10-KT 1 h54352e10vkt.htm FORM 10-KT - TRANSITION REPORT e10vkt
Table of Contents

 
UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
 
 
 
 
Form 10-KT
 
     
(Mark one)    
o
  ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
or
þ
  TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
    For the transition period from April 1, 2007 to December 31, 2007
 
Commission File Number: 1-8182
PIONEER DRILLING COMPANY
(Exact name of registrant as specified in its charter)
 
     
TEXAS   74-2088619
(State or other jurisdiction of
incorporation or organization)
  (I.R.S. Employer
Identification Number)
     
1250 N.E. Loop 410, Suite 1000
San Antonio, Texas
(Address of principal executive offices)
  78209
(Zip Code)
 
Registrant’s telephone number, including area code: (210) 828-7689
 
Securities registered pursuant to Section 12(b) of the Act:
 
     
Title of Each Class
 
Name of Each Exchange on Which Registered
 
Common Stock, $0.10 par value
  American Stock Exchange
 
Securities registered pursuant to Section 12(g) of the Act: None
 
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.  Yes o     No þ
 
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Exchange Act.  Yes o     No þ
 
Indicate by check mark whether the Registrant: (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.  Yes þ     No o
 
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-KT or any amendment to this Form 10-KT.  þ
 
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of “accelerated filer and large accelerated filer” in Rule 12b-2 of the Exchange Act. (Check one):
 
Large accelerated filer o  Accelerated filer þ  Non-accelerated filer o  Smaller reporting company o
 
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).  Yes o     No þ
 
The aggregate market value of the registrant’s common stock held by nonaffiliates of the registrant on the last business day of the registrant’s most recently completed second fiscal quarter (based on the closing sales price on the American Stock Exchange on September 30, 2007) was approximately $602,000,000.
 
As of February 8, 2008, there were 49,760,978 shares of common stock, par value $0.10 per share, of the registrant issued and outstanding.
 
DOCUMENTS INCORPORATED BY REFERENCE
 
Portions of the proxy statement related to the registrant’s 2008 Annual Meeting of Shareholders are incorporated by reference into Part III of this report.
 


 

 
TABLE OF CONTENTS
 
             
        Page
 
  Business     2  
  Risk Factors     11  
  Unresolved Staff Comments     18  
  Properties     19  
  Legal Proceedings     19  
  Submission of Matters to a Vote of Security Holders     19  
 
  Market for Registrant’s Common Equity, Related Shareholder Matters and Issuer Purchases of Equity Securities     20  
  Selected Financial Data     22  
  Management’s Discussion and Analysis of Financial Condition and Results of Operations     23  
  Quantitative and Qualitative Disclosures About Market Risk     40  
  Financial Statements and Supplementary Data     41  
  Changes in and Disagreements With Accountants on Accounting and Financial Disclosure     67  
  Controls and Procedures     67  
  Other Information     67  
 
  Directors, Executive Officers and Corporate Governance     68  
  Executive Compensation     68  
  Security Ownership of Certain Beneficial Owners and Management and Relate Shareholder Matters     68  
  Certain Relationships and Related Transactions, and Director Independence     68  
  Principal Accountant Fees and Services     68  
 
  Exhibits and Financial Statement Schedules     68  
 Subsidiaries
 Consent of Independent Registered Public Accounting Firm
 Certification of President & CEO Pursuant to Rule 13a-14(a)
 Certification of EVP & CFO Pursuant to Rule 13a-14(a)
 Certification of President & CEO Pursuant to Section 1350
 Certification of EVP & CFO Pursuant to Section 1350


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PART I
 
INTRODUCTORY NOTE
 
SPECIAL NOTE REGARDING FORWARD-LOOKING STATEMENTS
 
From time to time, our management or persons acting on our behalf make forward-looking statements to inform existing and potential security holders about our company. These statements may include projections and estimates concerning the timing and success of specific projects and our future backlog, revenues, income and capital spending. Forward-looking statements are generally accompanied by words such as “estimate,” “project,” “predict,” “believe,” “expect,” “anticipate,” “plan,” “intend,” “seek,” “will,” “should,” “goal” or other words that convey the uncertainty of future events or outcomes. These forward-looking statements speak only as of the date on which they are first made, which in the case of forward-looking statements made in this report is the date of this report. Sometimes we will specifically describe a statement as being a forward-looking statement and refer to this cautionary statement.
 
In addition, various statements that this Transition Report on Form 10-KT contains, including those that express a belief, expectation or intention, as well as those that are not statements of historical fact, are forward-looking statements. Those forward-looking statements appear in Item 1 — “Business” and Item 3 — “Legal Proceedings” in Part I of this report; in Item 5 — “Market for Registrant’s Common Equity, Related Shareholder Matters and Issuer Purchases of Equity Securities,” Item 7 — “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” Item 7A — “Quantitative and Qualitative Disclosures About Market Risk” and in the Notes to Consolidated Financial Statements we have included in Item 8 of Part II of this report; and elsewhere in this report. These forward-looking statements speak only as of the date of this report. We disclaim any obligation to update these statements, and we caution you not to rely on them unduly. We have based these forward-looking statements on our current expectations and assumptions about future events. While our management considers these expectations and assumptions to be reasonable, they are inherently subject to significant business, economic, competitive, regulatory and other risks, contingencies and uncertainties, most of which are difficult to predict and many of which are beyond our control. These risks, contingencies and uncertainties relate to, among other matters, the following:
 
  •  general economic and business conditions and industry trends;
 
  •  the continued strength of the contract land drilling industry in the geographic areas where we operate;
 
  •  levels and volatility of oil and gas prices;
 
  •  decisions about onshore exploration and development projects to be made by oil and gas companies;
 
  •  the highly competitive nature of our business;
 
  •  the supply of marketable drilling rigs within the industry;
 
  •  the success or failure of our acquisition strategy, including our ability to finance acquisitions and manage growth;
 
  •  the continued availability of drilling rig components;
 
  •  our future financial performance, including availability, terms and deployment of capital;
 
  •  the continued availability of qualified personnel; and
 
  •  changes in, or our failure or inability to comply with, governmental regulations, including those relating to the environment.
 
We believe the items we have outlined above are important factors that could cause our actual results to differ materially from those expressed in a forward-looking statement contained in this report or elsewhere. We have discussed many of these factors in more detail elsewhere in this report. These factors are not necessarily all the important factors that could affect us. Unpredictable or unknown factors we have not discussed in this report could also have material adverse effects on actual results of matters that are the subject


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of our forward-looking statements. We do not intend to update our description of important factors each time a potential important factor arises, except as required by applicable securities laws and regulations. We advise our security holders that they should (1) be aware that important factors not referred to above could affect the accuracy of our forward-looking statements and (2) use caution and common sense when considering our forward-looking statements. Also, please read the risk factors set forth in Item 1A — “Risk Factors.”
 
Item 1.   Business
 
In December 2007, our Board of Directors approved a change in our fiscal year end from March 31st to December 31st. The fiscal year end change was effective December 31, 2007 and resulted in a nine month reporting period from April 1, 2007 to December 31, 2007. We implemented the fiscal year end change to align our United States reporting period with the required Colombian statutory reporting period as well as the reporting periods of peer companies in the industry.
 
General
 
Pioneer Drilling Company provides contract land drilling services to independent and major oil and gas exploration and production companies. In addition to our drilling rigs, we provide the drilling crews and most of the ancillary equipment needed to operate our drilling rigs. We have focused our operations in select oil and natural gas production regions in the United States and Colombia. Our company was incorporated in 1979 as the successor to a business that had been operating since 1968. We conduct our operations in the United States through our principal operating subsidiary, Pioneer Drilling Services, Ltd. and we conduct our operations in Colombia through Pioneer de Colombia SDAD, Ltda, Surcusal Colombia. Our common stock trades on the American Stock Exchange under the symbol “PDC.”
 
Since September 1999, we have significantly expanded our fleet of drilling rigs through acquisitions, construction of new rigs and refurbishment of older rigs we acquired. The following table summarizes acquisitions in which we acquired rigs and related operations since September 1999:
 
                     
            Number of
 
Date
 
Acquisition(1)
  Market   Rigs Acquired  
 
September 1999
  Howell Drilling, Inc.      South Texas       2  
August 2000
  Pioneer Drilling Co.      South Texas       4  
March 2001
  Mustang Drilling, Ltd.      East Texas       4  
May 2002
  United Drilling Company     South Texas       2  
August 2003
  Texas Interstate Drilling Company, L. P.      North Texas       2  
March 2004
  Sawyer Drilling & Service, Inc.      East Texas       7  
March 2004
  SEDCO Drilling Co., Ltd.      North Texas       1  
November 2004
  Wolverine Drilling, Inc.      Rocky Mountains       7  
December 2004
  Allen Drilling Company     Western Oklahoma       5  
 
 
(1) The August 2000 acquisition of Pioneer Drilling Co. involved our acquisition of all the outstanding capital stock of that entity. Each other acquisition reflected in this table involved our acquisition of assets from the indicated entity.
 
During that same period, we also added 26 rigs to our fleet through construction of new rigs and construction of rigs from new and used components. In addition, during the year ended March 31, 2004, we acquired a rig that had been operating in Trinidad and integrated it into our operations in Texas, and during the nine months ended December 31, 2007, we acquired 3 rigs for international expansion. As of February 22, 2008, our rig fleet consisted of 67 operating drilling rigs, of which 27 are premium electric rigs that drill in depth ranges between 6,000 and 18,000 feet. Seventeen of our rigs are operating in our South Texas division, 20 are operating in our East Texas division, 10 are operating in our North Texas division, 6 are operating in our Western Oklahoma division, 11 are operating in our Rocky Mountain division consisting of locations in Utah and North Dakota and 3 are operating internationally in Colombia. Not included in our 67 operating rig


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count is a 1000 horsepower rig and a 1500 horsepower rig that we plan to deploy for further expansion into international markets.
 
We conduct our operations primarily in South, East and North Texas, western Oklahoma, North Louisiana, and the Rocky Mountains in the United States. We commenced international operations in Colombia during the nine months ended December 31, 2007 with 2 contracts for which we exported 2 drilling rigs to Colombia. Our customers remain primarily focused on drilling for natural gas. Substantially all the wells we drilled for our customers during the nine months ended December 31, 2007 were drilled in search of natural gas, except for wells we drilled using 5 rigs employed in search of oil in the Williston Basin of the Rocky Mountains and wells we drilled using 2 rigs employed in search of oil in Colombia.
 
For many years, the U.S. contract land drilling services industry has been characterized by an oversupply of drilling rigs and a large number of drilling contractors. Since 1996, however, there has been significant consolidation within the industry. We believe continued consolidation in the industry will generate more stability in dayrates, even during industry downturns. However, although consolidation in the industry is continuing, the industry is still highly fragmented and remains very competitive. For a discussion of market conditions in our industry, see “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Market Conditions in Our Industry” in Item 7 of Part II of this report. For information on our consolidated revenues and income from operations for the nine months ended December 31, 2007 and for the years ended March 31, 2007, and 2006 and our consolidated total assets as of December 31, 2007, March 31, 2007 and 2006, see our consolidated financial statements in this report.
 
Our Strategy
 
Our goal is to continue to build on our strong market position and reputation as a quality contract drilling company, diversify internationally and expand into other oilfield service sectors in a way that enhances shareholder value. We intend to accomplish this goal by:
 
  •  continuing to own and operate a high-quality fleet of land drilling rigs;
 
  •  continuing to acquire or construct high-quality rigs capable of generating our targeted returns on investment;
 
  •  continuing to expand into active natural gas drilling markets and diversifying into more crude oil drilling markets;
 
  •  expanding into international markets, beginning with Colombia;
 
  •  expanding into other sectors within the oilfield services industry that compliment our contract drilling business;
 
  •  positioning ourselves to maximize rig utilization and dayrates;
 
  •  training and maintaining high-quality, experienced crews; and
 
  •  maintaining an aggressive safety program.
 
We commenced international operations in Colombia with 2 contracts for which we exported 2 drilling rigs to Colombia that began operations in September 2007 and October 2007. We exported a third drilling rig to Colombia that began operating in February 2008. Our immediate international strategy is to continue our expansion in Colombia to include at least 5 drilling rigs by December 31, 2008 and continue to evaluate opportunities for expansion into other international markets.
 
On January 31, 2008, we entered into a definitive purchase agreement to acquire WEDGE Well Services, L.L.C., WEDGE Wireline, Inc. and WEDGE Fishing and Rental Services, L.L.C. (the “WEDGE Companies”) from affiliates of WEDGE Group Incorporated for $303 million. The WEDGE Companies provide oil and gas well workover, wireline, and fishing and rental services for energy producers in the United States. We expect to finance the acquisition through a combination of existing cash and a new, 5 year, senior revolving credit facility of up to $350 million led by Wells Fargo Bank, N.A. and Fortis Merchant Banking. The closing of the


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acquisition, which is expected before March 31, 2008, is subject to obtaining certain regulatory approvals, our receipt of financing and other customary closing conditions.
 
Drilling Equipment
 
General
 
A land drilling rig consists of engines, a hoisting system, a rotating system, pumps and related equipment to circulate drilling fluid, blowout preventers and related equipment.
 
Diesel or gas engines are typically the main power sources for a drilling rig. Power requirements for drilling jobs may vary considerably, but most land drilling rigs employ two or more engines to generate between 500 and 2,000 horsepower, depending on well depth and rig design. Most drilling rigs capable of drilling in deep formations, involving depths greater than 15,000 feet, use diesel-electric power units to generate and deliver electric current through cables to electrical switch gears, then to direct-current electric motors attached to the equipment in the hoisting, rotating and circulating systems.
 
Drilling rigs use long strings of drill pipe and drill collars to drill wells. Drilling rigs are also used to set heavy strings of large-diameter pipe, or casing, inside the borehole. Because the total weight of the drill string and the casing can exceed 500,000 pounds, drilling rigs require significant hoisting and braking capacities. Generally, a drilling rig’s hoisting system is made up of a mast, or derrick, a traveling block and hook assembly that attaches to the rotating system, a mechanism known as the drawworks, a drilling line and ancillary equipment. The drawworks mechanism consists of a revolving drum, around which the drilling line is wound, and a series of shafts, clutches and chain and gear drives for generating speed changes and reverse motion. The drawworks also houses the main brake, which has the capacity to stop and sustain the weights used in the drilling process. When heavy loads are being lowered, a hydraulic or electric auxiliary brake assists the main brake to absorb the great amount of energy developed by the mass of the traveling block, hook assembly, drill pipe, drill collars and drill bit or casing being lowered into the well.
 
The rotating equipment from top to bottom consists of a swivel, the kelly bushing, the kelly, the rotary table, drill pipe, drill collars and the drill bit. We refer to the equipment between the swivel and the drill bit as the drill stem. The swivel assembly sustains the weight of the drill stem, permits its rotation and affords a rotating pressure seal and passageway for circulating drilling fluid into the top of the drill string. The swivel also has a large handle that fits inside the hook assembly at the bottom of the traveling block. Drilling fluid enters the drill stem through a hose, called the rotary hose, attached to the side of the swivel. The kelly is a triangular, square or hexagonal piece of pipe, usually 40 feet long, that transmits torque from the rotary table to the drill stem and permits its vertical movement as it is lowered into the hole. The bottom end of the kelly fits inside a corresponding triangular, square or hexagonal opening in a device called the kelly bushing. The kelly bushing, in turn, fits into a part of the rotary table called the master bushing. As the master bushing rotates, the kelly bushing also rotates, turning the kelly, which rotates the drill pipe and thus the drill bit. Drilling fluid is pumped through the kelly on its way to the bottom. The rotary table, equipped with its master bushing and kelly bushing, supplies the necessary torque to turn the drill stem. The drill pipe and drill collars are both steel tubes through which drilling fluid can be pumped. Drill pipe, sometimes called drill string, comes in 30-foot sections, or joints, with threaded sections on each end. Drill collars are heavier than drill pipe and are also threaded on the ends. Collars are used on the bottom of the drill stem to apply weight to the drilling bit. At the end of the drill stem is the bit, which chews up the formation rock and dislodges it so that drilling fluid can circulate the fragmented material back up to the surface where the circulating system filters it out of the fluid.
 
Drilling fluid, often called mud, is a mixture of clays, chemicals and water or oil, which is carefully formulated for the particular well being drilled. Drilling mud accounts for a major portion of the cost incurred and equipment used in drilling a well. Bulk storage of drilling fluid materials, the pumps and the mud-mixing equipment are placed at the start of the circulating system. Working mud pits and reserve storage are at the other end of the system. Between these two points, the circulating system includes auxiliary equipment for drilling fluid maintenance and equipment for well pressure control. Within the system, the drilling mud is typically routed from the mud pits to the mud pump and from the mud pump through a standpipe and the


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rotary hose to the drill stem. The drilling mud travels down the drill stem to the bit, up the annular space between the drill stem and the borehole and through the blowout preventer stack to the return flow line. It then travels to a shale shaker for removal of rock cuttings, and then back to the mud pits, which are usually steel tanks. The reserve pits, usually one or two fairly shallow excavations, are used for waste material and excess water around the location.
 
There are numerous factors that differentiate land drilling rigs, including their power generation systems and their drilling depth capabilities. The actual drilling depth capability of a rig may be less than or more than its rated depth capability due to numerous factors, including the size, weight and amount of the drill pipe on the rig. The intended well depth and the drill site conditions determine the amount of drill pipe and other equipment needed to drill a well. Generally, land rigs operate with crews of five to six persons.
 
Our Fleet of Drilling Rigs
 
As of February 22, 2008, our rig fleet consists of 67 operating drilling rigs. Not included in our 67 operating rig count is a 1000 horsepower rig and a 1500 horsepower rig that we plan to deploy for further expansion into international markets. We own all the rigs in our fleet. The following table sets forth information regarding utilization for our fleet of operating drilling rigs:
 
                                                 
    Nine Months
                               
    Ended
                               
    December 31,
    Years Ended March 31,  
    2007     2007     2006     2005     2004     2003  
 
Average number of operating rigs for the period
    66.6       60.8       52.3       40.1       27.3       22.3  
Average utilization rate
    89 %     95 %     95 %     96 %     88 %     79 %
 
We believe that our drilling rigs and other related equipment are in good operating condition. Our employees perform periodic maintenance and minor repair work on our drilling rigs. We rely on various oilfield service companies for major repair work and overhaul of our drilling equipment when needed. We also engage in periodic improvement of our drilling equipment. In the event of major breakdowns or mechanical problems, our rigs could be subject to significant idle time and a resulting loss of revenue if the necessary repair services are not immediately available.
 
As of February 22, 2008, we owned a fleet of 75 trucks and related transportation equipment that we use to transport our drilling rigs to and from drilling sites. By owning our own trucks, we reduce the cost of rig moves and reduce downtime between rig moves.
 
Drilling Contracts
 
As a provider of contract land drilling services, our business and the profitability of our operations depend on the level of drilling activity by oil and gas exploration and production companies operating in the geographic markets where we operate. The oil and gas exploration and production industry is a historically cyclical industry characterized by significant changes in the levels of exploration and development activities. During periods of lower levels of drilling activity or excess rig capacity, price competition tends to increase and results in decreases in the profitability of daywork contracts. In this competitive price environment, we may be more inclined to enter into turnkey and footage contracts that expose us to greater risk of loss without commensurate increases in potential contract profitability.
 
We obtain our contracts for drilling oil and gas wells either through competitive bidding or through direct negotiations with customers. Our drilling contracts generally provide for compensation on either a daywork, turnkey or footage basis. The contract terms we offer generally depend on the complexity and risk of operations, the on-site drilling conditions, the type of equipment used and the anticipated duration of the work to be performed. Generally, our contracts provide for the drilling of a single well and typically permit the customer to terminate on short notice.


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The following table presents, by type of contract, information about the total number of wells we completed for our customers during each of the last three fiscal years.
 
                         
    Nine Months
       
    Ended
       
    December 31,
  Year Ended March 31,
    2007   2007   2006
 
Daywork
    606       742       565  
Turnkey
    5       2       19  
Footage
    66       60       106  
                         
Total number of wells
    677       804       690  
                         
 
Daywork Contracts.  Under daywork drilling contracts, we provide a drilling rig with required personnel to our customer who supervises the drilling of the well. We are paid based on a negotiated fixed rate per day while the rig is used. Daywork drilling contracts specify the equipment to be used, the size of the hole and the depth of the well. Under a daywork drilling contract, the customer bears a large portion of the out-of-pocket drilling costs and we generally bear no part of the usual risks associated with drilling, such as time delays and unanticipated costs.
 
Turnkey Contracts.  Under a turnkey contract, we agree to drill a well for our customer to a specified depth and under specified conditions for a fixed price, regardless of the time required or the problems encountered in drilling the well. We provide technical expertise and engineering services, as well as most of the equipment and drilling supplies required to drill the well. We often subcontract for related services, such as the provision of casing crews, cementing and well logging. Under typical turnkey drilling arrangements, we do not receive progress payments and are paid by our customer only after we have performed the terms of the drilling contract in full.
 
The risks to us under a turnkey contract are substantially greater than on a well drilled on a daywork basis. This is primarily because under a turnkey contract we assume most of the risks associated with drilling operations generally assumed by the operator in a daywork contract, including the risk of blowout, loss of hole, stuck drill pipe, machinery breakdowns, abnormal drilling conditions and risks associated with subcontractors’ services, supplies, cost escalations and personnel. We employ or contract for engineering expertise to analyze seismic, geologic and drilling data to identify and reduce some of the drilling risks we assume. We use the results of this analysis to evaluate the risks of a proposed contract and seek to account for such risks in our bid preparation. We believe that our operating experience, qualified drilling personnel, risk management program, internal engineering expertise and access to proficient third-party engineering contractors have allowed us to reduce some of the risks inherent in turnkey drilling operations. We also maintain insurance coverage against some, but not all, drilling hazards. However, the occurrence of uninsured or under-insured losses or operating cost overruns on our turnkey jobs could have a material adverse effect on our financial position and results of operations.
 
Footage Contracts.  Under footage contracts, we are paid a fixed amount for each foot drilled, regardless of the time required or the problems encountered in drilling the well. We typically pay more of the out-of-pocket costs associated with footage contracts as compared to daywork contracts. Similar to a turnkey contract, the risks to us on a footage contract are greater because we assume most of the risks associated with drilling operations generally assumed by the operator in a daywork contract, including loss of hole, stuck drill pipe, machinery breakdowns, abnormal drilling conditions and risks associated with subcontractors’ services, supplies, cost escalation and personnel. As with turnkey contracts, we manage this additional risk through the use of engineering expertise and bid the footage contracts accordingly, and we maintain insurance coverage against some, but not all, drilling hazards. However, the occurrence of uninsured or under-insured losses or operating cost overruns on our footage jobs could have a material adverse effect on our financial position and results of operations.


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Customers and Marketing
 
We market our rigs to a number of customers. During the nine months ended December 31, 2007, we drilled wells for 90 different customers, compared to 92 customers during the fiscal year ended March 31, 2007 and 128 customers during the fiscal year ended March 31, 2006. The following table shows our three largest customers as a percentage of our total contract drilling revenue for each of our last three fiscal years.
 
         
    Total Contract Drilling
Customer
  Revenue Percentage
 
Nine Months Ended December 31, 2007:
       
EOG Resources, Inc. 
    13.1 %
Anadarko Petroleum Corporation(1)
    8.8 %
Chesapeake Operating Inc. 
    7.7 %
         
Fiscal Year Ended March 31, 2007:
       
EOG Resources, Inc. 
    9.7 %
Chesapeake Operating Inc. 
    9.1 %
Anadarko Petroleum Corporation(1)
    6.1 %
         
Fiscal Year Ended March 31, 2006:
       
Chesapeake Operating Inc. 
    10.1 %
Kerr-McGee Oil & Gas(1)
    6.1 %
Chinn Exploration
    4.4 %
 
 
(1) Anadarko Petroleum Corporation acquired Kerr-McGee Oil and Gas in the year ended March 31, 2007.
 
