S-1 1 ds1.htm FORM S-1 INITIAL PUBLIC OFFERING Form S-1 Initial Public Offering
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As filed with the Securities and Exchange Commission on December 29, 2005

Registration No. 333-            


SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 

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.  ¨

 

CALCULATION OF REGISTRATION FEE

 


Title of Each Class of

Securities To Be Registered

   Proposed Maximum
Aggregate Offering Price
    Amount of
Registration Fee

Common stock, par value $0.01

   $ 345,000,000 (1)(2)   $ 36,915

(1) Includes common stock issuable upon exercise of the Underwriters’ option to purchase additional common stock.
(2) Estimated solely for the purpose of calculating the registration fee pursuant to Rule 457(o).

 

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 December 29, 2005

 

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 82 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 intend to apply to have our common stock listed on the                              under the symbol             .

 

     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 17.

 

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

   17

Use of proceeds

   32

Dividend policy

   32

Capitalization

   33

Dilution

   34

Unaudited pro forma financial data

   35

Selected consolidated historical financial data

   41

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

   43

Business and properties

   57

Management

   76

Principal and selling stockholders

   82

Certain relationships and related transactions

   83

Description of capital stock

   85

Shares eligible for future sale

   89

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

   91

Underwriting

   94

Legal matters

   98

Experts

   98

Reserve engineers

   98

Where you can find more information

   98

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 17 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 these 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, 2004, approximately 87% 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 Acquisition, L.P., or CEI Bristol, for $158 million. We have managed this limited partnership since 2000.

 

As of December 31, 2004, on a pro forma basis we had estimated proved reserves of 606 Bcfe and a PV-10 value of $1,010.3 million. For the nine months ended September 30, 2005, on a pro forma basis, our average daily production was 80.9 MMcfe, a 14% increase over the comparable period in 2004. As of December 31, 2004 on a pro forma basis, our estimated reserve life would have been 22.7 years. On a pro forma basis, our revenues and Adjusted EBITDA for the year ended December 31, 2004 were $125.6 million and $82.7 million, respectively. For the nine months ended September 30, 2005, on a pro forma basis, our revenues and Adjusted EBITDA were $107.9 million and $79.0 million, respectively. We set forth our definition of PV-10 value (a non-GAAP measure) and a reconciliation of a 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 from continuing operations before accounting change to Adjusted EBITDA, beginning on page 14.

 

For the period from 2001 to 2004, our proved reserves and production have grown at a compounded annual growth rate of 41% and 20%, respectively. We have grown primarily

 

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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 significant inventory of drillable prospects and an active drilling program. We have identified over 700 proved developmental drilling locations, as well as over 2,200 additional potential drilling locations, which combined represent over 15 years of drilling opportunities based on our current 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 one proprietary shoot and are currently permitting on two additional proprietary 3-D shoots.

 

Our capital expenditures for oil and gas properties for the nine months ended September 30, 2005 were $104.2 million (excluding the acquisition of the limited partner interest in CEI Bristol Acquisition, L.P.), representing a 51% increase over the comparable period in 2004. Our capital expenditure budget for oil and gas properties for 2006 is $200 million assuming this offering is consummated. We have budgeted approximately 58% of our 2006 capital expenditures on development activities (drilling—41%, enhancements—10% and tertiary recovery—7%), 37% for acquisitions and 5% for exploration activities. 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, which are characterized as lower risk and have relatively low finding and development costs. We also have a significant inventory of carbon dioxide (CO2) tertiary recovery projects in the Mid-Continent and Permian Basin, and we have budgeted increased capital expenditures for these projects going forward.

 

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The following tables present proved reserves and PV-10 value as of December 31, 2004, and average daily production for the year ended December 31, 2004 and nine months ended September 30, 2005 by major areas of operation for Chaparral and CEI Bristol.

 

    Proved reserves as of December 31, 2004

  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,
2004
  Nine months
ended
September 30,
2005

Chaparral

                             

Mid-Continent

  31,015   193,916   380,006   73.7%   $ 586.7   40.6   46.6

Permian Basin

  5,532   37,656   70,848   13.7%     129.0   6.2   8.1

East Texas

  1,030   20,095   26,275   5.1%     49.5   2.1   5.4

North Texas

  2,810   386   17,246   3.3%     40.4   1.6   2.0

Rocky Mountains

  1,241   3,206   10,652   2.1%     19.5   0.6   1.6

Gulf Coast

  386   7,392   9,708   1.9%     18.2   1.0   1.5

Other

  13   969   1,047   0.2%     1.8    
   

Chaparral total

  42,027   263,620   515,782   100.0%   $ 845.1   52.1   65.2
   

CEI Bristol

                             

Mid-Continent

  913   39,165   44,643   49.6%   $ 79.0   14.9   9.8

Permian Basin

  974   19,948   25,792   28.6%     48.6   2.1   2.1

East Texas

  102   8,567   9,179   10.2%     16.9   0.6   1.3

North Texas

  357   302   2,444   2.7%     4.0   0.4   0.5

Rocky Mountains

  176   1,414   2,470   2.7%     3.6   0.8   0.6

Gulf Coast

  318   3,643   5,551   6.2%     13.1   1.6   1.4
   

CEI Bristol total

  2,840   73,039   90,079   100.0%   $ 165.2   20.4   15.7
   

Pro forma total

  44,867   336,659   605,861       $ 1,010.3   72.5   80.9

 

 

Business strengths

 

Consistent track record of low-cost reserve additions and production growth.    From 2001 to 2004, we have grown reserves and production by a compounded annual growth rate of 41% and 20%, 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 610%, 468% and 1,219% of our production in 2002, 2003 and 2004, respectively, at a fully developed average F&D cost of $1.31 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 2002, 2003 and 2004, our capital expenditures for acquisitions were $17.7 million, $19.9 million and $30.5 million, respectively. These acquisition capital expenditures represented approximately 43%, 35% and 32%, respectively, of our total

 

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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, as of September 30, 2005, an estimated 115 Bcfe of proved reserves. Not including the acquisition of CEI Bristol, we spent $37.3 million on acquisitions during the first nine months of 2005, representing approximately 36% 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, 2004, we had an inventory of over 700 proved developmental drilling locations and over 2,200 additional potential drilling locations. Not including the CEI Bristol acquisition, we spent $52.1 million on development and exploration drilling for the first nine months of 2005. For 2006, we have budgeted $92 million to drill more than 55 operated wells and to participate in more than 130 wells operated by others. We believe these are low-to-medium risk opportunities with anticipated payouts in under 3 years. Additionally, we utilize 3-D seismic data to help identify additional reserve targets in, around and under older producing fields.

 

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 a second tertiary flood unit in the Oklahoma panhandle. We have subsequently acquired other related assets, and our proved reserves at December 31, 2004 include 16 projects that will utilize CO2 tertiary recovery methods. In 2004, we added 111.2 Bcfe of CO2 tertiary reserves to our proved undeveloped reserve category. The 16 CO2 tertiary recovery projects included in our proved reserves accounted for approximately 26% of our December 31, 2004 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 33 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 21 years, serving as President of Kitscoty Oil LLC and previously as our Chief Financial Officer. Mark Fischer and Charles Fischer are brothers. Individuals in our 24-person management team have an average of over 24 years of experience each 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

 

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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 $82 million, or 41% 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 acquisition, we have spent approximately $37.3 million on acquisitions through September 30, 2005. Our 2006 acquisition capital budget is $73 million, or 37% of our total capital expenditure budget.

 

Apply technical expertise to enhance mature properties.    Once we acquire a property and become its 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 14 field offices throughout Oklahoma and Texas. 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, 2004, we had an inventory of 221 developed enhancement projects requiring total estimated capital expenditures of $9 million.

 

Expand CO2 enhanced oil recovery activities.    We have accumulated interests in 45 fields in Oklahoma and Texas that meet the criteria for CO2 tertiary recovery operations and are expanding our CO2 pipeline system to initiate CO2 injection in a number of these fields. Four of our 16 CO2 projects in our proved reserves are scheduled to initiate CO2 injection in 2006. We have a 100% ownership interest in 86 miles of CO2 pipeline and control a 50% or larger ownership interest in an additional 160 miles of CO2 pipeline. The planned construction of 88 miles of CO2 pipeline will facilitate CO2 injection in these new projects. We have budgeted $14 million in 2006 towards these projects. To support our existing CO2 tertiary oil recovery projects, we currently inject approximately 37 MMcf per day of CO2.

 

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 approximately 5% of our 2006 capital expenditures on exploratory drilling.

 

Control operations and costs.    We generally 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

 

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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. Operations are crucial to the implementation of our programs and, accordingly, we are willing to take additional measures to become the operator. As of December 31, 2004, we operated properties comprising approximately 84% 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. Excluding PDP production attributable to the CEI Bristol acquisition, as of September 30, 2005, we had hedges in place for approximately 77%, 55% and 5% of our estimated PDP gas production for 2006, 2007 and 2008, respectively. We also had hedges in place for approximately 78%, 61% and 6% of our estimated PDP oil production for 2006, 2007 and 2008, respectively.

 

 

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 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. As a result of the acquisition, CEI Bristol became one of our wholly-owned subsidiaries.

 

CEI Bristol’s properties are 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 the fourth quarter of 2005 and in 2006 by approximately 1.4 Bcfe and 4.8 Bcfe, respectively.

 

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We funded $132 million of the acquisition costs with the proceeds from a bridge loan facility with General Electric Capital Corporation, which we refer to as the GE Bridge Loan, and the remainder with borrowings from our Credit Agreement and cash on hand. This bridge loan was repaid on December 1, 2005 with the proceeds from the issuance of our 8 1/2% Senior Notes. Prior to our acquisition of CEI Bristol, the borrowing base under our Credit Agreement was increased from $235.0 million to $270.0 million. Upon issuance of our 8 1/2% Senior Notes, our borrowing base was reduced from $270.0 million to $172.5 million.

 

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 per year. The ethanol plant is estimated to also generate approximately 8 MMcf per day of CO2, and 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 for this joint venture are estimated to be $76 million, with Chaparral having a 66.67% ownership interest. We expect Oklahoma Ethanol L.L.C. will receive approximately $46 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 construction to commence in 2006 with completion in 2007, and that our equity contribution will be approximately $18 million.

