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

FORM 10-Q

Commission File Number 2-70145

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

210-828-7689
(Registrant's telephone number, including area code)

(Former name, address and former fiscal year, if changed since last report)

        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

        As of November 6, 2002, there were 16,137,459 shares of common stock, par value $0.10 per share, of the registrant issued and outstanding.

PART 1. 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

(Unaudited)

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

        The condensed consolidated financial statements include the accounts of Pioneer Drilling Company and its wholly owned subsidiaries. All significant 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 management, all adjustments (consisting of normal recurring accruals) considered necessary for a fair presentation have been included.

        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.

        Certain amounts in the financial statements for the prior period have been reclassified to conform with the current year's presentation.

2. Long-term Debt, Subordinated Debt and Notes Payable

        On October 9, 2001, we issued a 6.75% five-year $18,000,000 convertible subordinated debenture, Series A, to WEDGE Energy Services, L.L.C. ("WEDGE"). The debenture was convertible into 4,500,000 shares of common stock at $4.00 per share. We used approximately $9,000,000 of the proceeds to complete the construction of two drilling rigs. Approximately $6,000,000 was used to reduce a $12,000,000 credit facility. The balance of the proceeds were used for drilling equipment and working capital. On July 3, 2002, we issued an additional $10,000,000 of 6.75% convertible subordinated debt to WEDGE with an effective conversion rate of $5.00 per share. The transaction was effected by an agreement between Pioneer and WEDGE under which WEDGE agreed to provide the additional $10,000,000 in financing and to cancel the previously issued debenture in the principal amount of $18,000,000 in exchange for $28,000,000 in new 6.75% convertible subordinated debentures. The new debentures are convertible into 6.5 million shares of common stock at $4.31 per share, which is a pro rata blending of the $5.00 conversion rate of the new $10,000,000 financing and the $4.00 conversion rate of the $18,000,000 debenture being cancelled. WEDGE funded $7,000,000 of the $10,000,000 on July 3, 2002 and $2,000,000 on July 29, 2002. William H. White, one of our Directors and the President of WEDGE, purchased the remaining $1,000,000 on July 29, 2002. Unlike the cancelled debenture, which was not redeemable by Pioneer, the new debentures are redeemable at a scheduled premium. Pioneer used $7,000,000 of the proceeds to pay down bank debt and $3,000,000 for the purchase of drilling equipment. If WEDGE were to convert the new debentures, it would own approximately 61 percent of Pioneer's outstanding common stock.

        On May 28, 2002, we purchased from United Drilling Company and U-D Holdings, L.P. two land drilling rigs, associated spare parts and equipment and vehicles for $7,000,000 in cash. We financed the

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acquisition of these assets with a $7,000,000 loan from our primary bank lender. Interest on the loan was payable monthly at prime. The loan was collateralized by the assets purchased and a $7,000,000 letter of credit that WEDGE provided. We repaid this loan on July 3, 2002 with $7,000,000 of the proceeds from the issuance of the subordinated debt described above.

        On September 30, 2002, we increased our credit facility with our primary bank lender from $6,000,000 to $8,000,000 and the maturity date was extended to June 29, 2003. On October 31, 2002, our primary bank lender extended the maturity date on our term loan from August 11, 2003 to August 11, 2004.

        We also have a $1,000,000 line of credit with our primary bank lender. Draws are limited to 75% of eligible accounts receivable. Therefore, if our eligible accounts receivable should fall below $1,333,334, our ability to draw under this line would be reduced. At September 30, 2002, there was no balance outstanding on this line and eligible accounts receivable were $6,401,232. In addition, our primary bank lender has issued on our behalf two letters of credit totaling $1,450,000 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 the lender will be required to fund any draws under these letters of credit. In August 2002, our primary bank lender issued five letters of credit totaling $704,922 to support our purchase of drill pipe. We expect delivery of this pipe in November of 2002.

3. Commitments and Contingencies

        As of September 30, 2002, we were constructing three new/refurbished land drilling rigs. We estimate the total cost of these rigs will be approximately $20,000,000, of which $3,125,159 has been incurred as of September 30, 2002, including capitalized interest costs of $30,402 relating to these rigs. We expect to receive the first rig in November 2002, the second in December 2002 and the third in March 2003. On September 30, 2002, we signed an agreement to purchase another drilling rig for $3,150,000. We expect to receive that rig in January 2003. We are financing these rig purchases with a combination of debt and equity.

        On May 17, 2002, Deborah Sutton and other working interest owners in a well that we drilled in May 2000 filed an amended petition naming us as a defendant in the 37^th Judicial District Court in Bexar County, Texas, Cause No. 2001-CI-06701. Other defendants included: the operator, Sutton Producing Corp,; the casing installer, Jens' Oil Field Service, Inc.; the seller of the subject casing and collars, Exploreco, Ltd.; and the casing and collar manufacturer, Baoshan Iron & Steel Corp. Plaintiffs dropped their claims against us on August 8, 2002. However, we remain in the suit because one of the co-defendants, Jens' Oil Field Services, Inc., filed a cross-claim against us, alleging it is entitled to contribution or indemnity from us in the event plaintiffs recover against them. Sutton Producing Corp. also filed a cross-claim against us; however, it subsequently agreed to drop its cross-claim and assume our defense against the claims asserted by Jens' Oil Field Service, Inc.

        The Plaintiffs seek: the cost of drilling the well, alleged to be in the amount of $828,549; lost production, which as of August 1, 2002 is claimed to be $896,036; the costs of plugging the well, estimated at $20,000; plus reasonable attorneys' fees, exemplary damages, prejudgment interest and court costs. The Plaintiffs have alleged that the total sum of all these elements of their damages does not exceed $7,500,000. We deny responsibility and will vigorously defend against any alleged loss

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sustained by the working interest owners as we were working in accordance with our contract under the direct control and supervision of the operator, Sutton Producing Corp., at the time of the alleged loss.

        In addition, due to the nature of our business, we are, from time to time, involved in routine litigation or subject to disputes or claims related to our business activities, including workers' compensation claims and employment-related disputes. 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 or results of operations.

4. Equity Transactions

        Directors and employees exercised stock options for the purchase of 215,000 shares of common stock at prices ranging from $.375 to $2.50 per share during the six months ended September 30, 2002. During the six months ended September 30, 2001, San Patricio Corporation exercised its option to acquire 150,000 shares of our common stock for $225,000 ($1.50 per share).

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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)

Our weighted average number of shares for the three and six months ended September 30, 2002 excludes 6,456,522 shares and 5,483,607 shares, respectively, from convertible debt and 1,195,232 shares and 1,352,103 shares, respectively, from options because of their antidilutive effect.

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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.

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.

        Beginning in 1998 and extending into 1999, the domestic contract land drilling industry was adversely affected by an extended period of low oil and gas prices and a domestic natural gas surplus. The price of West Texas Intermediate crude dropped to a low of $10.76 in December 1998 and the price of natural gas dropped to a low of $1.66 in February 1999. These conditions led to significant reductions in the overall level of domestic land drilling activity resulting in an historical low domestic land rig count of 393 rigs on April 23, 1999. Prior to this industry downturn, during 1997, the contract land drilling industry experienced a significant level of drilling activity, with a domestic land rig count of 899 rigs on December 26, 1997. Also in 1997, the average price of natural gas delivered at Henry Hub, Louisiana was approximately $2.48 per mmbtu and the average price of West Texas Intermediate crude was approximately $20.59 per barrel.

        Oil and natural gas prices rose sharply in calendar year 2000 and through mid 2001. The average price of natural gas for 2000 was $4.32 per mmbtu and for the period from January 1, 2001 through May 31, 2001 was $5.70. The average price of West Texas Intermediate crude for 2000 was $30.38 per barrel and for the period from January 1, 2001 through May 31, 2001 was $28.46. The average prices of natural gas and crude oil for our fiscal year ended March 31, 2002 were $3.00 per mmbtu and $24.00 per barrel, respectively. Natural gas prices began falling in mid 2001 to a low of approximately $2.00 per mmbtu before returning to current levels of $3.80 to $4.50 per mmbtu. Oil prices are currently in the $27.00 to $29.00 per barrel range.

        Primarily as a result of the increase in oil and natural gas prices, exploration and production companies increased their capital spending budgets in 2000 and early 2001. These increased spending budgets increased the demand for contract drilling services. The domestic land rig count climbed to 1,105 on May 31, 2001, representing an increase in the domestic land rig count of 181% from the low in April 1999 and of 23% since December 31, 1997. While market conditions improved in 2000 and into mid 2001, demand for contract land drilling services has declined since mid 2001 along with natural gas prices, leading to a substantial reduction in the rates land drilling companies have been able to obtain for their services. The domestic land rig count was 727 on October 25, 2002, a 20% decrease from 906 on October 26, 2001. While natural gas prices have recovered somewhat in recent months,

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drilling activity has not; therefore, we expect dayrates and rig utilization rates to remain depressed in our industry until demand for land drilling services begins to recover from current levels.

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. See "Results of Operations" below for a general description of these contracts. 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 well. Contract drilling in progress represents revenues we have recognized in excess of amounts billed on contracts in progress. Individual wells 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 well drilled on a daywork basis, because we assume most of the risks associated with drilling operations generally assumed by the operator in a daywork contract, including the risk of blowout, loss of hole, stuck drill pipe, machinery breakdowns, abnormal drilling conditions and risks associated with subcontractors' services, supplies, cost escalations and personnel operations.

        We accrue estimated contract costs on turnkey and footage contracts for each day of work completed based on our estimate of the total cost 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 and operating overhead allocations. Changes in job performance, job conditions and estimated profitability on uncompleted contracts may result in revisions to costs and income, including losses, which we recognize in the period in which we determine the revisions. 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.

        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. 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.

        Deferred taxes—We provide deferred taxes for the basis difference in our property and equipment between financial reporting and tax reporting purposes. 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 drilling rigs over 12 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 us to complete the contract and our total cost to complete the contract. Revenues and costs could be affected for contracts in progress at the end of a reporting period and not completed before our financial statements for that period are released. Our actual costs could substantially exceed our estimated costs if we encounter problems such as lost circulation, stuck drill

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pipe or an underground blowout subsequent to the release of the financial statements. Turnkey contract revenues accrued in "Contract Drilling in Progress" at September 30, 2002 were $1,195,620. All turnkey contracts in progress at September 30, 2002 were completed prior to the release of these financial statements.

        We estimate an allowance for doubtful accounts based on the creditworthiness of our customers as well as general economic conditions. Consequently, an adverse change in those factors could affect our estimate of our allowance for doubtful accounts.

        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.

        Our financial statements include costs incurred under the self-insurance portion of our health insurance and the deductible under our workers' compensation insurance. These accruals are based on information provided by the insurance companies and our historical experience with these types of insurance claims. We increased the self-insurance portion of our health insurance and we increased the deductibles on our workers' compensation insurance policies to better manage the overall cost of our insurance policies. We feel our safety policies and procedures justify our assumption of additional risks with regard to workers' compensation insurance.

Liquidity and Capital Resources

        Our cash and cash equivalents at September 30, 2002 were $7,421,629 compared to $5,383,045 at March 31, 2002. Our current ratio, which we calculate by dividing our current assets by our current liabilities, at September 30, 2002 was 0.87 compared to 0.98 at March 31, 2002. Our working capital deficit increased to $2,498,545 at September 30, 2002 from $301,273 at March 31, 2002.

        Our accounts receivable increased to $6,392,675 at September 30, 2002 from $6,160,797 at March 31, 2002, and contract drilling in progress decreased to $1,796,449 at September 30, 2002 from $3,120,252 at March 31, 2002. The decrease in the combination of accounts receivable and contract drilling in progress was due to a decline in rig utilization and revenue rates in the quarter ended September 30, 2002 compared to the March 31, 2002 quarter.

        Our cash flows from operating activities for the six months ended September 30, 2002 were $8,456,707 compared to $4,994,660 for this same period of 2001. Our cash flows from operating activities are affected by a number of factors. Some of the significant factors that affect our cash flows from operations are rig utilization rates, the types of contracts we are able to obtain, revenue rates we are able to obtain for our services, collection of receivables and the timing of expenditures.

        Since March 31, 2002, the additions to our property and equipment were $15,909,357. Additions consisted of the following:

        As of September 30, 2002, we were constructing three new/refurbished land drilling rigs. We estimate the total cost of these rigs will be approximately $20,000,000, of which $3,125,159 has been incurred as of September 30, 2002, including capitalized interest costs of $30,402 relating to these rigs. We expect to receive the first rig in November 2002, the second in December 2002 and the third in March 2003. On September 30, 2002, we signed an agreement to purchase another drilling rig for

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$3,150,000. We expect to receive that rig in January 2003. We are financing these rig purchases with a combination of debt and equity. In addition, we plan to continue to add rigs and/or purchase companies which fit our strategic objectives.

        Our debt obligations in the form of notes payable, capital leases and a convertible subordinated debenture increased by a net of $8,935,074 from March 31, 2002 to September 30, 2002. This increase resulted from a $10,000,000 increase in our subordinated debt, $72,080 to finance the premium on an insurance policy and $216,966 in capital leases for crew quarters and vehicles. We also made payments of $1,353,972 on our debt. In addition, on May 28, 2002, we obtained a $7,000,000 short-term loan from our primary bank lender, which we repaid on July 3, 2002 with $7,000,000 of proceeds from the issuance of new convertible subordinated debt as described below. Borrowings from our bank lenders are secured by drilling equipment. Our bank loans contain various covenants pertaining to leverage ratios, cash flow coverage ratios and capitalization or net worth ratios and restrict us from the payment of dividends. Under these credit arrangements, we determine compliance with the ratios on an annual basis, except for the capitalization and net worth ratios, which we determine on a quarterly basis. As of September 30, 2002, we are in compliance with all covenants applicable to our outstanding debt.

        On October 9, 2001, we issued a 6.75% five-year $18,000,000 convertible subordinated debenture, Series A, to WEDGE Energy Services, L.L.C. ("WEDGE"). The debenture was convertible into 4,500,000 shares of common stock at $4.00 per share. We used approximately $9,000,000 of the proceeds to complete the construction of two drilling rigs. Approximately $6,000,000 was used to reduce a $12,000,000 credit facility. The balance of the proceeds were used for drilling equipment and working capital. On July 3, 2002, we issued an additional $10,000,000 of 6.75% convertible subordinated debt to WEDGE with an effective conversion rate of $5.00 per share. The transaction was effected by an agreement between Pioneer and WEDGE under which WEDGE agreed to provide the additional $10,000,000 in financing and to cancel the previously issued debenture in the principal amount of $18,000,000 in exchange for $28,000,000 in new 6.75% convertible subordinated debentures. The new debentures are convertible into 6.5 million shares of common stock at $4.31 per share, which is a pro rata blending of the $5.00 conversion rate of the new $10,000,000 financing and the $4.00 conversion rate of the $18,000,000 debenture being cancelled. WEDGE funded $7,000,000 of the $10,000,000 on July 3, 2002 and $2,000,000 on July 29, 2002. William H. White, one of our Directors and the President of WEDGE, purchased the remaining $1,000,000 on July 29, 2002. Unlike the cancelled debenture, which was not redeemable by Pioneer, the new debentures are redeemable at a scheduled premium. Pioneer used $7,000,000 of the proceeds to pay down bank debt and $3,000,000 for the purchase of drilling equipment. If WEDGE were to convert the new debentures, it would own approximately 61 percent of Pioneer's outstanding common stock.

        On September 30, 2002, we increased our credit facility with our primary bank lender from $6,000,000 to $8,000,000 and the maturity date was extended to June 29, 2003. On October 31, 2002, our primary bank lender extended the maturity date on our term loan from August 11, 2003 to August 11, 2004.

        We also have a $1,000,000 line of credit with our primary bank lender. Draws are limited to 75% of eligible accounts receivable. Therefore, if our eligible accounts receivable should fall below $1,333,334, our ability to draw under this line would be reduced. At September 30, 2002, there was no balance outstanding on this line and eligible accounts receivable were $6,401,232. In addition, our primary bank lender has issued on our behalf two letters of credit totaling $1,450,000 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 the lender will be required to fund any draws under these letters of credit. In August 2002, our primary bank lender issued five letters of credit totaling $704,922 to support our purchase of drill pipe. We expect delivery of this pipe in November of 2002.

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        Our long-term debt and capital lease obligations maturing each year subsequent to September 30, 2002 are as follows:

        Events of default in our bank 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;



•

our incurrence of any additional indebtedness in excess of $2,000,000; and



•

any payment of cash dividends on our common stock.

        Our accounts payable at September 30, 2002 were $8,634,345, an increase of $2,127,176 from $6,507,169 at March 31, 2002. The increase in accounts payable was primarily the result of an increased level of turnkey contracts during the quarter ended September 30, 2002 compared to the quarter ended March 31, 2002 and costs incurred in the major refurbishment of a drilling rig which returned to service in late September 2002.

        On May 28, 2002, we purchased from United Drilling Company and U-D Holdings, L.P. two land drilling rigs, associated spare parts and vehicles for $7,000,000 in cash. We financed the acquisition of those assets with a $7,000,000 loan from our primary bank lender. Interest on the loan was payable monthly at prime. The loan was collateralized by the assets that we purchased and a $7,000,000 letter of credit that WEDGE provided. We repaid this loan on July 3, 2002 with $7,000,000 of the proceeds from the issuance of the subordinated debt as described above.

Results of Operations

        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.

        Daywork Contracts.    Under daywork drilling contracts, we provide a drilling rig with required personnel to our customer, who supervises the drilling of the well. We are paid based on a negotiated fixed rate per day while the rig is used. Daywork drilling contracts specify the equipment to be used, the size of the hole and the depth of the well. Under a daywork drilling contract, the customer bears a large portion of out-of-pocket costs of drilling and we generally bear no part of the usual risks associated with drilling, such as time delays and unanticipated costs.

        Turnkey Contracts.    Under a turnkey contract, we agree to drill a well for our customer to a specified depth and under specified conditions for a fixed price, regardless of the time required or the problems encountered in drilling the well. We provide technical expertise and engineering services, as

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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. Turnkey contracts generally afford an opportunity to earn a higher return than would normally be available on daywork contracts if the contract can be completed successfully without complications.

        Due to the current reduced demand for drilling rigs, we have returned to bidding on turnkey contracts in an effort to improve margins and rig utilization.

        The risks to us under a turnkey contract are substantially greater than on a well drilled on a daywork basis, because we assume most of the risks associated with drilling operations generally assumed by the operator in a daywork contract, including the risk of blowout, loss of hole, stuck drill pipe, machinery breakdowns, abnormal drilling conditions and risks associated with subcontractors' services, supplies, cost escalations and personnel. We employ or contract for engineering expertise to analyze seismic, geologic and drilling data to identify and reduce some of the drilling risks assumed by us. We use the results of this analysis to evaluate the risks of a proposed contract and seek to account for such risks in our bid preparation. We believe that our operating experience, qualified drilling personnel, risk management program, internal engineering expertise and access to proficient third- party engineering contractors have allowed us to reduce some of the risks inherent in turnkey drilling operations. We also maintain insurance coverage against some but not all drilling hazards. However, the occurrence of uninsured or under insured losses or operating cost overruns on our turnkey jobs could have a material adverse effect on our financial position and results of operations.

        Footage Contracts.    Under footage contracts, we are paid a fixed amount for each foot drilled, regardless of the time required or the problems encountered in drilling the well. We typically pay more of the out-of-pocket costs associated with footage contracts compared with daywork contracts. Similar to a turnkey contract, the risks to us on a footage contract are greater because we assume most of the risks associated with drilling operations generally assumed by the operator in a daywork contract, including the risk of blowout, loss of hole, stuck drill pipe, machinery breakdowns, abnormal drilling conditions and risks associated with subcontractors' services, supplies, cost escalation and personnel. As with turnkey contracts, we manage this additional risk through the use of engineering expertise and bid the footage contracts accordingly, and we maintain insurance coverage against some but not all drilling hazards. However, the occurrence of uninsured or under-insured losses or operating cost overruns on our footage jobs could have a material adverse effect on our financial position and results of operations.

        For the three-month and six-month periods ended September 30, 2002 and 2001, our rig utilization and revenue days were as follows:

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        For the three-month and six-month periods ended September 30, 2002 and 2001, the percentages of our drilling revenues by type of contract were as follows:

        Our drilling margin decreased to $2,303,045 for our quarter ended September 30, 2002 from $6,795,829 in the corresponding quarter of 2001. The decrease in 2002 from 2001 principally resulted from decreases in rig utilization and revenue rates we charged under our daywork drilling contracts. As a percentage of contract drilling revenue, our drilling margin was 14% for the quarter ended September 30, 2002 compared to 38% in the quarter ended September 30, 2001. Because the additional costs associated with turnkey contracts are included in revenues and costs, our drilling costs in 2002 are significantly higher than in 2001 and our drilling margin percentage is significantly lower in 2002 compared to 2001.

        Our drilling margin decreased to $5,651,920 for the six months ended September 30, 2002 from $14,339,691 in the corresponding period of 2001. The decrease in 2002 from 2001 principally resulted from decreases in rig utilization and revenue rates we charged under our daywork drilling contracts. As a percentage of contract drilling revenue, our drilling margin was 16% for the six months ended September 30, 2002 compared to 40% in the same period of 2001. Because the additional costs associated with turnkey contracts are included in revenues and costs, our drilling costs in 2002 are significantly higher than in 2001 and our drilling margin percentage is significantly lower in 2002 compared to 2001.

        Our depreciation and amortization expense in the quarter ended September 30, 2002 increased to $2,827,364 from $1,954,837 in the quarter ended September 30, 2001. Our depreciation and amortization expense in the six months ended September 30, 2002 increased to $5,515,645 from $3,567,156 in the corresponding period of 2001. The increase in the current periods resulted from our addition of four drilling rigs and related equipment since September 30, 2001.

        Our general and administrative expenses decreased to $617,023 in the quarter ended September 30, 2002 from $642,208 in the quarter ended September 30, 2001. Our general and administrative expenses decreased to $1,124,908 in the six months ended September 30, 2002 from $1,380,324 in the corresponding period of 2001. The decreases resulted from reduced payroll costs, legal and professional fees and investor relation costs.

        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 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 income tax expense differs from the federal statutory rate of 34% due to permanent differences.

Accounting Matters

        In June 2001, the Financial Accounting Standards Board issued Statement of Financial Accounting Standards ("SFAS") No. 143, "Accounting for Asset Retirement Obligations," which addresses financial accounting and reporting for obligations associated with the retirement of tangible long-lived assets and

15

the associated asset retirement costs. The standard applies to legal obligations associated with the retirement of long-lived assets that result from the acquisition, construction, development and/or normal use of the asset. We are required to adopt the provisions of SFAS No. 143 beginning April 1, 2003. In that connection, we must identify all our legal obligations relating to asset retirements and determine the fair value of these obligations on the date of adoption. We do not expect the adoption of SFAS No. 143 to have a material effect on our financial position or results of operations.

        SFAS No. 146, "Accounting for Costs Associated with Exit or Disposal Activities," issued in July 2002, addresses financial accounting and reporting for costs associated with exit or disposal activities. SFAS No. 146 requires that a liability be recognized for those costs only when the liability is incurred and can be measured at fair value. This statement nullifies Emerging Issues Task Force Issue No. 94-3, "Liability Recognition for Certain Employee Termination Benefits and Other Costs to Exit an Activity," which requires liability recognition for an exit cost when a company commits to an exit plan. SFAS No. 146 is effective for exit or disposal activities that are initiated after December 31, 2002. We will adopt SFAS No. 146 as of January 1, 2003. At this time, we do not believe that the adoption of SFAS No. 146 will have a material effect on our financial position or results of operations.

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 either of the periods reported.

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 September 30, 2002, we had outstanding debt of $14,622,213 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 $96,507, annually. We did not enter into these debt arrangements for trading purposes.

ITEM 4. CONTROLS AND PROCEDURES

        Within the 90-day period immediately preceding the filing of this report, our chief executive officer and chief financial officer have evaluated the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rules 13a-14(c) and 15d-14(c) under the Securities Exchange Act of 1934). Based on that evaluation, our chief executive officer and chief financial officer concluded that the design and operation of our disclosure controls and procedures were effective as of the date of that evaluation. There have been no significant changes in our internal controls or in other factors that could significantly affect those controls subsequent to the date of that evaluation.

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PART II. OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

        For information regarding litigation involving our company, see Note 3 to the condensed consolidated financial statements in Part I of this report.

ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K

(b)

Reports on Form 8-K.        We filed reports on Form 8-K on July 18, 2002 (to report a change in control under Item 1 of Form 8-K) and August 9, 2002 (to report Regulation FD disclosure under Item 9 of Form 8-K).

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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: November 8, 2002

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CERTIFICATIONS

I, Michael E. Little, chief executive officer of Pioneer Drilling Company, certify that:

1.

I have reviewed this quarterly report on Form 10-Q of Pioneer Drilling Company;

2.

Based on my knowledge, this quarterly report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this quarterly report;

3.

Based on my knowledge, the financial statements, and other financial information included in this quarterly report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this quarterly report;

4.

The registrant's other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have:

a)

designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this quarterly report is being prepared;



b)

evaluated the effectiveness of the registrant's disclosure controls and procedures as of a date within 90 days prior to the filing date of this quarterly report (the "Evaluation Date"); and



c)

presented in this quarterly report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date;

5.

The registrant's other certifying officers and I have disclosed, based on our most recent evaluation, to the registrant's auditors and the audit committee of registrant's board of directors (or persons performing the equivalent function):

a)

all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant's ability to record, process, summarize and report financial data and have identified for the registrant's auditors any material weaknesses in internal controls; and



b)

any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal controls; and

6.

The registrant's other certifying officers and I have indicated in this quarterly report whether or not there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses.

November 8, 2002

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I, Wm. Stacy Locke, president and chief financial officer of Pioneer Drilling Company, certify that:

1.

I have reviewed this quarterly report on Form 10-Q of Pioneer Drilling Company;

2.

Based on my knowledge, this quarterly report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this quarterly report;

3.

Based on my knowledge, the financial statements, and other financial information included in this quarterly report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this quarterly report;

4.

The registrant's other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have:

a)

designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this quarterly report is being prepared;



b)

evaluated the effectiveness of the registrant's disclosure controls and procedures as of a date within 90 days prior to the filing date of this quarterly report (the "Evaluation Date"); and



c)

presented in this quarterly report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date;

5.

The registrant's other certifying officers and I have disclosed, based on our most recent evaluation, to the registrant's auditors and the audit committee of registrant's board of directors (or persons performing the equivalent function):

a)

all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant's ability to record, process, summarize and report financial data and have identified for the registrant's auditors any material weaknesses in internal controls; and



b)

any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal controls; and

6.

The registrant's other certifying officers and I have indicated in this quarterly report whether or not there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses.

November 8, 2002

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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 1. LEGAL PROCEEDINGS
ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K