We primarily market our drilling rigs through employee marketing representatives. These marketing representatives use personal contacts and industry periodicals and publications to determine which operators are planning to drill oil and gas wells in the near future in our market areas. Once we have been placed on the “bid list” for an operator, we will typically be given the opportunity to bid on most future wells for that operator in the areas in which we operate. Our rigs are typically contracted on a well-by-well basis.
 
We can also enter into term contracts with our customers to provide drilling rigs for future periods at specified rates plus fuel and mobilization charges, if applicable, and escalation provisions. This practice is customary in the contract land drilling services business during times of tightening rig supply or when building new rigs. As demand for drilling rigs improved during calendar year 2005 and 2006, we entered into more longer-term drilling contracts. As of February 8, 2008, we had 19 contracts with terms of 6 months to 3 years in duration, of which 9 will expire by August 9, 2008, 6 have a remaining term of 6 to 12 months, 2 have a remaining term of 12 to 18 months and 2 have a remaining term in excess of 18 months. Due to the current excess supply of drilling rigs within our industry, some of these term contracts may not be renewed when the initial contract period expires.
 
Prior to our international expansion into Colombia during the nine months ended December 31, 2007, we earned all of our revenue from contract drilling services performed in the United States. As of December 31, 2007, we operated 2 drilling rigs in Colombia. We intend to continue expanding operations in Colombia and other international markets. For the nine months ended December 31, 2007, 3% of our revenue was generated from our operations in Colombia.
 
Competition
 
We encounter substantial competition from other drilling contractors. Our primary market areas are highly fragmented and competitive. The fact that drilling rigs are mobile and can be moved from one market to another in response to market conditions heightens the competition in the industry.
 
The drilling contracts we compete for are usually awarded on the basis of competitive bids. Our principal competitors are Helmerich & Payne, Inc., Grey Wolf, Inc., Patterson-UTI Energy, Inc., Nabors Industries, Inc.


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and Unit Corp. In addition to pricing and rig availability, we believe the following factors are also important to our customers in determining which drilling contractors to select:
 
  •  the type and condition of each of the competing drilling rigs;
 
  •  the mobility and efficiency of the rigs;
 
  •  the quality of service and experience of the rig crews;
 
  •  the safety records of the rigs;
 
  •  the offering of ancillary services; and
 
  •  the ability to provide drilling equipment adaptable to, and personnel familiar with, new technologies and drilling techniques.
 
While we must be competitive in our pricing, our competitive strategy generally emphasizes the quality of our equipment, the safety record of our rigs and the experience of our rig crews to differentiate us from our competitors.
 
Contract drilling companies compete primarily on a regional basis, and the intensity of competition may vary significantly from region to region at any particular time. If demand for drilling services improves in a region where we operate, our competitors might respond by moving in suitable rigs from other regions. An influx of rigs from other regions could rapidly intensify competition and make any improvement in demand for drilling rigs in a particular region short-lived.
 
Many of our competitors have greater financial, technical and other resources than we do. Their greater capabilities in these areas may enable them to:
 
  •  better withstand industry downturns;
 
  •  compete more effectively on the basis of price and technology;
 
  •  better retain skilled rig personnel; and
 
  •  build new rigs or acquire and refurbish existing rigs so as to be able to place rigs into service more quickly than us in periods of high drilling demand.
 
Raw Materials
 
The materials and supplies we use in our drilling operations include fuels to operate our drilling equipment, drilling mud, drill pipe, drill collars, drill bits and cement. We do not rely on a single source of supply for any of these items. While we are not currently experiencing any shortages, from time to time there have been shortages of drilling equipment and supplies during periods of high demand. Shortages could result in increased prices for drilling equipment or supplies that we may be unable to pass on to customers. In addition, during periods of shortages, the delivery times for equipment and supplies can be substantially longer. Any significant delays in our obtaining drilling equipment or supplies could limit drilling operations and jeopardize our relations with customers. In addition, shortages of drilling equipment or supplies could delay and adversely affect our ability to obtain new contracts for our rigs, which could have a material adverse effect on our financial condition and results of operations.
 
Operating Risks and Insurance
 
Our operations are subject to the many hazards inherent in the contract land drilling business, including the risks of:
 
  •  blowouts;
 
  •  fires and explosions;
 
  •  loss of well control;


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  •  collapse of the borehole;
 
  •  lost or stuck drill strings; and
 
  •  damage or loss from natural disasters.
 
Any of these hazards can result in substantial liabilities or losses to us from, among other things:
 
  •  suspension of drilling operations;
 
  •  damage to, or destruction of, our property and equipment and that of others;
 
  •  personal injury and loss of life;
 
  •  damage to producing or potentially productive oil and gas formations through which we drill; and
 
  •  environmental damage.
 
We seek to protect ourselves from some but not all operating hazards through insurance coverage. However, some risks are either not insurable or insurance is available only at rates that we consider uneconomical. Those risks include pollution liability in excess of relatively low limits. Depending on competitive conditions and other factors, we attempt to obtain contractual protection against uninsured operating risks from our customers. However, customers who provide contractual indemnification protection may not in all cases maintain adequate insurance to support their indemnification obligations. We can offer no assurance that our insurance or indemnification arrangements will adequately protect us against liability or loss from all the hazards of our operations. The occurrence of a significant event that we have not fully insured or indemnified against or the failure of a customer to meet its indemnification obligations to us could materially and adversely affect our results of operations and financial condition. Furthermore, we may not be able to maintain adequate insurance in the future at rates we consider reasonable.
 
Our current insurance coverage includes property insurance on our rigs, drilling equipment and real property. Our insurance coverage for property damage to our rigs and to our drilling equipment is based on our estimates of the cost of comparable used equipment to replace the insured property. The policy provides for a deductible on rigs of $250,000 per occurrence ($500,000 deductible for rigs with an insured value greater than $10 million). Our third-party liability insurance coverage is $51 million per occurrence and in the aggregate, with a deductible of $260,000 per occurrence. We believe that we are adequately insured for public liability and property damage to others with respect to our operations. However, such insurance may not be sufficient to protect us against liability for all consequences of well disasters, extensive fire damage or damage to the environment.
 
In addition, we generally carry insurance coverage to protect against certain hazards inherent in our turnkey contract drilling operations. This insurance covers “control-of-well,” including blowouts above and below the surface, redrilling, seepage and pollution. This policy provides coverage of $3 million, $5 million, $10 million, $15 million or $20 million depending on the area in which the well is drilled and its target depth, subject to a deductible of the greater of 15% of the well’s anticipated dry hole cost or $150,000. This policy also provides care, custody and control insurance, with a limit of $1 million, subject to a $100,000 deductible.
 
Employees
 
We currently have approximately 1,750 employees. Approximately 285 of these employees are salaried administrative or supervisory employees. The rest of our employees are hourly employees who operate or maintain our drilling rigs and rig-hauling trucks. The number of hourly employees fluctuates depending on the number of drilling projects we are engaged in at any particular time. None of our employment arrangements are subject to collective bargaining arrangements.
 
Our operations require the services of employees having the technical training and experience necessary to obtain proper operational standards. As a result, our operations depend, to a considerable extent, on the continuing availability of such personnel. Although we have not encountered material difficulty in hiring and retaining qualified rig crews, shortages of qualified personnel are occurring in our industry. If we should suffer


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any material loss of personnel to competitors or be unable to employ additional or replacement personnel with the requisite level of training and experience to adequately operate our equipment, our operations could be materially and adversely affected. While we believe our wage rates are competitive and our relationships with our employees are satisfactory, a significant increase in the wages paid by other employers could result in a reduction in our workforce, increases in wage rates, or both. The occurrence of either of these events for a significant period of time could have a material and adverse effect on our financial condition and results of operations.
 
Facilities
 
We own:
 
  •  a 15-acre division office, rig storage and maintenance yard in Corpus Christi, Texas;
 
  •  a 6-acre division office, storage and maintenance yard in Henderson, Texas;
 
  •  a 4-acre trucking department office, storage and maintenance yard in Kilgore, Texas;
 
  •  a 17-acre rig storage and maintenance yard in Woodward, Oklahoma;
 
  •  a 10-acre division office, rig storage and maintenance yard in Williston, North Dakota;
 
  •  a 5-acre division office, storage and maintenance yard in Paradise, Texas; and
 
  •  a 5-acre trucking department office, storage and maintenance yard in Springtown, Texas.
 
We lease:
 
  •  our corporate office facilities, at a cost escalating from $10,880 per month to $18,805 per month over 102 months, pursuant to a lease extending through December 2013;
 
  •  a trucking department office, storage and maintenance yard in Alice, Texas, at a cost of $5,200 per month, pursuant to a lease extending through July 2009;
 
  •  a 2.2-acre division office and storage yard in Vernal, Utah, at a cost escalating from $6,300 per month to $6,615 per month, pursuant to a lease extending through November 2009; and
 
  •  a marketing office in Denver Colorado, at a cost escalating from $1,092 to $1,217 per month, pursuant to a lease extending through June 2010.
 
Governmental Regulation
 
Our operations are subject to stringent laws and regulations relating to containment, disposal and controlling the discharge of hazardous oilfield waste and other non-hazardous waste material into the environment, requiring removal and cleanup under certain circumstances, or otherwise relating to the protection of the environment. In addition, our operations are often conducted in or near ecologically sensitive areas, such as wetlands, which are subject to special protective measures and which may expose us to additional operating costs and liabilities for accidental discharges of oil, natural gas, drilling fluids or contaminated water, or for noncompliance with other aspects of applicable laws. We are also subject to the requirements of the federal Occupational Safety and Health Act (“OSHA”) and comparable state statutes. The OSHA hazard communication standard, the Environmental Protection Agency “community right-to-know” regulations under Title III of the Federal Superfund Amendment and Reauthorization Act and comparable state statutes require us to organize and report information about the hazardous materials we use in our operations to employees, state and local government authorities and local citizens.
 
Environmental laws and regulations are complex and subject to frequent change. In some cases, they can impose liability for the entire cost of cleanup on any responsible party, without regard to negligence or fault, and can impose liability on us for the conduct of others or conditions others have caused, or for our acts that complied with all applicable requirements when we performed them. We may also be exposed to environmental or other liabilities originating from businesses and assets that we purchased from others. Compliance with


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applicable environmental laws and regulations has not, to date, materially affected our capital expenditures, earnings or competitive position, although compliance measures have added to our costs of operating drilling equipment in some instances. We do not expect to incur material capital expenditures in our next fiscal year in order to comply with current environment control regulations. However, our compliance with amended, new or more stringent requirements, stricter interpretations of existing requirements or the future discovery of contamination may require us to make material expenditures or subject us to liabilities that we currently do not anticipate.
 
In addition, our business depends on the demand for land drilling services from the oil and gas industry and, therefore, is affected by tax, environmental and other laws relating to the oil and gas industry generally, by changes in those laws and by changes in related administrative regulations. It is possible that these laws and regulations may in the future add significantly to our operating costs or those of our customers, or otherwise directly or indirectly affect our operations.
 
Available Information
 
Our Web site address is www.pioneerdrlg.com. We make available on this Web site under “Investor Relations-SEC Filings,” free of charge, our annual reports on Form 10-K, this transition report on Form 10-KT, quarterly reports on Form 10-Q, current reports on Form 8-K and amendments to those reports as soon as reasonably practicable after we electronically file those materials with, or furnish those materials to, the Securities and Exchange Commission. In addition, the Securities and Exchange Commission maintains an Internet site at www.sec.gov that contains reports, proxy and information statements and other information regarding issuers that file electronically. We have also posted on our Web site our: Charters for the Audit, Compensation, and Nominating and Corporate Governance Committees of our Board; Code of Conduct and Ethics; Rules of Conduct; and Company Contact Information.
 
Item 1A.   Risk Factors
 
We are including the following discussion to inform our existing and potential security holders generally of some of the risks and uncertainties that can affect our company and to take advantage of the “safe harbor” protection for forward-looking statements that applicable federal securities law affords. Additional information regarding forward-looking statements appears in the “Introductory Note” in Part I of this report.
 
Set forth below are various risks and uncertainties that could adversely impact our business, financial condition, results of operations and cash flows.
 
Risks Relating to the Oil and Gas Industry
 
We derive all our revenues from companies in the oil and gas exploration and production industry, a historically cyclical industry with levels of activity that are significantly affected by the levels and volatility of oil and gas prices.
 
As a provider of contract land drilling services, our business depends on the level of drilling activity by oil and gas exploration and production companies operating in the geographic markets where we operate. The oil and gas exploration and production industry is a historically cyclical industry characterized by significant changes in the levels of exploration and development activities. Oil and gas prices, and market expectations of potential changes in those prices, significantly affect the levels of those activities. Worldwide political, economic, natural disaster and military events have contributed to oil and gas price volatility and are likely to continue to do so in the future. Any prolonged reduction in the overall level of exploration and development activities, whether resulting from changes in oil and gas prices or otherwise, can materially and adversely affect us in many ways by negatively impacting:
 
  •  our revenues, cash flows and profitability;
 
  •  the fair market value of our rig fleet;
 
  •  our ability to maintain or increase our borrowing capacity;


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  •  our ability to obtain additional capital to finance our business and make acquisitions, and the cost of that capital; and
 
  •  our ability to retain skilled rig personnel whom we would need in the event of an upturn in the demand for our services.
 
Depending on the market prices of oil and gas, oil and gas exploration and production companies may cancel or curtail their drilling programs, thereby reducing demand for our services. Oil and gas prices have been volatile historically and, we believe, will continue to be so in the future. Many factors beyond our control affect oil and gas prices, including:
 
  •  the cost of exploring for, producing and delivering oil and gas;
 
  •  the discovery rate of new oil and gas reserves;
 
  •  the rate of decline of existing and new oil and gas reserves;
 
  •  available pipeline and other oil and gas transportation capacity;
 
  •  the ability of oil and gas companies to raise capital;
 
  •  economic conditions in the United States and elsewhere;
 
  •  actions by OPEC, the Organization of Petroleum Exporting Countries;
 
  •  political instability in the Middle East and other major oil and gas producing regions;
 
  •  governmental regulations, both domestic and foreign;
 
  •  domestic and foreign tax policy;
 
  •  weather conditions in the United States and elsewhere;
 
  •  the pace adopted by foreign governments for the exploration, development and production of their national reserves;
 
  •  the price of foreign imports of oil and gas; and
 
  •  the overall supply and demand for oil and gas.
 
Risks Relating to Our Business
 
Reduced demand for or excess capacity of drilling rigs can adversely affect our profitability.
 
Our profitability in the future will depend on many factors, but largely on utilization rates and dayrates for our drilling rigs. A reduction in the demand for drilling rigs or an increase in the supply of drilling rigs, whether through new construction or refurbishment, could decrease our dayrates and utilization rates, which would adversely affect our revenues and profitability.
 
Our acquisition strategy exposes us to various risks, including those relating to difficulties in identifying suitable acquisition opportunities and integrating businesses, assets and personnel, as well as difficulties in obtaining financing for targeted acquisitions and the potential for increased leverage or debt service requirements.
 
As a key component of our business strategy, we have pursued and intend to continue to pursue acquisitions of complementary assets and businesses. For example, since March 31, 2003, our rig fleet has increased from 24 to 69 drilling rigs, primarily as a result of acquisitions. Acquisitions involve numerous inherent risks, including:
 
  •  unanticipated costs and assumption of liabilities and exposure to unforeseen liabilities of acquired businesses, including environmental liabilities;
 
  •  difficulties in integrating the operations and assets of the acquired business and the acquired personnel;


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  •  limitations on our ability to properly assess and maintain an effective internal control environment over an acquired business, in order to comply with applicable periodic reporting requirements;
 
  •  potential losses of key employees and customers of the acquired businesses;
 
  •  risks of entering markets in which we have limited prior experience; and
 
  •  increases in our expenses and working capital requirements.
 
The process of integrating an acquired business may involve unforeseen costs and delays or other operational, technical and financial difficulties that may require a disproportionate amount of management attention and financial and other resources. Possible future acquisitions may be for purchase prices significantly higher than those we paid for previous acquisitions. We may be unable to continue to identify additional suitable acquisition opportunities, negotiate acceptable terms, obtain financing for acquisitions on satisfactory terms or successfully acquire identified targets. Our failure to achieve consolidation savings, to incorporate the acquired businesses and assets into our existing operations successfully or to minimize any unforeseen operational difficulties could have a material adverse effect on our financial condition and results of operations.
 
In addition, we may not have sufficient capital resources to complete additional acquisitions. Historically, we have funded the growth of our rig fleet through a combination of debt and equity financing. We may incur substantial additional indebtedness to finance future acquisitions and also may issue equity securities or convertible securities in connection with such acquisitions. Debt service requirements could represent a significant burden on our results of operations and financial condition and the issuance of additional equity or convertible securities could be dilutive to our existing shareholders. Furthermore, we may not be able to obtain additional financing on satisfactory terms.
 
Even if we have access to the necessary capital, we may be unable to continue to identify additional suitable acquisition opportunities, negotiate acceptable terms or successfully acquire identified targets.
 
Our strategy of constructing drilling rigs during periods of peak demand requires that we maintain an adequate supply of drilling rig components to complete our rig building program. Our suppliers may be unable to continue providing us the needed drilling rig components if their manufacturing sources are unable to fulfill their commitments.
 
We operate in a highly competitive, fragmented industry in which price competition could reduce our profitability.
 
We encounter substantial competition from other drilling contractors. Our primary market areas are highly fragmented and competitive. The fact that drilling rigs are mobile and can be moved from one market to another in response to market conditions heightens the competition in the industry.
 
The drilling contracts we compete for are usually awarded on the basis of competitive bids. In addition to pricing and rig availability, we believe the following factors are also important to our customers in determining which drilling contractor to select:
 
  •  the type and condition of each of the competing drilling rigs;
 
  •  the mobility and efficiency of the rigs;
 
  •  the quality of service and experience of the rig crews;
 
  •  the safety records of the rigs;
 
  •  the offering of ancillary services; and
 
  •  the ability to provide drilling equipment adaptable to, and personnel familiar with, new technologies and drilling techniques.
 
While we must be competitive in our pricing, our competitive strategy generally emphasizes the quality of our equipment, the safety record of our rigs and the quality of service and experience of our rig crews to


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differentiate us from our competitors. This strategy is less effective as lower demand for drilling services or an oversupply of drilling rigs intensifies price competition and makes it more difficult for us to compete on the basis of factors other than price. In all of the markets in which we compete, an oversupply of rigs can cause greater price competition, which can reduce our profitability.
 
Contract drilling companies compete primarily on a regional basis, and the intensity of competition may vary significantly from region to region at any particular time. If demand for drilling services improves in a region where we operate, our competitors might respond by moving in suitable rigs from other regions. An influx of rigs from other regions could rapidly intensify competition and reduce profitability and make any improvement in demand for drilling rigs short-lived.
 
We face competition from many competitors with greater resources.
 
Many of our competitors have greater financial, technical and other resources than we do. Their greater capabilities in these areas may enable them to:
 
  •  better withstand industry downturns;
 
  •  compete more effectively on the basis of price and technology;
 
  •  retain skilled rig personnel; and
 
  •  build new rigs or acquire and refurbish existing rigs so as to be able to place rigs into service more quickly than us in periods of high drilling demand.
 
Unexpected cost overruns on our turnkey drilling jobs and our footage contracts could adversely affect our financial position and our results of operations.
 
We have historically derived a significant portion of our revenues from turnkey drilling contracts, and turnkey contracts may represent a significant component of our future revenues. The occurrence of uninsured or under-insured losses or operating cost overruns on our turnkey jobs could have a material adverse effect on our financial position and results of operations. Under a typical turnkey drilling contract, we agree to drill a well for our customer to a specified depth and under specified conditions for a fixed price. We provide technical expertise and engineering services, as well as most of the equipment and drilling supplies required to drill the well. We often subcontract for related services, such as the provision of casing crews, cementing and well logging. Under typical turnkey drilling arrangements, we do not receive progress payments and are paid by our customer only after we have performed the terms of the drilling contract in full. For these reasons, the risk to us under a turnkey drilling contract is substantially greater than for a well drilled on a daywork basis, because we must assume most of the risks associated with drilling operations that the operator generally assumes under a daywork contract, including the risks of blowout, loss of hole, stuck drill pipe, machinery breakdowns, abnormal drilling conditions and risks associated with subcontractors’ services, supplies, cost escalations and personnel. Similar to our turnkey contracts, under a footage contract we assume most of the risks associated with drilling operations that the operator generally assumes under a daywork contract.
 
Although we attempt to obtain insurance coverage to reduce certain of the risks inherent in our turnkey drilling operations, adequate coverage may be unavailable in the future and we might have to bear the full cost of such risks, which could have an adverse effect on our financial condition and results of operations.
 
Our operations involve operating hazards, which, if not insured or indemnified against, could adversely affect our results of operations and financial condition.
 
Our operations are subject to the many hazards inherent in the contract land drilling business, including the risks of:
 
  •  blowouts;
 
  •  fires and explosions;
 
  •  loss of well control;


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  •  collapse of the borehole;
 
  •  lost or stuck drill strings; and
 
  •  damage or loss from natural disasters. Any of these hazards can result in substantial liabilities or losses to us from, among other things:
 
  •  suspension of drilling operations;
 
  •  damage to, or destruction of, our property and equipment and that of others;
 
  •  personal injury and loss of life;
 
  •  damage to producing or potentially productive oil and gas formations through which we drill; and
 
  •  environmental damage.
 
We seek to protect ourselves from some but not all operating hazards through insurance coverage. However, some risks are either not insurable or insurance is available only at rates that we consider uneconomical. Those risks include pollution liability in excess of relatively low limits. Depending on competitive conditions and other factors, we attempt to obtain contractual protection against uninsured operating risks from our customers. However, customers who provide contractual indemnification protection may not in all cases maintain adequate insurance to support their indemnification obligations. Our insurance or indemnification arrangements may not adequately protect us against liability or loss from all the hazards of our operations. The occurrence of a significant event that we have not fully insured or indemnified against or the failure of a customer to meet its indemnification obligations to us could materially and adversely affect our results of operations and financial condition. Furthermore, we may be unable to maintain adequate insurance in the future at rates we consider reasonable.
 
We face increased exposure to operating difficulties because we primarily focus on drilling for natural gas.
 
Most of our drilling contracts are with exploration and production companies in search of natural gas. Drilling on land for natural gas generally occurs at deeper drilling depths than drilling for oil. Although deep-depth drilling exposes us to risks similar to risks encountered in shallow-depth drilling, the magnitude of the risk for deep-depth drilling is greater because of the higher costs and greater complexities involved in drilling deep wells. We generally do not insure risks related to operating difficulties other than blowouts. If we do not adequately insure the increased risk from blowouts or if our contractual indemnification rights are insufficient or unfulfilled, our profitability and other results of operations and our financial condition could be adversely affected in the event we encounter blowouts or other significant operating difficulties while drilling at deeper depths.
 
Our current primary focus on drilling for natural gas could place us at a competitive disadvantage if we were to change our primary focus to drilling for oil.
 
