SELECTED FINANCIAL DATA

        The following table sets forth our selected financial data as of and for each of the fiscal years and interim periods indicated and is derived from our historical audited consolidated financial statements for the fiscal years indicated and from our historical unaudited consolidated financial statements for the interim periods indicated. You should review this information in conjunction with "Management's Discussion and Analysis of Financial Condition and Results of Operations" beginning on page 20 of this prospectus and our historical financial statements and related notes included in this prospectus.

Refer to Note 2 of our historical consolidated financial statements for information on acquisitions and the pro forma financial statements (and notes thereto) reflecting our acquisitions of the assets of Wolverine Drilling and Allen Drilling contained in this prospectus.

MANAGEMENT'S DISCUSSION AND ANALYSIS
OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Statements we make in the following discussion which 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, 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, government regulations, including those relating to the environment.

Company Overview

        Pioneer 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. Our companydirectors was incorporated in 1979 as the successor to a business that had been operating since 1968. We conduct our operations through our principal operating subsidiary, Pioneer Drilling Services, Ltd. 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 price of oil and natural gas.

        Our business strategy is to own and operate a high-quality fleet of land drilling rigs in active drilling markets, and position ourselves to maximize rig utilization and dayrates and to enhance 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 refurbished drilling rigs.

        Since September 1999, we have significantly expanded our fleet of drilling rigs through acquisitions and the construction of new and refurbished rigs. As of December 31, 2004, our rig fleet consisted of 49 land drilling rigs that drill in depth ranges between 6,000 and 18,000 feet. As of January 31, 2005, we had 15 rigs operating in South Texas, 17 in East Texas, four in North Texas, five in Western Oklahoma and eight in the Rocky Mountains. We actively market all of these rigs. Subject to obtaining satisfactory financing, we anticipate continued growth of our rig fleet in fiscal 2006. We are currently constructing a 1,000-horse power mechanical rig from new and used components.

        We earn our revenues by drilling oil and gas wells for our customers. 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 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.

        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 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. On daywork contracts, 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, some of 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.

        For the nine months ended December 31, 2004 and 2003 and for the three years ended March 31, 2004, our rig utilization, revenue days and number of rigs were as follows:

        The reasons for the increase in the number of revenue days in 2004 over 2003 and 2002 are the increase in size of our rig fleet and the improvement in our overall rig utilization rate due to improved market conditions. The reasons for the increase in the number of revenue days in the first nine months of 2004 over the first nine months of 2003 are the increase in size of our rig fleet from 28 at December 31, 2003 to 49 at December 31, 2004 and the improvement in our overall rig utilization rate. For the remainder of fiscal 2005 and through fiscal 2006, we anticipate continued growth in revenue days and maintaining relatively high utilization rates.

        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. Turnkey contracts currently account for approximately 25% of our contracts. Turnkey contracts provide us with the opportunity to keep our rigs working in periods of lower demand and improve our profitability, but at an increased risk. As was the case for several turnkey contracts under which we performed during the nine months ended December 31, 2004, a turnkey contract may not be profitable if it cannot be completed successfully without unanticipated complications.

        We devote substantial resources to maintaining and upgrading our rig fleet. During our fiscal year 2004, we removed three rigs from service for approximately three weeks each, in order to perform upgrades. In the short term, these actions resulted in fewer revenue days and slightly lower utilization; however, in the long term, we believe the upgrades will help the marketability of rigs and improve their operating performance. We are currently performing, between contracts or as necessary, safety and equipment upgrades to the 12 rigs we acquired in November and December 2004.

Market Conditions in Our Industry

        The United States 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.

        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, 2004 and each of our five most recent fiscal years in the period ended March 31, 2004 were:

        On January 31, 2005, the spot price for West Texas Intermediate crude oil was $48.20 and the spot price for Henry Hub natural gas was $6.16. For the week of January 28, 2005, the Baker Hughes land rig count was 1,130, a 16% increase from 973 as of the corresponding week in 2004.

