed in technical and senior management positions for Windsor Energy, most recently serving as its Chief Operating Officer. Prior to Windsor Energy, Mr. Dahlberg’s career included several technical and management roles with Enserch Exploration, Texas Oil and Gas, and Twister Gas Services. Mr. Dahlberg is a member of the Society of Petroleum Engineers and holds a Bachelor of Science degree in Petroleum Engineering from Louisiana Tech University, graduating in 1980.

Charles A. Fischer, Jr., Director and Co-Founder, co-founded the Company in 1988, and has served as a director of the Company since its inception. Mr. Fischer served as the Company’s Chief Administrative Officer and Executive Vice President from July 2005 until his retirement effective July 27, 2007. Mr. Fischer joined the Company full-time in 2000 and served as its Chief Financial Officer and Senior Vice President for five years until assuming the role of Chief Administrative Officer. In 1978 Mr. Fischer founded C.A. Fischer Lumber Co. Ltd., which owns eight retail building supply outlets in western Canada, and is the current President. Mr. Fischer also serves as manager of Altoma Energy GP. Mr. Fischer began his career with Renewable Resources in 1974 as a senior scientist on the Polar Gas Pipeline Project investigating the feasibility of bringing natural gas from the high Arctic to south-central Canada. Mr. Fischer served as director of the Canadian Western Retail Lumberman’s Association for 11 years, was President for six years, and received the 2001 Industry Achievement Award. He graduated from Texas A&M University with a Bachelor of Science degree in Biology and from the University of Wisconsin with a Master of Science degree in Ecology. Mr. Fischer is the board designee of the holders of our class C common stock.

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Domenic J. Dell’Osso, Director, was elected to the Company’s board of directors in February 2013. Mr. Dell’Osso currently serves as Executive Vice President and Chief Financial Officer for Chesapeake Energy Corporation (NYSE: CHK). Mr. Dell’Osso has also served as a director of the general partner of Access Midstream Partners, L.P. and as Vice President – Finance for Chesapeake Energy Corporation and Chief Financial Officer of Chesapeake’s wholly owned midstream subsidiary Chesapeake Midstream Development, L.P. Prior to joining Chesapeake, Mr. Dell’Osso was an energy investment banker with Jefferies & Co. from 2006 to 2008 and Banc of America Securities from 2004 to 2006. Mr. Dell’Osso earned an undergraduate degree from Boston College and a Masters of Business Administration from the University of Texas at Austin. Mr. Dell’Osso is the board designee of the holders of our class D common stock.

Christopher Behrens, Director, is a Managing Director in the New York office of CCMP Capital Advisors, LLC and a member of its Investment Committee. He focuses on making investments in the industrial, distribution and energy sectors. Prior to joining CCMP in 2006, Mr. Behrens was a partner with J.P. Morgan Partners, LLC. Prior to joining J.P. Morgan Partners in 1994, he was a Vice President in the Merchant Banking Group of The Chase Manhattan Corporation. Mr. Behrens holds a B.A. from the University of California, Berkeley and an M.A. from Columbia University. Mr. Behrens serves on the board of directors of a number of private companies. Mr. Behrens is one of the two board designees of the holders of our class E common stock.

Kyle Vann, Director, possesses experience in exploration and production, midstream, energy services and trading. Mr. Vann joined CCMP Capital Advisors, LLC in October 2012 as an Executive Advisor. Previously, he spent 25 years in various senior leadership positions at Koch Industries including leading the creation of Entergy-Koch LP, an energy trading and transportation joint venture between Entergy Corporation and Koch Industries operating in North America and Europe, and served as its CEO. A chemical engineer by training, Mr. Vann has supported development of early trading models for price-setting mechanisms between crude and refined products, the development of Koch’s Texas Pipeline System from Corpus Christi, Texas, to Dallas, and was also deeply involved with Charles Koch’s development of Market-Based Management^® which helped the company significantly out-perform the S&P 500. Mr. Vann started his career with Humble Oil and Refining Company (which later became part of Exxon) as a refinery engineer. He currently serves on the Board of Directors of Texon LP, Crosstex Energy and Legacy Reserves and provides energy consulting services to Entergy Corporation. He earned his B.S. in Chemical Engineering from the University of Kansas and recently was named as a recipient of the university’s Distinguished Engineering Service Award. Mr. Vann is one of the two board designees of the holders of our Class E common stock.

Board Committees

On April 12, 2010, our Board of Directors established a compensation committee and an audit committee, effective upon the closing of the sale of our common stock to CCMP. All members of the Board of Directors were appointed to both the compensation committee and the audit committee, and the Board of Directors adopted charters for both committees on November 10, 2010. Christopher Behrens has been appointed Chairman of the audit and compensation committees.

Code of Ethics

We have adopted a Code of Business Conduct and Ethics that is applicable to all employees, officers and members of our board of directors. The Code of Business Conduct and Ethics is available on our website at http://www.chaparralenergy.com.

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EXECUTIVE COMPENSATION

Compensation discussion and analysis

Overview & Oversight of Compensation Program

Our compensation programs include programs that are designed specifically for our most senior executive officers (“Senior Executives”), which includes our Principal Executive Officer (“PEO”) and the other executive officers named in the Summary Compensation Table (the “Named Executive Officers” or “NEOs”). Currently, our PEO and board of directors oversee the compensation programs for our Senior Executives.

Overview of Compensation Philosophy and Program

In order to recruit and retain the most qualified and competent individuals as Senior Executives, we strive to maintain a compensation program that is competitive in the labor market. The following compensation objectives are considered in setting the compensation programs for our Senior Executives:

• drive and reward performance which supports our core values;

• align the interests of Senior Executives with those of stockholders;

• design competitive total compensation and rewards programs to enhance our ability to attract and retain knowledgeable and experienced Senior Executives; and

• set compensation and incentive levels that reflect mid-range market practices.

Compensation Targets

From time to time, we review compensation data from a variety of different sources, including from the Oil & Gas E&P Survey prepared by Effective Compensation, Incorporated (the “Survey Data”) to ensure that our Senior Executive base salary compensation program generally aligns with the median of the Survey Data. The Survey Data is a compilation of compensation and other data from the prior year based upon over 100 exploration and production firms that participated in the survey. In specific preparation for 2012, we had a study of executive compensation done by Longnecker and Associates (the “Longnecker Study”), an independent compensation consultant focused in part on executive and employee compensation for public and private organizations in the energy industry.

In determining base salaries for our executive officers, in addition to the Survey Data and Longnecker Study referenced above, our Board also considers the current level of the Executive’s compensation, both internally and relative to other Company officers and current industry and economic factors. The process can best be described as (i) first, looking within our Company at the current salary structure among the executive group to ensure fairness and consistency, (ii) second, evaluating the Company’s performance to ensure that compensation is, in large part, performance-based, (iii) third, looking at general industry conditions, and (iv) fourth, looking at peer group companies to determine if the range of compensation paid to our Executives is within the “fairway” of the compensation paid to executives in similarly situated companies.

Compensation Elements and Rationale for Pay Mix Decisions

We believe that a competitive compensation program will enhance our ability to attract and retain Senior Executives. To reward both short- and long-term performance in our compensation program and in furtherance of our compensation objectives noted above, our executive compensation philosophy includes the following four principles:

(i) Compensation levels should be competitive

We review the Survey Data to ensure that the base salary compensation is aligned with median levels.

(ii) Compensation should be related to performance

We believe that a significant portion of a Senior Executive’s compensation should be tied to individual performance and to our overall performance measured primarily by growth in reserves, production and earnings.

(iii) Variable compensation should represent a portion of a Senior Executive’s total compensation

We intend for a portion of compensation paid to Senior Executives to be variable in order to: 1) allow flexibility when our performance and/or industry conditions are not optimum; 2) maintain the ability to reward Senior Executives for our overall growth; and 3) retain Senior Executives when industry conditions necessitate. Senior Executives should have the incentive of increasing our profitability and value in order to earn a portion of their compensation package.

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(iv) Compensation should balance short- and long-term performance

We seek to structure a balance between achieving strong short-term annual results and ensuring our long-term viability and success. To reinforce the importance of balancing these perspectives, Senior Executives are regularly provided compensation based on both the accomplishment of short-term objectives and incentives for achieving long-term objectives. While our annual bonus plans are structured to reward the accomplishment of short-term objectives, in 2004, we began a long-term compensation plan for our executive employees and other key employees. This plan is to deliver long-term incentive awards aligned with the interests of stockholders while simultaneously serving as a retention tool.

Review of Senior Executive Performance

The PEO reviews, on an annual basis, each compensation element of a Senior Executive. In each case, the PEO takes into account the scope of responsibilities and experience, succession potential, strengths and weaknesses, and contribution and performance over the past year and balances these against competitive salary levels. The PEO works daily with the Senior Executives, which allows him to form his assessment of each individual’s performance. The PEO’s performance is assessed by the Board, taking into account the scope of responsibilities and experience, strengths and weaknesses, and contributions and performance over the past year balanced against competitive salary levels.

Components of the Executive Compensation Program

We believe the total compensation and benefits program for Senior Executives should consist of the following:

• base salaries;

• annual bonus plans;

• long-term retention and incentive compensation; and

• health and welfare benefits and retirement.

Base Salaries

For 2012, Senior Executive base salaries were minimally increased from 2011 (on average five percent (5%)) due to general industry conditions and the economic and industry outlook for 2012. In making the decision to limit increases in base salaries, we reviewed certain market data and the Longnecker Study. We usually adjust base salaries for Senior Executives annually based on performance. The PEO did not rely solely on predetermined formulas or a limited set of criteria when evaluating the base salaries of the Senior Executives for 2012. This is in line with our philosophy that Senior Executive compensation should be paid at approximately the competitive median levels based on market data, and taking current industry and economic factors into consideration. The salaries paid to the PEO and the NEOs during fiscal year 2012 are shown in the Summary Compensation Table in this prospectus.

Annual Bonus Plans

Annual Officers’ Bonus Program

We established the Annual Officers’ Bonus program in September 2006. The Annual Officers’ Bonus program provides Senior Executives with the opportunity to earn cash bonuses based on our achievement of unspecified Company-wide goals as determined by the PEO. The bonus is a component of the compensation program designed to align Senior Executive pay with our annual (short-term) performance.

The Annual Officers Bonus program was structured to provide cash bonus targets to Senior Executives competitive to the median levels based on the Survey Data to be consistent with our philosophy that compensation levels should be variable and competitive. The Annual Officers’ Bonuses awarded to the PEO and the NEOs for 2010 are shown in the Summary Compensation Table. In 2011, we adopted the AIM program described below, and no further awards under the Annual Officers’ Bonus program will be made.

Annual Incentive Measure Bonus Program

In 2011, we created a non-binding, discretionary incentive program called the Annual Incentive Measure Bonus Program (the “AIM” program) which pays cash bonus awards to eligible employees when the Company achieves certain performance measures on a Company-wide basis. Amounts payable under the AIM program are tied to the approved Company budget and to certain individual, departmental, and business unit measures, including, but not limited to, employees who reach individual performance goals and contribute positively to their respective business units and the Company’s goals and objectives.

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Participation in the AIM program is limited to regular, full-time employees who achieve overall performance ratings of “Meets Expectations” and above for the plan year. The targets for individual awards are expressed as a percentage of an employee’s eligible earnings for the plan year and are based on pay grade and level of responsibility. The first 50% of the computation of an employee’s AIM award is determined based solely on the Company’s performance on six Company-wide performance measures: EBITDA – 20%; Production Volume (Boe/d) – 20%; Reserve Replacement – 15%; Proved Developed Finding and Development Costs ($/Boe) – 20%; Lease Operating Expenses ($/Boe) – 15%; and Safety – 10%. The remaining 50% of the computation of an employee’s AIM award is discretionary and is based on the performance of the department or business unit in which the employee works and his or her individual performance and contributions as reflected by his or her performance review.

For the 2012 AIM program plan year, the Company performed at 98% of its target. Therefore, 50% of all eligible employees’ target bonus was paid at 98% of target. The remaining 50% was discretionary and varied by employee based on individual targets, department and business unit performance, and individual contributions.

2010 Equity Incentive Plan

We adopted the Chaparral Energy, Inc. 2010 Equity Incentive Plan (the “2010 Plan”) in April 2010. The 2010 Plan reserves a total of 86,301 shares of our class A common stock for awards issued under the 2010 Plan. If any award is exercised, paid, forfeited, terminated or canceled without the delivery of shares, then the shares covered by such award will be available again for grant 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.

Purpose

The 2010 Plan is intended to aid us in recruiting and retaining employees, officers, directors, and consultants capable of assuring our future success. We expect that the awards of stock-based compensation under the 2010 Plan and opportunities for stock ownership in the Company will provide incentives to participants to exert their best efforts for our success and also align their interests with those of our stockholders.

Administration

The 2010 Plan is administered by our Compensation Committee. Subject to the terms of the 2010 Plan, the Compensation Committee has the full power and authority to, among other things: (i) designate participants in the 2010 Plan; (ii) determine the type or types of awards to be granted to a participant; (iii) determine the number of shares to be covered by, or with respect to which payments, rights, or other matters are to be calculated in connection with, awards; (iv) determine the terms and conditions of any award; (v) determine whether, to what extent, and under what circumstances awards may be settled or exercised in cash, shares, other securities, other awards or other property, or canceled, forfeited, or suspended and the method or methods by which awards may be settled, exercised, canceled, forfeited, or suspended; (vi) interpret and administer the 2010 Plan or any award agreement issued under the 2010 Plan; (vii) establish, amend, suspend, or waive such rules and regulations and appoint such agents as it shall deem appropriate for the proper administration of the 2010 Plan; (viii) determine the fair market value of any shares issued under the 2010 Plan; (ix) prescribe the form of each award agreement, which need not be identical for each participant; and (x) make any other determination and take any other action that the Compensation Committee deems necessary or desirable for the administration of the 2010 Plan.

Types of Awards

The 2010 Plan authorizes the following types of awards:

• Stock Options. The grant of either non-qualified or incentive stock options (“ISOs”) to purchase shares of our class A common stock are permitted under the 2010 Plan. ISOs are intended to qualify for favorable tax treatment under the Code to participants in the 2010 Plan. The stock options will provide for the right to purchase shares of our class A common stock at a specified price and will become exercisable after the grant date under the terms established by the Compensation Committee. In general, the per share option exercise price may not be less than 100% of the fair market value of a share of class A common stock on the grant date. No person owning more than 10% of the total combined voting power of the Company may be granted ISOs unless (i) the option exercise price is at least 110% of the fair market value of a share of class A common stock on the grant date and (ii) the term during which such ISO may be exercised does not exceed five years from the date of grant.

• Restricted Stock. Awards of restricted stock are permitted under the 2010 Plan, subject to any restrictions the Compensation Committee determines to impose, such as satisfaction of performance measures for a performance period, or restrictions on the right to vote or receive dividends.

• Performance Awards. Performance awards, denominated as a cash amount (e.g., $100 per award unit) at the time of grant are permitted under the 2010 Plan. Performance awards confer on the participant the right to receive payment of such award, in whole or in part, upon the achievement of certain performance objectives during such performance periods as established by the Compensation Committee.

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• Bonus Shares. Awards of class A common stock without restrictions are permitted under the 2010 Plan, but such grants may be subject to any terms and conditions the Compensation Committee may determine.

• Phantom Shares. Awards of phantom shares are permitted under the 2010 Plan, upon such terms and conditions as determined by the Compensation Committee. Each phantom share award shall constitute an agreement by us to issue or transfer a specified number of shares or pay an amount of cash equal to a specified number of shares, or a combination thereof to the participant in the future, subject to the fulfillment of performance objectives, if any, during the restricted period as the Compensation Committee may specify at the date of grant.

• Cash Awards. Grants of cash awards, subject to the terms and conditions established by the Compensation Committee, are permitted under the 2010 Plan. If granted, a cash award shall be granted (simultaneously or subsequently) in tandem with another award and shall entitle a participant to receive a specified amount of cash from us upon such other award becoming taxable to the participant, which cash amount may be based on a formula relating to the anticipated taxable income associated with such other award and the payment of the cash award.

• Other Stock-Based Awards. Grants of other types of awards that are denominated or payable in, valued in whole or in part by reference to, or otherwise based on or related to, shares of our class A common stock, subject to the terms and conditions established by the Compensation Committee, are permitted under the 2010 Plan.

Terms of Time Vested Restricted Stock Awards

Time vested restricted stock awards vest with respect to twenty percent (20%) of the shares subject to the award on each of the first, second, third, fourth and fifth anniversaries of the award date, subject to the NEO remaining employed by us as of those dates.

Termination by Company Without Cause or by NEO for Good Reason. If the NEO is terminated by the Company without cause or by the NEO for good reason, then the vesting of the shares scheduled to vest during the period beginning on the date the NEO’s employment was terminated (the “Separation Date”) and ending on the 12-month anniversary of the Separation Date shall accelerate as of the Separation Date. Any shares not vested on the Separation Date will be forfeited as of the Separation Date. “Cause” and “good reason” shall have the same meanings as those terms are defined in any employment agreement then in effect between the NEO and us. See “—Potential Payments Upon Termination or Change in Control—Employment Agreements with Our NEOs” for the definitions of “cause” and “good reason.”

Accelerated Vesting Upon Certain Transactions. In the event of a transaction whereby CCMP receives cash in exchange for the sale, transfer or other disposition of its common stock pursuant to (i) a sale of the Company or (ii) an offering of its common stock to the public pursuant to a registration statement filed under the Securities Act of 1933, or any sale of its common stock thereafter (a “Transaction”), the shares held by each NEO who remains employed by us as of the date of such Transaction shall vest with respect to the fraction obtained by dividing (x) the number of shares of common stock sold pursuant to the Transaction, by (y) the 504,276 shares of class E common stock issued to CCMP on April 12, 2010 (the “Vesting Fraction”). Any shares of common stock sold pursuant to an “Excepted Transfer” are excluded from both the numerator and the denominator when determining the Vesting Fraction. “Excepted Transfer” means the transfer by CCMP and its permitted transferees of up to 20% of the common stock owned by them on or immediately following April 12, 2010. All other shares will remain subject to the normal vesting schedule.

Performance Vested Restricted Stock Awards

Performance vested restricted stock awards vest in the event of a Transaction (i) whereby CCMP’s “net proceeds” from a Transaction yields certain target returns on investment, and (ii) the NEO remains employed by us as of the date of such Transaction. “Net proceeds” means the actual cash proceeds received by CCMP in a Transaction, but excludes the aggregate amount of out-of-pocket expenses incurred by CCMP in connection with such Transaction.

The table below sets forth the return-on-investment targets that initially triggered vesting of the Performance Vested restricted stock awards and the formula for calculating the number of shares of Performance Vested restricted stock that vest upon CCMP’s receipt of net proceeds in a Transaction.

Return on Investment Target	Target Shares Vested
200% per share	20% of shares multiplied by the Vesting Fraction
250% per share	20% of shares multiplied by the Vesting Fraction
300% per share	20% of shares multiplied by the Vesting Fraction
350% per share	20% of shares multiplied by the Vesting Fraction
400% per share	20% of shares multiplied by the Vesting Fraction

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Effective January 1, 2013, we amended and restated all outstanding Performance Vested restricted stock awards to reflect that (i) those shares which would vest if CCMP receives net proceeds from a Transaction that yields a return of at least 400% per share were removed from the initial Performance Vested restricted stock awards and an equal amount were granted effective as of January 1, 2013 under Time Vested restricted stock awards; and (ii) the remaining number of shares subject to the initial Performance Vesting restricted stock awards were reallocated among the following five targets for vesting:

Return on Investment Target	Target Shares Vested
175% per share	20% of shares multiplied by the Vesting Fraction
200% per share	20% of shares multiplied by the Vesting Fraction
250% per share	20% of shares multiplied by the Vesting Fraction
300% per share	20% of shares multiplied by the Vesting Fraction
350% per share	20% of shares multiplied by the Vesting Fraction

These vesting targets will apply for any new grants of Performance Vested restricted stock awards. Any shares of Performance Vested restricted stock not vested on an NEO’s Separation date will be forfeited as of the Separation Date.

Our Purchase Option

All Time Vested and Performance Vested restricted stock awards are subject to our right to purchase the shares that have vested under the terms of such awards, which purchase option lapses on the seventh anniversary of the grant date. If the NEO ceases his employment with us for any reason, we shall have the right to purchase the shares of restricted stock awarded to the NEO that have vested. If the NEO’s employment is terminated by us without cause, by the NEO for good reason, as a result of the NEO’s death or by the NEO without good reason, the purchase price for such shares shall be equal to the fair market value of such shares on the Separation Date. If the NEO’s employment is terminated by us for cause, the purchase price for such shares shall be $0.01 per share. In the event of the NEO’s material breach of the terms of any agreement with us that is in effect on or after the NEO’s Separation Date, other than a breach of noncompetition or nonsolicitation provisions, we may elect to purchase the shares for $0.01 per share.

Health and Welfare and Retirement Benefits

We offer a variety of health and welfare and retirement programs to all eligible employees. The Senior Executives are eligible for the same benefit programs on the same basis as the rest of our employees. The health and welfare programs are intended to protect employees against catastrophic loss and encourage a healthy lifestyle. Our health and welfare programs include medical, pharmacy, dental, life insurance, supplemental insurance policies and a flexible spending plan.

We offer a 401(k) Profit Sharing Plan that is intended to supplement the employee’s personal savings and social security. All employees, including Senior Executives, are generally eligible for the 401(k) plan. Senior Executives participate in the 401(k) plan on the same basis as other employees.

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We adopted the 401(k) plan to enable employees to save for retirement through a tax-advantaged combination of employee and Company contributions and to provide employees the opportunity to directly manage their retirement plan assets through a variety of investment options. The 401(k) plan allows eligible employees to elect to contribute from 1% to 60% of their eligible compensation, up to the annual IRS dollar limit. Eligible compensation generally means all wages, salaries and fees for services paid by us. The Company matches at a rate of $1.00 per $1.00 employee contribution for the first 6% of the employee’s salary. Company contributions vest as follows:

Years of Service for Vesting	Percentage
1		33	%
2		33	%
3		34	%

However, regardless of the number of years of service, an employee is fully vested in his 401(k) plan if the employee retires at age 65 or later, attains age 62 and completes 5 years of service, or the employee’s employment is terminated due to death or total and permanent disability. The 401(k) plan provides for different investment options, for which the participant has sole discretion in determining how both the employer and employee contributions are invested. The 401(k) plan does not provide our employees the option to invest directly in our stock. The 401(k) plan offers in-service withdrawals in the form of loans, hardship distributions, after-tax account distributions and age 59.5 distributions.

Indemnification agreements

We have indemnification agreements with Mark A. Fischer, K. Earl Reynolds, Joseph O. Evans, David J. Ketelsleger, Charles A. Fischer, Jr., Domenic J. Dell’Osso, Christopher Behrens and Kyle Vann. These indemnification agreements are intended to permit indemnification to the fullest extent now or hereafter permitted by the General Corporation Law of Delaware. It is possible that the applicable law could change the degree to which indemnification is expressly permitted.

The indemnification agreements cover expenses (including attorneys’ fees), judgments, fines and amounts paid in settlement incurred as a result of the fact that such person, in his capacity as a director or officer, is made or threatened to be made a party to any suit or proceeding. The indemnification agreements will generally cover claims relating to the fact that the indemnified party is or was an officer, director, employee or agent of us or any of our affiliates, or is or was serving at our request in such a position for another entity. The indemnification agreements will also obligate us to promptly advance all reasonable expenses incurred in connection with any claim. The indemnitee is, in turn, obligated to reimburse us for all amounts so advanced if it is later determined that the indemnitee is not entitled to indemnification. The indemnification provided under the indemnification agreements is not exclusive of any other indemnity rights; however, double payment to the indemnitee is prohibited.

We are not obligated to indemnify the indemnitee with respect to claims brought by the indemnitee against:

• us, except for:

• claims regarding the indemnitee’s rights under the indemnification agreement;

• claims to enforce a right to indemnification under any statute or law; and

• counter-claims against us in a proceeding brought by us against the indemnitee; or

• any other person, except for claims approved by our board of directors.

We also maintain director and officer liability insurance for the benefit of each of the above indemnitees. These policies include coverage for losses for wrongful acts and omissions and to ensure our performance under the indemnification agreements. Each of the indemnitees are named as an insured under such policies and provided with the same rights and benefits as are accorded to the most favorably insured of our directors and officers.

Employment Agreements

We have entered into employment agreements with each of our NEOs, under the terms of which each will serve in their respective officerial positions. The initial term of the employment agreements are three years, each with an automatic two-year renewal and automatic annual renewals thereafter.

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The employment agreements provide our NEOs the following compensation arrangements:

Name	Effective Date	Minimum Base Salary		Target Annual Bonus (as a % of Base)			Equity Grant (Time Vested)(1)		Equity Grant (Performance Vested)(1)
Mark A. Fischer	April 12, 2010	$	620,298		100	%	$	1,814,366	$	3,673,995
Joseph O. Evans	April 12, 2010		345,030		80	%		725,883		1,469,598
K. Earl Reynolds	February 1, 2011		375,000		80	%		746,201		1,528,860
David J. Ketelsleger	November 1, 2012		335,000		70	%		597,661		1,962,120
Scott C. Wehner	June 15, 2011		256,000		70	%		443,117		656,673
Jeffery D. Dahlberg	October 22, 2012		275,000		70	%		646,979		1,904,066

(1) The value shown is the aggregate grant date fair value computed in accordance with FASB ASC Topic 718.

Each NEO will also participate in our welfare benefit plans and fringe benefit, vacation and expense reimbursement policies. Each employment agreement provides for certain payments in the event of an NEO’s termination. The termination payments are discussed below under the heading “—Potential Payments Upon Termination or Change of Control.” Each employment agreement contains certain restrictive covenants that generally prohibit our NEOs from (i) competing against us, (ii) disclosing information that is confidential to us and our subsidiaries and (iii) during the employment term and for each NEO, a period of months equal to the product of 12 times the Severance Multiple of that NEO, as described below, thereafter, from soliciting or hiring our employees and those of our subsidiaries or soliciting our customers.

Compensation Committee Interlocks and Insider Participation

None of our executive officers have served as members of a compensation committee (or if no committee performs that function, the board of directors) of any other entity that has an executive officer serving as a member of our board of directors. All members of the Board of Directors serve on the compensation committee and Christopher Behrens has been appointed Chairman of the compensation committee.

Summary compensation table

The following table below summarizes the total compensation paid or earned by each of the NEOs for the fiscal year ended December 31, 2012, 2011, and 2010.

Name and Principal Position	Year		Salary ($)		Bonus ($)(1)		Stock awards ($)(2)		All other compensation ($)(3)		Total ($)
Mark A. Fischer		2012	$	657,914	$	720,836	$	—	$	51,969	$	1,430,719
Chief Executive Officer and President		2011		645,500		652,842		—		32,890		1,331,232
		2010		620,298		434,209		5,488,361		28,079		6,570,947
Joseph O. Evans		2012	$	362,452	$	299,223	$	—	$	29,063	$	690,738
Chief Financial Officer and Executive Vice President		2011		359,000		280,451		—		12,362		651,813
		2010		345,030		193,217		2,195,481		15,840		2,749,568
K. Earl Reynolds		2012	$	389,423	$	365,148	$	—	$	36,870	$	791,441
Chief Operating Officer and Executive Vice President		2011		346,154		305,827		2,275,061		59,324		2,986,366
		2010		—		—		—		—		—
David J. Ketelsleger		2012	$	53,632	$	70,000	$	2,559,781	$	11,466	$	2,694,879
Senior Vice President & General Counsel		2011		—		—		—		—		—
		2010		—		—		—		—		—
Scott C. Wehner		2012	$	258,462	$	189,198	$	796,668	$	35,408	$	1,279,736
Senior Vice President—EOR Business Unit Manager		2011		256,000		310,240		1,099,790		50,556		1,716,586
		2010		—		—		—		—		—
Jeffery D. Dahlberg		2012	$	241,433	$	193,189	$	2,228,676	$	26,416	$	2,689,714
Senior Vice President—Southern Region Manager		2011		—		—		—		—		—
		2010		—		—		—		—		—

(1) Bonuses earned by NEOs in 2012 and paid in 2013 were performance-based cash incentives under our AIM program except for a sign-on bonus of $70,000 for David J. Ketelsleger.

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(2) The value shown is the aggregate grant date fair value of restricted stock awards, computed in accordance with FASB ASC Topic 718.

(3) Perquisites and other compensation are limited in scope and in 2012 were primarily comprised of company 401K matching; company automobile and airplane usage; and employer-paid medical benefits including accidental death and dismemberment, dental, life, medical and long-term and short-term disability coverage.

Grants of plan-based awards in 2012

The following table shows grants of equity-based awards in 2012 for each NEO.

		Estimated Future Payouts Under Equity Incentive Plan Awards(1)						All Other Stock Awards: Number of Shares of Stock or		Grant Date Fair Value of Stock and Option
Name	Grant Date	Threshold (#)		Target (#)		Maximum (#)		Units(2) (#)		Awards(3) ($)
Scott C. Wehner—Performance Vested	September 17, 2012		0		n/a		2,200				796,668
David J. Ketelsleger—Time Vested	November 1, 2012								1,061	$	443,117
David J. Ketelsleger—Performance Vested	November 1, 2012		0		n/a		4,980				656,673
Jeffery D. Dahlberg—Time Vested	November 6, 2012								843		646,979
Jeffery D. Dahlberg—Performance Vested	November 6, 2012		0		n/a		4,393				1,904,066

(1) The vesting of the Performance Vested restricted stock awards is based solely upon the rate of return obtained by CCMP from the sale of its stock. See “Executive compensation—Compensation discussion and analysis—Long-term Retention and Incentive Compensation—2010 Equity Incentive Plan—Performance Vested Restricted Stock Awards” for specific information regarding the potential vesting scenarios. The vesting scenarios do not include a target number of awards to be vested.

(2) The Time Vested restricted stock awards vest over a five-year period.

(3) The value shown is the aggregate grant date fair value of restricted stock awards, computed in accordance with FASB ASC Topic 718.

Outstanding equity awards at fiscal year-end 2012

The following table shows outstanding restricted stock awards as of December 31, 2012 for each NEO.

	Time Vested Awards				Performance Vested Awards
Name	Number of Shares of Stock That Have Not Vested(1) (#)		Market Value of Shares of Stock That Have Not Vested(2) ($)		Number of Shares of Stock That Have Not Vested(3) (#)		Market Value of Shares of Stock That Have Not Vested(4) ($)
Mark A. Fischer		1,592	$	996,592		12,450	$	2,260,796
Joseph O. Evans		637		398,762		4,980		904,318
K. Earl Reynolds		848		530,848		4,980		904,318
David J. Ketelsleger		1,061		664,186		4,980		904,318
Scott C. Wehner		771		482,646		4,980		904,318
Jeffery D. Dahlberg		973		609,098		4,980		904,318

(1) The Time Vested restricted stock awards vest over a five-year period.

(2) The table assumes an estimated fair value per share of $626.00 as of December 31, 2012.

(3) See “Executive compensation—Compensation discussion and analysis—Long-term Retention and Incentive Compensation—2010 Equity Incentive Plan—Performance Vested Restricted Stock Awards” for specific information regarding the potential vesting scenarios.

(4) The table assumes an estimated fair value per share of $181.59 as of December 31, 2012.

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2012 stock vested

The following table shows restricted stock awards that vested during the year ended December 31, 2012 for each NEO that participates in the 2010 Plan.

	Time Vested Restricted Stock Awards
Name	Number of Shares of Stock That Have Vested (#)		Value Realized on Vesting ($)
Mark A. Fischer		530	$	395,952
Joseph O. Evans (1)		212		158,381
K. Earl Reynolds(2)		213		159,128
Scott C. Wehner (3)		212		158,381
Jeffery D. Dahlberg (4)		44		32,872

(1) We withheld 87 vested shares and paid taxes of $64,996 on May 9, 2012.

(2) We withheld 88 vested shares and paid taxes of $50,803 on March 27, 2012 and $14,942 on May 10, 2012.

(3) We withheld 31 vested shares and paid taxes of $17,462 on December 15, 2012.

(4) We withheld 17 vested shares and paid taxes of $12,700 on May 9, 2012.

Potential payments upon termination or change in control

Employment Agreements with our NEOs

Our employment agreements with our NEOs obligate us to pay certain separation benefits to them in the event of voluntary termination, termination without cause, termination for good reason and termination in the event of disability or death. The term “disability” means the NEO’s incapacity due to physical or mental illness whereby the NEO is substantially unable to perform his duties under the employment agreement (with or without reasonable accommodation, as defined under the Americans With Disabilities Act) for a period of six (6) consecutive months. The term “cause” means termination for one of the following reasons:

• the NEO’s conviction of, or entry by the NEO of a guilty or no contest plea to a felony or crime involving moral turpitude;

• the NEO’s willful commission of an act of fraud or dishonesty resulting in economic or financial injury to us or any affiliate;

• the NEO’s willful failure to substantially perform or gross neglect of his duties, including, but not limited to, the failure to follow any lawful directive of our Chief Executive Officer, within the reasonable scope of the NEO’s duties;

• the NEO’s performance of unapproved acts materially detrimental to us or any affiliate;

• the NEO’s use of narcotics, alcohol, or illicit drugs in a manner that has or may reasonably be expected to have a detrimental effect on his performance of his duties as our employee or on the reputation of the Company or any affiliate;

• the NEO’s commission of a material violation of any of our rules or policies which results in injury to us; or

• the NEO’s material breach of the employment agreement.

In Mr. Fischer’s case, the term “cause” also includes:

• the occurrence or existence of any event constituting “Cause,” with respect to Mr. Fischer under our Second Amended and Restated Certificate of Incorporation, as amended and restated on April 12, 2010; (the “Certificate of Incorporation”);

• a material breach by us of Article 7 of the Certificate of Incorporation caused by specific acts or omissions of Mr. Fischer, provided that we fail to remedy such breach within 90 days after we have knowledge of the initial existence of such breach; or

• a material breach by Fischer Investments, L.L.C. of that certain Stockholders’ Agreement dated April 12, 2010.

The term “good reason” means the occurrence, without the written consent of the NEO, of one of the events set forth below:

• a material diminution in the NEO’s authority, duties or responsibilities, combined with a demotion in the NEO’s pay grade ranking;

• the reduction by us of the NEO’s base salary by more than 10% (unless done so for all of our executive officers);

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• the requirement that the NEO be based at any office or location that is more than 50 miles from our principal executive offices, except for travel reasonably required in the performance of the NEO’s responsibilities; or

• any other action or inaction that constitutes a material breach by us under the employment agreement.

The term “change in control” means:

• the consummation of any transaction or series of related transactions involving the sale of our outstanding securities (but excluding a public offering of our capital stock) for securities or other consideration issued or paid or caused to be issued or paid by such other corporation or an affiliate thereof and which results in our shareholders (or their affiliates) immediately prior to such transaction not holding at least a majority of the voting power of the surviving or continuing entity following such transaction; or

• the consummation by us (whether directly involving us or indirectly involving us through one or more intermediaries) of (x) a merger, consolidation, reorganization, or business combination or (y) a sale or other disposition of all or substantially all of our assets or (z) the acquisition of assets or stock of another entity, in each case, other than a transaction which results in our voting securities outstanding immediately before the transaction continuing to represent (either by remaining outstanding or by being converted into our voting securities or the person that, as a result of the transaction, controls, directly or indirectly, us or owns, directly or indirectly, all or substantially all of our assets or otherwise succeeds to our business), directly or indirectly, at least a majority of the combined voting power of the successor entity’s outstanding voting securities immediately after the transaction.

Payments Made Upon Termination Without Cause or by the NEO for Good Reason Not Following a Change in Control

In the event an NEO’s employment is terminated without cause or by the NEO for good reason at any time that is not within two years after the occurrence of a change in control, we will be obligated:

• to pay to the NEO an amount equal to the Severance Multiple, as specified in the NEO’s employment agreement, times the sum of (x) the NEO’s base salary in effect on the date of termination plus (y) the annual bonus granted to the NEO for the fiscal year immediately on or preceding the date of termination, payable in the form of a salary continuation for a period of months equal to the product of 12 times the Severance Multiple;

• subject to certain limitations, to maintain for a period of 18 months following the date of termination, participation by the NEO (and his spouse and/or eligible dependents, as applicable) in our medical, hospitalization, and dental programs maintained for the benefit of our senior executive officers as in effect on the date of termination, at such level and terms and conditions (including, without limitation, contributions required by the NEO for such benefits) as in effect on the date of termination (the “Termination Welfare Benefits”);

• to pay to the NEO any earned but unpaid base salary, annual bonus from prior years, and vacation pay in the form of a lump sum payment; and

• to pay to the NEO any unreimbursed reasonable business expenses incurred by the NEO on our behalf in the form of a lump sum payment.

The following table quantifies amounts that would have been paid pursuant to the employment agreements for each of our NEOs assuming a termination without cause or by the NEO for good reason not following a change in control took place on December 31, 2012, and assuming all accrued compensation and reimbursable expenses had been paid on December 31, 2012.

Name	Base Salary		Annual Bonus		Severance Multiple		Benefits		Total
Mark A. Fischer	$	645,500	$	720,836		2.5	$	26,535	$	3,442,375
Joseph O. Evans		359,000		299,223		2.0		23,345		1,346,695
K. Earl Reynolds		375,000		365,148		2.0		20,925		1,501,221
David J. Ketelsleger		335,000		—		2.0		17,198		687,198
Scott C. Wehner		256,000		189,198		1.5		19,363		687,160
Jeffery D. Dahlberg		275,000		193,189		1.5		19,375		721,659

Payments Made Upon Termination Without Cause or by the NEO for Good Reason Following a Change in Control

If at any time within two years after a change in control (“CiC”), the NEO’s employment is terminated without cause or by the NEO for good reason, we will be obligated:

• to pay to the NEO an amount equal to the CiC Severance Multiple, as specified in the NEO’s employment agreement, times the sum of (x) the NEO’s base salary in effect on the date of termination plus (y) the annual bonus granted to the NEO for the fiscal year immediately on or preceding the date of termination, payable in the form of a salary continuation for a period of months equal to the product of 12 times the CiC Multiple, or in the form of a lump sum payment if the CiC occurs as a result of the sale or other disposition of all or substantially all of the Company’s assets;

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• subject to certain limitations, to provide the Termination Welfare Benefits;

• to pay to the NEO any earned but unpaid base salary, annual bonus from prior years and vacation pay in the form of a lump sum payment; and

• to pay to the NEO any unreimbursed reasonable business expenses incurred by the NEO on our behalf in the form of a lump sum payment.

The following table quantifies amounts that would have been paid pursuant to the employment agreements for each of our NEOs assuming a termination without cause or by the NEO for good reason following a CiC took place on December 31, 2012, and assuming all accrued compensation and reimbursable expenses had been paid on December 31, 2012.

Name	Base Salary		Annual Bonus		Severance Multiple		Benefits		Total
Mark A. Fischer	$	645,500	$	720,836		3.0	$	26,535	$	4,125,543
Joseph O. Evans		359,000		299,223		2.5		23,345		1,668,903
K. Earl Reynolds		375,000		365,148		2.5		20,295		1,871,295
David J. Ketelsleger		335,000		—		2.5		17,198		854,698
Scott C. Wehner		256,000		189,198		2.0		19,363		909,759
Jeffery D. Dahlberg		275,000		193,189		2.0		19,375		955,753

Payments Made Upon Termination for Cause or by the NEO Without Good Reason

In the event an NEO is terminated for cause, or the NEO resigns without good reason, we have no further obligations to the NEO other than a lump sum payment of the following amounts:

• any earned but unpaid base salary, annual bonus from prior years and vacation pay; and

• unreimbursed reasonable business expenses incurred by the NEO on our behalf, so long as the NEO was not fired for cause due to his misappropriation of Company funds.

No amounts would have been paid pursuant to the employment agreements for each of our NEOs assuming a termination for cause or by the NEO without good reason took place on December 31, 2012, and assuming all accrued compensation and reimbursable expenses had been paid on December 31, 2012.

Payments Made Upon Death or Disability

In the event of an NEO’s death or disability, we will be obligated to pay to the NEO:

• any earned but unpaid base salary, annual bonus from prior years and vacation pay;

• unreimbursed reasonable business expenses incurred by the NEO on our behalf; and

• a pro rata share of the annual bonus for the fiscal year in which the termination of employment occurs.

No amounts would have been paid pursuant to the employment agreements for each of our NEOs assuming an event of death or disability took place on December 31, 2012, and assuming all accrued compensation or reimbursable expenses had been paid on December 31, 2012.

Payments of separation benefits may be delayed if (i) the NEO is a “specified employee” within the meaning of Section 409A of the Code (“Section 409A”) as of the date of his separation from service and (ii) the amount of any separation benefits payable to him are subject to Section 409A. In such instance, the separation benefits will not be paid to the NEO until six months after the date of separation from service, or, if earlier, the date of his death.

Other Payments Made Upon Termination, Retirement, Death or Disability

Certain accelerated vesting provisions will apply to each NEO’s restricted stock awards if the NEO’s employment is terminated without cause or by the NEO for good reason. See “—Compensation Discussion and Analysis—Long-term Retention and Incentive Compensation—2010 Equity Incentive Plan.”

Regardless of the manner in which an NEO’s employment is terminated, he is entitled to receive amounts earned during his term of employment, including unused vacation pay and bonuses earned but not yet paid under the Annual Officers Bonus. All amounts earned by our NEOs under the AIM program were paid on March 15, 2013.

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Additionally, if an NEO is terminated due to death or disability, that NEO will receive benefits under our disability plan or payments under our life insurance plan.

Director compensation

Members of our Board of Directors do not receive compensation for their services as board members. We do, however, reimburse our directors for all reasonable out-of-pocket costs and expenses incurred by them in connection with their service as a director.

Compensation policies and risk management

While our Board strives to create incentives that encourage a level of risk-taking behavior consistent with our business strategy, our compensation policies and practices do not create risks that are reasonably likely to have a material adverse affect on our operations or financial condition.

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PRINCIPAL STOCKHOLDERS

The following table sets forth information, as of April 1, 2013, with respect to all persons who own of record or are known by us to own beneficially more than 5% of our outstanding common stock, each director, and each of the Named Executive Officers, and by all directors and executive officers as a group.

	Beneficial ownership
Name	Number		Class		% of class			% of total outstanding
Mark A. Fischer(1)(2)(8)		357,882		B		100.0	%		25.2	%
		1		G		33.3	%		*
		15,102		A		22.7	%		1.1	%
Altoma Energy G.P.(1)(3)		209,882		C		100.0	%		14.8	%
		1		G		33.3	%		*
Charles A. Fischer, Jr.(1)(4)		209,882		C		100.0	%		14.8	%
		1		G		33.3	%		*
CHK Energy Holdings, Inc.(5)		279,999		D		100.0	%		19.7	%
		1		G		33.3	%		*
Domenic J. Dell’Osso(5)		—		—		—			—
CCMP Capital Investors II (AV-2), L.P.(6)		386,750		E		76.7	%		27.2	%
		1		F		100.0	%		*
Christopher Behrens(6)		—		—		—			—
Kyle Vann(7)		—		—		—			—
K. Earl Reynolds(1)(8)		5,973		A		8.8	%		*
Joseph O. Evans(1)(8)		5,867		A		8.6	%		*
David J. Ketelsleger(1)(8)		6,041		A		8.9	%		*
Scott C. Wehner(1)(8)		6,010		A		8.8	%		*
Jeffery D. Dahlberg(1)(8)		6,007		A		8.8	%		*
All Directors and Officers as a group (13 persons—ownership of total outstanding)		630,493		Various					44.2	%

* Less than 1%

(1) The address of the stockholder is in care of Chaparral Energy, Inc., 701 Cedar Lake Boulevard, Oklahoma City, Oklahoma 73114.

(2) Fischer Investments, L.L.C., which is owned 50% by Mark A. Fischer 1994 Trust, for which Mark A. Fischer serves as Trustee, and 50% by Susan L. Fischer 1994 Trust, for which Susan L. Fischer, the spouse of Mark A. Fischer, serves as trustee, is the record owner of these shares of our common stock with the exception of 15,102 shares held by Mark A. Fischer and 3,030 shares held by the irrevocable trusts of his children, for which Mark A. Fischer serves as Trustee.

(3) Charles A. Fischer, Jr., one of our directors, is one of Altoma’s four managing general partners and beneficially owns a 23.15% general partner interest (including 0.90% owned by his spouse) in Altoma Energy G.P. The other partners of Altoma Energy G.P. who are each managing general partners and beneficially own in excess of 5% of its general partner interests are: Kenneth H. McCourt-36.75%; Ronald D. Jakimchuck-17.86%; and Gary H. Klassen-12.80%.

(4) Includes all 209,882 shares owned of record by Altoma Energy G.P. Charles A. Fischer, Jr. serves as one of four managing partners of Altoma Energy G.P. Charles A. Fischer, Jr. owns directly a 22.25% general partner interest and his spouse owns directly a 0.90% general partner interest in Altoma Energy G.P.

(5) Chesapeake Energy Corporation (“Chesapeake”) owns its interest in us through its 100% ownership of CHK Energy Holdings, Inc. (“CHK Energy Holdings”). Chesapeake has an Investment Committee consisting of Domenic J. Dell’Osso and Jennifer M. Grigsby that will exercise voting and investment control with respect to our shares of common stock. Chesapeake may be deemed to beneficially own the shares of common stock owned by CHK Energy Holdings. The address of Chesapeake and CHK Energy Holdings is 6100 North Western Avenue, Oklahoma City, Oklahoma 73118.

Mr. Dell’Osso and Ms. Grigsby disclaim any beneficial ownership of any shares beneficially owned by CHK Energy Holdings and its related entities described above.

(6) CCMP Capital Investors II (AV-2), L.P. (“AV-2”), which owns 386,750 shares of Class E common stock and 1 share of Class F common, is part of an affiliated group of our stockholders ultimately controlled by CCMP Capital, LLC (“CCMP Capital”). The affiliated group also includes CCMP Energy I, Ltd. (“CCMP Energy”), which is wholly owned by CCMP Capital Investors II (AV-1), L.P. (“AV-1”) and which owns 58,217 shares of Class E common stock, and CCMP Capital Investors (Cayman) II, L.P.

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(“CCMP Cayman”), which owns 59,309 shares of Class E common stock. We refer to CCMP Cayman, AV-2 and AV-1 as the “CCMP Capital Funds”. The affiliated group controlled by CCMP Capital owns an aggregate of 504,277, or 35.5%, of our common shares outstanding as of April 1, 2013.

The general partner of the CCMP Capital Funds is CCMP Capital Associates, L.P. (“CCMP Capital Associates”). The general partner of CCMP Capital Associates is CCMP Capital Associates GP, LLC (“CCMP Capital Associates GP”). CCMP Capital Associates GP is wholly owned by CCMP Capital. CCMP Capital ultimately exercises voting and dispositive power over the shares held directly or indirectly by the CCMP Capital Funds.

Christopher Behrens is a Managing Director of CCMP Capital Advisors, LLC, an investment advisor which is wholly owned by CCMP Capital. The address of Mr. Behrens and of each of the CCMP entities described above (other than CCMP Energy and CCMP Cayman) is c/o CCMP Capital, LLC, 245 Park Avenue, New York, NY 10167. The address of CCMP Energy and CCMP Cayman is c/o Walkers SPV Limited, PO Box 908 GT, Walker House, George Town, Grand Cayman, Cayman Islands.

Mr. Behrens disclaims any beneficial ownership of any shares beneficially owned by CCMP Capital and its related entities described above.

(7) The address of KyleVann is 11 Hepplewhite Way, The Woodlands, Texas 77382.

(8) Ownership of the class A common stock is pursuant to restricted stock grants under our 2010 Plan. When granted, the class A common stock related to these grants may vote, but remain subject to vesting in accordance with the 2010 Plan.

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CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE

Participation Interests

Historically, we have granted participation interests in the form of overriding royalty interests to a limited number of employees. We have also granted pro rata certain overriding royalty interests to our stockholders or their affiliates, including Mark A. Fischer and Charles A. Fischer, Jr. We discontinued in 2006 the granting of any additional participation interest to our stockholders, or their affiliates, including Mark A. Fischer or Charles A. Fischer, Jr. We have discontinued the granting of overriding royalty interests under our existing program to other employees effective December 31, 2005, other than certain specified wells that spud prior to April 1, 2006. Aggregate payments on these interests to all persons were $763,460 in 2012. Payments on these interests to Mark A. Fischer were $181,263 in 2012. Payments on these interests to Charles A. Fischer, Jr. were $42,039 in 2012. Payments on these interests to James M. Miller were $325,275 in 2012.

