S-1/A 1 ds1a.htm AMENDMENT NO. 2 TO FORM S-1 Amendment No. 2 to Form S-1
Table of Contents

As filed with the Securities and Exchange Commission on March 30, 2006

Registration No. 333-130749


SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 

Amendment No. 2

to

 

FORM S-1

REGISTRATION STATEMENT

UNDER

THE SECURITIES ACT OF 1933

 

Chaparral Energy, Inc.

(Exact name of registrant as specified in 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)

 

Robert W. Kelly II

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)

 

With a copy to:

 

David C. Buck

Andrews Kurth LLP

600 Travis, Suite 4200

Houston, Texas 77002

Telephone: (713) 220-4301

Facsimile: (713) 238-7126

 

Daniel J. Zubkoff

Cahill Gordon & Reindel LLP

80 Pine Street

New York, New York 10005

Telephone: (212) 701-3000

Facsimile: (212) 269-5420

 

Approximate date of commencement of proposed sale to the public:  As soon as practicable on or after the effective date of this Registration Statement.

 

If any of the securities being registered on this Form are to be offered on a delayed or continuous basis pursuant to Rule 415 under the Securities Act of 1933, 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(c) 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.  ¨

 

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 Securities and Exchange Commission, acting pursuant to said Section 8(a), may determine.

 



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The information in this preliminary prospectus is not complete and may be changed. These securities may not be sold until the registration statement filed with the Securities and Exchange Commission is effective. This preliminary prospectus is not an offer to sell nor does it seek an offer to buy these securities in any jurisdiction where the offer or sale is not permitted.

 

Subject to completion, dated March 30, 2006

 

Prospectus

 

             shares

 

LOGO

 

Chaparral Energy, Inc.

 

 

Common stock

 

Chaparral Energy, Inc. is selling                          shares of common stock, and the selling stockholders identified in this prospectus are selling an additional                          shares. We will not receive any of the proceeds from the sale of the shares by the selling stockholders. Certain of the selling stockholders are members of our management. See ”Principal and selling stockholders“ on page 80 for more information. This is the initial public offering of our common stock. The estimated initial public offering price is between $             and $            per share.

 

Prior to this offering, there has been no public market for our common stock. We have applied to list our common stock on the New York Stock Exchange under the symbol “CPR.”

 

     Per share    Total

Initial public offering price

   $              $                         

Underwriting discount

   $      $  

Proceeds to Chaparral Energy, Inc., before expenses

   $      $  

Proceeds to selling stockholders, before expenses

   $      $  

 

We and the selling stockholders have granted the underwriters an option for a period of 30 days to purchase up to an aggregate of                          additional shares of our common stock on the same terms and conditions set forth above to cover overallotments, if any.

 

Investing in our common stock involves a high degree of risk. See “ Risk factors” beginning on page 15.

 

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.

 

The underwriters expect to deliver the shares of common stock to investors on                 , 2006.

 

JPMorgan

 

Banc of America Securities LLC   Lehman Brothers
Comerica Securities   Fortis Securities

 

                , 2006


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Table of Contents

 

Table of contents

 

     Page

Special cautionary statement regarding forward-looking statements

   ii

Prospectus summary

   1

Risk factors

   15

Use of proceeds

   30

Dividend policy

   30

Capitalization

   31

Dilution

   32

Unaudited pro forma financial data

   34

Selected consolidated financial data

   37

Management’s discussion and analysis of financial condition and results of operations

   39

Business and properties

   54

Management

   73

Principal and selling stockholders

   80

Certain relationships and related transactions

   81

Description of capital stock

   83

Shares eligible for future sale

   87

Material U.S. federal tax consequences for non-U.S. holders of our common stock

   89

Underwriting

   92

Legal matters

   96

Experts

   96

Independent petroleum engineers

   96

Where you can find more information

   96

Glossary of terms

   A-1

Index to financial statements

   F-1

 


 

You should rely only on the information contained in this prospectus. We have not authorized anyone to provide you with information different from that contained in this prospectus. We are offering to sell, and seeking offers to buy, shares of our common stock only in jurisdictions where offers and sales are permitted. The information contained in this prospectus is accurate only as of the date of this prospectus, regardless of the time of delivery of this prospectus or of any sale of our common stock.

 

No action is being taken in any jurisdiction outside the United States to permit a public offering of the common stock or possession or distribution of this prospectus in that jurisdiction. Persons who come into possession of this prospectus in jurisdictions outside the United States are required to inform themselves about and to observe any restrictions as to this offering and the distribution of this prospectus applicable to those jurisdictions.

 

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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. Forward-looking statements include information concerning possible or assumed future results of operations of us and our affiliates. These statements may relate to, but are not limited to, information or assumptions about capital and other expenditures, dividends, financing plans, capital structure, cash flow, pending legal and regulatory proceedings and claims, including environmental matters, future economic performance, operating income, cost savings, management’s plans, strategies, goals and objectives for future operations and growth. These forward-looking statements generally are accompanied by words such as “intend,” “anticipate,” “believe,” “estimate,” “expect,” “should,” “seek,” “project,” “plan” or similar expressions. It should be understood that these forward-looking statements are necessarily estimates reflecting the best judgment of our 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 various financial and operational matters, including, among other things:

 

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

 

  the amount, nature and timing of capital expenditures;

 

  drilling of wells;

 

  competition and government regulations;

 

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

 

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

 

  increases in proved reserves;

 

  operating costs and other expenses;

 

  cash flow and anticipated liquidity;

 

  estimates of proved reserves;

 

  exploitation or property acquisitions;

 

  marketing of oil and natural gas; and

 

  general economic conditions and the other risks and uncertainties discussed in this prospectus.

 

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” beginning on page 15 of this prospectus.

 

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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 securities laws require us to do so.

 

 

Industry and market data

 

The 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 third-party sources are reliable, we have not independently verified the information and cannot guarantee its accuracy and completeness.

 

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Prospectus summary

 

This summary highlights information contained elsewhere in this prospectus. Because this section is only a summary, it does not contain all of the information that may be important to you or that you should consider before making an investment decision. For a more complete understanding of this offering, we encourage you to read this entire prospectus, including the information contained under the heading “Risk factors.” You should read the following summary together with the more detailed information, pro forma financial information and consolidated financial information and the notes thereto included elsewhere in this prospectus. In this prospectus, unless the context otherwise requires, the terms “Chaparral,” “Company,” “we,” “us” and “our” refer to Chaparral Energy, Inc. and its predecessor, Chaparral L.L.C., and its subsidiaries.

 

In this prospectus, “pro forma basis” means after giving pro forma effect to (1) our acquisition of the 99% limited partner interest in CEI Bristol Acquisition, L.P. on September 30, 2005, (2) the issuance of $325.0 million aggregate principal amount of our 8 1/2% Senior Notes due 2015 on December 1, 2005 and (3) the application of the net proceeds from the issuance of the notes. See “—Recent developments” and “Use of proceeds.” The number of shares and per share amounts will be adjusted to give effect to a          -for-          stock split that will be effected as a stock dividend prior to the consummation of this offering. Investors who are not familiar with oil and gas industry terms used in this prospectus should refer to the “Glossary of terms” section set forth in this prospectus.

 

 

Our business

 

Chaparral is an independent oil and natural gas production and exploitation company, headquartered in Oklahoma City, Oklahoma. Since our inception in 1988, we have increased reserves and production primarily by acquiring and enhancing properties in our core areas of the Mid-Continent and the Permian Basin. Beginning in 2000, we expanded our geographic focus to include East Texas, North Texas, the Gulf Coast and the Rocky Mountains. During this period, we also increased the percentage of our capital expenditures allocated to development drilling. As of December 31, 2005, approximately 84% of our proved reserves were located in our core areas which generally consist of lower-risk, long-lived properties.

 

As of December 31, 2005, we had estimated proved reserves of 618 Bcfe (69% proved developed and 67% natural gas) and a PV-10 value of $1.6 billion. For the year ended December 31, 2005, on a pro forma basis, our average daily production was 81 MMcfe. As of December 31, 2005, our estimated pro forma reserve life was 20.9 years. For the year ended December 31, 2005, on a pro forma basis, our revenues and Adjusted EBITDA were $150.0 million and $102.2 million, respectively. 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, and our definition of Adjusted EBITDA (a non-GAAP measure) and a reconciliation of our income before accounting change to Adjusted EBITDA, beginning on page 11.

 

For the period from 2002 to 2005, our proved reserves and production have grown at a compounded annual growth rate of 35% and 26%, respectively. We have grown primarily through a disciplined strategy of acquisitions of proved oil and natural gas reserves, followed by exploitation activities and the acquisition of additional interests in or near these acquired properties. We expect our future growth to continue through a combination of acquisitions and exploitation projects, complemented by a modest amount of exploration activities.

 

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Our capital expenditures for oil and gas properties for the year ended December 31, 2005 were $333.0 million, representing a 247% increase over the prior year. Excluding $152.9 million recorded for the oil and gas properties acquired as part of the CEI Bristol acquisition, our capital expenditures in 2005 for oil and gas properties were $180.1 million, representing an 88% increase over the prior year. Our 2006 capital expenditure budget for oil and gas properties is $210.0 million assuming this offering is consummated. We have budgeted approximately 62% of our 2006 capital expenditures on development activities (drilling—43%, enhancements—11% and tertiary recovery—8%), 33% for acquisitions and 5% for exploration activities. The majority of our capital expenditure budget for developmental drilling in 2006 is allocated to our core areas of the Mid-Continent and Permian Basin. The wells we drill in these areas are primarily infill or single stepout wells, which are characterized as lower risk and have relatively low finding and development costs. We have also budgeted increased capital expenditures for our carbon dioxide (CO2) tertiary recovery projects in the Mid-Continent and Permian Basin.

 

The following table presents proved reserves and PV-10 value as of December 31, 2005, and average daily production for the year ended December 31, 2005 by our areas of operation.

 

    Proved reserves as of December 31, 2005

  Average daily
production
(MMcfe per day)


  Pro forma
average daily
production
(MMcfe per day)


   

Oil

(MBbl)

 

Natural
gas

(MMcf)

  Total
(MMcfe)
  Percent
of
total
MMcfe
  PV-10
value
($mm)
  Year ended
December 31,
2005
  Year ended
December 31,
2005

 
 
 
 
 
 
 

Mid-Continent

  20,752   285,994   410,506   66.5%   $ 1,070.0   48.2   55.4

Permian Basin

  6,057   73,347   109,689   17.8%     265.3   7.8   9.3

East Texas

  1,257   26,059   33,601   5.4%     90.5   7.4   8.3

North Texas

  2,239   3,977   17,411   2.8%     48.5   2.1   2.5

Rocky Mountains

  1,916   4,245   15,741   2.5%     37.4   2.0   2.5

Gulf Coast

  1,692   20,762   30,914   5.0%     90.9   2.0   3.0
   
 
 
 
 

 
 

Total

  33,913   414,384   617,862   100.0%   $ 1,602.6   69.5   81.0

 
 
 
 
 
 
 

 

Business strengths

 

Consistent track record of low-cost reserve additions and production growth.    From 2002 to 2005, we have grown reserves and production by a compounded annual growth rate of 35% and 26%, respectively. We have achieved this through a combination of drilling success and acquisitions. We replaced approximately 468%, 794% and 822% of our production in 2003, 2004 and 2005, respectively, at an average fully developed FD&A cost of $1.82 per Mcfe over this three year period, which we believe is among the lowest in the industry.

 

Disciplined approach to acquisitions.    We have a dedicated team that conducts due diligence, including reserve engineering on a well-by-well basis, to determine whether assets under consideration meet our acquisition criteria. We typically target properties where we can identify enhancements that we believe will increase production rates and extend the producing life of the well. In 2003, 2004 and 2005, our capital expenditures for acquisitions were $19.9 million, $30.5 million and $222.3 million, respectively. These acquisition capital expenditures represented approximately 35%, 32% and 67%, respectively, of our total capital expenditures for those years.

 

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On September 30, 2005, we made the largest acquisition in the history of our company, the acquisition of CEI Bristol, which added an estimated 115 Bcfe of proved reserves as of that date. Excluding the acquisition of CEI Bristol, we spent $69.3 million on acquisitions during 2005, representing approximately 39% of our total capital expenditures. We expect to continue spending a significant percentage of our future capital expenditures on acquisitions as long as our investment criteria are met.

 

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

 

Inventory of drilling locations.    As of December 31, 2005, we had an inventory of over 790 proved developmental drilling locations and over 2,100 additional potential drilling locations, which combined represent over 15 years of drilling opportunities based on our 2005 drilling rate, as shown in the following table.

 

     Identified
proved
undeveloped
drilling
locations
   Identified
other
potential
drilling
locations
  

Developed
Acreage

Net

  

Undeveloped
Acreage

Net


  
  
  
  

Mid-Continent

   653    1,440    295,482    33,524

Permian Basin

   81    470    49,915    11,718

East Texas

   4    34    30,219    1,352

North Texas

   30    146    16,349    2,924

Rocky Mountains

   14    25    10,025    7,286

Gulf Coast

   11    12    25,399    6,775
    
  
  
  

Total

   793    2,127    427,389    63,579

  
  
  
  

 

Identified drilling locations represent total gross drilling locations identified by our management as an estimation of our multi-year drilling activities on existing acreage. Our actual drilling activities may change depending on the availability of capital, regulatory approvals, seasonal restrictions, oil and natural gas prices, costs, drilling results and other factors. See “Risk factors” beginning on page 15. We spent $87.3 million on development and exploration drilling for 2005. We have experienced a high historical drilling success rate of approximately 96% on a weighted average basis during 2003, 2004 and 2005. For 2006, we have budgeted $102.0 million to drill more than 80 operated wells and to participate in more than 130 wells operated by others. To support our drilling program, we have entered into agreements which allow access to 34,000 square miles of 3-D seismic data, conducted two proprietary shoots and applied for permits for one additional proprietary 3-D shoot.

 

Tertiary recovery expertise and assets.    Beginning in 2000, we expanded our operations to include CO2 enhanced oil recovery. CO2 enhanced oil recovery involves the injection of CO2, which mixes with the remaining oil in place in the producing reservoir, followed by the injection of water in cycles to drive the hydrocarbons to producing wells. We have a staff of six engineers that have substantial expertise in CO2 tertiary recovery operations, as well as specific software for modeling CO2 enhanced recovery. We own a 29.2% interest in and operate a large CO2 tertiary flood unit in southern Oklahoma and installed and operate a second tertiary flood unit with a

 

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54% interest in the Oklahoma panhandle. At December 31, 2005, our proved reserves included four properties where CO2 tertiary recovery methods are used, which comprise approximately 9% of our total proved reserves.

 

Experienced management team.    Mark A. Fischer, our CEO and founder who beneficially owns 50% of our outstanding common stock, has operated in the oil and gas industry for 34 years after starting his career at Exxon as a petroleum engineer. Charles A. Fischer, Jr., our Chief Administrative Officer, has an indirect pecuniary interest in approximately 12% of our stock owned directly by Altoma Energy G.P. and has been involved in the oil and gas business for 22 years, serving as President of Kitscoty Oil LLC and previously as our Chief Financial Officer. Mark Fischer and Charles Fischer are brothers. Joe Evans, our Chief Financial Officer, has over 27 years of experience in the oil and gas industry. Individuals in our 24-person management team have an average of over 25 years of experience in the oil and gas industry.

 

 

Business strategy

 

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

 

Continue lower-risk development drilling program.    We have allocated $91.0 million, or 43% of our 2006 capital expenditure budget, to development drilling. A majority of these drilling locations are in our core areas of the Mid-Continent and the Permian Basin. The wells we drill in these areas are generally development (infill or single stepout) wells.

 

Acquire long-lived properties with enhancement opportunities.    We continually evaluate acquisition opportunities and expect that they will continue to play a significant role in increasing our reserve base and future drilling inventory. We have traditionally targeted smaller asset acquisitions which allow us to absorb, enhance and exploit the properties without taking on excessive integration risk. Targeting numerous smaller acquisitions also provides us sufficient opportunity to achieve our planned reserve additions through acquisitions. Our 2006 acquisition capital budget is $70.0 million, or 33% of our total capital expenditure budget.

 

Apply technical expertise to enhance mature properties.    Once we acquire a property and become the operator, we seek to maximize production through enhancement techniques and the reduction of operating costs. We have built Chaparral 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 13 field offices throughout Oklahoma, Texas 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 of December 31, 2005, we had an inventory of 227 developed enhancement projects requiring total estimated capital expenditures of $16.3 million.

 

Expand CO2 enhanced oil recovery activities.    We have accumulated interests in 43 properties in Oklahoma and Texas that meet our criteria for CO2 tertiary recovery operations and are expanding our CO2 pipeline system to initiate CO2 injection in certain of these properties. We

 

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plan to expand our Camrick CO2 project in 2006 and initiate CO2 injection in our NW Camrick and Perryton Units in 2007. We have budgeted $16 million in 2006 towards these projects. To support our existing CO2 tertiary recovery projects, we currently inject approximately 37 MMcf per day of CO2. We have a 100% ownership interest in our 86 mile Borger CO2 pipeline, a 29% interest in the 120 mile Enid to Purdy CO2 pipeline, and a 58% interest in and operate the 23 mile Purdy to Velma CO2 pipeline.

 

Pursue modest exploration program.    In the current high-priced commodity environment, we believe a modest exploration program can provide a rate of return comparable or superior to property acquisitions in certain areas. We currently plan to spend $11.0 million, or approximately 5% of our 2006 capital expenditures, on exploration activities.

 

Control operations and costs.    We seek to serve as operator of the wells in which we own a significant interest. As operator, we are better positioned to control the (1) timing and plans for future enhancement and exploitation efforts; (2) costs of enhancement, drilling, completing and producing the wells; and (3) marketing negotiations for our oil and gas production to maximize both volumes and wellhead price. As of December 31, 2005, we operated properties comprising approximately 79% of our proved reserves.

 

Hedge production to stabilize cash flow.    Our long-lived reserves provide us with relatively predictable production. We maintain an active hedging program on our PDP production to protect cash flows that we use for capital investments and to lock in returns on acquisitions. As of December 31, 2005, we had hedges in place for approximately 73%, 57% and 17% of our estimated PDP gas production for 2006, 2007 and 2008, respectively. We also had hedges in place for approximately 73%, 60% and 15% of our estimated PDP oil production for 2006, 2007 and 2008, respectively. While oil and gas hedging protects our cash flows during periods of commodity price declines, these hedges have resulted in net losses on oil and gas hedging activities of $12.2 million, $21.4 million and $68.3 million for the years ended December 31, 2003, 2004, and 2005, respectively, as commodity prices have increased.

 

 

Recent developments

 

Issuance of 8 1/2% Senior Notes due 2015.    On December 1, 2005, we sold $325.0 million aggregate principal amount of 8 1/2% Senior Notes maturing on December 1, 2015, which we refer to as our 8 1/2% Senior Notes. Interest on our 8 1/2% Senior Notes is due semi-annually beginning June 1, 2006. The 8 1/2% Senior Notes are our senior unsecured obligations, rank equally in right of payment with all of our existing and future senior indebtedness and rank senior to all of our existing and future subordinated debt. The payment of the principal, interest and premium on the 8 1/2% Senior Notes are fully and unconditionally guaranteed on a senior unsecured basis by our existing and some of our future restricted subsidiaries. We used the net proceeds from the sale of our 8 1/2% Senior Notes to reduce outstanding indebtedness under our senior secured credit facility, and to repay indebtedness incurred in the acquisition of CEI Bristol. See “—Acquisition of CEI Bristol Acquisition, L.P.” and “Management’s discussion and analysis of financial condition and results of operations—Liquidity and capital resources—Our 8 1/2% Senior Notes due 2015.”

 

Acquisition of CEI Bristol Acquisition, L.P.    On September 30, 2005, we acquired the limited partner interest in CEI Bristol Acquisition, L.P. from TIFD III-X LLC, an affiliate of General Electric Capital Corporation. Total consideration paid by us, including costs associated with the settlement of all previously existing hedge positions by CEI Bristol, was approximately $158

 

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million. Prior to this acquisition, we held a 1% general partner interest through our wholly-owned subsidiary Chaparral Oil, L.L.C. and TIFD III-X LLC held a 99% limited partner interest in CEI Bristol. Chaparral Oil, L.L.C. also managed CEI Bristol and its properties since 2000.

 

CEI Bristol’s properties were located primarily in the Mid-Continent and Permian Basin areas. As of September 30, 2005, CEI Bristol had estimated proved reserves of 115 Bcfe, resulting in an acquisition price based on the total consideration paid by us for the reserves of approximately $1.34 per Mcfe. During the nine months ended September 30, 2005, CEI Bristol produced 4.2 Bcfe at an average daily production rate of 15.7 MMcfe. For the nine months ended September 30, 2005, CEI Bristol had oil and gas sales of $29.8 million and net income of $2.6 million. We expect the acquisition to increase our production in 2006 by approximately 4.8 Bcfe.

 

Oklahoma Ethanol L.L.C.    In August 2005, we entered into a joint venture, Oklahoma Ethanol L.L.C., with the Oklahoma Farmers Union Sustainable Energy LLC to construct and operate an ethanol production plant in Oklahoma. The ethanol plant is estimated to produce a minimum of 55 million gallons of ethanol, 176,000 tons of distillers dried grains and 2.8 Bcfe of CO2 per year. We will have the option to acquire all or part of this CO2 for use in our tertiary oil recovery projects. The start up and construction costs are estimated to be $80 million, with Chaparral having a 66.67% ownership interest. We expect Oklahoma Ethanol L.L.C. will receive approximately $48 million in secured indebtedness with recourse limited to our interests in this entity to fund construction costs and for related start-up working capital. We expect to enter into a construction contract in 2006 and expect construction to commence in late 2006 or early 2007 with completion in 2008, and that our equity contribution will be approximately $20 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:

 

  volatility of oil and gas prices;

 

  writedowns of the carrying values of our properties;

 

  risks inherent in estimating reserves;

 

  our leverage and ability to borrow future funds;

 

  competition for acquisitions;

 

  demand for oil field equipment, services and qualified personnel;

 

  changes in laws and regulations; and

 

  losses from hedging obligations.

 

You should consider carefully these and other risks described in “Risk factors” before deciding to invest in shares of our common stock.

 


 

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.

 

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The offering

 

Common stock offered:

 

By us:              shares

 

By the selling stockholders:              shares

 

Total offered hereby:              shares

 

Common stock to be outstanding immediately following the offering:              shares

 

The number of shares of our common stock outstanding after this offering is based on              shares of common stock outstanding as of                     , 2006.

 

 

Use of proceeds:

 

We intend to use the net proceeds received by us in connection with this offering to repay outstanding indebtedness under our Credit Agreement and for general corporate purposes, including working capital. Certain affiliates of the underwriters to this offering are lenders under our Credit Agreement and will receive a portion of the proceeds from this offering. See “Use of proceeds” and “Underwriting.” We will not receive any of the proceeds from the sale of the shares by the selling stockholders, some of whom are members of our management. See “Principal and selling stockholders.”

 

 

Dividend policy:

 

We do not anticipate paying any cash dividends on our common stock.

 

NYSE symbol:                

 

CPR

 

 

Other information about this prospectus

 

Unless specifically stated otherwise, the information in this prospectus:

 

  will be adjusted to reflect a             -for-             stock split of our shares of common stock to be effected in the form of a stock dividend prior to the consummation of this offering;

 

  assumes no exercise of the underwriters’ over-allotment option; and

 

  assumes an initial public offering price of $            , which is the mid-point of the range set forth on the front cover of this prospectus.

 

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Summary consolidated historical and

pro forma financial data

 

You should read the following summary consolidated historical and pro forma financial information in connection with the financial statements and related notes included in this prospectus, and the “Management’s discussion and analysis of financial condition and results of operations” beginning on page 39 and the “Unaudited pro forma financial data” beginning on page 34 of this prospectus. The historical consolidated financial data for each of the three fiscal years ended December 31, 2005 (except for balance sheet data as of December 31, 2003) were derived from our audited annual financial statements included in this prospectus. Our summary historical results are not necessarily indicative of results to be expected in future periods.

 

The acquisition of CEI Bristol occurred on September 30, 2005, and the accounts of CEI Bristol are included in our consolidated historical balance sheet as of December 31, 2005. The results of operations of CEI Bristol are included in our consolidated statements of operations subsequent to September 30, 2005.

 

The summary pro forma financial data for the fiscal year ended December 31, 2005 gives effect to the following transactions:

 

  our acquisition of the limited partner interest in CEI Bristol, including hedge settlement costs; and

 

  our issuance of $325.0 million aggregate principal amount of our 8 1/2% Senior Notes on December 1, 2005 and the application of net proceeds.

 

The unaudited pro forma condensed consolidated statement of operations for the year ended December 31, 2005 assumes the pro forma transactions described above all occurred on January 1, 2005.

 

The as adjusted financial position data as of December 31, 2005 gives effect to this common stock offering and the application of the net proceeds as described in “Use of proceeds.”