 


 

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

 

 

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 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.

 

Proposed              symbol:                

 

 

Risk factors:

 

See “Risk factors” and the other information included in this prospectus for a discussion of the factors you should consider carefully before deciding to invest in shares of our common stock.

 

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

 

 

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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Table of Contents

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 43 and the “Unaudited pro forma financial data” beginning on page 35 of this prospectus. The historical consolidated financial data for each of the three fiscal years ended December 31, 2004 (except for balance sheet data as of December 31, 2002) were derived from our audited annual financial statements included in this prospectus. The data for the nine months ended September 30, 2004 and 2005 were derived from our unaudited interim consolidated financial statements also appearing in this prospectus. In the opinion of management, this nine-month data includes all normal recurring adjustments necessary for a fair presentation of the results for those interim periods. 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 September 30, 2005. The results of operations of CEI Bristol will be 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, 2004 and nine months ended September 30, 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 statements of operations data for the year ended December 31, 2004 and for the nine months ended September 30, 2005 assume the pro forma transactions described above all occurred on January 1, 2004.

 

The pro forma, as adjusted financial position data as of September 30, 2005 gives effect to the transactions described above and this common stock offering and the application of the net proceeds as described in “Use of proceeds.”

 

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Table of Contents

The non-generally accepted accounting principle, or non-GAAP, financial measure of Adjusted EBITDA is defined by us as income from continuing operations 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 measure and reconciliation,” we have provided the necessary explanations and reconciliations for this non-GAAP financial measure.

 

    

Chaparral

Year ended December 31,


 
     Historical

   

Pro forma

2004

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


                       (unaudited)  

Operating results data:

                                

Revenues

                                

Oil and gas sales

   $ 42,653     $ 74,186     $ 113,546     $ 157,856  

Loss on oil and gas hedging activities

     (749 )     (12,220 )     (21,350 )     (32,242 )
    


Total revenues

     41,904       61,966       92,196       125,614  
    


Costs and expenses

                                

Lease operating

     14,506       18,706       25,392       32,085  

Production taxes and gas handling charges

     3,645       5,654       9,808       15,331  

Depreciation, depletion and amortization

     7,910       10,376       18,234       25,547  

General and administrative

     4,059       4,946       5,985       7,232  
    


Total costs and expenses

     30,120       39,682       59,419       80,195  
    


Operating income

     11,784       22,284       32,777       45,419  
    


Non-operating income (expense)

                                

Interest expense

     (3,998 )     (4,116 )     (6,162 )     (29,250 )

Other income

     1,012       208       279       188  
    


Net non-operating expense

     (2,986 )     (3,908 )     (5,883 )     (29,062 )
    


Income from continuing operations before income taxes and accounting change

     8,798       18,376       26,894       16,357  

Income tax expense

     3,134       6,932       9,629       5,856  
    


Income from continuing operations before accounting change

     5,664       11,444       17,265       10,501  

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

           (887 )            

Discontinued operations, net of income taxes

     (617 )                  
    


Net income

   $ 5,047     $ 10,557     $ 17,265     $ 10,501  
    


 

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Chaparral

Year ended December 31,


     Historical

   

Pro forma

2004

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

  

 

 

 
                       (unaudited)

Earnings per share (historical):

                              

Income per share from continuing operations

   $ 5,664     $ 11,444     $ 17,265     $ 10,501

Income (loss) per share from accounting change, net

           (887 )          

Income (loss) per share from discontinued operations, net

     (617 )                

Net income per share

   $ 5,047     $ 10,557     $ 17,265     $ 10,501

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 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

   $ 17,480     $ 32,541     $ 49,849       na

Net cash used in investing activities

     (27,505 )     (55,213 )     (95,120 )     na

Net cash provided by financing activities

     8,921       26,146       54,061       na

Other financial data:

                              

Capital expenditures for oil & gas properties

   $ 40,852     $ 56,962     $ 96,031       na

Adjusted EBITDA(1)

     21,311       33,288       51,894     $ 82,650
     As of December 31,

     
     2002

    2003

    2004

     

Financial position data:

                              

Cash and cash equivalents

   $ 1,578     $ 5,052     $ 13,842        

Total assets

     142,919       211,086       308,126        

Total debt

     91,780       118,355       176,622        

Undistributed earnings

     20,420       30,977       48,242        

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

     (3,733 )     (4,900 )     (12,107 )      

Total equity

     16,688       26,078       36,136        

 

(1)   Adjusted EBITDA is defined as income from continuing operations 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.”

 

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Table of Contents
     Chaparral
Nine months ended September 30,


 
     Historical

   

Pro forma
2005

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


Operating results data:

                        

Revenues

                        

Oil and gas sales

   $ 76,504     $ 130,727     $ 160,500  

Loss on oil and gas hedging activities

     (14,073 )     (39,743 )     (52,579 )
    


Total revenues

     62,431       90,984       107,921  
    


Costs and expenses

                        

Lease operating

     18,342       25,765       30,859  

Production taxes and gas handling charges

     6,537       12,075       15,613  

Depreciation, depletion and amortization

     11,559       23,089       28,581  

General and administrative

     4,473       6,631       7,520  
    


Total costs and expenses

     40,911       67,560       82,573  
    


Operating income

     21,520       23,424       25,348  
    


Non-operating income (expense)

                        

Interest expense

     (4,099 )     (8,283 )     (23,136 )

Other income

     336       524       541  
    


Net non-operating expense

     (3,763 )     (7,759 )     (22,595 )
    


Income before income taxes

     17,757       15,665       2,753  

Income tax expense

     6,358       5,701       1,002  
    


Net income

   $ 11,399     $ 9,964     $ 1,751  
    


Earnings per share (historical):

                        

Basic and diluted income per share

   $ 11,399     $ 9,964     $ 1,751  

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

     1,000       1,000       1,000  

Earnings per share (pro forma for stock split):

                        

Basic and diluted 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

   $ 36,285     $ 50,840       na  

Net cash used in investing activities

     (68,344 )     (222,009 )     na  

Net cash provided by financing activities

     38,256       208,384       na  

Other financial data:

                        

Capital expenditures for oil & gas properties

   $ 69,023     $ 260,985       na  

Adjusted EBITDA(1)

     35,011       58,717     $ 78,986  
           As of September 30,
2005


 
           Historical

    Proforma,
as adjusted


 

Financial position data:

                        

Cash and cash equivalents(2)

           $ 51,057     $ 83,557  

Total assets

             632,554       674,054  

Total debt

             388,229       337,729  

Undistributed earnings

             55,147       na  

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

             (75,030 )     na  

Total equity (deficit)

             (19,882 )     na  


(1)   Adjusted EBITDA is defined as income from continuing operations 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 part of the CEI Bristol acquisition. See “Non-GAAP financial measure and reconciliation.”
(2)   Includes $42.1 million of cash subsequently used to settle hedges of CEI Bristol on October 3, 2005.

 

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Table of Contents

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, 2004 less 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, 2004 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

   $ 586.7    $ 200.4    $ 386.3

Permian Basin

     129.0      44.1      84.9

East Texas

     49.5      16.9      32.6

North Texas

     40.4      13.8      26.6

Rocky Mountains

     19.5      6.7      12.8

Gulf Coast

     18.2      6.2      12.0

Other

     1.8      0.5      1.3
    

  

  

Total PV-10

   $ 845.1    $ 288.6    $ 556.5
    

  

  

 

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Table of Contents

Adjusted EBITDA

 

We define Adjusted EBITDA as income from continuing operations 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 from continuing operations before accounting changes to Adjusted EBITDA:

 

    Historical       Pro forma
    Year ended
December 31,
      Nine months
ended
September 30,
     

Year ended

December 31,

     

Nine months

ended

September 30,

(Dollars in thousands)
(unaudited)
  2002   2003   2004       2004   2005       2004       2005

Income from continuing operations before accounting change

  $ 5,664   $ 11,444   $ 17,265       $ 11,399   $ 9,964       $ 10,501       $ 1,751

Interest expense

    3,998     4,116     6,162         4,099     8,283         29,250         23,136

Income tax expense

    3,134     6,932     9,629         6,358     5,701         5,856         1,002

Depreciation, depletion and amortization

    7,910     10,376     18,234         11,559     23,089         25,547         28,581

Unrealized loss on ineffective portion of hedges

    605     420     604         1,596     11,680         604         11,680

Loss on CEI Bristol hedges

                                10,892         12,836

Adjusted EBITDA

  $ 21,311   $ 33,288   $ 51,894       $ 35,011   $ 58,717       $ 82,650       $ 78,986

 

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Table of Contents

Summary historical and pro forma reserve information

 

The following table summarizes our historical and pro forma 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, 2002, 2003 and 2004), discounted at 10% per annum. Estimates of our net proved oil and natural gas reserves as of December 31, 2002 and 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 were prepared by Cawley, Gillespie and Associates, Inc. (62% of PV-10 value) and Lee Keeling & Associates, Inc. (13% of PV-10 value), both independent petroleum engineering firms, and our engineering staff (25% of PV-10 value). Estimates of the net proved oil and natural gas reserves of CEI Bristol as of December 31, 2004 were also prepared by Cawley, Gillespie and Associates, Inc.

 

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,   

Pro forma
as of
December 31,

2004

    2002    2003    2004   

Proved reserves

                          

Oil (Mbbl)

    16,243      16,777      42,027      44,867

Natural gas (MMcf)

    151,773      203,677      263,620      336,659

Natural gas equivalent (MMcfe)

    249,231      304,339      515,782      605,861

Proved developed reserves percentage

    78%      81%      56%      60%

PV-10 value (in thousands)

  $ 320,648    $ 488,305    $ 845,064    $ 1,010,134

Estimated reserve life (in years)(1)

    19.6      19.9      27.2      22.7

Cost incurred (in thousands):

                          

Property acquisition costs

  $ 17,730    $ 19,864    $ 30,546    $ 30,932

Development costs

    21,343      36,758      62,371      72,299

Exploration costs

    1,779      340      3,114      3,299

Total

  $ 40,852    $ 56,962    $ 96,031    $ 106,530

Annual reserve replacement ratio(2)

    610%      468%      1,219%      907%

Three-year fully developed average F&D cost ($/Mcfe)

                $ 1.31       

 

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

 

(2)   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.

