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As filed with the Securities and Exchange Commission on November 15, 2005
Registration No. 333-128750
 
 
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
 
AMENDMENT NO. 1 TO
FORM S-1
REGISTRATION STATEMENT
UNDER
THE SECURITIES ACT OF 1933
 
Complete Production Services, Inc.
(Exact name of registrant as specified in its charter)
         
Delaware   1389   72-1503959
(State or other jurisdiction of
incorporation or organization)
  (Primary Standard Industrial Classification
Code Number)
  (I.R.S. Employer
Identification No.)
 
14450 JFK Blvd., Suite 400
Houston, Texas 77032
(281) 372-2300
(Address, including zip code, and telephone number, including area code, of registrant’s principal executive offices)
 
Joseph C. Winkler
Chief Executive Officer and President
14450 JFK Blvd., Suite 400
Houston, Texas 77032
(281) 372-2300
(Name, address, including zip code, and telephone number, including area code, of agent for service)
Copies to:
     
Vinson & Elkins L.L.P.
  Baker Botts L.L.P.
First City Tower, Suite 2300
  One Shell Plaza, 910 Louisiana Street
Houston, Texas 77002
  Houston, Texas 77002
(713) 758-2222
  (713) 229-1234
Attn: Scott N. Wulfe
  Attn: R. Joel Swanson
Attn: Nicole E. Clark
  Attn: Felix P. Phillips
      Approximate date of commencement of proposed sale to the public: As soon as practicable after this Registration Statement becomes effective.
      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, please check the following box.     o
      If this form is filed to register additional securities for an offering pursuant to Rule 462(b) under the Securities Act, please check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering.     o
      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.     o
      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.     o
      If delivery of the prospectus is expected to be made pursuant to Rule 434, please check the following box.     o
 
CALCULATION OF REGISTRATION FEE
             
             
             
Title of Each Class of Securities     Proposed Maximum     Amount of
to be Registered     Aggregate Offering Price(1)(2)     Registration Fee
             
Common Stock, par value $0.01
    $345,000,000     $40,607(3)
             
             
(1)  Includes common stock issuable upon the exercise of the underwriters’ over-allotment option.
(2)  Estimated solely for the purpose of calculating the registration fee in accordance with Rule 457(o) under the Securities Act of 1933.
(3)  Subsequent to the date of the initial filing of the registration statement, we increased the Proposed Maximum Aggregate Offering Price from $300,000,000 to $345,000,000. A registration fee of $35,310 relating to the original Proposed Maximum Aggregate Offering Price was paid at the time of the initial filing of the registration statement. The balance of the registration fee will be paid on the date of the filing of this Amendment No. 1.
 
      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 prospectus is not complete and may be changed. We may not sell these securities until the registration statement filed with the Securities and Exchange Commission is effective. This prospectus is not an offer to sell these securities and it is not soliciting an offer to buy these securities in any state where the offer or sale is not permitted.
SUBJECT TO COMPLETION, DATED NOVEMBER 15, 2005
                             Shares
(COMPLETE PRODUCTION SERVICES LOGO)
Complete Production Services, Inc.
Common Stock
 
        We are selling            shares of our common stock and the selling stockholders are selling            shares of our common stock. Prior to this offering, there has been no public market for our common stock. The initial public offering price of our common stock is expected to be between $          and $           per share. We have applied to list our common stock on the New York Stock Exchange under the symbol “                    .” We will not receive any of the proceeds from the shares of common stock sold by the selling stockholders.
      The underwriters have an option to purchase a maximum of                      additional shares from the selling stockholders to cover over-allotments of shares.
      Investing in our common stock involves risks. See “Risk Factors” beginning on page 10.
                                 
            Proceeds to    
        Underwriting   Complete   Proceeds to
    Price to   Discounts and   Production   Selling
    Public   Commissions   Services   Stockholders
                 
Per Share
     $          $          $          $    
Total
  $       $       $       $    
      Delivery of the shares of common stock will be made on or about                     , 2005.
      Neither the Securities and Exchange Commission nor any state securities commission has approved or disapproved of these securities or determined if this prospectus is truthful or complete. Any representation to the contrary is a criminal offense.
Credit Suisse First Boston UBS Investment Bank
Banc of America Securities LLC
  Jefferies
  Johnson Rice & Company L.L.C.
  Raymond James
  Simmons & Company
  International
  Pickering Energy Partners
The date of this prospectus is                     , 2005.


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(Operating Segments)


 
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    F-1  
 Form of Indemnification Agreement
 Credit Agreement
 2001 Stock Incentive Plan - Integrated Production
 2003 Stock Incentive Plan
 First Amendment to 2003 Stock Incentive Plan
 Second Amendment to 2003 Stock Incentive Plan
 2004 Stock Incentive Plan - I.E. Miller Services, Inc.
 Amended Integrated Production Services and Parchman Energy Group, Inc. Stock Incentive Plan
 Strategic Customer Relationship Agreement
 Form of Restricted Stock Grant Agreement (Employee)
 Form of Restricted Stock Agreement (Non-Employee Director)
 Consent of Grant Thorton LLP
 Consent of KPMG LLP
 
      You should rely only on the information contained in this prospectus or to which we have referred you. We have not authorized anyone to provide you with information that is different. This document may only be used where it is legal to sell these securities. The information in this document may only be accurate on the date of this document.
Dealer Prospectus Delivery Obligation
      Until                     , 2005 (25 days after the commencement of the offering), all dealers that effect transactions in these securities, whether or not participating in this offering, may be required to deliver a prospectus. This is in addition to the dealers’ obligation to deliver a prospectus when acting as an underwriter and with respect to unsold allotments or subscriptions.
Cautionary Note Regarding Industry and Market Data
      This prospectus includes industry data and forecasts that we obtained from publicly available information, industry publications and surveys. Our forecasts are based upon management’s understanding of industry conditions. We believe that the information included in this prospectus from industry surveys, publications and forecasts is reliable.
Non-GAAP Financial Measures
      The body of accounting principles generally accepted in the United States is commonly referred to as “GAAP.” A non-GAAP financial measure is generally defined by the Securities and Exchange Commission, or SEC, as one that purports to measure historical or future financial performance, financial position or cash flows, but excludes or includes amounts that would not be so adjusted in the most comparable GAAP measures. In this prospectus, we disclose EBITDA, a non-GAAP financial measure. EBITDA is calculated as net income before interest expense, taxes, depreciation and amortization and minority interest. EBITDA is not a substitute for the GAAP measures of earnings and cash flow. EBITDA is included in this prospectus because our management considers it an important supplemental measure of our performance and believes that it is frequently used by securities analysts, investors and other interested parties in the evaluation of companies in our industry, some of which present EBITDA when reporting their results.

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PROSPECTUS SUMMARY
      This prospectus summary highlights information contained in this prospectus. Before investing in our common stock, you should read this entire prospectus carefully, including the section entitled “Risk Factors” and our financial statements and related notes, for a more detailed description of our business and this offering. In this prospectus, “Complete,” “company,” “we,” “us” and “our” refer to Complete Production Services, Inc. and its subsidiaries, except as otherwise indicated. Please read “Glossary of Selected Industry Terms” included in this prospectus for definitions of certain terms that are commonly used in the oilfield services industry. Unless otherwise indicated, all references to “dollars” and “$” in this prospectus are to, and amounts are presented in, U.S. dollars. Unless the context indicates otherwise, all information in this prospectus assumes that the underwriters do not exercise their over-allotment option.
Our Company
      We provide specialized services and products focused on helping oil and gas companies develop hydrocarbon reserves, reduce costs and enhance production. We focus on basins within North America that we believe have attractive long-term potential for growth, and we deliver targeted, value-added services and products required by our customers within each specific basin. We believe our range of services and products positions us to meet many needs of our customers at the wellsite, from drilling and completion through production and eventual abandonment. We manage our operations from regional field service facilities located throughout the U.S. Rocky Mountain region, Texas, Oklahoma, Louisiana, western Canada and Mexico.
      We seek to differentiate ourselves from our competitors through our local leadership, basin-level expertise and the innovative application of proprietary and other technologies. We deliver solutions to our customers that we believe lower their costs and increase their production in a safe and environmentally friendly manner.
      Our business is comprised of three segments:
      Completion and Production Services. Through our completion and production services segment, we establish, maintain and enhance the flow of oil and gas throughout the life of a well. This segment is divided into the following primary service lines:
  •  Intervention Services. Well intervention requires the use of specialized equipment to perform an array of wellbore services. Our fleet of intervention service equipment includes coiled tubing units, pressure pumping units, nitrogen units, well service rigs, snubbing units and a variety of support equipment. Our intervention services provide customers with innovative solutions to increase production of oil and gas.
 
  •  Downhole and Wellsite Services. Our downhole and wellsite services include electric-line, slickline, production optimization, production testing, rental and fishing services. We also offer several proprietary services and products that we believe create significant value for our customers.
 
  •  Fluid Handling. We provide a variety of services to help our customers obtain, move, store and dispose of fluids that are involved in the development and production of their reservoirs. Through our fleet of specialized trucks, frac tanks and other assets, we provide fluid transportation, heating, pumping and disposal services for our customers.
      Drilling Services. Through our drilling services segment, we provide services and equipment that initiate or stimulate oil and gas production by providing land drilling, specialized rig logistics and site preparation. Through this segment, we also provide pressure control, drill string, pipe handling and other equipment. Our drilling rigs currently operate exclusively in the Barnett Shale region of north Texas.
      Product Sales. Through our product sales segment, we provide a variety of equipment used by oil and gas companies throughout the lifecycle of their wells. Our current product offering includes completion, flow control and artificial lift equipment as well as tubular goods.

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      For further information on our company, please read “Business – Our Company.”
Our Industry
      Our business depends on the level of exploration, development and production expenditures made by our customers. These expenditures are driven by the current and expected future prices for oil and gas, and the perceived stability and sustainability of those prices. Our business is primarily driven by natural gas drilling activity in North America. We believe the following two principal economic factors will positively affect our industry in the coming years:
  •  Higher demand for natural gas in North America. We believe that natural gas will be in high demand in North America over the next several years because of the growing popularity of this clean-burning fuel.
 
  •  Constrained North American gas supply. Although the demand for natural gas is projected to increase, supply is likely to be constrained as North American natural gas basins are becoming more mature and experiencing increased decline rates.
      Higher demand for natural gas and a constrained gas supply have resulted in higher prices and increased drilling activity. The increase in prices and drilling activity are driving three additional trends that we believe will benefit us:
        Trend toward drilling and developing unconventional North American natural gas resources. Due to the maturity of conventional North American oil and gas reservoirs and their accelerating production decline rates, unconventional oil and gas resources will comprise an increasing proportion of future North American oil and gas production. Unconventional resources include tight sands, shales and coalbed methane. These resources require more wells to be drilled and maintained, frequently on tighter acreage spacing. The appropriate technology to recover unconventional gas resources varies from region to region; therefore, knowledge of local conditions and operating procedures, and selection of the right technologies is key to providing customers with appropriate solutions.
 
        The advent of the resource play. A “resource play” is a term used to describe an accumulation of hydrocarbons known to exist over a large area which, when compared to a conventional play, has lower commercial development risks and a lower average decline rate. Once identified, resource plays have the potential to make a material impact because of their size and low decline rates. The application of appropriate technology and program execution are important to obtain value from resource plays.
 
        Increasingly complex technologies. Increasing prices and the development of unconventional oil and gas resources are driving the need for complex, new technologies to help increase recovery rates, lower production costs and accelerate field development. We believe that the increasing complexity of technology used in the oil and gas development process coupled with limited engineering resources will require production companies to increase their reliance on service companies to assist them in developing and applying these technologies.
      While we believe that these trends will benefit us, our markets may be adversely affected by industry conditions that are largely beyond our control. Any prolonged substantial reduction in oil and gas prices would likely affect oil and gas drilling and production levels and therefore affect demand for the services we provide. For more information on this and other risks to our business and our industry, please read “Risk Factors – Risks Related to Our Business and Our Industry.”
      For further information on our industry, please read “Business – Our Industry.”
Our Business Strategy
      Our goal is to build the leading oilfield services company focused on the completion and production phases in the life of an oil and gas well. We intend to capitalize on the emerging trends in the North

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American marketplace through the execution of a growth strategy that consists of the following components:
      Expand and capitalize on local leadership and basin-level expertise. A key component of our strategy is to build upon our base of strong local leadership and basin-level expertise. We have a significant presence in most of the key onshore continental U.S. and Canadian gas plays we believe have the potential for long-term growth. We intend to leverage our existing market presence, strong local leadership, expertise and customer relationships to expand our business within these gas plays. We also intend to replicate this approach in new regions by building and acquiring new businesses that have strong regional management with extensive local knowledge.
      Develop and deploy technical and operational solutions. We are focused on developing and deploying technical services, equipment and expertise that lower our customer’s costs.
      Capitalize on organic and acquisition-related growth opportunities. We believe there are numerous opportunities to sell new services and products to customers in our current geographic areas and to sell our current services and products to customers in new geographic areas. We have a proven track record of organic growth and successful acquisitions, and we intend to continue using capital investments and acquisitions to strategically expand our business.
      Focus on execution and performance. We have established and intend to develop further a culture of performance and accountability. Senior management spends a significant portion of its time ensuring that our customers receive the highest quality of service.
      Successful execution of our business strategy depends on our ability to retain key personnel and to continue to employ a sufficient number of skilled and qualified workers. The demand for skilled workers is high, and the supply is limited. If we are not able to retain key personnel and continue to employ a sufficient number of skilled and qualified workers, our business could be harmed. For more information on this and other risks to our business and our industry, please read “Risk Factors – Risks Related to Our Business and Our Industry.”
      For further information on our business strategy, please read “Business – Our Business Strategy.”
Our Competitive Strengths
      We believe that we are well positioned to execute our strategy and capitalize on opportunities in the North American oil and gas market based on the following competitive strengths:
      Strong local leadership and basin-level expertise. We operate our business with a focus on each regional basin complemented by our local reputations. We believe our local and regional businesses, some of which have been operating for more than 50 years, provide us with a significant advantage over many of our competitors. Our managers, sales engineers and field operators have extensive expertise in their local geological basins, understand the regional challenges our customers face and have long-term relationships with many customers. We strive to leverage this basin-level expertise to establish ourselves as the preferred provider of our services in the basins in which we operate.
      Significant presence in major North American basins. We operate in major oil and gas producing regions of the U.S. Rocky Mountains, Texas, Louisiana and Oklahoma, western Canada and Mexico, with concentrations in key “resource play” and unconventional basins. Resource plays are expected to become increasingly important in future North American oil and gas production as more conventional resources enter later stages of the exploration cycle. We believe we have an excellent position in highly active markets such as the Barnett Shale region of north Texas. Accelerating production and driving down development and production costs are key goals for oil and gas operators in these areas, resulting in strong demand for our services and products. In addition, our strong presence in these regions allows us to build solid customer relationships and take advantage of cross-selling opportunities.

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      Focus on complementary production and field development services. Our breadth of service and product offerings well positions us relative to our competitors. Our complementary services encompass the entire lifecycle of a well from drilling and completion, through production and eventual abandonment. This suite of services and products gives us the opportunity to cross-sell to our customer base and throughout our geographic regions. Leveraging our strong local leadership and basin-level expertise, we are able to offer expanded services and products to existing customers or current services and products to new customers.
      Innovative approach to technical and operational solutions. We develop and deploy services and products that enable our customers to increase production rates, stem production declines and reduce the costs of drilling, completion and production. The significant expertise we have developed in our areas of operation offers our customers customized operational solutions to meet their particular needs.
      Modern and active asset base. We have a modern and well-maintained fleet of coiled tubing units, pressure pumping equipment, wireline units, well service rigs, snubbing units, fluid transports, frac tanks and other specialized equipment. We believe our ongoing investment in our equipment allows us to better serve the diverse and increasingly challenging needs of our customer base. Our fleet is active with high utilization. We believe our future expenditures will be used to capitalize on growth opportunities within the areas we currently operate and to build out new platforms obtained through targeted acquisitions.
      Experienced management team with proven track record. Each executive officer and member of our key operational management team has over 20 years of experience in the oilfield services industry. We believe that their considerable knowledge of and experience in our industry enhances our ability to operate effectively throughout industry cycles. Our management also has substantial experience in identifying, completing and integrating acquisitions.
      While we believe that these strengths differentiate us from our competitors, the markets in which we operate are highly competitive and have relatively few barriers to entry. We face competition from large national and multi-national companies that have greater resources and greater name recognition than we do as well as from several smaller companies capable of competing effectively on a regional basis. In addition, we may face substantial competition from new entrants in the future. For more information on these and other risks to our business and our industry, please read “Risk Factors – Risks Related to Our Business and Our Industry.”
      For further information on our competitive strengths, see “Business – Our Competitive Strengths.”
The Combination
      Prior to 2001, SCF Partners, a private equity firm, began to target investment opportunities in service-oriented companies in the North American natural gas market with specific focus on the production phase of the exploration and production cycle. On May 22, 2001, SCF Partners, through SCF-IV, L.P. (“SCF”), formed Saber Energy Services, Inc. (“Saber”), a new company, in connection with its acquisition of two companies primarily focused on completion and production related services in Louisiana. In July 2002, SCF became the controlling stockholder of Integrated Production Services, Ltd. a production enhancement company that, at the time, focused its operation in Canada. In September 2002, Saber acquired this company and changed its name to Integrated Production Services, Inc. (“IPS”). Subsequently, IPS began to grow organically and through several acquisitions, with the ultimate objective of creating a technical leader in the enhancement of natural gas production. In November 2003, SCF formed another production services company, Complete Energy Services, Inc. (“CES”), establishing a platform from which to grow in the Barnett Shale region of north Texas. Subsequently, through organic growth and several acquisitions, CES extended its presence to the U.S. Rocky Mountain and the Mid-Continent regions. In the summer of 2004, SCF formed I.E. Miller Services, Inc. (“IEM”), which at the time had a presence in Louisiana and Texas. During 2004, IPS and IEM independently began to execute strategic initiatives to establish a presence in both the Barnett Shale and U.S. Rocky Mountain regions.

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      On September 12, 2005, IPS, CES and IEM were combined and became Complete Production Services, Inc. in a transaction we refer to as the “Combination.” We believe that operational and financial benefits realized through the Combination establish the foundation for long-term growth for the combined company. Immediately after the Combination, SCF held approximately 70% of our outstanding common stock. For additional information regarding the Combination, see “Business – The Combination.”
How You Can Contact Us
      Our principal executive offices are located at 14450 JFK Blvd., Suite 400, Houston, Texas 77032 and our telephone number is (281) 372-2300. Our corporate website address is www.completeprodsvcs.com. The information contained in or accessible from our corporate website is not part of this prospectus.

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The Offering
Common stock offered by us                      shares.
 
Common stock offered by the selling stockholders                      shares.
 
Common stock to be outstanding after the offering                      shares.
 
Common stock owned by the selling stockholders after the offering                      shares (                     shares if the underwriters’ over-allotment option is fully exercised).
 
Use of proceeds We estimate that our net proceeds from the sale of the shares offered by us, after deducting estimated expenses and underwriting discounts and commissions, will be approximately $240 million. We plan to use $50 million of our net proceeds from this offering to repay a portion of our term loan facility, $5 million to repay seller financed notes and the remainder to pay all outstanding balances under our revolving credit facility and for general corporate purposes, which may include cash payments made in connection with future acquisitions. Affiliates of some of the underwriters of this offering are lenders under our revolving credit facility and therefore will receive a portion of the proceeds from this offering that we use to repay indebtedness. We will not receive any of the proceeds from the sale of any shares of our common stock by the selling stockholders. See “Use of Proceeds” and “Underwriting.”
 
Over-allotment option The selling stockholders have granted the underwriters a 30-day option to purchase a maximum of                     additional shares of our common stock at the initial public offering price to cover over-allotments.
 
Reserved NYSE symbol “                    ”
 
Risk factors See “Risk Factors” included in this prospectus for a discussion of factors that you should carefully consider before deciding to invest in shares of our common stock.
      The number of shares of common stock that will be outstanding after the offering includes shares of restricted common stock issued to officers and other employees under our stock incentive plans (our “stock incentive plans”) that are subject to vesting. As of November 1, 2005, there were 561,542 shares of restricted stock outstanding that remain subject to vesting.
      The number of shares of common stock that will be outstanding after the offering excludes:
  •  1,746,518 shares issuable upon the exercise of options outstanding as of November 1, 2005 under our stock incentive plans;
 
  •  an aggregate of 892,171 shares of common stock reserved and available for future issuance as of November 1, 2005 under our stock incentive plans; and
 
  •  an aggregate of up to 618,479 shares, which may be issued as contingent consideration based on certain operating results of companies previously acquired.

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Summary Consolidated Financial Data
      The following table presents summary historical consolidated financial and operating data for the periods shown. The summary consolidated financial data as of December 31, 2001 and for the period from the incorporation of IPS on May 22, 2001 through December 31, 2001, have been derived from IPS’s audited consolidated financial statements for such date and period. The consolidated financial data as of December 31, 2002 have been derived from the audited consolidated financial statements of IPS for these dates. In addition, the following summary consolidated financial data as of December 31, 2004 and 2003 and for the three-year period ended December 31, 2004 have been derived from our audited consolidated financial statements for those dates and periods. The summary financial data as of September 30, 2005 and for the nine-month periods ended September 30, 2005 and 2004 have been derived from our unaudited consolidated financial statements. The following information should be read in conjunction with “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and our financial statements and related notes included in this prospectus.
                                                     
    Period from       Nine Months Ended
    May 22 to   Year Ended December 31,   September 30,
    December 31,        
    2001   2002   2003   2004   2004   2005
                         
    (In thousands, except per share data)
Statement of Operations Data:
                                               
Revenue:
                                               
 
Completion and production services
  $ 5,855     $ 30,110     $ 65,025     $ 194,953     $ 112,611     $ 351,154  
 
Drilling services
                2,707       44,474       23,820       89,016  
 
Products sales
          10,494       35,547       81,320       58,962       85,066  
                                     
   
Total
    5,855       40,604       103,279       320,747       195,393       525,236  
                                     
Expenses:
                                               
 
Service and product expenses(1)
    3,528       28,531       73,124       216,173       132,629       336,312  
 
Selling, general and administrative
    1,563       7,764       16,591       46,077       28,844       75,535  
 
Depreciation and amortization
    402       4,187       7,648       21,616       12,366       32,902  
                                     
   
Operating income
    362       122       5,916       36,881       21,554       80,487  
Interest expense
    176       1,260       2,687       7,471       4,525       15,617  
Write-off of deferred financing fees
                                  2,844  
Taxes
    86       (477 )     1,506       10,821       6,574       23,734  
                                     
 
Income (loss) before minority interest
    100       (661 )     1,723       18,589       10,455       38,292  
Minority interest
    7       (45 )     162       934       344       380  
                                     
 
Net income (loss)
  $ 93     $ (616 )   $ 1,561     $ 17,655     $ 10,111     $ 37,912  
                                     
Earnings (loss) per share – basic
  $ 0.08     $ (0.22 )   $ 0.22     $ 0.98     $ 0.71     $ 1.39  
                                     
Earnings (loss) per share – diluted
  $ 0.08     $ (0.22 )   $ 0.21     $ 0.97     $ 0.62     $ 1.28  
                                     
Weighted average shares – basic
    1,147       2,757       7,055       18,002       14,176       27,282  
Weighted average shares – diluted
    1,147       2,757       7,272       18,270       16,186       29,640  
 
(1)  Service and product expenses is the aggregate of service expenses and product expenses.

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    Period from       Nine Months Ended
    May 22 to   Year Ended December 31,   September 30,
    December 31,        
    2001   2002   2003   2004   2004   2005
                         
    (In thousands)
Other Financial Data:
                                               
EBITDA(2)
  $ 764     $ 4,309     $ 13,564     $ 58,497     $ 33,920     $ 110,545  
Cash flows from operating activities
    1,683       (8 )     13,965       34,622       15,467       48,471  
Cash flows from financing activities
    13,320       36,279       55,281       157,630       83,404       58,566  
Cash flows from investing activities
    (12,538 )     (35,616 )     (66,214 )     (186,776 )     (99,867 )     (99,145 )
Capital expenditures:
                                               
 
Acquisitions, net of cash acquired(3)
    9,860       27,851       54,798       139,362       75,119       18,163  
 
Property, plant and equipment
    2,678       6,799       11,084       46,904       24,748       84,885  
                                         
    As of December 31,    
        As of September 30,
    2001   2002   2003   2004   2005
                     
    (In thousands)
Balance Sheet Data:
                                       
Cash and cash equivalents
  $ 2,465     $ 3,120     $ 6,094     $ 11,547     $ 19,062  
Net property, plant and equipment
    7,110       47,808       95,217       235,211       340,246  
Total assets
    18,571       110,596       206,066       515,153       769,870  
Long-term debt, excluding current portion
    3,443       22,270       50,144       169,190       452,496  
Total stockholders’ equity
    14,550       60,810       102,207       209,529       178,561  
 
(2)  EBITDA consists of net income (loss) before interest expense, taxes, depreciation and amortization and minority interest. See “Non-GAAP Financial Measures.” EBITDA is included in this prospectus because our management considers it an important supplemental measure of our performance and believes that it is frequently used by securities analysts, investors and other interested parties in the evaluation of companies in our industry, some of which present EBITDA when reporting their results. We regularly evaluate our performance as compared to other companies in our industry that have different financing and capital structures and/or tax rates by using EBITDA. In addition, we use EBITDA in evaluating acquisition targets. Management also believes that EBITDA is a useful tool for measuring our ability to meet our future debt service, capital expenditures and working capital requirements, and EBITDA is commonly used by us and our investors to measure our ability to service indebtedness. EBITDA is not a substitute for the GAAP measures of earnings or of cash flow and is not necessarily a measure of our ability to fund our cash needs. In addition, it should be noted that companies calculate EBITDA differently and, therefore, EBITDA has material limitations as a performance measure because it excludes interest expense, taxes, depreciation and amortization and minority interest. The following table reconciles EBITDA with our net income (loss).
 
(3)  Acquisitions, net of cash required, consists only of the cash component of acquisitions. It does not include common stock and notes issued for acquisitions, nor does it include other non-cash assets issued for acquisitions.

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Reconciliation of EBITDA
                                                 
    Period from       Nine Months Ended
    May 22 to   Year Ended December 31,   September 30,
    December 31,        
    2001   2002   2003   2004   2004   2005
                         
    (In thousands)
Net income (loss)
  $ 93     $ (616 )   $ 1,561     $ 17,655     $ 10,111     $ 37,912  
Plus: interest expense
    176       1,260       2,687       7,471       4,525       15,617  
Plus: tax expense
    86       (477 )     1,506       10,821       6,574       23,734  
Plus: depreciation and amortization
    402       4,187       7,648       21,616       12,366       32,902  
Plus: minority interest
    7       (45 )     162       934       344       380  
                                     
EBITDA
  $ 764     $ 4,309     $ 13,564     $ 58,497     $ 33,920     $ 110,545  
                                     

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RISK FACTORS
      An investment in our common stock involves a high degree of risk. You should carefully consider the following risk factors, together with the other information contained in this prospectus, before deciding to invest in our common stock. If any of the following risks develop into actual events, our business, financial condition, results of operations or cash flows could be materially adversely affected, the trading price of shares of our common stock could decline, and you may lose all or part of your investment.
Risks Related to Our Business and Our Industry
  Our business depends on the oil and gas industry and particularly on the level of activity for North American oil and gas. Our markets may be adversely affected by industry conditions that are beyond our control.
      We depend on our customers’ willingness to make operating and capital expenditures to explore for, develop and produce oil and gas in North America. If these expenditures decline, our business will suffer. Our customers’ willingness to explore, develop and produce depends largely upon prevailing industry conditions that are influenced by numerous factors over which management has no control, such as:
  •  the supply of and demand for oil and gas;
 
  •  the level of prices, and expectations about future prices, of oil and gas;
 
  •  the cost of exploring for, developing, producing and delivering oil and gas;
 
  •  the expected rates of declining current production;
 
  •  the discovery rates of new oil and gas reserves;
 
  •  available pipeline and other transportation capacity;
 
  •  weather conditions, including hurricanes that can affect oil and gas operations over a wide area;
 
  •  domestic and worldwide economic conditions;
 
  •  political instability in oil and gas producing countries;
 
  •  technical advances affecting energy consumption;
 
  •  the price and availability of alternative fuels;
 
  •  the ability of oil and gas producers to raise equity capital and debt financing; and
 
  •  merger and divestiture activity among oil and gas producers.
      The level of activity in the North American oil and gas exploration and production industry is volatile. Expected trends in oil and gas production activities may not continue and demand for the services provided by us may not reflect the level of activity in the industry. Any prolonged substantial reduction in oil and gas prices would likely affect oil and gas production levels and therefore affect demand for the services we provide. A material decline in oil and gas prices or North American activity levels could have a material adverse effect on our business, financial condition, results of operations and cash flows. In addition, a decrease in the development rate of oil and gas reserves in our market areas may also have an adverse impact on our business, even in an environment of stronger oil and gas prices.
Because the oil and gas industry is cyclical, our operating results may fluctuate.
      Oil prices have been volatile over the last three years, with WTI Cushing crude oil spot price ranging from a low of $25.19 per bbl on November 13, 2002, to a high of $69.81 per bbl on August 30, 2005. Gas prices have also been volatile with Henry Hub natural gas spot price, ranging in the last year from $4.85 per mcf on November 19, 2004 to $14.65 per mcf on October 26, 2005. In addition, in recent periods, these prices have been at historically high levels. Prices may not remain at these levels. These price changes have caused oil and gas companies and drilling contractors to change their strategies and

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expenditure levels. We have experienced in the past, and may experience in the future, significant fluctuations in operating results based on these changes. We reported a loss in 2002, and our income in 2004 was $17.7 million compared to $1.6 million in 2003.
      Substantially all of the service and rental revenue we earn is based upon a charge for a relatively short period of time (an hour, a day, a week) for the actual period of time the service or rental is provided to our customer. By contracting services on a short-term basis, we are exposed to the risks of a rapid reduction in market price and utilization and volatility in our revenues. Product sales are recorded when the actual sale occurs and title or ownership passes to the customer and the product is shipped or delivered to the customer.
There is potential for excess capacity in our industry.
      Because oil and gas prices and drilling activity have been at historically high levels, oilfield service companies have been acquiring new equipment to meet their customers’ increasing demand for services. If these levels of price and activity do not continue, there is a potential for excess capacity in the oilfield service industry. This could result in an increased competitive environment for oilfield service companies, which could lead to lower prices and utilization for our services and could adversely affect our business.
We may be unable to employ a sufficient number of skilled and qualified workers.
      The delivery of our services and products requires personnel with specialized skills and experience who can perform physically demanding work. As a result of the volatility of the oilfield service industry and the demanding nature of the work, workers may choose to pursue employment in fields that offer a more desirable work environment at wage rates that are competitive. Our ability to be productive and profitable will depend upon our ability to employ and retain skilled workers. In addition, our ability to expand our operations depends in part on our ability to increase the size of our skilled labor force. The demand for skilled workers is high, and the supply is limited, particularly in the U.S. Rocky Mountain region, which is one of our key regions. A significant increase in the wages paid by competing employers could result in a reduction of our skilled labor force, increases in the wage rates that we must pay, or both. If either of these events were to occur, our capacity and profitability could be diminished and our growth potential could be impaired.
Our executive officers and certain key personnel are critical to our business and these officers and key personnel may not remain with us in the future.
      Our future success depends upon the continued service of our executive officers and other key personnel. If we lose the services of one or more of our executive officers or key employees, our business, operating results and financial condition could be harmed.
Our operating history may not be sufficient for investors to evaluate our business and prospects.
      We are a recently combined company with a short combined operating history. In addition, two of our combining companies, IPS and CES, have grown significantly over the last few years through acquisitions. This may make it more difficult for investors to evaluate our business and prospects and to forecast our future operating results. The historical combined financial statements and the unaudited pro forma combined financial statements included in this prospectus are based on the separate businesses of IPS, CES and IEM for the periods prior to the Combination. As a result, the historical and pro forma information may not give you an accurate indication of what our actual results would have been if the Combination had been completed at the beginning of the periods presented or of what our future results of operations are likely to be. Our future results will depend on our ability to efficiently manage our combined operations and execute our business strategy.

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We participate in a capital intensive business. We may not be able to finance future growth of our operations or future acquisitions.
      Historically, we have funded the growth of our operations and our acquisitions from bank debt and private placement of shares in addition to cash generated by our business. In the future, we may not be able to continue to obtain sufficient bank debt at competitive rates or complete equity and other debt financings. If we do not generate sufficient cash from our business to fund operations, our growth could be limited unless we are able to obtain additional capital through equity or debt financings. Our inability to grow as planned may reduce our chances of maintaining and improving profitability.
Our inability to control the inherent risks of acquiring and integrating businesses could adversely affect our operations.
      We are a recently combined company and integrating our ongoing businesses may be difficult. In particular, the integration of businesses and operations that are located in disparate regions of North America may prove difficult to achieve in a cost-effective manner. The inability of management to successfully integrate the combining companies could have a material adverse effect on our business, operating results and financial position. Moreover, we may not be able to cross sell our services and penetrate new markets successfully and we may not obtain the anticipated or desired benefits of the Combination. In addition to the Combination, acquisitions have been, and our management believes acquisitions will continue to be, a key element of our business strategy. We may not be able to identify and acquire acceptable acquisition candidates on favorable terms in the future. We may be required to incur substantial indebtedness to finance future acquisitions and also may issue equity securities in connection with such acquisitions. Such additional debt service requirements may impose a significant burden on our results of operations and financial condition. The issuance of additional equity securities could result in significant dilution to stockholders. Acquisitions may not perform as expected when the acquisition was made and may be dilutive to our overall operating results. Additional risks we will face include:
  •  retaining and attracting key employees;
 
  •  retaining and attracting new customers;
 
  •  increased administrative burden;
 
  •  developing our sales and marketing capabilities;
 
  •  managing our growth effectively;
 
  •  integrating operations;
 
  •  operating a new line of business; and
 
  •  increased logistical problems common to large, expansive operations.
If we fail to manage these risks successfully, our business could be harmed.
Our customer base is concentrated within the oil and gas production industry and loss of a significant customer could cause our revenue to decline substantially.
      Our top five customers accounted for approximately 21% of our consolidated revenue for the nine months ended September 30, 2005. Although none of our customers in the first nine months of 2005 accounted for more than 10% of our consolidated revenue, collectively, our top ten customers represented approximately 33% of consolidated revenue for the nine months ended September 30, 2005. It is likely that we will continue to derive a significant portion of our revenue from a relatively small number of customers in the future. If a major customer decided not to continue to use our services, revenue would decline and our operating results and financial condition could be harmed.

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Our indebtedness could restrict our operations and make us more vulnerable to adverse economic conditions.
      At September 30, 2005, our long-term debt (excluding the current portion) was $452 million and our stockholders’ equity was $179 million. Our level of indebtedness may adversely affect operations and limit our growth, and we may have difficulty making debt service payments on our indebtedness as such payments become due. Our level of indebtedness may affect our operations in several ways, including the following:
  •  our level of debt increases our vulnerability to general adverse economic and industry conditions;
 
  •  the covenants that are contained in the agreements that govern our indebtedness limit our ability to borrow funds, dispose of assets, pay dividends and make certain investments;
 
  •  our debt covenants also affect our flexibility in planning for, and reacting to, changes in the economy and in our industry;
 
  •  any failure to comply with the financial or other covenants of our debt could result in an event of default, which could result in some or all of our indebtedness becoming immediately due and payable;
 
  •  our level of debt may impair our ability to obtain additional financing in the future for working capital, capital expenditures, acquisitions or other general corporate purposes; and
 
  •  our business may not generate sufficient cash flow from operations to enable us to meet our obligations under our indebtedness.
      The majority of our debt is structured under floating interest rate terms. A one percentage point increase in the interest rates on our $420 million of Term Debt B debt currently outstanding causes a $4.2 million pre-tax annual increase in interest expense.
Our business depends upon our ability to obtain key raw materials and specialized equipment from suppliers.
      Should our current suppliers be unable to provide the necessary raw materials or finished products (such as workover rigs or fluid-handling equipment) or otherwise fail to deliver the products timely and in the quantities required, any resulting delays in the provision of services could have a material adverse effect on our business, financial condition, results of operations and cash flows.
  We may not be able to provide services that meet the specific needs of oil and gas exploration and production companies at competitive prices.
      The markets in which we operate are highly competitive and have relatively few barriers to entry. The principal competitive factors in our markets are price, product and service quality and availability, responsiveness, experience, technology, equipment quality and reputation for safety. We compete with large national and multi-national companies that have longer operating histories, greater financial, technical and other resources and greater name recognition than we do. Several of our competitors provide a broader array of services and have a stronger presence in more geographic markets. In addition, we compete with several smaller companies capable of competing effectively on a regional or local basis. Our competitors may be able to respond more quickly to new or emerging technologies and services and changes in customer requirements. Some contracts are awarded on a bid basis, which further increases competition based on price. As a result of competition, we may lose market share or be unable to maintain or increase prices for our present services or to acquire additional business opportunities, which could have a material adverse effect on our business, financial condition, results of operations and cash flows.

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Our operations are subject to hazards inherent in the oil and gas industry.
      Risks inherent to our industry, such as equipment defects, vehicle accidents, explosions and uncontrollable flows of gas or well fluids, can cause personal injury, loss of life, suspension of operations, damage to formations, damage to facilities, business interruption and damage to or destruction of property, equipment and the environment. These risks could expose us to substantial liability for personal injury, wrongful death, property damage, loss of oil and gas production, pollution and other environmental damages. The frequency and severity of such incidents will affect operating costs, insurability and relationships with customers, employees and regulators.
      We work in a dangerous business. Many of the claims filed against us relate to vehicle accidents that result in the loss of life or serious bodily injury. Our safety procedures may not always prevent such damages. Our insurance coverage may be inadequate to cover our liabilities. In addition, we may not be able to maintain adequate insurance in the future at rates we consider reasonable and commercially justifiable, or that insurance will continue to be available on terms as favorable as our current arrangements. The occurrence of a significant uninsured claim, a claim in excess of the insurance coverage limits maintained by us or a claim at a time when we are not able to obtain liability insurance, could have a material adverse effect on our ability to conduct normal business operations and on our financial condition, results of operations and cash flows.
If we become subject to product liability claims, it could be time-consuming and costly to defend.
      Since our customers use our products or third party products that we sell through our supply stores, errors, defects or other performance problems could result in financial or other damages to us. Our customers could seek damages from us for losses associated with these errors, defects or other performance problems. If successful, these claims could have a material adverse effect on our business, operating results or financial condition. Our existing product liability insurance may not be enough to cover the full amount of any loss we might suffer. A product liability claim brought against us, even if unsuccessful, could be time-consuming and costly to defend and could harm our reputation.
We are subject to extensive and costly environmental laws and regulations that may require us to take actions that will adversely affect our results of operations.
      Our business is significantly affected by stringent and complex foreign, federal, state and local laws and regulations governing the discharge of substances into the environment or otherwise relating to environmental protection. As part of our business, we handle, transport, and dispose of a variety of fluids and substances used or produced by our customers in connection with their oil and gas exploration and production activities. We also generate and dispose of hazardous waste. The generation, handling, transportation, and disposal of these fluids, substances, and waste are regulated by a number of laws, including the Resource Recovery and Conservation Act; the Comprehensive Environmental Response, Compensation, and Liability Act; the Clean Water Act; the Safe Drinking Water Act; and analogous state laws. Failure to properly handle, transport, or dispose of these materials or otherwise conduct our operations in accordance with these and other environmental laws could expose us to liability for governmental penalties, cleanup costs associated with releases of such materials, damages to natural resources, and other damages, as well as potentially impair our ability to conduct our operations. We could be exposed to liability for cleanup costs, natural resource damages and other damages under these and other environmental laws as a result of our conduct that was lawful at the time it occurred or the conduct of, or conditions caused by, prior operators or other third parties. Environmental laws and regulations have changed in the past, and they are likely to change in the future. If existing regulatory requirements or enforcement policies change, we may be required to make significant unanticipated capital and operating expenditures.

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      Any failure by us to comply with applicable environmental laws and regulations may result in governmental authorities taking actions against our business that could adversely impact our operations and financial condition, including the:
  •  issuance of administrative, civil and criminal penalties;
 
  •  denial or revocation of permits or other authorizations;
 
  •  imposition of limitations on our operations; and
 
  •  performance of site investigatory, remedial or other corrective actions.
      The effect of environmental laws and regulations on our business is discussed in greater detail under “Business — Environmental Matters.”
The nature of our industry subjects us to compliance with other regulatory laws.
      Our business is significantly affected by state and federal laws and other regulations relating to the oil and gas industry in general, and more specifically with respect to health and safety, waste management and the manufacture, storage, handling and transportation of hazardous materials and by changes in and the level of enforcement of such laws. The failure to comply with these rules and regulations can result in substantial penalties, revocation of permits, corrective action orders and criminal prosecution. The regulatory burden on the oil and gas industry increases our cost of doing business and, consequently, affects our profitability. We may be subject to claims alleging personal injury or property damage as a result of alleged exposure to hazardous substances. It is impossible for management to predict the cost or impact of such laws and regulations on our future operations.
If we fail to develop or maintain an effective system of internal controls, we may not be able to accurately report our financial results or prevent fraud.
      Effective internal controls are necessary for us to provide reliable financial reports and effectively prevent fraud. If we cannot provide reliable financial reports or prevent fraud, our reputation and operating results would be harmed. Our efforts to continue to develop and maintain internal controls may not be successful, and we may be unable to maintain adequate controls over our financial processes and reporting in the future, including compliance with the obligations under Section 404 of the Sarbanes-Oxley Act of 2002. Any failure to develop or maintain effective controls, or difficulties encountered in our implementation or other effective improvement of our internal controls, could harm our operating results.
A terrorist attack or armed conflict could harm our business.
      Terrorist activities, anti-terrorist efforts and other armed conflicts involving the United States or other countries may adversely affect the United States and global economies and could prevent us from meeting our financial and other obligations. If any of these events occur, the resulting political instability and societal disruption could reduce overall demand for oil and gas, potentially putting downward pressure on demand for our services and causing a reduction in our revenues. Oil and gas related facilities could be direct targets of terrorist attacks, and our operations could be adversely impacted if infrastructure integral to our customers’ operations is destroyed or damaged. Costs for insurance and other security may increase as a result of these threats, and some insurance coverage may become more difficult to obtain, if available at all.
Conservation measures and technological advances could reduce demand for oil and gas.
      Fuel conservation measures, alternative fuel requirements, increasing consumer demand for alternatives to oil and gas, technological advances in fuel economy and energy generation devices could reduce demand for oil and gas. Management cannot predict the impact of the changing demand for oil and gas services and products, and any major changes may have a material adverse effect on our business, financial condition, results of operations and cash flows.

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Fluctuations in currency exchange rates in Canada could adversely affect our business.
      We have substantial operations in Canada. As a result, fluctuations in currency exchange rates in Canada could materially and adversely affect our business. For the nine months ended September 30, 2005, our Canadian operations represented approximately 14% of our revenue and 7% of our net income before taxes and minority interest.
We are susceptible to seasonal earnings volatility due to adverse weather conditions in Canada.
      Our operations are directly affected by seasonal differences in weather in Canada. The level of activity in the Canadian oilfield services industry declines significantly in the second calendar quarter, when frost leaves the ground and many secondary roads are temporarily rendered incapable of supporting the weight of heavy equipment. The duration of this period is referred to as “spring breakup” and has a direct impact on our activity levels in Canada. The timing and duration of “spring breakup” depend on weather patterns but generally “spring breakup” occurs in April and May. Additionally, if an unseasonably warm winter prevents sufficient freezing, we may not be able to access wellsites and our operating results and financial condition may, therefore, be adversely affected. The demand for our services may also be affected by the severity of the Canadian winters. In addition, during excessively rainy periods, equipment moves may be delayed, thereby adversely affecting operating results. The volatility in weather and temperature in the Canadian oilfield can therefore create unpredictability in activity and utilization rates. As a result, full-year results are not likely to be a direct multiple of any particular quarter or combination of quarters.
Our operations in Mexico are subject to specific risks, including dependence on Petróleos Mexicanos (“PEMEX”) as the sole customer, exposure to fluctuation in the Mexican peso and workforce unionization.
      Our business in Mexico is substantially all performed for PEMEX pursuant to multi-year contracts. These contracts are generally two years in duration and are subject to competitive bid for renewal. Any failure by us to renew our contracts could have a material adverse effect on our financial condition, results of operations and cash flows.
      The PEMEX contracts provide that approximately 80% of the revenues thereunder are denominated in pesos at the date of invoice. Invoices are paid approximately 45 days after the invoice date and as such we are exposed to fluctuation in the peso during this 45-day period. A material decrease in the value of the Mexican peso relative to the U.S. dollar could negatively impact our revenues, cash flows and net income.
      Our operations in Mexico are party to a collective labor contract made effective as of October 1, 2003 between Servicios Petrotec S.A. DE C.V., one of our subsidiaries, and Unión Sindical de Trabajadores de la Industria Metálica y Similares, the metal and similar industry workers labor union. We have not experienced work stoppages in the past but cannot guarantee that we will not experience work stoppages in the future. A prolonged work stoppage could negatively impact our revenues, cash flows and net income.
Our U.S. operations in the Gulf of Mexico are adversely impacted by the hurricane season, which generally occurs in the third calendar quarter.
      Hurricanes and the threat of hurricanes during this period will often result in the shut-down of oil and gas operations in the Gulf of Mexico as well as land operations within the hurricane path. During a shut-down period, we are unable to access wellsites and our services are also shut down. This situation can therefore create unpredictability in activity and utilization rates, which can have a material adverse impact on our business, financial conditions, results of operations and cash flows.
When rig counts are low, our rig relocation customers may not have a need for our services.
      Many of the major U.S. onshore drilling services contractors have significant capabilities to move their own drilling rigs and related oilfield equipment and to erect rigs. When regional rig counts are high, drilling services contractors exceed their own capabilities and contract for additional oilfield equipment

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hauling and rig erection capacity. Our rig relocation business activity is highly correlated to the rig count; however, the correlation varies over the rig count range. As rig count drops, some drilling services contractors reach a point where all of their oilfield equipment hauling and rig erection needs can be met by their own fleets. If one or more of our rig relocation customers reach this “tipping point,” our revenues attributable to rig relocation will decline much faster than the corresponding overall decline in the rig count. This non-linear relationship between our rig relocation business activity and the rig count in the areas in which we have rig relocation operations can increase significantly our earnings volatility with respect to rig relocation.
Increasing trucking regulations may increase our costs and negatively impact our results of operations.
      Among the services we provide, we operate as a motor carrier and therefore are subject to regulation by the U.S. Department of Transportation and by various state agencies. These regulatory authorities exercise broad powers, governing activities such as the authorization to engage in motor carrier operations and regulatory safety. There are additional regulations specifically relating to the trucking industry, including testing and specification of equipment and product handling requirements. The trucking industry is subject to possible regulatory and legislative changes that may affect the economics of the industry by requiring changes in operating practices or by changing the demand for common or contract carrier services or the cost of providing truckload services. Some of these possible changes include increasingly stringent environmental regulations, changes in the hours of service regulations which govern the amount of time a driver may drive in any specific period, onboard black box recorder devices or limits on vehicle weight and size.
      Interstate motor carrier operations are subject to safety requirements prescribed by the U.S. Department of Transportation. To a large degree, intrastate motor carrier operations are subject to state safety regulations that mirror federal regulations. Such matters as weight and dimension of equipment are also subject to federal and state regulations.
      From time to time, various legislative proposals are introduced, including proposals to increase federal, state, or local taxes, including taxes on motor fuels, which may increase our costs or adversely impact the recruitment of drivers. We cannot predict whether, or in what form, any increase in such taxes applicable to us will be enacted.
Risks Related to Our Relationship with SCF
L.E. Simmons, through SCF, controls the outcome of stockholder voting and may exercise this voting power in a manner adverse to you.
      After the offering, SCF will own approximately             % of our outstanding common stock and approximately      % of our outstanding common stock if the over-allotment option is exercised in full. L.E. Simmons is the sole owner of L.E. Simmons and Associates, Incorporated, the ultimate general partner of SCF. Accordingly, Mr. Simmons, through his ownership of the ultimate general partner of SCF, will be in a position to control the outcome of matters requiring a stockholder vote, including the election of directors, adoption of amendments to our certificate of incorporation or bylaws or approval of transactions involving a change of control. The interests of Mr. Simmons may differ from yours, and SCF may vote its common stock in a manner that may adversely affect you.
SCF’s ownership interest and provisions contained in our certificate of incorporation and bylaws could discourage a takeover attempt, which may reduce or eliminate the likelihood of a change of control transaction and, therefore, your ability to sell your shares for a premium.
      In addition to SCF’s controlling position, provisions contained in our certificate of incorporation and bylaws, such as a classified board, limitations on the removal of directors, on stockholder proposals at meetings of stockholders and on stockholder action by written consent and the inability of stockholders to call special meetings, could make it more difficult for a third party to acquire control of our company. Our certificate of incorporation also authorizes our board of directors to issue preferred stock without

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stockholder approval. If our board of directors elects to issue preferred stock, it could increase the difficulty for a third party to acquire us, which may reduce or eliminate your ability to sell your shares of common stock at a premium. See “Description of Our Capital Stock.”
Two of our directors may have conflicts of interest because they are affiliated with SCF. The resolution of these conflicts of interest may not be in our or your best interests.
      Two of our directors, David C. Baldwin and Andrew L. Waite, are current officers of L.E. Simmons and Associates, Incorporated, the ultimate general partner of SCF. This may create conflicts of interest because these directors have responsibilities to SCF and its owners. Their duties as officers of L.E. Simmons and Associates, Incorporated may conflict with their duties as directors of our company regarding business dealings between SCF and us and other matters. The resolution of these conflicts may not always be in our or your best interest.
We have renounced any interest in specified business opportunities, and SCF and its director nominees on our board of directors generally have no obligation to offer us those opportunities.
      SCF has investments in other oilfield service companies that may compete with us, and SCF and its affiliates, other than our company, may invest in other such companies in the future. We refer to SCF and its other affiliates and its portfolio companies as the SCF group. Our certificate of incorporation provides that, so long as we have a director or officer that is affiliated with SCF (an “SCF Nominee”), we renounce any interest or expectancy in any business opportunity in which any member of the SCF group participates or desires or seeks to participate in and that involves any aspect of the energy equipment or services business or industry, other than (i) any business opportunity that is brought to the attention of an SCF Nominee solely in such person’s capacity as a director or officer of our company and with respect to which no other member of the SCF group independently receives notice or otherwise identifies such opportunity and (ii) any business opportunity that is identified by the SCF group solely through the disclosure of information by or on behalf of our company. We are not prohibited from pursuing any business opportunity with respect to which we have renounced any interest.
Risks Related to this Offering
Future sales of shares of our common stock may affect their market price and the future exercise of options may depress our stock price and result in immediate and substantial dilution.
      We cannot predict what effect, if any, future sales of shares of our common stock, or the availability of shares for future sale, will have on the market price of our common stock. Upon completion of this offering, SCF will own                      shares of our common stock, or           % of our outstanding common stock (or                      shares of our common stock, or           %, if the over-allotment option is fully exercised) and our existing stockholders (other than SCF) will own                      shares of our common stock, or           % of our outstanding common stock (or                      shares of our common stock or           % of our outstanding common stock if the over-allotment option is fully exercised). We and our officers and directors and the selling stockholders are subject to the lock-up agreements described in “Underwriting” for a period of 180 days after the date of this prospectus. Existing stockholders are parties to a registration rights agreement granting them certain demand and piggyback registrations in the future. In addition, shares beneficially held for at least one year will be eligible for sale in the public market pursuant to Rule 144 under the Securities Act of 1933, as amended, or the Securities Act, subject to the lock-up agreements. Sales of substantial amounts of our common stock in the public market following our initial public offering, or the perception that such sales could occur, could adversely affect the market price of our common stock and may make it more difficult for you to sell your shares at a time and price that you deem appropriate. Please read “Shares Eligible for Future Sale.”
      As soon as practicable after this offering, we intend to file one or more registration statements with the SEC on Form S-8 providing for the registration of shares of our common stock issued or reserved for issuance under our stock incentive plans. Subject to the expiration of lock-ups that we and certain of our

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stockholders have entered into and any applicable restrictions or conditions contained in our stock incentive plans, the shares registered under these registration statements on Form S-8 will be available for resale immediately in the public market without restriction.
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 pro forma net tangible book value as of September 30, 2005, after giving effect to this offering, would be $           per share. You will incur further dilution if outstanding options to purchase common stock are exercised. In addition, our certificate of incorporation allows us to issue significant numbers of additional shares, including shares that may be issued under our stock incentive plans. Please read “Dilution” for a complete description of the calculation of net tangible book value.
Because we have no current plans to pay dividends on our common stock, investors must look solely to stock appreciation for a return on their investment in us.
      We do not anticipate paying 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. 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.
There has been no active trading market for our common stock, and an active trading market may not develop.
      Prior to this offering, there has been no public market for our common stock. We will apply to list our common stock on the New York Stock Exchange, or NYSE. We do not know if an active trading market will develop for our common stock or how the common stock will trade in the future, which may make it more difficult for you to sell your shares. Negotiations between the underwriters and us determined the initial public offering price, which may not be indicative of the price at which our common stock will trade following the completion of this offering. You may not be able to resell your shares at or above the initial public offering price.
If our stock price fluctuates after the initial public offering, you could lose a significant part of your investment.
      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. The market price of our common stock could similarly be subject to wide fluctuations in response to a number of factors, most of which we cannot control, including:
  •  changes in securities analysts’ recommendations and their estimates of our financial performance;
 
  •  the public’s reaction to our press releases, announcements and our filings with the SEC and those of our competitors;
 
  •  fluctuations in broader stock market prices and volumes, particularly among securities of oil and gas service companies;
 
  •  changes in market valuations of similar companies;
 
  •  investor perception of our industry or our prospects;
 
  •  additions or departures of key personnel;

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  •  commencement of or involvement in litigation;
 
  •  changes in environmental and other governmental regulations;
 
  •  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 service companies;
 
  •  revenue and operating results failing to meet the expectations of securities analysts or investors in a particular quarter;
 
  •  changes in our pricing policies or pricing policies of our competitors;
 
  •  future issuances and sales of our common stock;
 
  •  demand for and trading volume of our common stock;
 
  •  domestic and worldwide supplies and prices of and demand for oil and gas; and
 
  •  changes in general conditions in the domestic and worldwide economies, financial markets or the oil and gas industry.
      The realization of any of these risks and other factors beyond our control could cause the market price of our common stock to decline significantly. In particular, the market price of our common stock may be influenced by variations in oil and gas commodity prices, because demand for our services is closely related to the prices of these commodities. This may cause our stock price to fluctuate with these underlying commodity prices, which are highly volatile.