        We believe capital spent on incremental natural gas production will be driven by an increase in hydrocarbon demand as well as shortages in supply of natural gas. The Energy Information Agency recently estimated that U.S. consumption of natural gas exceeded U.S. domestic productive capacity by 15% in 2003 and forecasts that U.S. consumption of natural gas will exceed U.S. domestic productive capacity by 25% by 2010. Most of this difference is expected to be driven by the growth in consumption by electric power generators, as a significant amount of natural gas-fired power generation capacity has been constructed within the last five years and older, less-efficient power generation capacity, not fired by natural gas, is expected to be decommissioned. In addition, a study published by the National Petroleum Council in September 2003 concluded from drilling and production data over the preceding 10 years that average "initial production rates from new wells have been sustained through the use of advanced technology; however, production declines from these initial rates have increased significantly; and recoverable volumes from new wells drilled in mature producing basins have declined over time. Without the benefit of new drilling, indigenous supplies have reached a point at which U.S. production declines by 25% to 30% each year. Eighty percent of gas production in 10 years will be from wells yet to be drilled." We believe all of these factors tend to support a higher natural gas price environment, which should create strong incentives for oil and natural gas exploration and production companies to increase drilling activity in North America. Consequently, these factors may result in higher rig dayrates and rig utilization.

        During fiscal 2004, 2003 and 2002 and the first nine months of fiscal 2005, substantially all the wells we drilled for our customers were drilled in search of natural gas because of the depth capacity of our rigs and the gas rich areas in which we operate. Although we have recently diversified our operations somewhat with the November 2004 acquisition of seven drilling rigs from Wolverine Drilling, with five of those rigs employed in search of oil in the Williston Basin of the Rocky Mountains, our customers remain primarily focused on drilling for natural gas. Natural gas reserves are typically found in deeper geological formations and generally require premium equipment and quality crews to drill the wells.

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 for the days completed, based on the contract amount divided by our estimate of the number of days to complete each contract. Contract drilling in progress represents revenues we have recognized in excess of amounts billed on contracts in progress. 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.

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 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 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, ultimate recovery of that value, in the event we were unable to drill to the agreed on depth in breach of the contract, 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, includingquantum 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 could differ significantly if our cost estimates are later revised from our original estimates for contracts in progress at the end of a reporting period which were not completed prior to the release of our financial statements.

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 utilizations rates, cash flows from our drilling rigs, current oil and gas prices, industry analysts' outlook for the industry and their view of our customers' access to debt or equity, discussions with major industry suppliers, discussions with officers of our primary lender regarding their experiences and expectations for oil and gas operators in our areas of operations and the 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 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 March 31, 2004, would have resulted in a corresponding increase in our net loss of approximately $962,000 for our fiscal year ended March 31, 2004. A one percent write-down in the cost of our drilling equipment, at December 31, 2004, would have resulted in a corresponding decrease in our net earnings of approximately $1,324,000 for the nine months ended December 31, 2004.

Deferred Taxes—We provide deferred taxes for net operating loss carryforwards and for the basis difference in our property and equipment between 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 eight to 15 years and refurbishments over three years, while federal income tax rules require that we depreciate drilling rigs and refurbishments over five years. Therefore, in the first five 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 five years, financial reporting depreciation exceeds tax depreciation, and the deferred tax liability begins to reverse.

Accounting Estimates—We consider the recognition of revenues and costs on turnkey and footage contracts critical accounting estimates. On these types of contracts, we are required to estimate the number of days it will require 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 shallower depth. Since 1995, when current management joined our company, 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 enable us to make reasonably dependable 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 immediately increase our cost estimate for the additional costs to complete the contracts. 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 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. During fiscal 2004, we experienced losses on eight of the 105 turnkey and footage contracts completed, with losses exceeding $25,000 on six contracts, including two contracts with losses exceeding $100,000. During the nine months ended December 31, 2004, we experienced losses on 14 of the 128 turnkey and footage contracts completed, with losses exceeding $25,000 on nine contracts and losses exceeding $100,000 on four contracts. We are more likely to encounter losses on turnkey and footage contracts in years 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. All but one of our turnkey contracts in progress at March 31, 2004 were completed prior to the release of our fiscal 2004 financial statements included in this prospectus. All our turnkey and footage contracts in progress at December 31, 2004 were completed prior to the release of the most recent interim-period financial statements included in this prospectus. At March 31, 2004, our contract drilling in progress totaled approximately $9,131,000. Of that amount accrued, turnkey and footage contract revenues were approximately $7,683,000. The remaining balance of approximately $1,448,000 relates to the revenue recognized but not yet billed on daywork contracts in progress at March 31, 2004. At December 31, 2004, our contract drilling in progress totaled approximately

$7,351,000, of which turnkey and footage contract revenues were approximately $2,547,000 and daywork contract revenues were approximately $4,804,000.