 

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The non-generally accepted accounting principle, or non-GAAP, financial measure of Adjusted EBITDA is defined by us as income before accounting changes, adjusted to exclude (1) interest and other financing costs, net of capitalized interest, (2) income taxes, (3) depreciation, depletion and amortization and (4) hedge ineffectiveness, and is presented in our summary historical and pro forma financial data. Adjusted EBITDA on a pro forma basis also includes an adjustment to exclude losses on hedges terminated as a part of the CEI Bristol acquisition. In the supplemental sections titled “Non-GAAP financial measures and reconciliations,” we have provided the necessary explanations and reconciliations for this non-GAAP financial measure.

 

     Year ended December 31,

 
     Historical

    Pro forma

 
(Dollars in thousands, except share and per share amounts)    2003     2004     2005     2005  


                       (unaudited)  

Operating results data:

                                

Revenues

                                

Oil and gas sales

   $ 74,186     $ 113,546     $ 201,410     $ 231,183  

Loss on oil and gas hedging activities

     (12,220 )     (21,350 )     (68,324 )     (81,160 )
    


Total revenues

     61,966       92,196       133,086       150,023  
    


Costs and expenses

                                

Lease operating

     19,520       26,928       42,147       48,321  

Production taxes

     4,840       8,272       14,626       17,084  

Depreciation, depletion and amortization

     10,376       18,234       31,423       37,941  

General and administrative

     4,946       5,985       9,808       10,697  
    


Total costs and expenses

     39,682       59,419       98,004       114,043  
    


Operating income

     22,284       32,777       35,082       35,980  
    


Non-operating income (expense)

                                

Interest expense

     (4,116 )     (6,162 )     (15,588 )     (33,105 )

Other income

     208       279       665       682  
    


Net non-operating expense

     (3,908 )     (5,883 )     (14,923 )     (32,423 )
    


Income before income taxes and accounting change

     18,376       26,894       20,159       3,557  

Income tax expense

     6,932       9,629       7,309       1,290  
    


Income before accounting change

     11,444       17,265       12,850       2,267  

Cumulative effect of change in accounting principle, net of income taxes

     (887 )                  
    


Net income

   $ 10,557     $ 17,265     $ 12,850     $ 2,267  
    


 

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     Year ended December 31,

 
     Historical

    Pro forma

 
(Dollars in thousands, except share and per share amounts)    2003     2004     2005     2005  

  

 

 

 

                       (unaudited)  

Earnings per share (historical):

                                

Income per share before accounting change

   $ 11,444     $ 17,265     $ 12,850     $ 2,267  

Income (loss) per share from accounting change, net

     (887 )                  

Net income per share

   $ 10,557     $ 17,265     $ 12,850     $ 2,267  

Weighted average number of shares used in calculation of basic and diluted earnings per share

     1,000       1,000       1,000       1,000  

Earnings per share (pro forma for stock split):

                                

Income per share before accounting change

   $       $       $       $    

Income (loss) per share from accounting change, net

                                

Net income per share

   $       $       $       $    

Weighted average number of shares used in calculation of basic and diluted earnings per share

                                

Cash flow data:

                                

Net cash provided by operating activities

   $ 32,541     $ 49,849     $ 65,111          

Net cash used in investing activities

     (55,213 )     (95,120 )     (334,435 )        

Net cash provided by financing activities

     26,146       54,061       257,080          

Other financial data:

                                

Capital expenditures for oil & gas properties

   $ 56,962     $ 96,031     $ 333,038          

Adjusted EBITDA(1)

     33,288       51,894       81,910     $ 102,179  
     As of December 31,

 
     Historical

    As
adjusted(2)


 
     2003     2004     2005     2005  
    

 

 

 

Financial position data:

                             (unaudited )

Cash and cash equivalents

   $ 5,052     $ 13,842     $ 1,598     $ 31,598  

Total assets

     211,086       308,126       646,679       676,679  

Total debt

     118,355       176,622       446,544       337,544  

Undistributed/retained earnings

     30,977       48,242       57,683       57,683  

Accumulated other comprehensive loss, net of income taxes

     (4,900 )     (12,107 )     (47,967 )     (47,967 )

Total equity

     26,078       36,136       9,717       148,717  


 

(1)   Adjusted EBITDA is defined as income before accounting changes, adjusted to exclude (1) interest and other financing costs, net of capitalized interest, (2) income taxes, (3) depreciation, depletion, and amortization and (4) hedge ineffectiveness. Adjusted EBITDA on a pro forma basis also includes an adjustment to exclude losses on hedges terminated as a part of the CEI Bristol acquisition. See “Non-GAAP financial measure and reconciliation.”
(2)   A $1.00 increase (decrease) in the assumed initial public offering price per share would increase (decrease) cash and cash equivalents and total assets by $        , assuming the number of shares offered by us set forth on the cover page of this prospectus remains the same and after deducting underwriting discounts and estimated offering expenses payable by us.

 

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Non-GAAP financial measures and reconciliations

 

PV-10 Value

 

The PV-10 value (PV-10) is derived from the standardized measure of discounted future net cash flows which is the most directly comparable GAAP financial measure. PV-10 is a computation of the standardized measure of discounted future net cash flows on a pre-tax basis. PV-10 is equal to the standardized measure of discounted future net cash flows at December 31, 2005 before deducting future income taxes, discounted at 10%. We believe that the presentation of the PV-10 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 corporate future income taxes and it is a useful measure for 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 is not a substitute for the standardized measure of discounted future net cash flows. Our PV-10 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 the standardized measure of discounted future net cash flows to PV-10 as of December 31, 2005 for our major areas of operation.

 

(Dollars in millions)


   PV-10
value


   Present value of
future income tax
discounted at 10%


   Standardized measure
of discounted future
net cash flows


Mid Continent

   $ 1,070.0    $ 357.0    $ 713.0

Permian Basin

     265.3      88.5      176.8

East Texas

     90.5      30.2      60.3

North Texas

     48.5      16.2      32.3

Rocky Mountains

     37.4      12.5      24.9

Gulf Coast

     90.9      30.3      60.6
    

  

  

Total

   $ 1,602.6    $ 534.7    $ 1,067.9
    

  

  

 

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Adjusted EBITDA

 

We define Adjusted EBITDA as income before accounting changes, adjusted to exclude (1) interest and other financing costs, net of capitalized interest, (2) income taxes, (3) depreciation, depletion and amortization and (4) hedge ineffectiveness.

 

Our Adjusted EBITDA measure provides additional information which may be used to better understand our operations. Adjusted EBITDA is used as a supplemental financial measurement in the evaluation of our business and should not be considered as an alternative to net income, as an indicator of our operating performance, as an alternative to cash flows from operating activities, or as a measure of liquidity. Adjusted EBITDA is not defined under generally accepted accounting principles and, accordingly, it may not be a comparable measurement to those used by other companies. Adjusted EBITDA on a pro forma basis also includes an adjustment to exclude losses on hedges terminated as a part of the CEI Bristol acquisition. The following table provides a reconciliation of income before accounting changes to Adjusted EBITDA.

 

     Year ended
December 31,


     Historical

   Pro forma

(Dollars in thousands) (unaudited)    2003    2004    2005    2005

  
  
  
  

Income before accounting change

   $ 11,444    $ 17,265    $ 12,850    $ 2,267

Interest expense

     4,116      6,162      15,588      33,105

Income tax expense

     6,932      9,629      7,309      1,290

Depreciation, depletion and amortization

     10,376      18,234      31,423      37,941

Unrealized loss on ineffective portion of hedges

     420      604      14,740      14,740

Loss on CEI Bristol hedges

                    12,836

Adjusted EBITDA

   $ 33,288    $ 51,894    $ 81,910    $ 102,179

  
  
  
  

 

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Summary reserve information

 

The following table summarizes our estimates of net proved oil and natural gas reserves as of the dates indicated and the present value attributable to the reserves at such dates (using prices in effect on December 31, 2003, 2004 and 2005), discounted at 10% per annum. Estimates of our net proved oil and natural gas reserves as of December 31, 2003 were prepared by Cawley, Gillespie & Associates, Inc., an independent petroleum engineering firm. Estimates of our net proved oil and natural gas reserves as of December 31, 2004 and 2005 were prepared by Cawley, Gillespie and Associates, Inc. (80% of PV-10 value in 2005) and Lee Keeling & Associates, Inc. (4% of PV-10 value in 2005), both independent petroleum engineering firms, and our engineering staff (16% of PV-10 value in 2005).

 

All proved reserve estimates were prepared using constant prices and costs in accordance with the guidelines of the Securities and Exchange Commission, based on the price differentials received on a property-by-property basis as of December 31 of each year. Proved reserve estimates do not include any value for probable or possible reserves which may exist, nor do they include any value for unproved acreage. The proved reserve estimates represent our net revenue interest in our properties.

 

    As of December 31,
    2003    2004    2005

 
  
  

Proved reserves

                   

Oil (Mbbl)

    16,777      28,585      33,913

Natural gas (MMcf)

    203,677      263,620      414,384

Natural gas equivalent (MMcfe)

    304,339      435,130      617,862

Proved developed reserves percentage

    81%      67%      69%

PV-10 value (in thousands)

  $ 488,305    $ 775,116    $ 1,602,610

Estimated reserve life (in years)(1)

    19.9      22.9      24.4

Cost incurred (in thousands):

                   

Property acquisition costs(2)

  $ 19,864    $ 30,546    $ 222,285

Development costs

    36,758      62,371      103,479

Exploration costs

    340      3,114      7,274

Total

  $ 56,962    $ 96,031    $ 333,038

Annual reserve replacement ratio(3)

    468%      794%      822%

Three-year average fully developed FD&A cost ($/Mcfe)(4)

         $ 1.21    $ 1.82

 
  
  
(1)   Calculated by dividing net proved reserves by net production volumes for the year indicated.
(2)   Includes $152,945 of costs related to the acquisition of CEI Bristol.
(3)   Calculated by dividing the sum of reserve additions from all sources (revisions, extensions and discoveries, improved recoveries, and acquisitions) by the production for the corresponding period.

 

(4)   Calculated as total costs incurred, plus the increase in future development costs, divided by total proved reserve acquisitions, extensions and discoveries, and revisions as shown below:

 

     2002    2003    2004    2005  

Purchases of minerals in place

     48,819      50,515      62,238      173,176  

Extensions and discoveries

     3,689      12,766      34,004      22,531  

Revisions

     24,295      102      14,535      (7,516 )

Improved recoveries

     623      8,202      39,722      20,262  

Total reserve additions

     77,426      71,585      150,499      208,453  

Costs incurred

   $ 40,852    $ 56,962    $ 96,031    $ 333,038  

Changes in future development costs

     25,268      20,494      121,938      154,042  

Total costs incurred

   $ 66,120    $ 77,456    $ 217,969    $ 487,080  

Three-year average fully developed FD&A cost ($/Mcfe)

                 $ 1.21    $ 1.82  

 

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Summary production and sales data

 

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

 

    Year ended December 31,
    2003    2004    2005

 
  
  

Net production volumes

                   

Oil (MBbls)

    924      1,173      1,449

Natural gas (MMcf)

    9,762      11,923      16,660

Combined (MMcfe)

    15,306      18,961      25,354

Oil and gas sales ($ in thousands)(1)

                   

Oil

  $ 27,643    $ 47,537    $ 77,899

Natural gas

    46,543      66,009      123,511

Total

  $ 74,186    $ 113,546    $ 201,410

Oil average sales price (per Bbl)

                   

Price excluding hedges

  $ 29.92    $ 40.53    $ 53.76

Price including hedges

  $ 26.70    $ 29.16    $ 36.43

Natural gas average sales price (per Mcf)

                   

Price excluding hedges

  $ 4.77    $ 5.54    $ 7.41

Price including hedges

  $ 3.82    $ 4.86    $ 4.82

Average production cost and production taxes (per Mcfe)

                   

Average production cost(2)

  $ 1.28    $ 1.42    $ 1.66

Average production taxes(3)

  $ 0.32    $ 0.44    $ 0.58

 
  
  

 

(1)   Does not include the effect of oil and gas hedging activities.

 

(2)   Our production costs include direct lifting costs (labor, repairs and maintenance, materials and supplies), the administrative costs of field offices, insurance and gas handling charges.

 

(3)   Includes severance and ad valorem taxes.

 

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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 investing in our common stock. Any of the following risks could materially and adversely affect our business, financial condition or results of operations. In such a case, you may lose all or part of your investment. The risks described below are not the only risks facing us. Additional risks and uncertainties not currently known to us or those we currently view to be immaterial may also materially adversely affect our business, financial condition or results of operations.

 

 

Risks relating to our business

 

Oil and natural gas prices are volatile. A decline in oil and natural gas prices could adversely affect our financial position, 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 amount of our cash flow we have available for capital expenditures and 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:

 

  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 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 that 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

 

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experiences significant price declines, we may, among other things, be unable to meet our financial obligations, including payments on our 8 1/2% Senior Notes, or make planned capital expenditures.

 

We could incur a write-down of the carrying values of our properties in the future depending on oil and natural gas prices, which could negatively impact our net income and stockholder’s equity.

 

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 unit-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 future net revenues attributable to proved oil and natural gas reserves discounted at 10% plus the lower of cost or market value of unproved properties. The full cost ceiling is evaluated at the end of each quarter using the prices for oil and natural gas at that date as adjusted for our cash flow hedge positions. A significant decline in oil and natural gas prices from current levels, or other factors, without other mitigating circumstances, could cause a future writedown of capitalized costs and a non-cash charge against future earnings.

 

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, 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 tertiary recovery operations. Reserve estimates are, therefore, inherently imprecise and, although we believe that we are reasonably certain of recovering the quantities we disclose as proved reserves, actual results most likely will vary from our estimates. Any significant variations from the interpretations or assumptions used in our estimates or changes of conditions 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 development 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 from the development and production of oil and 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 Commission, the estimates of present values are based on prices and costs as of the date of the estimates. 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, 2005 PV-10 value uses realized prices based on a Henry Hub spot price of $10.08 per MMBtu for natural gas and a WTI Cushing spot price of $61.04 per Bbl for oil.

 

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Approximately 31% of our total proved reserves as of December 31, 2005 are undeveloped, and those reserves may not ultimately be developed.

 

As of December 31, 2005, approximately 31% of our estimated proved reserves were undeveloped. Recovery of undeveloped reserves requires significant capital expenditures and successful drilling and enhanced recovery operations. The reserve data assumes that we can and will make these expenditures and conduct these operations successfully. While we are reasonably certain of our ability to make these expenditures and to conduct these operations under existing economic conditions, these assumptions may not prove correct.

 

Our level of indebtedness may adversely affect our operations and limit our growth. We may have difficulty making debt service payments on our indebtedness as such payments become due.

 

On an as adjusted basis after giving effect to the use of proceeds from this offering, our total debt would be $337.5 million and our total book capitalization would be $486.3 million. Our maximum commitment amount and the borrowing base under our Credit Agreement are $450.0 million and $172.5 million, respectively. We may incur additional debt, including significant secured indebtedness, in order to make future acquisitions, to develop our properties or for other purposes, and we expect to continue to be highly leveraged in the foreseeable future.

 

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

 

  a significant portion of our cash flows from operating activities must be used to service our indebtedness and is not available for other purposes;

 

  we may be at a competitive disadvantage as compared to similar companies that have less debt;

 

  the covenants contained in the agreements governing our outstanding indebtedness and future indebtedness may limit our ability to borrow additional funds, pay dividends and make certain investments and may also affect our flexibility in planning for, and reacting to, changes in the economy and in our industry;

 

  additional financing in the future for working capital, capital expenditures, acquisitions, general corporate or other purposes may have higher costs and more restrictive covenants;

 

  changes in the credit ratings of our debt may negatively affect the cost, terms, conditions and availability of future financing, and lower ratings will increase the interest rate and fees we pay on our revolving bank credit facility; and

 

  we may be more vulnerable to general adverse economic and industry conditions.

 

If an event of default occurs under our Credit Agreement or our 8 1/2% Senior Notes, the lenders or noteholders may declare the principal of, premium, if any, accrued and unpaid interest, and liquidated damages, if any, on such indebtedness to be due and payable.

 

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

 

Availability under our Credit Agreement is subject to a borrowing base set by the banks semi-annually on June 1 and December 1 of each year. In addition, the banks may request a borrowing base redetermination once every six months. If the outstanding borrowings under our Credit

 

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Agreement 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 90 days additional oil and 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 gas properties within 90 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.

 

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. We 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 and our revolving bank credit facility. 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 an economic basis 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.

 

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

 

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produce through successful development, exploration or acquisition activities, our proved reserves and production will decline over time. In addition, approximately 31% of our total estimated proved reserves (by volume) at December 31, 2005 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 enhanced recovery operations. Our reserve estimates reflect that our production rate on current proved developed producing reserve properties will decline at annual rates of approximately 15.8%, 12.4% and 10.2% during 2007, 2008 and 2009, respectively. Thus, our future oil and natural gas reserves and production and, therefore, our cash flow and income are highly dependent on our success in efficiently developing our current reserves and economically finding 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 drilled by us 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 produced economically. 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;

 

  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.

 

Shortages of oil field equipment, services and qualified personnel could reduce our cash flow and adversely affect results of operations.

 

The demand for qualified and experienced field personnel to drill wells and conduct field operations, geologists, geophysicists, engineers and other professionals in the oil and natural gas industry can fluctuate significantly, often in correlation with oil and natural gas prices, causing periodic shortages. Historically, there have been shortages of drilling rigs and other oilfield equipment as demand for rigs and equipment has increased along with the number of wells being drilled. These factors also cause significant increases in costs for equipment, services and personnel. Higher oil and natural gas prices generally stimulate demand and result in increased prices for drilling rigs, crews and associated supplies, equipment and services. It is beyond our

 

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control and ability to predict whether these conditions will exist in the future and, if so, what their timing and duration will be. These types of shortages or price increases could significantly decrease our profit margin, cash flow and operating results, or restrict our ability to drill the wells and conduct the operations which we currently have planned and budgeted.

 

We are subject to complex laws and regulations, including environmental and safety regulations, that 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, 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;

 

  unitization and pooling of properties;

 

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

 

  well stimulation processes;

 

  produced water disposal;

 

  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; and

 

  other environmental damages.

 

Our operations could be significantly delayed or curtailed and our costs of operations could significantly increase as a result of regulatory requirements or restrictions. We are unable to predict the ultimate cost of compliance with these requirements or their effect on our operations.

 

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Our use of hedging arrangements could result in financial losses or reduce our income.

 

To reduce our exposure to decreases in the price of oil and natural gas, we may use fixed-price swaps, collars and option contracts traded on the New York Mercantile Exchange, or NYMEX, over-the-counter options and price and basis swaps with other natural gas merchants and financial institutions or other similar transactions. Under our current hedging policy, we may hedge up to 80% of our anticipated monthly production for a maximum three-year period. As of December 31, 2005, we had hedged 23,760 MMcf and 2,083 MBbl of our natural gas and oil production for 2006 through 2008 at average monthly prices ranging from $6.87 to $10.07 per Mcf of natural gas and $39.33 to $63.27 per Bbl of oil. The fair value of our oil and natural gas derivative instruments outstanding as of December 31, 2005 was a liability of approximately $94.1 million. Hedging arrangements expose us to risk of financial loss in some circumstances, including when:

 

  our production is less than expected;

 

  the counter-party to the hedging contract defaults on its contract obligations; or

 

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

 

In addition, these hedging arrangements may limit the benefit we would receive from increases in the prices for oil and natural gas.

 

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. Although we currently do not, and do not anticipate that we will in the future, enter into derivative contracts that require an initial deposit of cash collateral, our working capital could be impacted if we enter into derivative instruments that require cash collateral and commodity prices change in a manner adverse to us. Future collateral requirements are uncertain and will depend on arrangements with our counterparties and highly volatile oil and natural gas prices.

 

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 gas prices, operating costs, and potential environmental and other liabilities. Such assessments are inexact and their accuracy is inherently uncertain. In connection with our assessments, we perform an engineering, geological and geophysical review of the acquired properties, which we believe is generally consistent with industry practices. However, 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

 

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for preclosing 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. We could incur significant unknown liabilities, including environmental liabilities, or experience losses due to title defects, in our 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.

 

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 CEO, 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 gas production, and developing and executing financing and hedging strategies. These persons include the executive officers listed in “Management—Executive officers and directors.” Our ability to hire and retain our officers and key employees 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.

 

If Mark A. Fischer ceases to be either our Chairman, CEO or President in connection with a change of control, such event could also result in a change of control event occurring under our Phantom Unit Plan as described in “Management—Phantom unit plan.”

 

Oil and natural gas drilling and producing 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;

 

  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 either by the previous owners of properties that we purchase or lease prior to the date we acquire them. While we maintain insurance against some, but not all, of the risks described above, our insurance may not be adequate to cover casualty losses or liabilities. Moreover, in the future, we may not be able to obtain such insurance coverage at premium levels that justify its purchase.

 

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Costs of environmental liabilities could exceed our estimates.

 

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; and

 

  future changes to environmental laws and regulations.

 

Although we believe we have established appropriate reserves for liabilities, including clean up costs, we could be required to set aside additional reserves in the future due to these uncertainties.

 

We are subject to financing and interest rate exposure risks.

 

Our future success depends on our ability to access capital markets and obtain financing at cost-effective rates. Our ability to access financial markets and obtain cost-effective rates in the future are 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 rates due to new tax laws.

 

All of the outstanding borrowings under the Credit Agreement as of December 31, 2005 are subject to market rates of interest as determined from time to time by the banks. Any increases in these rates can have an adverse impact on our results of operations and cash flow. Assuming a constant debt level of $172.5 million, equal to our borrowing base, the cash flow impact for a 12-month period resulting from a 100 basis point change in interest rates would be $1.7 million.

 

The concentration of accounts for our oil and 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, but we may incur an immaterial loss in connection with the bankruptcy of Entergy New Orleans, Inc. Future concentration of sales of oil and natural gas commensurate 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 nonperformance by counterparties. Generally, these contracts are with major

 

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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 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.

 

 

Risks relating to this offering and to owning our common stock

 

Certain stockholders’ shares are restricted from immediate resale but may be sold into the market in the near future. This could cause the market price of our common stock to drop significantly.

 

After this offering, we will have outstanding              shares of common stock. Of these shares, the             shares we and the selling stockholders are selling in this offering, or              shares if the underwriters exercise their over-allotment option in full, will be freely tradable without restriction under the Securities Act except for any shares purchased by one of our “affiliates” as defined in Rule 144 under the Securities Act. All of the shares outstanding other than the shares sold in this offering (a total of              shares, or              shares if the underwriters exercise their over-allotment option in full) will be “restricted securities” within the meaning of Rule 144 under the Securities Act and subject to lock-up arrangements.

 

In connection with this offering, we and our executive officers and directors and the holders of all of our outstanding common stock and common stock equivalents have agreed that, during the period beginning from the date of this prospectus and continuing to and including the date 180 days after the date of this prospectus, neither we nor any of them will, directly or indirectly, offer, sell, offer to sell, contract to sell or otherwise dispose of any shares of our common stock without the prior written consent of J.P. Morgan Securities Inc., except in limited circumstances. See “Underwriting” for a description of these lock-up arrangements. Upon the expiration of these lock-up agreements,              shares, or              shares if the underwriters exercise their over-allotment option in full, will be eligible for sale in the public market under Rule 144 of the Securities Act, subject to volume limitations and other restrictions contained in Rule 144.

 

After this offering, the holders of              shares, or              shares if the underwriters exercise their over-allotment option in full, will have rights, subject to some limited conditions, to demand that we include their shares in registration statements that we file on their behalf, on our behalf or on behalf of other stockholders. By exercising their registration rights and selling a large number of shares, these holders could cause the price of our common stock to decline. Furthermore, if we file a registration statement to offer additional shares of our common stock and have to include shares held by those holders, it could impair our ability to raise needed capital by depressing the price at which we could sell our common stock.

 

Purchasers of common stock will experience immediate and substantial dilution.

 

Based on an assumed initial public offering price of $          per share, purchasers of our common stock in this offering will experience an immediate and substantial dilution of $          per share in the net tangible book value per share of common stock from the initial public offering price, and our as adjusted net tangible book value as of December 31, 2005 after giving effect to this offering would be $          per share. Please read “Dilution” for a complete description of the calculation of net tangible book value.

 

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Our certificate of incorporation and bylaws, as well as Delaware law, contain provisions that could discourage acquisition bids or merger proposals, which may adversely affect the market price of our common stock.

 

Our certificate of incorporation authorizes our board of directors to issue preferred stock without stockholder approval. If our board of directors elects to issue preferred stock, it could discourage or make it more difficult for a third party to acquire us. In addition, some provisions of our certificate of incorporation and bylaws could make it more difficult for a third party to acquire control of us, even if the change of control would be beneficial to our stockholders, including:

 

  a classified board of directors, so that only approximately one-third of our directors are elected each year;

 

  limitations on the removal of directors; and

 

  limitations on the ability of our stockholders to call special meetings and establish advance notice provisions for stockholder proposals and nominations for elections to the board of directors to be acted upon at meetings of stockholders.

 

Delaware law prohibits us from engaging in any business combination with any “interested stockholder,” meaning generally that a stockholder who beneficially owns more than 15% of our stock cannot acquire us for a period of three years from the date this person became an interested stockholder, unless various conditions are met, such as approval of the transaction by our board of directors.