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FORWARD-LOOKING STATEMENTS
      This prospectus contains forward-looking statements. We have based these forward-looking statements largely on our current expectations and projections about future events and financial trends affecting the financial condition of our business. These forward-looking statements are subject to a number of risks, uncertainties and assumptions, including, among other things, the risk factors discussed in this prospectus and other factors, most of which are beyond our control.
      The words “believe,” “may,” “will,” “estimate,” “continue,” “anticipate,” “intend,” “plan,” “expect” and similar expressions are intended to identify forward-looking statements. All statements other than statements of current or historical fact contained in this prospectus are forward-looking statements.
      Although we believe that the forward-looking statements contained in this prospectus are based upon reasonable assumptions, the forward-looking events and circumstances discussed in this prospectus may not occur and actual results could differ materially from those anticipated or implied in the forward-looking statements.
      Important factors that may affect our expectations, estimates or projections include:
  •  a decline in or substantial volatility of oil and gas prices, and any related changes in expenditures by our customers;
 
  •  the effects of future acquisitions on our business;
 
  •  changes in customer requirements in markets or industries we serve;
 
  •  competition within our industry;
 
  •  general economic and market conditions;
 
  •  our access to current or future financing arrangements;
 
  •  our ability to replace or add workers at economic rates;
 
  •  environmental and other governmental regulations; and
 
  •  the effects of severe weather on our services centers or equipment.
      Our forward-looking statements speak only as of the date of this prospectus. Unless otherwise required by law, we undertake no obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events or otherwise.

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USE OF PROCEEDS
      We expect to receive net proceeds from the sale of                      shares of common stock by us in this offering of approximately $240 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 proceeds from any sale of shares of our common stock by the selling stockholders.
      We plan to use $50 million of our net proceeds from this offering to repay a portion of our term loan facility, $5 million to repay seller financed notes and the remainder to pay all outstanding balances under our revolving credit facility and for general corporate purposes, which may include cash payments made in connection with future acquisitions. Our current senior credit facility consists of a $130 million U.S. revolver, a $30 million Canadian revolver and a term loan facility of $420 million. As of September 30, 2005, we had $420 million of indebtedness outstanding under the term loan portion of our senior credit facility. The current term loan bears interest at either a base rate plus 1.75%, or the London Interbank Offered Rate (“LIBOR”) plus 2.75%, and matures in September 2012. As of September 30, 2005, we had approximately $26 million in indebtedness outstanding under our revolving credit facility. The revolving credit facility bears interest at either a base rate plus an applicable margin ranging between 0.25% and 1.75%, or LIBOR plus an applicable margin between 1.25% and 2.75% in the case of U.S. borrowings. In the case of borrowings under the Canadian revolving credit facility, interest is based on the Canadian Base Rate (as defined in the Credit Agreement) plus an applicable margin ranging between 0.25% and 1.75%. Our borrowings under the term loan and revolving credit facility were used to refinance existing debt, to pay the Dividend as described below and to provide for ongoing working capital and general corporate purposes.
      Please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations – Description of Our Indebtedness” for a description of our outstanding indebtedness and our senior credit facility following this offering.
      An affiliate of Credit Suisse First Boston LLC and an affiliate of UBS Securities LLC have each committed $9 million (or approximately 7%) of our $130 million U.S. revolver and therefore will receive a portion of the proceeds from this offering that we use to repay our U.S. revolver. Credit Suisse First Boston LLC and UBS Securities LLC are underwriters of this offering. Please read “Underwriting.”
DIVIDEND POLICY
      Immediately after the closing of the Combination, we paid a dividend of $5.24 per share of our common stock or an aggregate of approximately $147 million to our stockholders. The term “Dividend” refers to this payment. Other than the Dividend, we have not declared or paid any cash dividends on our common stock, and 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 future determination relating to our dividend policy will be at the discretion of our board of directors and will depend on our results of operations, financial condition, capital requirements and other factors deemed relevant by our board. We are also currently restricted in our ability to pay dividends under our senior credit facility.

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CAPITALIZATION
      The following table sets forth our capitalization at September 30, 2005:
  •  on an actual basis; and
 
  •  on an as adjusted basis to give effect to this offering and the application of our estimated net proceeds from this offering as set forth under “Use of Proceeds” as if the offering occurred on September 30, 2005.
      The information was derived from and is qualified by reference to our consolidated financial statements included elsewhere in this prospectus. You should read this information in conjunction with these consolidated financial statements, “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and “Use of Proceeds.”
                       
    September 30, 2005
     
    Actual   As Adjusted
         
    (In thousands)
Cash and cash equivalents(1)
  $ 14,377     $ 173,243  
             
Total long-term debt, including current portion:
               
 
Notes payable:
               
   
Revolving credit facilities
  $ 26,134     $  
   
Term loan facility
    420,000       370,000  
   
Other debt
    11,756       6,756  
             
     
Total
    457,890       376,756  
             
Stockholders’ equity:
               
 
Common stock, $0.01 par value, 100,000,000 shares authorized, 27,810,283 shares issued and outstanding;            shares issued and outstanding, as adjusted
    278          
 
Additional paid-in capital
    163,475          
 
Treasury stock, 17,785 shares at cost
    (202 )     (202 )
 
Deferred compensation
    (2,121 )     (2,121 )
 
Retained earnings
    936       936  
 
Accumulated other comprehensive income
    16,195       16,195  
             
     
Total stockholders’ equity
    178,561       418,561  
             
     
Total capitalization
  $ 636,451     $ 795,317  
             
 
(1)  Net of bank operating loans.

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DILUTION
      If you invest in our common stock, your interest will be diluted to the extent of the difference between the public offering price per share and the net tangible book value per share of the common stock after this offering. Our unaudited consolidated net tangible book value as of September 30, 2005 was $(1.20) per share of common stock, after giving effect to the Combination and the Dividend. 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 are outstanding. 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 $           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
  $ (1.20 )
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 and estimated offering expenses.
                                           
    Shares Purchased(1)   Total Consideration    
            Average Price
    Number   Percent   Amount   Percent   Per Share
                     
Existing stockholders(2)
    27,810,283       %     $         %     $    
New public investors
            %               %          
                               
 
Total
            100%     $         100%     $    
                               
 
(1)  The number of shares disclosed for the existing stockholders includes                     shares being sold by the selling stockholders in this offering. The number of shares disclosed for the new investors does not include the                     shares being purchased by the new investors from the selling stockholders in this offering.
 
(2)  With respect to our executive officers, directors and greater-than-10% stockholders, and assuming the exercise of all outstanding warrants and stock options, the number of shares of common stock purchased from us, the total consideration paid to us, and the average price per share paid by all of those affiliated persons, are as follows:
                                         
    Shares Purchased(1)   Total Consideration    
            Average Price
    Number   Percent   Amount   Percent   Per Share
                     
Affiliated persons
            %     $         %     $    
      As of September 30, 2005, there were 27,810,283 shares of our common stock outstanding. 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                      shares or approximately           % of the total number of shares of common stock outstanding after this offering.

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UNAUDITED PRO FORMA CONSOLIDATED FINANCIAL DATA
      On September 12, 2005, we completed the Combination transaction through which CES, IEM and IPS merged. To facilitate this transaction, we borrowed funds through our bank refinancing (the “Financing”), paid the Dividend to stockholders and recorded goodwill associated with the acquisition of minority interests (the “MI Acquisition”).
      The following summary unaudited pro forma consolidated statements of operations gives effect to the MI Acquisition, the Financing and the payment of the Dividend, assuming that the MI Acquisition, the Financing and the payment of the Dividend were effected on January 1, 2004. From a balance sheet perspective, these transactions have been reflected in our consolidated balance sheet as of September 30, 2005 included elsewhere in this prospectus.
      The historical statement of operations information for the year ended December 31, 2004 is derived from our audited consolidated financial statements. The historical statement of operations information for the nine-month period ended September 30, 2005 is derived from our unaudited consolidated financial statements.
      The unaudited pro forma consolidated statements of operations represent management’s preliminary determination of purchase accounting adjustments and are based on available information and assumptions that management considers reasonable under the circumstances. The purchase accounting estimate is expected to be finalized within one year of the closing date of the Combination. Consequently, the amounts reflected in the unaudited pro forma consolidated statements of operations are subject to change. Management does not expect that the differences between the preliminary and final purchase price allocation will have a material impact on our consolidated financial position or results of operations.
      The unaudited pro forma consolidated statements of operations do not purport to be indicative of the results that would have been obtained had the transactions described above been completed on the indicated dates or that may be obtained in the future.
      The following information should be read together with our historical consolidated financial statements and related notes included within this prospectus.

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COMPLETE PRODUCTION SERVICES, INC.
Pro Forma Consolidated Statement of Operations
Nine Months Ended September 30, 2005
                           
        Financing    
    Complete   Note 3   Consolidated
             
    (In thousands, except per share data)
    (Unaudited)
Revenue:
                       
 
Service
  $ 434,745     $     $ 434,745  
 
Product
    90,491             90,491  
                   
      525,236             525,236  
Service expenses
    266,344             266,344  
Product expenses
    69,968             69,968  
Selling, general and administrative expenses
    75,535             75,535  
Write-off of deferred financing fees
    2,844       (2,570 )(a)     274  
Depreciation and amortization
    32,902             32,902  
                   
 
Income before interest, taxes and minority interest
    77,643       2,570       80,213  
Interest expense
    15,617       7,560 (b)     23,177  
                   
 
Income before taxes and minority interest
    62,026       (4,990 )     57,036  
Taxes
    23,734       (1,747 )(c)     21,987  
                   
 
Income before minority interest
    38,292       (3,243 )     35,049  
Minority interest
    380             380  
                   
 
Net income (loss)
  $ 37,912     $ (3,243 )   $ 34,669  
                   
Earnings per share:
                       
 
Basic
  $ 1.39             $ 1.27  
                   
 
Diluted
  $ 1.28             $ 1.17  
                   
Weighted average shares:
                       
 
Basic
    27,282               27,282  
                   
 
Diluted
    29,640               29,640  
                   
See accompanying notes to pro forma consolidated statements of operations.

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COMPLETE PRODUCTION SERVICES, INC.
Pro Forma Consolidated Statement of Operations
Year Ended December 31, 2004
                                   
        MI Acq.   Financing    
                 
    Complete   Note 2   Note 3   Consolidated
                 
    (In thousands, except per share data)
    (Unaudited)
Revenue:
                               
 
Service
  $ 239,427     $     $     $ 239,427  
 
Product
    81,320                   81,320  
                         
      320,747                   320,747  
Service expenses
    157,540                   157,540  
Product expenses
    58,633                   58,633  
Selling, general and administrative expenses
    46,077                   46,077  
Write-off of deferred financing fees
                3,210 (a)     3,210  
Depreciation and amortization
    21,616                   21,616  
                         
 
Income before interest, taxes and minority interest
    36,881             (3,210 )     33,671  
Interest expense
    7,471             10,500 (b)     17,971  
                         
 
Income before taxes and minority interest
    29,410             (13,710 )     15,700  
Taxes
    10,821             (4,799 )(c)     6,022  
                         
 
Income before minority interest
    18,589             (8,911 )     9,678  
Minority interest (see note 2)
    934       (934 )            
                         
 
Net income (loss)
  $ 17,655     $ 934     $ (8,911 )   $ 9,678  
                         
Earnings per share:
                               
 
Basic
  $ 0.98                     $ 0.54  
                         
 
Diluted
  $ 0.97                     $ 0.53  
                         
Weighted average shares:
                               
 
Basic
    18,002                       18,002  
 
Diluted
    18,270                       18,270  
See accompanying notes to pro forma consolidated statements of operations.

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COMPLETE PRODUCTION SERVICES, INC.
Notes to Unaudited Pro Forma Consolidated Statements of Operations
Nine Months Ended September 30, 2005 and Year Ended December 31, 2004 (unaudited)
(In thousands, except as noted)
1. Basis of Presentation:
      On September 12, 2005, Integrated Production Services, Inc. (“IPS”) acquired Complete Energy Services, Inc. (“CES”) and I.E. Miller Services, Inc. (“IEM”) for stock. We refer to this transaction as the “Combination.” The Combination was accounted for using the continuity of interest method as described in note 1 of the audited consolidated financial statements. Upon closing the Combination, IPS changed its name to Complete Production Services, Inc.
      The accompanying pro forma consolidated statements of operations for the nine-month period ended September 30, 2005 and the year ended December 31, 2004 have been prepared by management in accordance with accounting principles generally accepted in the United States for inclusion in a registration statement on Form S-1.
      These pro forma consolidated statements of operations are not necessarily indicative of the results that would have actually occurred if the events reflected herein had been in effect on the dates indicated or of the results that may occur in the future.
      These pro forma consolidated statements of operations are based on our historical audited and unaudited consolidated financial statements, and the pro forma adjustments and assumptions outlined below. Accordingly, these pro forma consolidated statements of operations should be read in conjunction with our audited and unaudited consolidated financial statements presented elsewhere in this prospectus.
      The accounting policies used in the preparation of the pro forma consolidated statements of operations are those disclosed in our audited consolidated financial statements for the year ended December 31, 2004.
      CES is treated as the accounting acquirer of the minority interests as a result of the Combination. The purchase method of accounting was used to reflect the acquisition of the minority interests in IPS and IEM as at September 12, 2005. The purchase price was based on a fair value of the shares owned by the minority interests estimated by a financial advisor engaged in connection with the Combination. The financial advisor was not engaged to, and did not, determine the actual value of such shares. Under this accounting method, the excess of the purchase price over the fair value of the assets and liabilities allocable to the minority interests acquired has been reflected as goodwill. The estimated fair values of the assets and liabilities are preliminary and subject to change. The unaudited pro forma consolidated statements of operations for the year ended December 31, 2004 and the nine-month period ended September 30, 2005 have been adjusted for the effects of the purchase accounting, as described below.
2. Income Attributable to Minority Interests:
      Minority interest in income for the year ended December 31, 2004 was:
                         
    IPS   IEM   Total
             
Year ended December 31, 2004
  $ 378     $ 556     $ 934  
      For a discussion of the purchase price allocation associated with the Combination, see Note 2(a) of the consolidated financial statements at September 30, 2005.
3.  Financing:
      (a) To adjust amounts related to deferred financing fees as follows:
       For 2005, to add back $2.8 million of expense recorded as a write-off of deferred financing fees associated with debt facilities retired with the proceeds of our $420.0 million borrowing under the

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COMPLETE PRODUCTION SERVICES, INC.
Notes to Unaudited Pro Forma Consolidated Statements of Operations — (Continued)
Nine Months Ended September 30, 2005 and Year Ended December 31, 2004 (unaudited)
(In thousands, except as noted)
  Term B facility on September 12, 2005, partially offset by nine months of amortization of financing fees associated with the Term B facility, assuming the financing occurred on January 1, 2004. For 2004, to record the $2.8 million of expense associated with the deferred financing fees discussed above, assuming the Term B facility was borrowed on January 1, 2004, and amortization of fees associated with this facility for the year ended December 31, 2004.
      (b) To adjust interest expense for our senior secured financing and stockholder distribution, reflecting the estimated interest expense of 7.0% on net additional debt during 2004 of $10.5 million and $7.6 million for the year ended December 31, 2004 and the nine-month period ended September 30, 2005, respectively.
      (c) To record the tax benefit of the interest and deferred financing adjustments discussed in (a) and (b) at an assumed rate of 35%.

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SELECTED CONSOLIDATED FINANCIAL DATA
      The following table presents selected historical consolidated financial and operating data for the periods shown. The selected consolidated financial data as of December 31, 2001 and for the period from the incorporation of IPS on May 22, 2001 through December 31, 2001, have been derived from IPS’s consolidated audited financial statements for such date and period. The consolidated financial data as of December 31, 2002 have been derived from the audited consolidated financial statements of IPS for these dates. In addition, the following selected consolidated financial data as of December 31, 2004 and 2003 and for the three-year period ended December 31, 2004 have been derived from our audited consolidated financial statements for those dates and periods. The selected financial data as of September 30, 2005 and for the nine-month periods ended September 30, 2005 and 2004 have been derived from our unaudited consolidated financial statements. The following information should be read in conjunction with “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and our financial statements and related notes included in this prospectus.
                                                     
    Period from       Nine Months Ended
    May 22 to   Year Ended December 31,   September 30,
    December 31,        
    2001   2002   2003   2004   2004   2005
                         
    (In thousands, except per share data)
Statement of Operations Data:
                                               
Revenue:
                                               
 
Completion and production services
  $ 5,855     $ 30,110     $ 65,025     $ 194,953     $ 112,611     $ 351,154  
 
Drilling services
                2,707       44,474       23,820       89,016  
 
Products sales
          10,494       35,547       81,320       58,962       85,066  
                                     
   
Total
    5,855       40,604       103,279       320,747       195,393       525,236  
Expenses:
                                               
 
Service and product expenses(1)
    3,528       28,531       73,124       216,173       132,629       336,312  
 
Selling, general and administrative
    1,563       7,764       16,591       46,077       28,844       75,535  
 
Depreciation and amortization
    402       4,187       7,648       21,616       12,366       32,902  
                                     
   
Operating income
    362       122       5,916       36,881       21,554       80,487  
Interest expense
    176       1,260       2,687       7,471       4,525       15,617  
Write-off of deferred financing fees
                                  2,844  
Taxes
    86       (477 )     1,506       10,821       6,574       23,734  
                                     
 
Income (loss) before minority interest
    100       (661 )     1,723       18,589       10,455       38,292  
Minority interest
    7       (45 )     162       934       344       380  
                                     
 
Net income (loss)
  $ 93     $ (616 )   $ 1,561     $ 17,655     $ 10,111     $ 37,912  
                                     
Earnings (loss) per share – basic
  $ 0.08     $ (0.22 )   $ 0.22     $ 0.98     $ 0.71     $ 1.39  
                                     
Earnings (loss) per share – diluted
  $ 0.08     $ (0.22 )   $ 0.21     $ 0.97     $ 0.62     $ 1.28  
                                     
Weighted average shares – basic
    1,147       2,757       7,055       18,002       14,176       27,282  
Weighted average shares – diluted
    1,147       2,757       7,272       18,270       16,186       29,640  
 
(1)  Service and product expenses is the aggregate of service expenses and product expenses.

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    Period from       Nine Months Ended
    May 22 to   Year Ended December 31,   September 30,
    December 31,        
    2001   2002   2003   2004   2004   2005
                         
    (In thousands)
Other Financial Data:
                                               
EBITDA(2)
  $ 764     $ 4,309     $ 13,564     $ 58,497     $ 33,920     $ 110,545  
Cash flows from operating activities
    1,683       (8 )     13,965       34,622       15,467       48,471  
Cash flows from financing activities
    13,320       36,279       55,281       157,630       83,404       58,566  
Cash flows from investing activities
    (12,538 )     (35,616 )     (66,214 )     (186,776 )     (99,867 )     (99,145 )
Capital expenditures:
                                               
 
Acquisitions, net of cash acquired(3)
    9,860       27,851       54,798       139,362       75,119       18,163  
 
Property, plant and equipment
    2,678       6,799       11,084       46,904       24,748       84,885  
                                         
    As of December 31,    
        As of September 30,
    2001   2002   2003   2004   2005
                     
    (In thousands)
Balance Sheet Data:
                                       
Cash and cash equivalents
  $ 2,465     $ 3,120     $ 6,094     $ 11,547     $ 19,062  
Net property, plant and equipment
    7,110       47,808       95,217       235,211       340,246  
Total assets
    18,571       110,596       206,066       515,153       769,870  
Long-term debt, excluding current portion
    3,443       22,270       50,144       169,190       452,496  
Total stockholders’ equity
    14,550       60,810       102,207       209,521       178,561  
 
(2)  EBITDA consists of net income (loss) before interest expense, taxes, depreciation and amortization and minority interest. See “Non-GAAP Financial Measures.” EBITDA is included in this prospectus because our management considers it an important supplemental measure of our performance and believes that it is frequently used by securities analysts, investors and other interested parties in the evaluation of companies in our industry, some of which present EBITDA when reporting their results. We regularly evaluate our performance as compared to other companies in our industry that have different financing and capital structures and/or tax rates by using EBITDA. In addition, we use EBITDA in evaluating acquisition targets. Management also believes that EBITDA is a useful tool for measuring our ability to meet our future debt service, capital expenditures and working capital requirements, and EBITDA is commonly used by us and our investors to measure our ability to service indebtedness. EBITDA is not a substitute for the GAAP measures of earnings or of cash flow and is not necessarily a measure of our ability to fund our cash needs. In addition, it should be noted that companies calculate EBITDA differently and, therefore, EBITDA has material limitations as a performance measure because it excludes interest expense, taxes, depreciation and amortization and minority interest. The following table reconciles EBITDA with our net income (loss).
 
(3)  Acquisitions, net of cash required, consists only of the cash component of acquisitions. It does not include common stock and notes issued for acquisitions, nor does it include other non-cash assets issued for acquisitions.

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Reconciliation of EBITDA
                                                 
    Period from       Nine Months Ended
    May 22 to   Year Ended December 31,   September 30,
    December 31,        
    2001   2002   2003   2004   2004   2005
                         
    (In thousands)
Net income (loss)
  $ 93     $ (616 )   $ 1,561     $ 17,655     $ 10,111     $ 37,912  
Plus: interest expense
    176       1,260       2,687       7,471       4,525       15,617  
Plus: tax expense
    86       (477 )     1,506       10,821       6,574       23,734  
Plus: depreciation and amortization
    402       4,187       7,648       21,616       12,366       32,902  
Plus: minority interest
    7       (45 )     162       934       344       380  
                                     
EBITDA
  $ 764     $ 4,309     $ 13,564     $ 58,497     $ 33,920     $ 110,545  
                                     

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MANAGEMENT’S DISCUSSION AND ANALYSIS
OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
      The following discussion and analysis should be read in conjunction with our consolidated financial statements and related notes included within this prospectus. This discussion contains forward-looking statements based on our current expectations, assumptions, estimates and projections about us and the oil and gas industry. These forward-looking statements involve risks and uncertainties that may be outside of our control. Our actual results could differ materially from those indicated in these forward-looking statements. Factors that could cause or contribute to such differences include, but are not limited to: market prices for oil and gas, the level of oil and gas drilling, economic and competitive conditions, capital expenditures, regulatory changes and other uncertainties, as well as those factors discussed below and elsewhere in this prospectus, particularly in “Risk Factors” and “Forward-Looking Statements.” In light of these risks, uncertainties and assumptions, the forward-looking events discussed below may not occur. Except to the extent required by law, we undertake no obligation to update publicly any forward-looking statements, even if new information becomes available or other events occur in the future.
Overview
      We provide specialized services and products focused on helping oil and gas companies develop hydrocarbon reserves, reduce costs and enhance production. We focus on basins within North America that we believe have attractive long-term potential for growth, and we deliver targeted, value-added services and products required by our customers within each specific basin. We believe our range of services and products positions us to meet many needs of our customers at the wellsite, from drilling and completion through production and eventual abandonment. We manage our operations from regional field service facilities located throughout the U.S. Rocky Mountain region, Texas, Oklahoma, Louisiana, western Canada and Mexico.
      On September 12, 2005, we completed the Combination (see “Business – The Combination”) of Complete Energy Services, Inc. (“CES”), Integrated Production Services, Inc. (“IPS”) and I.E. Miller, Inc. (“IEM”). SCF-IV, L.P. (“SCF”) held a majority interest in each of CES, IPS and IEM prior to the Combination. Therefore, we accounted for the Combination using the continuity of interests method (see note 1 of the accompanying audited consolidated financial statements). The consolidated financial statements and the discussions herein, include the operating results of CES, IPS and IEM from the date that each became controlled by SCF (November 7, 2003, May 22, 2001 and August 26, 2004, respectively).
      We operate in three business segments:
  •  Completion and Production Services. Our completion and production services segment includes: (1) intervention services, which require the use of specialized equipment, such as coiled tubing units, pressure pumping units, nitrogen units, well service rigs and snubbing units, to perform various wellbore services, (2) downhole and wellsite services, such as wireline, production optimization, production testing and rental and fishing services, and (3) fluid handling services that are used to move, store and dispose of fluids that are involved in the development and production of oil and gas reservoirs.
 
  •  Drilling Services. Through our drilling services segment, we provide land drilling, specialized rig logistics and site preparation for oil and gas exploration and production companies.
 
  •  Product Sales. Through our product sales segment, we sell oil and gas field equipment, including completion, flow control and artificial lift equipment, as well as tubular goods.
      Substantially all of the service and rental revenue we earn is based upon a charge for a relatively short period of time (an hour, a day, a week) for the actual period of time the service or rental is provided to our customer. By contracting services on a short-term basis, we are exposed to the risks of a rapid reduction in market prices and utilization and volatility in our revenues. Product sales are recorded when

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the actual sale occurs and title or ownership passes to the customer and the product is shipped or delivered to the customer.
      Our customers include large multi-national and independent oil and gas producers, as well as smaller independent producers and the major land-based drilling contractors in North America (see “Business – Customers”). The primary factor influencing demand for our services and products is the level of drilling and workover activity of our customers, which in turn, depends on current and anticipated future oil and gas prices, production depletion rates and the resultant levels of cash flows generated and allocated by our customers to their drilling and workover budgets. As a result, demand for our services and products is cyclical, substantially depends on activity levels in the North American oil and gas industry and is highly sensitive to current and expected oil and natural gas prices. The following tables summarize average North American drilling and well service rig activity, as measured by Baker Hughes Incorporated (“BHI”), and historical commodity prices as provided by Bloomberg:
AVERAGE RIG COUNTS
                                                   
    Nine Months   Nine Months                
    Ended   Ended   Year Ended   Year Ended   Year Ended   Year Ended
BHI Rotary Rig Count:   9/30/05   9/30/04   12/31/04   12/31/03   12/31/02   12/31/01
                         
U.S. Land
    1,254       1,077       1,095       924       717       1,003  
U.S. Offshore
    97       96       97       108       113       153  
                                     
 
Total U.S. 
    1,351       1,173       1,192       1,032       830       1,156  
Canada
    416       346       365       372       263       341  
Mexico
    112       110       110       92       65       54  
                                     
 
Total North America
    1,879       1,629       1,667       1,496       1,158       1,551  
                                     
BHI Workover Rig Count:
                                               
 
United States
    1,320       1,215       1,235       1,129       1,010       1,211  
Canada
    613       574       615       350       261       342  
                                     
 
Total U.S. and Canada
    1,933       1,789       1,850       1,479       1,271       1,553  
                                     
 
Source: BHI (www.BakerHughes.com)
AVERAGE OIL AND GAS PRICES
                 
 
    Average Daily Closing   Average Daily Closing
    Henry Hub Spot Natural   WTI Cushing Spot Oil
Period   Gas Prices ($/mcf)   Price ($/bbl)
         
 
1/1/99 - 12/31/99
  $ 2.27     $ 19.30  
1/1/00 - 12/31/00
    4.30       30.37  
1/1/01 - 12/31/01
    3.96       25.96  
1/1/02 - 12/31/02
    3.37       26.17  
1/1/03 - 12/31/03
    5.49       31.06  
1/1/04 - 12/31/04
    5.90       41.51  
1/1/05 - 9/30/05
    7.75       55.46  
 
 
Source: Bloomberg NYMEX prices.
      We consider the number of drilling and well service rig counts to be an indication of spending by our customers in the oil and gas industry for exploration and development of new and existing hydrocarbon reserves. These spending levels are a primary driver of our business, and we believe that our customers

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tend to invest more in these activities when oil and gas prices are at higher levels or are increasing. We evaluate the utilization of our assets as a measure of operating performance. This utilization can be impacted by these and other external and internal factors. See “Risk Factors.”
      We generally charge for our services on a dayrate basis. Depending on the specific service, a dayrate may include one or more of these components: (1) a set-up charge, (2) an hourly service rate based on equipment and labor, (3) an equipment rental charge, (4) a consumables charge, and (5) a mileage and fuel charge. We generally determine the rates charged through a competitive process on a job-by-job basis. Typically, work is performed on a “call out” basis, whereby the customer requests services on a job-specific basis, but does not guarantee work levels beyond the specific job bid. For contract drilling services, fees are charged based on standard dayrates or, to a lesser extent, as negotiated by footage or through turnkey contracts. Product sales are generated through our supply stores and through wholesale distributors, using a purchase order process and a pre-determined price book.
Outlook
      Our growth strategy includes a focus on internal growth in our current basins by adding additional like kind equipment, expanding service and product offerings and, to a lesser extent, by increasing equipment utilization. In addition, we identify new basins in which to replicate this approach. We also augment our internal growth through strategic acquisitions.
  •  Internal Capital Investment. Our internal expansion activities generally consist of adding equipment and qualified personnel in locations where we have established a presence. We expect to grow our operations in each of these locations by expanding services to current customers, attracting new customers and hiring local personnel with local basin-level expertise and leadership recognition. Depending on customer demand, we will consider adding equipment to further increase the capacity of services currently being provided and/or add equipment to expand the services we provide. We invested $64.8 million in equipment additions over the three-year period ended December 31, 2004, which included $46.4 million for the completion and production services segment, $14.5 million for the drilling services segment and $3.9 million for the product sales segment. We invested an additional $84.9 million during the nine months ended September 30, 2005, of which $52.2 million related to the completion and production services segment, $29.3 million related to the drilling services segment, $1.5 million related to the product sales segment and $1.9 million related to general corporate operations.
 
  •  External Growth. We use strategic acquisitions as an integral part of our growth strategy. We consider acquisitions that will add to our service offerings in a current operating area or that will expand our geographical footprint into a targeted basin. We have completed several acquisitions in recent years. These acquisitions affect our operating performance period to period. Accordingly, comparisons of revenue and operating results are not necessarily comparable and should not be relied upon as indications of future performance. We have invested an aggregate of $336.9 million in acquisitions over the three-year period ended December 31, 2004 and an additional aggregate of $47.0 million during the nine months ended September 30, 2005.
Significant Acquisitions
  •  Integrated Production Services Ltd. On July 3, 2002, we acquired Integrated Production Services Ltd., a western Canada-based integrated well service company providing wireline, production testing and production optimization services in western Canada. This acquisition was completed through a series of transactions, in which we paid $29.5 million in cash in July 2002 and an additional $20.0 million in cash in October 2002. This acquisition was an important addition to our completion and production services segment, as it provided a platform to expand our business into the Canadian oilfield services market. We recorded $28.7 million of goodwill related to this acquisition.
 
  •  BSI. On November 7, 2003, we acquired BSI Holdings Management, LLC and BSI Holdings, L.P. and related parties (“BSI”) for $50.1 million in cash, and issued common stock totaling

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  $8.5 million. This acquisition provided us with a base of business in the Barnett Shale region of north Texas. BSI is an integrated provider of drilling, completion and production services in the oil and gas industry and sells various products used in the production of oil and gas. We recorded $14.4 million of goodwill related to this acquisition.
 
  •  I.E. Miller. On August 31, 2004, we acquired all the outstanding membership interests of I.E. Miller of Eunice (Texas) No. 2, L.L.C. and certain related entities (“I.E. Miller”) for $13.6 million in cash and issued common stock totaling $12.5 million. This acquisition was an important addition to our drilling services business, as I.E. Miller specializes in rig logistics. We recorded $8.5 million of goodwill associated with this acquisition.
 
  •  Hyland Enterprises, Inc. On September 3, 2004, we acquired Hyland Enterprises, Inc., a Wyoming-based fluid-handling and oilfield equipment rental company, for $17.7 million in cash, the issuance of common stock totaling $6.6 million and certain additional acquisition costs totaling $1.2 million. This acquisition expanded our completion and production services segment in the U.S. Rocky Mountain region. We recorded $5.5 million of goodwill related to this acquisition.
 
  •  Hamm Co. On October 14, 2004, we acquired Hamm and Phillips Service Company, Inc. and certain other entities (“Hamm Co.”), an Oklahoma-based fluid-handling, well-servicing and oilfield equipment rental company, for $48.1 million in cash, the issuance of common stock totaling $37.0 million and certain additional acquisition costs totaling $2.8 million. This acquisition expanded our completion and production services segment into the U.S. Mid-Continent region and provided additional heavy equipment hauling capability for the drilling services segment. We recorded $33.8 million of goodwill related to this acquisition.
 
  •  Parchman Energy Group, Inc. On February 11, 2005, we acquired Parchman Energy Group, Inc. (“Parchman”) for $9.8 million in cash, the issuance of common stock totaling $19.1 million, the issuance of a subordinated note totaling $5.0 million and the potential issuance of 500,000 shares of our common stock based upon certain operating results. Parchman performs intervention services and downhole services including coiled tubing, production testing and wireline services, and operates from locations in Texas, Louisiana and Mexico. We recorded $22.0 million of goodwill related to this acquisition.
 
  •  Big Mac. On November 1, 2005, we acquired all of the outstanding equity interests of the Big Mac group of companies (Big Mac Transports, LLC, Big Mac Tank Trucks, LLC and Fugo Services, LLC) for $40.8 million in cash. The Big Mac group of companies (“Big Mac”) is based in McAlester, Oklahoma, and provides fluid handling services primarily to customers in eastern Oklahoma and western Arkansas. Big Mac’s principal assets consist of rolling stock and frac tanks. The purchase price, which is subject to a post-closing adjustment for actual working capital and reimbursable capital expenditures as of the closing date, has not yet been finalized. Based on preliminary analysis, we expect to record between $20 million and $25 million of goodwill in connection with this acquisition. We will include the operating results of Big Mac in the completion and production services business segment from the date of acquisition. We believe that this acquisition provides a platform to enter the eastern Oklahoma market and new Fayetteville Shale play in Arkansas.
      In addition, we completed several other smaller acquisitions during the years ended December 31, 2004, 2003 and 2002, and during the nine months ended September 30, 2005 each of which has contributed to the expansion of our business into new geographic regions or enhanced our service and product offerings.
      We have accounted for these acquisitions using the purchase method of accounting, whereby the purchase price is allocated to the fair value of net assets acquired, including intangibles and property, plant and equipment at depreciated replacement costs with the excess to goodwill, with the exception of the merger of Integrated Production Services Ltd., and another predecessor company in 2002, which was accounted for using the continuity of interest method of accounting, a treatment similar to a pooling of

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interests. Results of operations related to each of the acquired companies have been included in our combined operations as of the date of acquisition.
Marketing Environment
      We operate in a highly competitive industry. Our competition includes many large and small oilfield service companies. As such, we price our services and products to remain competitive in the markets in which we operate, adjusting our rates to reflect current market conditions as necessary. We examine the rate of utilization of our equipment as one measure of our ability to compete in the current market environment.
Seasonality
      We generally experience a decline in sales for our Canadian operations during the second quarter of each year due to seasonality, as weather conditions make oil and gas operations in this region difficult during this period. Our Canadian operations accounted for approximately 15% of total revenues during 2004.
Critical Accounting Policies and Estimates
      The preparation of our consolidated financial statements in conformity with GAAP requires the use of estimates and assumptions that affect the reported amount of assets, liabilities, revenues and expenses, and related disclosure of contingent assets and liabilities. We base our estimates on historical experience and on various other assumptions that we believe are reasonable under the circumstances, and provide a basis for making judgments about the carrying value of assets and liabilities that are not readily available through open market quotes. Estimates and assumptions are reviewed periodically, and actual results may differ from those estimates under different assumptions or conditions. We must use our judgment related to uncertainties in order to make these estimates and assumptions.
      In the selection of our critical accounting policies, the objective is to properly reflect our financial position and results of operations for each reporting period in a consistent manner that can be understood by the reader of our financial statements. Our accounting policies and procedures are explained in note 1 of the notes to the consolidated financial statements contained elsewhere in this prospectus. We have identified the following as the most critical accounting policies which may have a significant effect on our reported financial results.
  •  Continuity of Interests Accounting. We applied the provisions of Statement of Financial Accounting Standards (“SFAS”) No. 141. “Business Combinations” to account for the formation of Complete. SFAS No. 141 permits us to account for the combination of several predecessor companies using a method similar to a pooling of interests if each is controlled by a common stockholder. In connection with the Combination, we paid a dividend to our stockholders of $5.24 per share and adjusted the number of shares subject to, and exercise price of, outstanding stock options and restricted shares in accordance with Financial Accounting Standards Board (“FASB”) Interpretation No. 44. “Accounting for Certain Transactions Involving Stock Compensation, an Interpretation of Accounting Principles Board (“APB”) Opinion No. 25.” On September 12, 2005, we completed the transaction, pursuant to which CES and IEM stockholders exchanged all of their common stock for common stock of IPS. CES stockholders received 19.704 shares of IPS for each share of CES, and IEM stockholders received 19.410 shares of IPS for each share of IEM. In connection with the Combination, IPS changed its name to Complete Production Services, Inc. We acquired the interests of the minority stockholders in these predecessor companies as of the date of the consummation and accounted for these transactions using the purchase method of accounting, resulting in goodwill of $38.4 million, which represented the excess of the purchase price over the carrying value of the net assets acquired.
 
  •  Revenue Recognition. We recognize service revenue as services are performed and when realized or earned. Revenue is deemed to be realized or earned when we determine that the following

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  criteria are met: (1) persuasive evidence of an arrangement exists; (2) delivery has occurred or services have been rendered; (3) the fee is fixed or determinable; and (4) collectibility is reasonably assured. These services are generally provided over a relatively short period of time pursuant to short-term contracts at pre-determined day-rate fees, or on a day-to-day basis. Revenue and costs related to drilling contracts are recognized as work progresses. Progress is measured as revenue is recognized based upon day rate charges. For certain contracts, we may receive lump-sum payments from our customers related to the mobilization of rigs and other drilling equipment. Under these arrangements, we defer revenues and the related cost of services and recognize them over the term of the drilling contract. Costs incurred to relocate rigs and other drilling equipment to areas in which a contract has not been secured are expensed as incurred. Revenues associated with product sales are recorded when product title is transferred to the customer.
 
  •  Impairment of Long-Lived Assets. We evaluate potential impairment of long-lived assets and intangibles, excluding goodwill and other intangible assets without defined services lives, when indicators of impairment are present, as defined in SFAS No. 144. If such indicators are present, we project the fair value of the assets by estimating the undiscounted future cash in-flows to be derived from the long-lived assets over their remaining estimated useful lives, as well as any salvage value. Then, we compare this fair value estimate to the carrying value of the assets and determine whether the assets are deemed to be impaired. For goodwill and other intangible assets without defined service lives, we apply the provisions of SFAS No. 142, which requires an annual impairment test, whereby we estimate the fair value of the asset by discounting future cash flows at our projected cost of capital rate. If the fair value estimate is less than the carrying value of the asset, an additional test is required whereby we apply a purchase price analysis consistent with that described in SFAS No. 141. If impairment is still indicated, we would record an impairment loss in the current reporting period for the amount by which the carrying value of the intangible asset exceeds its projected fair value. Our industry is highly cyclical and the estimate of future cash flows requires the use of assumptions and our judgment. Periods of prolonged down cycles in the industry could have a significant impact on the carrying value of these assets and may result in impairment charges.
 
  •  Stock Options. We have issued stock-based compensation to certain employees, officers and directors in the form of stock options. We account for these stock options by applying APB Opinion No. 25, “Accounting for Stock Issued to Employees,” which does not require us to recognize compensation expense related to these employee stock options when the exercise price of the option is at least equal to the market value of the stock on the date of grant. Accordingly, we have not recognized compensation expense related to our stock options issued. We have, however, included potential common shares associated with our stock option awards in the calculation of diluted shares outstanding in order to determine diluted earnings per share. We are not required to account for our stock-based compensation plans using the fair value recognition provision of SFAS No. 123, “Accounting for Stock-Based Compensation.” Accounting for these stock options using the fair value recognition provisions of SFAS No. 123 would negatively impact our financial position and results of operations, as it requires that the fair value of stock options issued be estimated using pricing models, which require the application of highly subjective assumptions that have an inherent degree of uncertainty, and require us to expense over the vesting period of the related options. In December 2004, the FASB issued SFAS No. 123R, “Share-Based Payment,” which revises SFAS No. 123 and supercedes APB Opinion No. 25. SFAS No. 123R will require us to measure the cost of employee services received in exchange for an award of equity instruments based on the grant-date fair value of the award, with limited exceptions. SFAS No. 123R becomes effective for us as of January 1, 2006. We are currently evaluating the impact that this statement will have on our financial position, results of operations and cash flows. We expect to incur expenses related to our stock options for each reporting period subsequent to our adoption of SFAS No. 123R in the first quarter of 2006.

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  •  Allowance for Bad Debts and Inventory Obsolescence. We record trade accounts receivable at billed amounts, less an allowance for bad debts. Inventory is recorded at cost, less an allowance for obsolescence. To estimate these allowances, management reviews the underlying details of these assets as well as known trends in the marketplace, and applies historical factors as a basis for recording these allowances. If market conditions are less favorable than those projected by management, or if our historical experience is materially different from future experience, additional allowances may be required.
 
  •  Property, Plant and Equipment. We record property, plant and equipment at cost less accumulated depreciation. Major betterments to existing assets are capitalized, while repairs and maintenance costs that do not extend the service lives of our equipment are expensed. We determine the useful lives of our depreciable assets based upon historical experience and the judgment of our operating personnel. We generally depreciate the historical cost of assets, less an estimate of the applicable salvage value, on the straight-line basis over the applicable useful lives, except office furniture and computers, which are depreciated using the declining balance method. Upon disposition or retirement of an asset, we record a gain or loss if the proceeds from the transaction differ from the net book value of the asset at the time of the disposition or retirement. If our depreciation estimates are not correct, we may record a disproportionate amount of gains or losses upon disposition of these assets. We believe our estimates of useful lives are materially correct.
 
  •  Deferred Income Taxes. Our income tax expense includes income taxes related to the United States, Canada and other foreign countries, including local, state and provincial income taxes. We account for tax ramifications using SFAS No. 109, “Accounting for Income Taxes.” Under SFAS No. 109, we record deferred income tax assets and liabilities based upon temporary differences between the carrying amount and tax basis of our assets and liabilities and measure tax expense using enacted tax rates and laws that will be in effect when the differences are expected to reverse. The effect of a change in tax rates is recognized in income in the period of the change. Furthermore, SFAS No. 109 requires us to record a valuation allowance for any net deferred income tax assets which we believe are likely to not be used through future operations. As of September 30, 2005, we had recorded a total valuation allowance of $0.7 million related to certain deferred tax assets in Canada. If our estimates and assumptions related to our deferred tax position change in the future, we may be required to record additional valuation allowances against our deferred tax assets and our effective tax rate may increase, which could result in a material adverse effect on our financial position, results of operations and cash flows. As of December 31, 2004, no deferred U.S. income taxes have been provided on the approximately $7.3 million of undistributed earnings of foreign subsidiaries in which we intend to indefinitely reinvest. Upon distribution of these earnings in the form of dividends or otherwise, we may be subject to U.S. income taxes and foreign withholding taxes.

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      The following table describes estimates, assumptions and methods regarding critical accounting policies used to prepare our consolidated financial statements. We consider an estimate to be critical if it is subjective and if changes in the estimate using different assumptions would result in a material impact on our financial position or results of operations:
         
Description   Estimates/Assumptions Used   Variability in Accounting
         
Revenue Recognition   We recognize revenue when realizable and earned as services are performed or as risk of ownership and physical possession passes to the buyer. We defer unearned revenue until earned. Any reimbursements of mobilization charges are amortized over the contract involved.   There is a risk that we may not record revenue in the proper period.
Impairment of Long-lived Assets
  We evaluate the recoverability of assets periodically, but at least annually for goodwill and intangible assets with indefinite lives, by reviewing operational performance and expected cash flows. Our management estimates future cash flows for this purpose and for intangible assets, discounts these cash flows at an applicable rate.   There is a risk that management’s estimates of future performance may not approximate actual performance or that rates used for discounting cash flows are not consistent with the actual discount rates. Our assets could be overstated if impairment losses are not identified timely.
Allowance for Bad Debts and Obsolete Inventory
  We estimate the recoverability of receivables and inventory on an individual basis based upon historical experience and management’s judgement.   There is a risk that management may not detect uncollectible accounts or unsalvageable inventory in the correct accounting period.
Property, Plant and Equipment
  Our management estimates useful lives of depreciable equipment and salvage values. The depreciation method used is generally the straight-line method, except for furniture and office equipment which is depreciated on an accelerated basis.   GAAP permits various depreciation methods to recognize the use of assets. Use of a different depreciation method or different depreciable lives could result in materially different results. The estimated useful lives are consistent with industry averages. There is a risk that the asset’s useful life used for our depreciation calculation will not approximate the actual useful life of the asset.

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Description   Estimates/Assumptions Used   Variability in Accounting
         
Valuation Allowance for Income Taxes
  We apply the provisions of SFAS No. 109 to account for income taxes. Differences between depreciation methods used for financial reporting purposes compared to tax purposes as well as other items, including loss carry forwards and valuation allowances against deferred tax assets, require management’s judgment related to the realizability of deferred tax accounts.   There is a risk that estimates related to the use of loss carry forwards and the realizability of deferred tax accounts may be incorrect, and that the result could materially impact our financial position and results of operations. In addition, future changes in tax laws could result in additional valuation allowances.
Stock Options
  We apply the provisions of APB No. 25 to account for stock options and estimate compensation expense that would be required to be recognized under SFAS No. 123 for pro forma footnote disclosures. The determination of the fair value of stock options requires subjective estimates of variables used in a pricing model, including stock volatility, dividend rate, risk-free interest rate and expected term of options.   GAAP permits the use of various models to determine the fair value of stock options and the variables used for the model are highly subjective. The use of different assumptions or a different model may have a material impact on our financial disclosures.
Results of Operations
      The following tables set forth our results of operations, including amounts expressed as a percentage of total revenue, for the periods indicated (in thousands, except percentages).
                                                           
                    Percent       Percent
                Change   Change   Change   Change
                2004/   2004/   2003/   2003/
    2004   2003   2002   2003   2003   2002   2002
                             
Revenue:
                                                       
Completion and production services
  $ 194,953     $ 65,025     $ 30,110     $ 129,928       200 %   $ 34,915       116 %
Drilling services
    44,474       2,707             41,767       NM       2,707       NM  
Product sales
    81,320       35,547       10,494       45,773       129 %     25,053       239 %
                                           
 
Total
  $ 320,747     $ 103,279     $ 40,604     $ 217,468       211 %   $ 62,675       154 %
                                           
EBITDA:
                                                       
Completion and production services
  $ 38,349     $ 9,134     $ 3,058     $ 29,215       320 %   $ 6,076       199 %
Drilling services
    10,093       712             9,381       NM       712       NM  
Product sales
    12,924       4,951       1,251       7,973       161 %     3,700       296 %
Corporate
    (2,869 )     (1,233 )           (1,636 )     133 %     (1,233 )     NM  
                                           
 
Total
  $ 58,497     $ 13,564     $ 4,309     $ 44,933       331 %   $ 9,255       215 %
                                           

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    Nine   Nine       Percent
    Months   Months   Change   Change
    Ended   Ended   2005/   2005/
    9/30/05   9/30/04   2004   2004
                 
Revenue:
                               
Completion and production services
  $ 351,154     $ 112,611     $ 238,543       212 %
Drilling services
    89,016       23,820       65,196       274 %
Product sales
    85,066       58,962       26,104       44 %
                         
 
Total
  $ 525,236     $ 195,393     $ 329,843       169 %
                         
EBITDA:
                               
Completion and production services
  $ 82,615     $ 21,939     $ 60,676       277 %
Drilling services
    27,658       5,104       22,554       442 %
Product sales
    11,131       10,199       932       9 %
Corporate
    (10,859 )     (3,322 )     (7,537 )     227 %
                         
 
Total
  $ 110,545     $ 33,920     $ 76,625       226 %
                         
 
“NM” denotes not meaningful.
“Corporate” includes amounts related to corporate personnel costs and other general expenses.
“EBITDA” consists of net income (loss) before interest expense, taxes, depreciation and amortization and minority interest. EBITDA is a non-cash measure of performance. We use EBITDA as the primary internal management measure for evaluating performance and allocating additional resources. See the discussion of EBITDA at note 2 to “Selected Consolidated Financial Data.”
      Our revenue and EBITDA results for the indicated periods generally increased due to the contribution of companies acquired and an increase in oilfield activity in North America as a result of higher commodity prices throughout the applicable periods.
      For a reconciliation of EBITDA, please see “Selected Consolidated Financial Data – Reconciliation of EBITDA.”
      Below is a more detailed discussion of our operating results by segment for these periods.
Nine Months Ended September 30, 2005 Compared to the Nine Months Ended September 30, 2004 (Unaudited)
Revenue
      Revenue for the nine months ended September 30, 2005 increased by 169%, or $329.8 million, to $525.2 million from $195.4 million for the nine months ended September 30, 2004. This increase by segment was as follows:
  •  Completion and Production Services. Segment revenue increased $238.5 million and resulted primarily from: (1) the acquisition of Hyland Enterprises, Inc. in September 2004, which contributed $44.4 million in 2005; (2) the acquisition of Hamm Co. in October 2004, which contributed $57.9 million; (3) the acquisition of Parchman in February 2005, which contributed $54.8 million; (4) several other smaller acquisitions in late 2004, which contributed revenues for a full nine-month period in 2005; and (5) an incremental increase in revenues earned as a result of additional capital investment in the well servicing, rental and fluid-handling businesses, as well as an improved pricing environment for our services and products.
 
  •  Drilling Services. Segment revenue increased $65.2 million, primarily related to an increase associated with acquisitions of $45.2 million, substantially contributed by the acquisition of IEM in September 2004. In addition, the segment benefited from increased prices for our services and increased oilfield activity, which provided incremental revenues of $20.0 million, achieved in part

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  through additional investment in drilling rigs and drilling logistics equipment for operations located in the Barnett Shale region of north Texas.
 
  •  Product Sales. Segment revenue increased $26.1 million, fueled by an incremental increase in supply store sales of $14.5 million, a $8.9 million incremental increase in sales of surface production equipment in Canada, improved sales in other international locations and an increase in the sale of flow control products. These increased product sales reflect the overall improved market conditions.
Service and Product Expenses
      Service and product expenses include labor costs associated with the execution and support of our services, materials used in the performance of those services and other costs directly related to the support and maintenance of equipment. These expenses increased 154%, or $203.7 million, for the nine months ended September 30, 2005, to $336.3 million from $132.6 million for the nine months ended September 30, 2004. As a percentage of revenues, service and product expenses were 64% for the first nine months of 2005 compared to 68% for the respective period in 2004. The decline in service and product expenses as a percentage of revenue reflected a favorable mix of services and products and improved prices, as more revenue was earned in 2005 from higher margin basins and related services in the United States, and increasing customer demand for our services. By segment, service and product expenses as a percentage of revenues for the nine months ended September 30, 2005 and 2004 were 63% and 65%, respectively, for the completion and production services segment; 57% and 70%, respectively, for the drilling services segment; and 76% and 71%, respectively, for the product sales segment.
Selling, General and Administrative Expenses
      Selling, general and administrative expenses consist primarily of salaries and other related expenses for our administrative, finance, information technology and human resource functions. Selling, general and administrative expenses increased 162%, or $46.7 million, for the nine months ended September 30, 2005, to $75.5 million from $28.8 million during the same period in 2004. This increase was primarily due to acquisitions, which provided additional headcount and general expenses. As a percentage of revenues, selling, general and administrative expense was 14% and 15% for the nine-month periods ended September 30, 2005 and 2004, respectively.
Depreciation and Amortization
      Depreciation and amortization expense increased 166%, or $20.5 million, to $32.9 million for the nine months ended September 30, 2005, from $12.4 million during the same period in 2004. The increase in depreciation and amortization expense was the result of equipment and intangible assets acquired through capital expenditures and purchase acquisitions. As a percentage of revenue, depreciation and amortization expense was 6% for the nine months ended September 30, 2005 and 2004.
Interest Expense
      Interest expense was $15.6 million for the nine months ended September 30, 2005, compared to $4.5 million for the respective period in 2004. The increase in interest expense was attributable to an increase in the average amount of debt outstanding as a result of acquisitions and capital expenditures completed in 2004 and the first nine months of 2005. The weighted-average interest rate outstanding has remained relatively consistent at 6.7% and 6.0% at September 30, 2005 and 2004, respectively.
Taxes
      Tax expense is comprised of three components: capital and franchise taxes, current income taxes and deferred income taxes. The capital and franchise tax component is generally based on our capital base and does not correlate to pretax income. The current and deferred taxes added together provide an indication of an effective rate of income tax.