Transactions with Chesapeake

CHK Energy Holdings owns approximately 20% of our outstanding common stock. We participate in ownership of properties operated by Chesapeake and received revenues and incurred joint interest billings of $3,625,000 and $4,896,000, respectively, for the year ended December 31, 2012 on these properties. In addition, Chesapeake participates in ownership of properties operated by us. During the year ended December 31, 2012, we paid revenues and recorded joint interest billings of $4,084,000 and $9,785,000, respectively, to Chesapeake. Amounts receivable from and payable to Chesapeake were $2,071,000 and $864,000, respectively, as of December 31, 2012.

CHK Energy Holdings has disclosed its intention to sell all of its equity interest in us. The sale by CHK Energy Holdings will be subject to the terms and conditions of the Stockholders Agreement described below, including the restrictions on its ability to sell its equity interest.

Stockholders Agreement

In connection with the closing of the private sale of our common stock to CCMP, we, CCMP, CHK Energy Holdings, Altoma Energy GP (“Altoma”), and Fischer Investments, L.L.C. (“Fischer”) entered into a Stockholders Agreement on the closing date of the above transaction. The Stockholders Agreement provides for certain general rights and restrictions, including board observer rights, informational rights, general restrictions on transfer of common stock, tag-along rights, preemptive rights, registration rights following a Qualified IPO (as defined in the Stockholders Agreement) and, subject to certain limited exceptions, prohibitions on the sale or acquisition of our common stock that would result in a change of control, as such term is defined under our indentures for our senior notes.

The Stockholders Agreement also provides for the following stockholder-specific rights or restrictions:

• Prior to a Qualified IPO, Altoma will not vote for the approval of (i) any merger, consolidation, conversion or a Demand IPO (as defined in the Stockholders Agreement), (ii) certain amendments to our organizational documents, (iii) the sale of all or substantially all of our assets, or (iv) a termination of the business of or liquidation or dissolution of the Company, unless Fischer votes for such approval.

• Other than pursuant to the exercise of preemptive rights, CHK Energy Holdings may not acquire more than 25% of our outstanding common stock.

• CCMP may sell up to 20% of its common stock owned on the Closing Date (as defined in the Stockholders Agreement) without restriction. Prior to a Qualified IPO and except in limited circumstances, CCMP is restricted from making further sales before the fourth anniversary of the Closing Date, and any sales thereafter (but before a Qualified IPO) will be subject to certain rights of first offer provisions set forth in the Stockholders Agreement (the “ROFO provisions”).

• Fischer may sell up to 20% of its common stock owned immediately prior to the Closing Date subject to certain restrictions. Prior to a Qualified IPO and except in limited circumstances, Fischer is restricted from making further sales before the fourth anniversary of the Closing Date, and any sales thereafter (but before a Qualified IPO) will be subject to the ROFO provisions.

• Prior to a Qualified IPO and except in limited circumstances, CHK Energy Holdings is restricted from selling its common stock before the 30 month anniversary of the Closing Date, and any sales thereafter (but before a Qualified IPO) will be subject to the ROFO provisions.

• If our common stock is not listed on a national securities exchange after August 15, 2011, Altoma may request to transfer its shares pursuant to a demand registration, but only after Altoma first offers such shares to the Company, and then to CHK Energy Holdings, Fischer and CCMP in accordance with the procedures set forth in the Stockholders Agreement.

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• At any time after the 18 month anniversary of the Closing Date, either (i) CCMP or (ii ) a majority in interest of Fischer, Altoma and CHK Energy Holdings may demand that we engage in a Qualified IPO if (a) the price per share to be received by the Company or such party or parties, as the case may be, in such Demand IPO is at least 1.75 times the price per share paid by CCMP for our common stock and (b) certain other conditions are met.

• At any time after the four year anniversary of the Closing Date, CCMP may demand a Demand IPO.

• At any time after the sixth anniversary of the Closing Date, and so long as a Qualified IPO has not yet occurred, CCMP may demand a Company Sale (as defined in the Stockholders Agreement), subject to a right of first offer to purchase the Company provided to Fischer.

With the exception of registration rights, the rights and preferences of a stockholder under the Stockholders Agreement will generally terminate on the earlier of (x) the closing date of a Qualified IPO or (y) the date that such holder and its permitted transferees cease to beneficially own 5% or more of the Company’s fully-diluted common stock.

Review, Approval or Ratification of Transactions with Related Persons

Our board of directors is responsible for approving all related party transactions between us and any officer or director that would potentially require disclosure. The board expects that any transactions in which related persons have a direct or indirect interest will be presented to the board for review and approval but we have no written policy in place at this time.

Director Independence

Our Board uses the independence standards under the New York Stock Exchange (“NYSE”) corporate governance rules for determining whether directors are independent. The Board has determined that Messrs. Behrens, Dell’Osso, Vann and Charles A. Fischer, Jr. are independent under these NYSE rules for purposes of service on the Board.

DESCRIPTION OF CERTAIN INDEBTEDNESS

Senior Secured Revolving Credit Facility

In April 2010, we entered into our senior secured revolving credit facility, which is collateralized by our oil and natural gas properties, and matures on April 1, 2016. The balance outstanding under our senior secured revolving credit facility at December 31, 2012 and 2011 was $25.0 million and $0.0 million, respectively. As of April 11, 2013, we had drawn down $79.0 million under our senior secured revolving credit facility and we had committed to borrow an additional $20.0 million under our senior secured revolving credit facility, which will be funded on April 16, 2013.

During 2012, we had three amendments to our senior secured revolving credit facility. The Eighth Amendment to our senior secured revolving credit facility, effective April 30, 2012, amended our Asset Sale Covenant to permit the sale of certain oil and natural gas properties located in southern Oklahoma and increased our permitted ratio of Consolidated Net Debt to Consolidated EBITDAX. The Ninth Amendment to our senior secured revolving credit facility, effective May 24, 2012, changed the calculation of Consolidated EBITDAX to permit the exclusion of our reasonable and customary fees and expenses related to the refinancing of our 8.875% Senior Notes. The Tenth Amendment to our senior secured revolving credit facility, effective November 1, 2012, increased our borrowing base from $375.0 million to $500.0 million; increased the Aggregate Maximum Credit Amount from $450.0 million to $750.0 million and the maximum Aggregate Maximum Credit Amount (after giving effect to any exercise of the accordion option on the terms and conditions set forth in the senior secured revolving credit facility) to $850.0 million; extended the maturity date to November 1, 2017; reduced the applicable margins added to the Adjusted LIBO Rate for the purposes of determining the interest rate (i) on Eurodollar loans to a margin ranging from 1.50% to 2.50% and (ii) on Alternate Base Rate (“ABR”) loans to a margin ranging from 0.50% to 1.50%, each depending on the utilization percentage of the conforming borrowing base; reduced commitment fees to 0.375% if less than 50% of the borrowing base is utilized; reaffirmed the borrowing base through May 1, 2013 and permitted the offering of the Add-on Notes without triggering the automatic 25% reduction of the borrowing base.

Amounts borrowed under our senior secured revolving credit facility are subject to varying rates of interest based on (1) the total outstanding borrowings in relation to the borrowing base (the “utilization percentage”) and (2) whether we elect to borrow at the Eurodollar rate or the ABR. As of December 31, 2012, the balance outstanding under our senior secured revolving credit facility was $25.0 million, all of which was subject to the Eurodollar rate.

The Eurodollar rate 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 that varies depending on our utilization percentage. During 2012, the margin varied from 1.50% to 2.75%. Interest payments on Eurodollar borrowings are due the last day of the interest period, if shorter than three months, or every three months.

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Interest on loans subject to the ABR 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 0.50%, or (3) the Adjusted LIBO Rate, as defined in our senior secured revolving credit facility, plus1.0%, plus a margin that varies depending on our utilization percentage. During 2012, the margin varied from 0.50% to 1.75%.

Commitment fees of 0.375% to 0.50% accrued on the unused portion of the borrowing base amount based on the utilization percentage 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.

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. Effective November 1, 2012, our borrowing base was increased to $500.0 million through May 1, 2013.

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.

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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, 2012 and 2011, our current ratio as computed using GAAP was 0.84 and 0.74, respectively. After giving effect to the adjustments, our current ratio computed for loan compliance purposes was 3.74 and 3.56, 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:

	December 31,
(in thousands)	2012			2011
Current assets per GAAP	$	163,617		$	124,123
Plus—Availability under senior secured revolving credit facility		474,080			372,080
Less—Short-term derivative instruments		(42,516	)		(12,840	)
Current assets as adjusted	$	595,181		$	483,363
Current liabilities per GAAP	$	194,590		$	167,717
Less—Short term derivative instruments		(436	)		(1,505	)
Less—Short-term asset retirement obligations		(2,900	)		(2,900	)
Less— Deferred tax liability on derivative instruments and asset retirement obligations		(32,051	)		(27,684	)
Current liabilities as adjusted	$	159,203		$	135,628
Current ratio for loan compliance		3.74			3.56

In April 2011, we amended our senior secured revolving credit facility to extend its maturity date from April 12, 2014 to April 1, 2016 and to permit the exclusion of our reasonable and customary fees and expenses related to the refinancing of our 8.5% Senior Notes due 2015 from the calculation of Consolidated EBITDAX.

Our senior secured revolving credit facility, as amended, requires us to maintain 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 each period of four consecutive fiscal quarters ending on the last day of such applicable fiscal quarter.

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.

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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.

Our 9.875% Senior Notes

On September 16, 2010, we issued $300.0 million aggregate principal amount of 9.875% Senior Notes maturing on October 1, 2020. The 9.875% Senior Notes are our senior unsecured obligations, rank equally in right of payment with all of our existing and future senior indebtedness, including the notes and our existing 8.875% Senior Notes and 8.25% Senior Notes, and rank senior to all of our existing and future subordinated debt. The payment of the principal, interest and premium on the 9.875% Senior Notes is fully and unconditionally guaranteed on a senior unsecured basis by our existing and future subsidiary guarantors, as defined in the indenture governing the 9.875% Senior Notes.

On and after October 1, 2015, we may redeem some or all of the 9.875% Senior Notes at any time at redemption prices specified in the indenture, plus accrued and unpaid interest to the date of redemption. Prior to October 1, 2015, the 9.875% 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 indenture governing the 9.875% Senior Notes.

We and our restricted subsidiaries are subject to certain negative and financial covenants under the indenture governing the 9.875% Senior Notes. The provisions of the indenture limit our and our restricted subsidiaries’ ability to, among other things:

• incur additional indebtedness;

• 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; and

• consolidate, merge or transfer assets.

If we experience a change of control (as defined in the indenture governing the 9.875% Senior Notes), or make certain asset sales, subject to certain conditions, we must give holders of the 9.875% Senior Notes the opportunity to sell to us their 9.875% Senior Notes at 101% of the principal amount, plus accrued and unpaid interest.

Our 8.25% Senior Notes

On February 22, 2011, we issued $400.0 million aggregate principal amount of 8.25% Senior Notes maturing on September 1, 2021. The 8.25% Senior Notes are our senior unsecured obligations, rank equally in right of payment with all of our existing and future senior indebtedness, including the notes and our existing 8.875% Senior Notes and our 9.875% Senior Notes, and rank senior to all of our existing and future subordinated debt. The payment of the principal, interest and premium on the 8.25% Senior Notes is fully and unconditionally guaranteed on a senior unsecured basis by our existing and future subsidiary guarantors, as defined in the indenture governing the 8.25% Senior Notes.

On and after September 1, 2016, we may redeem some or all of the 8.25% Senior Notes at any time at redemption prices specified in the indenture, plus accrued and unpaid interest to the date of redemption. Prior to September 1, 2016, the 8.25% 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 indenture governing the 8.25% Senior Notes.

We and our restricted subsidiaries are subject to certain negative and financial covenants under the indenture governing the 8.25% Senior Notes. The provisions of the indenture limit our and our restricted subsidiaries’ ability to, among other things:

• incur additional indebtedness;

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

• make investments;

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• 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; and

• consolidate, merge or transfer assets.

If we experience a change of control (as defined in the indenture governing the 8.25% Senior Notes), or make certain asset sales, subject to certain conditions, we must give holders of the 8.25% Senior Notes the opportunity to sell to us their 8.25% Senior Notes at 101% of the principal amount, plus accrued and unpaid interest.

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THE EXCHANGE OFFER

Purpose and effect of the exchange offer

On November 15, 2012, we sold $150.0 million in aggregate principal amount at maturity of the old notes in a private placement. The old notes were sold to the initial purchasers who in turn resold the notes to a limited number of qualified institutional buyers pursuant to Rule 144A and Regulation S of the Securities Act.

In connection with the sale of the old notes, we entered into a registration rights agreement with the initial purchasers of the old notes, pursuant to which we agreed to file and to use our reasonable best efforts to cause to be declared effective by the SEC a registration statement with respect to the exchange of the old notes for the new notes. We are making the exchange offer to fulfill our contractual obligations under that agreement. A copy of the registration rights agreement has been incorporated by reference as an exhibit to the registration statement of which this prospectus is a part.

Pursuant to the exchange offer, we will issue the new notes in exchange for old notes. The terms of the new notes are identical in all material respects to those of the old notes, except that the new notes (1) have been registered under the Securities Act and therefore will not be subject to certain restrictions on transfer applicable to the old notes and (2) will not have registration rights or provide for any liquidated damages related to the obligation to register. Please read “Description of the new notes” for more information on the terms of the respective notes and the differences between them.

We are not making the exchange offer to, and will not accept tenders for exchange from, holders of old notes in any jurisdiction in which an exchange offer or the acceptance thereof would not be in compliance with the securities or blue sky laws of such jurisdiction. Unless the context requires otherwise, the term “holder” with respect to the exchange offer means any person in whose name the old notes are registered on our books or any other person who has obtained a properly completed bond power from the registered holder, or any person whose old notes are held of record by The Depository Trust Company, referred to as DTC, who desires to deliver such old notes by book–entry transfer at DTC.

We make no recommendation to the holders of old notes as to whether to tender or refrain from tendering all or any portion of their old notes pursuant to the exchange offer. In addition, no one has been authorized to make any such recommendation. Holders of old notes must make their own decision whether to tender pursuant to the exchange offer and, if so, the aggregate amount of old notes to tender after reading this prospectus and the letter of transmittal and consulting with the advisers, if any, based on their own financial position and requirements.

In order to participate in the exchange offer, you must represent to us, among other things, that:

• you are acquiring the new notes in the exchange offer in the ordinary course of your business;

• you are not engaged in, and do not intend to engage in, a distribution of the new notes;

• you do not have and to your knowledge, no one receiving new notes from you has, any arrangement or understanding with any person to participate in the distribution of the new notes;

• you are not a broker-dealer tendering old notes acquired directly from us for your own account or if you are a broker-dealer, you will comply with the prospectus delivery requirements of the Securities Act in connection with any resale of the new notes; and

• you are not one of our “affiliates,” as defined in Rule 405 of the Securities Act.

Each broker-dealer that receives new notes for its own account in exchange for old notes, where such old notes were acquired by such broker-dealer as a result of market-making activities or other trading activities, must acknowledge that it will deliver a prospectus in connection with any resale of such new notes. Please read “Plan of distribution.”

Terms of exchange

Upon the terms and conditions described in this prospectus and in the accompanying letter of transmittal, which together constitute the exchange offer, we will accept for exchange old notes that are properly tendered at or before the expiration time and not withdrawn as permitted below. As of the date of this prospectus, $150.0 million aggregate principal amount of unregistered 7.625% Senior Notes due 2022 are outstanding. This prospectus, together with the letter of transmittal, is first being sent on or about the date on the cover page of the prospectus to all holders of old notes known to us. Old notes tendered in the exchange offer must be in denominations of principal amount of $2,000 and integral multiples of $1,000 thereafter.

Our acceptance of the tender of old notes by a tendering holder will form a binding agreement between the tendering holder and us upon the terms and subject to the conditions provided in this prospectus and in the accompanying letter of transmittal.

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The form and terms of the new notes being issued in the exchange offer are the same as the form and terms of the old notes except that:

• the new notes being issued in the exchange offer will have been registered under the Securities Act;

• the new notes being issued in the exchange offer will not bear the restrictive legends restricting their transfer under the Securities Act; and

• the new notes being issued in the exchange offer will not contain the registration rights contained in the old notes.

Expiration, extension and amendment

The expiration time of the exchange offer is 5:00 P.M., New York City time, on             , 2013. However, we may, in our sole discretion, extend the period of time for which the exchange offer is open and set a later expiration date for the offer. The term “expiration time” as used herein means the latest time and date to which we extend the exchange offer. If we decide to extend the exchange offer period, we will then delay acceptance of any old notes by giving oral or written notice of an extension to the holders of old notes as described below. During any extension period, all old notes previously tendered will remain subject to the exchange offer and may be accepted for exchange by us. Any old notes not accepted for exchange will be returned to the tendering holder after the expiration or termination of the exchange offer.

Our obligation to accept old notes for exchange in the exchange offer is subject to the conditions described below under “—Conditions to the Exchange Offer.” We may decide to waive any of the conditions in our discretion. Furthermore, we reserve the right to amend or terminate the exchange offer, and not to accept for exchange any old notes not previously accepted for exchange, upon the occurrence of any of the conditions of the exchange offer specified below under the same heading. We will give oral or written notice of any extension, amendment, non–acceptance or termination to the holders of the old notes as promptly as practicable. If we materially change the terms of the exchange offer, we will resolicit tenders of the old notes, file a post–effective amendment to the prospectus and provide notice to you. If the change is made less than five business days before the expiration of the exchange offer, we will extend the offer so that the holders have at least five business days to tender or withdraw. We will notify you of any extension by means of a press release or other public announcement no later than 9:00 A.M., New York City time, on the first business day after the previously scheduled expiration time.

Procedures for Tendering

Valid tender

Except as described below, a tendering holder must, prior to the expiration time, transmit to Wells Fargo Bank, National Association, the exchange agent, at the address listed below under the caption “—Exchange Agent”:

• a properly completed and duly executed letter of transmittal, including all other documents required by the letter of transmittal; or

• if old notes are tendered in accordance with the book–entry procedures listed below, an agent’s message transmitted through DTC’s Automated Tender Offer Program, referred to as ATOP.

In addition, you must:

• deliver certificates, if any, for the old notes to the exchange agent at or before the expiration time; or

• deliver a timely confirmation of the book–entry transfer of the old notes into the exchange agent’s account at DTC, the book–entry transfer facility, along with the letter of transmittal or an agent’s message; or

• comply with the guaranteed delivery procedures described below.

The term “agent’s message” means a message, transmitted by DTC to, and received by, the exchange agent and forming a part of a book–entry confirmation, that states that DTC has received an express acknowledgment that the tendering holder agrees to be bound by the letter of transmittal and that we may enforce the letter of transmittal against such holder.

If the letter of transmittal is signed by a person other than the registered holder of old notes, the letter of transmittal must be accompanied by a written instrument of transfer or exchange in satisfactory form duly executed by the registered holder with the signature guaranteed by an eligible institution. The old notes must be endorsed or accompanied by appropriate powers of attorney. In either case, the old notes must be signed exactly as the name of any registered holder appears on the old notes.

If the letter of transmittal or any old notes or powers of attorney are signed by trustees, executors, administrators, guardians, attorneys–in–fact, officers of corporations or others acting in a fiduciary or representative capacity, these persons should so indicate when signing. Unless waived by us, proper evidence satisfactory to us of their authority to so act must be submitted.

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By tendering, each holder will represent to us that, among other things, the person is not our affiliate, the new notes are being acquired in the ordinary course of business of the person receiving the new notes, whether or not that person is the holder, and neither the holder nor the other person has any arrangement or understanding with any person to participate in the distribution of the new notes. Each broker-dealer that receives new notes for its own account in exchange for old notes, where such old notes were acquired by such broker-dealer as a result of market-making activities or other trading activities, must acknowledge that it will deliver a prospectus in connection with any resale of such new notes. Please read “Plan of distribution.”

The method of delivery of old notes, letters of transmittal and all other required documents is at your election and risk, and the delivery will be deemed made only upon actual receipt or confirmation by the exchange agent. If the delivery is by mail, we recommend that you use registered mail, properly insured, with return receipt requested. In all cases, you should allow sufficient time to assure timely delivery. Holders tendering through DTC’s ATOP system should allow sufficient time for completion of the ATOP procedures during the normal business hours of DTC on such dates.

No old notes, agent’s messages, letters of transmittal or other required documents should be sent to us. Delivery of all old notes, agent’s messages, letters of transmittal and other documents must be made to the exchange agent. Holders may also request their respective brokers, dealers, commercial banks, trust companies or nominees to effect such tender for such holders.

If you are a beneficial owner whose old notes are registered in the name of a broker, dealer, commercial bank, trust company or other nominee, and wish to tender, you should promptly instruct the registered holder to tender on your behalf. Any registered holder that is a participant in DTC’s ATOP system may make book–entry delivery of the old notes by causing DTC to transfer the old notes into the exchange agent’s account. The tender by a holder of old notes, including pursuant to the delivery of an agent’s message through DTC’s ATOP system, will constitute an agreement between such holder and us in accordance with the terms and subject to the conditions set forth herein and in the letter of transmittal.

All questions as to the validity, form, eligibility, time of receipt and withdrawal of the tendered old notes will be determined by us in our sole discretion, which determination will be final and binding. We reserve the absolute right to reject any and all old notes not validly tendered or any old notes which, if accepted, would, in the opinion of our counsel, be unlawful. We also reserve the absolute right to waive any irregularities or conditions of tender as to particular old notes. Our interpretation of the terms and conditions of this exchange offer, including the instructions in the letter of transmittal, will be final and binding on all parties. Unless waived, any defects or irregularities in connection with tenders of old notes must be cured within such time as we shall determine. Although we intend to notify you of defects or irregularities with respect to tenders of old notes, none of us, the exchange agent, or any other person shall be under any duty to give notification of defects or irregularities with respect to tenders of old notes, nor shall any of them incur any liability for failure to give such notification. Tenders of old notes will not be deemed to have been made until such irregularities have been cured or waived. Any old notes received by the exchange agent that are not validly tendered and as to which the defects or irregularities have not been cured or waived will be returned without cost to such holder by the exchange agent, unless otherwise provided in the letter of transmittal, as soon as practicable following the expiration date of the exchange offer.

Although we have no present plan to acquire any old notes that are not tendered in the exchange offer or to file a registration statement to permit resales of any old notes that are not tendered in the exchange offer, we reserve the right, in our sole discretion, to purchase or make offers for any old notes after the expiration date of the exchange offer, from time to time, through open market or privately negotiated transactions, one or more additional exchange or tender offers, or otherwise, as permitted by law, the indenture and our other debt agreements. Following consummation of this exchange offer, the terms of any such purchases or offers could differ materially from the terms of this exchange offer.

Signature guarantees

Signatures on a letter of transmittal or a notice of withdrawal must be guaranteed, unless the old notes surrendered for exchange are tendered:

• by a registered holder of the old notes who has not completed the box entitled “Special Registration Instructions” or “Special Delivery Instructions” on the letter of transmittal, or

• for the account of an “eligible institution.”

If signatures on a letter of transmittal or a notice of withdrawal are required to be guaranteed, the guarantees must be by an “eligible institution.” An “eligible institution” is an “eligible guarantor institution” meeting the requirements of the registrar for the notes within the meaning of Rule 17Ad-15 under the Exchange Act.

Book-entry transfer

The exchange agent will make a request to establish an account for the old notes at DTC for purposes of the exchange offer. Any financial institution that is a participant in DTC’s system may make book–entry delivery of old notes by causing DTC to transfer those old notes into the exchange agent’s account at DTC in accordance with DTC’s procedure for transfer. The participant should transmit its acceptance to DTC at or prior to the expiration time or comply with the guaranteed delivery procedures described below.

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DTC will verify this acceptance, execute a book–entry transfer of the tendered old notes into the exchange agent’s account at DTC and then send to the exchange agent confirmation of this book–entry transfer. The confirmation of this book–entry transfer will include an agent’s message confirming that DTC has received an express acknowledgment from this participant that this participant has received and agrees to be bound by the letter of transmittal and that we may enforce the letter of transmittal against this participant.

Delivery of new notes issued in the exchange offer may be effected through book–entry transfer at DTC. However, the letter of transmittal or facsimile of it or an agent’s message, with any required signature guarantees and any other required documents, must:

• be transmitted to and received by the exchange agent at the address listed under “—Exchange agent” at or prior to the expiration time; or

• comply with the guaranteed delivery procedures described below.

Delivery of documents to DTC in accordance with DTC’s procedures does not constitute delivery to the exchange agent.

Guaranteed delivery

If a registered holder of old notes desires to tender the old notes, and the old notes are not immediately available, or time will not permit the holder’s old notes or other required documents to reach the exchange agent before the expiration time, or the procedures for book–entry transfer described above cannot be completed on a timely basis, a tender may nonetheless be made if:

• the tender is made through an eligible institution;

• prior to the expiration time, the exchange agent receives by facsimile transmission, mail or hand delivery from such eligible institution a properly and validly completed and duly executed notice of guaranteed delivery, substantially in the form provided by us:

1. stating the name and address of the holder of old notes and the amount of old notes tendered,

2. stating that the tender is being made, and

3. guaranteeing that within three New York Stock Exchange trading days after the expiration time, the certificates for all physically tendered old notes, in proper form for transfer, or a book–entry confirmation, as the case may be, and a properly completed and duly executed letter of transmittal, or an agent’s message, and any other documents required by the letter of transmittal will be deposited by the eligible institution with the exchange agent; and

• the certificates for all physically tendered old notes, in proper form for transfer, or a book–entry confirmation, as the case may be, and a properly completed and duly executed letter of transmittal, or an agent’s message, and all other documents required by the letter of transmittal, are received by the exchange agent within three New York Stock Exchange trading days after the date of execution of the notice of guaranteed delivery.

Determination of validity

We will determine in our sole discretion all questions as to the validity, form and eligibility of old notes tendered for exchange. This discretion extends to the determination of all questions concerning the timing of receipts and acceptance of tenders. These determinations will be final and binding. We reserve the right to reject any particular old note not properly tendered or of which our acceptance might, in our judgment or our counsel’s judgment, be unlawful. We also reserve the right to waive any defects or irregularities or conditions of the exchange offer as to any particular old note either before or after the expiration time, including the right to waive the ineligibility of any tendering holder. Our interpretation of the terms and conditions of the exchange offer as to any particular old note either before or after the applicable expiration time, including the letter of transmittal and the instructions to the letter of transmittal, shall be final and binding on all parties. Unless waived, any defects or irregularities in connection with tenders of old notes must be cured within a reasonable period of time.

Neither we, the exchange agent nor any other person will be under any duty to give notification of any defect or irregularity in any tender of old notes. Moreover, neither we, the exchange agent nor any other person will incur any liability for failing to give notifications of any defect or irregularity.

Acceptance of old notes for exchange; issuance of new notes

Upon the terms and subject to the conditions of the exchange offer, we will accept, promptly after the expiration time, all old notes properly tendered. We will issue the new notes promptly after acceptance of the old notes. For purposes of an exchange offer, we will be deemed to have accepted properly tendered old notes for exchange when, as and if we have given oral or written notice to the exchange agent, with prompt written confirmation of any oral notice.

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For each old note accepted for exchange, the holder will receive a new note registered under the Securities Act having a principal amount equal to that of the surrendered old note. As a result, registered holders of old notes issued in the exchange offer on the relevant record date for the first interest payment date following the completion of the exchange offer will receive interest accruing from the most recent date to which interest has been paid on the old notes. Old notes that we accept for exchange will cease to accrue interest from and after the date of completion of the exchange offer. Under the registration rights agreement, we may be required to make additional payments in the form of liquidated damages to the holders of the old notes under circumstances relating to the timing of the exchange offer.

In all cases, issuance of new notes for old notes will be made only after timely receipt by the exchange agent of:

• certificate for the old notes, or a timely book-entry confirmation of the old notes, into the exchange agent’s account at the book-entry transfer facility;

• a properly completed and duly executed letter of transmittal or an agent’s message; and

• all other required documents.

Unaccepted or non-exchanged old notes will be returned without expense to the tendering holder of the old notes. In the case of old notes tendered by book-entry transfer in accordance with the book-entry procedures described above, the non-exchanged old notes will be credited to an account maintained with DTC as promptly as practicable after the expiration or termination of the exchange offer. For each old note accepted for exchange, the holder of the old note will receive a new note having a principal amount equal to that of the surrendered old note.

Interest payments on the new notes

The new notes will bear interest from the most recent date to which interest has been paid on the old notes for which they were exchanged. Accordingly, registered holders of new notes on the relevant record date for the first interest payment date following the completion of the exchange offer will receive interest accruing from the most recent date to which interest has been paid. Old notes accepted for exchange will cease to accrue interest from and after the date of completion of the exchange offer and will be deemed to have waived their rights to receive the accrued interest on the old notes.

Withdrawal rights

Tender of old notes may be properly withdrawn at any time before 5:00 p.m., New York City time, on the expiration date of the exchange offer.

For a withdrawal to be effective with respect to old notes, the exchange agent must receive a written notice of withdrawal before the expiration time delivered by hand, overnight by courier or by mail, at the address indicated under “—Exchange Agent” or, in the case of eligible institutions, at the facsimile number, or a properly transmitted “Request Message” through DTC’s ATOP system. Any notice of withdrawal must:

• specify the name of the person, referred to as the depositor, having tendered the old notes to be withdrawn;

• identify the old notes to be withdrawn, including certificate numbers and principal amount of the old notes;

• contain a statement that the holder is withdrawing its election to have the old notes exchanged;

• other than a notice transmitted through DTC’s ATOP system, be signed by the holder in the same manner as the original signature on the letter of transmittal by which the old notes were tendered, including any required signature guarantees, or be accompanied by documents of transfer to have the trustee with respect to the old notes register the transfer of the old notes in the name of the person withdrawing the tender; and

• specify the name in which the old notes are registered, if different from that of the depositor.

If certificates for old notes have been delivered or otherwise identified to the exchange agent, then, prior to the release of these certificates the withdrawing holder must also submit the serial numbers of the particular certificates to be withdrawn and signed notice of withdrawal with signatures guaranteed by an eligible institution, unless this holder is an eligible institution. If old notes have been tendered in accordance with the procedure for book-entry transfer described below, any notice of withdrawal must specify the name and number of the account at the book-entry transfer facility to be credited with the withdrawn old notes.

Any old notes properly withdrawn will be deemed not to have been validly tendered for exchange. New notes will not be issued in exchange unless the old notes so withdrawn are validly re-tendered.

Properly withdrawn old notes may be re-tendered by following the procedures described under “—Procedures for tendering” above at any time at or before the expiration time.

We will determine all questions as to the validity, form and eligibility, including time of receipt, of notices of withdrawal.

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Conditions to the exchange offer

Notwithstanding any other provisions of the exchange offer, or any extension of the exchange offer, we will not be required to accept for exchange, or to exchange, any old notes for any new notes, and, as described below, may terminate an exchange offer, whether or not any old notes have been accepted for exchange, or may waive any conditions to or amend the exchange offer, if any of the following conditions has occurred or exists:

• there shall occur a change in the current interpretation by the staff of the SEC which permits the new notes issued pursuant to such exchange offer in exchange for old notes to be offered for resale, resold and otherwise transferred by the holders (other than broker-dealers and any holder which is an affiliate) without compliance with the registration and prospectus delivery provisions of the Securities Act, provided that such new notes are acquired in the ordinary course of such holders’ business and such holders have no arrangement or understanding with any person to participate in the distribution of the new notes;

• any action or proceeding shall have been instituted or threatened in any court or by or before any governmental agency or body seeking to enjoin, make illegal or delay completion of the exchange offer or otherwise relating to the exchange offer;

• any law, statute, rule or regulation shall have been adopted or enacted which, in our judgment, would reasonably be expected to impair our ability to proceed with such exchange offer;

• a banking moratorium shall have been declared by United States federal or New York State authorities;

• trading on the New York Stock Exchange or generally in the United States over-the-counter market shall have been suspended, or a limitation on prices for securities imposed, by order of the SEC or any other governmental authority;

• an attack on the United States, an outbreak or escalation of hostilities or acts of terrorism involving the United States, or any declaration by the United States of a national emergency or war shall have occurred;

• a stop order shall have been issued by the SEC or any state securities authority suspending the effectiveness of the registration statement of which this prospectus is a part or proceedings shall have been initiated or, to our knowledge, threatened for that purpose or any governmental approval has not been obtained, which approval we shall, in our sole discretion, deem necessary for the consummation of such exchange offer; or

• any change, or any development involving a prospective change, in our business or financial affairs or any of our subsidiaries has occurred which is or may be adverse to us or we shall have become aware of facts that have or may have an adverse impact on the value of the old notes or the new notes, which in our sole judgment in any case makes it inadvisable to proceed with such exchange offer and/or with such acceptance for exchange or with such exchange.

If we determine in our sole discretion that any of the foregoing events or conditions has occurred or exists, we may, subject to applicable law, terminate the exchange offer, whether or not any old notes have been accepted for exchange, or may waive any such condition or otherwise amend the terms of such exchange offer in any respect. Please read “—Expiration, extension and amendment” above.

If any of the above events occur, we may:

• terminate the exchange offer and promptly return all tendered old notes to tendering holders;

• complete and/or extend the exchange offer and, subject to your withdrawal rights, retain all tendered old notes until the extended exchange offer expires;

• amend the terms of the exchange offer; or

• waive any unsatisfied condition and, subject to any requirement to extend the period of time during which the exchange offer is open, complete the exchange offer.

We may assert these conditions with respect to the exchange offer regardless of the circumstances giving rise to them. All conditions to the exchange offer, other than those dependent upon receipt of necessary government approvals, must be satisfied or waived by us before the expiration of the exchange offer. We may waive any condition in whole or in part at any time in our reasonable discretion. Our failure to exercise our rights under any of the above circumstances does not represent a waiver of these rights. Each right is an ongoing right that may be asserted at any time. Any determination by us concerning the conditions described above will be final and binding upon all parties.

If a waiver constitutes a material change to the exchange offer, we will promptly disclose the waiver by means of a prospectus supplement that we will distribute to the registered holders of the old notes, and we will extend the exchange offer for a period of five to ten business days, as required by applicable law, depending upon the significance of the waiver and the manner of disclosure to the registered holders, if the exchange offer would otherwise expire during the five to ten business day period.

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Resales of new notes

Based on interpretations by the staff of the SEC, as described in no-action letters issued to third parties that are not related to us, we believe that new notes issued in the exchange offer in exchange for old notes may be offered for resale, resold or otherwise transferred by holders of the new notes without compliance with the registration and prospectus delivery provisions of the Securities Act, if:

• the new notes are acquired in the ordinary course of the holder’s business;

• the holders have no arrangement or understanding with any person to participate in the distribution of the new notes;

• the holders are not “affiliates” of ours within the meaning of Rule 405 under the Securities Act; and

• the holders are not a broker-dealer who purchased old notes directly from us for resale pursuant to Rule 144A or any other available exemption under the Securities Act.

However, the SEC has not considered the exchange offer described in this prospectus in the context of a no-action letter. The staff of the SEC may not make a similar determination with respect to the exchange offer as in the other circumstances. Each holder who wishes to exchange old notes for new notes will be required to represent that it meets the requirements above.

Any holder who is an affiliate of ours or who intends to participate in the exchange offer for the purpose of distributing new notes or any broker-dealer who purchased old notes directly from us for resale pursuant to Rule 144A or any other available exemption under the Securities Act:

• cannot rely on the applicable interpretations of the staff of the SEC mentioned above;

• will not be permitted or entitled to tender the old notes in the exchange offer; and

• must comply with the registration and prospectus delivery requirements of the Securities Act in connection with any resale transaction.

Each broker-dealer that receives new notes for its own account in exchange for old notes must acknowledge that the old notes were acquired by it as a result of market-making activities or other trading activities and agree that it will deliver a prospectus that meets the requirements of the Securities Act in connection with any resale of the new notes. The letter of transmittal states that by so acknowledging and by delivering a prospectus, a broker-dealer will not be deemed to admit that it is an “underwriter” within the meaning of the Securities Act. Please read “Plan of distribution.” A broker-dealer may use this prospectus, as it may be amended or supplemented from time to time, in connection with the resales of new notes received in exchange for old notes that the broker-dealer acquired as a result of market-making or other trading activities. Any holder that is a broker-dealer participating in the exchange offer must notify the exchange agent at the telephone number set forth in the enclosed letter of transmittal and must comply with the procedures for broker-dealers participating in the exchange offer. We have not entered into any arrangement or understanding with any person to distribute the new notes to be received in the exchange offer.

In addition, to comply with state securities laws, the new notes may not be offered or sold in any state unless they have been registered or qualified for sale in such state or an exemption from registration or qualification, with which there has been compliance, is available. The offer and sale of the new notes to “qualified institutional buyers,” as defined under Rule 144A of the Securities Act, is generally exempt from registration or qualification under the state securities laws. We currently do not intend to register or qualify the sale of new notes in any state where an exemption from registration or qualification is required and not available.

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Exchange agent

Wells Fargo Bank, National Association has been appointed as the exchange agent for the exchange offer. All executed letters of transmittal and any other required documents should be directed to the exchange agent at the address or facsimile number set forth below. Questions and requests for assistance, requests for additional copies of this prospectus or of the letter of transmittal and requests for notices of guaranteed delivery should be directed to the exchange agent addressed as follows:

WELLS FARGO BANK, NATIONAL ASSOCIATION

By Facsimile for Eligible Institutions: (612) 667-6282 By Registered or Certified Mail: Wells Fargo Bank, National Association, Corporate Trust Operations, MAC N9303-121, P.O. Box 1517, Minneapolis, MN 55480   By Overnight Delivery or Regular Mail: Wells Fargo Bank, National Association, Corporate Trust Operations, Sixth and Marquette, MAC N9303-121, Minneapolis, MN 55479   By Hand Delivery: Wells Fargo Bank, National Association, 12th Floor—Northstar East Building, Corporate Trust Operations, 608 Second Avenue South, Minneapolis, MN 55402 Confirm By Telephone or for Information:
(800) 344-5128

DELIVERY OF THE LETTER OF TRANSMITTAL TO AN ADDRESS OTHER THAN AS SET FORTH ABOVE OR TRANSMISSION OF SUCH LETTER OF TRANSMITTAL VIA FACSIMILE OTHER THAN AS SET FORTH ABOVE DOES NOT CONSTITUTE A VALID DELIVERY OF THE LETTER OF TRANSMITTAL.

Fees and expenses

The expenses of soliciting tenders pursuant to this exchange offer will be paid by us. We have agreed to pay the exchange agent reasonable and customary fees for its services and will reimburse it for its reasonable out-of-pocket expenses in connection with the exchange offer. We will also pay brokerage houses and other custodians, nominees and fiduciaries the reasonable out-of-pocket expenses incurred by them in forwarding copies of this prospectus and related documents to the beneficial owners of old notes, and in handling or tendering for their customers. We will not make any payment to brokers, dealers or others soliciting acceptances of the exchange offer.

Holders who tender their old notes for exchange will not be obligated to pay any transfer taxes on the exchange. If, however, new notes are to be delivered to, or are to be issued in the name of, any person other than the registered holder of the old notes tendered, or if a transfer tax is imposed for any reason other than the exchange of old notes in connection with the exchange offer, then the amount of any such transfer taxes (whether imposed on the registered holder or any other persons) will be payable by the tendering holder. If satisfactory evidence of payment of such taxes or exemption therefrom is not submitted with the letter of transmittal, the amount of such transfer taxes will be billed directly to such tendering holder.

Transfer taxes

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

Consequences of failure to exchange outstanding securities

Holders who desire to tender their old notes in exchange for new notes registered under the Securities Act should allow sufficient time to ensure timely delivery. Neither the exchange agent nor us is under any duty to give notification of defects or irregularities with respect to the tenders of old notes for exchange.

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Old notes that are not tendered or are tendered but not accepted will, following the completion of the exchange offer, continue to be subject to the provisions in the indenture regarding the transfer and exchange of the old notes and the existing restrictions on transfer set forth in the legend on the old notes set forth in the indenture for the notes. Except in limited circumstances with respect to specific types of holders of old notes, we will have no further obligation to provide for the registration under the Securities Act of such old notes. In general, old notes, unless registered under the Securities Act, may not be offered or sold except pursuant to an exemption from, or in a transaction not subject to, the Securities Act and applicable state securities laws.

We do not currently anticipate that we will take any action to register the old notes under the Securities Act or under any state securities laws. Upon completion of the exchange offer, holders of the old notes will not be entitled to any further registration rights under the registration rights agreement, except under limited circumstances.

Holders of the new notes issued in the exchange offer, any old notes which remain outstanding after completion of the exchange offer and the previously issued notes will vote together as a single class for purposes of determining whether holders of the requisite percentage of the class have taken certain actions or exercised certain rights under the indenture.

Accounting treatment

We will record the new notes at the same carrying value as the old notes, as reflected in our accounting records on the date of the exchange. Accordingly, we will not recognize any gain or loss for accounting purposes. The expenses of the exchange offer will be amortized over the term of the new notes.

Other

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

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DESCRIPTION OF THE NEW NOTES

The Company will issue the registered senior unsecured notes due 2022 (the “Notes”) under an indenture (the “Indenture”) among itself, the Subsidiary Guarantors and Wells Fargo Bank, National Association, as trustee (the “Trustee”). The terms of the Notes include those expressly set forth in the Indenture and those made part of the Indenture by reference to the Trust Indenture Act of 1939, as amended (the “Trust Indenture Act”). An unlimited aggregate principal amount of Notes may be issued under the Indenture. We previously issued $400.0 million aggregate principal amount of the Notes under the Indenture on May 2, 2012 (the “Existing 2022 Notes”). The issuance of Notes in this offering will be limited to $150.0 million. References to “Notes” in this description of senior notes include both the $150.0 million of Notes to be issued in this offering (the “New Notes”) and the Existing 2022 Notes. We may issue an unlimited principal amount of additional notes having identical terms and conditions as the Notes (the “Additional Notes”). We will only be permitted to issue such Additional Notes in compliance with the covenant described under the subheading “—Certain Covenants—Limitation on Indebtedness and Preferred Stock.” The New Notes and any Additional Notes will be part of the same issue as the Existing 2022 Notes and will vote on all matters with the holders of the Existing 2022 Notes. Unless the context otherwise requires, for all purposes of the Indenture and this “Description of the New Notes,” references to the Notes include the New Notes and any Additional Notes actually issued.

This description of senior notes is intended to be a useful overview of the material provisions of the Notes and the Indenture. Since this description of senior notes is only a summary, you should refer to the Indenture for a complete description of the obligations of the Company and your rights.

You will find the definitions of capitalized terms used in this description of senior notes under the heading “—Certain Definitions.” For purposes of this description, references to “the Company,” “we,” “our” and “us” refer only to Chaparral Energy, Inc. and not to any of its subsidiaries.

General

The Notes. The Notes:

• are general unsecured, senior obligations of the Company;

• mature on November 15, 2022;

• will be issued in denominations of $2,000 and integral multiples of $1,000 thereafter;

• will be represented by one or more registered Notes in global form, but in certain circumstances may be represented by Notes in definitive form, see “Book-Entry, Delivery and Form”;

• rank senior in right of payment to all existing and future Subordinated Obligations of the Company;

• rank equally in right of payment to any future senior Indebtedness of the Company, without giving effect to collateral arrangements;

• are unconditionally guaranteed on a senior basis by Chaparral Real Estate, L.L.C., Chaparral Resources, L.L.C., Chaparral CO2, L.L.C., Chaparral Energy, L.L.C., CEI Acquisition, L.L.C., CEI Pipeline, L.L.C., Green Country Supply, Inc., Chaparral Exploration, L.L.C. and Roadrunner Drilling, L.L.C., representing each material direct and indirect wholly owned subsidiary of the Company, see “—Subsidiary Guarantees”; and

• effectively rank junior to any existing or future secured Indebtedness of the Company, including amounts that may be borrowed under our Senior Secured Credit Agreement, to the extent of the value of the collateral securing such Indebtedness.

Interest. Interest on the Notes will compound semi-annually and will:

• accrue at the rate of 7.625% per annum;

• in the case of the New Notes, accrue from November 15, 2012 or, if interest has already been paid, from the most recent interest payment date;

• be payable in cash semi-annually in arrears on May 15 and November 15, and in the case of the New Notes, commencing on May 15, 2013;

• be payable to the holders of record on the May 1 and November 1 immediately preceding the related interest payment dates; and

• be computed on the basis of a 360-day year comprised of twelve 30-day months.

If an interest payment date falls on a day that is not a Business Day, the interest payment to be made on such interest payment date will be made on the next succeeding Business Day with the same force and effect as if made on such interest payment date, and no additional interest will accrue as a result of such delayed payment. The Company will pay interest on overdue principal of the Notes at 0.5 percentage points per annum in excess of the above rate, and overdue installments of interest at such higher rate, to the extent lawful.

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We also will pay liquidated damages to holders of the Notes if we fail to complete the exchange offer described in the Registration Rights Agreement within 270 days or if certain other conditions contained in the Registration Rights Agreement are not satisfied. All references in the Indenture, in any context, to any interest or other amount payable on or with respect to the Notes shall be deemed to include any liquidated damages pursuant to the Registration Rights Agreement.

Payments on the Notes; Paying Agent and Registrar

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

We will pay principal of, premium, if any, liquidated damages, if any, and interest on, Notes in global form registered in the name of or held by The Depository Trust Company or its nominee in immediately available funds to The Depository Trust Company or its nominee, as the case may be, as the registered holder of such global Note.

Transfer and Exchange

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

The registered holder of a Note will be treated as the owner of it for all purposes.

Optional Redemption

On and after May 15, 2017, we may redeem all or, from time to time, a part of the Notes upon not less than 30 nor more than 60 days’ prior notice, at the following redemption prices (expressed as a percentage of principal amount of the Notes) plus accrued and unpaid interest on the Notes, if any, to the applicable redemption date (subject to the right of holders of record on the relevant record date to receive interest due on the relevant interest payment date), if redeemed during the twelve-month period beginning on May 15 of the years indicated below:

Year	Percentage
2017		103.813	%
2018		102.542	%
2019		101.271	%
2020 and thereafter		100.000	%

Prior to May 15, 2015 we may, at our option, on any one or more occasions redeem up to 35% of the aggregate principal amount of the Notes (including Additional Notes) issued under the Indenture with the Net Cash Proceeds of one or more Equity Offerings at a redemption price of 107.625% of the principal amount thereof, plus accrued and unpaid interest, if any, and liquidated damages, if any, to the redemption date (subject to the right of holders of record on the relevant record date to receive interest due on the relevant interest payment date); provided that:

(1) at least 65% of the original principal amount of the Notes issued on the Issue Date remains outstanding after each such redemption; and

(2) the redemption occurs within 90 days after the closing of the related Equity Offering.

In addition, the Notes may be redeemed, in whole or in part, at any time prior to May 15, 2017, at our option, upon not less than 30 nor more than 60 days prior notice, at a redemption price equal to 100% of the principal amount of the Notes redeemed plus the Applicable Premium as of, and accrued and unpaid interest to, the applicable redemption date (subject to the right of holders of record on the relevant record date to receive interest due on the relevant interest payment date).

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Further, if a Change of Control occurs at any time on or prior to June 1, 2013, the Company may, at its option, redeem all, but not less than all, of the Notes, at a redemption price equal to 110.000% of the principal amount of the Notes plus accrued and unpaid interest, if any, and liquidated damages, if any, to the date of purchase (subject to the right of holders of record on the relevant record date to receive interest due on the relevant interest payment date). If the Company elects to exercise this redemption right, it must do so by mailing a redemption notice to each Holder with a copy to the Trustee within 30 days following the Change of Control (or, at the Company’s option, prior to such Change of Control but after the transaction giving rise to such Change of Control is publicly announced). Any such redemption may be conditioned upon the Change of Control occurring if the notice is mailed prior to the Change of Control. If the Company exercises the Change of Control redemption right, it may elect not to make the Change of Control Offer pursuant to the covenant described under the caption “—Change of Control” unless it defaults in payments due upon redemption.

Selection and Notice

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

Mandatory Redemption; Offers to Purchase; Open Market Purchases

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

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

Ranking

The Notes will be general unsecured obligations of the Company that rank senior in right of payment to all existing and future Indebtedness that is expressly subordinated in right of payment to the Notes. The Notes will rank equally in right of payment with all existing and future liabilities of the Company that are not so subordinated and will be effectively subordinated to all of our secured indebtedness (to the extent of the value of the collateral securing such Indebtedness) and liabilities of any of our Subsidiaries that do not guarantee the Notes. In the event of bankruptcy, liquidation, reorganization or other winding up of the Company or its Subsidiary Guarantors or upon a default in payment with respect to, or the acceleration of, any Indebtedness under the Senior Secured Credit Agreement or other secured Indebtedness, the assets of the Company and its Subsidiary Guarantors that secure secured Indebtedness will be available to pay obligations on the Notes and the Subsidiary Guarantees only after all indebtedness under such Credit Facility and other secured indebtedness has been repaid in full from such assets. We advise you that there may not be sufficient assets remaining to pay amounts due on any or all the Notes and the Subsidiary Guarantees then outstanding.