Our rig fleet consists of rigs capable of drilling on land at drilling depths of 6,000 to 18,000 feet because most of our contracts are with customers drilling in search of natural gas, which generally occurs at deeper drilling depths than drilling in search of oil, which often occurs at drilling depths less than 6,000 feet. Generally, larger drilling rigs capable of deep drilling generally incur higher mobilization costs than smaller drilling rigs drilling at shallower depths. If our primary focus shifts from drilling for customers in search of natural gas to drilling for customers in search of oil, the majority of our rig fleet would be disadvantaged in competing for new oil drilling projects as compared to competitors that primarily use shallower drilling depth rigs when drilling in search of oil.


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Our international operations are subject to political, economic and other uncertainties not encountered in our domestic operations.
 
As we continue to implement our strategy of expanding into areas outside the United States, our international operations will be subject to political, economic and other uncertainties not generally encountered in our U.S. operations. These will include, among potential others:
 
  •  risks of war, terrorism, civil unrest and kidnapping of employees;
 
  •  expropriation, confiscation or nationalization of our assets;
 
  •  renegotiation or nullification of contracts;
 
  •  foreign taxation;
 
  •  the inability to repatriate earnings or capital, due to laws limiting the right and ability of foreign subsidiaries to pay dividends and remit earnings to affiliated companies;
 
  •  changing political conditions and changing laws and policies affecting trade and investment;
 
  •  regional economic downturns;
 
  •  the overlap of different tax structures;
 
  •  the burden of complying with multiple and potentially conflicting laws;
 
  •  the risks associated with the assertion of foreign sovereignty over areas in which our operations are conducted;
 
  •  difficulty in collecting international accounts receivable; and
 
  •  potentially longer payment cycles.
 
Our international operations may also face the additional risks of fluctuating currency values, hard currency shortages and controls of foreign currency exchange. Additionally, in some jurisdictions, we may be subject to foreign governmental regulations favoring or requiring the awarding of contracts to local contractors or requiring foreign contractors to employ citizens of, or purchase supplies from, a particular jurisdiction. These regulations could adversely affect our ability to compete.
 
Our operations are subject to various laws and governmental regulations that could restrict our future operations and increase our operating costs.
 
Many aspects of our operations are subject to various federal, state and local laws and governmental regulations, including laws and regulations governing:
 
  •  environmental quality;
 
  •  pollution control;
 
  •  remediation of contamination;
 
  •  preservation of natural resources; and
 
  •  worker safety.
 
Our operations are subject to stringent federal, state and local laws and regulations governing the protection of the environment and human health and safety. Some of those laws and regulations relate to the disposal of hazardous oilfield waste substances and restrict the types, quantities and concentrations of those substances that can be released into the environment. Several of those laws also require removal and remedial action and other cleanup under certain circumstances, commonly regardless of fault. Planning, implementation and maintenance of protective measures are required to prevent accidental discharges. Spills of oil, natural gas liquids, drilling fluids and other substances may subject us to penalties and cleanup requirements. Handling, storage and disposal of both hazardous and non-hazardous wastes are also subject to these regulatory


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requirements. In addition, our operations are often conducted in or near ecologically sensitive areas, such as wetlands, which are subject to special protective measures and which may expose us to additional operating costs and liabilities for accidental discharges of oil, gas, drilling fluids, contaminated water or other substances, or for noncompliance with other aspects of applicable laws and regulations.
 
The federal Clean Water Act, as amended by the Oil Pollution Act, the federal Clean Air Act, the federal Resource Conservation and Recovery Act, the federal Comprehensive Environmental Response, Compensation, and Liability Act, or CERCLA, the Safe Drinking Water Act, the Occupational Safety and Health Act, or OSHA, and their state counterparts and similar statutes are the primary statutes that impose those requirements and provide for civil, criminal and administrative penalties and other sanctions for violation of their requirements. The OSHA hazard communication standard, the Environmental Protection Agency “community right-to-know” regulations under Title III of the federal Superfund Amendment and Reauthorization Act and comparable state statutes require us to organize and report information about the hazardous materials we use in our operations to employees, state and local government authorities and local citizens. In addition, CERCLA, also known as the “Superfund” law, and similar state statutes impose strict liability, without regard to fault or the legality of the original conduct, on certain classes of persons who are considered responsible for the release or threatened release of hazardous substances into the environment. These persons include the current owner or operator of a facility where a release has occurred, the owner or operator of a facility at the time a release occurred, and companies that disposed of or arranged for the disposal of hazardous substances found at a particular site. This liability may be joint and several. Such liability, which may be imposed for the conduct of others and for conditions others have caused, includes the cost of removal and remedial action as well as damages to natural resources. Few defenses exist to the liability imposed by environmental laws and regulations. It is also common for third parties to file claims for personal injury and property damage caused by substances released into the environment.
 
Environmental laws and regulations are complex and subject to frequent change. Failure to comply with governmental requirements or inadequate cooperation with governmental authorities could subject a responsible party to administrative, civil or criminal action. We may also be exposed to environmental or other liabilities originating from businesses and assets which we acquired from others. Our compliance with amended, new or more stringent requirements, stricter interpretations of existing requirements or the future discovery of contamination or regulatory noncompliance may require us to make material expenditures or subject us to liabilities that we currently do not anticipate.
 
In addition, our business depends on the demand for land drilling services from the oil and gas industry and, therefore, is affected by tax, environmental and other laws relating to the oil and gas industry generally, by changes in those laws and by changes in related administrative regulations. It is possible that these laws and regulations may in the future add significantly to our operating costs or those of our customers, or otherwise directly or indirectly affect our operations.
 
We could be adversely affected if shortages of equipment, supplies or personnel occur.
 
From time to time there have been shortages of drilling equipment and supplies during periods of high demand which we believe could reoccur. Shortages could result in increased prices for drilling equipment or supplies that we may be unable to pass on to customers. In addition, during periods of shortages, the delivery times for equipment and supplies can be substantially longer. Any significant delays in our obtaining drilling equipment or supplies could limit drilling operations and jeopardize our relations with customers. In addition, shortages of drilling equipment or supplies could delay and adversely affect our ability to obtain new contracts for our rigs, which could have a material adverse effect on our financial condition and results of operations.
 
Our operations require the services of employees having the technical training and experience necessary to obtain the proper operational results. As a result, our operations depend, to a considerable extent, on the continuing availability of such personnel. Shortages of qualified personnel are occurring in our industry. If we should suffer any material loss of personnel to competitors or be unable to employ additional or replacement personnel with the requisite level of training and experience to adequately operate our equipment, our operations could be materially and adversely affected. A significant increase in the wages paid by other


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employers could result in a reduction in our workforce, increases in wage rates, or both. The occurrence of either of these events for a significant period of time could have a material and adverse effect on our financial condition and results of operations.
 
Risks Relating to Our Capitalization and Organizational Documents
 
We do not intend to pay dividends on our common stock in the foreseeable future, and therefore only appreciation of the price of our common stock will provide a return to our shareholders.
 
We have not paid or declared any dividends on our common stock and currently intend to retain any earnings to fund our working capital needs and growth opportunities. Any future dividends will be at the discretion of our board of directors after taking into account various factors it deems relevant, including our financial condition and performance, cash needs, income tax consequences and the restrictions imposed by the Texas Business Corporation Act and other applicable laws and by our credit facilities. Our debt arrangements include provisions that generally prohibit us from paying dividends on our capital stock, including our common stock.
 
We may issue preferred stock whose terms could adversely affect the voting power or value of our common stock.
 
Our articles of incorporation authorize us to issue, without the approval of our shareholders, one or more classes or series of preferred stock having such designations, preferences, limitations and relative rights, including preferences over our common stock respecting dividends and distributions, as our board of directors may determine. The terms of one or more classes or series of preferred stock could adversely impact the voting power or value of our common stock. For example, we might grant holders of preferred stock the right to elect some number of our directors in all events or on the happening of specified events or the right to veto specified transactions. Similarly, the repurchase or redemption rights or liquidation preferences we might assign to holders of preferred stock could affect the residual value of the common stock.
 
Provisions in our organizational documents could delay or prevent a change in control of our company, even if that change would be beneficial to our shareholders.
 
The existence of some provisions in our organizational documents could delay or prevent a change in control of our company, even if that change would be beneficial to our shareholders. Our articles of incorporation and bylaws contain provisions that may make acquiring control of our company difficult, including:
 
  •  provisions regulating the ability of our shareholders to nominate candidates for election as directors or to bring matters for action at annual meetings of our shareholders;
 
  •  limitations on the ability of our shareholders to call a special meeting and act by written consent;
 
  •  provisions dividing our board of directors into three classes elected for staggered terms; and
 
  •  the authorization given to our board of directors to issue and set the terms of preferred stock.
 
Item 1B.   Unresolved Staff Comments
 
None.


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Item 2.   Properties
 
For a description of our significant properties, see “Business — Drilling Equipment” and “Business — Facilities” in Item 1 of this report. We consider each of our significant properties to be suitable for its intended use.
 
Item 3.   Legal Proceedings
 
Due to the nature of our business, we are, from time to time, involved in routine litigation or subject to disputes or claims related to our business activities, including workers’ compensation claims and employment-related disputes. In the opinion of our management, none of the pending litigation, disputes or claims against us will have a material adverse effect on our financial condition or results of operations.
 
Item 4.   Submission of Matters to a Vote of Security Holders
 
We did not submit any matter to a vote of our shareholders during the quarter ended December 31, 2007.


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PART II
 
Item 5.   Market for Registrant’s Common Equity, Related Shareholder Matters and Issuer Purchases of Equity Securities
 
As of February 8, 2008, 49,760,978 shares of our common stock were outstanding, held by 465 shareholders of record. The number of record holders does not necessarily bear any relationship to the number of beneficial owners of our common stock.
 
Our common stock trades on the American Stock Exchange under the symbol “PDC.” The following table sets forth, for each of the periods indicated, the high and low sales prices per share on the American Stock Exchange:
 
                 
    Low     High  
 
Nine Months Ended December 31, 2007:
               
First Quarter
  $ 12.69     $ 16.00  
Second Quarter
    11.81       14.88  
Third Quarter
    11.49       12.49  
Fiscal Year Ended March 31, 2007:
               
First Quarter
  $ 12.60     $ 18.00  
Second Quarter
    10.79       15.70  
Third Quarter
    11.57       14.65  
Fourth Quarter
    11.46       13.47  
Fiscal Year Ended March 31, 2006:
               
First Quarter
  $ 10.57     $ 16.30  
Second Quarter
    14.00       19.93  
Third Quarter
    14.25       19.98  
Fourth Quarter
    13.10       23.06  
 
The last reported sales price for our common stock on the American Stock Exchange on February 8, 2008 was $12.17 per share.
 
We have not paid or declared any dividends on our common stock and currently intend to retain earnings to fund our working capital needs and growth opportunities. Any future dividends will be at the discretion of our board of directors after taking into account various factors it deems relevant, including our financial condition and performance, cash needs, income tax consequences and the restrictions Texas and other applicable laws and our credit facilities then impose. Our debt arrangements include provisions that generally prohibit us from paying dividends, other than dividends on our preferred stock. We currently have no preferred stock outstanding.
 
No shares of our common stock were purchased by or on behalf of our company or any affiliated purchaser during the nine months ended December 31, 2007.


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Performance Graph
 
The following graph compares, for the periods from March 31, 2003 to December 31, 2007, the cumulative total shareholder return on our common stock with the cumulative total return on the companies that comprise the AMEX Composite Index and a peer group index that includes the five companies within our industry. The comparison assumes that $100 was invested on March 31, 2003 in our common stock, the companies that compose the AMEX Composite Index and the companies that compose the peer group index, and further assumes all dividends were reinvested.
 
The companies that comprise the peer group index are Helmerich & Payne, Inc., Grey Wolf, Inc., Patterson-UTI Energy, Inc., Nabors Industries Ltd. and Unit Corp.
 
Comparison of 5 Year Cumulative Total Return
Assumes Initial Investment of $100
December 2007
 
(PERFORMANCE GRAPH)


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Equity Compensation Plan Information
 
The following table provides information on our equity compensation plans as of December 31, 2007:
 
                         
            Number of securities
            remaining available for
    Number of securities to be
  Weighted-average
  future issuance under equity
    issued upon exercise of
  exercise price per share
  compensation plans
    outstanding options,
  of outstanding options,
  (excluding securities
Plan category
  warrants and rights
  warrants and rights
  reflected in column (a))
    (a)   (b)   (c)
 
Equity compensation plans approved by security holders
    2,800,499       10.87       3,351,834  
Equity compensation plans not approved by security holders
                       
                         
Total
    2,800,499       10.87       3,351,834  
                         
 
Item 6.   Selected Financial Data
 
The following information derives from our audited financial statements. You should review this information in conjunction with “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in Item 7 of this report and the historical financial statements and related notes this report contains.
 
                                         
    Nine Months
               
    Ended
               
    December 31,
  Years Ended March 31,
    2007   2007   2006   2005   2004
    (In thousands, except per share amounts)
 
Contract drilling revenues
    313,884       416,178       284,148       185,246       107,876  
Income from operations
    55,260       126,976       77,909       18,774       438  
Income (loss) before income taxes
    57,774       130,789       79,813       17,161       (2,216 )
Net earnings (loss) applicable to common stockholders
    39,645       84,180       50,567       10,812       (1,790 )
Earnings (loss) per common share-basic
    0.80       1.70       1.08       0.31       (0.08 )
Earnings (loss) per common share-diluted
    0.79       1.68       1.06       0.30       (0.08 )
Long-term debt and capital lease obligations, excluding current installments
                      13,445       44,892  
Shareholders’ equity
    471,072       428,109       340,676       221,615       70,836  
Total assets
    560,212       501,495       400,678       276,009       143,731  
Capital expenditures
    128,038       147,230       128,871       80,388       44,845  


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Item 7.   Management’s Discussion and Analysis of Financial Condition and Results of Operations
 
Statements we make in the following discussion that express a belief, expectation or intention, as well as those that are not historical fact, are forward-looking statements that are subject to risks, uncertainties and assumptions. Our actual results, performance or achievements, or industry results, could differ materially from those we express in the following discussion as a result of a variety of factors, including general economic and business conditions and industry trends, the continued strength or weakness of the contract land drilling industry in the geographic areas in which we operate, decisions about onshore exploration and development projects to be made by oil and gas companies, the highly competitive nature of our business, the availability, terms and deployment of capital, the availability of qualified personnel, and changes in, or our failure or inability to comply with, government regulations, including those relating to the environment. We have discussed many of these factors in more detail elsewhere in this report, including under the headings “Special Note Regarding Forward-Looking Statements” in the Introductory Note to Part I and “Risk Factors” in Item 1A. These factors are not necessarily all the important factors that could affect us. Unpredictable or unknown factors we have not discussed in this report or could also have material adverse effects on actual results of matters that are the subject of our forward-looking statements. All forward-looking statements speak only as the date on which they are made and we undertake no duty to update or revise any forward-looking statements. We advise our shareholders that they should (1) be aware that important factors not referred to above could affect the accuracy of our forward-looking statements and (2) use caution and common sense when considering our forward-looking statements.
 
Company Overview
 
Pioneer Drilling Company provides contract land drilling services to independent and major oil and gas exploration and production companies. In addition to our drilling rigs, we provide the drilling crews and most of the ancillary equipment needed to operate our drilling rigs. We have focused our operations in selected oil and natural gas production regions in the United States and Colombia. Our company was incorporated in 1979 as the successor to a business that had been operating since 1968. We conduct our operations in the United States through our principal operating subsidiary, Pioneer Drilling Services, Ltd. and we conduct our operations in Colombia through Pioneer de Colombia SDAD, Ltda, Surcusal Colombia. We are an oil and gas services company. We do not invest in oil and natural gas properties. The drilling activity of our customers is highly dependent on the current and forecasted future price of oil and natural gas. Since November 2006, we have been experiencing a decline in the demand for drilling rigs and have experienced a decline in revenue rates on contract renewals due to an excess supply of drilling rigs within the industry, which is due to the substantial addition of new and refurbished drilling rigs during the past year. Any continued weakness in the demand for additional drilling rigs will likely result in lower revenue rates for our rigs as existing contracts expire and more drilling rigs are added to the market.
 
Our business strategy is to continue to build on our strong market position and reputation as a quality contract drilling company, diversify internationally and expand into other oilfield service sectors in a way that enhances shareholder value. We intend to continue making additions to our drilling fleet, either through acquisitions of businesses or selected assets or through the construction of new or refurbished drilling rigs, as attractive opportunities arise. We commenced international operations in Colombia with 2 contracts for which we exported 2 drilling rigs to Colombia that began operations in September 2007 and October 2007. We exported a third drilling rig to Colombia that began operating in February 2008. Our immediate international strategy is to continue our expansion in Colombia to include at least 5 drilling rigs by December 31, 2008 and continue to evaluate opportunities for expansion into other international markets.
 
Our business strategy also includes expansion into other sectors within the oilfield services industry. On January 31, 2008, we entered into a definitive purchase agreement to acquire WEDGE Well Services, L.L.C., WEDGE Wireline, Inc. and WEDGE Fishing and Rental Services, L.L.C. (the “WEDGE Companies”) from affiliates of WEDGE Group Incorporated for $303 million. The WEDGE Companies provide oil and gas well workover, wireline, and fishing and rental services for energy producers in the United States. We expect to finance the acquisition through a combination of existing cash and a new, 5 year, senior revolving credit facility of up to $350 million led by Wells Fargo Bank, N.A. and Fortis Merchant Banking. The closing of the


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acquisition, which is expected before March 31, 2008, is subject to obtaining certain regulatory approvals, our receipt of financing and other customary closing conditions.
 
Since September 1999, we have significantly expanded our fleet of drilling rigs through acquisitions and the construction of new and refurbished rigs. As of February 22, 2008, our rig fleet consisted of 67 operating drilling rigs, of which 27 are premium electric rigs that drill in depth ranges between 6,000 and 18,000 feet. Seventeen of our rigs are operating in our South Texas division, 20 in our East Texas division, 10 in our North Texas division, 6 in our western Oklahoma division, 11 in our Rocky Mountains divisions in Utah and North Dakota and 3 in Colombia. We actively market all of these rigs. Not included in our 67 operating rig count is a 1000 horsepower rig and a 1500 horsepower rigs that we plan to deploy for further expansion into international markets.
 
We earn our revenues by drilling oil and gas wells for our customers, as our rigs can be used by our customers to drill for either oil or natural gas. We obtain our contracts for drilling oil and gas wells either through competitive bidding or through direct negotiations with customers. Our drilling contracts generally provide for compensation on either a daywork, turnkey or footage basis. Contract terms generally depend on the complexity and risk of operations, the on-site drilling conditions, the type of equipment used and the anticipated duration of the work to be performed. Historically, our contracts provide for the drilling of a single well and typically permit the customer to terminate on short notice. As demand for drilling rigs improved during the years ended December 31, 2005 and 2006, we entered into more longer-term drilling contracts. As of February 8, 2008, we had 19 contracts with terms of 6 months to 3 years in duration, of which 9 will expire by August 9, 2008, 6 have a remaining term of 6 to 12 months, 2 have a remaining term of 12 to 18 months and 2 have a remaining term in excess of 18 months.
 
A significant performance measurement in our industry is rig utilization. We compute rig utilization rates by dividing revenue days by total available days during a period. Total available days are the number of calendar days during the period that we have owned and marketed the rig. Revenue days for each rig are days when the rig is earning revenues under a contract, which is usually a period from the date the rig begins moving to the drilling location until the rig is released from the contract.
 
For the nine months ended December 31, 2007 and 2006 and the years ended March 31, 2007, 2006 and 2005 our rig utilization, revenue days and average number of operating rigs during the period were as follows:
 
                                         
    Nine Months Ended December 31,     Years Ended March 31,  
    2007     2006     2007     2006     2005  
 
Utilization Rates
    89 %     97 %     95 %     95 %     96 %
Revenue Days
    16,289       15,727       20,930       18,164       13,894  
Average number of operating rigs during the period
    66.7       59.6       60.8       52.3       40.1  
 
The primary reason for the increase in the number of revenue days in 2007 over 2006 is the increase in size of our rig fleet. Due to the current excess supply of drilling rigs available for work, we currently expect a 2% to 5% decrease in utilization rates for the year ended December 31, 2008 as compared to the nine months ended December 31, 2007.
 
In addition to high commodity prices, we attribute our relatively high utilization rates to a strong sales effort, quality equipment, good field and operations personnel, a disciplined safety approach, and our generally successful performance of turnkey operations during periods of reduced demand for drilling rigs.
 
We devote substantial resources to maintaining and upgrading our rig fleet. In the short term, these actions result in fewer revenue days and slightly lower utilization; however, in the long term, we believe the upgrades will help the marketability of our rigs and improve their operating performance. Upgrades for the nine months ended December 31, 2007 primarily focused on: replacing older engines with more modern, efficient engines; upgrading to higher horsepower mud pumps; upgrading to modern mud cleaning systems on some of our drilling rigs; and adding iron roughnecks to approximately 30 of our drilling rigs.


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Market Conditions in Our Industry
 
The U.S. contract land drilling services industry is highly cyclical. Volatility in oil and gas prices can produce wide swings in the levels of overall drilling activity in the markets we serve and affect the demand for our drilling services and the dayrates we can charge for our rigs. The availability of financing sources, past trends in oil and gas prices and the outlook for future oil and gas prices strongly influence the number of wells oil and gas exploration and production companies decide to drill.
 
In addition, the availability of drilling rigs capable of working affects our revenue rates and utilization rates. Until the quarter ended December 31, 2006, our industry experienced a shortage of drilling rigs leading to revenue rates and utilization rates that were at historically high levels. However, our industry is currently experiencing an excess drilling rig supply due to new construction and refurbishments. This condition may correct itself over time if older drilling rigs are retired and if the outlook for oil and gas pricing improves and results in an increase in drilling activity.
 
On February 8, 2008, the spot price for West Texas Intermediate crude oil was $91.77, the spot price for Henry Hub natural gas was $8.06 and the Baker Hughes land rig count was 1,677, a 3% increase from 1,622 on February 9, 2007. Since October 1, 2006, the Baker Hughes land rig count has been between 1,586 and 1,739.
 
The average weekly spot prices of West Texas Intermediate crude oil and Henry Hub natural gas and the average weekly domestic land rig count, per the Baker Hughes land rig count, for the nine months ended December 31, 2007 and each of the previous five years ended March 31st were:
 
                                                 
    Nine Months
                               
    Ended
                               
    December 31,
    Years Ended March 31,  
    2007     2007     2006     2005     2004     2003  
 
Oil (West Texas Intermediate)
  $ 77.42     $ 64.96     $ 59.94     $ 45.04     $ 31.47     $ 29.27  
Natural Gas (Henry Hub)
  $ 6.82     $ 6.53     $ 9.10     $ 5.99     $ 5.27     $ 4.24  
U.S. Land Rig Count
    1,684       1,589       1,329       1,110       964       723  
 
Most of our customers drill in search of natural gas; however, we currently operate 5 rigs in the Williston Basin of the Rocky Mountains and 3 rigs in Colombia, where our customers drill in search of oil.
 
Critical Accounting Policies and Estimates
 
Revenue and cost recognition — We earn our revenues by drilling oil and gas wells for our customers under daywork, turnkey or footage contracts, which usually provide for the drilling of a single well. We recognize revenues on daywork contracts for the days completed based on the dayrate each contract specifies. We recognize revenues from our turnkey and footage contracts on the percentage-of-completion method based on our estimate of the number of days to complete each contract. Individual contracts are usually completed in less than 60 days. The risks to us under a turnkey contract and, to a lesser extent, under footage contracts, are substantially greater than on a contract drilled on a daywork basis. Under a turnkey contract, we assume most of the risks associated with drilling operations that are generally assumed by the operator in a daywork contract, including the risks of blowout, loss of hole, stuck drill pipe, machinery breakdowns and abnormal drilling conditions, as well as risks associated with subcontractors’ services, supplies, cost escalations and personnel operations.
 