 

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Table of Contents

Summary historical production and sales data

 

The following table sets forth certain information regarding Chaparral’s historical 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,         Nine months ended
September 30,
    2002    2003    2004         2004    2005

Net production volumes

                                      

Oil (MBbls)

    791      924      1,173           852      1,026

Natural gas (MMcf)

    7,952      9,762      11,923           8,241      11,456

Combined (MMcfe)

    12,698      15,306      18,961           13,353      17,612

Oil and gas sales ($ in thousands)(1)

                                      

Oil

  $ 19,560    $ 27,643    $ 47,537         $ 32,611    $ 54,921

Natural gas

    23,093      46,543      66,009           43,893      75,806

Total

  $ 42,653    $ 74,186    $ 113,546         $ 76,504    $ 130,727

Oil average sales price (per Bbl)

                                      

Price excluding hedges

  $ 24.73    $ 29.92    $ 40.53         $ 38.28    $ 53.53

Price including hedges

  $ 25.00    $ 26.70    $ 29.16         $ 30.98    $ 35.67

Natural gas average sales price (per Mcf)

                                      

Price excluding hedges

  $ 2.90    $ 4.77    $ 5.54         $ 5.33    $ 6.62

Price including hedges

  $ 2.78    $ 3.82    $ 4.86         $ 4.37    $ 4.75

Average production cost and production taxes (per Mcfe)

                                      

Average production cost(2)

  $ 1.14    $ 1.22    $ 1.34         $ 1.37    $ 1.46

Average production taxes(3)

  $ 0.29    $ 0.37    $ 0.52         $ 0.49    $ 0.69

 

(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), and the administrative costs of field offices and insurance.

 

(3)   Includes property and severance taxes and gas handling charges.

 

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Table of Contents

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. Our cash flow from operations is highly dependent on the prices that we receive for oil and natural gas. 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 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 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.

 

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Table of Contents

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. 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 actual results most likely will vary from our estimates. Also, the use of a 10% discount factor in calculating discounted future net cash flows for reporting purposes, as prescribed by the Securities and Exchange Commission, may not necessarily represent the most appropriate discount factor, given actual interest rates and risks to which our business or the oil and natural gas industry in general are subject. 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.

 

The reserve data included in this prospectus represent only estimates. 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, 2004 PV-10 value uses realized prices based on a Henry Hub spot price of $6.35 per MMBtu for natural gas and a WTI Cushing spot price of $43.51 per Bbl for oil.

 

As of December 31, 2004, approximately 44% of our estimated proved reserves were undeveloped. Recovery of undeveloped reserves requires significant capital expenditures and

 

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successful drilling and enhanced recovery operations. The reserve data assumes that we can and will make these expenditures and conduct these operations successfully, but these assumptions may not prove correct.

 

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

 

As of September 30, 2005 on a pro forma, as adjusted basis after giving effect to the issuance of our 8 1/2% Senior Notes, this offering and the use of proceeds from the issuance of these notes and this offering, our long-term indebtedness including capital leases would have been approximately $337.7 million, with no amount drawn under the revolving credit line of our senior secured Credit Agreement. On a pro forma, as adjusted basis after giving effect to the issuance of our 8 1/2% Senior Notes, this offering and the use of proceeds from the issuance of these notes and this offering, our total debt would have been $337.7 million and our total book capitalization would have been $456.8 million at September 30, 2005. We increased the maximum commitment amount and the borrowing base under our Credit Agreement to $450.0 million and $235.0 million, respectively, on June 22, 2005 and further increased the borrowing base to $270.0 million on September 30, 2005 prior to our acquisition of CEI Bristol. Our borrowing base under our Credit Agreement was reduced from $270.0 million to $172.5 million as a result of the issuance of our 8 1/2% Senior Notes. 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.

 

We may incur additional debt, including significant secured indebtedness, in order to make future acquisitions, to develop our properties or for other purposes. A higher level of indebtedness increases the risk that we may default on our debt obligations. Our ability to meet our debt obligations and to reduce our level of indebtedness depends on many factors. General economic conditions, oil and natural gas prices and financial, business and other factors affect our operations and our future performance. Many of these factors are beyond our control. We may not be able to generate sufficient cash flow to pay the interest on our debt, and future working capital, borrowings or equity financing may not be available to pay or refinance such

 

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debt. Factors that will affect our ability to raise cash through an offering of our capital stock or a refinancing of our debt include financial market conditions, the value of our assets and our performance at the time we need capital.

 

In addition, our bank borrowing base is subject to periodic redetermination. We could be forced to repay a portion of our bank borrowings due to redeterminations of our borrowing base. If we are forced to do so, 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 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 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 we are not able to replace reserves, we may not be able to sustain production.

 

Our future success depends largely upon our ability to find, develop or acquire additional oil and natural gas reserves that are economically recoverable. Unless we replace the reserves we produce through successful development, exploration or acquisition activities, our proved reserves and production will decline over time. In addition, approximately 44% of our total estimated proved reserves (by volume) at December 31, 2004 were undeveloped. By their nature,

 

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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 currently producing properties will decline at an average annual rate of approximately 17% during 2005 and 2006. 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 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.

 

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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.

 

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,

 

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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 September 30, 2005, we had hedged 20,130 MMcf and 2,013 MBbl of our natural gas and oil production for 2005 through 2008 at average monthly prices ranging from $6.06 to $10.02 per Mcf of natural gas and $36.00 to $64.53 per Bbl of oil. The fair value of our oil and natural gas derivative instruments outstanding as of September 30, 2005 was a liability of approximately $177.3 million, which includes approximately $42.1 million of hedge settlement costs related to the CEI Bristol acquisition. 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. The use of derivatives also 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.

 

Acquisitions are subject to the uncertainties of evaluating recoverable reserves and potential 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, many of which are beyond our control. These factors include 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 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. As a result, we may not be able to acquire oil and natural gas properties that contain economically recoverable reserves or be able to complete such acquisitions on acceptable terms.

 

 

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Additionally, significant acquisitions can change the nature of our operations and business depending upon the character of the acquired properties, which may have substantially different operating and geological characteristics or be in different geographic locations than our existing properties. It is our current intention to continue focusing on acquiring properties with development and exploration potential located in our core areas and growth areas. To the extent that we acquire properties substantially different from the properties in our primary operating regions or acquire properties that require different technical expertise, we may not be able to realize the economic benefits of these acquisitions as efficiently as in our prior acquisitions.

 

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 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. Additionally, if we are unable to find, hire and retain needed key personnel in the future, our results of operations could be materially and adversely affected.

 

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.

 

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

 

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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.

 

Terrorist attacks aimed at our energy operations could adversely affect our business.

 

The continued threat of terrorism and the impact of military and other government action has led and may lead to further increased volatility in prices for oil and natural gas and could affect these commodity markets for our operations or financial markets used by us. In addition, the U.S. government has issued warnings that energy assets may be a future target of terrorist organizations. These developments have subjected our oil and natural gas operations to increased risks. Any future terrorist attack on our facilities, those of our customers and, in some cases, those of other energy companies, could have a material adverse effect on our business.

 

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.

 

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 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 investment grade financial institutions and historically we have not experienced any credit losses.

 

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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 September 30, 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;

 

  the prohibition of stockholder action by written consent; 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 existing 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;

 

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

 

  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 intend to list our common stock on the             . We cannot predict the extent to which investor interest in our company will lead to the development of an active trading market on the                                                                                    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.

 

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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               , with which we are not 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

 

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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             . In addition, failure to comply with Section 404 or the report by us of a material weakness may cause investors to lose confidence 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            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 will be deemed to be a “controlled company” under the rules of the                         . Under these rules, we may elect not to comply with certain corporate governance requirements of the                 , 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                 . 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. 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.

 

As of September 30, 2005, we had $243.5 million outstanding under our restated Credit Agreement. Interest rates on approximately $208.5 million and $9.0 million were based on LIBOR (effective rates of 5.88% and 5.81%, respectively, at September 30, 2005). In addition at September 30, 2005 we had $26.0 million outstanding bearing interest at prime plus a margin (effective rate of 7.25%). Effective October 5, 2005 this amount was converted to a LIBOR loan with interest at 5.94%. We used the borrowings under the revolving credit line to acquire oil and gas properties and to fund our capital budget for drilling and enhancements. On December 1, 2005 we issued $325 million aggregate principal amount of our 8 1/2% Senior Notes and used a portion of the proceeds from the offering of these notes to repay approximately $184.0 million of the outstanding indebtedness under our Credit Agreement. Our borrowing base under the restated credit agreement was reduced from $270.0 million to $172.5 million as a result of the issuance of our 8 1/2% Senior Notes.

 

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 September 30, 2005:

 

  on a historical basis;

 

  on a pro forma basis to reflect the issuance of $325.0 million principal amount of our 8 1/2% Senior Notes and the repayment of the GE Bridge Loan with the net proceeds from the issuance of these notes; and

 

  on a pro forma, 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 September 30, 2005.

 

As of December 1, 2005, we had $94.0 million of indebtedness outstanding under our Credit Agreement, a portion of 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 September 30, 2005

 
(Dollars in thousands)   Historical     Pro forma     Pro forma,
as adjusted
 


Cash and cash equivalents(1)

  $ 51,057     $ 51,057     $ 130,557  

GE Bridge Loan

    132,000              

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

                       

Credit Agreement

    243,500       59,500        

Other

    12,729       12,729       12,729  

8 1/2% Senior Notes due 2015

          325,000       325,000  

Total debt

    388,229       397,229       337,729  

Stockholders’ equity (deficit):

                       

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

    1       1       1  

Additional paid-in capital

    0       0       139,000  

Retained earnings

    55,147       55,147       55,147  

Accumulated other comprehensive loss, net of taxes

    (75,030 )     (75,030 )     (75,030 )

Total stockholders’ equity (deficit)

    (19,882 )     (19,882 )     119,118  

Total capitalization

  $ 368,347     $ 377,347     $ 456,847  


 

(1)   Includes $42.1 million of cash subsequently used to settle hedges of CEI Bristol and $0.35 million used to pay a cash distribution on October 3, 2005.

