SELECTED FINANCIAL DATA

        The following table sets forth our selected financial data as of and for each of the years indicated and is derived from our audited consolidated financial statements. You should review this information in conjunction with "Management's Discussion and Analysis of Financial Condition and Results of Operations" beginning on page 21 of this prospectus and the consolidated financial statements and related notes included in this prospectus.

Refer to Note 2 of the consolidated financial statements for information on acquisitions.

SUPPLEMENTARY FINANCIAL INFORMATION

        The following table summarizes our quarterly financial data for our fiscal years ended March 31, 2004 and 2003 (in thousands, except per share data):

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 which 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 the natural gas production regions of South, East and North Texas. Our company 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, 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.

        Over the past five fiscal years, we have significantly expanded our fleet of drilling rigs through acquisitions and the construction of new and refurbished rigs. As of March 31, 2004, our rig fleet consisted of 35 land drilling rigs that drill in depth ranges between 8,000 and 18,000 feet. Fourteen of our rigs are operating in South Texas, 17 in East Texas and four in North Texas. We actively market all of these rigs. We completed construction of our 36th rig in late May 2004 and began moving it to its first drilling location on May 28, 2004. Subject to obtaining satisfactory financing, we anticipate continued growth of our rig fleet in fiscal 2005. However, we are not currently committed to any acquisitions.

        We earn our revenues by drilling oil and gas wells. 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, usually on payment of an agreed fee.

        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 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.

        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. For 2005, we anticipate continued growth in revenue days and maintaining relatively high utilization rates.

        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 one-third 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. Occasionally, a turnkey contract will not be profitable if the contract cannot be completed successfully without unanticipated complications.

        We devote substantial resources to maintaining and upgrading our rig fleet. During 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 the rigs and improve their operating performance.

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.

        For the three months ended March 31, 2004, the average weekly spot price for West Texas Intermediate crude oil was $35.08, the average weekly spot price for Henry Hub natural gas was $5.56 and the average weekly Baker Hughes land rig count was 1,002. On July 23, 2004, the spot price for West Texas Intermediate crude oil was $41.76, the spot price for Henry Hub natural gas was $5.99. For the week of July 16, 2004, the Baker Hughes land rig count was 1,097, a 13.0% increase from 967 as of the corresponding week in 2003.

        The average weekly spot prices of West Texas Intermediate crude oil, Henry Hub natural gas and the average weekly domestic land rig count, per the Baker Hughes land rig count, for each of the previous six years ended March 31, 2004 were:

        The decline in oil and natural gas prices from mid-2001 to mid-2002 resulted in a reduction in the demand for contract land drilling services, which resulted in a substantial reduction in the rates land drilling companies were able to obtain for their services. While oil and natural gas prices have recovered in recent months, drilling activity has not yet recovered to a level at which we are able to significantly improve our revenue rates and profitability.

        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 20% in 2002 and forecasts that U.S. consumption of natural gas will exceed U.S. domestic productive capacity by 28% 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, 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. 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 based on 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 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.

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 eight contracts, including two contracts with losses exceeding $100,000. 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 the 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.

        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.

        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 estimate 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.

        Other accrued expenses in our March 31, 2004 financial statements include an accrual of approximately $680,000 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. 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 eight rigs as of August 1, 2000 to 35 rigs as of March 31, 2004. We have financed this growth with a combination of debt and equity financing. We have raised additional equity or used equity for growth six times since January 2000 and have increased our long-term debt from approximately $3,909,000 at June 30, 2000 to approximately $48,500,000 at March 31, 2004. We plan to continue to grow our rig fleet. We believe that near-term growth will require the use of equity financing rather than additional debt. At March 31, 2004, our total debt to total capital was approximately 41%. Due to the volatility in our industry, we are reluctant to take on substantial additional debt at this time. 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.

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. As of March 31, 2004, we had incurred approximately $2,800,000 of construction costs on this rig and anticipate additional related construction costs of approximately $2,547,000. We began moving it to its first drilling location on May 28, 2004. For fiscal 2005, we project regular capital expenditures to be approximately $10,200,000 and rig upgrade expenditures to be approximately $4,500,000. These regular capital expenditures and rig upgrade capital expenditures are expected to be funded primarily from operating cash flow.

        In fiscal 2004, the additions to our property and equipment totaled $44,844,745. Additions consisted of the following:

(1)

Includes capitalized interest costs of $106,395.