Our management has determined that it is appropriate to use the percentage-of-completion method, as defined in the American Institute of Certified Public Accountants’ Statement of Position 81-1, to recognize revenue on our turnkey and footage contracts. Although our turnkey and footage contracts do not have express terms that provide us with rights to receive payment for the work that we perform prior to drilling wells to the agreed-on depth, we use this method because, as provided in applicable accounting literature, we believe we achieve a continuous sale for our work-in-progress and believe, under applicable state law, we ultimately could recover the fair value of our work-in-progress even in the event we were unable to drill to the agreed-on depth in breach of the applicable contract. However, in the event we were unable to drill to the agreed-on depth in


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breach of the contract, ultimate recovery of that value would be subject to negotiations with the customer and the possibility of litigation.
 
If a customer defaults on its payment obligation to us under a turnkey or footage contract, we would need to rely on applicable law to enforce our lien rights, because our turnkey and footage contracts do not expressly grant to us a security interest in the work we have completed under the contract and we have no ownership rights in the work-in-progress or completed drilling work, except any rights arising under the applicable lien statute on foreclosure. If we were unable to drill to the agreed-on depth in breach of the contract, we also would need to rely on equitable remedies outside of the contract, including quantum meruit, available in applicable courts to recover the fair value of our work-in-progress under a turnkey or footage contract.
 
We accrue estimated contract costs on turnkey and footage contracts for each day of work completed based on our estimate of the total costs to complete the contract divided by our estimate of the number of days to complete the contract. Contract costs include labor, materials, supplies, repairs and maintenance, operating overhead allocations and allocations of depreciation and amortization expense. In addition, the occurrence of uninsured or under-insured losses or operating cost overruns on our turnkey and footage contracts could have a material adverse effect on our financial position and results of operations. Therefore, our actual results for a contract could differ significantly if our cost estimates for that contract are later revised from our original cost estimates for a contract in progress at the end of a reporting period which was not completed prior to the release of our financial statements.
 
With most drilling contracts, we receive payments contractually designated for the mobilization of rigs and other equipment. Payments received, and costs incurred for the mobilization services are deferred and recognized on a straight line basis over the contract term of certain drilling contracts. Costs incurred to relocate rigs and other drilling equipment to areas in which a contract has not been secured are expensed as incurred. Reimbursements that we receive for out-of-pocket expenses are recorded as revenue and operating costs.
 
The asset “contract drilling in progress” represents revenues we have recognized in excess of amounts billed on contracts in progress. The asset “prepaid and other current assets” includes deferred mobilization costs for certain drilling contracts. The liability “prepaid drilling contracts” represents deferred mobilization revenues for certain drilling contracts and amounts collected on contracts in excess of revenues recognized.
 
Asset impairments — We assess the impairment of property and equipment whenever events or circumstances indicate that the carrying value may not be recoverable. Factors that we consider important and which could trigger an impairment review would be our customers’ financial condition and any significant negative industry or economic trends. More specifically, among other things, we consider our contract revenue rates, our rig utilization rates, cash flows from our drilling rigs, current oil and gas prices and trends in the price of used drilling equipment observed by our management. If a review of our drilling rigs indicates that our carrying value exceeds the estimated undiscounted future net cash flows, we are required under applicable accounting standards to write down the drilling equipment to its fair market value. A one percent write-down in the cost of our drilling equipment, at December 31, 2007, would have resulted in a corresponding decrease in our net earnings of approximately $3.6 million for the nine months ended December 31, 2007.
 
Deferred taxes — We provide deferred taxes for the basis differences in our property and equipment between financial reporting and tax reporting purposes and other costs such as compensation, foreign net operating loss carryforwards, employee benefit and other accrued liabilities which are deducted in different periods for financial reporting and tax reporting purposes. For property and equipment, basis differences arise from differences in depreciation periods and methods and the value of assets acquired in a business acquisition where we acquire an entity rather than just its assets. For financial reporting purposes, we depreciate the various components of our drilling rigs over 5 to 15 years and refurbishments over 3 to 5 years, while federal income tax rules require that we depreciate drilling rigs and refurbishments over 5 years. Therefore, in the first 5 years of our ownership of a drilling rig, our tax depreciation exceeds our financial reporting depreciation, resulting in our providing deferred taxes on this depreciation difference. After 5 years, financial reporting depreciation exceeds tax depreciation, and the deferred tax liability begins to reverse.


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Accounting estimates — We consider the recognition of revenues and costs on turnkey and footage contracts to be critical accounting estimates. On these types of contracts, we are required to estimate the number of days needed for us to complete the contract and our total cost to complete the contract. Our actual costs could substantially exceed our estimated costs if we encounter problems such as lost circulation, stuck drill pipe or an underground blowout on contracts still in progress subsequent to the release of the financial statements.
 
We receive payment under turnkey and footage contracts when we deliver to our customer a well completed to the depth specified in the contract, unless the customer authorizes us to drill to a more shallow depth. Since 1995, we have completed all our turnkey or footage contracts. Although our initial cost estimates for turnkey and footage contracts do not include cost estimates for risks such as stuck drill pipe or loss of circulation, we believe that our experienced management team, our knowledge of geologic formations in our areas of operations, the condition of our drilling equipment and our experienced crews have previously enabled us to make reasonable cost estimates and complete contracts according to our drilling plan. While we do bear the risk of loss for cost overruns and other events that are not specifically provided for in our initial cost estimates, our pricing of turnkey and footage contracts takes such risks into consideration. When we encounter, during the course of our drilling operations, conditions unforeseen in the preparation of our original cost estimate, we increase our cost estimate to complete the contract. If we anticipate a loss on a contract in progress at the end of a reporting period due to a change in our cost estimate, we accrue the entire amount of the estimated loss, including all costs that are included in our revised estimated cost to complete that contract, in our consolidated statement of operations for that reporting period. During the nine months ended December 31, 2007, we experienced losses on 12 of the 71 turnkey and footage contracts completed, with losses of less than $25,000 each on 7 contracts and losses ranging from $25,000 to $65,000 each on the remaining 5 contracts. During the nine months ended December 31, 2006, we experienced losses on 6 of 44 footage contracts completed, and those losses were each less than $25,000. We are more likely to encounter losses on turnkey and footage contracts in periods in which revenue rates are lower for all types of contracts. During periods of reduced demand for drilling rigs, our overall profitability on turnkey and footage contracts has historically exceeded our profitability on daywork contracts.
 
Revenues and costs during a reporting period could be affected for contracts in progress at the end of a reporting period which have not been completed before our financial statements for that period are released. We had 1 turnkey and 4 footage contracts in progress at December 31, 2007, which were completed prior to the release of the financial statements included in this report. Our contract drilling in progress totaled $7.9 million at December 31, 2007. Of that amount accrued, turnkey and footage contract revenues were $.7 million. The remaining balance of $7.2 million related to the revenue recognized but not yet billed on daywork contracts in progress at December 31, 2007. At March 31, 2007, drilling in progress totaled $9.8 million, of which $.3 million related to footage contracts and $9.5 million related to daywork contracts.
 
We estimate an allowance for doubtful accounts based on the creditworthiness of our customers as well as general economic conditions. We evaluate the creditworthiness of our customers based on commercial credit reports, trade references, bank references, financial information, production information and any past experience we have with the customer. Consequently, an adverse change in those factors could affect our estimate of our allowance for doubtful accounts. In some instances, we require new customers to establish escrow accounts or make prepayments. We typically invoice our customers at 15-day intervals during the performance of daywork contracts and upon completion of the daywork contract. Turnkey and footage contracts are invoiced upon completion of the contract. Our typical contract provides for payment of invoices in 10 to 30 days. We generally do not extend payment terms beyond 30 days and have not extended payment terms beyond 90 days for any of our contracts in the last three fiscal years. We recorded bad debt expense of $2.6 million during the nine months ended December 31, 2007 and wrote off a $3.6 million accounts receivable balance that we do not expect to recover from a customer in bankruptcy. We had no allowance for doubtful accounts at December 31, 2007. At March 31, 2007, our allowance for doubtful accounts was $1.0 million.
 
Another critical estimate is our determination of the useful lives of our depreciable assets, which directly affects our determination of depreciation expense and deferred taxes. A decrease in the useful life of our


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drilling equipment would increase depreciation expense and reduce deferred taxes. We provide for depreciation of our drilling, transportation and other equipment on a straight-line method over useful lives that we have estimated and that range from 3 to 15 years. We record the same depreciation expense whether a rig is idle or working. Our estimates of the useful lives of our drilling, transportation and other equipment are based on our more than 35 years of experience in the drilling industry with similar equipment.
 
As of December 31, 2007, we had foreign net operating losses for tax purposes and other tax benefits available to reduce future taxable income in a foreign jurisdiction. The valuation allowance in the amount of $4.0 million offsets in part our foreign net operating losses and other tax benefits. In assessing the realizability of our foreign deferred tax assets, we recognized a tax benefit to the extent of taxable income we expect to earn over the terms of three existing drilling contracts in the foreign jurisdiction. The terms of these contracts expire in February 2008, May 2008 and February 2009. If one or more of these contracts are extended or renewed or new contracts are entered into, then we expect to recognize additional tax benefits to the extent projected future taxable income increases. The foreign net operating loss has an indefinite carryforward period.
 
Our accrued insurance premiums and deductibles as of December 31, 2007 include accruals of approximately $.8 million and $7.6 million for costs incurred under the self-insurance portion of our health insurance and under our workers’ compensation insurance, respectively. We have a deductible of (1) $125,000 per covered individual per year under the health insurance and (2) $250,000 per occurrence under our workers’ compensation insurance, except in North Dakota, where we do not have a deductible. Our deductible under our workers’ compensation insurance increased to $500,000 in October 2007. We accrue for these costs as claims are incurred based on historical claim development data, and we accrue the costs of administrative services associated with claims processing. We also evaluate our workers’ compensation claim cost estimates based on estimates provided by the insurance companies that provide claims processing services and estimates provided by a professional actuary.
 
Liquidity and Capital Resources
 
Sources of Capital Resources
 
Our rig fleet has grown from eight rigs in August 2000 to 69 rigs as of February 8, 2008. We have financed this growth with a combination of cash flows from operations, debt and equity financing. We have raised additional equity for growth nine times since January 2000. We plan to continue to grow our rig fleet, continue our international expansion and diversify into other oilfield sector services beginning with our acquisition of the WEDGE Companies that is expected to close before March 31, 2008. We expect to finance the acquisition of the WEDGE Companies through a combination of existing cash and a new, 5 year, senior revolving credit facility of up to $350 million. We may finance additional growth and expansion opportunities with new debt and equity financing.
 
We have a $20 million credit facility with Frost National Bank consisting of a $10 million revolving line and letter of credit facility and a $10 million acquisition facility for the acquisition of drilling rigs, drilling rig transportation equipment and associated equipment. Borrowings under the credit facility bear interest at a rate equal to Frost National Bank’s prime rate (7.25% at December 31, 2007) or, at our option, at LIBOR plus a percentage ranging from 1.5% to 2.25%, based on our operating leverage ratio. Borrowings are secured by most of our assets, including all our U.S. drilling rigs and associated equipment and receivables. At December 31, 2007, we had no borrowings under the acquisition facility and we had used $8 million of availability under the revolving line and letter of credit facility through the issuance of letters of credit in the ordinary course of business. The remaining availability under the revolving line and letter of credit facility is $2 million. Both the revolving line and letter of credit facility and acquisition facility are scheduled to mature in October 2008. However, we expect to replace the existing $20 million credit facility prior to maturity with the new senior revolving credit facility that we expect to enter into for the acquisition of the WEDGE Companies.
 
In January 2008, we invested $16.5 million in auction rate securities which are private placement securities with long-term nominal maturities for which the interest rates are reset through a “Dutch” auction


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each week. These auction rate securities are collateralized by securities issued by municipalities. The weekly auctions historically have provided a liquid market for these securities. Due to liquidity issues in global credit and capital markets, our auction rate securities have experienced multiple failed auctions as the amount of securities submitted for sale have exceeded purchase orders. The result of failed auctions is that these auction rate securities continue to pay interest in accordance with their terms. Liquidity will be limited until there is a successful auction or until such time as other markets for auction rate securities develop. As a result of these events, we are evaluating the extent of any impairment in the value of our auction rate securities that may result from this lack of liquidity. At this time, we are not able to quantify the amount of such impairment, if any, which would result in an impairment charge that would need to be recorded in the quarter ending March 31, 2008. We believe that any lack of liquidity relating to our auction rate securities will not have an impact on our ability to fund our operations.
 
Uses of Capital Resources
 
For the nine months ended December 31, 2007 and the year ended March 31, 2007, the additions to our property and equipment consisted of the following:
 
                 
    Nine Months
       
    Ended
    Year Ended
 
    December 31, 2007     March 31, 2007  
    (In thousands)  
 
Drilling rigs
  $ 59,582     $ 74,457  
Other drilling equipment
    64,767       63,660  
Transportation equipment
    3,057       7,597  
Other
    632       1,516  
                 
    $ 128,038     $ 147,230  
                 
 
Property and equipment additions for the nine months ended December 31, 2007 include $1.9 million of purchases recorded in accounts payable at December 31, 2007. Property and equipment additions for the year ended March 31, 2007 include $2.7 million of purchases recorded in accounts payable at March 31, 2007.
 
As of March 31, 2007, we were constructing one 1000-horsepower mechanical rig. We placed this rig into service in April 2007 and incurred $2.2 million of rig construction costs during the nine months ended December 31, 2007. In addition, we incurred $56.2 million during the nine months ended December 31, 2007 to purchase and upgrade the 3 drilling rigs acquired for expansion into international markets.
 
For the fiscal year ending December 31, 2008, we project capital expenditures excluding new rig construction and acquisitions to be approximately $64.3 million, comprised of routine rig capital expenditures of approximately $19.8 million, rig upgrade expenditures of approximately $18.6 million (including approximately $9.6 million for iron roughnecks), tubular capital expenditures of approximately $12 million, capital expenditures for our Colombian operations of approximately $7.4 million, spare equipment expenditures of approximately $2.5 million, transportation equipment expenditures of approximately $3.3 million, and other capital expenditures of approximately $.7 million. We expect to fund these capital expenditures primarily from operating cash flow in excess of our working capital and other normal cash flow requirements.
 
Working Capital
 
Our working capital was $99.8 million at December 31, 2007, compared to $124.1 million at March 31, 2007. Our current ratio, which we calculate by dividing our current assets by our current liabilities, was 3.4 at December 31, 2007, compared to 4.6 at March 31, 2007.
 
Our operations have historically generated cash flows sufficient to at least meet our requirements for debt service and normal capital expenditures. However, during periods when higher percentages of our contracts are turnkey and footage contracts, our short-term working capital needs could increase. If necessary, we can defer rig upgrades to improve our cash position. We expect to finance the acquisition of the WEDGE Companies for $303 million through a combination of existing cash and a new, 5 year, senior revolving credit facility of up to


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$350 million led by Wells Fargo Bank, N.A. and Fortis Merchant Banking. The closing of the acquisition, which is expected before March 31, 2008, is subject to obtaining certain regulatory approvals, our receipt of financing and other customary closing conditions. We believe our cash generated by operations and our ability to borrow under the unused portion of either our current credit facility or the new senior revolving credit facility should allow us to meet our routine financial obligations for at least the next twelve months.
 
The changes in the components of our working capital were as follows:
 
                         
    December 31, 2007     March 31, 2007     Change  
    (In thousands)  
 
Cash and cash equivalents
  $ 76,703     $ 84,945     $ (8,242 )
Trade receivables, net
    46,759       54,206       (7,447 )
Contract drilling in progress
    7,861       9,837       (1,976 )
Income tax receivable
    611       3,492       (2,881 )
Deferred income taxes
    3,670       2,175       1,495  
Inventory
    1,180             1,180  
Prepaid expenses
    5,073       3,653       1,420  
                         
Current assets
    141,857       158,308       (16,451 )
                         
Accounts payable
    21,424     $ 18,626       2,798  
Prepaid drilling contracts
    1,933             1,933  
Accrued payroll and related employee costs
    5,172       7,086       (1,914 )
Accrued insurance premiums and deductibles
    9,548       6,754       2,794  
Other accrued expenses
    3,973       1,753       2,220  
                         
Current liabilities
    42,050       34,219       7,831  
                         
Working capital
  $ 99,807     $ 124,089     $ (24,282 )
                         
 
The decrease in cash and cash equivalents was primarily due to property and equipment expenditures of $126.2 million during the nine months ended December 31, 2007. This decrease in cash and cash equivalents was partially offset by $115.5 million of net cash provided by operating activities.
 
The decrease in our receivables and contract drilling in progress at December 31, 2007 from March 31, 2007, was due to a $744 per day decrease in average revenue rates and a 5% decrease in average utilization rates during the quarter ended December 31, 2007, compared to the quarter ended March 31, 2007.
 
The decrease in our income tax receivable is due to the collection of an income tax refund that resulted from an excess tax deposit for our fiscal year ended March 31, 2007.
 
During the nine months ended December 31, 2007, we began maintaining inventories of replacement parts and supplies for our drilling rigs operating in Colombia to ensure efficient operations in geographically remote areas.
 
Most of our prepaid expenses as of December 31, 2007 and March 31, 2007 consisted of prepaid insurance. We renew and pay most of our insurance premiums in late October of each year and some in April of each year. At March 31, 2007, we had amortized 5 months of October insurance premiums, compared to 2 months of amortization as of December 31, 2007. Prepaid expenses also increased due to deferred mobilization costs relating to our drilling contracts in Colombia. Mobilization costs are deferred and recognized over the term of the related drilling contract.
 
The increase in accounts payable at December 31, 2007, as compared to March 31, 2007, was primarily due to a $367 per day increase in average drilling costs during the quarter ended December 31, 2007, as compared to the quarter ended March 31, 2007.
 
The increase in prepaid drilling contracts as of December 31, 2007, as compared to March 31, 2007, was due to amounts billed for mobilization revenues on our Colombian drilling contracts in excess of revenue


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recognized. Mobilization billings are deferred and the associated revenues are recognized over the term of the underlying drilling contract.
 
The decrease in accrued payroll and related employee costs was primarily due to a decrease in accrued bonuses for the nine months ended December 31, 2007, as compared to the year ended March 31, 2007.
 
The increase in accrued insurance premiums and deductibles was primarily due to increases in costs incurred for the self-insurance portion of our health and workers compensation insurance during the nine months ended December 31, 2007, as compared to March 31, 2007.
 
The increase in other accrued expenses at December 31, 2007, as compared to March 31, 2007, was primarily due to accruals for property taxes. The majority of property taxes are paid in January of each year, so the accrual increases each quarter until the property taxes are paid.
 
Long-term Debt
 
We had no long-term debt outstanding at December 31, 2007. See “Sources of Capital Resources” for a description of our credit facility.
 
Contractual Obligations
 
The following table includes all our contractual obligations of the types specified below at December 31, 2007.
 
                                         
    Payments Due by Period  
Contractual
        Less than 1
    1-3
    4-5
    More than 5
 
Obligations
  Total     year     years     years     years  
    (In thousands)  
 
Purchase Obligations
  $ 3,690     $ 3,690     $     $     $  
Operating Lease Obligations
    1,605       371       573       437       224  
                                         
Total
  $ 5,295     $ 4,061     $ 573     $ 437     $ 224  
                                         
 
Debt Requirements
 
The sum of (1) the draws and (2) the amount of all outstanding letters of credit issued for our account under the revolving line and letter of credit facility portion of our credit facility is limited to 75% of our eligible accounts receivable, not to exceed $10.0 million. Therefore, if 75% of our eligible accounts receivable was less than $10.0 million, our ability to draw under this line would be reduced. At December 31, 2007, we had no outstanding advances under this line of credit, we had outstanding letters of credit of $8.0 million and 75% of our eligible accounts receivable was $32.4 million. The letters of credit have been issued to three workers’ compensation insurance companies to secure possible future claims under the deductibles on these policies. It is our practice to pay any amounts due under these deductibles as they are incurred. Therefore, we do not anticipate that the lenders will be required to fund any draws under these letters of credit.
 
Our credit facility contains various covenants pertaining to a debt to total capitalization ratio, operating leverage ratio and fixed charge coverage ratio and restricts us from paying dividends. We determine compliance with the ratios on a quarterly basis, based on the previous four quarters. Events of default, which could trigger an early repayment requirement, include, among others:
 
  •  our failure to make required payments;
 
  •  any sale of assets by us not permitted by the credit facility;
 
  •  our failure to comply with financial covenants related to a debt to total capitalization ratio not to exceed 0.2 to 1, an operating leverage ratio of not more than 2.5 to 1, and a fixed charge coverage ratio of not less than 1.5 to 1;
 
  •  our incurrence of additional indebtedness in excess of $3.0 million, to the extent not otherwise allowed by the credit facility;


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  •  any event which results in a change in the ownership of at least 40% of all classes of our outstanding capital stock; and
 
  •  any payment of cash dividends on our common stock.
 
We expect to finance the acquisition of the WEDGE Companies for $303 million through a combination of existing cash and a new, 5 year, senior revolving credit facility of up to $350 million led by Wells Fargo Bank, N.A. and Fortis Merchant Banking. The closing of the acquisition, which is expected before March 31, 2008, is subject to obtaining certain regulatory approvals, our receipt of financing and other customary closing conditions. The new senior revolving credit facility will replace our existing $20 million credit facility with Frost National Bank and will contain various new debt requirements and covenants.
 
Results of Operations
 
Our operations consist of drilling oil and gas wells for our customers under daywork, turnkey or footage contracts usually on a well-to-well basis. Daywork contracts are the least complex for us to perform and involve the least risk. Turnkey contracts are the most difficult to perform and involve much greater risk but provide the opportunity for higher operating profits.
 
Daywork Contracts.  Under daywork drilling contracts, we provide a drilling rig with required personnel to our customer, who supervises the drilling of the well. We are paid based on a negotiated fixed rate per day while the rig is used. During the mobilization period, we typically earn a fixed amount of revenue based on the mobilization rate stated in the contract. We attempt to set the mobilization rate at an amount equal to our external costs for the move plus our internal costs during the mobilization period. We begin earning our contracted daywork rate when we begin drilling the well. Occasionally, in periods of increased demand, our contracts will provide for the trucking costs to be paid by the customer, and we will receive a reduced dayrate during the mobilization period.
 
Turnkey Contracts.  Under a turnkey contract, we agree to drill a well for our customer to a specified depth and under specified conditions for a fixed price, regardless of the time required or the problems encountered in drilling the well. We provide technical expertise and engineering services, as well as most of the equipment and drilling supplies required to drill the well. We often subcontract for related services, such as the provision of casing crews, cementing and well logging. Under typical turnkey drilling arrangements, we do not receive progress payments and are entitled to be paid by our customer only after we have performed the terms of the drilling contract in full. The risks under a turnkey contract are greater than those under a daywork contract, because under a turnkey contract we assume most of the risks associated with drilling operations that the operator generally assumes under a daywork contract.
 
Footage Contracts.  Under footage contracts, we are paid a fixed amount for each foot drilled, regardless of the time required or the problems encountered in drilling the well. We typically pay more of the out-of-pocket costs associated with footage contracts as compared to daywork contracts. Similar to turnkey contracts, under a footage contract we assume most of the risks associated with drilling operations that the operator generally assumes under a daywork contract.
 