As of December 31, 2012:

• we and our Subsidiary Guarantors had approximately $1.3 billion of total Indebtedness; and

• of the approximately $1.3 billion of total Indebtedness, $42.7 million constituted secured indebtedness and we had additional availability of $474.1 million under our Senior Secured Credit Agreement as to which the Notes were effectively subordinated to the extent of the assets secured thereby.

Subsidiary Guarantees

The Subsidiary Guarantors, as primary obligors and not merely as sureties, will, jointly and severally, irrevocably and unconditionally guarantee on a senior unsecured basis our obligations under the Notes and all obligations under the Indenture. The obligations of Subsidiary Guarantors under the Subsidiary Guarantees will rank equally in right of payment with other Indebtedness of such Subsidiary Guarantor, except to the extent such other Indebtedness is expressly subordinate to the obligations arising under the Subsidiary Guarantee.

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As of December 31, 2012, outstanding Indebtedness of Subsidiary Guarantors was $1.3 billion, of which $42.7 million was secured.

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

The obligations of each Subsidiary Guarantor under its Subsidiary Guarantee will be limited as necessary to prevent that Subsidiary Guarantee from constituting a fraudulent conveyance or fraudulent transfer under applicable law, although no assurance can be given that a court would give the holder the benefit of such provision. See “Risk Factors—Risks Related to the New Notes—Federal and state fraudulent transfer laws may permit a court to void the guarantees, and, if that occurs, you may not receive any payments on the notes.” If a Subsidiary Guarantee were rendered voidable, it could be subordinated by a court to all other indebtedness (including guarantees and other contingent liabilities) of the applicable Subsidiary Guarantor, and, depending on the amount of such indebtedness, a Subsidiary Guarantor’s liability on its Subsidiary Guarantee could be reduced to zero. If the obligations of a Subsidiary Guarantor under its Subsidiary Guarantee were avoided, holders of Notes would have to look to the assets of any remaining Subsidiary Guarantors for payment. There can be no assurance in that event that such assets would suffice to pay the outstanding principal and interest on the Notes.

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

In addition, a Subsidiary Guarantor will be released from its obligations under the Indenture, its Subsidiary Guarantee and the Registration Rights Agreement if the Company designates such Subsidiary as an Unrestricted Subsidiary and such designation complies with the other applicable provisions of the Indenture or in connection with any legal defeasance or satisfaction and discharge of the Notes as provided below under the captions “—Defeasance” and “—Satisfaction and Discharge.”

Change of Control

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

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

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

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

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

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

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

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

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(7) that if we are redeeming less than all of the Notes, the holders of the remaining Notes will be issued new Notes and such new Notes will be equal in principal amount to the unpurchased portion of the Notes surrendered. The unpurchased portion of the Notes must be equal to $2,000 or an integral multiple of $1,000 thereafter; and

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

On the Change of Control Payment Date, the Company will, to the extent lawful:

(1) accept for payment all Notes or portions of Notes (of at least $2,000 or an integral multiple of $1,000 thereafter) properly tendered pursuant to the Change of Control Offer;

(2) deposit with the paying agent an amount equal to the Change of Control Payment in respect of all Notes or portions of Notes properly tendered and not properly withdrawn; and

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

The paying agent will promptly mail to each holder of Notes properly tendered and not properly withdrawn the Change of Control Payment for such Notes, and the Trustee will promptly authenticate and mail (or cause to be transferred by book entry) to each holder a new Note equal in principal amount to any unpurchased portion of the Notes surrendered, if any; provided that each such new Note will be in a principal amount of $2,000 or an integral multiple of $1,000 thereafter.

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

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

We will not be required to make a Change of Control Offer upon a Change of Control if a third party makes the Change of Control Offer in the manner, at the times and otherwise in compliance with the requirements set forth in the Indenture applicable to a Change of Control Offer made by us and purchases all Notes validly tendered and not withdrawn under such Change of Control Offer. Notwithstanding anything to the contrary herein, a Change of Control Offer may be made in advance of a Change of Control, conditional upon such Change of Control, if a definitive agreement is in place for the Change of Control at the time of making of the Change of Control Offer.

We will comply, to the extent applicable, with the requirements of Rule 14e-1 of the Exchange Act and any other securities laws or regulations in connection with the repurchase of Notes as a result of a Change of Control. To the extent that the provisions of any securities laws or regulations conflict with provisions of the Indenture, or compliance with the Change of Control provisions of the Indenture would constitute a violation of any such laws or regulations, we will comply with the applicable securities laws and regulations and will not be deemed to have breached our obligations described in the Indenture by virtue of our compliance with such securities laws or regulations.

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

The Senior Secured Credit Agreement prohibits the Company from purchasing any Note and also provides that the occurrence of certain change in control events with respect to the Company would constitute a default thereunder. In the event a Change in Control occurs at a time when the Company is prohibited from purchasing Notes, we may seek the consent from the lenders under the Senior Secured Credit Agreement to the purchase of Notes or may attempt to refinance the borrowings that contain such prohibition. If we do not obtain such a consent or repay such borrowings, the Company will remain prohibited from purchasing Notes. In such case, the Company’s failure to offer to purchase Notes would constitute a Default under the Indenture after any giving of notice and lapse of

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time, which would, in turn, constitute a default under the Senior Secured Credit Agreement. Moreover, the exercise by the holders of Notes of their right to require the Company to repurchase the Notes could cause a default under the Credit Facilities, even if the Change of Control itself does not, due to the financial effect of such repurchase. Finally, the Company’s ability to pay cash to the holders of Notes upon a repurchase may be limited by the Company’s then existing financial resources. There can be no assurance that sufficient funds will be available when necessary to make any required repurchases. See “Risk Factors—Risks Relating to the New Notes—We may not be able to satisfy our obligations to holders of the notes upon a change of control.”

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

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

The definition of “Change of Control” includes a disposition of all or substantially all of the property and assets of the Company and its Restricted Subsidiaries taken as a whole to any Person other than a Permitted Holder. Although there is a limited body of case law interpreting the phrase “substantially all,” there is no precise established definition of the phrase under applicable law. Accordingly, in certain circumstances there may be a degree of uncertainty as to whether a particular transaction would involve a disposition of “all or substantially all” of the property or assets of a Person. As a result, it may be unclear as to whether a Change of Control has occurred and whether a holder of Notes may require the Company to make an offer to repurchase the Notes as described above. In a recent decision, the Chancery Court of Delaware raised the possibility that a change of control as a result of a failure to have “continuing directors” comprising a majority of the Board of Directors may be unenforceable on public policy grounds.

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

Certain Covenants

Suspension of Covenants

Following the first day:

(a) the Notes have achieved Investment Grade Status; and

(b) no Default or Event of Default has occurred and is continuing under the Indenture,

then, beginning on that day and continuing until the Reversion Date (as defined below), the Company and its Restricted Subsidiaries will not be subject to the provisions of the indenture summarized under the following headings (collectively, the “Suspended Covenants”):

• “—Limitation on Indebtedness and Preferred Stock,”

• “—Limitation on Restricted Payments,”

• “—Limitation on Restrictions on Distributions From Restricted Subsidiaries,”

• “—Limitation on Sales of Assets and Subsidiary Stock,”

• “—Limitation on Affiliate Transactions,”

• “—Future Subsidiary Guarantors,” and

• the provisions of clause (3) of the first paragraph of “—Merger and Consolidation.”

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If at any time the Notes cease to have such Investment Grade Status or if a Default or Event of Default occurs and is continuing, then the Suspended Covenants will thereafter be reinstated as if such covenants had never been suspended (the “Reversion Date”) and be applicable pursuant to the terms of the Indenture (including in connection with performing any calculation or assessment to determine compliance with the terms of the Indenture), unless and until the Notes subsequently attain Investment Grade Status and no Default or Event of Default is in existence (in which event the Suspended Covenants shall no longer be in effect for such time that the Notes maintain an Investment Grade Status and no Default or Event of Default is in existence); provided, however, that no Default, Event of Default or breach of any kind shall be deemed to exist under the Indenture, the Notes or the Subsidiary Guarantees with respect to the Suspended Covenants based on, and neither the Company nor any of its Subsidiaries shall bear any liability for, any actions taken or events occurring during the Suspension Period (as defined below), or any actions taken at any time pursuant to any contractual obligation arising prior to the Reversion Date, regardless of whether such actions or events would have been permitted if the applicable Suspended Covenants remained in effect during such period. The period of time between the date of suspension of the covenants and the Reversion Date is referred to as the “Suspension Period.”

On the Reversion Date, all Indebtedness Incurred during the Suspension Period will be classified to have been Incurred pursuant to the first paragraph of “—Limitation on Indebtedness and Preferred Stock” or one of the clauses set forth in the second paragraph of “—Limitation on Indebtedness and Preferred Stock” (to the extent such Indebtedness would be permitted to be Incurred thereunder as of the Reversion Date and after giving effect to the Indebtedness Incurred prior to the Suspension Period and outstanding on the Reversion Date). To the extent such Indebtedness would not be so permitted to be Incurred pursuant to the first and second paragraphs of “—Limitation on Indebtedness and Preferred Stock,” such Indebtedness will be deemed to have been outstanding on the Issue Date, so that it is classified as permitted under clause (4)(b) of the second paragraph of “—Limitation on Indebtedness and Preferred Stock.” Calculations made after the Reversion Date of the amount available to be made as Restricted Payments under “—Limitation on Restricted Payments” will be made as though the covenants described under “—Limitation on Restricted Payments” had been in effect since the Issue Date and throughout the Suspension Period. Accordingly, Restricted Payments made during the Suspension Period will reduce the amount available to be made as Restricted Payments under the first paragraph of “—Limitation on Restricted Payments.” For purposes of determining compliance with the covenant described under “—Limitation on Sales of Assets and Subsidiary Stock,” on the Reversion Date, the Net Available Cash from Asset Dispositions not applied in accordance with such covenant will be deemed reset at zero. In addition, any future obligation to grant further Subsidiary Guarantees shall be released. All such further obligation to grant Subsidiary Guarantees shall be reinstated upon the Reversion Date. The Company will provide written notice to the Trustee of the occurrence of any Suspension Period or Reversion Date.

During any Suspension Period, the Company may not designate any of the Company’s Subsidiaries as Unrestricted Subsidiaries pursuant to the Indenture unless such designation would have been allowed if the Suspended Covenants had been in effect at the time of such designation and throughout such period and applied to all activities of the Company and its Restricted Subsidiaries throughout such period.

There can be no assurance that the Notes will ever achieve or maintain Investment Grade Status.

Limitation on Indebtedness and Preferred Stock

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

(1) the Consolidated Coverage Ratio for the Company and its Restricted Subsidiaries is at least 2.00 to 1.00, determined on a pro forma basis (including a pro forma application of proceeds); and

(2) no Default will have occurred or be continuing or would occur as a consequence of Incurring the Indebtedness or transactions relating to such Incurrence.

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

(1) Indebtedness of the Company Incurred pursuant to one or more Credit Facilities in an aggregate amount not to exceed the greater of (a) $600.0 million less the aggregate amount of all permanent principal repayments since the Issue Date under a Credit Facility that are made under clause (3)(a) of the first paragraph of the covenant described under “—Certain Covenants—Limitation on Sales of Assets and Subsidiary Stock,” or (b) 30% of Adjusted Consolidated Net Tangible Assets determined as of the date of the Incurrence of such Indebtedness after giving effect to the application of the proceeds therefrom, in each case outstanding at any one time;

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

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(3) Indebtedness of the Company owing to and held by any Restricted Subsidiary or Indebtedness of a Restricted Subsidiary owing to and held by the Company or any Restricted Subsidiary; provided, however, that (i) any subsequent issuance or transfer of Capital Stock or any other event which results in any such Indebtedness being held by a Person other than the Company or a Restricted Subsidiary of the Company and (ii) any sale or other transfer of any such Indebtedness to a Person other than the Company or a Restricted Subsidiary of the Company shall be deemed, in each case, to constitute an Incurrence of such Indebtedness by the Company or such Subsidiary, as the case may be;

(4) Indebtedness represented by (a) the Notes issued on the Issue Date, and the related exchange notes issued in a registered exchange offer (or shelf registration) pursuant to the Registration Rights Agreement, and all Subsidiary Guarantees, (b) any Indebtedness (other than the Indebtedness described in clauses (1), (2) and (4)(a)) outstanding on the Issue Date (including the Existing Senior Notes) and (c) any Refinancing Indebtedness Incurred in respect of any Indebtedness described in this clause (4) or clause (5) or incurred pursuant to the first paragraph of this covenant;

(5) Indebtedness of a Person that becomes a Restricted Subsidiary or is acquired by the Company or a Restricted Subsidiary or merged into the Company or a Restricted Subsidiary in accordance with the Indenture and outstanding on the date on which such Person became a Restricted Subsidiary or was acquired by or was merged into the Company or such Restricted Subsidiary (other than Indebtedness Incurred (a) to provide all or any portion of the funds utilized to consummate the transaction or series of related transactions pursuant to which such Person became a Restricted Subsidiary or was otherwise acquired by or was merged into the Company or a Restricted Subsidiary or (b) otherwise in connection with, or in contemplation of, such acquisition); provided, however, that at the time such Person becomes a Restricted Subsidiary or is acquired by or was merged into the Company or a Restricted Subsidiary, either (x) the Company would have been able to incur $1.00 of additional Indebtedness pursuant to the first paragraph of this covenant or (y) the Consolidated Coverage Ratio for the Company and its Restricted Subsidiaries would not be greater than immediately prior to such time, in either case after giving effect to the Incurrence of such Indebtedness pursuant to this clause (5);

(6) the Incurrence by the Company or any Restricted Subsidiary of Indebtedness represented by Capitalized Lease Obligations, mortgage financings or purchase money obligations, in each case incurred for the purpose of financing all or any part of the purchase price or cost of construction or improvements or carrying costs of property used in the business of the Company or such Restricted Subsidiary, and Refinancing Indebtedness Incurred to Refinance any Indebtedness Incurred pursuant to this clause (6) in an aggregate outstanding principal amount which, when taken together with the principal amount of all other Indebtedness Incurred pursuant to this clause (6) and then outstanding, will not exceed $35.0 million at any time outstanding;

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

(8) Capital Stock (other than Disqualified Stock) of the Company or of any of the Subsidiary Guarantors;

(9) Indebtedness, including Refinancing Indebtedness, Incurred by a Foreign Subsidiary in an aggregate amount not to exceed 15% of such Foreign Subsidiary’s Adjusted Consolidated Net Tangible Assets at any time outstanding;

(10) any Guarantee by the Company or any Restricted Subsidiary that directly owns Capital Stock of an Unrestricted Subsidiary that is recourse only to, or secured only by, such Capital Stock; and

(11) in addition to the items referred to in clauses (1) through (10) above, Indebtedness of the Company and its Subsidiary Guarantors in an aggregate outstanding principal amount which, when taken together with the principal amount of all other Indebtedness Incurred pursuant to this clause (11) and then outstanding, will not exceed $35.0 million at any time outstanding.

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

(1) in the event an item of that Indebtedness meets the criteria of more than one of the types of Indebtedness described in the first and second paragraphs of this covenant, the Company, in its sole discretion, will classify such item of Indebtedness on the date of Incurrence, and in that connection shall be entitled to treat a portion of such Indebtedness as having been Incurred under the first paragraph and thereafter the remainder of such Indebtedness having been Incurred under the second paragraph, and, subject to clause (2) below, may later reclassify such item of Indebtedness and only be required to include the amount and type of such Indebtedness in one of such clauses;

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

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

(4) if obligations in respect of letters of credit are incurred pursuant to a Credit Facility and are being treated as Incurred pursuant to clause (1) of the second paragraph above and the letters of credit relate to other Indebtedness, then such other Indebtedness shall not be included;

(5) the principal amount of any Disqualified Stock of the Company or a Restricted Subsidiary, or Preferred Stock of a Restricted Subsidiary that is not a Subsidiary Guarantor, will be equal to the greater of the maximum mandatory redemption or repurchase price (not including, in either case, any redemption or repurchase premium) or the liquidation preference thereof;

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

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

Accrual of interest, accrual of dividends, the amortization of debt discount or the accretion of accreted value, the payment of interest in the form of additional Indebtedness, the payment of dividends in the form of additional shares of Preferred Stock or Disqualified Stock and unrealized losses or charges in respect of Hedging Obligations (including those resulting from the application of ASC Topic 815, Derivatives and Hedging) will not be deemed to be an Incurrence of Indebtedness for purposes of this covenant. The amount of any Indebtedness outstanding as of any date shall be (i) the accreted value thereof in the case of any Indebtedness issued with original issue discount and (ii) the principal amount or liquidation preference thereof, together with any interest thereon that is more than 30 days past due, in the case of any other Indebtedness.

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

For purposes of determining compliance with any U.S. dollar-denominated restriction on the Incurrence of Indebtedness, the U.S. dollar-equivalent principal amount of Indebtedness denominated in a foreign currency shall be calculated based on the relevant currency exchange rate in effect on the date such Indebtedness was Incurred, in the case of term Indebtedness, or first committed, in the case of revolving credit Indebtedness; provided that if such Indebtedness is Incurred to refinance other Indebtedness denominated in a foreign currency, and such refinancing would cause the applicable U.S. dollar-denominated restriction to be exceeded if calculated at the relevant currency exchange rate in effect on the date of such refinancing, such U.S. dollar-denominated restriction shall be deemed not to have been exceeded so long as the principal amount of such Refinancing Indebtedness does not exceed the principal amount of such Indebtedness being refinanced. Notwithstanding any other provision of this covenant, the maximum amount of Indebtedness that the Company may Incur pursuant to this covenant shall not be deemed to be exceeded solely as a result of fluctuations in the exchange rate of currencies. The principal amount of any Indebtedness Incurred to refinance other Indebtedness, if Incurred in a different currency from the Indebtedness being refinanced, shall be calculated based on the currency exchange rate applicable to the currencies in which such Refinancing Indebtedness is denominated that is in effect on the date of such refinancing.

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

Limitation on Restricted Payments

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

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

(a) dividends or distributions by the Company payable solely in Capital Stock of the Company (other than Disqualified Stock) or in options, warrants or other rights to purchase such Capital Stock of the Company; and

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

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

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

(4) make any Restricted Investment in any Person;

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

(a) a Default shall have occurred and be continuing (or would result therefrom);

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

(c) the aggregate amount of such Restricted Payment and all other Restricted Payments declared or made subsequent to December 1, 2005 would exceed the sum of:

(i) 50% of Consolidated Net Income for the period (treated as one accounting period) from October 1, 2005 to the end of the most recent fiscal quarter ending prior to the date of such Restricted Payment for which internal financial statements are in existence (or, in case such Consolidated Net Income is a deficit, minus 100% of such deficit);

(ii) 100% of the aggregate Net Cash Proceeds, and the Fair Market Value (as determined by the Company’s Board of Directors in good faith) of property or securities other than cash (including Capital Stock of Persons engaged primarily in the Oil and Gas Business or assets used in the Oil and Gas Business), in each case received by the Company from the issue or sale of its Capital Stock (other than Disqualified Stock) or other capital contributions subsequent to December 1, 2005 (other than Net Cash Proceeds received from an issuance or sale of such Capital Stock to (x) management, employees, directors or any direct or indirect parent of the Company, to the extent such Net Cash Proceeds have been used to make a Restricted Payment pursuant to clause (5)(a) of the next succeeding paragraph, (y) a Subsidiary of the Company or (z) an employee stock ownership plan, option plan or similar trust (to the extent such sale to an employee stock ownership plan, option plan or similar trust is financed by loans from or Guaranteed by the Company or any Restricted Subsidiary unless such loans have been repaid with cash on or prior to the date of determination));

(iii) the amount by which Indebtedness of the Company or its Restricted Subsidiaries is reduced on the Company’s balance sheet upon the conversion or exchange (other than by a Wholly Owned Subsidiary of the Company) subsequent to December 1, 2005 of any Indebtedness of the Company or its Restricted Subsidiaries convertible or exchangeable for Capital Stock (other than Disqualified Stock) of the Company (less the amount of any cash, or the Fair Market Value of any other property (other than such Capital Stock), distributed by the Company upon such conversion or exchange), together with the net proceeds, if any, received by the Company or any of its Restricted Subsidiaries upon such conversion or exchange; and

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

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

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

(C) the sale (other than to the Company or a Restricted Subsidiary) of the Capital Stock of an Unrestricted Subsidiary or a distribution from an Unrestricted Subsidiary or a dividend from an Unrestricted Subsidiary.

The provisions of the preceding paragraph will not prohibit:

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

(2) any purchase, repurchase, redemption, defeasance or other acquisition or retirement of Subordinated Obligations of the Company or Guarantor Subordinated Obligations of any Subsidiary Guarantor made by exchange for, or out of the proceeds of the substantially concurrent sale of, Subordinated Obligations of the Company or any purchase, repurchase, redemption, defeasance or other acquisition or retirement of Guarantor Subordinated Obligations made by exchange for or out of the proceeds of the substantially concurrent sale of Guarantor Subordinated obligations that, in each case, is permitted to be Incurred pursuant to the covenant described under “—Limitation on Indebtedness and Preferred Stock”; provided, however, that such purchase, repurchase, redemption, defeasance, acquisition or retirement will be excluded from subsequent calculations of the amount of Restricted Payments;

(3) any purchase, repurchase, redemption, defeasance or other acquisition or retirement of Disqualified Stock of the Company or a Restricted Subsidiary made by exchange for or out of the proceeds of the substantially concurrent sale of Disqualified Stock of the Company or such Restricted Subsidiary, as the case may be, that, in each case, is permitted to be Incurred pursuant to the covenant described under “—Limitation on Indebtedness and Preferred Stock”; provided, however, that such purchase, repurchase, redemption, defeasance, acquisition or retirement will be excluded from subsequent calculations of the amount of Restricted Payments;

(4) dividends paid or distributions made within 60 days after the date of declaration if at such date of declaration such dividend or distribution would have complied with this covenant; provided, however, that such dividends and distributions will be included in subsequent calculations of the amount of Restricted Payments; and provided, however, that for purposes of clarification, this clause (4) shall not include cash payments in lieu of the issuance of fractional shares included in clause (9) below;

(5) (a) (i) the purchase, redemption or other acquisition, cancellation or retirement for value (each, a “Purchase”) of either phantom stock under the Phantom Stock Plan or restricted stock units under the Restricted Stock Unit Plan held by any existing or former employees, management or directors of Parent, the Company or any Subsidiary of the Company or their assigns, estates or heirs, in each case in connection with the repurchase provisions under the Phantom Stock Plan; or (ii) so long as no Default has occurred and is continuing, the Purchase of Capital Stock, or options, warrants, equity appreciation rights or other rights to purchase or acquire Capital Stock of Parent, the Company or any Restricted Subsidiary (other than Purchases covered by subclause (a)(i) above) held by any existing or former employees, management or directors of Parent, the Company or any Subsidiary of the Company or their assigns, estates or heirs, in each case in connection with the repurchase provisions under employee stock option or stock purchase agreements or other agreements to compensate management, employees or directors; provided that such redemptions or repurchases pursuant to this subclause (a)(ii) during any calendar year will not exceed $5.0 million in the aggregate (with unused amounts in any calendar year being carried over to succeeding calendar years subject to a maximum (without giving effect to the immediately following proviso) of $7.0 million in any calendar year); provided further, that such amount in any calendar year may be increased by an amount not to exceed (A) the cash proceeds received by the Company from the sale of Capital Stock of the Company to members of management or directors of the Company and its Restricted Subsidiaries that occurs after the Issue Date (to the extent the cash proceeds from the sale of such Capital Stock have not otherwise been applied to the payment of Restricted Payments by virtue of the clause (c) of the preceding paragraph), plus (B) the cash proceeds of key man life insurance policies received by the Company and its Restricted Subsidiaries after the Issue Date, less (C) the amount of any Restricted Payments made pursuant to clauses (A) and (B) of this clause (5)(a); provided further, however, that the amount of any such repurchase or redemption under each of subclauses (a)(i) and (a)(ii) will be excluded in subsequent calculations of the amount of Restricted Payments and the proceeds received from any such sale will be excluded from clause (c)(ii) of the preceding paragraph; and

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(b) the cancellation of loans or advances to employees or directors of the Company or any Subsidiary of the Company the proceeds of which are used to purchase Capital Stock of the Company, in an aggregate amount not in excess of $2.0 million at any one time outstanding; provided, however, that the Company and its Subsidiaries will comply in all material respects with all applicable provisions of the Sarbanes-Oxley Act of 2002 and the rules and regulations promulgated in connection therewith in connection with such loans or advances; provided further, that the amount of such cancelled loans and advances will be included in subsequent calculations of the amount of Restricted Payments;

(6) repurchases, redemptions or other acquisitions or retirements for value of Capital Stock deemed to occur upon the exercise of stock options, warrants, rights to acquire Capital Stock or other convertible securities if such Capital Stock represents a portion of the exercise or exchange price thereof, and any repurchases, redemptions or other acquisitions or retirements for value of Capital Stock made in lieu of withholding taxes in connection with any exercise or exchange of warrants, options or rights to acquire Capital Stock; provided, however, that such repurchases will be excluded from subsequent calculations of the amount of Restricted Payments;

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

(8) payments or distributions to dissenting stockholders pursuant to applicable law or in connection with the settlement or other satisfaction of legal claims made pursuant to or in connection with a consolidation, merger or transfer of assets; provided, however, that any payment pursuant to this clause (8) shall be included in the calculation of the amount of Restricted Payments;

(9) cash payments in lieu of the issuance of fractional shares; provided, however, that any payment pursuant to this clause (9) shall be excluded in the calculation of the amount of Restricted Payments;

(10) Permitted Payments to Parent;

(11) Restricted Payments in an amount not to exceed $25.0 million at any one time outstanding; provided, however, that the amount of such Restricted Payments will be included in subsequent calculations of the amount of Restricted Payments.

The amount of all Restricted Payments (other than cash) shall be the Fair Market Value on the date of such Restricted Payment of the asset(s) or securities proposed to be paid, transferred or issued by the Company or such Restricted Subsidiary, as the case may be, pursuant to such Restricted Payment. The Fair Market Value of any cash Restricted Payment shall be its face amount and the Fair Market Value of any non-cash Restricted Payment shall be determined conclusively by the Board of Directors of the Company acting in good faith whose resolution with respect thereto shall be delivered to the Trustee, such determination to be based upon an opinion or appraisal issued by an accounting, appraisal or investment banking firm of national standing if such Fair Market Value is estimated in good faith by the Board of Directors of the Company to exceed $25.0 million. Not later than the date of making any Restricted Payment, the Company shall deliver to the Trustee an Officers’ Certificate stating that such Restricted Payment is permitted and setting forth the basis upon which the calculations required by the covenant described under “—Limitation on Restricted Payments” were computed, together with a copy of any fairness opinion or appraisal required by the Indenture.

As of the Issue Date, all of our Subsidiaries will be Restricted Subsidiaries other than Chaparral Biofuels, L.L.C. and Oklahoma Ethanol L.L.C. We will not permit any Unrestricted Subsidiary to become a Restricted Subsidiary except pursuant to the last sentence of the definition of “Unrestricted Subsidiary.”

For purpose of designating any Restricted Subsidiary as an Unrestricted Subsidiary, all outstanding Investments by the Company and its Restricted Subsidiaries (except to the extent repaid) in the Subsidiary so designated will be deemed to be Restricted Payments in an amount determined as set forth in the last sentence of the definition of “Investment.” Such designation will be permitted only if a Restricted Payment in such amount would be permitted at such time, whether pursuant to the first paragraph of this covenant or under clause (11) of the second paragraph of this covenant, or pursuant to the definition of “Permitted Investments,” and if such Subsidiary otherwise meets the definition of an Unrestricted Subsidiary. Unrestricted Subsidiaries will not be subject to any of the restrictive covenants set forth in the Indenture.

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As of December 31, 2012, we had approximately $600.0 million of Restricted Payment capacity under clause (c) of this covenant.

Limitation on Liens

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

Any Lien created for the benefit of the holders of the Notes pursuant to the preceding paragraph shall provide by its terms that such Lien shall be automatically and unconditionally released and discharged upon the release and discharge of the initial Lien.

Limitation on Restrictions on Distributions From Restricted Subsidiaries

The Company will not, and will not permit any Restricted Subsidiary to, create or otherwise cause or permit to exist or become effective any consensual encumbrance or consensual restriction on the ability of any Restricted Subsidiary to:

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

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

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

The preceding provisions will not prohibit:

(i) any encumbrance or restriction pursuant to or by reason of an agreement in effect at or entered into on the Issue Date, including, without limitation, the Indenture in effect on such date;

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

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

(iv) any encumbrance or restriction with respect to a Unrestricted Subsidiary pursuant to or by reason of an agreement that the Unrestricted Subsidiary is a party to entered into before the date on which such Unrestricted Subsidiary became a Restricted Subsidiary; provided, that such agreement was not entered into in anticipation of the Unrestricted Subsidiary becoming a Restricted Subsidiary and any such encumbrance or restriction shall not extend to any assets or property of the Company or any other Restricted Subsidiary other than the assets and property so acquired;

(v) with respect to any Foreign Subsidiary, any encumbrance or restriction contained in the terms of any Indebtedness or any agreement pursuant to which such Indebtedness was Incurred if:

(a) either (1) the encumbrance or restriction applies only in the event of a payment default or a default with respect to a financial covenant in such Indebtedness or agreement or (2) the Company determines that any such encumbrance or restriction will not materially affect the Company’s ability to make principal or interest payments on the Notes, as determined in good faith by the Board of Directors of the Company, whose determination shall be conclusive; and

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(b) the encumbrance or restriction is not materially more disadvantageous to the holders of the Notes than is customary in comparable financing (as determined by the Company);

(vi) any encumbrance or restriction with respect to a Restricted Subsidiary pursuant to an agreement effecting a refunding, replacement or refinancing of Indebtedness Incurred pursuant to an agreement referred to in clauses (i) through (v) or clause (xii) of this paragraph or this clause (vi) or contained in any amendment, restatement, modification, renewal, supplemental, refunding, replacement or refinancing of an agreement referred to in clauses (i) through (v) or clause (xii) of this paragraph or this clause (vi); provided, however, that the encumbrances and restrictions with respect to such Restricted Subsidiary contained in any such agreement taken as a whole are no less favorable in any material respect to the holders of the Notes than the encumbrances and restrictions contained in such agreements referred to in clauses (i) through (v) or clause (xii) of this paragraph on the Issue Date or the date such Restricted Subsidiary became a Restricted Subsidiary or was merged into a Restricted Subsidiary, whichever is applicable;

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

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

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

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

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

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

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

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

(x) any customary encumbrances or restrictions imposed pursuant to any agreement of the type described in the definition of “Permitted Business Investment”;

(xi) encumbrances or restrictions arising or existing by reason of applicable law or any applicable rule, regulation or order; and

(xii) the Senior Secured Credit Agreement as in effect as of the Issue Date, and any amendments, modifications, restatements, renewals, increases, supplements, refundings, replacements or refinancings thereof, provided that such amendments, modifications, restatements, renewals, increases, supplements, refundings, replacements or refinancings are no more restrictive with respect to such dividend and other payment restrictions than those contained in the Senior Secured Credit Agreement as in effect on the Issue Date.

Limitation on Sales of Assets and Subsidiary Stock

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

(1) the Company or such Restricted Subsidiary, as the case may be, receives consideration at the time of such Asset Disposition at least equal to the Fair Market Value (such Fair Market Value to be determined on the date of contractually agreeing to such Asset Disposition), as determined in good faith by the Board of Directors (including as to the value of all non-cash consideration), of the shares and assets subject to such Asset Disposition;

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

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

(a) to the extent the Company or any Restricted Subsidiary, as the case may be, elects (or is required by the terms of any Indebtedness), to prepay, repay, redeem or purchase Indebtedness of the Company under the Senior Secured Credit Agreement, any other Indebtedness of the Company or a Subsidiary Guarantor that is secured by a Lien permitted to be Incurred under the Indenture or Indebtedness (other than Disqualified Stock) of any Wholly Owned Subsidiary that is not a Subsidiary Guarantor; provided, however, that, in connection with any prepayment, repayment, redemption or purchase of Indebtedness pursuant to this clause (a), the Company or such Restricted Subsidiary will retire such Indebtedness and will cause the related commitment (if any) to be permanently reduced in an amount equal to the principal amount so prepaid, repaid or purchased; or

(b) to invest in Additional Assets;

provided that pending the final application of any such Net Available Cash in accordance with this covenant, the Company and its Restricted Subsidiaries may temporarily reduce Indebtedness or otherwise invest such Net Available Cash in any manner not prohibited by the Indenture.

Any Net Available Cash from Asset Dispositions that is not applied or invested as provided in the preceding paragraph will be deemed to constitute “Excess Proceeds.” Not later than the day following the date that is one year from the later of the date of such Asset Disposition or the receipt of such Net Available Cash, if the aggregate amount of Excess Proceeds exceeds $20.0 million, the Company will be required to make an offer (“Asset Disposition Offer”) to all holders of Notes and to the extent required by the terms of other Pari Passu Indebtedness, to all holders of other Pari Passu Indebtedness outstanding with similar provisions requiring the Company to make an offer to purchase such Pari Passu Indebtedness with the proceeds from any Asset Disposition (“Pari Passu Notes”), to purchase the maximum principal amount of Notes and any such Pari Passu Notes to which the Asset Disposition Offer applies that may be purchased out of the Excess Proceeds, at an offer price in cash in an amount equal to 100% of the principal amount (or, in the event such Pari Passu Indebtedness of the Company was issued with significant original issue discount, 100% of the accreted value thereof) of the Notes and Pari Passu Notes plus accrued and unpaid interest and liquidated damages, if any (or in respect of such Pari Passu Indebtedness, such lesser price, if any, as may be provided for by the terms of such Indebtedness), to the date of purchase (subject to the right of holders of record on the relevant record date to receive interest due on the relevant interest payment date), in accordance with the procedures set forth in the Indenture or the agreements governing the Pari Passu Notes, as applicable, in each case in denominations of at least $2,000 or an integral multiple of $1,000 thereafter. If the aggregate principal amount of Notes surrendered by holders thereof and other Pari Passu Notes surrendered by holders or lenders, collectively, exceeds the amount of Excess Proceeds, the Trustee shall select the Notes to be purchased on a pro rata basis on the basis of the aggregate principal amount of tendered Notes and Pari Passu Notes. To the extent that the aggregate amount of Notes and Pari Passu Notes so validly tendered and not properly withdrawn pursuant to an Asset Disposition Offer is less than the Excess Proceeds, the Company may use any remaining Excess Proceeds for general corporate purposes, subject to the other covenants contained in the Indenture. Upon completion of such Asset Disposition Offer, the amount of Excess Proceeds shall be reset at zero.

The Asset Disposition Offer will remain open for a period of 20 Business Days following its commencement, except to the extent that a longer period is required by applicable law (the “Asset Disposition Offer Period”). No later than five Business Days after the termination of the Asset Disposition Offer Period (the “Asset Disposition Purchase Date”), the Company will purchase the principal amount of Notes and Pari Passu Notes required to be purchased pursuant to this covenant (the “Asset Disposition Offer Amount”) or, if less than the Asset Disposition Offer Amount has been so validly tendered, all Notes and Pari Passu Notes validly tendered in response to the Asset Disposition Offer.

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

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

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Notes so validly tendered and not properly withdrawn by such holder or lender, as the case may be, and accepted by the Company for purchase, and the Company will promptly issue a new Note, and the Trustee, upon delivery of an Officers’ Certificate from the Company, will authenticate and mail or deliver such new Note to such holder, in a principal amount equal to any unpurchased portion of the Note surrendered; provided that each such new Note will be in a principal amount of $2,000 or an integral multiple of $1,000 thereafter. In addition, the Company will take any and all other actions required by the agreements governing the Pari Passu Notes. Any Note not so accepted will be promptly mailed or delivered by the Company to the holder thereof. The Company will publicly announce the results of the Asset Disposition Offer on the Asset Disposition Purchase Date.

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

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

(1) the assumption by the transferee of Indebtedness (other than Subordinated obligations or Disqualified Stock) of the Company or Indebtedness of a Restricted Subsidiary (other than Guarantor Subordinated Obligations or Disqualified Stock of any Restricted Subsidiary that is a Subsidiary Guarantor) and the release of the Company or such Restricted Subsidiary from all liability on such Indebtedness in connection with such Asset Disposition (or in lieu of such a release, the agreement of the acquirer or its parent company to indemnify and hold the Company or such Restricted Subsidiary harmless from and against any loss, liability or cost in respect of such assumed Indebtedness; provided, however, that such indemnifying party (or its long term debt securities) shall have an Investment Grade Rating (with no indication of a negative outlook or credit watch with negative implications, in any case, that contemplates such indemnifying party (or its long term debt securities) failing to have an Investment Grade Rating), in which case the Company will, without further action, be deemed to have applied such deemed cash to Indebtedness in accordance with clause (3)(a) of the first paragraph of this covenant; and

(2) securities, notes or other obligations received by the Company or any Restricted Subsidiary from the transferee that are converted by the Company or such Restricted Subsidiary into cash within 90 days after receipt thereof.

Notwithstanding the foregoing, the 75% limitation referred to in clause (2) of the first paragraph of this covenant shall be deemed satisfied with respect to any Asset Disposition in which the cash or Cash Equivalents portion of the consideration received therefrom, determined in accordance with the foregoing provision on an after-tax basis, is equal to or greater than what the after-tax proceeds would have been had such Asset Disposition complied with the aforementioned 75% limitation.

The requirement of clause (3)(b) of the first paragraph of this covenant above shall be deemed to be satisfied if an agreement (including a lease, whether a capital lease or an operating lease) committing to make the acquisitions or expenditures referred to therein is entered into by the Company or its Restricted Subsidiary within the specified time period and such Net Available Cash is subsequently applied in accordance with such agreement within six months following such agreement.

Limitation on Affiliate Transactions

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

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

(2) if such Affiliate Transaction involves an aggregate consideration in excess of $5.0 million, the terms of such transaction have been approved by a majority of the members of the Board of Directors of the Company and by a majority of the members of such Board having no personal stake in such transaction, if any (and such majority or majorities, as the case may be, determines that such Affiliate Transaction satisfies the criteria in clause (1) above); and

(3) if such Affiliate Transaction involves an aggregate consideration in excess of $25.0 million, the Board of Directors of the Company has received a written opinion from an independent investment banking, accounting or appraisal firm of nationally recognized standing that such Affiliate Transaction is fair, from a financial standpoint, to the Company or such Restricted Subsidiary or is not materially less favorable than those that could reasonably be expected to be obtained in a comparable transaction at such time on an arm’s-length basis from a Person that is not an Affiliate.

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The preceding paragraph will not apply to:

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

(2) any issuance of Capital Stock (other than Disqualified Stock), or other payments, awards or grants in cash, Capital Stock (other than Disqualified Stock) or otherwise pursuant to, or the funding of, employment or severance agreements and other compensation arrangements, options to purchase Capital Stock (other than Disqualified Stock) of the Company, restricted stock plans, long-term incentive plans, stock appreciation rights plans, participation plans or similar employee benefits plans and/or indemnity provided on behalf of officers and employees approved by the Board of Directors of the Company;

(3) loans or advances to employees, officers or directors in the ordinary course of business of the Company or any of its Restricted Subsidiaries;

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

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

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

(7) indemnities of officers, directors and employees of the Company or any of its Restricted Subsidiaries permitted by charter documents or statutory provisions and any employment agreement or other employee compensation plan or arrangement entered into in the ordinary course of business by the Company or any of its Restricted Subsidiaries;

(8) the payment of reasonable compensation and fees paid to, and indemnity provided on behalf of, officers or directors of the Company or any Restricted Subsidiary;

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

(10) transactions with customers, clients, suppliers, or purchasers or sellers of goods or services, in each case in the ordinary course of business and otherwise in compliance with the terms of the Indenture which are fair to the Company and its Restricted Subsidiaries, in the reasonable determination of the Board of Directors of the Company or the senior management thereof, or are on terms at least as favorable as might reasonably have been obtained at such time from an unaffiliated party.

SEC Reports

The Indenture will provide that, whether or not the Company is subject to the reporting requirements of Section 13 or 15(d) of the Exchange Act, to the extent not prohibited by the Exchange Act, the Company will file with the SEC, and make available to the Trustee and the registered holders of the Notes without cost to any holder, the annual reports and the information, documents and other reports (or copies of such portions of any of the foregoing as the SEC may by rules and regulations prescribe) that are specified in Sections 13 and 15(d) of the Exchange Act and applicable to a U.S. corporation within the time periods specified therein with respect to a non-accelerated filer. In the event that the Company is not permitted to file such reports, documents and information with the SEC pursuant to the Exchange Act, the Company will nevertheless make available such Exchange Act information to the Trustee and the holders of the Notes without cost to any holder as if the Company were subject to the reporting requirements of Section 13 or 15(d) of the Exchange Act within the time periods specified therein with respect to a non-accelerated filer.

If the Company has designated any of its Subsidiaries as Unrestricted Subsidiaries, then the quarterly and annual financial information required by the preceding paragraph shall include a reasonably detailed presentation, either on the face of the financial statements or in the footnotes to the financial statements and in Management’s Discussion and Analysis of Results of Operations and Financial Condition, of the financial condition and results of operations of the Company and its Restricted Subsidiaries.

In addition, the Company and the Subsidiary Guarantors have agreed that they will make available to the holders and to prospective investors, upon the request of such holders, the information required to be delivered pursuant to Rule 144A(d)(4) under the Securities Act so long as the Notes are not freely transferable under the Securities Act to the extent not satisfied by the foregoing. For purposes of this covenant, the Company and the Subsidiary Guarantors will be deemed to have furnished the reports to the Trustee and the holders of Notes as required by this covenant if it has filed such reports with the SEC via the EDGAR filing system and such reports are publicly available.

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Merger and Consolidation

The Company will not consolidate with or merge with or into or wind up into (whether or not the Company is the surviving corporation), or convey, transfer or lease all or substantially all its assets in one or more related transactions to, any Person, unless:

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

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

(3) immediately after giving effect to such transaction, either (a) the Successor Company would be able to Incur at least an additional $1.00 of Indebtedness pursuant to the first paragraph of the covenant described under “—Limitation on Indebtedness and Preferred Stock” or (b) the Consolidated Coverage Ratio for the Company and its Restricted Subsidiaries would not be greater than immediately prior to giving effect to such transaction;

(4) each Subsidiary Guarantor (unless it is the other party to the transactions above, in which case clause (1) shall apply) shall have by supplemental indenture confirmed that its Subsidiary Guarantee shall apply to such Person’s obligations in respect of the Indenture and the Notes and its obligations under the Registration Rights Agreement (if applicable) shall continue to be in effect; and

(5) the Company shall have delivered to the Trustee an Officers’ Certificate and an Opinion of Counsel, each stating that such consolidation, merger or transfer and such supplemental indenture (if any) comply with the Indenture.

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

The Successor Company will succeed to, and be substituted for, and may exercise every right and power of, the Company under the Indenture; and its predecessor Company, except in the case of a lease of all or substantially all its assets, will be released from the obligation to pay the principal of and interest on the Notes.

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

Notwithstanding the preceding clause (3), (x) any Restricted Subsidiary may consolidate with, merge into or transfer all or part of its properties and assets to the Company and the Company may consolidate with, merge into or transfer all or part of its properties and assets to a Wholly Owned Subsidiary and (y) the Company may merge with an Affiliate incorporated solely for the purpose of reincorporating the Company in another jurisdiction; provided that, in the case of a Restricted Subsidiary that consolidates with, merges into or transfers all or part of its properties and assets to the Company, the Company will not be required to comply with the preceding clause (5).

In addition, the Company will not permit any Subsidiary Guarantor to consolidate with or merge with or into, and will not permit the conveyance, transfer or lease of substantially all of the assets of any Subsidiary Guarantor to, any Person (other than the Company or another Subsidiary Guarantor) unless:

(1) (a) the resulting, surviving or transferee Person will be a corporation, partnership, trust or limited liability company organized and existing under the laws of the United States of America, any State of the United States or the District of Columbia and such Person (if not such Subsidiary Guarantor) will expressly assume, by supplemental indenture, executed and delivered to the Trustee, all the obligations of such Subsidiary Guarantor under its Subsidiary Guarantee, (b) immediately after giving effect to such transaction (and treating any Indebtedness that becomes an obligation of the resulting, surviving or transferee Person or any Restricted Subsidiary as a result of such transaction as having been Incurred by such Person or such Restricted Subsidiary at the time of such transaction), no Default shall have occurred and be continuing, and (c) the Company shall have delivered to the Trustee an Officers’ Certificate and Opinion of Counsel each stating that such consolidation, merger or transfer and such supplemental indenture complies with the Indenture; or

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(2) the transaction is made in compliance with the covenants described under “—Subsidiary Guarantees” and “—Certain Covenants—Limitation on Sales of Assets and Subsidiary Stock.”

Future Subsidiary Guarantors

The Indenture provides that the Company will cause each Restricted Subsidiary that Incurs any Indebtedness other than a Foreign Subsidiary created or acquired by the Company or one or more of its Restricted Subsidiaries to execute and deliver to the Trustee within 60 days a Subsidiary Guarantee pursuant to which such Subsidiary Guarantor will unconditionally Guarantee, on a joint and several basis, the full and prompt payment of the principal of, premium, if any, interest and liquidated damages, if any, on the Notes on a senior basis; provided that any Restricted Subsidiary that constitutes an Immaterial Subsidiary need not become a Subsidiary Guarantor until such time as it ceases to be an Immaterial Subsidiary.

Limitation on Lines of Business

The Company will not, and will not permit any Restricted Subsidiary to, engage in any business other than the Oil and Gas Business, except to the extent as would not be material to the Company and its Restricted Subsidiaries taken as a whole.

Payments for Consent

Neither the Company nor any of its Restricted Subsidiaries will, directly or indirectly, pay or cause to be paid any consideration, whether by way of interest, fees or otherwise, to any holder of any Notes for or as an inducement to any consent, waiver or amendment of any of the terms or provisions of the Indenture or the Notes unless such consideration is offered to be paid or is paid to all holders of the Notes that consent, waive or agree to amend in the time frame set forth in the solicitation documents relating to such consent, waiver or amendment.

Events of Default

Each of the following is an Event of Default:

(1) default in any payment of interest or liquidated damages (as required by the Registration Rights Agreement) on any Note when due, continued for 30 days;

(2) default in the payment of principal of or premium, if any, on any Note when due at its Stated Maturity, upon optional redemption, upon required repurchase, upon declaration of acceleration or otherwise;

(3) failure by the Company or any Subsidiary Guarantor to comply with its obligations under “—Certain Covenants—Merger and Consolidation”;

(4) failure by the Company to comply for 30 days after notice as provided below with any of its obligations under the covenant described under “Change of Control” above or under the covenants described under “—Certain Covenants” above (in each case, other than a failure to purchase Notes which will constitute an Event of Default under clause (2) above and other than a failure to comply with “—Certain Covenants—Merger and Consolidation” which is covered by clause (3));

(5) failure by the Company to comply for 60 days after notice as provided below with its other agreements contained in the Indenture;

(6) default under any mortgage, indenture or instrument under which there may be issued or by which there may be secured or evidenced any Indebtedness for money borrowed by the Company or any of its Restricted Subsidiaries (or the payment of which is guaranteed by the Company or any of its Restricted Subsidiaries), other than Indebtedness owed to the Company or a Restricted Subsidiary, whether such Indebtedness or guarantee now exists, or is created after the date of the Indenture, which default:

(a) is caused by a failure to pay principal of, or interest or premium, if any, on such Indebtedness prior to the expiration of the grace period provided in such Indebtedness (and any extensions of any grace period) (“payment default”); or

(b) results in the acceleration of such Indebtedness prior to its maturity (the “cross acceleration provision”);

and, in each case, the principal amount of any such Indebtedness, together with the principal amount of any other such Indebtedness under which there has been a payment default or the maturity of which has been so accelerated, aggregates $20.0 million or more;

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(7) certain events of bankruptcy, insolvency or reorganization of the Company or a Significant Subsidiary or group of Restricted Subsidiaries that, taken together (as of the latest audited consolidated financial statements for the Company and its Restricted Subsidiaries), would constitute a Significant Subsidiary (the “bankruptcy provisions”);

(8) failure by the Company or any Significant Subsidiary or group of Restricted Subsidiaries that, taken together (as of the latest audited consolidated financial statements for the Company and its Restricted Subsidiaries), would constitute a Significant Subsidiary to pay final judgments aggregating in excess of $20.0 million (to the extent not covered by insurance by a reputable and creditworthy insurer as to which the insurer has not disclaimed coverage), which judgments are not paid or discharged, and there shall be any period of 60 consecutive days following entry of such final judgment or decree during which a stay of enforcement of such final judgment or decree, by reason of pending appeal or otherwise, shall not be in effect (the “judgment default provision”); or

(9) any Subsidiary Guarantee of a Significant Subsidiary or group of Restricted Subsidiaries that, taken together (as of the latest audited consolidated financial statements for the Company and its Restricted Subsidiaries) would constitute a Significant Subsidiary ceases to be in full force and effect (except as contemplated by the terms of the Indenture) or is declared null and void in a judicial proceeding or any Subsidiary Guarantor that is a Significant Subsidiary or group of Subsidiary Guarantors that, taken together (as of the latest audited consolidated financial statements of the Company and its Restricted Subsidiaries) would constitute a Significant Subsidiary denies or disaffirms its obligations under the Indenture or its Subsidiary Guarantee.

However, a default under clauses (4) and (5) of this paragraph will not constitute an Event of Default until the Trustee or the holders of 25% in principal amount of the outstanding Notes notify the Company in writing and, in the case of a notice given by the holders, the Trustee, of the default and the Company does not cure such default within the time specified in clauses (4) and (5) of this paragraph after receipt of such notice.

If an Event of Default (other than an Event of Default described in clause (7) above) occurs and is continuing, the Trustee by notice to the Company, or the holders of at least 25% in principal amount of the outstanding Notes by notice to the Company and the Trustee, may, and the Trustee at the request of such holders shall, declare the principal of, premium, if any, accrued and unpaid interest, if any, and liquidated damages, if any, on all the Notes to be due and payable. If an Event of Default described in clause (7) above occurs and is continuing, the principal of, premium, if any, accrued and unpaid interest and liquidated damages, if any, on all the Notes will become and be immediately due and payable without any declaration or other act on the part of the Trustee or any holders. The holders of a majority in principal amount of the outstanding Notes may waive all past defaults (except with respect to nonpayment of principal, premium, interest or liquidated damages, if any) and rescind any such acceleration with respect to the Notes and its consequences if (1) rescission would not conflict with any judgment or decree of a court of competent jurisdiction and (2) all existing Events of Default, other than the nonpayment of the principal of, premium, if any, and interest on the Notes that have become due solely by such declaration of acceleration, have been cured or waived.

Subject to the provisions of the Indenture relating to the duties of the Trustee, if an Event of Default occurs and is continuing, the Trustee will be under no obligation to exercise any of the rights or powers under the Indenture at the request or direction of any of the holders unless such holders have offered to the Trustee indemnity or security satisfactory to the Trustee against any loss, liability or expense. Except to enforce the right to receive payment of principal, premium, if any, or interest when due, no holder may pursue any remedy with respect to the Indenture or the Notes unless:

(1) such holder has previously given the Trustee notice that an Event of Default is continuing;

(2) holders of at least 25% in principal amount of the outstanding old notes and the Notes have requested the Trustee to pursue the remedy;

(3) such holders have offered the Trustee security or indemnity satisfactory to the Trustee against any loss, liability or expense;

(4) the Trustee has not complied with such request within 60 days after the receipt of the request and the offer of security or indemnity; and

(5) the holders of a majority in principal amount of the outstanding old notes and the Notes have not waived such Event of Default or otherwise given the Trustee a direction that, in the opinion of the Trustee, is inconsistent with such request within such 60-day period.

Subject to certain restrictions, the holders of a majority in principal amount of the outstanding old notes and the Notes are given the right to direct the time, method and place of conducting any proceeding for any remedy available to the Trustee or of exercising any trust or power conferred on the Trustee. The Indenture provides that in the event an Event of Default has occurred and is continuing, the Trustee will be required in the exercise of its powers to use the degree of care that a prudent person would use under the circumstances in the conduct of its own affairs. The Trustee, however, may refuse to follow any direction that conflicts with law or the Indenture or that the Trustee determines is unduly prejudicial to the rights of any other holder or that would involve the Trustee in personal liability. Prior to taking any action under the Indenture, the Trustee will be entitled to indemnification satisfactory to it in its sole discretion against all losses and expenses caused by taking or not taking such action.

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If a default occurs and is continuing and is known to the Trustee the Trustee must mail to each holder of the Notes notice of default within 90 days after it occurs. Except in the case of a default in the payment of principal, premium, if any, interest or liquidated damages, if any, the Trustee may withhold notice if and so long as a committee of trust officers of the Trustee in good faith determines that withholding notice is in the interests of the holders. In addition, the Company is required to deliver to the Trustee, within 120 days after the end of each fiscal year, a certificate indicating whether the signers thereof know of any Default that occurred during the previous year. The Company also is required to deliver to the Trustee, within 30 days after the occurrence thereof, written notice of any events which would constitute certain Defaults, their status and what action the Company is taking or proposing to take in respect thereof.

Amendments and Waivers

Subject to certain exceptions, the Indenture and the Notes may be amended or supplemented with the consent of the holders of a majority in principal amount of the old notes and the Notes then outstanding (including without limitation, consents obtained in connection with a purchase of, or tender offer or exchange offer for, old notes and the Notes) and, subject to certain exceptions, any past default or compliance with any provisions may be waived with the consent of the holders of a majority in principal amount of the old notes and the Notes then outstanding (including, without limitation, consents obtained in connection with a purchase of, or tender offer or exchange offer for, old notes and the Notes). However, without the consent of each holder of an outstanding Note affected, no amendment may, among other things:

(1) reduce the principal amount of Notes whose holders must consent to an amendment, supplement or waiver;

(2) reduce the stated rate of or extend the stated time for payment of interest on any Note;

(3) reduce the principal of or extend the Stated Maturity of any Note;

(4) reduce the premium payable upon the redemption of any Note as described above under “—Optional Redemption,” or change the time at which any Note may be redeemed as described above under “—Optional Redemption,” or make any change to the covenants described above under “—Change of Control” after the occurrence of a Change of Control, or make any change to the provisions relating an Asset Disposition Offer that has been made, in each case whether through an amendment or waiver of provisions in the covenants, definitions or otherwise;

(5) make any Note payable in money other than that stated in the Note;

(6) impair the right of any holder to receive payment of, premium, if any, principal of and interest on such holder’s Notes on or after the due dates therefor or to institute suit for the enforcement of any payment on or with respect to such holder’s Notes;

(7) make any change in the amendment provisions which require each holder’s consent or in the waiver provisions;

(8) modify the Subsidiary Guarantees in any manner adverse to the holders of the Notes; or

(9) make any change to or modify the ranking of the Notes that would adversely affect the holders.

Notwithstanding the foregoing, without the consent of any holder, the Company, the Guarantors and the Trustee may amend the Indenture and the Notes to:

(1) cure any ambiguity, omission, defect, mistake or inconsistency;

(2) provide for the assumption by a successor corporation of the obligations of the Company or any Subsidiary Guarantor under the Indenture;

(3) provide for uncertificated Notes in addition to or in place of certificated Notes (provided that the uncertificated Notes are issued in registered form for purposes of Section 163(f) of the Code, or in a manner such that the uncertificated Notes are described in Section 163(f)(2)(B) of the Code);

(4) add Guarantees with respect to the Notes, including Subsidiary Guarantees, or release a Subsidiary Guarantor from its Subsidiary Guarantee and terminate such Subsidiary Guarantee; provided, however, that the release and termination is in accord with the applicable provisions of the Indenture;

(5) secure the Notes or Subsidiary Guarantees;

(6) add to the covenants of the Company or a Subsidiary Guarantor for the benefit of the holders or surrender any right or power conferred upon the Company or a Subsidiary Guarantor;

(7) make any change that does not adversely affect the rights of any holder;

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(8) comply with any requirement of the SEC in connection with the qualification of the Indenture under the Trust Indenture Act;

(9) provide for the issuance of exchange securities which shall have terms substantially identical in all respects to the Notes (except that the transfer restrictions contained in the Notes shall be modified or eliminated as appropriate) and which shall be treated, together with any outstanding Notes, as a single class of securities; or

(10) provide for the succession of a successor Trustee.

The consent of the holders is not necessary under the Indenture to approve the particular form of any proposed amendment. It is sufficient if such consent approves the substance of the proposed amendment. A consent to any amendment or waiver under the Indenture by any holder of Notes given in connection with a tender of such holder’s Notes will not be rendered invalid by such tender. After an amendment under the Indenture becomes effective, the Company is required to mail to the holders a notice briefly describing such amendment. However, the failure to give such notice to all the holders, or any defect in the notice will not impair or affect the validity of the amendment.

Defeasance

The Company at any time may terminate all its obligations under the Notes and the Indenture (“legal defeasance”), except for certain obligations, including those respecting the defeasance trust and obligations to register the transfer or exchange of the Notes, to replace mutilated, destroyed, lost or stolen Notes and to maintain a registrar and paying agent in respect of the Notes. If the Company exercises its legal defeasance option, the Subsidiary Guarantees in effect at such time will terminate.

The Company at any time may terminate its obligations described under “—Change of Control” and under covenants described under “—Certain Covenants” (other than “—Merger and Consolidation”), the operation of the cross default upon a payment default, cross acceleration provisions, the bankruptcy provisions with respect to Significant Subsidiaries, the judgment default provision and the Subsidiary Guarantee provision described under “—Events of Default” above and the limitations contained in clause (3) under “—Certain Covenants—Merger and Consolidation” above (“covenant defeasance”).

The Company may exercise its legal defeasance option notwithstanding its prior exercise of its covenant defeasance option. If the Company exercises its legal defeasance option, payment of the Notes may not be accelerated because of an Event of Default with respect to the Notes. If the Company exercises its covenant defeasance option, payment of the Notes may not be accelerated because of an Event of Default specified in clause (4), (5), (6), (7) (with respect only to Significant Subsidiaries), (8) or (9) under “—Events of Default” above or because of the failure of the Company to comply with clause (3) under “—Certain Covenants—Merger and Consolidation” above.

In order to exercise either defeasance option, the Company must, among other things, irrevocably deposit in trust (the “defeasance trust”) with the Trustee money or U.S. Government Obligations for the payment of principal, premium, if any, interest and liquidated damages, if any, on the Notes to redemption or maturity, as the case may be, and must comply with certain other conditions, including delivery to the Trustee of an Opinion of Counsel (subject to customary exceptions and exclusions) to the effect that holders of the Notes will not recognize income, gain or loss for federal income tax purposes as a result of such deposit and defeasance and will be subject to Federal income tax on the same amount and in the same manner and at the same times as would have been the case if such deposit and defeasance had not occurred. In the case of legal defeasance only, such Opinion of Counsel must be based on a ruling of the Internal Revenue Service or other change in applicable federal income tax law.

Satisfaction and Discharge

The Indenture will be discharged and will cease to be of further effect as to all Notes issued thereunder, when either:

(1) all Notes that have been authenticated (except lost, stolen or destroyed Notes that have been replaced or paid and Notes for whose payment money has theretofore been deposited in trust or segregated and held in trust by the Company and thereafter repaid to the Company or discharged from such trust) have been delivered to the Trustee for cancellation, or

(2) all Notes that have not been delivered to the Trustee for cancellation have become due and payable or will become due and payable within one year by reason of the giving of a notice of redemption or otherwise and the Company or any Subsidiary Guarantor has irrevocably deposited or caused to be irrevocably deposited with the Trustee as trust funds in trust solely for such purpose, cash in U.S. dollars, U.S. Government Obligations, or a combination thereof, in such amounts as will be sufficient without consideration of any reinvestment of interest, to pay and discharge the entire indebtedness on the Notes not delivered to the Trustee for cancellation for principal and accrued interest to the date of maturity or redemption, and in each case certain other requirements set forth in the Indenture are satisfied.

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No Personal Liability of Directors, Officers, Employees and Stockholders

No director, officer, employee, incorporator or stockholder of the Company or any Subsidiary Guarantor, as such, shall have any liability for any obligations of the Company or any Subsidiary Guarantor under the Notes, the Indenture or the Subsidiary Guarantees or for any claim based on, in respect of, or by reason of, such obligations or their creation. Each holder by accepting a Note waives and releases all such liability. The waiver and release are part of the consideration for issuance of the Notes.

Concerning the Trustee

Wells Fargo Bank, National Association, is the Trustee under the Indenture and has been appointed by the Company as registrar and paying agent with regard to the Notes.

Governing Law

The Indenture provides that it and the Notes will be governed by, and construed in accordance with, the laws of the State of New York.

Certain Definitions

“Acquired Indebtedness” means Indebtedness (i) of a Person or any of its Subsidiaries existing at the time such Person becomes or is merged with and into a Restricted Subsidiary or (ii) assumed in connection with the acquisition of assets from such Person, in each case whether or not Incurred by such Person in connection with, or in anticipation or contemplation of, such Person becoming a Restricted Subsidiary or such acquisition. Acquired Indebtedness shall be deemed to have been Incurred, with respect to clause (i) of the preceding sentence, on the date such Person becomes or is merged with and into a Restricted Subsidiary and, with respect to clause (ii) of the preceding sentence, on the date of consummation of such acquisition of assets.

“Additional Assets” means:

(1) any properties or assets to be used by the Company or a Restricted Subsidiary in the Oil and Gas Business;

(2) capital expenditures by the Company or a Restricted Subsidiary in the Oil and Gas Business;

(3) the Capital Stock of a Person that becomes a Restricted Subsidiary as a result of the acquisition of such Capital Stock by the Company or a Restricted Subsidiary; or

(4) Capital Stock constituting a minority interest in any Person that at such time is a Restricted Subsidiary;

provided, however, that, in the case of clauses (3) and (4), such Restricted Subsidiary is primarily engaged in the Oil and Gas Business.

“Adjusted Consolidated Net Tangible Assets” of a Person means (without duplication), as of the date of determination, the remainder of:

(a) the sum of:

(i) discounted future net revenues from proved oil and gas reserves of such Person and its Restricted Subsidiaries calculated in accordance with SEC guidelines before any state or federal income taxes, as both estimated by the Company in a reserve report prepared as of the end of the Company’s most recently completed fiscal year and included in audited financial statements either filed with the SEC or provided to the Trustee and the holders of the Notes as required under the heading “—Certain Covenants—SEC Reports,” as increased by, as of the date of determination, the estimated discounted future net revenues from

(A) estimated proved oil and gas reserves acquired since such year end, which reserves were not reflected in such year end reserve report, and

(B) estimated oil and gas reserves attributable to extensions, discoveries and other additions and upward revisions of estimates of proved oil and gas reserves (including previously estimated development costs Incurred during the period and the accretion of discount since the prior period end) since such year end due to exploration, development or exploitation, production or other activities, which would, in accordance with standard industry practice, cause such revisions, in each case calculated in accordance with SEC guidelines (utilizing the prices for the fiscal quarter ending prior to the date of determination),

and decreased by, as of the date of determination, the estimated discounted future net revenues from

(C) estimated proved oil and gas reserves produced or disposed of since such year end, and

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(D) estimated oil and gas reserves attributable to downward revisions of estimates of proved oil and gas reserves since such year end due to changes in geological conditions or other factors which would, in accordance with standard industry practice, cause such revisions, in each case calculated on a pre-tax basis and substantially in accordance with SEC guidelines (utilizing the prices for the fiscal quarter ending prior to the date of determination),

provided, however, that in the case of each of the determinations made pursuant to clauses (A) through (D), such increases and decreases shall be as estimated by the Company’s petroleum engineers;

(i) the capitalized costs that are attributable to oil and gas properties of such Person and its Restricted Subsidiaries to which no proved oil and gas reserves are attributable, based on such Person’s books and records as of a date no earlier than the date of such Person’s latest available annual or quarterly financial statements;

(ii) the Net Working Capital of such Person on a date no earlier than the date of such Person’s latest annual or quarterly financial statements; and

(iii) the greater of

(A) the net book value of other tangible assets of such Person and its Restricted Subsidiaries, as of a date no earlier than the date of such Person’s latest annual or quarterly financial statement, and

(B) the appraised value, as estimated by independent appraisers, of other tangible assets of such Person and its Restricted Subsidiaries, as of a date no earlier than the date of such Person’s latest audited financial statements;

minus

(b) the sum of:

(i) Minority Interests;

(ii) any net gas balancing liabilities of such Person and its Restricted Subsidiaries reflected in such Person’s latest audited balance sheet;

(iii) to the extent included in (a)(i) above, the discounted future net revenues, calculated in accordance with SEC guidelines (utilizing the prices utilized in such Person’s year end reserve report), attributable to reserves which are required to be delivered to third parties to fully satisfy the obligations of the Company and its Restricted Subsidiaries with respect to Volumetric Production Payments (determined, if applicable, using the schedules specified with respect thereto); and

(iv) the discounted future net revenues, calculated in accordance with SEC guidelines, attributable to reserves subject to Dollar-Denominated Production Payments which, based on the estimates of production and price assumptions included in determining the discounted future net revenues specified in (a)(i) above, would be necessary to fully satisfy the payment obligations of such Person and its Subsidiaries with respect to Dollar-Denominated Production Payments (determined, if applicable, using the schedules specified with respect thereto).

If the Company changes its method of accounting from the full cost method of accounting to the successful efforts or a similar method, “Adjusted Consolidated Net Tangible Assets” will continue to be calculated as if the Company were still using the full cost method of accounting.

“Affiliate” of any specified Person means any other Person, directly or indirectly, controlling or controlled by or under direct or indirect common control with such specified Person. For the purposes of this definition, “control” when used with respect to any Person means the power to direct the management and policies of such Person, directly or indirectly, whether through the ownership of voting securities, by contract or otherwise; and the terms “controlling” and “controlled” have meanings correlative to the foregoing; provided that beneficial ownership of 10% or more of the Voting Stock of a Person shall be deemed to be control.

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

(1) 1.0% of the principal amount of such Note; and

(2) the excess, if any, of:

(a) the present value at such redemption date of: (i) the redemption price of such Note at May 15, 2017 plus (ii) all required interest payments (excluding accrued and unpaid interest to such redemption date) due on such Note through May 15, 2017, computed using a discount rate equal to the Treasury Rate as of such redemption date plus 50 basis points; over

(b) the principal amount of such Note.

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“ASC” means the Financial Accounting Standards Board Accounting Standards Codification.

“Asset Disposition” means any direct or indirect sale, lease (other than an operating lease entered into in the ordinary course of the Oil and Gas Business), transfer, issuance or other disposition, or a series of related sales, leases, transfers, issuances or dispositions that are part of a common plan, of (A) shares of Capital Stock of a Restricted Subsidiary (other than directors’ qualifying shares or shares required by applicable law to be held by a Person other than the Company or a Restricted Subsidiary), (B) all or substantially all the assets of any division or line of business of the Company or any Restricted Subsidiary, or (C) any other assets of the Company or any Restricted Subsidiary outside of the ordinary course of business of the Company or such Restricted Subsidiary (each referred to for the purposes of this definition as a “disposition”), in each case by the Company or any of its Restricted Subsidiaries, including any disposition by means of a merger, consolidation or similar transaction.

Notwithstanding the preceding, the following items shall not be deemed to be Asset Dispositions:

(1) a disposition by a Restricted Subsidiary to the Company or by the Company or a Restricted Subsidiary to a Wholly Owned Subsidiary;

(2) the sale of Cash Equivalents in the ordinary course of business;

(3) a disposition of Hydrocarbons or mineral products inventory in the ordinary course of business;

(4) a disposition of damaged, unserviceable, obsolete or worn out equipment or equipment that is no longer necessary for the proper conduct of the business of the Company and its Restricted Subsidiaries and that is disposed of in each case in the ordinary course of business;

(5) transactions in accordance with the covenant described under “—Certain Covenants—Merger and Consolidation”;

(6) an issuance of Capital Stock by a Restricted Subsidiary to the Company or to a Wholly Owned Subsidiary;

(7) for purposes of “—Certain Covenants—Limitation on Sales of Assets and Subsidiary Stock” only, the making of a Permitted Investment or a Restricted Payment (or a disposition that would constitute a Restricted Payment but for the exclusions from the definition thereof) permitted by the covenant described under “—Certain Covenants—Limitation on Restricted Payments”;

(8) an Asset Swap;

(9) dispositions of assets with a Fair Market Value of less than $5.0 million;

(10) Permitted Liens;

(11) dispositions of receivables in connection with the compromise, settlement or collection thereof in the ordinary course of business or in bankruptcy or similar proceedings and exclusive of factoring or similar arrangements;

(12) the licensing or sublicensing of intellectual property or other general intangibles and licenses, leases or subleases of other property in the ordinary course of business which do not materially interfere with the business of the Company and its Restricted Subsidiaries;

(13) foreclosure on assets;

(14) any Production Payments and Reserve Sales; provided that any such Production Payments and Reserve Sales, other than incentive compensation programs on terms that are reasonably customary in the Oil and Gas Business for geologists, geophysicists and other providers of technical services to the Company or a Restricted Subsidiary, shall have been created, Incurred, issued, assumed or Guaranteed in connection with the financing of, and within 60 days after the acquisition of, the property that is subject thereto;

(15) a disposition of oil and natural gas properties in connection with tax credit transactions complying with Section 29 or any successor or analogous provisions of the Code;

(16) surrender or waiver of contract rights, oil and gas leases, concessions or the settlement, release or surrender of contract, tort or other claims of any kind;

(17) the abandonment, farm-out, lease or sublease of developed or undeveloped oil and gas properties in the ordinary course of business; and

(18) the sale or transfer (whether or not in the ordinary course of business) of any oil and gas property or interest therein to which no proved reserves are attributable at the time of such sale or transfer.

“Asset Swap” means any concurrent purchase and sale or exchange of any oil or natural gas property or CO2 property used in the Oil and Gas Business, an interest therein or equity interest in an entity that owns only such property between the Company or any of its Restricted Subsidiaries and another Person; provided, that any cash received must be applied in accordance with “—Certain Covenants—Limitation on Sales of Assets and Subsidiary Stock” as if the Asset Swap were an Asset Disposition.

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“Average Life” means, as of the date of determination, with respect to any Indebtedness or Preferred Stock, the quotient obtained by dividing (1) the sum of the products of the numbers of years from the date of determination to the dates of each successive scheduled principal payment of such Indebtedness or redemption or similar payment with respect to such Preferred Stock multiplied by the amount of such payment by (2) the sum of all such payments.

“Beneficial Owner” has the meaning assigned to such term in Rule 13d-3 and Rule 13d-5 under the Exchange Act, except that in calculating the beneficial ownership of any particular “person” (as that term is used in Section 13(d)(3) of the Exchange Act), such “person” will be deemed to have beneficial ownership of all securities that such “person” has the right to acquire by conversion or exercise of other securities, whether such right is currently exercisable or is exercisable only after the passage of time. The terms “Beneficially Owns” and “Beneficially Owned” have a corresponding meaning.

“Board of Directors” means, as to any Person that is a corporation, the board of directors of such Person or any duly authorized committee thereof or as to any Person that is not a corporation, the board of managers or such other individual or group serving a similar function.

“Business Day” means each day that is not a Saturday, Sunday or other day on which commercial banking institutions in New York, New York, Minneapolis, Minnesota or Dallas/Fort Worth, Texas are authorized or required by law to close.

“Capital Stock” of any Person means any and all shares, interests, rights to purchase, warrants, options, participation or other equivalents of or interests in (however designated) equity of such Person, including any Preferred Stock, but excluding any debt securities convertible into such equity.

“Capitalized Lease Obligations” means an obligation that is required to be classified and accounted for as a capitalized lease for financial reporting purposes in accordance with GAAP, and the amount of Indebtedness represented by such obligation will be the capitalized amount of such obligation at the time any determination thereof is to be made as determined in accordance with GAAP, and the Stated Maturity thereof will be the date of the last payment of rent or any other amount due under such lease prior to the first date such lease may be terminated without penalty.

“Cash Equivalents” means:

(1) securities issued or directly and fully guaranteed or insured by the United States Government or any agency or instrumentality of the United States (provided that the full faith and credit of the United States is pledged in support thereof), having maturities of not more than one year from the date of acquisition;

(2) marketable general obligations issued by any state of the United States of America or any political subdivision of any such state or any public instrumentality thereof maturing within one year from the date of acquisition (provided that the full faith and credit of the United States is pledged in support thereof) and, at the time of acquisition, having a credit rating of “A” (or the equivalent thereof) or better from either Standard & Poor’s Ratings Services or Moody’s Investors Service, Inc.;

(3) certificates of deposit, time deposits, eurodollar time deposits, overnight bank deposits or bankers’ acceptances having maturities of not more than one year from the date of acquisition thereof issued by any commercial bank the long-term debt of which is rated at the time of acquisition thereof at least “A” or the equivalent thereof by Standard & Poor’s Ratings Services, or “a2” or the equivalent thereof by Moody’s Investors Service, Inc., and having combined capital and surplus in excess of $500.0 million;

(4) repurchase obligations with a term of not more than seven days for underlying securities of the types described in clauses (1), (2) and (3) entered into with any bank meeting the qualifications specified in clause (3) above;

(5) commercial paper rated at the time of acquisition thereof at least “A-2” or the equivalent thereof by Standard & Poor’s Ratings Services or “P-2” or the equivalent thereof by Moody’s Investors Service, Inc., or carrying an equivalent rating by a nationally recognized rating agency, if both of the two named rating agencies cease publishing ratings of investments, and in any case maturing within one year after the date of acquisition thereof; and

(6) interests in any investment company or money market fund which invests 95% or more of its assets in instruments of the type specified in clauses (1) through (5) above.

“Change of Control” means:

(1) any “person” or “group” of related persons (as such terms are used in Sections 13(d) and 14(d) of the Exchange Act), other than Parent or one or more Permitted Holders, is or becomes the Beneficial Owner, directly or indirectly, of more than 50% of the total voting power of the Voting Stock of the Company (or its successor by merger, consolidation or purchase of all or substantially all of its assets) (for the purposes of this clause (1), such person or group shall be deemed to Beneficially Own any Voting Stock of the Company held by a parent entity, if such person or group Beneficially Owns, directly or indirectly, more than 50% of the total voting power of the Voting Stock of such parent entity);

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(2) the first day on which a majority of the members of the Board of Directors of the Company are not Continuing Directors; or

(3) the sale, lease, transfer, conveyance or other disposition (other than by way of merger or consolidation), in one or a series of related transactions, of all or substantially all of the assets of the Company and its Restricted Subsidiaries taken as a whole to any “person” (as such term is used in Sections 13(d) and 14(d) of the Exchange Act) other than a Permitted Holder or a Person controlled by a Permitted Holder;

(4) the adoption by the stockholders of the Company of a plan or proposal for the liquidation or dissolution of the Company; or

(5) the first day on which Parent ceases to own 100% of the outstanding Capital Stock of the Company (after having acquired such Capital Stock).

“Code” means the Internal Revenue Code of 1986, as amended.

“Commodity Agreements” means, in respect of any Person, any forward contract, commodity swap agreement, commodity option agreement or other similar agreement or arrangement in respect of Hydrocarbons used, produced, processed or sold by such Person that are customary in the Oil and Gas Business and designed to protect such Person against fluctuation in Hydrocarbon prices.

“Common Stock” means with respect to any Person, any and all shares, interests or other participations in, and other equivalents (however designated and whether voting or nonvoting) of such Person’s common stock whether or not outstanding on the Issue Date, and includes, without limitation, all series and classes of such common stock.

“Consolidated Coverage Ratio” means as of any date of determination, the ratio of (x) the aggregate amount of Consolidated EBITDA of such Person for the period of the most recent four consecutive fiscal quarters ending prior to the date of such determination for which financial statements are in existence to (y) Consolidated Interest Expense for such four fiscal quarters, provided, however, that:

(1) if the Company or any Restricted Subsidiary:

(a) has Incurred any Indebtedness since the beginning of such period that remains outstanding on such date of determination or if the transaction giving rise to the need to calculate the Consolidated Coverage Ratio is an Incurrence of Indebtedness, Consolidated EBITDA and Consolidated Interest Expense for such period will be calculated after giving effect on a pro forma basis to such Indebtedness and the use of proceeds thereof as if such Indebtedness had been Incurred on the first day of such period and such proceeds had been applied as of such date (except that in making such computation, (x) the amount of Indebtedness under any revolving credit facility outstanding on the date of such calculation will be deemed to be (i) the average daily balance of such Indebtedness during such four fiscal quarters or such shorter period for which such facility was outstanding or (ii) if such facility was created after the end of such four fiscal quarters, the average daily balance of such Indebtedness during the period from the date of creation of such facility to the date of such calculation, in each case, provided that such average daily balance shall take into account any repayment of Indebtedness under such facility as provided in clause (b) and (y) Indebtedness Incurred or issued on the date of determination pursuant to the second paragraph of the covenant described under “—Certain Covenants—Limitation on Indebtedness and Preferred Stock” shall not be given pro forma effect); or

(b) has repaid, repurchased, defeased or otherwise discharged any Indebtedness since the beginning of the period, including with the proceeds of such new Indebtedness, that is no longer outstanding on such date of determination or if the transaction giving rise to the need to calculate the Consolidated Coverage Ratio involves a discharge of Indebtedness (in each case other than Indebtedness Incurred under any revolving credit facility unless such Indebtedness has been permanently repaid and the related commitment terminated), Consolidated EBITDA and Consolidated Interest Expense for such period will be calculated after giving effect on a pro forma basis to such discharge of such Indebtedness as if such discharge had occurred on the first day of such period;

(2) if, since the beginning of such period, the Company or any Restricted Subsidiary will have made any Asset Disposition or if the transaction giving rise to the need to calculate the Consolidated Coverage Ratio is such an Asset Disposition, the Consolidated EBITDA for such period will be reduced by an amount equal to the Consolidated EBITDA (if positive) directly attributable to the assets which are the subject of such Asset Disposition for such period or increased by an amount equal to the Consolidated EBITDA (if negative) directly attributable thereto for such period and Consolidated Interest Expense for such period shall be reduced by an amount equal to the Consolidated Interest Expense directly attributable to any Indebtedness of the Company or any Restricted Subsidiary repaid, repurchased, defeased or otherwise discharged with respect to the Company and its continuing Restricted Subsidiaries in connection with or with the proceeds from such Asset Disposition for such period (or, if the Capital Stock of any Restricted Subsidiary is sold, the Consolidated Interest Expense for such period directly attributable to the Indebtedness of such Restricted Subsidiary to the extent the Company and its continuing Restricted Subsidiaries are no longer liable for such Indebtedness after such sale);

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(3) if since the beginning of such period the Company or any Restricted Subsidiary (by merger or otherwise) will have made an Investment in any Restricted Subsidiary (or any Person which becomes a Restricted Subsidiary or is merged with or into the Company or a Restricted Subsidiary) or an acquisition (or will have received a contribution) of assets, including any acquisition or contribution of assets occurring in connection with a transaction causing a calculation to be made hereunder, which constitutes all or substantially all of a company, division, operating unit, segment, business, group of related assets or line of business, Consolidated EBITDA and Consolidated Interest Expense for such period will be calculated after giving pro forma effect thereto (including the Incurrence of any Indebtedness) as if such Investment or acquisition or contribution had occurred on the first day of such period; and

(4) if since the beginning of such period any Person (that subsequently became a Restricted Subsidiary or was merged with or into the Company or any Restricted Subsidiary since the beginning of such period) made any Asset Disposition or any Investment or acquisition of assets that would have required an adjustment pursuant to clause (2) or (3) above if made by the Company or a Restricted Subsidiary during such period, Consolidated EBITDA and Consolidated Interest Expense for such period will be calculated after giving pro forma effect thereto as if such Asset Disposition or Investment or acquisition of assets had occurred on the first day of such period.

For purposes of this definition, whenever pro forma effect is to be given to any calculation under this definition, the pro forma calculations will be determined in good faith by a responsible financial or accounting Officer of the Company (including pro forma expense and cost reductions calculated on a basis consistent with Regulation S-X under the Securities Act). If any Indebtedness bears a floating rate of interest and is being given pro forma effect, the interest expense on such Indebtedness will be calculated as if the average rate in effect from the beginning of such period to the date of determination had been the applicable rate for the entire period (taking into account any Interest Rate Agreement applicable to such Indebtedness, but if the remaining term of such Interest Rate Agreement is less than 12 months, then such Interest Rate Agreement shall only be taken into account for that portion of the period equal to the remaining term thereof). If any Indebtedness that is being given pro forma effect bears an interest rate at the option of the Company, the interest rate shall be calculated by applying such optional rate chosen by the Company. Interest on Indebtedness that may optionally be determined at an interest rate based upon a factor of a prime or similar rate, a eurocurrency interbank offered rate, or other rate, shall be deemed to have been based upon the rate actually chosen, or, if none, then based upon such optional rate chosen as the Company may designate.

“Consolidated EBITDA” for any period means, without duplication, the Consolidated Net Income for such period, plus the following, without duplication and to the extent deducted (and not added back) in calculating such Consolidated Net Income:

(1) Consolidated Interest Expense;

(2) Consolidated Income Taxes of the Company and its Restricted Subsidiaries;

(3) consolidated depletion and depreciation expense of the Company and its Restricted Subsidiaries;

(4) consolidated amortization expense or impairment charges of the Company and its Restricted Subsidiaries recorded in connection with the application of Statement of Financial Accounting Standard No. 142—ASC Topic 350 Intangibles—Goodwill and Other, and statement of Financial Accounting Standard No. 144—ASC Topic 360 Property, Plant & Equipment;

(5) other non-cash charges of the Company and its Restricted Subsidiaries (excluding any such non-cash charge to the extent it represents an accrual of or reserve for cash charges in any future period or amortization of a prepaid cash expense that was paid in a prior period not included in the calculation); and

(6) consolidated exploration expense of the Company and its Restricted Subsidiaries, if applicable for such period; and less, to the extent included in calculating such Consolidated Net Income and in excess of any costs or expenses attributable thereto that were deducted (and not added back) in calculating such Consolidated Net Income, the sum of (x) the amount of deferred revenues that are amortized during such period and are attributable to reserves that are subject to Volumetric Production Payments, (y) amounts recorded in accordance with GAAP as repayments of principal and interest pursuant to Dollar-Denominated Production Payments and (z) other non-cash gains (excluding any non-cash gain to the extent it represents the reversal of an accrual or reserve for a potential cash item that reduced Consolidated EBITDA in any prior period).

Notwithstanding the preceding sentence, clauses (2) through (6) relating to amounts of a Restricted Subsidiary of a Person will be added to Consolidated Net Income to compute Consolidated EBITDA of such Person only to the extent (and in the same proportion) that the net income (loss) of such Restricted Subsidiary was included in calculating the Consolidated Net Income of such Person and, to the extent the amounts set forth in clauses (2) through (6) are in excess of those necessary to offset a net loss of such Restricted Subsidiary or if such Restricted Subsidiary has net income for such period included in Consolidated Net Income, only if a

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corresponding amount would be permitted at the date of determination to be dividended to the Company by such Restricted Subsidiary without prior approval (that has not been obtained), pursuant to the terms of its charter and all agreements, instruments, judgments, decrees, orders, statutes, rules and governmental regulations applicable to that Restricted Subsidiary or its stockholders.

“Consolidated Income Taxes” means, with respect to any Person for any period, taxes imposed upon such Person or other payments required to be made by such Person by any governmental authority which taxes or other payments are calculated by reference to the income, profits or capital of such Person or such Person and its Restricted Subsidiaries (to the extent such income or profits were included in computing Consolidated Net Income for such period), regardless of whether such taxes or payments are required to be remitted to any governmental authority.

“Consolidated Interest Expense” means, for any period, the total consolidated interest expense of the Company and its Restricted Subsidiaries, whether paid or accrued, plus, to the extent not included in such interest expense and without duplication:

(1) interest expense attributable to Capitalized Lease Obligations and the interest component of any deferred payment obligations;

(2) amortization of debt discount and debt issuance cost (provided that any amortization of bond premium will be credited to reduce Consolidated Interest Expense unless, pursuant to GAAP, such amortization of bond premium has otherwise reduced Consolidated Interest Expense);

(3) non-cash interest expense;

(4) commissions, discounts and other fees and charges owed with respect to letters of credit and bankers’ acceptance financing;

(5) the interest expense on indebtedness of another Person that is Guaranteed by the Company or one of its Restricted Subsidiaries or secured by a Lien on assets of the Company or one of its Restricted Subsidiaries;

(6) costs associated with Interest Rate Agreements (including amortization of fees); provided, however, that if Interest Rate Agreements result in net benefits rather than costs, such benefits shall be credited to reduce Consolidated Interest Expense unless, pursuant to GAAP, such net benefits are otherwise reflected in Consolidated Net Income;

(7) the consolidated interest expense of such Person and its Restricted Subsidiaries that was capitalized during such period;

(8) all dividends paid or payable in cash, Cash Equivalents or indebtedness or accrued during such period on any series of Disqualified Stock of the Company or on Preferred Stock of its Restricted Subsidiaries payable to a party other than the Company or a Wholly Owned Subsidiary; and

(9) the cash contributions to any employee stock ownership plan or similar trust to the extent such contributions are used by such plan or trust to pay interest or fees to any Person (other than the Company) in connection with Indebtedness Incurred by such plan or trust;

minus, to the extent included above, write-off of deferred financing costs (and interest) attributable to Dollar-Denominated Production Payments.

For the purpose of calculating the Consolidated Coverage Ratio in connection with the Incurrence of any Indebtedness described in the final paragraph of the definition of “Indebtedness,” the calculation of Consolidated Interest Expense shall include all interest expense (including any amounts described in clauses (1) through (9) above) relating to any Indebtedness of the Company or any Restricted Subsidiary described in the final paragraph of the definition of “Indebtedness.”

“Consolidated Net Income” means, for any period, the aggregate net income (loss) (excluding non-controlling interests) of the Company and its consolidated Subsidiaries determined in accordance with GAAP and before any reduction in respect of preferred stock dividends of such Person; provided, however, that there will not be included in such Consolidated Net Income:

(1) any net income (loss) of any Person (other than the Company) if such Person is not a Restricted Subsidiary, except that:

(a) subject to the limitations contained in clauses (3), (4) and (5) below, the Company’s equity in the net income of any such Person for such period will be included in such Consolidated Net Income up to the aggregate amount of cash actually distributed by such Person during such period to the Company or a Restricted Subsidiary as a dividend or other distribution (subject, in the case of a dividend or other distribution to a Restricted Subsidiary, to the limitations contained in clause (2) below); and

(b) the Company’s equity in a net loss of any such Person for such period will be included in determining such Consolidated Net Income to the extent such loss has been funded with cash from the Company or a Restricted Subsidiary during such period;

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(2) any net income (but not loss) of any Restricted Subsidiary if such Subsidiary is subject to restrictions, directly or indirectly, on the payment of dividends or the making of distributions by such Restricted Subsidiary, directly or indirectly, to the Company, except that:

(a) subject to the limitations contained in clauses (3), (4) and (5) below, the Company’s equity in the net income of any such Restricted Subsidiary for such period will be included in such Consolidated Net Income up to the aggregate amount of cash that could have been distributed by such Restricted Subsidiary during such period to the Company or another Restricted Subsidiary as a dividend or other distribution (subject, in the case of a dividend or other distribution paid to another Restricted Subsidiary, to the limitation contained in this clause); and

(b) the Company’s equity in a net loss of any such Restricted Subsidiary for such period will be included in determining such Consolidated Net Income;

(3) any gain (loss) realized upon the sale or other disposition of any property, plant or equipment of the Company or its consolidated Subsidiaries (including pursuant to any Sale/ Leaseback Transaction) which is not sold or otherwise disposed of in the ordinary course of business and any gain (loss) realized upon the sale or other disposition of any Capital Stock of any Person;

(4) any extraordinary or nonrecurring gains or losses, together with any related provision for taxes on such gains or losses and all related fees and expenses;

(5) the cumulative effect of a change in accounting principles;

(6) any asset impairment writedowns on Oil and Gas Properties under GAAP or SEC guidelines;

(7) any unrealized non-cash gains or losses or charges in respect of Hedging Obligations (including those resulting from the application of SFAS 133– ASC Topic 815 Derivatives and Hedging);

(8) income or loss attributable to discontinued operations (including, without limitation, operations disposed of during such period whether or not such operations were classified as discontinued); and

(9) any non-cash compensation charge arising from any grant of stock, stock options or other equity-based awards (other than non-cash compensation charges associated with the Phantom Stock Plan), provided that the proceeds resulting from any such grant will be excluded from clause (c)(ii) of the first paragraph of the covenant described under “—Certain Covenants-Limitation on Restricted Payments.”

Consolidated Net Income will be reduced by the amount of Permitted Payments to Parent paid during such period to the extent that the related taxes have not reduced Consolidated Net Income by at least such amount.

“Continuing Directors” means, as of any date of determination, any member of the Board of Directors of the Company who: (1) was a member of such Board of Directors on the date of the Indenture; or (2) was nominated for election or elected to such Board of Directors with the approval of a majority of the Continuing Directors who were members of such Board of Directors at the time of such nomination or election.

“Credit Facility” means, with respect to the Company or any Subsidiary Guarantor, one or more debt facilities (including, without limitation, the Senior Secured Credit Agreement, indentures or commercial paper facilities providing for revolving credit loans, term loans, receivables financing (including through the sale of receivables to such lenders or to special purpose entities formed to borrow from such lenders against such receivables) or letters of credit, in each case, as amended, restated, modified, renewed, refunded, replaced or refinanced in whole or in part from time to time (and whether or not with the original administrative agent and lenders or another administrative agent or agents or other lenders and whether provided under the original Senior Secured Credit Agreement, or any other credit or other agreement or indenture).

“Currency Agreement” means in respect of a Person any foreign exchange contract, currency swap agreement, futures contract, option contract or other similar agreement as to which such Person is a party or a beneficiary.

“Default” means any event which is, or after notice or passage of time or both would be, an Event of Default.

“Disqualified Stock” means, with respect to any Person, any Capital Stock of such Person which by its terms (or by the terms of any security into which it is convertible or for which it is exchangeable) at the option of the holder of the Capital Stock) or upon the happening of any event:

(1) matures or is mandatorily redeemable (other than redeemable only for Capital Stock of such Person which is not itself Disqualified Stock) pursuant to a sinking fund obligation or otherwise;

(2) is convertible or exchangeable for Indebtedness or Disqualified Stock (excluding Capital Stock which is convertible or exchangeable solely at the option of the Company or a Restricted Subsidiary); or

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(3) is redeemable at the option of the holder of the Capital Stock in whole or in part,

in each case on or prior to the date that is 91 days after the earlier of the date (a) of the Stated Maturity of the Notes or (b) on which there are no Notes outstanding; provided that only the portion of Capital Stock which so matures or is mandatorily redeemable, is so convertible or exchangeable or is so redeemable at the option of the holder thereof prior to such date will be deemed to be Disqualified Stock; provided, further, that any Capital Stock that would constitute Disqualified Stock solely because the holders thereof have the right to require the Company to repurchase such Capital Stock upon the occurrence of a change of control or asset sale (each defined in a substantially identical manner to the corresponding definitions in the Indenture) shall not constitute Disqualified Stock if the terms of such Capital Stock (and all such securities into which it is convertible or for which it is ratable or exchangeable) provide that (i) the Company may not repurchase or redeem any such Capital Stock (and all such securities into which it is convertible or for which it is ratable or exchangeable) pursuant to such provision prior to compliance by the Company with the provisions of the Indenture described under the captions “—Change of Control” and “—Certain Covenants—Limitation on Sales of Assets and Subsidiary Stock” and (ii) such repurchase or redemption will be permitted solely to the extent also permitted in accordance with the provisions of the Indenture described under the caption “—Certain Covenants—Limitation on Restricted Payments.”

The amount of any Disqualified Stock that does not have a fixed redemption, repayment or repurchase price will be calculated in accordance with the terms of such Disqualified Stock as if such Disqualified Stock were redeemed, repaid or repurchased on any date on which the amount of such Disqualified Stock is to be determined pursuant to the Indenture; provided, however, that if such Disqualified Stock could not be required to be redeemed, repaid or repurchased at the time of such determination, the redemption, repayment or repurchase price will be the book value of such Disqualified Stock as reflected in the most recent financial statements of such Person.

“Dollar-Denominated Production Payments” means production payment obligations recorded as liabilities in accordance with GAAP, together with all undertakings and obligations in connection therewith.

“Equity Offering” means (i) a public offering for cash by the Company of Capital Stock (other than Disqualified Stock) made pursuant to a registration statement, other than public offerings registered on Form S-4 or S-8 and (ii) a private offering for cash by the Company of its Capital Stock (other than Disqualified Stock) (except that, prior to the first underwritten public offering of the Company’s Common Stock, such private offering may only be made to non-Affiliates); provided, however, that any offering described in clause (1) or (2) occurring on or prior to June 1, 2013 shall be deemed not to be an “Equity Offering” if (x) a Change of Control has occurred or (y) such offering is made in connection with, or in contemplation of, a Change of Control.

“Exchange Act” means the Securities Exchange Act of 1934, as amended, and the rules and regulations of the SEC promulgated thereunder.

“Existing Senior Notes” means the Company’s $300.0 million 9.875% Senior Notes due 2020 and $400.0 million 8.250% Senior Notes due 2021.

“Existing Senior Notes Indentures” means, collectively, the indentures governing the Existing Senior Notes, among the Company and certain of its subsidiaries party thereto and the trustees named therein from time to time, as amended, restated, supplemented or otherwise modified from time to time in accordance with the requirements thereof.

“Fair Market Value” means, with respect to any asset or property, the sale value that would be obtained in an arm’s-length transaction between an informed and willing seller under no compulsion to sell and an informed and willing buyer under no compulsion to buy.

“Foreign Subsidiary” means any Restricted Subsidiary that is not organized under the laws of the United States of America or any state thereof or the District of Columbia.

“GAAP” means generally accepted accounting principles in the United States of America as in effect from time to time. All ratios and computations based on GAAP contained in the Indenture will be computed in conformity with GAAP. At any time after the Issue Date, the Company may elect to apply IFRS accounting principles in lieu of GAAP and, upon any such election, references herein to GAAP shall thereafter be construed to mean IFRS (except as otherwise provided in the Indenture); provided that any such election, once made, shall be irrevocable, unless otherwise required by the SEC; provided, further, any calculation or determination in the Indenture that requires the application of GAAP for periods that include fiscal quarters ended prior to the Company’s election to apply IFRS shall remain as previously calculated or determined in accordance with GAAP. The Company shall give notice of any such election made in accordance with this definition to the Trustee and the holders of the Notes.

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“Guarantee” means any obligation, contingent or otherwise, of any Person directly or indirectly guaranteeing any indebtedness of any other Person and any obligation, direct or indirect, contingent or otherwise, of such Person:

(1) to purchase or pay (or advance or supply funds for the purchase or payment of) such Indebtedness of such other Person (whether arising by virtue of partnership arrangements, or by agreement to keep-well, to purchase assets, goods, securities or services, to take-or-pay, or to maintain financial statement conditions or otherwise); or

(2) entered into for purposes of assuring in any other manner the obligee of such Indebtedness of the payment thereof or to protect such obligee against loss in respect thereof (in whole or in part);

provided, however, that the term “Guarantee” will not include endorsements for collection or deposit in the ordinary course of business or any obligation to the extent it is payable only in Capital Stock of the Guarantor that is not Disqualified Stock. The term “Guarantee” used as a verb has a corresponding meaning.

“Guarantor Subordinated Obligation” means, with respect to a Subsidiary Guarantor, any Indebtedness of such Subsidiary Guarantor (whether outstanding on the Issue Date or thereafter Incurred) which is expressly subordinate in right of payment to the obligations of such Subsidiary Guarantor under its Subsidiary Guarantee pursuant to a written agreement.

“Hedging Obligations” of any Person means the obligations of such Person pursuant to any Interest Rate Agreement, Currency Agreement or Commodity Agreement.

“Hydrocarbons” means oil, natural gas, casing head gas, drip gasoline, natural gasoline, condensate, distillate, liquid hydrocarbons, gaseous hydrocarbons and all constituents, elements or compounds thereof and products refined or processed therefrom.

“IFRS” means the International Financial Reporting Standards as adopted by the International Accounting Standards Board.

“Immaterial Subsidiary” means, as of any date, any Restricted Subsidiary whose total assets, as of that date, are less than $1,000,000 and whose total revenues for the most recent 12-month period do not exceed $1,000,000; provided that a Restricted Subsidiary will not be considered to be an Immaterial Subsidiary if it, directly or indirectly, Guarantees or otherwise provides direct credit support for any Indebtedness of the Company.