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      Tax expense was 38.5% and 38.3% of pretax income for the nine-month periods ended September 30, 2005 and 2004, respectively.
Year Ended December 31, 2004 Compared to the Year Ended December 31, 2003
Revenue
      Revenue for the year ended December 31, 2004 increased by 211%, or $217.5 million, to $320.7 million from $103.3 million for the year ended December 31, 2003. This increase by segment was as follows:
  •  Completion and Production Services. Segment revenue increased $129.9 million and resulted primarily from: (1) the acquisition of BSI in late 2003, which contributed $40.2 million of incremental revenues in 2004, of which $20.9 million was derived from a full-year’s operation in 2004 and $16.1 million was derived from investment in capital equipment; (2) the acquisition of eleven smaller companies throughout 2004 which contributed to 2004 revenue totals but did not contribute to operating results in 2003; and (3) a general increase in the use of our services attributable to more favorable oilfield activity levels associated with rising commodity prices.
 
  •  Drilling Services. Segment revenue increased $41.8 million. Of this increase, $18.9 million was provided through acquisitions, and more specifically, the acquisition of BSI in late 2003, which contributed $17.7 million of incremental revenues in 2004, and the Hamm Co. acquisition completed in late 2004, which provided an additional $1.2 million of drilling revenues. The remaining revenue increase in 2004 relative to 2003 was due to additional investment in drilling rigs for operations located in the Barnett Shale region of north Texas.
 
  •  Product Sales. Segment revenue increased $45.8 million, of which $31.2 million was derived from the product sales component of BSI’s acquisition and a general increase in product sales from existing operations as a result of improved market conditions in the oil and gas industry, including higher international sales and, in particular, sales of surface production equipment in Canada, and increased sales of flow control equipment.
Service and Product Expenses
      Service and product expenses increased by 196%, or $143.0 million, for the year ended December 31, 2004, to $216.2 million from $73.1 million for the year ended December 31, 2003. As a percentage of revenues, service and product expenses were 67% in 2004 compared to 71% in 2003. The decline in service and product expenses as a percentage of revenue reflected a favorable mix of products and strong prices, as more revenue was earned in 2004 from higher margin basins and related services in the United States, and increasing customer demand for oilfield service providers’ services. By segment, service and product expenses as a percentage of revenues for the years ended December 31, 2004 and 2003 were 65% and 70%, respectively, for the completion and production services segment; 70% and 70%, respectively, for the drilling services segment; and 72% and 73%, respectively, for the product sales segment. Overall declines in service and product expense as a percentage of revenues for the completion and production services and product sales segments yielded better operating margins.
Selling, General and Administrative Expenses
      Selling, general and administrative expense for the year ended December 31, 2004 increased by 178%, or $29.5 million, to $46.1 million from $16.6 million for the year ended December 31, 2003. This increase was primarily due to additional headcount and general expenses added as a result of acquisitions. Selling, general and administrative expense as a percentage of revenues was 14% in 2004 as compared to 16% in 2003.

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Depreciation and Amortization
      Depreciation and amortization expense increased 183%, or $14.0 million, to $21.6 million, for the year ended December 31, 2004 compared to $7.6 million for the year ended December 31, 2003. We increased our property, plant and equipment through acquisitions and capital expenditures throughout the two years ended December 31, 2004, as gross book value increased to $268.8 million at December 31, 2004 compared to $109.1 million at December 31, 2003. This higher depreciable base resulted in an increase in depreciation expense during these years. In addition, we acquired certain intangible assets that were amortized in 2004 after the date of acquisition. As a percentage of revenue, depreciation and amortization was 7% in 2004 and in 2003.
Interest Expense
      Interest expense was $7.5 million for the year ended December 31, 2004 compared to $2.7 million for the year ended December 31, 2003. The increase in interest expense was consistent with increased levels of bank debt used to finance acquisitions and capital expenditures. We did not experience any significant changes in interest rates for the years ended December 31, 2004 and 2003.
Taxes
      Tax expense was 36.8% and 46.6% of pretax income for the years ended December 31, 2004 and 2003, respectively. These rates reflected the mix of tax rates in the jurisdictions in which we operated. In particular, in 2003 there was a Large Corporation’s Tax and Capital Tax of approximately $0.3 million that was payable under Canadian tax law.
Year Ended December 31, 2003 Compared to the Year Ended December 31, 2002
Revenue
      Revenue for the year ended December 31, 2003 increased by 154%, or $62.7 million, to $103.3 million from $40.6 million in the year ended December 31, 2002. This increase by segment was as follows:
  •  Completion and Production Services. Segment revenue increased $34.9 million and resulted primarily from: (1) the acquisition of Integrated Production Services Ltd. in July 2002, which contributed incremental revenues of $22.5 million in 2003; (2) the acquisition of BSI in late-2003, which contributed $3.2 million of revenue included in the 2003 results; and (3) a general increase in demand by our customers for our wireline services in the U.S. Gulf Coast region and higher Canadian activity levels.
 
  •  Drilling Services. Segment revenue was $2.7 million in 2003. Prior to 2003, we did not provide drilling services. We began offering these services with the acquisition of BSI in late 2003.
 
  •  Product Sales. Segment revenue increased $25.1 million, of which $20.2 million represented an incremental increase in product sales due to the acquisition of Integrated Production Services Ltd. in July 2002, the acquisition of BSI in November 2003, and the acquisition of Canadian-based Ess-Ell Tools, a provider of flow control products, in March 2003.
Service and Product Expenses
      Service and product expenses increased by 156%, or $44.6 million, for the year ended December 31, 2003, to $73.1 million from $28.5 million for the year ended December 31, 2002. This increase was consistent with an increase in revenues of 154% for the respective periods. As a percentage of revenues, service and product expenses were 71% and 70% for the years ended December 31, 2003 and 2002, respectively. By segment, service and product expenses as a percentage of revenues for the years ended December 31, 2003 and 2002 were 70% and 70%, respectively, for the completion and production services segment; and 73% and 70%, respectively, for the product sales segment. The drilling services segment

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began contributing to operations in 2003, but had no operations in 2002. Service and product expenses as percentage of revenues for the drilling services segment in 2003 were 70%. Improved margins reflected an overall increase in oilfield activity in 2003 compared to 2002.
Selling, General and Administrative Expenses
      Selling, general and administrative expenses increased 114%, or $8.8 million, for the year ended December 31, 2003, to $16.6 million from $7.8 million for the year ended December 31, 2002. As a percentage of revenue, selling, general and administrative expense was 16% and 19% for the years ended December 31, 2003 and 2002, respectively. This decline in selling, general and administrative expense as a percentage of revenues reflected efficiencies achieved in the centralization of certain administrative functions and a slower growth rate for headcount relative to revenues.
Depreciation and Amortization
      Depreciation and amortization increased to $7.6 million for the year ended December 31, 2003, compared to $4.2 million for the year ended December 31, 2002, reflecting an increase in the base cost of property, plant and equipment as well as intangible assets in 2003, compared to 2002 through acquisitions and capital expenditures. As a percentage of revenue, depreciation and amortization declined from 10% in 2002 to 7% in 2003. This decline in depreciation as a percentage of revenue reflected improved equipment utilization, as we were able to more effectively deploy our assets to customer locations on a timely basis.
Interest Expense
      Interest expense was $2.7 million for the year ended December 31, 2003 and $1.3 million for the year ended December 31, 2002. The increase in interest expense was consistent with increased levels of bank debt used to finance acquisitions and capital expenditures. We did not experience any significant changes in interest rates between years.
Taxes
      Tax expense was 46.6% for the year ended December 31, 2003. In 2003, there was a Large Corporation’s Tax and Capital Tax of approximately $0.3 million that was payable under Canadian tax law. In 2002, we had an income tax recovery as a result of an operating loss.
Liquidity and Capital Resources
      Our primary liquidity needs are to fund capital expenditures, such as expanding our coiled tubing, wireline and production testing fleets, building new drilling rigs, increasing and replacing rental tool and well service rigs and snubbing units, funding new product development and funding general working capital needs. In addition, we need capital to fund strategic business acquisitions. Our primary sources of funds have historically been cash flow from operations, proceeds from borrowings under bank credit facilities and the issuance of equity securities, primarily associated with acquisitions. Upon completion of this offering, we anticipate that we will rely on cash generated from operations, borrowings under our revolving credit facility, future debt offerings and future public equity to satisfy our liquidity needs. We believe that funds from these sources should be sufficient to meet both our short-term working capital requirements and our long-term capital requirements. Our ability to fund planned capital expenditures and to make acquisitions will depend upon our future operating performance, and more broadly, on the availability of equity and debt financing, which will be affected by prevailing economic conditions in our industry, and general financial, business and other factors, some of which are beyond our control.

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      The following table summarizes cash flows by type for the periods indicated (in thousands):
                                           
    Nine Months Ended    
    September 30,   Year Ended December 31,
         
    2005   2004   2004   2003   2002
                     
Cash flows provided by (used in):
                                       
 
Operating activities
  $ 48,471     $ 15,467     $ 34,622     $ 13,965     $ (8 )
 
Financing activities
    58,566       83,404       157,630       55,281       36,279  
 
Investing activities
    (99,145 )     (99,867 )     (186,776 )     (66,214 )     (35,616 )
      Net cash provided by operating activities increased $33.0 million for the nine months ended September 30, 2005, compared to the nine months ended September 30, 2004. This increase reflected a $27.8 million increase in net income and a $5.2 million increase in non-cash items, including $20.5 million related to depreciation, offset by a $24.0 million increase in working capital. In general, our gross receipts increased during 2005 as demand for our services grew, resulting in more billable hours and more favorable billing rates, while we expanded our current business and entered new markets through acquisitions and capital investment. The increase in billings resulted in higher revenues and net income, and depreciation expense increased as we began to depreciate new equipment that we purchased. The increase in working capital resulted primarily from higher accounts receivable balances associated with higher revenues. For the years ended December 31, 2004, 2003 and 2002, cash flows from operating activities continued to trend higher on this basis, as a result of growing our business through acquisitions and investment in capital expenditures and general improvements in activity levels and pricing.
      Net cash provided by financing activities declined $24.8 million for the nine months ended September 30, 2005 compared to the nine months ended September 30, 2004. This decline reflects the use of cash generated by operating activities to fund capital investment during the first nine months of 2005, rather than the use of debt financing, the primary source of funds for expansion during the first nine months of 2004. Increases in borrowings under our new term loan facility were offset by repayments of long-term debt outstanding under prior facilities and the payment of a one-time dividend to stockholders of $146.9 million. For the years ended December 31, 2004, 2003 and 2002, net cash provided by financing activities increased as we borrowed under existing credit arrangements and through seller financing to finance our investment in capital expenditures and acquisitions. Our long-term debt balances, including current maturities, were $457.9 million, $201.8 million and $67.7 million as of September 30, 2005, December 31, 2004 and December 31, 2003, respectively.
      Net cash used in investing activities decreased by $0.7 million for the nine months ended September 30, 2005, compared to the nine months ended September 30, 2004. We acquired several companies during the first nine months of 2004 for a total use of cash of $75.1 million, but fewer acquisitions during the first nine months of 2005 for a total use of cash of $18.2 million. This decrease in cash used for acquisitions was offset by an incremental increase in capital equipment expenditures of $60.1 million for the first nine months of 2005, compared to the respective period in 2004. Significant capital equipment expenditures in 2005 included drilling rigs, well services rigs, fluid-handling equipment, rental equipment and coiled tubing equipment. For the years ended December 31, 2004, 2003 and 2002, cash used for investing activities continued to increase as we invested in long-term assets and made significant acquisitions. Significant capital equipment expenditures in 2004 included drilling rigs, well services rigs, fluid-handling equipment, rental equipment and coiled tubing equipment. For 2003, capital equipment expenditures primarily included drilling equipment and coiled tubing equipment for operations in Texas, and for 2002, capital equipment expenditures were primarily used for maintenance of equipment levels and additional coiled tubing units for operations near the U.S. Gulf of Mexico. Funds used for acquisitions totaled $139.4 million in 2004, $54.8 million in 2003 and $27.9 million in 2002. See “— Significant Acquisitions” above.
      We expect to expend approximately $100 million for investment in capital expenditures, excluding acquisitions, during the year ended December 31, 2005, of which approximately $85.0 million had been expended through September 30, 2005, excluding acquisitions of complementary companies. We believe

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that our operating cash flows and borrowing capacity will be sufficient to fund our operations for the next 12 months.
      In addition to making investments in capital expenditures, we also will continue to evaluate acquisitions of complementary companies. We are currently in the process of planning our 2006 capital expenditure budget, but based on current market conditions, we would expect our capital expenditures, in 2006, excluding acquisitions to be an amount at least as much as our capital expenditure made in 2005. We evaluate each acquisition based upon the circumstances and our financing capabilities at that time.
Dividends
      On September 12, 2005, we paid a dividend of $5.24 per share for an aggregate payment of approximately $146.9 million to stockholders of record on that date. We do not intend to pay dividends in the future, but rather plan to reinvest such funds in our business. Furthermore, our current term loan and revolving debt facility, which we entered into on September 12, 2005, contains restrictive debt covenants which preclude us from paying future dividends on our common stock.
Description of Our Indebtedness
      Our credit facilities as of December 31, 2004 are described in the accompanying audited consolidated financial statements (see notes 9 and 10 to the audited consolidated financial statements).
      On September 12, 2005, concurrently with the completion of the Combination, we entered into a senior secured credit facility (the “Credit Agreement”) with Wells Fargo Bank, National Association, as U.S. Administrative Agent, and certain other financial institutions. The Credit Agreement provides for a $130 million U.S. revolving credit facility that will mature in 2010, a $30 million Canadian revolving credit facility (with Integrated Production Services, Ltd. as the borrower thereof) that will mature in 2010 and a $420 million Term B term loan credit facility that will mature in 2012. Subject to certain limitations, we have the ability to increase, decrease or reallocate the commitments under the various aforementioned credit facilities. In addition, certain portions of the credit facilities are available to be borrowed in U.S. Dollars, Canadian Dollars, Pounds Sterling, Euros and other currencies approved by the lenders.
      Concurrently with the completion of the Combination, we borrowed approximately $450 million under the Credit Agreement as of the closing of the Combination to: (i) finance the Combination (including the payment of the Dividend) and (ii) to repay in full indebtedness outstanding under our previous credit agreements. Future borrowings under the revolving credit facilities under the Credit Agreement are available for working capital and general corporate purposes. The revolving facilities under the Credit Agreement may be drawn on and repaid without restriction so long as we are in compliance with the terms of the Credit Agreement, including certain financial covenants, but the term credit facility under the Credit Agreement may not be reborrowed once repaid. We are required to repay the principal of the term facility in quarterly installments equal to 0.25% of the original principal amount thereof commencing December 31, 2005.
      The Credit Agreement contains various prepayment provisions including provisions requiring us to (a) make prepayments in the amount by which the Dollar Equivalent (as defined in the Credit Agreement) of the outstanding borrowings under the Credit Agreement exceed the commitments thereunder as of certain dates on which the Dollar Equivalent of the aggregate U.S. revolving oustandings and the Canadian outstandings are determined using current exchange rates, (b) make prepayments, on each March 31st beginning March 31, 2007, in an amount equal to 50% of Excess Cash Flow (as defined in the Credit Agreement) if our Leverage Ratio (as defined in the Credit Agreement) is greater than 3.0 to 1.0 as of the preceding December 31st, (c) make prepayments in the amount by which net condemnation or insurance proceeds in respect of assets received during any fiscal year exceed $3,000,000 if such proceeds are not utilized to repair or replace (or have not been contractually committed to repair or replace) such assets within 365 days after the underlying casualty or condemnation event; provided that, if an Event of Default (as defined in the Credit Agreement) has occurred and is continuing, then we are required to make prepayments equal to 100% of all such casualty insurance or condemnation proceeds

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received, (d) make prepayments equal to 50% of any Debt Incurrence Proceeds (as defined in the Credit Agreement) in excess of $5,000,000 received during any fiscal year while Term B outstanding borrowings exist under the Credit Agreement, (e) make prepayments in the amount by which Equity Issuance Proceeds (as defined in the Credit Agreement, but excluding proceeds of equity issuances to our stockholders as of the closing date for the Credit Agreement so long as no Default or Event of Default exists) received during any fiscal year exceed $50,000,000 up to a maximum prepayment of $50,000,000 in any fiscal year, and (f) prepay (or convert of the applicable advances into U.S. Dollars) any revolving advances outstanding under the Credit Agreement that are denominated in a currency that ceases to be an Agreed Currency (as defined in the Credit Agreement).
      The Credit Agreement also contains various covenants that limit our and our subsidiaries’ ability to grant certain liens; make certain loans and investments; make capital expenditures; make distributions; make acquisitions; enter into operating leases; enter into hedging transactions; merge or consolidate; or engage in certain asset dispositions. Additionally, the Credit Agreement limits our and our subsidiaries’ ability to incur additional indebtedness with certain exceptions, including purchase money indebtedness and indebtedness related to capital leases not to exceed 10% of our Consolidated Net Worth (as defined in the Credit Agreement), unsecured indebtedness not to exceed $300 million, and indebtedness qualifying as Permitted Subordinated Debt (as defined in the Credit Agreement).
      The Credit Agreement contains covenants which, among other things, require us and our subsidiaries, on a consolidated basis, to maintain specified ratios or conditions as follows (with such ratios tested at the end of each fiscal quarter):
  •  EBITDA (as defined in the Credit Agreement) to Interest Expense (as defined in the Credit Agreement) of not less than 3.0 to 1.0;
 
  •  total debt to EBITDA of not more than 4.25 to 1.0 through September 30, 2006, 4.00 to 1.0 from December 31, 2006 through September 30, 2007, and 3.75 to 1.0 thereafter; and
 
  •  total senior secured debt to EBITDA of not more than 3.75 to 1.0 through March 31, 2006, 3.5 to 1.0 from June 30, 2006 through September 30, 2006, 3.25 to 1.0 from December 31, 2006 to September 30, 2007, 3.00 to 1.0 from December 31, 2007 through September 30, 2008, and 2.50 to 1.0 thereafter.
      All of the obligations under the U.S. portion of Credit Agreement are secured by first priority liens on substantially all of the assets of our U.S. subsidiaries as well as a pledge of approximately 66% of the stock of our first-tier foreign subsidiaries. Additionally, all of the obligations under the U.S. portion of the Credit Agreement are guaranteed by substantially all of our U.S. subsidiaries. All of the obligations under the Canadian portions of the Credit Agreement are secured by first priority liens on substantially all of the assets of all or certain of our subsidiaries. Additionally, all of the obligations under the Canadian portions of the Credit Agreement are guaranteed by us as well as all or certain of our subsidiaries.
      We have the ability to elect how interest under the Credit Agreement will be computed. Interest under the Credit Agreement may be determined by reference to (1) the London Interbank Offered Rate, or LIBOR, plus an applicable margin between 1.25% and 2.75% per annum (with the applicable margin depending upon our ratio of total debt to EBITDA) for revolving advances and 2.75% for term advances (or 2.5% if our debt ratings are upgraded by either Moody’s or Standard & Poor’s), or (2) the Canadian Base Rate (as defined in the Credit Agreement), in the case of Canadian loans or the greater of the prime rate and the federal funds rate plus 0.5%, in the case of U.S. loans, plus an applicable margin between 0.25% and 1.75% per annum for revolving advances and 1.75% for term advances (or 1.5% if our debt ratings are upgraded). Interest is payable quarterly for base rate loans and at the end of applicable interest periods for LIBOR loans, except that if the interest period for a LIBOR loan is six months, interest will be paid at the end of each three-month period.

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      If an event of default exists under the Credit Agreement, the lenders may accelerate the maturity of the obligations outstanding under the Credit Agreement and exercise other rights and remedies. Each of the following is an event of default:
  •  failure to pay any principal when due or any interest, fees or other amount within certain grace periods;
 
  •  breach of representations in the Credit Agreement or other loan documents;
 
  •  failure to perform or otherwise comply with the covenants in the Credit Agreement or other loan documents, subject, in certain instances, to certain grace periods;
 
  •  default by us and any of our subsidiaries on the payment of any other indebtedness in excess of $10.0 million, any other event or condition shall occur or exist with respect to such indebtedness beyond the applicable grace period if the effect of such event or condition is to permit or cause the acceleration of the indebtedness, or such indebtedness shall be declared due and payable prior to its scheduled maturity;
 
  •  bankruptcy or insolvency events involving us or our subsidiaries;
 
  •  the entry of one or more adverse judgments in excess of $10.0 million (excluding applicable insurance proceeds) against which enforcement proceedings are brought or that are not stayed pending appeal; and
 
  •  the occurrence of a change of control (as defined in the Credit Agreement).
      At September 30, 2005, we had $446.1 million outstanding under our term loan and revolving credit facilities and an additional $5.3 million of outstanding letters of credit, leaving approximately $137.0 million available to be drawn under the facilities. Our weighted average interest rate on outstanding borrowings at September 30, 2005 was approximately 6.7%. For the years ended December 31, 2004, 2003 and 2002, our weighted average interest rates on outstanding bank borrowings were approximately 6.1%, 6.0% and 6.0%, respectively.
Acquisition of Big Mac
      On November 1, 2005, we acquired all of the outstanding equity interests of Big Mac for $40.8 million in cash. We used $40 million under our bank credit facility to finance a portion of the purchase price. Big Mac provides fluid handling services primarily to customers in eastern Oklahoma and western Arkansas. The purchase price, which is subject to a post-closing adjustment for actual working capital and reimbursable capital expenditures as of the closing date, has not yet been finalized. Based on preliminary analysis, we expect to record between $20 million and $25 million of goodwill in connection with this acquisition. We will include the operating results of Big Mac in the completion and production services business segment from the date of acquisition. We believe that this acquisition provides a platform to enter the eastern Oklahoma market and new Fayetteville Shale play in Arkansas.
Other Arrangements
      We have entered into two separate agreements with customers of our contract drilling operation in north Texas whereby the customers have advanced funds to us and we have agreed to provide drilling services in the future to these customers. Payments received as of September 30, 2005 totaled $7.4 million, and are included in the accompanying balance sheet as a current liability. In connection with these prepayments, we have constructed two drilling rigs to commit to these customers’ drilling programs. One of the rigs was completed in October 2005 at a total cost of approximately $4.0 million and the second rig will be completed in December 2005 at a total cost of approximately $4.0 million. The recognition of revenue from deferred revenue will begin once the rigs begin drilling for each customer. The first rig commenced drilling in October 2005 for one of the customers. It is expected that the entire portion of deferred revenue will be earned and recognized as revenue within the next 12 months. Revenue will only be recorded as it is earned.

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Outstanding Debt and Operating Lease Commitments
      The following table summarizes our known contractual obligations as of September 30, 2005 (in thousands):
                                             
    Payments Due by Period
     
Contractual Obligations   Total   2005   2006-2007   2008-2009   Thereafter
                     
Long-term debt, including capital (finance) lease obligations
  $ 449,406     $ 4,287     $ 8,554     $ 8,515     $ 428,050  
 
Purchase obligations(1)
    19,840       19,840                    
 
Operating lease obligations
    36,303       10,408       15,626       9,566       703  
 
Other long-term obligations(2)
    8,450                   3,450       5,000  
                               
   
Total contractual obligations
  $ 513,999     $ 34,535     $ 24,180     $ 21,531     $ 433,753  
                               
 
(1)  Purchase obligations were pursuant to inventory and equipment purchase orders outstanding as of September 30, 2005. We have no significant purchase orders which extend beyond one year.
 
(2)  Other long-term obligations include amounts due under subordinated note arrangements with maturity dates beginning in 2009.
Off-Balance Sheet Arrangements
      We have entered into operating lease arrangements for our light vehicle fleet, certain of our specialized equipment and for our office and field operating locations in the normal course of business. The terms of the facility leases range from monthly to five years. The terms of the light vehicle leases range from three to four years. The terms of the specialized equipment leases range from two to six years. Annual payments pursuant to these leases are detailed above.
      We have entered into purchase agreements with the former owners of Double Jack and MGM as described in note 2 of our audited consolidated financial statements. Pursuant to the Double Jack purchase agreement, we agreed to pay contingent consideration of up to $1.2 million based on certain operating results of Double Jack. As of September 30, 2005, we had paid $0.5 million of this contingent consideration to the former stockholders of Double Jack. Pursuant to the MGM purchase agreement, we agreed to pay contingent consideration of up to $3.4 million and 107,066 shares of our common stock based on certain operating results of MGM. In connection with the Combination, we have agreed to pay cash consideration of up to $0.6 million to the former stockholders and key employees of MGM. In addition, we have committed 11,413 shares of our restricted stock and approximately $0.6 million to certain former employees of Double Jack who are now our employees. On February 11, 2005, we entered into an agreement and plan of merger with Parchman, pursuant to which we purchased Parchman. This agreement and plan of merger contains provisions for the issuance of up to an additional 500,000 shares of our common stock on a contingent basis. In connection with the Combination, we have agreed to pay cash consideration of up to $2.6 million to the owners of these shares. See note 20(a) of the accompanying audited consolidated financial statements.
      Other than the normal operating leases described above and the contingent consideration that may be issued pursuant to purchase agreements, we do not have any off-balance sheet financing arrangements.
Quantitative and Qualitative Disclosures About Market Risk
      The demand, pricing and terms for oil and gas services provided by us are largely dependent upon the level of activity for the U.S. and Canadian gas industry. Industry conditions are influenced by numerous factors over which we have no control, including, but not limited to: the supply of and demand for oil and gas; the level of prices, and expectations about future prices, of oil and gas; the cost of exploring for, developing, producing and delivering oil and gas; the expected rates of declining current production; the discovery rates of new oil and gas reserves; available pipeline and other transportation capacity; weather

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conditions; domestic and worldwide economic conditions; political instability in oil-producing countries; technical advances affecting energy consumption; the price and availability of alternative fuels; the ability of oil and gas producers to raise equity capital and debt financing; and merger and divestiture activity among oil and gas producers.
      The level of activity in the U.S. and Canadian oil and gas exploration and production industry is volatile. Expected trends in oil and gas production activities may not continue and demand for our services may not reflect the level of activity in the industry. Any prolonged substantial reduction in oil and gas prices would likely affect oil and gas production levels and therefore affect demand for our services. A material decline in oil and gas prices or U.S. and Canadian activity levels could have a material adverse effect on our business, financial condition, results of operations and cash flows. Recently, demand for our services has been strong and we are currently electing to continue our past practice of committing our equipment on a short-term or day-to-day basis rather than entering into longer-term contracts.
      As of September 30, 2005, approximately 14% of our revenues and 13% of our total assets and liabilities were denominated in Canadian dollars, our functional currency in Canada. As a result, a material decrease in the value of the Canadian dollar relative to the U.S. dollar may negatively impact our revenues, cash flows and net income. Each one percentage point change in the value of the Canadian dollar impacts our revenues by approximately $0.7 million per year. We do not currently use hedges or forward contracts to offset this risk.
      Our Mexican operation uses the U.S. dollar as its functional currency, and as a result, all transactions and translation gains and losses are recorded currently in the financial statements. The balance sheet amounts are translated into U.S. dollars at the exchange rate at the end of the month and the income statement amounts are translated at the average exchange rate for the month. We estimate that a hypothetical 10% movement of the Mexican peso relative to the U.S. dollar would affect net income by approximately $0.2 million. Currently, we conduct a portion of our business in Mexico in the local currency, the Mexican peso. The effects of currency fluctuations on our Mexican operations are partly mitigated because the majority of our local expenses are also denominated in the Mexican peso.
      All of our bank debt is structured under floating rate terms and, as such, our interest expense is sensitive to fluctuations in the prime rates in the U.S. and Canada. Based on the debt structure in place as of September 30, 2005, a 1% increase in interest rates would increase interest expense by approximately $4.5 million per year and reduce operating cash flows by approximately $2.9 million.
Recent Accounting Pronouncements
      In April 2002, the FASB issued SFAS No. 145, “Rescission of FASB Statements No. 4, 44 and 64, Amendment of FASB Statement No. 13 and Technical Corrections.” SFAS No. 145 provides guidance for the classification of gains or losses on the extinguishment of debt and accounting for certain lease modifications that have economic effects that are similar to a sale-leaseback transaction. SFAS No. 145 became effective on January 1, 2003. The adoption of SFAS No. 145 did not have a material impact on our financial position, results of operations or cash flows.
      In June 2002, the FASB issued SFAS No. 146, “Accounting for Exit or Disposal Activities,” which provides guidance related to the recognition, measurement and reporting of costs associated with exit and disposal activities, including restructuring activities previously accounted for pursuant to Emerging Issues Task Force Issue No. 94-3, “Liability Recognition for Certain Employee Termination Benefits and Other Costs to Exit an Activity.” SFAS No. 146 became effective on January 1, 2003. The adoption of SFAS No. 146 did not have a material impact on our financial position, results of operations or cash flows.
      In November 2002, the FASB issued Interpretation No. 45, “Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness to Others, an interpretation of FASB Statements No. 5, 57 and 107 and a rescission of FASB Interpretation No. 34.” Interpretation No. 45 expands the interim and annual financial statement disclosures that a guarantor must make related to its obligations under guarantees issued, and clarifies that a guarantor is required to recognize, at the

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inception of the guarantee, a liability for the fair value of the obligation taken. The initial measurement and recognition provisions of Interpretation No. 45 become applicable to guarantees issued or modified after December 31, 2002. Application of Interpretation No. 45 did not have a material impact on our financial position, results of operations or cash flows.
      In December 2002, the FASB issued SFAS No. 148, “Accounting for Stock-Based Compensation – Transition and Disclosure, an amendment to FASB Statement No. 123.” SFAS No. 148 amends SFAS No. 123, “Accounting for Stock-Based Compensation,” to provide alternative methods to transition, on a volunteer-basis, to the fair value method of accounting for stock-based compensation, and amends disclosure requirements under SFAS No. 123 to require prominent disclosures in both annual and interim financial statements. We did not elect to transition to SFAS No. 123 pursuant to SFAS No. 148.
      In January 2003, the FASB issued FASB Interpretation No. 46. “Consolidation of Variable Interest Entities.” FIN No. 46 requires the consolidation of each variable interest entity in which an enterprise absorbs a majority of the entity’s expected losses or receives a majority of the entity’s expected residual returns, or both, as a result of ownership, contractual or other financial interests in the entity. FIN No. 46 did not have a material impact on our financial position, results of operations or cash flows.
      On January 1, 2003, we adopted SFAS No. 143, “Accounting for Asset Retirement Obligations.” SFAS No. 143 addresses financial accounting and reporting for obligations associated with the retirement of long-lived assets. SFAS No. 143 requires that the fair value of a liability associated with an asset retirement obligation (“ARO”) be recognized in the period in which it is incurred if a reasonable estimate can be made. The liability for the ARO is revised each subsequent period due to the passage of time and changes in estimates. The associated retirement costs are capitalized as part of the carrying amount of the long-lived asset and subsequently depreciated over the estimated useful life of the asset. The adoption of SFAS No. 143 in 2003 did not have a material impact on our financial position, results of operations or cash flows.
      In April 2003, the FASB issued SFAS No. 149, “Amendment of Statement 133 on Derivative Instruments and Hedging Activities.” SFAS No. 149 provides additional guidance to account for derivative instruments, including certain derivative instruments embedded in other contracts, and other hedging activities described in SFAS No. 133. SFAS No. 149 became effective for new contract arrangements and hedging transactions entered into after June 30, 2003, with exceptions for certain SFAS No. 133 implementation issues begun prior to June 15, 2003. The adoption of this policy had no material impact on our financial position, results of operations or cash flows.
      In May 2003, the FASB issued SFAS No. 150, “Accounting for Certain Financial Instruments with Characteristics of both Liabilities and Equity.” SFAS No. 150 provides guidance on how to classify and measure certain financial instruments that have characteristics of both liabilities and equity. SFAS No. 150 generally requires treatment of these instruments as liabilities, including certain obligations that the issuer can or must settle by issuing its own equity securities. SFAS No. 150, which became effective for all financial instruments entered into or modified after May 31, 2003, and otherwise became effective on July 1, 2003, required cumulative effect of change in accounting principle treatment upon adoption. We adopted SFAS No. 150 on July 1, 2003. The adoption of this policy had no material impact on our financial position, results of operations or cash flows.
      In December 2003, the FASB revised SFAS No. 132, “Employers’ Disclosures about Pensions and Other Postretirement Benefits” (“Revised SFAS No. 132”). Revised SFAS No. 132 augments employers’ required disclosures about pension plans and other postretirement benefit plans, but does not change the measurement or recognition principles required by other statements promulgated by GAAP. Revised SFAS No. 132 became effective for financial statements with fiscal years ending after December 15, 2003. The adoption of Revised SFAS No. 132 did not have a material impact on our financial position, results of operations or cash flows.
      In November 2004, the FASB issued SFAS No. 151, “Inventory Costs.” SFAS No. 151 amends the guidance in Accounting Research Bulletin No. 43, Chapter 4, “Inventory Pricing,” to clarify the

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accounting for abnormal amounts of idle facility expense, freight, handling costs and wasted material (spoilage), and generally requires that these amounts be expensed in the period that the cost arises, rather than being included in the cost of inventory, thereby requiring that the allocation of fixed production overheads to the costs of conversion be based on normal capacity of the production facilities. SFAS No. 151 becomes effective for inventory costs incurred during fiscal years beginning after June 15, 2005, but earlier application is permitted. We are currently evaluating the impact of SFAS No. 151 on our financial statements, but we do not expect that it will have a material impact on our financial position, results of operations or cash flows.
      In December 2004, the FASB issued SFAS No. 153, “Exchanges of Nonmonetary Assets.” SFAS No. 153 amends current guidance related to the exchange on nonmonetary assets as per ABP Opinion No. 29, “Accounting for Nonmonetary Transactions,” to eliminate an exception that allowed exchange of similar nonmonetary assets without determination of the fair value of those assets, and replaced this provision with a general exception for exchanges of nonmonetary assets that do not have commercial substance. A nonmonetary exchange has commercial substance if the future cash flows of the entity are expected to change significantly as a result of the exchange. SFAS No. 153 becomes effective for nonmonetary asset exchanges occurring in fiscal periods beginning after June 15, 2005. We do not anticipate that the adoption of this policy will have a material impact on our financial position, results of operations or cash flows.
      In December 2004, the FASB issued SFAS No. 123R, “Share-Based Payment,” which revises SFAS No. 123 and supercedes APB No. 25. SFAS No. 123R will require us to measure the cost of employee services received in exchange for an award of equity instruments based on the grant-date fair value of the award, with limited exceptions. The fair value of the award will be remeasured at each reporting date through the settlement date, with changes in fair value recognized as compensation expense of the period. Entities should continue to use an option-pricing model, adjusted for the unique characteristics of those instruments, to determine fair value as of the grant date of the stock options. SFAS No. 123R was to become effective as of the beginning of the first interim or annual reporting period that begins after June 15, 2005. However, the SEC issued an extension which allows public companies to defer adoption of SFAS No. 123R until the beginning of their fiscal year that begins after June 15, 2005. We have not yet adopted SFAS No. 123R and are currently evaluating the impact that this policy will have on our financial position, results of operations and cash flows.
      In May 2005, the FASB issued SFAS No. 154, “Accounting Changes and Error Corrections, a Replacement of APB Opinion No. 20 and FASB Statement No. 3.” SFAS No. 154 requires retrospective application of changes in accounting principle to prior periods’ financial statements, rather than the use of the cumulative effect of a change in accounting principle, unless impracticable. If impracticable to determine the impact on prior periods, then the new accounting principle should be applied to the balances of assets and liabilities as of the beginning of the earliest period for which retrospective application is practicable, with a corresponding adjustment to equity, unless impracticable for all periods presented, in which case prospective treatment should be applied. SFAS No. 154 applies to all voluntary changes in accounting principle, as well as those required by the issuance of new accounting pronouncements if no specific transition guidance is provided. SFAS No. 154 does not change the previously issued guidance for reporting a change in accounting estimate or correction of an error. SFAS No. 154 becomes effective for accounting changes and corrections of errors made in fiscal years beginning after December 15, 2005. We do not expect this policy to have a material impact on our financial position, results of operations or cash flows.

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BUSINESS
Our Company
      We provide specialized services and products focused on helping oil and gas companies develop hydrocarbon reserves, reduce costs and enhance production. We focus on basins within North America that we believe have attractive long-term potential for growth, and we deliver targeted, value-added services and products required by our customers within each specific basin. We believe our range of services and products positions us to meet many needs of our customers at the wellsite, from drilling and completion through production and eventual abandonment. The following figure illustrates some of our services used during the lifecycle of a well.
(GRAPHIC)
      We seek to differentiate ourselves from our competitors through our local leadership, our basin-level expertise and the innovative application of proprietary and other technologies. We deliver solutions to our customers that we believe lower their costs and increase their production in a safe and environmentally friendly manner.
      We manage our operations from regional field service facilities located throughout the U.S. Rocky Mountain region, Texas, Oklahoma, Louisiana, western Canada and Mexico.
      Our business is comprised of three segments:
      Completion and Production Services. Through our completion and production services segment, we establish, maintain and enhance the flow of oil and gas throughout the life of a well. This segment is divided into the following primary service lines:
  •  Intervention Services. Well intervention requires the use of specialized equipment to perform an array of wellbore services. Our fleet of intervention service equipment includes coiled tubing units, pressure pumping units, nitrogen units, well service rigs, snubbing units and a variety of support equipment. Our intervention services provide customers with innovative solutions to increase production of oil and gas. For example, in the Barnett Shale region of north Texas we operate advanced coiled tubing units that have electric-line conductors within the units’ coiled tubing string. These specially configured units can deploy perforating guns, logging tools and plugs, without a separate electric-line unit in high inclination and “horizontal” wells that are prevalent throughout that basin.
 
  •  Downhole and Wellsite Services. Our downhole and wellsite services include electric-line, slickline, production optimization, production testing, rental and fishing services. We also offer several proprietary services and products that we believe create significant value for our customers. Examples of these proprietary services and products include: (1) our Green Flowback system, which permits the flow of gas to our customers while performing drill-outs and flowback operations, increasing production, accelerating time to production and eliminating the need to flare gas, and (2) our patented plunger lift system that, when combined with our diagnostic and installation

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  services, removes fluids from gas wells resulting in increased production and the extension of the life of the well.
 
  •  Fluid Handling. We provide a variety of services to help our customers obtain, move, store and dispose of fluids that are involved in the development and production of their reservoirs. Through our fleet of specialized trucks, frac tanks and other assets, we provide fluid transportation, heating, pumping and disposal services for our customers.
      Drilling Services. Through our drilling services segment, we provide services and equipment that initiate or stimulate oil and gas production by providing land drilling, specialized rig logistics and site preparation. Through this segment, we also provide pressure control, drill string, pipe handling and other equipment. Our drilling rigs currently operate exclusively in the Barnett Shale region of north Texas.
      Product Sales. Through our product sales segment, we provide a variety of equipment used by oil and gas companies throughout the lifecycle of their wells. Our current product offering includes completion, flow control and artificial lift equipment as well as tubular goods. We sell products throughout North America primarily through our supply stores and through distributors on a wholesale basis. We also sell products through agents in markets outside of North America.
Our Industry
      Our business depends on the level of exploration, development and production expenditures made by our customers. These expenditures are driven by the current and expected future prices for oil and gas, and the perceived stability and sustainability of those prices. Our business is primarily driven by natural gas drilling activity in North America. We believe the following two principal economic factors will positively affect our industry in the coming years:
  •  Higher demand for natural gas in North America. We believe that natural gas will be in high demand in North America over the next several years because of the growing popularity of this clean-burning fuel. According to the International Energy Association’s 2004 World Energy Outlook, natural gas demand in North America (United States, Canada and Mexico) is projected to grow by approximately 45% from 2002 to 2030.
 
  •  Constrained North American gas supply. Although the demand for natural gas is projected to increase, supply is likely to be constrained as North American natural gas basins are becoming more mature and experiencing increased decline rates. Even though the number of wells drilled in North America has increased significantly in recent years, a corresponding increase in domestic production has not occurred. As a result, producers are required to increase drilling just to maintain flat production. To supply the growing demand for natural gas, the primary alternatives are to increase drilling, enhance recovery rates or import LNG from overseas. To date minimal increases have occurred, although many forecasts anticipate a material increase of LNG imports.
      As a result of the above factors, we expect that there will continue to be a tight supply of, and high demand for, natural gas in North America. We believe this will continue to support high natural gas prices and high levels of drilling activity.

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      As illustrated in the table below, 2004 marked the second consecutive year of gas price increases and the third consecutive year of oil price increases, with an average daily closing Henry Hub spot price for natural gas of $5.90 per mcf and an average daily closing WTI Cushing spot oil price of $41.51 per bbl. Furthermore, the average price for natural gas and the average oil price have increased from $5.50 per mcf and $42.12 per bbl, respectively, on January 3, 2005, to $14.50 per mcf and $65.07 per bbl, respectively on September 27, 2005. In addition, as of September 27, 2005, NYMEX forward curve prices were above $8.00 per mcf and $60.00 per bbl, for natural gas and oil, respectively, through 2009. The number of drilling rigs under contract in the United States and Canada has increased from 1,181 at the beginning of 2003 to 1,981 in August 2005, according to BHI. The number of well service rigs has increased from 1,478 to 2,045 from the beginning of 2003 through August 2005. The table below sets forth average daily closing prices for the WTI Cushing spot oil price and the average daily closing prices for the Henry Hub price for natural gas since 1999:
                 
    Average Daily Closing   Average Daily Closing
    Henry Hub Spot Natural   WTI Cushing Spot Oil
Period   Gas Prices ($/mcf)   Price ($/bbl)
         
1/1/99 - 12/31/99
  $ 2.27     $ 19.30  
1/1/00 - 12/31/00
    4.30       30.37  
1/1/01 - 12/31/01
    3.96       25.96  
1/1/02 - 12/31/02
    3.37       26.17  
1/1/03 - 12/31/03
    5.49       31.06  
1/1/04 - 12/31/04
    5.90       41.51  
1/1/05 - 9/30/05
    7.75       55.46  
 
Source: Bloomberg NYMEX prices.
      Higher demand for natural gas and a constrained gas supply have resulted in higher prices and increased drilling activity. The increase in prices and drilling activity are driving three additional trends that we believe will benefit us:
        Trend toward drilling and developing unconventional North American natural gas resources. Due to the maturity of conventional North American oil and gas reservoirs and their accelerating production decline rates, unconventional oil and gas resources will comprise an increasing proportion of future North American oil and gas production. Unconventional resources include tight sands, shales and coalbed methane. These resources require more wells to be drilled and maintained, frequently on tighter acreage spacing. The appropriate technology to recover unconventional gas resources varies from region to region; therefore, knowledge of local conditions and operating procedures, and selection of the right technologies is key to providing customers with appropriate solutions.
 
        The advent of the resource play. A “resource play” is a term used to describe an accumulation of hydrocarbons known to exist over a large area which, when compared to a conventional play, has lower commercial development risks and a lower average decline rate. Once identified, resource plays have the potential to make a material impact because of their size and low decline rates. The application of appropriate technology and program execution are important to obtain value from resource plays. Resource play developments occur over long periods of time, well by well, in large-scale developments that repeat common tasks in an assembly-line fashion and capture economies of scale to drive down costs.
 
        Increasingly complex technologies. Increasing prices and the development of unconventional oil and gas resources are driving the need for complex, new technologies to help increase recovery rates, lower production costs and accelerate field development. We believe that the increasing complexity of technology used in the oil and gas development process coupled with limited engineering resources will require production companies to increase their reliance on service companies to assist them in developing and applying these technologies.

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Our Business Strategy
      Our goal is to build the leading oilfield services company focused on the completion and production phases in the life of an oil and gas well. We intend to capitalize on the emerging trends in the North American marketplace through the execution of a growth strategy that consists of the following components:
      Expand and capitalize on local leadership and basin-level expertise. A key component of our strategy is to build upon our base of strong local leadership and basin-level expertise. We have a significant presence in most of the key onshore continental U.S. and Canadian gas plays we believe have the potential for long-term growth. Our position in these basins capitalizes on our strong local leadership that has accumulated a valuable knowledge base and strong customer relationships. We intend to leverage our existing market presence, expertise and customer relationships to expand our business within these gas plays. We also intend to replicate this approach in new regions by building and acquiring new businesses that have strong regional management with extensive local knowledge.
      Develop and deploy technical and operational solutions. We are focused on developing and deploying technical services, equipment and expertise that lower our customers’ costs.
      Capitalize on organic and acquisition-related growth opportunities. We believe there are numerous opportunities to sell new services and products to customers in our current geographic areas and to sell our current services and products to customers in new geographic areas. We have a proven track record of organic growth and successful acquisitions, and we intend to continue using capital investments and acquisitions to strategically expand our business. We employ a rigorous acquisition screening process and have developed comprehensive post-acquisition integration capabilities designed to ensure each acquisition is effectively assimilated. We use a returns method for evaluating capital investment opportunities, and we apply a disciplined approach to adding new equipment.
      Focus on execution and performance. We have established and intend to develop further a culture of performance and accountability. Senior management spends a significant portion of its time ensuring that our customers receive the highest quality of service by focusing on the following:
  •  clear business direction;
 
  •  thorough planning process;
 
  •  clearly defined targets and accountabilities;
 
  •  close performance monitoring;
 
  •  strong performance incentives for management and employees; and
 
  •  effective communication.
Our Competitive Strengths
      We believe that we are well positioned to execute our strategy and capitalize on opportunities in the North American oil and gas market based on the following competitive strengths:
      Strong local leadership and basin-level expertise. We operate our business with a focus on each regional basin complemented by our local reputations. We believe our local and regional businesses, some of which have been operating for more than 50 years, provide us with a significant advantage over many of our competitors. Our managers, sales engineers and field operators have extensive expertise in their local geological basins and understand the regional challenges our customers face. We have long-term relationships with many customers, and most of the services and products we offer are sold or contracted at a local level, allowing our operations personnel to bring their expertise to bear while selling services and products to our customers. We strive to leverage this basin-level expertise to establish ourselves as the preferred provider of our services in the basins in which we operate.

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      Significant presence in major North American basins. We operate in major oil and gas producing regions of the U.S. Rocky Mountains, Texas, Louisiana and Oklahoma, western Canada and Mexico, with concentrations in key “resource play” and unconventional basins. Resource plays are expected to become increasingly important in future North American oil and gas production as more conventional resources enter later stages of the exploration cycle. We believe we have an excellent position in highly active markets such as the Barnett Shale region of north Texas. Each of these markets is among the most active areas for exploration and development of onshore oil and gas. Accelerating production and driving down development and production costs are key goals for oil and gas operators in these areas, resulting in strong demand for our services and products. In addition, our strong presence in these regions allows us to build solid customer relationships and take advantage of cross-selling opportunities.
      Focus on complementary production and field development services. Our breadth of service and product offerings well positions us relative to our competitors. Our services encompass the entire lifecycle of a well from drilling and completion, through production and eventual abandonment. We deliver complementary services and products, which we may provide in tandem or sequentially over the life of the well. This suite of services and products gives us the opportunity to cross-sell to our customer base and throughout our geographic regions. Leveraging our strong local leadership and basin-level expertise, we are able to offer expanded services and products to existing customers or current services and products to new customers.
      Innovative approach to technical and operational solutions. We develop and deploy services and products that enable our customers to increase production rates, stem production declines and reduce the costs of drilling, completion and production. The significant expertise we have developed in our areas of operation offers our customers customized operational solutions to meet their particular needs. For example, our Canadian operation provides highly skilled personnel and a combination of heliportable and specialized equipment that includes wireline (electric-line and slickline) and production testing services that can work together and be deployed quickly and efficiently in the harsh environment of the Northwest Territories of Canada. Our ability to develop these technical and operational solutions is possible due to our understanding of applicable technology, our basin-level expertise and our close local relationships with customers.
      Modern and active asset base. We have a modern and well-maintained fleet of coiled tubing units, pressure pumping equipment, wireline units, well service rigs, snubbing units, fluid transports, frac tanks and other specialized equipment. We believe our ongoing investment in our equipment allows us to better serve the diverse and increasingly challenging needs of our customer base. New equipment is generally less costly to maintain and operate on an annual basis and is more efficient for our customers. Modern equipment reduces the downtime and associated expenditures and enables the increased utilization of our assets. Our fleet is active with high utilization. We believe our future expenditures will be used to capitalize on growth opportunities within the areas we currently operate and to build out new platforms obtained through targeted acquisitions.
      Experienced management team with proven track record. Each member of our operating management team has over 20 years of experience in the oilfield services industry. We believe that their considerable knowledge of and experience in our industry enhances our ability to operate effectively throughout industry cycles. Our management also has substantial experience in identifying, completing and integrating acquisitions. In addition, our management supports local leadership by developing corporate strategy, implementing corporate governance procedures and overseeing a company-wide safety program.
The Combination
      Prior to 2001, SCF Partners, a private equity firm that focuses on investments in the oilfield services segment of the energy industry, began to target investment opportunities in service oriented companies in the North American natural gas market with specific focus on the production phase of the exploration and production cycle. On May 22, 2001, SCF Partners through SCF formed Saber, a new company, in connection with its acquisition of two companies primarily focused on completion and production related

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services in Louisiana. In July 2002, SCF became the controlling stockholder of Integrated Production Services, Ltd., a production enhancement company that, at the time, focused its operation in Canada. In September 2002, Saber acquired this company and changed its name to Integrated Production Services, Inc. Subsequently, IPS began to grow organically and through several acquisitions, with the ultimate objective of creating a technical leader in the enhancement of natural gas production. In November 2003, SCF formed another production services company, CES, establishing a platform from which to grow in the Barnett Shale region of north Texas. Subsequently, through organic growth and several acquisitions, CES extended its presence to the U.S. Rocky Mountain and the Mid-Continent regions. In the summer of 2004, SCF formed IEM, which at the time had a presence in Louisiana and Texas. During 2004, IPS and IEM independently began to execute strategic initiatives to establish a presence in both the Barnett Shale and U.S. Rocky Mountain regions.
      On September 12, 2005, IPS, CES and IEM were combined and became Complete Production Services, Inc. in a transaction we refer to as the “Combination.” In the Combination, CES served as the acquiring entity for accounting purposes and IPS served as the acquirer for tax and legal purposes. Immediately after the Combination, SCF held approximately 70% of our outstanding common stock, the former CES stockholders (other than SCF) in the aggregate held approximately 18.8% of our outstanding common stock, the former IEM stockholders (other than SCF) in the aggregate held approximately 2.4% of our outstanding common stock and the former IPS stockholders (other than SCF) in the aggregate held approximately 8.4% of our outstanding common stock.
      We believe that operational and financial benefits realized through the Combination enhance the growth potential and establish the foundation for long-term growth for the combined company.
Overview of Our Segments
      We manage our business through three primary segments: completion and production services, drilling services and product sales. Within each of these segments, we perform services and deliver products, as detailed in the table below. However, significant regional growth opportunities remain. We constantly monitor the North American market for opportunities to expand our business by building our presence in existing regions and expanding our services and products into attractive, new regions.
                                                                                                   
        Gulf                                       Western
        Coast/               Central &   DJ   Western           North   Canadian
        South   South   East   North   Western   Basin   Slope   SW   Western   Rockies   Sedimentary
Product/Service Offering   Mexico   Louisiana   Texas   Texas   Texas   Oklahoma   (CO)   (CO & UT)   Wyoming   Wyoming   (MT & ND)   Basin
                                                 
Completion and Production Services:
                                                                                               
 
Coiled Tubing
    ü       ü       ü       ü       ü                                       ü       ü          
 
Well Servicing
                            ü       ü       ü       ü       ü       ü                          
 
Snubbing
                    ü               ü                               ü                          
 
Electric-line
            ü                       ü                                                       ü  
 
Slickline
    ü               ü       ü       ü                                                       ü  
 
Production Optimization
                    ü       ü       ü       ü               ü       ü       ü               ü  
 
Production Testing
    ü               ü       ü       ü                       ü               ü               ü  
 
Rental Equipment
                            ü       ü               ü       ü                       ü          
 
Pressure Testing
                                                            ü       ü       ü                  
 
Fluid Handling
                            ü       ü       ü       ü       ü       ü               ü          
 
Drilling Services:
                                                                                               
 
Contract Drilling
                                    ü                                                          
 
Drilling Logistics
            ü       ü       ü       ü       ü                       ü       ü       ü          
 
Product Sales:
                                                                                               
 
Supply Stores
                            ü       ü                       ü                                  
 
Production Enhancement Products
                    ü               ü                                                       ü  
 
ü”  denotes a service or product currently offered by us in this area.
      On November 1, 2005, we acquired all of the outstanding equity interests of Big Mac for $40.8 million in cash. Big Mac is based in McAlester, Oklahoma, and provides fluid handling services primarily to customers in eastern Oklahoma and western Arkansas. We will include the operating results of Big Mac in the complete and production services business segment from the date of acquisition. We

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believe that this acquisition provides a platform to enter the eastern Oklahoma market and new Fayetteville Shale play in Arkansas.
Completion and Production Services (67% of Revenue for the Nine Months Ended September 30, 2005)
      Through our completion and production services segment, we establish, maintain and enhance the flow of oil and gas throughout the life of a well. This segment is divided into intervention services, downhole and wellsite services and fluid handling.
Intervention Services
      We use our intervention assets, which include coiled tubing units, pressure pumping equipment, nitrogen units, well service rigs and snubbing units to perform three major types of services for our customers:
  •  Completion Services. As newly drilled oil and gas wells are prepared for production, our operations may include selectively perforating the well casing to access producing zones, stimulating and testing these zones and installing downhole equipment. We provide intervention services and products to assist in the performance of these services. The completion process typically lasts from a few days to several weeks, depending on the nature and type of the completion. Oil and gas producers use our intervention services to complete their wells because we have well trained employees, the experience necessary to perform such services and a strong record for safety and reliability.
 