During periods of reduced demand for drilling rigs or excess capacity of drilling rigs in the industry, revenue rates and utilization rates may be significantly lower than the rates we are currently experiencing. Our profitability in the future will depend on many factors, but significantly on utilization rates and revenue rates for our drilling rigs.
 
The current demand for drilling rigs greatly influences the types of contracts we are able to obtain. As the demand for rigs increases, daywork rates move up and we are able to switch primarily to daywork contracts.


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For the nine months ended December 31, 2007 and 2006, and the years ended March 31, 2007 and 2006, the percentages of our drilling revenues by type of contract were as follows:
 
                                 
    Nine Months Ended
    Years Ended
 
    December 31,     March 31,  
    2007     2006     2007     2006  
 
Daywork Contracts
    93 %     97 %     96 %     89 %
Turnkey Contracts
    2 %           1 %     4 %
Footage Contracts
    5 %     3 %     3 %     7 %
 
We had 1 turnkey contract and 4 footage contracts in progress at December 31, 2007. We had no turnkey contracts in progress at March 31, 2007 or at March 31, 2006. We had 2 footage contracts in progress at both March 31, 2007 and March 31, 2006.


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Statements of Operations Analysis — Nine Months Ended December 31, 2007 Compared with the Nine Months Ended December 31, 2006
 
The following table provides information about our operations for the nine months ended December 31, 2007 and December 31, 2006.
 
                 
    Nine Months Ended
 
    December 31,  
    2007     2006  
    (In thousands)  
 
Contract drilling revenues:
               
Daywork contracts
  $ 292,617     $ 302,272  
Turnkey contracts
    4,979        
Footage contracts
    16,288       10,559  
                 
Total contract drilling revenues
  $ 313,884     $ 312,831  
                 
Contract drilling costs:
               
Daywork contracts
  $ 179,521     $ 156,479  
Turnkey contracts
    3,168        
Footage contracts
    12,907       7,538  
                 
Total contract drilling costs
  $ 195,596     $ 164,017  
                 
Drilling margin:
               
Daywork contracts
  $ 113,096     $ 145,793  
Turnkey contracts
    1,811        
Footage contracts
    3,381       3,021  
                 
Total drilling margin
  $ 118,288     $ 148,814  
                 
Revenue days by type of contract:
               
Daywork contracts
    15,203       15,084  
Turnkey contracts
    118        
Footage contracts
    968       643  
                 
Total revenue days
    16,289       15,727  
                 
EBITDA
  $ 104,241     $ 139,548  
                 
Contract drilling revenue per revenue day
  $ 19,270     $ 19,891  
Contract drilling costs per revenue day
  $ 12,008     $ 10,429  
Drilling margin per revenue day
  $ 7,262     $ 9,462  
Rig utilization rates
    89 %     97 %
Average number of rigs during the period
    66.7       59.6  


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We present drilling margin and earnings before interest, taxes, depreciation and amortization (EBITDA) information because we believe it provides investors and our management additional information to assist them in assessing our business and performance in comparison to other companies in our industry. Since drilling margin and EBITDA are “non-GAAP” financial measure under the rules and regulations of the SEC, we are providing the following reconciliation of drilling margin and EBITDA to net earnings, which is the nearest comparable GAAP financial measure.
 
                 
    Nine Months Ended
 
    December 31,  
    2007     2006  
    (In thousands)  
 
Reconciliation of drilling margin and EBITDA to net earnings:
               
Drilling margin
  $ 118,288     $ 148,814  
General and administrative expense
    (11,564 )     (8,516 )
Bad debt expense
    (2,612 )     (800 )
Other income
    129       50  
                 
EBITDA
    104,241       139,548  
                 
Income tax expense
    (18,129 )     (37,341 )
Interest income (expense), net
    2,385       2,874  
Depreciation and amortization
    (48,852 )     (38,120 )
                 
Net earnings
  $ 39,645     $ 66,961  
                 
 
Our contract drilling revenues grew by $1.1 million, or .3%, for the nine months ended December 31, 2007 from the nine months ended December 31, 2006, due to a 4% increase in revenue days due to an increase in the number of rigs in our fleet. The overall increase was partially offset by a decrease in contract drilling revenues of $621 per day, or 3%, resulting from a reduced demand for drilling rigs.
 
Our contract drilling costs grew by $31.6 million, or 19%, during the nine months ended December 31, 2007 from the corresponding period in 2006, primarily due to the increase in the number of revenue days resulting from the increase in the number of rigs in our fleet. Our contract drilling costs per revenue day increased by $1,579, or 15%, during the nine months ended December 31, 2007 from the corresponding period in 2006, primarily due to higher payroll and higher repairs and maintenance expenses. Contract drilling costs also increased due to a shift to more turnkey and footage revenue days as a percentage of total revenue days. Turnkey and footage revenue days represented 7% of total revenue days during the nine months ended December 31, 2007, compared to 4% during the nine months ended December 31, 2006. Under turnkey and footage contracts, we provide supplies and materials such as fuel, drill bits, casing and drilling fluids, which significantly add to drilling costs when compared to daywork contracts. These costs are also included in the revenues we recognize for turnkey and footage contracts, resulting in higher revenue rates per day for turnkey and footage contracts compared to daywork contracts which do not include such costs.
 
Our general and administrative expense for the nine months ended December 31, 2007 increased by $3.0 million, or 36%, compared to the corresponding period in 2006. The increase resulted from $1.1 million in additional compensation-related expenses for salaries, bonuses, relocation benefits and stock options incurred for existing and new employees in our corporate office. Professional and consulting expenses increased $1.1 million during the nine months ended December 31, 2007. In addition, we incurred $.3 million of additional general and administrative expenses during the nine months ended December 31, 2007 relating to the commencement of our Colombian operations.
 
Our depreciation and amortization expenses for the nine months ended December 31, 2007 increased by $10.7 million, or 28%, compared to the corresponding period in 2006. These increase in 2007 over 2006 resulted primarily from an increase in the average size of our rig fleet, which increases consisted entirely of newly constructed rigs. The higher costs of our new rigs increased our average depreciation costs per revenue


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day by $575 to $2,999 from $2,424 during the nine months ended December 31, 2007, compared to the corresponding period in 2006.
 
Interest income for the nine months ended December 31, 2007 decreased by $.5 million, or 16%, compared to the corresponding period in 2006 due to lower average cash and cash equivalents balances during the nine months ended December 31, 2007 as compared to the corresponding period in 2006. Average cash and cash equivalents balances were $74.2 million and $85.8 million during the nine months ended 2007 and 2006, respectively.
 
Our contract land drilling operations are subject to various federal and state laws and regulations designed to protect the environment. Maintaining compliance with these regulations is part of our day-to-day operating procedures. We monitor each of our yard facilities and each of our rig locations on a day-to-day basis for potential environmental spill risks. In addition, we maintain a spill prevention control and countermeasures plan for each yard facility and each rig location. The costs of these procedures represent only a small portion of our routine employee training, equipment maintenance and job site maintenance costs. We estimate the annual compliance costs for this program to be approximately $.4 million. We are not aware of any potential environmental clean-up obligations that would have a material adverse effect on our financial condition or results of operations.
 
Our effective income tax rates of 31.4% and 35.8% for the nine months ended December 31, 2007 and 2006, respectively, differ from the federal statutory rate of 35% due to tax benefits in foreign jurisdictions, tax benefits recognized for a previously unrecognized tax position, permanent differences and state income taxes.


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Statements of Operations Analysis — Year Ended March 31, 2007 Compared to the Year Ended March 31, 2006
 
The following table provides information about our operations for the years ended March 31, 2007 and March 31, 2006.
 
                 
    Years Ended March 31,  
    2007     2006  
    (In thousands)  
 
Contract drilling revenues:
               
Daywork contracts
  $ 399,188     $ 252,103  
Turnkey contracts
    3,445       10,830  
Footage contracts
    13,545       21,215  
                 
Total contract drilling revenues
  $ 416,178     $ 284,148  
                 
Contract drilling costs:
               
Daywork contracts
  $ 211,334     $ 143,130  
Turnkey contracts
    2,615       7,449  
Footage contracts
    10,474       15,632  
                 
Total contract drilling costs
  $ 224,423     $ 166,211  
                 
Drilling margin:
               
Daywork contracts
  $ 187,854     $ 108,973  
Turnkey contracts
    830       3,381  
Footage contracts
    3,071       5,583  
                 
Total drilling margin
  $ 191,755     $ 117,937  
                 
Revenue days by type of contract:
               
Daywork contracts
    19,995       16,138  
Turnkey contracts
    81       558  
Footage contracts
    854       1,468  
                 
Total revenue days
    20,930       18,164  
                 
EBITDA
  $ 179,890     $ 111,368  
                 
Contract drilling revenue per revenue day
  $ 19,884     $ 15,643  
Contract drilling costs per revenue day
  $ 10,723     $ 9,151  
Drilling margin per revenue day
  $ 9,162     $ 6,493  
Rig utilization rates
    95 %     95 %
Average number of rigs during the period
    60.8       52.3  


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We present drilling margin and EBITDA information because we believe it provides investors and our management additional information to assist them in assessing our business and performance in comparison to other companies in our industry. Since drilling margin and EBITDA are “non-GAAP” financial measure under the rules and regulations of the SEC, we are providing the following reconciliation of drilling margin and EBITDA to net earnings, which is the nearest comparable GAAP financial measure.
 
                 
    Years Ended March 31,  
    2007     2006  
    (In thousands)  
 
Reconciliation of drilling margin and EBITDA to net earnings:
               
Drilling margin
  $ 191,755     $ 117,937  
General and administrative expense
    (11,123 )     (6,792 )
Bad debt (expense) recovery
    (800 )     152  
Other income
    58       71  
                 
EBITDA
    179,890       111,368  
                 
Income tax expense
    (46,609 )     (29,247 )
Interest income (expense), net
    3,755       1,833  
Depreciation and amortization
    (52,856 )     (33,388 )
                 
Net earnings
  $ 84,180     $ 50,566  
                 
 
Our contract drilling revenues grew by $132.0 million, or 46%, in the year ended March 31, 2007 from the year ended March 31, 2006, primarily due to an improvement of $4,241 per day in average rig revenue rates resulting from an increase in demand for drilling rigs and the 15% increase in revenue days that primarily resulted from an increase in the number of rigs in our fleet.
 
Our contract drilling costs grew by $58.2 million, or 35%, in the year ended March 31, 2007 from the year ended March 31, 2006, primarily due to an increase in average drilling costs per revenue day of $1,572, and an increase in the number of revenue days resulting from the increase in the number of rigs in our fleet. The increase in average drilling costs per revenue day was primarily attributable to an increase in wage rates for rig personnel and an increase in supplies, repairs and maintenance expenses.
 
Our general and administrative expenses increased by $4.3 million, or 64%, in the year ended March 31, 2007 from the year ended March 31, 2006. The increase resulted primarily from stock-based compensation costs and an increase in payroll and bonus accrual costs. Effective April 1, 2006, we adopted Statement of Financial Accounting Standards (“SFAS”) No. 123 (Revised), Share-Based Payment, and, as a result, recognized $2.5 million of stock-based compensation expense in general and administrative expense in the year ended March 31, 2007. See the “Stock-based Compensation” section of Note 1 to the consolidated financial statements included in this report for additional information. Payroll and bonus accrual costs increased by $1.4 million in the year ended March 31, 2007, due to pay raises and an increase in the number of employees in our corporate office as compared to the year ended March 31, 2006.
 
Our depreciation and amortization expense in the year ended March 31, 2007 increased by $19.5 million, or 58%, from the year ended March 31, 2006. The increase in 2007 over 2006 resulted from our addition of 10 drilling rigs and related equipment in 2007 at a cost of approximately $91.4 million and rig upgrade costs of $19.9 million. The higher costs of our new rigs increased our average depreciation costs per revenue day by $687 to $2,525 in the year ended March 31, 2007 from $1,838 in the year ended March 31, 2006.
 
Interest income increased by $1.9 million, or 105%, in the year ended March 31, 2007 from the year ended March 31, 2006 due to higher average cash and cash equivalents balances during the year ended March 31, 2007 as compared to 2006. Average cash and cash equivalents balances were $85.7 million during the year ended March 31, 2007 and $56.5 million in 2006.
 
Our effective income tax rates of 35.6% for the year ended March 31, 2007, and 36.6% for the year ended March 31, 2006, differ from the federal statutory rate of 35% for each fiscal year, due to permanent


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differences and state income taxes. Permanent differences are costs included in results of operations in the accompanying financial statements which are not fully deductible for federal income tax purposes. During the quarter ended June 30, 2006, we recognized a nonrecurring increase in income tax expense and deferred income taxes of $.4 million, due to the effects of changes in Texas franchise taxes on the future reversals of temporary differences. The Texas franchise tax changes became effective June 1, 2006. At March 31, 2005, we had net operating loss carryforwards for income tax purposes of $16.5 million, which were fully utilized in fiscal year 2006.
 
Inflation
 
Due to the increased rig count in each of our market areas, availability of personnel to operate our rigs is limited. In April 2005, January 2006 and May 2006, we raised wage rates for our rig personnel by an average of 6%, 6% and 14%, respectively. We were able to pass these wage rate increases on to our customers based on contract terms. We currently do not anticipate additional wage rate increases in the year ending December 31, 2008.
 
We are experiencing increases in costs for rig repairs and maintenance and costs of rig upgrades and new rig construction, due to the increased industry-wide demand for equipment, supplies and service. We estimate these costs increased by 10% to 15% in the nine months ended December 31, 2007. We expect similar cost increases during the year ended December 31, 2008 as rig counts are expected to remain at historically high levels.
 
Off-Balance Sheet Arrangements
 
We do not currently have any off-balance sheet arrangements.
 
Recently Issued Accounting Standards
 
In July 2006, the Financial Accounting Standards Board issued FASB Interpretation No. 48, Accounting for Uncertainty in Income Taxes — An Interpretation of FASB Statement No. 109 (“FIN No. 48”). FIN No. 48 clarifies the accounting for uncertainty in income taxes recognized in a company’s financial statements in accordance with SFAS No. 109. FIN No. 48 also prescribes a recognition threshold and measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. The new FASB standard also provides guidance on derecognition, classification, interest and penalties, accounting in interim periods, disclosure and transition. We adopted the provisions of FIN No. 48 effective April 1, 2007. The adoption of FIN No. 48 had no material impact on our financial position or results of operations and financial condition.
 
In September 2006, the FASB issued SFAS No. 157, Fair Value Measurements. SFAS No. 157 defines fair value, establishes a framework for measuring fair value and expands disclosure of fair value measurements. SFAS No. 157 applies under other accounting pronouncements that require or permit fair value measurements and, accordingly, does not require any new fair value measurements. SFAS No. 157, as issued, was effective for financial statement issued for fiscal years beginning after November 15, 2007, and interim periods within those fiscal years. However, on February 12, 2008, the FASB issued FSP FAS No. 157-2, Effective Dates of FASB Statement No. 157, which delays the effective date of SFAS No. 157 for fiscal years beginning after November 15, 2008 for all nonfinancial assets and nonfinancial liabilities, except those that are recognized or disclosed at fair value in the financial statements on a recurring basis. We do not expect the adoption of SFAS No. 157 to have a material impact on our financial position or results of operations and financial condition.
 
In February 2007, the FASB issued SFAS No. 159, The Fair Value Option for Financial Assets and Financial Liabilities — Including an amendment of FASB Statement No. 115. This statement permits entities to choose to measure many financial instruments and certain other items at fair value that are not currently required to be measured at fair value and establishes presentation and disclosure requirements designed to facilitate comparisons between entities that choose different measurement attributes for similar types of assets and liabilities. SFAS No. 159 is effective for fiscal years beginning after November 15, 2007. We do not


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expect the adoption of SFAS No. 159 to have a material impact on our financial position or results of operations and financial condition.
 
In December 2007, the FASB issued SFAS No. 160, Noncontrolling interests in Consolidated Financial Statements — an Amendment of ARB No. 51. This statement establishes accounting and reporting standards for the non-controlling interest in a subsidiary and for the deconsolidation of a subsidiary. SFAS No. 160 clarifies that a non-controlling interest in a subsidiary, which is sometimes referred to as minority interest, is an ownership interest in the consolidated entity that should be reported as a component of equity in the consolidated financial statements. Among other requirements, SFAS No. 160 requires consolidated net income to be reported at amounts that include the amounts attributable to both the parent and the non-controlling interest. It also requires disclosure, on the face of the consolidated income statement, of the amounts of consolidated net income attributable to the parent and to the non-controlling interest. SFAS No. 160 is effective for fiscal years beginning on or after December 15, 2008. We do not expect the adoption to have a material impact on our financial position or results of operations and financial condition.
 
In December 2007, the FASB issued SFAS No. 141R (revised 2007) which replaces SFAS No. 141, Business Combinations (“SFAS No. 141R”). SFAS No. 141R applies to all transactions and other events in which one entity obtains control over one or more other businesses. SFAS No. 141R requires an acquirer, upon initially obtaining control of another entity, to recognize the assets, liabilities and any non-controlling interest in the acquiree at fair value as of the acquisition date. Contingent consideration is required to be recognized and measured at fair value on the date of acquisition rather than at a later date when the amount of that consideration may be determinable beyond a reasonable doubt. This fair value approach replaces the cost-allocation process required under SFAS No. 141 whereby the cost of an acquisition was allocated to the individual assets acquired and liabilities assumed based on their estimated fair value. SFAS No. 141R requires acquirers to expense acquisition-related costs as incurred rather than allocating such costs to the assets acquired and liabilities assumed, as was previously the case under SFAS No. 141. Under SFAS No. 141R, the requirements of SFAS No. 146, Accounting for Costs Associated with Exit or Disposal Activities, would have to be met in order to accrue for a restructuring plan in purchase accounting. Pre-acquisition contingencies are to be recognized at fair value, unless it is a non-contractual contingency that is not likely to materialize, in which case, nothing should be recognized in purchase accounting and, instead, that contingency would be subject to the recognition criteria of SFAS No. 5, Accounting for Contingencies. SFAS No. 141R is expected to have a significant impact on our accounting for business combinations closing on or after January 1, 2009.
 
Item 7A.   Quantitative and Qualitative Disclosures About Market Risk
 
Interest Rate Risk
 
Our exposure to market risk from changes in interest rates primarily relates to our cash equivalents, which consist of investments in highly liquid debt instruments denominated in U.S. dollars. We are averse to principal loss and ensure the safety and preservation of our invested funds by limiting default risk, market risk and reinvestment risk. We are also subject to market risk exposure related to changes in interest rates on floating rate debt we may incur under our credit facility. However, at December 31, 2007, we had no outstanding borrowings under our credit facility.
 
Foreign Currency Risk
 
Our international operations in Colombia expose us to movements in currency exchange rates, which may be volatile at times. The economic impact of currency exchange rate movements is complex because changes are often linked to various real growth, inflation, interest rates, governmental actions and other factors. These changes, if material, could cause us to change our financing and operating strategies.
 
During the nine months ended December 31, 2007, we began operating 2 drilling rigs in Colombia that generated 3% of our total revenue. We estimate, based upon our net income for our Colombian operations for the nine months ended December 31, 2007, a 10% change in foreign currency exchange rates would not have resulted in a material impact to consolidated net income.
 
We do not currently use derivative financial instruments to hedge against interest rate risk or foreign currency risk.


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Item 8.   Financial Statements and Supplementary Data
 
PIONEER DRILLING COMPANY
 
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
 
         
    Page  
 
    42  
    44  
    45  
    46  
    47  
    48  


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Report of Independent Registered Public Accounting Firm
 
To the Board of Directors and Shareholders
Pioneer Drilling Company:
 
We have audited the accompanying consolidated balance sheets of Pioneer Drilling Company and subsidiaries as of December 31, 2007 and March 31, 2007, and the related consolidated statements of operations, shareholders’ equity and comprehensive income, and cash flows for the nine months ended December 31, 2007 and for each of the years in the two-year period ended March 31, 2007. In connection with our audits of the consolidated financial statements, we also have audited the financial statement schedule II. These consolidated financial statements and financial statement schedule are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated financial statements and financial statement schedule based on our audits.
 
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. 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 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 Pioneer Drilling Company and subsidiaries as of December 31, 2007 and March 31, 2007, and the results of their operations and their cash flows for the nine months ended December 31, 2007 and for each of the years in the two-year period ended March 31, 2007, in conformity with U.S. generally accepted accounting principles. Also in our opinion, the related financial statement schedule, when considered in relation to the basic consolidated financial statements taken as a whole, presents fairly, in all material respects, the information set forth therein.
 
As discussed in Note 1 to the consolidated financial statements, the Company adopted the provisions of Statement of Financial Accounting Standards No. 123 (Revised 2004), Share-Based Payment, effective April 1, 2006, and the Company adopted Financial Accounting Standards Board Interpretation No. 48, Accounting for Uncertainty in Income Taxes — an interpretation of FASB Statement No. 109, effective April 1, 2007.
 
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the effectiveness of Pioneer Drilling Company’s internal control over financial reporting as of December 31, 2007, based on criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), and our report dated February 26, 2008 expressed an unqualified opinion on the effectiveness of the Company’s internal control over financial reporting.
 
/s/  KPMG LLP
 
San Antonio, Texas
February 26, 2008


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Report of Independent Registered Public Accounting Firm
 
The Board of Directors and Stockholders Pioneer Drilling Company:
 
We have audited Pioneer Drilling Company’s internal control over financial reporting as of December 31, 2007, based on criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Pioneer Drilling Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting included in the accompanying Management’s Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting 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 effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audit also included performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
 
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
 
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
 
In our opinion, Pioneer Drilling Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2007, based on criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.
 
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of Pioneer Drilling Company as of December 31, 2007 and March 31, 2007, and the related consolidated statements of operations, shareholders’ equity and comprehensive income, and cash flows for the nine months ended December 31, 2007 and for each of the years in the two-year period ended March 31, 2007, and our report dated February 26, 2008 expressed an unqualified opinion on those consolidated financial statements.
 
/s/  KPMG LLP
 
San Antonio, Texas
February 26, 2008


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PIONEER DRILLING COMPANY AND SUBSIDIARIES
 
 
                 
    December 31,
    March 31,
 
    2007     2007  
    (In thousands, except share data)  
 
ASSETS
Current assets:
               
Cash and cash equivalents
  $ 76,703     $ 84,945  
Receivables:
               
Trade, net
    46,759       54,206  
Contract drilling in progress
    7,861       9,837  
Income tax receivable
    611       3,492  
Deferred income taxes
    3,670       2,175  
Inventory
    1,180        
Prepaid expenses
    5,073       3,653  
                 
Total current assets
    141,857       158,308  
                 
Property and equipment, at cost:
               
Drilling rigs and equipment
    553,864       441,072  
Transportation equipment
    18,676       15,941  
Land, buildings and other
    6,157       5,736  
                 
      578,697       462,749  
Less accumulated depreciation and amortization
    161,675       119,848  
                 
Net property and equipment
    417,022       342,901  
Deferred income taxes
    573        
Intangible and other assets
    760       286  
                 
Total assets
  $ 560,212     $ 501,495  
                 
 
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities:
               
Accounts payable
  $ 21,424     $ 18,626  
Prepaid drilling contracts
    1,933        
Accrued expenses:
               
Payroll and related employee costs
    5,172       7,086  
Insurance premiums and deductibles
    9,548       6,754  
Other
    3,973       1,753  
                 
Total current liabilities
    42,050       34,219  
Non-current liabilities
    254       346  
Deferred income taxes
    46,836       38,821  
                 
Total liabilities
    89,140       73,386  
                 
Commitments and contingencies
               
Shareholders’ equity:
               
Preferred stock, 10,000,000 shares authorized; none issued and outstanding
           
Common stock $.10 par value; 100,000,000 shares authorized; 49,650,978 shares and 49,628,478 shares issued and outstanding at December 31, 2007 and March 31, 2006, respectively
    4,965       4,963  
Additional paid-in capital
    294,922       291,607  
Accumulated earnings
    171,185       131,539  
                 
Total shareholders’ equity
    471,072       428,109  
                 
Total liabilities and shareholders’ equity
  $ 560,212     $ 501,495  
                 
 
See accompanying notes to consolidated financial statements.


