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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

FORM 10-Q

Commission File Number 1-8182

PIONEER DRILLING COMPANY
(Exact name of registrant as specified in its charter)

        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 Exchange 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 ý    No o

        Indicate by check mark whether the registrant is an accelerated filer (as defined in Rule 12b-2 of the Exchange Act). Yes o    No ý

        As of August 4, 2004, there were 27,305,126 shares of common stock, par value $0.10 per share, of the registrant issued and outstanding.

PART I. FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

PIONEER DRILLING COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS

See accompanying notes to condensed consolidated financial statements.

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PIONEER DRILLING COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

See accompanying notes to condensed consolidated financial statements.

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PIONEER DRILLING COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

See accompanying notes to condensed consolidated financial statements.

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PIONEER DRILLING COMPANY AND SUBSIDARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

1. Organization and Basis of Presentation

Business and Principles of Consolidation

        The condensed consolidated financial statements include the accounts of Pioneer Drilling Company and its wholly owned subsidiaries. All intercompany balances and transactions have been eliminated in consolidation.

        The accompanying unaudited condensed consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America for interim financial information and with the instructions to Form 10-Q and Rule 10-01 of Regulation S-X. Accordingly, they do not include all of the information and footnotes required by generally accepted accounting principles for complete financial statements. In the opinion of our management, all adjustments (consisting of normal recurring accruals) necessary for a fair presentation have been included.

Income Taxes

        We use the asset and liability method of Statement of Financial Accounting Standards ("SFAS") No. 109 for accounting for income taxes. Under this method, we recognize deferred tax assets and liabilities for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases. We measure deferred tax assets and liabilities using 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, the effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period that includes the enactment date. At the end of each interim period, we make our best estimate of the effective tax rate we expect to be applicable for the full year and use that rate to determine our income tax expense or benefit on a year-to-date basis.

Stock-based Compensation

        We have adopted SFAS No. 123, Accounting for Stock-Based Compensation. SFAS No. 123 allows a company to adopt a fair value based method of accounting for a stock-based employee compensation plan or to continue to use the intrinsic value based method of accounting prescribed by Accounting Principles Board ("APB") Opinion No. 25, "Accounting for Stock Issued to Employees." We have elected to continue accounting for stock-based compensation under the intrinsic value method. Under this method, we record no compensation expense for stock option grants when the exercise price of the options granted is equal to the fair market value of our common stock on the date of grant. If we had elected to recognize compensation cost based on the fair value of the options we granted at their

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respective grant dates as SFAS No. 123 prescribes, our net earnings (loss) and net earnings (loss) per share would have been reduced to the pro forma amounts the table below indicates:

        We estimate the fair value of each option grant on the date of grant using a Black-Scholes options-pricing model. The model assumed expected volatility of 88% and 68% and weighted-average risk-free interest rates of 4.0% and 2.9% for grants in the three-month periods ended June 30, 2004 and 2003, respectively, and an expected life of five years. 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 model.

Related Party Transaction

        At June 30, 2004, Chesapeake Energy Corporation owned 19.54% of our outstanding common stock. During the three months ended June 30, 2004, we recognized revenues of approximately $9,000 on a daywork contract with Chesapeake Energy Corporation. Although our normal payment terms are 30 days from date of invoice, we have agreed to 60-day payment terms with Chesapeake Energy Corporation.

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 Notes Payable

        Notes payable at June 30, 2004 consists of a $223,967 insurance premium note due in monthly installments of $112,355 through August 26, 2004 which bears interest at the rate of 2.65% per year.

        Long-term debt at June 30, 2004 includes two notes payable to Frost National Bank and one note payable to Merrill Lynch Capital. The balance on these notes at June 30, 2004 and the terms of each note are described in a table in Management's Discussion and Analysis of Financial Conditions and Results of Operations under Liquidity and Capital Resources.