“Incur” means issue, create, assume, Guarantee, incur or otherwise become directly or indirectly liable for, contingently or otherwise; provided, however, that any Indebtedness or Capital Stock of a Person existing at the time such Person becomes a Restricted Subsidiary (whether by merger, consolidation, acquisition or otherwise) will be deemed to be Incurred by such Restricted Subsidiary at the time it becomes a Restricted Subsidiary; and the terms “Incurred” and “Incurrence” have meanings correlative to the foregoing.

“Indebtedness” means, with respect to any Person on any date of determination (without duplication, whether or not contingent):

(1) the principal of and premium (if any) in respect of indebtedness of such Person for borrowed money;

(2) the principal of and premium (if any) in respect of obligations of such Person evidenced by bonds, debentures, notes or other similar instruments;

(3) the principal component of all obligations of such Person in respect of letters of credit, bankers’ acceptances or other similar instruments (including reimbursement obligations with respect thereto except to the extent such reimbursement obligation relates to a trade payable, to the extent such letters of credit are not drawn upon or, if and to the extent drawn upon, such obligation is satisfied within 30 days of payment on the letter of credit);

(4) the principal component of all obligations of such Person (other than obligations payable solely in Capital Stock that is not Disqualified Stock) to pay the deferred and unpaid purchase price of property (except accrued expenses and trade payables and other accrued liabilities arising in the ordinary course of business that are not overdue by 90 days or more or are being contested in good faith by appropriate proceedings promptly instituted and diligently conducted), which purchase price is due more than six months after the date of placing such property in service or taking delivery and title thereto to the extent such obligations would appear as liabilities upon the consolidated balance sheet of such Person in accordance with GAAP;

(5) Capitalized Lease Obligations of such Person to the extent such Capitalized Lease Obligations would appear as liabilities on the consolidated balance sheet of such Person in accordance with GAAP;

(6) the principal component or liquidation preference of all obligations of such Person with respect to the redemption, repayment or other repurchase of any Disqualified Stock or, with respect to any Subsidiary that is not a Subsidiary Guarantor, any Preferred Stock (but excluding, in each case, any accrued dividends);

(7) the principal component of all Indebtedness of other Persons secured by a Lien on any asset of such Person, whether or not such Indebtedness is assumed by such Person; provided, however, that the amount of such Indebtedness will be the lesser of (a) the Fair Market Value of such asset at such date of determination (as determined in the good faith by the Board of Directors) and (b) the amount of such Indebtedness of such other Persons;

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(8) the principal component of Indebtedness of other Persons to the extent Guaranteed by such Person; and

(9) to the extent not otherwise included in this definition, net obligations of such Person under Commodity Agreements, Currency Agreements and Interest Rate Agreements (the amount of any such obligations to be equal at any time to the termination value of such agreement or arrangement giving rise to such obligation that would be payable by such Person at such time);

provided, however, that any indebtedness which has been defeased in accordance with GAAP or defeased pursuant to the deposit of cash or Cash Equivalents (in an amount sufficient to satisfy all such indebtedness obligations at maturity or redemption, as applicable, and all payments of interest and premium, if any) in a trust or account created or pledged for the sole benefit of the holders of such indebtedness, and subject to no other Liens, shall not constitute “Indebtedness.”

The amount of indebtedness of any Person at any date will be the outstanding balance at such date of all unconditional obligations as described above and the maximum liability, upon the occurrence of the contingency giving rise to the obligation, of any contingent obligations at such date.

Notwithstanding the preceding, “Indebtedness” shall not include:

(1) Production Payments and Reserve Sales;

(2) any obligation of a Person in respect of a farm-in agreement or similar arrangement whereby such Person agrees to pay all or a share of the drilling, completion or other expenses of an exploratory or development well (which agreement may be subject to a maximum payment obligation, after which expenses are shared in accordance with the working or participation interest therein or in accordance with the agreement of the parties) or perform the drilling, completion or other operation on such well in exchange for an ownership interest in an oil or gas property;

(3) any obligations under Currency Agreements, Commodity Agreements and Interest Rate Agreements; provided, that such Agreements are entered into for bona fide hedging purposes of the Company or its Restricted Subsidiaries (as determined in good faith by the Board of Directors or senior management of the Company, whether or not accounted for as a hedge in accordance with GAAP) and, in the case of Currency Agreements or Commodity Agreements, such Currency Agreements or Commodity Agreements are related to business transactions of the Company or its Restricted Subsidiaries entered into in the ordinary course of business and, in the case of Interest Rate Agreements, such Interest Rate Agreements substantially correspond in terms of notional amount, duration and interest rates, as applicable, to Indebtedness of the Company or its Restricted Subsidiaries Incurred without violation of the Indenture;

(4) any obligation arising from agreements of the Company or a Restricted Subsidiary providing for indemnification, Guarantees, adjustment of purchase price, holdbacks, contingency payment obligations or similar obligations (other than Guarantees of Indebtedness), in each case, Incurred or assumed in connection with the acquisition or disposition of any business, assets or Capital Stock of a Restricted Subsidiary, provided that such Indebtedness is not reflected on the face of the balance sheet of the Company or any Restricted Subsidiary;

(5) any obligation arising from the honoring by a bank or other financial institution of a check, draft or similar instrument (except in the case of daylight overdrafts) drawn against insufficient funds in the ordinary course of business, provided, however, that such Indebtedness is extinguished within five business days of Incurrence;

(6) in-kind obligations relating to net oil or natural gas balancing positions arising in the ordinary course of business; and

(7) all contracts and other obligations, agreements, instruments or arrangements described in clauses (20), (21), (22), (29)(a) or (30) of the definition of “Permitted Liens.”

In addition, “Indebtedness” of any Person shall include Indebtedness described in the first paragraph of this definition of “Indebtedness” that would not appear as a liability on the balance sheet of such Person if:

(1) such Indebtedness is the obligation of a partnership or joint venture that is not a Restricted Subsidiary (a “Joint Venture”);

(2) such Person or a Restricted Subsidiary of such Person is a general partner of the Joint Venture or otherwise liable for all or a portion of the Joint Venture’s liabilities (a “General Partner”); and

(3) there is recourse, by contract or operation of law, with respect to the payment of such Indebtedness to property or assets of such Person or a Restricted Subsidiary of such Person; and then such Indebtedness shall be included in an amount not to exceed:

(a) the lesser of (i) the net assets of the General Partner and (ii) the amount of such obligations to the extent that there is recourse, by contract or operation of law, to the property or assets of such Person or a Restricted Subsidiary of such Person; or

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(b) if less than the amount determined pursuant to clause (a) immediately above, the actual amount of such Indebtedness that is recourse to such Person or a Restricted Subsidiary of such Person, if the Indebtedness is evidenced by a writing and is for a determinable amount.

“Interest Rate Agreement” means with respect to any Person any interest rate protection agreement, interest rate future agreement, interest rate option agreement, interest rate swap agreement, interest rate cap agreement, interest rate collar agreement, interest rate hedge agreement or other similar agreement or arrangement as to which such Person is party or a beneficiary.

“Investment” means, with respect to any Person, all investments by such Person in other Persons (including Affiliates) in the form of any direct or indirect advance, loan or other extensions of credit (including by way of Guarantee or similar arrangement, but excluding any debt or extension of credit represented by a bank deposit other than a time deposit and advances or extensions of credit to customers in the ordinary course of business) or capital contribution to (by means of any transfer of cash or other property to others or any payment for property or services for the account or use of others), or any purchase or acquisition of Capital Stock, Indebtedness or other similar instruments (excluding any interest in a crude oil or natural gas leasehold to the extent constituting a security under applicable law) issued by, such other Person and all other items that are or would be classified as investments on a balance sheet prepared in accordance with GAAP; provided that none of the following will be deemed to be an Investment:

(1) Hedging Obligations entered into in the ordinary course of business and in compliance with the Indenture;

(2) endorsements of negotiable instruments and documents in the ordinary course of business; and

(3) an acquisition of assets, Capital Stock or other securities by the Company or a Subsidiary for consideration to the extent such consideration consists of Common Stock of the Company.

The amount of any Investment shall not be adjusted for increases or decreases in value, write-ups, write-downs or write-offs with respect to such Investment.

For purposes of the definition of “Unrestricted Subsidiary” and the covenant described under “Certain Covenants—Limitation on Restricted Payments,”

(1) “Investment” will include the portion (proportionate to the Company’s equity interest in a Restricted Subsidiary to be designated as an Unrestricted Subsidiary) of the Fair Market Value of the net assets of such Restricted Subsidiary at the time that such Restricted Subsidiary is designated an Unrestricted Subsidiary; provided, however, that upon a redesignation of such Subsidiary as a Restricted Subsidiary, the Company will be deemed to continue to have a permanent “Investment” in an Unrestricted Subsidiary in an amount (if positive) equal to (a) the Company’s “Investment” in such Subsidiary at the time of such redesignation less (b) the portion (proportionate to the Company’s equity interest in such Subsidiary) of the Fair Market Value of the net assets of such Subsidiary (as conclusively determined by the Board of Directors of the Company in good faith) at the time that such Subsidiary is so redesignated a Restricted Subsidiary; and

(2) any property transferred to or from an Unrestricted Subsidiary will be valued at its Fair Market Value at the time of such transfer, in each case as determined in good faith by the Board of Directors of the Company.

“Investment Grade Rating” means a rating equal to or higher than Baa3 (or the equivalent) by Moody’s Investors Service, Inc. and BBB- (or the equivalent) by Standard & Poor’s Ratings Services (or the equivalent rating by any successor rating agency).

“Investment Grade Status” shall occur when the Notes receive an Investment Grade Rating from both Moody’s Investors Service, Inc. and Standard & Poor’s Ratings Services (or, if any such entity ceases to rate the Notes for reasons outside of the control of the Company, the equivalent investment grade credit rating from any other “nationally recognized statistical rating organization” within the meaning of Section 3(a)(62) of the Exchange Act selected by the Company as a replacement agency).

“Issue Date” means the first date on which the Notes were issued under the Indenture, which was May 2, 2012.

“Lien” means, with respect to any asset, any mortgage, lien (statutory or otherwise), pledge, hypothecation, charge, security interest, preference, priority or encumbrance of any kind in respect of such asset, whether or not filed, recorded or otherwise perfected under applicable law, including any conditional sale or other title retention agreement, any lease in the nature thereof, any option or other agreement to sell or give a security interest in and any filing of or agreement to give any financing statement under the Uniform Commercial Code (or equivalent statutes) of any jurisdiction; provided that in no event shall an operating lease be deemed to constitute a Lien.

“Minority Interest” means the percentage interest represented by any shares of any class of Capital Stock of a Restricted Subsidiary that are not owned by the Company or a Restricted Subsidiary.

“Net Available Cash” from an Asset Disposition means cash payments received (including any cash payments received by way of deferred payment of principal pursuant to a note or installment receivable or otherwise and net proceeds from the sale or other disposition of any securities received as consideration, but only as and when received, but excluding any other consideration received in the form of assumption by the acquiring Person of Indebtedness or other obligations relating to the properties or assets that are the subject of such Asset Disposition or received in any other non-cash form) therefrom, in each case net of:

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(1) all legal, accounting, investment banking, title and recording tax expenses, commissions and other fees and expenses Incurred, and all federal, state, provincial, foreign and local taxes required to be paid or accrued as a liability under GAAP (after taking into account any available tax credits or deductions and any tax sharing agreements), as a consequence of such Asset Disposition;

(2) all payments made on any Indebtedness which is secured by any assets subject to such Asset Disposition, in accordance with the terms of any Lien upon such assets, or which must by its terms, or in order to obtain a necessary consent to such Asset Disposition, or by applicable law be repaid out of the proceeds from such Asset Disposition;

(3) all distributions and other payments required to be made to minority interest holders in Subsidiaries or joint ventures or to holders of royalty or similar interests as a result of such Asset Disposition; and

(4) the deduction of appropriate amounts to be provided by the seller as a reserve, in accordance with GAAP, against any liabilities associated with the assets disposed of in such Asset Disposition and retained by the Company or any Restricted Subsidiary after such Asset Disposition.

“Net Cash Proceeds,” with respect to any issuance or sale of Capital Stock or any contribution to equity capital, means the cash proceeds of such issuance, sale or contribution net of attorneys’ fees, accountants’ fees, underwriters’ or placement agents’ fees, listing fees, discounts or commissions and brokerage, consultant and other fees and charges actually Incurred in connection with such issuance, sale or contribution and net of taxes paid or payable as a result of such issuance or sale (after taking into account any available tax credit or deductions and any tax sharing arrangements).

“Net Working Capital” means (a) all current assets of the Company and its Restricted Subsidiaries except current assets from commodity price risk management activities arising in the ordinary course of the Oil and Gas Business, less (b) all current liabilities of the Company and its Restricted Subsidiaries, except current liabilities included in Indebtedness and any current liabilities from commodity price risk management activities arising in the ordinary course of the Oil and Gas Business, in each case as set forth in the consolidated financial statements of the Company prepared in accordance with GAAP.

“Non-Recourse Debt” means Indebtedness of a Person:

(1) as to which neither the Company nor any Restricted Subsidiary (a) provides any Guarantee or credit support of any kind (including any undertaking, guarantee, indemnity, agreement or instrument that would constitute indebtedness) or (b) is directly or indirectly liable (as a guarantor or otherwise);

(2) no default with respect to which (including any rights that the holders thereof may have to take enforcement action against an Unrestricted Subsidiary) would permit (upon notice, lapse of time or both) any holder of any other Indebtedness of the Company or any Restricted Subsidiary to declare a default under such other indebtedness or cause the payment thereof to be accelerated or payable prior to its stated maturity; and

(3) the explicit terms of which provide there is no recourse against any of the assets of the Company or its Restricted Subsidiaries.

“Officer” means the Chairman of the Board, the Chief Executive Officer, the President, the Chief Financial Officer, Chief Operating Officer, any Vice President, the Treasurer or the Secretary of the Company. Officer of any Subsidiary Guarantor has a correlative meaning.

“Officers’ Certificate” means a certificate signed by two Officers of the Company.

“Oil and Gas Business” means: (1) the business of acquiring, exploring, exploiting, developing, producing, operating and disposing of interests in oil, natural gas, liquid natural gas and other hydrocarbon and mineral properties or products produced in association with any of the foregoing; (2) the business of gathering, marketing, distributing, treating, processing, storing, refining, selling and transporting of any production from such interests or properties and products produced in association therewith and the marketing of oil, natural gas, other hydrocarbons and minerals obtained from unrelated Persons; (3) any other related energy business, including power generation and electrical transmission business, directly or indirectly, from oil, natural gas and other hydrocarbons and minerals produced substantially from properties in which the Company or its Restricted Subsidiaries, directly or indirectly, participates; (4) any business relating to oil field sales and service; and (5) any business or activity relating to, arising from, or necessary, appropriate or incidental to the activities described in the foregoing clauses (1) through (4) of this definition (including, without limitation, the acquisition, development and operation of CO2 producing properties, the acquisition or construction and operation of CO2 pipelines and transportation or sales of CO2, and the ownership and operation of ethanol plants, a by-product of which is the production of CO2, as related to the activities described in the foregoing clauses (1) through (2)).

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“Opinion of Counsel” means a written opinion from legal counsel who is acceptable to the Trustee. The counsel may be an employee of or counsel to the Company or the Trustee.

“Parent” means any entity that acquires 100% of the outstanding Capital Stock of the Company in a transaction in which the Beneficial Owners of the Company immediately prior to such transaction are Beneficial Owners in the same proportion of the Company immediately after such transaction.

“Pari Passu Indebtedness” means Indebtedness that ranks equally in right of payment to the Notes, including the Existing Senior Notes.

“Permitted Business Investment” means any Investment made in the ordinary course of, and of a nature that is or shall have become customary in, the Oil and Gas Business including investments or expenditures for actively exploiting, exploring for, acquiring, developing, producing, processing, gathering, marketing or transporting oil, natural gas or other hydrocarbons and minerals through agreements, transactions, interests or arrangements which permit one to share risks or costs, comply with regulatory requirements regarding local ownership or satisfy other objectives customarily achieved through the conduct of the Oil and Gas Business jointly with third parties, including:

(1) ownership interests in oil, natural gas, other hydrocarbons and minerals properties, liquid natural gas facilities, processing facilities, gathering systems, pipelines, storage facilities or related systems or ancillary real property interests;

(2) Investments in the form of or pursuant to operating agreements, working interests, royalty interests, mineral leases, processing agreements, farm-in agreements, farm-out agreements, contracts for the sale, transportation or exchange of oil, natural gas, other hydrocarbons and minerals, production sharing agreements, participation agreements, development agreements, area of mutual interest agreements, unitization agreements, pooling agreements, joint bidding agreements, service contracts, joint venture agreements, partnership agreements (whether general or limited), subscription agreements, stock purchase agreements, stockholder agreements and other similar agreements (including for limited liability companies) with third parties (including Unrestricted Subsidiaries); and

(3) direct or indirect ownership interests in drilling rigs and related equipment, including, without limitation, transportation equipment.

“Permitted Holders” means:

(1) Mark A. Fischer, Charles A. Fischer, Jr., Fischer Investments, L.L.C., Mark A. Fischer 1994 Trust and Susan L. Fischer 1994 Trust;

(2) any immediate family member (in the case of an individual) of any Person referred to in clause (1);

(3) CCMP Capital Investors II (AV-2), L.P., CCMP Energy I LTD. and CCMP Capital Investors (Cayman) II, L.P. and their Affiliates that are not operating portfolio companies; or

(4) any trust, corporation, partnership or other entity, the beneficiaries, stockholders, partners, owners or Persons Beneficially Owning a 50% or more controlling interest of which consist of any one or more Persons referred to in clauses (1), (2), or (3).

“Permitted Investment” means an Investment by the Company or any Restricted Subsidiary in:

(1) the Company, a Restricted Subsidiary or a Person which will, upon the making of such Investment, become a Restricted Subsidiary; provided, however, that the primary business of such Restricted Subsidiary is the Oil and Gas Business;

(2) another Person whose primary business is the Oil and Gas Business if as a result of such Investment such other Person becomes a Restricted Subsidiary or is merged or consolidated with or into, or transfers or conveys all or substantially all its assets to, the Company or a Restricted Subsidiary and, in each case, any Investment held by such Person; provided, that such Investment was not acquired by such Person in contemplation of such acquisition, merger, consolidation or transfer;

(3) cash and Cash Equivalents;

(4) receivables owing to the Company or any Restricted Subsidiary created or acquired in the ordinary course of business and payable or dischargeable in accordance with customary trade terms; provided, however, that such trade terms may include such concessionary trade terms as the Company or any such Restricted Subsidiary deems reasonable under the circumstances;

(5) payroll, commission, travel, relocation and similar advances to cover matters that are expected at the time of such advances ultimately to be treated as expenses for accounting purposes and that are made in the ordinary course of business;

(6) loans or advances to employees made in the ordinary course of business consistent with past practices of the Company or such Restricted Subsidiary;

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(7) Capital Stock, obligations or securities received in settlement of debts created in the ordinary course of business and owing to the Company or any Restricted Subsidiary or in satisfaction of judgments;

(8) Investments made as a result of the receipt of non-cash consideration from an Asset Disposition that was made pursuant to and in compliance with the covenant described under “—Certain Covenants—Limitation on Sales of Assets and Subsidiary Stock”;

(9) Investments in existence on the Issue Date;

(10) Commodity Agreements, Currency Agreements, Interest Rate Agreements and related Hedging Obligations, which transactions or obligations are Incurred in compliance with “—Certain Covenants—Limitation on Indebtedness and Preferred Stock”;

(11) Guarantees issued in accordance with the covenant described under “—Certain Covenants—Limitation on Indebtedness and Preferred Stock”;

(12) any Asset Swap or acquisition of Additional Assets made in accordance with the covenant described under “—Certain Covenants—Limitation on Sales of Assets and Subsidiary Stock”;

(13) Investments in Oklahoma Ethanol L.L.C. or any other Unrestricted Subsidiary the primary business of which is the acquisition, development and operation of CO2 producing properties, the acquisition or construction and operation of CO2 pipelines and transportation or sales of CO2 and the ownership and operation of ethanol plants, a by-product of which is the production of CO2, having an aggregate Fair Market Value, taken together with all other Investments made pursuant to this clause (13) that are at the time outstanding, not to exceed $35.0 million (with the Fair Market Value of such Investment being measured at the time such Investment is made and without giving effect to subsequent changes in value);

(14) Permitted Business Investments;

(15) any Person where such Investment was acquired by the Company or any of its Restricted Subsidiaries (a) in exchange for any other Investment or accounts receivable held by the Company or any such Restricted Subsidiary in connection with or as a result of a bankruptcy, workout, reorganization or recapitalization of the issuer of such other Investment or accounts receivable or (b) as a result of a foreclosure by the Company or any of its Restricted Subsidiaries with respect to any secured Investment or other transfer of title with respect to any secured Investment in default;

(16) any Person to the extent such Investments consist of prepaid expenses, negotiable instruments held for collection and lease, utility and workers’ compensation, performance and other similar deposits made in the ordinary course of business by the Company or any Restricted Subsidiary;

(17) Guarantees of performance or other obligations (other than indebtedness) arising in the ordinary course in the Oil and Gas Business, including obligations under oil and natural gas exploration, development, joint operating, and related agreements and licenses or concessions related to the Oil and Gas Business;

(18) acquisitions of assets, Equity Interests or other securities by the Company for consideration consisting of common equity securities of the Company;

(19) Investments in the Existing Senior Notes and the Notes; and

(20) Investments by the Company or any of its Restricted Subsidiaries, together with all other Investments pursuant to this clause (20), in an aggregate amount at the time of such Investment not to exceed $30.0 million outstanding at any one time (with the Fair Market Value of such Investment being measured at the time such Investment is made and without giving effect to subsequent changes in value).

“Permitted Liens” means, with respect to any Person:

(1) Liens securing Indebtedness and other obligations under, and related Hedging Obligations and Liens on assets of Restricted Subsidiaries securing Guarantees of Indebtedness and other obligations of the Company under, any Credit Facility permitted to be Incurred under the Indenture under the provisions described in clause (1) of the second paragraph under “—Certain Covenants—Limitation on Indebtedness and Preferred Stock”;

(2) pledges or deposits by such Person under workmen’s compensation laws, unemployment insurance laws, social security or old age pension laws or similar legislation, or good faith deposits in connection with bids, tenders, contracts (other than for the payment of Indebtedness) or leases to which such Person is a party, or deposits (which may be secured by a Lien) to secure public or statutory obligations of such Person including letters of credit and bank guarantees required or requested by the United States, any State thereof or any foreign government or any subdivision, department, agency, organization or instrumentality of any of the foregoing in connection with any contract or statute (including lessee or operator obligations under statutes, governmental regulations, contracts or instruments related to the ownership, exploration and production of oil, natural gas, other hydrocarbons and minerals on State, Federal or foreign lands or waters), or deposits of cash or United States government bonds to secure indemnity performance, surety or appeal bonds or other similar bonds to which such Person is a party, or deposits as security for contested taxes or import or customs duties or for the payment of rent, in each case Incurred in the ordinary course of business;

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(3) statutory and contractual Liens of landlords and Liens imposed by law, including carriers’, warehousemen’s, mechanics’ materialmen’s and repairmen’s Liens, in each case for sums not yet due or being contested in good faith by appropriate proceedings if a reserve or other appropriate provisions, if any, as shall be required by GAAP shall have been made in respect thereof;

(4) Liens for taxes, assessments or other governmental charges or claims not yet subject to penalties for non-payment or which are being contested in good faith by appropriate proceedings; provided that appropriate reserves, if any, required pursuant to GAAP have been made in respect thereof;

(5) Liens in favor of issuers of surety or performance bonds or letters of credit or bankers’ acceptances issued pursuant to the request of and for the account of such Person in the ordinary course of its business; provided, however, that such letters of credit do not constitute Indebtedness;

(6) survey exceptions, encumbrances, ground leases, easements or reservations of, or rights of others for, licenses, rights of way, sewers, electric lines, telegraph and telephone lines and other similar purposes, or zoning, building codes or other restrictions (including, without limitation, minor defects or irregularities in title and similar encumbrances) as to the use of real properties or Liens incidental to the conduct of the business of such Person or to the ownership of its properties which do not in the aggregate materially adversely affect the value of the assets of such Person and its Restricted Subsidiaries, taken as a whole, or materially impair their use in the operation of the business of such Person;

(7) Liens securing Hedging Obligations (excluding Hedging Obligations entered into for speculative purposes) so long as the related indebtedness is, and is permitted to be under the Indenture, secured by a Lien on the same property securing such Hedging Obligation;

(8) leases, licenses, subleases and sublicenses of assets (including, without limitation, real property and intellectual property rights) which do not materially interfere with the ordinary conduct of the business of the Company or any of its Restricted Subsidiaries;

(9) prejudgment Liens and judgment Liens not giving rise to an Event of Default so long as such Lien is adequately bonded and any appropriate legal proceedings which may have been duly initiated for the review of such judgment have not been finally terminated or the period within which such proceedings may be initiated has not expired;

(10) Liens for the purpose of securing the payment of all or a part of the purchase price of, or Capitalized Lease Obligations, purchase money obligations or other payments Incurred to finance the acquisition, lease, improvement or construction of or repairs or additions to, assets or property acquired or constructed in the ordinary course of business; provided that

(a) the aggregate principal amount of Indebtedness secured by such Liens is otherwise permitted to be Incurred under the Indenture; and

(b) such Liens are created within 180 days of the later of the acquisition, lease, completion of improvements, construction, repairs or additions or commencement of full operation of the assets or property subject to such Lien and do not encumber any other assets or property of the Company or any Restricted Subsidiary other than such assets or property and assets affixed or appurtenant thereto;

(11) Liens arising solely by virtue of any statutory or common law provisions relating to banker’s Liens, rights of set-off or similar rights and remedies as to deposit accounts or other funds maintained with a depositary institution; provided that:

(a) such deposit account is not a dedicated cash collateral account and is not subject to restrictions against access by the Company in excess of those set forth by regulations promulgated by the Federal Reserve Board; and

(b) such deposit account is not intended by the Company or any Restricted Subsidiary to provide collateral to the depository institution;

(12) Liens arising from Uniform Commercial Code financing statement filings regarding operating leases entered into by the Company and its Restricted Subsidiaries in the ordinary course of business;

(13) Liens existing on the Issue Date;

(14) Liens on property or shares of Capital Stock of a Person at the time such Person becomes a Subsidiary; provided, however, that such Liens are not created, Incurred or assumed in connection with, or in contemplation of, such other Person becoming a Subsidiary; provided further, however, that any such Lien may not extend to any other property owned by the Company or any Restricted Subsidiary (other than assets or property affixed or appurtenant thereto);

(15) Liens on property at the time the Company or any of its Subsidiaries acquired the property, including any acquisition by means of a merger or consolidation with or into the Company or any of its Subsidiaries; provided, however, that such Liens are not created, incurred or assumed in connection with, or in contemplation of, such acquisition; provided further, however, that such Liens may not extend to any other property owned by the Company or any Restricted Subsidiary (other than assets or property affixed or appurtenant thereto);

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(16) Liens securing Indebtedness or other obligations of a Subsidiary owing to the Company or a Wholly Owned Subsidiary;

(17) Liens securing the Notes, Subsidiary Guarantees and other obligations under the Indenture;

(18) Liens securing Refinancing Indebtedness Incurred to refinance Indebtedness that was previously so secured, provided that any such Lien is limited to all or part of the same property or assets (plus improvements, accessions, proceeds or dividends or distributions in respect thereof) that secured (or, under the written arrangements under which the original Lien arose, could secure) the Indebtedness being refinanced or is in respect of property or assets that is the security for a Permitted Lien hereunder;

(19) any interest or title of a lessor under any Capitalized Lease Obligation or operating lease;

(20) Liens in respect of Production Payments and Reserve Sales, which Liens shall be limited to the property that is the subject of such Production Payments and Reserve Sales;

(21) Liens arising under farm-out agreements, farm-in agreements, division orders, contracts for the sale, purchase, exchange, transportation, gathering or processing of Hydrocarbons, unitizations and pooling designations, declarations, orders and agreements, development agreements, joint venture agreements, partnership agreements, operating agreements, royalties, working interests, net profits interests, joint interest billing arrangements, participation agreements, production sales contracts, area of mutual interest agreements, gas balancing or deferred production agreements, injection, repressuring and recycling agreements, salt water or other disposal agreements, seismic or geophysical permits or agreements, and other agreements which are customary in the Oil and Gas Business;

(22) Liens on pipelines or pipeline facilities that arise by operation of law;

(23) Liens securing Indebtedness (other than Subordinated Obligations and Guarantor Subordinated Obligations) in an aggregate principal amount outstanding at any one time, added together with all other Indebtedness secured by Liens Incurred pursuant to this clause (23), not to exceed $35.0 million;

(24) Liens in favor of the Company or any Subsidiary Guarantor;

(25) deposits made in the ordinary course of business to secure liability to insurance carriers;

(26) Liens in favor of customs and revenue authorities arising as a matter of law to secure payment of customs duties in connection with the importation of goods in the ordinary course of business;

(27) Liens deemed to exist in connection with Investments in repurchase agreements permitted under “—Certain Covenants—Limitation on Indebtedness and Preferred Stock”; provided that such Liens do not extend to any assets other than those that are the subject of such repurchase agreement;

(28) Liens encumbering reasonable customary initial deposits and margin deposits and similar Liens attaching to commodity trading accounts or other brokerage accounts incurred in the ordinary course of business and not for speculative purposes;

(29) any (a) interest or title of a lessor or sublessor under any lease, liens reserved in oil, gas or other Hydrocarbons, minerals, leases for bonus, royalty or rental payments and for compliance with the terms of such leases; (b) restriction or encumbrance that the interest or title of such lessor or sublessor may be subject to (including, without limitation, ground leases or other prior leases of the demised premises, mortgages, mechanics’ liens, tax liens, and easements); or (c) subordination of the interest of the lessee or sublessee under such lease to any restrictions or encumbrance referred to in the preceding clause (b);

(30) Liens (other than Liens securing Indebtedness) on, or related to, assets to secure all or part of the costs incurred in the ordinary course of the Oil and Gas Business for the exploration, drilling, development, production, processing, transportation, marketing, storage or operation thereof;

(31) Liens upon specific items of inventory or other goods and proceeds of any Person securing such Person’s obligations in respect of bankers’ acceptances issued or created for the account of such Person to facilitate the purchase, shipment or storage of such inventory or other goods;

(32) Liens arising under the Indenture in favor of the Trustee for its own benefit and similar Liens in favor of other trustees, agents and representatives arising under instruments governing Indebtedness permitted to be incurred under the Indenture, provided, however, that such Liens are solely for the benefit of the trustees, agents or representatives in their capacities as such and not for the benefit of the holders of such Indebtedness;

(33) Liens arising from the deposit of funds or securities in trust for the purpose of decreasing or defeasing Indebtedness so long as such deposit of funds or securities and such decreasing or defeasing of Indebtedness are permitted under the covenant described under “––Certain Covenants—Limitation on Restricted Payments”;

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(34) Liens in favor of collecting or payer banks having a right of setoff, revocation, or charge back with respect to money or instruments of the Company or any Subsidiary of the Company on deposit with or in possession of such bank; and

(35) Liens on the Capital Stock of an Unrestricted Subsidiary held by the Company or its Restricted Subsidiaries in favor of any lender to such Unrestricted Subsidiary.

In each case set forth above, notwithstanding any stated limitation on the assets that may be subject to such Lien, a Permitted Lien on a specified asset or group or type of assets may include Liens on all improvements, additions and accessions thereto and all products and proceeds thereof (including dividends, distributions and increases in respect thereof).

“Permitted Payments to Parent” means, for so long as the Company is a member of a group filing a consolidated or combined tax return with the Parent, payments to the Parent in respect of an allocable portion of the tax liabilities of such group that is attributable to the Company and its Subsidiaries (“Tax Payments”). The Tax Payments shall not exceed the lesser of (a) the amount of the relevant tax (including any penalties and interest) that the Company would owe if the Company were filing a separate tax return (or a separate consolidated or combined return with its Subsidiaries that are members of the consolidated or combined group), taking into account any carryovers and carrybacks of tax attributes (such as net operating losses) of the Company and such Subsidiaries from other taxable years and (b) the net amount of the relevant tax that the Parent actually owes to the appropriate taxing authority. Any Tax Payments received from the Company shall be paid over to the appropriate taxing authority within 30 days of the Parent’s receipt of such Tax Payments or refunded to the Company.

“Person” means any individual, corporation, partnership, joint venture, association, joint-stock company, trust, unincorporated organization, limited liability company, government or any agency or political subdivision hereof or any other entity.

“Phantom Stock Plan” means the Company’s Second Amended and Restated Phantom Stock Plan, dated as of December 31, 2008 as in effect on the Issue Date, as it may be amended or modified from time to time.

“Preferred Stock,” as applied to the Capital Stock of any corporation, means Capital Stock of any class or classes (however designated) which is preferred as to the payment of dividends, or as to the distribution of assets upon any voluntary or involuntary liquidation or dissolution of such corporation, over shares of Capital Stock of any other class of such corporation.

“Production Payments and Reserve Sales” means the grant or transfer by the Company or a Restricted Subsidiary to any Person of a royalty, overriding royalty, net profits interest, production payment (whether volumetric or dollar denominated), partnership or other interest in oil and gas properties, reserves or the right to receive all or a portion of the production or the proceeds from the sale of production attributable to such properties where the holder of such interest has recourse solely to such production or proceeds of production, subject to the obligation of the grantor or transferor to operate and maintain, or cause the subject interests to be operated and maintained, in a reasonably prudent manner or other customary standard or subject to the obligation of the grantor or transferor to indemnify for environmental, title or other matters customary in the Oil and Gas Business, including any such grants or transfers pursuant to incentive compensation programs on terms that are reasonably customary in the Oil and Gas Business for geologists, geophysicists or other providers of technical services to the Company or a Restricted Subsidiary.

“Refinancing Indebtedness” means Indebtedness that is incurred to refund, refinance, replace, exchange, renew, repay, extend, prepay, redeem or retire (including pursuant to any defeasance or discharge mechanism) (collectively, “refinance,” “refinances” and “refinanced” shall have correlative meanings) any Indebtedness (including Indebtedness of the Company that refinances Indebtedness of any Restricted Subsidiary and Indebtedness of any Restricted Subsidiary that refinances Indebtedness of another Restricted Subsidiary, but excluding Indebtedness of a Subsidiary that is not a Restricted Subsidiary that refinances Indebtedness of the Company or a Restricted Subsidiary), including indebtedness that refinances Refinancing Indebtedness, provided, however, that:

(1) (a)  if the Stated Maturity of the indebtedness being Refinanced is earlier than the Stated Maturity of the Notes, the Refinancing Indebtedness has a Stated Maturity no earlier than the Stated Maturity of the Indebtedness being refinanced or (b) if the Stated Maturity of the Indebtedness being refinanced is later than the Stated Maturity of the Notes, the Refinancing Indebtedness has a Stated Maturity at least 91 days later than the Stated Maturity of the Notes;

(2) the Refinancing Indebtedness has an Average Life at the time such Refinancing Indebtedness is Incurred that is equal to or greater than the Average Life of the Indebtedness being refinanced;

(3) such Refinancing Indebtedness is Incurred in an aggregate principal amount (or if issued with original issue discount, an aggregate issue price) that is equal to or less than the sum of the aggregate principal amount (or if issued with original issue discount, the aggregate accreted value) then outstanding of the Indebtedness being refinanced (plus, without duplication, any additional Indebtedness Incurred to pay interest, premiums or defeasance costs required by the instruments governing such existing Indebtedness and fees and expenses Incurred in connection therewith); and

(4) if the Indebtedness being Refinanced is subordinated in right of payment to the Notes or the Subsidiary Guarantee, such Refinancing Indebtedness is subordinated in right of payment to the Notes or the Subsidiary Guarantee on terms at least as favorable to the holders as those contained in the documentation governing the Indebtedness being Refinanced.

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For the avoidance of doubt, Refinancing Indebtedness will not include Indebtedness Incurred under a Credit Facility pursuant to clause (1) of the second paragraph of the covenant described under “—Certain Covenants—Limitation on Indebtedness and Preferred Stock.”

“Registration Rights Agreement” means that certain registration rights agreement relating to the Notes, dated as of the date of the Supplemental Indenture by and among the Company, the Subsidiary Guarantors and the initial purchasers set forth therein.

“Restricted Investment” means any Investment other than a Permitted Investment.

“Restricted Stock Unit Plan” means the Company’s Non-Officer Restricted Stock Unit Plan, dated as of March 1, 2012 as in effect on the Issue Date, as it may be amended or modified from time to time.

“Restricted Subsidiary” means any Subsidiary of the Company other than an Unrestricted Subsidiary.

“Sale/Leaseback Transaction” means an arrangement relating to property now owned or hereafter acquired whereby the Company or a Restricted Subsidiary transfers such property to a Person and the Company or a Restricted Subsidiary leases it from such Person.

“SEC” means the United States Securities and Exchange Commission.

“Senior Secured Credit Agreement” means the Credit Agreement dated as of April 12, 2010 among the Company, as parent and guarantor, the Subsidiaries of the Company parties thereto as Borrowers, JPMorgan Chase Bank, N.A., as Administrative Agent, and the lenders parties thereto from time to time, including any guarantees, collateral documents, instruments and agreements executed in connection therewith, and any amendments, supplements, modifications, extensions, renewals, restatements, refundings or refinancings thereof and any indentures or credit facilities or commercial paper facilities with banks or other institutional lenders or investors that replace, refund or refinance any part of the loans, notes, other credit facilities or commitments thereunder, including any such replacement, refunding or refinancing facility or indenture that increases the amount borrowable thereunder or alters the maturity thereof (provided that such increase in borrowings is permitted under “—Certain Covenants—Limitation on Indebtedness and Preferred Stock” above).

“Significant Subsidiary” means any Restricted Subsidiary that would be a “Significant Subsidiary” of the Company within the meaning of Rule 1-02 under Regulation S-X promulgated by the SEC, as in effect on the Issue Date.

“Stated Maturity” means, with respect to any security, the date specified in such security as the fixed date on which the payment of principal of such security is due and payable, including pursuant to any mandatory redemption provision, but shall not include any contingent obligations to repay, redeem or repurchase any such principal prior to the date originally scheduled for the payment thereof.

“Subordinated Obligation” means any Indebtedness of the Company or Subsidiary Guarantor (whether outstanding on the Issue Date or thereafter Incurred) that is subordinate or junior in right of payment to the Notes pursuant to a written agreement.

“Subsidiary” of any Person means (a) any corporation, association or other business entity (other than a partnership, joint venture, limited liability company or similar entity) of which more than 50% of the total ordinary voting power of shares of Capital Stock entitled (without regard to the occurrence of any contingency) to vote in the election of directors, managers or trustees thereof (or Persons performing similar functions) or (b) any partnership, joint venture, limited liability company or similar entity of which more than 50% of the capital accounts, distribution rights, total equity and voting interests or general or limited partnership interests, as applicable, is, in the case of clauses (a) and (b), at the time owned or controlled, directly or indirectly, by (1) such Person, (2) such Person and one or more Subsidiaries of such Person or (3) one or more Subsidiaries of such Person. Unless otherwise specified herein, each reference to a Subsidiary (other than in this definition) will refer to a Subsidiary of the Company.

“Subsidiary Guarantee” means, individually, any Guarantee of payment of the Notes and exchange notes issued in a registered exchange offer pursuant to the Registration Rights Agreement by a Subsidiary Guarantor pursuant to the terms of the Indenture and any supplemental indenture thereto, and, collectively, all such Guarantees. Each such Subsidiary Guarantee will be in the form prescribed by the Indenture.

“Subsidiary Guarantor” means Chaparral Real Estate, L.L.C., Chaparral Resources, L.L.C., Chaparral CO2, L.L.C., Chaparral Energy, L.L.C., CEI Acquisition, L.L.C., CEI Pipeline, L.L.C., Green Country Supply, Inc., Chaparral Exploration, L.L.C. and Roadrunner Drilling, L.L.C., and any Restricted Subsidiary created or acquired by the Company after the Issue Date (other than a Foreign Subsidiary) that incurs any Indebtedness.

“Supplemental Indenture” means the supplement to the Indenture entered into by the Company, the Subsidiary Guarantors, and the Trustee with respect to the issuance of the New Notes.

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“Treasury Rate” means, as of any redemption date, the yield to maturity at the time of computation of United States Treasury securities with a constant maturity (as compiled and published in the most recent Federal Reserve Statistical Release H.15 (519) which has become publicly available at least two Business days prior to the redemption date (or, if such Statistical Release is no longer published, any publicly available source or similar market data)) most nearly equal to the period from the redemption date to May 15, 2017; provided, however, that if the period from the redemption date to May 15, 2017 is not equal to the constant maturity of a United States Treasury security for which a weekly average yield is given, the Treasury Rate shall be obtained by linear interpolation (calculated to the nearest one-twelfth of a year) from the weekly average yields of United States Treasury securities for which such yields are given, except that if the period from the redemption date to May 15, 2017 is less than one year, the weekly average yield on actually traded United States Treasury securities adjusted to a constant maturity of one year shall be used. The Company shall (1) calculate the Treasury Rate as of the second Business Day preceding the applicable redemption date and (2) prior to such redemption date file with the Trustee an Officers’ Certificate setting forth the Applicable Premium and the Treasury Rate and showing the calculation in reasonable detail.

“Unrestricted Subsidiary” means:

(1) any Subsidiary of the Company that at the time of determination shall be designated an Unrestricted Subsidiary by the Board of Directors of the Company in the manner provided below; and

(2) any Subsidiary of an Unrestricted Subsidiary.

The Board of Directors of the Company may designate any Subsidiary of the Company (including any newly acquired or newly formed Subsidiary or a Person becoming a Subsidiary through merger or consolidation or Investment therein) to be an Unrestricted Subsidiary only if:

(1) such Subsidiary or any of its Subsidiaries does not own any Capital Stock or Indebtedness of or have any Investment in, or own or hold any Lien on any property of, any other Subsidiary of the Company which is not a Subsidiary of the Subsidiary to be so designated or otherwise an Unrestricted Subsidiary;

(2) all the indebtedness of such Subsidiary and its Subsidiaries shall, at the date of designation, and will at all times thereafter, consist of Non-Recourse Debt;

(3) on the date of such designation, such designation and the Investment of the Company in such Subsidiary complies with “—Certain Covenants—Limitation on Restricted Payments”;

(4) such Subsidiary is a Person with respect to which neither the Company nor any of its Restricted Subsidiaries has any direct or indirect obligation:

(a) to subscribe for additional Capital Stock of such Person; or

(b) to maintain or preserve such Person’s financial condition or to cause such Person to achieve any specified levels of operating results; and

(5) on the date such Subsidiary is designated an Unrestricted Subsidiary, such Subsidiary is not a party to any agreement, contract, arrangement or understanding with the Company or any Restricted Subsidiary with terms substantially less favorable to the Company than those that might have been obtained from Persons who are not Affiliates of the Company.

In addition, without further designation, Chaparral Biofuels, L.L.C. and Oklahoma Ethanol L.L.C. will be Unrestricted Subsidiaries.

Any such designation by the Board of Directors of the Company shall be evidenced to the Trustee by filing with the Trustee a resolution of the Board of Directors of the Company giving effect to such designation and an Officers’ Certificate certifying that such designation complies with the foregoing conditions. If, at any time, any Unrestricted Subsidiary would fail to meet the foregoing requirements as an Unrestricted Subsidiary, it shall thereafter cease to be an Unrestricted Subsidiary for purposes of the Indenture and any Indebtedness of such Subsidiary shall be deemed to be Incurred as of such date.

The Board of Directors of the Company may designate any Unrestricted Subsidiary to be a Restricted Subsidiary; provided that immediately after giving effect to such designation, (a) no Default or Event of Default shall have occurred and be continuing or would occur as a consequence thereof and (b) either (i) the Company could Incur at least $1.00 of additional Indebtedness under the first paragraph of the covenant described under “—Certain Covenants—Limitation on Indebtedness and Preferred Stock” or (ii) the Consolidated Coverage Ratio for the Company and its Restricted Subsidiaries would not be greater than immediately prior to such designation, in either case on a pro forma basis taking into account such designation.

“U.S. Government Obligations” means securities that are (a) direct obligations of the United States of America for the timely payment of which its full faith and credit is pledged or (b) obligations of a Person controlled or supervised by and acting as an agency or instrumentality of the United States of America the timely payment of which is unconditionally guaranteed as a full faith and credit obligation of the United States of America, which, in either case, are not callable or redeemable at the option of the issuer thereof, and shall also include a depositary receipt issued by a bank (as defined in Section 3(a)(2) of the Securities Act), as custodian with respect

149

to any such U.S. Government Obligations or a specific payment of principal of or interest on any such U.S. Government Obligations held by such custodian for the account of the holder of such depositary receipt; provided that (except as required by law) such custodian is not authorized to make any deduction from the amount payable to the holder of such depositary receipt from any amount received by the custodian in respect of the U.S. Government Obligations or the specific payment of principal of or interest on the U.S. Government Obligations evidenced by such depositary receipt.

“Volumetric Production Payments” means production payment obligations recorded as deferred revenue in accordance with GAAP, together with all undertakings and obligations in connection therewith.

“Voting Stock” of an entity means all classes of Capital Stock of such entity then outstanding and normally entitled to vote in the election of members of such entity’s Board of Directors.

“Wholly Owned Subsidiary” means a Restricted Subsidiary, all of the Capital Stock of which (other than directors’ qualifying shares) is owned by the Company or another Wholly Owned Subsidiary.

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CERTAIN U.S. FEDERAL INCOME TAX CONSEQUENCES

The following discussion summarizes the material U.S. federal income tax consequences of an exchange of the old notes for the new notes pursuant to the exchange offer. This discussion does not purport to be a complete analysis of all the potential tax consequences. It is based on the provisions of the Internal Revenue Code of 1986, as amended (the “Code”), the Treasury regulations promulgated or proposed thereunder, judicial authority, published administrative positions of the Internal Revenue Service (the “IRS”) and other applicable authorities, all as in effect on the date of this prospectus, and all of which are subject to change, possibly on a retroactive basis. We have not sought any ruling from the IRS with respect to the statements made and the conclusions reached in this summary, and there can be no assurance that the IRS will agree with our statements and conclusions. This summary applies only to a person who holds the outstanding old note and the new note as “capital assets” within the meaning of Section 1221 of the Code (generally, property held for investment).

This summary does not purport to deal with all aspects of U.S. federal income taxation that might be relevant to a particular holder in light of the holder’s particular circumstances or status, nor does it address considerations applicable to an investor that may be subject to special tax rules, like a financial institution, tax-exempt organization, pension fund, S corporation, partnership or other pass-through entity or investors in those entities, regulated investment company, real estate investment trust, insurance company, broker-dealer, dealer or trader in securities or currencies, a person who holds a note as part of a hedge, straddle, synthetic security, conversion transaction or other risk reduction transaction, a holder whose “functional currency” is not the U.S. dollar, a person deemed to sell a note under the constructive sale provisions of the Code, a controlled foreign corporation, a passive foreign investment company, a former citizen or resident of the United States or a taxpayer subject to the alternative minimum tax. Moreover, the effect of any state, local or non-U.S. tax laws is not discussed.

The exchange of an outstanding old note for a new note pursuant to the exchange offer will not constitute a taxable exchange for U.S. federal income tax purposes. As a result, (1) you will not recognize taxable gain or loss as a result of exchanging an outstanding old note for a new note pursuant to the exchange offer, (2) your holding period for a new note will include your holding period for the outstanding old note exchanged therefor, and (3) your tax basis in the new note will be the same as your tax basis in the outstanding old note exchanged therefor.

THE FOREGOING DISCUSSION DOES NOT PURPORT TO ADDRESS ALL OF THE U.S. FEDERAL INCOME TAX CONSEQUENCES OF EXCHANGING AN OUTSTANDING OLD NOTE FOR A NEW NOTE OR THE CONSEQUENCES OF ACQUIRING, HOLDING OR DISPOSING OF AN OUTSTANDING OLD NOTE OR A NEW NOTE THAT MAY BE RELEVANT TO A PARTICULAR HOLDER IN LIGHT OF HIS PARTICULAR CIRCUMSTANCES OR IN LIGHT OF ANY SPECIAL RULES TO WHICH HE MAY BE SUBJECT. IF YOU ARE CONSIDERING AN EXCHANGE OF AN OUTSTANDING OLD NOTE FOR A NEW NOTE, YOU SHOULD CONSULT YOUR OWN TAX ADVISOR CONCERNING YOUR TAX CONSEQUENCES, INCLUDING THE TAX CONSEQUENCES ARISING UNDER U.S. FEDERAL, STATE, LOCAL OR FOREIGN LAWS.

