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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 ý    No o

        As of February 7, 2005, there were 38,914,978 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

(Unaudited)

See accompanying notes to condensed consolidated financial statements.

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PIONEER DRILLING COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

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 accompanying unaudited 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 use the intrinsic value method of the SFAS No. 123, Accounting for Stock-Based Compensation ("SFAS No. 123"). 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 respective grant dates as SFAS No. 123 prescribes, our net earnings (loss)

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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 for each of the three-month and nine-month periods ended December 31, 2004 and 2003:

        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.

In December 2004, the Financial Accounting Standards Board issued SFAS No. 123 (revised 2004), Share-Based Payment ("SFAS No. 123R"), which will require the compensation costs related to share-based payment transactions to be recognized in financial statements. With limited exceptions, the amount of compensation cost will be measured based on the grant-date fair value of the equity instruments issued. Compensation cost will be recognized over the vesting period during which an employee provides service in exchange for the award. SFAS No. 123R will be effective for us July 1, 2005. Two alternative methods of adoption will be available to us. Under the modified prospective method, unvested equity-classified awards would continue to be accounted for in accordance with SFAS No. 123 as disclosed above except that amounts would be recognized in the statement of operations, beginning July 1, 2005. Under the modified retrospective method, previously reported amounts would be restated for all periods presented to reflect the SFAS No. 123 amounts in the statements of operations. We have not quantified the effect SFAS No. 123R will have on future reporting periods or chosen the transition adoption method we will use.

Related Party Transactions

        On August 11, 2004 and August 31, 2004, Chesapeake Energy Corporation ("Chesapeake") purchased 631,133 shares and 94,670 shares of our common stock, respectively, at $6.90 per share

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pursuant to the preemptive rights we granted to Chesapeake in the stock purchase agreement we entered into in March 2003 when we sold shares of common stock to Chesapeake. As of December 31, 2004, Chesapeake owned 16.97% of our outstanding common stock. During the three and nine months ended December 31, 2004, we recognized revenues of approximately $1,340,000 and $1,349,000, respectively, and recorded contract drilling costs of approximately $823,000 and $837,000, respectively, excluding depreciation, on contracts with Chesapeake. Accounts receivable at December 31, 2004 include $973,920 due from Chesapeake.

        We purchased services from R&B Answering Service and Frontier Services, Inc. during 2004 and 2003. These companies are more than 5% owned by our Chief Operating Officer and an immediate family member of our Vice President, South Texas Division, respectively. The following summarizes the transactions with these companies in each period.

Reclassifications

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

2.     Acquisitions

        On November 30, 2004, we acquired all the contract drilling assets and a 4.7—acre rig storage and maintenance yard of Wolverine Drilling, Inc., a land drilling contractor based in Kenmare, North Dakota. The equipment included seven mechanical land drilling rigs and related assets, including trucks, trailers, vehicles, spare drill pipe and yard equipment. We paid $28,000,000 in cash for these assets and non-competition agreements with the two owners of Wolverine. We funded this acquisition with $28,000,000 of bank debt described in note 3. This purchase was accounted for as the acquisition of a business, and we have included the results of operations of the acquired business in our statement of operations since the date of acquisition. We allocated the purchase price to property and equipment and related assets, including the non-competition agreements and other intangibles, based on their relative fair values at the date of acquisition.

        On December 15, 2004, we acquired all the contract drilling assets and a 17—acre rig storage and maintenance yard of Allen Drilling Company, a land drilling contractor based in Woodward, Oklahoma. The equipment included five mechanical land drilling rigs and related assets, including trucks, trailers, vehicles, spare drill pipe and yard equipment. We paid $7,200,000 in cash for these assets. We also entered into a non-competition agreement with the President of Allen Drilling which provides for the payment of $500,000 due in annual installments of $100,000 each beginning December 15, 2005. We funded this acquisition with $7,200,000 of bank debt described in note 3. This purchase was accounted for as the acquisition of a business, and we have included the results of operations of the acquired business in our statement of operations since the date of acquisition. We allocated the purchase price to property and equipment and related assets, including the non-competition agreements and other intangibles, based on their relative fair values at the date of acquisition.

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        The following table summarizes the allocation of purchase price to property and equipment and other assets acquired in the Wolverine and Allen Drilling acquisitions:

        We have not yet obtained all the information required to complete the purchase price allocation for Allen Drilling Company.