  •  Workover Services. Producing oil and gas wells occasionally require major repairs or modifications, called “workovers.” These services include extensions of existing wells to drain new formations either through deepening wellbores to new zones or by drilling horizontal lateral wellbores to improve reservoir drainage patterns. In less extensive workovers, we provide services and products to seal off depleted zones in existing wellbores and access previously bypassed productive zones. Other workover services which we provide include: major subsurface repairs, such as casing repair or replacement; recovery of tubing and removal of foreign objects in the wellbore; repairing downhole equipment failures; plugging back the bottom of a well to reduce the amount of water being produced; cleaning out and recompleting a well if production has declined; and repairing leaks in the tubing and casing.
 
  •  Maintenance Services. Maintenance services are required throughout the life of most producing oil and gas wells to ensure efficient and continuous operation. We provide services that include mechanical repairs necessary to maintain production from the well, such as repairing inoperable pumping equipment or replacing defective tubing, and removing debris from the well. Other services include pulling rods, tubing, pumps and other downhole equipment out of the wellbore to identify and repair a production problem.
      The key intervention assets we use to perform the above services are as follows:
Coiled Tubing and Pressure Pumping Units
      We are one of the leading providers of coiled tubing services in North America. As of September 30, 2005, we operated a fleet of 32 coiled tubing units and 27 pressure pumping units, as well as 14 nitrogen units. We use these assets to perform a variety of wellbore applications, including foam washing, acidizing, displacing, cementing, gravel packing, plug drilling, fishing and jetting. Coiled tubing is a key segment of the well service industry today, which allows operators to continue production during service operations without shutting down the well, reducing the risk of formation damage. The growth in deep well and horizontal drilling has increased the market for coiled tubing. We have developed innovative equipment configurations to capitalize on emerging market opportunities. For example, in the Barnett Shale region of north Texas, we have introduced advanced coiled tubing units that have electric-line conductors within the units’ coiled tubing string. These specially configured units provide electric-line and coiled tubing controls

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in one fully integrated package, and allow us to deploy perforating guns, logging tools and plugs in high inclination wells for our customers. We provide coiled tubing and pressure pumping services primarily in Wyoming, Colorado, Oklahoma, Texas, Louisiana, Mexico and offshore in the Gulf of Mexico.
Well Service Rigs
      As of September 30, 2005, we owned and operated a fleet of 103 well service rigs, including 63 units that are either recently constructed or have been rebuilt over the past five years. We believe we have a leading market position in the Barnett Shale region of north Texas and in some of the most active regions of the U.S. Rocky Mountains. As of September 30, 2005, we also operated 31 swabbing units, 11 of which are highly customized hydraulic units which we use to diagnose and remediate gas well production problems. We provide well service rig operations in Wyoming, Colorado, Utah, Montana, North Dakota, Oklahoma and Texas. These rigs are used to perform a variety of completion, workover and maintenance services, such as installations, completions, assisting with perforating, removing defective equipment and sidetracking wells.
Snubbing Units
      As of September 30, 2005, we operated a fleet of 11 snubbing units, four of which are rig assist units. Snubbing services use specialized hydraulic well service units that permit an operator to repair damaged casing, production tubing and downhole production equipment in high-pressure, “live-well” environments. A snubbing unit makes it possible to remove and replace downhole equipment while maintaining pressure in the well. Applications for snubbing units include “live-well” completions and workovers, underground blowout control, underbalanced completions, underbalanced drilling and the snubbing of tubing, casing or drillpipe into or out of the wellbore. Our snubbing units operate primarily in Texas, Oklahoma, and Wyoming.
Downhole and Wellsite Services
      We provide an array of complementary downhole and wellsite services that we classify into four groups: wireline services; production optimization services; production testing services; and rental, fishing and pressure testing services.
      Wireline Services. As of September 30, 2005, we owned and operated a fleet of 75 wireline units in North America and provided both electric-line and slickline services. Truck and skid mounted wireline services are used to evaluate downhole well conditions, to initiate production from a formation by perforating a well’s casing, and to provide mechanical services such as setting equipment in the well, or fishing lost equipment out of a well. We provide wireline services in the western Canadian Sedimentary Basin, Texas, Louisiana and offshore in the Gulf of Mexico. Of our fleet of 75 wireline units, we have 41 electric-line units, 11 of which are offshore skids, and 34 slickline units.
      With our fleet of wireline equipment we provide the following services:
  •  Perforating Services. Perforating involves positioning a perforating gun that contains explosive jet charges down the wellbore next to a productive zone. A detonator is fired and primer cord is ignited, which then detonates the jet charges. The resulting explosion burns a hole through the wellbore casing and cement and into the formation, thus allowing the formation fluid to flow into the wellbore and be produced to the surface. The perforating gun may be deployed in a number of ways. The gun can be conveyed by a conventional wireline cable if the wellbore geometry allows, it may be conveyed on coiled tubing, it may be conveyed on conventional tubing or the gun may be “pumped-down” to the correct depth in the wellbore.
 
  •  Logging Services. Cased hole logging requires the use of a single or multi-conductor, braided steel cable (electric-line), mounted on a hydraulically operated drum, and a specialized logging truck. Electronic instruments are attached to the end of the cable and lowered to the bottom of the well and the line is slowly pulled out of the well transmitting wellbore data up the cable to the surface

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  where the information is processed by a surface computer system and displayed on a paper graph in a logging format. This information is used by customers to analyze different downhole formation structures, to detect the presence of oil, gas and water and to check the integrity of the casing or the cement behind the pipe. Logs are also run to detect gas or fluid migration between zones or to the surface.
 
  •  Slickline Services. Slickline services are used primarily for well maintenance. The line used for this application is generally a small single steel line. Typical applications of this service would include bottom hole pressure surveys, running temperature gradients, setting tubing plugs, opening and closing sliding sleeves, fishing operations, plunger lift installations, gas lift installations and other maintenance services that the well would require during its lifecycle.
      Production Optimization Services. Our production optimization services provide customers with technical solutions to stem declining production that result from liquid loading, reduced bottom-hole pressures or improper wellsite designs. We assist in identifying candidates, designing solutions, executing on-site and following up to ensure continued performance. We have developed proprietary technologies that allow us to enhance recovery for our customers and provide on-going service. Specific services we provide include:
  •  Plunger Lift Services and Products. We provide plunger lift candidate selection, installation and maintenance services which may incorporate the use of our patented Pacemaker Plunger Lift System. Plunger lift systems facilitate the removal of fluids that restrict the production of natural gas wells. Removing fluids that accumulate in wells increases production and in many cases slows decline rates. The proprietary design of our Pacemaker Plunger Lift System incorporates a large bypass area which allows it to make more trips per day and remove more wellbore fluids, versus other plunger lift designs, in wells with certain characteristics.
 
  •  Acoustic Pressure Surveys. We provide acoustic pressure surveys which are an analytical technique that assists our customers in determining static reservoir pressure and the existence of near wellbore formation damage.
 
  •  Dynamometer Analysis. Our dynamometer analysis services include the analysis of reciprocating rod pumping systems (pumpjacks) to determine pump performance and provide our customers with critical information for well performance used to optimize the production and recovery of oil and gas.
 
  •  Fluid Level Analysis. We provide fluid level analysis services which record an acoustic pulse as it travels down the wellbore in order to determine the fluid depth.
      We offer production optimization services to customers across the United States and in Canada. We provide production optimization services in Canada through our 50% joint venture with Premier Production Services Ltd.
      Production Testing Services. Production testing is a service required by exploration and production companies to evaluate and clean out new and existing wells. We use a proprietary technology and service approach and are a leading independent provider in North America. We provide production testing services throughout the western Canadian Sedimentary Basin and also provide production testing services in Wyoming, Utah, Colorado, Texas and Mexico. As of September 30, 2005, we operated a total of 72 production testing units.
Production testing has the following primary applications:
  •  Well clean-ups or flowbacks are done shortly after completing or stimulating a well and are designed to remove damaging drilling fluids, completion fluids, sand and other debris. This “clean-up” prevents damage to the permanent production facilities and flowlines, thereby improving production. Our clean-up offering includes our Green Flowback services, which permit the flow of gas to our customers while performing drill- outs and flowback operations, increasing production, accelerating time to production and eliminating the need to flare gas;

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  •  Exploration well testing measures how a reservoir performs under various flow conditions. These measurements allow reservoir and production engineers, and geologists to understand a well’s or reservoir’s production capability. Exploration testing jobs can last from a few days to several months; and
 
  •  In-line production testing measures a well’s flow rates, oil, gas and water composition, pressure and temperature. These measurements are used by engineers to identify and solve well and reservoir problems. In-line production testing is performed after a well has been completed and is already producing. In-line tests can run from several hours to more than several months.
      Rental Equipment, Fishing and Pressure Testing Services. Oil and gas producers and drilling contractors often find it uneconomical to maintain complete inventories of tools, drillpipe, pressure testing equipment and other specialized equipment and to retain the qualified personnel to operate this equipment. We provide the following services and products:
  •  Rental Equipment and Services. We rent specialized tools, equipment and tubular goods for the drilling, completion and workover of oil and gas wells. Items rented include pressure control equipment, drill string equipment, pipe handling equipment, fishing and downhole tools, and other equipment, including stabilizers, power swivels and bottom-hole assemblies.
 
  •  Fishing Services. We provide highly skilled downhole services, including fishing, milling and cutting services, which consist of removing or otherwise eliminating “fish” or “junk” (a piece of equipment, a tool, a part of the drill string or debris) in a well that is causing an obstruction. We also install whipstocks to sidetrack wells, provide plugging and abandonment services, pipe recovery and wireline recovery services, foam services and casing patch installation.
 
  •  Pressure Testing Services. We provide specialized pressure testing services which involve the use of truck mounted equipment designed to carry small fluid volumes with high pressure pumps and hydraulic torque equipment. This equipment is primarily used to perform pressure tests on flow line, pressure vessels, lubricators, well heads, casings and tubing strings. The units are also used to assemble and disassemble BOPs for the drilling and work over sector. We have developed specialized, multi-service pressure testing units that enable one or two employees to complete multiple services simultaneously. As of September 30, 2005, we had 30 multi-service pressure testing units that we operated in Colorado, Utah and Wyoming.
Fluid Handling
      Oil and gas operations use and produce significant quantities of fluids. We provide a variety of services to assist our customers to obtain, move, store and dispose of fluids that are involved in the development and production of their reservoirs. We provide fluid handling services in Texas, Oklahoma, Colorado, Wyoming, North Dakota and Montana.
  •  Fluid Transpiration. As of September 30, 2005, we operated over 600 specialized transport trucks to deliver, transport and dispose of fluids safely and efficiently. We transport fresh water, completion fluids, produced water, drilling mud and other fluids to and from our customers’ wellsites. Our assets include U.S. Department of Transportation certified equipment for transportation of hazardous waste.
 
  •  Frac Tank Rental. As of September 30, 2005, we operated a fleet of over 1,250 frac tanks that are often used during hydraulic fracturing operations. We use our fleet of fluid transport assets to fill and empty these tanks and we deliver and remove these tanks from the wellsite with our fleet of winch trucks.
 
  •  Fluid Disposal. As of September 30, 2005, we owned 14 salt water disposal wells in Oklahoma and Texas and one produced water evaporation facility in Wyoming. These facilities are used to dispose of water from fracturing operations and from fluids produced during the routine production

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  of oil and gas. In addition, we also operated two mud disposal facilities that are used to store and ultimately dispose of drilling mud.
 
  •  Other Services. We own and operate a fleet of hot oilers and superheaters, which are assets capable of heating high volumes of fluids. We also sell fluids used during well completions, such as fresh water and potassium chloride, and drilling mud, which we move to our customers’ wellsites using our fluid transportation services.
Drilling Services (17% of Revenue for the Nine Months Ended September 30, 2005)
      Through our drilling services segment, we deliver services that initiate or stimulate oil and gas production by providing land drilling, specialized rig logistics and site preparation. Through this segment, we also provide pressure control, drill string, pipe handling and downhole tools and equipment. Our drilling rigs currently operate exclusively in the Barnett Shale region of north Texas.
Contract Drilling
      We provide contract drilling services to major oil companies and independent oil and gas producers in north Texas. Contract drilling services are primarily provided under standard day rate, and, to a lesser extent, footage or turnkey contracts. Drilling rigs vary in size and capability and may include specialized equipment. As of September 30, 2005, the majority of our drilling rig fleet of 12 drilling rigs was equipped with mechanical power systems and had depth ratings ranging from approximately 8,000 to 15,000 feet. We also had two land drilling rigs under construction as of September 30, 2005 which we expect to be operational by the end of 2005.
Drilling Logistics
We provide a variety of drilling logistic services as follows:
  •  Drilling Rig Moving. Through our owned and operated fleet of over 200 specialized trucks as of September 30, 2005, we provide drilling rig mobilization services primarily in Louisiana, Texas, Oklahoma, Arkansas and Wyoming. Our capabilities allow us to move the largest rigs in the United States. Our operations are strategically located in regions where approximately 50% of the land drilling rigs in the United States are located. We believe we have a leading market position in the Gulf Coast region of Texas and Louisiana. We believe our highly skilled personnel position us as one of the leading rig moving companies in the industry.
 
  •  Wellsite Preparation and Remediation. We provide equipment and services to build and reclaim drilling wellsites before and after the drilling operations take place. We build roads, dig pits, clear land, move earth and provide a host of construction services to drilling contractors and to oil and gas producers. Our wellsite preparation and remediation services are in Texas, Colorado and Wyoming.
Product Sales (17% of Revenue for the Nine Months Ended September 30, 2005)
      Through our product sales segment, we provide a variety of equipment used by oil and gas companies throughout the lifecycle of their wells. Our current product offering includes completion, flow control and artificial lift equipment as well as tubular goods. We sell products throughout North America primarily through our supply stores and through distributors on a wholesale basis. We also sell products through agents in markets outside of North America.
Supply Stores
      We own and operate supply stores that provide products and services to the oil and gas industry. As of September 30, 2005, we had a total of 11 supply stores and 2 sales offices in Texas, Colorado, Louisiana and Oklahoma. We market tubular products, drill pipe, flow control and completion equipment, valves, fittings and other oilfield products.

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Production Enhancement Products
      Our production enhancement products group designs, assembles and distributes flow control, well completion and artificial lift products primarily in North America.
  •  Flow Control Products. We are a leading independent supplier of subsurface flow control equipment to the North American oil and gas market. Our product line includes downhole blanking plugs, landing nipples, sliding sleeves, flapper valves and bottom-hole chokes. Through our flow control business, we also provide a proprietary thermo chemical metal treatment process known as HARD KOTEtm that increases the useful life of downhole equipment by providing enhanced resistance to abrasion, adhesion, erosion and corrosion.
 
  •  Well Completion Products. We offer a comprehensive line of well completion products, which include packers, tubing anchors, plugs, retainers and other completion accessories.
 
  •  Artificial Lift Systems. Our line of artificial lift system accessories is designed to optimize the performance of rod pump and progressive cavity (“PC”) or screw pump systems. We are a leader in tools designed to prevent the counter rotation of PC pumps, particularly during high-volume operation, and we hold eight patents in this area. Other accessories include tubing centralizers and downhole gas separators installed below the pump. Downhole gas separators remove the natural gas from the reservoir fluid before it enters the pump, thus improving pump efficiency.
      Our production enhancement products are sold throughout North America primarily through distributors on a wholesale basis, through our supply stores and through agents in international markets.
Manufacturing
      Our manufacturing business produces a number of wellsite production processing facility components. Products include pressure vessels, separators, line heaters, dehydration units, header packages and metering skids. Our equipment is designed to comply with the standards of the American Society of Mechanical Engineers National Board “U” stamp and the Alberta Boilers Safety Association. Customers for our manufactured products are predominantly gas producing companies in Canada; however, the business does provide equipment throughout North America and may periodically ship products into international markets, including India and South America.
Overseas Operations
      We operate an oilfield sales service and rental business based in Singapore. This business sells new and reconditioned equipment used in the construction and upgrade of offshore drilling rigs; rents mud coolers, tubular handling equipment, BOPs and other service tools; and provides machining and repair services.
Properties
      As of September 30, 2005, we own 41 offices, facilities and yards, of which seven are in Texas, 19 are in Oklahoma, one is in North Dakota, one is in Montana, six are in Wyoming, two are in Colorado, three are in Louisiana, one is in Alberta, Canada, and one is in Poza Rica, Mexico. As of September 30, 2005, we own 14 salt water disposal wells, of which three are in Texas and 11 are in Oklahoma. As of September 30, 2005, we own one drilling mud disposal facility in Oklahoma and one produced water evaporation facility in Wyoming.
      In addition, as of September 30, 2005, we lease 136 offices, facilities and yards, of which 49 are in Texas, eight are in Oklahoma, 22 are in Wyoming, 19 are in Colorado, seven are in Louisiana, three are in Utah, 20 are in Alberta, Canada, one is in British Columbia, Canada, three are in Mexico and four are in Singapore.

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Sales and Marketing
      Most sales and marketing activities are performed through our local operations in each geographical region. We believe our local field sales personnel have an excellent understanding of basin-specific issues and customer operating procedures and, therefore, can effectively target marketing activities. We also have a small corporate sales team located in Houston, Texas that supplements our field sales efforts and focuses on large accounts and selling technical services.
Customers
      Our customers consist of large multi-national and independent oil and gas producers, as well as smaller independent producers and virtually all of the major land-based drilling contractors in North America. Our top ten customers accounted for approximately 33% of combined revenue for the nine months ended September 30, 2005, with no one customer representing more than 10% of revenues in this period. We believe we have a broad customer base and wide geographic coverage of operations, which somewhat insulates us from regional or customer specific circumstances that might cause a significant erosion in revenue.
Operating Risk and Insurance
      Our operations are subject to hazards inherent in the oil and gas industry, such as accidents, blowouts, explosions, fires and oil spills that can cause:
  •  personal injury or loss of life;
 
  •  damage or destruction of property, equipment and the environment; and
 
  •  suspension of operations.
      In addition, claims for loss of oil and gas production and damage to formations can occur in the well services industry. If a serious accident were to occur at a location where our equipment and services are being used, it could result in our being named as a defendant in lawsuits asserting large claims.
      Because our business involves the transportation of heavy equipment and materials, we may also experience traffic accidents which may result in spills, property damage and personal injury.
      Despite our efforts to maintain high safety standards, we from time to time have suffered accidents in the past and anticipate that we could experience accidents in the future. In addition to the property and personal losses from these accidents, the frequency and severity of these incidents affect our operating costs and insurability and our relationships with customers, employees and regulatory agencies. Any significant increase in the frequency or severity of these incidents, or the general level of compensation awards, could adversely affect the cost of, or our ability to obtain, workers’ compensation and other forms of insurance, and could have other material adverse effects on our financial condition and results of operations.
      Although we maintain insurance coverage of types and amounts that we believe to be customary in the industry, we are not fully insured against all risks, either because insurance is not available or because of the high premium costs. We do maintain commercial general liability, workers’ compensation, business auto, excess auto liability, commercial property, rig physical damage and contractor’s equipment, motor truck cargo, umbrella liability and excess liability, non-owned aircraft liability, directors and officers, employment practices liability, fiduciary, commercial crime and kidnap and ransom insurance policies. However, any insurance obtained by us may not be adequate to cover any losses or liabilities and this insurance may not continue to be available or available on terms which are acceptable to us. Liabilities for which we are not insured, or which exceed the policy limits of our applicable insurance, could have a material adverse effect on us.

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Competition
      The markets in which we operate are highly competitive. To be successful, a company must provide services and products that meet the specific needs of oil and gas exploration and production companies and drilling services contractors at competitive prices.
      We provide our services and products across North America, and we compete against different companies in each service and product line we offer. Our competition includes many large and small oilfield service companies, including the largest integrated oilfield services companies.
      Our major competitors for our completion and production services segment include Schlumberger Ltd., BJ Services Company, Halliburton Company, Weatherford International Ltd., Baker Hughes Inc., Key Energy Services, Inc., Basic Energy Services, Inc., Superior Energy Services, Inc., Tetra Technologies, Inc. and a significant number of locally oriented businesses. In our drilling services segment, our primary competitors include Nabors Industries Ltd., Patterson-UTI Energy, Inc., Unit Corporation and Helmerich & Payne, Grey Wolf Inc. Our principal competitors in our product sales segment include National Oilwell Varco, Inc., Baker Hughes Inc., Weatherford International Ltd., Halliburton Company, Smith International, Inc., and various smaller providers of equipment. We believe that the principal competitive factors in the market areas that we serve are quality of service and products, reputation for safety and technical proficiency, availability and price. While we must be competitive in our pricing, we believe our customers select our services and products based on local leadership and basin-expertise that our personnel use to deliver quality services and products.
Government Regulation
      We operate under the jurisdiction of a number of regulatory bodies that regulate worker safety standards, the handling of hazardous materials, the transportation of explosives, the protection of the environment and driving standards of operation. Regulations concerning equipment certification create an ongoing need for regular maintenance which is incorporated into our daily operating procedures. The oil and gas industry is subject to environmental regulation pursuant to local, state and federal legislation.
      Among the services we provide, we operate as a motor carrier and therefore are subject to regulation by the U.S. Department of Transportation and by various state agencies. These regulatory authorities exercise broad powers, governing activities such as the authorization to engage in motor carrier operations, and regulatory safety, financial reporting and certain mergers, consolidations and acquisitions. There are additional regulations specifically relating to the trucking industry, including testing and specification of equipment and product handling requirements. The trucking industry is subject to possible regulatory and legislative changes that may affect the economics of the industry by requiring changes in operating practices or by changing the demand for common or contract carrier services or the cost of providing truckload services. Some of these possible changes include increasingly stringent environmental regulations, changes in the hours of service regulations which govern the amount of time a driver may drive in any specific period, onboard black box recorder devices or limits on vehicle weight and size.
      Interstate motor carrier operations are subject to safety requirements prescribed by the Department of Transportation. To a large degree, intrastate motor carrier operations are subject to safety regulations that mirror federal regulations. Such matters as weight and dimension of equipment are also subject to federal and state regulations. Department of Transportation regulations mandate drug testing of drivers.
      From time to time, various legislative proposals are introduced, including proposals to increase federal, state, or local taxes, including taxes on motor fuels, which may increase our costs or adversely impact the recruitment of drivers. We cannot predict whether, or in what form, any increase in such taxes applicable to us will be enacted.
Environmental Matters
      Our operations are subject to numerous foreign, federal, state and local environmental laws and regulations governing the release and/or discharge of materials into the environment or otherwise relating

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to environmental protection. Numerous governmental agencies issue regulations to implement and enforce these laws, for which compliance is often costly and difficult. The violation of these laws and regulations may result in the denial or revocation of permits, issuance of corrective action orders, assessment of administrative and civil penalties, and even criminal prosecution. We believe that we are in substantial compliance with applicable environmental laws and regulations. Further, we do not anticipate that compliance with existing environmental laws and regulations will have a material effect on our consolidated financial statements. However, it is possible that substantial costs for compliance may be incurred in the future. Moreover, it is possible that other developments, such as the adoption of stricter environmental laws, regulations, and enforcement policies, could result in additional costs or liabilities that we cannot currently quantify.
      We generate wastes, including hazardous wastes, that are subject to the federal Resource Conservation and Recovery Act, or RCRA, and comparable state statutes. The U.S. Environmental Protection Agency, or EPA, and state agencies have limited the approved methods of disposal for some types of hazardous and nonhazardous wastes. Some wastes handled by us in our field service activities that currently are exempt from treatment as hazardous wastes may in the future be designated as “hazardous wastes” under RCRA or other applicable statutes. If this were to occur, we would become subject to more rigorous and costly operating and disposal requirements.
      The federal Comprehensive Environmental Response, Compensation, and Liability Act, CERCLA or the “Superfund” law, and comparable state statutes impose liability, without regard to fault or legality of the original conduct, on classes of persons that are considered to have contributed to the release of a hazardous substance into the environment. Such classes of persons include the current and past owners or operators of sites where a hazardous substance was released, and companies that disposed or arranged for disposal of hazardous substances at offsite locations such as landfills. Under CERCLA, these persons may be subject to joint and several liability for the costs of cleaning up the hazardous substances that have been released into the environment and for damages to natural resources, and it is not uncommon for neighboring landowners and other third parties to 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 and facilities that for many years have been used for industrial activities, including oil and gas production operations. 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 where such substances have been taken for disposal. In addition, some of these properties have been operated by third parties or by previous owners whose treatment and disposal or release 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 (including substances disposed of or released by prior owners or operators), remediate contaminated property (including groundwater contamination, whether from prior owners or operators or other historic activities or spills), or perform remedial plugging or pit closure operations to prevent future contamination. These laws and regulations may also expose us to liability for our acts that were in compliance with applicable laws at the time the acts were performed.
      In the course of our operations, some of our equipment may be exposed to naturally occurring radiation associated with oil and gas deposits, and this exposure may result in the generation of wastes containing naturally occurring radioactive materials or “NORM.” NORM wastes exhibiting trace levels of naturally occurring radiation in excess of established state standards are subject to special handling and disposal requirements, and any storage vessels, piping, and work area affected by NORM may be subject to remediation or restoration requirements. Because many of the properties presently or previously owned, operated, or occupied by us have been used for oil and gas production operations for many years, it is possible that we may incur costs or liabilities associated with elevated levels of NORM.
      The Federal Water Pollution Control Act, also known as the Clean Water Act, and analogous state laws impose restrictions and strict controls regarding the discharge of pollutants into state waters or waters of the United States. The discharge of pollutants into jurisdictional waters is prohibited unless the discharge is permitted by the EPA or applicable state agencies. Many of our properties and operations

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require permits for discharges of wastewater and/or stormwater, and we have a system for securing and maintaining these permits. In addition, the Oil Pollution Act of 1990 imposes a variety of requirements on responsible parties related to the prevention of oil spills and liability for damages, including natural resource damages, resulting from such spills in waters of the United States. A responsible party includes the owner or operator of a facility. The Federal Water Pollution Control Act and analogous state laws provide for administrative, civil and criminal penalties for unauthorized discharges and, together with the Oil Pollution Act, impose rigorous requirements for spill prevention and response planning, as well as substantial potential liability for the costs of removal, remediation, and damages in connection with any unauthorized discharges.
      Our underground injection operations are subject to the federal Safe Drinking Water Act, as well as analogous state and local laws and regulations. Under Part C of the Safe Drinking Water Act, the EPA established the Underground Injection Control program, which established the minimum program requirements for state and local programs regulating underground injection activities. The Underground Injection Control program includes requirements for permitting, testing, monitoring, record keeping and reporting of injection well activities, as well as a prohibition against the migration of fluid containing any contaminant into underground sources of drinking water. State regulations require us to obtain a permit from the applicable regulatory agencies to operate our underground injection wells. We believe that we have obtained the necessary permits from these agencies for our underground injection wells and that we are in substantial compliance with permit conditions and state rules. Nevertheless, these regulatory agencies have the general authority to suspend or modify one or more of these permits if continued operation of one of our underground injection wells is likely to result in pollution of freshwater, substantial violation of permit conditions or applicable rules, or leaks to the environment. Although we monitor the injection process of our wells, any leakage from the subsurface portions of the injection wells could cause degradation of fresh groundwater resources, potentially resulting in cancellation of operations of a well, issuance of fines and penalties from governmental agencies, incurrence of expenditures for remediation of the affected resource and imposition of liability by third parties for property damages and personal injuries. In addition, our sales of residual crude oil collected as part of the saltwater injection process could impose liability on us in the event that the entity to which the oil was transferred fails to manage the residual crude oil in accordance with applicable environmental health and safety laws.
      Some of our operations also result in emissions of regulated air pollutants. The federal Clean Air Act and analogous state laws require permits for facilities that have the potential to emit substances into the atmosphere that could adversely affect environmental quality. Failure to obtain a permit or to comply with permit requirements could result in the imposition of substantial administrative, civil and even criminal penalties.
      We are also subject to the requirements of the federal Occupational Safety and Health Act (OSHA) and comparable state statutes that regulate the protection of the health and safety of workers. In addition, the OSHA hazard communication standard requires that information be maintained about hazardous materials used or produced in operations and that this information be provided to employees, state and local government authorities and the public. We believe that our operations are in substantial compliance with the OSHA requirements, including general industry standards, record keeping requirements, and monitoring of occupational exposure to regulated substances.
Employees
      As of September 30, 2005, we had 3,889 employees. Of our total employees, 3,157 were in the United States, 502 were in Canada, 174 were in Mexico and 56 were in Singapore and other locations in the Far East. We are a party to certain collective bargaining agreements in Mexico. Other than these agreements in Mexico, we are not a party to any collective bargaining agreements, and we consider our relations with our employees to be satisfactory.

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Legal Proceedings
      We operate in a dangerous business. We are party to various pending or threatened claims, lawsuits and administrative proceedings seeking damages or other remedies concerning our commercial operations, products, employees and other matters, including warranty and product liability claims and occasional claims by individuals alleging exposure to hazardous materials, on the job injuries and fatalities as a result of our products or operations. Many of the claims filed against us relate to motor vehicle accidents that result in the loss of life or serious bodily injury. Some of these claims relate to matters occurring prior to our acquisition of businesses. In certain cases, we are entitled to indemnification from the sellers of businesses.
      Although we cannot know the outcome of pending legal proceedings and the effect such outcomes may have on us, we believe that any ultimate liability resulting from the outcome of such proceedings, to the extent not otherwise provided for or covered by insurance, will not have a material adverse effect on our financial position, results of operations or liquidity.

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MANAGEMENT
      Our directors, executive officers and other key operational management employees, their ages and their positions as of September 30, 2005 are as follows:
             
Name   Age   Position
         
Andrew L. Waite
    44     Chairman of the Board
Joseph C. Winkler
    54     Director, President and Chief Executive Officer
J. Michael Mayer
    49     Senior Vice President and Chief Financial Officer
James F. Maroney, III
    54     Vice President, Secretary and General Counsel
Kenneth L. Nibling
    54     Vice President, Human Resources and Administration
Robert L. Weisgarber
    53     Vice President — Accounting and Controller
David C. Baldwin
    42     Director
Robert S. Boswell
    55     Director
Harold G. Hamm
    59     Director
R. Graham Whaling
    51     Director
James D. Woods
    73     Director
Ronald Boyd
    49     President Mid-Continent Division
Lee Daniel, III
    59     President Rockies Division
Brian K. Moore
    48     President IPS Operations
John D. Schmitz
    45     President Texas Division
      Andrew L. Waite. Mr. Waite has served as Chairman of our board of directors since the date of the Combination. Mr. Waite is a Managing Director of L.E. Simmons and Associates, Incorporated and has been an officer of that company since October 1995. He was previously Vice President of Simmons & Company International, where he served from August 1993 to September 1995. From 1984 to 1991, Mr. Waite held a number of engineering and management positions with the Royal Dutch/ Shell Group, an integrated energy company. From November 2003 to June 2005, he served as Chairman, President and Chief Executive Officer of CES. He served as Chairman of CES prior to the Combination and currently serves as a director of Oil States International, Inc. (NYSE: OIS), a provider of products and services to oil and gas drilling and production companies and as a director of Hornbeck Offshore Services, Inc. (NYSE: HOS), an operator of offshore supply vessels and other marine assets. He received an M.B.A. degree from the Harvard University Graduate School of Business Administration and an M.S. degree from the California Institute of Technology.
      Joseph C. Winkler. Mr. Winkler has served as our President and Chief Executive Officer since the date of the Combination and a director since June 2005. On June 20, 2005, Mr. Winkler assumed his duties as President and Chief Executive Officer of CES and a director of CES, IEM and IPS. Mr. Winkler served as the Executive Vice President and Chief Operating Officer of National Oilwell Varco, Inc. from March 2005 until June 2005 and Varco International, Inc.’s President and Chief Operating Officer from May 2003 until March 2005. From April 1996 until May 2003, Mr. Winkler served in various other capacities with Varco and its predecessor including Executive Vice President and Chief Financial Officer. From 1993 to April 1996, Mr. Winkler served as the Chief Financial Officer of D.O.S., Ltd., a privately held provider of solids control equipment and services and coil tubing equipment to the oil and gas industry, which was acquired by Varco in April 1996. Prior to joining D.O.S., Ltd., he was Chief Financial Officer of Baker Hughes INTEQ, and served in a similar role for various companies owned by Baker Hughes Incorporated including Eastman/ Teleco and Milpark Drilling Fluids. Mr. Winkler received a Bachelor of Science degree from Louisiana State University.
      J. Michael Mayer. Mr. Mayer has served as our Senior Vice President and Chief Financial Officer since the date of the Combination. He joined CES as Vice President and Chief Financial Officer in May 2004. Prior to joining CES, Mr. Mayer served as the Chief Financial Officer of Tri-Point Energy Services,

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Inc., a Houston based private company providing repair and refurbishment services to the drilling industry from March 2003 until May 2004. Before joining Tri-Point, Mr. Mayer was the Chief Financial Officer of NATCO Group Inc., an NYSE-listed provider of process and production equipment to the oil and gas industry from September 1999 to March 2003. At NATCO, Mr. Mayer was active in taking the company public in 2000 and completed a number of acquisitions while in that role. He has served as Chief Financial Officer in a number of private entities engaged in various facets of the oilfield service industry, as well as approximately 10 years in various financial management positions at Baker Hughes Incorporated. Mr. Mayer received a Bachelor of Business Administration degree from Texas A&M University and is a certified public accountant.
      James F. Maroney, III. Mr. Maroney has served as our Vice President, Secretary and General Counsel since October 2005. From August 2005 until October 2005 Mr. Maroney surveyed various opportunities until accepting employment with us. Mr. Maroney served as Of Counsel to National Oilwell Varco, Inc. from March to August 2005. He served as Vice President, Secretary and General Counsel of Varco International, Inc. from May 2000 until March 2005. Prior to that time, Mr. Maroney served as Vice President, Secretary and General Counsel of Tuboscope, Inc.
      Kenneth L. Nibling. Mr. Nibling has served as our Vice President, Human Resources and Administration since October 2005. From July 2005 to October 2005, Mr. Nibling surveyed various opportunities until accepting employment with us. He served as Vice President, Human Resources of National Oilwell Varco, Inc. from March through July 2005. He served as Varco International, Inc.’s Vice President, Human Resources and Administration of Varco International, Inc. from May 2000 until March 2005. Prior to that time, Mr. Nibling served as Vice President, Human Resources and Administration of Tuboscope, Inc.
      Robert L. Weisgarber. Mr. Weisgarber has served as our Vice President – Accounting and Controller since September 2005. From April 2004 until September 2005, he served as the Vice President – Accounting of CES. From October 2003 until April 2004, Mr. Weisgarber served as CFO Partner for Tatum Partners. Prior to joining Tatum Partners, Mr. Weisgarber served as Chief Financial Officer of DSI Toys, Inc. from March 1999 until October 2003.
      David C Baldwin. Mr. Baldwin has served as a director since September 2002. From September 2002 to April 2004, Mr. Baldwin occupied the position of President and Chief Executive Officer of IPS. Mr. Baldwin is a Managing Director of L.E. Simmons and Associates, Incorporated, which he joined 1991. He served as Chairman of the board of directors of IPS and IEM prior to the Combination. Prior to joining SCF, Mr. Baldwin was a drilling and production engineer with Union Pacific Resources. He received both a B.S. degree in Petroleum Engineering and an M.B.A. degree from the University of Texas at Austin.
      Robert S. Boswell. Mr. Boswell has served as a director since the date of the Combination. He serves as Chairman and Chief Executive Officer of Laramie Energy, LLC, a Denver-based privately held oil and gas exploration and production company he founded in September 2003. Prior to his time at Laramie, Mr. Boswell served as Chairman of the board of directors of Forest Oil from March 2000 until September 2003. He served as Chief Executive Officer of Forest Oil Corporation from December 1995 until September 2003. Mr. Boswell served as Forest Oil’s President from November 1993 to March 2000 and Chief Financial Officer from May 1991 until December 1995. Mr. Boswell was a member of the board of directors of Forest Oil from 1986 until September 2003. He has also served as a director of C.E. Franklin Ltd.
      Harold G. Hamm. Mr. Hamm has served as a director since the date of the Combination. Mr. Hamm was elected Chairman of the board of directors of Hiland Partners’ general partner in October 2004. Hiland Partners is a NASDAQ publicly traded midstream master limited partnership. Mr. Hamm has served as President and Chief Executive Officer and as a director of Continental Gas, Inc. since December 1994 and then served as Chief Executive Officer and a director to 2004. Since its inception in 1967, Mr. Hamm has served as President and Chief Executive Officer and a director of Continental Resources, Inc. and currently serves as Chairman of its board of directors. Mr. Hamm is the chairman of

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the Oklahoma Independent Petroleum Association. He is the founder and served as Chairman of the board of directors of Save Domestic Oil, Inc. Currently, Mr. Hamm is President of the National Stripper Well Association, and serves on the executive boards of the Oklahoma Independent Petroleum Association and the Oklahoma Energy Explorers.
      R. Graham Whaling. Mr. Whaling has served as a director since the date of the Combination. In addition, he has served as a director of Brigham Exploration Company, an independent exploration and production company, since June 2001. Mr. Whaling is currently Chairman and Chief Executive Officer of Laredo Energy, LP and has spent his entire career in the energy industry, as a petroleum engineer, an energy investment banker, a chief financial officer and a chief executive officer of energy companies. Mr. Whaling worked as a petroleum engineer for nine years in the beginning of his career primarily with Ryder Scott Company, an oil and gas consulting firm. Mr. Whaling then spent seven years as an investment banker focusing on the energy industry with Lazard Freres & Co. and Credit Suisse First Boston. Mr. Whaling then became the Chief Financial Officer for Santa Fe Energy where he managed the initial public offering and the spin-off of Santa Fe’s western division, Monterey Resources. Mr. Whaling was Chairman and Chief Executive Officer of Monterey Resources from its inception until it was acquired by Texaco in 1997. From May 1999 to May 2001, Mr. Whaling was a Managing Director with Credit Suisse First Boston’s Global Energy Partners, which specializes in private equity investments in energy businesses world-wide. Immediately prior to joining Laredo Energy, LP, Mr. Whaling was Chairman of Michael Petroleum.
      James D. Woods. Mr. Woods has served as a director since June 2001. During the period beginning in 1988 and ending in March 2005, Mr. Woods served as director of Varco at various times. Mr. Woods is the Chairman Emeritus and retired Chief Executive Officer of Baker Hughes Incorporated. Mr. Woods was Chief Executive Officer of Baker Hughes from April 1987, and Chairman from January 1989, in each case until January 1997. Mr. Woods is also a director of National Oilwell Varco, Inc. and ESCO Technologies, an NYSE-listed supplier of engineered filtration precuts to the process, healthcare and transportation markets; Foster Wheeler Ltd., an OTC-traded holding company of various subsidiaries which provides a broad range of engineering, design, construction and environmental services; OMI Corporation, an NYSE-listed bulk shipping company providing seaborne transportation services primarily of crude oil and refined petroleum products; and USEC Inc., an NYSE-listed supplier of enriched uranium.
Key Operational Management
      Ronald Boyd – President Mid-Continent Division. Mr. Boyd served as the President of the Mid-Continent Division of CES from October 2004 until the date of the Combination. He currently serves in this capacity with us. Mr. Boyd joined the Hamm Group of Companies in 1988 where he served as President until the group was acquired by CES in October 2004. From 1982 to 1988, he served as Vice President for MB Oilfield Services, an oilfield services company. He received his drilling fluid engineer certification and was Regional Engineer Supervisor for Milchem, Inc., a drilling fluids company until 1982. Mr. Boyd began his career in Western Oklahoma in 1973 working on drilling rigs.
      Lee Daniel, III – President Rockies Division. Mr. Daniel served as the President of the Rockies Division of CES from February 2004 until the date of the Combination. Mr. Daniel currently serves in this capacity with us. Mr. Daniel founded LEED Energy Services in February 1990 and served as President and Chief Executive Officer of LEED until it was acquired by CES in February 2004. Prior to founding LEED, Mr. Daniel was the President and Chief Operating Officer of Oil Field Rental Service Company (“OFRS”) in Houston, Texas. OFRS was a subsidiary of Enterra Corporation, which has since merged with Weatherford International. Mr. Daniel received a Bachelor of Business Administration degree from the University of Oklahoma.
      Brian K. Moore – President IPS Operations. From April 2004 through September 12, 2005, Mr. Moore served as President and Chief Executive Officer and a director of IPS. From January 2001 through April 2004, Mr. Moore served as General Manager – Oilfield Services, U.S. Land Central Region,

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at Schlumberger. Prior to serving as General Manager – Oilfield Services, Mr. Moore served as Pressure Pumping Manager for Schlumberger’s Eastern Region from July 1999 to January 2001. Mr. Moore has over 24 years of oilfield service experience including 15 years with Camco International where he served in various management and engineering positions including General Manager – Coiled Tubing Operations.
      John D. Schmitz – President Texas Division. Mr. Schmitz served as the President of the Texas Division of CES from November 2003 until the date of the Combination. Mr. Schmitz currently serves in this capacity with us. In 1983, Mr. Schmitz founded Brammer Supply (“Brammer”) and spent the next 20 years growing Brammer, both organically and through acquisitions, into BSI, an integrated wellsite service provider with over 16 locations in North and East Texas, Oklahoma and Louisiana, which was acquired by CES in November 2003. Mr. Schmitz began his career as a sales representative for Fluid Packed Pumps in 1979.
      There are no family relationships among any of our directors, executive officers or key operational management employees. The address of each director, executive officer and key operational management employee is: c/o Complete Production Services, Inc., 14450 JFK Blvd., Suite 400, Houston, Texas 77032.
Board of Directors
      Our board of directors currently consists of seven members, including three independent members – Messrs. Boswell, Whaling and Woods. The listing requirements of the NYSE require that our board of directors be composed of a majority of independent directors within one year of the listing of our common stock on the NYSE. Accordingly, we intend to appoint additional independent directors to our board of directors following the completion of this offering.
      Our board of directors is divided into three classes. The directors serve staggered three-year terms. The initial terms of the directors of each class will expire at the annual meetings of stockholders to be held in 2006 (Class I), 2007 (Class II) and 2008 (Class III). At each annual meeting of stockholders, one class of directors will be elected for a full term of three years to succeed that class of directors whose terms are expiring. The classification of directors are as follows:
  •  Class I – Messrs. Joseph C. Winkler, Andrew L. Waite and R. Graham Whaling;
 
  •  Class II – Messrs. Harold G. Hamm and James D. Woods; and
 
  •  Class III – Messrs. David C. Baldwin and Robert S. Boswell.
      SCF has certain rights to designate up to two members of our board of directors. See “Description of Our Capital Stock – Stockholders Agreement – Management Rights.”
Audit Committee
      Our audit committee is currently comprised of Messrs. Whaling and Boswell. Our board has determined that Messrs. Whaling and Boswell are independent directors as defined under and required by the Securities Exchange Act of 1934, or the Exchange Act, and the listing requirements of the NYSE. Rule 10A-3 under the Exchange Act and the listing requirements of the NYSE require that our audit committee be composed of a minimum of three members and that it be composed of a majority of independent directors within 90 days of the effectiveness of the registration statement of which this prospectus is a part and that it be composed solely of independent directors within one year of such date. Accordingly, we intend to appoint an additional director to our audit committee prior to the completion of the offering and to take any further action needed to comply with Rule 10A-3 under the Exchange Act and the listing requirements of the NYSE following completion of the offering. Following this offering, one member of the audit committee will be designated as the audit committee financial expert, as defined by Item 401(h) of Regulation S-K of the Exchange Act. The principal duties of the audit committee will be as follows:
  •  to review our external financial reporting;

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  •  to engage our independent auditors; and
 
  •  to review our procedures for internal auditing and the adequacy of our internal accounting controls.
      Our board of directors has adopted a written charter for the audit committee that will be available on our website after the completion of this offering.
Nominating and Corporate Governance Committee
      Our nominating and corporate governance committee is currently comprised of Messrs. Woods and Hamm. The listing requirements of the NYSE require that our nominating and corporate governance committee be composed of a majority of independent directors within 90 days of the listing of our common stock on the NYSE and that it be composed solely of independent directors within one year of such date. The principal duties of the nominating and corporate governance committee will be as follows:
  •  to recommend to the board of directors proposed nominees for election to the board of directors by the stockholders at annual meetings, including an annual review as to the renominations of incumbents and proposed nominees for election by the board of directors to fill vacancies that occur between stockholder meetings; and
 
  •  to make recommendations to the board of directors regarding corporate governance matters and practices.
      Our board of directors has adopted a written charter for the corporate governance and nominating committee that will be available on our website after the closing of this offering.
Compensation Committee
      Our compensation committee is currently comprised of Messrs. Woods and Whaling. Our board has determined that Messrs. Woods and Whaling are independent as required by the listing requirements of the NYSE. The principal duties of the compensation committee will be as follows:
  •  to administer our stock plans and incentive compensation plans, including our stock incentive plans, and in this capacity, make all option grants or awards to our directors and employees under such plans;
 
  •  to make recommendations to the board of directors with respect to the compensation of our chief executive officer and our other executive officers; and
 
  •  to review key employee compensation policies, plans and programs.
      Our board of directors has adopted a written charter for the compensation committee that will be available on our website after the completion of this offering.
Compensation of Directors
      Directors who are also employees do not receive a retainer or fees for service on our board of directors or any committees. Directors who are not employees will receive an annual fee of $27,500 and fees of $1,500 for attendance at each meeting of our board of directors or $750 for each meeting of our board of directors attended telephonically. In addition, the chairman of the audit committee will receive an annual fee of $15,000 and each director who serves as committee chairmen (other than chairman of the audit committee) will receive an annual fee of $7,500 for each committee on which he serves as chairman. Directors who are not employees will receive options to purchase 2,500 shares of our common stock in connection with their election to the board of directors and options to purchase 2,500 shares of our common stock at each annual meeting after which they continue to serve. These options will be granted under our 2001 Stock Incentive Plan, will vest in four annual installments and will expire ten years from the date of grant. In the event of a change of control, the options will vest in accordance with the plan. The exercise price of these options will be the fair market value at the date of grant. In addition, directors who are not employees will receive an annual grant of restricted stock valued at $50,000. The restricted

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stock will vest on the anniversary of the date of grant. Directors must retain 65% of the restricted stock so long as they are a director of the Company. All of our directors are reimbursed for reasonable out-of-pocket expenses incurred in attending meetings of our board of directors or committees and for other reasonable expenses related to the performance of their duties as directors.
Web Access
      We will provide access through our website at www.completeprodsvcs.com to current information relating to governance, including a copy of each board committee charter, our code of conduct, our corporate governance guidelines and other matters impacting our governance principles. You may also contact our Chief Financial Officer for paper copies of these documents free of charge.
Compensation Committee Interlocks and Insider Participation
      None of our executive officers serve as a member of the board of directors or compensation committee of any entity that has one or more of its executive officers serving as a member of our board of directors or compensation committee.
Compensation of Executive Officers
      The following table summarizes all compensation earned by our Chief Executive Officer and our other most highly compensated executive officers during the year ended December 31, 2004, to whom we refer in this prospectus as our named executive officers.
Summary Compensation Table
                                   
                Options
Name and Principal Position   Year   Salary   Bonus   Granted
                 
Joseph C. Winkler(1)
    2004     $     $        
  President and Chief     2003                    
  Executive Officer     2002                    
J. Michael Mayer(2)
    2004     $ 106,298     $ 89,186       62,572  
  Senior Vice President and     2003                    
  Chief Financial Officer     2002                    
James F. Maroney, III(3)
    2004     $     $        
  Vice President, Secretary and     2003                    
  General Counsel     2002                    
Kenneth L. Nibling(4)
    2004     $     $        
  Vice President,     2003                    
  Human Resources and     2002                    
  Administration                                
Robert L. Weisgarber(5)
    2004     $ 141,667     $ 13,513       46,929  
  Vice President — Accounting     2003                    
  and Controller     2002                    
Andrew L. Waite(6)
    2004     $     $        
  Chairman of the Board     2003                    
  and Former Chief     2002                    
  Executive Officer                                
 
(1)  Upon the completion of the Combination, Mr. Winkler became our Chief Executive Officer, President and director. See “– Employment Agreements” below for a description of the terms of Mr. Winkler’s employment. Mr. Winkler was employed by CES as Chief Executive Officer and President and appointed as a director of CES in June 2005. The stockholders of CES prior to the Combination held a majority ownership in us following the Combination. In addition, former directors

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of CES represent a majority of the directors of our board of directors. Accordingly, CES is treated as the accounting acquirer in the Combination.
(2)  Upon the completion of the Combination, Mr. Mayer became our Senior Vice President and Chief Financial Officer. Mr. Mayer was employed by CES as Vice President and Chief Financial Officer in May 2004.
 
(3)  On October 3, 2005, Mr. Maroney became our Vice President, Secretary and General Counsel.
 
(4)  On October 3, 2005, Mr. Nibling became our Vice President, Human Resources and Administration.
 
(5)  Upon the completion of the Combination, Mr. Weisgarber became our Vice President — Accounting and Controller. Mr. Weisgarber was employed by CES as Vice President — Accounting in April 2004.
 
(6)  Mr. Waite is the Chairman of our board of directors and served as the Chief Executive Officer of CES prior to the hiring of Mr. Winkler in June 2005. Mr. Waite served as the Chief Executive Officer of CES from November 7, 2003 until June 20, 2005. Mr. Waite did not receive compensation from CES for his services as Chief Executive Officer. Mr. Waite is a Managing Director of L.E. Simmons and Associates, Incorporated. L.E. Simmons and Associates, Incorporated received certain consideration from CES in connection with its provision of support services to CES. For a description of these services, see “Certain Relationships and Related Party Transactions.”
Equity Grants
      The following table summarizes the option grants made to the Chief Executive Officer and the other named executive officers during 2004:
                                                   
                    Potential Realizable
                    Value at Assumed
                    Annual Rates of
                    Stock Price
    Appreciation for
Individual Grants   Options Term
     
    Number of   Percent of Total        
    Securities   Options/SARs        
    Underlying   Granted to   Exercise or        
    Option/SARs   Employees in   Base Price   Expiration    
Name   Granted   Fiscal Year   Per Share   Date   5%   10%
                         
Joseph C. Winkler
                                   
  President and Chief                                                
  Executive Officer                                                
J. Michael Mayer
    62,572       11.1%     $ 4.00(1)       06/2009     $ 69,070     $ 152,627  
  Senior Vice President and                                                
  Chief Financial Officer                                                
James F. Maroney, III
                                   
  Vice President, Secretary                                                
  and General Counsel                                                
Kenneth L. Nibling
                                   
  Vice President, Human                                                
  Resources and                                                
  Administration                                                
Robert L. Weisgarber
    46,929       8.3%       9.59(1)       11/2009     $ 124,340     $ 274,760  
  Vice President —                                                
  Accounting                                                
  and Controller                                                
Andrew L. Waite
                                   
  Chairman of the Board                                                
  Former Chief Executive                                                
  Officer                                                
 
(1)  Option price has been adjusted pursuant to FIN 44 to take into account the impact of the approximate $147.0 million Dividend paid to our stockholders following the Combination.

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Aggregated Option Exercises in 2004 and Fiscal Year-End Option Values
      The following table sets forth information concerning options exercised during the last fiscal year and held as of December 31, 2004 by each of the named executive officers. None of the named executive officers exercised options during the year ended December 31, 2004. Because there was no public market for our common stock as of December 31, 2004, amounts described in the following table under the heading “Value of Unexercised In-the-Money Options at December 31, 2004” are determined by multiplying the number of shares issued or issuable upon the exercise of the option by the difference between the assumed initial public offering price of $           per share and the per share option exercise price.
                                 