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        Subordinated debt at June 30, 2004 consists of $28,000,000 of convertible subordinated debentures of which $27,000,000 is payable to WEDGE Energy Services, LLC ("WEDGE") due July 2007 at 6.75%. At June 30, 2004, WEDGE owns 26.52% of our outstanding common stock, 40.24% if the debentures were converted.

        We have a $2,500,000 line of credit available from Frost National Bank. Any borrowings under this line of credit are secured by our trade receivables and bear interest at a rate of prime (4.25% at June 30, 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 June 30, 2004, we had no outstanding advances under this line of credit, letters of credit were $1,664,000 and 75% of our eligible accounts receivable was approximately $9,231,000. The letters of credit are issued to two 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 lender will be required to fund any draws under these letters of credit.

        At June 30, 2004, we were in compliance with all covenants applicable to our outstanding debt. Those covenants include, among others, the maintenance of ratios of debt to net worth, leverage and cash flow coverage. The covenants also restrict the payment of dividends on our common stock.

3. Commitments and Contingencies

        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 such 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.

4. Equity Transactions

        On August 1, 2003, we issued 477,000 shares of our common stock at $4.45 per share to Texas Interstate Drilling Company, L.P. as part of the purchase price of two land drilling rigs.

        On February 20, 2004, we sold 4,400,000 shares of our common stock at $5.40 per share in a private placement for $23,760,000 in proceeds, before related offering expenses. Although we issued those shares without registration under the Securities Act of 1933 in reliance on the exemption that Section 4(2) of that Act provides for transactions not involving any public offering, we filed a registration statement on Form S-3 to register the resale of those shares. The registration statement became effective on June 22, 2004.

        Employees exercised stock options for the purchase of 20,000 shares of common stock at $2.25 per share during the three months ended June 30, 2003.

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5. Earnings (Loss) Per Common Share

        The following table presents a reconciliation of the numerators and denominators of the basic EPS and diluted EPS computations as required by SFAS No. 128:

(1)

Employee stock options to purchase 1,941,000 shares in 2003 and 6,496,519 shares from convertible debentures in both periods were not included in the computation of diluted loss per share for the three months ended June 30, 2004 and 2003, because they are antidilutive.

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ITEM 2. 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 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 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, 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.

        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 June 30, 2004, our rig fleet consisted of 36 land drilling rigs that drill in depth ranges between 8,000 and 18,000 feet. Currently, we have 15 rigs operating in South Texas, 17 in East Texas and four in North Texas. We actively market all of these rigs. 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 and obtain our contracts 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 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.

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        For the three months ended June 30, 2004 and 2003, our rig utilization and revenue days were as follows:

        The reasons for the increase in the number of revenue days in 2004 over 2003 are the increase in size of our rig fleet from 25 at June 30, 2003 to 36 at June 30, 2004 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 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. As was the case for several turnkey contracts under which we performed during the quarter ended June 30, 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 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. We are currently performing, between contracts or as necessary, safety and equipment upgrades to the eight rigs we acquired in March 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.

        For the three months ended June 30, 2004, the average weekly spot price for West Texas Intermediate crude oil was $38.30, the average weekly spot price for Henry Hub natural gas was $6.06 and the average weekly Baker Hughes land rig count was 1,048. 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 and the Baker Hughes land rig count was 1,097, a 13% increase from 967 on July 25, 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 June 30, 2004 were:

        During fiscal 2004 and the first three 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

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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 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, 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 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

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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 June 30, 2004, would have resulted in a corresponding decrease in our net earnings of approximately $994,000 for the three months ended June 30, 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 the three months ended June 30, 2004, we experienced losses on five of the 45 turnkey and footage contracts completed, with losses exceeding $25,000 on four contracts and losses exceeding $100,000 on one contract. 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

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period are released. All but three of our turnkey and footage contracts in progress at June 30, 2004 were completed prior to the release of the financial statements included in this report. At June 30, 2004, our contract drilling in progress totaled approximately $10,461,000, of which turnkey and footage contract revenues were approximately $8,886,000 and daywork contract revenues were approximately $1,575,000.