        The following pro forma information gives effect to the Wolverine and Allen Drilling acquisitions as though they were effective as of the beginning of the fiscal year for each period presented. Pro forma adjustments primarily relate to additional depreciation, amortization and interest costs. The information reflects our historical data and historical data from these acquired businesses for the periods indicated. The pro forma data may not be indicative of the results we would have achieved had we completed these acquisitions on April 1, 2003 or 2004, or that we may achieve in the future. The pro forma financial information should be read in conjunction with the accompanying historical financial statements.

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

        On August 11, 2004, the entire $28,000,000 in aggregate principal amount of our 6.75% convertible subordinated debentures held by WEDGE Energy Services, L.L.C. and William H. White was converted in accordance with the terms of those debentures into 6,496,519 shares of our common stock.

        On August 12, 2004, we made a $2,000,000 principal payment on our collateral installment note held by Merrill Lynch Capital, due in December 2007. In accordance with the terms of the note, we also gave Merrill Lynch Capital the required 30-days notice of our intent to repay the balance outstanding under the note. On September 10, 2004, we repaid the approximately $10,083,000 balance of the note and paid a prepayment fee of approximately $101,000.

        On August 12, 2004, we retired our note payable to Frost National Bank in the principal amount of approximately $2,852,000, which was due in March 2007.

        On August 16, 2004, we retired our note payable to Frost National Bank in the principal amount of approximately $3,856,000, which was due in August 2007.

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        On October 29, 2004, we entered into a $47,000,000 credit facility with a group of lenders consisting of a $7,000,000 revolving line and letter of credit facility and a $40,000,000 acquisition facility for the acquisition of drilling rigs, drilling rig transportation equipment and associated equipment. Frost National Bank is the administrative agent and lead arranger under the new credit facility, and the lenders include Frost National Bank, the Bank of Scotland and Zions First National Bank. Borrowings under the new credit facility bear interest at a rate equal to Frost National Bank's prime rate and are secured by most of our assets, including all our drilling rigs and associated equipment and receivables. As of December 31, 2004, we have utilized $35,200,000 of the acquisition facility to fund our purchases of the land drilling assets of Wolverine Drilling, Inc. and Allen Drilling Company as described in note 2. The loan balance of $35,200,000 at December 31, 2004 is due in monthly installments of approximately $488,889 plus interest at Frost National Bank's floating prime rate (5.25% at December 31, 2005). The remaining unpaid balance is due December 1, 2007. The $35,200,000 matures as follows: $5,866,667 by December 1, 2005; $5,866,667 by December 1, 2006; and $23,466,666 by December 1, 2007.

        The sum of draws under our revolving line and letter of credit facility and the amount of all outstanding letters of credit issued by the banks for our account are limited to 75% of eligible accounts receivable not to exceed $7,000,000. Therefore, if 75% of our eligible accounts receivable was less than $7,000,000 our ability to draw under this line would be reduced. At December 31, 2004, we had no outstanding advances under this line of credit, letters of credit were $2,505,000 and 75% of our eligible accounts receivable was approximately $12,379,000. 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 lenders will be required to fund any draws under these letters of credit. The termination date for the revolving line and letter of credit facility is October 28, 2005.

        At December 31, 2004, we were in compliance with all covenants applicable to our credit facility. Those covenants include, among others, the maintenance of ratios of debt to total capitalization, fixed charge coverage and operating leverage. The covenants also restrict the payment of dividends on our common stock.

4.     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.

5.     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.

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

        On August 11, 2004, the entire $28,000,000 in aggregate principal amount of our 6.75% convertible subordinated debentures held by WEDGE Energy Services, L.L.C. and William H. White was converted in accordance with the terms of those debentures into 6,496,519 shares of our common stock.

        On August 31, 2004, we sold 600,000 additional shares of our common stock at approximately $6.61 per share, net of underwriters' commissions, pursuant to the underwriters' exercise of an over-allotment option granted in connection with the public offering we referred to above.

        Employees exercised stock options for the purchase of 118,333 shares and 34,000 shares of common stock during the nine months ended December 31, 2004 and 2003, respectively, at prices ranging from $2.25 to $6.44 per share.

6.     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 2,310,000 shares and 6,496,519 shares from convertible debentures were not included in the computation of diluted loss per share for the three months and nine months ended December 31, 2003, because they were 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 selected oil and natural gas production regions in the United States. 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.