 

Because our existing dividend policy and contractual restrictions limit our ability to pay dividends, investors must look solely to stock appreciation for a return on their investment in us.

 

We do not anticipate paying any cash dividends on our common stock in the foreseeable future. We currently intend to retain all future earnings to fund the development and growth of our business. Any payment of future dividends will be at the discretion of our board of directors and will depend on, among other things, our earnings, financial condition, capital requirements, level of indebtedness, statutory and contractual restrictions applying to the payment of dividends and other considerations that the board of directors deems relevant. The terms of our Credit Agreement and the indenture governing our 8 1/2% Senior Notes limit the payment of dividends. Investors must rely on sales of their common stock after price appreciation, which may never occur, as the only way to realize a return on their investment. Investors seeking cash dividends should not purchase our common stock.

 

If our stock price declines after the initial offering, you could lose a significant part of your investment.

 

The market price of our common stock could be subject to wide fluctuations in response to a number of factors, most of which we cannot control, including:

 

  the failure of securities analysts to cover our common stock after this offering or changes in securities analysts’ recommendations and their estimates of our financial performance;

 

  the public’s reaction to our press releases, announcements and our filings with the Securities and Exchange Commission;

 

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  fluctuations in broader stock market prices and volumes, particularly among securities of oil and gas exploration and production companies;

 

  changes in market valuations of similar companies;

 

  additions or departures of key personnel;

 

  commencement of or involvement in litigation;

 

  announcements by us or our competitors of strategic alliances, significant contracts, new technologies, acquisitions, commercial relationships, joint ventures or capital commitments;

 

  variations in our quarterly results of operations or cash flows or those of other oil and gas exploration and production companies;

 

  risks relating to our business and our industry, including those discussed above;

 

  strategic actions by us or our competitors;

 

  future issuances and sales of our common stock, including sales by our management;

 

  changes in general conditions in the U.S. economy, financial markets or the oil and gas industry; and

 

  investor perceptions of the investment opportunity associated with our common stock relative to other investment alternatives.

 

In recent years, the stock market has experienced extreme price and volume fluctuations. This volatility has had a significant effect on the market price of securities issued by many companies for reasons unrelated to the operating performance of these companies. These market fluctuations may also result in a lower price of our common stock.

 

There is no existing market for our common stock, and we do not know if one will develop to provide you with adequate liquidity. Our stock price will fluctuate after this offering, as a result, you could lose a significant part or all of your investment.

 

Prior to this offering, there has not been a public market for our common stock. We have applied to list our common stock on the NYSE. We cannot predict the extent to which investor interest in our company will lead to the development of an active trading market on the NYSE or otherwise or how liquid that market might become. If an active trading market does not develop, you may have difficulty selling any of our common stock that you buy. The initial public offering price for the shares will be determined by negotiations between us and the underwriters and may not be indicative of prices that will prevail in the open market following this offering. Consequently, you may not be able to sell shares of our common stock at prices equal to or greater than the price paid by you in this offering.

 

The requirements of being a public company, including compliance with the reporting requirements of the Exchange Act and the requirements of the Sarbanes-Oxley Act, may strain our resources, increase our costs and distract management, and we may be unable to comply with these requirements in a timely or cost-effective manner.

 

As a public company with listed equity securities, we will need to comply with new laws, regulations and requirements, certain corporate governance provisions of the Sarbanes-Oxley Act of 2002, related regulations of the SEC and requirements of the NYSE, with which we are not

 

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required to comply as a private company. Complying with these statutes, regulations and requirements will occupy a significant amount of the time of our board of directors and management and will increase our costs and expenses. We will need to:

 

  institute a more comprehensive compliance function;

 

  design, establish, evaluate and maintain a system of internal controls over financial reporting in compliance with the requirements of Section 404 of the Sarbanes-Oxley Act of 2002 and the related rules and regulations of the SEC and the Public Company Accounting Oversight Board;

 

  prepare and distribute periodic public reports in compliance with our obligations under the federal securities laws;

 

  establish new internal policies, such as those relating to disclosure controls and procedures and insider trading;

 

  involve and retain to a greater degree outside counsel and accountants in the above activities; and

 

  establish an investor relations function.

 

In addition, we also expect that being a public company subject to these rules and regulations will require us to modify our director and officer liability insurance, and we may be required to accept reduced coverage or incur substantially higher costs to obtain coverage. These factors could also make it more difficult for us to attract and retain qualified members of our board of directors, particularly to serve on our audit committee, and qualified executive officers.

 

Failure by us to achieve and maintain effective internal control over financial reporting in accordance with the rules of the SEC could harm our business and operating results and/or result in a loss of investor confidence in our financial reports, which could have a material adverse effect on our business and stock price.

 

We are in the process of evaluating our internal controls systems to allow management to report on, and our independent auditors to audit, our internal controls over financial reporting. We will be performing the system and process evaluation and testing (and any necessary remediation) required to comply with the management certification and auditor attestation requirements of Section 404 of the Sarbanes-Oxley Act of 2002. We will be required to comply with Section 404 as of December 31, 2007. However, we cannot be certain as to the timing of completion of our evaluation, testing and remediation actions or the impact of the same on our operations. Furthermore, upon completion of this process, we may identify control deficiencies of varying degrees of severity under applicable SEC and Public Company Accounting Oversight Board rules and regulations that remain unremediated. As a public company, we will be required to report, among other things, control deficiencies that constitute a “material weakness” or changes in internal controls that, or that are reasonably likely to, materially affect internal controls over financial reporting. A “material weakness” is a significant deficiency or combination of significant deficiencies that results in more than a remote likelihood that a material misstatement of the annual or interim financial statements will not be prevented or detected. If we fail to implement the requirements of Section 404 in a timely manner, we might be subject to sanctions or investigation by regulatory authorities such as the SEC or the NYSE. In addition, failure to comply with Section 404 or the report by us of a material weakness may cause investors to lose confidence

 

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in our financial statements, and our stock price may be adversely affected as a result. If we fail to remedy any material weakness, our financial statements may be inaccurate, we may face restricted access to the capital markets, and our stock price may be adversely affected.

 

Our controlling stockholders may have conflicts of interest with other stockholders in the future.

 

After this offering, Mark A. Fischer, our President and Chief Executive Officer, and Charles A. Fischer, Jr., our Executive Vice President and Chief Administrative Officer, will beneficially own approximately     % of our common stock, or approximately     % if the underwriters exercise their over-allotment option in full. As a result, Mark A. Fischer and Charles A. Fischer, Jr. will be able to control the election of our directors, determine our corporate and management policies and determine, without the consent of our other stockholders, the outcome of any corporate transaction or other matter submitted to our stockholders for approval, including potential mergers or acquisitions, asset sales and other significant corporate transactions. So long as this group continues to own a significant amount of the outstanding shares of our common stock, they will continue to be able to strongly influence or effectively control our decisions, including whether to pursue or consummate potential mergers or acquisitions, asset sales and other significant corporate transactions. The interests of Mark A. Fischer and Charles A. Fischer, Jr. may not coincide with the interests of other holders of our common stock.

 

We are a “controlled company” within the meaning of the New York Stock Exchange rules and, as a result, will qualify for, and may rely on, exemptions from certain corporate governance requirements.

 

Because our existing three stockholders acting as a group will beneficially own in excess of 50% of our outstanding shares of common stock after the completion of this offering, these stockholders acting together will be able to control the composition of our board of directors and to direct our management and policies. We expect to be deemed a “controlled company” under the rules of the NYSE. Under these rules, we will elect not to comply with certain corporate governance requirements of the NYSE, including:

 

  the requirement that a majority of our board of directors consist of independent directors;

 

  the requirement that we have a nominating/corporate governance committee that is composed entirely of independent directors with a written charter addressing the committee’s purpose and responsibilities; and

 

  the requirement that we have a compensation committee that is composed entirely of independent directors with a written charter addressing the committee’s purpose and responsibilities.

 

Following this offering, we may utilize some or all of these exemptions. Accordingly, you may not have the same protections afforded to stockholders of companies that are subject to all of the corporate governance requirements of the NYSE. These stockholders’ significant ownership interest could adversely affect investors’ perceptions of our corporate governance.

 

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Affiliates of several of the underwriters of this offering are lenders and/or agents under our Credit Agreement, which may present conflicts of interest.

 

JPMorgan Chase Bank, N.A., an affiliate of J.P. Morgan Securities Inc., is the administrative agent, collateral agent and a lender under our Credit Agreement. In addition, each of Banc of America Securities LLC, Comerica Securities, Inc. and Fortis Securities LLC has an affiliate that is a lender and/or agent under our Credit Agreement. The amount of outstanding indebtedness owed to these lender affiliates under our Credit Agreement will be reduced with a portion of the net proceeds from this offering, which may result in these underwriters being deemed to have received more than 10% of the net offering proceeds. Accordingly, this offering will be made in accordance with the applicable provisions of Rule 2720 of the Conduct Rules of the National Association of Securities Dealers, Inc., which requires, among other things, that the initial public offering price be no higher than that recommended by a “qualified independent underwriter.” Lehman Brothers Inc. is serving as the qualified independent underwriter in connection with this offering. See “Use of proceeds” and “Underwriting.”

 

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Use of proceeds

 

We estimate that our net proceeds from this offering will be approximately $139.0 million, assuming an initial public offering price of $             per share and after deducting underwriting discounts and commissions and estimated offering expenses. A $1.00 increase (decrease) in the assumed initial public offering price per share would increase (decrease) the net proceeds to us from this offering by $         million, assuming the number of shares offered by us, as set forth on the cover page of this prospectus, remains the same and after deducting underwriting discounts and estimated offering expenses payable by us. We will not receive any of the net proceeds from the sale of shares of common stock by the selling stockholders, some of whom are members of our management. See “Principal and selling stockholders.” We intend to use $             million of the net proceeds from this offering to repay the outstanding indebtedness on our Credit Agreement and will use the remaining $             for working capital and general corporate purposes. Although we do not have any material pending or probable acquisitions, we anticipate that we may draw down additional amounts in the future for acquisitions.

 

Certain affiliates of the underwriters to this offering are lenders under our Credit Agreement. JPMorgan Chase Bank, N.A., an affiliate of J.P. Morgan Securities Inc., is the administrative agent, collateral agent and a lender under our Credit Agreement. In addition, each of Banc of America Securities LLC, Comerica Securities, Inc. and Fortis Securities LLC has an affiliate that is a lender and/or agent under our Credit Agreement. We intend to repay $             million of the amounts outstanding under our Credit Agreement with a portion of the net proceeds of this offering, of which approximately $             million will reduce the indebtedness outstanding to such affiliates in the aggregate. See “Underwriting.”

 

 

Dividend policy

 

Following this offering of our common stock, we do not currently anticipate paying any cash dividends on our common stock. We currently intend to retain all future earnings following this offering to fund the development and growth of our business. Any future determination relating to our dividend policy will be at the discretion of our board of directors and will depend on our results of operations, financial condition, capital requirements and other factors deemed relevant by our board. We are also currently limited in our ability to pay dividends under our Credit Agreement and the indenture governing our 8 1/2% Senior Notes.

 

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Capitalization

 

The following table sets forth our capitalization as of December 31, 2005:

 

  on a historical basis;

 

  on an as adjusted basis to reflect a          -for-          stock split to be effected as a stock dividend prior to the consummation of this offering, this offering and the application of the net proceeds from this offering as described under “Use of proceeds” above, as if this offering occurred on December 31, 2005.

 

As of March 1, 2006, we had $129.0 million of indebtedness outstanding under our Credit Agreement, which will be repaid with the net proceeds of this offering as described under “Use of proceeds.” This table is unaudited and should be read together with our financial statements and the accompanying notes included in this prospectus.

 

    As of December 31, 2005

 
(Dollars in thousands)   Historical     As Adjusted(1)  

 

 

Cash and cash equivalents

  $ 1,598     $ 31,598  

Long-term debt, including capital leases and current maturities(2):

               

Credit Agreement

    109,000        

Other

    12,544       12,544  

8 1/2% Senior Notes due 2015

    325,000       325,000  

Total debt

    446,544       337,544  

Stockholders’ equity:

               

Common stock, $.01 par value; 1,000 shares issued and outstanding historical;          shares issued and outstanding, as adjusted

    1       1  

Additional paid-in capital

          139,000  

Retained earnings

    57,683       57,683  

Accumulated other comprehensive loss, net of taxes

    (47,967 )     (47,967 )

Total stockholders’ equity

    9,717       148,717  

Total capitalization

  $ 456,261     $ 486,261  

 

 

 

(1)   A $1.00 increase (decrease) in the assumed initial public offering price per share would increase (decrease) each of as adjusted cash and cash equivalents, additional paid-in capital, total stockholders’ equity and total capitalization by $         million, assuming the number of shares offered by us, as set forth on the cover page of this prospectus, remains the same and after deducting underwriting discounts and estimated offering expenses payable by us. The pro forma information discussed above is illustrative only and following the completion of this offering will be adjusted based on the actual initial public offering price and other terms of this offering determined at pricing.

 

(2)   Includes current maturities of long-term debt and capital leases of $3.1 million.

 

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Dilution

 

Purchasers of the common stock in this offering will experience immediate and substantial dilution in the net tangible book value per share of the common stock for accounting purposes. Net tangible book value per share represents the amount of the total tangible assets less our total liabilities, divided by the number of shares of common stock that will be outstanding after giving effect to a              stock split to be effected in the form of a stock dividend prior to the closing of this offering. At December 31, 2005, we had a net tangible book value of $0.6 million, or $             per share of outstanding common stock after giving effect to a              -for-             stock split to be effected in the form of a stock dividend prior to the closing of this offering. After giving effect to the sale of              shares of common stock in this offering at an assumed initial public offering price of $         per share and after the deduction of underwriting discounts and commissions and estimated offering expenses, the as adjusted net tangible book value at December 31, 2005 would have been $139.6 million or $         per share. This represents an immediate increase in such net tangible book value of $         per share to existing stockholders and an immediate and substantial dilution of $         per share to new investors purchasing common stock in this offering. The following table illustrates this per share dilution:

 

Assumed initial public offering price per share

          $               

Net tangible book value per share as of December 31, 2005

   $                

Increase attributable to new public investors

   $                

As adjusted net tangible book value per share after this offering

          $               

Dilution in as adjusted net tangible book value per share to new investors

          $               

 

A $1.00 increase (decrease) in the assumed initial public offering price per share would increase (decrease) our pro forma net tangible book value by $         million, our net tangible book value per share by $         per share and the dilution in pro forma net tangible book value to new investors in this offering by $         per share, assuming the number of shares offered by us, as set forth on the cover page of this prospectus, remains the same.

 

The following table summarizes, on an as adjusted basis set forth above as of December 31, 2005, the total number of shares of common stock owned by existing stockholders and to be owned by new investors, the total consideration paid, and the average price per share paid by our existing stockholders and to be paid by new investors in this offering at $            , the mid-point of the range of the initial public offering prices set forth on the cover page of this prospectus, calculated before deduction of estimated underwriting discounts and commissions.

 

     Shares
Purchased(1)


   Total Consideration(2)

  

Average Price

Per Share

     Number    Percent     Amount      Percent    

Existing Stockholders

                %    $ 1,000            %    $             

New Public Investors

                            
    

Total

        100.0%    $      100.0%       

 

(1)   The number of shares disclosed for the existing stockholders includes              shares being sold by the selling stockholders in this offering. The number of shares disclosed for the new investors does not include the shares being purchased by the new investors from the selling stockholders in this offering.
(2)   A $1.00 increase (decrease) in the assumed initial public offering price per share would increase (decrease) total consideration paid by new investors by $             million, or increase (decrease) the percent of total consideration paid by new investors by         %, assuming the number of shares offered by us, as set forth on the cover page of this prospectus, remains the same.

 

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As of December 31, 2005, there were              shares of our common stock outstanding, after giving effect to the stock split to be effected in the form of a stock dividend prior to the closing of this offering, held by three stockholders of record. Sales by the selling stockholders in this offering will reduce the number of shares of common stock held by existing stockholders to              or approximately         % of the total number of shares of common stock outstanding after this offering and will increase the number of shares of common stock held by new investors to             or approximately         % of the total number of shares of common stock outstanding after this offering.

 

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Unaudited pro forma financial data

 

The following unaudited pro forma condensed financial information for the fiscal year ended December 31, 2005 gives effect to the following transactions:

 

  our acquisition of the limited partner interest in CEI Bristol, including hedge settlement costs; and

 

  the issuance of $325.0 million principal amount of our 8 1/2% Senior Notes on December 1, 2005 and the application of net proceeds.

 

The following unaudited pro forma financial information and explanatory notes present how the combined financial statements of Chaparral and CEI Bristol may have appeared had the two transactions above been effective as of January 1, 2005.

 

The unaudited pro forma combined financial information shows the impact of the acquisition of the limited partners’ interest in CEI Bristol on Chaparral’s historical results of operations under the purchase method of accounting. The unaudited pro forma financial information combines the historical financial information of Chaparral and CEI Bristol for the year ended December 31, 2005.

 

The unaudited pro forma combined financial information is presented for illustrative purposes only and does not indicate the financial results of the combined companies had the companies actually been combined. In addition, as explained in more detail in the accompanying notes to the unaudited pro forma combined financial information, the allocation of the purchase price reflected in the pro forma combined financial information is subject to adjustment and may vary from the actual purchase price allocation that will be recorded.

 

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Chaparral Energy, Inc. and subsidiaries

Unaudited pro forma condensed consolidated statement of

operations for the year ended December 31, 2005

 

(Dollars in thousands, except share and per share
amounts)
  Chaparral
historical
    CEI Bristol
historical
    Adjustments
(Note 2)
    Pro forma  


Revenues

                               

Oil and gas sales

  $ 201,410     $ 29,773     $     $ 231,183  

Loss on oil and gas hedging activities

    (68,324 )     (12,836 )           (81,160 )

Total revenues

    133,086       16,937             150,023  

Costs and expenses

                               

Lease operating

    42,147       6,867       (693 )(a)     48,321  

Production tax

    14,626       2,458             17,084  

Depreciation, depletion and amortization

    31,423       4,818       1,700 (b)     37,941  

General and administrative

    9,808       196       693 (a)     10,697  

Total costs and expenses

    98,004       14,339       1,700       114,043  

Operating income

    35,082       2,598       (1,700 )     35,980  

Non-operating income (expense)

                               

Interest expense

    (15,588 )           (17,517 )(c)     (33,105 )

Other income

    665       20       (3 )(d)     682  

Net non-operating income (expense)

    (14,923 )     20       (17,520 )     (32,423 )

Income before income taxes

    20,159       2,618       (19,220 )     3,557  

Income tax expense

    7,309             (6,019 )(e)     1,290  

Net income

  $ 12,850     $ 2,618     $ (13,201 )   $ 2,267  
   


 


 


 


Earnings per share (historical)

                               

Net income per share

  $ 12,850                     $ 2,267  
   


                 


Weighted average number of shares used in calculation of basic and diluted earnings per share

    1,000                       1,000  
   


                 


Earnings per share (pro forma for stock split)

                               

Net income per share

  $                       $    
   


                 


Weighted average number of shares used in calculation of basic and diluted earnings per share

                               
   


                 


 

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Notes to unaudited pro forma condensed

consolidated statement of operations

 

Note 1: Basis of presentation

 

The accompanying unaudited pro forma statement of operations of Chaparral for the year ended December 31, 2005 has been prepared to give effect to the issuance of $325.0 million principal amount of the notes issued on December 1, 2005, and the acquisition of CEI Bristol as if the transactions occurred on January 1, 2005. The effects of the issuance of the $325.0 million principal amount of the notes are not included in the pro forma combined financial information included in Note 2 to the Chaparral Energy, Inc. financial statements.

 

Chaparral uses the full cost method of accounting for its oil and gas producing activities while CEI Bristol uses the successful efforts method of accounting. Adjustments have been made to present the pro forma condensed consolidated statements of operations on the full cost method of accounting for oil and gas operations.

 

All intercompany balances and transactions have been eliminated.

 

 

Note 2: Pro forma adjustments

 

The unaudited pro forma statements of operations include the following adjustments:

 

(a)   Represents the elimination of joint operating overhead reimbursements historically charged to CEI Bristol by Chaparral.

 

(b)   Represents the adjustment of depletion, depreciation and amortization of oil and gas properties related to the allocation of additional basis of oil and gas properties associated with the purchase price allocation and change in accounting for depletion, depreciation and amortization for CEI Bristol from successful efforts to full cost.

 

(c)   Represents the adjustment to historical interest expense for the debt issued in connection with the offering of the notes and for the reduction of the revolving credit facility as presented in the following table:

 

(Dollars in thousands)    Year ended
December 31, 2005

  

Historical interest expense

   $ 15,588

Interest expense resulting from the notes issued

     25,323

Reduction in interest expense from the reduction of the revolving credit line

     (8,648)

Amortization of $9.1 million deferred financing costs related to the notes issued—10 years

     842
    

Total pro forma interest expense

   $ 33,105

  

 

(d)   Elimination of CEI Bristol’s gain on sale of oil and gas properties as required by the full-cost method of accounting. Also includes the elimination of the 1% general partners interest of equity in earnings of CEI Bristol historically included in Chaparral’s income statement.

 

(e)   Adjustments to record the income tax impact of the inclusion of CEI Bristol’s results of operations and the pro forma adjustments at Chaparral’s effective tax rate of 36.3%.

 

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Selected consolidated financial data

 

You should read the following financial data of Chaparral in connection with the financial statements and related notes and “Management’s discussion and analysis of financial condition and results of operations” included in this prospectus. The financial data as of and for each of the five years ended December 31, 2005 were derived from our audited consolidated financial statements. Our historical results are not necessarily indicative of results to be expected in future periods.

 

    Year ended December 31,

 
(Dollars in thousands)   2001     2002     2003     2004     2005  

 

 

 

 

 

Operating results data:

                                       

Revenues

                                       

Oil and gas sales

  $ 44,250     $ 42,653     $ 74,186     $ 113,546     $ 201,410  

Gain (loss) on oil and gas hedging activities

    10       (749 )     (12,220 )     (21,350 )     (68,324 )
   


 


 


 


 


Total revenues

    44,260       41,904       61,966       92,196       133,086  
   


 


 


 


 


Costs and expenses

                                       

Lease operating

    13,566       15,037       19,520       26,928       42,147  

Production taxes

    3,226       3,114       4,840       8,272       14,626  

Depreciation, depletion and amortization

    5,835       7,910       10,376       18,234       31,423  

General and administrative

    3,506       4,059       4,946       5,985       9,808  
   


 


 


 


 


Total costs and expenses

    26,133       30,120       39,682       59,419       98,004  
   


 


 


 


 


Operating income

    18,127       11,784       22,284       32,777       35,082  
   


 


 


 


 


Non-operating income (expense)

                                       

Interest expense

    (4,966 )     (3,998 )     (4,116 )     (6,162 )     (15,588 )

Other income

    201       1,012       208       279       665  
   


 


 


 


 


Net non-operating expense

    (4,765 )     (2,986 )     (3,908 )     (5,883 )     (14,923 )

Income from continuing operations before income taxes and accounting change

    13,362       8,798       18,376       26,894       20,159  

Income tax expense

    5,099       3,134       6,932       9,629       7,309  
   


 


 


 


 


Income from continuing operations before accounting change

    8,263       5,664       11,444       17,265       12,850  

Cumulative effect of change in accounting principle, net of income taxes

                (887 )            

Discontinued operations, net of income taxes

    (575 )     (617 )                  
   


 


 


 


 


Net income

  $ 7,688     $ 5,047     $ 10,557     $ 17,265     $ 12,850  

 

 

 

 

 

 

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    Year ended December 31,

 
(Dollars in thousands, except share and per share amounts)   2001     2002     2003     2004     2005  

 

 

 

 

 

Earnings per share (historical):

                                       

Income per share from continuing operations

  $ 8,263     $ 5,664     $ 11,444     $ 17,265     $ 12,850  

Income (loss) per share from accounting change, net

                (887 )            

Income (loss) per share from discontinued operations, net

    (575 )     (617 )                  
   


 


 


 


 


Net income per share

  $ 7,688     $ 5,047     $ 10,557     $ 17,265     $ 12,850  
   


 


 


 


 


Weighted average number of shares used in calculation of basic and diluted earnings per share

    1,000       1,000       1,000       1,000       1,000  

Earnings per share (pro forma for stock split):

                                       

Income per share from continuing operations

  $       $       $       $       $    

Income (loss) per share from accounting change, net

                                       

Income (loss) per share from discontinued operations, net

                                       
   


 


 


 


 


Net income per share

  $       $       $       $       $    
   


 


 


 


 


Weighted average number of shares used in calculation of basic and diluted earnings per share

                                       

Cash flow data:

                                       

Net cash provided by operating activities

  $ 13,036     $ 17,480     $ 32,541     $ 49,849     $ 65,111  

Net cash used in investing activities

    (47,846 )     (27,505 )     (55,213 )     (95,120 )     (334,435 )

Net cash provided by financing activities

    24,821       8,921       26,146       54,061       257,080  

 

 

 

 

 

 

    As of December 31,

 
(Dollars in thousands)   2001   2002     2003     2004     2005  

 
 

 

 

 

Financial position data:

                                     

Cash and cash equivalents

  $ 2,237   $ 1,578     $ 5,052     $ 13,842     $ 1,598  

Total assets

    129,855     142,919       211,086       308,126       646,679  

Total debt

    79,868     91,780       118,355       176,622       446,544  

Undistributed earnings

    15,373     20,420       30,977       48,242       57,683  

Accumulated other comprehensive income (loss), net of income taxes

    3,379     (3,733 )     (4,900 )     (12,107 )     (47,967 )

Total equity

    18,753     16,688       26,078       36,136       9,717  

 
 

 

 

 

 

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Management’s discussion and analysis of financial

condition and results of operations

 

The following discussion is intended to assist you in understanding our business and results of operations together with our present financial condition. This section should be read in conjunction with our consolidated financial statements and the accompanying notes included elsewhere in this prospectus.