Working Capital

        Our working capital decreased to $6,028,018 at March 31, 2004 from $11,144,309 at March 31, 2003. Our current ratio, which we calculate by dividing our current assets by our current liabilities, was 1.27 at March 31, 2004 compared to 1.55 at March 31, 2003. The principal reason for the decrease in our working capital at March 31, 2004 was our use of approximately $3,400,000 of working capital toward the purchase of drilling equipment. We used substantially all the $20,000,000 in proceeds from the shares of common stock we sold to Chesapeake on March 31, 2003 to expand our rig fleet or reduce debt we incurred to expand our rig fleet. We have used approximately $17,000,000 of the funds we raised in February 2004 to expand our rig fleet or acquire other equipment. Our operations have historically generated sufficient cash flow to meet our requirements for debt service and equipment expenditures, even during periods of industry downturns. During periods when a higher percentage of our contracts are turnkey and footage contracts, our short-term working capital needs could increase. We have available a $2,500,000 line of credit for short-term cash requirements. We did not make any borrowings under the line of credit during fiscal 2004. We have used debt and equity to finance our long-term growth strategy to increase the size of our rig fleet. During periods of improved revenue rates, we believe we can generate cash flows in excess of our normal cash requirements.

        The changes in the components of our working capital were as follows:

        The large cash balance at March 31, 2003 was due to our sale of $20,000,000 of equity on March 31, 2003, of which $14,000,000 was in the March 31, 2003 cash balance. The $14,000,000 was used during fiscal 2004 to purchase drilling rigs and equipment.

        The increase in our receivables at March 31, 2004 from March 31, 2003 was due to our operating eleven additional rigs in the quarter ended March 31, 2004, including an approximately $3,693,000 increase in contract drilling in progress related to turnkey contracts, and an improvement in revenue rates in fiscal 2004 over fiscal 2003.

        Substantially all our prepaid expenses at March 31, 2004 consisted of prepaid insurance. The increase in prepaid insurance is due to the increase in the size of our drilling rig fleet from 24 rigs at March 31, 2003 to 35 rigs at March 31, 2004.

        The increase in accrued payroll is due to the approximately 50% increase in our number of employees and the increase in the number of payroll days included in the accrual from seven at March 31, 2003 to nine at March 31, 2004.

        The total increase in accrued expenses at March 31, 2004 from March 31, 2003 was due to an increase of approximately $477,000 in the accrual for our insurance deductibles and additional insurance premiums, expense accruals of approximately $250,000 related to the sale of common stock in February and accrued property taxes of approximately $205,000 due to increases in rig valuations and the size of our rig fleet.

Long-term Debt

        Our long-term debt at March 31, 2004 consisted of the following:

(1)

WEDGE holds $27,000,000 of the convertible subordinated debentures and William H. White, a former director of our company, holds $1,000,000. WEDGE owns 26.5% of our common stock (40.2% assuming conversion of the debentures). WEDGE and Mr. White, the holders of all of the convertible subordinated debentures, have agreed to convert those debentures in accordance with their terms into 6,496,519 shares of our common stock prior to the closing of this offering. In the absence of that conversion, we would have the option to redeem all or part of the debentures by paying a premium of 5% through July 2, 2005, 4% through July 2, 2006, 3% through July 2, 2007 and 0% thereafter.

(2)

We incurred this debt to finance the purchase of Rig #4, which we were previously leasing.

Contractual Obligations

        We do not have any routine purchase obligations. However, as of March 31, 2004, we were in the process of constructing a drilling rig as described above. The following table excludes interest payments on long-term debt and capital lease obligations. The following table includes all of our contractual obligations at March 31, 2004.

Debt Requirements

        Borrowings from Frost National Bank and Merrill Lynch Capital, a division of Merrill Lynch Business Financial Services, Inc. ("MLC"), contain various covenants pertaining to leverage, cash flow coverage, fixed charge coverage and net worth ratios and restrict us from paying dividends. Under these credit arrangements, we determine compliance with the ratios on a quarterly basis, based on the previous four quarters. As of March 31, 2004, we were in compliance with all covenants applicable to our outstanding debt.

        Events of default in our loan agreements, which could trigger an early repayment requirement, include, among others:

•

our failure to make required payments;



•

our failure to comply with financial covenants related to the maintenance of a ratio of debt to tangible net worth, a leverage ratio, a cash flow coverage ratio and a senior cash flow coverage ratio;



•

our incurrence of additional indebtedness in excess of $2,000,000 not already allowed by the loan agreements without each lender's approval; and



•

any payment of cash dividends on our common stock.