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PIONEER DRILLING COMPANY AND SUBSIDIARIES
 
 
                         
    Nine Months
             
    Ended
             
    December 31,
    Years Ended March 31,  
    2007     2007     2006  
    (In thousands, except per share data)  
 
Contract drilling revenues
  $ 313,884     $ 416,178     $ 284,148  
                         
Costs and expenses:
                       
Contract drilling
    195,596       224,423       166,211  
Depreciation and amortization
    48,852       52,856       33,388  
General and administrative
    11,564       11,123       6,792  
Bad debt expense (recovery)
    2,612       800       (152 )
                         
Total operating costs and expenses
    258,624       289,202       206,239  
                         
Income from operations
    55,260       126,976       77,909  
                         
Other income (expense):
                       
Interest expense
    (16 )     (73 )     (236 )
Interest income
    2,401       3,828       2,069  
Other
    129       58       71  
                         
Total other income
    2,514       3,813       1,904  
                         
Income before income taxes
    57,774       130,789       79,813  
Income tax expense
    (18,129 )     (46,609 )     (29,247 )
                         
Net earnings
  $ 39,645     $ 84,180     $ 50,566  
                         
Earnings per common share — Basic
  $ 0.80     $ 1.70     $ 1.08  
                         
Earnings per common share — Diluted
  $ 0.79     $ 1.68     $ 1.06  
                         
Weighted average number of shares outstanding — Basic
    49,645       49,603       46,808  
                         
Weighted average number of shares outstanding — Diluted
    50,201       50,132       47,506  
                         
 
See accompanying notes to consolidated financial statements.


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PIONEER DRILLING COMPANY AND SUBSIDIARIES
 
 
                                         
                Additional
          Total
 
    Shares
    Amount
    Paid In
    Accumulated
    Shareholders’
 
    Common     Common     Capital     Earnings (Deficit)     Equity  
    (In thousands)  
 
Balance as of March 31, 2005
    45,893     $ 4,589     $ 220,232     $ (3,206 )   $ 221,615  
Comprehensive income:
                                       
Net earnings
                      50,567       50,567  
                                         
Total comprehensive income
                            50,567  
                                         
Issuance of common stock for:
                                       
Sale, net of related expenses of $968
    3,000       300       61,402             61,702  
Exercise of options and related income tax benefits of $4,010
    699       70       6,722             6,792  
                                         
Balance as of March 31, 2006
    49,592       4,959       288,356       47,361       340,676  
Comprehensive income:
                                       
Net earnings
                      84,179       84,179  
                                         
Total comprehensive income
                            84,179  
                                         
Issuance of common stock for:
                                       
Exercise of options and related income tax benefits of $24
    37       4       190             194  
Stock-based compensation expense
                3,061             3,061  
                                         
Balance as of March 31, 2007
    49,629       4,963       291,607       131,540       428,110  
Comprehensive income:
                                       
Net earnings
                      39,645       39,645  
                                         
Total comprehensive income
                            39,645  
                                         
Issuance of common stock for:
                                       
Exercise of options and related income tax benefits of $54
    22       2       158             160  
Stock-based compensation expense
                3,157             3,157  
                                         
Balance as of December 31, 2007
    49,651     $ 4,965     $ 294,922     $ 171,185     $ 471,072  
                                         
 
See accompanying notes to consolidated financial statements.


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PIONEER DRILLING COMPANY AND SUBSIDIARIES
 
 
                         
    Nine Months
             
    Ended
             
    December 31,
    Years Ended March 31,  
    2007     2007     2006  
    (In thousands)  
 
Cash flows from operating activities:
                       
Net earnings
  $ 39,645     $ 84,180     $ 50,566  
Adjustments to reconcile net earnings to net cash provided by operating activities:
                       
Depreciation and amortization
    48,852       52,856       33,388  
Allowance for doubtful accounts
    2,612       800       (152 )
Loss on dispositions of property and equipment
    2,809       5,760       2,895  
Stock-based compensation expense
    3,157       3,061        
Deferred income taxes
    5,947       10,653       14,279  
Change in other assets
    (519 )     20       209  
Change in non-current liabilities
    (92 )     (41 )     (12 )
Changes in current assets and liabilities:
                       
Receivables
    9,692       (23,170 )     (13,540 )
Inventory
    (1,180 )            
Prepaid expenses
    (1,420 )     (1,445 )     (331 )
Accounts payable
    919       (137 )     419  
Income tax payable
          (6,843 )     6,639  
Prepaid drilling contracts
    1,933       (140 )     (33 )
Accrued expenses
    3,100       5,976       2,757  
                         
Net cash provided by operating activities
    115,455       131,530       97,084  
                         
Cash flows from financing activities:
                       
Proceeds from exercise of options
    107       174       6,792  
Proceeds from common stock, net of offering cost of $968 in 2006
                61,702  
Payments of debt
                (18,860 )
Excess tax benefit of stock option exercises
    54       27        
                         
Net cash provided by financing activities
    161       201       49,634  
                         
Cash flows from investing activities:
                       
Purchases of property and equipment
    (126,158 )     (144,507 )     (128,871 )
Proceeds from sale (purchase) of marketable securities, net
                1,000  
Proceeds from sale of property and equipment
    2,300       6,547       2,654  
                         
Net cash used in investing activities
    (123,858 )     (137,960 )     (125,217 )
                         
Net increase (decrease) in cash and cash equivalents
    (8,242 )     (6,229 )     21,501  
Beginning cash and cash equivalents
    84,945       91,174       69,673  
                         
Ending cash and cash equivalents
  $ 76,703     $ 84,945     $ 91,174  
                         
Supplementary disclosure:
                       
Interest paid
  $ 15     $ 104     $ 407  
Income tax paid
  $ 9,473     $ 46,258     $ 4,322  
Tax benefit from exercise of nonqualified options
  $     $     $ 4,010  
 
See accompanying notes to consolidated financial statements.


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PIONEER DRILLING COMPANY AND SUBSIDIARIES
 
 
1.   Organization and Summary of Significant Accounting Policies
 
Business and Principles of Consolidation
 
Pioneer Drilling Company provides contract land drilling services to its customers in select oil and natural gas exploration and production regions in the United States and Colombia. As of December 31, 2007, our rig fleet consisted of 66 operating drilling rigs, 17 of which were operating in our South Texas division, 20 of which were operating in our East Texas division, 10 of which were operating in our North Texas division, 6 of which were operating in our Western Oklahoma division, 11 of which were operating in our Rocky Mountain division consisting of locations in Utah and North Dakota and 2 of which were operating internationally in Colombia. Not included in our 66 operating rig count is a 1000 horsepower rig that began operations in Colombia on February 20, 2008 and 2 additional rigs that we plan to deploy for further expansion into international markets.
 
We conduct our operations in the United States through our principal operating subsidiary, Pioneer Drilling Services, Ltd. and we conduct our operations in Colombia through Pioneer de Colombia SDAD, Ltda, Surcusal Colombia. The accompanying consolidated financial statements include our accounts and the accounts of our wholly owned subsidiaries. All intercompany balances and transactions have been eliminated in consolidation. In December 2007, our Board of Directors approved a change in our fiscal year end from March 31st to December 31st. The fiscal year end change was effective December 31, 2007 and resulted in a nine month reporting period from April 1, 2007 to December 31, 2007. We implemented the fiscal year end change to align our United States reporting period with the required Colombian statutory reporting period as well as the reporting periods of peer companies in the industry.
 
We have prepared the accompanying consolidated financial statements in accordance with accounting principles generally accepted in the United States of America. In preparing the financial statements, we make various estimates and assumptions that affect the amounts of assets and liabilities we report as of the dates of the balance sheets and income and expenses we report for the periods shown in the income statements and statements of cash flows. Our actual results could differ significantly from those estimates. Material estimates that are particularly susceptible to significant changes in the near term relate to our recognition of revenues and costs for turnkey contracts, our estimate of the allowance for doubtful accounts, our estimate of the self-insurance portion of our health and workers’ compensation insurance, our estimate of asset impairments, our estimate of the valuation allowance for deferred taxes and our determination of depreciation and amortization expense.
 
Drilling Contracts
 
Our drilling contracts generally provide for compensation on either a daywork, turnkey or footage basis. Contract terms generally depend on the complexity and risk of operations, the on-site drilling conditions, the type of equipment used and the anticipated duration of the work to be performed. Generally, our contracts provide for the drilling of a single well and typically permit the customer to terminate on short notice. However, we have entered into more longer-term drilling contracts during periods of high rig demand. In addition, we have entered into longer-term drilling contracts for our newly constructed rigs. As of February 8, 2008, we had 19 contracts with terms of 6 months to 3 years in duration, of which 9 will expire by August 9, 2008, 6 have a remaining term of 6 to 12 months, 2 have a remaining term of 12 to 18 months and 2 have a remaining term in excess of 18 months.
 
Income Taxes
 
Pursuant to Statement of Financial Accounting Standards (“SFAS”) No. 109, “Accounting for Income Taxes,” we follow the asset and liability method of accounting for income taxes, under which we recognize deferred tax assets and liabilities for the future tax consequences attributable to differences between the


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PIONEER DRILLING COMPANY AND SUBSIDIARIES
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
financial statement carrying amounts of existing assets and liabilities and their respective tax basis. We measure our deferred tax assets and liabilities by using the enacted tax rates we expect to apply to taxable income in the years in which we expect to recover or settle those temporary differences. Under SFAS No. 109, we reflect in income the effect of a change in tax rates on deferred tax assets and liabilities in the period during which the change occurs.
 
Earnings Per Common Share
 
We compute and present earnings per common share in accordance with SFAS No. 128, “Earnings per Share.” This standard requires dual presentation of basic and diluted earnings per share on the face of our statement of operations.
 
Stock-based Compensation
 
Effective April 1, 2006, we adopted SFAS No. 123 (Revised), Share-Based Payment (“SFAS 123R”), utilizing the modified prospective approach. Prior to the adoption of SFAS 123R, we accounted for stock option grants in accordance with the intrinsic-value-based method prescribed by Accounting Principles Board Opinion No. 25, Accounting for Stock Issued to Employees (“APB 25”), and related interpretations, as permitted by SFAS No. 123, Accounting for Stock-Based Compensation (“SFAS 123”). Accordingly, we recognized no compensation expense for stock options granted, as all stock options were granted at an exercise price equal to the closing market value of the underlying common stock on the date of grant. Under the modified prospective approach, compensation cost for the fiscal year ended March 31, 2007 includes compensation cost for all stock options granted prior to, but not yet vested as of, April 1, 2006, based on the grant-date fair value estimated in accordance with SFAS 123, and compensation cost for all stock options granted subsequent to April 1, 2006, based on the grant-date fair value estimated in accordance with SFAS 123R. We use the graded vesting method for recognizing compensation costs for stock options. Prior periods were not restated to reflect the impact of adopting this new standard.
 
The following table illustrates the pro forma effect on operating results and per share information had we accounted for stock-based compensation in accordance with SFAS 123R for the year ended March 31, 2006 (amounts in thousands, except per share data):
 
         
Net earnings — as reported
  $ 50,566  
Deduct: Total stock-based employee compensation expense determined under fair-value-based method for all awards, net of related tax effect
    (1,894 )
         
Net earnings — pro forma
  $ 48,672  
         
Net earnings per share — as reported — basic
  $ 1.08  
Net earnings per share — as reported — diluted
  $ 1.06  
Net earnings per share — pro forma — basic
  $ 1.04  
Net earnings per share — pro forma — diluted
  $ 1.02  
 
As a result of adopting SFAS 123R on April 1, 2006, our income before income taxes, net earnings and basic and diluted earnings per common share for the fiscal year ended March 31, 2007 were $3.1 million, $2.0 million and $.04 per share lower, respectively, than if we had continued to account for stock-based compensation under APB 25 for our stock option grants. Compensation costs of approximately $2.5 million and $.5 million for stock options were recognized in general and administrative expense and contract drilling costs, respectively, for the fiscal year ended March 31, 2007. Approximately $.3 million of the compensation costs included in general and administrative expense relate to stock options granted to outside directors that vested immediately upon grant pursuant to our stock option plans. In accordance with SFAS 123R, the entire compensation cost has been recognized for stock options that are fully vested at the grant date.


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PIONEER DRILLING COMPANY AND SUBSIDIARIES
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
Compensation costs of approximately $2.5 million and $.7 million for stock options were recognized in general and administrative expense and contract drilling costs, respectively, for the nine months ended December 31, 2007. Approximately $.4 million of the compensation costs included in general and administrative expense relate to stock options granted to outside directors that vested immediately upon grant pursuant to our stock option plans.
 
We receive a tax deduction for certain stock option exercises during the period the options are exercised, generally for the excess of the price at which the options are sold over the exercise price of the options. In accordance with SFAS 123R, we reported all excess tax benefits resulting from the exercise of stock options as financing cash flows in our consolidated statement of cash flows. There were 22,500 stock options exercised during the nine months ended December 31, 2007.
 
Revenue and Cost Recognition
 
We earn our revenues by drilling oil and gas wells for our customers under daywork, turnkey or footage contracts, which usually provide for the drilling of a single well. We recognize revenues on daywork contracts for the days completed based on the dayrate each contract specifies. We recognize revenues from our turnkey and footage contracts on the percentage-of-completion method based on our estimate of the number of days to complete each contract. With most drilling contracts, we receive payments contractually designated for the mobilization of rigs and other equipment. Payments received, and costs incurred for the mobilization services are deferred and recognized on a straight line basis over the contract term of certain drilling contracts. Costs incurred to relocate rigs and other drilling equipment to areas in which a contract has not been secured are expensed as incurred. Reimbursements that we receive for out-of-pocket expenses are recorded as revenue and operating costs.
 
Our management has determined that it is appropriate to use the percentage-of-completion method, as defined in the American Institute of Certified Public Accountants’ Statement of Position 81-1, to recognize revenue on our turnkey and footage contracts. Although our turnkey and footage contracts do not have express terms that provide us with rights to receive payment for the work that we perform prior to drilling wells to the agreed-on depth, we use this method because, as provided in applicable accounting literature, we believe we achieve a continuous sale for our work-in-progress and we believe, under applicable state law, we ultimately could recover the fair value of our work-in-progress even in the event we were unable to drill to the agreed-on depth in breach of the applicable contract. However, in the event we were unable to drill to the agreed-on depth in breach of the contract, ultimate recovery of that value would be subject to negotiations with the customer and the possibility of litigation.
 
If a customer defaults on its payment obligation to us under a turnkey or footage contract, we would need to rely on applicable law to enforce our lien rights, because our turnkey and footage contracts do not expressly grant to us a security interest in the work we have completed under the contract and we have no ownership rights in the work-in-progress or completed drilling work, except any rights arising under the applicable lien statute on foreclosure. If we were unable to drill to the agreed-on depth in breach of the contract, we also would need to rely on equitable remedies outside of the contract, including quantum meruit, available in applicable courts to recover the fair value of our work-in-progress under a turnkey or footage contract.
 
We accrue estimated contract costs on turnkey and footage contracts for each day of work completed based on our estimate of the total costs to complete the contract divided by our estimate of the number of days to complete the contract. Contract costs include labor, materials, supplies, repairs and maintenance, operating overhead allocations and allocations of depreciation and amortization expense. We charge general and administrative expenses to expense as we incur them. Changes in job performance, job conditions and estimated profitability on uncompleted contracts may result in revisions to costs and income. When we encounter, during the course of our drilling operations, conditions unforeseen in the preparation of our original cost estimate, we immediately increase our cost estimate for the additional costs to complete the contract. If


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PIONEER DRILLING COMPANY AND SUBSIDIARIES
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
we anticipate a loss on a contract in progress at the end of a reporting period due to a change in our cost estimate, we immediately accrue the entire amount of the estimated loss including all costs that are included in our revised estimated cost to complete that contract in our consolidated statement of operations for that reporting period.
 
The asset “contract drilling in progress” represents revenues we have recognized in excess of amounts billed on contracts in progress. The asset “prepaid and other current assets” includes deferred mobilization costs for certain drilling contracts. The liability “prepaid drilling contracts” represents deferred mobilization revenues for certain drilling contracts and amounts collected on contracts in excess of revenues recognized.
 
Foreign Currencies
 
Our functional currency for our foreign subsidiary in Colombia is the U.S. dollar. Nonmonetary assets and liabilities are translated at historical rates and monetary assets and liabilities are translated at exchange rates in effect at the end of the period. Income statement accounts are translated at average rates for the period. Gains and losses from remeasurement of foreign currency financial statements into U.S. dollars and from foreign currency transactions are included in other income or expense.
 
Cash and Cash Equivalents
 
For purposes of the statements of cash flows, we consider all highly liquid debt instruments purchased with a maturity of three months or less to be cash equivalents. Cash equivalents consist of investments in corporate and government money market accounts. Cash equivalents at December 31, 2007 and March 31, 2007 were $69.0 million and $84.9 million, respectively.
 
Trade Accounts Receivable
 
We record trade accounts receivable at the amount we invoice our customers. These accounts do not bear interest. The allowance for doubtful accounts is our best estimate of the amount of probable credit losses in our accounts receivable as of the balance sheet date. We determine the allowance based on the credit worthiness of our customers and general economic conditions. Consequently, an adverse change in those factors could affect our estimate of our allowance for doubtful accounts. We review our allowance for doubtful accounts monthly. Balances more than 90 days past due are reviewed individually for collectability. We charge off account balances against the allowance after we have exhausted all reasonable means of collection and determined that the potential for recovery is remote. We do not have any off-balance sheet credit exposure related to our customers. We recorded bad debt expense of $2.6 million during the nine months ended December 31, 2007 and wrote off a $3.6 million accounts receivable balance that we do not expect to recover from a customer in bankruptcy. We had no allowance for doubtful accounts at December 31, 2007. At March 31, 2007, our allowance for doubtful accounts was $1.0 million.
 
Prepaid Expenses
 
Prepaid expenses include items such as insurance, rent deposits and fees. We routinely expense these items in the normal course of business over the periods these expenses benefit. Prepaid expenses also include deferred mobilization costs for certain drilling contracts that are recognized on a straight line basis over the contract term.
 
Inventories
 
Inventories are primarily replacement parts and supplies held for use in our drilling operations. Inventories are valued at the lower of cost (first in, first out or actual) or market value.


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PIONEER DRILLING COMPANY AND SUBSIDIARIES
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
Property and Equipment
 
We provide for depreciation of our drilling, transportation and other equipment using the straight-line method over useful lives that we have estimated and that range from 3 to 15 years. We record the same depreciation expense whether a rig is idle or working.
 
We charge our expenses for maintenance and repairs to contract drilling costs. We charge our expenses for renewals and betterments to the appropriate property and equipment accounts. We recorded losses on disposition of our property and equipment in contract drilling costs of $2.8 million, $5.8 million and $2.9 million during the nine months ended December 31, 2007 and the years ended March 31, 2007, and 2006, respectively. During the year ended March 31, 2006, we capitalized $.2 million of interest costs incurred during the construction periods of certain drilling equipment. We did not capitalize any interest costs during the nine months ended December 31, 2007 or during the year ended March 31, 2007. At March 31, 2007, costs incurred on rigs under construction were approximately $8.6 million. We had no rigs under construction at December 31, 2007.
 
We review our long-lived assets and intangible assets for impairment whenever events or circumstances provide evidence that suggests that we may not recover the carrying amounts of any of these assets. In performing the review for recoverability, we estimate the future net cash flows we expect to obtain from the use of each asset and its eventual disposition. If the sum of these estimated future undiscounted net cash flows is less than the carrying amount of the asset, we recognize an impairment loss.
 
Intangibles and Other Assets
 
Intangible and other assets consist of cash deposits related to the deductibles on our workers compensation insurance policies, loan fees, net of amortization, and non-compete agreements relating to acquisitions, net of amortization. Loan fees are being amortized over the two-year term of the related credit facility described in Note 2. Non-compete agreements are amortized over the term of the non-compete agreements of three to five years.
 
Derivative Instruments and Hedging Activities
 
We do not have any free standing derivative instruments and we do not engage in hedging activities.
 
Related-Party Transactions
 
Our Chief Executive Officer, Chief Operating Officer, Senior Vice President of Marketing, and a Vice President of Operations occasionally acquire a 1% to 5% minority working interest in oil and gas wells that we drill for 1 of our customers. These individuals acquired a minority working interest in 4, 3 and 1 well(s) that we drilled for this customer during the nine months ended December 31, 2007 and during the years ended March 31, 2007 and 2006, respectively. We recognized contract drilling revenues of $1.6 million, $1.9 million and $.5 million on these wells during the nine months ended December 31, 2007 and during the years ended March 31, 2007 and 2006, respectively.
 
Recently Issued Accounting Standards
 
In July 2006, the Financial Accounting Standards Board issued FASB Interpretation No. 48, Accounting for Uncertainty in Income Taxes — An Interpretation of FASB Statement No. 109 (“FIN No. 48”). FIN No. 48 clarifies the accounting for uncertainty in income taxes recognized in a company’s financial statements in accordance with SFAS No. 109. FIN No. 48 also prescribes a recognition threshold and measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. The new FASB standard also provides guidance on derecognition, classification, interest and penalties, accounting in interim periods, disclosure and transition. We adopted the provisions of FIN No. 48


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PIONEER DRILLING COMPANY AND SUBSIDIARIES
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
effective April 1, 2007. The adoption of FIN No. 48 had no material impact on our financial position or results of operations and financial condition.
 
In September 2006, the FASB issued SFAS No. 157, Fair Value Measurements. SFAS No. 157 defines fair value, establishes a framework for measuring fair value and expands disclosure of fair value measurements. SFAS No. 157 applies under other accounting pronouncements that require or permit fair value measurements and, accordingly, does not require any new fair value measurements. SFAS No. 157, as issued, was effective for financial statement issued for fiscal years beginning after November 15, 2007, and interim periods within those fiscal years. However, on February 12, 2008, the FASB issued FSP FAS No. 157-2, Effective Dates of FASB Statement No. 157, which delays the effective date of SFAS No. 157 for fiscal years beginning after November 15, 2008 for all nonfinancial assets and nonfinancial liabilities, except those that are recognized or disclosed at fair value in the financial statements on a recurring basis. We do not expect the adoption of SFAS No. 157 to have a material impact on our financial position or results of operations and financial condition.
 
In February 2007, the FASB issued SFAS No. 159, The Fair Value Option for Financial Assets and Financial Liabilities — Including an amendment of FASB Statement No. 115. This statement permits entities to choose to measure many financial instruments and certain other items at fair value that are not currently required to be measured at fair value and establishes presentation and disclosure requirements designed to facilitate comparisons between entities that choose different measurement attributes for similar types of assets and liabilities. SFAS No. 159 is effective for fiscal years beginning after November 15, 2007. We do not expect the adoption of SFAS No. 159 to have a material impact on our financial position or results of operations and financial condition.
 