CERTAIN ERISA CONSIDERATIONS

To ensure compliance with U.S. Internal Revenue Service Circular 230, holders of the old notes are hereby notified that any discussion of tax matters set forth in this summary was written in connection with the promotion or marketing of the transactions or matters addressed herein and was not intended or written to be used, and cannot be used by any holder, for the purpose of avoiding tax-related penalties under federal, state or local law. Each holder should seek advice based on its particular circumstances from an independent tax advisor.

Section 406 of ERISA and Section 4975 of the Code prohibit employee benefit plans that are subject to Title I of ERISA, as well as individual retirement accounts and other plans subject to Section 4975 of the Code or any entity deemed to hold assets of a plan subject to Title I of ERISA or Section 4975 of the Code (each of which we refer to as a “Plan”), from engaging in certain transactions involving “plan assets” with persons who are “parties in interest” under ERISA or “disqualified persons” under Section 4975 of the Code, hereinafter known as “Parties in Interest,” with respect to such Plans. If we are a Party in Interest with respect to a Plan (either directly or by reason of our ownership of our subsidiaries), the purchase and holding of the new notes by or on behalf of the Plan may be a prohibited transaction under Section 406(a)(1) of ERISA and Section 4975(c)(1) of the Code, unless exemptive relief were available under an applicable administrative exemption (as described below) or there were some other basis on which the transaction was not prohibited.

Employee benefit plans that are governmental plans (as defined in Section 3(32) of ERISA), certain church plans (as defined in Section 3(33) of ERISA) and foreign plans (as described in Section 4(b)(4) of ERISA) are not subject to these “prohibited transaction” rules of ERISA or Section 4975 of the Code, but may be subject to similar rules under any federal, state, local, non-U.S or other laws or regulations that are similar to such provisions of ERISA or Section 4975 of the Code.

151

Accordingly, the new notes may not be sold, exchanged or transferred to, and each purchaser, holder or transferee, by its purchase, exchange or holding of such notes, shall be deemed to have represented and covenanted that it is not purchasing, exchanging or holding the notes for or on behalf of, a Plan or other plan subject to similar law, except that such purchase or exchange for or on behalf of a Plan or other plan subject to similar law shall be permitted to the extent that such purchase or exchange will not give rise to a transaction described in Section 406 of ERISA or Section 4975(c)(1) of the Code for which a statutory or administrative exemption is unavailable or which is not otherwise prohibited under ERISA, Section 4975 of the Code or the provisions under any federal, state, local, non-U.S. or other laws or regulations that are similar to such provisions of ERISA or Section 4975 of the Code.

The foregoing discussion is general in nature and is not intended to be all-inclusive. Due to the complexity of the applicable rules, it is particularly important that fiduciaries or other persons considering purchasing the new notes on behalf of or with “plan assets” of any Plan consult with their counsel regarding the relevant provisions of ERISA and the Code and any other provision under any federal, state, local, non-U.S. or other laws or regulations that are similar to such provisions of ERISA or the Code and the availability of exemptive relief applicable to the purchase and holding of the new notes.

PLAN OF DISTRIBUTION

The staff of the SEC has taken the position that any broker-dealer that receives new notes for its own account in the exchange offer in exchange for the outstanding old notes that were acquired by such broker-dealer as a result of market-making or other trading activities, may be deemed to be an “underwriter” within the meaning of the Securities Act and must deliver a prospectus meeting the requirements of the Securities Act in connection with any resale of such new notes.

Each broker-dealer that receives new notes for its own account in the exchange offer must acknowledge that it will deliver a prospectus in connection with any resale of the new notes. This prospectus, as it may be amended or supplemented from time to time, may be used by a broker-dealer in connection with resales of new notes received in exchange for the outstanding notes where the outstanding notes were acquired as a result of market-making activities or other trading activities. We have agreed that, for a period ending on the earlier of (i) 180 days after the date of this prospectus and (ii) the date on which a broker-dealer is no longer required to deliver a prospectus in connection with market-making or other trading activities, we will make this prospectus, as amended or supplemented, available to any broker-dealer for use in connection with any resale.

We will not receive any proceeds from any sale of new notes by broker-dealers. New notes received by broker-dealers for their own account in the exchange offer may be sold from time to time in one or more transactions in the over-the-counter market, in negotiated transactions, through the writing of options on the new notes or a combination of these methods of resale. These resales may be made at market prices prevailing at the time of resale, at prices related to these prevailing market prices or negotiated prices. Any resale may be made directly to purchasers or to or through brokers or dealers who may receive compensation in the form of commissions or concessions from any broker-dealer and/or the purchasers of any of the new notes. Any broker-dealer that resells new notes that were received by it for its own account in the exchange offer and any broker or dealer that participates in a distribution of the new notes may be deemed to be an “underwriter” within the meaning of the Securities Act, and any profit on the resale of new notes and any commission or concessions received by those persons may be deemed to be underwriting compensation under the Securities Act. Any such broker-dealer must comply with the registration and prospectus delivery requirements of the Securities Act in connection with any resale transaction, including the delivery of a prospectus that contains information with respect to any selling holder required by the Securities Act in connection with any resale of the new notes. By delivering a prospectus, however, a broker-dealer will not be deemed to admit that it is an underwriter within the meaning of the Securities Act.

Furthermore, any broker-dealer that acquired any of its outstanding old notes directly from us:

• may not rely on the applicable interpretation of the staff of the SEC’s position contained in Exxon Capital Holdings Corp., SEC no-action letter (April 13, 1988), Morgan, Stanley & Co. Inc., SEC no-action letter (June 5, 1991) and Shearman & Sterling, SEC no-action letter (July 2, 1993); and

• must comply with the registration and prospectus delivery requirements of the Securities Act in connection with any resale of the new notes.

We have agreed to pay all expenses incident to the performance of our obligations in relation to the exchange offer (including the expenses of one counsel for the holders of the outstanding old notes) other than commissions or concessions of any brokers or dealers. We will indemnify the holders of the new notes against certain liabilities, including liabilities under the Securities Act.

152

LEGAL MATTERS

The validity of the new notes and certain other matters will be passed upon for us by McAfee & Taft A Professional Corporation, Oklahoma City, Oklahoma.

EXPERTS

The consolidated financial statements included in this prospectus and elsewhere in this registration statement have been so included in reliance upon the report of Grant Thornton LLP, independent registered public accountants, upon the authority of said firm as experts in accounting and auditing in giving said report.

INDEPENDENT PETROLEUM ENGINEERS

Certain estimates of our net oil and natural gas reserves and related information as of December 31, 2010, 2011 and 2012 included in this prospectus have been derived from engineering reports prepared by Cawley, Gillespie & Associates, Inc. and Ryder Scott Company LP. All such information has been so included on the authority of such firms as experts regarding the matters contained in their reports.

WHERE YOU CAN FIND MORE INFORMATION

We have filed with the SEC a registration statement on Form S-4, including exhibits and schedules, under the Securities Act with respect to the offer to exchange our senior notes. This prospectus, which constitutes a part of the registration statement, does not contain all of the information set forth in the registration statement or the exhibits and schedules that are part of the registration statement. For further information about us and the exchange offer, you should refer to the registration statement. Any statements made in this prospectus as to the contents of any contract, agreement or other document are not necessarily complete. With respect to each such contract, agreement or other document filed as an exhibit to the registration statement, you should refer to the exhibit for a more complete description of the matter involved, and each statement in this prospectus shall be deemed qualified in its entirety by this reference.

You may read, without charge, and copy, at prescribed rates, all or any portion of the registration statement or any of our other reports, statements or other information in the files at the public reference facilities of the SEC’s principal office at 100 F Street NE, Washington, D.C., 20549. You can request copies of these documents upon payment of a duplicating fee by writing to the SEC. You may call the SEC at 1-800-SEC-0330 for further information on the operation of its public reference rooms. Our filings, including the registration statement, will also be available to you on the Internet web site maintained by the SEC at http://www.sec.gov.

Our website on the Internet is located at http://www.chaparralenergy.com, and we make our periodic reports and other information filed with or furnished to the SEC available, free of charge, through our website, as soon as reasonably practicable after those reports and other information are electronically filed with or furnished to the SEC. Information on our website or any other website is not incorporated by reference into this prospectus and does not constitute a part of this prospectus. You may also request a copy of these filings at no cost, by writing or telephoning us at the following address: Chaparral Energy, Inc., Attention: Chief Financial Officer, 701 Cedar Lake Boulevard, Oklahoma City, Oklahoma 73114, (405) 478-8770.

We intend to furnish or make available to our stockholders and holders of the new notes annual reports containing our audited financial statements prepared in accordance with GAAP. We also intend to furnish or make available to our stockholders and holders of the new notes quarterly reports containing our unaudited interim financial information, including the information required by Form 10-Q, for the first three fiscal quarters of each fiscal year.

153

GLOSSARY OF TERMS

The terms defined in this section are used throughout this prospectus:

Basin	A large natural depression on the earth’s surface in which sediments generally brought by water accumulate.
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.
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.
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.
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.
Limestone/carbonate	A sedimentary rock composed primarily of calcium carbonate. It is an important reservoir rock for hydrocarbon production in the earth’s subsurface. It can be composed of various calcium carbonate grains or chemically precipitated. It often contains variable amounts of silica, silt, and clay. It is highly soluble which often results in secondary porosity and karsting. This can vary greatly from place to place. These factors all generally make this rock type a more heterogeneous deposit than sandstone.
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.

154

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.
NYMEX	The New York Mercantile Exchange.
PDP	Proved developed producing.
Play	A term describing an area of land following the identification by geologists and geophysicists of reservoirs with potential oil and natural gas reserves.
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.
PV-10 value	When used with respect to oil and natural gas reserves, PV-10 value means the estimated future gross revenue to be generated from the production of proved reserves, net of estimated production and future development costs, excluding escalations of prices and costs based upon future conditions, before income taxes, and without giving effect to non-property-related expenses, discounted to a present value using an annual discount rate of 10%.
Sandstone	A clastic sedimentary rock composed mainly of cemented sand-sized minerals or rock grains. Most sandstone is composed of quartz or feldspar. It is an important reservoir rock for hydrocarbon production in the earth’s subsurface. It is usually a more resistant rock than limestone and generally has less lateral variability in porosity.
SEC	The Securities and Exchange Commission.
Secondary recovery	The recovery of oil and natural gas through the injection of liquids or gases into the reservoir, supplementing its natural energy. Secondary recovery methods are often applied when production slows due to depletion of the natural pressure.
Seismic survey	Also known as a seismograph survey, it is a survey of an area by means of an instrument which records the vibrations of the earth. By recording the time interval between the source of the shock wave and the reflected or refracted shock waves from various formations, geophysicists are able to define the underground configurations.
Spacing	The distance between wells producing from the same reservoir. Spacing is often expressed in terms of acres, e.g., 40-acre spacing, and is often established by regulatory agencies.
Unit	The joining of all or substantially all interests in a reservoir or field, rather than a single tract, to provide for development and operation without regard to separate property interests. Also, the area covered by a unitization agreement.

155

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.

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Chaparral Energy, Inc.

Index to financial statements

	Page
Chaparral Energy, Inc. consolidated financial statements:
Report of independent registered public accounting firm		F-2
Consolidated balance sheets as of December 31, 2012 and 2011		F-3
Consolidated statements of operations for the years ended December 31, 2012, 2011, and 2010		F-5
Consolidated statements of comprehensive income for the years ended December 31, 2012, 2011, and 2010		F-6
Consolidated statements of stockholders’ equity for the years ended December  31, 2012, 2011, and 2010		F-7
Consolidated statements of cash flows for the years ended December 31, 2012, 2011, and 2010		F-8
Notes to consolidated financial statements		F-9

F-1

Report of independent registered public accounting firm

Board of Directors

Chaparral Energy, Inc.

We have audited the accompanying consolidated balance sheets of Chaparral Energy, Inc. and subsidiaries (the “Company”) as of December 31, 2012 and 2011, and the related consolidated statements of operations, comprehensive income, stockholders’ equity and cash flows for each of the three years in the period ended December 31, 2012. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Chaparral Energy, Inc. and subsidiaries as of December 31, 2012 and 2011, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2012 in conformity with accounting principles generally accepted in the United States of America.

/S/ GRANT THORNTON LLP

Oklahoma City, Oklahoma

April 1, 2013

F-2

Chaparral Energy, Inc. and subsidiaries

Consolidated balance sheets

	December 31,
(dollars in thousands, except per share data)	2012			2011
Assets
Current assets:
Cash and cash equivalents	$	29,819		$	34,589
Accounts receivable, net		77,307			64,788
Inventories, net		10,510			8,641
Prepaid expenses		3,465			3,265
Derivative instruments		42,516			12,840
Total current assets		163,617			124,123
Property and equipment—at cost, net		65,601			65,711
Oil and natural gas properties, using the full cost method:
Proved		2,860,611			2,535,404
Unevaluated (excluded from the amortization base)		162,921			22,831
Accumulated depreciation, depletion, amortization and impairment		(1,290,356	)		(1,135,567	)
Total oil and natural gas properties		1,733,176			1,422,668
Derivative instruments		517			16,785
Assets held for sale		5,689			—
Deferred income taxes		—			7,526
Other assets		38,952			32,920
	$	2,007,552		$	1,669,733

The accompanying notes are an integral part of these consolidated financial statements.

F-3

	December 31,
(dollars in thousands, except per share data)	2012		2011
Liabilities and stockholders’ equity
Current liabilities:
Accounts payable and accrued liabilities	$	101,598	$	68,930
Accrued payroll and benefits payable		19,655		18,818
Accrued interest payable		24,131		30,882
Revenue distribution payable		18,152		20,800
Current maturities of long-term debt and capital leases		3,746		3,078
Derivative instruments		436		1,505
Deferred income taxes		26,872		23,704
Total current liabilities		194,590		167,717
Long-term debt and capital leases, less current maturities		1,289,656		1,031,495
Derivative instruments		2,192		127
Stock-based compensation		3,042		2,788
Asset retirement obligations		46,314		43,593
Deferred income taxes		8,901		—
Commitments and contingencies (Note 13)
Stockholders’ equity:
Preferred stock, 600,000 shares authorized, none issued and outstanding		—		—
Class A Common stock, $0.01 par value, 10,000,000 shares authorized 67,991 and 66,165 shares issued and outstanding at December 31, 2012 and 2011, respectively		—		—
Class B Common stock, $0.01 par value, 10,000,000 shares authorized and 357,882 shares issued and outstanding		4		4
Class C Common stock, $0.01 par value, 10,000,000 shares authorized and 209,882 shares issued and outstanding		2		2
Class D Common stock, $0.01 par value, 10,000,000 shares authorized and 279,999 shares issued and outstanding		3		3
Class E Common stock, $0.01 par value, 10,000,000 shares authorized and 504,276 shares issued and outstanding		5		5
Class F Common stock, $0.01 par value, 1 share authorized, issued, and outstanding		—		—
Class G Common stock, $0.01 par value, 3 shares authorized, issued, and outstanding		—		—
Additional paid in capital		422,434		419,370
Retained earnings (accumulated deficit)		17,186		(47,217	)
Accumulated other comprehensive income, net of taxes		23,223		51,846
		462,857		424,013
	$	2,007,552	$	1,669,733

The accompanying notes are an integral part of these consolidated financial statements.

F-4

Chaparral Energy, Inc. and subsidiaries

Consolidated statements of operations

	Year ended December 31,
(in thousands)	2012			2011			2010
Revenues:
Oil and natural gas sales	$	509,503		$	530,041		$	408,561
Gain (loss) from oil and natural gas hedging activities		46,746			(27,452	)		(29,393	)
Other revenues		—			4,070			4,127
Total revenues		556,249			506,659			383,295
Costs and expenses:
Lease operating		130,960			121,420			106,127
Production taxes		32,003			34,321			26,495
Depreciation, depletion and amortization		169,307			146,083			109,503
Loss on impairment of other assets		2,000			—			4,150
General and administrative		49,812			42,056			29,915
Other expenses		—			3,448			3,148
Total costs and expenses		384,082			347,328			279,338
Operating income		172,167			159,331			103,957
Non-operating income (expense):
Interest expense		(98,402	)		(96,720	)		(81,370	)
Non-hedge derivative gains		49,685			34,408			38,595
Loss on extinguishment of debt		(21,714	)		(20,592	)		(2,241	)
Financing costs		—			—			(1,812	)
Other income		504			1,545			387
Net non-operating expense		(69,927	)		(81,359	)		(46,441	)
Income before income taxes		102,240			77,972			57,516
Income tax expense		37,837			35,924			23,803
Net income	$	64,403		$	42,048		$	33,713

The accompanying notes are an integral part of these consolidated financial statements.

F-5

Chaparral Energy, Inc. and subsidiaries

Consolidated statements of comprehensive income

	Year ended December 31,
(in thousands)	2012			2011			2010
Net income	$	64,403		$	42,048		$	33,713
Other comprehensive income (loss)
Reclassification adjustment for hedge (gains) losses included in net income		(46,746	)		27,452			28,733
Unrealized loss on hedges		—			—			(1,034	)
Income tax expense (benefit) related to other comprehensive income (loss)		18,123			(10,580	)		(10,343	)
Other comprehensive income (loss), net of tax		(28,623	)		16,872			17,356
Comprehensive income	$	35,780		$	58,920		$	51,069

The accompanying notes are an integral part of these consolidated financial statements.

F-6

Chaparral Energy, Inc. and subsidiaries

Consolidated statements of stockholders’ equity

						Additional paid in			Retained earnings (accumulated			Accumulated other comprehensive
	Common stock
(dollars in thousands)	Shares			Amount		capital			deficit)			income			Total
Balance at January 1, 2010		877,000		$	9	$	100,918		$	(122,978	)	$	17,618		$	(4,433	)
Common stock issuance for cash		475,043			5		313,226			—			—			313,231
Restricted stock issuances		51,346			—		—			—			—			—
Stock-based compensation		—			—		3,690			—			—			3,690
Net income		—			—		—			33,713			—			33,713
Other comprehensive income, net
Unrealized loss on hedges, net of taxes of $386		—			—		—			—			(648	)		(648	)
Reclassification adjustment for hedge losses included in net income, net of taxes of $10,729		—			—		—			—			18,004			18,004
Total comprehensive income																51,069
Balance at December 31, 2010		1,403,389			14		417,834			(89,265	)		34,974			363,557
Restricted stock issuances		17,642			—		—			—			—			—
Restricted stock forfeitures		(2,295	)		—		—			—			—			—
Restricted stock repurchased		(528	)		—		—			—			—			—
Stock-based compensation		—			—		4,137			—			—			4,137
Modification of Time Vesting awards to liability plan		—			—		(2,640	)		—			—			(2,640	)
Time Vesting awards settled in restricted stock		—			—		39			—			—			39
Net income		—			—		—			42,048			—			42,048
Other comprehensive income, net
Reclassification adjustment for hedge losses included in net income, net of taxes of $10,580		—			—		—			—			16,872			16,872
Total comprehensive income																58,920
Balance at December 31, 2011		1,418,208			14		419,370			(47,217	)		51,846			424,013
Restricted stock issuances		17,494			—		—			—			—			—
Restricted stock forfeitures		(14,199	)		—		—			—			—			—
Restricted stock repurchased		(1,469	)		—		—			—			—			—
Stock-based compensation		—			—		2,463			—			—			2,463
Time Vesting awards settled in restricted stock		—			—		601			—			—			601
Net income		—			—		—			64,403			—			64,403
Other comprehensive income, net
Reclassification adjustment for hedge gains included in net income, net of taxes of $18,123		—			—		—			—			(28,623	)		(28,623	)
Total comprehensive income																35,780
Balance at December 31, 2012		1,420,034		$	14	$	422,434		$	17,186		$	23,223		$	462,857

The accompanying notes are an integral part of these consolidated financial statements.

F-7

Chaparral Energy, Inc. and subsidiaries

Consolidated statements of cash flows

	Year ended December 31,
(in thousands)	2012			2011			2010
Cash flows from operating activities
Net income	$	64,403		$	42,048		$	33,713
Adjustments to reconcile net income to net cash provided by operating activities
Depreciation, depletion, & amortization		169,307			146,083			109,503
Loss on impairment of other assets		2,000			—			4,150
Deferred income taxes		37,719			35,745			23,724
Unrealized loss (gain) on ineffective portion of hedges and reclassification adjustments		(46,746	)		27,452			23,889
Non-hedge derivative gains		(49,685	)		(34,408	)		(38,595	)
Loss on extinguishment of debt		21,714			20,592			2,241
Net gain on sale of assets		(149	)		(1,284	)		(184	)
Other		2,864			3,057			2,211
Change in assets and liabilities
Accounts receivable		(12,502	)		(4,762	)		(6,463	)
Inventories		(2,304	)		328			(785	)
Prepaid expenses and other assets		2,360			1,583			5,141
Accounts payable and accrued liabilities		3,988			16,519			9,452
Revenue distribution payable		(2,648	)		3,577			(1,450	)
Stock-based compensation		1,679			3,086			1,155
Net cash provided by operating activities		192,000			259,616			167,702
Cash flows from investing activities
Purchase of property and equipment and oil and natural gas properties		(506,787	)		(339,863	)		(310,125	)
Proceeds from asset dispositions		46,246			38,356			445
Settlement of non-hedge derivative instruments		37,274			(23,491	)		45,490
Other		21			—			18
Net cash used in investing activities		(423,246	)		(324,998	)		(264,172	)
Cash flows from financing activities
Proceeds from long-term debt		208,561			21,724			209,533
Repayment of long-term debt		(183,482	)		(24,785	)		(717,561	)
Proceeds from Senior Notes		556,750			400,000			293,016
Repayment of Senior Notes		(325,000	)		(325,000	)		—
Proceeds from equity issuance		—			—			313,231
Principal payments under capital lease obligations		(10	)		(120	)		(249	)
Payment of debt issuance costs and other financing fees		(14,516	)		(11,858	)		(19,806	)
Payment of debt extinguishment costs		(15,827	)		(15,101	)		—
Net cash provided by financing activities		226,476			44,860			78,164
Net decrease in cash and cash equivalents		(4,770	)		(20,522	)		(18,306	)
Cash and cash equivalents at beginning of period		34,589			55,111			73,417
Cash and cash equivalents at end of period	$	29,819		$	34,589		$	55,111

The accompanying notes are an integral part of these consolidated financial statements.

F-8

Chaparral Energy, Inc. and subsidiaries

Notes to consolidated financial statements

(dollars in thousands, unless otherwise noted)

Note 1: Nature of operations and summary of significant accounting policies

Chaparral Energy, Inc. and its subsidiaries, (collectively, “we”, “our”, “us”, or the “Company”) are involved in the acquisition, exploration, development, production and operation of oil and natural gas properties. Properties are located primarily in Oklahoma, Texas, New Mexico, Louisiana, Arkansas, and Kansas.

A summary of the significant accounting policies applied in the preparation of the accompanying consolidated financial statements follows.

Principles of consolidation

The consolidated financial statements include the accounts of Chaparral Energy, Inc. and its wholly owned subsidiaries. All significant intercompany balances and transactions have been eliminated.

Use of estimates

The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America (“GAAP”) requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from these estimates. Significant estimates affecting these financial statements include estimates for quantities of proved oil and natural gas reserves, valuation allowances associated with deferred income taxes, asset retirement obligations, fair value of derivative instruments, and others, and are subject to change.

Reclassifications

Certain reclassifications have been made to prior period financial statements to conform to current period presentation.

Cash and cash equivalents

We consider all highly liquid investments with an original maturity of three months or less to be cash equivalents. We maintain cash and cash equivalents in bank deposit accounts and money market funds which may not be federally insured. As of December 31, 2012, cash with a recorded balance totaling $27,732 was held at JP Morgan Chase Bank, N.A. We have not experienced any losses in such accounts and believe we are not exposed to any significant credit risk on such accounts.

Accounts receivable

We have receivables from joint interest owners and oil and natural gas purchasers which are generally uncollateralized. We generally review our oil and natural gas purchasers for credit worthiness and general financial condition. We may have the ability to withhold future revenue disbursements to recover non-payment of joint interest billings on properties of which we are the operator. Accounts receivable from joint interest owners are stated at amounts due, net of an allowance for doubtful accounts. Accounts receivable are generally due within 30 days and accounts outstanding longer than 60 days are considered past due. We determine our allowance by considering the length of time past due, previous loss history, future net revenues of the debtor’s ownership interest in oil and natural gas properties we operate, and the owner’s ability to pay its obligation, among other things.

We write off accounts receivable when they are determined to be uncollectible. Bad debt expense for the years ended December 31, 2012, 2011, and 2010 was $731, $179, and $17, respectively. Accounts receivable consisted of the following at December 31:

	2012			2011
Joint interests	$	19,282		$	16,926
Accrued oil and natural gas sales		50,814			47,667
Derivative settlements		8,013			449
Other		472			380
Allowance for doubtful accounts		(1,274	)		(634	)
	$	77,307		$	64,788

F-9

Inventories

Inventories are comprised of equipment used in developing oil and natural gas properties, oil and natural gas product inventories, and equipment for resale. Equipment inventory and inventory for resale are carried at the lower of cost or market using the average cost method. Oil and natural gas product inventories are stated at the lower of production cost or market. We regularly review inventory quantities on hand and record provisions for excess or obsolete inventory, if necessary. The provision for excess or obsolete inventory for the years ended December 31, 2012, 2011, and 2010 was $0, $602, and $810, respectively. Inventories consisted of the following at December 31:

	2012			2011
Equipment inventory	$	8,047		$	6,164
Oil and natural gas product		3,175			3,793
Inventory valuation allowance		(712	)		(1,316	)
	$	10,510		$	8,641

Property and equipment

Property and equipment are capitalized and stated at cost, while maintenance and repairs are expensed currently.

Depreciation and amortization are provided in amounts sufficient to relate the cost of depreciable assets to operations over their estimated service lives using the straight-line method. Estimated useful lives are as follows:

Furniture and fixtures	10 years
Automobiles and trucks	5 years
Machinery and equipment	10 - 20 years
Office and computer equipment	5 - 10 years
Building and improvements	10 - 40 years

Oil and natural gas properties

We use the full cost method of accounting for oil and natural gas properties and activities. Accordingly, we capitalize all costs incurred in connection with the exploration for and development of oil and natural gas reserves. Proceeds from the disposition of oil and natural gas properties are accounted for as a reduction in capitalized costs, with no gain or loss generally recognized unless such dispositions involve a significant alteration in the depletion rate. We capitalize internal costs that can be directly identified with exploration and development activities, but do not include any costs related to production, general corporate overhead or similar activities. Capitalized costs include geological and geophysical work, 3D seismic, delay rentals, drilling and completing and equipping oil and natural gas wells, including salaries, benefits, capitalized interest on qualified projects and other internal costs directly attributable to these activities.

Depreciation, depletion and amortization (“DD&A”) of oil and natural gas properties are provided using the units-of-production method based on estimates of proved oil and natural gas reserves and production, which are converted to a common unit of measure based upon their relative energy content. Our cost basis for depletion includes estimated future development costs to be incurred on proved undeveloped properties. The computation of DD&A takes into consideration restoration, dismantlement, and abandonment costs, and the anticipated proceeds from salvaging equipment.

In accordance with the full cost method of accounting, the net capitalized costs of oil and natural gas properties are not to exceed their related estimated future net revenues discounted at 10% (“PV-10 value”), as adjusted for our cash flow hedge positions and net of tax considerations, plus the cost of unproved properties not being amortized.

Our estimates of oil and natural gas reserves as of December 31, 2012, 2011, and 2010 were prepared using an average price for oil and natural gas based upon the first day of each month for the prior twelve months as required by the SEC’s Modernization of Oil and Gas Reporting and the guidance of the Financial Accounting Standard Board (“FASB”) relating to Oil and Gas Reserve Estimation and Disclosures. As of December 31, 2012, the cost center ceiling exceeded the net capitalized cost of our oil and natural gas properties, and no ceiling test impairment was recorded. The PV-10 value of our reserves was estimated based on average prices of $94.71 per Bbl of oil and $2.76 per Mcf of gas for the year ended December 31, 2012.

A decline in oil and natural gas prices subsequent to December 31, 2012 could result in additional ceiling test write-downs in future periods. The amount of any future impairment is difficult to predict, and will depend on the average oil and gas prices during each period, the incremental proved reserves added during each period, and additional capital spent.

F-10

Assets Held for Sale

In the fourth quarter of 2012, the Company finalized a plan to dispose of certain of the company’s owned drilling rigs by sale. The accounting for these assets is in accordance with ASC 360-10, Property, Plant and Equipment. Under this guidance, the assets are carried on the balance sheet at their carrying value or fair value less cost to sell, whichever is less. In determining fair value for the assets, management performed internal estimates of the value of the assets based on prices that would be received to sell each rig in an orderly transaction between market participants. As a result of determining fair value on the assets held for sale, an impairment loss was recorded for the year ended December 31, 2012 on certain of the assets held for sale in the amount of $1,500 which was included in the Loss on impairment of other assets in the Statements of Operations.

Impairment of long-lived assets

Impairment losses are recorded on property and equipment used in operations and other long lived assets when indicators of impairment are present and the undiscounted cash flows estimated to be generated by those assets are less than the assets’ carrying amount. Impairment is measured based on the excess of the carrying amount over the fair value of the asset.

In 2012, we recognized $1,500 of impairment losses on certain of our owned drilling rigs classified as assets held for sale due to the expectation that these particular drilling rigs could not be sold at a price that would exceed their carrying values in the current market climate. We estimated the fair value of the drilling rigs using prices that would be received to sell each rig in an orderly transaction between market participants. Also in 2012, we recognized $500 of additional impairment losses primarily related to drill pipe.

We owned an interest in the Levelland/Hockley County ethanol plant in Levelland, Texas, and we own a pipeline constructed for the sole purpose of supplying natural gas to the ethanol plant. During the fourth quarter of 2010, we determined that any future cash flows generated by either the ethanol plant or by our pipeline, which supplies gas to the ethanol plant, would probably not be sufficient to allow us to recover our investment in these assets. We accordingly recorded an impairment charge of $4,150, which included our $2,042 investment in the ethanol plant and the $2,108 carrying value of our pipeline assets.

Deferred income taxes

Deferred income taxes are provided for significant carryforwards and temporary differences between the tax basis of an asset or liability and its reported amount in the financial statements that will result in taxable or deductible amounts in future years. Deferred income tax assets or liabilities are determined by applying the presently enacted tax rates and laws. We record a valuation allowance for the amount of net deferred tax assets when, in management’s opinion, it is more likely than not that such assets will not be realized.

Realization of our deferred tax assets is dependent upon generating sufficient future taxable income. Although realization is not assured, we believe it is more likely than not that the deferred tax asset will be realized. The amount of the deferred tax asset considered realizable, however, could be reduced in the near-term if estimates of future taxable income are reduced.

If applicable, we would report a liability for tax benefits resulting from uncertain tax positions taken or expected to be taken in a tax return, and would recognize interest and penalties related to uncertain tax positions in interest expense. As of December 31, 2012 and 2011, we have not recorded a liability or accrued interest or penalties related to uncertain tax positions.

Tax years beginning with 1999 remain open to examination for federal income tax purposes and by the other major taxing jurisdictions to which we are subject.

Derivative transactions

We use derivative instruments to reduce the effect of fluctuations in crude oil and natural gas prices, and we recognize all derivatives as either assets or liabilities measured at fair value. The accounting for changes in the fair value of a derivative depends on the use of the derivative and the resulting designation.

Changes in the fair value of derivatives that are not accounted for as hedges are reported immediately in non-hedge derivative gains (losses) in the statement of operations. Cash flows associated with non-hedge derivatives are reported as investing activities in the statement of cash flows unless the derivatives contain a significant financing element, in which case they are reported as financing activities.

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. Cash flows associated with hedges are reported as operating activities in the statement of cash flows unless the hedges contain a significant financing element, in which case they are reported as financing activities.

F-11

If it is probable the oil or natural gas sales which are hedged will not occur, hedge accounting is discontinued and the gain or loss reported in accumulated other comprehensive income (loss) (“AOCI”) 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 is discontinued. The gain or loss associated with the discontinued hedges remains in AOCI and is reclassified into income as the hedged transactions occur. Effective April 1, 2010, we have 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.

We offset assets and liabilities for derivative contracts executed with the same counterparty under a master netting arrangement. See Note 5 for additional information regarding our derivative transactions.

Fair value measurements

Fair value is defined by the FASB as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. Where available, fair value is based on observable market prices or parameters or derived from such prices or parameters. Where observable prices or inputs are not available, valuation models are applied. These valuation techniques involve some level of management estimation and judgment, the degree of which is dependent on the price transparency for the instruments or market and the instruments’ complexity.

Assets and liabilities recorded at fair value in the balance sheet are categorized according to the fair value hierarchy defined by the FASB. The hierarchical levels are based upon the level of judgment associated with the inputs used to measure the fair value of the assets and liabilities. In certain cases, the inputs used to measure fair value may fall into different levels of the fair value hierarchy. In such cases, the asset or liability is categorized based on the lowest level input that is significant to the fair value measurement in its entirety. Our assessment of the significance of a particular input to the fair value measurement in its entirety requires judgment, and may affect the placement of assets and liabilities within the levels of the fair value hierarchy.

Level 1 inputs are unadjusted quoted prices in active markets for identical assets or liabilities at the measurement date. Level 2 inputs include adjusted quoted prices for similar instruments in active markets, and inputs other than quoted prices that are observable for the asset or liability. Fair value assets and liabilities included in this category are derivatives with fair values based on published forward commodity price curves and other observable inputs. Level 3 inputs are unobservable inputs for the asset or liability, and include situations where there is little, if any, market activity for the asset or liability. Assets carried at fair value and included in this category are certain financial derivatives, additions to our asset retirement obligations, and assets acquired through a non-monetary exchange transaction.

See Note 5 for additional information regarding our fair value measurements.

Asset retirement obligations

We record the fair value of a liability for an asset retirement obligation in the period in which it is incurred and a corresponding increase in the carrying amount of oil and natural gas properties. The accretion of the asset retirement obligations is included in depreciation, depletion and amortization on the consolidated statements of operations. See Note 6 for additional information regarding our asset retirement obligations.

Environmental liabilities

We are subject to extensive federal, state and local environmental laws and regulations covering discharge of materials into the environment. Because these laws and regulations change regularly, we are unable to predict the conditions and other factors over which we do not exercise control that may give rise to environmental liabilities affecting us. Environmental expenditures that relate to an existing condition caused by past operations and that do not contribute to current or future revenue generation are expensed. Liabilities are accrued when environmental assessments and/or clean-ups are probable, and the costs can be reasonably estimated. As of December 31, 2012 and 2011, we have not accrued for or been fined or cited for any environmental violations which would have a material adverse effect upon our financial position, operating results, or cash flows.

Sale of common stock

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 $313,231, net of fees and other expenses of $11,769, and were used to repay the amounts owing under our Seventh Restated Credit Agreement (our “prior credit facility”).

F-12

Revenue recognition

Oil revenue is recognized when the product is delivered to the purchaser and natural gas revenue when delivered to the gas purchaser’s sales meter. Well supervision fees and overhead reimbursements from producing properties are recognized as expense reimbursements from outside interest owners when the services are performed. Sales of products or services are recognized at the time of delivery of materials or performance of service.

Gas balancing

In certain instances, the owners of the natural gas produced from a well will select different purchasers for their respective ownership interest in the wells. If one purchaser takes more than its rateable portion of the gas, the owners selling to that purchaser will be required to satisfy the imbalance in the future by cash payments or by allowing the other owners to sell more than their share of production. We recognize gas imbalances on the sales method and, accordingly, have recognized revenue on all production delivered to our purchasers. To the extent future reserves exist to enable the other owners to sell more than their rateable share of gas, no liability is recorded for our obligation for natural gas taken by our purchasers which exceeds our ownership interest of the well’s total production. As of December 31, 2012 and 2011, our aggregate imbalance due to under production was approximately 2,690 MMcf and 2,860 MMcf , respectively. As of December 31, 2012 and 2011, our aggregate imbalance due to over production was approximately 1,658 MMcf and 1,802 MMcf, respectively, and a liability for gas imbalances of $1,984 and $1,819, respectively, was included in accounts payable and accrued liabilities.

Stock-based compensation

Our stock-based compensation programs consist of phantom stock, restricted stock units (“RSU”), and restricted stock awards issued to employees. Generally, we use new shares to grant restricted stock awards, and we cancel restricted shares forfeited or repurchased for tax withholding. Canceled shares are available to be issued as new grants under our 2010 Equity Incentive Plan.

The estimated fair value of the phantom stock and RSU awards are remeasured at the end of each reporting period until settlement. The estimated fair market value of these awards is calculated based on our total asset value less total liabilities, with both assets and liabilities being adjusted to fair value in accordance with the terms of the Phantom Stock Plan and the Non-Officer Restricted Stock Unit Plan. The primary adjustment required is the adjustment of oil and natural gas properties from net book value to the discounted and risk-adjusted reserve value based on internal reserve reports priced on NYMEX forward strips. Compensation cost associated with the phantom stock awards and RSU awards is recognized over the vesting period using the straight-line method and the accelerated method, respectively.

The fair value of our restricted stock awards that include a service condition is based upon the estimated fair market value of our common equity per share on a minority, non-marketable basis on the date of grant, and is remeasured at the end of each reporting period until settlement. We recognize compensation cost over the requisite service period using the accelerated method for awards with graded vesting.

We use a Monte Carlo model to estimate the grant date fair value of restricted stock awards that include a market condition. This model includes various significant assumptions, including the expected volatility of the share awards and the probabilities of certain vesting conditions. Compensation cost associated with restricted stock awards that include a market condition is recognized over the requisite service period using the straight-line method.

The assumptions used to value our stock-based compensation awards reflect our best estimates, but they involve inherent uncertainties based on market conditions generally outside of our control. As a result, if other assumptions had been used, stock-based compensation expense could have been significantly impacted.

The costs associated with our stock-based compensation programs is calculated net of forfeitures, which are estimated based on our historical and expected turnover rates. If our actual forfeiture rate is materially different from our estimate, the stock-based compensation cost could be different from what we have recorded in the current period.

See Note 8 for additional information relating to stock-based compensation.

Recently adopted and issued accounting pronouncements

In May 2011, the FASB issued authoritative guidance that clarifies the application of fair value measurement and disclosure requirements and changes particular principles or requirements for measuring fair value. This guidance is effective for interim and annual periods beginning after December 15, 2011, and we adopted it on January 1, 2012. There was no significant impact on our consolidated financial statements other than additional disclosures.

F-13

In June 2011, the FASB issued new authoritative guidance that requires entities that report other comprehensive income to present the components of net income and comprehensive income in either one continuous financial statement or two consecutive financial statements. It does not change the items that must be reported in other comprehensive income or when an item of other comprehensive income must be reclassified to net income. This guidance is effective for interim and annual periods beginning after December 15, 2011, and we applied it retrospectively beginning on January 1, 2012. We have elected to present the components of net income and comprehensive income in two consecutive financial statements.

In July 2011, the FASB issued authoritative guidance regarding how health insurers should recognize and classify in their income statements the fees mandated by the Health Care and Education Reconciliation Act (“HCERA”). The HCERA imposes an annual fee upon health insurers for each calendar year beginning on or after January 1, 2014. The annual fee will be allocated to individual entities providing health insurance to employees based on a ratio, as provided for in the HCERA, and is not tax deductible. This guidance specifies that once the entity has provided qualifying health insurance in the calendar year in which the fee is payable, the liability for the entity’s fee should be estimated and recorded in full with a corresponding deferred cost that is amortized to expense on a straight line basis, unless another method better allocates the fee over the calendar year that it is payable. This guidance is effective for calendar years beginning after December 15, 2013, once the fee is instituted. We are currently assessing the impact that this fee and the adoption of the related authoritative guidance will have on our financial statements.

In December 2011, the FASB issued authoritative guidance requiring entities to provide enhanced disclosures that will enable users of its financial statements to evaluate the effect or potential effect of netting arrangements on an entity’s financial position. The guidance is effective for interim and annual periods beginning on or after January 1, 2013. We will adopt the requirements with the preparation of our Form 10-Q for the quarter ending March 31, 2013, which will require additional footnote disclosures for our derivative instruments and are not expected to have a material effect on our consolidated financial statements.

Note 2: Supplemental disclosures to the consolidated statements of cash flows

Supplemental disclosures to the consolidated statements of cash flows are presented below:

	Year ended December 31,
	2012			2011			2010
Net cash provided by operating activities included:
Cash payments for interest	$	103,350		$	85,222		$	67,529
Interest capitalized		(4,437	)		(2,379	)		(2,036	)
Cash payments for interest, net of amounts capitalized	$	98,913		$	82,843		$	65,493
Cash (receipts) payments for income taxes	$	255		$	179		$	(21	)
Non-cash investing activities included:
Asset retirement costs capitalized	$	1,079		$	2,522		$	1,488
Oil and natural gas properties acquired through increase (decrease) in accounts payable and accrued liabilities	$	24,280		$	(14,667	)	$	25,773
Non-cash financing activities included:
Modification of Time Vesting equity awards to liability plan	$	—		$	2,640		$	—

F-14

Note 3: Property and equipment

Major classes of property and equipment consist of the following at December 31:

	2012		2011
Furniture and fixtures	$	2,327	$	2,115
Automobiles and trucks		13,618		12,966
Machinery and equipment		52,326		59,190
Office and computer equipment		10,603		8,823
Building and improvements		26,051		22,758
		104,925		105,852
Less accumulated depreciation and amortization		46,080		45,500
		58,845		60,352
Land		6,756		5,359
	$	65,601	$	65,711

Property and equipment leased under capital leases, which are included in the above amounts, consist of the following at December 31:

	2012		2011
Office and computer equipment	$	1,926	$	1,926
Machinery and equipment		642		642
		2,568		2,568
Less accumulated depreciation and amortization		2,241		2,175
	$	327	$	393

Note 4: Long-term debt

As of the dates indicated, long-term debt consists of the following:

	December 31,
	2012		2011
8.875% Senior Notes due 2017, net of discount of $0 and $1,658, respectively	$	—	$	323,342
9.875% Senior Notes due 2020, net of discount of $5,969 and $6,441, respectively		294,031		293,559
8.25% Senior Notes due 2021		400,000		400,000
7.625% Senior Notes due 2022, including premium of $6,631 and $0, respectively		556,631		—
Senior secured revolving credit facility		25,000		—
Real estate mortgage notes, principal and interest payable monthly, bearing interest at rates ranging from 2.54% to 5.46%, due January 2013 through December 2028; collateralized by real property		12,596		12,116
Installment notes payable, principal and interest payable monthly, bearing interest at rates ranging from 2.00% to 6.99%, due January 2013 through October 2017; collateralized by automobiles, machinery and equipment		5,144		5,546
Capital lease obligations		—		10
		1,293,402		1,034,573
Less current maturities		3,746		3,078
	$	1,289,656	$	1,031,495

F-15

On March 27, 2013, we committed to borrow an additional $20,000 under our senior secured revolving credit facility and will receive the funds on April 1, 2013.

Maturities of long-term debt and capital leases, excluding premiums or discounts on our Senior Notes, are as follows as of December 31, 2012:

2013	$	3,746
2014		2,098
2015		1,473
2016		732
2017		25,646
2018 and thereafter		1,259,045
	$	1,292,740

Senior Notes

On May 2, 2012, we issued $400,000 aggregate principal amount of 7.625% Senior Notes maturing on November 15, 2022. We used the net proceeds from the May 2, 2012 7.625% Senior Notes issuance to consummate a tender offer for all of our 8.875% Senior Notes due 2017, to redeem the 8.875% Senior Notes not purchased in the tender offer, and for general corporate purposes. Interest is payable on the 7.625% Senior Notes semi-annually on May 15 and November 15 each year beginning November 15, 2012. On or after May 15, 2017, we may, at our option, redeem the 7.625% Senior Notes at the following redemption prices plus accrued and unpaid interest: 103.813% after May 15, 2017; 102.542% after May 15, 2018; 101.271% after May 15, 2019; and 100% after May 15, 2020. Prior to May 15, 2015, we may redeem up to 35% of the 7.625% Senior Notes with the net proceeds of one or more equity offerings at a redemption price of 107.625%, plus accrued and unpaid interest. The initial $400,000 of 7.625% Senior Notes were exchanged for registered notes effective September 28, 2012.

On November 15, 2012, we issued an additional $150,000 aggregate principal amount of 7.625% Senior Notes under the same indenture covering the issuance on May 2, 2012 (the “Add-on Notes”). The net proceeds from the additional 7.625% Senior Notes issuance were used to repay the outstanding balance of the indebtedness under our senior secured revolving credit facility and for general corporate purposes. In connection with the sale of the Add-on Notes, we entered into a registration rights agreement in which we agree to file a registration statement with the SEC related to an offer to exchange the Add-on Notes for an issue of registered notes within 270 days of the closing date (the “Target Registration Date”). If we fail to complete the exchange offer by the Target Registration 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-day period, up to a maximum of 1.0% per annum.

In connection with the issuance of the May 2, 2012 7.625% Senior Notes, we capitalized approximately $8,778 of issuance costs related to underwriting and other fees that are amortized to interest expense using the effective interest method. In connection with the issuance of the November 15, 2012 Add-on Notes, we recorded a premium of $6,750 and capitalized $3,485 of issuance costs related to underwriting and other fees that are amortized to interest expense using the effective interest method. Amortization of $119 was netted against interest expense during the year ended December 31, 2012 related to the premium and amortization of $419 was charged to interest expense during the year ended December 31, 2012 related to the issuance costs. Unamortized issuance costs of $11,844 were included in “Other assets” as of December 31, 2012.

During 2012, we recorded a $21,714 loss associated with the refinancing of our 8.875% Senior Notes, including $15,827 in repurchase or redemption-related fees and a $5,887 write-off of deferred financing costs and unaccreted discount.

On February 22, 2011, we issued $400,000 aggregate principal amount of 8.25% senior notes maturing on September 1, 2021. The net proceeds, after underwriting and issuance costs, were used 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. Interest is payable on the 8.25% senior notes semi-annually on March 1 and September 1 each year beginning September 1, 2011. On or after September 1, 2016, we may, at our option, redeem the notes at the following redemption prices plus accrued and unpaid interest: 104.125% after September 1, 2016, 102.750% after September 1, 2017, 101.375% after September 1, 2018, and 100% after September 1, 2019. Prior to March 1, 2014, we may redeem up to 35% of the notes with the net proceeds of one or more equity offerings at a redemption price of 108.250%, plus accrued and unpaid interest.

In connection with the issuance of the 8.25% Senior Notes, we capitalized $8,785 of issuance costs related to underwriting and other fees that are amortized to interest expense using the effective interest method. Unamortized issuance costs of $7,750 and $8,329 were included in “Other assets” as of December 31, 2012 and 2011, respectively. Amortization of $579 and $456 was charged to interest expense during the year ended December 31, 2012 and 2011, respectively.

F-16

During the year ended December 31, 2011, we recorded a $20,592 loss associated with the refinancing of our 8.5% senior notes due 2015, including $15,101 in repurchase or redemption-related fees and a $5,491 write-off of deferred financing costs.

On September 16, 2010, we issued $300,000 of 9.875% senior notes due 2020 at a price of 97.672% of the principal amount. The net proceeds, after underwriting and issuance costs, were used to pay down the outstanding indebtedness under our revolving line of credit and for working capital. Interest is payable on the senior notes semi-annually on April 1 and October 1 each year beginning April 1, 2011. The notes mature on October 1, 2020. On or after October 1, 2015, we may, at our option, redeem the notes at the following redemption prices plus accrued and unpaid interest: 104.938% after October 1, 2015, 103.292% after October 1, 2016, 101.646% after October 1, 2017, and 100% after October 1, 2018 and thereafter. Prior to October 1, 2013, we may redeem up to 35% of the notes with the net proceeds of one or more equity offerings at a redemption price of 109.875%, plus accrued and unpaid interest.

In connection with the issuance of the 9.875% senior notes, we recorded a discount of $6,984 and capitalized $6,796 of issuance costs related to underwriting and other fees that are amortized to interest expense using the effective interest method. Unamortized issuance costs of $5,816 and $6,275 were included in “Other assets” as of December 31, 2012 and 2011, respectively. Accretion of $472, $424, and $119 was charged to interest expense during the years ended December 31, 2012, 2011, and 2010, respectively, related to the discount, and amortization of $459, $409, and $112 was charged to interest expense during the years ended December 31, 2012, 2011, and 2010, respectively, related to the issuance costs.

On January 18, 2007, we issued $325,000 of 8.875% senior notes due 2017 at a price of 99.178% of the principal amount. The net proceeds, after underwriting and issuance costs, were used to reduce outstanding indebtedness under our revolving line of credit and for working capital. Interest on the notes is payable semi-annually on February 1 and August 1 each year beginning August 1, 2007, and the notes mature on February 1, 2017. These notes were repurchased or redeemed upon issuance of the 7.625% Senior Notes maturing on November 15, 2022 issued May 2, 2012.