        The limitation on additional indebtedness has not affected our operations or liquidity and we do not expect it to affect us in the future as we expect to continue to generate adequate cash flow from operations.

        We also have a $2,500,000 line of credit from Frost National Bank to supplement our short-term cash needs. Any borrowings under this line of credit are secured by our trade receivables and bear interest at a rate of prime (4.00% at March 31, 2004) plus 1.0%. The sum of draws under this line and the amount of all outstanding letters of credit issued by the bank for our account are limited to 75% of eligible accounts receivable. Therefore, if 75% of our eligible accounts receivable is less than $2,500,000 plus any outstanding letters of credit issued by the bank on our behalf, our ability to draw under this line would be reduced. At March 31, 2004, we had no outstanding advances under this line of credit, letters of credit were $1,664,000 and 75% of eligible accounts receivable was approximately $8,030,000. The letters of credit are issued to two workers' compensation insurance companies to secure possible future claims that do not exceed the deductibles on these policies. It is our practice to pay any amounts

due that do not exceed these deductibles as they are incurred. Therefore, we do not anticipate the lender will be required to fund any draws under these letters of credit.

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 easiest 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 profitability.

        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.

        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 under a turnkey contract are greater than those under a daywork contract. This is primarily 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.

        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.

        For the years ended March 31, 2004, 2003 and 2002, the percentages of our drilling revenues by type of contract were as follows:

        While current demand for drilling rigs has increased, we continue to bid on turnkey contracts in an effort to improve profitability and maintain rig utilization. Although oil and natural gas prices have improved, we anticipate only a moderate change in the mix of our types of contracts in fiscal 2005.

        In our quarter ended March 31, 2004, we recognized revenues of approximately $924,000 and recorded contract drilling costs of approximately $747,000, excluding depreciation, on one daywork contract with Chesapeake, who owns approximately 19.5% of our outstanding common stock.

Statement of Operations Analysis

        The following table provides information about our operations for the years ended March 31, 2004, March 31, 2003, and March 31, 2002.

        Our contract drilling revenues grew by approximately 35% in fiscal 2004 from fiscal 2003, due to an improvement in rig revenue rates, a 37% increase in revenue days, a 9% increase in rig utilization and an increase in the number of rigs in our fleet. Approximately 52% of the increase in revenue days was an increase in daywork revenue days resulting in a $183 decrease in average contract drilling revenue per day. Revenue rates on daywork contracts are lower than on turnkey and footage contracts because we incur fewer costs on daywork contracts.

        Our contract drilling revenue in fiscal 2003 grew by approximately $11,556,000, or 17%, from fiscal 2002 due to a 19% increase in revenue days, an increase in the number of rigs in our fleet and a higher percentage of turnkey contracts.

        Our contract drilling costs grew by approximately $17,681,000, or 25%, in fiscal 2004 from fiscal 2003 due to the increase in revenue days, rig utilization and the number of rigs in our fleet. The increase in daywork revenue days resulted in a $934 decrease in contract drilling costs per revenue day because costs associated with the drilling of daywork contracts is less than costs associated with turnkey and footage contracts. Under daywork contracts, our customer provides supplies and materials such as fuel, drill bits, casing, drilling fluids, etc.

        Our contract drilling costs in fiscal 2003 grew by approximately $24,678,000, or 53% from fiscal 2002, due primarily to the increase in revenue days, increase in number of rigs and additional costs associated with the increase in turnkey contracts. The increase in contract drilling costs per day of $2,462 in 2003 from 2002 is due to the increase in turnkey contracts.

        Our depreciation and amortization expense in 2004 increased by approximately $4,200,000, or 35%, from 2003. Depreciation and amortization expense in 2003 increased approximately $3,534,000, or 42%, from 2002. The increase in 2004 over 2003 resulted from our addition of eleven drilling rigs and related equipment in 2004. The increase in 2003 over 2002 resulted from our addition of four drilling rigs and related equipment during 2003.

        Our general and administrative expenses increased by approximately $541,000, or 24%, in the year ended March 31, 2004 from the corresponding period of 2003. The increase resulted from increased payroll costs, employment fees, loan fees, insurance costs and director fees. In 2004, payroll cost increased by approximately $310,000 due to pay raises and the increase from 12 to 17 employees in our

corporate office. Employment and loan fees increased by $61,000 due to the employee additions and fees associated with the Merrill Lynch Capital loan. In addition, our directors' and officers' liability and employment practices insurance increased by approximately $60,000 and directors' fees increased by approximately $93,000.