        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 information obtained from major industry suppliers, current prices of oil and gas 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 60 days for any of our contracts in the last three fiscal years. We established an allowance for doubtful accounts of $452,000 at December 31, 2004, an increase of $342,000 from $110,000 at March 31, 2004.

        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 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 three 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.

        Our other accrued expenses as of December 31, 2004 and March 31, 2004 include accruals of approximately $1,232,000 and $680,000, respectively, for costs incurred under the self-insurance portion of our health insurance and under our workers' compensation insurance. We have a deductible of (1) $100,000 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 the deductible is $100,000. We accrue for these costs as claims are incurred based on cost estimates established for each claim by the insurance companies providing the administrative services for processing the claims, including an estimate for incurred but not reported claims, estimates for claims paid directly by us, our estimate of the administrative costs associated with these claims and our historical experience with these types of claims.

Liquidity and Capital Resources

Sources of Capital Resources

        Our rig fleet has grown from six rigs in September 1999 to 49 rigs as of December 31, 2004. We have financed this growth with a combination of debt and equity financing. At March 31, 2004, our total debt to total capitalization was approximately 41% (21% at December 31, 2004). We plan to continue to grow our rig fleet. We believe that our growth will require the use of equity financing, in addition to debt. However, our ability to continue funding our growth through the issuance of shares of our common stock is uncertain, as our common stock is not heavily traded and the market price for our common stock has been volatile in recent periods.

        On February 20, 2004, we sold 4,400,000 shares of our common stock at $5.40 per share in a private placement to accredited investors for $23,760,000 in proceeds, before related offering expenses.

        On August 11, 2004, we also sold 4,000,000 shares of our common stock at approximately $6.61 per share, net of underwriters' commissions, pursuant to a public offering we registered with the SEC under a registration statement filed on Form S-1. On August 31, 2004, we sold 600,000 additional

shares of our common stock at approximately $6.61 per share, net of underwriters' commissions, pursuant to the underwriters' exercise of an over-allotment option grantedappointed in connection with that public offering.

        On October 29, 2004, we entered into a $47,000,000 credit facility with a group of lenders consisting of a $7,000,000 revolving linethe Plan, and letter of credit facility and a $40,000,000 acquisition facility for the acquisition of drilling rigs, rig transportation equipment and associated equipment. Frost National Bank is the administrative agent and lead arranger under the new credit facility, and the lenders include Frost National Bank, the Bank of Scotland and Zions First National Bank. Borrowings under the new credit facility bear interest at a rate equal to Frost National Bank's prime rate (5.25% at January 31, 2005) and are secured by most of our assets, including all our drilling rigs, associated equipment and receivables. As described below, we have borrowed $35,200,000 of the amount available under the acquisition facility and we have used approximately $2,800,000 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 approximately $4,800,000 and $4,200,000 of availability under the acquisition facility and the revolving line and letter of credit facility, respectively, should remain available to us until those facilities mature in October 2006 and October 2005, respectively.

Uses of Capital Resources

        In May 2003, we added one refurbished 18,000-foot SCR land drilling rig at a cost of approximately $7,300,000. On August 1, 2003, we purchased two land drilling rigs, associated spare parts and equipment and vehicles from Texas Interstate Drilling Company, L. P. for $2,500,000 in cash and the issuance of 477,000 shares of our common stock valued at $4.45 per share. On August 26, 2003, we purchased a 14,000-foot mechanical rig for $2,925,661 in cash. After accepting delivery of the rig, we spent approximately $2,400,000 upgrading the rig before placing it in service. On December 15, 2003, we acquired a rig for approximately $3,770,000 that we had previously been leasing.

        On March 2, 2004, we acquired 23 used rig hauling trucks and associated trailers and equipment from A&R Trejo Trucking for $1,200,000. On March 4, 2004, we acquired a seven-rig drilling fleet from Sawyer Drilling & Service, Inc. for $12,000,000. On March 12, 2004, we acquired one drilling rig from SEDCO Drilling Co., Ltd. for $2,015,000. These acquisitions were funded with proceeds from the February 20, 2004 sale of our common stock.

        In late May 2004, we completed constructing, primarily from used components, a 1,000-hp electric drilling rig. We incurred approximately $4,900,000 of construction costs on this rig.