    Number of Shares Underlying   Value of Unexercised
    Unexercised Options at   In-the-Money Options at
    December 31, 2004   December 31, 2004
         
    Exercisable   Unexercisable   Exercisable   Unexercisable
                 
Joseph C. Winkler
                         
J. Michael Mayer
          62,572             $    
James F. Maroney, III
                       
Kenneth L. Nibling
                       
Robert L. Weisgarber
          46,929             $    
Andrew L. Waite
                         
Stock Incentive Plans
2001 Stock Incentive Plan
      In 2001 we adopted a stock incentive plan, which we refer to as the 2001 Stock Incentive Plan, for our and our affiliates’ officers, directors, consultants and employees. The 2001 Stock Incentive Plan amended and restated in its entirety our predecessor’s 2001 Stock Incentive Plan. Under the 2001 Stock Incentive Plan, eligible participants may receive incentive and nonqualified options to purchase shares of our common stock and/or an award of shares of our restricted stock. Under the 2001 Stock Incentive Plan, options to purchase up to 1,905,364 shares of our common stock may be granted to eligible participants. The terms of each incentive and non-qualified option will be determined by a committee of, and established by, our board of directors (the “Committee”). The Committee will determine the exercise price for both incentive and non-qualified options. Generally, these shares vest equally over a three-year period, have a five-year life and may be exercised only if the holder is one of our employees. As of September 30, 2005, under the 2001 Stock Incentive Plan, employees have been granted options for approximately 853,064 shares of our common stock.
      Our restricted stock that is granted under the 2001 Stock Incentive Plan is subject to certain restrictions on disposition by the holder and an obligation of the holder to forfeit and surrender the shares of our restricted stock to us under certain circumstances. These forfeiture restrictions are determined by the Committee and may lapse upon the occurrence of the following: (i) the attainment of certain performance targets established by the Committee, (ii) the holder’s continued employment with our company or an affiliate of our company or continued service as a consultant to or director of our company for a specified period of time, (iii) any event or the satisfaction of any condition specified by the Committee or (iv) a combination of the foregoing. As of September 30, 2005, 40,326 shares of our restricted stock have been granted under the 2001 Stock Incentive Plan.
2003 Stock Incentive Plan
      In connection with the Combination, we assumed CES’s 2003 Stock Incentive Plan, which we refer to as the 2003 Stock Incentive Plan, for certain officers, directors, consultants and employees. Under the 2003 Stock Incentive Plan, as amended, eligible participants received incentive and nonqualified options to purchase shares of CES common stock and/or an award of CES restricted stock, which options and shares were converted, respectively, to options for, and shares of, our common stock pursuant to the terms and conditions of the Combination. Generally, these shares vest equally over a three-year or four-year period, have a five-year life and may be exercised only if the holder is one of our employees, directors or

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consultants. As of September 30, 2005, under the 2003 Stock Incentive Plan, employees have been granted options for approximately 968,355 shares of our common stock. All options (other than options granted to Mr. Winkler) expire on the earlier of (i) 5 years from the date of grant; (ii) 90 days from the employee’s termination date; or (iii) one year from the employee’s termination due to death or disability.
      The restricted stock granted under the 2003 Stock Incentive Plan is subject to certain restrictions on disposition by the holder and an obligation of the holder to forfeit and surrender the shares of the restricted stock to us under certain circumstances. These forfeiture restrictions were determined by the CES board of directors and may lapse upon the occurrence of the following: (i) the attainment of certain performance targets established by the CES board of directors, (ii) the holder’s continued employment with our company or an affiliate of our company or continued service as a consultant to or director of our company for a specified period of time, (iii) any event or the satisfaction of any condition specified by the CES board of directors or (iv) a combination of the foregoing. As of September 30, 2005, 72,116 shares of our restricted stock had been granted under the 2003 Stock Incentive Plan.
      The 2003 Stock Incentive Plan shall continue to govern the existing options and restricted stock granted thereunder; however, no future awards will be made under the 2003 Stock Incentive Plan.
2004 Stock Incentive Plan
      In connection with the Combination, we assumed IEM’s 2004 Stock Incentive Plan, which we refer to as the 2004 Stock Incentive Plan, for certain officers, directors, consultants and employees. Under the 2004 Stock Incentive Plan, eligible participants received incentive and nonqualified options to purchase shares of IEM common stock and/or an award of IEM restricted stock, which options and shares were converted, respectively, to options for, and shares of, our common stock pursuant to the terms and conditions of the Combination. Generally, these shares vest equally over a three-year or four-year period, have a five-year life and may be exercised only if the holder is one of our employees, directors or consultants. As of September 30, 2005, under the 2004 Stock Incentive Plan, directors of IEM had been granted options for 33,877 shares of our common stock. No options were granted to employees of IEM. All options (other than options granted to Mr. Winkler) expire on the earlier of (i) 5 years from the date of grant; (ii) 90 days from the employee’s termination date; or (iii) one year from the employee’s termination due to death or disability.
      The restricted stock granted under the 2004 Stock Incentive Plan is subject to certain restrictions on disposition by the holder and an obligation of the holder to forfeit and surrender the shares of the restricted stock to us under certain circumstances. These forfeiture restrictions were determined by the IEM board of directors and may lapse upon the occurrence of the following: (i) the attainment of certain performance targets established by the IEM board of directors, (ii) the holder’s continued employment with our company or an affiliate of our company or continued service as a consultant to or director of our company for a specified period of time, (iii) any event or the satisfaction of any condition specified by the IEM board of directors or (iv) a combination of the foregoing. As of September 30, 2005, 131,387 shares of our restricted stock were granted under the 2004 Stock Incentive Plan.
      The 2004 Stock Incentive Plan will continue to govern the existing options and restricted stock granted thereunder; however, no future awards will be made under the 2004 Stock Incentive Plan.
Parchman Stock Incentive Plan
      In connection with our acquisition of Parchman Energy Group, Inc. in February 2005, we assumed Parchman’s 2003 Restricted Stock Plan, which we refer to as the Parchman Plan, for certain of our employees. Under the Parchman Plan, eligible participants received an award of our restricted stock subject to the restrictions described below. The restricted stock granted under the Parchman Plan is subject to certain restrictions on disposition by the holder and an obligation of the holder to forfeit and surrender the shares of restricted stock to us under certain circumstances. These forfeiture restrictions were determined by the former compensation committee of Parchman and may lapse upon the occurrence of the following: (i) the attainment of certain performance targets established by the former compensation

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committee of Parchman, (ii) the holder’s continued employment with our company or an affiliate of our company or continued service as a consultant to our company for a specified period of time, or (iii) a combination of the foregoing. As of September 30, 309,251 shares of our restricted stock had been granted under the Parchman Plan.
      The Parchman Plan will continue to govern the existing restricted stock granted thereunder; however, no future awards will be granted under the Parchman Plan.
Employment Agreements
      We have entered into an employment agreement with Mr. Winkler, the initial term of which terminates on June 20, 2008. Unless either party gives notice of its intention not to renew prior to May 6, 2007, the term will be automatically extended for successive one-year periods until notice is given by either party prior to May 6 of any subsequent year that the term of employment will expire on June 20 of the following year. Mr. Winkler’s annual base salary is $400,000, subject to increase at the discretion of our board of directors, and he will receive annual bonuses based on performance criteria determined at the discretion of our board of directors. For 2005, Mr. Winkler’s bonus will be in an amount of up to $600,000 if certain performance targets are met, which amount would be prorated to cover the period beginning June 20, 2005, the effective date of Mr. Winkler’s employment, to December 31, 2005. Mr. Winkler is also entitled to an annual car allowance equal to $9,600.
      Under the employment agreement, if Mr. Winkler’s employment is terminated prior to his attainment of age 63 (and not during the two-year period following any Change of Control (as such term is defined in the employment agreement)) by Mr. Winkler for Good Reason (as defined in the employment agreement) or by us for any reason other than for Cause (as such term is defined in the employment agreement), or the disability or death of Mr. Winkler, Mr. Winkler will be entitled to receive the following benefits:
        (A) his base salary when otherwise due through the date of the termination,
 
        (B) a bonus, in an amount determined in good faith by our board of directors in accordance with the performance criteria established under the employment agreement, prorated through and including the date of termination,
 
        (C) an amount equal to two times the sum of his base salary and average annual bonus (deemed to be 100% of his base salary for this purpose), payable in a lump-sum within 30 days following the date of termination,
 
        (D) all restricted shares, restricted stock units, performance shares, and performance units and stock options held by Mr. Winkler will vest immediately at the time of the termination, and
 
        (E) additional benefits, such as health and disability coverage, outplacement services and an automobile allowance, for up to two years.
      Under the employment agreement, if during the two-year period commencing on the effective date of any Change of Control, Mr. Winkler’s employment is terminated by Mr. Winkler for Good Reason or by us for any reason other than for Cause, or the disability or death of Mr. Winkler, Mr. Winkler will be entitled to receive the following benefits:
        (A) his base salary when otherwise due through the date of the termination,
 
        (B) a bonus, in an amount determined in good faith by our board of directors in accordance with the performance criteria established under the employment agreement, prorated through and including the date of termination,
 
        (C) an amount equal to three times the sum of his base salary and average annual bonus (deemed to be 100% of his base salary for this purpose), payable in a lump-sum within 30 days following the date of termination,
 
        (D) all restricted shares, restricted stock units, performance shares, performance units and stock options held by Mr. Winkler will vest immediately at the time of the termination,

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        (E) Mr. Winkler will become fully vested in accrued benefits under benefit plans maintained by us; provided, that, if such acceleration is prohibited by law or would require accelerated vesting for all participants in such plans, we will instead make a lump-sum payment to Mr. Winker equal to the present value of such unvested accrued benefits, and
 
        (F) additional benefits, such as health and disability coverage and benefits, outplacement services and an automobile allowance, for up to three years.
      Under the terms of the agreement, subject to certain exceptions, Mr. Winkler may not compete in the market in which we and our affiliates engage in business during his employment with us and for 18 months following the termination of his employment. Also under the agreement, subject to certain exceptions, we have agreed to pay a gross-up payment to Mr. Winkler so as to cover any excise tax imposed on benefits provided to Mr. Winkler by us.
      In connection with Mr. Winkler’s employment with us, we granted Mr. Winkler options to purchase 301,396 shares of our common stock. The options are subject to option agreements, which provide that the options vest 25% per year. Mr. Winkler’s options may not be exercised after June 20, 2015, the date of expiration of such options. Furthermore, Mr. Winkler purchased 58,827 shares of our common stock and was granted an additional 58,827 shares of restricted common stock in connection with his stock purchase. The shares of restricted stock are subject to restricted stock agreements between Mr. Winkler and us. These agreements provide that all of the shares of restricted stock will vest on the fourth anniversary of the date of grant.
      We have also entered into an employment agreement with James F. Maroney, III, our Vice President, Secretary and General Counsel. Under the agreement, Mr. Maroney will receive an annual base salary equal to $225,000 and a bonus of up to 75% of his base salary per year. Any bonus earned during 2005 will be prorated based on the number of days Mr. Maroney has been employed by us. In addition, if we terminate Mr. Maroney’s employment for reasons other than for Cause (as such term is defined in the employment agreement) Mr. Maroney may be entitled to receive the following:
  •  a severance payment equal to 150% of his annual base salary;
 
  •  all unvested stock options and restricted stock will immediately vest; and
 
  •  a bonus for the year during which his employment is terminated, prorated for the days served.
      In connection with Mr. Maroney’s employment with us, we granted Mr. Maroney options to purchase 26,000 shares of our common stock. The options are subject to an option agreement, which provides that the options vest 331/3% per year. Mr. Maroney’s options may not be exercised after October 3, 2015, the date of expiration of such options. Furthermore, Mr. Maroney purchased 21,450 shares of our common stock and was granted an additional 7,510 shares of restricted common stock in connection with his stock purchase. The shares of restricted stock are subject to a restricted stock agreement between Mr. Maroney and us. The agreement provides that the restricted stock vests 25% per year. Mr. Maroney is also entitled to an annual car allowance equal to $9,600.
      We have also entered into an employment agreement with Kenneth L. Nibling, our Vice President, Human Resources and Administration. Under the agreement, Mr. Nibling will receive an annual base salary equal to $205,000 and a bonus of up to 75% of his base salary per year. Any bonus earned during 2005 will be prorated based on the number of days Mr. Nibling has been employed by us. In addition, if we terminate Mr. Nibling’s employment for reasons other than for Cause (as such term is defined in the employment agreement) Mr. Nibling may be entitled to receive the following:
  •  a severance payment equal to his annual base salary; and
 
  •  all unvested stock options and restricted stock will immediately vest; and
 
  •  a bonus for the year during which his employment is terminated, prorated for the days served.
      In connection with Mr. Nibling’s employment with us, we granted Mr. Nibling options to purchase 26,000 shares of our common stock. The options are subject to an option agreement, which

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provides that the options vest 331/3% per year. Mr. Nibling’s options may not be exercised after October 3, 2015, the date of expiration of such options. Furthermore, Mr. Nibling purchased 21,450 shares of our common stock and was granted an additional 7,510 shares of restricted common stock in connection with his stock purchase. The shares of restricted stock are subject to a restricted stock agreement between Mr. Nibling and us. The agreement provides that the restricted stock vests 25% per year. Mr. Nibling is also entitled to an annual car allowance equal to $9,600.
Indemnification Agreements
      Our directors and our executive officers have entered into customary indemnification agreements with us, pursuant to which we have agreed to indemnify our directors and our executive officers to the fullest extent permitted by law.

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CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS
      The descriptions set forth below are qualified in their entirety by reference to the applicable agreements.
Offering By Selling Stockholders
      We are paying the expenses of the offering by the selling stockholders, other than the underwriting discounts, commissions and transfer taxes with respect to shares of stock sold by the selling stockholders and the fees and expenses of any attorneys, accountants and other advisors separately retained by them.
The Combination
      The Combination closed on September 12, 2005. Immediately prior to the Combination, SCF owned 6,920,178 shares or 69.9% of the outstanding shares of common stock of IPS; 550,000 shares or 67.2% of the outstanding shares of common stock of CES; and 100,000 shares or 75.2% of the outstanding shares of common stock of IEM. As a result of the Combination, as of September 12, 2005, SCF held a total of 19,698,378 shares or approximately 70% of our total shares outstanding. For a discussion of the Combination, please see “Business – The Combination.”
Transactions with Our Significant Stockholder Prior to the Combination
      IPS was party to that certain Services Agreement dated as of December 1, 2002 with L.E. Simmons and Associates, Incorporated, the ultimate general partner of SCF, pursuant to which IPS paid L.E. Simmons and Associates, Incorporated $20,000 per month for the services of David C. Baldwin in his capacity as its former Chief Executive Officer and certain administrative staff. David C. Baldwin serves as one of our directors and is a Managing Director of L.E. Simmons and Associates, Incorporated. In April 2004, this agreement was terminated by the parties and is no longer in effect.
      CES was a party to that certain Financial Advisory Agreement dated as of November 7, 2003 with L.E. Simmons and Associates, Incorporated, pursuant to which CES paid L.E. Simmons and Associates, Incorporated fees totaling $1,970,000 for the provision of support services during 2003 and 2004. In addition, L.E. Simmons and Associates, Incorporated provided certain management services, including the services of Andrew L. Waite in his capacity as its former Chief Executive Officer, to CES in exchange for $50,000 in the first quarter in 2004, $87,500 in each of the second and third quarters of 2004 and $125,000 in the fourth quarter of 2004 and the first and second quarters of 2005. This agreement has been terminated by the parties and is no longer in effect.
      IEM was party to that Financial Advisory Agreement dated as of August 14, 2004, with L.E. Simmons and Associates, Incorporated, the ultimate general partner of SCF, pursuant to which IEM paid L.E. Simmons and Associates, Incorporated an upfront fee of $250,000 and subsequent to that $31,250 per quarter for management services. This agreement has been terminated by the parties and is no longer in effect.
Transactions with our Directors, Officers and Key Operational Managers
      Andrew L. Waite, the Chairman of our board of directors, is also a Managing Director and an officer of L.E. Simmons and Associates, Incorporated. David C. Baldwin, one of our directors, is also a Managing Director and an officer of L.E. Simmons and Associates, Incorporated.
      We provide services to Laramie Energy, an exploration and production company. Robert S. Boswell is a principal of Laramie as well as the Chairman and Chief Executive Officer. Mr. Boswell is a member of our board of directors. Laramie paid us approximately $205,000 for such services for the year ended December 31, 2004 and approximately $944,000 for the nine months ended September 30, 2005.
      We sell services and products to Continental Resources, Inc. and its subsidiaries. Revenues attributable to these sales totaled approximately $3.3 million from October 14, 2004, the date of CES’s

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acquisition of Hamm Co., through December 31, 2004 and approximately $15.6 million for the nine months ended September 30, 2005. Harold G. Hamm is a majority owner of Continental Resources, Inc. and serves as a member of our board of directors.
      In connection with CES’s acquisition of Hamm Co. in 2004, CES entered into that certain Strategic Customer Relationship Agreement with Continental Resources. By virtue of the Combination, through a subsidiary, we are now a party to such agreement. The agreement provides Continental Resources the option to engage a limited amount of our assets into a long-term contract at market rates. Mr. Hamm is a majority owner of Continental Resources and serves as a member of our board of directors.
      We lease offices and an oilfield yard from Continental Management Co. and Harold G. Hamm for an aggregate of approximately $8,000 per month. These leases expire between 2009 and 2010. Harold G. Hamm is the owner of Continental Management Co. and serves as a member of our board of directors.
      We are obligated to pay Lee Daniel, III an aggregate principal amount of $2.2 million pursuant to a subordinated promissory note due March 31, 2009 that was issued by CES in connection with the acquisition of LEED Energy Services in 2004. Mr. Daniel is an officer of one of our subsidiaries.
      We sell products and services to HEP Oil Company and its subsidiaries. Revenues attributable to these sales totaled approximately $8.4 million in 2004 and approximately $5.0 million for the nine months ended September 30, 2005. John D. Schmitz is a majority owner of HEP Oil Company and serves as an officer of one of our subsidiaries.
      We lease various oilfield yards, office buildings and other locations from G-ville Properties and B-29 Investments for approximately $69,000 per month. These leases expire between 2008 and 2015. John D. Schmitz is a majority owner of G-ville Properties and B-29 Investments. Mr. Schmitz is an officer of one of our subsidiaries.
      On September 29, 2005, we entered into that certain Asset Purchase Agreement with Spindletop Production Services, Ltd. and Mr. Schmitz. Pursuant to the agreement, we purchased the assets of Spindletop in exchange for approximately $0.2 million cash and 45,182 shares of our common stock. Mr. Schmitz is an officer of one of our subsidiaries.
      We believe that all of these related party transactions were either on terms at least as favorable to us as could have been obtained through arm’s-length negotiations with unaffiliated third parties or were negotiated in connection with acquisitions, the overall terms of which were as favorable to us as could have been obtained through arm’s-length negotiations with unaffiliated third parties. We intend to address future material transactions with our affiliates by having the transactions approved by a committee of disinterested directors.

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PRINCIPAL AND SELLING STOCKHOLDERS
      The following table1 sets forth information with respect to the beneficial ownership of our common stock as of November 1, 2005 by:
  •  each person who is known by us to own beneficially 5% or more of our outstanding common stock;
 
  •  each of our named executive officers;
 
  •  each of our directors;
 
  •  all of our executive officers and directors as a group (11 persons); and
 
  •  each selling stockholder.
      Except as otherwise indicated, the person or entities listed below have sole voting and investment power with respect to all shares of our common stock beneficially owned by them, except to the extent this power may be shared with a spouse. Unless otherwise indicated, the address of each stockholder listed below is 14450 JFK Blvd., Suite 400, Houston, Texas 77032.
                                                                 
                    Shares   Shares
                    Beneficially   Beneficially
                    Owned After   Owned After
                    Offering   Offering
            Maximum No.   (Assuming No   (Assuming
    Shares Beneficially       of Shares to   Exercise of Over-   Exercise of Over-
    Owned Prior       be Sold Upon   Allotment   Allotment Option
    to this Offering   Number of Shares   Exercise of   Option)   in Full)
        to be Sold in   Over-Allotment        
    Number   Percent   Offering   Option(1)   Number   Percent   Number   Percent
                                 
SCF-IV, L.P.(2)
    19,698,378       70.0 %                                                
Andrew L. Waite(3)(7)
    2,145       *                                                  
Joseph C. Winkler(7)
    117,654       *                                                  
J. Michael Mayer(4)(7)
    69,261       *                                                  
James F. Maroney, III(7)
    28,960       *                                                  
Kenneth L. Nibling(7)
    28,960       *                                                  
Robert L. Weisgarber(4)
    28,945       *                                                  
David C. Baldwin(5)(7)
    2,145       *                                                  
Robert S. Boswell(4)(7)
    14,082       *                                                  
Harold G. Hamm(6)(7)
    2,029,133       7.3 %                                                
R. Graham Whaling(4)(7)
    13,083       *                                                  
James D. Woods(4)(7)
    5,855       *                                                  
Directors and Executive Officers as a Group (11 persons) (3)(4)(5)(6)(7)
    2,340,223       8.4 %                                                
 
1  We will add the selling stockholders to the table once they have been determined.

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  * Less than one percent.
(1)  Assuming the over-allotment option is exercised in full.
 
(2)  L.E. Simmons is the natural person who has voting and investment control over the securities owned by SCF-IV, L.P. Mr. Simmons serves as chairman of the Board and President of L.E. Simmons and Associates, Incorporated, the ultimate general partner of SCF-IV, L.P.
(3)  Mr. Waite serves as Managing Director of L.E. Simmons and Associates, Incorporated, the ultimate general partner of SCF-IV, L.P. As such, Mr. Waite may be deemed to have voting and dispositive power over the shares beneficially owned by SCF-IV, L.P. Mr. Waite disclaims beneficial ownership of the shares owned by SCF-IV, L.P.
(4)  Includes shares that may be acquired within 60 days through the exercise of options to purchase shares of our common stock as follows: Messrs. Mayer – 20,857; Weisgarber – 15,643; Boswell – 2,085; Whaling – 1,233; and Woods – 3,710.
 
(5)  Mr. Baldwin serves as Managing Director of L.E. Simmons and Associates, Incorporated, the ultimate general partner of SCF-IV, L.P. As such, Mr. Baldwin may be deemed to have voting and dispositive power over the shares beneficially owned by SCF-IV, L.P. Mr. Baldwin disclaims beneficial ownership of the shares owned by SCF-IV, L.P.
 
(6)  Includes an aggregate of 2,026,988 shares owned by Harold G. Hamm GRAT 4, Harold G. Hamm GRAT 6, and Harold G. Hamm GRAT 8, each of which is an estate planning trust (collectively, the “Hamm Trusts”). Mr. Hamm serves as the trustee of each of the Hamm Trusts. As such, Mr. Hamm may be deemed to have voting and dispositive power over the shares beneficially owned by the Hamm Trusts.
 
(7)  Includes restricted common stock as follows: Waite – 2,145; Winkler – 58,827; Mayer – 19,704; Maroney – 7,510; Nibling – 7,510; Baldwin – 2,145; Boswell – 2,145; Hamm – 2,145; Whaling – 2,145; Woods – 2,145.
Registration Rights
      For a discussion of our stockholder agreement, please see “Description of Our Capital Stock – Stockholders Agreement.”

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DESCRIPTION OF OUR CAPITAL STOCK
      Our authorized capital stock consists of 100,000,000 shares of common stock, par value $.01 per share, and 5,000,000 shares of preferred stock, par value $.01 per share. As of September 30, 2005, we had 27,810,283 shares of common stock outstanding.
Common Stock
      As of September 30, 2005, there were 134 holders of our common stock. Holders of our common stock are entitled to one vote per share on all matters to be voted upon by our stockholders. Because holders of our common stock do not have cumulative voting rights, the holders of a majority of the shares of our common stock can elect all of the members of the board of directors standing for election, subject to the rights, powers and preferences of any outstanding series of preferred stock. Subject to the rights and preferences of any preferred stock that we may issue in the future, the holders of our common stock are entitled to receive:
  •  dividends as may be declared by our board of directors; and
 
  •  all of our assets available for distribution to holders of our common stock in liquidation, pro rata, based on the number of shares held.
      There are no redemption or sinking fund provisions applicable to our common stock. All outstanding shares of our common stock are fully paid and non-assessable.
Preferred Stock
      Subject to the provisions of our certificate of incorporation and legal limitations, our board of directors has the authority, without further vote or action by our stockholders:
  •  to issue up to 5,000,000 shares of preferred stock in one or more series; and
 
  •  to fix the rights, preferences, privileges and restrictions of our preferred stock, including provisions related to dividends, conversion, voting, redemption, liquidation and the number of shares constituting the series or the designation of that series, which may be superior to those of our common stock.
      There were no shares of preferred stock outstanding as of November 10, 2005, and we have no present plans to issue any preferred stock.
      The issuance of shares of preferred stock by our board of directors as described above may adversely affect the rights of the holders of our common stock. For example, preferred stock may rank prior to our common stock as to dividend rights, liquidation preference or both, may have full or limited voting rights and may be convertible into shares of our common stock. The issuance of shares of preferred stock may discourage third-party bids for our common stock or may otherwise adversely affect the market price of our common stock. In addition, the preferred stock may enable our board of directors to make more difficult or to discourage attempts to obtain control of our company through a hostile tender offer, proxy contest, merger or otherwise, or to make changes in our management.
Anti-Takeover Provisions of Our Certificate of Incorporation and Bylaws
      Our certificate of incorporation and bylaws contain several provisions that could delay or make more difficult the acquisition of us through a hostile tender offer, open market purchases, proxy contest, merger or other takeover attempt that a stockholder might consider in his or her best interest, including those attempts that might result in a premium over the market price of our common stock.
Written Consent of Stockholders
      Our certificate of incorporation provides that, on and after the date when SCF ceases to own a majority of the shares of our outstanding securities entitled to vote in the election of directors, any action by our stockholders must be taken at an annual or special meeting of stockholders, and stockholders cannot act by written consent. Until that date, any action required or permitted to be taken by our

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stockholders may be taken at a duly called meeting of stockholders or by the written consent of stockholders owning the minimum number of shares required to approve the action.
Special Meetings of Stockholders
      Subject to the rights of the holders of any series of preferred stock, our bylaws provide that special meetings of the stockholders may only be called by the chairman of the board of directors or by the resolution of our board of directors approved by a majority of the total number of authorized directors. No business other than that stated in our notice may be transacted at any special meeting.
Advance Notice Procedure for Director Nominations and Stockholder Proposals
      Our bylaws provide that adequate notice must be given to nominate candidates for election as directors or to make proposals for consideration at annual meetings of our stockholders. For nominations or other business to be properly brought before an annual meeting by a stockholder, the stockholder must have delivered a written notice to the secretary of our company at our principal executive offices not earlier than the close of business on the 120th calendar day prior to the first anniversary of the date of the preceding year’s annual meeting nor later than the close of business on the 90th calendar day prior to the first anniversary of the date of the preceding year’s annual meeting; provided, however, that in the event that the date of the annual meeting is more than 30 calendar days before or more than 70 calendar days after such anniversary date, notice by the stockholder to be timely must be so delivered not earlier than the close of business on the 120th calendar day prior to such annual meeting nor later than the close of business on the later of the 90th calendar day prior to such annual meeting or the 10th calendar day following the calendar day on which public announcement, if any, of the date of such meeting is first made by us.
      Nominations of persons for election to our board of directors may be made at a special meeting of stockholders at which directors are to be elected pursuant to our notice of meeting (i) by or at the direction of our board of directors, or (ii) by any stockholder of our company who is a stockholder of record at the time of the giving of notice of the meeting, who is entitled to vote at the meeting and who complies with the notice procedures set forth in our bylaws. In the event we call a special meeting of stockholders for the purpose of electing one or more directors to our board of directors, any stockholder may nominate a person or persons (as the case may be) for election to such position(s) if the stockholder provides written notice to the secretary of our company at our principal executive offices not earlier than the close of business on the 120th calendar day prior to such special meeting, nor later than the close of business on the later of the 90th calendar day prior to such special meeting or the 10th calendar day following the day on which public announcement, if any, is first made of the date of the special meeting and of the nominees proposed by our board of directors to be elected at such meeting.
      These procedures may operate to limit the ability of stockholders to bring business before a stockholders meeting, including the nomination of directors and the consideration of any transaction that could result in a change in control and that may result in a premium to our stockholders.
Classified Board of Directors
      Our certificate of incorporation divides our directors into three classes serving staggered three-year terms. As a result, stockholders will elect approximately one-third of the board of directors each year. This provision, when coupled with the provision of our restated certificate of incorporation authorizing only the board of directors to fill vacant or newly created directorships or increase the size of the board of directors and the provision providing that directors may only be removed for cause, may deter a stockholder from gaining control of our board of directors by removing incumbent directors or increasing the number of directorships and simultaneously filling the vacancies or newly created directorships with its own nominees.
Renouncement of Business Opportunities
      SCF has investments in other oilfield service companies that may compete with us, and SCF and its affiliates, other than us, may invest in other such companies in the future. We refer to SCF, its other affiliates

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and its portfolio companies as the SCF group. Our certificate of incorporation provides that, so long as we have a director or officer that is affiliated with SCF (an “SCF Nominee”), we renounce any interest or expectancy in any business opportunity in which any member of the SCF group participates or desires or seeks to participate in and that involves any aspect of the energy equipment or services business or industry, other than:
  •  any business opportunity that is brought to the attention of an SCF Nominee solely in such person’s capacity as a director or officer of our company and with respect to which no other member of the SCF group independently receives notice or otherwise identifies such opportunity; or
 
  •  any business opportunity that is identified by the SCF group solely through the disclosure of information by or on behalf of us.
      Thus, for example, members of the SCF group may pursue opportunities in the oilfield services industry for their own account or present such opportunities to SCF’s other portfolio companies. Our certificate of incorporation provides that the SCF group has no obligation to offer such opportunities to us, even if the failure to provide such opportunity would have a competitive impact on us. We are not prohibited from pursuing any business opportunity with respect to which we have renounced any interest.
Amendment of the Bylaws
      Our board of directors may amend or repeal the bylaws and adopt new bylaws by the affirmative vote of a majority of the total number of authorized directors. The holders of common stock may amend or repeal the bylaws and adopt new bylaws by a majority vote at any annual meeting or special meeting for which notice of the proposed amendment, repeal or adoption was contained in the notice for such special meeting.
Limitation of Liability of Directors
      Our directors will not be personally liable to us or our stockholders for monetary damages for breach of fiduciary duty as a director, except, if required by Delaware law, for liability:
  •  for any breach of the duty of loyalty to us or our stockholders;
 
  •  for acts or omissions not in good faith or involving intentional misconduct or a knowing violation of law;
 
  •  for unlawful payment of a dividend or unlawful stock purchases or redemptions; or
 
  •  for any transaction from which the director derived an improper personal benefit.
      As a result, neither we nor our stockholders have the right, through stockholders’ derivative suits on our behalf, to recover monetary damages against a director for breach of fiduciary duty as a director, including breaches resulting from grossly negligent behavior, except in the situations described above.
Delaware Takeover Statute
      Under the terms of our certificate of incorporation and as permitted under Delaware law, we have elected not to be subject to Delaware’s anti-takeover law in order to give our significant stockholders, including SCF, greater flexibility in transferring their shares of our common stock. This law provides that specified persons who, together with affiliates and associates, own, or within three years did own, 15% or more of the outstanding voting stock of a corporation could not engage in specified business combinations with the corporation for a period of three years after the date on which the person became an interested stockholder. The law defines the term “business combination” to encompass a wide variety of transactions with or caused by an interested stockholder, including mergers, asset sales and other transactions in which the interested stockholder receives or could receive a benefit on other than a pro rata basis with other stockholders. With the approval of our stockholders, we may amend our certificate of incorporation in the future to become governed by the anti-takeover law. This provision would then have an anti-takeover effect for transactions not approved in advance by our board of directors, including discouraging takeover attempts that might result in a premium over the market price for the shares of our common stock. By

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opting out of the Delaware anti-takeover law, a transferee of SCF could pursue a takeover transaction that was not approved by our board of directors.
Stockholders Agreement
      Complete and the existing stockholders are parties to that certain Stockholders Agreement dated September 12, 2005 (the “Stockholders Agreement”).
Management Rights
      As long as SCF owns 20% or more of our outstanding common stock, we have agreed to take all action within our power required to cause the board of directors at all times to include at least two members designated by SCF and so long as SCF owns 5% or more, at least one member designated by SCF.
Demand Registration Rights
      Under the Stockholders Agreement, from and after 180 days following this offering, SCF has the right to demand on five occasions, and Non-SCF stockholders holding at least 50% of our unregistered common stock not held by SCF have the right to demand on one occasion, that we register all or any portion of their registrable securities so long as the registrable securities proposed to be sold on an individual registration statement have an aggregate gross offering price of at least $20 million, unless we otherwise agree to a lesser amount (a “Demand Registration”). Holders of registrable securities may not require us to effect more than one Demand Registration in any six-month period. After such time that we become eligible to use Form S-3 (or comparable form) for the registration under the Securities Act of any of its securities, any demand request by SCF with a reasonably anticipated aggregate offering price of $100 million may be for a “shelf” registration statement pursuant to Rule 415 under the Securities Act.
Piggyback Registration Rights
      If we propose to file a registration statement under the Securities Act relating to an offering of our common stock, subject to certain exceptions, upon the written request of holders of registrable securities, we will use our commercially reasonable efforts to include in such registration, and any related underwriting, all of the registrable securities included in such requests, subject to customary cutback provisions.
Registration Procedures and Expenses
      The Stockholders Agreement contains customary procedures relating to underwritten offerings and the filing of registration statements. We have agreed to pay all registration expenses incurred in connection with any registration, including all registration, qualification and filings fees, printing expenses, accounting fees, escrow fees, legal fees of our company, reasonable fees of one counsel to the holders of registrable securities, blue sky fees and expenses and the expense of any special audits incident to or required by any such registration. All underwriting discounts and selling commissions and stock transfer taxes applicable to securities registered by holders and fees of counsel to any such holder (other than as described above) will be payable by holders of registrable securities.
Transfer Agent and Registrar
      The transfer agent and registrar for the common stock is Wells Fargo Shareowner Services.
Listing
      We have applied to include our shares of common stock for listing on the NYSE under the symbol “                    .”

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SHARES ELIGIBLE FOR FUTURE SALE
      Prior to this offering, there has been no public market for our common stock. The market price of our common stock could drop due to sales of a large number of shares of our common stock or the perception that these sales could occur. These factors also could make it more difficult to raise funds through future offerings of common stock.
      After this offering,                      shares of common stock will be outstanding. Of these shares, the shares sold in this offering, including any shares sold pursuant to the underwriters’ over-allotment option, will be freely tradable without restriction under the Securities Act of 1933, as amended (“Securities Act”), except for any shares purchased by one of our “affiliates” as defined in Rule 144 under the Securities Act. All of our other outstanding shares of common stock will be “restricted securities” within the meaning of Rule 144 under the Securities Act or subject to lock-up arrangements.
      The restricted securities generally may not be sold unless they are registered under the Securities Act or are sold under an exemption from registration, such as the exemption provided by Rule 144 under the Securities Act. After this offering, the holders of shares of our common stock prior to this offering 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. For a description of the registration rights held by our stockholders, please see “Description of Our Capital Stock – Stockholders Agreement.”
      Our officers and directors and the selling stockholders will enter into lock-up agreements described in “Underwriting.”
      As restrictions on resale end, the market price of our common stock could drop significantly if the holders of these restricted shares sell them, or are perceived by the market as intending to sell them.
      As soon as practicable after this offering, we intend to file one or more registration statements with the SEC on Form S-8 providing for the registration of shares of our common stock issued or reserved for issuance under our stock incentive plans. Subject to the exercise of unexercised options or the expiration or waiver of vesting conditions for restricted stock and the expiration of lock-ups that we and our stockholders have entered into, shares registered under these registration statements on Form S-8 will be available for resale immediately in the public market without restriction.
Rule 144
      In general, beginning 90 days after the date of this prospectus, under Rule 144 as currently in effect, any person (or persons whose shares are aggregated), including an affiliate, who has beneficially owned shares for a period of at least one year is entitled to sell, within any three-month period, a number of shares that does not exceed the greater of:
  •  1% of the then outstanding shares of common stock; and
 
  •  the average weekly trading volume in the common stock on the NYSE during the four calendar weeks immediately preceding the date on which the notice of the sale on Form 144 is filed with the SEC.
      Sales under Rule 144 are also subject to other provisions relating to notice and manner of sale and the availability of current public information about us.
Rule 144(k)
      Under Rule 144(k), a person who is not deemed to have been one of our affiliates at any time during the 90 days preceding a sale, and who has beneficially owned the shares proposed to be sold for at least two years,

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including the holding period of any prior owner other than an “affiliate,” is entitled to sell the shares without complying with the manner of sale, public information, volume limitation or notice provision of Rule 144.
Rule 701
      In general, under Rule 701 under the Securities Act as currently in effect, any of our employees, consultants or advisors who purchased or received shares from us in connection with a compensatory stock or option plan or other written agreement in a transaction that was completed in reliance on Rule 701 and complied with the requirements of Rule 701 is eligible to resell such shares beginning 90 days after the date of this prospectus in reliance on Rule 144, but without compliance with most of its restrictions, including the holding period, contained in Rule 144.

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PRINCIPAL U.S. FEDERAL TAX CONSEQUENCES
TO NON-U.S. HOLDERS OF COMMON STOCK
      The following is a general discussion of the principal U.S. federal income and estate tax consequences of the ownership and disposition of our common stock applicable to Non-U.S. Holders. For purposes of this discussion, a “Non-U.S. Holder” is any beneficial owner of our common stock that is not:
  •  an individual who is a citizen or resident of the United States;
 
  •  a corporation (or other entity taxed as a corporation for U.S. federal income tax purposes) created or organized in the United States or under the laws of the United States, any state thereof or the District of Columbia;
 
  •  an estate whose income is subject to U.S. federal income taxation regardless of its source; or
 
  •  a trust whose administration is subject to the primary supervision of a U.S. court and which has one or more U.S. persons who have the authority to control all substantial decisions of the trust, or a trust in existence on August 20, 1996 that has elected to continue to be treated as a “United States person” (as defined for U.S. federal income tax purposes).
      In the case of shares of our common stock held by a partnership (or any other entity treated as a partnership for U.S. federal income tax purposes), the tax treatment of a partner generally will depend upon the status of the partner as a Non-U.S. Holder and the activities of the partnership. An individual may be treated as a resident of the United States for federal income tax purposes with respect to a calendar year if the individual is present in the United States on at least 31 days in that calendar year and at least 183 days during that calendar year and the two preceding calendar years (counting, for this purpose, each day present in the first preceding year as 1/3 of a day and each day present in the second preceding year as 1/6 of a day). Residents are taxed for U.S. federal income tax purposes as if they were U.S. citizens.
      This discussion is based on current provisions of the Internal Revenue Code, Treasury Regulations promulgated under the Internal Revenue Code, judicial opinions, published positions of the Internal Revenue Service, and other applicable authorities, all of which are subject to change, possibly with retroactive effect. This discussion does not address all aspects of U.S. federal income and estate taxation or any aspects of state, local, or non-U.S. taxation, nor does it consider any specific facts or circumstances that may apply to particular Non-U.S. Holders that may be subject to special treatment under the U.S. federal tax laws, such as insurance companies, tax-exempt organizations, financial institutions, brokers, dealers in securities, regulated investment companies, real estate investment trusts, and certain former citizens or former long-term residents of the United States. This discussion does not address special tax rules that may apply to a Non-U.S. Holder that holds our common stock as part of a “straddle,” “hedge,” “conversion transaction,” “synthetic security” or other integrated investment, and assumes that a Non-U.S. Holder holds our common stock as a capital asset.
      Each Non-U.S Holder is urged to consult a tax advisor regarding the U.S. federal, state, local and non-U.S. income and other tax considerations of acquiring, holding and disposing of shares of our common stock.
Dividends
      Distributions on our common stock generally will constitute dividends for U.S. federal income tax purposes to the extent paid from our current or accumulated earnings and profits, as determined under U.S. federal income tax principles. In general, dividends paid to a Non-U.S. Holder of our common stock that are not effectively connected with the conduct of a trade or business in the United States will be subject to U.S. withholding tax at a rate of 30% of the gross amount, or a lower rate prescribed by an applicable income tax treaty. In order to claim a reduced rate of withholding tax under an applicable income tax treaty, a Non-U.S. Holder must certify its eligibility by filing Internal Revenue Service Form W-8BEN. In the case of common stock held by a foreign partnership, the certification generally is

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applied to the partners of the partnership, unless the partnership agrees to become a “withholding foreign partnership” and to provide eligibility information to the Internal Revenue Service.
      Dividends that are effectively connected with a Non-U.S. Holder’s conduct of a trade or business in the United States (and, if an income tax treaty applies, that are attributable to the Non-U.S. Holder’s permanent establishment in the United States) are taxed on a net income basis at the regular graduated rates generally in the manner applicable to U.S. persons. Such dividends are not subject to U.S. withholding tax if the Non-U.S. Holder files Internal Revenue Service Form W-8ECI. A Non-U.S. Holder that is a corporation also may be subject to a branch profits tax at a rate of 30%, or such lower rate as may be specified by an applicable income tax treaty, on the repatriation from the United States of its earnings and profits effectively connected with its U.S. trade or business.
      A Non-U.S. Holder of our common stock that is eligible for a reduced rate of U.S. withholding tax under a tax treaty may obtain a refund of any excess amounts withheld by filing an appropriate claim for refund with the Internal Revenue Service.
Gain on Disposition of Common Stock
      In general, a Non-U.S. Holder will not be subject to U.S. federal income tax on any gain realized upon the sale, exchange, redemption, retirement or other disposition of shares of our common stock so long as:
  •  the gain is not effectively connected with the conduct of a trade or business in the United States by the Non-U.S. Holder (or, if an income tax treaty applies, is not attributable to the Non-U.S. Holder’s permanent establishment in the United States);
 
  •  if the Non-U.S. Holder is an individual, the Non-U.S. Holder either is not present in the United States for 183 days or more in the taxable year of disposition or does not have a “tax home” in the United States for U.S. federal income tax purposes and meets certain other requirements;
 
  •  the Non-U.S. Holder is not subject to tax under the provisions of the Internal Revenue Code regarding the taxation of certain former citizens or former long-term residents of the United States; and
 
  •  we are not and have not been a U.S. real property holding corporation for U.S. federal income tax purposes at any time during the shorter of the Non-U.S. Holder’s holding period of our common stock and the five-year period ending on the date of disposition.
      Generally, a corporation is a U.S. real property holding corporation if the fair market value of its U.S. real property interests equals or exceeds 50% of the fair market value of its worldwide real property and its other assets used or held for use in a trade or business. We believe that we are not currently, and we do not anticipate becoming in the future, a U.S. real property holding corporation.
Certain U.S. Federal Estate Tax Consequences
      Common stock owned or treated as owned by an individual who is not a citizen or resident (as defined for U.S. federal estate tax purposes) of the United States at the time of death will be includible in the individual’s gross estate for U.S. federal estate tax purposes and therefore may be subject to U.S. federal estate tax, unless an applicable estate tax treaty provides otherwise.
Information Reporting and Backup Withholding
      Dividends paid to you may be subject to information reporting and U.S. backup withholding tax (at a rate of 28%). If you are a Non-U.S. Holder you will be exempt from backup withholding if you provide a Form W-8BEN certifying that you are a Non-U.S. Holder or you otherwise meet documentary evidence requirements for establishing that you are a Non-U.S. Holder, or you otherwise establish an exemption.

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      The gross proceeds from the disposition of our common stock may be subject to information reporting and U.S. backup withholding tax. If you sell your common stock outside the United States through a non-U.S. office of a non-U.S. broker and the sales proceeds are paid to you outside the United States, information reporting and backup withholding generally will not apply to that payment. However, information reporting, but not backup withholding, will generally apply to a payment of sales proceeds, even if that payment is made outside the United States, if you sell your common stock through a non-U.S. office of a broker that is:
  •  a U.S. person;
 
  •  a “controlled foreign corporation” for U.S. federal income tax purposes;
 
  •  a foreign person 50% or more of whose gross income from a specified period is effectively connected with the conduct of a U.S. trade or business; or
 
  •  a foreign partnership if at any time during its tax year either (i) one or more of its partners are U.S. persons who in the aggregate hold more than 50% of the income or capital interests in the partnership, or (ii) the foreign partnership is engaged in a U.S. trade or business,
unless the broker has documentary evidence in its files that you are a Non-U.S. Holder and certain other conditions are met, or you otherwise establish an exemption.
      If you receive payments of the proceeds of a sale of our common stock to or through a U.S. office of a broker, the payment is subject to both U.S. backup withholding tax and information reporting unless you provide a Form W-8BEN certifying that you are a Non-U.S. Holder, or you otherwise establish an exemption.
      Backup withholding is not an additional tax. You generally may obtain a refund of any amounts withheld under the backup withholding rules that exceed your U.S. federal income tax liability by timely filing a properly completed refund claim with the U.S. Internal Revenue Service.

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UNDERWRITING
      Under the terms and subject to the conditions contained in an underwriting agreement dated                     , 2005, we and the selling stockholders have agreed to sell to the underwriters named below, for whom Credit Suisse First Boston LLC and UBS Securities LLC are acting as representatives, the following respective number of shares of our common stock:
           
    Number of
Underwriter   Shares
     
Credit Suisse First Boston LLC
       
UBS Securities LLC
       
Banc of America Securities LLC
       
Jefferies & Company, Inc. 
       
Johnson Rice & Company L.L.C. 
       
Raymond James & Associates, Inc. 
       
Simmons & Company International
       
Pickering Energy Partners, Inc. 
       
       
 
Total
       
       
      The underwriting agreement provides that the underwriters are obligated to purchase all of the shares of our common stock in this offering if any are purchased, other than those shares covered by the over-allotment option described below. The underwriting agreement also provides that if an underwriter defaults, the purchase commitments of the non-defaulting underwriters may be increased or this offering may be terminated.
      The selling stockholders have granted to the underwriters a 30-day option to purchase on a pro rata basis up to                     additional outstanding shares from the selling stockholders at the initial public offering price less the underwriting discounts and commissions. The option may be exercised only to cover any over-allotments of common stock.
      The underwriters propose to offer the shares of common stock initially at the public offering price on the cover page of this prospectus and to selling group members at that price less a selling concession of $           per share. The underwriters and selling group members may allow a discount of $           per share on sales to other broker/ dealers. After the initial public offering, the representatives may change the public offering price and concession and discount to broker/ dealers.
      The following table summarizes the compensation and estimated expenses we and the selling stockholders will pay:
                                 
    Per Share   Total
         
    Without   With   Without   With
    Over-allotment   Over-allotment   Over-allotment   Over-allotment
                 
Underwriting discounts and commissions paid by us
  $       $       $       $    
Expenses payable by us
  $       $       $       $    
Underwriting discounts and commissions paid by selling stockholders
  $       $       $       $    
      We estimate that our out-of-pocket expenses for this offering will be approximately $          .
      The representatives have informed us that the underwriters do not expect sales to accounts over which the underwriters have discretionary authority to exceed 5% of the shares of common stock being offered.
      We have agreed that we will not offer, sell, contract to sell, pledge or otherwise dispose of, directly or indirectly, or file with the SEC a registration statement under the Securities Act relating to, any shares of

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our common stock or securities convertible into or exchangeable or exercisable for any shares of our common stock, or publicly disclose the intention to make any offer, sale, pledge, disposition or filing, without the prior written consent of Credit Suisse First Boston LLC and UBS Securities LLC for a period of 180 days after the date of this prospectus, except with respect to common stock issued or issuable pursuant to stock options outstanding on the date of this prospectus, common stock contingently issuable under existing acquisition contracts, common stock, not to exceed            shares, issued in connection with future acquisitions subject to the same 180-day restriction on resales and common stock and other stock-based awards issued or issuable pursuant to our stock incentive plans. However, in the event that either (1) during the last 17 days of the “lock-up” period, we release earnings results or material news or a material event relating to us occurs or (2) prior to the expiration of the “lock-up” period, we announce that we will release earnings results during the 16-day period beginning on the last day of the “lock-up” period, then in either case the expiration of the “lock-up” will be extended until the expiration of the 18-day period beginning on the date of the release of the earnings results or the occurrence of the material news or event, as applicable, unless Credit Suisse First Boston LLC and UBS Securities LLC waive, in writing, such an extension.
      Our officers and directors, the selling stockholders and certain other persons have agreed that they will not offer, sell, contract to sell, pledge or otherwise dispose of, directly or indirectly, any shares of our common stock or securities convertible into or exchangeable or exercisable for any shares of our common stock, enter into a transaction that would have the same effect, or enter into any swap, hedge or other arrangement that transfers, in whole or in part, any of the economic consequences of ownership of our common stock, whether any of these transactions are to be settled by delivery of our common stock or other securities, in cash or otherwise, or publicly disclose the intention to make any offer, sale, pledge or disposition, or to enter into any transaction, swap, hedge or other arrangement, without, in each case, the prior written consent of Credit Suisse First Boston LLC and UBS Securities LLC for a period of 180 days after the date of this prospectus. However, in the event that either (1) during the last 17 days of the “lock-up” period, we release earnings results or material news or a material event relating to us occurs or (2) prior to the expiration of the “lock-up” period, we announce that we will release earnings results during the 16-day period beginning on the last day of the “lock-up” period, then in either case the expiration of the “lock-up” will be extended until the expiration of the 18-day period beginning on the date of the release of the earnings results or the occurrence of the material news or event, as applicable, unless Credit Suisse First Boston LLC and UBS Securities LLC waive, in writing, such an extension.
      The underwriters have reserved for sale at the initial public offering price up to 5% of the total shares of our common stock offered hereby (excluding any shares to be sold pursuant to the over-allotment option)for employees, directors and other persons associated with us who have expressed an interest in purchasing common stock in the offering. The number of shares available for sale to the general public in the offering will be reduced to the extent these persons purchase the reserved shares. Any reserved shares not so purchased will be offered by the underwriters to the general public on the same terms as the other shares.
      We and the selling stockholders have agreed to indemnify the underwriters against liabilities under the Securities Act, or contribute to payments that the underwriters may be required to make in that respect.
      We will apply to list our common stock on the New York Stock Exchange.
      Some of the underwriters and their affiliates have engaged in transactions with, and performed commercial and investment banking financial advisor or lending services for, us and our affiliates from time to time, for which they have received customary compensation and may do so in the future. Affiliates of UBS Securities LLC are arrangers and agents under our credit facility and receive fees customary for performing these services and interest on such. In addition, a portion of the net proceeds from this offering may be used to repay a portion of our revolving credit facility, in which case lenders under such facility, including affiliates of some of the underwriters, will receive their proportionate share of the net proceeds (consisting of less than 10% of such proceeds) used to repay such debt.

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      Prior to this offering, there has been no public market for our common stock. The initial public offering price for our common stock will be determined by negotiation between us and the underwriters. The principal factors to be considered in determining the initial public offering price include the following:
  •  the information included in this prospectus and otherwise available to the underwriters;
 
  •  market conditions for initial public offerings;
 
  •  the history of and prospects for our business and our past and present operations;
 
  •  the history of and prospects for the industry in which we compete;
 
  •  our past and present earnings and current financial position;
 
  •  an assessment of our management;
 
  •  the market of securities of companies in businesses similar to ours; and
 
  •  the general condition of the securities markets.
      The initial public offering price may not correspond to the price at which our common stock will trade in the public market subsequent to this offering, and an active trading market may not develop and continue after this offering.
      In connection with the offering, the underwriters may engage in stabilizing transactions, over-allotment transactions, syndicate covering transactions and penalty bids in accordance with Regulation M under the Exchange Act.
  •  Stabilizing transactions permit bids to purchase the underlying security so long as the stabilizing bids do not exceed a specified maximum.
 
  •  Over-allotment involves sales by the underwriters of shares in excess of the number of shares the underwriters are obligated to purchase, which creates a syndicate short position. The short position may be either a covered short position or a naked short position. In a covered short position, the number of shares over-allotted by the underwriters is not greater than the number of shares that they may purchase in the over-allotment option. In a naked short position, the number of shares involved is greater than the number of shares in the over-allotment option. The underwriters may close out any covered short position by either exercising their over-allotment option and/or purchasing shares in the open market.
 
  •  Syndicate covering transactions involve purchases of the common stock in the open market after the distribution has been completed in order to cover syndicate short positions. In determining the source of shares to close out the short position, the underwriters will consider, among other things, the price of shares available for purchase in the open market as compared to the price at which they may purchase shares through the over-allotment option. If the underwriters sell more shares than could be covered by the over- allotment option, a naked short position, the position can only be closed out by buying shares in the open market. A naked short position is more likely to be created if the underwriters are concerned that there could be downward pressure on the price of the shares in the open market after pricing that could adversely affect investors who purchase in the offering.

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  •  Penalty bids permit the representatives to reclaim a selling concession from a syndicate member when the common stock originally sold by the syndicate member is purchased in a stabilizing or syndicate covering transaction to cover syndicate short positions.
      These stabilizing transactions, syndicate covering transactions and penalty bids may have the effect of raising or maintaining the market price of our common stock or preventing or retarding a decline in the market price of the common stock. As a result, the price of our common stock may be higher than the price that might otherwise exist in the open market. These transactions may be effected on the New York Stock Exchange or otherwise and, if commenced, may be discontinued at any time.
      A prospectus in electronic format may be made available on the websites maintained by one or more of the underwriters, or selling group members, if any, participating in this offering and one or more of the underwriters participating in this offering may distribute prospectuses electronically. The representatives may agree to allocate a number of shares to underwriters and selling group members for sale to their online brokerage account holders. Internet distributions will be allocated by the underwriters and selling group members that will make Internet distributions on the same basis as other allocations.