 

(2)   Includes current maturities of long-term debt and capital leases of $2.9 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 September 30, 2005, we had a net tangible book deficit of $(19.9) 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 September 30, 2005 would have been $119.1 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 September 30, 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

          $               

 

The following table summarizes, on an as adjusted basis set forth above as of September 30, 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

  

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.

 

As of September 30, 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, 2004 and nine months ended September 30, 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 businesses actually been combined as of January 1, 2004.

 

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 nine months ended September 30, 2005 and for the year ended December 31, 2004.

 

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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Table of Contents

Chaparral Energy, Inc. and subsidiaries

Unaudited pro forma condensed consolidated statement of

operations for the nine months ended September 30, 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

  $ 130,727     $ 29,773           $ 160,500  

Loss on oil and gas hedging activities

    (39,743 )     (12,836 )           (52,579 )

Total revenues

    90,984       16,937               107,921  

Costs and expenses

                               

Lease operating

    25,765       5,787     $ (693 )(a)     30,859  

Production tax and gas handling charges

    12,075       3,538             15,613  

Depreciation, depletion and amortization

    23,089       4,818       674 (b)     28,581  

General and administrative

    6,631       196       693 (a)     7,520  

Total costs and expenses

    67,560       14,339       674       82,573  

Operating income

    23,424       2,598       (674 )     25,348  

Non-operating income (expense)

                               

Interest expense

    (8,283 )           (14,853 )(d)     (23,136 )

Other income

    524       20       (3 )(e)     541  

Net non-operating income (expense)

    (7,759 )     20       (14,856 )     (22,595 )

Income from continuing operations before income taxes

    15,665       2,618       (15,530 )     2,753  

Income tax expense

    5,701             (4,699 )(f)     1,002  

Net income

  $ 9,964     $ 2,618     $ (10,831 )   $ 1,751  
   


 


 


 


Earnings per share (historical)

                               

Net income per share

  $ 9,964                     $ 1,751  
   


                 


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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Table of Contents

Chaparral Energy, Inc. and subsidiaries

Unaudited pro forma condensed consolidated statement

of operations for the year ended December 31, 2004

 

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


Revenues

                               

Oil and gas sales

  $ 113,546     $ 44,310           $ 157,856  

Loss on oil and gas hedging activities

    (21,350 )     (10,892 )           (32,242 )

Total revenues

    92,196       33,418             125,614  

Costs and expenses

                               

Lease operating

    25,392       7,589     $ (896 )(a)     32,085  

Production tax and gas handling charges

    9,808       5,523             15,331  

Depreciation, depletion and amortization

    18,234       8,571       (1,258 )(b)     25,547  

Impairment of long-lived assets

          2,180       (2,180 )(c)      

General and administrative

    5,985       351       896 (a)     7,232  

Total costs and expenses

    59,419       24,214       (3,438 )     80,195  

Operating income

    32,777       9,204       3,438       45,419  

Non-operating income (expense)

                               

Interest expense

    (6,162 )           (23,088 )(d)     (29,250 )

Other income

    279       123       (214 )(e)     188  

Net non-operating income (expense)

    (5,883 )     123       (23,302 )     (29,062 )

Income from continuing operations before income taxes

    26,894       9,327       (19,864 )     16,357  

Income tax expense

    9,629             (3,773 )(f)     5,856  

Net income

  $ 17,265     $ 9,327     $ (16,091 )   $ 10,501  
   


 


 


 


Earnings per share (historical)

                               

Net income per share

  $ 17,265                     $ 10,501  
   


                 


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 statements of operations

 

Note 1: Basis of presentation

 

The accompanying unaudited pro forma statements of operations of Chaparral for the nine months ended September 30, 2005 and the year ended December 31, 2004 have 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, 2004.

 

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 elimination of impairment of oil and gas properties due to change in accounting for impairment for CEI Bristol from successful efforts to a full cost ceiling test.

 

(d)   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,
2004
   

Nine months

ended
September 30,
2005

 


Historical interest expense

   $ 6,162     $ 8,283  

Interest expense resulting from the notes issued

     27,625       20,719  

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

     (5,437 )     (6,541 )

Amortization of $9.0 million deferred financing costs related to the notes issued—10 years

     900       675  
    


Total pro forma interest expense

   $ 29,250     $ 23,136  


 

(e)   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.

 

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Table of Contents
(f)   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 35.8% in 2004 and 36.4% in 2005.

 

 

Note 3: Unaudited supplemental pro forma combined information related to oil and gas activities

 

The following unaudited supplemental pro forma combined information for oil and gas producing activities is presented pursuant to the disclosure requirements of Statement of Financial Accounting Standards No. 69 “Disclosures About Oil and Gas Producing Activities.”

 

Pro forma combined reserve quantity information

 

The following table sets forth the changes in net reserve quantities of oil and gas reserves for Chaparral, CEI Bristol and on a pro forma combined basis for the year ended December 31, 2004.

 

    Chaparral historical

    CEI Bristol historical

    Pro forma

 
    Oil
(Mbbls)
    Gas
(MMcf)
    Total
(Mmcfe)
    Oil
(Mbbls)
    Gas
(MMcf)
    Total
(Mmcfe)
    Oil
(Mbbls)
    Gas
(MMcf)
    Total
(Mmcfe)
 


Balance at December 31, 2003

  16,777     203,677     304,339     2,708     68,835     85,083     19,485     272,512     389,422  

Purchase of minerals in place

  3,724     39,894     62,238     143     6,334     7,192     3,867     46,228     69,430  

Sales of minerals in place

  (91 )   (201 )   (747 )               (91 )   (201 )   (747 )

Extensions and discoveries

  1,589     24,470     34,004     19     4,014     4,128     1,608     28,484     38,132  

Revisions

  2,051     2,229     14,535     186     (471 )   645     2,237     1,758     15,180  

Improved recoveries

  19,150     5,474     120,374     58     642     990     19,208     6,116     121,364  

Production

  (1,173 )   (11,923 )   (18,961 )   (275 )   (6,315 )   (7,965 )   (1,448 )   (18,238 )   (26,926 )
   

Balance at December 31, 2004

  42,027     263,620     515,782     2,839     73,039     90,073     44,866     336,659     605,855  
   

Proved developed reserves:

                                                     

December 31, 2004

  17,358     186,544     290,692     2,568     58,918     74,326     19,926     245,462     365,018  


 

Pro forma combined standardized measure of discounted future net cash flows

 

The following table sets forth the standardized measure of discounted future net cash flows relating to proved oil and gas reserves of Chaparral, CEI Bristol and on a pro forma combined basis as of December 31, 2004, as well as changes therein for the year then ended for Chaparral, CEI Bristol and on a pro forma combined basis (including adjustments to recognize the future tax effects on CEI Bristol):

 

(Dollars in thousands)    Chaparral
historical
    CEI Bristol
historical
    Adjustments     Pro forma  


Future cash flows

   $ 3,324,252     $ 530,846             $ 3,855,098  

Future production costs

     (1,095,352 )     (178,721 )             (1,274,073 )

Future development and abandonment costs

     (325,115 )     (17,797 )             (342,912 )

Future income tax provision

     (657,950 )         $ (110,604 )     (768,554 )
    


Net future cash flows

     1,245,835       334,328       (110,604 )     1,469,559  

Less effect of 10% discount factor

     (689,309 )     (169,125 )     55,951       (802,483 )
    


Standardized measure of discounted future net cash flows

   $ 556,526     $ 165,203     $ (54,653 )   $ 667,076  


 

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Table of Contents

Pro forma sources of changes in standardized measure of discounted future net cash flows

 

The principal changes in the aggregate standardized measure of discounted future net cash flows attributable to the proved oil and gas reserves of Chaparral, CEI Bristol and pro forma combined for the year ended December 31, 2004 are as follows:

 

(Dollars in thousands)    Chaparral
historical
    CEI Bristol
historical
    Adjustments     Pro forma  


Beginning of year

   $ 325,250     $ 140,440     $ (43,760 )   $ 421,930  

Sale of oil and gas produced, net of production costs

     (78,472 )     (31,198 )             (109,670 )

Net changes in prices and production costs

     89,687       9,986               99,673  

Extensions and discoveries

     56,933       2,471               59,404  

Improved recoveries

     143,366       5,696               149,062  

Changes in future development costs

     (69,721 )     (6,846 )             (76,567 )

Development costs incurred during the period that reduced future development costs

     11,230       2,491               13,721  

Revisions of previous quantity estimates

     32,775       1,121               33,896  

Purchases and sales of reserves in place, net

     109,754       17,468               127,222  

Accretion of discount

     49,565       14,044               63,609  

Net changes in income taxes

     (126,942 )           (10,893 )     (137,835 )

Changes in production rates and other

     13,101       9,530               22,631  
    


End of year

   $ 556,526     $ 165,203     $ (54,653 )   $ 667,076  


 

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Table of Contents

Selected consolidated historical financial data

 

You should read the following historical 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, 2004 were derived from our audited consolidated financial statements. The data for the nine months ended September 30, 2004 and 2005 were derived from our unaudited interim consolidated financial statements appearing in this prospectus. In the opinion of management, this nine-month data includes all normal recurring adjustments necessary for a fair statement of the results for those interim periods. Our historical results are not necessarily indicative of results to be expected in future periods.