        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.

        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.

        Other accrued expenses in our June 30, 2004 financial statements include an accrual of approximately $705,000 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 in August 2000 to 36 as of June 30, 2004. We have financed this growth with a combination of debt and equity financing. We have raised additional equity or used equity for growth five times since January 2000 and have increased our long-term debt from approximately $3,909,000 at June 30, 2000 to approximately $47,600,000 at June 30, 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 June 30, 2004, our total debt to total capital ratio was approximately 40%. 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 July 9, 2004, we filed a Form S-1 registration statement covering our offering for sale of 4,000,000 shares of our common stock. We intend to use proceeds from this offering to retire our long-term debt payable to Frost National Bank and Merrill Lynch Capital and general corporate

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purposes, including the funding of working capital and capital expenditures. In addition, WEDGE Energy Services, L.L.C. ("WEDGE") and William H. White, who are offering 4,000,000 shares and 232,018 shares, respectively, of our common stock for sale in the offering, have agreed to convert the entire amount of our $28,000,000 of convertible subordinated debentures, pursuant to their existing terms, into 6,496,519 shares of our common stock immediately prior to, and conditioned on, the closing of the offering.

Uses of Capital Resources

        For the three months ended June 30, 2004, the additions to our property and equipment were $8,415,522. Additions consisted of the following:

(1)

Includes capitalized interest costs of $28,740.

Working Capital

        Our working capital decreased to $2,251,383 at June 30, 2004 from $6,028,018 at March 31, 2004. Our current ratio, which we calculate by dividing our current assets by our current liabilities, was 1.08 at June 30, 2004 compared to 1.27 at March 31, 2004. The principal reason for the decrease in our working capital at June 30, 2004 was our use of approximately $2,600,000 of working capital to complete the construction of a drilling rig which we placed in service in late May 2004 and rig upgrades of approximately $1,200,000. Our operations generated cash flows in excess of our requirements for debt service and normal capital expenditures. If necessary, we can defer rig upgrades to improve our cash position. Therefore, we believe our cash generated by operations and our ability to borrow on our currently unused line of credit of $2,500,000 should allow us to meet our routine financial obligations.

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

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        The increase in our receivables at June 30, 2004 from March 31, 2004 was due to our operating one additional rig and the improvement in rig utilization and revenue rates.

        The increase in contract drilling in progress was primarily due to the number and stage of completion of turnkey contracts in progress at June 30, 2004.

        Substantially all our prepaid expenses at June 30, 2004 consisted of prepaid insurance. We renew and pay our insurance premium in late October of each year. At June 30, 2004, we had amortized eight months of the premiums, compared to five months of amortization as of March 31, 2004.

        The increase in accounts payable was due to the increase in turnkey contracts completed during June and in progress at June 30, 2004 and rig upgrades.

        The increase in accrued payroll was due to the 16 days of payroll accrual at June 30, 2004 versus 9 days at March 31, 2004.

        The increase in accrued expenses at June 30, 2004 from March 31, 2004 was primarily due to increases of approximately $480,000 in our accruals for insurance deductibles and additional insurance premiums, approximately $475,000 for six months compared to three months of accrued interest on subordinated debt and approximately $221,000 for six months compared to three months of accrued property taxes.

Long-term Debt

        Our long-term debt at June 30, 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 and former President and CEO of WEDGE, holds $1,000,000. WEDGE owns 26.52% of our common stock (40.24% if the debentures were converted). Beginning July 3, 2004, we 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. Wedge and Mr. White have agreed to convert all the debentures into 6,496,519 shares of our common stock immediately prior to, and conditioned on, the offering referred to above under "—Sources of Capital Resources".