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NOTICE TO CANADIAN RESIDENTS
Resale Restrictions
      The distribution of our common stock in Canada is being made only on a private placement basis exempt from the requirement that we and the selling stockholders prepare and file a prospectus with the securities regulatory authorities in each province where trades of common stock are made. Any resale of the common stock in Canada must be made under applicable securities laws which will vary depending on the relevant jurisdiction, and which may require resales to be made under available statutory exemptions or under a discretionary exemption granted by the applicable Canadian securities regulatory authority. Purchasers are advised to seek legal advice prior to any resale of the common stock.
Representations of Purchasers
      By purchasing common stock in Canada and accepting a purchase confirmation, a purchaser is representing to us, the selling stockholders and the dealer from whom the purchase confirmation is received that:
  •  the purchaser is entitled under applicable provincial securities laws to purchase the common stock without the benefit of a prospectus qualified under those securities laws;
 
  •  where required by law, that the purchaser is purchasing as principal and not as agent; and
 
  •  the purchaser has reviewed the text above under “– Resale Restrictions.”
Rights of Action – Ontario Purchasers Only
      Under Ontario securities legislation, a purchaser who purchases a security offered by this prospectus during the period of distribution will have a statutory right of action for damages, or while still the owner of the common stock, for rescission against us and the selling stockholders in the event that this prospectus contains a misrepresentation. A purchaser will be deemed to have relied on the misrepresentation. The right of action for damages is exercisable not later than the earlier of 180 days from the date the purchaser first had knowledge of the facts giving rise to the cause of action and three years from the date on which payment is made for the common stock. The right of action for rescission is exercisable not later than 180 days from the date on which payment is made for the common stock. If a purchaser elects to exercise the right of action for rescission, the purchaser will have no right of action for damages against us or the selling stockholders. In no case will the amount recoverable in any action exceed the price at which the common stock was offered to the purchaser and if the purchaser is shown to have purchased the securities with knowledge of the misrepresentation, we and the selling stockholders will have no liability. In the case of an action for damages, we and the selling stockholders will not be liable for all or any portion of the damages that are proven to not represent the depreciation in value of the common stock as a result of the misrepresentation relied upon. These rights are in addition to, and without derogation from, any other rights or remedies available at law to an Ontario purchaser. The foregoing is a summary of the rights available to an Ontario purchaser. Ontario purchasers should refer to the complete text of the relevant statutory provisions.
Enforcement of Legal Rights
      All of our directors and officers as well as the experts named herein and the selling stockholders may be located outside of Canada and, as a result, it may not be possible for Canadian purchasers to effect service of process within Canada upon us or those persons. All or a substantial portion of our assets and the assets of those persons may be located outside of Canada and, as a result, it may not be possible to satisfy a judgment against us or those persons in Canada or to enforce a judgment obtained in Canadian courts against us or those persons outside of Canada.

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Taxation and Eligibility for Investment
      Canadian purchasers of common stock should consult their own legal and tax advisors with respect to the tax consequences of an investment in the common stock in their particular circumstances and about the eligibility of the common stock for investment by the purchaser under relevant Canadian legislation.
LEGAL MATTERS
      The validity of the shares of common stock offered by this prospectus will be passed upon for us by Vinson & Elkins L.L.P., Houston, Texas and certain legal matters in connection with this offering will be passed upon for the underwriters by Baker Botts L.L.P., Houston, Texas.
EXPERTS
      The consolidated financial statements of Complete Production Services, Inc. and subsidiaries as of December 31, 2004 and for the year then ended included in this prospectus and elsewhere in the registration statement have been audited by Grant Thornton LLP, independent registered public accountants, as indicated in their report with respect thereto, and are included herein in reliance upon the authority of said firm as experts in accounting and auditing.
      The consolidated financial statements of Complete Production Services, Inc. and subsidiaries as of December 31, 2003, and for each of the years in the two-year period ended December 31, 2003, have been included herein and in the registration statement in reliance upon the report of KPMG LLP (“KPMG”), independent registered public accounting firm, appearing elsewhere herein, and upon the authority of said firm as experts in accounting and auditing.
      Complete Production Services, Inc. has agreed to indemnify and hold KPMG harmless against and from any and all legal costs and expenses incurred by KPMG in the successful defense of any legal action or proceeding that arises as a result of KPMG’s consent to the inclusion of its audit reports on the Company’s past financial statements included in this registration statement.

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WHERE YOU CAN FIND MORE INFORMATION
      We have filed with the SEC a registration statement on Form S-1 regarding the common stock offered by this prospectus. This prospectus does not contain all of the information found in the registration statement. For further information regarding us and the common stock offered in this prospectus, you may desire to review the full registration statement, including its exhibits. The registration statement, including the exhibits, may be inspected and copied at the public reference facilities maintained by the SEC at 100 F Street, N.E., Washington D.C. 20549. Copies of this material can also be obtained upon written request from the Public Reference Section of the SEC at prescribed rates, or accessed at the SEC’s website on the Internet at www.sec.gov. Please call the SEC at 1-800-SEC-0330 for further information on its public reference room. In addition, our future public filings can also be inspected and copied at the offices of the New York Stock Exchange, Inc., 20 Broad Street, New York, New York 10005.
      We are not, and the underwriters are not, making an offer to sell these securities in any jurisdiction where an offer or sale is not permitted. You should assume that the information appearing in this prospectus is accurate as of the date on the front cover of this prospectus only. Our business, financial condition, results of operations and prospects may have changed since that date.
      Following the completion of this offering, we will file with or furnish to the SEC periodic reports and other information. These reports and other information may be inspected and copied at the public reference facilities maintained by the SEC or obtained from the SEC’s website as provided above. Our website on the Internet is located at www.completeprodsvcs.com, and we expect to make our periodic reports and other information filed with or furnished to the SEC available, free of charge, through our website, as soon as reasonably practicable after those reports and other information are electronically filed with or furnished to the SEC. Information on our website or any other website is not incorporated by reference into this prospectus and does not constitute a part of this prospectus. You may also request a copy of these filings at no cost, by writing or telephoning us at the following address: Complete Production Services, Inc., Attention: Chief Financial Officer, 14450 JFK Blvd., Suite 400, Houston, Texas 77032, (281) 372-2300.
      We intend to furnish or make available to our stockholders annual reports containing our audited financial statements prepared in accordance with GAAP. We also intend to furnish or make available to our stockholders quarterly reports containing our unaudited interim financial information, including the information required on a Quarterly Report on Form 10-Q, for the first three fiscal quarters of each fiscal year.

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INDEX TO FINANCIAL STATEMENTS
Complete Production Services, Inc.
           
    Page
     
Unaudited Interim Consolidated Financial Statements
       
 
Consolidated Balance Sheets as of September 30, 2005 and December 31, 2004
    F-2  
 
Consolidated Statements of Operations and Consolidated Statements of Comprehensive Income for the Nine Months Ended September 30, 2005 and 2004
    F-3  
 
Consolidated Statement of Stockholders’ Equity for the Nine Months Ended September 30, 2005
    F-4  
 
Consolidated Statements of Cash Flows for the Nine Months Ended September 30, 2005 and 2004
    F-5  
 
Notes to Consolidated Financial Statements
    F-6  
Audited Consolidated Financial Statements
       
 
Report of Independent Registered Public Accounting Firm
    F-20  
 
Report of Independent Registered Public Accounting Firm
    F-21  
 
Report of Independent Registered Public Accounting Firm
    F-22  
 
Report of Independent Registered Public Accounting Firm
    F-23  
 
Consolidated Balance Sheets as of December 31, 2004 and 2003
    F-24  
 
Consolidated Statements of Operations (Loss) and Consolidated Statements of Comprehensive Income (Loss) for the Years Ended December 31, 2004, 2003 and 2002
    F-25  
 
Consolidated Statements of Stockholders’ Equity for the Years Ended
December 31, 2004, 2003 and 2002
    F-26  
 
Consolidated Statements of Cash Flows for the Years Ended December 31, 2004, 2003 and 2002
    F-27  
 
Notes to Consolidated Financial Statements
    F-28  

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COMPLETE PRODUCTION SERVICES, INC.
Consolidated Balance Sheets
September 30, 2005 (unaudited) and December 31, 2004
                     
    2005   2004
         
    (In thousands, except
    share data)
ASSETS
Current assets:
               
 
Cash and cash equivalents
  $ 19,062     $ 11,547  
 
Trade accounts receivable, net
    137,121       85,801  
 
Inventory
    38,937       21,910  
 
Prepaid expenses
    12,820       5,825  
 
Deferred tax asset
    849       870  
             
   
Total current assets
    208,789       125,953  
Property, plant and equipment, net
    340,246       235,211  
Intangible assets, net of accumulated amortization of $1,888, and other
    5,648       4,073  
Deferred financing costs, net of accumulated amortization of $623
    4,198       4,467  
Goodwill
    210,989       145,449  
             
 
Total assets
  $ 769,870     $ 515,153  
             
 
LIABILITIES AND STOCKHOLDERS’ EQUITY
 
Current liabilities:
               
 
Bank operating loans
  $ 4,685     $ 21,745  
 
Current maturities of long-term debt
    5,394       28,493  
 
Convertible debentures
          4,150  
 
Accounts payable
    44,424       27,688  
 
Accrued liabilities
    23,345       18,848  
 
Unearned revenue
    7,400        
 
Notes payable
    1,532       2,735  
 
Taxes payable
    447       1,081  
             
   
Total current liabilities
    87,227       104,740  
Long-term debt
    452,496       169,190  
Deferred income taxes
    49,234       26,225  
Minority interest
    2,352       5,477  
             
 
Total liabilities
    591,309       305,632  
Commitments and contingencies
               
Stockholders’ equity:
               
 
Common stock, $0.01 par value per share, 100,000,000 shares authorized, 27,810,283 (2004 – 25,107,341) issued
    278       251  
 
Additional paid-in capital
    163,475       177,015  
 
Retained earnings
    936       18,690  
 
Treasury stock, 17,785 shares at cost
    (202 )      
 
Deferred compensation
    (2,121 )     (932 )
 
Accumulated other comprehensive income
    16,195       14,497  
             
 
Total stockholders’ equity
    178,561       209,521  
             
   
Total liabilities and stockholders’ equity
  $ 769,870     $ 515,153  
             
See accompanying notes to consolidated financial statements.

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COMPLETE PRODUCTION SERVICES, INC.
Consolidated Statements of Operations
Nine Months Ended September 30, 2005 and 2004 (unaudited)
                   
    2005   2004
         
    (In thousands, except
    per share data)
Revenue:
               
 
Service
  $ 434,745     $ 136,431  
 
Product
    90,491       58,962  
             
      525,236       195,393  
Service expenses
    266,344       91,018  
Product expenses
    69,968       41,611  
Selling, general and administrative expenses
    75,535       28,844  
Write-off of deferred financing fees
    2,844        
Depreciation and amortization
    32,902       12,366  
             
 
Income before interest, taxes and minority interest
    77,643       21,554  
Interest expense
    15,617       4,525  
             
 
Income before taxes and minority interest
    62,026       17,029  
Taxes
    23,734       6,574  
             
 
Income before minority interest
    38,292       10,455  
Minority interest
    380       344  
             
 
Net income
  $ 37,912     $ 10,111  
             
Earnings per share:
               
 
Basic
  $ 1.39     $ 0.71  
             
 
Diluted
  $ 1.28     $ 0.62  
             
Weighted average shares:
               
 
Basic
    27,282       14,176  
 
Diluted
    29,640       16,186  
Consolidated Statements of Comprehensive Income
Nine Months Ended September 30, 2005 and 2004 (unaudited)
                   
    2005   2004
         
    (In thousands)
Net income
  $ 37,912     $ 10,111  
Change in cumulative translation adjustment
    1,698       1,021  
             
 
Comprehensive income
  $ 39,610     $ 11,132  
             
See accompanying notes to consolidated financial statements.

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COMPLETE PRODUCTION SERVICES, INC.
Consolidated Statement of Stockholders’ Equity
Nine Months Ended September 30, 2005 (unaudited)
                                                                   
                            Accumulated    
            Additional               Other    
    Number   Common   Paid-In   Treasury   Retained   Deferred   Comprehensive    
    of Shares   Stock   Capital   Stock   Earnings   Compensation   Income   Total
                                 
    (In thousands, except share data)
Balance at December 31, 2004
    25,107,341     $ 251     $ 177,015     $     $ 18,690     $ (932 )   $ 14,497     $ 209,521  
Net income
                            37,912                   37,912  
Cumulative translation adjustment
                                        1,698       1,698  
Issuance of common stock:
                                                               
 
Acquisition of Parchman
    1,500,000       15       19,050                               19,065  
 
Acquisition of RSI
    68,222       1       1,159                               1,160  
 
Acquisition of Spindletop
    45,182             1,053                               1,053  
 
Exercise of warrants
    1,024,250       10       9,990                               10,000  
 
For cash
    75,532       1       1,199                               1,200  
 
Exercise of stock options
    7,541             79                               79  
Purchase of warrants
                (256 )                             (256 )
Issuance of restricted stock
                1,641                   (1,641 )            
Amortization of deferred compensation
                                  452             452  
Purchase of minority interest
                43,769                               43,769  
Dividend paid
                (91,224 )           (55,666 )                 (146,890 )
Repurchase of common stock
    (17,785 )                 (202 )                       (202 )
                                                 
Balance at September 30, 2005
    27,810,283     $ 278     $ 163,475     $ (202 )   $ 936     $ (2,121 )   $ 16,195     $ 178,561  
                                                 
See accompanying notes to consolidated financial statements.

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Table of Contents

COMPLETE PRODUCTION SERVICES, INC.
Consolidated Statements of Cash Flows
Nine Months Ended September 30, 2005 and 2004 (unaudited)
                     
    2005   2004
         
    (In thousands)
Cash provided by (used in):
               
Operating activities:
               
 
Net income
  $ 37,912     $ 10,111  
 
Items not affecting cash:
               
   
Depreciation and amortization
    32,902       12,366  
   
Deferred income taxes
    19,276       14,647  
   
Minority interest
    380       344  
   
Write-off of deferred financing fees
    2,844        
   
Other
    1,362       180  
 
Net change in working capital
    (46,205 )     (22,181 )
             
      48,471       15,467  
Financing activities:
               
 
Issuances of long-term debt
    634,109       109,823  
 
Repayments of long-term debt
    (413,055 )     (51,811 )
 
Net borrowings (repayments) under lines of credit
    (17,060 )     6,744  
 
Issuances (repayments) of notes payable
    (1,203 )     17,925  
 
Repayment of convertible debenture
    (4,069 )      
 
Proceeds from issuances of common stock
    11,268       3,956  
 
Repurchase of common stock/warrants
    (458 )      
 
Dividends paid
    (146,890 )      
 
Deferred financing costs
    (4,076 )     (3,233 )
             
      58,566       83,404  
Investing activities:
               
 
Business acquisitions, net of cash acquired
    (18,163 )     (75,119 )
 
Additions to property, plant and equipment
    (84,885 )     (24,748 )
 
Proceeds from disposal of capital assets
    3,903        
             
      (99,145 )     (99,867 )
Effect of exchange rate changes on cash
    (377 )     (9 )
             
Change in cash and cash equivalents
    7,515       (1,005 )
Cash and cash equivalents, beginning of period
    11,547       6,094  
             
Cash and cash equivalents, end of period
  $ 19,062     $ 5,089  
             
See accompanying notes to consolidated financial statements.

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Table of Contents

COMPLETE PRODUCTION SERVICES, INC.
Notes to Consolidated Financial Statements
Nine Months Ended September 30, 2005 and 2004 (unaudited)
(In thousands, except as noted and per share data)
1.     General:
(a) Nature of operations:
      Complete Production Services, Inc. (“Complete” or the “Company”) is a provider of specialized services and products focused on developing hydrocarbon reserves, reducing operating costs and enhancing production for oil and gas companies. The Company focuses on basins within North America and delivers targeted services and products required by its customers within each specific basin. The Company manages its operations from regional field service facilities located throughout the U.S. Rocky Mountain region, Texas, Oklahoma, Louisiana, western Canada and Mexico. The Company also has offices in Southeast Asia from which it delivers products to international oil and gas customers. Complete’s business depends, to a large degree, on the level of spending by oil and gas companies for exploration, development and production activities. Therefore, a sustained increase or decrease in the price of oil and gas, which could have a material impact on exploration, development and production activities, also could materially affect our financial position, results of operations and cash flows.
      On September 12, 2005, the Company completed the combination (“Combination”) of Complete Energy Services, Inc. (“CES”), Integrated Production Services, Inc. (“IPS”) and I.E. Miller Services, Inc. (“IEM”) pursuant to which the CES and IEM shareholders exchanged all of their common stock for common stock of IPS. CES shareholders received 19.704 shares of IPS common stock for each share of CES, and IEM shareholders received 19.410 shares of IPS common stock for each share of IEM. Subsequent to the combination, IPS changed its name to Complete Production Services, Inc. and the former CES shareholders owned 57.6% of Complete common shares, IPS shareholders owned 33.2% and the former IEM shareholders owned 9.2%.
      The consolidated financial statements include the activities of CES, IPS and IEM for the respective periods presented, and have been prepared using the continuity of interests accounting method, which yields results similar to the pooling of interests method, under which the Company combined these entities which were under common control and majority ownership of SCF-IV, L.P. (“SCF”), a private equity firm that focuses on investments in the oilfield services segment of the energy industry. Under this method of accounting, the historical financial statements of CES, IPS and IEM are combined for the nine months ended September 30, 2005 and September 30, 2004, in each case from the date each became controlled by SCF (IPS – May 22, 2001, CES – November 7, 2003, and IEM – August 26, 2004). The accounting policies adopted by the Company were the same policies that the predecessor companies employed. Upon the completion of the Combination, the shareholders of CES held a majority ownership position in the equity of Complete, retained senior officer positions and former CES directors represent a majority of the directors of Complete. Accordingly, CES will be treated as the accounting acquirer of the minority interests as a result of the Combination. The minority interest in net income for each year is calculated based upon the percentage of equity ownership not held by SCF in each of IPS and IEM. The consolidated financial statements have been adjusted to reflect minority interest ownership in Complete.
(b) Basis of presentation:
      The unaudited interim consolidated financial statements reflect all normal recurring adjustments that are, in the opinion of management, necessary for a fair statement of the financial position of Complete as of September 30, 2005 and the statements of operations, comprehensive income, stockholders’ equity and cash flows for the nine months ended September 30, 2005 and 2004. Certain information and disclosures normally included in annual financial statements prepared in accordance with U.S. GAAP have been condensed or omitted. These unaudited interim consolidated financial statements should be read in conjunction with the audited consolidated financial statements of the Company for the year ended

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COMPLETE PRODUCTION SERVICES, INC.
Notes to Consolidated Financial Statements — (Continued)
Nine Months Ended September 30, 2005 and 2004 (unaudited)
(In thousands, except as noted and per share data)
December 31, 2004. Management believes that these financial statements contain all adjustments required to make them not misleading.
      In preparing financial statements, management makes informed judgments and estimates that affect the reported amounts of assets and liabilities as of the date of the financial statements and affect the reported amounts of revenues and expenses during the reporting period. On an ongoing basis, management reviews its estimates, including those related to impairment of long-lived assets and goodwill, contingencies and income taxes. Changes in facts and circumstances may result in revised estimates and actual results may differ from these estimates.
      The results of operations for interim periods are not necessarily indicative of the results of operations that could be expected for the full year.
2.     Business combinations:
(a) The Combination:
      On September 12, 2005, Integrated Production Services, Inc. (“IPS”) acquired Complete Energy Services, Inc. (“CES”) and I.E. Miller Services, Inc. (“IEM”) for stock. The Company refers to this transaction as the “Combination.” The Combination was accounted for using the continuity of interest method as described in note 1 of the audited consolidated financial statements at December 31, 2004. Upon closing the Combination, IPS changed its name to Complete Production Services, Inc. For accounting purposes, CES was deemed to be the acquiring entity.
      The acquisition of the minority interests of IPS and IEM in exchange for shares of our common stock and the elimination of the historical amounts reflected in the combined group was as noted below.
                           
    IPS   IEM   Total
             
Common stock to minority interest
  $ 58,284     $ 15,773     $ 74,057  
Minority interest in fair value of net assets acquired
    30,848       4,792       35,640  
                   
 
Amount recorded as goodwill
  $ 27,436     $ 10,981     $ 38,417  
                   
      Since this transaction represents the purchase of a minority interest in the combined entity, assets and liabilities were deemed to be recorded at historical cost which approximated fair value. Therefore, the Company recorded an increase in additional paid-in-capital with a similar increase in goodwill, with no other changes to asset or liability accounts. The purchase price of the minority interest in IEM and IPS is preliminary as of September 30, 2005.
(b) Parchman Energy Group, Inc. (“Parchman”):
      On February 11, 2005, the Company acquired all of the common shares of Parchman in a business combination accounted for as a purchase. Parchman performs coiled tubing services, well testing services, snubbing services and wireline services in Louisiana, Texas, Wyoming and Mexico. The results of operations for Parchman were included in the accounts of Complete from the date of acquisition. In addition, the purchase agreement provides for the issuance of up to 500,000 common shares of the Company as contingent consideration over the period from the date of acquisition to December 31, 2005 based on certain operating results of the Company’s operations in the United States. Goodwill of $21,975 resulted from the acquisition and was allocated entirely to the completion and production services segment. Intangible assets included customer relationships and patents that are being amortized over a 3 to 5 year period.

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Table of Contents

COMPLETE PRODUCTION SERVICES, INC.
Notes to Consolidated Financial Statements — (Continued)
Nine Months Ended September 30, 2005 and 2004 (unaudited)
(In thousands, except as noted and per share data)
      The following table summarizes the preliminary purchase price allocation:
           
Net assets acquired:
       
 
Non-cash working capital
  $ 3,401  
 
Property, plant and equipment
    48,688  
 
Intangible assets
    459  
 
Goodwill (no tax basis)
    21,975  
 
Long-term debt
    (32,017 )
 
Deferred income taxes
    (8,608 )
       
Net assets acquired
  $ 33,898  
       
Consideration:
       
 
Cash, net of cash and cash equivalents acquired
  $ 9,833  
 
Subordinated note
    5,000  
 
Issuance of common stock (1,500,000 shares)
    19,065  
       
Consideration
  $ 33,898  
       
      The price for common shares was based on internal calculations of the fair value and consultations with the seller. The purchase price allocation is preliminary and certain items such as acquisition costs, final tax basis and fair values of asset and liabilities as of the acquisition date have not been finalized.
(c) Premier Integrated Technologies (“Premier”):
      On January 1, 2005, the Company acquired a 50% interest in Premier in a business combination accounted for as a purchase. Premier provides optimization services in Alberta, British Columbia and Saskatchewan. The Company consolidates Premier, including results of operations, in the accounts of Complete from the date of acquisition and has recorded the minority interest ownership. Goodwill of $997 resulted from this acquisition and was allocated entirely to the completion and production services segment.
      The following table summarizes the preliminary purchase price allocated to the Company’s 50% interest:
           
Net assets acquired:
       
 
Non-cash working capital
  $ 2,390  
 
Property, plant and equipment
    2,164  
 
Goodwill
    997  
 
Long-term debt
    (750 )
 
Minority interest
    (1,902 )
       
Net assets acquired
  $ 2,899  
       
Consideration:
       
 
Non-cash working capital
  $ 1,559  
 
Property, plant and equipment
    1,340  
       
Consideration
  $ 2,899  
       

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Table of Contents

COMPLETE PRODUCTION SERVICES, INC.
Notes to Consolidated Financial Statements — (Continued)
Nine Months Ended September 30, 2005 and 2004 (unaudited)
(In thousands, except as noted and per share data)
      The purchase price allocation is preliminary and certain items such as fair value of assets and liabilities as of the acquisition date have not been finalized.
(d) Roustabout Specialties Inc. (“RSI”):
      On July 7, 2005, the Company acquired all of the common shares of RSI in a business combination accounted for as a purchase. RSI is a field services and rental company headquartered in Grand Junction, Colorado, with a primary service area of operation in the Piceance Basin of Western Colorado. The results of operations for RSI were included in the accounts of Complete from the date of acquisition. Goodwill of $2,300 resulted from the acquisition and was allocated entirely to the completion and production services segment.
      The following table summarizes the preliminary purchase price allocation:
           
Net assets acquired:
       
 
Non-cash working capital
  $ 1,718  
 
Property, plant and equipment
    4,900  
 
Goodwill
    2,294  
Net assets acquired
  $ 8,912  
       
Consideration:
       
 
Cash, net of cash and cash equivalents acquired
  $ 7,752  
 
Issuance of common stock (68,222 shares)
    1,160  
       
Consideration
  $ 8,912  
       
      The price for common shares was based on internal calculations of the fair value. The purchase price allocation is preliminary and certain items such as acquisition costs, final tax basis and fair values of asset and liabilities as of the acquisition date have not been finalized.
(e) Spindletop Production Services, Ltd. (“Spindletop”):
      On September 29, 2005, the Company acquired all of the assets of Spindletop, an entity owned by a related party, in a transaction accounted for as a purchase. This business consists of a manufacturing and equipment repair operation located in Gainsville, Texas, which produces completion products to be sold through our supply stores, distributors and direct sales force, with a primary service area of the Barnett Shale region of north Texas. The results of operations for this business were included in the accounts of the Company from the date of acquisition. Goodwill of $613 resulted from the acquisition and was allocated entirely to the product sales segment.

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Table of Contents

COMPLETE PRODUCTION SERVICES, INC.
Notes to Consolidated Financial Statements — (Continued)
Nine Months Ended September 30, 2005 and 2004 (unaudited)
(In thousands, except as noted and per share data)
      The following table summarizes the preliminary purchase price allocation:
           
Net assets acquired:
       
 
Non-cash working capital
  $ (9 )
 
Property, plant and equipment
    686  
 
Goodwill
    613  
Net assets acquired
  $ 1,290  
       
Consideration:
       
 
Cash, net of cash and cash equivalents acquired
  $ 237  
 
Issuance of common stock (45,182 shares)
    1,053  
       
Consideration
  $ 1,290  
       
      The price for common shares was based on internal calculations of the fair value. The purchase price allocation is preliminary and certain items such as acquisition costs, final tax basis and fair values of asset and liabilities as of the acquisition date have not been finalized.
3. Inventory:
                 
    2005   2004
         
Finished goods
  $ 34,203     $ 19,929  
Manufacturing parts and materials
    6,337       3,344  
             
      40,540       23,273  
Inventory reserves
    1,603       1,363  
             
    $ 38,937     $ 21,910  
             
4.     Accounts receivable:
                 
    2005   2004
         
Trade
  $ 129,542     $ 80,980  
Unbilled revenue
    7,264       4,152  
Notes receivable
    713       183  
Other
    711       1,029  
             
      138,230       86,344  
Allowance for doubtful accounts
    1,109       543  
             
    $ 137,121     $ 85,801  
             

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Table of Contents

COMPLETE PRODUCTION SERVICES, INC.
Notes to Consolidated Financial Statements — (Continued)
Nine Months Ended September 30, 2005 and 2004 (unaudited)
(In thousands, except as noted and per share data)
5.     Property, plant and equipment:
                 
    2005   2004
         
Land
  $ 3,770     $ 848  
Building
    4,814       6,577  
Field equipment
    358,557       238,948  
Vehicles
    24,242       18,610  
Office furniture and computers
    4,001       2,254  
Leasehold improvements
    3,638       1,556  
Construction in progress
    5,516        
             
      404,538       268,793  
Accumulated depreciation and amortization
    64,291       33,582  
             
    $ 340,247     $ 235,211  
             
6.     Long-term debt:
      Effective February 11, 2005, the Company and a group of banks entered into a new credit facility replacing the facilities described in notes 9 and 10(a) of the December 31, 2004 audited consolidated financial statements. The new syndicated credit facility included five separate facilities secured by a common security package. The agreement included a U.S. operating facility providing up to $20,000 and a Canadian operating facility providing up to C$15,000. Each operating facility was to mature on February 10, 2008. The agreement also included two reducing term facilities ($20,000 and C$30,000) which were to mature on February 10, 2010 and required quarterly payments of $1,000 and C$1,500, respectively. Each of these four facilities bore interest from prime plus 0.25% to prime plus 1.50% per annum, 1.5% at September 30, 2005, on a grid based on certain financial ratios. The fifth term facility was in the amount of $35,000, was to mature February 10, 2011, required quarterly payments of $88, and bore interest at the London Interbank Borrowing Rate (“LIBOR”) plus 3.5%. The credit facilities required the maintenance of certain financial ratios and other covenants and were secured by substantially all of the assets of IPS. The Canadian dollar to U.S. dollar exchange rate at September 30, 2005 was $1.1713.
      During the first quarter of 2005, the Company amended the term and revolving loans described in note 10(b) of the December 31, 2004 audited consolidated financial statements several times which resulted in increased total borrowing capacity and the extension of the maturity dates of the term loan to February 2012 and the revolving line of credit to February 2009. Quarterly principal payments of $350 were required on the term loan. All borrowings under the term loan portion of this facility were retired on September 12, 2005. As of September 30, 2005, the Company had outstanding borrowings under the revolving portion of this facility of $26,100.
      Concurrent with the consummation of the Combination (note 1(a)), the Company entered into a syndicated senior secured credit facility (the “Credit Facility”) pursuant to which all bank debt held by each of IPS, CES and IEM was repaid and replaced with the proceeds from the Credit Facility. The Credit Facility was comprised of a $420,000 Term B term loan credit facility that will mature in September 2012, a U.S. revolving credit facility of $130,000 that will mature in September 2010, and a Canadian revolving credit facility of $30,000 that will mature in September 2010. Interest on the Credit Facility is determined by reference to LIBOR plus a margin of 1.25% to 2.75% (dependent on the ratio of total debt to EBITDA, as defined in the agreement) for revolving advances and a margin of 2.75% for Term B term loan advances. Interest on advances under the Canadian revolving facility was calculated at

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Table of Contents

COMPLETE PRODUCTION SERVICES, INC.
Notes to Consolidated Financial Statements — (Continued)
Nine Months Ended September 30, 2005 and 2004 (unaudited)
(In thousands, except as noted and per share data)
the Canadian Prime Rate plus a margin of 0.25% to 1.75%. Quarterly principal repayments of 0.25% of the original principal amount are required for the Term B term loans commencing December 2005. The Credit Facility contains covenants restricting the levels of certain transactions including: entering into certain loans, the granting of certain liens, capital expenditures, acquisitions, distributions to shareholders, certain asset dispositions and operating leases. The Credit Facility is secured by substantially all of the assets of the Company. As of September 30, 2005, the Company had borrowings of $420,000 outstanding under the term loan portion of this facility, which bore interest at 6.72%, leaving no borrowing capacity available. Under the revolving portion of this facility, there were no borrowings outstanding at September 30, 2005, only letters of credit totaling $5,300, leaving a borrowing capacity of $124,700.
7.     Subordinated notes:
      On February 11, 2005, the Company issued subordinated notes to certain sellers of Parchman common shares (note 2(a)). These notes are unsecured, subordinated to all present and future senior debt and bear interest at 6.0% during the first three years of the note, 8.0% during year four and 10.0% thereafter. There are no fixed terms of repayment and the Company, at its option, may repay the notes at anytime so long as such payment does not result in an event of default under any loan agreement. These subordinated notes, recorded as long-term debt at September 30, 2005, included notes totaling $4,765 which were beneficially held by directors or employees of the Company.
8.     Stockholders’ equity:
(a) Authorized:
      On September 12, 2005, the authorized share capital of the Company was increased to 100,000,000 common shares from 12,000,000 common shares with par value of $0.01 per share and to 5,000,000 preferred shares from 1,000 preferred shares with a par value of $0.01 per share.
      The Company’s board of directors approved a stock split on a ten-for-one basis in September 2002. This stock split has been reflected retroactively in these financial statements. Outstanding warrants and stock options awarded have also been retroactively adjusted to account for the stock split.
      On September 12, 2005, the Company completed the Combination of CES, IPS and IEM pursuant to which CES and IEM stockholders exchanged all of their common stock for common stock of IPS. The CES stockholders received 19.704 shares of IPS common stock for each share of CES, and the IEM stockholders received 19.410 shares of IPS common stock for each share of IEM. Subsequent to the combination, IPS changed its name to Complete Production Services, Inc. and the former CES stockholders owned 57.6% of Complete’s common shares, IPS stockholders owned 33.2% and the former IEM stockholders owned 9.2%. The amounts of authorized and issued stock, warrants and options of CES have been adjusted to reflect the exchange ratio of 19.704 pursuant to the Combination. The amounts of authorized and issued stock, warrants and options of IEM have been adjusted to reflect the exchange ratio of 19.410 pursuant to the Combination.
(b) Dividend:
      On September 12, 2005, Complete paid a dividend of $5.24 per share for an aggregate payment of approximately $146,900 to stockholders of record on that date. Up to an additional $3,100 will be paid to stockholders in respect of stock earnable pursuant to contingent consideration provisions of certain acquisition agreements previously entered into by the Company.

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Table of Contents

COMPLETE PRODUCTION SERVICES, INC.
Notes to Consolidated Financial Statements — (Continued)
Nine Months Ended September 30, 2005 and 2004 (unaudited)
(In thousands, except as noted and per share data)
(c) Warrants:
      On May 23, 2001, the Company issued a warrant to its major shareholder, SCF-IV, L.P. (“SCF”), giving SCF the right to purchase up to 2,000,000 shares of the Company’s common stock at an exercise price of $10.00 per share anytime through May 23, 2011. The warrant was issued as a source of future financing for the Company’s growth. In 2001 and 2004, SCF purchased 370,000 shares and 200,000 shares, respectively, pursuant to the warrant. On February 9, 2005, SCF purchased another 1,000,000 shares pursuant to the warrant. The warrant was cancelled on September 12, 2005.
      In August 2004, the Company issued a warrant to SCF to purchase up to 3,105,600 shares of the Company’s common stock at an exercise price of $5.15 per share at any time through August 31, 2007 and a warrant to one of the Company’s minority shareholders giving them the right to purchase up to 485,250 shares of the Company’s common stock at an exercise price of $5.15 per share at any time through August 31, 2007. These warrants were cancelled on September 12, 2005.
      Pursuant to the Subordinate Credit Agreement (note 10(e) of the December 31, 2004 audited consolidated financial statements), the Company issued detachable warrants to the lenders to purchase up to 35,909 shares of the Company’s common stock at $5.15 per share at any time through August 31, 2007. These warrants were cancelled on September 12, 2005.
      Also pursuant to the Subordinate Credit Agreement (note 10(e) of the December 31, 2004 audited consolidated financial statements), the Company issued detachable warrants to the lenders to purchase up to 24,263 shares of the Company’s common stock at $0.01 per share at any time through August 31, 2007. The fair value of these warrants, $125,000, was recorded as additional paid-in capital and as a discount on the liability under the Subordinate Credit Agreement. These warrants were exercised on September 12, 2005.
(d) Employee stock incentive plans:
      Following the Combination, the Company maintained each of the options plans previously maintained by IPS, CES and IEM. Under the three option plans, options could be granted to employees, officers and directors to purchase up to 1,500,000 common shares, 1,182,240 common shares and 388,200 common shares of the Company, respectively. The exercise price of each option is based on the fair value of the individual company’s stock at the date of grant. Options may be exercised over a 5-year period and generally a third of the options vest on each of the first three anniversaries from the grant date.
      Pursuant to the Combination, upon payment of the dividend of $5.24 per share as described in note 8(b), the terms of all options outstanding were adjusted to offset the decrease in the Company’s per share price attributable to the dividend. The result of this adjustment, applied to the options outstanding as at December 31, 2004, was an increase in the number of options outstanding to 1,129,698 and a reduction

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Table of Contents

COMPLETE PRODUCTION SERVICES, INC.
Notes to Consolidated Financial Statements — (Continued)
Nine Months Ended September 30, 2005 and 2004 (unaudited)
(In thousands, except as noted and per share data)
of the average exercise price to $7.20. The following table summarizes the change in the Company’s stock options outstanding, as adjusted, through September 30, 2005.
                 
    Options Outstanding
     
        Weighted
        Average
        Exercise
    Number   Price
         
Balance at December 31, 2004
    1,129,698     $ 7.20  
Granted
    639,286       11.90  
Exercised
    (7,541 )     8.23  
Cancelled
    (255,004 )     7.62  
             
Balance at September 30, 2005
    1,506,439     $ 9.03  
             
(e) Stock-based compensation:
      The Company applied the minimum value method prescribed in Accounting Principles Board (“APB”) No. 25 in accounting for its stock-based compensation plans. If compensation cost for the Company’s stock-based compensation plans had been determined using the fair value approach set forth in Statement of Financial Accounting Standards (“SFAS”) No. 123, the Company’s results of operation, for the nine months ended September 30, 2005 and 2004, would have been amounts indicated below:
                   
    2005   2004
         
Net income:
               
 
As reported
  $ 37,912     $ 10,111  
 
Add: Compensation expense recorded related to stock-based compensation, net of tax
    294       5  
 
Deduct: Impact of stock-based compensation expense determined under fair value method, net of tax
    (348 )     (58 )
             
 
Pro forma net income
  $ 37,858     $ 10,058  
             
Basic earnings per share:
               
 
As reported
  $ 1.39     $ 0.71  
             
 
Pro forma
  $ 1.39     $ 0.71  
             
Diluted earnings per share:
               
 
As reported
  $ 1.28     $ 0.62  
             
 
Pro forma
  $ 1.28     $ 0.62  
             

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COMPLETE PRODUCTION SERVICES, INC.
Notes to Consolidated Financial Statements — (Continued)
Nine Months Ended September 30, 2005 and 2004 (unaudited)
(In thousands, except as noted and per share data)
      The fair value of each stock option award on the grant date was estimated using the minimum value option pricing model with the following fair option values and assumptions applied to new grants during the nine months ended September 30, 2005 and 2004:
                   
    2005   2004
         
Weighted average fair value
  $ 2.15     $ 0.70  
Assumptions:
               
 
Risk free interest rate
    3.8% to 4.9 %     4.9 %
 
Dividend yield
           
 
Expected life (in years)
    3 to 4.5       3  
      The expected dividend rate used was zero, as the Company does not intend to pay dividends on its common stock in the future.
(f) Per share amounts:
      The weighted average common stock outstanding used in calculating basic and diluted net earnings per share at September 30, 2005 were 27,281,718 (2004 – 14,176,036) and 29,640,329 (2004 – 16,185,858), respectively. The reconciling items between basic and diluted weighted average common stock outstanding was the dilutive impact of outstanding stock options restricted stock, convertible debentures and stock and warrants. The Company excluded the effect of anti-dilutive securities from the calculation of diluted weighted average shares for the nine-month periods ended September 30, 2005 and 2004. If these securities had been included in the calculations, diluted weighted average shares would have been 29,708,414 and 16,307,336, respectively, with no impact on earnings per share as disclosed.
(g) Repurchase of common stock:
      In 2005, the Company paid $200 to repurchase 17,785 shares of common stock from a former officer of a predecessor company.
9.     Goodwill:
      The change in the carrying amount of goodwill for the nine months ended September 30, 2005 was as follows:
           
Balance at December 31, 2004
  $ 145,449  
Acquisition of:
       
 
Parchman Energy Group
    21,975  
 
Premier Integrated Technologies Ltd. 
    997  
 
Roustabout Specialties Inc. 
    2,294  
 
Spindletop
    613  
Purchase of minority interest
    38,417  
Impact of foreign currency translation and other
    1,243  
       
 
Balance at September 30, 2005
  $ 210,988  
       
10.     Related party transactions:
      On December 1, 2001, Bison Oilfield Tools, Ltd. (“Bison”), and PEG, a subsidiary of IPS, entered into a lease agreement pursuant to which PEG leases real property from Bison. A former director of IPS controls Bison as the president of its two general partners. IPS is required to pay Bison $4 per month until December 2006, the date on which the lease terminates.

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COMPLETE PRODUCTION SERVICES, INC.
Notes to Consolidated Financial Statements — (Continued)
Nine Months Ended September 30, 2005 and 2004 (unaudited)
(In thousands, except as noted and per share data)
      Premier Integrated Technologies Ltd. (“PIT”), a subsidiary of IPS, purchased $472 of machining services from a company controlled by employees of PIT during the nine-month period ended September 30, 2005.
      The Company has entered into lease agreements for properties owned by employees and directors of the Company. The leases expire at different times through June 2014. In the nine months ended September 30, 2005, the total lease expense pursuant to these leases was $1,100.
      The Company has provided services to companies majority-owned by directors of the Company aggregating $16,500 in the nine months ended September 30, 2005. The Company has provided services to a company majority-owned by an officer of a subsidiary of the Company aggregating $5,000 in the nine months ended September 30, 2005.
      On September 29, 2005, we entered into that certain Asset Purchase Agreement with Spindletop and Mr. Schmitz. Pursuant to the agreement, we purchased the assets of Spindletop in exchange for approximately $200 cash and 45,182 shares of our common stock. Mr. Schmitz is an officer of one of our subsidiaries.
11.     Segmented information:
      SFAS No. 131, Disclosure About Segments of an Enterprise and Related Information, establishes standards for the reporting of information about operating segments, products and services, geographic areas, and major customers. The method of determining what information to report is based on the way management organizes the operating segments within the Company for making operational decisions and assessments of financial performance. The Company evaluates performance and allocates resources based on net income (loss) before interest expense, taxes, depreciation and amortization and minority interest (“EBITDA”). The calculation of EBITDA should not be viewed as a substitute for calculations under U.S. GAAP, in particular net income. EBITDA calculated by the Company may not be comparable to another company.
      The Company has three reportable operating segments: completion and production services (“C&PS”), drilling services and product sales as well as three geographic regions: the United States, Canada and International. The accounting policies of the segments are the same as those described in note 1. Other inter-segment transactions are accounted for on a cost recovery basis.

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COMPLETE PRODUCTION SERVICES, INC.
Notes to Consolidated Financial Statements — (Continued)
Nine Months Ended September 30, 2005 and 2004 (unaudited)
(In thousands, except as noted and per share data)
Operational segments:
                                         
        Drilling   Product        
Nine Months Ended September 30, 2005   C&PS   Services   Sales   Corporate   Total
                     
Revenue from external customers
  $ 351,154     $ 89,016     $ 85,066     $     $ 525,236  
EBITDA, as defined
  $ 82,615     $ 27,658     $ 11,131     $ (10,859 )   $ 110,545  
Depreciation and amortization
  $ 27,100     $ 3,968     $ 1,204     $ 630     $ 32,902  
                               
Operating income (loss)
  $ 55,515     $ 23,690     $ 9,927     $ (11,489 )   $ 77,643  
Capital expenditures
  $ 52,172     $ 29,316     $ 1,459     $ 1,938     $ 84,885  
September 30, 2005
                                       
                               
 
Segment assets
  $ 521,356     $ 111,532     $ 65,768     $ 71,214     $ 769,870  
Goodwill
  $ 151,649     $ 15,025     $ 6,147     $ 38,168     $ 210,989  
                                         
        Drilling   Product        
Nine Months Ended September 30, 2004   C&PS   Services   Sales   Corporate   Total
                     
Revenue from external customers
  $ 112,611     $ 23,820     $ 58,962     $     $ 195,393  
EBITDA, as defined
  $ 21,939     $ 5,104     $ 10,199     $ (3,322 )   $ 33,920  
Depreciation and amortization
  $ 9,514     $ 1,401     $ 856     $ 595     $ 12,366  
                               
Operating income (loss)
  $ 12,425     $ 3,703     $ 9,343     $ (3,917 )   $ 21,554  
Capital expenditures
  $ 18,717     $ 4,374     $ 1,243     $ 414     $ 24,748  
December 31, 2004
                                       
                               
 
Segment assets
  $ 384,014     $ 72,839     $ 53,751     $ 4,549     $ 515,153  
Goodwill
  $ 124,197     $ 15,022     $ 6,230     $     $ 145,449  
Geographic information:
                                 
    United       Other    
Nine Months Ended September 30, 2005   States   Canada   International   Total
                 
Revenue by sale origin to external customers
  $ 421,471     $ 73,776     $ 29,989     $ 525,236  
Net income before taxes and minority interest
  $ 52,399     $ 4,612     $ 5,015     $ 62,026  
September 30, 2005
                               
                         
 
Long-lived assets
  $ 631,384     $ 100,467     $ 38,019     $ 769,870  
                                 
    United       Other    
Nine Months Ended September 30, 2004   States   Canada   International   Total
                 
Revenue by sale origin to external customers
  $ 132,862     $ 51,320     $ 11,211     $ 195,393  
Income before taxes and minority interest
  $ 14,653     $ 539     $ 1,837     $ 17,029  
December 31, 2004
                               
                         
 
Long-lived assets
  $ 432,093     $ 79,662     $ 3,398     $ 515,153  

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COMPLETE PRODUCTION SERVICES, INC.
Notes to Consolidated Financial Statements — (Continued)
Nine Months Ended September 30, 2005 and 2004 (unaudited)
(In thousands, except as noted and per share data)
12.     Supplemental cash flow information:
                   
    2005   2004
         
Changes in:
               
 
Accounts receivable
  $ (43,718 )   $ (12,556 )
 
Inventory
    (16,489 )     (3,242 )
 
Prepaid expenses
    (6,901 )     (3,467 )
 
Accounts payable
    16,265       2,084  
 
Accrued liabilities
    5,600       (11,133 )
 
Other
    (962 )     6,133  
             
    $ (46,205 )   $ (22,181 )
             
Cash interest paid
  $ 15,776     $ 3,599  
Cash taxes paid
  $ 5,924     $ 585  
Common stock issued on acquisitions
  $ 21,278     $ 41,737  
Acquisition of minority interest
  $ 38,417        
Notes issued for acquisitions
  $ 5,000     $ 4,150  
Non-cash assets as acquisition consideration
  $ 2,899        
13.     Recent accounting pronouncements:
      In November 2004, the FASB issued SFAS No. 151, “Inventory Costs.” SFAS No. 151 amends the guidance in Accounting Research Bulletin No. 43, Chapter 4, “Inventory Pricing,” to clarify the accounting for abnormal amounts of idle facility expense, freight, handling costs and wasted material (spoilage), and generally requires that these amounts be expensed in the period the cost arises, rather than being included in the cost of inventory, thereby requiring that the allocation of fixed production overheads to the costs of conversion be based on normal capacity of the production facilities. SFAS No. 151 becomes effective for inventory costs incurred during fiscal years beginning after June 15, 2005, but earlier application is permitted. The Company is currently evaluating the impact of SFAS No. 151 on our financial statements, but the Company does not expect that it will have a material impact on its financial position, results of operations or cash flows.
      In December 2004, the FASB issued SFAS No. 153, “Exchanges of Nonmonetary Assets.” SFAS No. 153 amends current guidance related to the exchange on nonmonetary assets as per APB Opinion No. 29, “Accounting for Nonmonetary Transactions,” to eliminate an exception that allowed exchange of similar nonmonetary assets without determination of the fair value of those assets, and replaced this provision with a general exception for exchanges of nonmonetary assets that do not have commercial substance. A nonmonetary exchange has commercial substance if the future cash flows of the entity are expected to change significantly as a result of the exchange. SFAS No. 153 becomes effective for nonmonetary asset exchanges occurring in fiscal periods beginning after June 15, 2005. The Company does not anticipate that the adoption of this policy will have a material impact on our financial position, results of operations or cash flows.
      In December 2004, the FASB issued SFAS No. 123R, “Share-Based Payment,” which revises SFAS No. 123 and supercedes APB No. 25. SFAS No. 123R will require the Company to measure the cost of employee services received in exchange for an award of equity instruments based on the grant-date fair value of the award, with limited exceptions. The fair value of the award will be remeasured at each

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COMPLETE PRODUCTION SERVICES, INC.
Notes to Consolidated Financial Statements — (Continued)
Nine Months Ended September 30, 2005 and 2004 (unaudited)
(In thousands, except as noted and per share data)
reporting date through the settlement date, with changes in fair value recognized as compensation expense of the period. Entities should continue to use an option-pricing model, adjusted for the unique characteristics of those instruments, to determine fair value as of the grant date of the stock options. SFAS No. 123R was to become effective as of the beginning of the first interim or annual reporting period that begins after June 15, 2005. However, the SEC issued an extension which allows public companies to defer adoption of SFAS No. 123R until the beginning of their fiscal year that begins after June 15, 2005. The Company has not yet adopted SFAS No. 123R and is currently evaluating the impact that this policy will have on its financial position, results of operations and cash flows.
      In May 2005, the FASB issued SFAS No. 154, “Accounting Changes and Error Corrections, a Replacement of APB Opinion No. 20 and FASB Statement No. 3.” SFAS No. 154 requires retrospective application of changes in accounting principle to prior periods’ financial statements, rather than the use of the cumulative effect of a change in accounting principle, unless impracticable. If impracticable to determine the impact on prior periods, then the new accounting principle should be applied to the balances of assets and liabilities as of the beginning of the earliest period for which retrospective application is practicable, with a corresponding adjustment to equity, unless impracticable for all periods presented, in which case prospective treatment should be applied. SFAS No. 154 applies to all voluntary changes in accounting principle, as well as those required by the issuance of new accounting pronouncements if no specific transition guidance is provided. SFAS No. 154 does not change the previously issued guidance for reporting a change in accounting estimate or correction of an error. SFAS No. 154 becomes effective for accounting changes and corrections of errors made in fiscal years beginning after December 15, 2005. The Company does not expect this policy to have a material impact on its financial position, results of operations or cash flows.
14.     Subsequent events:
      On November 1, 2005, Complete acquired the all the outstanding equity interests of the Big Mac group of companies (Big Mac Transports, LLC, Big Mac Tank Trucks, LLC and Fugo Services, LLC) for $40,800 in cash. The Big Mac group of companies (“Big Mac”) is based in McAlester, Oklahoma, and provides fluid handling services primarily to customers in eastern Oklahoma and western Arkansas. The purchase price, which is subject to a post-closing adjustment for actual working capital and reimbursable capital expenditures as of the closing date, has not yet been finalized. The Company will include the operating results of Big Mac in the completion and production services business segment from the date of acquisition. Complete believes that this acquisition provides a platform to enter the eastern Oklahoma market and new Fayetteville Shale play in Arkansas.

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
The Board of Directors
Complete Production Services, Inc.:
      We have audited the accompanying consolidated balance sheet of Complete Production Services, Inc. and subsidiaries as of December 31, 2004, and the related consolidated statements of operations, comprehensive income, stockholders’ equity and cash flows for the year then ended. These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated financial statements based on our audit. We did not audit the consolidated financial statements of Integrated Production Services, Inc., which financial statements reflect total assets constituting 35 percent as of December 31, 2004 and total revenues constituting 38 percent for the year ended December 31, 2004 of the related consolidated totals. Those consolidated financial statements were audited by other auditors whose report has been furnished to us, and our opinion, insofar as it relates to the amounts included for Integrated Production Services, Inc., is based solely on the accompanying report of the other auditors.
      We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audit and the report of other auditors provide a reasonable basis for our opinion.
      In our opinion, based on our audit and the report of other auditors, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Complete Production Services, Inc. and subsidiaries as of December 31, 2004, and the results of their operations and their cash flows for the year then ended, in conformity with accounting principles generally accepted in the United States of America.
/s/ Grant Thornton LLP
Houston, Texas
September 30, 2005

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
The Board of Directors
Complete Energy Services, Inc.:
      We have audited the accompanying consolidated balance sheet of Complete Energy Services, Inc. and subsidiaries as of December 31, 2003, and the related consolidated statements of earnings, shareholder’s equity and cash flows for the period from inception (November 7, 2003) through December 31, 2003 (not presented separately herein). These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated financial statements based on our audit.
      We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall consolidated financial statement presentation. We believe that our audit provide a reasonable basis for our opinion.
      In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Complete Energy Services, Inc. and subsidiaries as of December 31, 2003, and the consolidated results of their operations and their consolidated cash flows for the period from inception (November 7, 2003) through December 31, 2003, in conformity with accounting principles generally accepted in the United States of America.
/s/ Grant Thornton LLP
Houston, Texas
September 28, 2005

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
The Board of Directors
Complete Production Services, Inc.:
      We have audited the accompanying consolidated balance sheet of Complete Production Services, Inc. and subsidiaries as of December 31, 2003, and the related consolidated statements of operations (loss), comprehensive income, stockholders’ equity and cash flows for each of the years in the two-year period ended December 31, 2003. These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits. We did not audit the consolidated financial statements of Complete Energy Services, Inc., which financial statements reflect total assets constituting 35 percent as of December 31, 2003 and total revenues constituting 10 percent for the period from its formation on November 7, 2003 to December 31, 2003 of the related consolidated totals. Those consolidated financial statements were audited by other auditors whose report has been furnished to us, and our opinion, insofar as it relates to the amounts included for Complete Energy Services, Inc., is based solely on the accompanying report of the other auditors.
      We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits and the report of other auditors provide a reasonable basis for our opinion.
      In our opinion, based on our audits and the report of other auditors, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Complete Production Services, Inc. and subsidiaries as of December 31, 2003, and the results of their operations and their cash flows for each of the years in the two-year period ended December 31, 2003, in conformity with U.S. generally accepted accounting principles.
/s/ KPMG
Calgary, Canada
September 30, 2005

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
The Board of Directors
Integrated Production Services, Inc.:
      We have audited the consolidated balance sheet of Integrated Production Services, Inc. and subsidiaries as of December 31, 2004, and the related consolidated statements of earnings, comprehensive income, stockholders’ equity and cash flows for the year then ended (not presented separately herein). These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated financial statements based on our audit.
      We conducted our audit in accordance with standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for our opinion.
      In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Integrated Production Services, Inc. and subsidiaries as of December 31, 2004, and the results of their operations and their cash flows for the year then ended in conformity with U.S. generally accepted accounting principles.
/s/ KPMG
Calgary, Canada
April 8, 2005
(except as to note 18, which is as
of August 19, 2005)

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COMPLETE PRODUCTION SERVICES, INC.
Consolidated Balance Sheets
December 31, 2004 and 2003
                     
    2004   2003
         
    (In thousands, except
    share data)
ASSETS
Current assets:
               
 
Cash and cash equivalents
  $ 11,547     $ 6,094  
 
Trade accounts receivable, net
    85,801       27,255  
 
Inventory
    21,910       12,294  
 
Prepaid expenses
    5,825       1,820  
 
Deferred tax asset
    870        
             
   
Total current assets
    125,953       47,463  
Property, plant and equipment, net
    235,211       95,217  
Intangible assets, net
    4,073       2,445  
Deferred financing costs, net
    4,467       1,645  
Goodwill
    145,449       59,296  
             
   
Total assets
  $ 515,153     $ 206,066  
             
 
LIABILITIES AND STOCKHOLDERS’ EQUITY
 
Current liabilities:
               
 
Bank operating loans
  $ 21,745     $ 5,929  
 
Current maturities of long-term debt
    28,493       13,699  
 
Convertible debentures
    4,150        
 
Accounts payable
    27,688       12,369  
 
Accrued liabilities
    18,848       8,134  
 
Notes payable
    2,735       57  
 
Taxes payable
    1,081       396  
             
   
Total current liabilities
    104,740       40,584  
Long-term debt
    169,190       50,144  
Convertible debentures
          3,862  
Deferred income taxes
    26,225       4,456  
Minority interest
    5,477       4,813  
             
   
Total liabilities
    305,632       103,859  
Commitments and contingencies
               
Stockholders’ equity:
               
 
Common stock, $0.01 par value per share, 100,000,000 shares authorized, 25,107,341 (2003 - 11,922,260) issued
    251       119  
 
Additional paid-in capital
    177,015       90,770  
 
Retained earnings
    18,690       1,035  
 
Deferred compensation
    (932 )     (180 )
 
Accumulated other comprehensive income
    14,497       10,463  
             
   
Total stockholders’ equity
    209,521       102,207  
             
Total liabilities and stockholders’ equity
  $ 515,153     $ 206,066  
             
See accompanying notes to consolidated financial statements.

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COMPLETE PRODUCTION SERVICES, INC.
Consolidated Statements of Operations (Loss)
Years Ended December 31, 2004, 2003 and 2002
                           
    2004   2003   2002
             
    (In thousands, except per share data)
Revenue:
                       
 
Service
  $ 239,427     $ 67,732     $ 30,110  
 
Product
    81,320       35,547       10,494  
                   
      320,747       103,279       40,604  
Service expenses
    157,540       47,329       21,153  
Product expenses
    58,633       25,795       7,378  
Selling, general and administrative expenses
    46,077       16,591       7,764  
Depreciation and amortization
    21,616       7,648       4,187  
                   
 
Income before interest, taxes and minority interest
    36,881       5,916       122  
Interest expense
    7,471       2,687       1,260  
                   
 
Income (loss) before taxes and minority interest
    29,410       3,229       (1,138 )
Taxes
    10,821       1,506       (477 )
                   
 
Income (loss) before minority interest
    18,589       1,723       (661 )
Minority interest
    934       162       (45 )
                   
 
Net income (loss)
  $ 17,655     $ 1,561     $ (616 )
                   
Earnings (loss) per share:
                       
 
Basic
  $ 0.98     $ 0.22     $ (0.22 )
 
Diluted
  $ 0.97     $ 0.21     $ (0.22 )
Weighted average shares:
                       
 
Basic
    18,002       7,055       2,757  
 
Diluted
    18,270       7,272       2,757  
Consolidated Statements of Comprehensive Income (Loss)
Years Ended December 31, 2004, 2003 and 2002
                           
    2004   2003   2002
             
    (In thousands)
Net income (loss)
  $ 17,655     $ 1,561     $ (616 )
Change in cumulative translation adjustment
    4,034       10,143       320  
                   
 
Comprehensive income (loss)
  $ 21,689     $ 11,704     $ (296 )
                   
See accompanying notes to consolidated financial statements.

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COMPLETE PRODUCTION SERVICES, INC.
Consolidated Statements of Stockholders’ Equity
Years Ended December 31, 2004, 2003 and 2002
                                                                   
                        Accumulated        
            Additional           Other        
    No. of   Dollar   Paid-In   Retained   Deferred   Comprehensive   Partners’    
    Shares   Amounts   Capital   Earnings   Compensation   Income   Equity   Total
                                 
    (In thousands, except share amounts)
Balance at December 31, 2001
    1,445,000     $ 1     $ 9,962     $ 90     $     $     $ 20,000     $ 30,053  
Net loss
                      (616 )                       (616 )
Cumulative translation adjustment
                                  320             320  
Issuance of common stock:
                                                               
 
Acquisition of IPSL
    4,694,010       60       50,993                         (20,000 )     31,053  
                                                 
Balance at December 31, 2002
    6,139,010       61       60,955       (526 )           320             60,810  
Net income
                      1,561                         1,561  
Cumulative translation adjustment
                                  10,143             10,143  
Issuance of common stock:
                                                               
 
Acquisitions
    5,703,497       57       29,281                               29,338  
 
Exercise of options
    28,095             320                               320  
 
For cash
    6,433             73                               73  
Issuance of restricted stock
    59,112       1       299             (300 )                  
Amortization of deferred compensation
                            120                   120  
Repurchase of common stock
    (13,887 )           (158 )                             (158 )
                                                 
Balance at December 31, 2003
    11,922,260       119       90,770       1,035       (180 )     10,463             102,207  
Net income
                      17,655                         17,655  
Cumulative translation adjustment
                                  4,034             4,034  
Issuance of common stock:
                                                               
 
Acquisitions
    12,616,207       126       81,204                               81,330  
 
Exercise of options
    40,590             185                               185  
 
For cash
    328,284       4       1,756                               1,760  
 
Exercise of warrants
    200,000       2       2,123                               2,125  
Issuance of restricted stock
                977             (977 )                  
Amortization of deferred compensation
                            225                   225  
                                                 
Balance at December 31, 2004
    25,107,341     $ 251     $ 177,015     $ 18,690     $ (932 )   $ 14,497     $     $ 209,521  
                                                 
See accompanying notes to consolidated financial statements.

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COMPLETE PRODUCTION SERVICES, INC.
Consolidated Statements of Cash Flows
Years Ended December 31, 2004, 2003 and 2002
                             
    2004   2003   2002
             
    (In thousands)
Cash provided by (used in):
                       
Operating activities:
                       
 
Net income (loss)
  $ 17,655     $ 1,561     $ (616 )
 
Items not affecting cash:
                       
   
Depreciation and amortization
    21,616       7,648       4,187  
   
Deferred income taxes (benefit)
    9,267       728       (599 )
   
Minority interest
    934       162       (45 )
   
Other
    (44 )     125        
 
Net change in working capital
    (14,806 )     3,741       (2,935 )
                   
      34,622       13,965       (8 )
Financing activities:
                       
 
Issuances of long-term debt
    121,639       35,878       31,534  
 
Repayments of long-term debt
    (9,859 )     (7,275 )     (24,250 )
 
Net borrowings (repayments) under lines of credit
    32,500       6,429       (2,786 )
 
Proceeds from issuances of common stock
    16,611       21,075       32,015  
 
Issuances (repayments) of notes payable
    376       (18 )      
 
Deferred financing costs
    (3,637 )     (808 )     (234 )
                   
      157,630       55,281       36,279  
Investing activities:
                       
 
Business acquisitions, net of cash acquired
    (139,362 )     (54,798 )     (27,851 )
 
Additions to property, plant and equipment
    (46,904 )     (11,084 )     (6,799 )
 
Proceeds on disposal of other assets
    489       652       (825 )
 
Additions to intangible assets
    (999 )     (984 )     (141 )
                   
      (186,776 )     (66,214 )     (35,616 )
Effect of exchange rate changes on cash
    (23 )     (58 )      
                   
Change in cash and cash equivalents
    5,453       2,974       655  
Cash and cash equivalents, beginning of year
    6,094       3,120       2,465  
                   
Cash and cash equivalents, end of year
  $ 11,547     $ 6,094     $ 3,120  
                   
See accompanying notes to consolidated financial statements.

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COMPLETE PRODUCTION SERVICES, INC.
Notes to Consolidated Financial Statements
Years Ended December 31, 2004, 2003 and 2002
(In thousands, except as noted and per share data)
1.     Significant accounting policies:
      Complete Production Services, Inc. (“Complete” or the “Company”) is a provider of specialized services and products focused on developing hydrocarbon reserves, reducing operating costs and enhancing production for oil and gas companies. The Company focuses on basins within North America and delivers targeted services and products required by its customers within each specific basin. The Company manages its operations from regional field service facilities located throughout the U.S. Rocky Mountain region, Texas, Oklahoma, Louisiana, western Canada and Mexico. The Company also has offices in Southeast Asia from which it delivers products to international oil and gas customers. Complete’s business depends, to a large degree, on the level of spending by oil and gas companies for exploration, development and production activities. Therefore, a sustained increase or decrease in the price of natural gas or oil, which could have a material impact on exploration, development and production activities, also could materially affect our financial position, results of operations and cash flows.
      On September 12, 2005, the Company completed the combination (“Combination”) of Complete Energy Services, Inc. (“CES”), Integrated Production Services, Inc. (“IPS”) and I.E. Miller Services, Inc. (“IEM”) pursuant to which the CES and IEM shareholders exchanged all of their common stock for common stock of IPS. CES shareholders received 19.704 shares of IPS for each share of CES, and IEM shareholders received 19.410 shares of IPS for each share of IEM. Subsequent to the combination, IPS changed its name to Complete Production Services, Inc. The former CES shareholders owned 57.6% of Complete common shares, IPS shareholders owned 33.2% and the former IEM shareholders owned 9.2%.
      The consolidated financial statements include the activities of CES, IPS and IEM for the respective periods and have been prepared using the continuity of interests accounting method, which yields results similar to the pooling of interests method, under which the Company combined entities which were under common control and majority ownership of SCF-IV, L.P. (“SCF”), a private equity fund that focuses on investments in the energy services segment of the energy industry. Under this method of accounting, the historical financial statements of CES, IPS and IEM were combined for the years ended December 31, 2004, 2003 and 2002, in each case from the date each became controlled by SCF (IPS – May 22, 2001, CES – November 7, 2003, and IEM – August 26, 2004). The accounting policies adopted by the Company were the same policies that the predecessor companies employed. Upon the completion of the Combination, the shareholders of CES held a majority ownership position in the equity of Complete, retained senior officer positions and former CES directors represent a majority of the directors of Complete. Accordingly, CES will be treated as the accounting acquirer of the minority interest ownership as a result of the Combination. The minority interest ownership in net income for each year is calculated based upon the percentage of equity ownership not held by SCF in each of IPS and IEM. The consolidated financial statements have been adjusted to reflect minority interest ownership in Complete.
      The consolidated financial statements of the Company are expressed in U.S. dollars and have been prepared by management in accordance with accounting principles generally accepted in the United States. The preparation of financial statements in conformity with accounting principles generally accepted in the United States (“GAAP”) requires management to make estimates and assumptions that affect amounts reported in the financial statements and accompanying notes. Actual results could differ from those estimates. The financial statements have, in management’s opinion, been properly prepared using careful judgment with reasonable limits of materiality and within the framework of the significant accounting policies summarized below.

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COMPLETE PRODUCTION SERVICES, INC.
Notes to Consolidated Financial Statements — (Continued)
Years Ended December 31, 2004, 2003 and 2002
(In thousands, except as noted and per share data)
Complete Energy Services, Inc.
      CES, a Delaware corporation, was formed on November 7, 2003. CES is an integrated wellsite services provider with operations in north and east Texas as well as in the Mid-Continent and the Rocky Mountain regions of the United States. CES provides a wide range of services to the oil and gas exploration industry, including contract drilling, well servicing, fluid handling, wellsite rentals, materials and supplies and other support services.
      These consolidated financial statements include the operations of CES from the date of its incorporation on November 7, 2003.
Integrated Production Services, Inc. (formerly Saber Energy Services, Inc. (“Saber”))
      IPS, a Delaware corporation, was formerly named Saber Energy Services, Inc. On September 18, 2002, an amendment to the certificate of incorporation for Saber was filed with the State of Delaware to change the name of the company from Saber to IPS. Saber was incorporated on May 22, 2001 at which date SCF was its controlling shareholder. As described in note 2(f) Saber entered into a combination agreement with Integrated Production Services Ltd. (“IPSL”) on September 20, 2002. SCF held an equity interest in IPSL from October 16, 2000 and became the controlling shareholder of IPSL on July 3, 2002. IPS provides a wide range of services and products to the oil and gas industry designed to reduce customers’ operating costs and increase production from customers’ hydrocarbon reserves. Services provided include coiled tubing, wireline, production testing and production optimization. Operations are located in western Canada, Texas, Louisiana and Southeast Asia.
      These consolidated financial statements include the operations of Saber from the date of its incorporation on May 22, 2001 and the operations of Integrated Productions Services Ltd. (“IPSL”) from the date of an initial investment by SCF-IV, L.P. (“SCF”) on October 16, 2000, following the continuity of interest method of accounting based on common ownership by SCF. Details of the business combinations are outlined in note 2.
I.E. Miller Services, Inc.
      IEM, a Delaware corporation, was formed on August 26, 2004 to acquire certain businesses that perform land rig moving services in Louisiana and Texas and vacuum truck services in south Louisiana.
      These consolidated financial statements include the operations of IEM from the date of its incorporation on August 26, 2004.
(a) Basis of preparation:
      The consolidated financial statements include the accounts of the legal entities discussed above and their wholly owned subsidiaries. All material inter-company balances and transactions have been eliminated.
(b) Foreign currency translation:
      Assets and liabilities of foreign subsidiaries, whose functional currencies are the local currency, are translated from their respective functional currencies to U.S. dollars at the balance sheet date exchange rates. Income and expense items are translated at the average rates of exchange prevailing during the year. Foreign exchange gains and losses resulting from translation of account balances are included in income or

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COMPLETE PRODUCTION SERVICES, INC.
Notes to Consolidated Financial Statements — (Continued)
Years Ended December 31, 2004, 2003 and 2002
(In thousands, except as noted and per share data)
loss in the year in which they occur. The adjustment resulting from translating the financial statements of such foreign subsidiaries into U.S. dollars is reflected as a separate component of stockholders’ equity.
(c) Revenue recognition:
      The Company recognizes service revenue when it is realized and earned. The Company considers revenue to be realized and earned when the services have been provided to the customer, the product has been delivered, the sales price has been fixed or determinable and collectibility is reasonably assured. Generally services are provided over a relatively short time.
      Revenue and costs on drilling contracts are recognized as work progresses. Progress is measured and revenues recognized based upon agreed day-rate charges. For certain contracts, the Company receives additional lump-sum payments for the mobilization of rigs and other drilling equipment. Consistent with the drilling contract day-rate revenues and charges, revenues and related direct costs incurred for the mobilization are deferred and recognized over the term of the related drilling contract. Costs incurred to relocate rigs and other drilling equipment to areas in which a contract has not been secured are expensed as incurred.
      We recognize revenue under service contracts as services are performed. The Company had no unearned revenues associated with long-term service contracts as of December 31, 2004.
(d) Cash and cash equivalents:
      Short-term investments with maturities less than three months are considered to be cash equivalents and are recorded at cost, which approximates fair market value. For the purposes of the consolidated statements of cash flows, the Company considers all investments in highly liquid debt instruments with original maturities of three months or less to be cash equivalents.
(e) Trade accounts receivable:
      Trade accounts receivable are recorded at the invoiced amount and do not bear interest. The allowance for doubtful accounts is the Company’s best estimate of the amount of probable credit losses in the Company’s existing accounts receivable. The Company determines the allowance based on historical write-off experience, account aging and management’s assumptions about the oil and gas industry economic cycle. The Company reviews its allowance for doubtful accounts monthly. Past due balances over 90 days and over a specified amount are reviewed individually for collectibility. All other balances are reviewed on a pooled basis. Account balances are charged off against the allowance after all appropriate means of collection have been exhausted and the potential for recovery is considered remote. Based on its customer base, the Company does not believe that it has any significant concentrations of credit risk other than its concentration in the oil and gas industry. The Company does not have any off balance-sheet credit exposure related to its customers.
(f) Inventory:
      Inventory consisting of finished goods and materials and supplies held for resale is carried at the lower of cost and market. Market is defined as net realizable value for finished goods and as a replacement cost for manufacturing parts and materials. Cost is determined on a first-in first-out basis for refurbished parts and an average cost basis for all other inventories and includes the cost of raw materials and labor for finished goods.

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COMPLETE PRODUCTION SERVICES, INC.
Notes to Consolidated Financial Statements — (Continued)
Years Ended December 31, 2004, 2003 and 2002
(In thousands, except as noted and per share data)
(g) Property, plant and equipment:
      Property, plant and equipment are carried at cost less accumulated depreciation. Major betterments are capitalized. Repairs and maintenance that do not extend the useful life of equipment are expensed.
      Depreciation is provided over the estimated useful life of each asset as follows:
           
Asset   Basis   Rate
         
Buildings
  straight-line   39 years
Field Equipment
       
 
Wireline, optimization and coiled tubing equipment
  straight-line   10 years
 
Gas testing equipment
  straight-line   15 years
 
Drilling rigs
  straight-line   20 years
 
Well-servicing rigs
  straight-line   25 years
Office furniture and computers
  declining balance   30%
Leasehold improvements
  straight-line   5 years
Vehicles and other equipment
  straight-line   3 to 10 years
(h) Intangible assets:
      Intangible assets, consisting of acquired customer relationships, service marks, non-compete agreements, acquired patents and technology, are carried at cost less accumulated amortization, which is calculated on a straight-line basis over a period of 3 to 10 years depending on the asset’s estimated useful life. The weighted average amortization period was 5 years as of December 31, 2004.
(i) Impairment of long-lived assets:
      In accordance with SFAS 144, long-lived assets, such as property, plant and equipment, and purchased intangibles subject to amortization, are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. Recoverability of assets to be held and used is measured by a comparison of the carrying amount of an asset to estimated undiscounted future cash flows expected to be generated by the asset. If the carrying amount of an asset exceeds its estimated future cash flows, an impairment charge is recognized in the amount by which the carrying amount of the asset exceeds the fair value of the asset. Assets to be disposed of would be separately presented in the balance sheet and reported at the lower of the carrying amount or fair value less costs to sell, and are no longer depreciated.
      The assets and liabilities of a disposal group classified as held for sale would be presented separately in the appropriate asset and liability sections of the balance sheet.
(j) Asset retirement obligations:
      In June 2001, SFAS 143, Accounting for Asset Retirement Obligations, was issued. SFAS 143 requires the Company to record the fair value of an asset retirement obligation as a liability in the period in which it incurs a legal obligation associated with the retirement of tangible long-lived assets that result from the acquisition, construction, development, and/or normal use of the assets. The Company also would record a corresponding asset that is depreciated over the life of the asset. Subsequent to the initial measurement of the asset retirement obligation, the obligation would be adjusted at the end of each period to reflect the passage of time and changes in the estimated future cash flows underlying the obligation.

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COMPLETE PRODUCTION SERVICES, INC.
Notes to Consolidated Financial Statements — (Continued)
Years Ended December 31, 2004, 2003 and 2002
(In thousands, except as noted and per share data)
The Company was required to adopt SFAS 143 on January 1, 2003. The adoption of SFAS 143 did not affect the Company’s financial statements.
(k) Deferred financing costs:
      Deferred financing costs associated with long-term debt are carried at cost and are expensed over the term of the relevant long-term debt.
(l) Goodwill:
      Goodwill represents the excess of costs over fair value of assets of businesses acquired. Goodwill acquired in a business combination is not amortized, but instead tested for impairment at least annually in the fourth quarter. Under this goodwill impairment test, if the fair value of a reporting unit does not exceed its carrying value, the excess of fair value of a reporting unit over the fair value of its net assets is considered to be the implied fair value of goodwill. If the carrying value of goodwill exceeds its implied fair value, the difference is recognized as an impairment loss.
(m) Deferred income taxes:
      The Company follows the liability method of accounting for income taxes. Under this method, deferred income tax assets and liabilities are determined based upon temporary differences between the carrying amount and tax basis of the Company’s assets and liabilities and measured using enacted tax rates and laws that will be in effect when the differences are expected to reverse. The effect on deferred tax assets and liabilities of a change in the tax rates is recognized in income in the period in which the change occurs. The Company records a valuation reserve in each reporting period when management believes that it is more likely than not that any deferred tax asset created will not be realized.
(n) Financial instruments:
      The financial instruments recognized in the balance sheet consist of cash and cash equivalents, trade accounts receivable, bank operating loans, accounts payable and accrued liabilities, long-term debt and convertible debentures. The fair value of all financial instruments approximates their carrying amounts due to their current maturities or market rates of interest.
(o) Per share amounts:
      The treasury stock method of calculating diluted per share amounts is utilized. This method assumes that any proceeds from the exercise of options and other dilutive instruments where the fair value exceeds the exercise price would be used to purchase common stock at the average fair value during the period.
(p) Stock-based compensation:
      The Company has stock-based compensation plans for its employees, officers and directors to acquire common stock. Options are issued with an exercise price equal to fair value of the stock on the date of grant; consequently, under Accounting Principles Board Opinion No. 25, Accounting for Stock Issued to Employees, no compensation expense is recorded. Consideration paid on the exercise of stock options is credited to share capital and additional paid-in capital. Pro forma information required by Statement of Financial Accounting Standard (“SFAS”) No. 123, Accounting for Stock-Based Compensation, is noted below. Restricted shares are awarded at a price equal to fair value and the related compensation expense is charged to income over the vesting period of the restricted stock.

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COMPLETE PRODUCTION SERVICES, INC.
Notes to Consolidated Financial Statements — (Continued)
Years Ended December 31, 2004, 2003 and 2002
(In thousands, except as noted and per share data)
      The Company applied the minimum value method prescribed in APB No. 25 in accounting for its stock-based compensation plans. If compensation cost for the Company’s stock-based compensation plans had been determined using the fair value approach set forth in SFAS No. 123, the Company’s results of operations for the years ended December 31, 2004, 2003 and 2002 would approximate the pro forma amounts below:
                           
    2004   2003   2002
             
Net income (loss):
                       
 
As reported
  $ 17,655     $ 1,561     $ (616 )
 
Impact of stock-based compensation expense determined under fair value method, net of tax
    (298 )     (202 )     (96 )
                   
 
Pro forma net income (loss)
  $ 17,357     $ 1,359     $ (712 )
                   
Basic earnings (loss) per share:
                       
 
As reported
  $ 0.98     $ 0.22     $ (0.22 )
 
Pro forma
  $ 0.96     $ 0.19     $ (0.26 )
Diluted earnings (loss) per share:
                       
 
As reported
  $ 0.97     $ 0.21     $ (0.22 )
 
Pro forma
  $ 0.95     $ 0.19     $ (0.26 )
      The fair value of each stock option award on the grant date was estimated using the minimum value option pricing model with the following fair values and assumptions:
                           
    2004   2003   2002
             
Weighted average fair value
  $ 1.52     $ 1.84     $ 1.74  
Assumptions:
                       
 
Risk free interest rate
    4.9 %     6 %     6 %
 
Dividend yield
                 
 
Expected life (in years)
    3.0       3.0       3.0  
(q) Research and development:
      Research and development costs are charged to income as period costs when incurred.
(r) Contingencies:
      Liabilities for loss contingencies, including environmental remediation costs not within the scope of SFAS No. 143 arising from claims, assessments, litigation, fines, and penalties and other sources, are recorded when it is probable that a liability has been incurred and the amount of the assessment and/or remediation can be reasonably estimated.
(s) Measurement uncertainty:
      The Company’s consolidated financial statements are prepared in accordance with U.S. GAAP. The preparation of the consolidated financial statements in accordance with U.S. GAAP necessarily requires the Company to make estimates and judgments that affect the reported amounts of assets, liabilities, revenues and expenses, and related disclosure of contingent assets and liabilities. The Company evaluates its estimates including those related to bad debts, inventory obsolescence, property plant and equipment

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COMPLETE PRODUCTION SERVICES, INC.
Notes to Consolidated Financial Statements — (Continued)
Years Ended December 31, 2004, 2003 and 2002
(In thousands, except as noted and per share data)
useful lives, goodwill, intangible assets, income taxes, contingencies and litigation on an ongoing basis. The Company bases its estimates on historical experience and on various other assumptions that are believed at the time to be reasonable under the circumstances. Under different assumptions or conditions, the actual results could differ, possibly materially, from those previously estimated. Many of the conditions impacting these assumptions are estimates outside of the Company’s control.
(t) Comparative figures:
      Certain prior year figures have been reclassified to conform to the current year’s presentation.
2. Business combinations:
(a) IPS 2004 Acquisitions:
      During 2004, the Company acquired all of the interests of the following entities in transactions accounted for as a purchase. The businesses acquired included Double Jack Testing and Services, Inc. (“Double Jack”), Nortex Perforating Group, Inc. (“Nortex”), and MGM Well Service, Inc. (“MGM”).
      The following table summarizes the purchase price allocation in millions of dollars:
                                   
    Double Jack   Nortex   MGM   Total
                 
Non-cash working capital
  $ 0.8     $     $ 2.6     $ 3.4  
Property, plant and equipment
    2.5       0.8       0.9       4.2  
Goodwill
    7.5       1.0       5.2       13.7  
Deferred income taxes
    (0.6 )           (0.8 )     (1.4 )
                         
Net assets acquired
  $ 10.2     $ 1.8     $ 7.9     $ 19.9  
                         
Consideration:
                               
 
Cash
  $ 8.0     $ 1.8     $ 6.7     $ 16.5  
 
Issuance of common stock
    1.9             1.2       3.1  
 
Cash contingent consideration
    0.3                   0.3  
                         
Total consideration
  $ 10.2     $ 1.8     $ 7.9     $ 19.9  
                         
      There were 266,727 common shares issued as consideration on these acquisitions. The share price of $11.39 per share was determined based on an internal valuation using a market multiple methodology and approved by the Company’s Board of Directors. These acquisitions provide platforms for the provision of the Company’s services in the Barnett Shale and Rocky Mountain regions. In addition, MGM operates an optimization and swabbing business in Texas, and through distributors in Wyoming and Canada, provides the Company with expertise, personnel, and a platform to expand its optimization business in North America. The results of operations are included in the accounts from the date of acquisition. The purchase agreement for Double Jack provides for up to $1,200 of contingent consideration over the period from the date of acquisition to December 31, 2005 based on operating results of the acquired business. Contingent consideration will be accounted for as an adjustment to the purchase price in the period earned. At December 31, 2004, $300 of the contingent consideration was earned. The purchase agreement for MGM provides for contingent consideration of up to $3,430 of cash and 107,066 common shares over the period from the date of acquisition to December 31, 2006 based on certain operating results of the acquired MGM business. Contingent consideration will be accounted for as an adjustment to the purchase price in

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COMPLETE PRODUCTION SERVICES, INC.
Notes to Consolidated Financial Statements — (Continued)
Years Ended December 31, 2004, 2003 and 2002
(In thousands, except as noted and per share data)
the period earned. The goodwill for these acquisitions was allocated entirely to the completion and production services segment. Of the total goodwill recorded of $13,700, $12,700 is without tax basis.
(b) CES 2004 Acquisitions:
      During 2004, the Company acquired all of the interests (except as noted) of the following entities in a combination accounted for as a purchase. The businesses acquired included LEED Energy Services (“LEED”), Salmon Drilling (“Salmon”), A&W Water Service (“A&W”), Monument Well Service and R&W Rentals (“MWS”), Hyland Enterprises (“Hyland”), Hamm Co. Companies (Hamm Management Co., Hamm and Phillips Service Co., Stride Well Service Company, Inc., Rigmovers, Co., Guard Drilling Mud Disposal, Inc., and Oil Tool Rentals, Co.) (collectively, “Hamm”), and the remaining 50% interest in Price Pipeline (“Price”).
      The following table summarizes the purchase price allocation associated with these transactions in millions of dollars:
                                                                   
    LEED   Salmon   A&W   MWS   Hyland   Hamm   Price   Total
                                 
Current assets
  $ 6.9     $ 0.5     $ 1.4     $ 0.8     $ 7.1     $ 7.4     $ 0.4     $ 24.5  
Property, plant and equipment
    14.4       3.6       5.5       7.0       21.9       48.7       0.7       101.8  
Other assets
    0.6       0.2       0.5       0.3       0.4       0.1       0.3       2.4  
Intangible assets
    0.3             0.2       0.3       0.3       0.4             1.5  
Goodwill
    5.5       0.4       8.8       5.7       5.5       33.8       1.2       60.9  
Liabilities
    (6.8 )           (1.4 )     (0.4 )     (9.7 )     (2.5 )     (1.2 )     (22.0 )
                                                 
Net assets acquired
  $ 20.9     $ 4.7     $ 15.0     $ 13.7     $ 25.5     $ 87.9     $ 1.4     $ 169.1  
                                                 
Consideration:
                                                               
 
Cash and seller notes
  $ 14.4     $ 4.0     $ 6.6     $ 6.6     $ 17.7     $ 48.1     $ 0.2     $ 97.6  
 
Issuance of common stock
    5.9       0.5       7.9       6.6       6.6       37.0       1.2       65.7  
 
Acquisition costs
    0.6       0.2       0.5       0.5       1.2       2.8             5.8  
                                                 
Total consideration
  $ 20.9     $ 4.7     $ 15.0     $ 13.7     $ 25.5     $ 87.9     $ 1.4     $ 169.1  
                                                 
      There were 9,923,232 common shares issued as consideration in connection with these acquisitions. The share price of $5.08 or $12.18 per share was determined based on an internal valuation using a market multiple methodology and approved by the Company’s board of directors. These acquisitions provide the Company with a presence in the completion and production services and drilling services segments to the oil and gas industry in the Mid-Continent and Rocky Mountain and Barnett Shale regions. The results of operations have been included in the accounts of Complete from the dates of the respective acquisitions. Goodwill associated with these acquisitions was allocated as follows: $1,549 to the drilling services segment and $59,386 to the completion and production services segment. Intangible assets are comprised of customer relationships, service marks and non-compete agreements and are being amortized over a 3 to 5 year period.
(c) I.E. Miller 2004 Acquisitions:
      On August 31, 2004, the Company acquired all of the stock of I.E. Miller of Eunice (Texas) No. 2, L.L.C., I.E. Miller – Fowler Trucking (Texas) No. 2, L.L.C. and I.E. Miller – Heldt Brothers Trucking (Texas) No. 2, L.L.C. in a combination accounted for as a purchase. The results of operations were

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COMPLETE PRODUCTION SERVICES, INC.
Notes to Consolidated Financial Statements — (Continued)
Years Ended December 31, 2004, 2003 and 2002
(In thousands, except as noted and per share data)
included in the accounts of Complete from the date of acquisition. Goodwill associated with these acquisitions was entirely allocated to the drilling services segment. The price per common share of $5.15 was a negotiated price with the seller.
      The following table summarizes the purchase price allocation:
           
Net assets acquired:
       
 
Current assets
  $ 8,641  
 
Property, plant and equipment
    12,250  
 
Goodwill (no tax basis)
    8,543  
 
Current liabilities
    (3,361 )
       
Net assets acquired
  $ 26,073  
       
Consideration:
       
 
Cash
  $ 13,573  
 
Issuance of common stock (2,426,250 common shares)
    12,500  
       
Total Consideration
  $ 26,073  
       
(d) CES 2003 Acquisitions:
      On November 7, 2003, the Company acquired all of the interests (except as noted) of BSI in a combination accounted for as a purchase. BSI include Basin Tool, Bell Supply I, LP, Felderhoff Drilling, Mercer Well Service, Price Pipeline (50% interest acquired), Shale Tank Truck, L.P., Tejas Oilfield Services, LLC, and Western Bentonite. BSI provided the Company with a platform business in the Barnett Shale region of north Texas. The results of operations of these acquired companies have been included in the accounts of Complete from the date of acquisition. Goodwill associated with these acquisitions was allocated $9,471 to the completion and production services segment and $4,940 to the drilling services segment. The price for common stock, of $5.08 per share, issued pursuant to the transaction was based on a negotiated price with the seller. Intangible assets acquired were comprised of customer relationships, service marks and non-compete agreements and are being amortized over a 3 to 5 year period.
      The following table summarizes the purchase price allocation:
           
Current assets
  $ 12,226  
Property, plant and equipment
    36,160  
Intangible assets
    1,048  
Goodwill
    14,411  
Current liabilities
    (5,252 )
       
Net assets acquired
  $ 58,593  
       
Consideration:
       
 
Cash
  $ 50,093  
 
Issuance of common stock (1,688,948 common shares)
    8,500  
       
Total consideration
  $ 58,593  
       

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COMPLETE PRODUCTION SERVICES, INC.
Notes to Consolidated Financial Statements — (Continued)
Years Ended December 31, 2004, 2003 and 2002
(In thousands, except as noted and per share data)
(e) IPS 2003 Acquisitions:
      On April 30, 2003, the Company acquired all of the stock of Ess-Ell Tool Co. Ltd., 852592 Alberta Ltd. and Sentry Oil Tools LLC as well as related holding companies in a business combination accounted for as a purchase. The companies operate a flow control products business in Canada and Texas providing the Company with an expanded line of production enhancement products and geographic platforms from which to expand. The results of operations of these acquired companies have been included in the accounts of Complete from the date of acquisition. Goodwill associated with these acquisitions was entirely allocated to the product sales segment. The price for common stock of $11.39 per share issued pursuant to the transaction was based on the fair value estimated by the financial advisor engaged in connection with the September 20, 2002 combination as described in note 2(f) and updated with an internally-prepared valuation using a market-multiple approach.
      The following table summarizes the purchase price allocation:
           
Net assets acquired:
       
 
Non-cash working capital
  $ 528  
 
Property, plant and equipment
    167  
 
Goodwill (no tax basis)
    4,062  
 
Long-term debt
    (54 )
       
Net assets acquired
  $ 4,703  
       
Consideration:
       
 
Cash, net of cash acquired
  $ 3,863  
 
Issuance of common stock (73,749 common shares)
    840  
       
Total consideration
  $ 4,703  
       
(f) IPS 2002 Combination:
      On September 20, 2002, Saber Energy Services, Inc. (“Saber”) and Integrated Production Services Ltd. (“IPSL”) entered into a combination agreement to form IPS. Each of the predecessor companies was on oil and gas well services company. Pursuant to the combination agreement, all of the issued and outstanding stock of IPSL was acquired in exchange for 4,694,010 common shares of Saber, representing an exchange ratio of 0.1694 Saber common shares for every IPSL common share. In connection with the combination, a financial advisor was engaged and provided an opinion that the combination was fair from a financial point of view to the minority shareholders of IPSL and IPS. Prior to the combination transaction, SCF held a controlling interest in each of IPSL and Saber; accordingly, the transaction was accounted for using the continuity of interests method. On September 18, 2002, Saber changed its name to Integrated Production Services, Inc. The accounting policies adopted by the Company were the same policies that the predecessor companies employed.
(g) IPS 2002 Acquisition:
      On July 3, 2002, SCF completed a step-by-step acquisition of IPSL. SCF initially purchased a 44.8% equity interest in IPSL for cash consideration of $20,000 (C$30,000) on October 16, 2000. On July 2, 2002, SCF, through a subsidiary company (“Acquisition Co.”), acquired the remaining 55.2% of the stock of IPSL, which it did not hold, for a cash consideration of $29,508 (C$44,885), including transaction costs of $1,631 (C$2,589), pursuant to a take over bid. Coincident with the second purchase, SCF transferred

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COMPLETE PRODUCTION SERVICES, INC.
Notes to Consolidated Financial Statements — (Continued)
Years Ended December 31, 2004, 2003 and 2002
(In thousands, except as noted and per share data)
its 44.8% equity to Acquisition Co., at cost, and Acquisition Co. and IPSL were amalgamated. The financial statements record the acquisition of IPSL following the purchase method with the allocation of the aggregate purchase price of $49,508 to assets and liabilities at fair values as outlined below.
      For the period from October 16, 2000 to July 3, 2002, the initial 44.8% investment was recorded following the equity method with no equity earnings (losses). Subsequent to July 2, 2002, the full results of IPSL were included in the financial statements. Goodwill associated with the acquisition was allocated $26,892 to the completion and production services segment and $1,814 to the product sales segment.
      The following table summarizes the purchase price allocation:
           
Net assets acquired:
       
 
Cash and cash equivalents
  $ 2,279  
 
Non-cash working capital
    9,827  
 
Property, plant and equipment
    37,899  
 
Intangible assets (amortized over 5 to 10 years)
    510  
 
Other assets
    693  
 
Goodwill (no tax basis)
    28,706  
 
Bank operating loan
    (4,802 )
 
Long-term debt
    (17,831 )
 
Convertible debentures
    (3,174 )
 
Deferred income taxes
    (4,599 )
       
Net assets acquired
  $ 49,508  
       
Consideration:
       
 
Cash purchase on July 3, 2002
  $ 29,508  
 
Cash purchase on October 16, 2000
    20,000  
       
Total consideration
  $ 49,508  
       

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Table of Contents

COMPLETE PRODUCTION SERVICES, INC.
Notes to Consolidated Financial Statements — (Continued)
Years Ended December 31, 2004, 2003 and 2002
(In thousands, except as noted and per share data)
(h) Goodwill:
      The changes in the carrying amount of goodwill for the three-year period ended December 31, 2004 were as follows:
         
Balance at December 31, 2001
  $ 7,001  
Acquisitions
    28,706  
Foreign currency translation
    (23 )
       
Balance at December 31, 2002
    35,684  
Acquisitions
    18,473  
Tax valuation adjustment
    (1,400 )
Foreign currency translation
    6,539  
       
Balance at December 31, 2003
    59,296  
Acquisitions
    83,183  
Contingency adjustment
    250  
Foreign currency translation
    2,720  
       
Balance at December 31, 2004
  $ 145,449  
       
      The tax valuation adjustment of $1,400 was recorded to properly reflect management’s estimate of the net realizable deferred tax assets associated with acquisitions made prior to December 31, 2003, based upon a review of the tax provision as of that date.
3. Accounts receivable:
                 
    2004   2003
         
Trade
  $ 80,980     $ 27,287  
Unbilled revenue
    4,152       677  
Notes receivable
    183       10  
Other
    1,029       368  
             
      86,344       28,342  
Allowance for doubtful accounts
    543       1,087  
             
    $ 85,801     $ 27,255  
             
4. Inventory:
                 
    2004   2003
         
Finished goods
  $ 18,566     $ 10,813  
Manufacturing parts and materials
    3,344       1,481  
             
    $ 21,910     $ 12,294  
             

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Table of Contents

COMPLETE PRODUCTION SERVICES, INC.
Notes to Consolidated Financial Statements — (Continued)
Years Ended December 31, 2004, 2003 and 2002
(In thousands, except as noted and per share data)
5. Property, plant and equipment:
                         
        Accumulated    
        Depreciation    
        and   Net
December 31, 2004   Cost   Amortization   Book Value
             
Land
  $ 848     $     $ 848  
Building
    6,577       340       6,237  
Field equipment
    238,948       29,314       209,634  
Vehicles
    18,610       2,232       16,378  
Office furniture and computers
    2,254       775       1,479  
Leasehold improvements
    1,556       921       635  
                   
    $ 268,793     $ 33,582     $ 235,211  
                   
                         
December 31, 2003            
             
Land
  $ 138     $     $ 138  
Building
    1,009       226       783  
Field equipment
    102,814       12,575       90,239  
Vehicles
    2,743       106       2,637  
Office furniture and computers
    856       320       536  
Leasehold improvements
    1,548       664       884  
                   
    $ 109,108     $ 13,891     $ 95,217  
                   
6. Intangible assets:
                                                           
    As of December 31, 2004   As of December 31, 2003
         
    Term   Historical   Accumulated   Net Book   Historical   Accumulated   Net Book
Description   (in months)   Cost   Amortization   Value   Cost   Amortization   Value
                             
Patents and trademarks
    60     $ 2,049     $ 461     $ 1,588     $ 2,049     $ 249     $ 1,800  
Contractual agreements and other
    60 to 120       3,031       546       2,485       645             645  
                                           
 
Totals
    60     $ 5,080     $ 1,007     $ 4,073     $ 2,694     $ 249     $ 2,445  
                                           
      The Company recorded amortization expense associated with intangible assets of $740, $212 and $26 for the years ended December 31, 2004, 2003 and 2002, respectively. The Company expects to record amortization expense associated with these intangible assets for the next five years approximating: 2005 - $909; 2006 - $900; 2007 - $626; 2008 - $405; and 2009 - $221.
7. Deferred financing costs:
                         
        Accumulated   Net
December 31, 2004   Cost   Amortization   Book Value
             
Deferred financing costs
  $ 5,763     $ 1,296     $ 4,467  
                   
                         
December 31, 2003            
             
Deferred financing costs
  $ 2,170     $ 525     $ 1,645  
                   

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COMPLETE PRODUCTION SERVICES, INC.
Notes to Consolidated Financial Statements — (Continued)
Years Ended December 31, 2004, 2003 and 2002
(In thousands, except as noted and per share data)
8. Taxes:
      Tax expense (benefit) consisted of:
                           
    2004   2003   2002
             
Domestic:
                       
 
Franchise taxes
  $ 171     $ 172     $  
 
Current income taxes
    218              
 
Deferred income taxes (benefit)
    8,015       (594 )     (405 )
                   
      8,404       (422 )     (405 )
Foreign:
                       
 
Capital taxes
    197       344       (84 )
 
Current income taxes
    968       262       203  
 
Deferred income taxes (benefit)
    1,252       1,322       (191 )
                   
      2,417       1,928       (72 )
                   
Tax expense (benefit)
  $ 10,821     $ 1,506     $ (477 )
                   
      The Company operates in several tax jurisdictions. A reconciliation of the U.S. federal income tax rate of 34% (2003 and 2002–34%) to the Company’s effective income tax rate follows:
                           
    2004   2003   2002
             
Expected provision (benefit) for taxes:
  $ 9,999     $ 1,098     $ (387 )
Increase (decrease) resulting from
                       
 
Foreign tax rate differential
    (396 )     (297 )     156  
 
Foreign capital taxes
    197       344       (84 )
 
State franchise taxes
    631       172       (61 )
 
Non-deductible expenses
    200       122       (78 )
 
Other, net
    190       67       (23 )
                   
Tax expense (benefit)
  $ 10,821     $ 1,506     $ (477 )
                   

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Table of Contents

COMPLETE PRODUCTION SERVICES, INC.
Notes to Consolidated Financial Statements — (Continued)
Years Ended December 31, 2004, 2003 and 2002
(In thousands, except as noted and per share data)
      The net deferred income tax liability was comprised of the tax effect of the following temporary differences:
                   
    2004   2003
         
Deferred income tax assets:
               
 
Net operating loss
  $ 11,062     $ 6,695  
 
Intangible assets
    443       785  
 
Research and development credits
    154       143  
 
Restricted stock compensation costs
    18       41  
 
Investment tax credits
    190       117  
             
      11,867       7,781  
 
Less valuation allowance
    (877 )     (168 )
             
      10,990       7,613  
             
Deferred income tax liabilities:
               
 
Property, plant and equipment
    (33,159 )     (12,058 )
 
Goodwill
    (2,432 )      
 
Other
    (754 )     (11 )
             
      (36,345 )     (12,069 )
             
Net deferred income tax liability
  $ (25,355 )   $ (4,456 )
             
      The net deferred income tax liability consisted of:
                 
    2004   2003
         
Domestic
  $ (18,566 )   $ 604  
Foreign
    (6,789 )     (5,060 )
             
    $ (25,355 )   $ (4,456 )
             
      In assessing the realizability of deferred income tax assets, management considers whether it is more likely than not that some portion or all of the deferred income tax assets will not be realized. The ultimate realization of deferred income tax assets is dependent upon the generation of future taxable income during the periods in which those temporary differences become deductible. In order to fully realize the deferred tax asset, the Company will need to generate future taxable income of approximately $26,000 prior to the expiration of the net operating loss carryforwards in 2024.
      The Company has U.S. loss carryforwards of $26,023 (2003 – $13,945) which expire between 2021 and 2024. The Company also has approximately $3,772 (2003 – $5,160) of foreign non-capital loss carryforwards which expire between 2004 and 2009.
      In 2003, the Company completed a review of the tax basis arising from certain acquisitions which resulted in a reduction to the valuation allowance by $1,400. The reduction in the valuation allowance resulted in a reduction in goodwill attributable to the completion and production services segment.
      No deferred income taxes were provided on approximately $7,300 of undistributed earnings of foreign subsidiaries as of December 31, 2004, as the Company intends to indefinitely reinvest these funds. Upon distribution of these earnings in the form of dividends or otherwise, the Company may be subject to

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Table of Contents

COMPLETE PRODUCTION SERVICES, INC.
Notes to Consolidated Financial Statements — (Continued)
Years Ended December 31, 2004, 2003 and 2002
(In thousands, except as noted and per share data)
U.S. income taxes and foreign withholding taxes. It is not practical, however, to estimate the amount of taxes that may be payable on the eventual distribution of these earnings after consideration of available foreign tax credits.
9. Bank operating loans:
      At December 31, 2004, the Company had Canadian– and U.S. dollar–syndicated revolving operating credit facilities (see note 10(a)) in place. The Canadian operating facility provided up to C$10,000 (2003 – C$16,800). The U.S. operating facility line provided a revolving credit facility up to $10,000 (2003 – $3,000). Interest was on a grid based on certain financial ratios and ranged from prime–to–prime plus 1.25% per annum. At December 31, 2004, Canadian and U.S. prime were 4.25% and 5.25% (2003 – 4.5% and 4.0%), respectively. The facilities were secured by a general security agreement providing a first charge against the Company’s assets. The Canadian and U.S. credit facilities included a commitment fee of 0.25% and 0.375% per annum, respectively, on the average unused portion of the revolving credit facilities.
      The maximum amounts available under these credit facilities were subject to a borrowing base formula based upon trade accounts receivable and inventory. As at December 31, 2004, the maximum available under these combined facilities was limited by the borrowing base formula to $20,536 (2003 – $13,509).
      At December 31, 2004, the Company had drawn $15,745 (2003 – $5,929) on these operating lines and an additional amount of $6,000 outstanding pursuant to an overnight facility in the United States offset by a corresponding $6,000 of cash on deposit in Canada. As at December 31, 2004, $48 (2003 – $122) of letters of credit were outstanding.
10. Long-term debt:
                 
    2004   2003
         
Reducing Canadian term facility(a)
  $ 22,552     $ 22,750  
Reducing U.S. term facility(a)
    17,168       7,275  
Term loan(b)
    120,650       30,600  
Revolving line of credit(b)
    19,850       2,800  
Subordinated seller notes(c)
    3,450        
Term loan(d)
    9,274        
Subordinated note(e)
    4,383        
Capital leases(f)
    356       418  
             
      197,683       63,843  
Less: current maturities
    (28,493 )     (13,699 )
             
    $ 169,190     $ 50,144  
             
 
(a) At December 31, 2004, the Company had a syndicated credit facility which included four separate facilities secured by a common security package. The two operating facilities are described in Note 9. The agreement also included a Canadian reducing term facility (“CTF”) and a U.S. reducing term facility (“UTF”). The CTF had been fully drawn and was repayable in equal quarterly installments of C$1,370 and $175. The UTF had also been fully drawn and was repayable in equal quarterly installments of C$954. The facilities were to mature on June 30, 2007 and bore interest from prime

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Table of Contents

COMPLETE PRODUCTION SERVICES, INC.
Notes to Consolidated Financial Statements — (Continued)
Years Ended December 31, 2004, 2003 and 2002
(In thousands, except as noted and per share data)
plus 0.25% to prime plus 1.50% per annum on a grid based on certain financial ratios. At December 31, 2004, Canadian and U.S. prime were 4.25% and 5.25% (2003 – 4.5% and 4.0%, 2002 – 4.5% and 4.25%), respectively. The Company was in compliance with all of the terms of these facilities at December 31, 2004.
 
Effective February 11, 2005, in conjunction with the acquisition of Parchman Energy Group, Inc. (see Note 20), the Company and a group of banks entered into a new credit facility replacing the current credit facility. The new credit facility was comprised of five separate facilities secured by a common security package including a first charge against the Company’s assets. There are two operating facilities ($20,000 and C$15,000), each of which was to mature on February 10, 2008, which replaced the existing operating facilities. There were two reducing term facilities ($20,000 and C$30,000) which were to mature on February 10, 2010 and which required quarterly payments of $1,000 and C$1,500 respectively. Each of these four facilities bore interest from prime plus 0.25% to prime plus 1.50% per annum on a grid based on certain financial ratios. The fifth term facility was in the amount of $35,000, was to mature on February 10, 2011, required quarterly payments of $88, and bore interest at LIBOR plus 3.5%. Each of the three term facilities were drawn in full on February 11, 2005. The credit facilities required maintenance of certain financial ratios and other covenants.
 
(b) In November 2003, the Company established a secured $30,600 term loan and an $8,000 secured revolving line of credit. During 2004, the Company amended the term loan and revolving line of credit several times to facilitate the acquisitions described in note 2, which resulted in increasing the Company’s total borrowing capacity to $120,650 and $30,000, respectively, and extension of the maturity dates. At December 31, 2004, the Company did not have any remaining borrowing capacity on the term loan and $10,200 of remaining capacity on the revolving line of credit.
 
Substantially all of CES’s real and personal property and a pledge of the ownership interest of present and future subsidiaries secure both the term loan and the revolving line of credit. The term loan and revolving line of credit bore interest at either the lead bank’s prime rate plus a margin of 1.75% to 2.25% or the LIBOR plus a margin of 2.75% to 3.25%, depending on the Company’s leverage ratio, as defined. The interest rate on the term loan in 2004 averaged 5.75% (2003 – 6.25%). The interest rate on the revolving loan in 2004 averaged 6.13% (2003 – 6.25%).
 
There are quarterly principal payments on the term loan in the amount of $4,350 with final maturity on August 31, 2009. The revolving line of credit was due on August 31, 2007. The Company must pay a commitment fee in the amount of 0.50% on the unused revolving line of credit capacity.
 
The Company was required to maintain certain financial ratios and other financial conditions. In addition, the Company was prohibited from making certain investments, advances or loans. The term loan and credit agreements restrict substantial asset sales, capital expenditures and cash dividends. The Company was in compliance with all covenants and conditions as of December 31, 2004.
 
(c) The subordinated seller note was unsecured, bore interest at 6.0% and was to mature in March 2009.
 
(d) In August 2004, the Company entered into a Senior Secured Agreement (“the Agreement”) with a group of financial institutions with a maximum commitment of $12,000 and a maturity date of August 31, 2008. Quarterly principal payments of $464 are required under the facility. As part of the Agreement, the Company entered into a Revolving Note Agreement (“Revolver”) providing for borrowings of up to $8,000 with a maturity date of August 31, 2007. At December 31, 2004, there were no outstanding borrowings under the Revolver. Pursuant to the Agreement, interest on the borrowings was calculated using a variable base rate plus a margin. The margin ranges from 0.25% to 1.25% for base rate advances and from 2.50% to 3.50% for LIBOR loans depending on IEM’s leverage ratio. The interest rate averaged approximately 5.18% for the four months ended December 31, 2004. In addition to interest, the banks receive various fees, including a commitment fee. The commitment fee varies from 0.375% to 0.50% of average unused commitment amount on the Revolver, depending on IEM’s leverage ratio. The note was subject to restrictive covenants. The

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COMPLETE PRODUCTION SERVICES, INC.
Notes to Consolidated Financial Statements — (Continued)
Years Ended December 31, 2004, 2003 and 2002
(In thousands, except as noted and per share data)
Company was in compliance with all covenants during 2004. The Agreement was secured by substantially all of IEM’s assets.
 
(e) On August 31, 2004, the Company entered into a Subordinate Credit Agreement with a maximum term commitment of $20,000 and maturity of August 31, 2009. Principal plus accrued interest was to be due at maturity. Pursuant to the credit agreement, interest on borrowings was calculated using a variable base rate equal to the greater of the agent bank’s Prime Rate or the Federal Funds Rate plus 0.5% plus a margin. The margin ranges from 2.0% to 4.0% depending on IEM’s leverage ratio. The interest rate for the four months ended December 31, 2004 was approximately 7.25%. The note was subject to restrictive covenants. The Company was in compliance with all covenants during 2004.
 
(f) At December 31, 2004, the Company’s capital leases are collateralized by specific assets and bear interest at various rates averaging 10.29% (2003 – 7.0%).
 
(g) Concurrent with the completion of the Combination (Note 20(b)), the Company entered into a syndicated senior secured credit facility (the “Credit Facility”) pursuant to which all bank debt held by each of IPS, CES and IEM was repaid and replaced with the proceeds from the Credit Facility. The Credit Facility is comprised of a $420,000 Term B term loan credit facility that will mature in September 2012, a U.S. revolving credit facility of $130,000 that will mature in September 2010, and a $30,000 revolving credit facility that will mature in September 2010. Interest on the Credit Facility is determined by reference to LIBOR plus a margin of 1.25% to 2.75% (dependent on the ratio of total debt to EBITDA, as defined in the Agreement) for revolving advances and a margin of 2.75% for Term B term loan advances. Interest on advances under the Canadian revolving facility is calculated at the Canadian Prime Rate plus a margin of 0.25% to 1.75%. The revolving facility includes a commitment fee ranging from 0.25% to 0.50% (dependent on the ratio of total debt to EBITDA, as defined in the Agreement). Quarterly principal repayments of 0.25% of the original principal amount are required for the Term B term loans commencing December 2005. The Credit Facility contains covenants restricting the levels of certain transactions, including entering into certain loans, the granting of certain liens, capital expenditures, acquisitions, distributions to shareholders, certain asset dispositions and operating leases. The Credit Facility is secured by substantially all of the assets of the Company.
      Principal repayments on the long-term debt (including capital leases) over the next five years pursuant to the September 12, 2005 credit facility are:
         
2005
  $ 7,189  
2006
    4,297  
2007
    4,257  
2008
    4,264  
2009
    7,701  
11. Convertible debentures:
      On May 31, 2000, IPSL, a wholly-owned subsidiary of the Company, issued convertible debentures of C$5,000 maturing June 30, 2005 and convertible into 313,704 common shares at the holders’ option at C$15.94 per share at any time prior to maturity. The debentures were secured by a general security agreement providing a charge against IPSL’s assets, subordinated to any other senior indebtedness, and bore interest at 9% per annum. The chief executive officer of the debenture holder was a director of the Company. The debenture was repaid in full on June 30, 2005.