 

    Year ended December 31,

    Nine months ended
September 30,


 
(Dollars in thousands)   2000     2001     2002     2003     2004     2004     2005  


                                  (unaudited)  

Operating results data:

                                                       

Revenues

                                                       

Oil and gas sales

  $ 37,796     $ 44,250     $ 42,653     $ 74,186     $ 113,546     $ 76,504     $ 130,727  

Gain (loss) on oil and gas hedging activities

    (6,879 )     10       (749 )     (12,220 )     (21,350 )     (14,073 )     (39,743 )
   


Total revenues

    30,917       44,260       41,904       61,966       92,196       62,431       90,984  
   


Costs and expenses

                                                       

Lease operating

    8,401       13,025       14,506       18,706       25,392       18,342       25,765  

Production taxes and gas handling charges

    3,132       3,767       3,645       5,654       9,808       6,537       12,075  

Depreciation, depletion and amortization

    3,162       5,835       7,910       10,376       18,234       11,559       23,089  

General and administrative

    2,294       3,506       4,059       4,946       5,985       4,473       6,631  
   


Total costs and expenses

    16,989       26,133       30,120       39,682       59,419       40,911       67,560  
   


Operating income

    13,928       18,127       11,784       22,284       32,777       21,520       23,424  
   


Non-operating income (expense)

                                                       

Interest expense

    (4,243 )     (4,966 )     (3,998 )     (4,116 )     (6,162 )     (4,099 )     (8,283 )

Other income

    318       201       1,012       208       279       336       524  
   


Net non-operating expense

    (3,925 )     (4,765 )     (2,986 )     (3,908 )     (5,883 )     (3,763 )     (7,759 )

Income from continuing operations before income taxes and accounting change

    10,003       13,362       8,798       18,376       26,894       17,757       15,665  

Income tax expense

    3,764       5,099       3,134       6,932       9,629       6,358       5,701  
   


Income from continuing operations before accounting change

    6,239       8,263       5,664       11,444       17,265       11,399       9,964  

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

                      (887 )                  

Discontinued operations, net of income taxes

          (575 )     (617 )                        
   


Net income

  $ 6,239     $ 7,688     $ 5,047     $ 10,557     $ 17,265     $ 11,399     $ 9,964  


 

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    Year ended December 31,

    Nine months ended
September 30,


 
(Dollars in thousands, except share and per
share amounts)
  2000     2001     2002     2003     2004     2004     2005  


                                  (unaudited)  

Earnings per share (historical):

                                                       

Income per share from continuing operations

  $ 6,239     $ 8,263     $ 5,664     $ 11,444     $ 17,265     $ 11,399     $ 9,964  

Income (loss) per share from accounting change, net

                      (887 )                  

Income (loss) per share from discontinued operations, net

          (575 )     (617 )                        
   


 


 


 


 


 


 


Net income per share

  $ 6,239     $ 7,688     $ 5,047     $ 10,557     $ 17,265     $ 11,399     $ 9,964  
   


 


 


 


 


 


 


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       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

  $ 19,062     $ 13,036     $ 17,480     $ 32,541     $ 49,849     $ 36,285     $ 50,840  

Net cash used in investing activities

    (21,565 )     (47,846 )     (27,505 )     (55,213 )     (95,120 )     (68,344 )     (222,009 )

Net cash provided by financing activities

    11,378       24,821       8,921       26,146       54,061       38,256       208,384  


 

    As of December 31,

    As of September 30,

 
(Dollars in thousands)   2000   2001   2002     2003     2004     2005  


                              (unaudited)  

Financial position data:

                                           

Cash and cash equivalents

  $ 10,647   $ 2,237   $ 1,578     $ 5,052     $ 13,842     $ 51,057  

Total assets

    84,839     129,855     142,919       211,086       308,126       632,554  

Total debt

    54,438     79,868     91,780       118,355       176,622       388,229  

Undistributed earnings

    7,686     15,373     20,420       30,977       48,242       55,147  

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

        3,379     (3,733 )     (4,900 )     (12,107 )     (75,030 )

Total equity (deficit)

    7,687     18,753     16,688       26,078       36,136       (19,882 )


 

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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, 2004, we had estimated proved reserves of 516 Bcfe, with a PV-10 value of $845 million. Our reserves were 56% proved developed and 51% gas.

 

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. 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;

 

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  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 are believed reasonable under the circumstances. Actual results may differ from these estimates.

 

 

Comparison of nine months ended September 30, 2005 to nine months ended September 30, 2004

 

Oil and gas sales.    Oil and gas sales before losses from hedging activity increased $54.2 million, or 71%, from 2004. The increase was due to average realized prices being 30% higher in 2005 and an increase of 32% in production volumes. The average prices received for oil increased 40% to $53.53 per barrel and for gas increased 25% to $6.62 per Mcf compared to 2004. Because of the increase in oil and gas prices our loss from oil and gas hedging activities increased by $25.7 million from 2004. The effect of our hedging program decreased average realized prices $2.26 per Mcfe in 2005 compared to a decrease of $1.05 of Mcfe in 2004.

 

Production volumes increased 32% (4,259 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 18% (1,877 MMcfe) in the Mid-Continent, 43% (651 MMcfe) in the Permian Basin, 191% (954 MMcfe) in East Texas, 94% (215 MMcfe) in the Gulf Coast, 174% (336 MMcfe) in North Texas, and 115% (226 MMcfe) in the Rocky Mountains.

 

Lease operating expenses.    Lease operating expenses increased $7.4 million, or 40%, from 2004 due to increases in the number of producing wells and higher oilfield service costs. We incurred $3.2 million of costs associated with workovers in 2005 compared to $1.7 million in 2004. On a per unit basis, lease operating expenses increased $0.09 per Mcfe primarily due to higher field level costs.

 

Production taxes and gas handling charges.    Production taxes and gas handling charges increased by $5.5 million from 2004. Production taxes, which include ad valorem taxes, are paid primarily based on oil and gas sales prices and increased by $3.7 million from 2004. This increase was caused by a 30% increase in prices and a 32% increase in oil and gas production. On a per Mcfe basis, production taxes increased from $0.41 to $0.53 due primarily to higher prices. Gas handling charges increased by $1.8 million primarily caused by increased production.

 

Depreciation, depletion and amortization (DD&A).    DD&A increased $11.5 million, or 100%, primarily due to an increase in DD&A on oil and gas properties of $10.7 million. For oil and gas properties, $4.9 million of the increase was due to higher production volumes in 2005 and $5.8 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 $0.45 to $1.31 per Mcfe primarily due to addition of higher-cost CO2 tertiary recovery reserves to our proved undeveloped reserves at the end of 2004.

 

General and administrative expenses (G&A).    G&A expense increased by $2.2 million, or 48%, from 2004. Approximately $0.4 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

 

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and related requirements caused by the increase in our level of activity. G&A expense is net of $4.3 million in 2005 and $3.0 million in 2004 capitalized as part of our exploration and development activities. On a per unit basis, G&A expense increased from $0.33 per Mcfe in 2004 to $0.38 per Mcfe in 2005.

 

Interest expense.    Interest expense increased $4.2 million, or 102%, from 2004 primarily due to an increase of approximately $79 million in the average amount of outstanding debt in 2005 (which is 58% higher than in 2004) and an increase in the average interest rate paid during 2005 of 1.7% (which is 28% higher than in 2004).

 

 

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 $6.7 million, or 36%, from 2003 due to increases in the number of 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 $0.12 per Mcfe primarily due to higher field level costs.

 

Production taxes and gas handling charges.    Production taxes and gas handling charges increased by $4.2 million from 2003. Production 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. Gas handling charges increased by $0.7 million largely caused by increased production.

 

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 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 $0.96 primarily due to the addition of higher cost CO2 tertiary recovery reserves to our proved undeveloped reserves in 2004. 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 is due primarily to an increase in our office staff and related requirements

 

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caused by the increase in our level of activity. G&A expense is 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 $2.0 million, or 50%, from 2003. An increase in outstanding debt in 2004 accounted for $1.7 million of the increase and an increase in interest rates accounted for the remainder.

 

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.

 

 

Comparison of year ended December 31, 2003 to year ended December 31, 2002

 

Oil and gas sales.    Oil and gas sales before losses from hedging activity increased $31.5 million, or 74%, from 2002. The increase was due to the average realized price being 44% higher in 2003 and an increase of 21% in production volumes. The average price received for oil increased 21% to $29.92 per barrel and for gas increased 65% to $4.77 per Mcf compared to 2002. Because of the increase in oil and gas prices our loss from oil and gas hedging activities increased by $11.5 million from 2002. The effect of our hedging program decreased the average realized price by $0.80 per Mcfe in 2003 compared to a decrease of $0.06 per Mcfe in 2002.

 

Production volumes increased 21% (2,608 MMcfe) from 2002 due to our drilling program, additions from acquisitions and enhancements of our existing properties. Production volumes increased in our areas by 18% (2,003 MMcfe) in the Mid-Continent, 38% (250 MMcfe) in the Permian Basin, 106% (205 MMcfe) in East Texas, 77% (105 MMcfe) in North Texas, and 144% (99 MMcfe) in the Rocky Mountains. Production volumes declined 20% (54 MMcfe) in the Gulf Coast area.

 

Lease operating expenses.    Lease operating expenses increased $4.2 million, or 29%, from 2002 due to increases in the number of producing wells and higher oilfield service costs. We incurred $1.6 million of costs associated with workovers in 2003 compared to $0.3 million in 2002. On a per unit basis, lease operating expenses increased $0.08 per Mcfe primarily due to higher field level costs.

 

Production taxes and gas handling charges.    Production taxes and gas handling charges increased by $2.0 million from 2002. Production taxes are paid primarily based on oil and gas sales and increased by $1.7 million from 2002. This increase was caused mostly by a 44% increase

 

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in prices and a 21% increase in production. On a per Mcfe basis, production taxes increased from $0.25 to $0.32 primarily due to higher prices. Gas handling charges increased by $0.3 million primarily caused by higher production.

 

Depreciation, depletion and amortization.    DD&A increased $2.5 million, or 31%, from 2002 consisting of an increase in DD&A on oil and gas properties of $1.7 million, the accretion of our asset retirement obligation for the first year of implementation of $0.6 million and an increase in DD&A on property and equipment of $0.2 million. For oil and gas properties, $1.4 million of the increase was due to higher production volumes in 2003 and $0.3 million of the increase was due to an increase in the unit of production rate in 2003.

 

General and administrative expenses.    G&A expense increased by $0.9 million, or 22%, from 2002. 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 $3.1 million in 2003 and $3.1 million in 2002 capitalized as part of our exploration and development activities. On a per Mcfe basis, G&A expense was $0.32 in 2002 and 2003.

 

Interest expense.    Interest expense increased $0.1 million, or 3%, from 2002 of which $0.8 million was due to an increase in outstanding debt in 2003, offset by $0.7 million from a decrease in interest rates.

 

Income tax expense.    The effective tax rates for 2003 and 2002 were 38% and 36% 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.