In connection with the issuance of the 8.875% senior notes, we recorded a discount of $2,671 and capitalized $7,316 of issuance costs related to underwriting and other fees that are amortized to interest expense using the effective interest method. Unamortized issuance costs of $0 and $4,552 were included in “Other assets” as of December 31, 2012 and 2011, respectively. Accretion of $86, $243, and $222 was charged to interest expense during the years ended December 31, 2012, 2011, and 2010, respectively, related to the discount, and amortization of $237, $669, and $609 was charged to interest expense during the years ended December 31, 2012, 2011, and 2010, respectively, related to the issuance costs.

The indentures governing our 9.875% senior notes due 2020, and our 8.25% senior notes due 2021, and our 7.625% senior notes due 2022 (collectively, our “Senior Notes”) contain certain covenants which limit our ability to:

• 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 debt;

• make investments;

• incur liens on assets;

• create restrictions on the ability of our restricted subsidiaries to pay dividends, make loans, or transfer property to us;

• engage in transactions with 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.

Chaparral Energy, Inc. is a holding company and owns no operating assets and has no significant operations independent of its subsidiaries. Our obligations under our outstanding Senior Notes have been fully and unconditionally guaranteed, on a joint and several basis, by all of our wholly owned subsidiaries except for Oklahoma Ethanol, LLC and Chaparral Biofuels, LLC.

F-17

Senior secured revolving credit facility

In April 2010, we entered into an Eighth Restated Credit Agreement (our “senior secured revolving credit facility”), which is collateralized by our oil and natural gas properties and, as amended, matures on November 1, 2017. 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 Seventh Restated Credit Agreement. During the year ended December 31, 2010, we wrote off deferred financing costs associated with the refinancing of our Seventh Restated Credit Agreement of $2,241, and we recorded deferred financing costs associated with the closing of our senior secured revolving credit facility of $10,909. The Eighth Amendment to our senior secured revolving credit facility, effective April 30, 2012, amended our Asset Sale Covenant to permit the sale of certain oil and natural gas properties located in southern Oklahoma and increased our permitted ratio of Consolidated Net Debt to Consolidated EBITDAX. The Ninth Amendment to our senior secured revolving credit facility, effective May 24, 2012, amended the calculation of Consolidated EBITDAX to permit the exclusion of our reasonable and customary fees related to the refinancing of our 8.875% Senior Notes. The Tenth Amendment to our senior secured revolving credit facility, effective November 1, 2012, increased our borrowing base from $375,000 to $500,000; increased the Aggregate Maximum Credit Amount from $450,000 to $750,000 and the maximum Aggregate Maximum Credit Amount (after giving effect to any exercise of the accordion option on the terms and conditions set forth in the senior secured revolving credit facility) to $850,000; extended the maturity date to November 1, 2017; reduced the applicable margins added to the Adjusted LIBO Rate for the purposes of determining the interest rate (i) on Eurodollar loans to a margin ranging from 1.50% to 2.50% and (ii) on ABR loans to a margin ranging from 0.50% to 1.50%, each depending on the utilization percentage of the conforming borrowing base; reduced commitment fees to 0.375% if less than 50% of the borrowing base is utilized; reaffirmed the borrowing base through May 1, 2013 and permitted the offering of the Add-on Notes without triggering the automatic 25% reduction of the borrowing base.

Amounts borrowed under our senior secured revolving credit facility are subject to varying rates of interest based on (1) the total outstanding borrowings in relation to the borrowing base (the “utilization percentage”) and (2) whether we elect to borrow at the Eurodollar rate or the Alternate Base Rate (“ABR”). The entire balance outstanding at December 31, 2012 was subject to the Eurodollar rate.

The Eurodollar rate 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 that varies depending on our utilization percentage. During 2012, the margin varied from 1.50% to 2.75%. 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 loans subject to the ABR 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 0.50%, or (3) the Adjusted LIBO Rate, as defined in our senior secured revolving credit facility, plus 1%, plus a margin that varies depending on our utilization percentage. During 2012, the margin varied from 0.50% to 1.75%.

Commitment fees of 0.375% to 0.50% accrue on the unused portion of the borrowing base amount, based on the utilization percentage, 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;

F-18

• 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, as amended, also has certain negative and affirmative covenants that require, among other things, maintaining a Current Ratio, as defined in our senior secured revolving credit facility, of not less than 1.0 to 1.0 and 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 each period of four consecutive fiscal quarters ending on the last day of such applicable fiscal quarter.

The First Amendment to our senior secured revolving credit facility, dated July 26, 2010, modified the definition of Consolidated EBITDAX 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 $4,500 in one-time cash expenses associated with our financing transactions that were incurred and paid during the second quarter of 2010.

The Fourth Amendment to our senior secured revolving credit facility, effective April 1, 2011, amended the definition of Consolidated EBITDAX to permit the exclusion of our reasonable and customary fees and expenses related to the refinancing of our 8.5% Senior Notes due 2015 from the calculation of Consolidated EBITDAX.

We believe we were in compliance with all covenants under our senior secured revolving credit facility as of December 31, 2012.

Our senior secured revolving credit facility also specifies events of default, including non-payment, breach of warranty, non-performance of financial covenants, default on other indebtedness, certain adverse judgments, and change of control, among others. In addition, bankruptcy and insolvency events with respect to us or certain of our subsidiaries will result in an automatic acceleration of the indebtedness under our senior secured revolving credit facility. An acceleration of our indebtedness under our senior secured revolving credit facility could in turn result in an event of default under the indentures for our Senior Notes, which in turn could result in the acceleration of the Senior Notes.

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.

Note 5: Derivative activities and fair value measurements

Overview

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. See Note 1 for additional information regarding our accounting policies for derivative transactions and fair value measurements.

For commodity price swaps, we receive a fixed price for the hedged commodity and pay a floating market price to the counterparty. The fixed-price payment and the floating-price payment are netted, resulting in a net amount due to or from the counterparty.

Collars contain a fixed floor price (put) and ceiling price (call). If the market price exceeds the call strike price or falls below the put strike price, we receive the fixed price and pay the market price. If the market price is between the call and the put strike price, no payments are due from either party. A three-way collar contract consists of a standard collar contract plus a put option contract sold by us with a price below the floor price of the collar. This additional put option requires us to make a payment to the counterparty if the market price is below the additional put option price. If the market price is greater than the additional put option price, the result is the same as it would have been with a standard collar contract only. By combining the collar contract with the additional put option, we are entitled to a net payment equal to the difference between the floor price of the standard collar and the additional put option price if the market price falls below the additional put option price. This strategy enables us to increase the floor and the ceiling price of the collar beyond the range of a traditional costless collar while defraying the associated cost with the sale of the additional put option.

F-19

We use basis protection swaps to reduce basis risk. Basis is the difference between the physical commodity being hedged and the price of the futures contract used for hedging. Basis risk is the risk that an adverse change in the futures market will not be completely offset by an equal and opposite change in the cash price of the commodity being hedged. Basis risk exists in natural gas primarily due to the geographic price differentials between cash market locations and futures contract delivery locations. Natural gas basis protection swaps are arrangements that guarantee a price differential for natural gas from a specified pricing point. We receive a payment from the counterparty if the price differential is greater than the stated terms of the contract and pay the counterparty if the price differential is less than the stated terms of the contract.

In December 2011, we amended our senior secured revolving credit facility to provide greater flexibility when hedging our anticipated production. The terms of the amendment allow us to protect a portion of our natural gas liquids production from price volatility using crude oil derivatives. Our outstanding derivative instruments as of December 31, 2012 are summarized below:

	Oil derivatives
	Swaps				Three-way collars
	Volume MBbls						Weighted average fixed price per Bbl
			Weighted average  fixed price per Bbl		Volume MBbls		Additional put option		Put		Call
2013		1,020	$	96.78		3,710	$	77.88	$	99.94	$	114.26
2014		—		—		1,320		75.91		92.54		103.08
		1,020				5,030

	Natural gas swaps				Natural gas basis protection swaps
	Volume BBtu		Weighted average fixed  price per MMBtu		Volume BBtu		Weighted average fixed  price per MMBtu
2013		16,800	$	4.31		16,400	$	0.20
2014		8,400		3.95		14,090		0.23
		25,200				30,490

Discontinuance of cash flow hedge accounting

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 statements 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, 2012, AOCI consists of deferred net gains of $37,134 ($23,223 net of tax) that will be recognized as gains from oil and natural gas hedging activities through December 2013 as the hedged production is sold.

F-20

Derivative activities

Gains and losses associated with cash flow hedges are summarized below.

	Year ended December 31,
	2012			2011			2010
Amount of loss recognized in AOCI (effective portion)
Oil swaps	$	—		$	—		$	(1,034	)
Income taxes		—			—			386
	$	—		$	—		$	(648	)
Amount of gain (loss) reclassified from AOCI in income (effective portion)(1)
Oil swaps	$	46,746		$	(27,452	)	$	(30,243	)
Natural gas swaps					—			1,510
Income taxes		(18,123	)		10,580			10,729
	$	28,623		$	(16,872	)	$	(18,004	)
Loss on oil swaps recognized in income (ineffective portion)(1)	$	—		$	—		$	(660	)

(1) Included in “Gain (loss) from oil and natural gas hedging activities” in our consolidated statements of operations.

“Gain (loss) from oil and natural gas hedging activities,” which is a component of total revenues in the consolidated statements of operations, consists of the reclassification of hedge gains (losses) on discontinued oil hedges into income and is comprised of the following:

	Year ended December 31,
	2012		2011			2010
Oil hedges
Reclassification adjustment for hedge gains (losses) included in net income	$	46,746	$	(27,452	)	$	(30,243	)
Loss on ineffective portion of derivatives qualifying for hedge accounting		—		—			(660	)
Natural gas hedges
Reclassification adjustment for hedge gains included in net income		—		—			1,510
	$	46,746	$	(27,452	)	$	(29,393	)

During 2010, we received proceeds of $7,097 on the early settlement of certain oil and natural gas derivative contracts with original settlement dates from April 2010 through December 2012. The proceeds from early settlement are recorded as a component of “Non-hedge derivative gains” in the consolidated statements of operations.

F-21

“Non-hedge derivative gains” in the consolidated statements of operations are comprised of the following:

	Year ended December 31,
	2012			2011			2010
Change in fair value of commodity price swaps	$	(8,440	)	$	50,004		$	8,610
Change in fair value of costless collars		21,182			3,540			(24,846	)
Change in fair value of natural gas basis differential contracts		(331	)		4,355			9,341
Receipts from (payments on) settlement of commodity price swaps		28,716			(16,801	)		27,332
Receipts from settlement of costless collars		10,229			1,250			28,268
Payments on settlement of natural gas basis differential contracts		(1,671	)		(7,940	)		(10,110	)
	$	49,685		$	34,408		$	38,595

Fair value of derivative instruments

All derivative financial instruments are recorded on the balance sheet at fair value. We estimate the fair value of our derivative instruments using a combined income and market valuation methodology. Future cash flows from the derivatives are estimated based on the difference between the fixed contract price and the underlying published forward market price, and are discounted at the LIBOR swap rate. The fair value of collars is determined using an option pricing model which takes into account market volatility as well as the inputs described above. All derivative instruments are discounted further using a rate that incorporates our nonperformance risk for derivative liabilities and our counterparties’ nonperformance risk for derivative assets. As of December 31, 2012 and 2011, the rate reflecting our nonperformance risk was 1.50% and 1.75%, respectively, and the weighted-average rate reflecting our counterparties’ nonperformance risk was approximately 0.32% and 3.38%, respectively.

The estimated fair values of derivative instruments are provided below. The carrying amounts of these instruments are equal to the estimated fair values.

	As of December 31, 2012								As of December 31, 2011
	Assets		Liabilities			Net value			Assets		Liabilities			Net value
Derivatives not designated as hedging instruments:
Natural gas swaps	$	13,642	$	(1,487	)	$	12,155		$	30,124	$	—		$	30,124
Oil swaps		4,957		(1,339	)		3,618			3,832		(9,744	)		(5,912	)
Oil collars		27,411		(1,180	)		26,231			6,296		(1,247	)		5,049
Natural gas basis differential swaps		—		(1,599	)		(1,599	)		—		(1,268	)		(1,268	)
Total derivative instruments		46,010		(5,605	)		40,405			40,252		(12,259	)		27,993
Less:
Netting adjustments (1)		2,977		(2,977	)		—			10,627		(10,627	)		—
Current portion asset (liability)		42,516		(436	)		42,080			12,840		(1,505	)		11,335
	$	517	$	(2,192	)	$	(1,675	)	$	16,785	$	(127	)	$	16,658

(1) Amounts represent the impact of master netting agreements that allow us to net settle positive and negative positions with the same counterparty.

Derivative settlements outstanding were as follows at December 31:

	2012		2011
Derivative settlements receivable included in accounts receivable	$	8,013	$	449
Derivative settlements payable included in accounts payable and accrued liabilities	$	41	$	5,042

F-22

We have no Level 1 assets or liabilities as of December 31, 2012 or 2011. Our derivative contracts classified as Level 2 are valued using NYMEX forward commodity price curves and quotations provided by price index developers such as Platts. In certain less liquid markets, forward prices are not as readily available. In these circumstances, commodity swaps are valued using internally developed methodologies that consider historical relationships among various commodities that result in management’s best estimate of fair value. These contracts are classified as Level 3. Due to unavailability of observable volatility data input, the fair value measurement of all our collars has been categorized as Level 3.

The fair value hierarchy for our financial assets and liabilities is shown by the following table:

	As of December 31, 2012								As of December 31, 2011
	Derivative assets			Derivative liabilities			Net assets (liabilities)		Derivative assets			Derivative liabilities			Net assets (liabilities)
Significant other observable inputs (Level 2)	$	18,599		$	(4,425	)	$	14,174	$	33,956		$	(11,012	)	$	22,944
Significant unobservable inputs (Level 3)		27,411			(1,180	)		26,231		6,296			(1,247	)		5,049
Netting adjustments (1)		(2,977	)		2,977			—		(10,627	)		10,627			—
	$	43,033		$	(2,628	)	$	40,405	$	29,625		$	(1,632	)	$	27,993

(1) Amounts represent the impact of master netting agreements that allow us to net settle positive and negative positions with the same counterparty.

Changes in the fair value of net commodity derivatives classified as Level 3 in the fair value hierarchy at December 31 were:

	For the year ended December 31,
Net derivative assets	2012			2011
Beginning balance	$	5,049		$	1,509
Realized and unrealized gains included in “Non-hedge derivative gains”		31,411			4,790
Settlements received		(10,229	)		(1,250	)
Ending balance	$	26,231		$	5,049
Gains relating to assets still held at the reporting date included in “Non-hedge derivative gains” for the period	$	21,534		$	5,049

Fair value of other financial instruments

The carrying values of items comprising current assets and current liabilities approximate fair values due to the short-term maturities of these instruments. The carrying value for long-term debt at December 31, 2012 and 2011 approximates fair value because the rates are comparable to those at which we could currently borrow under similar terms. The carrying value and estimated market value of our Senior Notes at December 31, 2012 and 2011 were as follows:

	December 31, 2012				December 31, 2011
	Carrying value		Estimated fair value		Carrying value		Estimated fair value
8.875% Senior Notes due 2017	$	—	$	—	$	323,342	$	326,625
9.875% Senior Notes due 2020		294,031		341,250		293,559		322,500
8.25% Senior Notes due 2021		400,000		434,000		400,000		402,400
7.625% Senior Notes due 2022		556,631		574,750		—		—
	$	1,250,662	$	1,350,000	$	1,016,901	$	1,051,525

Fair value amounts have been estimated based on quoted market prices. The use of different market assumptions or valuation methodologies may have a material effect on the estimated fair value amounts.

F-23

Concentrations of credit risk

Financial instruments which potentially subject us to concentrations of credit risk consist principally of derivative instruments and accounts receivable. Derivative instruments are exposed to credit risk from counterparties. We do not require collateral or other security to support the derivative instruments subject to credit risk, however, our derivative contracts have been executed with the institutions that are affiliates of our lenders, and we believe the credit risks associated with all of these institutions are acceptable. At December 31, 2012, we had significant commodity derivative net asset balances outstanding with the following counterparties:

	Percentage of future hedged
Counterparty	production
JP Morgan Chase Bank, N.A.		33	%
Societe Generale		16	%
Royal Bank of Canada		14	%
Wells Fargo		7	%
Bank of Nova Scotia		7	%
Macquarie Bank Limited		6	%
		83	%

We did not post collateral under any of our derivative contracts as they are secured under our senior secured revolving credit facility. As of December 31, 2012, we had $25,000 outstanding under our senior secured revolving credit facility. Payment on our derivative contracts would be accelerated in the event of a default on our revolving credit facility. The aggregate fair value of our derivative liabilities was $5,605 at December 31, 2012.

Accounts receivable are primarily from purchasers of oil and natural gas products, and exploration and production companies who own interests in properties we operate. The industry concentration has the potential to impact our overall exposure to credit risk, either positively or negatively, in that customers may be similarly affected by changes in economic, industry or other conditions.

Sales of oil and natural gas to three purchasers accounted for 19.6%, 13.9% and 12.7% of total oil and natural gas revenues, excluding the effects of hedging activities, during the year ended December 31, 2012. Sales of oil and natural gas to three purchasers accounted for 15.1%, 13.6% and 10.4% of total oil and natural gas revenues, excluding the effects of hedging activities, during the year ended December 31, 2011. Sales of oil and natural gas to one purchaser accounted for 20.3% of total oil and natural gas revenues, excluding the effects of hedging activities, during the year ended December 31, 2010. If we were to lose a purchaser, we believe we could replace it with a substitute purchaser.

Note 6: Asset retirement obligations

Our asset retirement obligations consist of the estimated present value of future costs to plug and abandon or otherwise dispose of our oil and natural gas properties and related facilities. Significant inputs used in determining such obligations include estimates of plugging and abandonment costs, inflation rates, discount rates, and well life, all of which are Level 3 inputs according to the fair value hierarchy. The estimated future costs to dispose of properties added during the years ended December 31, 2012 and 2011 were escalated using an annual inflation rate of 2.95% in each period, and discounted using our credit-adjusted risk-free interest rate of approximately 7.1% and 8.6%, respectively. These estimates may change based upon future inflation rates and changes in statutory remediation rules. See Note 1 for additional information regarding our accounting policies for fair value measurements.

F-24

The following table provides a summary of our asset retirement obligation activity during the years ended December 31, 2012 and 2011.

	For the year ended December 31,
	2012			2011
Beginning balance	$	46,493		$	41,695
Liabilities incurred in current period		1,079			2,522
Liabilities settled in current period		(2,303	)		(1,354	)
Accretion expense		3,945			3,630
		49,214			46,493
Less current portion		2,900			2,900
	$	46,314		$	43,593

We have funds held in escrow that are legally restricted for certain of our asset retirement obligations. The balance of this escrow account was $1,631 and $1,653 at December 31, 2012 and 2011, respectively, and is included in “Other assets” in our consolidated balance sheets. We are entitled to make quarterly withdrawals from the plugging escrow account equal to one-half of the interest earnings for the period and as reimbursement for actual plugging and abandonment expenses incurred on the North Burbank Unit, provided that written documentation has been provided. The balance is not intended to reflect our total future financial obligation for the plugging and abandonment of these wells.

Note 7: Income taxes

Income tax expense (benefit) consists of the following for the years ended December 31:

	2012			2011			2010
Current tax expense (benefit)
Federal tax benefit	$	(23	)	$	(21	)	$	(16	)
State tax expense		141			200			95
Current tax expense		118			179			79
Deferred tax expense
Federal tax expense		35,579			27,290			19,712
State tax expense		2,140			8,455			4,012
Deferred tax expense		37,719			35,745			23,724
	$	37,837		$	35,924		$	23,803

Income tax expense (benefit) differed from amounts computed by applying the U.S. Federal income tax rate as follows for the years ended December 31:

	2012			2011			2010
Statutory rate		35.0	%		35.0	%		35.0	%
State income taxes, net of federal benefit		2.1	%		3.6	%		5.5	%
Statutory depletion		(0.04	)%		(0.5	)%		(0.7	)%
Valuation allowance		—			7.3	%		—
Other		(0.04	)%		0.7	%		1.6	%
Effective tax rate		37.0	%		46.1	%		41.4	%

F-25

Components of the deferred tax assets and liabilities are as follows at December 31:

	2012			2011
Deferred tax assets related to
Asset retirement obligations	$	8,496		$	7,386
Accrued expenses, allowance and other		10,129			9,755
Net operating loss carryforwards
Federal		153,709			142,920
State		16,339			13,097
Statutory depletion carryforwards		2,242			2,107
Alternative minimum tax credit carryforwards		308			308
		191,223			175,573
Less valuation allowance		(11,858	)		(11,858	)
Deferred tax asset		179,365			163,715
Deferred tax liabilities related to
Derivative instruments		(32,438	)		(52,698	)
Property and equipment		(181,489	)		(125,737	)
Inventories		(1,211	)		(1,458	)
Deferred tax liability		(215,138	)		(179,893	)
Net deferred tax liability		(35,773	)		(16,178	)
Less net current deferred tax liability		(26,872	)		(23,704	)
Long-term deferred tax asset (liability)	$	(8,901	)	$	7,526

Approximately $33,066 and $28,699 of the current deferred tax liability at December 31, 2012 and 2011, respectively, relates to our short-term derivative instruments. Additionally, approximately $1,015 and $1,015 of the current deferred tax liability relates to asset retirement obligations at December 31, 2012 and 2011, respectively. At December 31, 2012 and 2011, taxes receivable of $245 and $56, respectively, are included in accounts receivable.

We have federal net operating loss carryforwards of approximately $439,000 at December 31, 2012, portions of which will begin to expire in 2018 if unused. At December 31, 2012, we have state net operating loss carryforwards of approximately $413,000, which will begin to expire in 2013. In addition, at December 31, 2012 we had tax percentage depletion carryforwards of approximately $6,400, which are not subject to expiration.

At December 31, 2012, approximately $300,000 of the state net operating loss carryforwards have been reduced by a valuation allowance based on our assessment that it is more likely than not that a portion will not be realized. No adjustment to the valuation allowance was recorded during 2012.

Realization of our deferred tax assets is dependent upon generating sufficient future taxable income. Although realization is not assured, we believe it is more likely than not that our deferred tax assets will be realized. The amount of our deferred tax assets considered realizable, however, could be reduced in the near-term if estimates of future taxable income are reduced.

F-26

Note 8: Stock-based compensation

Phantom Stock Plan and Restricted Stock Unit Plan

Effective January 1, 2004, we implemented a Phantom Unit Plan, which was revised on December 31, 2008 as the Second Amended and Restated Phantom Stock Plan (the “Plan”), to provide deferred compensation to certain key employees (the “Participants”). Phantom stock may be awarded to Participants in total up to 2% of the fair market value of the Company. No Participant may be granted, in the aggregate, more than 5% of the maximum number of phantom shares available for award. Under the Plan, awards vest on the fifth anniversary of the award date, but may also vest on a pro-rata basis following a Participant’s termination of employment with us due to death, disability, retirement or termination by us without cause. Also, phantom stock will vest if a change of control event occurs. Phantom shares are cash-settled within 120 days of the vesting date.

Effective March 1, 2012, we implemented a Non-Officer Restricted Stock Unit Plan (the “RSU Plan”) to create incentives to motivate Participants to put forth maximum effort toward the success and growth of the Company and to enable the Company to attract and retain experienced individuals who by their position, ability and diligence are able to make important contributions to the Company’s success. The RSU Plan is intended to replace the Phantom Plan. Although the Phantom Plan remains in effect, we do not expect to make any further awards under the Phantom Plan. Restricted stock units may be awarded to Participants in total up to 2% of the fair market value of the Company. Under the RSU Plan, awards generally vest in equal annual increments over a three-year period. RSU awards may also vest following a Participant’s termination of employment in combination with the occurrence of a change of control event, as specified in the RSU Plan. RSU awards are cash-settled, generally within 120 days of the vesting date.

The estimated fair market value of phantom stock and RSU awards is calculated based on our total asset value less total liabilities, with both assets and liabilities being adjusted to fair value in accordance with the terms of the Plans. The primary adjustment required is the adjustment of oil and natural gas properties from net book value to the discounted and risk adjusted reserve value based on internal reserve reports priced on NYMEX forward strips.

A summary of our phantom stock and RSU activity during the three years ended December 31, 2012 is presented in the following table:

	Phantom Plan							RSU Plan
	Weighted average grant date fair value		Phantom shares			Vest date fair value		Weighted average grant date fair value		Restricted Stock Units
	(per share)							(per share)
Unvested and outstanding at January 1, 2010	$	12.77		175,482				$	—		—
Granted	$	23.93		18,841				$	—		—
Vested	$	9.17		(59,652	)	$	1,442	$	—		—
Forfeited	$	13.63		(7,812	)			$	—		—
Unvested and outstanding at December 31, 2010	$	16.04		126,859				$	—		—
Granted	$	18.55		37,316				$	—		—
Vested	$	17.91		(17,064	)		309	$	—		—
Forfeited	$	16.98		(21,343	)			$	—		—
Unvested and outstanding at December 31, 2011	$	16.37		125,768				$	—		—
Granted	$	—		—				$	17.07		177,026
Vested	$	14.38		(26,908	)		431	$	—		—
Forfeited	$	17.18		(14,096	)			$	16.80		(25,117	)
Unvested and outstanding at December 31, 2012	$	16.87		84,764				$	17.12		151,909

Payments for phantom shares totaled $434, $306, and $1,445 in 2012, 2011, and 2010, respectively. Based on an estimated fair value of $12.86 per phantom share and RSU as of December 31, 2012, the aggregate intrinsic value of the unvested phantom shares and RSUs outstanding was $3,044.

2010 Equity Incentive Plan

We adopted the Chaparral Energy, Inc. 2010 Equity 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 Affiliated Entities’ employees, officers, directors, and consultants, as defined in the 2010 Plan, are eligible to participate in the 2010 Plan. The awards granted under the 2010 Plan consist of shares that are subject to service vesting conditions (the “Time Vested” awards) and shares that are subject to market and Performance Vested conditions (the “Performance Vested” awards).

F-27

The Time Vested awards vest in equal annual installments over the five year vesting period. In the event of a transaction whereby CCMP receives cash upon the sale of its class E common stock (a “Transaction” as defined in the restricted stock agreements), vesting of the Time Vested awards will be accelerated with respect to the fraction obtained by dividing (x) the number of shares of common stock sold pursuant to the Transaction, by (y) the 504,276 shares of class E common stock owned by CCMP on April 12, 2010 (the “Vesting Fraction”). All other shares will remain subject to the normal vesting schedule. Since we believe the occurrence of a Transaction is probable, compensation cost is recognized over the derived service period associated with the accelerated vesting provision.

The Performance Vested awards vest in the event of a Transaction, as defined in the agreements, whereby CCMP’s net proceeds from the Transaction yield certain target returns on investment, as shown in the following table:

Return on investment target	Shares vested
200% per share	20% of shares multiplied by the Vesting Fraction
250% per share	40% of shares multiplied by the Vesting Fraction
300% per share	60% of shares multiplied by the Vesting Fraction
350% per share	80% of shares multiplied by the Vesting Fraction
400% per share	100% of shares multiplied by the Vesting Fraction

Since we believe the occurrence of a Transaction is probable, compensation cost is recognized over the derived service period.

The estimated fair value of our common equity per share, after a 23% discount for lack of control and a 22% discount for lack of marketability, was considered to be the fair value of the Time Vested awards granted during 2012. A combined income and market valuation methodology was used to estimate the fair value of our common equity per share. The estimated fair value of our common equity per share, after a 23% discount for lack of control and a 20% discount for lack of marketability, was considered to be the fair value of the Time Vested awards granted during 2011. The price paid by CCMP for our class E common stock on April 12, 2010, was considered to be the fair value of the Time Vested awards granted during 2010.

The Monte Carlo simulation method was used to value the Performance Vested awards. A Monte Carlo simulation allows for the analysis of a complex security through statistical measures applied to a model that is simulated thousands of times to build distributions of potential outcomes. The variables and assumptions used in this calculation were as follows:

	2012		2011		2010
Risk free interest rate		0.25% to 1.21%		0.29% to 3.04%		0.44% to 3.65%
Expected volatility		42% to 50%		45%		55%
Expected life		6 years		7 years		8 years
Expected dividends	$	—	$	—	$	—

Our expected volatility was calculated based on the average of the historical stock price volatility and the volatility implicit in the prices of the options or other traded financial instruments of our peer group. In 2012, our peer group consisted of Berry Petroleum Co., Concho Resources, Inc., Continental Resources, Inc., Denbury Resources, Inc., Pioneer Natural Resources Co., Sandridge Energy, Inc., Laredo Petroleum Holdings, Inc., and Whiting Petroleum Corp. In 2011, our peer group consisted of the following oil and gas exploration and production companies: Berry Petroleum Co., Concho Resources, Inc., Continental Resources, Inc., Denbury Resources, Inc., Encore Energy Partners, LP, Pioneer Natural Resources Co., Sandridge Energy, Inc., Venoco, Inc., and Whiting Petroleum Corp. In 2010, our expected volatility was calculated based on the average historical stock price volatility of our peer group, which consisted of the following oil and gas exploration and production companies: Berry Petroleum Co., Cabot Oil & Gas Corporation, Comstock Resources, Inc., Concho Resources, Inc., Continental Resources, Inc., Denbury Resources, Inc., Encore Energy Partners, LP, EXCO Resources, Inc., and Whiting Petroleum Corp.

Effective June 28, 2011, our board of directors modified the terms of the Time Vested awards to allow all participants in the 2010 Plan to elect, upon vesting of their Time Vested awards, to have us withhold shares having a fair market value greater than the minimum statutory withholding amounts for income and payroll taxes that would be due with respect to such vested shares. This modification changed the classification of the Time Vested awards from equity to liability awards and resulted in a reclassification from additional paid-in capital to stock-based compensation liabilities of $2,640. These awards are remeasured to fair value at the end of each reporting period. Because the modification did not affect the fair value of the awards or the number of awards expected to vest, no incremental compensation cost was recorded as a result of the modification.

F-28

Effective January 1, 2013, we amended and restated all outstanding Performance Vested awards to reflect that (i) those shares which would vest if CCMP receives net proceeds from a Transaction that yields a return of at least 400% per share were removed from the initial Performance Vested awards and an equal amount were granted effective as of January 1, 2013 under Time Vesting awards; and (ii) the remaining number of shares subject to the initial Performance Vested awards were reallocated among the five targets for vesting. These vesting targets will apply for any new grants of Performance Vested awards. Any shares of Performance Vested awards not vested on a Separation Date will be forfeited as of the Separation Date.

Return on Investment Target	Target Shares Vested
175% per share	20% of shares multiplied by the Vesting Fraction
200% per share	20% of shares multiplied by the Vesting Fraction
250% per share	20% of shares multiplied by the Vesting Fraction
300% per share	20% of shares multiplied by the Vesting Fraction
350% per share	20% of shares multiplied by the Vesting Fraction

A summary of our Time and Performance award activity during the three years ended December 31, 2012 is presented in the following table:

	Time Vested							Performance Vested
	Weighted average grant date fair value		Restricted shares			Vest date fair value		Weighted average grant date fair value		Restricted shares
	($ per share)							($ per share)
Unvested and outstanding at January 1, 2010	$	—		—				$	—		—
Granted	$	684.15		10,049				$	295.10		41,297
Vested	$	—		—		$	—	$	—		—
Forfeited	$	—		—				$	—		—
Unvested and outstanding at December 31, 2010	$	684.15		10,049				$	295.10		41,297
Granted	$	674.33		4,030				$	307.00		13,612
Vested	$	684.15		(2,010	)	$	1,351	$	—		—
Forfeited	$	684.15		(484	)			$	295.10		(1,811	)
Unvested and outstanding at December 31, 2011	$	680.74		11,585				$	298.15		53,098
Granted	$	572.70		2,444				$	394.00		15,050
Vested	$	681.41		(2,673	)	$	1,980	$	—		—
Forfeited	$	684.43		(1,875	)			$	295.96		(12,324	)
Unvested and outstanding at December 31, 2012	$	651.97		9,481				$	298.15		55,824

We repurchased and canceled 1,469 and 528 vested shares, primarily for tax withholding in 2012 and 2011, respectively, and we expect to repurchase approximately 1,000 restricted shares vesting during the next twelve months. Payments for Time Vested restricted shares totaled $952 and $355 in 2012 and 2011, respectively. Based on an estimated fair value of $626.00 per Time Vested restricted share as of December 31, 2012, the aggregate intrinsic value of the unvested Time Vested restricted shares outstanding was $5,935.

Stock-based compensation cost

A portion of stock-based compensation cost associated with employees involved in our acquisition, exploration, and development activities has been capitalized as part of our oil and natural gas properties. The remaining cost is reflected in lease operating and general and administrative expenses in the consolidated statements of operations. We recognized stock-based compensation expense as follows for the years ended December 31:

	2012			2011			2010
Stock-based compensation cost	$	4,982		$	6,042		$	3,980
Less: stock-based compensation cost capitalized		(1,917	)		(2,295	)		(1,380	)
Stock-based compensation expense	$	3,065		$	3,747		$	2,600
Recognized tax benefit associated with stock-based compensation	$	1,230		$	1,547		$	1,076

F-29

As of December 31, 2012 and 2011, accrued payroll and benefits payable included $2,636 and $2,359, respectively, for stock-based compensation costs expected to be settled within the next twelve months. Unrecognized stock-based compensation cost of approximately $7,497 is expected to be recognized over a weighted-average period of 2.3 years.

Note 9: Stockholders’ equity

On March 23, 2010, we entered into a Stock Purchase Agreement with CCMP, pursuant to which CCMP would purchase and we would sell 475,042 shares of our class E common stock, par value $0.01 per share, and one share of class F common stock, par value $0.01 per share, for a purchase price of $325,000. Fees and other expenses of the transaction were $11,769. The closing date of the Stock Purchase Agreement (the “Closing Date”) was April 12, 2010.

In connection with the execution of the Stock Purchase Agreement, on April 12, 2010, two of the three principal stockholders of the Company, Fischer Investments, L.L.C. (“Fischer”) and Altoma Energy GP (“Altoma”), each executed a stock purchase agreement with CCMP pursuant to which CCMP purchased from such stockholder 14,617 shares of Company common stock for a purchase price of $10,000.

Amended and Restated Certificate of Incorporation and Amended Bylaws

In connection with the execution of the Stock Purchase Agreement, we filed the Amended and Restated Certificate of Incorporation with the Delaware Secretary of State on April 12, 2010. The Amended and Restated Certificate of Incorporation creates seven classes of $0.01 par value per share common stock, classes A through G, with the rights and preferences summarized below. The class A common stock carries standard voting, dividend and liquidation rights. The class B, C and D common stock was issued to our existing stockholders, with a separate class issued to each stockholder. The class E and class F common stock was issued to CCMP. One share of class G common stock was issued to each of our existing stockholders. All shares of class B through G common stock will automatically convert to class A common stock upon consummation of an initial public offering of shares of class A common stock resulting in proceeds to us of at least $250,000, which is underwritten on a firm commitment basis by a nationally recognized investment banking firm, and which results in the initial listing or quotation of the class A common stock on any national securities exchange (a “Qualified IPO”).

Holders of class B, C and D common stock have the right, in aggregate, to designate three of our five directors. Holders of class E common stock have the right to designate the remaining two directors. Holders of each of the class B, C, D, and E common stock have designated their respective directors. All of the initial designees of the class B, C, D and E common stock were approved by the existing board of directors prior to being empanelled.

The class B, E, F and G common stock carry the following additional voting and consent rights:

• So long as the class B holders own 80% or more of the common stock they owned as of the Closing Date, and without such holder’s prior consent, we may neither initiate nor consummate a sale of the Company, whether in the form of a stock sale, asset sale, merger or any other form whatsoever (a “Company Sale”), or a liquidation or dissolution of the Company, on or prior to the sixth anniversary of the Closing Date.

• In certain circumstances, we are prohibited from incurring debt, consummating sales or acquisitions of assets, taking certain operational actions or engaging in other specified transactions without the prior consent of the holders of the class E common stock.

• Upon the triggering of a Company Sale or a Demand IPO (each as summarized below) by holders of class E common stock, the voting and other rights related to the class F common stock will permit holders of class E common stock to cause any actions necessary to be taken by our board of directors or stockholders to consummate such Company Sale or Demand IPO.

• Upon the triggering of a Demand IPO by a majority in interest of our existing stockholders, the voting and other rights related to the class G common stock will permit the majority of the holders of class G common stock to cause any actions necessary to be taken by the Company’s board of directors or stockholders to consummate such Demand IPO.

The rights and preferences of a holder of class B, C, D, E, F and G common stock terminate on the earlier of (x) the closing date of a Qualified IPO or (y) the date that such holder and its permitted transferees cease to beneficially own 5% or more of our fully-diluted common stock.

Our bylaws have been amended to conform to the provisions of the Amended and Restated Certificate of Incorporation.

F-30

Stockholders Agreement

In connection with the closing of the Stock Purchase Agreement, the Company, CCMP and our existing stockholders executed the Stockholders Agreement on April 12, 2010. The Stockholders Agreement provides for certain general rights and restrictions, including board observer rights, informational rights, general restrictions on transfer of common stock, tag-along rights, preemptive rights, registration rights following a Qualified IPO and, subject to certain limited exceptions, prohibitions on the sale or acquisition of our common stock that would result in a change of control, as such term is defined under the indentures for our Senior Notes.

The Stockholders Agreement also provides for the following stockholder-specific rights or restrictions:

• Prior to a Qualified IPO, Altoma will not vote for the approval of (i) any merger, consolidation, conversion or a Demand IPO, (ii) certain amendments to our organizational documents, (iii) the sale of all or substantially all of our assets, or (iv) a termination of the business of or liquidation or dissolution of the Company, unless Fischer votes for such approval.

• Other than pursuant to the exercise of preemptive rights, CHK Energy Holdings may not acquire more than 25% of our outstanding common stock.

• CCMP may sell up to 20% of its common stock owned on the Closing Date without restriction. Prior to a Qualified IPO and except in limited circumstances, CCMP is restricted from making further sales before the fourth anniversary of the Closing Date, and any sales thereafter (but before a Qualified IPO) will be subject to certain rights of first offer provisions set forth in the Stockholders Agreement (the “ROFO provisions”).

• Fischer may sell up to 20% of its common stock owned immediately prior to the Closing Date subject to certain restrictions. Prior to a Qualified IPO and except in limited circumstances, Fischer is restricted from making further sales before the fourth anniversary of the Closing Date, and any sales thereafter (but before a Qualified IPO) will be subject to the ROFO provisions.

• Prior to a Qualified IPO and except in limited circumstances, CHK Energy Holdings is restricted from selling its common stock before the 30 month anniversary of the Closing Date, and any sales thereafter (but before a Qualified IPO) will be subject to the ROFO provisions.

• If our common stock is not listed on a national securities exchange after August 15, 2011, Altoma may request to transfer its shares pursuant to a demand registration, but only after Altoma first offers such shares to the Company, and then to CHK Energy Holdings, Fischer and CCMP in accordance with the procedures set forth in the Stockholders Agreement.

• At any time after the 18 month anniversary of the Closing Date, either (i) CCMP or (ii ) a majority in interest of our existing stockholders may demand that we engage in a Qualified IPO (a “Demand IPO”), if (a) the price per share to be received by the Company or such party or parties, as the case may be, in such Demand IPO is at least 1.75 times the price per share paid by CCMP for our common stock pursuant to the Stock Purchase Agreement and (b) certain other conditions are met.

• At any time after the four year anniversary of the Closing Date, CCMP may demand a Demand IPO.

• At any time after the sixth anniversary of the Closing Date, and so long as a Qualified IPO has not yet occurred, CCMP may demand a Company Sale, subject to a right of first offer to purchase the Company provided to Fischer.

With the exception of registration rights, the rights and preferences of a stockholder under the Stockholders Agreement will generally terminate on the earlier of (x) the closing date of a Qualified IPO or (y) the date that such holder and its permitted transferees cease to beneficially own 5% or more of our fully-diluted common stock.

F-31

Summary of changes in common stock

The following is a summary of the changes in our common shares outstanding during the years ended December 31, 2012, 2011, and 2010:

	Common Stock
	Class A			Class B		Class C		Class D		Class E		Class F		Class G		Shares outstanding on April 11, 2010			Total
Shares issued at January 1, 2010		—			—		—		—		—		—		—		877,000			877,000
Change in classification		—			357,882		209,882		279,999		29,234		—		3		(877,000	)		—
Common stock issuance for cash		—			—		—		—		475,042		1		—		—			475,043
Restricted stock issuances		51,346			—		—		—		—		—		—		—			51,346
Shares issued at December 31, 2010		51,346			357,882		209,882		279,999		504,276		1		3		—			1,403,389
Restricted stock issuances		17,642			—		—		—		—		—		—		—			17,642
Restricted stock forfeitures		(2,295	)		—		—		—		—		—		—		—			(2,295	)
Restricted stock repurchased		(528	)		—		—		—		—		—		—		—			(528	)
Shares issued at December 31, 2011		66,165			357,882		209,882		279,999		504,276		1		3		—			1,418,208
Restricted stock issuances		17,494			—		—		—		—		—		—		—			17,494
Restricted stock forfeitures		(14,199	)		—		—		—		—		—		—		—			(14,199	)
Restricted stock repurchased		(1,469	)		—		—		—		—		—		—		—			(1,469	)
Shares issued at December 31, 2012		67,991			357,882		209,882		279,999		504,276		1		3		—			1,420,034

Note 10: Related party transactions

Transactions with Chesapeake Energy Corporation

CHK Energy Holdings, Inc., an indirect wholly owned subsidiary of Chesapeake Energy Corporation (“Chesapeake”), owns approximately 20% of our outstanding common stock. We participate in ownership of properties operated by Chesapeake, and we received revenues and incurred joint interest billings on these properties as follows:

	Year ended December 31,
	2012			2011			2010
Revenues	$	3,625		$	5,028		$	6,395
Joint interest billings	$	(4,896	)	$	(1,764	)	$	(5,111	)

In addition, Chesapeake participates in ownership of properties operated by us, and we paid revenues and recorded joint interest billings to Chesapeake on these properties as follows:

	Year ended December 31,
	2012			2011			2010
Revenues	$	(4,084	)	$	(2,834	)	$	(1,553	)
Joint interest billings	$	9,785		$	4,056		$	1,765

F-32

Amounts receivable from and payable to Chesapeake were as follows:

	As of December 31,
	2012		2011
Receivable from Chesapeake	$	2,071	$	223
Payable to Chesapeake	$	864	$	207

Chesapeake has disclosed its intention to sell all of its equity interest in us. The sale by Chesapeake will be subject to the terms and conditions of the Stockholders Agreement described in Note 9, including the restrictions on its ability to sell its equity interest.

Transactions with CCMP

On April 12, 2010, we closed the sale of an aggregate of 475,043 shares of our common stock to CCMP, and as a result of this transaction, CCMP owns approximately 36% of our total outstanding common stock. Fees and other expenses associated with the sale were $11,769, which includes $5,000 paid to CCMP for its expenses in connection with the transaction. See Note 9 for additional information regarding the sale of stock to CCMP.

Note 11: Retirement benefits

We provide a 401(k) retirement plan for all employees, and we match employee contributions 100%, up to 6% of each employee’s gross wages. At December 31, 2012, 2011, and 2010, there were 661, 625, and 595 employees, respectively, participating in the plan. Our contribution expense was $2,809, $2,390, and $2,360 for the years ended December 31, 2012, 2011 and 2010, respectively.

Note 12: Divestitures

On May 30, 2012, we sold certain mature oil and natural gas properties located in our Velma Area in southern Oklahoma for a cash price of $37,000 subject to post-closing adjustments. In accordance with the full cost method of accounting, we reduced our full cost pool by the amount of the net proceeds and did not record a gain or loss on the sale.

On November 28, 2011, we sold certain non-strategic oil and natural gas properties located in our Rocky Mountains area to Charger Resources, LLC for a cash price of approximately $33,100. In accordance with the full cost method of accounting, we reduced our full cost pool by the amount of the net proceeds and did not record a gain or loss on the sale.

On November 7, 2011, we sold substantially all the remaining assets of Green Country Supply Inc., a wholly owned subsidiary, for a cash price of $4,433. We recorded a gain on the sale of $2,630, which is included in “Other income” on the consolidated statement of operations.

Note 13: Commitments and contingencies

Standby letters of credit (“Letters”) available under our senior secured revolving credit facility are used in lieu of surety bonds with various organizations for liabilities relating to the operation of oil and natural gas properties. We had various Letters outstanding totaling $920 and $2,920 as of December 31, 2012 and 2011, respectively. Interest on each Letter accrues at the lender’s prime rate for all amounts paid by the lenders under the Letters. No amounts were paid by the lenders under the Letters, therefore we paid no interest on the Letters during the years ended December 31, 2012, 2011, or 2010.

We have a long-term contract to purchase CO₂ manufactured at an existing ethanol plant. As of December 31, 2012, we were purchasing approximately 14 MMcf/d of CO₂ under this contract, and we expect to purchase an average of approximately 13 MMcf/d over the fifteen-year contract term, which expires in May 2024. Purchases under this contract were $1,099, $481, and $305 during 2012, 2011, and 2010, respectively. Pricing is fixed for the remainder of the contract and the contract has renewal language.

We have rights under two additional contracts with fertilizer plants under which we purchase CO₂ that is restricted in whole or in part, for use only in EOR projects. Under both of these contracts, the fertilizer plant reserves the right to install additional equipment and use some of the CO₂ to make certain fertilizer products, which could reduce our CO₂ purchases. Under one of these contracts, as of December 31, 2012, we were purchasing an average of approximately 19 MMcf/d and expect our purchases to remain at that level over the remainder of the contract term, which expires in February 2021. Purchases under this contract were $1,518, $1,465, and $961 during 2012, 2011, and 2010, respectively. Under the second of these contracts, we have elected to purchase 10 MMcf/d of CO₂ through 2014, subject to availability. During 2012, we were purchasing approximately 1 MMcf/d of CO₂ under this contract. Purchases under this contract, which include transportation charges, were $1,243, $3,065, and $1,310 during 2012, 2011, and 2010, 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.

F-33

On March 24, 2011, we signed a long-term contract to purchase up to 100% of CO₂ emissions from an existing nitrogen fertilizer plant in Coffeyville, Kansas that produces approximately 42 MMcf/d of CO₂. We intend to use these CO₂ volumes 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. Beginning no later than July 2013, and assuming the fertilizer plant produces and delivers a specified quality of CO₂, we will be obligated to purchase an average of approximately 24 MMcf/d the first year of the contract and 35 MMcf/d for the remaining contract years or pay for any deficiencies at the price in effect when the minimum delivery was to have occurred. After the first ten contract years, we may permanently reduce up to 100% of our purchase rate under this contract with six months’ notice. We expect to purchase an average of approximately 24 MMcf/d of CO₂ under this contract beginning on April 1, 2013 and for the remainder of 2013.

Based on current prices, our estimated minimum purchase obligations under our CO₂ contracts are as follows:

2013	$	1,397
2014		4,974
2015		1,289
2016		1,289
2017		1,289
2018 and thereafter		22,648
	$	32,886

We have entered into operating lease agreements for the use of office space and equipment. We also rent equipment used on our oil and natural gas properties. Rent expense for the years ended December 31, 2012, 2011, and 2010 was $8,144, $6,715, and $4,647, respectively. We have leases relating to office space and equipment that have terms of up to five years. As of December 31, 2012, total remaining payments associated with these operating leases were $729.

We have entered into change of control severance agreements under which our officers are entitled to receive certain severance benefits. The severance payment will be paid in equal monthly installments over a period of months as calculated under the terms of the agreement and will be equal to a set multiplier times the sum of (A) the officer’s base salary as in effect immediately prior to his or her termination date, plus (B) the officer’s bonus for the full year in which the termination date occurred.

Naylor Farms, Inc. v. Chaparral Energy, L.L.C.

On June 7, 2011, Naylor Farms, Inc. (the “Plaintiff”), filed a complaint against us, alleging claims on behalf of itself and non-governmental royalty interest owners in oil and natural gas wells we operate in Oklahoma. The Plaintiff asserts class claims seeking recovery for underpayment of royalties, alleging damages in excess of $5,000. The Plaintiff also requests allowable interest, punitive damages, cancellation of leases, other equitable relief, and an award of attorney fees and costs. We have denied liability on the claims and raised arguments and defenses that, if accepted by the Court, will result in no loss to us. The matter is currently stayed pending resolution of unrelated cases currently on appeal with the U.S. Court of Appeals for the Tenth Circuit. These cases are expected to influence the ruling on class certification in the Plaintiff’s case. At the time that the matter was stayed no class had been certified and discovery was ongoing. As such, we are not yet able to estimate a possible loss, or range of possible loss, if any.