        The approximately $623,000 decrease in general and administrative expenses in 2003 from 2002 is due to reduced payroll costs of approximately $269,000 and lower legal and professional fees of approximately $520,000, offset by other increases of approximately $166,000. The higher payroll costs in 2002 were due to bonuses paid in that year.

        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 is approximately $143,000. We are not aware of any potential clean-up obligations that would have a material adverse effect on our financial condition or results of operations.

        Our effective income tax rates of 19.2%, 30.4% and 35.1% for 2004, 2003 and 2002, respectively, differ from the federal statutory rate of 34% due to permanent differences. Permanent differences are costs included in results of operations in the accompanying financial statements which are not fully deductible for federal income tax purposes.

Inflation

        As a result of the relatively low levels of inflation during the past two years, inflation did not significantly affect our results of operations in any of the periods reported.

Off Balance Sheet Arrangements

        We do not currently have any off balance sheet arrangements.

Quantitative and Qualitative Disclosures About Market Risk

        We are subject to market risk exposure related to changes in interest rates on most of our outstanding debt. At March 31, 2004, we had outstanding debt of approximately $20,511,000 that was subject to variable interest rates, in each case based on an agreed percentage-point spread from the lender's prime interest rate. An increase or decrease of 1% in the interest rate would have a corresponding decrease or increase in our net income (loss) of approximately $135,000 annually. We did not enter into any of these debt arrangements for trading purposes.

BUSINESS

General

        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 the natural gas production regions of South, East and North Texas. Our company 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. Our common stock trades on the American Stock Exchange under the symbol "PDC."

        Over the past five years, we have significantly expanded our fleet of drilling rigs through acquisitions and the construction of new rigs and the refurbishment of older rigs we acquired. The following table summarizes acquisitions in which we acquired rigs and related operations during the past five years:

        During that same five-year period, we also added seven rigs to our fleet through construction of new rigs and construction of rigs from new and used components. In addition, in August 2003, we acquired a rig that had been operating in Trinidad and integrated it into our operations in Texas. As of July 27, 2004, our rig fleet consists of 36 operating drilling rigs, 15 of which are operating in South Texas, 17 of which are operating in East Texas and four of which are operating in North Texas. During our fiscal year ended March 31, 2002, we added four rigs, consisting of two newly constructed rigs and two refurbished rigs, increasing our rig fleet to a total of 20 rigs at March 31, 2002. During our fiscal year ended March 31, 2003, we added two additional refurbished rigs and two rigs we acquired from United Drilling Company, increasing our rig fleet to a total of 24 rigs at March 31, 2003. During our fiscal year ended March 31, 2004, we added two refurbished rigs, acquired two rigs from Texas Interstate Drilling Company, L.P., acquired seven rigs from Sawyer Drilling & Service, Inc. and acquired one rig from SEDCO Drilling Co., Ltd. (which we named Rig 5 in place of our old Rig 5, which was retired and the components of which were moved to our inventory of spare equipment). In December 2003, we acquired the one rig (Rig #4) we had previously been leasing under an operating lease since August 2000. As a result, we now own all 36 of the operating rigs in our fleet.

        We conduct our operations primarily in South, East and North Texas. During fiscal 2004, substantially all the wells we drilled for our customers were drilled in search of natural gas. Natural gas reserves are typically found in deep geological formations and generally require premium equipment and quality crews to drill the wells.

        For many years, the United States 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."

Our Strategy

        Our goal is to continue to build on our strong market position and reputation as a quality contract drilling company in a way that enhances shareholder value. We intend to accomplish this goal by:

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continuing to own and operate a high-quality fleet of land drilling rigs in active natural gas drilling markets;



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fueling growth through the acquisition of high-quality rigs capable of drilling for natural gas reserves and capable of generating our targeted returns on investment;



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positioning ourselves to maximize rig utilization and dayrates;



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training and maintaining high quality, experienced crews capable of employing drilling techniques that are best suited to the regional subsurface geology; and



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maintaining the recent improvements in our safety record.

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 equipment and cost of 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 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 July 27, 2004, our rig fleet consists of 36 drilling rigs. We own all the rigs in our fleet. The following table sets forth information regarding utilization for our fleet of drilling rigs: