UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

For the quarterly period ended December 31, 2006June 30, 2007

OR

For the transition period from                        to                        

Commission File Number 1-8182

PIONEER DRILLING COMPANY

(Exact name of registrant as specified in its charter)

210-828-7689

(Registrant’s telephone number, including area code)

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  xþ     No  ¨

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of “accelerated filer and large accelerated filer” in Rule 12b-2 of the Exchange Act.

Large accelerated filer  ¨         Accelerated filer  xþ         Non-accelerated filer  ¨

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes  ¨ No  xþ

As of FebruaryAugust 1, 2007, there were 49,616,47849,650,978 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 SUBSIDARIESSUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

1. Organization and Basis of Presentation

Business and Principles of Consolidation

Pioneer Drilling Company provides contract land drilling services to its customers in select oil and natural gas exploration and production regions in the United States. As of December 31, 2006,June 30, 2007, our rig fleet consisted of 6366 operating drilling rigs, 17 of which were operating in our South Texas division, 1820 of which were operating in our East Texas division, nineten of which were operating in our North Texas division, sevensix of which were operating in our Western Oklahoma division and 1213 of which were operating in our Rocky Mountain divisions in Utah and North Dakota. In addition, at June 30, 2007, we were upgrading, with top drives and other components, a 1500 horsepower rig acquired in April 2007 and a 1500 horsepower rig acquired in May 2007. We placed one additionalalso agreed to acquire another 1500 horsepower rig in operationMay 2007 that is currently under construction. These three rigs are ideally suited for our expansion into international markets and are not included in January 2007.our 66 operating rig count. We conduct our operations through our principal operating subsidiary, Pioneer Drilling Services, Ltd. The accompanying unaudited condensed consolidated financial statements include our accounts and the accounts of our 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. In preparing the accompanying unaudited condensed consolidated financial statements, we make various estimates and assumptions that affect the amounts of assets and liabilities we report as of the dates of the balance sheets and income and expenses we report for the periods shown in the income statements and statements of cash flows. Our actual results could differ significantly from those estimates. Material estimates that are particularly susceptible to significant changes in the near term relate to our recognition of revenues and costs for turnkey contracts, our estimate of the allowance for doubtful accounts, our estimate of the self-insurance portion of our health and workers’ compensation insurance, our estimate of asset impairments, our estimate of deferred taxes and our determination of depreciation and amortization expense. The condensed consolidated balance sheet as of March 31, 20062007 has been derived from our audited financial statements. We suggest that you read these condensed consolidated financial statements together with the consolidated financial statements and the related notes included in our annual report on Form 10-K for the fiscal year ended March 31, 2006.2007.

Drilling Contracts

Our drilling contracts generally provide for compensation on either a daywork, turnkey or footage basis. Contract terms 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, during periods of high rig demand, we enter into more longer-term drilling contracts. In addition, we have entered into longer-term drilling contracts for our newly constructed rigs. As of FebruaryAugust 1, 2007, we had 3725 contracts with terms of six months to two years in duration, of which 1813 will expire by August 31, 2007, 11February 1, 2008, five have a remaining term of sixseven to 12 months, threefour have a remaining term of 1213 to 18 months and fivethree have a remaining term in excess of 18 months. We also have term contracts of two and three years for two rigs under construction at February 1, 2007.

Income Taxes

Pursuant to Statement of Financial Accounting Standards (“SFAS”) No. 109,Accounting “Accounting for Income Taxes,,” we follow the asset and liability method of accounting for income taxes, under which 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 basis. We measure our deferred tax assets and liabilities by using the 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, we reflect in income the effect of a change in tax rates on deferred tax assets and liabilities in the period during which the change occurs.

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Stock-based Compensation

We have stock option plans that are administered by the compensation committee of our Board of Directors, which selects persons eligible to receive awards and determines the number of stock options subject to each award and the terms, conditions and other provisions of the awards. Employee stock options generally become exercisable over three- to five-year periods, and generally expire 10 years after the date of grant. Stock options granted to outside directors vest immediately and expire five years after the date of grant. Our plans provide that all options must have an exercise price not less than the fair market value of our common stock on the date of grant.

Effective April 1, 2006, we adopted SFAS No. 123 (Revised),Share-Based Payment(“SFAS 123R”),utilizing the modified prospective approach. Prior to the adoption of SFAS 123R, we accounted for stock option grants in accordance with the intrinsic-value-based method prescribed by Accounting Principles Board Opinion No. 25,Accounting for Stock Issued to Employees(“APB 25”),and related interpretations, as permitted by SFAS No. 123,Accounting for Stock-Based Compensation(“SFAS 123”). Accordingly, we recognized no compensation expense for stock options granted, as all stock options were granted at an exercise price equal to the closing market value of the underlying common stock on the date of grant. Under the modified prospective approach, compensation cost for the ninethree months ended December 31, 2006June 30, 2007 includes compensation cost for all stock options granted prior to, but not yet vested as of, April 1, 2006, based on the grant-date fair value estimated in accordance with SFAS 123, and compensation cost for all stock options granted subsequent to April 1, 2006, based on the grant-date fair value estimated in accordance with SFAS 123R. We use the graded vesting method for recognizing compensation costs for stock options. Prior periods were not restated to reflect the impact of adopting this new standard.

As a result of adopting SFAS 123R on April 1, 2006, our income before income taxes, net earnings and basic and diluted earnings per common share for the nine months ended December 31, 2006, were $2,474,000, $1,608,000 and $.03 per share lower, respectively, than if we had continued to account for stock-based compensation under APB 25 for our stock option grants. Compensation costs of approximately $2,071,000$875,000 and $403,000$200,000 for stock options were recognized in general and administrative expense and contract drilling costs, respectively, for the ninethree months ended December 31, 2006.June 30, 2007. Approximately $260,000$261,000 of the compensation costs included in general and administrative expense relate to stock options granted to outside directors that vested immediately upon grant pursuant to our stock option plans. TheIn accordance with SFAS 123R, the entire compensation cost must behas been recognized for stock options that are fully vested at the grant date. We expect compensation costs relating to nonvested stock options to be approximately $590,000 for the remainder of fiscal year 2007.

We receive a tax deduction for certain stock option exercises during the period the options are exercised, generally for the excess of the price at which the options are sold over the exercise price of the options. Prior to adoption ofIn accordance with SFAS 123R, we reported all excess tax benefits resulting from the exercise of stock options as operatingfinancing cash flows in our condensed consolidated statement of cash flows. There were 12,50022,500 stock options exercised during the ninethree months ended December 31, 2006.June 30, 2007.

The following table illustrates the pro forma effect on operating results and per share information had we accounted for stock-based compensation in accordance with SFAS 123R for the three and nine months ended December 31, 2005:

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We estimate the fair value of each option grant on the date of grant using a Black-Scholes options-pricing model. The following table summarizes the assumptions used in the Black-Scholes option-pricing model for the ninethree months ended December 31, 2006June 30, 2007 and 2005. We did not grant any stock options during the three-month periods ended December 31, 2006 or 2005.2006:

The assumptions above are based on multiple factors, including historical exercise patterns of homogeneous groups with respect to exercise and post-vesting employment termination behaviors, expected future exercising patterns for these same homogeneous groups and volatility of our stock price. 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 options-pricing model.

At December 31, 2006, there was approximately $2,619,000 of unrecognized compensation cost relating to stock options which are expected to be recognized over a weighted-average period of 1.92 years.

The following table represents stock option activity for the nine months ended December 31, 2006:

Shares available for future stock option grants to employees and directors under existing plans were 1,157,833 at December 31, 2006. At December 31, 2006, the aggregate intrinsic value of stock options outstanding was approximately $9,106,000 and the aggregate intrinsic value of stock options exercisable was approximately $5,971,000. Intrinsic value is the difference between the exercise price of a stock option and the closing market price of our common stock, which was $13.28 on December 31, 2006.

The following table summarizes our nonvested stock option activity for the nine months ended December 31, 2006:

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Related-Party Transactions

We purchased services from R&B Answering Service and Frontier Services, Inc. during the three and nine months ended December 31, 2006June 30, 2007 and 2005. R&B Answering Service was more than 5% owned by our Chief Operating Officer until August 2006, when he sold his interest in that company.2006. Frontier Services, Inc. is more than 5% owned by an immediate family member of oura Vice President andof Operations Manager.of our company. The following summarizes the transactions with these companiesthis company in each period.

InFrom July 2005 to June 2007, we began leasingleased a portion of our corporate office space on a month-to-month basis to Wedge Oil and Gas Services Incorporated for $370 per month for one of its employees located in San Antonio. Wedge Oil and Gas Services Incorporated is an affiliate of WEDGE Group Incorporated. An officer of WEDGE Group Incorporated is a member of our Board of Directors.

Our Chief Executive Officer, Chief Operating Officer, Senior Vice President of Marketing, and a Vice President andof Operations Manager occasionally acquire a 1% to 5% minority working interest in oil and gas wells that we drill for one of our customers. These individuals acquired a minority working interest onin two wells that we drilled for this customer during the ninethree months ended December 31, 2006.June 30, 2007. We recognized contract drilling revenues of approximately $1,072,000$859,000 on these wells during the ninethree months ended December 31, 2006.June 30, 2007. These individuals did not acquire a minority working interestsinterest in any wells that we drilled for this customer during the ninethree months ended December 31, 2005.June 30, 2006.

Recently Issued Accounting Standards

In July 2006, the Financial Accounting Standards Board (the “FASB”) issued FASB Interpretation No. 48,Accounting for Uncertainty in Income Taxes -— An Interpretation of FASB Statement No. 109 (“FIN 48”). FIN 48 clarifies the accounting for uncertainty in income taxes recognized in a company’s financial statements in accordance with SFAS No. 109. FIN 48 also prescribes a recognition threshold and measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. The new FASB standard also provides guidance on derecognition, classification, interest and penalties, accounting in interim periods, disclosure and transition. We adopted the provisions of FIN 48 is effective for fiscal years beginning after December 15, 2006. We do not expect theApril 1, 2007. The adoption of FIN 48 to have ahad no material impact on our financial position or results of operations and financial condition.

In September 2006, the FASB issued SFAS No. 157,Fair Value Measurements. SFAS No. 157 defines fair value, establishes a framework for measuring fair value and expands disclosure of fair value measurements. SFAS No. 157 applies under other accounting pronouncements that require or permit fair value measurements and, accordingly, does not require any new fair value measurements. SFAS No. 157 is effective for financial statements issued for fiscal years beginning after November 15, 2007. We do not expect the adoption of SFAS No. 157 to have a material impact on our financial position or results of operations and financial condition.

In September 2006, the FASB issued Staff Position AUG AIR-1,Accounting for Planned Major Maintenance Activities, which eliminates the acceptability of the accrue-in-advance method of accounting for planned major maintenance activities. This FASB Staff Position is effective for fiscal years beginning after December 15, 2006. We do not use the accrue-in-advance method of accounting for rig refurbishments. We use a “built-in overhaul” method of accounting for rig refurbishments, whereby these expenditures are recognized as capital asset additions when incurred. The application of this FASB Staff Position will not have ahad no material impact on our financial position or results of operations and financial condition.

In September 2006, the U.S. Securities and Exchange Commission (the “SEC”)SEC released Staff Accounting Bulletin No. 108,Considering the Effects of Prior Year Misstatements When Quantifying Misstatements in Current Year Financial Statements, (“SAB 108”), which provides interpretive guidance on the SEC’s views regarding the process of

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quantifying materiality of financial statement misstatements. SAB 108 is effective for fiscal years ending after November 15, 2006, with early application for the first interim period ending after November 15, 2006. We do not expectSince we had no prior-year misstatements during the year ended March 31, 2007, the application of SAB 108 willdid not have a material effect on our financial position or results of operations and financial condition.

Reclassifications

Certain amounts in

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In February 2007, the FASB issued SFAS No. 159,The Fair Value Option for Financial Assets and Financial Liabilities — Including an amendment of FASB Statement No. 115. This statement permits entities to choose to measure many financial statementsinstruments and certain other items at fair value that are not currently required to be measured at fair value and establishes presentation and disclosure requirements designed to facilitate comparisons between entities that choose different measurement attributes for similar types of assets and liabilities. SFAS No. 159 is effective for fiscal years beginning after November 15, 2007. We do not expect the prior yearadoption of SFAS No. 159 to have been reclassified to conform to the current year’s presentation.a material impact on our financial position or results of operations and financial condition.

2. Long-term Debt and Notes Payable

We have a $20,000,000 credit facility with Frost National Bank, consisting of a $10,000,000 revolving line and letter of credit facility and a $10,000,000 acquisition facility for the acquisition of drilling rigs, drilling rig transportation equipment and associated equipment. Borrowings under the credit facility bear interest at a rate equal to Frost National Bank’s prime rate (8.25% at December 31, 2006)June 30, 2007) or, at our option, at LIBOR plus a percentage ranging from 1.5% to 2.25%, based on our operating leverage ratio. Borrowings are secured by most of our assets, including all our drilling rigs and associated equipment and receivables. At December 31, 2006,June 30, 2007, we had no borrowings under the acquisition facility and we had used approximately $4,267,000 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 availability under the revolving line and letter of credit facility is $5,733,000. Both the revolving line and letter of credit facility and acquisition facility are scheduled to mature in October 2008.

The sum of (1) the draws 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 credit facility is limited to 75% of our eligible accounts receivable, not to exceed $10,000,000. Therefore, if 75% of our eligible accounts receivable was less than $10,000,000, our ability to draw under this line would be reduced. At December 31, 2006,June 30, 2007, we had no outstanding advances under this line of credit, we had outstanding letters of credit of approximately $4,267,000 and 75% of our eligible accounts receivable was approximately $36,706,000.$34,372,000. The letters of credit have been issued to three 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.

At December 31, 2006,June 30, 2007, we were in compliance with all covenants contained in the credit agreement related to our credit facility. Those covenants include, among others, requirements that we maintain a debt to total capitalization ratio of not greater than 0.2 to 1, a fixed charged coverage ratio of not less than 1.5 to 1 and an operating leverage ratio of not more than 2.5 to 1. The covenants also restrict us from paying dividends, restrict us from the sale of assets not permitted by the credit facility and restrict us from the incurrence of additional indebtedness in excess of $3,000,000, to the extent not otherwise allowed by the credit facility.

3. Commitments and Contingencies

AsIn May 2007, we paid a deposit of December 31, 2006, we were constructing, from new and used components, two 1000-horsepower diesel electric rigs and one 1000-horsepower mechanical$4,565,000 towards the $9,130,000 purchase price of a 1500 horsepower rig at estimated costs ranging from $8,300,000 to $9,600,000 each. We placed onethat is currently under construction. Of the remaining $4,565,000 balance of those rigsour purchase commitment 50% was paid in operation in JanuaryJuly 2007 and expect the remaining two rigs to50% will be completed and become available for operation in February and March 2007. As of December 31, 2006, we had incurred approximately $16,593,000paid upon delivery of the approximately $26,295,000 of estimated construction costsrig in August 2007.

In connection with our expansion into international markets, we have obtained bonds for bidding on the three rigsdrilling contracts, performing under construction. During the quarter ended September 30, 2006, we canceled the construction of one new rig we had previously planned to build.

drilling contracts, and remitting customs and importation duties. We have purchase obligations for rig equipment consisting of 70 iron roughnecks and power slips to improve the efficiency and safety of our rig fleet and three topdrives. The iron roughnecks and power slips will be delivered over the 24-month period beginning January 2007, at a total costguaranteed payments of approximately $18,300,000, plus installation costs of approximately $3,000,000. Two topdrives at a total cost of approximately $3,300,000 are$8,300,000 relating to our performance relating to these bonds.

In addition, due for delivery in February 2007. A third topdrive at a cost of approximately $1,650,000 is due for delivery in July 2007.

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. Legal costs relating to these matters are expensed as incurred. In the opinion of our management, none of suchthe 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.operations and there is only a remote possibility that any such matter will require any additional loss accrual.

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4. Earnings Per Common Share

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

5. Equity Transactions

On February 10, 2006, we sold 3,000,000 shares of our common stock, at approximately $20.63 per share, net of underwriters’ commissions, in a public offering we registered with the SEC.

Employees exercised stock options for the purchase of 12,50022,500 shares of common stock during the ninethree months ended December 31, 2006June 30, 2007 at prices ranging from $4.52 to $4.77 per share. Directors and employees exercisedThere were no stock options for the purchase of 658,667 shares of common stockexercised during the ninethree months ended December 31, 2005, at prices ranging from $3.00 to $8.81 per share.June 30, 2006.

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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 that 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. We have discussed many of these factors in more detail elsewhere in this report and in our annual report on Form 10-K for the fiscal year ended March 31, 2006.2007. These factors are not necessarily all the important factors that could affect us. Unpredictable or unknown factors we have not discussed in this report or in our annual report on Form 10K could also have material adverse effects on actual results of matters that are the subject of our forward-looking statements. We do not intend to update our description of important factors each time a potential important factor arises, except as required by applicable securities laws and regulations. We advise our shareholders that they should (1) be aware that important factors not referred to above could affect the accuracy of our forward-looking statements and (2) use caution and common sense when considering our forward-looking statements.

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 and forecasted future price of oil and natural gas. During the quarter ended December 31,Since November 2006, we beganhave been experiencing a decline in the demand for drilling rigs and have experienced a decline in revenue rates on some contract renewals. Ifrenewals due to an excess supply of drilling rigs within the recentindustry, which is due to the substantial addition of new and refurbished drilling rigs during the past year. Any continued weakness in oil and natural gas prices continues through the winter months, we could see a continued slowdown indemand for additional drilling activity by oil and gas exploration companies. Any continued slowdown in drilling activity wouldrigs will likely result in lower revenue rates for our rigs as currentexisting contracts expire.expire and more drilling rigs are added to the market.

Our business strategy is to own and operate a high-quality fleet of land drilling rigs in active drilling markets, and to 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 new or refurbished drilling rigs, as attractive opportunities arise. We may explore acquiring businesses in other sectors within the oilfield services industry. In addition, we are evaluating opportunities for expansion into international markets beginning with Colombia. We will commence operations in Colombia with a contract for one drilling rig in August 2007 and we are negotiating a contract for a second drilling rig that would begin in September 2007. Our immediate international business strategy is to continue our expansion in Colombia to include at least three drilling rigs by fiscal year end.

Since September 1999, we have significantly expanded our fleet of drilling rigs through acquisitions and the construction of new and refurbished rigs. As of FebruaryAugust 1, 2007, our rig fleet consisted of 64 land66 operating drilling rigs, of which 2425 are premium electric rigs that drill in depth ranges between 6,000 and 18,000 feet. Seventeen of our rigs are operating in our South Texas division, 1820 in our East Texas division, ten in our North Texas division, sevensix in our western Oklahoma division and 1213 in our Rocky Mountains divisions in Utah and North Dakota. We actively market all of these rigs. As of February 1,In addition, at June 30, 2007, we were constructing one 1000-horsepower diesel electricupgrading, with top drives and other components, a 1500 horsepower rig acquired in April 2007 and one 1000-horsepower mechanical rig.a 1500 horsepower rig acquired in May 2007. We expect thesealso agreed to acquire another 1500 horsepower rig in May 2007 that is currently under construction. These three rigs to be completedare ideally suited for our expansion into international markets and to become available for operationare not included in February and March 2007.our 66 operating rig count.

We earn our revenues by drilling oil and gas wells for our customers, as our rigs can be used by our customers to drill for either oil or natural gas. 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 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. Historically, our contracts provide for the drilling of a single well and typically permit the customer to terminate on short notice. However,As demand for drilling

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rigs improved during periods of high rig demand,the past two years, we enterentered into more longer-term drilling contracts. In addition, we have entered into longer-term drilling contracts for our newly constructed rigs. As of FebruaryAugust 1, 2007, we had 3725 contracts with terms of six months to two years in duration, of which 1813 will expire by August 31, 2007, 11February 1, 2008, five have a remaining term of sixseven to 12 months, threefour have a remaining term of 1213 to 18 months and fivethree have a remaining term in excess of 18 months. We also have term contracts of two and three years for two rigs under construction at February 1, 2007.

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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. For each period presented below, all of our rigs were capable of working and are included in our rig utilization calculations.

For the three and nine months ended December 31,June 30, 2007 and 2006 and 2005, our rig utilization, and revenue days and number of operating drilling rigs were as follows:

The primary reason for the increase in the number of revenue days in 2007 over 2006 over 2005 wasis the increase in size of our rig fleet from 54fleet. Due to the current excess supply of drilling rigs at December 31, 2005available for work, we currently expect a 5% to 63 rigs at December 31, 2006. For the remainder of fiscal year 2007, we anticipate continued growth10% decrease in revenue days as we continue to construct more rigs and put them into operation. We expect utilization rates for the remainder of fiscal year 2007 and2008 as compared to fiscal year 2008 to decline modestly due to new rigs entering the market and weakness in oil and gas prices.2007.

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 during periods of reduced demand for drilling rigs.

We devote substantial resources to maintaining and upgrading our rig fleet. In the short term, these actions result 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 are currently performing, between contracts or as necessary, safetyUpgrades for the fiscal year ending March 31, 2008 will primarily focus on: replacing older engines with more modern, efficient engines; upgrading to higher horsepower mud pumps; upgrading to modern mud cleaning systems on some of our drilling rigs; and equipment upgradesadding iron roughnecks to the eight rigs we acquired in March 2004 and the 12 rigs we acquired in November and December 2004. During the nine months ended December 31, 2006, we expended approximately $14,608,000 upgrading 15 rigs, using over 391 potential revenue days in the upgrade process.38 of our drilling rigs.

Market Conditions in Our Industry

The U.S. 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.

In addition, the availability of drilling rigs capable of working affects our revenue rates and utilization rates. For much of the past two years, our industry experienced a shortage of drilling rigs leading to revenue rates and utilization rates that were at historically high levels. However, our industry is currently experiencing an excess drilling rig supply due to new construction and refurbishments. This condition may correct itself over time if older drilling rigs are retired and if the outlook for oil and gas pricing improves and results in an increase in drilling activity.

On January 19,July 20, 2007, the spot price for West Texas Intermediate crude oil was $51.99,$75.57, the spot price for Henry Hub natural gas was $6.40$6.45 and the Baker Hughes land rig count was 1,638,1,685, a 19%7% increase from 1,3761,571 on January 20,July 21, 2006. Since SeptemberJanuary 1, 20062007, the Baker Hughes land rig count has been between 1,5861,588 and 1,641.1,704.

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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 three monthsquarter ended December 31, 2006June 30, 2007 and each of the previous five years ended December 31,June 30, 2007 were:

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Most of our customers drill in search of natural gas; however, we currently operate fourfive rigs in the Williston Basin of the Rocky Mountains, where our customers drill in search of oil.

Critical Accounting Policies and Estimates

Revenue and cost recognition– We earn our revenues by drilling oil and gas wells for our customers under daywork, turnkey or footage contracts, which usually provide for the drilling of a single well. We recognize revenues on daywork contracts for the days completed based on the dayrate each contract specifies. We recognize revenues from our turnkey and footage contracts on the percentage-of-completion method based on our estimate of the number of days to complete each contract. Contract drilling in progress represents revenues we have recognized in excess of amounts billed on contracts in progress. Individual contracts are usually completed in less than 60 days. The risks to us under a turnkey contract and, to a lesser extent, under footage contracts, are substantially greater than on a contract drilled on a daywork basis. Under a turnkey contract, we assume most of the risks associated with drilling operations that are 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, as defined in the American Institute of Certified Public Accountants’ Statement of Position 81-1, to recognize revenue on our turnkey and footage contracts. Although our turnkey and footage contracts do not have express terms that provide us with rights to receive payment for the work that we perform prior to drilling wells to the agreed-on depth, we use this method because, as provided in applicable accounting literature, we believe we achieve a continuous sale for our work-in-progress and believe, under applicable state law, we ultimately could recover the fair value of our work-in-progress even in the event we were unable to drill to the agreed-on depth in breach of the applicable contract. However, in the event we were unable to drill to the agreed-on depth in breach of the contract, ultimate recovery of that value would be subject to negotiations with the customer and the possibility of litigation.

If a customer defaults on its payment obligation to us under a turnkey or footage contract, we would need to rely on applicable law to enforce our lien rights, because our turnkey and footage contracts do not expressly grant to us a security interest in the work we have completed under the contract and we have no ownership rights in the work-in-progress or completed drilling work, except any rights arising under the applicable lien statute on foreclosure. If we were unable to drill to the agreed-on depth in breach of the contract, we also would need to rely on equitable remedies outside of the contract, includingquantum meruit,, available in applicable courts to recover the fair value of our work-in-progress under a turnkey or footage contract.

We accrue estimated contract costs on turnkey and footage contracts for each day of work completed based on our estimate of the total costs to complete the contract divided by our estimate of the number of days to complete the contract. Contract costs include labor, materials, supplies, repairs and maintenance, operating overhead allocations and allocations of depreciation and amortization expense. In addition, the occurrence of uninsured or under-insured losses or operating cost overruns on our turnkey and footage contracts could have a material adverse effect on our financial position and results of operations.Therefore,operations. Therefore, our actual results for a contract could differ significantly if our cost estimates for that contract are later revised from our original cost estimates for a contract in progress at the end of a reporting period which was 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

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specifically, among other things, we consider our contract revenue rates, our rig utilization rates, cash flows from our drilling rigs, current oil and gas prices and 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 net 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, 2006,June 30, 2007, would have resulted in a corresponding decrease in our net earnings of approximately $2,762,000$3,177,000 for the ninethree months ended December 31, 2006.June 30, 2007.

Deferred taxes– We provide deferred taxes for the basis differences in our property and equipment between financial reporting and tax reporting purposes and other costs such as compensation, employee benefit and other accrued liabilities which are deducted in different periods for 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 five to 15 years and refurbishments over three to five years, while federal income tax rules

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

We receive payment under turnkey and footage contracts when we deliver to our customer a well completed to the depth specified in the contract, unless the customer authorizes us to drill to a shallower depth. Since 1995, when current management joined our company, we have completed all our turnkey or footage contracts. Although our initial cost estimates for turnkey and footage contracts do not include cost estimates for risks such as stuck drill pipe or loss of circulation, we believe that our experienced management team, our knowledge of geologic formations in our areas of operations, the condition of our drilling equipment and our experienced crews enable us to make reasonably dependable cost estimates and complete contracts according to our drilling plan. While we do bear the risk of loss for cost overruns and other events that are not specifically provided for in our initial cost estimates, our pricing of turnkey and footage contracts takes such risks into consideration. When we encounter, during the course of our drilling operations, conditions unforeseen in the preparation of our original cost estimate, we increase our cost estimate to complete the contract. 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 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 monthsquarter ended December 31, 2006, we experienced losses of less than $25,000 each on six of the 44 turnkey and footage contracts completed. During the nine months ended December 31, 2005,June 30, 2007, we experienced losses on 17three of the 11118 turnkey and footage contracts completed, with losses of less thanexceeding $25,000 each on 14two contracts. During the quarter ended June 30, 2006, we experienced losses on two of the 15 turnkey and footage contracts completed, and those losses exceeding $25,000 butwere each less than $100,000 on two contracts, and a loss exceeding $100,000 on one contract.$25,000. We are more likely to encounter losses on turnkey and footage contracts in periods 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. We had no turnkey contracts and twoone footage contractscontract in progress at December 31, 2006,June 30, 2007, which werewas completed prior to the release of the financial statements included in this report. Our contract drilling in progress totaled approximately $14,006,000$10,615,000 at December 31, 2006.June 30, 2007. Of that amount accrued, footage contract revenues were approximately $584,000.$593,000. The remaining balance of approximately $13,422,000$10,022,000 related to the revenue recognized but not yet billed on daywork contracts in progress at December 31, 2006.June 30, 2007. At March 31, 2006,2007, drilling in progress totaled $9,620,000,$9,837,000, of which $599,000$329,000 related to footage contracts and $9,021,000$9,508,000 related to daywork contracts.

We estimate an allowance for doubtful accounts based on the creditworthiness of our customers as well as general economic conditions. We evaluate the creditworthiness of our customers based on information obtained from major industry suppliers, current prices of oil and gas and any past experience we have with the customer. Consequently, an adverse change in those factors could affect our estimate of our allowance for doubtful accounts. In some instances, we require new customers to establish escrow accounts or make prepayments. We typically invoice our customers at 15-day intervals during the performance of daywork contracts and upon completion of the daywork contract. Turnkey and footage contracts are invoiced upon completion of the contract. Our typical contract provides for payment of invoices in 10 to 30 days. We generally do not

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extend payment terms beyond 30 days and have not extended payment terms beyond 6090 days for any of our contracts in the last three fiscal years. We had an allowance for doubtful accounts of $1,000,000 and $200,000 at December 31, 2006June 30, 2007 and March 31, 2006, respectively.2007.

Another critical estimate is our determination of the useful lives of our depreciable assets, which directly affects our determination of depreciation expense and deferred taxes. A decrease in the useful life of our drilling equipment would increase depreciation expense and reduce deferred taxes. We provide for depreciation of our drilling, transportation and other equipment on a straight-line method over useful lives that we have estimated and that range from three to 15 years. We record the same depreciation expense whether a rig is idle or working. Our estimates of the useful lives of our drilling, transportation and other equipment are based on our more than 35 years of experience in the drilling industry with similar equipment.

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Our other accrued expensesinsurance premiums and deductibles as of December 31, 2006June 30, 2007 include accruals of approximately $608,000$621,000 and $2,947,000$5,518,000 for costs incurred under the self-insurance portion of our health insurance and under our workers’ compensation insurance, respectively. We have a deductible of (1) $125,000 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 we do not have a deductible. We accrue for these costs as claims are incurred based on historical claim development data, and we accrue the costs of administrative services associated with claims processing. We also evaluate our claim cost estimates based on estimates provided by the insurance companies that provide claims processing services.

Liquidity and Capital Resources

Sources of Capital Resources

Our rig fleet has grown from eight rigs in August 2000 to 6466 operating rigs as of FebruaryAugust 1, 2007. We have financed this growth with a combination of debt and equity financing. We have raised additional equity or used equity for growth nine times since January 2000. We plan to continue to grow our rig fleet. Over the remainder of fiscal year 2007, we expect to finance the construction of two additional rigs from existing cashfleet and cash flows from operations. However, we may pursue other business opportunities that are complementary to our U.S. contract land drilling business. We may finance otherthese growth opportunities through the issuance of debt and the issuance of additional shares of our common stock.

On February 10, 2006, we sold 3,000,000 shares of our common stock, at approximately $20.63 per share, net of underwriters’ commissions, in a public offering we registered with the U.S. Securities and Exchange Commission (the “SEC”).

We have a $20,000,000 credit facility with Frost National Bank consisting of a $10,000,000 revolving line and letter of credit facility and a $10,000,000 acquisition facility for the acquisition of drilling rigs, drilling rig transportation equipment and associated equipment. Borrowings under the credit facility bear interest at a rate equal to Frost National Bank’s prime rate (8.25% at December 31, 2006)June 30, 2007) or, at our option, at LIBOR plus a percentage ranging from 1.5% to 2.25%, based on our operating leverage ratio. Borrowings are secured by most of our assets, including all our drilling rigs and associated equipment and receivables. At December 31, 2006,June 30, 2007, we had no borrowings under the acquisition facility and we had used approximately $4,267,000 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 availability under the revolving line and letter of credit facility is $5,733,000. Both the revolving line and letter of credit facility and acquisition facility are scheduled to mature in October 2008.

Uses of Capital Resources

For the three and nine months ended December 31, 2006,June 30, 2007, the additions to our property and equipment consisted of the following:

Property and equipment additions for the three months ended June 30, 2007 include approximately $1,257,000 of purchases recorded in accounts payable at March 31, 2007.

As of DecemberMarch 31, 2006,2007, we were constructing from new and used components, two 1000-horsepower diesel electric rigs and one 1000-horsepower mechanical rig at estimated costs ranging from $8,300,000 to $9,600,000 each.rig. We placed onethis rig into service in operation in JanuaryApril 2007 and expect the remaining two rigs to be completed and become available for operation in February and March 2007. As of December 31, 2006, we had incurred approximately $16,593,000 of the approximately $26,295,000 of estimated$2,124,000 for construction costs onduring the three months ended June 30, 2007 for this rig. In addition, we incurred approximately $33,047,000 during the three months ended June 30, 2007 to purchase and upgrade the three drilling rigs under construction. Duringwe intend to use for expansion into international markets. We expect to incur an additional $26,000,000 on acquisition and upgrade costs for these three drilling rigs during the quarter ended September 30, 2006, we canceled the constructionremainder of one new rig we had previously planned to build.fiscal year 2008.

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For the remainder of fiscal year 2007,2008, we project regular rig capital expenditures (excluding constructionthe new rig acquisition and upgrade costs to completefor the construction of thethree drilling rigs referred tonoted above) to be approximately $14,300,000,$61,500,000, comprised of routine rig capital expenditures of approximately $28,500,000, rig upgrade expenditures to beof approximately $9,600,000,$27,300,000, spare equipment expenditures of approximately $1,300,000, transportation equipment capital expenditures to beof approximately $5,400,000$3,300,000, and other capital expenditures of approximately $1,100,000. We expect to be approximately $200,000. Thesefund these capital expenditures are expected to be funded primarily from operating cash flow in excess of our working capital and other normal cash flow necessary to meet routine financial obligations.requirements.