        Since September 1999, we have significantly expanded our fleet of drilling rigs through acquisitions, construction of new rigs and the refurbishment of older rigs. As of December 31, 2004, our rig fleet consisted of 49 land drilling rigs that drill in depth ranges between 6,000 and 18,000 feet. As of January 31, 2005, we had 15 rigs operating in South Texas, 17 in East Texas, four in North Texas, five in western Oklahoma and eight in the Rocky Mountains. We actively market all of these rigs. Subject to obtaining satisfactory financing, we anticipate continued growth of our rig fleet in fiscal 2006. We are currently constructing a 1000-horse power mechanical rig from new and used components.

        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. However, we completed construction of a rig in late December which began a one year contract in early January for a customer in the Rocky Mountains.

        A significant performance measurement in our industry is rig utilization. We compute rig utilization rates by dividing revenue days by total available days during a period. Total available days are the number of calendar days during the period that we have owned the rig. Revenue days for each rig are days when the rig is earning revenues under a contract, which is usually a period from the date the rig begins moving to the drilling location until the rig is released from the contract. On daywork contracts, during the mobilization period we typically earn a fixed amount of revenue based on the mobilization rate stated in the contract. We attempt to set the mobilization rate at an amount equal to

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our external costs for the move, plus our internal costs during the mobilization period. We begin earning our contracted daywork rate when we begin drilling the well. Occasionally, in periods of increased demand, some of our contracts will provide for the trucking costs to be paid by the customer and we will receive a reduced dayrate during the mobilization period.

For the three-month and nine-month periods ended December 31, 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 28 rigs at December 31, 2003 to 49 rigs at December 31, 2004 and the improvement in our overall rig utilization rate due to the improved market conditions. For the remainder of fiscal 2005 and into fiscal 2006, we anticipate continued growth in revenue days and maintaining relatively high utilization rates.

        In addition to high commodity prices, we attribute our relatively high utilization rates to a strong sales effort, quality equipment, good field and operations personnel, a disciplined safety approach, and our generally successful performance of turnkey operations. For the nine months ended December 31, 2004, turnkey contracts accounted for approximately 37 percent of our contracts. Turnkey contracts provide us with the opportunity to keep our rigs working in periods of lower demand and improve our profitability, but at an increased risk. As was the case for several turnkey contracts under which we performed during the nine months ended December 31, 2004, a turnkey contract may not be profitable if it cannot be completed successfully without unanticipated complications.

        We devote substantial resources to maintaining and upgrading our rig fleet. During our fiscal year 2004, we removed three rigs from service for approximately three weeks each, in order to perform upgrades. In the short term, these actions resulted in fewer revenue days and slightly lower utilization; however, in the long term, we believe the upgrades will help the marketability of our rigs and improve their operating performance. We expended approximately $4,818,000 on rig upgrades during the nine months ended December 31, 2004. We are currently performing, between contracts or as necessary, safety and equipment upgrades to 12 rigs we acquired in November and December 2004.

Market Conditions in Our Industry

        The United States contract land drilling services industry is highly cyclical. Volatility in oil and gas prices can produce wide swings in the levels of overall drilling activity in the markets we serve and affect the demand for our drilling services and the dayrates we can charge for our rigs. The availability of financing sources, past trends in oil and gas prices and the outlook for future oil and gas prices strongly influence the number of wells oil and gas exploration and production companies decide to drill.

        On January 28, 2005, the spot price for West Texas Intermediate crude oil was $47.18, the spot price for Henry Hub natural gas was $6.23 and the Baker Hughes land rig count was 1,130, a 16% increase from 973 on January 30, 2004.

        The average weekly spot prices of West Texas Intermediate crude oil and Henry Hub natural gas and the average weekly domestic land rig count, per the Baker Hughes land rig count, for the nine

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months ended December 31, 2004 and each of the five most recent years in the period ended December 31, 2004 were:

        For the three months ended December 31, 2004, the average weekly spot price for West Texas Intermediate crude oil was $48.42, the average weekly spot price for Henry Hub natural gas was $6.08 and the average weekly Baker Hughes land rig count was 1,127.