 

Loss on discontinued operations.    During 2002, we sold a contract drilling business that we acquired in 2001. The asset group sold was distinguishable as a component of Chaparral, and the operating results of the contract drilling operations were reported as discontinued operations. For 2002, contract drilling revenues were approximately $3.0 million and the pretax loss was $0.9 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 September 30, 2005, we had approximately $8.9 million of cash and cash equivalents, after the $42.1 million used to settle the CEI Bristol hedges on October 3, 2005, and $26.5 million of availability under our revolving credit line with a borrowing base of $270.0 million. At September 30, 2005, on a pro forma, as adjusted basis, after giving effect to our issuance of $325 million aggregate principal amount of 8 1/2% Senior Notes, we had approximately $113.0 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

 

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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 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.    As of September 30, 2005, we had incurred actual costs as summarized by area in the following table:

 

(Dollars in thousands)   Actual expenditures
for the nine
months ended
September 30, 2005(1)
   Percentage
of total

Mid-Continent

  $ 40,373    37.9%

Permian Basin

    27,107    25.4%

East Texas

    18,917    17.7%

Gulf Coast

    2,439    2.3%

North Texas

    14,002    13.1%

Rocky Mountains

    3,821    3.6%
    $ 106,659    100.0%

 

(1)   Includes $2.5 million of additions relating to increases in Chaparral’s asset retirement obligations.

 

In addition to the planned capital expenditures for oil and gas properties, we plan to spend approximately $7 million for acquisition and construction of new office and administrative facilities and equipment during 2005.

 

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. Factors such as product prices and the availability and cost of drilling rigs could increase or decrease the actual level of expenditures during 2006.

 

Cash provided from operating activities.    Substantially all of our cash flow from operating activities is from the production and sale of oil and gas. We use the net cash provided by operations to partially fund our acquisition, exploration and development activities. For the nine months ended September 30, 2005, the net cash provided from operations was approximately 47% of our net cash used in investing activities excluding the CEI Bristol acquisition. For the nine months ended September 30, 2005, cash flow from operating activities increased by 40% from the comparable period in the prior year. This increase was due primarily to an increase in oil and gas sales revenue partially offset by higher operating expense.

 

For the year ended December 31, 2004, the net cash provided from operations was approximately 52% of our net cash used in investing activities. For the year ended December 31, 2004, cash flow from operating activities increased by 53% from the prior year. This increase was due primarily to an increase in net income, an increase in the non-cash charge for depreciation, depletion and amortization and a decrease in accounts receivable.

 

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Our current credit facility.    We entered into a Sixth Restated Credit Agreement, which we refer to as the 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 the credit agreement is subject to a borrowing base set by the banks semi-annually on December 1 and June 1 of each year. 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 the Credit Agreement, and the borrowing base was $270.0 million. Our borrowing base under the 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.

 

Borrowings under the Credit Agreement are made, at our option, as either Eurodollar loans or Alternate Base Rate, or ABR, loans. At September 30, 2005 $217.5 million of our borrowings were Eurodollar loans and $26.0 million was an ABR loan. On October 5, 2005 the $26.0 million was converted to a Eurodollar loan.

 

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 September 30, 2005, the LIBOR rate was 4.14%, the Statutory Reserve Rate multiplier was 100% and the applicable margin was 2.00% resulting in an effective interest rate of 6.14% 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 the 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 September 30, 2005 the applicable rate was 6.75% and the applicable margin was 0.50% 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.

 

As of September 30, 2005 our weighted average interest rate on all borrowings under the Credit Agreement was 6.27%.

 

We have the right to make prepayments of the borrowings at any time without penalty or premium.

 

The 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 the Credit Agreement, of not less than 1.0 and a Minimum Debt Service Coverage Ratio, as defined in the Credit Agreement, of not less than 1.0. We believe we are in compliance with all covenants as of September 30, 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 the Credit Agreement, we consider the current ratio calculated under the Credit Agreement to be useful as a measure of our liquidity because it includes the funds available to us under the Credit Agreement and is not affected by the volatility in working capital caused by changes in the fair value of derivatives. At September 30, 2005 and December 31, 2004 our current ratio as computed using generally accepted accounting principles was 0.41 and 0.92, respectively. After giving effect to the adjustments, our current ratio computed for loan compliance purposes was 1.43 and 1.57, 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:

 

(Dollars in thousands)    December 31,
2004
    September 30,
2005
 


Current assets per GAAP

   $ 52,499     $ 133,490  

Plus—Availability under Credit Agreement

     20,611       25,500  

Less—Deferred tax asset on hedges and asset retirement obligation

     (5,291 )     (32,882 )

Less—Current assets of CEI Bristol

           (52,207 )

Less—Short term hedge instruments

           (103 )
    


Current assets as adjusted

   $ 67,819     $ 73,798  
    


Current liabilities per GAAP

   $ 57,185     $ 326,773  

Less—Short term hedge instruments

     (13,810 )     (136,603 )

Less—Short term asset retirement obligation

     (262 )     (1,382 )

Less—Other current liabilities of CEI Bristol

           (5,316 )

Less—GE Bridge Loan

           (132,000 )
    


Current liabilities as adjusted

   $ 43,113     $ 51,472  
    


Current ratio for loan compliance

     1.57       1.43  


 

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 refer to as the GE Bridge Loan, is due at maturity on June 30, 2006, bears interest at LIBOR plus 2% and is 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 pay down the borrowings 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.

 

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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 of certain equity offerings, 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.

 

Prior to December 1, 2010, we are entitled to redeem the 8 1/2% Senior Notes in whole or in part at a redemption price equal to the principal amount of the notes plus an applicable premium and accrued and unpaid interest to the date of redemption.

 

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

 

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, 2004:

 

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

Debt:

                                 

Revolving credit line—including estimated interest expense(1)

  $ 7,241    $ 168,009    $    $    $ 175,250

Other long-term notes—including estimated interest expense(2)

    2,192      5,287      745      6,732      14,956

Capital leases—including estimated interest

    589      285      19           893

Operating leases

    450      75                525

Abandonment obligations

    262      4,308      127      5,627      10,324

Derivative obligations

    13,810      7,425                21,235

Total

  $ 24,544    $ 185,389    $ 891    $ 12,359    $ 223,183

 

(1)   On a pro forma basis to reflect the offering of our 8 1/2% Senior Notes, as of September 30, 2005, the amount of the revolving credit line due in 3-5 years, excluding estimated interest expense, would be $59.5 million and the total amount would be $59.5 million.

 

(2)   On a pro forma basis to reflect the offering of our 8 1/2% Senior Notes, our other long-term notes more than 5 years and the total amount would be increased by $325.0 million, excluding estimated interest expense.

 

 

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

 

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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 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 75% of the estimated future net revenues of our proved reserves discounted at 10% as of December 31, 2004 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.

 

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  Costs not subject to amortization.    Costs of unevaluated properties are excluded from our amortization base until we have evaluated the properties. The costs associated with unevaluated leasehold acreage and seismic data, exploratory wells currently drilling and capitalized interest are initially excluded from our amortization base. Leasehold costs are either transferred to the amortization base with the costs of drilling a well or are assessed quarterly for possible impairment. At December 31, 2004 we had approximately $5.0 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, including changing technology and regulatory requirements, that are subject to future revisions. 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

 

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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 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 will adopt this statement in our first reporting period in 2006. We have not had any stock option plans and, therefore the adoption of SFAS 123(R) currently would have no impact on our financial position or results of operations. The adoption could have a future impact, however, if we implement any stock incentive plan.

 

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.

 

 

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

 

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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, 2004 production, our gross revenues from oil and gas sales would change approximately $1.2 million for each $0.10 change in gas prices and $1.2 million for each $1.00 change in oil prices.

 

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 September 30, 2005 are summarized below:

 

     Natural gas

   Crude oil

Period   

Total

MMcf

  

Weighted average
fixed price to be

received

  

Total

MBbl

  

Weighted average
fixed price to be

received


10/2005 to 12/2005

   3,490    $ 7.55    315    $ 38.26

01/2006 to 03/2006

   3,330      8.30    282      38.06

04/2006 to 06/2006

   3,180      6.79    273      38.74

07/2006 to 09/2006

   3,090      6.78    267      41.36

10/2006 to 12/2006

   2,670      7.76    255      44.46

01/2007 to 03/2007

   2,460      8.49    222      45.86

04/2007 to 06/2007

   2,460      6.94    216      45.68

07/2007 to 09/2007

   2,460      6.94    174      48.75

10/2007 to 12/2007

   1,260      8.56    108      53.86

01/2008 to 03/2008

   810      9.99    39      63.75

04/2008 to 06/2008

   720      8.05    39      63.40

07/2008 to 09/2008

   360      8.03    4      61.66

 

Interest rates.    All of the outstanding borrowings under the Credit Agreement as of September 30, 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, 2004, approximately 87% 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. The following discussion excludes the effects of the CEI Bristol acquisition in September 2005 except where specifically stated.

 

As of December 31, 2004, on a pro forma basis we had estimated proved reserves of 606 Bcfe and a PV-10 value of $1,010.3 million. For the nine months ended September 30, 2005, on a pro forma basis, our average daily production was 80.9 MMcfe, a 14% increase over the comparable period in 2004. As of December 31, 2004, on a pro forma basis, our estimated reserve life would have been 22.7 years. On a pro forma basis, our revenues and Adjusted EBITDA for the year ended December 31, 2004 were $125.6 million and $82.7 million, respectively. For the nine months ended September 30, 2005, on a pro forma basis, our revenue and Adjusted EBITDA were $107.9 million and $79.0 million, respectively. We set forth our definition of PV-10 value (a non-GAAP measure) and a reconciliation of a 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 from continuing operations before accounting change to Adjusted EBITDA, beginning on page 14.

 

For the period from 2001 to 2004, our proved reserves and production have grown at a compounded annual growth rate of 41% and 20%, 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 significant inventory of drillable prospects and an active drilling program. We have identified over 700 proved developmental drilling locations, as well as over 2,200 additional potential drilling locations, which combined represent over 15 years of drilling opportunities based on our current 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 one proprietary shoot and are currently permitting on two additional proprietary 3-D shoots.

 

Our capital expenditures for oil and gas properties for the nine months ended September 30, 2005 were $104.2 million (excluding the acquisition of the limited partner interest in CEI Bristol

 

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Acquisition, L.P.), representing a 51% increase over the comparable period in 2004. Our capital expenditure budget for oil and gas properties for 2006 is $200 million. We have budgeted approximately 58% of our 2006 capital expenditures on development activities (drilling—41%, enhancements—10% and tertiary recovery—7%), 37% for acquisitions and 5% for exploration activities. 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, which are characterized as lower risk and have relatively low finding and development costs. We also have a significant inventory of carbon dioxide (CO2) tertiary recovery projects in the Mid-Continent and Permian Basin, and we have budgeted increased capital expenditures for these projects going forward.

 

 

Business strengths

 

Consistent track record of low-cost reserve additions and production growth.    From 2001 to 2004, we have grown reserves and production by a compounded annual growth rate of 41% and 20%, 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 610%, 468% and 1,219% of our production in 2002, 2003 and 2004, respectively, at a fully developed average F&D cost of $1.31 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 2002, 2003 and 2004, our capital expenditures for acquisitions were $17.7 million, $19.9 million and $30.5 million, respectively. These acquisition capital expenditures represented approximately 43%, 35% and 32%, 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, as of September 30, 2005, an estimated 115 Bcfe of proved reserves. Not including the acquisition of CEI Bristol, we spent $37.3 million on acquisitions during the first nine months of 2005, representing approximately 36% 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, 2004, we had an inventory of over 700 proved developmental drilling locations and over 2,200 additional potential drilling locations. Not including the CEI Bristol acquisition, we spent $52.1 million on development and exploration drilling for the first nine months of 2005. For 2006, we have budgeted $92 million to drill more than 55 operated wells and to participate in more than 130 wells operated by others. We

 

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believe these are low-to-medium risk opportunities with anticipated payouts in under 3 years. Additionally, we utilize 3-D seismic data to help identify additional reserve targets in, around and under older producing fields.

 

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 a second tertiary flood unit in the Oklahoma panhandle. We have subsequently acquired other related assets, and our proved reserves at December 31, 2004 include 16 projects that will utilize CO2 tertiary recovery methods. In 2004, we added 111.2 Bcfe of CO2 tertiary reserves to our proved undeveloped reserve category. The 16 CO2 tertiary recovery projects included in our proved reserves accounted for approximately 26% of our December 31, 2004 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 33 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 21 years, serving as President of Kitscoty Oil LLC and previously as our Chief Financial Officer. Mark Fischer and Charles Fischer are brothers. Individuals in our 24-person management team have an average of over 24 years of experience each 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 $82 million, or 41% 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 have spent

 

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approximately $37.3 million on acquisitions through September 30, 2005. Our 2006 acquisition capital budget is $73 million, or 37% of our total capital expenditure budget.

 

Apply technical expertise to enhance mature properties.    Once we acquire a property and become its 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 14 field offices throughout Oklahoma and Texas. 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, 2004, we had an inventory of 221 developed enhancement projects requiring total estimated capital expenditures of $9 million.

 

Expand CO2 enhanced oil recovery activities.    We have accumulated interests in 45 fields in Oklahoma and Texas that meet the criteria for CO2 tertiary recovery operations and are expanding our CO2 pipeline system to initiate CO2 injection in a number of these fields. Four of our 16 CO2 projects in our proved reserves are scheduled to initiate CO2 injection in 2006. We have a 100% ownership interest in 86 miles of CO2 pipeline and control a 50% or larger ownership interest in an additional 160 miles of CO2 pipeline. The planned construction of 88 miles of CO2 pipeline will facilitate CO2 injection in these new projects. We have budgeted $14 million in 2006 towards these projects. To support our existing CO2 tertiary oil recovery projects, we currently inject approximately 37 MMcf per day of CO2.

 

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 approximately 5% of our 2006 capital expenditures on exploratory drilling.

 

Control operations and costs.    We generally 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. Operations are crucial to the implementation of our programs and, accordingly, we are willing to take additional measures to become the operator. As of December 31, 2004, we operated properties comprising approximately 84% 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. Excluding PDP production attributable to the CEI Bristol acquisition, as of September 30, 2005, we had hedges in place for approximately 77%, 55% and 5% of our estimated PDP gas production for 2006, 2007 and 2008, respectively. We also had hedges in place for approximately 78%, 61% and 6% of our estimated PDP oil production for 2006, 2007 and 2008, respectively.

 

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Properties

 

The following tables present proved reserves and PV-10 value as of December 31, 2004, and average daily production for the year ended December 31, 2004 and nine months ended September 30, 2005 by major areas of operation for Chaparral and CEI Bristol.

 

    Proved reserves as of December 31, 2004

  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,
2004
  Nine months
ended
September 30,
2005

Chaparral

                             

Mid-Continent

  31,015   193,916   380,006   73.7%   $ 586.7   40.6   46.6

Permian Basin

  5,532   37,656   70,848   13.7%     129.0   6.2   8.1

East Texas

  1,030   20,095   26,275   5.1%     49.5   2.1   5.4

North Texas

  2,810   386   17,246   3.3%     40.4   1.6   2.0

Rocky Mountains

  1,241   3,206   10,652   2.1%     19.5   0.6   1.6

Gulf Coast

  386   7,392   9,708   1.9%     18.2   1.0   1.5

Other

  13   969   1,047   0.2%     1.8    
   

Chaparral total

  42,027   263,620   515,782   100.0%   $ 845.1   52.1   65.2
   

CEI Bristol

                             

Mid-Continent

  913   39,165   44,643   49.6%   $ 79.0   14.9   9.8

Permian Basin

  974   19,948   25,792   28.6%     48.6   2.1   2.1

East Texas

  102   8,567   9,179   10.2%     16.9   0.6   1.3

North Texas

  357   302   2,444   2.7%     4.0   0.4   0.5

Rocky Mountains

  176   1,414   2,470   2.7%     3.6   0.8   0.6

Gulf Coast

  318   3,643   5,551   6.2%     13.1   1.6   1.4
   

CEI Bristol total

  2,840   73,039   90,079   100.0%   $ 165.2   20.4   15.7
   

Pro forma total

  44,867   336,659   605,861       $ 1,010.3   72.5   80.9

 

Our properties have relatively long reserve lives and highly predictable production profiles. Based on our December 31, 2004 proved reserves and 2004 production, our reserve life was 27 years. As of December 31, 2004 on a pro forma basis, our estimated reserve life would have been 22.7 years. In general, these properties have extensive production histories and production enhancement opportunities. While our portfolio of oil and gas properties is geographically diversified, 90% of our 2004 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, 2004 we owned interests in 4,772 gross (1,161 net) producing wells and we operated wells representing 84% 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.

 

The following summaries do not include the effects of the CEI Bristol acquisition.

 

 

Mid-Continent

 

The Mid-Continent Area is the larger of our two core areas and, as of December 31, 2004, accounted for 73.7% of our proved reserves and 69.4% of our PV-10 value. On a pro forma basis at December 31, 2004, the Mid-Continent Area accounted for 70.1% of our proved reserves and

 

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65.9% of our PV-10 value. We own an interest in 3,114 wells in the Mid-Continent, of which we operate 1,047. Our three largest properties and 13 of our 20 largest properties, in terms of PV-10 value, are located in this area. During the nine months ended September 30, 2005, our net average daily production in the Mid-Continent Area was approximately 46.6 MMcfe per day, or 71.5% of our total net average daily production. This area is characterized by stable, long-life shallow decline reserves. We produce and drill in most of the basins in the region and have significant holdings and activity in the areas described below.

 

Camrick area—Beaver and Texas Counties, Oklahoma.    The Camrick area represents 2.2% of our proved reserves and 3.3% of the PV-10 value of our proved reserves at December 31, 2004. 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 16.4 MMBbl of primary reserves and 13.4 MMBbl of secondary reserves. There are approximately 30 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 production in the Camrick Unit from approximately 100 Bbls per day in 2001 to approximately 825 Bbls per day as of August 2005. We currently plan to expand CO2 injection operations across all of the units.

 

Southwest Antioch Gibson Sand Unit (SWAGSU)—Garvin County, Oklahoma.    SWAGSU represents 2.6% of our proved reserves and 2.8% of the PV-10 value of our proved reserves at December 31, 2004. 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 21 active producing wells in this unit. During the last twelve months, we have drilled three wells and are scheduled to drill one additional well and re-enter three additional abandoned wells.

 

Cleveland Sand Play—Ellis County, Oklahoma.    We control approximately 5,190 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 four wells in 2005 and have plans to drill five wells in 2006. Horizontal drilling technology has been employed in two recently drilled wells. Recovery is expected to be 1.4 Bcfe per horizontal well. 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 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

 

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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 89 active producing wells in this unit.

 

Harmon County 3-D Shoot—Harmon County, Oklahoma.    Chaparral has leased in excess of 29,000 acres in Harmon County, Oklahoma and will begin a proprietary 3-D seismic shoot on this acreage in December 2005. Based on very limited well control, potential pay horizons exist in the Mississippi Reef, Bend Conglomerate and Canyon intervals. Drilling is expected to start in mid-2006 with the potential to drill 150 wells.

 

CO2 Enhanced Recovery Operations—Various counties, Oklahoma and Texas.    We have accumulated 45 fields in Oklahoma and Texas that meet our criteria for CO2 tertiary recovery operations. Four of these fields are scheduled to initiate CO2 injection within the next year. We have a 100% ownership and operate 86 miles of CO2 pipeline. We also control a 50% or larger ownership interest in an additional 160 miles of pipeline. To facilitate the expansion of our CO2 enhanced oil recovery program to the eight fields currently budgeted in 2006 and 2007, we will be extending our CO2 pipeline infrastructure by 88 miles. We are negotiating 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 and to in excess of 75 MMcf by July 2007. 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 9.0 billion Bbls of oil 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, 2004, accounted for 13.7% of our proved reserves and 15.3% of our PV-10 value. On a pro forma basis at December 31, 2004, the Permian Basin Area accounted for 16.0% of our proved reserves and 17.6% of our PV-10 value. We own an interest in 450 properties in the Permian Basin, of which we operate 246. Six of our 20 largest properties, in terms of PV-10 value, are located in this area. During the nine months ended September 30, 2005, our net average daily production in the Permian Basin Area was approximately 8.1 MMcfe per day, or 12.4% of our total net average daily production. 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.    The 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 nine months ended September 30, 2005, we have drilled nine wells in this play. We have identified 31 potential drilling locations in this play. We have recently acquired through a farmout from Chevron approximately 12,880 acres that are adjacent to the existing Tunstill field play.

 

Haley Area Strawn and Morrow Play—Loving County, Texas.    The Haley Area Strawn and Morrow Play encompasses 3,200 acres. We own interests in and operate five producing wells in

 

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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, completing a recently drilled well and have three more scheduled for 2006. We anticipate drilling costs for these proposed wells of $8.5 million per well. Development is eventually expected to be on a 160 acre pattern.

 

 

East Texas

 

East Texas is one of our four growth areas and, as of December 31, 2004, accounted for 5.1% of our proved reserves and 5.9% of our PV-10 value. On a pro forma basis at December 31, 2004, East Texas accounted for 5.9% of our proved reserves and 6.6% of our PV-10 value. We own an interest in 170 properties in East Texas, of which we operate 138. 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 have scheduled an Edwards test in this field. We are currently leasing on an additional 1,000 acres adjacent to this field and anticipate two more Edwards wells could be drilled on this acreage.

 

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 the last 12 months we have drilled two development wells 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, 2004, accounted for 3.3% of our proved reserves and 4.8% of our PV-10 value. On a pro forma basis at December 31, 2004, North Texas accounted for 3.2% of our proved reserves and 4.4% of our PV-10 value. We own an interest in 107 properties in North Texas, of which we operate 74. 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.

 

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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 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 June 2004, we have drilled six wells in the north half of the section and nine wells in the south half with initial production from 15 to 130 Bbls of oil per day. In addition, we have identified 28 PUD locations and 43 probable 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, Mississippian Reef at 6,300 feet, Viola at 6,500 feet and the Ellenberger at 6,800 feet. We have approximately 20 active producing wells in this area. We have drilled five wells and have one additional well drilling. We may drill up to 36 additional wells if this initial drilling effort proves successful.

 

 

Rocky Mountains

 

The Rocky Mountains is our third growth area and, as of December 31, 2004, accounted for 2.1% of our proved reserves and 2.3% of our PV-10 value. On a pro forma basis at December 31, 2004, the Rocky Mountains accounted for 2.2% of our proved reserves and 2.3% of our PV-10 value. We own 97 properties in the Rocky Mountains Area, of which we operate 36. 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 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 August 2005, the well was producing 313 Bbls of oil per day and 190 Mcf of natural gas per day.

 

We recently leased approximately 8,000 acres in the immediate area of the McVay #2-34H and have five wells scheduled to be drilled in 2006.

 

 

Gulf Coast

 

Our fourth growth area is the Gulf Coast and, as of December 31, 2004, accounted for 1.9% of our proved reserves and 2.2% of our PV-10 value. On a pro forma basis at December 31, 2004, the Gulf Coast Area accounted for 2.5% of our proved reserves and 3.1% of our PV-10 value. We own 195 properties in the Gulf Coast, of which we operate 99. 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.

 

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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 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, 2004. 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. (62% of PV-10 value) and by Lee Keeling & Associates, Inc. for our CO2 enhanced oil recovery proved undeveloped reserves (13% of PV-10 value). Our internal engineering staff has prepared a report of estimated proved reserves on our remaining smaller value properties (25% of PV-10 value).

 

     Net proved reserves

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

Developed—producing

   157,724    15,346    249,800    $ 459,115

Developed—non-producing

   28,820    2,012    40,892      76,204

Undeveloped

   77,076    24,669    225,090      309,745
    

Total proved

   263,620    42,027    515,782    $ 845,064

 

The reserve life as of December 31 2002, 2003 and 2004 was 19.6, 19.9, and 27.2 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 present value of those revenues and the prices used in projecting them over the past three years:

 

(Dollars in thousands, except prices)    2002    2003    2004

Future net revenue

   $ 658,710    $ 1,053,624    $ 1,903,785

PV-10 value

     320,648      488,305      845,064

Standardized measure of discounted future net cash flows

     218,266      325,250      556,526

Oil price (per Bbl)

   $ 31.23    $ 32.52    $ 43.51

Natural gas price (per Mcf)

   $ 4.59    $ 6.19    $ 6.35

 

There are numerous uncertainties inherent in estimating quantities of proved reserves, in projecting future rates of production and in the timing of development expenditures, including many factors beyond our control. The reserve data represent only estimates. The quality of the estimates is a function of the quality of the available data and of engineering and geological

 

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interpretations and judgments. Estimates are subject to revision based on a number of factors, including reservoir performance, prices, economic conditions and governmental regulations. Consequently, material revisions to existing reserve estimates occur from time to time.

 

The following table sets forth information at December 31, 2004 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

   2,406    568

Natural gas

   2,366    593
    

Total

   4,772    1,161

 

The following table details our gross and net interest in developed and undeveloped acreage at December 31, 2004.

 

     Acres

     Gross    Net

Developed

   980,909    343,702

Undeveloped

   28,392    18,154
    

Total

   1,009,301    361,856

 

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.

 

     2002

   2003

   2004

     Gross    Net    Gross    Net    Gross    Net

Development wells

                             

Productive

   74.0    12.2    87.0    23.9    127.0    37.1

Dry

   6.0    2.1    2.0    0.7    5.0    2.8

Exploratory wells

                             

Productive

   2.0    0.5    2.0    1.4    1.0    0.1

Dry

   4.0    2.9            

Total wells

                             

Productive

   76.0    12.7    89.0    25.3    128.0    37.2

Dry

   10.0    5.0    2.0    0.7    5.0    2.8
    

Total

   86.0    17.7    91.0    26.0    133.0    40.0
    

Percent productive

   88%    72%    98%    97%    96%    93%

 

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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,

     2002    2003    2004

Production:

                    

Oil (MBbl)

     791      924      1,173

Natural gas (MMcf)

     7,952      9,762      11,923

Combined (MMcfe)

     12,698      15,306      18,961

Average daily production:

                    

Oil (Bbls)

     2,167      2,532      3,214

Natural gas (Mcf)

     21,786      26,745      32,666

Combined (Mcfe)

     34,788      41,937      51,950

Average prices (before effect of hedges):

                    

Oil (per Bbl)

   $ 24.73    $ 29.92    $ 40.53

Natural gas (per Mcf)

     2.90      4.77      5.54

Combined (per Mcfe)

     3.36      4.85      5.99

Average costs per Mcfe:

                    

Lease operating

   $ 1.14    $ 1.22    $ 1.34

Production tax and gas handling charges

   $ 0.29    $ 0.37    $ 0.52

Depreciation, depletion, and amortization

   $ 0.62    $ 0.68    $ 0.96

General and administrative

   $ 0.32    $ 0.32    $ 0.32

 

 

Competition

 

There are many oil and natural gas companies in the United States and competition is strong among companies involved in the exploration for and production of oil and natural gas. We expect to encounter competition at every phase of our business. We will compete with entities having financial resources and staff substantially larger than ours.

 

There will be competition among operators for acreage, drilling equipment, goods and drilling crews. Such competition may affect our ability to acquire leases suitable for development and to expeditiously develop such leases once they are acquired.

 

The national supply of natural gas is widely diversified. As a result of deregulation of the natural gas industry by Congress and the Federal Energy Regulatory Commission, or FERC, in 1978, competitive forces generally determine natural gas prices. Prices of crude oil, condensate and natural gas liquids are not currently regulated and are also generally determined by competitive forces.

 

 

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;

 

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  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 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;

 

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  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 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, 2004, 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 2005 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.

 

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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 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

 

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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 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.

 

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

 

Drilling and production

 

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

 

  the location of wells;
  the method of drilling and casing wells;
  the rates of production or “allowables”;
  the surface use and restoration of properties upon which wells are drilled;
  the plugging and abandoning of wells; and
  notice to surface owners and other third parties.

 

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

 

Natural gas sales transportation

 

Historically, federal legislation and regulatory controls have affected the price of the natural gas we produce and the manner in which we market our production. 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

 

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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 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 upon the Company.

 

 

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

 

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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 September 30, 2005, we had 319 full-time employees, including 8 geologists and geophysicists, 21 production and reservoir engineers and 8 land professionals. Of these, 192 work in our Oklahoma City office and 127 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

Robert W. Kelly II

   47    Senior Vice President and General Counsel

Larry E. Gateley

   56    Senior Vice President—Reservoir Engineering

James M. Miller

   43    Senior Vice President—Production Engineering and Operations

 

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 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).

 

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Joseph O. Evans, Chief Financial Officer & Executive Vice President, joined Chaparral in July of 2005 as Chief Financial Officer. From 1998 to June 2005, Mr. Evans was a consultant and practiced public accounting with the firm of Evans Gaither & Assoc. From 1997 to 1998, he served as Senior Vice President and Financial Advisor, Energy Lending, for First National Bank of Commerce in New Orleans. From 1976 until 1997, Mr. Evans worked in the Oklahoma practice of Deloitte & Touche where he became an Audit Partner. While at Deloitte he was a member of the energy industry group and was responsible for services on numerous 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 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.

 

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Board structure and compensation of directors

 

Upon completion of the offering, our board of directors will consist of three members. Our board has determined that Mr.              is independent under the applicable rules of the                     . 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. Following the phase-in period, our board of directors will consist of seven members, three of which will be independent.

 

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 $            . Each non-employee director also will receive a fee of $             for each board meeting attended and $             for each committee meeting attended. In addition, the chairman of the audit committee will receive an annual fee of $            , the chairman of the compensation committee will receive an annual fee of $             and the chairman of the nominating and governance committee will receive an annual fee of $            .

 

 

Board committees

 

Our board of directors plans to have an audit committee, a nominating and governance committee and a compensation committee following this offering. Following the phase-in period permitted under the                      rules, we intend that all the members of our nominating and governance committee and of our compensation committee will be independent under applicable provisions of those rules. In addition, we intend that the members of our audit committee will be independent under applicable provisions of the Securities Exchange Act of 1934 and the                      rules following the phase-in period.

 

Audit Committee.    The audit committee, which is expected to consist of Messrs.              (chair),              and             , 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.

 

Nominating and Governance Committee.    The nominating and governance committee, which is expected to consist of Messrs.                  (chair),              and             , 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

 

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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 is expected to consist of Messrs.