In our opinion, there are no other material pending legal proceedings to which we 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. While the outcome of these legal matters cannot be predicted with certainty, we do not expect them to have a material adverse effect on our financial condition, results of operations or cash flows.

F-34

Note 14: Oil and natural gas activities

Our oil and natural gas activities are conducted entirely in the United States. Costs incurred in oil and natural gas producing activities are as follows for the years ended December 31:

	2012		2011		2010
Property acquisition costs
Proved properties	$	1,108	$	1,024	$	32,458
Unproved properties		46,895		15,795		9,062
Total acquisition costs		48,003		16,819		41,520
Development costs		409,429		250,182		251,564
Exploration costs(1)		54,432		57,016		34,180
Total	$	511,864	$	324,017	$	327,264

(1) Includes $52,188 and $33,030 of EOR costs in 2012 and 2011, respectively.

Depreciation, depletion, and amortization expense of oil and natural gas properties was $154,788, $132,307, and $96,676 for the years ended December 31, 2012, 2011, and 2010, respectively. The average depreciation, depletion and amortization rate per equivalent unit of production was $16.98, $15.29, and $12.01 for the years ended December 31, 2012, 2011, and 2010, respectively.

Oil and natural gas properties not subject to amortization consist of the cost of unevaluated properties and seismic costs associated with specific unevaluated properties. Of the $162,921 of unproved property costs at December 31, 2012 being excluded from the amortization base, $136,652, $16,377, and $4,567 were incurred in 2012, 2011, and 2010, respectively, and $5,325 was incurred in prior years. These costs are primarily seismic, pipeline, and lease acquisition costs. We expect to complete our evaluation for the majority of these costs relating to non-EOR properties within the next two to five years.

Note 15: Disclosures about oil and natural gas activities (unaudited)

The estimate of proved reserves and related valuations were based upon the reports of Cawley, Gillespie & Associates, Inc. and Ryder Scott Company, L.P., each independent petroleum and geological engineers, and our engineering staff. Users of this information should be aware that the process of estimating quantities of “proved” and “proved developed” 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.

F-35

Our oil and natural gas reserves are attributable solely to properties within the United States. A summary of the changes in our quantities of proved oil and natural gas reserves for the three years ended December 31, 2012 are as follows:

	Oil (MBbls)(1)			Natural Gas (MMcf)			Total (MBoe)
Balance at January 1, 2010		89,469			314,430			141,874
Purchase of minerals in place		1,352			17,166			4,213
Sales of minerals in place		—			(6	)		(1	)
Extensions and discoveries		4,767			37,914			11,086
Revisions		(2,694	)		(10,542	)		(4,451	)
Improved recoveries		4,611			—			4,611
Production		(4,093	)		(23,742	)		(8,050	)
Balance at December 31, 2010		93,412			335,220			149,282
Purchase of minerals in place		241			822			378
Sales of minerals in place		(2,355	)		(7,134	)		(3,544	)
Extensions and discoveries		6,362			40,896			13,178
Revisions		6,711			(12,882	)		4,564
Improved recoveries		1,057			—			1,057
Production		(5,048	)		(21,642	)		(8,655	)
Balance at December 31, 2011		100,380			335,280			156,260
Purchase of minerals in place		—			57			9
Sales of minerals in place		(2,694	)		(6,608	)		(3,795	)
Extensions and discoveries		7,117			37,256			13,326
Revisions(2)		3,410			(89,036	)		(11,429	)
Improved recoveries		842			—			842
Production		(5,812	)		(19,834	)		(9,118	)
Balance at December 31, 2012		103,243			257,115			146,095
Proved developed reserves:
January 1, 2010		55,861			228,006			93,862
December 31, 2010		55,607			257,754			98,566
December 31, 2011		62,450			226,008			100,118
December 31, 2012		63,956			185,826			94,927
Proved undeveloped reserves:
January 1, 2010		33,608			86,424			48,012
December 31, 2010		37,805			77,466			50,716
December 31, 2011		37,930			109,272			56,142
December 31, 2012		39,287			71,289			51,169

(1) Includes natural gas liquids.

(2) The downward revision in our oil and natural gas reserves during 2012 was primarily due to a decrease in SEC pricing for oil from $96.19 as of December 31, 2011 to $94.71 as of December 31, 2012 and a decrease in our natural gas SEC pricing from $4.11 as of December 31, 2011 to $2.76 as of December 31, 2012. SEC pricing was computed using the 12-month unweighted average of the first-day-of-the-month commodity prices as required by SEC rules.

F-36

The following information was developed using procedures prescribed by GAAP. The standardized measure of discounted future net cash flows should not be viewed as representative of our current value. It and the other information contained in the following tables may be useful for certain comparative purposes, but should not be solely relied upon in evaluating us or our performance.

We believe that, in reviewing the information that follows, the following factors should be taken into account:

• future costs and sales prices will probably differ from those required to be used in these calculations;

• actual rates of production achieved in future years may vary significantly from the rates of production assumed in the calculations;

• a 10% discount rate may not be reasonable as a measure of the relative risk inherent in realizing future net oil and natural gas revenues; and

• future net revenues may be subject to different rates of income taxation.

For 2012, 2011, and 2010, future cash inflows used in the standardized measure calculation were estimated by applying a twelve-month average price for oil and natural gas, adjusted for location and quality differences, to the estimated future production of year-end proved reserves. Future cash inflows do not reflect the impact of future production that is subject to open hedge positions (see Note 5, “Derivative activities and fair value measurements”). Future cash inflows were reduced by estimated future development, abandonment and production costs based on year-end costs in order to arrive at net cash flows before tax. Future income tax expense has been computed by applying year-end statutory tax rates to aggregate future pre-tax net cash flows reduced by the tax basis of the properties involved and tax carryforwards. GAAP requires the use of a 10% discount rate and prices and costs excluding escalations based upon future conditions.

In general, management does not rely on the following information in making investment and operating decisions. Such decisions are based upon a wide range of factors, including estimates of probable and possible as well as proved reserves and varying price and cost assumptions considered more representative of a range of possible economic conditions that may be anticipated.

The standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves are as follows:

	For the year ended December 31,
	2012			2011			2010
Future cash flows	$	9,690,171		$	10,737,829		$	8,614,519
Future production costs		(3,737,069	)		(4,061,713	)		(3,448,904	)
Future development and abandonment costs		(1,172,786	)		(1,202,438	)		(1,054,771	)
Future income tax provisions		(1,223,036	)		(1,653,666	)		(1,211,143	)
Net future cash flows		3,557,280			3,820,012			2,899,701
Less effect of 10% discount factor		(2,033,599	)		(2,222,100	)		(1,663,675	)
Standardized measure of discounted future net cash flows	$	1,523,681		$	1,597,912		$	1,236,026

Future cash flows as shown above were reported without consideration for the effects of cash flow hedges outstanding at each period end. We discontinued the use of hedge accounting effective April 1, 2010.

F-37

The changes in the standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves are as follows:

	For the year ended December 31,
	2012			2011			2010
Beginning of year	$	1,597,912		$	1,236,026		$	971,364
Sale of oil and natural gas produced, net of production costs		(346,627	)		(374,300	)		(275,939	)
Net changes in prices and production costs		(206,640	)		538,466			512,006
Extensions and discoveries		224,903			224,027			166,330
Improved recoveries		14,204			17,969			69,181
Changes in future development costs		(18,184	)		(238,881	)		(236,031	)
Development costs incurred during the period that reduced future development costs		118,502			166,161			84,327
Revisions of previous quantity estimates		(192,894	)		77,588			(66,781	)
Purchases and sales of reserves in place, net		(54,070	)		(40,662	)		63,205
Accretion of discount		214,794			169,679			124,480
Net change in income taxes		166,238			(177,142	)		(181,858	)
Changes in production rates and other		5,543			(1,019	)		5,742
End of year	$	1,523,681		$	1,597,912		$	1,236,026

The following prices before field differentials were used in determining future net revenues related to the standardized measure calculation:

	2012		2011		2010
Oil (per Bbl)	$	94.71	$	96.19	$	79.43
Natural gas (per Mcf)	$	2.76	$	4.11	$	4.38

F-38

$150,000,000

OFFER TO EXCHANGE

Outstanding

7.625% Senior Notes due 2022

for

Registered

7.625% Senior Notes due 2022

Prospectus

            , 2013

Until                     , 2013, all dealers that effect transactions in these securities, whether or not participating in the exchange offer, may be required to deliver a prospectus. This is in addition to the dealers’ obligation to deliver a prospectus when acting as underwriters with respect to their unsold allotments or subscriptions.

Part II

Information not required in the prospectus

Item 20. Indemnification of directors and officers.

Chaparral Energy, Inc.

Chaparral Energy, Inc. is a Delaware corporation. Section 145 of the Delaware General Corporation Law authorizes a court to award, or a corporation’s board of directors to grant, indemnity under certain circumstances to directors, officers employees or agents in connection with actions, suits or proceedings, by reason of the fact that the person is or was a director, officer, employee or agent, against expenses and liabilities incurred in such actions, suits or proceedings so long as they acted in good faith and in a manner the person reasonable believed to be in, or not opposed to, the best interests of the company, and with respect to any criminal action if they had no reasonable cause to believe their conduct was unlawful. With respect to suits by or in the right of such corporation, however, indemnification is generally limited to attorneys’ fees and other expenses and is not available if such person is adjudged to be liable to such corporation unless the court determines that indemnification is appropriate.

As permitted by Delaware law, our certificate of incorporation includes a provision that eliminates the personal liability of our directors to us or our stockholders for monetary damages for breach of fiduciary duty as a director, except for liability:

• for any breach of the director’s duty of loyalty to us or our stockholders;

• for acts or omissions not in good faith or that involve intentional misconduct or a knowing violation of law;

• under section 174 of the Delaware General Corporation Law regarding unlawful dividends and stock purchases; or

• for any transaction for which the director derived an improper personal benefit.

As permitted by Delaware law, our certificate of incorporation provides that we are required to indemnify our directors and officers to the fullest extent permitted by Delaware law.

As permitted by Delaware law, our bylaws provide that:

• we will indemnify our officers and directors, subject to very limited exceptions;

• we are required to advance expenses (including without limitation, attorneys’ fees), as incurred, to our directors and officers in connection with a legal proceeding, subject to very limited exceptions; and

• the rights conferred in our bylaws are not exclusive.

The indemnification provisions in our certificate of incorporation may be sufficiently broad to permit indemnification of our directors and officers for liabilities arising under the Securities Act.

Under Delaware law, corporations also have the power to purchase and maintain insurance for directors, officers, employees and agents.

We and our subsidiaries are covered by liability insurance policies which indemnify their directors and officers against loss arising from claims by reason of their legal liability for acts as such directors, officers, or trustees, subject to limitations and conditions as set forth in the policies.

The foregoing discussion of our certificate of incorporation, our bylaws, and Delaware law is not intended to be exhaustive and is qualified in its entirety by such certificate of incorporation, bylaws, or law.

We have entered into indemnification agreements with certain of our directors and certain of our executive officers. These indemnification agreements are intended to permit indemnification to the fullest extent now or hereafter permitted by the General Corporation Law of the State of Delaware. It is possible that the applicable law could change the degree to which indemnification is expressly permitted.

The indemnification agreements cover expenses (including attorneys’ fees), judgments, fines and amounts paid in settlement incurred as a result of the fact that such person, in his or her capacity as a director or officer, is made or threatened to be made a party to any suit or proceeding. The indemnification agreements generally cover claims relating to the fact that the indemnified party is or was an officer, director, employee or agent of us or any of our affiliates, or is or was serving at our request in such a position for another entity. The indemnification agreements also obligate us to promptly advance all reasonable expenses incurred in connection with any claim. The indemnitee is, in turn, obligated to reimburse us for all amounts so advanced if it is later determined that the indemnitee is not entitled to indemnification. The indemnification provided under the indemnification agreements is not exclusive of any other indemnity rights; however, double payment to the indemnitee is prohibited.

II-1

We are not be obligated to indemnify the indemnitee with respect to claims brought by the indemnitee against:

• us, except for:

• claims regarding the indemnitee’s rights under the indemnification agreement;

• claims to enforce a right to indemnification under any statute or law; and

• counter-claims against us in a proceeding brought by us against the indemnitee; or

• any other person, except for claims approved by our board of directors.

CEI Acquisition, L.L.C.

Under the Delaware Limited Liability Company Act, a limited liability company may, and shall have the power to, indemnify and hold harmless any member or manager or other person from and against any and all claims and demands whatsoever.

The Agreement of Limited Liability Company of CEI Acquisition, L.L.C. provides that a member shall not be liable to CEI Acquisition, L.L.C. for any act or omission based upon errors of judgment or other fault in connection with the business or affairs of CEI Acquisition, L.L.C. if such member’s conduct does not constitute gross negligence or willful misconduct. Furthermore, the Agreement of Limited Liability Company of CEI Acquisition, L.L.C. provides that a member shall be indemnified and held harmless by CEI Acquisition, L.L.C., to the fullest extent permitted by law, from and against any and all losses, claims, damages and settlements arising from any and all claims, demands, actions, suits or proceedings, whether civil, criminal, administrative or investigative, in which the member is involved, as a party or otherwise, by reason of the management of the affairs of CEI Acquisition, L.L.C., provided that no member shall be entitled to indemnification for such losses, claims, damages and settlements arising as a result of the gross negligence or willful misconduct of such member.

Oklahoma Limited Liability Company Guarantors

Under the Oklahoma Limited Liability Company Act, a limited liability company may (i) limit or eliminate the personal liability of a manager for monetary damages for breach of any duty under the Oklahoma Limited Liability Company Act or (ii) provide for indemnification of a manager for judgments, settlements, penalties, fines or expenses incurred in any proceeding because such manager is or was a manager of the limited liability company, except, in either case, for any breach of a manager’s duty of loyalty or any acts or omissions not in good faith or which involve intentional misconduct or a knowing violation of law.

The Operating Agreements of each of Chaparral Energy, L.L.C., Chaparral CO₂, L.L.C., Chaparral Real Estate, L.L.C., and Chaparral Resources, L.L.C., which are Oklahoma limited liability companies, provide indemnification and eliminate liability for each manager or officer of such limited liability company from any and all monetary damages, claims, demands and actions of every kind and nature whatsoever which may arise by reason of a manager’s or officer’s performance of his or her duties and responsibilities, except (i) for liabilities arising as a result of a breach of the manager’s or officer’s duty of loyalty to such limited liability company or its members, (ii) for acts or omissions not in good faith or which involve intentional misconduct or a knowing violation of the law, (iii) for any transaction from which the manager or officer derived an improper personal benefit and (iv) with respect to indemnification, a breach of any provision of such limited liability company’s Operating Agreement.

II-2

Item 21. Exhibit and financial statement schedules.

(a) Exhibits.

Exhibit No.	Description
3.1*	Second Amended and Restated Certificate of Incorporation of Chaparral Energy, Inc. (the “Company”) dated as of April 12, 2010. (Incorporated by reference to Exhibit 3.1 to the Company’s Annual Report on Form 10-K filed on April 14, 2010)
3.2*	Second Amended and Restated Bylaws of the Company dated as of April 12, 2010. (Incorporated by reference to Exhibit 3.2 to the Company’s Annual Report on Form 10-K filed on April 14, 2010)
4.1*	Indenture dated September 16, 2010, among Chaparral Energy, Inc., the guarantors party thereto, and Wells Fargo Bank, National Association, as trustee. (Incorporated by reference to Exhibit 4.1 of the Company’s Current Report on Form 8-K (SEC File No.333-134748) filed on September 16, 2010)
4.2*	Form of 9 7/8% Senior Note due 2020. (included in Exhibit 4.1) (Incorporated by reference to Exhibit 4.2 of the Company’s Current Report on Form 8-K (SEC File No. 333-134748) filed on September 16, 2010)
4.3*	Indenture dated February 22, 2011, among Chaparral Energy, Inc., the guarantors party thereto, and Wells Fargo Bank, National Association, as trustee. (Incorporated by reference to Exhibit 4.1 of the Company’s Current Report on Form 8-K filed on February 22, 2011)
4.4*	Form of 8 1/4% Senior Note due 2021. (included as Exhibit A to Exhibit 4.3) (Incorporated by reference to Exhibit 4.2 of the Company’s Current Report on Form 8-K filed on February 22, 2011)
4.5*	Indenture dated May 2, 2012, among Chaparral Energy, Inc., the guarantors party thereto, and Wells Fargo Bank, National Association, as trustee. (Incorporated by reference to Exhibit 4.1 of the Company’s Current Report on Form 8-K filed on May 2, 2012)
4.6*	Form of 7.625% Senior Note due 2022. (included as Exhibit A to Exhibit 4.5) (Incorporated by reference to Exhibit 4.2 of the Company’s Current Report on Form 8-K filed on May 2, 2012)
4.7*	First Supplemental Indenture dated November 15, 2012, among Chaparral Energy, Inc., the guarantors party thereto, and Wells Fargo Bank, National Association, as trustee. (Incorporated by reference to Exhibit 4.1 of the Company’s Current Report on Form 8-K filed on November 15, 2012)
4.8*	Form of 7.625% Senior Note due 2022. (included as Exhibit A to Exhibit 4.7) (Incorporated by reference to Exhibit 4.2 of the Company’s Current Report on Form 8-K filed on November 15, 2012)
5.1**	Opinion of McAfee & Taft A Professional Corporation.
10.1*†	Form of Indemnification Agreements, between the Company and each of the directors and certain executive officers thereof. (Incorporated by reference to Exhibit 10.6 to Form S-4 (SEC File No. 333-134748) filed on June 6, 2006)
10.2*†	Form of Assignment of Overriding Royalty Interest to James M. Miller. (Incorporated by reference to Exhibit 10.7 to Form S-1 (SEC File No. 333-130749) filed on December 29, 2005)
10.3*†	Form of Change of Control Severance Agreement for Corporate Officers, between the Company and certain executive officers thereof. (Incorporated by reference to Exhibit 10.15 to the Company’s Annual Report on Form 10-K (SEC File No. 333-134748) filed on March 31, 2008)
10.4*	Stockholders’ Agreement dated as of April 12, 2010, by and among the Company, CHK Energy Holdings, L.L.C. CCMP Capital Investors II (AV-2), L.P., CMP Energy I LTD., CCMP Capital Investors (Cayman) II, L.P Altoma Energy GP and Fischer Investments, L.L.C. (Incorporated by reference to Exhibit 10.17 to the Company’s Annual Report on Form 10-K filed on April 14, 2010)
10.5*	Eighth Restated Credit Agreement dated as of April 12, 2010, by and among the Company, Chaparral Energy, L.L.C., in its capacity as Borrower Representative for the Borrowers, JPMorgan Chase Bank, N.A., as Administrative Agent, and each of the Lenders named therein. (Incorporated by reference to Exhibit 10.18 to the Company’s Annual Report on Form 10-K filed on April 14, 2010)
10.6*	First Amendment to Eighth Restated Credit Agreement dated as of July 26, 2010. (Incorporated by reference to Exhibit 10.28 to the Company’s Quarterly Report on Form 10-Q filed on August 11, 2010)

II-3

Exhibit No.	Description
10.7*	Second Amendment to Eighth Restated Credit Agreement dated as of January 11, 2011. (Incorporated by reference to Exhibit 4.3 of the Company’s Current Report on Form 8-K filed on February 8, 2011)
10.8*	Third Amendment to Eighth Restated Credit Agreement dated as of February 7, 2011. (Incorporated by reference to Exhibit 4.3 of the Company’s Current Report on Form 8-K filed on February 8, 2011)
10.9*	Fourth Amendment to Eighth Restated Credit Agreement dated as of April 1, 2011. (Incorporated by reference to Exhibit 10.1 of the Company’s Current Report on Form 8-K filed on April 4, 2011)
10.10*	Fifth Amendment to Eighth Restated Credit Agreement dated as of October 31, 2011. (Incorporated by reference to Exhibit 10.1 of the Company’s Quarterly Report on Form 10-Q filed on November 14, 2011)
10.11*	Sixth Amendment to Eighth Restated Credit Agreement dated as of December 1, 2011. (Incorporated by reference to Exhibit 10.18 of the Company’s Annual Report on Form 10-K filed on March 29, 2012)
10.12*	Seventh Amendment to Eighth Restated Credit Agreement dated as of April 17, 2012. (Incorporated by reference to Exhibit 10.2 of the Company’s Current Report on Form 8-K filed on April 20, 2012)
10.13*	Eighth Amendment to Eighth Restated Credit Agreement dated as of April 17, 2012. (Incorporated by reference to Exhibit 10.2 of the Company’s Current Report on Form 8-K filed on April 20, 2012)
10.14*	Ninth Amendment to Eighth Restated Credit Agreement dated as of May 24, 2012. (Incorporated by reference to Exhibit 10.6 of the Company’s Quarterly Report on Form 10-Q filed on August 14, 2012)
10.15*	Tenth Amendment to Eighth Restated Credit Agreement dated as of November 2, 2012. (Incorporated by reference to Exhibit 10.1 of the Company’s Quarterly Report on Form 10-Q filed on November 13, 2012)
10.16*†	Second Amended and Restated Phantom Stock Plan dated December 31, 2008. (Incorporated by reference to Exhibit 10.22 of the Company’s Quarterly Report on Form 10-Q filed on November 10, 2009)
10.17*†	Employment Agreement dated as of April 12, 2010, by and among the Company and Mark A. Fischer. (Incorporated by reference to Exhibit 10.23 of the Company’s Annual Report on Form 10-K filed on April 14, 2010)
10.18*†	Employment Agreement dated as of April 12, 2010, by and among the Company and Joseph O. Evans. (Incorporated by reference to Exhibit 10.24 of the Company’s Annual Report on Form 10-K filed on April 14, 2010)
10.19*†	Employment Agreement dated as of April 12, 2010, by and among the Company and James M. Miller. (Incorporated by reference to Exhibit 10.26 of the Company’s Annual Report on Form 10-K filed on April 14, 2010)
10.20*†	Employment Agreement dated as of February 1, 2011, by and among the Company and K. Earl Reynolds. (Incorporated by reference to Exhibit 10.27 of the Company’s Annual Report on Form 10-K filed on March 29, 2011)
10.21*	Registration Rights Agreement dated February 22, 2011, among Chaparral Energy, Inc., the guarantors party thereto, and the initial purchasers party thereto. (Incorporated by reference to Exhibit 10.1 of the Company’s Current Report on Form 8-K filed on February 22, 2011)
10.22*	Carbon Dioxide Purchase and Sale Agreement dated March 24, 2011, by and between Chaparral CO2, LLC, as buyer and Coffeyville Resources Nitrogen Fertilizers, LLC, as seller. (Incorporated by reference to Exhibit 10.31 of the Company’s Annual Report on Form 10-K filed on March 29, 2011)
10.23*	Purchase Agreement dated as of April 18, 2012, by and among Chaparral Energy, Inc. and certain of its subsidiaries named therein, and Credit Suisse Securities (USA) LLC, as Representative of the several Initial Purchasers named therein. (Incorporated by reference to Exhibit 10.1 of the Company’s Current Report on Form 8-K filed on April 20, 2012)
10.24*	Solicitation Agent and Dealer Manager Agreement dated April 18, 2012, by and between Chaparral Energy, Inc. and Credit Suisse Securities (USA) LLC. (Incorporated by reference to Exhibit 10.3 of the Company’s Current Report on Form 8-K filed on April 20, 2012)
10.25*	Registration Rights Agreement dated May 2, 2012, among Chaparral Energy, Inc., the guarantors party thereto, and a representative of the initial purchasers. (Incorporated by reference to Exhibit 10.1 of the Company’s Current Report on Form 8-K filed on May 2, 2012)
10.26*†	Non-Officer Restricted Stock Unit Plan dated as of March 1, 2012. (Incorporated by reference to Exhibit 10.6 of the Company’s Quarterly Report on Form 10-Q filed on May 2, 2012)

II-4

Exhibit No.	Description
10.27*	Purchase Agreement dated as of November 2, 2012, by and among Chaparral Energy, Inc. and certain of its subsidiaries named therein, and Wells Fargo Securities, LLC, as Representative of the several Initial Purchasers named therein. (Incorporated by reference to Exhibit 10.2 of the Company’s Quarterly Report on Form 10-Q filed on November 13, 2012)
10.28*	Registration Rights Agreement dated November 15, 2012, among Chaparral Energy, Inc., the guarantors party thereto, and a representative of the initial purchasers. (Incorporated by reference to Exhibit 10.1 of the Company’s Current Report on Form 8-K filed on November 15, 2012)
10.29*†	Employment Agreement dated as of June 13, 2011, by and among the Company and G. Don Culpepper, Jr. (Incorporated by reference to Exhibit 10.35 of the Company’s Annual Report on Form 10-K filed on March 29, 2012)
10.30*†	Employment Agreement dated as of June 15, 2011, by and among the company and Scott C. Wehner. (Incorporated by reference to Exhibit 10.36 of the Company’s Annual Report on Form 10-K filed on March 29, 2012)
10.31*†	Employment Agreement dated as of October 31, 2012, by and among the Company and Jeffery D. Dahlberg. (Incorporated by reference to Exhibit 10.31 of the Company’s Annual Report on Form 10-K filed on April 1, 2013)
10.32*†	Employment Agreement dated as of November 1, 2012, by and among the Company and David J. Ketelsleger. (Incorporated by reference to Exhibit 10.32 of the Company’s Annual Report on Form 10-K filed on April 1, 2013)
10.33*†	Employment Agreement dated as of February 6, 2013, by and among the Company and Jeffrey M. Gutman. (Incorporated by reference to Exhibit 10.33 of the Company’s Annual Report on Form 10-K filed on April 1, 2013)
10.34*†	Amended and Restated 2010 Equity Incentive Plan effective January 1, 2013. (Incorporated by reference to Exhibit 10.34 of the Company’s Annual Report on Form 10-K filed on April 1, 2013)
10.35*†	Amended Form of Restricted Stock Award Grant Notice and Restricted Stock Agreement (Time Vesting) effective January 1, 2013. (Incorporated by reference to Exhibit 10.35 of the Company’s Annual Report on Form 10-K filed on April 1, 2013)
10.36*†	Amended Form of Restricted Stock Award Grant Notice and Restricted Stock Agreement (Performance Vesting) effective January 1, 2013. (Incorporated by reference to Exhibit 10.36 of the Company’s Annual Report on Form 10-K filed on April 1, 2013)
12.1**	Statement regarding computation of ratio of earnings to fixed charges.
21.1*	Subsidiaries of the Company. (Incorporated by reference to Exhibit 21.1 of the Company’s Annual Report on Form 10-K filed on April 1, 2013)
23.1**	Consent of Grant Thornton LLP.
23.2**	Consent of McAfee & Taft A Professional Corporation. (included as part of Exhibit 5.1)
23.3**	Consent of Cawley, Gillespie & Associates, Inc.
23.4**	Consent of Ryder Scott Company, L.P.
25.1**	Form T-1 Statement of Eligibility of Wells Fargo Bank, National Association, as Trustee for Indenture dated May 2, 2012.
99.1*	Report of Cawley, Gillespie & Associates, Inc. (Incorporated by reference to Exhibit 99.1 of the Company’s Annual Report on Form 10-K filed on April 1, 2013)
99.2*	Report of Ryder Scott Company, L.P. (Incorporated by reference to Exhibit 99.2 of the Company’s Annual Report on Form 10-K filed on April 1, 2013)
99.3**	Form of Letter of Transmittal.
99.4**	Form of Notice of Guaranteed Delivery.
99.5**	Form of Letter to Registered Holders and DTC Participants.
99.6**	Form of Instructions to Registered Holder or DTC Participant from Beneficial Owner.
99.7**	Form of Letter to Clients.
101.INS***	XBRL Instance Document
101.SCH***	XBRL Taxonomy Extension Schema Document
101.CAL***	XBRL Taxonomy Extension Calculation Linkbase Document
101.DEF***	XBRL Taxonomy Extension Definition Linkbase Document
101.LAB***	XBRL Taxonomy Extension Label Linkbase Document
101.PRE***	XBRL Taxonomy Extension Presentation Linkbase Document

II-5

* Indicates exhibits incorporated by reference.

** Indicates exhibits filed herewith.

*** Furnished herewith.

† Indicates management contract or compensatory plan or arrangement

(b) All financial statement schedules are omitted because the required information is not present or is not present in amounts sufficient to require submission of the schedule, or because the information required is included in the consolidated financial statements or notes thereto.

Item 22. Undertakings.

The undersigned registrants hereby undertake:

(a)(1) To file, during any period in which offers or sales are being made, a post-effective amendment to this registration statement:

(i) To include any prospectus required by section 10(a)(3) of the Securities Act of 1933;

(ii) To reflect in the prospectus any facts or events arising after the effective date of the registration statement (or the most recent post-effective amendment thereof) which, individually or in the aggregate, represent a fundamental change in the information set forth in the registration statement. Notwithstanding the foregoing, any increase or decrease in volume of securities offered (if the total dollar value of securities offered would not exceed that which was registered) and any deviation from the low or high end of the estimated maximum offering range may be reflected in the form of prospectus filed with the Commission pursuant to Rule 424(b) if, in the aggregate, the changes in volume and price represent no more than 20% change in the maximum aggregate offering price set forth in the “Calculation of Registration Fee” table in the effective registration statement; and

(iii) To include any material information with respect to the plan of distribution not previously disclosed in the registration statement or any material change to such information in the registration statement;

(2) That, for the purpose of determining any liability under the Securities Act of 1933, each such post-effective amendment shall be deemed to be a new registration statement relating to the securities offered therein, and the offering of such securities at that time shall be deemed to be the initial bona fide offering thereof.

(3) To remove from registration by means of a post-effective amendment any of the securities being registered which remain unsold at the termination of the offering.

(4) That, for the purpose of determining liability under the Securities Act of 1933 to any purchaser, each prospectus filed pursuant to Rule 424(b) as part of a registration statement relating to an offering, other than registration statements relying on Rule 430B or other than prospectuses filed in reliance on Rule 430A (§ 230.430A of this chapter), shall be deemed to be part of and included in the registration statement as of the date it is first used after effectiveness, provided, however, that no statement made in a registration statement or prospectus that is part of the registration statement or made in a document incorporated or deemed incorporated by reference into the registration statement or prospectus that is part of the registration statement will, as to a purchaser with a time of contract of sale prior to such first use, supersede or modify any statement that was made in the registration statement or prospectus that was part of the registration statement or made in any such document immediately prior to such date of first use.

(5) That, for the purpose of determining liability of the registrant under the Securities Act to any purchaser in the initial distribution of the securities: The undersigned registrant undertakes that in a primary offering of securities of the undersigned registrant pursuant to this registration statement, regardless of the underwriting method used to sell the securities to the purchaser, if the securities are offered or sold to such purchaser by means of any of the following communications, the undersigned registrant will be a seller to the purchaser and will be considered to offer or sell such securities to such purchaser:

(i) Any preliminary prospectus or prospectus of the undersigned registrant relating to the offering required to be filed pursuant to Rule 424;

(ii) Any free writing prospectus relating to the offering prepared by or on behalf of the undersigned registrant or used or referred to by the undersigned registrant;

(iii) The portion of any other free writing prospectus relating to the offering containing material information about the undersigned registrant or its securities provided by or on behalf of the undersigned registrant; and

(iv) Any other communication that is an offer in the offering made by the undersigned registrant to the purchaser.

(b) To respond to requests for information that is incorporated by reference into the prospectus pursuant to Items 4, 10(b), 11, or 13 of this Form, within one business day of receipt of such request, and to send the incorporated documents by first class mail or other equally prompt means. This includes information contained in documents filed subsequent to the effective date of the registration statement through the date of responding to the request.

II-6

(c) To supply by means of a post-effective amendment all information concerning a transaction, and the company being acquired involved therein, that was not the subject of and included in this registration statement when it became effective.

(d) Insofar as indemnification for liabilities arising under the Securities Act may be permitted to directors, officers and controlling persons of the Registrant pursuant to the foregoing provisions, or otherwise, the registrants have been advised that in the opinion of the Securities and Exchange Commission such indemnification is against public policy as expressed in the Securities Act and is, therefore, unenforceable. In the event that a claim for indemnification against such liabilities (other than the payment by the registrants of expenses incurred or paid by a director, officer or controlling person of the registrants in the successful defense of any action, suit or proceeding) is asserted by such director, officer or controlling person in connection with the securities being registered hereunder, the registrants will, unless in the opinion of its counsel the matter has been settled by controlling precedent, submit to a court of appropriate jurisdiction the question whether such indemnification by it is against public policy as expressed in the Securities Act and will be governed by the final adjudication of such issue.

II-7

Signatures

Pursuant to the requirements of the Securities Act, the registrant has duly caused this registration statement to be signed on its behalf by the undersigned, thereunder duly authorized, in Oklahoma City, Oklahoma on April 11, 2013.

CHAPARRAL ENERGY, INC.
By:	/S/ MARK A. FISCHER
Name:	Mark A. Fischer
Title:	President and Chief Executive Officer

Pursuant to the requirements of the Securities Act of 1933, this registration statement has been signed by the following persons in the capacities and on the dates indicated.

Signature	Title	Date
/S/ MARK A. FISCHER Mark A. Fischer	President, Chief Executive Officer and Chairman (Principal Executive Officer)	April 11, 2013
/S/ JOSEPH O. EVANS Joseph O. Evans	Chief Financial Officer and Treasurer (Principal Financial Officer and Principal Accounting Officer)	April 11, 2013
/S/ CHARLES A. FISCHER, JR. Charles A. Fischer, Jr.	Director	April 11, 2013
/S/ DOMENIC J. DELL’OSSO Domenic J. Dell’Osso	Director	April 11, 2013
/S/ KYLE VANN Kyle Vann	Director	April 11, 2013
/S/ CHRISTOPHER BEHRENS Christopher Behrens	Director	April 11, 2013

II-8

Signatures

Pursuant to the requirements of the Securities Act, the registrant has duly caused this registration statement to be signed on its behalf by the undersigned, thereunder duly authorized, in Oklahoma City, Oklahoma on April 11, 2013.

GREEN COUNTRY SUPPLY, INC.
By:	/S/ MARK A. FISCHER
Name:	Mark A. Fischer
Title:	President

Pursuant to the requirements of the Securities Act of 1933, this registration statement has been signed by the following persons in the capacities and on the dates indicated.

Signature	Title	Date
/S/ MARK A. FISCHER Mark A. Fischer	Director	April 11, 2013
/S/ JOSEPH O. EVANS Joseph O. Evans	Director	April 11, 2013

II-9

Signatures

Pursuant to the requirements of the Securities Act, the registrant has duly caused this registration statement to be signed on its behalf by the undersigned, thereunder duly authorized, in Oklahoma City, Oklahoma on April 11, 2013.

Each of the LLC Guarantors Named on Schedule A-1 Hereto
By:	/S/ MARK A. FISCHER
Name:	Mark A. Fischer
Title:	President

II-10

Schedule A-1

LLC Guarantors

Chaparral Real Estate, L.L.C.

Chaparral Resources, L.L.C.

Chaparral CO₂, L.L.C.

Chaparral Energy, L.L.C.

CEI Acquisition, L.L.C.

CEI Pipeline, L.L.C.

Chaparral Exploration, L.L.C.

Roadrunner Drilling, L.L.C.

II-11

Exhibit index

Exhibit No.	Description
3.1*	Second Amended and Restated Certificate of Incorporation of Chaparral Energy, Inc. (the “Company”) dated as of April 12, 2010. (Incorporated by reference to Exhibit 3.1 to the Company’s Annual Report on Form 10-K filed on April 14, 2010)
3.2*	Second Amended and Restated Bylaws of the Company dated as of April 12, 2010. (Incorporated by reference to Exhibit 3.2 to the Company’s Annual Report on Form 10-K filed on April 14, 2010)
4.1*	Indenture dated September 16, 2010, among Chaparral Energy, Inc., the guarantors party thereto, and Wells Fargo Bank, National Association, as trustee. (Incorporated by reference to Exhibit 4.1 of the Company’s Current Report on Form 8-K (SEC File No.333-134748) filed on September 16, 2010)
4.2*	Form of 9 7/8% Senior Note due 2020. (included in Exhibit 4.1) (Incorporated by reference to Exhibit 4.2 of the Company’s Current Report on Form 8-K (SEC File No. 333-134748) filed on September 16, 2010)
4.3*	Indenture dated February 22, 2011, among Chaparral Energy, Inc., the guarantors party thereto, and Wells Fargo Bank, National Association, as trustee. (Incorporated by reference to Exhibit 4.1 of the Company’s Current Report on Form 8-K filed on February 22, 2011)
4.4*	Form of 8 1/4% Senior Note due 2021. (included as Exhibit A to Exhibit 4.3) (Incorporated by reference to Exhibit 4.2 of the Company’s Current Report on Form 8-K filed on February 22, 2011)
4.5*	Indenture dated May 2, 2012, among Chaparral Energy, Inc., the guarantors party thereto, and Wells Fargo Bank, National Association, as trustee. (Incorporated by reference to Exhibit 4.1 of the Company’s Current Report on Form 8-K filed on May 2, 2012)
4.6*	Form of 7.625% Senior Note due 2022. (included as Exhibit A to Exhibit 4.5) (Incorporated by reference to Exhibit 4.2 of the Company’s Current Report on Form 8-K filed on May 2, 2012)
4.7*	First Supplemental Indenture dated November 15, 2012, among Chaparral Energy, Inc., the guarantors party thereto, and Wells Fargo Bank, National Association, as trustee. (Incorporated by reference to Exhibit 4.1 of the Company’s Current Report on Form 8-K filed on November 15, 2012)
4.8*	Form of 7.625% Senior Note due 2022. (included as Exhibit A to Exhibit 4.7) (Incorporated by reference to Exhibit 4.2 of the Company’s Current Report on Form 8-K filed on November 15, 2012)
5.1**	Opinion of McAfee & Taft A Professional Corporation.
10.1*†	Form of Indemnification Agreements, between the Company and each of the directors and certain executive officers thereof. (Incorporated by reference to Exhibit 10.6 to Form S-4 (SEC File No. 333-134748) filed on June 6, 2006)
10.2*†	Form of Assignment of Overriding Royalty Interest to James M. Miller. (Incorporated by reference to Exhibit 10.7 to Form S-1 (SEC File No. 333-130749) filed on December 29, 2005)
10.3*†	Form of Change of Control Severance Agreement for Corporate Officers, between the Company and certain executive officers thereof. (Incorporated by reference to Exhibit 10.15 to the Company’s Annual Report on Form 10-K (SEC File No. 333-134748) filed on March 31, 2008)
10.4*	Stockholders’ Agreement dated as of April 12, 2010, by and among the Company, CHK Energy Holdings, L.L.C. CCMP Capital Investors II (AV-2), L.P., CMP Energy I LTD., CCMP Capital Investors (Cayman) II, L.P Altoma Energy GP and Fischer Investments, L.L.C. (Incorporated by reference to Exhibit 10.17 to the Company’s Annual Report on Form 10-K filed on April 14, 2010)
10.5*	Eighth Restated Credit Agreement dated as of April 12, 2010, by and among the Company, Chaparral Energy, L.L.C., in its capacity as Borrower Representative for the Borrowers, JPMorgan Chase Bank, N.A., as Administrative Agent, and each of the Lenders named therein. (Incorporated by reference to Exhibit 10.18 to the Company’s Annual Report on Form 10-K filed on April 14, 2010)
10.6*	First Amendment to Eighth Restated Credit Agreement dated as of July 26, 2010. (Incorporated by reference to Exhibit 10.28 to the Company’s Quarterly Report on Form 10-Q filed on August 11, 2010)
10.7*	Second Amendment to Eighth Restated Credit Agreement dated as of January 11, 2011. (Incorporated by reference to Exhibit 4.3 of the Company’s Current Report on Form 8-K filed on February 8, 2011)

II-12

Exhibit No.	Description
10.8*	Third Amendment to Eighth Restated Credit Agreement dated as of February 7, 2011. (Incorporated by reference to Exhibit 4.3 of the Company’s Current Report on Form 8-K filed on February 8, 2011)
10.9*	Fourth Amendment to Eighth Restated Credit Agreement dated as of April 1, 2011. (Incorporated by reference to Exhibit 10.1 of the Company’s Current Report on Form 8-K filed on April 4, 2011)
10.10*	Fifth Amendment to Eighth Restated Credit Agreement dated as of October 31, 2011. (Incorporated by reference to Exhibit 10.1 of the Company’s Quarterly Report on Form 10-Q filed on November 14, 2011)
10.11*	Sixth Amendment to Eighth Restated Credit Agreement dated as of December 1, 2011. (Incorporated by reference to Exhibit 10.18 of the Company’s Annual Report on Form 10-K filed on March 29, 2012)
10.12*	Seventh Amendment to Eighth Restated Credit Agreement dated as of April 17, 2012. (Incorporated by reference to Exhibit 10.2 of the Company’s Current Report on Form 8-K filed on April 20, 2012)
10.13*	Eighth Amendment to Eighth Restated Credit Agreement dated as of April 17, 2012. (Incorporated by reference to Exhibit 10.2 of the Company’s Current Report on Form 8-K filed on April 20, 2012)
10.14*	Ninth Amendment to Eighth Restated Credit Agreement dated as of May 24, 2012. (Incorporated by reference to Exhibit 10.6 of the Company’s Quarterly Report on Form 10-Q filed on August 14, 2012)
10.15*	Tenth Amendment to Eighth Restated Credit Agreement dated as of November 2, 2012. (Incorporated by reference to Exhibit 10.1 of the Company’s Quarterly Report on Form 10-Q filed on November 13, 2012)
10.16*†	Second Amended and Restated Phantom Stock Plan dated December 31, 2008. (Incorporated by reference to Exhibit 10.22 of the Company’s Quarterly Report on Form 10-Q filed on November 10, 2009)
10.17*†	Employment Agreement dated as of April 12, 2010, by and among the Company and Mark A. Fischer. (Incorporated by reference to Exhibit 10.23 of the Company’s Annual Report on Form 10-K filed on April 14, 2010)
10.18*†	Employment Agreement dated as of April 12, 2010, by and among the Company and Joseph O. Evans. (Incorporated by reference to Exhibit 10.24 of the Company’s Annual Report on Form 10-K filed on April 14, 2010)
10.19*†	Employment Agreement dated as of April 12, 2010, by and among the Company and James M. Miller. (Incorporated by reference to Exhibit 10.26 of the Company’s Annual Report on Form 10-K filed on April 14, 2010)
10.20*†	Employment Agreement dated as of February 1, 2011, by and among the Company and K. Earl Reynolds. (Incorporated by reference to Exhibit 10.27 of the Company’s Annual Report on Form 10-K filed on March 29, 2011)
10.21*	Registration Rights Agreement dated February 22, 2011, among Chaparral Energy, Inc., the guarantors party thereto, and the initial purchasers party thereto. (Incorporated by reference to Exhibit 10.1 of the Company’s Current Report on Form 8-K filed on February 22, 2011)
10.22*	Carbon Dioxide Purchase and Sale Agreement dated March 24, 2011, by and between Chaparral CO2, LLC, as buyer and Coffeyville Resources Nitrogen Fertilizers, LLC, as seller. (Incorporated by reference to Exhibit 10.31 of the Company’s Annual Report on Form 10-K filed on March 29, 2011)
10.23*	Purchase Agreement dated as of April 18, 2012, by and among Chaparral Energy, Inc. and certain of its subsidiaries named therein, and Credit Suisse Securities (USA) LLC, as Representative of the several Initial Purchasers named therein. (Incorporated by reference to Exhibit 10.1 of the Company’s Current Report on Form 8-K filed on April 20, 2012)
10.24*	Solicitation Agent and Dealer Manager Agreement dated April 18, 2012, by and between Chaparral Energy, Inc. and Credit Suisse Securities (USA) LLC. (Incorporated by reference to Exhibit 10.3 of the Company’s Current Report on Form 8-K filed on April 20, 2012)
10.25*	Registration Rights Agreement dated May 2, 2012, among Chaparral Energy, Inc., the guarantors party thereto, and a representative of the initial purchasers. (Incorporated by reference to Exhibit 10.1 of the Company’s Current Report on Form 8-K filed on May 2, 2012)
10.26*†	Non-Officer Restricted Stock Unit Plan dated as of March 1, 2012. (Incorporated by reference to Exhibit 10.6 of the Company’s Quarterly Report on Form 10-Q filed on May 2, 2012)

II-13

Exhibit No.	Description
10.27*	Purchase Agreement dated as of November 2, 2012, by and among Chaparral Energy, Inc. and certain of its subsidiaries named therein, and Wells Fargo Securities, LLC, as Representative of the several Initial Purchasers named therein. (Incorporated by reference to Exhibit 10.2 of the Company’s Quarterly Report on Form 10-Q filed on November 13, 2012)
10.28*	Registration Rights Agreement dated November 15, 2012, among Chaparral Energy, Inc., the guarantors party thereto, and a representative of the initial purchasers. (Incorporated by reference to Exhibit 10.1 of the Company’s Current Report on Form 8-K filed on November 15, 2012)
10.29*†	Employment Agreement dated as of June 13, 2011, by and among the Company and G. Don Culpepper, Jr. (Incorporated by reference to Exhibit 10.35 of the Company’s Annual Report on Form 10-K filed on March 29, 2012)
10.30*†	Employment Agreement dated as of June 15, 2011, by and among the company and Scott C. Wehner. (Incorporated by reference to Exhibit 10.36 of the Company’s Annual Report on Form 10-K filed on March 29, 2012)
10.31*†	Employment Agreement dated as of October 31, 2012, by and among the Company and Jeffery D. Dahlberg. (Incorporated by reference to Exhibit 10.31 of the Company’s Annual Report on Form 10-K filed on April 1, 2013)
10.32*†	Employment Agreement dated as of November 1, 2012, by and among the Company and David J. Ketelsleger. (Incorporated by reference to Exhibit 10.32 of the Company’s Annual Report on Form 10-K filed on April 1, 2013)
10.33*†	Employment Agreement dated as of February 6, 2013, by and among the Company and Jeffrey M. Gutman. (Incorporated by reference to Exhibit 10.33 of the Company’s Annual Report on Form 10-K filed on April 1, 2013)
10.34*†	Amended and Restated 2010 Equity Incentive Plan effective January 1, 2013. (Incorporated by reference to Exhibit 10.34 of the Company’s Annual Report on Form 10-K filed on April 1, 2013)
10.35*†	Amended Form of Restricted Stock Award Grant Notice and Restricted Stock Agreement (Time Vesting) effective January 1, 2013. (Incorporated by reference to Exhibit 10.35 of the Company’s Annual Report on Form 10-K filed on April 1, 2013)
10.36*†	Amended Form of Restricted Stock Award Grant Notice and Restricted Stock Agreement (Performance Vesting) effective January 1, 2013. (Incorporated by reference to Exhibit 10.36 of the Company’s Annual Report on Form 10-K filed on April 1, 2013)
12.1**	Statement regarding computation of ratio of earnings to fixed charges.
21.1*	Subsidiaries of the Company. (Incorporated by reference to Exhibit 21.1 of the Company’s Annual Report on Form 10-K filed on April 1, 2013)
23.1**	Consent of Grant Thornton LLP.
23.2**	Consent of McAfee & Taft A Professional Corporation. (included as part of Exhibit 5.1)
23.3**	Consent of Cawley, Gillespie & Associates, Inc.
23.4**	Consent of Ryder Scott Company, L.P.
25.1**	Form T-1 Statement of Eligibility of Wells Fargo Bank, National Association, as Trustee for Indenture dated May 2, 2012.
99.1*	Report of Cawley, Gillespie & Associates, Inc. (Incorporated by reference to Exhibit 99.1 of the Company’s Annual Report on Form 10-K filed on April 1, 2013)
99.2*	Report of Ryder Scott Company, L.P. (Incorporated by reference to Exhibit 99.2 of the Company’s Annual Report on Form 10-K filed on April 1, 2013)
99.3**	Form of Letter of Transmittal.
99.4**	Form of Notice of Guaranteed Delivery.
99.5**	Form of Letter to Registered Holders and DTC Participants.
99.6**	Form of Instructions to Registered Holder or DTC Participant from Beneficial Owner.
99.7**	Form of Letter to Clients.
101.INS***	XBRL Instance Document
101.SCH***	XBRL Taxonomy Extension Schema Document
101.CAL***	XBRL Taxonomy Extension Calculation Linkbase Document
101.DEF***	XBRL Taxonomy Extension Definition Linkbase Document
101.LAB***	XBRL Taxonomy Extension Label Linkbase Document
101.PRE***	XBRL Taxonomy Extension Presentation Linkbase Document

* Indicates exhibits incorporated by reference.

** Indicates exhibits filed herewith.

*** Furnished herewith.

† Indicates management contract or compensatory plan or arrangement

II-14