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Contractual Obligations

        We do not have any routine purchase obligations. The following table excludes interest payments on long-term debt and capital lease obligations. The following table includes all of our contractual obligations at June 30, 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 debt to net worth, leverage and cash flow coverage 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 June 30, 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 have a $2,500,000 line of credit available 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 (4.25% at June 30, 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 June 30, 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 $9,231,000. 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.

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Results of Operations

Contracts

        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 operating margins.

        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 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. 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 compared with 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 to primarily daywork contracts.

        For the three months ended June 30, 2004 and 2003, 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. In spite of improvements in oil and natural gas prices, we anticipate only a moderate change in the mix of our types of contracts in the near future.

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Statement of Operations Analysis

        The following table provides information for our operations for the three months ended June 30, 2004 and June 30, 2003.

        Our contract drilling revenues grew by approximately $16,869,000, or 71%, in 2004 from 2003, due to an improvement in rig revenue rates, an increase in the number of rigs in our fleet and a 6% increase in rig utilization.

        Our contract drilling costs grew by approximately $13,488,000, or 66%, in 2004 from 2003 due to the increases in the number of rigs in our fleet and rig utilization. The $894 increase in costs per revenue day is due to the 94% increase in turnkey revenue days in 2004 compared to 2003 and to operational difficulties in the performance under several contracts. Under turnkey and footage contracts we provide supplies and materials such as fuel, drill bits, casing, drilling fluids, etc., which significantly adds to drilling costs.

        Our depreciation and amortization expense in 2004 increased by approximately $1,424,000, or 39%, from 2003. The increase in 2004 over 2003 resulted from our addition of eleven drilling rigs and related equipment since June 30, 2003 for a 44% increase in the size of our rig fleet.

        Our general and administrative expenses increased by approximately $122,000, or 19%, in the three months ended June 30, 2004 from the corresponding period of 2003. The increase resulted from increased payroll costs, insurance costs and director fees. In 2004, payroll cost increased by approximately $39,000 due to pay raises and the increase in employees in our corporate office. Directors' and officers' liability and employment practices insurance increased by approximately $19,000 and directors' fees increased by approximately $57,000.

        Our effective income tax benefit rates of 39% and 28% for the three-month periods ended June 30, 2004 and 2003, 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.

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Off Balance Sheet Arrangements

        We do not currently have any off balance sheet arrangements.

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

        We are subject to market risk exposure related to changes in interest rates on some of our outstanding debt. At June 30, 2004, we had outstanding debt of approximately $19,583,000 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 of approximately $129,000 annually. We did not enter into these debt arrangements for trading purposes.

ITEM 4. 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 on that evaluation, our Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures were effective as of June 30, 2004 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 controls over financial reporting that occurred during the three months ended June 30, 2004 that has materially affected, or is reasonably likely to materially affect, our internal controls over financial reporting.

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PART II. OTHER INFORMATION

ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K

        (a)   Exhibits. The following exhibits are filed as part of this report or incorporated by reference herein:

*

Incorporated herein by reference to the specified prior filing by Pioneer Drilling Company.

        (b)   Reports on Form 8-K. On April 8, 2004, we filed a current report on Form 8-K with respect to our March 5, 2004 press release covering our acquisition of the drilling assets of Sawyer Drilling & Services, Inc. and our purchase of the assets of A&R Trejo Trucking. We also reported our March 12, 2004 acquisition of the drilling assets of SEDCO Drilling Co., Ltd.

On May 18, 2004, we filed a current report on Form 8-K to report on the election of two new directors and certain operating updates.

On June 23, 2004, we filed a current report on Form 8-K to file specified financial tables included in the press release we issued on June 23, 2004 with respect to our results of operations for the year ended March 31, 2004, and to furnish the remainder of that press release.

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        Pursuant to the requirements 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.

Dated: August 4, 2004

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Index to Exhibits

*

Incorporated herein by reference to the specified prior filing by Pioneer Drilling Company.

QuickLinks

ITEM 1. FINANCIAL STATEMENTS

ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
ITEM 4. CONTROLS AND PROCEDURES

ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K