 

Statements in our discussion may be forward-looking statements. These forward-looking statements involve risks and uncertainties. We caution that a number of factors could cause future production, revenues and expenses to differ materially from our expectations.

 

 

Overview

 

We are an independent oil and natural gas company engaged in the production, acquisition and exploitation of oil and natural gas properties. Our areas of operation include the Mid-Continent, Permian Basin, Gulf Coast, East Texas, North Texas and the Rocky Mountains. We maintain a portfolio of proved reserves, development and exploratory drilling opportunities, and enhanced oil recovery projects. As of December 31, 2005, we had estimated proved reserves of 618 Bcfe, with a PV-10 value of $1.6 billion. Our reserves were 69% proved developed and 67% gas.

 

On September 30, 2005, we acquired the limited partner interest in CEI Bristol Acquisition, L.P. from TIFD III-X LLC, an affiliate of General Electric Capital Corporation. Total consideration paid by us, including costs associated with the settlement of all previously existing hedge positions by CEI Bristol, was approximately $158 million. Prior to this acquisition, we held a 1% general partner interest through our wholly-owned subsidiary Chaparral Oil, L.L.C. and TIFD III-X LLC held a 99% limited partner interest in CEI Bristol. Chaparral Oil, L.L.C. also managed CEI Bristol and its properties since 2000.

 

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 gas reserves that are economically recoverable. The preparation of our financial statements in conformity with generally accepted accounting principles 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 gas activities.

 

Oil and gas prices fluctuate widely. The prices we receive for our oil and gas production affect our:

 

  cash flow available for capital expenditures;
  ability to borrow and raise additional capital;
  quantity of oil and natural gas we can produce;
  quantity of oil and gas reserves; and
  operating results for oil and gas activities.

 

We generally hedge a substantial portion of our expected future oil and natural gas production to reduce our exposure to commodity price decreases. See ”—Quantitative and qualitative disclosures regarding market risks“ below for a discussion of our hedging and hedge positions.

 

Generally our producing properties have declining production rates. Our reserve estimates reflect that our production rate on current proved developed producing reserve properties will decline

 

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at annual rates of approximately 15.8%, 12.4% and 10.2% during 2007, 2008 and 2009, respectively. 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.

 

We believe the most significant, subjective or complex estimates we make in preparation of our financial statements are:

 

  the amount of estimated revenues from oil and gas sales;
  the quantity of our proved oil and gas reserves;
  the timing of future drilling, development and abandonment activities;
  the value of our derivative positions;
  the realization of deferred tax assets; and
  the full cost ceiling limitation.

 

We base our estimates on historical experience and various assumptions that we believe are reasonable under the circumstances. Actual results may differ from these estimates.

 

 

Comparison of year ended December 31, 2005 to year ended December 31, 2004

 

Oil and gas sales.    Oil and gas sales before losses from hedging activity increased $87.9 million, or 77%, from 2004. The increase was due to average realized prices being 33% higher in 2005 and an increase of 34% in production volumes. The average prices received for oil increased 33% to $53.76 per barrel and for gas increased 34% to $7.41 per Mcf compared to 2004. Because of the increase in oil and gas prices our loss from oil and gas hedging activities increased by $47.0 million from 2004. Of the $47.0 million increase, $32.8 million was related to hedge settlement payments and $14.2 million was due to hedge ineffectiveness. The effect of our hedging program decreased average realized prices $2.69 per Mcfe in 2005 compared to a decrease of $1.13 of Mcfe in 2004.

 

Production volumes increased 34% (6,393 MMcfe) from 2004 primarily due to our expanded drilling program, the addition of volumes from acquisitions and enhancements of our existing properties. Production volumes increased by 19% (2,770 MMcfe) in the Mid-Continent, 26% (586 MMcfe) in the Permian Basin, 259% (1,943 MMcfe) in East Texas, 105% (376 MMcfe) in the Gulf Coast, 36% (203 MMcfe) in North Texas, and 248% (515 MMcfe) in the Rocky Mountains.

 

Lease operating expenses.    Lease operating expenses increased $15.2 million, or 57%, from 2004 due to increases in the number of net producing wells and higher oilfield service costs. Approximately $2.4 million was due to increases in gas handling charges primarily due to increased production volumes. We incurred $4.5 million of costs associated with workovers in 2005 compared to $2.4 million in 2004. On a per unit basis, lease operating expenses increased $0.24 per Mcfe primarily due to higher field level costs.

 

Production taxes.    Production taxes, which include ad valorem taxes, are paid primarily based on oil and gas sales prices and increased by $6.4 million from 2004. This increase was caused by a 33% increase in prices and a 34% increase in oil and gas production. On a per Mcfe basis, production taxes increased from $0.44 to $0.58 due primarily to higher prices.

 

Depreciation, depletion and amortization (DD&A).    DD&A increased $13.2 million, or 72%, primarily due to an increase in DD&A on oil and gas properties of $12.4 million. For oil and gas properties, $7.0 million of the increase was due to higher production volumes in 2005 and $5.4

 

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million was due to an increase in the DD&A rate per equivalent unit of production. Our DD&A rate per equivalent unit of production increased by $0.28 to $1.09 per Mcfe primarily due to estimated higher future development costs for reserve extensions and discoveries.

 

General and administrative expenses (G&A).    G&A expense increased by $3.8 million, or 64%, from 2004. Approximately $0.5 million of the increase is due to professional fees associated with documenting our internal controls over financial reporting for compliance with the Sarbanes- Oxley Act of 2002. The remainder of the increase is due primarily to an increase in our office staff and related requirements caused by the increase in our level of activity. G&A expense is net of $6.2 million in 2005 and $4.2 million in 2004 capitalized as part of our exploration and development activities. On a per unit basis, G&A expense increased from $0.32 per Mcfe in 2004 to $0.39 per Mcfe in 2005.

 

Interest expense.    Interest expense increased by $9.4 million, or 153%, compared to 2004, primarily as a result of increased levels of borrowings and higher interest rates paid. Approximately $5.6 million of the increase is due to an increase of approximately $64.0 million in the average amount outstanding under the Credit Agreement and term notes and an increase in the average interest rate paid from 4.3% in 2004 to 5.7% in 2005 (which is 33.3% higher than 2004). Approximately $2.4 million of the increase is due to the issuance of the 8 1/2% Senior Notes on December 1, 2005 and $1.4 million of the increase is due to the GE Bridge Loan entered into to finance the CEI-Bristol acquisition.

 

 

Comparison of year ended December 31, 2004 to year ended December 31, 2003

 

Oil and gas sales.    Oil and gas sales before losses from hedging activity increased $39.4 million, or 53%, from 2003. The increase was due to the average realized price being 24% higher in 2004 and an increase of 24% in production volumes. The average price received for oil increased 36% to $40.53 per barrel and for gas increased 16% to $5.54 per Mcf compared to 2003. Because of the increase in oil and gas prices our loss from oil and gas hedging activities increased by $9.1 million from 2003. The effect of our hedging program decreased the average realized price by $1.13 per Mcfe in 2004 compared to a decrease of $0.80 per Mcfe in 2003.

 

Production volumes increased 24% (3,655 MMcfe) from 2003 due to our drilling program, additions from acquisitions and enhancements of our existing properties. Production volumes increased in our areas by 10% (1,452 MMcfe) in the Mid-Continent, 148% (1,349 MMcfe) in the Permian Basin, 88% (351 MMcfe) in East Texas, 63% (138 MMcfe) in the Gulf Coast, 134% (325 MMcfe) in North Texas, and 24% (40 MMcfe) in the Rocky Mountains.

 

Lease operating expenses.    Lease operating expenses increased $7.4 million, or 38%, from 2003 due to increases in the number of net producing wells and higher oilfield service costs. We incurred $2.4 million of costs associated with workovers in 2004 compared to $1.6 million in 2003. On a per unit basis, lease operating expenses increased $0.14 per Mcfe primarily due to higher field level costs.

 

Production taxes.    Production taxes, which include ad valorem taxes, are paid primarily based on oil and gas sales and increased by $3.4 million from 2003. This increase was caused mostly by a 24% increase in prices and a 24% increase in oil and gas production. On a per Mcfe basis, production taxes increased from $0.32 to $0.44 primarily due to higher prices.

 

Depreciation, depletion and amortization.    DD&A of oil and gas properties increased $7.2 million, DD&A for property and equipment increased $0.5 million and the accretion for our asset

 

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retirement obligation increased $0.2 million for a total increase of $7.9 million, or 76%, from 2003. For oil and gas properties, $3.0 million of the increase was due to higher production volumes in 2004 and $4.2 million of the increase was due to an increase in the DD&A rate per equivalent unit of production in 2004. Our DD&A rate per equivalent unit of production increased by $0.28 per Mcfe to $0.81 primarily due to estimated higher future development costs for reserve extensions and discoveries. DD&A on property and equipment increased due to acquisition of additional assets.

 

General and administrative expenses.    G&A expense increased by $1.0 million, or 21%, from 2003. The increase was due primarily to an increase in our office staff and related requirements caused by the increase in our level of activity. G&A expense was net of $4.2 million in 2004 and $3.1 million in 2003 capitalized as part of our exploration and development activities. On a per unit basis, G&A expense was $0.32 per Mcfe in 2003 and 2004.

 

Interest expense.    Interest expense increased by $2.0 million, or 50%, compared to 2003, primarily as a result of increased levels of borrowings and higher interest rates paid. An increase in outstanding debt in 2004 accounted for $1.7 million of the increase.

 

Income tax expense.    The effective tax rates for 2004 and 2003 were 36% and 38% respectively. The effective tax rate exceeds the federal statutory tax rate primarily due to state income taxes imposed by the various states where we have production offset partially by reductions for statutory depletion carryforwards and other items. Estimates of future taxable income can be significantly affected by changes in oil and gas prices, estimates of the timing and amount of future production and estimates of future operating expenses and capital costs.

 

Cumulative effect of change in accounting principle.    We adopted SFAS No. 143 “Accounting for Asset Retirement Obligations” as of January 1, 2003. This statement changed the method of accounting for expected future costs associated with our obligation to perform site reclamation, dismantle facilities and plug and abandon wells. As a result of our adoption of SFAS No. 143, we recorded a $4.4 million increase in the net capitalized costs of our oil and gas properties and an initial asset retirement obligation of $5.9 million. Additionally, we recognized a cumulative loss effect of the accounting change of $0.9 million, net of a tax benefit of $0.5 million.

 

 

Liquidity and capital resources

 

Overview.    Our primary sources of liquidity are cash generated from our operations and our $450.0 million revolving credit line. At December 31, 2005, we had approximately $1.6 million of cash and cash equivalents and $62.5 million of availability under our revolving credit line with a borrowing base of $172.5 million. We believe that we will have sufficient funds available through our cash from operations and borrowing capacity under our revolving line of credit to meet our normal recurring operating needs, debt service obligations, planned capital expenditures and contingencies for the next 12 months.

 

We pledge our producing oil and gas properties to secure our revolving credit line. The banks establish a borrowing base by making an estimate of the collateral value of our oil and gas properties. We utilize the available funds as needed to supplement our operating cash flows as a financing source for our capital expenditures. Our ability to fund our capital expenditures is dependent on the level of product prices and the success of our acquisition and development program in adding to our available borrowing base. If oil and gas prices decrease from the amounts used in estimating the collateral value of our oil and gas properties, the borrowing base

 

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may be reduced, thus reducing funds available for our capital expenditures. We mitigate a potential reduction in our borrowing base caused by a decrease in oil and gas prices through the use of commodity derivatives.

 

In this section we describe our current plans for capital expenditures, identify the resources available to fund the capital expenditures and discuss the principal factors that can affect our liquidity and capital resources.

 

Capital expenditures.    For the year ended December 31, 2005, we incurred actual costs as summarized by area in the following table:

 

(Dollars in thousands)   For the year ended
December 31, 2005(1)
   Percent
of total

Mid-Continent

  $ 158,999    47.7%

Permian Basin

    74,762    22.4%

East Texas

    24,880    7.5%

North Texas

    29,177    8.8%

Rocky Mountains

    13,213    4.0%

Gulf Coast

    32,007    9.6%
    $ 333,038    100.0%

 

(1)   Includes $4.7 million of additions relating to increases in Chaparral’s asset retirement obligations.

 

In addition to the capital expenditures for oil and gas properties, we spent approximately $5.7 million for acquisition and construction of new office and administrative facilities and equipment during 2005.

 

Our current 2006 capital expenditure budget for oil and gas properties is $210.0 million assuming this offering is consummated. Our 2005 actual and 2006 budgeted capital expenditures are detailed in the table below:

 

(Dollars in thousands)    For the year
ended
December 31,
2005(1)
   Percent
of total
   2006
budgeted
capital
expenditures
   Percent
of total

Development activities:

                       

Developmental drilling

   $ 81,527    24.5%    $ 91,000    43.3%

Enhancements

     15,549    4.6%      22,000    10.5%

Tertiary recovery

     6,403    1.9%      16,000    7.6%

Acquisitions

     222,285    66.8%      70,000    33.4%

Exploration activities

     7,274    2.2%      11,000    5.2%

Total

   $ 333,038    100.0%    $ 210,000    100.0%

 

(1)   Includes $4.7 million of additions relating to increases in Chaparral’s asset retirement obligations.

 

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Our budgeted development and exploratory drilling capital expenditures summarized by area are detailed in the table below:

 

(Dollars in thousands)   2006 drilling
capital
expenditures
   Percent
of total

Mid-Continent

  $ 61,000    59.8%

Permian Basin

    11,000    10.8%

East Texas

    1,000    1.0%

North Texas

    9,000    8.8%

Rocky Mountains

    10,000    9.8%

Gulf Coast

    10,000    9.8%
    $ 102,000    100.0%

 

A majority of our capital expenditure budget for developmental drilling in 2006 is allocated to our core areas of the Mid-Continent and Permian Basin. The wells we drill in these areas are primarily infill or single stepout wells. We also have budgeted increased capital expenditures for our CO2 tertiary recovery projects in the Mid-Continent and Permian Basin.

 

We continually evaluate our capital needs and compare them to our estimated funds available. Our actual expenditures during fiscal 2006 may be higher or lower than our budgeted amounts. The final determination with respect to the drilling of any well, including those currently budgeted, will depend on a number of factors, including the results of our development and exploration efforts, the availability of sufficient capital resources by us and other participants for drilling prospects, economic and industry conditions at the time of drilling, including prevailing and anticipated prices for oil and natural gas and the availability of drilling rigs and crews, our financial results and the availability of leases on reasonable terms and permitting for the potential drilling locations.

 

Cash provided from operating activities.    Substantially all of our cash flow from operating activities is from the production and sale of oil and gas reduced by associated hedging activities. We use the net cash provided by operations to partially fund our acquisition, exploration and development activities. For the year ended December 31, 2005, the net cash provided from operations was approximately 36% of our net cash used in investing activities excluding the CEI Bristol acquisition. For the year ended December 31, 2005, cash flow from operating activities increased by 31% from the prior year. This increase was due primarily to an increase in oil and gas sales revenue partially offset by higher operating expense.

 

Our current credit facility.    We entered into a Sixth Restated Credit Agreement, which we refer to as our Credit Agreement, on June 22, 2005 which provides for a $450.0 million maximum commitment amount, is secured by our oil and gas properties and matures on June 22, 2009. Availability under our Credit Agreement is subject to a borrowing base set by the banks semi-annually on June 1 and December 1 of each year. In addition, the banks may request a borrowing base redetermination once every six months. If the outstanding borrowings under our Credit Agreement 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 90 days additional oil and gas properties we own for consideration in connection with the determination of the borrowing base sufficient to

 

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eliminate the excess or (3) to eliminate the excess through a combination of repayments and the submission of additional oil and gas properties within 90 days. Prior to the acquisition of CEI Bristol, the borrowing base was increased from $235.0 million to $270.0 million on September 30, 2005. At September 30, 2005 we had an outstanding balance of $243.5 million under our Credit Agreement, and the borrowing base was $270.0 million. The borrowing base under our Credit Agreement was reduced from $270.0 million to $172.5 million as a result of our additional debt issued in the offering of our 8 1/2% Senior Notes on December 1, 2005. As of March 1, 2006, we had $129.0 million outstanding under our Credit Agreement.

 

Borrowings under our Credit Agreement are made, at our option, as either Eurodollar loans or Alternate Base Rate, or ABR, loans. At December 31, 2005 all of our borrowings were Eurodollar loans.

 

Interest on Eurodollar loans is computed at LIBOR, 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 the agreement, plus a margin where the margin varies from 1.25% to 2.00% depending on the utilization percentage of the borrowing base. At December 31, 2005, the LIBOR rate was 4.43%, the Statutory Reserve Rate multiplier was 100% and the applicable margin and commitment fee together were 1.95% resulting in an effective interest rate of 6.38% for Eurodollar borrowings. 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 the ABR loans is computed as the greater of (1) the Prime Rate, as defined in our Credit Agreement, or (2) the Federal Funds Effective Rate plus  1/2 of 1%; plus a margin where the margin varies from 0.00% to 0.50% depending on the utilization percentage of the borrowing base. At December 31, 2005 the applicable rate was 7.25% and the applicable margin was 0% resulting in an effective interest rate of 7.25% for ABR borrowings. Interest payments on ABR borrowings are due the last day of each March, June, September and December.

 

Commitment fees of 0.25% to 0.375% accrue on the unused portion of the borrowing base amount, depending 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 Credit Agreement contains restrictive covenants that may limit our ability to, among other things, pay cash dividends, incur additional indebtedness, sell assets, make loans to others, make investments, enter into mergers, change material contracts, incur liens and engage in certain other transactions without the prior consent of the lenders. The agreement also requires us to maintain a Current Ratio, as defined in our Credit Agreement, of not less than 1.0 and a Minimum Debt Service Coverage Ratio, as defined in our Credit Agreement, of not less than 1.0. We believe we are in compliance with all covenants as of December 31, 2005.

 

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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 accordance with generally accepted accounting principles. Since compliance with financial covenants is a material requirement under our Credit Agreement, we consider the current ratio calculated under our Credit Agreement to be useful as a measure of our liquidity because it includes the funds available to us under our Credit Agreement and is not affected by the volatility in working capital caused by changes in the fair value of derivatives. At December 31, 2004 and 2005 our current ratio as computed using generally accepted accounting principles was 0.92 and 0.65, respectively. After giving effect to the adjustments, our current ratio computed for loan compliance purposes was 1.57 and 2.05, respectively. The following table reconciles our current assets and current liabilities using generally accepted accounting principles to the same items for purposes of calculating the current ratio for our loan compliance:

 

     December 31,

 
(Dollars in thousands)    2004     2005  


Current assets per GAAP

   $ 52,499     $ 77,255  

Plus—Availability under Credit Agreement

     20,611       62,500  

Less—Deferred tax asset on hedges and asset retirement obligation

     (5,291 )     (24,057 )

Less—Short-term hedge instruments

           (1,016 )
    


Current assets as adjusted

   $ 67,819     $ 114,682  
    


Current liabilities per GAAP

   $ 57,185     $ 119,293  

Less—Short term hedge instruments

     (13,810 )     (63,125 )

Less—Short term asset retirement obligation

     (262 )     (346 )
    


Current liabilities as adjusted

   $ 43,113     $ 55,822  
    


Current ratio for loan compliance

     1.57       2.05  


 

On September 30, 2005, in connection with the CEI Bristol acquisition, we borrowed $132.0 million from General Electric Capital Corporation. This loan, which we referred to as the GE Bridge Loan, was due at maturity on June 30, 2006, bore interest at LIBOR plus 2% and was collateralized by the oil and gas properties of CEI Bristol. The net proceeds of the offering of our 8 1/2% Senior Notes on December 1, 2005 were used to repay approximately $175.0 million of the amount outstanding under the Credit Agreement and pay off the GE Bridge Loan.

 

Our 8 1/2% Senior Notes due 2015.    On December 1, 2005, we sold $325.0 million aggregate principal amount of 8 1/2% Senior Notes maturing on December 1, 2015. There is no sinking fund for the 8 1/2% Senior Notes. The 8 1/2% Senior Notes are our senior unsecured obligations, rank equally in right of payment with all of our existing and future senior indebtedness and rank senior to all of our existing and future subordinated debt. The payment of the principal, interest and premium on the 8 1/2% Senior Notes are fully and unconditionally guaranteed on a senior unsecured basis by our existing and some of our future restricted subsidiaries.

 

On and after December 1, 2010, we may redeem some or all of the 8 1/2% Senior Notes at any time at redemption prices specified in the indenture, plus accrued and unpaid interest to the date of redemption.

 

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In addition, upon completion of a qualified equity offering prior to December 1, 2008, we are entitled to redeem up to 35% of the aggregate principal amount of the 8 1/2% Senior Notes from the proceeds, so long as:

 

  we pay to the holders of such notes a redemption price of 108.5% of the principal amount of the 8 1/2% Senior Notes, plus accrued and unpaid interest to the date of redemption; and

 

  at least 65% of the aggregate principal amount of the 8 1/2% Senior Notes remains outstanding after each such redemption, other than 8 1/2% Senior Notes held by us or our affiliates.

 

Finally, prior to December 1, 2010, the 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.

 

We and our restricted subsidiaries are subject to certain negative and financial covenants under the indenture governing the 8 1/2% 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 8 1/2% Senior Notes), subject to certain conditions, we must give holders of the 8 1/2% Senior Notes the opportunity to sell to us their 8 1/2% Senior Notes at 101% of the principal amount, plus accrued and unpaid interest.

 

Alternative capital resources.    We have historically used cash flow from operations and secured bank financing as our primary sources of capital. In the future we may use additional sources such as asset sales, 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.

 

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Contractual obligations.    The following table summarizes our contractual obligations and commitments as of December 31, 2005:

 

(Dollars in thousands)(1)   Less than
1 year
   1-3 years    3-5
years
   More
than 5
years
   Total

Debt:

                                 

Revolving credit line—including estimated interest expense

  $

7,050

   $

126,597

   $    $    $ 133,647

Senior notes, including estimated interest expense

    27,625   

 
82,875      82,875      407,875      601,250

Other long-term notes—including estimated interest expense

    3,598      5,200      5,030      233      14,061

Capital leases—including estimated interest

    153      214                367

Abandonment obligations

    346      6,305      520      8,625      15,796

Derivative obligations

    62,109      32,001                94,110

Total

  $ 100,881    $ 253,192    $ 88,425    $ 416,733    $ 859,231

(1)   As of December 31, 2005, the Company has no off-balance sheet arrangements.

 

 

Critical accounting policies and estimates

 

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 a discussion of additional 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 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.

 

Hedging.    Our crude oil and natural gas derivative contracts are designed to be treated as cash flow hedges under Statement of Financial Accounting Standards No. 133, “Accounting for Derivative Instruments and Hedging Activity”, as amended, or SFAS 133. 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. Pursuant to SFAS 133, the effective portion of the hedge gain or loss, meaning that the change in the fair value of the contract offsets the changes in the expected future cash flows from our forecasted 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) on oil and gas hedging activities” line in our consolidated

 

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statements of income. Until hedged production is reported in earnings and the contract settles, the change in the fair value of the contract is reported in the “Accumulated other comprehensive income (loss)” line item in our consolidated statements of member’s equity/stockholders’ equity (deficit). The ineffective portion of the hedge gain or loss is reported in the “Gain (loss) on oil and gas hedging activities” line item each period. If our hedges did not qualify for cash flow hedge treatment, then our consolidated statements of income could include large non-cash fluctuations, particularly in volatile pricing environments, as our contracts are marked to their period end market values.

 

Oil and gas properties.

 

  Full cost accounting.    We use the full cost method of accounting for our oil and gas properties. Under this method, all costs incurred in the exploration and development of oil and 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 gas reserves quantities.    Proved oil and gas reserves are the estimated quantities of crude oil and natural gas which geologic and engineering data demonstrate with reasonable certainty to be recoverable in future periods from known reservoirs under existing economic and operating conditions. 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 Lee Keeling & Associates, Inc., each independent petroleum engineers, and our engineering staff. The independent petroleum engineers evaluated approximately 84% of the estimated future net revenues of our proved reserves discounted at 10% as of December 31, 2005 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 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 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 gas properties recorded on our balance sheet cannot exceed the estimated future net revenues discounted at 10% plus the lower of cost or fair market value of unevaluated properties. The ceiling calculation requires that prices and costs used to determine the estimated future net revenues are those in effect as of the last day of the quarter. If oil and gas prices decline or if we have downward revisions to our estimated reserve quantities, it is possible that write downs of our oil and 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

 

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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. At December 31, 2005 we had approximately $10.2 million of costs excluded from the amortization base. Our future depreciation, depletion and amortization rate would increase if costs are transferred to the amortization base without any associated reserves.

 

  Future development and abandonment costs.    Our future development cost 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 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 judgements are subject to future revisions from changing technology and and regulatory requirements. We review our assumptions and estimates of future development and future abandonment costs on a quarterly basis.

 

The accounting for future abandonment costs changed on January 1, 2003 with our adoption of Statement on Financial Accounting Standards No. 143. This standard requires that a liability for the discounted fair value of an asset retirement obligation be recorded in the period in which it is incurred and the corresponding cost 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. The present value calculation requires us to make numerous assumptions and judgments, including 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. 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.    We provide for income taxes in accordance with Statement on Financial Accounting Standards No. 109, “Accounting for 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. Generally we 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

 

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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 will 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.

 

 

Recent accounting pronouncements

 

In December 2004, the FASB issued Statement on Financial Accounting Standards No. 153, “Exchanges of Nonmonetary Assets an amendment of APB Opinion No. 29”, or SFAS 153. SFAS 153 specifies the criteria required to record a nonmonetary asset exchange using carryover basis. SFAS 153 is effective for nonmonetary asset exchanges occurring after July 1, 2005. We adopted this statement in the third quarter of 2005, and it did not have a material effect on our financial statements.

 

In December 2004, the FASB issued Statement on Financial Accounting Standards No. 123 (revised 2004), “Share-Based Payments”, or SFAS 123R. SFAS 123R requires that the cost from all share-based payment transactions, including stock options, be recognized in the financial statements at fair value. We are adopting SFAS No. 123R as of January 1, 2006 and for stock awards on and after that date, a valuation model will be used to value those stock awards. The adoption of SFAS No. 123R will not significantly change recorded compensation expense or the fair value of phantom units previously issued.

 

In March 2005, the FASB issued FASB Interpretation 47 (“FIN 47”), an interpretation of SFAS No. 143, “Accounting for Asset Retirement Obligations” (“SFAS No. 143”). FIN 47 clarifies the term “conditional asset retirement obligation” as it is used in SFAS No. 143. We expect to apply the guidance of FIN 47 commencing January 1, 2006 and expect no impact on our financial statements.

 

In May 2005, the FASB issued SFAS No. 154, Accounting Changes and Error Corrections: a replacement of APB Opinion No. 20 and FASB Statement No. 3. SFAS No. 154 requires voluntary changes in accounting principles to be applied retrospectively, unless it is impracticable. SFAS No. 154’s retrospective application requirement replaces APB 20’s requirement to recognize most voluntary changes in accounting principle by including in net income of the period of the change the cumulative effect of changing to the new accounting principle. If retrospective application for all prior periods is impracticable, the method used to report the change and the reason the retrospective application is impracticable are to be disclosed.

 

Under SFAS No. 154, retrospective application will be the transition method in the unusual instance that a newly issued accounting pronouncement does not provide specific transition guidance. It is expected that many pronouncements will specify transition methods other than retrospective. SFAS No. 154 is effective for accounting changes made in fiscal years beginning after December 15, 2005, and the adoption of this statement is expected to have no impact on our financial position or results of operations.

 

The FASB issued SFAS No. 155, Accounting for Certain Hybrid Financial Instruments—an amendment of FASB Statements No. 133 and 140, in February 2006. SFAS No. 155 addresses accounting for beneficial interests in securitized financial instruments. The guidance allows fair value remeasurement for any hybrid financial instrument containing an embedded derivative that would otherwise require bifurcation and clarifies which interest-only and principal-only

 

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strips are not subject to SFAS No. 133. SFAS No. 155 also established a requirement to evaluate interests in securitized financial assets to identify any interests that are either freestanding derivatives or contain an embedded derivative requiring bifurcation. The statement is effective for all financial instruments issued or acquired after the beginning of the first fiscal year that begins after September 15, 2006. Management does not expect this statement will have a material impact on our financial position, results of operations or cash flows.

 

 

Effects of inflation and pricing

 

While the general level of inflation affects certain of our costs, factors unique to the oil and gas industry result in independent price fluctuations. Historically, significant fluctuations have occurred in oil and 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 gas, price fluctuations have had, and will continue to have, a material effect on us.

 

 

Quantitative and qualitative disclosures regarding market risks

 

Oil and 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 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 gas prices with any degree of certainty. Sustained declines in oil and gas prices may adversely affect our financial condition and results of operations, and may also reduce the amount of net oil and gas reserves that we can produce economically. Any reduction in reserves, including reductions due to price fluctuations, can reduce our borrowing base under our Credit Agreement and adversely affect our liquidity and our ability to obtain capital for our acquisition, exploration and development activities. Based on our year ended December 31, 2005 production, our gross revenues from oil and gas sales would change approximately $1.7 million for each $0.10 change in gas prices and $1.4 million for each $1.00 change in oil prices.

 

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We periodically enter into derivative contracts, consisting primarily of swaps, to manage our exposure to decreases in oil and gas prices. When using swaps to hedge our oil and gas production, we receive a fixed price for the respective commodity and pay a floating market price as defined in each contract (generally NYMEX futures prices), resulting in a net amount due to or from the counterparty. Our derivative contracts have historically qualified for cash flow hedge accounting under SFAS No. 133 which allows the aggregate change in fair value to be recorded as accumulated other comprehensive income (loss) on the consolidated balance sheet. Recognition in the income statement occurs in the period of contract settlement. Our Credit Agreement allows us to hedge up to 80% of our expected future production for three years. Our outstanding hedges as of December 31, 2005 are summarized below:

 

     Natural gas

    Crude oil

Period   

Total

MMcf

  

Weighted average
fixed price to be

received

  

Percent of

PDP
production
hedged

   

Total

MBbl

  

Weighted average
fixed price to be

received

  

Percent of

PDP
production
hedged


  
  

01/2006 to 03/2006

   3,570    $ 8.71    73.2 %   300    $ 39.40    72.1%

04/2006 to 06/2006

   3,420      7.06    73.9 %   291      40.14    72.6%

07/2006 to 09/2006

   3,330      7.06    75.2 %   285      42.68    73.5%

10/2006 to 12/2006

   2,910      8.04    68.4 %   273      45.67    72.6%

01/2007 to 03/2007

   2,460      8.49    61.9 %   240      47.13    69.4%

04/2007 to 06/2007

   2,460      6.94    64.1 %   234      47.01    69.8%

07/2007 to 09/2007

   2,460      6.94    66.3 %   192      50.06    58.8%

10/2007 to 12/2007

   1,260      8.56    35.0 %   126      55.06    39.7%

01/2008 to 03/2008

   810      9.99    23.8 %   57      63.14    19.4%

04/2008 to 06/2008

   720      8.05    21.8 %   57      62.78    19.9%

07/2008 to 09/2008

   360      8.03    11.2 %   22      61.13    7.9%

10/2008 to 12/2008

               6      60.73    6.5%

  
  

 

Interest rates.    All of the outstanding borrowings under our Credit Agreement as of December 31, 2005 are subject to market rates of interest as determined from time to time by the banks. We may designate borrowings under our Credit Agreement as either ABR loans or Eurodollar loans. ABR loans bear interest at a fluctuating rate that is linked to the discount rate established by the Federal Reserve Board. 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 $172.5 million, equal to our borrowing base, the cash flow impact for a 12-month period resulting from a 100 basis point change in interest rates would be $1.7 million.

 

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Business and properties

 

Our business

 

Chaparral is an independent oil and natural gas production and exploitation company, headquartered in Oklahoma City, Oklahoma. Since our inception in 1988, we have increased reserves and production primarily by acquiring and enhancing properties in our core areas of the Mid-Continent and the Permian Basin. Beginning in 2000, we expanded our geographic focus to include East Texas, North Texas, the Gulf Coast and the Rocky Mountains. During this period, we also increased the percentage of our capital expenditures allocated to developmental drilling. As of December 31, 2005, approximately 84% of our proved reserves were located in our core areas which generally consist of lower-risk, long-lived properties. On September 30, 2005, we acquired the 99% limited partner interest in CEI Bristol for $158 million. We have managed this limited partnership since 2000.

 

As of December 31, 2005, we had estimated proved reserves of 618 Bcfe and a PV-10 value of $1.6 billion. For the year ended December 31, 2005, on a pro forma basis, our average daily production was 81 MMcfe. As of December 31, 2005 our estimated pro forma reserve life is 20.9 years. For the year ended December 31, 2005, on a pro forma basis, our revenue and Adjusted EBITDA were $150.0 million and $102.2 million, respectively. 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, and our definition of Adjusted EBITDA (a non-GAAP measure) and a reconciliation of our income before accounting change to Adjusted EBITDA, beginning on page 11.

 

For the period from 2002 to 2005, our proved reserves and production have grown at a compounded annual growth rate of 35% and 26%, respectively. We have grown primarily through a disciplined strategy of acquisitions of proved oil and natural gas reserves, followed by exploitation activities and the acquisition of additional interests in or near these acquired properties. We typically pursue properties in the second half of their life with stable production, shallow decline rates and with particular producing trends and characteristics indicative of production or reserve enhancement opportunities. We expect our future growth to continue through a combination of acquisitions and exploitation projects, complemented by a modest amount of exploration activities.

 

We have a multi-year inventory of drillable prospects and an active drilling program. We have identified over 790 proved developmental drilling locations, as well as over 2,100 additional potential drilling locations, which combined represent over 15 years of drilling opportunities based on our 2005 drilling rate. We normally have three to six drilling rigs active at any time, depending on the availability of rigs. To support our drilling program, we have entered into agreements which allow access to 34,000 square miles of 3-D seismic data, conducted two proprietary shoots and are currently permitting on one additional proprietary 3-D shoot.

 

Our capital expenditures for oil and gas properties for the year ended December 31, 2005 were $333.0 million, representing a 247% increase over the prior year. Excluding $152.9 million recorded for the oil and gas properties acquired as part of the CEI Bristol acquisition, our capital expenditures in 2005 for oil and gas properties were $180.1 million, representing an 88% increase over the prior year. Our capital expenditure budget for oil and gas properties for 2006 is $210.0 million. We have budgeted approximately 62% of our 2006 capital expenditures on development activities (drilling—43%, enhancements—11% and tertiary recovery—8%), 33% for

 

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acquisitions and 5% for exploration activities. The majority of our capital expenditure budget for developmental drilling in 2006 is allocated to our core areas of the Mid-Continent and Permian Basin. The wells we drill in these areas are primarily infill or single stepout wells, which are characterized as lower risk and have relatively low finding and development costs. We have also budgeted increased capital expenditures for our carbon dioxide (CO2) tertiary recovery projects in the Mid-Continent and Permian Basin.

 

Chaparral Energy, Inc. was incorporated in the state of Delaware on September 14, 2005 as a wholly owned subsidiary of Chaparral, L.L.C. Chaparral, L.L.C. was then merged with and into Chaparral Energy, Inc. effective September 16, 2005, with Chaparral Energy, Inc. surviving the merger. At the effective time of the merger, all shares of capital stock of Chaparral Energy, Inc. issued and outstanding prior to the merger were cancelled and all units of Chaparral, L.L.C. issued and outstanding prior to the merger were converted to shares of the surviving entity, Chaparral Energy, Inc.

 

 

Business strengths

 

Consistent track record of low-cost reserve additions and production growth.    From 2002 to 2005, we have grown reserves and production by a compounded annual growth rate of 35% and 26%, respectively. We have achieved this through a combination of drilling success and acquisitions. Our reserve replacement ratio, which reflects our reserve additions in a given period stated as a percentage of our production in the same period, has averaged nearly 500% per year since 1999. We replaced approximately 468%, 794% and 822% of our production in 2003, 2004 and 2005 respectively, at an average fully developed FD&A cost of $1.82 per Mcfe over this three year period, which we believe is among the lowest in the industry.

 

Disciplined approach to acquisitions.    We have a dedicated team that analyzes all of our acquisition opportunities. This team conducts due diligence, with reserve engineering on a well-by-well basis, to determine whether assets under consideration meet our acquisition criteria. We typically target properties where we can identify enhancements that we believe will increase production rates and extend the producing life of the well. The large number of acquisition opportunities we review allows us to be selective and focus on properties that we believe have the most potential for value enhancement. In 2003, 2004 and 2005 our capital expenditures for acquisitions were $19.9 million, $30.5 million and $222.3 million, respectively. These acquisition capital expenditures represented approximately 35%, 32% and 67%, respectively, of our total capital expenditures for those years. In 2005 we made the largest acquisition in the history of our company, the acquisition of CEI Bristol, which added an estimated 115 Bcfe of proved reserves, as of September 30, 2005. Excluding the acquisition of CEI Bristol, we spent $69.3 million on acquisitions during 2005, representing approximately 39% of our total capital expenditures for that period. We expect to continue spending a significant percentage of our future capital expenditures on acquisitions as long as our investment criteria are met.

 

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

 

Inventory of drilling locations.    As of December 31, 2005, we had an inventory of over 790 proved developmental drilling locations and over 2,100 additional potential drilling locations,

 

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which combined represent over 15 years of drilling inventory based on our 2005 drilling rate as shown in the following table.

 

     Identified
proved
undeveloped
drilling
locations
   Identified
other
potential
drilling
locations
   Developed
Acreage
Net
  

Undeveloped
Acreage

Net


  
  
  
  

Mid-Continent

   653    1,440    295,482    33,524

Permian Basin

   81    470    49,915    11,718

East Texas

   4    34    30,219    1,352

North Texas

   30    146    16,349    2,924

Rocky Mountains

   14    25    10,025    7,286

Gulf Coast

   11    12    25,399    6,775
    
  
  
  

Total

   793    2,127    427,389    63,579

  
  
  
  

 

Identified drilling locations represent total gross drilling locations identified by our management as an estimation of our multi-year drilling activities on existing acreage. Our actual drilling activities may change depending on the availability of capital, regulatory approvals, seasonal restrictions, oil and natural gas prices, costs, drilling results and other factors. See “Risk factors” beginning on page 15. We spent $87.3 million on development and exploration drilling for 2005. We have experienced a high historical drilling success rate of approximately 96% on a weighted average basis during 2003, 2004 and 2005. For 2006, we have budgeted $102.0 million to drill more than 80 operated wells and to participate in more than 130 wells operated by others. To support our drilling program, we have entered into agreements which allow access to 34,000 square miles of 3-D seismic data, conducted two proprietary shoots and applied for permits for one additional proprietary 3-D shoot.

 

Tertiary recovery expertise and assets.    Beginning in 2000, we expanded our operations to include CO2 enhanced oil recovery. CO2 enhanced oil recovery involves the injection of CO2, which mixes with the remaining oil in place in the producing reservoir, followed by the injection of water in cycles to drive the hydrocarbons to producing wells. We have a staff of six engineers that have substantial expertise in CO2 tertiary recovery operations, as well as specific software for modeling CO2 enhanced recovery. We own a 29.2% interest in and operate a large CO2 tertiary flood unit in southern Oklahoma and installed and operate a second tertiary flood unit with a 54% interest in the Oklahoma panhandle. At December 31, 2005, our proved reserves included 4 properties where CO2 tertiary recovery methods are used, which comprise approximately 9% of our total proved reserves.

 

Experienced management team.    Mark A. Fischer, our CEO and founder who beneficially owns 50% of our outstanding common stock, has operated in the oil and gas industry for 34 years after starting his career at Exxon as petroleum engineer. Charles A. Fischer, Jr., our Chief Administrative Officer, has an indirect pecuniary interest in approximately 12% of our stock owned directly by Altoma Energy G.P. and has been involved in the oil and gas business for 22 years, serving as President of Kitscoty Oil LLC and previously as our Chief Financial Officer. Mark Fischer and Charles Fischer are brothers. Joe Evans, our Chief Financial Officer, has over 27 years of experience in the oil and gas industry. Individuals in our 24-person management team have an average of over 25 years of experience in the oil and gas industry.

 

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Business strategy

 

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

 

Continue lower-risk development drilling program.    We have allocated $91.0 million, or 43% of our 2006 capital expenditure budget, to development drilling. A majority of these drilling locations are in our core areas of the Mid-Continent and the Permian Basin. The wells we drill in these areas are generally development (infill or single stepout) wells.

 

Acquire long-lived properties with enhancement opportunities.    We continually evaluate acquisition opportunities and expect that they will continue to play a significant role in increasing our reserve base and future drilling inventory. We have traditionally targeted smaller asset acquisitions which allow us to absorb, enhance and exploit the properties without taking on excessive integration risk. Targeting numerous smaller acquisitions also provides us sufficient opportunity to achieve our planned reserve additions through acquisitions. We generally pursue mature properties in the second half of their life which are located in proven fields in which we have an opportunity to improve operations through cost control, and to increase production and reserves through the application of improved technology and additional drilling. Excluding the CEI Bristol acquisition, which was larger than our typical acquisitions, we spent approximately $69.3 million on acquisitions during 2005. Our 2006 acquisition capital budget is $70 million, or 33% of our total capital expenditure budget.

 

Apply technical expertise to enhance mature properties.    Once we acquire a property and become the operator, we seek to maximize production through enhancement techniques and the reduction of operating costs. We have built Chaparral 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 13 field offices throughout Oklahoma, Texas 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 of December 31, 2005, we had an inventory of 227 developed enhancement projects requiring total estimated capital expenditures of $16.3 million.

 

Expand CO2 enhanced oil recovery activities.    We have accumulated interests in 43 properties in Oklahoma and Texas that meet our criteria for CO2 tertiary recovery operations and are expanding our CO2 pipeline system to initiate CO2 injection in certain of these properties. We plan to expand our Camrick CO2 project in 2006 and initiate CO2 injection in our NW Camrick and Perryton Units in 2007. We have budgeted $16 million in 2006 towards these projects. To support our existing CO2 tertiary recovery projects, we currently inject approximately 37 MMcf per day of CO2. We have a 100% ownership interest in our 86 mile Borger CO2 pipeline, a 29% interest in the 120 mile Enid to Purdy CO2 pipeline, and a 58% interest in and operate the 23 mile Purdy to Velma CO2 pipeline.

 

Pursue modest exploration program.    In the current high-priced commodity environment, we believe a modest exploration program can provide a rate of return comparable or superior to property acquisitions in certain areas. We currently plan to spend $11.0 million, or approximately 5% of our 2006 capital expenditures, on exploration activities.

 

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Control operations and costs.    We seek to serve as operator of the wells in which we own a significant interest. As operator, we are better positioned to control the (1) timing and plans for future enhancement and exploitation efforts; (2) costs of enhancement, drilling, completing and producing the wells; and (3) marketing negotiations for our oil and gas production to maximize both volumes and wellhead price. As of December 31, 2005, we operated properties comprising approximately 79% of our proved reserves.

 

Hedge production to stabilize cash flow.    Our long-lived reserves provide us with relatively predictable production. We maintain an active hedging program on our PDP production to protect cash flows that we use for capital investments and to lock in returns on acquisitions. As of December 31, 2005, we had hedges in place for approximately 73%, 57% and 17% of our estimated PDP gas production for 2006, 2007 and 2008, respectively. We also had hedges in place for approximately 73%, 60% and 15% of our estimated PDP oil production for 2006, 2007 and 2008, respectively. While oil and gas hedging protects our cash flows during periods of commodity price declines, these hedges have resulted in net losses on oil and gas hedging activities of $12.2 million, $21.4 million, and $68.3 million for the years ended December 31, 2003, 2004, and 2005, respectively, as commodity prices have increased.

 

 

Properties

 

The following table presents proved reserves and PV-10 value as of December 31, 2005, and average daily production for the year ended December 31, 2005 by major areas of operation.

 

    Proved reserves as of December 31, 2005

  Average
daily
production
(MMcfe per
day)


  Pro forma
average daily
production
(MMcfe per
day)


   

Oil

(MBbl)

 

Natural
gas

(MMcf)

  Total
(MMcfe)
  Percent
of total
MMcfe
  PV-10
value
($mm)
  Year ended
December 31,
2005
  Year ended
December 31,
2005

 
 
 
 
 
 
 

Mid-Continent

  20,752   285,994   410,506   66.5%   $ 1,070.0   48.2   55.4

Permian Basin

  6,057   73,347   109,689   17.8%     265.3   7.8   9.3

East Texas

  1,257   26,059   33,601   5.4%     90.5   7.4   8.3

North Texas

  2,239   3,977   17,411   2.8%     48.5   2.1   2.5

Rocky Mountains

  1,916   4,245   15,741   2.5%     37.4   2.0   2.5

Gulf Coast

  1,692   20,762   30,914   5.0%     90.9   2.0   3.0
   
 
 
 
 

 
 

Total

  33,913   414,384   617,862   100.0%   $ 1,602.6   69.5   81.0

 
 
 
 
 
 
 

 

Our properties have relatively long reserve lives and highly predictable production profiles. In general, these properties have extensive production histories and production enhancement opportunities. While our portfolio of oil and gas properties is geographically diversified, 81% of our 2005 production was concentrated in our core areas, which allows for substantial economies of scale in production and cost effective application of reservoir management techniques. As of December 31, 2005 we owned interests in 5,455 gross (1,422 net) producing wells and we operated wells representing 79% 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.

 

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Mid-Continent

 

The Mid-Continent Area is the larger of our two core areas and, as of December 31, 2005, accounted for 66% of our proved reserves and 67% of our PV-10 value. We own an interest in 3,636 wells in the Mid-Continent, of which we operate 944. Our three largest properties and 13 of our 20 largest properties, in terms of PV-10 value, are located in this area. During the year ended December 31, 2005, our net average daily production in the Mid-Continent Area was approximately 48.2 MMcfe per day, or 69% of our total net average daily production (or approximately 55.4 MMcfe per day, or 68% of our total net average daily production, on a pro forma basis). This area is characterized by stable, long-life, shallow decline reserves. We produce and drill in most of the basins in the region and have significant holdings and activity in the areas described below.

 

Camrick area—Beaver and Texas Counties, Oklahoma.    The Camrick area represents 6% of our proved reserves and 6.2% of the PV-10 value of our proved reserves at December 31, 2005. This area consists of three unitized fields, the Camrick Unit, which covers 9,080 acres, the NW Camrick Unit, which covers 4,080 acres and the Perryton Unit, which covers 2,040 acres. We currently operate these three fields with an average working interest of 54%. Production in the Camrick area is from the Morrow reservoir that occurs at a depth of approximately 6,800 feet. The three units have produced approximately 16.1 MMBbl of primary reserves and approximately 13.4 MMBbl of secondary reserves. There are approximately 36 active producing wells in this area. Currently CO2 injection operations are under way in the Phase I area of the Camrick Unit. CO2 injection has improved the gross production in the Camrick Unit from approximately 75 Bbls per day in 2001 from 11 wells to approximately 800 Bbls per day for December 2005 from 17 wells. We currently plan to expand CO2 injection operations across all of the units.

 

Southwest Antioch Gibson Sand Unit (SWAGSU)—Garvin County, Oklahoma.    SWAGSU represents 4.9% of our proved reserves and 5.8% of the PV-10 value of our proved reserves at December 31, 2005. SWAGSU encompasses approximately 9,520 acres with production from the Gibson Sand, which occurs between the depths of 6,500 and 7,200 feet. We currently operate this unit with an average working interest of 99%. The field has produced approximately 39.9 MMBbls of oil and 255.1 Bcf of natural gas since its discovery in 1946. The field was unitized in 1948 and began unitized production as a pressure maintenance operation, utilizing selective production (based on gas/oil ratios) and gas injection. Water injection began in 1952. Gas injection ceased in 1960 without significant blowdown of the injected gas. Field shutdown and plugging activities began in 1966, and all water injection ceased in 1970. A program is currently underway to re-enter abandoned wells and drill new wells to produce the injected gas. We have approximately 22 active producing wells in this unit. Since January 2005, we have re-entered three wells, drilled one well and are scheduled to drill four additional wells in 2006.

 

Cleveland Sand Play—Ellis County, Oklahoma and Lipscomb County, Texas.    We own approximately 6,120 acres in the Cleveland Sand Play. The Cleveland Sand occurs at 8,300 feet and is considered a tight gas sand reservoir. We currently have interests in 18 Cleveland Sand producing wells, have drilled three wells in 2005 and have plans to drill five wells in 2006. Horizontal drilling technology has been employed in two recently drilled wells. Future wells will utilize a mix of vertical and horizontal technology.

 

Velma Sims Unit CO2 Flood—Stephens County, Oklahoma.    The EVWB Sims Sand Unit which covers approximately 1,300 acres was discovered in 1949 and was unitized in 1962. We currently operate this unit with an average working interest of 29%. Hydrocarbon gas injection into the Sims C2 Sand was initiated in the top of the structure in 1962. Waterflood operations began in

 

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1972. Hydrocarbon gas injection ended around 1977 and a miscible CO2 injection program was initiated in 1982. This miscible CO2 injection was first begun in the updip portion of the reservoir and in 1990 expanded into the mid-section area of the Sims C2 reservoir. In 1996 miscible CO2 injection began in the downdip section of the Sims C2. We have approximately 47 active producing wells in this unit.

 

Harmon County 3-D Shoot—Harmon County, Oklahoma.    We have leased in excess of 29,000 acres in Harmon County, Oklahoma and have conducted a proprietary 3-D seismic shoot on this acreage. Based on very limited well control, potential pay horizons exist in the Mississippi Reef, Bend Conglomerate and Canyon intervals. Drilling of three wells is expected to start in the third quarter of 2006 with the potential to drill 150 wells.

 

CO2 Enhanced Recovery Operations—Various counties, Oklahoma and Texas.    We plan to expand our Camrick CO2 project in 2006 and initiate CO2 injection in our NW Camrick and Perryton Units in 2007. We have in place transportation and supply agreements to provide the necessary CO2 for these projects. With this expansion, we expect to increase our CO2 volumes transported to 30 MMcf per day by July 2006.

 

We have accumulated 43 properties in Oklahoma and Texas that meet our criteria for CO2 tertiary recovery operations. We have a 100% ownership and operate our 86 mile Borger CO2 pipeline, own a 29% interest in the 120 mile Enid to Purdy CO2 pipeline, and own a 58% interest in and operate the 23 mile Purdy to Velma CO2 pipeline. To facilitate the expansion of our CO2 tertiary recovery program currently budgeted in the next three years, we will be extending our CO2 pipeline infrastructure by 88 miles. Arrangements to secure additional sources of CO2 are currently in process. The U.S. Department of Energy-Office of Fossil Energy provided a report in April 2005 estimating that significant oil reserves could be technically recovered in the State of Oklahoma through CO2 enhanced oil recovery processes. With our infrastructure, we believe that we will be well positioned to participate in the exploitation of these reserves.

 

 

Permian Basin

 

The Permian Basin Area is the second of our two core areas and, as of December 31, 2005, accounted for 18% of our proved reserves and 17% of our PV-10 value. We own an interest in 916 wells in the Permian Basin, of which we operate 285. Six of our 20 largest properties, in terms of PV-10 value, are located in this area. During the year ended December 31, 2005, our net average daily production in the Permian Basin Area was approximately 7.8 MMcfe per day, or 11% of our total net average daily production (or approximately 9.3 MMcfe per day, or 11% of our total net average daily production, on a pro forma basis). Similar to the Mid-Continent Area, it is characterized by its stable long life shallow decline reserves.

 

Tunstill Field Play—Loving and Reeves Counties, Texas.    Our original Tunstill Field Play covers approximately 6,480 acres. We operate these wells with a working interest of 100%. Primary objectives in this play are the Bell Canyon Sands that occur at depths from 3,300 to 4,200 feet and the Cherry Canyon Sands that occur at depths from 4,300 to 5,200 feet. Older wells produce from the shallower Bell Canyon Sands including the Ramsey and Olds while more recent wells have established production from the deeper Cherry Canyon Sands as well as the shallower sands. During the year ended December 31, 2005, we drilled nine wells in this play. We have identified 36 potential drilling locations in this play, of which eight are scheduled to be drilled in 2006. We have acquired leasehold rights to approximately 12,880 acres that are an expansion to our original Tunstill field play.

 

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Haley Area Strawn and Morrow Play—Loving County, Texas.    The Haley Area Strawn and Morrow Play encompasses 3,840 gross acres. We own interests in and operate five producing wells in this play. Production has been established from two main intervals: the Strawn at a depth of approximately 15,500 feet and the Morrow at a depth of approximately 17,700 feet. Two of the existing wells are completed in the Strawn and the other three wells are completed in the Morrow. Recent activity in the area, on all four sides of our acreage, has established significant producing wells from the Strawn/Morrow commingled interval with some initial potentials of 20 to 30 MMcfe per day. We are currently drilling one well and completing a recently drilled well.

 

 

East Texas

 

East Texas is one of our four growth areas and, as of December 31, 2005, accounted for 5% of our proved reserves and 5% of our PV-10 value. We own an interest in 116 wells in East Texas, of which we operate 98. These reserves are characterized by shorter life and higher initial potential.

 

Giddings North Edwards—Fayette County, Texas.    We control 4,780 acres in the Gidding North Edwards Field. We operate this field with an average working interest of 98%. Eight wells are producing from the Edwards Lime that occurs at a depth of 10,100 feet. These eight wells have produced 554 MBbls of oil and 42.3 Bcf of natural gas. We are currently drilling an Edwards test and have scheduled a second Edwards test in this field. We have recently leased an additional 1,200 acres adjacent to this field.

 

Winnsboro Field—Wood County, Texas.    We control approximately 1,072 acres in the Winnsboro Field and operate 11 wells. Primary objectives in this field are the Travis Peak and Cotton Valley that occur at depths from 8,600 to 10,300 feet. Additional potential pay zones are the Sub-Clarksville, Bacon Lime, Hill, Gloyd and the Pettit-Pittsburg that occur at depths from 4,150 to 8,500 feet. During 2005 we drilled one development well in this field. We have plans to drill several more development wells in this play.

 

 

North Texas

 

North Texas is the second of our four growth areas and, as of December 31, 2005, accounted for 3% of our proved reserves and 3% of our PV-10 value. We own an interest in 559 wells in North Texas, of which we operate 103. One of our three proprietary 3-D seismic shoots has been completed in this area.

 

Percy Jones Clearfork Play—Howard and Mitchell Counties, Texas.    We own and operate the Percy Jones, Percy Jones A and Percy Jones B leases, encompassing 640 acres in the Laton East Howard Field. We currently operate these properties with an average working interest of 100%. A total of 54 wells have been completed in the Glorieta at depths of 2,500 feet and Upper Clearfork at depths of 2,700 feet since its discovery in 1947. The Percy Jones lease (north half of Section 13) has a total of 44 producing wells and is developed on 10 acre spacing with some increased density development to 5 acres and cumulative production of 1.8 MMBbls of oil and 24 MMcf of natural gas. The Percy Jones A and B leases make up the south half of the section, have a total of 10 existing wells and have cumulative production of 365 MBbls of oil and 22 MMcf of natural gas. Secondary recovery through water injection has proven successful in offset leases but has been done on a very limited basis in the Percy Jones lease.

 

Recent increased density drilling activity in the Laton East Howard Field, as well as patterned waterflood development has shown marked success. This type of development in the Percy Jones

 

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leases has the potential to increase reserves since much of the south half of the section, which has only 10 existing wells, has not been developed. In addition, new productive zones have been identified by drilling through the Middle and Lower Clearfork which were not developed in existing wells in the section. Reserves from these zones will be captured in the new wells we drill and potentially through the recompletion of the existing wells to greater depths.

 

Since January 2005, we have drilled five wells in the north half of the section and two wells in the south half. Four wells are scheduled to be drilled in 2006. In addition, we have identified 24 PUD locations and 43 potential locations.

 

Eanes Units—Montague County, Texas.    We own and operate the North Eanes, East Eanes and South Eanes Units. These units cover approximately 7,000 acres and produce from the Caddo at approximately 5,600 feet. We currently operate these units with an average working interest of 95%. We have conducted an 11.5 square mile proprietary 3-D seismic program in these units. Potential pay zones have been identified in the Caddo at 5,600 feet, Atoka at 5,700 feet, Barnett shale at 6,000 feet, Mississippian Reef at 6,300 feet, Viola at 6,500 feet and the Ellenberger at 6,800 feet. We have approximately 24 active producing wells in this area. We drilled six wells in 2005. We have three wells scheduled to be drilled in 2006. We may drill up to 33 additional wells if this initial drilling effort proves successful.

 

 

Rocky Mountains

 

The Rocky Mountains is our third growth area and, as of December 31, 2005, accounted for 3% of our proved reserves and 2% of our PV-10 value. We own an interest in 74 wells in the Rocky Mountains Area, of which we operate 34. Unlike our core areas, this area is not as well developed and holds potential for material upside growth.

 

Bakken Horizontal Play—Richland County, Montana.    We are currently pursuing acreage in Richland County, Montana. We recently drilled a dual leg horizontal well in the Bakken interval on acreage we own that was producing from the Red River formation. The McVay #2-34H well was drilled as a horizontal dual leg lateral with the first lateral measuring 3,648 feet in length and the second lateral measuring 3,496 feet in length. During February 2006, the well was producing 210 Bbls of oil per day and 210 Mcf of natural gas per day.

 

We recently leased approximately 10,400 acres in the immediate area of the McVay #2-34H and have six wells scheduled to be drilled in 2006.

 

 

Gulf Coast

 

Our fourth growth area is the Gulf Coast and, as of December 31, 2005, accounted for 5% of our proved reserves and 6% of our PV-10 value. We own an interest in 154 wells in the Gulf Coast, of which we operate 73. Unlike our core areas, the Gulf Coast Area is characterized by shorter life and high initial potential production. We believe a balance of this type of production with our long-life reserves adds a dimension for increasing our near-term cash flow.

 

Mustang Island & Mesquite Bay—Nueces County, TX.    We control approximately 6,000 producing acres and recently were the successful bidder on approximately 6,400 net acres of new leases to be issued by the State of Texas. Multiple producing sand intervals are found from depths of 6,500 feet to 8,000 feet. We now operate 12 active producing wells in this area. We are

 

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currently permitting a 3D seismic survey to be conducted in 2006 over parts of this area in an attempt to find bypassed reserves or other potential reservoirs.

 

Vivian Borchers Area—Lavaca County, Texas.    We control approximately 1,300 acres in the Vivian Borchers Area. Multiple Frio and Miocene pay zones occur at depths shallower than 4,000 feet. Based on 3-D seismic reprocessing, we have successfully drilled and completed three wells to depths of approximately 4,000 feet. These wells had initial test rates as high as 900 Mcf of natural gas per day. In addition, we have several deep 3-D seismic based Wilcox tests planned for the area. We have licensed 200 square miles of seismic data and are currently evaluating it for additional prospects, similar to those mentioned above. As prospects are identified, additional leasing and drilling activity will be proposed.

 

 

Oil and natural gas reserves

 

The table below summarizes our net proved oil and natural gas reserves and PV-10 values at December 31, 2005. Information in the table is derived from reserve reports of estimated proved reserves on the top 75% of our non-CO2 enhanced oil recovery proved undeveloped reserves prepared by Cawley, Gillespie & Associates, Inc. (80% of PV-10 value) and by Lee Keeling & Associates, Inc. for our CO2 enhanced oil recovery proved undeveloped reserves (4% of PV-10 value). Our internal engineering staff has prepared a report of estimated proved reserves on our remaining smaller value properties (16% of PV-10 value).

 

     Net proved reserves

     Oil
(MBbl)
   Natural
gas
(MMcf)
   Total
(MMcfe)
   PV-10 value
(In thousands)

Developed—producing

   21,081    239,932    366,418    $ 991,215

Developed—non-producing

   2,681    43,241    59,327      157,728

Undeveloped

   10,151    131,211    192,117      453,667
    
  
  
  

Total proved

   33,913    414,384    617,862    $ 1,602,610

 

The reserve life as of December 31 2003, 2004 and 2005 was 19.9, 22.9 and 24.4 years, respectively. The reserve life was calculated by dividing total proved reserves by production volumes for the year indicated.

 

The following table sets forth the estimated future net revenues from proved reserves, the PV-10, the standardized measure of discounted future net cash flows and the prices used in projecting them over the past three years.

 

(Dollars in thousands, except prices)    2003   

2004

as restated(1)

   2005

Future net revenue

   $ 1,053,624    $ 1,663,141    $ 3,597,300

PV-10 value

     488,305      775,116      1,602,610

Standardized measure of discounted future net cash flows

     325,250      514,041      1,067,888

Oil price (per Bbl)

   $ 32.52    $ 43.51    $ 61.04

Natural gas price (per Mcf)

   $ 6.19    $ 6.35    $ 10.08

(1)   See note 14 of the Chaparral Energy, Inc. and Subsidiaries notes to consolidated financial statements.

 

Proved reserves are the estimated quantities of crude oil, natural gas, and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable in future

 

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years from known reservoirs under existing economic and operating conditions, i.e., prices and costs as of the date the estimate is made. Prices include consideration of changes in existing prices provided only by contractual arrangements, but not on escalations based upon future conditions.

 

The following table sets forth information at December 31, 2005 relating to the producing wells in which we owned a working interest as of that date. 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 an interest, and net wells is the sum of our working interest in all wells.

 

     Total wells

     Gross    Net

Crude oil

   2,529    734

Natural gas

   2,926    688
    

Total

   5,455    1,422

 

The following table details our gross and net interest in producing wells in which we have an interest at December 31, 2005.

 

     Total wells

     Gross    Net

Mid-Continent

   3,636    866

Permian Basin

   916    269

East Texas

   116    89

North Texas

   559    108

Rocky Mountains

   74    25

Gulf Coast

   154    65
    

Total

   5,455    1,422

 

The following table details our gross and net interest in developed and undeveloped acreage at December 31, 2005.

 

     Developed Acreage

   Undeveloped Acreage

         Gross        Net        Gross        Net

  
  
  
  

Mid-Continent

   808,677    295,482    45,693    33,524

Permian Basin

   92,664    49,915    12,088    11,718

East Texas

   41,639    30,219    1,874    1,352

North Texas

   21,826    16,349    3,170    2,924

Rocky Mountains

   34,565    10,025    14,194    7,286

Gulf Coast

   55,273    25,399    10,352    6,775
    
  
  
  

Total

   1,054,644    427,389    87,371    63,579

  
  
  
  

 

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

 

     2003

   2004

   2005

     Gross    Net    Gross    Net    Gross    Net

Development wells

                             

Productive

   87.0    23.9    89.0    24.4    171.0    52.0

Dry

   2.0    0.7    5.0    2.8    2.0    0.8

Exploratory wells

                             

Productive

   2.0    1.4    1.0    0.1    11.0    6.0

Dry

               1.0    0.4

Total wells

                             

Productive

   89.0    25.3    90.0    24.5    182.0    58.0

Dry

   2.0    0.7    5.0    2.8    3.0    1.2
    

Total

   91.0    26.0    95.0    27.3    185.0    59.2
    

Percent productive

   98%    97%    95%    90%    98%    98%

 

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

 

     Year ended December 31,

     2003    2004    2005

Production:

                    

Oil (MBbl)

     924      1,173      1,449

Natural gas (MMcf)

     9,762      11,923      16,660

Combined (MMcfe)

     15,306      18,961      25,354

Average daily production:

                    

Oil (Bbls)

     2,532      3,214      3,970

Natural gas (Mcf)

     26,745      32,666      45,644

Combined (Mcfe)

     41,937      51,950      69,464

Average prices (before effect of hedges):

                    

Oil (per Bbl)

   $ 29.92    $ 40.53    $ 53.76

Natural gas (per Mcf)

     4.77      5.54      7.41

Combined (per Mcfe)

     4.85      5.99      7.94

Average costs per Mcfe:

                    

Lease operating

   $ 1.28    $ 1.42    $ 1.66

Production tax

   $ 0.32    $ 0.44    $ 0.58

Depreciation, depletion, and amortization

   $ 0.53    $ 0.81    $ 1.09

General and administrative

   $ 0.32    $ 0.32    $ 0.39

 

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Competition

 

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

 

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

 

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

 

 

Markets

 

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

 

  the amount of crude oil and natural gas imports;

 

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

 

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

 

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

 

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

 

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

 

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

 

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

 

Members of the Organization of Petroleum Exporting Countries establish prices and production quotas from time to time with the intent of reducing the current global oversupply and

 

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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 pollution control equipment;

 

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

 

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

 

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

 

  impose substantial liabilities for pollution resulting from our operation; 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 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 gas industry could have a significant impact on our operating costs.

 

We believe that we substantially comply with all current applicable environmental laws and regulations and that our continued compliance with existing requirements will not have a

 

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material adverse impact on our financial condition and results of operations. However, we cannot predict how future environmental laws and regulations may affect our properties or operations. For the year ended December 31, 2005, 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 environmental issues or claims that will require material capital expenditures during 2006 or that will otherwise have material impact on our financial position or results of operations.

 

Environmental laws and regulations that could have a material impact on the oil and 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, or 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 natural gas and oil projects.

 

Waste handling

 

The Resource Conservation and Recovery Act, or 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 Environmental Protection Agency, or 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 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, or CERCLA, also known as the “Superfund” law, imposes joint and several liability, without regard to fault or

 

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legality of conduct, on persons who are considered to be responsible for the release of a “hazardous substance” into the environment. These persons include the owner or operator of the site where the release occurred and companies that disposed or arranged for the disposal of the hazardous substance at the site. Under CERCLA, such persons may be liable for the costs of cleaning up the hazardous substances released into the environment, for damages to natural resources and for the costs of certain health studies. In addition, neighboring landowners and other third parties may file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment.

 

We currently own, lease, or operate numerous properties that have produced oil and natural gas for many years. Although we believe we have utilized operating and waste disposal practices that were standard in the industry at the time, hazardous substances, wastes, or hydrocarbons may have been released on or under 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.

 

Air emissions

 

The Clean Air Act, and associated state laws and regulations, regulate emissions of various air pollutants through the issuance of permits 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. 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 emission limitations. 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 that we are in substantial compliance with the requirements of the Clean Air Act.

 

Other laws and regulation

 

The Kyoto Protocol to the United Nations Framework Convention on Climate Change became effective in February 2005. Under the Protocol, participating nations are required to implement programs to reduce emissions of certain gases, generally referred to as greenhouse gases, that

 

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are suspected of contributing to global warming. The United States is not currently a participant in the Protocol, and Congress has resisted recent proposed legislation directed at reducing greenhouse gas emissions. However, 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 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 addressing greenhouse gas emissions would impact our business.

 

Other regulation of the oil and gas industry

 

The oil and gas industry is extensively regulated by numerous federal, state and local authorities. Legislation affecting the oil and 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 gas industry and its individual members, some of which carry substantial penalties for failure to comply. Although the regulatory burden on the oil and gas industry increases our cost of doing business and, consequently, affects our profitability, these burdens generally do not affect us any differently or to any greater or lesser extent than they affect other companies in the industry with similar types, quantities and locations of production.

 

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

 

Drilling and production

 

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

 

  the location of wells;

 

  the method of drilling and casing wells;

 

  the rates of production or “allowables”;

 

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

 

  the plugging and abandoning of wells; and

 

  notice to surface owners and other third parties.

 

State laws regulate the size and shape of drilling and spacing units or proration units governing the pooling of oil and natural gas properties. Some states allow forced pooling or integration of tracts to facilitate exploration while other states rely on voluntary pooling of lands and leases. In some instances, forced pooling or unitization may be implemented by third parties and may reduce our interest in the unitized properties. In addition, state conservation laws establish maximum rates of production from oil and natural gas wells, generally prohibit the venting or

 

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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. The Federal Energy Regulatory Commission, or 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 gas to point-of-sale locations.

 

Natural gas gathering regulations

 

State regulation of natural gas gathering facilities generally include 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 may receive greater regulatory scrutiny in the future.

 

State regulation

 

The various states regulate the drilling for, and the production, gathering and sale of, oil and natural gas, including imposing severance taxes and requirements for obtaining drilling permits. States also regulate the method of developing new fields, the spacing and operation of wells and the prevention of waste of oil and natural gas resources. States may regulate rates of production

 

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and may establish maximum daily production allowables from oil and natural gas wells based on market demand or resource conservation, or both. States do not regulate wellhead prices or engage in other similar direct economic regulation, but there can be no assurance that they will not do so in the future. The effect of these regulations may be to limit the amounts of oil and natural gas that may be produced from our wells, and to limit the number of wells or locations we can drill.

 

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

 

Seasonality

 

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

 

Legal proceedings

 

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

 

Title to properties

 

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

 

 

Employees

 

As of December 31, 2005, we had 342 full-time employees, including 12 geologists and geophysicists, 24 production and reservoir engineers and 11 land professionals. Of these, 203 work in our Oklahoma City office and 139 are 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

 

The following provides brief biographical information for each of our executive officers, directors and other key management personnel.

 

 

Executive officers and directors

 

The following table provides information regarding our executive officers and directors:

 

Name    Age    Position

Mark A. Fischer

   56    Chairman, Chief Executive Officer and President

Charles A. Fischer, Jr.

   57    Chief Administrative Officer, Executive Vice President and Director

Joseph O. Evans

   51    Chief Financial Officer and Executive Vice President and Director Nominee

Robert W. Kelly II

   48    Senior Vice President and General Counsel

Larry E. Gateley

   56    Senior Vice President—Reservoir Engineering and Acquisitions

James M. Miller

   43    Senior Vice President—Operations and Production Engineering

William O. Powell III

   59    Director Nominee

James A. Watt

   56    Director Nominee

Bill M. Lamkin

   60    Director Nominee

 

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, 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 1984-1986. 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.

 

Charles A. Fischer, Jr., Chief Administrative Officer, Executive Vice President, Director and Co-Founder, co-founded Chaparral in 1988, and has served as its Chief Administrative Officer and Executive Vice President since July 2005. Mr. Fischer joined Chaparral 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 one in the Turks and Caicos Islands, and is the current President. Mr. Fischer also serves as the manager of Altoma Energy GP. Mr. Fischer began his career with Renewable Resources in 1974 as a senior scientist on the Polar

 

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Gas Pipeline Project investigating the feasibility of bringing natural gas from the high Arctic to south-central Canada. Mr. Fischer served as a director of the Canadian Western Retail Lumberman’s Association for 11 years, was President for 6 years, and received the 2001 Industry Achievement Award. He graduated from Texas A&M University in 1970 (Bachelor of Science degree in Biology) and the University of Wisconsin in 1973 (Master of Science degree in Ecology).

 

Joseph O. Evans, Chief Financial Officer & Executive Vice President & Director Nominee, 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 Commission 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.

 

Robert W. Kelly II, Sr. Vice President & General Counsel, joined Chaparral in 2001 and oversees the legal, land, marketing and environmental functions. Prior to joining Chaparral, Mr. Kelly worked for Ricks Exploration Inc. as Director of Business Development & Gas Marketing for two years. From 1990 until 1999, he was with EOG Resources Inc. (formerly Enron Oil & Gas Company) initially as Land Manager for its Oklahoma City division and later building their business development department. During 1989 and 1990, Mr. Kelly was a title attorney in his own partnership firm in Oklahoma City. He began his oil and gas career as a Landman with TXO Production Corp. in 1981, subsequently receiving promotions to District Landman by 1988. He is a member of the Oklahoma Bar Association, the Oklahoma Independent Producers Association, and several other business and legal associations. Mr. Kelly received a Bachelor of Business Administration (Petroleum Land Management) degree from the University of Oklahoma in 1981, and a Juris Doctor from the Oklahoma City University School of Law in 1989.

 

Larry E. Gateley, Sr. Vice President—Reservoir Engineering and Acquisitions, joined Chaparral in 1997 as the Reservoir Engineering and Acquisitions Manager, and currently performs reservoir studies on over 4,000 wells per year. Mr. Gateley has 32 years of diversified management and operational and technical engineering experience. His previous positions include Reservoir/Production/Drilling Engineer for Exxon Company USA, Sr. Petroleum Engineer for J.M. Huber Corp., Chief Drilling Engineer for Post Petroleum Inc., Vice President and Co-Owner of Wood-Gate Engineering Inc., Vice President of Acquisitions for SMR Energy Income Funds, and Acquisitions Manager for Frontier Natural Gas Corporation. Mr. Gateley is a registered Professional Engineer in the states of Oklahoma and Texas. He is a graduate of the University of Oklahoma with a Bachelor of Science degree in Mechanical Engineering.

 

James M. Miller, Sr. Vice President—Operations & Production Engineering, joined Chaparral in 1996, as Operations Engineer. Since joining Chaparral, Mr. Miller has been promoted to positions of increasing responsibility and currently oversees all company production operations and field services. 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

 

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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.

 

William O. Powell III, Director Nominee, has served as Senior Vice President, Chief Financial Officer and Treasurer of ABS Group of Companies since 2005. From 2003 to 2004, Mr. Powell served as Vice President and Chief Accounting Officer of La Quinta Corporation. From 1974 to 2002, he was employed by PricewaterhouseCoopers LLP, serving as Worldwide Engagement Leader-Partner from 1985 to 2002 for multiple clients in the energy industry. Mr. Powell was a Commissioned Officer in the United States Navy from 1968 to 1974. Mr. Powell received a Bachelor of Science in Engineering from the U.S. Naval Academy and a Bachelor of Arts in Accounting from the University of West Florida. Mr. Powell is a Certified Public Accountant.

 

James A. Watt, Director Nominee, has served as Chief Executive Officer of Remington Oil & Gas Corporation since 1998 and has been a member of its board of directors since 1997, serving as Chairman since 2003. From 1993 to 1997, Mr. Watt served as Vice President of Exploration for Seagull E&P, Inc. From 1991 to 1993, he served as Vice President of Exploration and Exploitation for Nerco Oil & Gas, Inc. Mr. Watt served in various technical and management positions with Union Texas Petroleum Corp. from 1974 to 1991 and was a geologist with Amoco Production Company from 1971 to 1974. Mr. Watt received a Bachelor of Science in Physics from Rensselaer Polytechnic Institute in 1971.

 

Bill M. Lamkin, Director Nominee, served as Executive Vice President and Chief Financial Officer of Quicksilver Resources Inc. from 1999 until his retirement in November 2005. From 1978 to 1999, Mr. Lamkin was employed by Union Pacific Resources Group Inc., serving in various positions including Treasurer, Director of Financial Services and Controller. From 1976 to 1978, he served as Chief Financial Officer and Controller of Sargent Industries, Inc. Mr. Lamkin served in various management positions with Whittaker Corporation from 1966 to 1976. Mr. Lamkin received a Bachelor of Science in Physics from the University of Texas at Austin in 1967 and a B.B.A. in Accounting from Texas Wesleyan University in 1968. He is a Certified Cash Manager and a Certified Management Accountant.

 

 

Board structure and compensation of directors

 

Upon completion of the offering, our board of directors will consist of six members. Our board has determined that Messrs. Powell, Watt and Lamkin are independent under the applicable rules of the NYSE. Following the phase-in period permitted under those rules, we intend to rely initially upon the controlled company exemption from rules that would otherwise require that a majority of the members of our board will be independent directors.

 

Our directors will be divided into three classes serving staggered three-year terms. Class I, Class II and Class III directors will serve until our annual meetings of stockholders in 2007, 2008 and 2009, respectively. At each annual meeting of stockholders, directors will be elected to succeed the class of directors whose terms have expired. This classification of our board of directors could have the effect of increasing the length of time necessary to change the composition of a majority of the board of directors. In general, at least two annual meetings of stockholders will be necessary for stockholders to effect a change in a majority of the members of the board of directors.

 

Directors who are also full-time officers or employees of our company will receive no additional compensation for serving as directors. All other directors will receive an annual retainer of

 

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$25,000 and an annual grant of 4,000 shares of restricted stock. Each non-employee director also will receive a fee of $1,500 for each board meeting attended and $1,000 for each committee meeting attended. In addition, the chairman of the audit committee will receive an annual fee of $10,000, the chairman of the compensation committee will receive an annual fee of $5,000 and the chairman of the nominating and governance committee will receive an annual fee of $5,000.

 

 

Board committees

 

Our board of directors will have an audit committee, a nominating and governance committee and a compensation committee following this offering. We intend that all the members of our audit committee will be independent under applicable provisions of the Securities Exchange Act of 1934 and the NYSE rules following the phase-in period. Following the phase-in period permitted under the NYSE rules, we intend to rely initially on the controlled company exemption from rules that would otherwise require that all the members of our nominating and governance committee and of our compensation committee will be independent under applicable provisions of those rules.

 

Audit Committee.    The audit committee, which will consist of Messrs. Powell (chair), Watt and Lamkin, will assist the board in overseeing (a) the integrity of our financial statements, (b) our compliance with legal and regulatory requirements, (c) the independence, qualifications and performance of our independent registered public accounting firm and (d) the performance of our internal audit function. Our board has determined that Mr. Powell will be designated an “audit committee financial expert.”

 

Nominating and Governance Committee.    The nominating and governance committee, which will consist of Messrs. Lamkin (chair), Watt and Evans, will assist the board in identifying and recommending candidates to fill vacancies on the board of directors and for election by the stockholders, recommending committee assignments for directors to the board of directors, monitoring and assessing the performance of the board of directors and individual non-employee directors, reviewing compensation received by directors for service on the board of directors and its committees and developing and recommending to the board of directors appropriate corporate governance policies, practices and procedures for our company.

 

Compensation Committee.    The compensation committee, which will consist of Messrs. Watt (chair), Lamkin and Charles A. Fischer, Jr., will (a) review and approve the compensation of our executive officers and other key employees, (b) evaluate the performance of our chief executive officer and oversee the performance evaluation of senior management and (c) administer and make recommendations to the board of directors with respect to our incentive-compensation plans, equity-based plans and other compensation benefit plans.

 

 

Web access

 

We will provide access through our website at www.chaparralenergy.com to current information relating to governance, including a copy of each board committee charter, our Code of Conduct, our corporate governance guidelines and other matters impacting our governance principles. You may also contact our General Counsel for paper copies of these documents free of charge.

 

 

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.

 

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Compensation of executive officers

 

The following table summarizes all compensation earned by our Chief Executive Officer and our four other most highly compensated executive officers during the year ended December 31, 2005, to whom we refer in this prospectus as our named executive officers. The following table does not include Joseph O. Evans, our Chief Financial Officer who joined us in July 2005.

 

 

Summary compensation table

 

          Annual Compensation

    
     Year           Salary           Bonus    All Other
Compensation(1)(2)

Mark A. Fischer

   2005    $ 303,000    $ 19,629    $ 15,307

Chairman, Chief Executive Officer and President

                         

Charles A. Fischer, Jr.  

   2005    $ 187,980    $ 13,482    $ 13,470

    Chief Administrative Officer, Executive Vice President and Director

                         

Larry E. Gateley

   2005    $ 164,559    $ 12,176    $ 8,826

    Senior Vice President—Reservoir Engineering and Acquisitions

                         

Robert W. Kelly II

   2005    $ 154,304    $ 11,273    $ 8,279

Senior Vice President and General Counsel

                         

James M. Miller

   2005    $ 144,615    $ 10,684    $ 83,996

    Senior Vice President—Operations and Production Engineering

                         

 

(1)   Includes: for Mark A. Fischer, $5,623 reflecting allocable expenses for personal use of aircraft and vehicles and $9,684 in Chaparral matching 401(k) contributions; for Charles A. Fischer, Jr., $3,397 reflecting allocable expenses for personal use of aircraft and vehicles and $10,073 in Chaparral matching 401(k) contributions; for Larry E. Gateley, $8,826 in Chaparral matching 401(k) contributions; for Robert W. Kelly II, $8,279 in Chaparral matching 401(k) contributions; and for James M. Miller, $76,231 in payments pursuant to overriding royalty interests subject to vesting and $7,765 in Chaparral matching 401(k) contributions.

 

(2)   Does not include payments to Mark A. Fischer and Charles A. Fischer, Jr. made pursuant to previously granted overriding royalty interests which are vested and owned by Mark A. Fischer and Charles A. Fischer, Jr. See “Certain relationships and related transactions—Participation interests.”

 

 

Phantom unit plan

 

Effective January 1, 2004, we implemented a Phantom Unit Plan, or the Plan, to provide deferred compensation to certain key employees as the participants. Phantom units may be awarded to participants in total up to 2% of the fair market value of Chaparral, as defined by the Plan. No participant may be granted, in the aggregate, more than 5% of the maximum number of phantom units available for award. Generally, phantom units vest on the seventh anniversary of the award date of the phantom unit, 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 Chaparral without cause. Also, phantom units vest if a change of control event occurs. A change of control event will occur under the Plan if (1) our three current stockholders collectively sell a majority of their shares (either publicly or privately) to a person who is not majority owned by them collectively, and in the process lose operational control of us (i.e., the position of President, Chief Executive Officer or Chairman of us or our subsidiary Chaparral Energy, LLC, is not held by either Mark A. Fischer or Chuck A. Fischer), (2) the termination,

 

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liquidation or dissolution of us or Chaparral Energy, LLC unless our business is substantially carried on by a successor company that remains majority owned or operationally controlled as described above, or (3) we sell all or substantially all of our assets. Upon vesting, participants are entitled to the value of their phantom units payable in cash immediately. Compensation expense is recognized over the vesting periods of the phantom units. We recognized deferred compensation expense of $120,000 and $525,000 for the year ended December 31, 2004 and 2005, respectively related to the Plan.

 

Employment agreements

 

We have agreed to pay Joseph O. Evans an annual salary of $212,000 and an aggregate bonus of not less than $50,000 for his first year of employment with us. In addition, on July 1, 2005, we granted Mr. Evans a $50,000 award under our Phantom Unit Plan. We have also agreed to pay Mr. Evans a minimum severance amount of $424,000 in bonus and phantom units if we terminate his employment without cause, if a change of control occurs, if Chaparral is terminated, liquidated or dissolved or if we sell substantially all of the assets of Chaparral, at any time before June 30, 2010. Our severance arrangement with Mr. Evans will terminate automatically after the completion of this offering on the adoption of a revised severance package by the compensation committee.

 

We have granted certain participation interests in the form of overriding royalty interests to James M. Miller. Our subsidiary, Chaparral CO2, L.L.C., has assigned Mr. Miller an overriding royalty interest equal to a total 0.00500 net revenue interest in the production from the Northwest Camrick Unit, the Camrick Unit and the North Perryton (George Morrow) Unit, in each case limited to the unitized Upper Morrow Sand formation. The assignments provide that if Mr. Miller terminates his employment between the following dates, the applicable portions of the overriding royalty interests granted will automatically revert to Chaparral CO2, L.L.C.: July 1, 2000 and June 30, 2002, 100%; July 1, 2002 and June 30, 2004, 80%; July 1, 2004 and June 30, 2005, 60%; July 1, 2005 and June 30, 2006, 40%; July 1, 2006 and June 30, 2007, 20%. Mr. Miller may terminate his employment with us at any time on or after July 1, 2007, without any part of the overriding royalty interest granted reverting to us. In the event of Mr. Miller’s death, if we terminate Mr. Miller’s employment for any reason or if Chaparral Energy, L.L.C. merges into another entity in which Chaparral is not the surviving entity or if there is a sale of Chaparral Energy, L.L.C. before July 1, 2007, the entire overriding royalty interest granted will be owned by Mr. Miller without the possibility of reversion. In addition, if we sell our interest in one of the Units covered by the assignment, the overriding royalty interest granted with respect to that Unit will be owned by Mr. Miller without possibility of reversion.

 

 

Indemnification agreements

 

We have also entered into indemnification agreements with all of our directors and some 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

 

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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.

 

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 have also agreed to obtain and maintain director and officer liability insurance for the benefit of each of the above indemnities. These policies will include coverage for losses for wrongful acts and omissions and to ensure our performance under the indemnification agreements. Each of the indemnities will be 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.

 

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Principal and selling stockholders

 

The following table sets forth information, as of December 15, 2005, 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, each director nominee and each of the five most highly compensated executive officers, by all directors, director nominees and executive officers as a group, and each selling stockholder. The number of shares in the column “Number of Shares Offered” represents all of the shares that each selling stockholder may offer under this prospectus assuming no exercise of the underwriters’ over-allotment option. Except as noted below in the footnotes, the selling stockholders will each sell a pro rata number of the total shares that may be sold pursuant to the underwriters’ over-allotment option. To our knowledge, each of the selling stockholders has sole voting and investment power as to the shares shown, except as disclosed in this prospectus or to the extent this power may be shared with a spouse. None of the selling stockholders are broker dealers or affiliates of broker dealers. Beneficial ownership as shown in the table below has been determined in accordance with the applicable rules and regulations promulgated under the Exchange Act.

 

     Shares beneficially
owned prior to
this offering


   Number
of Shares
Offered
   Shares beneficially
owned after
this offering


Name(1)    Number    Percent       Number    Percent

Mark A. Fischer(2)

        50%              %

Altoma Energy G.P.(3)

        50%                          %

Charles A. Fischer, Jr.(4)

        50%              %

Joseph O. Evans

              

Robert W. Kelly II

              

Larry E. Gateley

              

James M. Miller

              

William O. Powell III(5)

              

James A. Watt(5)

              

Bill M. Lamkin(5)

              

All Directors, Director Nominees and Officers as a group (9 persons)

        100%              %

 

*   Less than 1%.

 

(1)   The address of the directors and executive officers and principal stockholders is in care of Chaparral Energy, Inc., 701 Cedar Lake Boulevard, Oklahoma City, Oklahoma 73114.

 

(2)   Includes 250 shares owned of record by the Mark A. Fischer 1994 Trust, for which Mark A. Fischer serves as Trustee, and 250 shares owned of record by Susan L. Fischer 1994 Trust, for which Susan L. Fischer, the spouse of Mark A. Fischer, serves as trustee.

 

(3)   Charles A. Fischer, Jr., our director, Chief Administrative Officer and Executive Vice President, is one of 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 500 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)   We expect that each non-employee director nominee will be granted 4,000 shares of restricted stock upon the closing of this offering, which shares shall vest in equal one-third increments upon each of the first three anniversary dates of the initial grant date.

 

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Certain relationships and related transactions

 

CEI Bristol

 

Prior to September 30, 2005, Chaparral managed and administered the business of CEI Bristol Acquisition, L.P. At December 31, 2004, we had accounts receivable of approximately $1,441,000, due from CEI Bristol. Chaparral acted as operator of certain partnership wells and received overhead reimbursements as provided for in operating agreements. Fees received for these overhead reimbursements were approximately $939,000 and $1,018,000 for the years ended December 31, 2003 and 2004, respectively and $735,000 for the nine months ended September 30, 2005. Additionally, we were compensated for management services provided to CEI Bristol through a management fee. Management fees earned by Chaparral were approximately $89,000 and $228,000 for the years ended December 31, 2003 and 2004, respectively and $111,000 for the nine months ended September 30, 2005. On September 30, 2005 we acquired the 99% limited partner interest in CEI Bristol Acquisition L.P. and therefore will no longer receive any of these fees.

 

 

Participation interests

 

Historically, Chaparral has granted participation interests in the form of overriding royalty interests to a limited number of employees. Chaparral has also granted pro rata certain overriding royalty interests to its stockholders or their affiliates, including Mark A. Fischer and Charles A. Fischer, Jr. We believe that the granting of these participation interests to our employees in certain prospects promotes in them a proprietary interest in our exploration efforts for the benefit of us and our stockholders. Aggregate payments on these interests to all persons were $314,251, $522,965 and $538,825 in 2003, 2004 and 2005, respectively. Payments on these interests to Mark A. Fischer were $82,999, $130,509 and $120,373 in 2003, 2004 and 2005, respectively. Payments on these interests to Charles A. Fischer, Jr. were $21,572, $34,421 and $31,758 in 2003, 2004 and 2005, respectively. We made grants of additional overriding royalty interests in 2005.

 

We do not intend to continue the grant 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.

 

 

Port Aransas property

 

On December 28, 2005, Mark A. Fischer acquired our beneficial interest in a house and certain furnishings in Port Aransas, Texas for $112,475 in cash together with the assumption of a loan, which represents our net book value and its estimated current fair market value. The house was acquired by us in April 2004 for the purchase price of $327,500. Record title was taken in the name of Mark A. Fischer, and Mr. Fischer entered into a mortgage securing a $262,000 loan. As it was intended for the house to be used by various officers of Chaparral, and various officers of Chaparral enjoyed the use of the house, our board of directors approved the payment by our subsidiary of the downpayment on the house and the principal and interest payments on the loan. We made monthly payments of principal and interest totaling approximately $37,697 through November 2005.

 

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Offering by selling stockholders

 

We are paying the expenses of the offering by the selling stockholders, including a single firm of attorneys for the selling stockholders. We will not be paying the underwriting discounts, commissions and taxes with respect to shares of common stock sold by the selling stockholders and the fees and expenses of any other attorneys, accountants and other advisors separately retained by them.

 

 

Registration rights agreement

 

We intend to enter into a registration rights agreement with each of our three existing stockholders. Under the agreement, any one of the three existing stockholders may require us to file a registration statement under the Securities Act to register the sale of shares of our common stock, subject to certain limitations, including that the reasonably anticipated gross proceeds must be at least $15.0 million. These stockholders may request a total of six such registrations (two by the Mark A. Fischer 1994 Trust, two by the Susan L. Fischer 1994 Trust, and two by Altoma Energy G.P.) and only one in any six-month period. These stockholders also have the right to cause us to register their registrable securities on Form S-3, when it becomes available to us, if the reasonably anticipated gross proceeds would be at least $10.0 million. In addition, if we propose to register securities under the Securities Act, then the stockholders who are party to the agreement will have “piggy-back” rights, subject to quantity limitations determined by underwriters if the offering involves an underwriting, to request that we register their registrable securities. There is no limit to the number of these “piggy-back” registrations in which these stockholders may request their shares be included. We generally will bear the registration expenses incurred in connection with registrations. We have agreed to indemnify these stockholders against certain liabilities, including liabilities under the Securities Act, in connection with any registration effected under the agreement. These registration rights will terminate at the earlier of (a) ten years from the closing date of this offering or (b) with respect to any stockholder, the date that all registrable securities held by that stockholder may be sold in a three-month period without registration under Rule 144 of the Securities Act and such registrable securities represent less than one-percent of all outstanding shares of our capital stock.

 

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Description of capital stock

 

Upon the completion of this offering, our authorized capital stock will consist of:

 

               shares of common stock, $0.01 par value; and
               shares of preferred stock, $0.01 par value, none of which are currently designated.

 

Upon the completion of this offering,              shares of common stock and no shares of preferred stock will be outstanding.

 

The following summarizes the material provisions of our capital stock and important provisions of our certificate of incorporation and bylaws. This summary is qualified by our certificate of incorporation and bylaws, copies of which have been filed as exhibits to the registration statement of which this prospectus is a part and by the provisions of applicable law.

 

 

Common stock

 

Holders of common stock are entitled to one vote per share on all matters to be voted upon by the stockholders. Because holders of common stock do not have cumulative voting rights, the holders of a majority of the shares of common stock can elect all of the members of the board of directors standing for election. The holders of common stock are entitled to receive dividends as may be declared by the board of directors. Upon our liquidation, dissolution or winding up, and subject to any prior rights of outstanding preferred stock, the holders of our common stock will be entitled to share pro rata in the distribution of all of our assets available for distribution to our stockholders after satisfaction of all of our liabilities and the payment of the liquidation preference of any preferred stock that may be outstanding. There are no redemption or sinking fund provisions applicable to the common stock. All outstanding shares of common stock are fully paid and non-assessable. The holders of our common stock will have no preemptive or other subscription rights to purchase our common stock.

 

 

Preferred stock

 

Subject to the provisions of the certificate of incorporation and limitations prescribed by law, the board of directors will have the authority to issue up to              shares of preferred stock in one or more series and to fix the rights, preferences, privileges and restrictions of the preferred stock, including dividend rights, dividend rates, conversion rates, voting rights, terms of redemption, redemption prices, liquidation preferences and the number of shares constituting any series or the designation of the series, which may be superior to those of the common stock, without further vote or action by the stockholders. We have no present plans to issue any shares of preferred stock.

 

One of the effects of undesignated preferred stock may be to enable the board of directors to render more difficult or to discourage an attempt to obtain control of us by means of a tender offer, proxy contest, merger or otherwise, and, as a result, protect the continuity of our management. The issuance of shares of the preferred stock under the board of directors’ authority described above may adversely affect the rights of the holders of common stock. For example, preferred stock issued by us may rank prior to the common stock as to dividend rights, liquidation preference or both, may have full or limited voting rights and may be convertible into shares of

 

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common stock. Accordingly, the issuance of shares of preferred stock may discourage bids for the common stock or may otherwise adversely affect the market price of the common stock.

 

 

Provisions of our certificate of incorporation and bylaws

 

Written consent of stockholders

 

Our certificate of incorporation and bylaws provide that any action required or permitted to be taken by our stockholders must be taken at a duly called meeting of stockholders and not by written consent.

 

Amendment of the Bylaws

 

Under Delaware law, the power to adopt, amend or repeal bylaws is conferred upon the stockholders. A corporation may, however, in its certificate of incorporation also confer upon the board of directors the power to adopt, amend or repeal its bylaws. Our charter and bylaws grant our board the power to adopt, amend and repeal our bylaws on the affirmative vote of a majority of the directors then in office. Our stockholders may adopt, amend or repeal our bylaws but only at any regular or special meeting of stockholders by the holders of not less than 66 2/3% of the voting power of all outstanding voting stock.

 

Special meetings of stockholders

 

Our bylaws preclude the ability of our stockholders to call special meetings of stockholders.

 

Other limitations on stockholder actions

 

Advance notice is required for stockholders to nominate directors or to submit proposals for consideration at meetings of stockholders. In addition, the ability of our stockholders to remove directors without cause is precluded.

 

Classified Board

 

Only one of three classes of directors is elected each year. See “Management—Board of Directors.”

 

Limitation of liability of directors

 

Our certificate of incorporation provides that no director shall be personally liable to us or our stockholders for monetary damages for breach of fiduciary duty as a director, except for liability as follows:

 

  for any breach of the director’s duty of loyalty to us or our stockholders;

 

  for acts or omissions not in good faith or which involve intentional misconduct or a knowing violation of laws;

 

  for unlawful payment of a dividend or unlawful stock purchase or stock redemption; and

 

  for any transaction from which the director derived an improper personal benefit.

 

The effect of these provisions is to eliminate our rights and our stockholders’ rights, through stockholders’ derivative suits on our behalf, to recover monetary damages against a director for a

 

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breach of fiduciary duty as a director, including breaches resulting from grossly negligent behavior, except in the situations described above.

 

Business Combination Under Delaware Law

 

We are subject to the provisions of Section 203 of the Delaware General Corporation Law. In general, Section 203 prohibits a publicly held Delaware corporation from engaging in a “business combination” with an “interested stockholder” for a period of three years after the date of the transaction in which the person became an interested stockholder, unless the business combination is approved in a prescribed manner.

 

Section 203 defines a “business combination” as a merger, asset sale or other transaction resulting in a financial benefit to the interested stockholders. Section 203 defines an “interested stockholder” as a person who, together with affiliates and associates, owns, or, in some cases, within three years prior, did own, 15% or more of the corporation’s voting stock. Under Section 203, a business combination between us and an interested stockholder is prohibited unless:

 

  our board of directors approved either the business combination or the transaction that resulted in the stockholders becoming an interested stockholder prior to the date the person attained the status;

 

  upon consummation of the transaction that resulted in the stockholder becoming an interested stockholder, the interested stockholder owned at least 85% of our voting stock outstanding at the time the transaction commenced, excluding, for purposes of determining the number of shares outstanding, shares owned by persons who are directors and also officers and issued employee stock plans, under which employee participants do not have the right to determine confidentially whether shares held under the plan will be tendered in a tender or exchange offer; or

 

  the business combination is approved by our board of directors on or subsequent to the date the person became an interested stockholder and authorized at an annual or special meeting of the stockholders by the affirmative vote of the holders of at least 66 2/3% of the outstanding voting stock that is not owned by the interested stockholder.

 

This provision has an anti-takeover effect with respect to transactions not approved in advance by our board of directors, including discouraging takeover attempts that might result in a premium over the market price for the shares of our common stock. With approval of our stockholders, we could amend our certificate of incorporation in the future to elect not to be governed by the anti-takeover law. This election would be effective 12 months after the adoption of the amendment and would not apply to any business combination between us and any person who became an interested stockholder on or before the adoption of the amendment.

 

 

Registration rights

 

We intend to enter into a registration rights agreement with each of our three existing holders. Under the agreement, any one of the three existing holders may require us to file a registration statement under the Securities Act to register the sale of shares of our common stock, subject to certain limitations, including that the reasonably anticipated gross proceeds must be at least $15.0 million. These stockholders may request a total of six such registrations (two by the Mark A. Fischer 1994 Trust, two by the Susan L. Fischer 1994 Trust, and two by Altoma Energy G.P.) and

 

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only one in any six-month period. These holders also have the right to cause us to register their registrable securities on Form S-3, when it becomes available to us, if the reasonably anticipated gross proceeds would be at least $10.0 million. In addition, if we propose to register securities under the Securities Act, then the holders who are party to the agreement will have “piggy-back” rights, subject to quantity limitations determined by underwriters if the offering involves an underwriting, to request that we register their registrable securities. There is no limit to the number of these “piggy-back” registrations in which these holders may request their shares be included. We generally will bear the registration expenses incurred in connection with registrations. We have agreed to indemnify these stockholders against certain liabilities, including liabilities under the Securities Act, in connection with any registration effected under the agreement. These registration rights will terminate at the earlier of (a) ten years from the closing date of this offering or (b) with respect to any holder, the date that all registrable securities held by that holder may be sold in a three-month period without registration under Rule 144 of the Securities Act and such registrable securities represent less than one-percent of all outstanding shares of our capital stock.

 

 

Transfer agent and registrar

 

The transfer agent and registrar for the common stock is UMB Bank, n.a.

 

 

Listing

 

We have applied to list our shares of common stock on the New York Stock Exchange under the symbol “CPR.”

 

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Shares eligible for future sale

 

Prior to this offering, there has been no public market for our common stock. The market price of our common stock could drop due to sales of a large number of shares of our common stock or the perception that these sales could occur. These factors also could make it more difficult to raise funds through future offerings of common stock.

 

After this offering,              shares of common stock will be outstanding. Of these shares, the              shares sold in this offering, or              shares if the underwriters exercise their over-allotment option in full, will be freely tradable without restriction under the Securities Act except for any shares purchased by one of our “affiliates” as defined in Rule 144 under the Securities Act. All of the shares outstanding other than the shares sold in this offering (a total of              shares, or              shares if the underwriters exercise their over-allotment option in full) will be “restricted securities” within the meaning of Rule 144 under the Securities Act and subject to lock-up arrangements.

 

In connection with this offering, we and our executive officers and directors and the holders of all of our outstanding common stock and common stock equivalents have agreed that, during the period beginning from the date of this prospectus and continuing to and including the date 180 days after the date of this prospectus, neither we nor any of them will, directly or indirectly, offer, sell, offer to sell, contract to sell or otherwise dispose of any shares of our common stock without the prior written consent of J.P. Morgan Securities Inc., except in limited circumstances. See “Underwriting” for a description of these lock-up arrangements. Upon the expiration of these lock-up agreements,              shares, or              shares if the underwriters exercise their over-allotment option in full, will be eligible for sale in the public market under Rule 144 of the Securities Act, subject to volume limitations and other restrictions contained in Rule 144.

 

The restricted securities generally may not be sold unless they are registered under the Securities Act or are sold under an exemption from registration, such as the exemption provided by Rule 144 under the Securities Act. After this offering, the holders of              shares, or              shares if the underwriters exercise their over-allotment option in full, will have rights, subject to some limited conditions, to demand that we include their shares in registration statements that we file on their behalf, on our behalf or on behalf of other stockholders. By exercising their registration rights and selling a large number of shares, these holders could cause the price of our common stock to decline. Furthermore, if we file a registration statement to offer additional shares of our common stock and have to include shares held by those holders, it could impair our ability to raise needed capital by depressing the price at which we could sell our common stock.

 

Our officers and directors and all of our stockholders will enter into lock-up agreements described in “Underwriting.”

 

As restrictions on resale end, the market price of our common stock could drop significantly if the holders of these restricted shares sell them, or are perceived by the market as intending to sell them.

 

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Rule 144

 

In general, under Rule 144 as currently in effect, any person (or persons whose shares are aggregated), including an affiliate, who has beneficially owned shares for a period of at least one year is entitled to sell, within any three-month period, a number of shares that does not exceed the greater of:

 

  1% of the then outstanding shares of common stock; and

 

  the average weekly trading volume in the common stock on the NYSE during the four calendar weeks immediately preceding the date on which the notice of the sale on Form 144 is filed with the Securities Exchange Commission.

 

Sales under Rule 144 are also subject to other provisions relating to notice and manner of sale and the availability of current public information about us.

 

 

Rule 144(k)

 

Under Rule 144(k), a person who is not deemed to have been one of our affiliates at any time during the 90 days preceding a sale, and who has beneficially owned the shares proposed to be sold for at least two years, including the holding period of any prior owner other than an “affiliate,” is entitled to sell the shares without complying with the manner of sale, public information, volume limitation or notice provision of Rule 144.

 

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Material U.S. federal tax consequences

for non-U.S. holders of our common stock

 

The following is a general discussion of the material U.S. federal income and estate tax consequences to non-U.S. Holders with respect to the acquisition, ownership and disposition of our common stock. In general, a “Non-U.S. Holder” for purposes of this discussion is any beneficial owner of our common stock other than the following:

 

  an individual citizen or resident of the U.S., including an alien individual who is a lawful permanent resident of the U.S. or meets the “substantial presence” test under section 7701(b)(3) of the Internal Revenue Code of 1986, as amended (the “Code”);

 

  a corporation (or an entity treated as a corporation) created or organized in the U.S. or under the laws of the U.S., any state thereof, or the District of Columbia;

 

  a partnership (or an entity treated as a partnership);

 

  an estate, the income of which is subject to U.S. federal income tax regardless of its source; or

 

  a trust, if a U.S. court can exercise primary supervision over the administration of the trust and one or more U.S. persons can control all substantial decisions of the trust, or certain other trusts that have a valid election to be treated as a U.S. person pursuant to the applicable Treasury Regulations.

 

This discussion is based on current provisions of the Code, final, temporary and proposed Treasury Regulations, judicial opinions, published positions of the Internal Revenue Service, or IRS, and all other applicable administrative and judicial authorities, all of which are subject to change, possibly with retroactive effect. This discussion does not address all aspects of U.S. federal income and estate taxation or any aspects of state, local, or non-U.S. taxation, nor does it consider any specific facts or circumstances that may apply to particular Non-U.S. Holders that may be subject to special treatment under the U.S. federal income tax laws including, but not limited to, insurance companies, real estate investment trusts, regulated investment companies, persons holding our common stock as part of a hedging or conversion transaction or a straddle or other risk-reduction transaction, tax-exempt organizations, pass-through entities, banks or financial institutions, brokers, dealers in securities, and U.S. expatriates. If a partnership or other entity treated as a partnership for U.S. federal income tax purposes is a beneficial owner of our common stock, the tax treatment of a partner in the partnership will generally depend upon the status of the partner and the activities of the partnership. This discussion assumes that the Non-U.S. Holder will hold our common stock as a capital asset, which generally is property held for investment.

 

Prospective investors are urged to consult their tax advisors regarding the U.S. federal, state and local, and non-U.S. income and other tax considerations of acquiring, holding and disposing of shares of common stock.

 

 

Dividends

 

In general, dividends paid to a Non-U.S. Holder (to the extent paid out of our current or accumulated earnings and profits, as determined under U.S. federal income tax principles) will be subject to U.S. withholding tax at a rate equal to 30% of the gross amount of the dividend, or a lower rate prescribed by an applicable income tax treaty, unless the dividends are effectively

 

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connected with a trade or business carried on by the Non-U.S. Holder within the U.S. Under applicable Treasury regulations, a Non-U.S. Holder will be required to satisfy certain certification requirements, generally on IRS Form W-8BEN, or any successor form, directly or through an intermediary, in order to claim a reduced rate of withholding under an applicable income tax treaty. If tax is withheld in an amount in excess of the amount applicable under an income tax treaty, a refund of the excess amount may generally be obtained by filing an appropriate claim for refund with the IRS.

 

Dividends that are effectively connected with a U.S. trade or business (and, where an income tax treaty applies, are attributable to a U.S. permanent establishment of the Non-U.S. Holder) generally will not be subject to U.S. withholding tax if the Non-U.S. Holder files the properly completed required forms, including IRS Form W-8ECI, or any successor form, with the payor of the dividend, but instead generally will be subject to U.S. federal income tax on a net income basis in the same manner as if the Non-U.S. Holder were a resident of the U.S. A corporate Non-U.S. Holder that receives effectively connected dividends may be subject to an additional branch profits tax at a rate of 30%, or a lower rate prescribed by an applicable income tax treaty, on its “effectively connected earnings and profits,” subject to adjustments.

 

 

Gain on sale or other disposition of common stock

 

In general, a Non-U.S. Holder will not be subject to U.S. federal income tax on any gain realized upon the sale or other taxable disposition of the Non-U.S Holder’s shares of common stock unless:

 

  the gain is effectively connected with a trade or business carried on by the Non-U.S. Holder within the U.S. (and, where an income tax treaty applies, is attributable to a U.S. permanent establishment of the Non-U.S. Holder), in which case the branch profits tax discussed above may also apply if the Non-U.S. Holder is a corporation;

 

  the Non-U.S. Holder is an individual who holds shares of common stock as capital assets and is present in the U.S. for 183 days or more in the taxable year of disposition and certain other conditions are met; or

 

  we are or have been a “U.S. real property holding corporation” for U.S. federal income tax purposes during specified periods.

 

A Non-U.S. Holder described in the first and third bullet points above will be subject to tax on the net gain derived from the sale under regular graduated U.S. federal income tax rates. A Non-U.S. Holder described in the second bullet point above will be subject to a 30% tax on the gain derived from the sale, which may be offset by U.S. source capital losses.

 

Because of the oil and gas properties and other real property assets we own, we may be a “U.S. real property holding corporation.” The determination of whether we are a “U.S. real property holding corporation” is fact specific and depends on the composition of our assets. Generally, a corporation is a U.S. real property holding corporation if the fair market value of its U.S. real property interests, as defined in the Internal Revenue Code and applicable regulations, equals or exceeds 50% of the aggregate fair market value of its worldwide real property interests and its other assets used or held for use in a trade or business. If we are, have been, or become, a U.S. real property holding corporation, and our common stock is regularly traded on an established

 

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securities market, a Non-U.S. Holder who (actually or constructively) holds or held (at anytime during the shorter of the five year period preceding the date of dispositions or the holder’s holding period) more than five percent of our common stock would be subject to U.S. federal income tax on a disposition of our common stock, but other Non-U.S. Holders generally would not be. If our common stock is not so traded, all Non-U.S. Holders would be subject to U.S. federal income tax on disposition of our common stock.

 

You are encouraged to consult your own tax advisor regarding our possible status as a “U.S. real property holding corporation” and its possible consequences in your particular circumstances.

 

 

Information reporting and backup withholding

 

Generally, we must report annually to the IRS the amount of dividends paid, the name and address of the recipient, and the amount, if any, of tax withheld. A similar report is sent to the recipient. These information reporting requirements apply even if withholding was not required because the dividends were effectively connected dividends or withholding was reduced by an applicable income tax treaty. Under income tax treaties or other agreements, the IRS may make its reports available to tax authorities in the recipient’s country of residence.

 

Dividends paid to a Non-U.S. Holder that is not an exempt recipient generally will be subject to backup withholding, currently at a rate of 28% of the gross proceeds, unless a Non-U.S. Holder certifies as to its foreign status, which certification may be made on IRS Form W-8BEN.

 

Proceeds from the disposition of common stock by a Non-U.S. Holder effected by or through a U.S. office of a broker will be subject to information reporting and backup withholding, currently at a rate of 28% of the gross proceeds, unless the Non-U.S. Holder certifies to the payor under penalties of perjury as to, among other things, its address and status as a Non-U.S. Holder or otherwise establishes an exemption. Generally, U.S. information reporting and backup withholding will not apply to a payment of disposition proceeds if the transaction is effected outside the U.S. by or through a non-U.S. office. However, if the broker is, for U.S. federal income tax purposes, a U.S. person, a controlled foreign corporation, a foreign person who derives 50% or more of its gross income for specified periods from the conduct of a U.S. trade or business, specified U.S. branches of foreign banks or insurance companies or a foreign partnership with various connections to the U.S., information reporting, but not backup withholding, will apply unless:

 

  the broker has documentary evidence in its files that the holder is a Non-U.S Holder and certain other conditions are met; or

 

  the holder otherwise establishes an exemption.

 

Backup withholding is not an additional tax. Rather, the amount of tax withheld is applied as a credit to the U.S. federal income tax liability of persons subject to backup withholding. If backup withholding results in an overpayment of U.S. federal income taxes, a refund may be obtained, provided the required documents are timely filed with the IRS.

 

 

Estate tax

 

Our common stock owned or treated as owned by an individual who is not a citizen or resident of the U.S. (as specifically defined for U.S. federal estate tax purposes) at the time of death will be includible in the individual’s gross estate for U.S. federal estate tax purposes, unless an applicable estate tax treaty provides otherwise.

 

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Underwriting

 

J.P. Morgan Securities Inc. is acting as sole bookrunner, Banc of America Securities LLC and Lehman Brothers Inc. are acting as joint lead managers and Comerica Securities, Inc. and Fortis Securities LLC are acting as co-managers for this offering.

 

We and the underwriters named below have entered into an underwriting agreement covering the common stock to be sold in this offering. Each underwriter has severally agreed to purchase, and we and the selling stockholders have agreed to sell to each underwriter, the number of shares of common stock set forth opposite its name in the following table.

 

Name    Number of shares

J.P. Morgan Securities Inc.  

    

Banc of America Securities LLC

    

Lehman Brothers Inc.  

    

Comerica Securities, Inc.  

    

Fortis Securities LLC

    
    

Total

    

 

The underwriting agreement provides that if the underwriters take any of the shares presented in the table above, then they must take all of the shares. No underwriter is obligated to take any shares allocated to a defaulting underwriter except under limited circumstances. The underwriting agreement provides that the obligations of the underwriters are subject to certain conditions precedent, including the absence of any material adverse change in our business and the receipt of certain certificates, opinions and letters from us, our counsel and our independent auditors.

 

The underwriters are offering the shares of common stock, subject to the prior sale of shares, and when, as and if such shares are delivered to and accepted by them. The underwriters will initially offer to sell shares to the public at the initial public offering price shown on the front cover page of this prospectus. The underwriters may sell shares to securities dealers at a discount of up to $             per share from the initial public offering price. Any such securities dealers may resell shares to certain other brokers or dealers at a discount of up to $             per share from the initial public offering price. After the initial public offering, the underwriters may vary the public offering price and other selling terms.

 

If the underwriters sell more shares than the total number shown in the table above, the underwriters have the option to buy up to an additional              shares of common stock from us and              shares from the selling stockholders to cover such sales. They may exercise this option during the 30-day period from the date of this prospectus. If any shares are purchased with this option, the underwriters will purchase shares in approximately the same proportion as shown in the table above. If any additional shares of common stock are purchased, the underwriters will offer the additional shares on the same terms as those on which the shares are being offered.

 

At our request, the underwriters have reserved up to 5% of the total underwritten shares offered by this prospectus as part of our Directed Share Program. These shares will be offered at the initial public offering price to certain of our officers, directors, employees and certain other persons associated with us. The number of shares available for sale to the general public will be reduced to the extent such persons purchase such reserved shares. Any reserved shares not so

 

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purchased will be offered by the underwriters to the general public on the same basis as the other shares offered hereby. The Directed Share Program will be arranged through one of our underwriters, Lehman Brothers.

 

The following table shows the per share and total underwriting discounts that we and the selling stockholders will pay to the underwriters. These amounts are shown assuming both no exercise and full exercise of the underwriters’ option to purchase additional shares.

 

     Paid by the Company

   Paid by selling stockholders

     Without
option exercise
   With full
option exercise
   Without
option exercise
   With full
option exercise

Per share

   $             $             $             $         

Total

   $             $             $             $         

 

The underwriters have advised us that they may make short sales of our common stock in connection with this offering, resulting in the sale by the underwriters of a greater number of shares than they are required to purchase pursuant to the underwriting agreement. The short position resulting from those short sales will be deemed a “covered” short position to the extent that it does not exceed the shares subject to the underwriters’ overallotment option and will be deemed a “naked” short position to the extent that it exceeds that number. A naked short position is more likely to be created if the underwriters are concerned that there may be downward pressure on the trading price of the common stock in the open market that could adversely affect investors who purchase shares in this offering. The underwriters may reduce or close out their covered short position either by exercising the overallotment option or by purchasing shares in the open market. In determining which of these alternatives to pursue, the underwriters will consider the price at which shares are available for purchase in the open market as compared to the price at which they may purchase shares through the overallotment option. Any “naked” short position will be closed out by purchasing shares in the open market. Similar to the other stabilizing transactions described below, open market purchases made by the underwriters to cover all or a portion of their short position may have the effect of preventing or retarding a decline in the market price of our common stock following this offering. As a result, our common stock may trade at a price that is higher than the price that otherwise might prevail in the open market.

 

The underwriters have advised us that, pursuant to Regulation M under the Securities Act, they may engage in transactions, including stabilizing bids or the imposition of penalty bids, that may have the effect of stabilizing or maintaining the market price of the shares of common stock at a level above that which might otherwise prevail in the open market. A “stabilizing bid” is a bid for or the purchase of shares of common stock on behalf of the underwriters for the purpose of fixing or maintaining the price of the common stock. A “penalty bid” is an arrangement permitting the underwriters to claim the selling concession otherwise accruing to an underwriter or syndicate member in connection with the offering if the common stock originally sold by that underwriter or syndicate member is purchased by the underwriters in the open market pursuant to a stabilizing bid or to cover all or part of a syndicate short position. The underwriters have advised us that stabilizing bids and open market purchases may be effected on the NYSE, in the over-the-counter market or otherwise and, if commenced, may be discontinued at any time.

 

One or more of the underwriters may facilitate the marketing of this offering online directly or through one of its affiliates. In those cases, prospective investors may view offering terms and a

 

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prospectus online and, depending upon the particular underwriter, place orders online or through their financial advisor.

 

We estimate that our share of the total expenses of this offering, excluding underwriting discounts, will be approximately $2,000,000.

 

We and the selling stockholders have agreed to indemnify the underwriters against certain liabilities, including liabilities under the Securities Act.

 

We and our executive officers and directors and the holders of all of our outstanding common stock and common stock equivalents have agreed that, during the period beginning from the date of this prospectus and continuing to and including the date 180 days after the date of this prospectus, neither we nor any of them will, directly or indirectly, offer, sell, offer to sell, contract to sell or otherwise dispose of any shares of our common stock without the prior written consent of J.P. Morgan Securities Inc., except in limited circumstances. Notwithstanding the foregoing, our executive officers, directors and stockholders may transfer shares of common stock or common stock equivalents (1) as a bona fide gift or gifts without consideration, (2) to any trust for the direct or indirect benefit of such person or the immediate family member of such person, (3) to any “affiliate” of such stockholder, or (4) to any partner or beneficiary of such current stockholder as a distribution or upon the dissolution of such stockholder, provided in each case the donee or assignee thereof agrees to be bound in writing by the foregoing lock-up restrictions. In addition, we may issue shares of common stock or securities convertible into or exchangeable or exercisable for shares of common stock (1) for the benefit of our employees, directors and officers under benefit plans described in this prospectus or (2) in connection with any acquisitions in an aggregate amount not to exceed 10% of the number of our issued and outstanding shares of common stock on the closing date of this offering, provided that the recipient of any such shares agrees to be bound by the foregoing lock-up restrictions.

 

The underwriters have informed us that they will not confirm sales to accounts over which they exercise discretionary authority without prior written approval of the customer.

 

We have applied to list our common stock on the NYSE under the symbol “CPR.” The underwriters intend to sell shares of our common stock to a minimum of 2,000 beneficial owners in lots of 100 or more so as to meet the distribution requirements of this listing.

 

There has been no public market for the common stock prior to this offering. We, the selling stockholders and the underwriters will negotiate the initial public offering price. In determining the initial public offering price, we, the selling stockholders and the underwriters expect to consider a number of factors in addition to prevailing market conditions, including:

 

  the history of and prospects for our industry;
  an assessment of our management;
  our present operations;
  our historical results of operations;
  the trend of our revenues and earnings; and
  our earnings prospects.

 

We, the selling stockholders and the underwriters will consider these and other relevant factors in relation to the price of similar securities of generally comparable companies. None of the Company, the selling stockholders and the underwriters can assure investors that an active

 

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trading market will develop for the common stock, or that the common stock will trade in the public market at or above the initial public offering price.

 

JPMorgan Chase Bank, N.A., an affiliate of J.P. Morgan Securities Inc., is the administrative agent, collateral agent and a lender under our Credit Agreement. In addition, each of Banc of America Securities LLC, Comerica Securities, Inc. and Fortis Securities LLC has an affiliate that is a lender and/or agent under our Credit Agreement. The amount of outstanding indebtedness owed to such lender affiliates under our Credit Agreement will be reduced with a portion of the net proceeds from this offering, which may result in these underwriters being deemed to have received more than 10% of the net offering proceeds. Accordingly, this offering will be made in compliance with the applicable provisions of Rule 2720 of the Conduct Rules. Rule 2720 requires that the initial public offering price can be no higher than that recommended by a “qualified independent underwriter,” as defined by the NASD. Accordingly, Lehman Brothers Inc., another underwriter of this offering, is assuming the responsibilities of acting as the qualified independent underwriter in pricing this offering, conducting due diligence and reviewing and participating in the preparation of this prospectus and the registration statement of which this prospectus forms a part. The initial public offering price of the shares of common stock will be no higher than the price recommended by Lehman Brothers Inc.

 

From time to time in the ordinary course of their respective businesses, certain of the underwriters and their affiliates perform various financial advisory, investment banking and commercial banking services from time to time for us and our affiliates. For example, J.P. Morgan Chase Bank, an affiliate of J.P. Morgan Securities Inc., is the administrative agent, collateral agent and a lender under our Credit Agreement. In addition, each of Banc of America Securities LLC, Comerica Securities, Inc. and Fortis Securities LLC has an affiliate that is a lender and/or agent under our Credit Agreement. We intend to repay $             million of the amounts outstanding under our Credit Agreement with a portion of the net proceeds of this offering, of which approximately $             million will reduce the indebtedness outstanding to such affiliates in the aggregate. See “Use of proceeds.”

 

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Legal matters

 

The validity of our shares of common stock offered by this prospectus will be passed upon for us by Andrews Kurth LLP, Houston, Texas. Legal matters in connection with this offering will be passed upon for the underwriters by Cahill Gordon & Reindel LLP, New York, New York.

 

 

Experts

 

The consolidated financial statements of Chaparral Energy Inc. and subsidiaries as of December 31, 2004 and 2005 and for each of the three years in the period ended December 31, 2005 and the financial statements of CEI Bristol Acquisition, L.P. as of December 31, 2003 and 2004 and for each of the three years in the period ended December 31, 2004, included in this prospectus and registration statement, have been audited by Grant Thornton LLP, independent registered public accounting firm, as stated in their reports appearing herein, and are included in reliance upon the authority of said firm as experts in accounting and auditing.

 

 

Independent petroleum engineers

 

Certain estimates of our net oil and natural gas reserves and related information as of December 31, 2003 included in this prospectus have been derived from engineering reports prepared by Cawley, Gillespie & Associates, Inc. Certain estimates of our net proved oil and natural gas reserves and the net proved oil and natural gas reserves of CEI Bristol as of December 31, 2004 and 2005 included in this prospectus have been derived from engineering reports prepared by Cawley, Gillespie & Associates, Inc. and Lee Keeling & Associates, Inc. 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-1, including exhibits and schedules, under the Securities Act with respect to the common stock to be sold in this offering. 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 our common stock, 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 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

 

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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.

 

Following the completion of this offering, we will file with or furnish to the SEC periodic reports and other information. These reports and other information may be inspected and copied at the public reference facilities maintained by the SEC or obtained from the SEC’s website as provided above. Our website on the Internet is located at http://www.chaparralenergy.com, and we expect to 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 annual reports containing our audited financial statements prepared in accordance with GAAP. We also intend to furnish or make available to our stockholders 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.

 

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Glossary of terms

 

The terms defined in this section are used throughout this prospectus:

 

Bbl

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

Bcf

   One billion cubic feet of natural gas.

Bcfe

   One billion cubic feet of natural gas equivalent using the ratio of one barrel of crude oil, condensate or natural gas liquids to 6 Mcf of natural gas.

Btu

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

Basin

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

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.

Fully developed finding, development and acquisition cost (FD&A)

  



Total costs incurred plus the increase in future development costs divided by total proved reserve acquisitions, extensions and discoveries and revisions.

Henry Hub spot price

   The price of natural gas, in dollars per MMbtu, being traded at the Henry Hub in Louisiana in transactions for next-day delivery, measured downstream from the wellhead after the natural gas liquids have been removed and a transportation cost has been incurred.

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.

MBbl

   One thousand barrels of crude oil, condensate or natural gas liquids.

Mcf

   One thousand cubic feet of natural gas.

Mcfe

   One thousand cubic feet of natural gas equivalents.

MMBbl

   One million barrels of crude oil, condensate or natural gas liquids.

MMBtu

   One million British thermal units.

MMcf

   One million cubic feet of natural gas.

 

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MMcfe

   One million cubic feet of natural gas equivalents.

NYMEX

   The New York Mercantile Exchange.

Net acres

   The percentage of total acres an owner has out of a particular number of acres, or a specified tract. An owner who has 50% interest in 100 acres owns 50 net acres.

Net working interest

   A working interest owner’s gross working interest in production, less the related royalty, overriding royalty, production payment, and net profits interests.

PDP

   Proved developed producing.

PV-10 value

   When used with respect to oil and natural gas reserves, PV-10 value means the estimated future gross revenue to be generated from the production of proved reserves, net of estimated production and future development and abandonment costs, using prices and costs in effect at the determination date, before income taxes, and without giving effect to non-property-related expenses, discounted to a present value using an annual discount rate of 10% in accordance with the guidelines of the Commission.

Primary recovery

   The period of production in which oil moves from its reservoir through the wellbore under naturally occurring reservoir pressure.

Proved developed reserves

   Reserves that can be expected to be recovered through existing wells with existing equipment and operating methods.

Proved reserves

   The estimated quantities of crude oil, natural gas and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions, i.e., prices and costs as of the date the estimate is made. Prices include consideration of changes in existing prices provided only by contractual arrangements, but not on escalations based upon future conditions.

Proved undeveloped reserves

   Reserves that are expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for recompletion.

Sand

   A geological term for a formation beneath the surface of the earth from which hydrocarbons are produced. Its make-up is sufficiently homogenous to differentiate it from other formations.

Secondary recovery

   The recovery of oil and 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.

 

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Seismic survey

   Also known as a seismograph survey, 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.

Tertiary recovery

   The use of any improved recovery method, including injection of CO2, to remove additional oil after secondary recovery. Compare primary recovery, secondary recovery.

Unit

   The joining of all or substantially all interests in a reservoir or field, rather than a single tract, to provide for development and operation without regard to separate property interests. Also, the area covered by a unitization agreement.

WTI Cushing spot price

   The price of West Texas Intermediate grade crude oil, in dollars per barrel, in transactions for immediate delivery at Cushing, Oklahoma.

Waterflood

   The injection of water into an oil reservoir to “push” additional oil out of the reservoir rock and into the wellbores of producing wells. Typically a secondary recovery process.

Wellbore

   The hole drilled by the bit that is equipped for oil or 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, 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 rock.

 

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Index to financial statements