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

Critical Accounting Policies and Estimates

        Revenue and cost recognition—We earn our revenues by drilling oil and gas wells for our customers under daywork, turnkey or footage contracts, which usually provide for the drilling of a single well. We recognize revenues on daywork contracts for the days completed based on the dayrate each contract specifies. We recognize revenues from our turnkey and footage contracts on the percentage-of-completion method for the days completed, based on the contract amount divided by our estimate of the number of days to complete each contract. Contract drilling in progress represents revenues we have recognized in excess of amounts billed on contracts in progress. Individual contracts are usually completed in less than 60 days. The risks to us under a turnkey contract, and to a lesser extent under footage contracts, are substantially greater than on a contract drilled on a daywork basis. This is primarily because, under a turnkey contract, we assume most of the risks associated with drilling operations generally assumed by the operator in a daywork contract, including the risks of blowout, loss of hole, stuck drill pipe, machinery breakdowns and abnormal drilling conditions, as well as risks associated with subcontractors' services, supplies, cost escalations and personnel operations.

        Our management has determined that it is appropriate to use the percentage-of-completion method to recognize revenue on our turnkey and footage contracts. Although our turnkey and footage contracts do not have express terms that provide us with rights to receive payment for the work that we perform prior to drilling wells to the agreed-on depth, we use this method because, as provided in applicable accounting literature, we believe we achieve a continuous sale for our work-in-progress and we believe, under applicable state law, we ultimately could recover the fair value of our work-in-progress even in the event we were unable to drill to the agreed-on depth in breach of the applicable contract. However, ultimate recovery of that value, in the event we were unable to drill to the agreed-on depth in breach of the contract, would be subject to negotiations with the customer and the possibility of litigation.

        If a customer defaults on its payment obligation to us under a turnkey or footage contract, we would need to rely on applicable law to enforce our lien rights, because our turnkey and footage

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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 expense. In addition, the occurrence of uninsured or under-insured losses or operating cost overruns on our turnkey and footage contracts could have a material adverse effect on our financial position and results of operations. Therefore, our actual results could differ significantly if our cost estimates are later revised from our original estimates for contracts in progress at the end of a reporting period which were not completed prior to the release of our financial statements.

        Asset impairments—We assess the impairment of property and equipment whenever events or circumstances indicate that the carrying value may not be recoverable. Factors that we consider important and which could trigger an impairment review would be our customers' financial condition and any significant negative industry or economic trends. More specifically, among other things, we consider our contract revenue rates, our rig utilizations rates, cash flows from our drilling rigs, current oil and gas prices, industry analysts' outlook for the industry and their view of our customers' access to debt or equity, discussions with major industry suppliers, discussions with officers of our primary lender regarding their experiences and expectations for oil and gas operators in our areas of operations and the trends in the price of used drilling equipment observed by our management. If a review of our drilling rigs indicates that our carrying value exceeds the estimated undiscounted future cash flows, we are required under applicable accounting standards to write down the drilling equipment to its fair market value. A one percent write-down in the cost of our drilling equipment, at December 31, 2004, would have resulted in a corresponding decrease in our net earnings of approximately $1,324,000 for the three-months and nine-months ended December 31, 2004.

        Deferred taxes—We provide deferred taxes for net operating loss carryforwards and for the basis difference in our property and equipment between financial reporting and tax reporting purposes. For property and equipment, basis differences arise from differences in depreciation periods and methods and the value of assets acquired in a business acquisition where we acquire an entity rather than just its assets. For financial reporting purposes, we depreciate the various components of our drilling rigs over eight to 15 years and refurbishments over three years, while federal income tax rules require that we depreciate drilling rigs and refurbishments over five years. Therefore, in the first five years of our ownership of a drilling rig, our tax depreciation exceeds our financial reporting depreciation, resulting in our providing deferred taxes on this depreciation difference. After five years, financial reporting depreciation exceeds tax depreciation, and the deferred tax liability begins to reverse.

        Accounting estimates—We consider the recognition of revenues and costs on turnkey and footage contracts critical accounting estimates. On these types of contracts, we are required to estimate the number of days it will require for us to complete the contract and our total cost to complete the contract. Our actual costs could substantially exceed our estimated costs if we encounter problems such as lost circulation, stuck drill pipe or an underground blowout on contracts still in progress subsequent to the release of the financial statements.

        We receive payment under turnkey and footage contracts when we deliver to our customer a well completed to the depth specified in the contract, unless the customer authorizes us to drill to a shallower depth. Since 1995, when current management joined our company, we have completed all our

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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 nine months ended December 31, 2004, we experienced losses on 14 of the 128 turnkey and footage contracts completed, with losses exceeding $25,000 on nine contracts and losses exceeding $100,000 on four contracts. We are more likely to encounter losses on turnkey and footage contracts in years in which revenue rates are lower for all types of contracts. During periods of reduced demand for drilling rigs, our overall profitability on turnkey and footage contracts has historically exceeded our profitability on daywork contracts.

        Revenues and costs during a reporting period could be affected for contracts in progress at the end of a reporting period which have not been completed before our financial statements for that period are released. All of our turnkey and footage contracts in progress at December 31, 2004 were completed prior to the release of the financial statements included in this report. At December 31, 2004, our contract drilling in progress totaled approximately $7,351,000, of which turnkey and footage contract revenues were approximately $2,547,000 and daywork contract revenues were approximately $4,804,000. At March 31, 2004, our contract drilling in progress totaled approximately $9,131,000, of which turnkey and footage contract revenues were approximately $7,683,0000 and daywork contract revenues were approximately $1,448,000.

        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 had with the customer. Consequently, an adverse change in those factors could affect our estimate of our allowance for doubtful accounts. In some instances, we require new customers to establish escrow accounts or make prepayments. We typically invoice our customers at 15-day intervals during the performance of daywork contracts and upon completion of the daywork contract. Turnkey and footage contracts are invoiced upon completion of the contract. Our typical contract provides for payment of invoices in 10 to 30 days. We generally do not extend payment terms beyond 30 days and have not extended payment terms beyond 60 days for any of our contracts in the last three fiscal years. We established an allowance for doubtful accounts of $452,000 at December 31, 2004, an increase of $342,000 from $110,000 at March 31, 2004.

        Another critical estimate is our determination of the useful lives of our depreciable assets, which directly affects our determination of depreciation expense and deferred taxes. A decrease in the useful life of our drilling equipment would increase depreciation expense and reduce deferred taxes. We provide for depreciation of our drilling, transportation and other equipment on a straight-line method over useful lives that we have estimated and that range from three to 15 years. We record the same depreciation expense whether a rig is idle or working. Our estimates of the useful lives of our drilling, transportation and other equipment are based on our substantial experience in the drilling industry with similar equipment.

        Our other accrued expenses as of December 31, 2004 and March 31, 2004 include accruals of approximately $1,232,000 and $680,000, respectively, for costs incurred under the self-insurance portion

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of our health insurance and under our workers' compensation insurance. We have a deductible of (1) $100,000 per covered individual per year under the health insurance and (2) $250,000 per occurrence under our workers' compensation insurance, except in North Dakota where the deductible is $100,000. We accrue for these costs as claims are incurred, based on cost estimates established for each claim by the insurance companies providing the administrative services for processing the claims, including an estimate for incurred but not reported claims, estimates for claims paid directly by us, our estimate of the administrative costs associated with these claims and our historical experience with these types of claims.

Liquidity and Capital Resources

Sources of Capital Resources

        Our rig fleet has grown from six rigs in September 1999 to 49 rigs as of December 31, 2004. We have financed this growth with a combination of debt and equity financing. At December 31, 2004 our total debt to total capitalization was approximately 21%, compared to 41% at March 31, 2004. We plan to continue to grow our rig fleet. We have obtained a new credit facility to finance near-term growth and anticipate the use of equity financing for additional long-term growth. 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 August 11, 2004, the entire $28,000,000 in aggregate principal amount of our 6.75% convertible subordinated debentures held by WEDGE Energy Services, L.L.C. and William H. White was converted in accordance with the terms of those debentures into 6,496,519 shares of our common stock. 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.

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

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

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Uses of Capital Resources

        For the three and nine months ended December 31, 2004, the additions to our property and equipment consisted of the following:

(1)

Includes capitalized interest costs of $0 for the three months and $28,740 for the nine months ended December 31, 2004.

        In November 2004, we acquired a fleet of seven drilling rigs and related equipment from Wolverine Drilling, obtained non-competition agreements from the two stockholders of Wolverine Drilling and purchased a 4.7-acre rig storage and maintenance yard in Kenmore, North Dakota for total consideration of $28,000,000 in cash. In December 2004, we acquired a fleet of five drilling rigs and related equipment and a 17-acre rig storage and maintenance yard located in Woodward, Oklahoma from Allen Drilling for total consideration of $7,200,000 in cash. We also obtained a non-competition agreement from the President of Allen Drilling for additional consideration to be paid over the next five years. We funded the purchase price for each of these acquisitions with borrowings under our new credit facility aggregating $35,200,000.

        In January 2005, we began constructing, from new and used components, a 1000-horse power mechanical drilling rig. We estimate we will incur approximately $5,500,000 of construction costs for that rig which will be funded from existing cash and operating cash flow or an additional draw on the rig acquisition facility. We expect to complete construction of the rig in March 2005. We have also begun ordering components for the construction of two 1000 horse power SCR electric rigs at an estimated cost of $6,100,000 each. Construction of these rigs is subject to obtaining adequate financing.

        For the remainder of fiscal 2005, we project regular capital expenditures (excluding construction costs to complete the construction of the three rigs referred to above) to be approximately $6,000,000, including approximately $1,800,000 for rig upgrade expenditures. We expect to fund these capital expenditures primarily from operating cash flow.

Working Capital

        Our working capital increased to $11,842,627 at December 31, 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 1.48 at December 31, 2004, compared to 1.27 at March 31, 2004. The principal reason for the increase in our working capital at December 31, 2004 was our August 2004 public offering of common stock, in which we raised proceeds of approximately $29,700,000. Approximately $18,800,000 of those proceeds was used to retire substantially all our long-term debt existing on August 11, 2004. Our operations have historically generated cash flows in excess of our requirements for debt service and normal capital expenditures. The significant improvement in operating cash flow for the nine months ended December 31, 2004 over December 31, 2003 is due primarily to the approximately $7,500,000 overall improvement in net earnings, components of which are discussed in "—Results of Operations." That improvement was net of approximately $4,5000,000 increase in noncash depreciation and amortization expense. If necessary, we can defer rig upgrades to improve our cash position. However, during periods when a higher percentage of our contracts are turnkey or footage contracts, our short-term working

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capital needs could increase. We believe our cash generated by operations and our ability to borrow on the currently unused portion of our line of credit and letter of credit facility of approximately $4,200,000, after reductions for approximately $2,800,000 of outstanding letters of credit as of January 31, 2005, should allow us to meet our routine financial obligations.

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

        The increase in our receivables at December 31, 2004 from March 31, 2004 was due to our operating 14 additional rigs, the improvement in rig utilization and revenue rates and the timing of the completion of contracts as reflected in the decrease in contract drilling in progress. We invoiced approximately $18,500,000 of completed work in December 2004.

        The change in contract drilling in progress was primarily due to the number and stage of completion of turnkey contracts in progress at December 31, 2004 compared to March 31, 2004.

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

        The decrease in accounts payable was due to the decrease in turnkey contracts completed during December and in progress at December 31, 2004. We had seven turnkey and four footage contracts in progress at December 31, 2004 compared to 16 turnkey contracts in progress at March 31, 2004.

        The increase in accrued payroll was due to the increase in the number of our employees due to the rig additions and a payroll tax deposit for our December 31, 2004 payroll made on January 3, 2005, partially offset by inclusion of only four days of payroll at December 31, 2004 compared to nine days at March 31, 2004.

        The increase in accrued expenses at December 31, 2004 compared to March 31, 2004 was principally due to the increase in the accrual for property taxes and self insurance costs, partially offset by a decrease in accrued interest expense.

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Long-term Debt

        Our long-term debt at December 31, 2004 consisted of:

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 our contractual obligations of the types specified below at December 31, 2004.

Debt Requirements

        The $35,200,000 aggregate amount of indebtedness we incurred in November and December 2004 under the acquisition facility portion of our new credit facility is due in monthly installments of $488,889 plus interest, which we began paying on the first business day of January 2005, based on a 72-month amortization schedule, with all remaining unpaid principal being due on December 1, 2007. All the indebtedness under the acquisition facility bears interest at Frost National Bank's prime rate (5.25% as of January 31, 2005). The sum of (1) the draws under and (2) the amount of all outstanding letters of credit issued for our account under the revolving line and letter of credit facility portion of our new credit facility are limited to 75% of our eligible accounts receivable, not to exceed $7,000,000. Therefore, if 75% of our eligible accounts receivable was less than $7,000,000, our ability to draw under this line would be reduced. At December 31, 2004, we had no outstanding advances under this line of credit, outstanding letters of credit were $2,505,000 and 75% of our eligible accounts receivable was approximately $12,379,000. 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 lenders will be required to fund any draws under these letters of credit. The termination date of the revolving line and letter of credit facility portion of our new credit facility is October 28, 2005.

        Our new credit facility contains various covenants pertaining to a debt to total capitalization ratio, operating leverage ratio and fixed charge coverage ratio and restricts us from paying dividends. We will

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determine compliance with the ratios on a quarterly basis, based on the previous four quarters. Events of default, which could trigger an early repayment requirement, include, among others:

•

our failure to make required payments;



•

any sale of assets by us not permitted by the agreement;



•

our failure to comply with financial covenants related to a debt to total capitalization ratio not to exceed 0.3 to 1, an operating leverage ratio of not more than 3 to 1, and a fixed charge coverage ratio of not less than 1.5 to 1;



•

our incurrence of additional indebtedness in excess of $3,000,000 not already allowed by the credit agreement;



•

any event which results in a change in the ownership of at least 40% of all classes of our outstanding capital stock; and



•

any payment of cash dividends on our common stock.

        We do not expect the limitation on additional indebtedness described above to affect our operations or liquidity in the future, as we expect to continue to generate adequate cash flow from operations to fund our anticipated working capital and other normal cash flow requirements.

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 profits.

        Daywork Contracts.    Under daywork drilling contracts, we provide a drilling rig with required personnel to our customer, who supervises the drilling of the well. We are paid based on a negotiated fixed rate per day while the rig is used.

        Turnkey Contracts.    Under a turnkey contract, we agree to drill a well for our customer to a specified depth and under specified conditions for a fixed price, regardless of the time required or the problems encountered in drilling the well. We provide technical expertise and engineering services, as well as most of the equipment and drilling supplies required to drill the well. We often subcontract for related services, such as the provision of casing crews, cementing and well logging. Under typical turnkey drilling arrangements, we do not receive progress payments and are entitled to be paid by our customer only after we have performed the terms of the drilling contract in full. The risks under a turnkey contract are greater than those under a daywork contract, because we assume most of the risks associated with drilling operations that the operator generally assumes under a daywork contract.

        Footage Contracts.    Under footage contracts, we are paid a fixed amount for each foot drilled, regardless of the time required or the problems encountered in drilling the well. We typically pay more of the out-of-pocket costs associated with footage contracts as compared to daywork contracts. Similar to turnkey contracts, under a footage contract we assume most of the risks associated with drilling operations that the operator generally assumes under a daywork contract.

        The current demand for drilling rigs greatly influences the types of contracts we are able to obtain. As the demand for rigs increases, daywork rates move up and we are able to switch to primarily daywork contracts.

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        For the three and nine month periods ended December 31, 2004 and 2003, the percentages of our drilling revenues by type of contract were as follows:

        While current demand for drilling rigs has been increasing, we continue to bid on turnkey contracts in an effort to improve profitability and maintain rig utilization. With the improvements in daywork rates, we anticipate a gradual decline in the number of turnkey contracts. We had seven turnkey contracts in progress at December 31, 2004, compared to 16 turnkey contracts in progress at March 31, 2004. We also had four footage contracts in progress at December 31, 2004 and none at March 31, 2004.

        During the three and nine months ended December 31, 2004, we recognized revenues of approximately $1,340,000 and $1,349,000, respectively, and recorded contract drilling costs of approximately $823,000 and $837,000, respectively, excluding depreciation, on contracts with Chesapeake. Accounts receivable at December 31, 2004 include $973,920 due from Chesapeake.

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Statement of Operations Analysis

        The following table provides information for our operations for the three-month and nine-month periods ended December 31, 2004 and December 31, 2003.

        Our contract drilling revenues grew by approximately $19,973,000, or 76%, in the quarter ended December 31, 2004 from the quarter ended December 31, 2003, due to an improvement in rig revenue rates resulting from an increase in demand for drilling rigs, an increase in the number of rigs in our fleet and a 10% increase in rig utilization. Our contract drilling revenues grew by approximately $55,381,000, or 74%, in the nine months ended December 31, 2004 from the corresponding period in 2003, due to an improvement in rig revenue rates resulting from an increase in demand for drilling rigs, an increase in the number of rigs in our fleet and a 9% increase in rig utilization. The improvement in contract drilling revenue per day is due to the improvement in revenue rates.

        Our contract drilling costs grew by approximately $10,757,000, or 50%, in the quarter ended December 31, 2004 from the corresponding quarter of 2003 due to the increase in the number of rigs in our fleet, the increase in rig utilization and the increase in revenue days in 2004 compared to 2003. The decline in average contract drilling cost per revenue day is due to the shift to more daywork revenue days as a percentage of total revenue days. Under turnkey and footage contracts we provide supplies and materials such as fuel, drill bits, casing and drilling fluids, which significantly adds to drilling costs for turnkey and footage contracts. These costs are also included in the revenues we recognize for turnkey and footage contracts, resulting in higher revenue rates per day for turnkey and footage contracts compared to daywork contracts which do not include such costs.

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        Our contract drilling costs grew by approximately $39,045,000, or 63%, in the nine months ended December 31, 2004 from the corresponding period in 2003 due to the increase in the number of rigs in our fleet, the increase in rig utilization and the 92% increase in turnkey revenue days in 2004 compared to 2003.

        Our depreciation and amortization expense in the quarter ended December 31, 2004 increased by approximately $1,651,000, or 40%, from the corresponding quarter of 2003. Our depreciation and amortization expense for the nine months ended December 31, 2004 increased by approximately $4,454,000, or 38%, from the corresponding nine months of 2003. The increases in 2004 over 2003 primarily resulted from the approximate 42% increase in the average size of our rig fleet and the expansion of our trucking fleet.

        Our general and administrative expense in the quarter ended December 31, 2004 increased by approximately $528,000, or 77%, from the corresponding quarter of 2003. The increase resulted from increased payroll costs, insurance costs, professional fees and director fees. In the quarter ended December 31, 2004, payroll cost increased by approximately $177,000, due to pay raises and an increase in the number of employees in our corporate office. Directors' and officers' liability and employment practices insurance increased by approximately $23,000, professional fees increased by approximately $250,000 and director fees increased by approximately $17,000.

        Our general and administrative expenses increased by approximately $884,000, or 44%, in the nine months ended December 31, 2004 from the corresponding period of 2003. The increase resulted from increased payroll costs, insurance costs, professional fees and director fees. In 2004, payroll cost increased by approximately $298,000, due to pay raises and the increase in the number of employees in our corporate office. Directors' and officers' liability and employment practices insurance increased by approximately $66,000, professional fees increased by approximately $314,000 and directors' fees increased by approximately $127,000.

        Our effective income tax rates of 37% and 18% for the three-month periods ended December 31, 2004 and 2003, respectively, and 37% and 24% for the nine-month periods ended December 31, 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.

Accounting Matters

        In December 2004, the Financial Accounting Standards Board issued the Statement of Financial Accounting Standards ("SFAS") No. 123 (revised 2004), Share-Based Payment ("SFAS No. 123R"), which will require the compensation costs related to share-based payment transactions to be recognized in financial statements. With limited exceptions, the amount of compensation cost will be measured based on the grant-date fair value of the equity instruments issued. Compensation cost will be recognized over the vesting period during which an employee provides service in exchange for the award. SFAS No. 123R will be effective for us July 1, 2005. Two alternative methods of adoption will be available to us. Under the modified prospective method, unvested equity-classified awards would continue to be accounted for in accordance with SFAS No. 123, Accounting for Stock-Based Compensation ("SFAS No. 123") as disclosed above except that amounts would be recognized in the statement of operations, beginning July 1, 2005. Under the modified retrospective method, previously reported amounts would be restated for all periods presented to reflect the SFAS No. 123 amounts in the statements of operations. We have not quantified the effect SFAS No. 123R will have on future reporting periods or chosen the transition adoption method we will use.

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Inflation

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

Off Balance Sheet Arrangements

        We do not currently have any off balance sheet arrangements.

ITEM 3.    QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

        We are usually subject to market risk exposure related to changes in interest rates on our outstanding floating rate debt. At December 31, 2004, we had outstanding debt of approximately $35,200,000 that was subject to variable interest rates, in each case based on the lender's prime interest rate. An increase or decrease of 1% in the interest rate would have a corresponding decrease or increase in our net income (loss) of approximately $232,000 annually. We did not enter into any of our 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 December 31, 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 control over financial reporting that occurred during the three months ended December 31, 2004 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

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PART II. OTHER INFORMATION

ITEM 4.    SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

        There were no matters submitted to the shareholders of the Company for their approval during the quarter ended December 31, 2004.

ITEM 6.    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.

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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 initially filed with the Securities and Exchange Commission on February 7, 2005.

Dated: February 7, 2005

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Index to Exhibits

*

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

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ITEM 1. FINANCIAL STATEMENTS