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COMPLETE PRODUCTION SERVICES, INC.
Notes to Consolidated Financial Statements — (Continued)
Years Ended December 31, 2004, 2003 and 2002
(In thousands, except as noted and per share data)
12. Share capital:
      The amounts of authorized and issued stock, warrants and options of CES have been adjusted to reflect the exchange ratio of 19.704 pursuant to the Combination (notes 1 and 19). The amounts of authorized and issued stock, warrants and options of IEM have been adjusted to reflect the exchange ratio of 19.410 pursuant to the Combination (notes 1 and 19).
(a) Authorized:
      Share capital consists of:
        100,000,000 voting common shares with par value of $0.01 per share, and 5,000,000 preferred shares with a par value of $0.01 per share.
(b) Stock split:
      The Company’s board of directors approved a stock split on a ten-for-one basis in September 2002. This stock split has been reflected retroactively in these financial statements. Outstanding warrants and stock options awarded have also been retroactively adjusted to account for the stock split.
(c) Warrants:
      On May 23, 2001, the Company issued a warrant to its major shareholder, SCF-IV, L.P. (“SCF”), to purchase up to 2,000,000 shares of the Company’s common stock at an exercise price of $10.00 per share any time through May 23, 2011. The warrant was issued as a source of future financing for the Company’s growth. In 2001 and 2004, SCF purchased 370,000 shares and 200,000 shares, respectively, under the warrant. On February 9, 2005, SCF purchased another 1,000,000 shares under the warrant. The warrant was cancelled on September 12, 2005.
      In November 2003, the Company issued a warrant to SCF to purchase up to 6,896,400 shares of the Company’s common stock at an exercise price of $5.08 per share. This warrant was exercised in full during 2004.
      In August 2004, the Company issued a warrant to SCF to purchase up to 3,105,600 shares of the Company’s common stock at an exercise price of $5.15 per share at any time through August 31, 2007 and a warrant to one of the Company’s minority stockholders to purchase up to 485,250 shares of the Company’s common stock at an exercise price of $5.15 per share at any time through August 31, 2007. These warrants were cancelled on September 12, 2005.
      Pursuant to the Subordinate Credit Agreement (note 10(e)), the Company issued detachable warrants to the lenders to purchase up to 35,909 shares of the Company’s common stock at $5.15 per share at any time through August 31, 2007. These warrants were cancelled on September 12, 2005.
      Also pursuant to the Subordinate Credit Agreement (note 10(e)), the Company issued detachable warrants to the lenders to purchase up to 24,263 shares of the Company’s common stock at $0.01 per share at any time through August 31, 2007. The fair value of these warrants, $125,000, was recorded as additional paid-in capital and as a discount on the liability under the subordinate credit agreement. These warrants were exercised on September 12, 2005.

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COMPLETE PRODUCTION SERVICES, INC.
Notes to Consolidated Financial Statements — (Continued)
Years Ended December 31, 2004, 2003 and 2002
(In thousands, except as noted and per share data)
(d) Employee stock incentive plan:
      Following the Combination, the Company maintains each of the options plans previously maintained by IPS, CES and IEM. Under the three option plans, the options could be granted to employees, officers and directors to purchase up to 1,500,000 common shares, 738,900 common shares (increased to 1,182,240 during 2005) and 388,200 common shares, respectively. The exercise price of each option is based on the fair value of the individual company’s stock at the date of grant. Options may be exercised over a 5-year period and generally a third of the options vest on each of the first three anniversaries from the grant date.
                 
    Options Outstanding
     
        Weighted
        Average
        Exercise
    Number   Price
         
Balance at December 31, 2001
    42,500     $ 10.00  
Granted
    292,187       10.89  
Cancelled
    (4,743 )     11.39  
             
Balance at December 31, 2002
    329,944       10.77  
Granted
    98,207       7.89  
Exercised
    (28,095 )     11.39  
Cancelled
    (21,532 )     11.39  
             
Balance at December 31, 2003
    378,524       9.94  
Granted
    559,428       8.28  
Exercised
    (40,590 )     4.57  
Cancelled
    (8,006 )     11.39  
             
Balance at December 31, 2004
    889,356     $ 9.15  
             
      Pursuant to the Combination, upon payment of the dividend of $5.24 per share as described in Note 20(c), the terms of all options outstanding at that time will be adjusted to offset the decrease in the Company’s per share price attributable to the dividend. The result of this adjustment, if applied to the options outstanding as at December 31, 2004, would be to increase the number of options outstanding to 1,129,698 and reduce the average exercise price to $7.20.
                                         
    Options Outstanding   Options Exercisable
         
        Weighted   Weighted       Weighted
    Outstanding at   Average   Average   Exercisable at   Average
    December 31,   Remaining   Exercise   December 31,   Exercise
Range of Exercise Price   2004   Life (months)   Price   2004   Price
                     
$5.08-5.58
    310,250       53     $ 5.18       19,704     $ 5.58  
$10.00
    148,141       20       10.00       136,260       10.00  
$11.39
    265,944       39       11.39       107,846       11.39  
$12.18
    165,021       48       12.18              
                               
      889,356       42     $ 9.15       263,810     $ 10.24  
                               

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COMPLETE PRODUCTION SERVICES, INC.
Notes to Consolidated Financial Statements — (Continued)
Years Ended December 31, 2004, 2003 and 2002
(In thousands, except as noted and per share data)
(e) Per share amounts:
      The weighted average number of common shares outstanding used in calculating basic and diluted earnings (loss) per share at December 31, 2004 and 2003 were 18,002,373 (2003 – 7,055,266; 2002 – 2,756,776) and 18,269,962 (2003 – 7,272,264; 2002 – 2,756,776), respectively. The reconciling item between basic and diluted weighted average common shares outstanding was the dilutive impact of outstanding restricted stock, stock options and warrants. The Company excluded the impact of anti-dilutive potential common shares from the calculation of diluted weighted average shares for the year ended December 31, 2002. If these potential common shares were included in the calculation, diluted weighted average shares would have been approximately 3,031,000 and diluted loss per share would have decreased to a loss $0.20 per share. The Company had no anti-dilutive potential common shares for the years ended December 31, 2004 and 2003 except as related to convertible debentures discussed below.
      In 2004, interest expense, net of tax, of $234 (2003 – $209; 2002 – $171) on the convertible debentures (see note 11) was added back to the numerator in calculating diluted earning per share when the impact, if converted, is dilutive. In 2004, 2003 and 2002, the impact of conversion of the convertible debentures would have been anti-dilutive.
13. Supplemental cash flow information:
                         
    2004   2003   2002
             
Change in:
                       
Trade accounts receivable
  $ (20,585 )   $ (687 )   $ (3,695 )
Inventory
    (7,936 )     (1,959 )     625  
Prepaid expenses
    (3,480 )     (614 )     (428 )
Accounts payable
    5,032       1,635       285  
Accrued liabilities
    10,706       5,244        
Taxes payable
    388       122       278  
Notes payable
    1,069              
                   
    $ (14,806 )   $ 3,741     $ (2,935 )
                   
Cash interest paid
  $ 6,756     $ 2,415     $ 1,260  
Cash taxes paid
  $ 1,136     $ 778     $ 119  
Common stock issued for acquisitions
  $ 81,329     $ 29,338     $  
Notes issued for acquisitions
  $ 4,150     $     $  
14. Segment information:
      SFAS No. 131, Disclosure About Segments of an Enterprise and Related Information, establishes standards for the reporting of information about operating segments, products and services, geographic areas, and major customers. The method of determining what information to report is based on the way management organizes the operating segments within the Company for making operational decisions and assessments of financial performance. The Company evaluates performance and allocates resources based on net income (loss) before interest expense, taxes, depreciation and amortization and minority interest (“EBITDA”). The calculation of EBITDA should not be viewed as a substitute to calculations under U.S. GAAP, in particular not net earnings. EBITDA calculated by the Company may not be comparable to another company.

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COMPLETE PRODUCTION SERVICES, INC.
Notes to Consolidated Financial Statements — (Continued)
Years Ended December 31, 2004, 2003 and 2002
(In thousands, except as noted and per share data)
      The Company has three reportable operating segments: completion and production services (“C&PS”), drilling services and product sales, and three geographic regions: the United States, Canada and International. The accounting policies of the segments are the same as those described in note 1. Inter-segment transactions are accounted for on a cost-recovery basis.
Operational segments:
                                         
        Drilling   Product        
Year Ended December 31, 2004   C&PS   Services   Sales   Corporate   Total
                     
Revenue from external customers
  $ 194,953     $ 44,474     $ 81,320     $     $ 320,747  
EBITDA, as defined
  $ 38,349     $ 10,093     $ 12,924     $ (2,869 )   $ 58,497  
Depreciation and amortization
  $ 16,750     $ 2,737     $ 907     $ 1,222     $ 21,616  
                               
Operating income (loss)
  $ 21,599     $ 7,356     $ 12,017     $ (4,091 )   $ 36,881  
Capital expenditures
  $ 32,004     $ 11,840     $ 2,944     $ 116     $ 46,904  
                                         
December 31, 2004                    
                     
Segment assets
  $ 384,014     $ 72,839     $ 53,751     $ 4,549     $ 515,153  
Goodwill
  $ 124,197     $ 15,022     $ 6,230     $     $ 145,449  
                                         
        Drilling   Product        
Year Ended December 31, 2003   C&PS   Services   Sales   Corporate   Total
                     
Revenue from external customers
  $ 65,025     $ 2,707     $ 35,547     $     $ 103,279  
EBITDA, as defined
  $ 9,134     $ 712     $ 4,951     $ (1,233 )   $ 13,564  
Depreciation and amortization
  $ 6,147     $ 130     $ 644     $ 727     $ 7,648  
                               
Operating income (loss)
  $ 2,987     $ 582     $ 4,307     $ (1,960 )   $ 5,916  
Capital expenditures
  $ 7,474     $ 2,623     $ 987     $     $ 11,084  
                                         
December 31, 2003                    
                     
Segment assets
  $ 148,165     $ 23,547     $ 34,177     $ 177     $ 206,066  
Goodwill
  $ 48,456     $ 4,940     $ 5,900     $     $ 59,296  
                                         
        Drilling   Product        
Year Ended December 31, 2002   C&PS   Services   Sales   Corporate   Total
                     
Revenue from external customers
  $ 30,110     $     $ 10,494     $     $ 40,604  
EBITDA, as defined
  $ 3,058     $     $ 1,251     $     $ 4,309  
Depreciation and amortization
    3,559             213       415       4,187  
                               
Operating income (loss)
  $ (501 )   $     $ 1,038     $ (415 )   $ 122  
Capital expenditures
  $ 6,799     $     $     $     $ 6,799  
Geographic information:
                                 
    United       Other    
Year Ended December 31, 2004   States   Canada   International   Total
                 
Revenue by sale origin to external customers
  $ 231,509     $ 73,743     $ 15,495     $ 320,747  
Income before taxes and minority interest
  $ 22,786     $ 4,048     $ 2,576     $ 29,410  

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COMPLETE PRODUCTION SERVICES, INC.
Notes to Consolidated Financial Statements — (Continued)
Years Ended December 31, 2004, 2003 and 2002
(In thousands, except as noted and per share data)
                                 
December 31, 2004                
                 
Long-lived assets
  $ 306,140     $ 79,662     $ 3,398     $ 389,200  
                                 
    United       Other    
Year Ended December 31, 2003   States   Canada   International   Total
                 
Revenue by sale origin to external customers
  $ 28,129     $ 62,376     $ 12,774     $ 103,279  
Income (loss) before taxes and minority interest
  $ (771 )   $ 2,211     $ 1,789     $ 3,229  
                                 
December 31, 2003                
                 
Long-lived assets
  $ 79,067     $ 76,604     $ 2,932     $ 158,603  
                                 
    United       Other    
Year Ended December 31, 2002   States   Canada   International   Total
                 
Revenue by sale origin to external customers
  $ 13,243     $ 21,968     $ 5,393     $ 40,604  
Income (loss) before taxes and minority interest
  $ (1,012 )   $ (805 )   $ 679     $ (1,138 )
      The Company does not have revenue from any single customer which amounts to 10% or more of the Company’s total revenue.
15. Financial instruments:
(a) Interest rate risk:
      The Company manages its exposure to interest rate risks through a combination of fixed and floating rate borrowings. At December 31, 2004, 99% of its total long-term debt was in floating rate borrowings and the convertible debentures bore interest at a fixed rate of 9%.
(b) Foreign currency rate risk:
      The Company is exposed to foreign currency fluctuations in relation to its foreign operations. In 2004, approximately 20% of the Company’s operations were conducted in Canadian dollars and the related balance sheet accounts were denominated in Canadian dollars.
(c) Credit risk:
      A significant portion of the Company’s trade accounts receivable are from companies in the oil and gas industry, and as such, the Company is exposed to normal industry credit risks. The Company evaluates the credit-worthiness of its major new and existing customers’ financial condition and generally does not require collateral.

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COMPLETE PRODUCTION SERVICES, INC.
Notes to Consolidated Financial Statements — (Continued)
Years Ended December 31, 2004, 2003 and 2002
(In thousands, except as noted and per share data)
16. Commitment and contingences:
      Under the terms of operating leases for premises and equipment, the Company is committed to make the following minimum lease payments over the next five years:
         
2005
  $ 6,993  
2006
    4,444  
2007
    2,872  
2008
    2,217  
2009
    1,330  
       
    $ 17,856  
       
      In 2004, operating lease payments expensed were $6,585 (2003 – $4,031; 2002  – $3,330).
      The Company is subject to legal procedures and claims, either asserted or unasserted, in the ordinary course of business. While the outcome of these claims cannot be predicted with certainty, management does not believe that the outcome of any of these legal matters will have a material adverse effect on its combined financial position, results of operations or cash flows.
17. Related party transactions:
      The Company believes all transactions with related parties have the terms and conditions no less favorable to the Company as transactions with unaffiliated parties.
      The Company has entered into lease agreements for properties owned by employees and directors of the Company. The leases expire at different times through June 2014. In 2004, the total lease expense pursuant to these leases was $1,439 (2003 – $151; 2002 – $57).
      In conjunction with the acquisition of Hamm Co., the Company became party to an agreement with a customer, majority-owned by a director of the Company, pursuant to which, at the customer’s option, the customer may engage a specified amount of the Company’s assets into a long-term contract at market rates. The Company provided services aggregating $2,680 and $620 to this customer in 2004 and 2003, respectively. The Company provided services aggregating $205 during 2004 to a customer, the principal of whom is a director of the Company. The Company provided services aggregating $8,400 during 2004 to a customer which is majority-owned by an officer of one of the Company’s subsidiaries. In 2003 and 2002, the Company provided wireline and coiled tubing services to a company whose former chief operating officer is a director of the Company. In 2003, revenue for these services was $836 (2002 – $860). At December 31, 2004, $2,940 (2003 $796; 2002 – $229) was owed to the Company in trade receivables for services provided to this company. At December 31, 2004, the Company also had a payable balance of $185 with this company.
      Effective December 1, 2002, the Company entered into a management services agreement with an affiliate of its major shareholder. This agreement provides for monthly payments of $20 for services rendered. In 2004, $60 (2003 – $240; 2002 – $20) was expensed pursuant to this agreement. This agreement was terminated March 31, 2004. Effective November 7, 2003, the Company entered into a financial advisory services agreement with an affiliate of its major shareholder, which provided for an upfront fee of $250 and quarterly payments of $31. This agreement was cancelled effective September 12, 2005. Effective August 14, 2004, the Company entered into a financial advisory services agreement with an affiliate of its major shareholder pursuant to which it paid fees of $1,600 in conjunction with the

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COMPLETE PRODUCTION SERVICES, INC.
Notes to Consolidated Financial Statements — (Continued)
Years Ended December 31, 2004, 2003 and 2002
(In thousands, except as noted and per share data)
Company’s 2004 acquisitions, and management fees of $350 during 2004. This agreement was cancelled effective September 12, 2005.
      In 2003 and 2002, the Company purchased equipment with aggregate value of $2,378 (2002 – $5,800) from a company in which the Company’s major shareholder has an equity interest. The Company’s major shareholder no longer holds an equity interest in this equipment supplier. The amounts payable at December 31, 2003 were $1,397. No amounts were due to this supplier as of December 31, 2002.
      The Company is obligated to pay an employee an aggregate principal amount of $2,200 pursuant to a subordinated promissory note due March 31, 2009 that was issued by CES in connection with the acquisition of LEED Energy Services in 2004. This employee is an officer of one of the Company’s subsidiaries.
18. Retirement plans:
      The Company maintains defined contribution retirement plans for substantially all of its U.S. and Canadian employees who have completed six months of service. Employees may voluntarily contribute up to a maximum percentage of their salaries to these plans subject to certain statutory maximum dollar values. The maximums range from 20% to 60%, depending on the plan. The Company makes matching contributions at 25% – 50% of the first 6% or 7% of the employee’s contributions, depending on the plan. The employer contributions vest immediately with respect to the Canadian RRSP plan and vest at varying rates under the U.S. 401(k) plans. Vesting ranges from immediately to a graduated scale with 100% vesting after five years of service.
      In 2004, the Company recognized an expense of $853 (2003 – $331; 2002 – $285) related to its various defined contribution plans.
19. Recent accounting pronouncements:
      In November 2004, the FASB issued SFAS No. 151, “Inventory Costs.” SFAS No. 151 amends the guidance in Accounting Research Bulletin No. 43, Chapter 4, “Inventory Pricing,” to clarify the accounting for abnormal amounts of idle facility expense, freight, handling costs and wasted material (spoilage), and generally requires that these amounts be expensed in the period that the cost arises, rather than being included in the cost of inventory, thereby requiring that the allocation of fixed production overheads to the costs of conversion be based on normal capacity of the production facilities. SFAS No. 151 becomes effective for inventory costs incurred during fiscal years beginning after June 15, 2005, but earlier application is permitted. The Company is currently evaluating the impact of SFAS No. 151 on our financial statements, but the Company does not expect that it will have a material impact on its financial position, results of operations or cash flows.
      In December 2004, the FASB issued SFAS No. 153, “Exchanges of Nonmonetary Assets.” SFAS No. 153 amends current guidance related to the exchange on nonmonetary assets as per APB Opinion No. 29, “Accounting for Nonmonetary Transactions,” to eliminate an exception that allowed exchange of similar nonmonetary assets without determination of the fair value of those assets, and replaced this provision with a general exception for exchanges of nonmonetary assets that do not have commercial substance. A nonmonetary exchange has commercial substance if the future cash flows of the entity are expected to change significantly as a result of the exchange. SFAS No. 153 becomes effective for nonmonetary asset exchanges occurring in fiscal periods beginning after June 15, 2005. The Company does not anticipate that the adoption of this policy will have a material impact on our financial position, results of operations or cash flows.

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COMPLETE PRODUCTION SERVICES, INC.
Notes to Consolidated Financial Statements — (Continued)
Years Ended December 31, 2004, 2003 and 2002
(In thousands, except as noted and per share data)
      In December 2004, the FASB issued SFAS No. 123R, “Share-Based Payment,” which revises SFAS No. 123 and supercedes APB No. 25. SFAS No. 123R will require the Company to measure the cost of employee services received in exchange for an award of equity instruments based on the grant-date fair value of the award, with limited exceptions. The fair value of the award will be remeasured at each reporting date through the settlement date, with changes in fair value recognized as compensation expense of the period. Entities should continue to use an option-pricing model, adjusted for the unique characteristics of those instruments, to determine fair value as of the grant date of the stock options. SFAS No. 123R was to become effective as of the beginning of the first interim or annual reporting period that begins after June 15, 2005. However, the SEC issued an extension which allows public companies to defer adoption of SFAS No. 123R until the beginning of their fiscal year that begins after June 15, 2005. The Company has not yet adopted SFAS No. 123R and is currently evaluating the impact that this policy will have on its financial position, results of operations and cash flows.
      In May 2005, the FASB issued SFAS No. 154, “Accounting Changes and Error Corrections, a Replacement of APB Opinion No. 20 and FASB Statement No. 3.” SFAS No. 154 requires retrospective application of changes in accounting principle to prior periods’ financial statements, rather than the use of the cumulative effect of a change in accounting principle, unless impracticable. If impracticable to determine the impact on prior periods, then the new accounting principle should be applied to the balances of assets and liabilities as of the beginning of the earliest period for which retrospective application is practicable, with a corresponding adjustment to equity, unless impracticable for all periods presented, in which case prospective treatment should be applied. SFAS No. 154 applies to all voluntary changes in accounting principle, as well as those required by the issuance of new accounting pronouncements if no specific transition guidance is provided. SFAS No. 154 does not change the previously-issued guidance for reporting a change in accounting estimate or correction of an error. SFAS No. 154 becomes effective for accounting changes and corrections of errors made in fiscal years beginning after December 15, 2005. The Company does not expect this policy to have a material impact on its financial position, results of operations or cash flows.
20. Subsequent events:
(a) Parchman Energy Group, Inc. (“Parchman”):
      On February 11, 2005, the Company acquired all of the stock of Parchman in a business combination accounted for as a purchase. Parchman performs coiled tubing services, well testing services, snubbing services and wireline services in Louisiana, Texas, Wyoming and Mexico. The results of operations will be included in the accounts of Complete from the date of acquisition. The purchase agreement provides for the issuance of up to 500,000 shares of common stock of the Company as contingent consideration over the period from the date of acquisition to December 31, 2005 based on certain operating results. Goodwill associated with the acquisition was allocated to the completion and production services segment.

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COMPLETE PRODUCTION SERVICES, INC.
Notes to Consolidated Financial Statements — (Continued)
Years Ended December 31, 2004, 2003 and 2002
(In thousands, except as noted and per share data)
      The following table summarizes the preliminary purchase price allocation:
           
Net assets acquired:
       
 
Non-cash working capital
  $ 3,401  
 
Property, plant and equipment
    48,688  
 
Intangible assets
    459  
 
Goodwill (no tax basis)
    21,975  
 
Long-term debt
    (32,017 )
 
Deferred income taxes
    (8,608 )
       
Net assets acquired
  $ 33,898  
       
Consideration:
       
 
Cash, net of cash and cash equivalents acquired
  $ 9,833  
 
Subordinated note
    5,000  
 
Issuance of common stock (1,500,000 shares)
    19,065  
       
Total consideration
  $ 33,898  
       
      The price for common shares was based on internal calculations of the fair value and consultations with the seller. The purchase price allocation is preliminary and certain items such as acquisition costs, final tax basis and fair values of asset and liabilities as of the acquisition date have not been finalized.
(b) Combination:
      On September 12, 2005, the Company completed the Combination of CES, IPS and IEM pursuant to which CES and IEM stockholders exchanged all of their common stock for common stock of IPS. CES stockholders received 19.704 shares of IPS common stock for each share of CES, and IEM stockholders received 19.410 shares of IPS common stock for each share of IEM. Subsequent to the Combination, IPS changed its name to Complete Production Services, Inc. (“Complete”) and CES stockholders owned 57.6% of Complete’s common shares, IPS stockholders owned 33.2% and the former IEM stockholders owned 9.2%.
(c) Dividend:
      On September 12, 2005, Complete paid a dividend of $5.24 per share for an aggregate payment of approximately $146,900 to stockholders of record on that date. Up to an additional $3,100 will be paid to stockholders in respect of stock earnable pursuant to contingent consideration provisions of certain acquisition agreements previously entered into by the Company.
(d) Authorized share capital:
      On September 12, 2005, the authorized share capital of the Company was increased to 100,000,000 common shares, from 12,000,000 common shares, at a par value of $0.01 per share, and to 5,000,000 preferred shares from 1,000 preferred shares at a par value of $0.01 per share.

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APPENDIX A
Glossary of Selected Industry Terms
      Acidizing. The pumping of acid into the wellbore to remove near-well formation damage and other damaging substances.
      Acoustic pressure surveys. Surveys that determine oil and gas reservoir pressure from surface using pressure transducers and sound waves.
      Artificial lift equipment. A system that adds energy to the fluid column in a wellbore with the objective of initiating and improving production from the well.
      Blowout. An uncontrolled flow of reservoir fluids into the wellbore, and sometimes catastrophically to the surface.
      Blowout preventer (BOP). A large valve at the top of a well that may be closed to regain control of a reservoir, if the drilling crew or other well site personnel loses control of formation fluids.
      Bottom-hole assemblies. The lower portion of the drillstring, consisting of (from the bottom up in a vertical well) the bit, bit sub, a mud motor (in certain cases), stabilizers, drill collars, heavy-weight drillpipe, jarring devices (“jars”) and crossovers for various threadforms.
      Casing. Large-diameter pipe lowered into an openhole wellbore and cemented in place.
      Casing patch. A downhole assembly or tool system used in the remedial repair of casing damage, corrosion or leaks.
      Cementing. To prepare and pump cement into place in a wellbore.
      Choke. A device incorporating an orifice that is used to control fluid flow rate or downstream system pressure.
      Coiled tubing. A long, continuous length of pipe wound on a spool. The pipe is straightened prior to pushing into a wellbore and recoiled to spool the pipe back onto the transport and storage spool.
      Completion phase. A generic term used to describe the assembly of downhole tubulars and equipment required to enable safe and efficient production from an oil or gas well. The point at which the completion process begins may depend on the type and design of the well.
      Downhole. Pertaining to or in the wellbore (as opposed to being on the surface).
      Drillpipe. Tubular steel conduit fitted with special threaded ends called tool joints. The drillpipe connects the surface equipment with the bottomhole assembly, both to pump drilling fluid to the bit and to be able to raise, lower and rotate the bottomhole assembly and bit.
      Drill string. The combination of the drillpipe, the bottomhole assembly and any other tools used to make the drill bit turn at the bottom of the wellbore.
      Electric-line. Related to any aspect of logging that employs an electrical cable to lower tools into the borehole and to transmit data.
      Fishing. The application of tools, equipment and techniques for the removal of junk, debris or lost or stuck equipment from a wellbore.
      Flapper valves. A check valve that has a spring-loaded plate (or flapper) that may be pumped through, generally in the downhole direction, but closes if the fluid attempts to flow back through the drillstring to the surface.

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      Flare gas. A vapor or gas that is burned through a pipe or burners.
      Flowback. The process of allowing fluids to flow from the well following a treatment, either in preparation for a subsequent phase of treatment or in preparation for cleanup and returning the well to production.
      Foam. Drilling foam is a fluid that contains air or gas bubbles, that can withstand high salinity, hard water, solids, entrained oil and high temperatures.
      Frac tanks. A tank used to hold fluid during a frac job. Capacity of such tanks are from 400 to 600 bbls.
      Hydrocarbon. A naturally occurring organic compound comprising hydrogen and carbon. Hydrocarbons can be as simple as methane, but many are highly complex molecules, and can occur as gases, liquids or solids. Petroleum is a complex mixture of hydrocarbons. The most common hydrocarbons are natural gas, oil and coal.
      Jars. A mechanical device used downhole to deliver an impact load to another downhole component, especially when that component is stuck.
      Jetting. A downhole treatment in which a fluid laden with solid particles is used to remove deposits from the surface of wellbore tubulars and completion components.
      Landing nipples. A completion component fabricated as a short section of heavy wall tubular with a machined internal surface that provides a seal area and a locking profile.
      Live-well. A well that is flowing or has the ability to flow into the wellbore.
      Log. The measurement versus depth or time, or both, of one or more physical quantities in or around a well. The term comes from the word “log” used in the sense of a record or a note.
      Logging tools. The downhole hardware needed to make a log.
      Manifold. An arrangement of piping or valves designed to control, distribute and often monitor fluid flow. Manifolds are often configured for specific functions, such as a choke or kill manifold used in well-control operations and a squeeze manifold used in squeeze-cementing work.
      Milling. A downhole tool used to cut and remove material from equipment or tools located in the wellbore.
      Mud coolers. A mud cooling system is used in a variety of applications where drilling safety or efficiency is enhanced by cooling the drilling fluid.
      Nitrogen unit. A high-pressure pump or compressor unit capable of delivering high-purity nitrogen gas for use in oil or gas wells.
      Overshots. A downhole tool used in fishing operations to engage on the outside surface of a tube or tool.
      Packer. A downhole device used in many completions to isolate the annulus from the production conduit, enabling controlled production, injection or treatment.
      Progressive Cavity (PC) pump. A type of sucker rod-pumping unit that uses a rotor and a stator. The rotation of the rod cavity by means of an electric motor at surface causes the fluid contained in a cavity to flow upward.
      Perforating guns. A device used to perforate oil and gas wells in preparation for production. Perforating guns contain several shaped explosive charges and are available in a range of sizes and configurations.

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      Perforate. To create holes in the casing or liner to achieve efficient communication between the reservoir and the wellbore.
      Pipe handling. Equipment used to move and connect drillpipe.
      Plug drilling. The process by which plugs are removed from the wellbore.
      Plugs. A downhole packer assembly used in a well to seal off or isolate a particular formation for testing, acidizing, cementing, etc.; also a type of plug used to seal off a well temporarily while the wellhead is removed.
      Plunger lift. An artificial-lift method principally used in gas wells to unload relatively small volumes of liquid.
      Power swivels. On a drilling rig, a swivel is a mechanical device that must simultaneously suspend the weight of the drillstring, provide for rotation of the drill string beneath it while keeping the upper portion stationary, and permit high-volume flow of high-pressure drilling mud from the fixed portion to the rotating portion without leaking. Well service rigs do not have integral swivels; therefore, if rotation capability for drilling or any other reason is required on a well service rig, then a power swivel is added to the well service rig.
      Drilling rig. The machine used to drill a wellbore.
      Shale. A fine-grained, fissile, sedimentary rock formed by consolidation of clay- and silt-sized particles into thin, relatively impermeable layers.
      Slickline. A thin non-electric cable used for selective placement and retrieval of wellbore hardware, such as plugs, gauges and valves. Valves and sleeves can also be adjusted using slickline tools.
      Sliding sleeves. Completion devices that can be operated to provide a flow path between the production conduit and the annulus.
      Snubbing. The act of putting drillpipe or tubing into the wellbore when the blowout preventers (BOPs) are closed and pressure is contained in the well.
      Stabilizers. A bottom-hole-assembly component having a body diameter about the same size as a drill collar, and having longitudinal or spiral blades that form a larger diameter, often at or near hole diameter.
      Supply stores. Retail stores that sell equipment for use in oil and gas exploration, development and production.
      Swabbing. The act of unloading liquids from the production tubing to initiate or improve flow from the reservoir.
      Tight sands. A type of unconventional tight reservoir. Tight reservoirs are those which have low permeability, often quantified as less than 0.1 millidarcies.
      Tongs. Large-capacity, self-locking wrenches used to grip drillstring components and apply torque.
      Tubing string. A pipe set inside the well casing, through which the oil or gas is produced.
      Underbalanced. A well condition where the amount of pressure exerted on a formation is less than the internal fluid pressure of the formation, enabling formation fluids to enter the wellbore. The drilling rate typically increases as an underbalanced condition is approached.
      Well casing – see Casing.

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      Well clean-up. A period of controlled production, generally following a stimulation treatment, during which time treatment fluids return from the reservoir formation.
      Wellbore. The physical conduit from surface into the hydrocarbon reservoir.
      Whipstock. An inclined wedge placed in a wellbore to force the drill bit to start drilling in a direction away from the wellbore axis.
      Wireline. A general term used to describe well-intervention operations conducted using single-strand or multistrand wire or cable for intervention in oil or gas wells.

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(COMPLETE PRODUCTION SERVICES LOGO)


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PART II
INFORMATION NOT REQUIRED IN PROSPECTUS
ITEM 13. Other Expenses of Issuance and Distribution
      Set forth below are the expenses (other than underwriting discounts and commissions) expected to be incurred in connection with the issuance and distribution of the securities registered hereby. With the exception of the SEC registration fee and the NASD filing fee, the amounts set forth below are estimates:
           
SEC registration fee
  $ 40,607  
NASD filing fee
    35,000  
NYSE listing fee
       
Printing and engraving expenses
       
Legal fees and expenses
       
Accounting fees and expenses
       
Blue sky fees and expenses (including legal fees)
       
Transfer agent and registrar fees
       
Miscellaneous
       
       
 
Total
  $    
       
ITEM 14. Indemnification of Directors and Officers
      Section 145 of the Delaware General Corporation Law (“DGCL”) provides that a corporation may indemnify any person who was or is a party or is threatened to be made a party to any threatened, pending or completed action, suit or proceeding whether civil, criminal, administrative or investigative (other than an action by or in the right of the corporation) by reason of the fact that he is or was a director, officer, employee or agent of the corporation, or is or was serving at the request of the corporation as a director, officer, employee or agent of another corporation, partnership, joint venture, trust or other enterprise, against expenses (including attorneys’ fees), judgments, fines and amounts paid in settlement actually and reasonably incurred by him in connection with such action, suit or proceeding if he acted in good faith and in a manner he reasonably believed to be in or not opposed to the best interests of the corporation, and, with respect to any criminal action or proceeding, had no reasonable cause to believe his conduct was unlawful. Section 145 further provides that a corporation similarly may indemnify any such person serving in any such capacity who was or is a party or is threatened to be made a party to any threatened, pending or completed action or suit by or in the right of the corporation to procure a judgment in its favor by reason of the fact that he is or was a director, officer, employee or agent of the corporation or is or was serving at the request of the corporation as a director, officer, employee or agent of another corporation, partnership, joint venture, trust or other enterprise, against expenses (including attorneys’ fees) actually and reasonably incurred in connection with the defense or settlement of such action or suit if he acted in good faith and in a manner he reasonably believed to be in or not opposed to the best interests of the corporation and except that no indemnification shall be made in respect of any claim, issue or matter as to which such person shall have been adjudged to be liable to the corporation unless and only to the extent that the Delaware Court of Chancery or such other court in which such action or suit was brought shall determine upon application that, despite the adjudication of liability but in view of all of the circumstances of the case, such person is fairly and reasonably entitled to indemnity for such expenses which the Delaware Court of Chancery or such other court shall deem proper. Our certificate of incorporation and bylaws provide that indemnification shall be to the fullest extent permitted by the DGCL for all our current or former directors or officers. As permitted by the DGCL, our certificate of incorporation provides that we will indemnify our directors against liability to us or our stockholders for monetary damages for breach of fiduciary duty as a director, except (1) for any breach of the director’s duty of loyalty to us or our stockholders, (2) for acts or omissions not in good faith or which involve intentional

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misconduct or knowing violation of law, (3) under Section 174 of the DGCL or (4) for any transaction from which a director derived an improper personal benefit.
      We have also entered into indemnification agreements with all of our directors and all of our executive officers (including each of our named executive officers). These indemnification agreements are intended to permit indemnification to the fullest extent now or hereafter permitted by the DGCL. It is possible that the applicable law could change the degree to which indemnification is expressly permitted.
      The indemnification agreements cover expenses (including attorneys’ fees), judgments, fines and amounts paid in settlement incurred as a result of the fact that such person, in his or her capacity as a director or officer, is made or threatened to be made a party to any suit or proceeding. The indemnification agreements generally cover claims relating to the fact that the indemnified party is or was an officer, director, employee or agent of us or any of our affiliates, or is or was serving at our request in such a position for another entity. The indemnification agreements also obligate us to promptly advance all reasonable expenses incurred in connection with any claim. The indemnitee is, in turn, obligated to reimburse us for all amounts so advanced if it is later determined that the indemnitee is not entitled to indemnification. The indemnification provided under the indemnification agreements is not exclusive of any other indemnity rights; however, double payment to the indemnitee is prohibited.
      We are not obligated to indemnify the indemnitee with respect to claims brought by the indemnitee against:
  •  us, except for:
  •  claims regarding the indemnitee’s rights under the indemnification agreement;
 
  •  claims to enforce a right to indemnification under any statute or law; and
 
  •  counter-claims against us in a proceeding brought by us against the indemnitee; or
  •  any other person, except for claims approved by our board of directors.
      We have obtained director and officer liability insurance for the benefit of each of the above indemnitees. These policies include coverage for losses for wrongful acts and omissions and to ensure our performance under the indemnification agreements. Each of the indemnitees are named as an insured under such policies and provided with the same rights and benefits as are accorded to the most favorably insured of our directors and officers.
ITEM 15. Recent Sales of Unregistered Securities
      During the past three years, we have issued unregistered securities to a limited number of persons, as described below. None of these transactions involved any underwriters or public offerings, and we believe that each of these transactions was exempt from registration requirements pursuant to Section 3(a)(9) or Section 4(2) of the Securities Act, Regulation D promulgated thereunder or Rule 701 of the Securities Act. The recipients of these securities represented their intention to acquire the securities for investment only and not with a view to or for sale in connection with any distribution thereof, and appropriate legends were affixed to the share certificates and instruments issued in these transactions. No remuneration or commission was paid or given directly or indirectly.
      On September 20, 2002, we entered into a combination agreement with Integrated Production Services Ltd. (“IPSL”). Pursuant to the combination agreement, all of the outstanding shares of IPSL were acquired in exchange for 4,694,010 of our shares.
      On April 30, 2003, we acquired all of the shares of Ess-Ell Tool Co. Ltd. and Sentry Oil Tools LLC for a total consideration of $3.9 million in cash and 73,749 of our shares.
      On March 31, 2004, we issued an aggregate of 131,696 shares of our common stock to former stockholders of Double Jack Testing and Services, Inc. (“Double Jack”) as consideration for the purchase of all of the shares of common stock of Double Jack.

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      On December 10, 2004, we issued 104,302 shares of our common stock to former stockholders of MGM Well Services, Inc. (“MGM”), as consideration for the acquisition of all of the common stock of MGM. We also issued 14,224 shares of restricted stock to key employees who were former employees of MGM. In addition, the purchase included contingent consideration of up to 107,066 shares of our common stock over the period of March 31, 2005 to December 31, 2006 based on certain operating results of MGM.
      On February 11, 2005, we issued 1,500,000 shares of our common stock to former stockholders of Parchman, as consideration for the acquisition of all of the capital stock of Parchman. In addition, the acquisition included contingent consideration of up to 500,000 shares of our common stock over the period of February 11, 2005 to December 31, 2005 based on certain operating results of one of our divisions.
      On June 20, 2005, Joseph C. Winkler, our Chief Executive Officer and President purchased 20,898 shares of our common stock at purchase price of $17.00 per share or an aggregate price of $355,270.
      On July 7, 2005, we issued 68,214 shares of our common stock to former stockholders of Roustabout Specialties Inc. (“RSI”), as consideration for the acquisition of all of the capital stock of RSI.
      On September 12, 2005, we completed the Combination. We issued an aggregate of 16,060,321 shares of our common stock to former stockholders of CES and 2,450,881 shares of our common stock to former stockholders of IEM. In addition, we issued 72,116 shares of restricted stock to former holders of CES restricted stock and 131,387 shares of restricted stock to former holders of IEM restricted stock. Holders of options to purchase shares of CES common stock received an aggregate of options to purchase 957,103 shares of our common stock and holders of options to purchase shares of IEM common stock received an aggregate of options to purchase 33,877 shares of our common stock.
      On September 29, 2005, we issued 45,182 shares of our common stock to John D. Schmitz, an officer of one of our subsidiaries, as consideration for the acquisition of the assets of Spindletop Production Services, Ltd.
      On October 3, 2005, James F. Maroney, III, our Vice President, General Counsel and Secretary purchased 21,450 shares of our common stock at a purchase price of $23.31 per share or an aggregate price of $499,999.50
      On October 3, 2005, Kenneth L. Nibling, our Vice President, Human Resources and Administration, purchased 21,450 shares of our common stock at a purchase price $23.31 per share or an aggregate price $499,999.50.
      On October 10, 2005, we issued 8,023 shares of our common stock to some of our employees as a bonus for their services.
      On November 1, 2005, we acquired the equity interests of Big Mac. In connection with this acquisition, we issued options to purchase 45,000 shares of our common stock to the former owner of Big Mac and options to purchase 70,000 shares of our common stock to certain of Big Mac’s employees.
      We issued options to purchase an aggregate of 252,094 shares of our common stock to certain of our current and former directors and officers under our 2001 Stock Incentive Plan and the Parchman Plan during the period beginning on January 1, 2005 and ending on November 1, 2005. During the year ended December 31, 2004, we issued options to purchase an aggregate of 83,072 shares of our common stock to certain of our current and former directors and officers under our 2001 Stock Incentive Plan. During the year ended December 31, 2003, we issued options to purchase an aggregate of 12,700 shares of our common stock to certain of our current and former directors and officers under our 2001 Stock Incentive Plan. During the year ended December 31, 2002, we issued options to purchase an aggregate of 59,472 shares of our common stock to certain of our current and former directors and officers under our 2001 Stock Incentive Plan.
      We also issued 48,788 shares of our restricted stock to certain of our current and former directors and officers under our 2001 Stock Incentive Plan during the period beginning on January 1, 2005 and ending

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on November 1, 2005. We issued 8,780 shares of our restricted stock to certain of our current and former directors and officers under our 2001 Stock Incentive Plan during the year ended December 31, 2004. During the year ended December 31, 2003, we did not issue any shares of our restricted stock to our current and former directors or officers under our 2001 Incentive Plan. During the year ended December 31, 2002, we did not issue shares of our restricted stock to our current and former directors or officers under our 2001 Stock Incentive Plan.
      We relied upon Rule 701 of the Securities Act, among others, for the exemption from registration of the issuance of these options and shares of restricted stock.
ITEM 16. Exhibits and Financial Statement Schedules
      a. Exhibits:
             
  1 .1     Form of Underwriting Agreement
  3 .1**     Form of Amended and Restated Certificate of Incorporation
  3 .2**     Form of Amended and Restated Bylaws
  4 .1     Specimen Stock Certificate representing common stock
  5 .1     Opinion of Vinson & Elkins L.L.P.
  10 .1*     Form of Indemnification Agreement
  10 .2**     Employment Agreement dated as of June 22, 2005 with Joseph C. Winkler
  10 .3     Amended and Restated Stockholders’ Agreement dated as of September 12, 2005 by and among Complete Production Services, Inc. and the stockholders listed therein
  10 .4**     Combination Agreement dated as of August 9, 2005, with Complete Energy Services, Inc., I.E. Miller Services, Inc. and Complete Energy Services, LLC and I.E. Miller Services, LLC
  10 .5*     Credit Agreement, dated as of September 12, 2005 by and among Complete Production Services, Inc., as U.S. Borrower, Integrated Production Services Ltd., as Canadian Borrower, Wells Fargo Bank, National Association, as U.S. Administrative Agent, U.S. Issuing Lender and US Swingline Lender, HSBC Bank Canada, as Canadian Administrative Agent, Canadian Issuing Lender and Canadian Swingline Lender, and the Lenders party thereto, Wells Fargo Bank, National Association as Sole Book Runner and Co-Lead Arranger, UBS Securities LLC, as Co-Lead Arranger and Syndication Agent and Amegy Bank N.A. and Comerica Bank, as Co-Documentation Agents
  10 .6*     Integrated Production Services, Inc. 2001 Stock Incentive Plan
  10 .7*     Complete Energy Services, Inc. 2003 Stock Incentive Plan
  10 .8*     First Amendment to the Complete Energy Services, Inc. 2003 Stock Incentive Plan
  10 .9*     Second Amendment to the Complete Energy Services, Inc. 2003 Stock Incentive Plan
  10 .10*     I.E. Miller Services, Inc. 2004 Stock Incentive Plan
  10 .11*     Amended and Restated Integrated Production Services and Parchman Energy Group, Inc. Stock Incentive Plan
  10 .12*     Strategic Customer Relationship Agreement, dated as of October 14, 2004, by and among Complete Energy Services, Inc., CES Mid-Continent Hamm, Inc. and Continental Resources, Inc.
  10 .13     Form of Non-Qualified Option Grant Agreement (Executive Officer)
  10 .14     Form of Non-Qualified Option Grant Agreement (Non-Employee Director)
  10 .15*     Form of Restricted Stock Grant Agreement (Employee)
  10 .16*     Form of Restricted Stock Agreement (Non-Employee Director)
  21 .1     Subsidiaries of Complete Production Services, Inc.
  23 .1*     Consent of Grant Thornton LLP
  23 .2*     Consent of KPMG LLP
  23 .3     Consent of Vinson & Elkins L.L.P. (contained in Exhibit 5.1)
  24 .1     Power of Attorney (included on signature page)
 
  Filed herewith
**  Filed previously

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      Certain of the exhibits filed herewith contain representations and warranties made by us or our subsidiaries to other parties. The assertions embodied in those representations and warranties are in certain cases qualified by information in confidential disclosure schedules. While we do not believe that the disclosure schedules contain information that the securities laws require to be publicly disclosed, the disclosure schedules do contain information that modifies, qualifies and creates exceptions to the representations and warranties set forth in the applicable exhibits. Accordingly, you should not rely on the representations and warranties as characterizations of the actual state of facts, since they are modified by the underlying disclosure schedules. Moreover, information concerning the subject matter of the representations and warranties may have changed since the date of the applicable exhibit, which subsequent information may or may not be fully reflected in this registration statement.
      b. Financial Statement Schedules:
      None
ITEM 17. Undertakings
      The undersigned Registrant hereby undertakes:
        (a) Insofar as indemnification for liabilities arising under the Securities Act of 1933 may be permitted to directors, officers and controlling persons of the Registrant pursuant to the provisions described in Item 14, or otherwise, the Registrant has been advised that in the opinion of the SEC such indemnification is against public policy as expressed in the Act and is, therefore, unenforceable. In the event that a claim for indemnification against such liabilities (other than the payment by the Registrant of expenses incurred or paid by a director, officer or controlling person of the Registrant in the successful defense of any action, suit or proceeding) is asserted by such director, officer or controlling person in connection with the securities being registered, the Registrant will, unless in the opinion of its counsel the matter has been settled by controlling precedent, submit to a court of appropriate jurisdiction the question whether such indemnification by it is against public policy as expressed in the Act and will be governed by the final adjudication of such issue.
 
        (b) To provide to the underwriters at the closing specified in the underwriting agreement, certificates in such denominations and registered in such names as required by the underwriters to permit prompt delivery to each purchaser.
 
        (c) For purpose of determining any liability under the Securities Act of 1933, the information omitted from the form of prospectus filed as part of this Registration Statement in reliance upon Rule 430A and contained in the form of prospectus filed by the Registrant pursuant to Rule 424(b)(1) or (4) or 497(h) under the Securities Act shall be deemed to be part of this Registration Statement as of the time it was declared effective.
 
        (d) For the purpose of determining any liability under the Securities Act of 1933, each post-effective amendment that contains a form of prospectus shall be deemed to be a new registration statement relating to the securities offered therein, and the offering of such securities at that time shall be deemed to be the initial bona fide offering thereof.

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SIGNATURES
      Pursuant to the requirements of the Securities Act of 1933, as amended, the Registrant has duly caused this Registration Statement to be signed on its behalf by the undersigned, thereunto duly authorized, in the City of Houston, in the State of Texas, on November 14, 2005.
  COMPLETE PRODUCTION SERVICES, INC.
  By:  /s/ Joseph C. Winkler
 
 
  Name: Joseph C. Winkler
  Title: President, Chief Executive Officer and Director
      KNOW ALL MEN BY THESE PRESENTS, that each person whose signature appears below constitutes and appoints Joseph C. Winkler and J. Michael Mayer, and each of them severally, his true and lawful attorney or attorneys-in-fact and agents, with full power to act with or without the others and with full power of substitution and resubstitution, to execute in his name, place and stead, in any and all capacities, any or all amendments (including pre-effective and post-effective amendments) to this Registration Statement and any registration statement for the same offering filed pursuant to Rule 462 under the Securities Act of 1933, as amended, and to file the same, with all exhibits thereto, and other documents in connection therewith, with the Securities and Exchange Commission, granting unto said attorneys-in-fact and agents and each of them, full power and authority to do and perform in the name of on behalf of the undersigned, in any and all capacities, each and every act and thing necessary or desirable to be done in and about the premises, to all intents and purposes and as fully as they might or could do in person, hereby ratifying, approving and confirming all that said attorneys-in-fact and agents or their substitutes may lawfully do or cause to be done by virtue hereof.
      Pursuant to the requirements of the Securities Act of 1933, as amended, this Registration Statement has been signed below by the following persons in the capacities and on the dates indicated below.
             
Signature   Position   Date
         
 
/s/ Joseph C. Winkler
 
Joseph C. Winkler
  President, Chief Executive Officer and Director
(Principal Executive Officer)
  November 14, 2005
 
/s/ J. Michael Mayer
 
J. Michael Mayer
  Senior Vice President and Chief Financial Officer (Principal Financial Officer   November 14, 2005
 
/s/ Robert L. Weisgarber
 
Robert L. Weisgarber
  Vice President-Accounting and Controller (Principal Accounting Officer   November 14, 2005
 
/s/ Andrew L. Waite*
 
Andrew L. Waite
  Chairman of the Board   November 14, 2005
 
/s/ David C. Baldwin*
 
David C. Baldwin
  Director   November 14, 2005
 
/s/ Robert Boswell*
 
Robert Boswell
  Director   November 14, 2005

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Signature   Position   Date
         
 
/s/ Harold G. Hamm*
 
Harold G. Hamm
  Director   November 14, 2005
 
/s/ R. Graham Whaling*
 
R. Graham Whaling
  Director   November 14, 2005
 
/s/ James D. Woods*
 
James D. Woods
  Director   November 14, 2005
 
*By:   /s/ J. Michael Mayer
 
J. Michael Mayer
Pursuant to a Power of Attorney previously filed as Exhibit 24.1 to
this Registration Statement
       

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EXHIBIT INDEX
             
  1 .1     Form of Underwriting Agreement
  3 .1**     Form of Amended and Restated Certificate of Incorporation
  3 .2**     Form of Amended and Restated Bylaws
  4 .1     Specimen Stock Certificate representing common stock
  5 .1     Opinion of Vinson & Elkins L.L.P.
  10 .1*     Form of Indemnification Agreement
  10 .2**     Employment Agreement dated as of June 22, 2005 with Joseph C. Winkler
  10 .3     Amended and Restated Stockholders’ Agreement dated as of September 12, 2005 by and among Complete Production Services, Inc. and the stockholders listed therein
  10 .4**     Combination Agreement dated as of August 9, 2005, with Complete Energy Services, Inc., I.E. Miller Services, Inc. and Complete Energy Services, LLC and I.E. Miller Services, LLC
  10 .5*     Credit Agreement, dated as of September 12, 2005 by and among Complete Production Services, Inc., as U.S. Borrower, Integrated Production Services Ltd., as Canadian Borrower, Wells Fargo Bank, National Association, as U.S. Administrative Agent, U.S. Issuing Lender and US Swingline Lender, HSBC Bank Canada, as Canadian Administrative Agent, Canadian Issuing Lender and Canadian Swingline Lender, and the Lenders party thereto, Wells Fargo Bank, National Association as Sole Book Runner and Co-Lead Arranger, UBS Securities LLC, as Co-Lead Arranger and Syndication Agent and Amegy Bank N.A. and Comerica Bank, as Co-Documentation Agents
  10 .6*     Integrated Production Services, Inc. 2001 Stock Incentive Plan
  10 .7*     Complete Energy Services, Inc. 2003 Stock Incentive Plan
  10 .8*     First Amendment to the Complete Energy Services, Inc. 2003 Stock Incentive Plan
  10 .9*     Second Amendment to the Complete Energy Services, Inc. 2003 Stock Incentive Plan
  10 .10*     I.E. Miller Services, Inc. 2004 Stock Incentive Plan
  10 .11*     Amended and Restated Integrated Production Services and Parchman Energy Group, Inc. Stock Incentive Plan
  10 .12*     Strategic Customer Relationship Agreement, dated as of October 14, 2004, by and among Complete Energy Services, Inc., CES Mid-Continent Hamm, Inc. and Continental Resources, Inc.
  10 .13     Form of Non-Qualified Option Grant Agreement (Executive Officer)
  10 .14     Form of Non-Qualified Option Grant Agreement (Non-Employee Director)
  10 .15*     Form of Restricted Stock Grant Agreement (Employee)
  10 .16*     Form of Restricted Stock Agreement (Non-Employee Director)
  21 .1     Subsidiaries of Complete Production Services, Inc.
  23 .1*     Consent of Grant Thornton LLP
  23 .2*     Consent of KPMG LLP
  23 .3     Consent of Vinson & Elkins L.L.P. (contained in Exhibit 5.1)
  24 .1     Power of Attorney (included on signature page)
 
 *  Filed herewith
 
**  Filed previously
      Certain of the exhibits filed herewith contain representations and warranties made by us or our subsidiaries to other parties. The assertions embodied in those representations and warranties are in certain cases qualified by information in confidential disclosure schedules. While we do not believe that the disclosure schedules contain information that the securities laws require to be publicly disclosed, the disclosure schedules do contain information that modifies, qualifies and creates exceptions to the representations and warranties set forth in the applicable exhibits. Accordingly, you should not rely on the representations and warranties as characterizations of the actual state of facts, since they are modified by the underlying disclosure schedules. Moreover, information concerning the subject matter of the representations and warranties may have changed since the date of the applicable exhibit, which subsequent information may or may not be fully reflected in this registration statement.