In December 2007, the FASB issued SFAS No. 160, Noncontrolling interests in Consolidated Financial Statements — an Amendment of ARB No. 51. This statement establishes accounting and reporting standards for the non-controlling interest in a subsidiary and for the deconsolidation of a subsidiary. SFAS No. 160 clarifies that a non-controlling interest in a subsidiary, which is sometimes referred to as minority interest, is an ownership interest in the consolidated entity that should be reported as a component of equity in the consolidated financial statements. Among other requirements, SFAS No. 160 requires consolidated net income to be reported at amounts that include the amounts attributable to both the parent and the non-controlling interest. It also requires disclosure, on the face of the consolidated income statement, of the amounts of consolidated net income attributable to the parent and to the non-controlling interest. SFAS No. 160 is effective for fiscal years beginning on or after December 15, 2008. We do not expect the adoption to have a material impact on our financial position or results of operations and financial condition.
 
In December 2007, the FASB issued SFAS No. 141R (revised 2007) which replaces SFAS No. 141, Business Combinations (“SFAS No. 141R”). SFAS No. 141R applies to all transactions and other events in which one entity obtains control over one or more other businesses. SFAS No. 141R requires an acquirer, upon initially obtaining control of another entity, to recognize the assets, liabilities and any non-controlling interest in the acquiree at fair value as of the acquisition date. Contingent consideration is required to be recognized and measured at fair value on the date of acquisition rather than at a later date when the amount of that consideration may be determinable beyond a reasonable doubt. This fair value approach replaces the cost-allocation process required under SFAS No. 141 whereby the cost of an acquisition was allocated to the individual assets acquired and liabilities assumed based on their estimated fair value. SFAS No. 141R requires acquirers to expense acquisition-related costs as incurred rather than allocating such costs to the assets acquired and liabilities assumed, as was previously the case under SFAS No. 141. Under SFAS No. 141R, the requirements of SFAS No. 146, Accounting for Costs Associated with Exit or Disposal Activities, would have to be met in order to accrue for a restructuring plan in purchase accounting. Pre-acquisition contingencies are to be recognized at fair value, unless it is a non-contractual contingency that is not likely to materialize, in which case, nothing should be recognized in purchase accounting and, instead, that contingency would be


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PIONEER DRILLING COMPANY AND SUBSIDIARIES
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
subject to the recognition criteria of SFAS No. 5, Accounting for Contingencies. SFAS No. 141R is expected to have a significant impact on our accounting for business combinations closing on or after January 1, 2009.
 
Reclassifications
 
Certain amounts in the financial statements for the prior years have been reclassified to conform to the current year’s presentation.
 
2.   Long-term Debt, Subordinated Debt and Note Payable
 
We have a $20.0 million credit facility with Frost National Bank, consisting of a $10.0 million revolving line and letter of credit facility and a $10.0 million acquisition facility for the acquisition of drilling rigs, drilling rig transportation equipment and associated equipment. Borrowings under the credit facility bear interest at a rate equal to Frost National Bank’s prime rate (7.25% at December 31, 2007) or, at our option, at LIBOR plus a percentage ranging from 1.5% to 2.25%, based on our operating leverage ratio. Borrowings are secured by most of our assets, including all our drilling rigs and associated equipment and receivables. At December 31, 2007, we had no borrowings under the acquisition facility and we had used approximately $8.0 million of availability under the revolving line and letter of credit facility through the issuance of letters of credit in the ordinary course of business. The remaining availability under the revolving line and letter of credit facility is $2.0 million. Both the revolving line and letter of credit facility and acquisition facility are scheduled to mature in October 2008.
 
The sum of (1) the draws and (2) the amount of all outstanding letters of credit issued for our account under the revolving line and letter of credit facility portion of our credit facility is limited to 75% of our eligible accounts receivable, not to exceed $10.0 million. Therefore, if 75% of our eligible accounts receivable was less than $10.0 million, our ability to draw under this line would be reduced. At December 31, 2007, we had no outstanding advances under this line of credit, we had outstanding letters of credit of $8.0 million and 75% of our eligible accounts receivable was $32.4 million. The letters of credit have been issued to three workers’ compensation insurance companies to secure possible future claims under the deductibles on these policies. It is our practice to pay any amounts due under these deductibles as they are incurred. Therefore, we do not anticipate that the lenders will be required to fund any draws under these letters of credit.
 
At December 31, 2007, we were in compliance with all covenants contained in the credit agreement related to our credit facility. Those covenants include, among others, requirements that we maintain a debt to total capitalization ratio of not greater than 0.2 to 1, a fixed charged coverage ratio of not less than 1.5 to 1 and an operating leverage ratio of not more than 2.5 to 1. The covenants also restrict us from paying dividends, restrict us from the sale of assets not permitted by the credit facility and restrict us from the incurrence of additional indebtedness in excess of $3.0 million, to the extent not otherwise allowed by the credit facility.
 
3.   Leases
 
We lease various office equipment under non-cancelable operating leases expiring through 2010 and real estate under non-cancelable operating leases as follows:
 
  •  our corporate office facilities, at a cost escalating from $10,880 per month to $18,805 per month over 102 months, pursuant to a lease extending through December 2013;
 
  •  a trucking department office, storage and maintenance yard in Alice, Texas, at a cost of $5,200 per month, pursuant to a lease extending through July 2009;
 
  •  a 2.2-acre division office and storage yard in Vernal, Utah, at a cost escalating from $6,300 per month to $6,615 per month, pursuant to a lease extending through November 2009; and


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PIONEER DRILLING COMPANY AND SUBSIDIARIES
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
 
  •  a marketing office in Denver Colorado, at a cost escalating from $1,092 to $1,217 per month, pursuant to a lease extending through June 2010.
 
Rent expense under operating leases for the nine months ended December 31, 2007 and the years ended March 31, 2007 and 2006 was $.3 million in each period.
 
Future lease obligations as of December 31, 2007 were as follows (amounts in thousands):
 
         
Years Ended
     
December 31,
     
 
2008
  $ 371  
2009
    346  
2010
    227  
2011
    217  
2012
    220  
Thereafter
    224  
         
    $ 1,605  
         
 
4.   Income Taxes
 
The jurisdictional components of income before income taxes consist of the following (amounts in thousands):
 
                         
    Nine Months
             
    Ended
             
    December 31,
    Years Ended March 31,  
    2007     2007     2006  
 
Domestic
  $ 55,752     $ 130,789     $ 79,813  
Foreign
    2,022              
                         
Income before income tax
  $ 57,774     $ 130,789     $ 79,813  
                         
 
The components of our income tax expense (benefit) consist of the following (amounts in thousands):
 
                         
    Nine Months
             
    Ended
             
    December 31,
    Years Ended March 31,  
    2007     2007     2006  
 
Current tax:
                       
Federal
  $ 10,587     $ 34,252     $ 14,266  
State
    1,593       1,704       701  
Foreign
                 
                         
      12,180       35,956       14,967  
                         
Deferred taxes:
                       
Federal
    6,533       9,195       13,967  
State
    (100 )     1,458       313  
Foreign
    (484 )            
                         
      5,949       10,653       14,280  
                         
Income tax expense
  $ 18,129     $ 46,609     $ 29,247  
                         


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PIONEER DRILLING COMPANY AND SUBSIDIARIES
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
The difference between the income tax expense and the amount computed by applying the federal statutory income tax rate (35%) to income before income taxes consist of the following (amounts in thousands):
 
                         
    Nine Months
             
    Ended
             
    December 31,
    Years Ended March 31,  
    2007     2007     2006  
 
Expected tax expense
  $ 20,221     $ 45,776     $ 27,935  
State income taxes
    971       2,417       659  
Incentive stock options
    538       547        
Tax basis adjustment to 35%
                814  
Tax benefits in foreign jurisdictions
    (1,191 )            
Domestic production activities deduction
    (729 )     (1,388 )      
Tax-exempt interest income
    (475 )     (422 )      
Non deductible items for tax purposes
    61       48       32  
Uncertain tax positions
    (717 )     (372 )     (198 )
Other
    (550 )     3       5  
                         
    $ 18,129     $ 46,609     $ 29,247  
                         
 
Income tax expense (benefit) was allocated as follows (amounts in thousands):
 
                         
    Nine Months
             
    Ended
             
    December 31,
    Years Ended March 31,  
    2007     2007     2006  
 
Results of operations
  $ 18,129     $ 46,609     $ 29,247  
Stockholders’ equity
    (54 )     (24 )     (4,010 )
                         
    $ 18,075     $ 46,585     $ 25,237  
                         


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PIONEER DRILLING COMPANY AND SUBSIDIARIES
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
Deferred income taxes arise from temporary differences between the tax bases of assets and liabilities and their reported amounts in the consolidated financial statements. The components of our deferred income tax assets and liabilities were as follows (amounts in thousands):
 
                 
    December 31,
    March 31,
 
    2007     2007  
 
Deferred tax assets:
               
Employee benefits accrual
  $ 3,292     $ 1,821  
Accounts receivable reserve
          354  
Employee stock based compensation
    1,095       510  
Accrued expenses not deductible for tax purposes
    498       58  
Accrued revenue not income for book purposes
    613        
Foreign net operating loss carryforward
    3,637        
                 
      9,135       2,743  
Valuation allowance
    (3,997 )      
                 
Total deferred tax assets
    5,138       2,743  
                 
Deferred tax liabilities:
               
Property and equipment
    47,731       38,672  
Other
          717  
                 
Total deferred tax liabilities
    47,731       39,389  
                 
Net deferred tax liabilities
  $ 42,593     $ 36,646  
                 
 
In assessing the realizability of deferred tax assets, we consider whether it is more likely than not that some portion or all of the deferred tax assets will not be realized. Based on the expectation of future taxable income and that the deductible temporary differences will offset existing taxable temporary differences, we believe it is more likely than not that we will realize the benefits of these deductible temporary differences, net of the existing valuation allowance at December 31, 2007.
 
As of December 31, 2007, we had foreign net operating losses and other tax benefits available to reduce future taxable income in a foreign jurisdiction. The valuation allowance in the amount of $4.0 million offsets in part our foreign net operating losses and other tax benefits. In assessing the realizability of our foreign deferred tax assets, we recognized a tax benefit to the extent of taxable income we expect to earn over the terms of three existing drilling contracts in the foreign jurisdiction. The terms of these contracts expire in February 2008, May 2008 and February 2009. If one or more of these contracts are extended or renewed or new contracts are entered into, then we expect to recognize additional tax benefits to the extent projected future taxable income increases. The foreign net operating loss has an indefinite carryforward period.
 
Deferred United States income taxes have not been provided on the undistributed earnings of our foreign subsidiaries as these earnings have been, and under current plans will continue to be permanently reinvested in these subsidiaries. If those earnings were not considered permanently reinvested, federal deferred income taxes would have been recorded. However, the amount of additional taxes which may be payable upon distribution would not be material for the current year and may not be practicable to estimate in future years.


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PIONEER DRILLING COMPANY AND SUBSIDIARIES
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
We did not recognize a change to our unrecognized tax benefits as a result of implementing FIN No. 48. A reconciliation of the beginning and ending amounts of unrecognized tax benefit is as follows (amounts in thousands):
 
         
Beginning balance at April 1, 2007
  $ 717  
Additions to current year tax positions
     
Additions for prior year tax positions
     
Reductions for prior year tax positions
     
Settlements
    (717 )
         
Ending balance at December 31, 2007
  $  
         
 
We adopted a policy to record interest and penalty expense related to income taxes in accounts used in arriving at income before income taxes. At December 31, 2007, no interest or penalties have been or are required to be accrued. Our open tax years for our federal income tax returns are for the years ended March 31, 2005, 2006 and 2007.
 
5.   Fair Value of Financial Instruments
 
The carrying amounts of our cash and cash equivalents, trade receivables and payables approximate their fair values.
 
6.   Earnings Per Common Share
 
The following table presents a reconciliation of the numerators and denominators of the basic earnings per share and diluted earnings per share comparisons as required by SFAS No. 128 (amounts in thousands, except per share data):
 
                         
    Nine Months
             
    Ended
             
    December 31,
    Years Ended March 31,  
    2007     2007     2006  
 
Basic
                       
Net earnings
  $ 39,645     $ 84,180     $ 50,566  
                         
Weighted average shares
    49,645       49,603       46,808  
                         
Earnings per share
  $ 0.80     $ 1.70     $ 1.08  
                         
                         
Diluted
                       
Net earnings
  $ 39,645     $ 84,180     $ 50,566  
Effect of dilutive securities
                 
                         
Net earnings available to common shareholders after assumed conversion
  $ 39,645     $ 84,180     $ 50,566  
                         
Weighted average shares:
                       
Outstanding
    49,645       49,603       46,808  
Options
    556       529       698  
                         
      50,201       50,132       47,506  
                         
Earnings per share
  $ 0.79     $ 1.68     $ 1.06  
                         


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PIONEER DRILLING COMPANY AND SUBSIDIARIES
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
7.   Equity Transactions
 
On February 10, 2006, we sold 3 million shares of our common stock, at approximately $20.63 per share, net of underwriters’ commissions, pursuant to a public offering we registered with the SEC.
 
Employees exercised stock options for the purchase of 22,500 shares of common stock at prices ranging from $4.52 to $4.77 per share during the nine months ended December 31, 2007. Employees exercised stock options for the purchase of 36,500 shares of common stock at prices ranging from $3.20 to $4.77 per share during the year ended March 31, 2007. Directors and employees exercised stock options for the purchase of 698,667 shares of common stock at prices ranging from $2.25 to $10.31 per share during the year ended March 31, 2006.
 
8.   Stock Option Plans
 
We have stock option plans that are administered by the compensation committee of our Board of Directors, which selects persons eligible to receive awards and determines the number of stock options subject to each award and the terms, conditions and other provisions of the awards. Employee stock options generally become exercisable over three- to five-year periods, and generally expire 10 years after the date of grant. Stock options granted to outside directors vest immediately and expire five years after the date of grant. Our plans provide that all options must have an exercise price not less than the fair market value of our common stock on the date of grant.
 
We estimate the fair value of each option grant on the date of grant using a Black-Scholes options-pricing model. The following table summarizes the assumptions used in the Black-Scholes option-pricing model for the nine months ended December 31, 2007 and for the years ended March 31, 2007 and 2006:
 
                         
    Nine Months
       
    Ended
       
    December 31,
  Fiscal Years Ended March 31,
    2007   2007   2006
 
Expected volatility
    46 %     49 %     52 %
Weighted-average risk-free interest rates
    4.7 %     5.0 %     4.0 %
Weighted-average expected life in years
    4.00       2.86       4.10  
Weighted-average grant-date fair value
  $ 5.84     $ 5.36     $ 6.47  
 
The assumptions above are based on multiple factors, including historical exercise patterns of homogeneous groups with respect to exercise and post-vesting employment termination behaviors, expected future exercising patterns for these same homogeneous groups and volatility of our stock price. As we have not declared dividends since we became a public company, we did not use a dividend yield. In each case, the actual value that will be realized, if any, will depend on the future performance of our common stock and overall stock market conditions. There is no assurance the value an optionee actually realizes will be at or near the value we have estimated using the Black-Scholes options-pricing model.
 
At December 31, 2007, there was $3.8 million of unrecognized compensation cost relating to stock options which are expected to be recognized over a weighted-average period of 1.47 years.


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PIONEER DRILLING COMPANY AND SUBSIDIARIES
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
The following table represents stock option activity from April 1, 2006 through December 31, 2007:
 
                         
                Weighted-Average
 
    Number of
    Weighted-Average
    Remaining
 
    Shares     Exercise Price     Contract Life  
 
Outstanding options as of March 31, 2006
    1,592,833     $ 7.71          
Granted
    482,000       14.53          
Exercised
    (36,500 )     4.63          
Canceled
                   
Forfeited
    (91,833 )     11.09          
                         
Outstanding options as of March 31, 2007
    1,946,500     $ 9.29          
                         
Granted
    931,500       14.06          
Exercised
    (22,500 )     4.74          
Canceled
                   
Forfeited
    (55,001 )     11.73          
                         
Outstanding options as of December 31, 2007
    2,800,499     $ 10.87       7.23  
                         
Options exercisable as of December 31, 2007
    1,296,658     $ 8.64       5.68  
                         
 
Shares available for future stock option grants to employees and directors under existing plans were 3,351,834 at December 31, 2007. At December 31, 2007, the aggregate intrinsic value of stock options outstanding was $6.9 million and the aggregate intrinsic value of stock options exercisable was $5.4 million. Intrinsic value is the difference between the exercise price of a stock option and the closing market price of our common stock, which was $11.88 on December 31, 2007.
 
The following table summarizes our nonvested stock option activity from March 31, 2006 through December 31, 2007:
 
                 
          Weighted-Average
 
    Number of
    Grant-Date
 
    Shares     Fair Value  
 
Nonvested options as of March 31, 2006
    1,046,167     $ 4.90  
Granted
    422,000       5.51  
Vested
    (495,668 )     4.70  
Forfeited
    (91,833 )     5.88  
                 
Nonvested options as of March 31, 2007
    880,666     $ 5.48  
Granted
    931,500       5.84  
Vested
    (253,324 )     5.49  
Forfeited
    (55,001 )     5.89  
                 
Nonvested options as of December 31, 2007
    1,503,841     $ 5.64  
                 
 
9.   Employee Benefit Plans and Insurance
 
We maintain a 401(k) retirement plan for our eligible employees. Under this plan, we may make a matching contribution, on a discretionary basis, equal to a percentage of each eligible employee’s annual contribution, which we determine annually. Our contributions for the nine months ended December 31, 2007 and the years ended March 31, 2007 and 2006 were $.8 million, $1.0 million and $.6 million, respectively.


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PIONEER DRILLING COMPANY AND SUBSIDIARIES
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
We maintain a self-insurance program, for major medical, hospitalization and dental coverage for employees and their dependents, which is partially funded by payroll deductions. We have provided for both reported and incurred but not reported medical costs in the accompanying consolidated balance sheets. We have a maximum liability of $125,000 per employee/dependent per year. Amounts in excess of the stated maximum are covered under a separate policy provided by an insurance company. Accrued expenses at December 31, 2007 and March 31, 2007 include $.8 million and $.6 million, respectively, for our estimate of incurred but unpaid costs related to the self-insurance portion of our health insurance.
 
We are self-insured for up to $250,000 per incident for all workers’ compensation claims submitted by employees for on-the-job injuries, except in North Dakota where there is no deductible. Our deductible under workers’ compensation insurance increased to $500,000 in October 2007. We have provided for both reported and incurred but not reported costs of workers’ compensation coverage in the accompanying consolidated balance sheets. Accrued insurance premiums and deductibles at December 31, 2007 and March 31, 2007 include $7.8 million and $4.4 million, respectively, for our estimate of incurred but unpaid costs related to workers’ compensation claims. Based upon our past experience, management believes that we have adequately provided for potential losses. However, future multiple occurrences of serious injuries to employees could have a material adverse effect on our financial position and results of operations.
 
10.   Business Segments and Concentrations
 
Substantially all our operations relate to contract drilling of oil and gas wells. Accordingly, we classify all our operations in a single segment.
 
During the nine months ended December 31, 2007, our three largest customers accounted for 13.1%, 8.8% and 7.7% respectively, of our total contract drilling revenue. All three of these customers were customers of ours during the year ended Marc h 31, 2007. During the year ended March 31, 2007, our three largest customers accounted for 9.7%, 9.1% and 6.1% respectively, of our total contract drilling revenue. All three of these customers were customers of ours during the year ended March 31, 2006. During the year ended March 31, 2006, our three largest customers accounted for 10.1%, 6.1% and 4.4% respectively, of our total contract drilling revenue. All three of these customers were customers of ours during the year ended March 31, 2005.
 
11.   Commitments and Contingencies
 
In connection with our expansion into international markets, our foreign subsidiaries have obtained bonds for bidding on drilling contracts, performing under drilling contracts, and remitting customs and importation duties. We have guaranteed payments of $25.5 million relating to our performance under these bonds.
 
In addition, due to the nature of our business, we are, from time to time, involved in routine litigation or subject to disputes or claims related to our business activities, including workers’ compensation claims and employment-related disputes. Legal costs relating to these matters are expensed as incurred. In the opinion of our management, none of the pending litigation, disputes or claims against us will have a material adverse effect on our financial condition, results of operations or cash flow from operations and there is only a remote possibility that any such matter will require any additional loss accrual.
 
12.   Subsequent Events
 
On January 31, 2008, we entered into a definitive purchase agreement to acquire WEDGE Well Services, L.L.C., WEDGE Wireline, Inc. and WEDGE Fishing and Rental Services, L.L.C. (the “WEDGE Companies”) from affiliates of WEDGE Group Incorporated for $303 million. The WEDGE Companies provide oil and gas well workover, wireline, and fishing and rental services for energy producers in the United States. We expect to finance the acquisition through a combination of existing cash and a new, 5 year, senior revolving credit


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PIONEER DRILLING COMPANY AND SUBSIDIARIES
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
facility of up to $350 million led by Wells Fargo Bank, N.A. and Fortis Merchant Banking. The closing of the acquisition, which is expected before March 31, 2008, is subject to obtaining certain regulatory approvals, our receipt of financing and other customary closing conditions.
 
In January 2008, we invested $16.5 million in auction rate securities which are private placement securities with long-term nominal maturities for which the interest rates are reset through a “Dutch” auction each week. These auction rate securities are collateralized by securities issued by municipalities. The weekly auctions historically have provided a liquid market for these securities. Due to liquidity issues in global credit and capital markets, our auction rate securities have experienced multiple failed auctions as the amount of securities submitted for sale have exceeded purchase orders. The result of failed auctions is that these auction rate securities continue to pay interest in accordance with their terms. Liquidity will be limited until there is a successful auction or until such time as other markets for auction rate securities develop. As a result of these events, we are evaluating the extent of any impairment in the value of our auction rate securities that may result from this lack of liquidity. At this time, we are not able to quantify the amount of such impairment, if any, which would result in an impairment charge that would need to be recorded in the quarter ending March 31, 2008. We believe that any lack of liquidity relating to our auction rate securities will not have an impact on our ability to fund our operations.
 
13.   Quarterly Results of Operations (unaudited)
 
The following table summarizes quarterly financial data for the nine months ended December 31, 2007 and the year ended March 31, 2007 (in thousands, except per share data):
 
                                         
    First
    Second
    Third
    Fourth
       
    Quarter     Quarter     Quarter     Quarter     Total  
 
Nine Months Ended December 31, 2007
                                       
Revenues
  $ 102,779     $ 106,516     $ 104,589           $ 313,884  
Income from operations
    19,569       17,307       18,384             55,260  
Income tax expense
    (7,362 )     (6,255 )     (4,512 )           (18,129 )
Net earnings
    13,088       11,780       14,777             39,645  
Earnings per share:
                                       
Basic
    .26       .24       .30             .80  
Diluted
    .26       .23       .29             .79  
                                         
Year Ended March 31, 2007
                                       
Revenues
  $ 93,493     $ 106,917     $ 112,421     $ 103,347     $ 416,178  
Income from operations
    29,455       35,674       36,250       25,597       126,976  
Income tax expense
    (11,026 )     (13,213 )     (13,102 )     (9,268 )     (46,609 )
Net earnings
    19,486       23,486       23,988       17,219       84,179  
Earnings per share:
                                       
Basic
    .39       .47       .48       .36       1.70  
Diluted
    .39       .47       .48       .34       1.68  


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PIONEER DRILLING COMPANY AND SUBSIDIARIES
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
14.   Change in Fiscal Year End and Comparative Financial Information
 
In December 2007, our Board of Directors approved a change in our fiscal year end from March 31 to December 31. The fiscal year end change was effective December 31, 2007 and resulted in a nine month reporting period from April 1, 2007 to December 31, 2007. We implemented the fiscal year end change to align our United States reporting period with the required Colombian statutory reporting period as well as the reporting periods of peer companies in the industry.
 
The consolidated balance sheets, consolidated statements of operations and cash flows are provided below with comparative information as of and for the nine months ended December 31, 2007 and 2006. The financial information provided as of and for the nine months ended December 31, 2006 is unaudited, since it represented an interim period of the fiscal year ended March 31, 2007. The unaudited financial information as of and for the nine months ended December 31, 2006, include all normal recurring adjustments necessary for the fair statement of the results for that period.


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PIONEER DRILLING COMPANY AND SUBSIDIARIES
 
CONSOLIDATED BALANCE SHEETS
(In thousands, except per share data)
 
                 
    December 31,
    December 31,
 
    2007     2006  
          (Unaudited)  
 
ASSETS
Current assets:
               
Cash and cash equivalents
  $ 76,703     $ 74,754  
Receivables:
               
Trade, net
    46,759       55,677  
Contract drilling in progress
    7,861       14,006  
Income tax receivable
    611        
Deferred income taxes
    3,670       1,754  
Inventory
    1,180        
Prepaid expenses
    5,073       4,027  
                 
Total current assets
    141,857       150,218  
                 
Property and equipment, at cost:
               
Drilling rigs and equipment
    553,864       424,875  
Transportation equipment
    18,676       11,790  
Land, buildings and other
    6,157       4,457  
                 
      578,697       441,122  
Less accumulated depreciation and amortization
    161,675       111,473  
                 
Net property and equipment
    417,022       329,649  
Deferred income taxes
    573        
Intangible and other assets
    760       306  
                 
Total assets
  $ 560,212     $ 480,173  
                 
 
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities:
               
Accounts payable
  $ 21,424     $ 19,639  
Income tax payable
          3,791  
Prepaid drilling contracts
    1,933        
Accrued expenses:
               
Payroll and related employee costs
    5,172       5,387  
Insurance premiums and deductibles
    9,548       5,874  
Other
    3,973       2,655  
                 
Total current liabilities
    42,050       37,346  
Non-current liabilities
    254       432  
Deferred income taxes
    46,836       32,221  
                 
Total liabilities
    89,140       69,999  
                 
Commitments and contingencies
               
Shareholders’ equity:
               
Preferred stock, 10,000,000 shares authorized; none issued and outstanding
           
Common stock $.10 par value; 100,000,000 shares authorized; 49,650,978 shares and 49,604,478 shares issued and outstanding at December 31, 2007 and 2006, respectively
    4,965       4,960  
Additional paid-in capital
    294,922       290,893  
Accumulated earnings
    171,185       114,321  
                 
Total shareholders’ equity
    471,072       410,174  
                 
Total liabilities and shareholders’ equity
  $ 560,212     $ 480,173  
                 


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PIONEER DRILLING COMPANY AND SUBSIDIARIES
 
CONSOLIDATED STATEMENTS OF OPERATIONS
(In thousands, except per share data)
 
                 
    Nine Months Ended
 
    December 31,  
    2007     2006  
          (Unaudited)  
 
Contract drilling revenues
  $ 313,884     $ 312,831  
                 
Costs and expenses:
               
Contract drilling
    195,596       164,017  
Depreciation and amortization
    48,852       38,120  
General and administrative
    11,564       8,516  
Bad debt expense
    2,612       800  
                 
Total operating costs and expenses
    258,624       211,453  
                 
Income from operations
    55,260       101,378  
                 
Other income (expense):
               
Interest expense
    (16 )     (73 )
Interest income
    2,401       2,947  
Other
    129       50  
                 
Total other income
    2,514       2,924  
                 
Income before income taxes
    57,774       104,302  
Income tax expense
    (18,129 )     (37,341 )
                 
Net earnings
  $ 39,645     $ 66,961  
                 
Earnings per common share — Basic
  $ 0.80     $ 1.35  
                 
Earnings per common share — Diluted
  $ 0.79     $ 1.34  
                 
Weighted average number of shares outstanding — Basic
    49,645       49,598  
                 
Weighted average number of shares outstanding — Diluted
    50,201       50,148  
                 


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PIONEER DRILLING COMPANY AND SUBSIDIARIES
 
CONSOLIDATED STATEMENTS OF CASH FLOWS
(In thousands)
 
                 
    Nine Months Ended
 
    December 31,  
    2007     2006  
          (Unaudited)  
 
Cash flows from operating activities:
               
Net earnings
  $ 39,645     $ 66,961  
Adjustments to reconcile net earnings to net cash provided by operating activities:
               
Depreciation and amortization
    48,852       38,120  
Allowance for doubtful accounts
    2,612       800  
Loss on dispositions of property and equipment
    2,809       5,183  
Stock-based compensation expense
    3,157       2,474  
Deferred income taxes
    5,947       4,474  
Change in other assets
    (519 )     15  
Change in non-current liabilities
    (92 )     44  
Changes in current assets and liabilities:
               
Receivables
    9,692       (25,318 )
Inventory
    (1,180 )      
Prepaid expenses
    (1,420 )     (1,819 )
Accounts payable
    919       3,033  
Income tax payable
          (3,051 )
Prepaid drilling contracts
    1,933       (140 )
Accrued expenses
    3,100       4,300  
                 
Net cash provided by operating activities
    115,455       95,076  
                 
Cash flows from financing activities:
               
Proceeds from exercise of options
    107       64  
Excess tax benefit of stock option exercises
    54       8  
                 
Net cash provided by financing activities
    161       72  
                 
Cash flows from investing activities:
               
Purchases of property and equipment
    (126,158 )     (116,638 )
Proceeds from sale of property and equipment
    2,300       5,070  
                 
Net cash used in investing activities
    (123,858 )     (111,568 )
                 
Net increase (decrease) in cash and cash equivalents
    (8,242 )     (16,420 )
Beginning cash and cash equivalents
    84,945       91,174  
                 
Ending cash and cash equivalents
  $ 76,703     $ 74,754  
                 


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Item 9.   Changes in and Disagreements With Accountants on Accounting and Financial Disclosure
 
Not applicable.
 
Item 9A.   Controls and Procedures
 
In accordance with Exchange Act Rules 13a-15 and 15d-15, we carried out an evaluation, under the supervision and with the participation of management, including our Chief Executive Officer and Chief Financial Officer, of the effectiveness of our disclosure controls and procedures as of the end of the period covered by this report. Based upon that evaluation, our Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures were effective as of December 31, 2007 to provide reasonable assurance that information required to be disclosed in our reports filed or submitted under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the Securities and Exchange Commission’s rules and forms.
 
There has been no change in our internal control over financial reporting that occurred during the three months ended December 31, 2007 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.
 
Management’s Report on Internal Control Over Financial Reporting
 
The management of Pioneer Drilling Company is responsible for establishing and maintaining adequate internal control over financial reporting. Pioneer Drilling Company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that: (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
 
Pioneer Drilling Company’s management assessed the effectiveness of Pioneer Drilling Company’s internal control over financial reporting as of December 31, 2007. In making this assessment, it used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control-Integrated Framework. Based on our assessment we have concluded that, as of December 31, 2007, Pioneer Drilling Company’s internal control over financial reporting was effective based on those criteria.
 
KPMG LLP, the independent registered public accounting firm that audited the consolidated financial statements of Pioneer Drilling Company included in this Annual Report on Form 10-KT, has issued an attestation report on the effectiveness of Pioneer Drilling Company’s internal control over financial reporting as of December 31, 2007. This report appears on page 43.
 
Item 9B.   Other Information
 
Not applicable.


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PART III
 
In Items 10, 11, 12, 13 and 14 below, we are incorporating by reference the information we refer to in those Items from the definitive proxy statement for our 2008 Annual Meeting of Shareholders. We intend to file that definitive proxy statement with the SEC by April 11, 2008.
 
Item 10.   Directors, Executive Officers and Corporate Governance
 
Please see the information appearing under the headings “Proposal 1 — Election of Directors,” “Executive Officers,” “Information Concerning Meetings and Committees of the Board of Directors,” “Code of Conduct and Ethics” and “Section 16(a) Beneficial Ownership Reporting Compliance” in the definitive proxy statement for our 2008 Annual Meeting of Shareholders for the information this Item 10 requires.
 
Item 11.   Executive Compensation
 
Please see the information appearing under the headings “Compensation Discussion and Analysis,” “Compensation of Directors,” “Compensation of Executive Officers,” “Compensation Committee Interlocks and Insider Participation” and “Compensation Committee Report” in the definitive proxy statement for our 2008 Annual Meeting of Shareholders for the information this Item 11 requires.
 
Item 12.   Security Ownership of Certain Beneficial Owners and Management and Related Shareholder Matters
 
Please see the information appearing (1) under the heading “Equity Compensation Plan Information” in Item 5 of Part II of this report and (2) under the heading “Security Ownership of Certain Beneficial Owners and Management” in the definitive proxy statement for our 2008 Annual Meeting of Shareholders for the information this Item 12 requires.
 
Item 13.   Certain Relationships and Related Transactions, and Director Independence
 
Please see the information appearing under the headings “Proposal 1 — Election of Directors” and “Certain Relationships and Related Transactions” in the definitive proxy statement for our 2008 Annual Meeting of Shareholders for the information this Item 13 requires.
 
Item 14.   Principal Accountant Fees and Services
 
Please see the information appearing under the heading “Proposal 2 — Ratification of Appointment of Independent Auditors” in the definitive proxy statement for our 2008 Annual Meeting of Shareholders for the information this Item 14 requires.
 
PART IV
 
Item 15.   Exhibits and Financial Statement Schedules
 
(1) Financial Statements.
 
See Index to Consolidated Financial Statements on page 41.
 
(2) Financial Statement Schedules:
 
Schedule II is filed with this report. All other schedules for which provision is made in the applicable regulations of the SEC have been omitted because they are not required under the relevant instructions or because the required information is included in the financial statements or the related footnotes contained in this report.


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Schedule II
 
                                 
    Valuation and Qualifying Accounts  
    Balance
    Charged
             
    at
    to Costs
    Additions to/
    Balance
 
    Beginning
    and
    Deductions from
    at
 
    of Year     Expenses     Accounts     Year End  
    (In thousands)  
 
Year ended March 31, 2006
                               
Allowance for doubtful receivables
  $ 352     $ (152 )   $     $ 200  
                                 
Year ended March 31, 2007
                               
Allowance for doubtful receivables
  $ 200     $ 800     $     $ 1,000  
                                 
Nine months ended December 31, 2007
                               
Allowance for doubtful receivables
  $ 1,000     $ 2,612     $ (3,612 )   $  
                                 
Valuation allowance for deferred income taxes
  $     $ (484 )   $ 4,481     $ 3,997  
                                 
 
(3) Exhibits.  The following exhibits are filed as part of this report:
 
             
Exhibit
       
Number
     
Description
 
  2 .1*     Asset Purchase Agreement dated November 11, 2004 between Wolverine Drilling, Inc. and Robert Mau, Robert S. Blackford and Pioneer Drilling Services, Ltd. (Form 8-K dated November 12, 2004 (File No. 1-8182, Exhibit 2.1)).
  2 .2*     Asset Purchase Agreement dated November 29, 2004, by and among Allen Drilling Company, the Earl Allen Family Trust dated April 1, 1979, the sole shareholder of Allen Drilling Company, Dixon Allen, Paula K. Hoisington and Lisa D. Johonnesson, all of the beneficiaries of the Trust, and Pioneer Drilling Services, Ltd. (Form 8-K dated December 2, 2004 (File No. 1-8182, Exhibit 2.1)).
  3 .1*     Articles of Incorporation of Pioneer Drilling Company, as amended (Form 10-K for the year ended March 31, 2001 (File No. 1-8182, Exhibit 3.1)).
  3 .2*     Articles of Amendment to the Articles of Incorporation of Pioneer Drilling Company (Form 10-Q for the quarter ended September 30, 2001 (File No. 1-8182, Exhibit 3.1)).
  3 .3*     Amended and Restated Bylaws of Pioneer Drilling Company (Form 8-K dated December 10, 2007 (File No. 1-8182, Exhibit 3.1)).
  4 .1*     Form of Certificate representing Common Stock of Pioneer Drilling Company (Form S-8 filed November 18, 2003 (Reg. No. 333-110569, Exhibit 4.3)).
  4 .2*     Credit Agreement between Pioneer Drilling Services, Ltd. and Frost National Bank, as Administrative Agent, Agent, Lead Arranger and Lender dated October 29, 2004 (Form 8-K dated November 2, 2004 (File No. 1-8182, Exhibit 4.1)).
  4 .3*     Second Amendment, dated May 11, 2005, to Credit Agreement between Pioneer Drilling Services, Ltd. and Frost National Bank, as Administrative Agent, Lead Arranger and Lender dated October 29, 2004 (Form 8-K dated May 13, 2005 (File No. 1-8182, Exhibit 4.1)).
  4 .4*     Third Amendment, dated October 25, 2005, to Credit Agreement between Pioneer Drilling Services, Ltd. and Frost National Bank, as Administrative Agent, Lead Arranger and Lender dated October 29, 2004 (Form 8-K dated October 28, 2005 (File No. 1-8182, Exhibit 4.1)).
  4 .5*     Fourth Amendment, dated December 15, 2005, to Credit Agreement between Pioneer Drilling Services, Ltd. and Frost National Bank, as Administrative Agent, Lead Arranger and Lender dated October 29, 2004 (Form 8-K dated December 16, 2005 (File No. 1-8182, Exhibit 4.1)).


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Exhibit
       
Number
     
Description
 
  4 .6*     Fifth Amendment, dated October 30, 2006, to Credit Agreement between Pioneer Drilling Services, Ltd. and Frost National Bank, as Administrative Agent, Lead Arranger and Lender dated October 29, 2004 (Form 8-K dated October 31, 2006 (File No. 1-8182, Exhibit 4.1)).
  10 .1+*     Pioneer Drilling Services, Ltd. Annual Incentive Compensation Plan dated August 5, 2005 (Form 8-K dated August 5, 2005 (File No. 1-8182, Exhibit 10.1)).
  10 .2+*     Pioneer Drilling Services, Ltd. Key Executive Severance Plan dated August 3, 2007 (Form 8-K dated August 8, 2007 (File No. 1-8182, Exhibit 10.2)).
  10 .3+*     Pioneer Drilling Company’s 1995 Stock Plan and form of Stock Option Agreement (Form 10-K for the year ended March 31, 2001 (File No. 1-8182, Exhibit 10.5)).
  10 .4+*     Pioneer Drilling Company’s 1999 Stock Plan and form of Stock Option Agreement (Form 10-K for the year ended March 31, 2001 (File No. 1-8182, Exhibit 10.7)).
  10 .5+*     Pioneer Drilling Company 2003 Stock Plan (Form S-8 filed November 18, 2003 (File No. 333-110569, Exhibit 4.4)).
  10 .6+*     Pioneer Drilling Company 2007 Incentive Plan (Form DEF14A filed June 22, 2007 (File No. 1-8182, Annex A)).
  10 .7+*     Joyce M. Schmidt Employment Letter, dated July 17, 2007 (Form 8-K dated July 18, 2007 (File No. 1-8182, Exhibit 10.1)).
  10 .8+*     William D. Hibbetts Reassignment Letter, dated July 17, 2007 (Form 8-K dated July 18, 2007 (File No. 1-8182, Exhibit 10.2)).
  10 .9+*     Pioneer Drilling Company Form of Indemnification Agreement (Form 8-K dated August 8, 2007 (File No. 1-8182, Exhibit 10.1)).
  10 .10+*     Pioneer Drilling Company Employee Relocation Policy Executive Officers — Package A (Form 8-K dated August 8, 2007 (File No. 1-8182, Exhibit 10.3)).
  21 .1     Subsidiaries of Pioneer Drilling Company.
  23 .1     Consent of Independent Registered Public Accounting Firm.
  31 .1     Certification by Wm. Stacy Locke, President and Chief Executive Officer, pursuant to Rule 13a-14(a) or Rule 15d-14(a) under the Securities Exchange Act of 1934.
  31 .2     Certification by Joyce M. Schuldt, Executive Vice President and Chief Financial Officer, pursuant to Rule 13a-14(a) or Rule 15d-14(a) under the Securities Exchange Act of 1934.
  32 .1     Certification by Wm. Stacy Locke, President and Chief Executive Officer, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (Subsections (a) and (b) of Section 1350, Chapter 63 of Title 18, United States Code).
  32 .2     Certification by Joyce M. Schuldt, Executive Vice President and Chief Financial Officer, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (Subsections (a) and (b) of Section 1350, Chapter 63 of Title 18, United States Code).
 
 
* Incorporated by reference to the filing indicated.
 
+ Management contract or compensatory plan or arrangement.

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SIGNATURES
 
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
 
PIONEER DRILLING COMPANY
 
  By: 
/s/  Wm. Stacy Locke
Wm. Stacy Locke
Chief Executive Officer and President
 
February 26, 2008
 
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.
 
             
Signature
 
Title
 
Date
 
         
/s/  C. Robert Bunch

C. Robert Bunch
  Chairman   February 25, 2008
         
/s/  Wm. Stacy Locke

Wm. Stacy Locke
  President, Chief Executive Officer and Director (Principal Executive Officer)   February 25, 2008
         
/s/  Joyce M. Schuldt

Joyce M. Schuldt
  Executive Vice President,
Chief Financial Officer and Secretary
(Principal Financial and Accounting Officer)
  February 25, 2008
         
/s/  C. John Thompson

C. John Thompson
  Director   February 25, 2008
         
/s/  Dean A. Burkhardt

Dean A. Burkhardt
  Director   February 25, 2008
         
/s/  Michael F. Harness

Michael F. Harness
  Director   February 25, 2008


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Index To Exhibits
 
             
  2 .1*     Asset Purchase Agreement dated November 11, 2004 between Wolverine Drilling, Inc. and Robert Mau, Robert S. Blackford and Pioneer Drilling Services, Ltd. (Form 8-K dated November 12, 2004 (File No. 1-8182, Exhibit 2.1)).
  2 .2*     Asset Purchase Agreement dated November 29, 2004, by and among Allen Drilling Company, the Earl Allen Family Trust dated April 1, 1979, the sole shareholder of Allen Drilling Company, Dixon Allen, Paula K. Hoisington and Lisa D. Johonnesson, all of the beneficiaries of the Trust, and Pioneer Drilling Services, Ltd. (Form 8-K dated December 2, 2004 (File No. 1-8182, Exhibit 2.1)).
  3 .1*     Articles of Incorporation of Pioneer Drilling Company, as amended (Form 10-K for the year ended March 31, 2001 (File No. 1-8182, Exhibit 3.1)).
  3 .2*     Articles of Amendment to the Articles of Incorporation of Pioneer Drilling Company (Form 10-Q for the quarter ended September 30, 2001 (File No. 1-8182, Exhibit 3.1)).
  3 .3*     Amended and Restated Bylaws of Pioneer Drilling Company (Form 8-K dated December 10, 2007 (File No. 1-8182, Exhibit 3.1)).
  4 .1*     Form of Certificate representing Common Stock of Pioneer Drilling Company (Form S-8 filed November 18, 2003 (Reg. No. 333-110569, Exhibit 4.3)).
  4 .2*     Credit Agreement between Pioneer Drilling Services, Ltd. and Frost National Bank, as Administrative Agent, Agent, Lead Arranger and Lender dated October 29, 2004 (Form 8-K dated November 2, 2004 (File No. 1-8182, Exhibit 4.1)).
  4 .3*     Second Amendment, dated May 11, 2005, to Credit Agreement between Pioneer Drilling Services, Ltd. and Frost National Bank, as Administrative Agent, Lead Arranger and Lender dated October 29, 2004 (Form 8-K dated May 13, 2005 (File No. 1-8182, Exhibit 4.1)).
  4 .4*     Third Amendment, dated October 25, 2005, to Credit Agreement between Pioneer Drilling Services, Ltd. and Frost National Bank, as Administrative Agent, Lead Arranger and Lender dated October 29, 2004 (Form 8-K dated October 28, 2005 (File No. 1-8182, Exhibit 4.1)).
  4 .5*     Fourth Amendment, dated December 15, 2005, to Credit Agreement between Pioneer Drilling Services, Ltd. and Frost National Bank, as Administrative Agent, Lead Arranger and Lender dated October 29, 2004 (Form 8-K dated December 16, 2005 (File No. 1-8182, Exhibit 4.1)).
  4 .6*     Fifth Amendment, dated October 30, 2006, to Credit Agreement between Pioneer Drilling Services, Ltd. and Frost National Bank, as Administrative Agent, Lead Arranger and Lender dated October 29, 2004 (Form 8-K dated October 31, 2006 (File No. 1-8182, Exhibit 4.1)).
  10 .1+*     Pioneer Drilling Services, Ltd. Annual Incentive Compensation Plan dated August 5, 2005 (Form 8-K dated August 5, 2005 (File No. 1-8182, Exhibit 10.1)).
  10 .2+*     Pioneer Drilling Services, Ltd. Key Executive Severance Plan dated August 3, 2007 (Form 8-K dated August 8, 2007 (File No. 1-8182, Exhibit 10.1)).
  10 .3+*     Pioneer Drilling Company’s 1995 Stock Plan and form of Stock Option Agreement (Form 10-K for the year ended March 31, 2001 (File No. 1-8182, Exhibit 10.5)).
  10 .4+*     Pioneer Drilling Company’s 1999 Stock Plan and form of Stock Option Agreement (Form 10-K for the year ended March 31, 2001 (File No. 1-8182, Exhibit 10.7)).
  10 .5+*     Pioneer Drilling Company 2003 Stock Plan (Form S-8 filed November 18, 2003 (File No. 333-110569, Exhibit 4.4)).
  10 .6+*     Pioneer Drilling Company 2007 Incentive Plan (Form DEF14A filed June 22, 2007 (File No. 1-8182, Annex A)).
  10 .7+*     Joyce M. Schmidt Employment Letter, dated July 17, 2007 (Form 8-K dated July 18, 2007 (File No. 1-8182, Exhibit 10.1)).


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  10 .8+*     William D. Hibbetts Reassignment Letter, dated July 17, 2007 (Form 8-K dated July 18, 2007 (File No. 1-8182, Exhibit 10.2)).
  10 .9+*     Pioneer Drilling Company Form of Indemnification Agreement (Form 8-K dated August 8, 2007 (File No. 1-8182, Exhibit 10.1)).
  10 .10+*     Pioneer Drilling Company Employee Relocation Policy Executive Officers — Package A (Form 8-K dated August 8, 2007 (File No. 1-8182, Exhibit 10.3)).
  21 .1     Subsidiaries of Pioneer Drilling Company.
  23 .1     Consent of Independent Registered Public Accounting Firm.
  31 .1     Certification by Wm. Stacy Locke, President and Chief Executive Officer, pursuant to Rule 13a-14(a) or Rule 15d-14(a) under the Securities Exchange Act of 1934.
  31 .2     Certification by Joyce M. Schuldt, Executive Vice President and Chief Financial Officer, pursuant to Rule 13a-14(a) or Rule 15d-14(a) under the Securities Exchange Act of 1934.
  32 .1     Certification by Wm. Stacy Locke, President and Chief Executive Officer, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (Subsections (a) and (b) of Section 1350, Chapter 63 of Title 18, United States Code).
  32 .2     Certification by Joyce M. Schuldt, Executive Vice President and Chief Financial Officer, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (Subsections (a) and (b) of Section 1350, Chapter 63 of Title 18, United States Code).
 
 
* Incorporated by reference to the filing indicated.
 
+ Management contract or compensatory plan or arrangement.


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