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Working Capital

Our working capital was $112,871,827$106,162,169 at December 31, 2006,June 30, 2007, compared to $106,904,106$124,088,849 at March 31, 2006.2007. Our current ratio, which we calculate by dividing our current assets by our current liabilities, was 4.03.5 at December 31, 2006,June 30, 2007, compared to 4.34.6 at March 31, 2006.2007.

Our operations have historically generated cash flows sufficient to at least meet our requirements for debt service and normal capital expenditures. However, during periods when higher percentages of our contracts are turnkey and footage contracts, our short-term working capital needs could increase. If necessary, we can defer rig upgrades to improve our cash position. The significant improvement in operating cash flow for the nine months ended December 31, 2006 over December 31, 2005 is due primarily to the approximately $34,362,000 improvement in net earnings, plus the increase of approximately $14,252,000 in depreciation and amortization expense. We believe our cash generated by operations and our ability to borrow under the currently unused portion of our line of credit and letter of credit facility should allow us to meet our routine financial obligations for the foreseeable future.

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

The increasedecrease in cash and cash equivalents was primarily due to property and equipment expenditures of approximately $50,649,000 during the three months ended June 30, 2007.

The decrease in our receivables and contract drilling in progress at December 31, 2006June 30, 2007 from March 31, 20062007 was due to our operating seven additional rigs and the increasedecrease of approximately $2,554$784 per day in average revenue rates.rates, partially offset by our operating one additional rig.

The decrease in our income tax receivable is due to the collection of an income tax refund that resulted from an excess tax deposit for our fiscal year ended March 31, 2007.

Substantially all our prepaid expenses at December 31, 2006June 30, 2007 and March 31, 20062007 consisted of prepaid insurance. We renew and pay most of our insurance premiums in late October of each year and some in April of each year. At March 31, 2006,June 30, 2007, we had amortized fiveeight months of the October premiums, compared to twofive months of amortization as of DecemberMarch 31, 2006. In addition, insurance premiums have increased in the current year as a result of our growth.2007.

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The increase in accounts payable at June 30, 2007 from March 31, 2007 was primarily due to our operating seven additional rigstiming of property and the increase of approximately $1,164 per day in average drilling costs.equipment purchases.

The increasedecrease in accrued expenses at December 31, 2006,June 30, 2007, compared to March 31, 2006,2007, was primarily due to increasesfewer days of accrued payroll, partially offset by an increase in the accruals for property taxes and self-insurance costs.

The decreaseincrease in income tax payable at DecemberJune 30, 2007 from March 31, 20062007 primarily related to the timing of quarterly income tax payments which was partially offset by the increase in current taxable income as a percentage of income before taxes. Also, income taxes payable for the year ended March 31, 2006 were decreased when we fully utilized net operating loss carryforwards.payments.

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Long-term Debt

We had no long-term debt outstanding at December 31, 2006.June 30, 2007. See “- Sources of Capital Resources” for a description of our credit facility.

Contractual Obligations

We have purchase obligations for rig equipment consisting of 70 iron roughnecks and power slips and three topdrives at a cost of approximately $21,300,000 and $4,950,000, respectively. We do not have other routine purchase obligations. However, as of December 31, 2006, we were in the process of constructing three drilling rigs, as described above. The following table includes all our contractual obligations of the types specified below at December 31, 2006.June 30, 2007.

Debt Requirements

The sum of (1) the draws 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 credit facility is limited to 75% of our eligible accounts receivable, not to exceed $10,000,000. Therefore, if 75% of our eligible accounts receivable was less than $10,000,000, our ability to draw under this line would be reduced. At December 31, 2006,June 30, 2007, we had no outstanding advances under this line of credit, we had outstanding letters of credit of approximately $4,267,000 and 75% of our eligible accounts receivable was approximately $36,706,000.$34,372,000. The letters of credit have been issued to three 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.

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 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:

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

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Results of Operations

Our operations consist of drilling oil and gas wells for our customers under daywork, turnkey or footage contracts usually on a well-to-well basis. Daywork contracts are the least complex 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. During the mobilization period, we typically earn a fixed amount of revenue based on the mobilization rate stated in the contract. We attempt to set the mobilization rate at an amount equal to our external costs for the move plus our internal costs during the mobilization period. We begin earning our contracted daywork rate when we begin drilling the well. Occasionally, in periods of increased demand, 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.

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 under a turnkey contract we assume most of the risks associated with drilling operations that the operator generally assumes under a daywork contract.

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

During periods of reduced demand for drilling rigs or excess capacity of drilling rigs in the industry, revenue rates and utilization rates may be significantly lower than current revenuethe rates and we may incur net losses primarily due to significant depreciation costs associated with our drilling equipment.are currently experiencing. Our profitability in the future will depend on many factors, but largely on utilization rates and revenue rates for our drilling rigs. We incurred net losses of approximately $1,800,000, $5,100,000 and $400,000 in the fiscal years ended March 31, 2004, 2003 and 2000, respectively.

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

For the three and nine months ended December 31,June 30, 2007 and 2006, and 2005, the percentages of our drilling revenues by type of contract were as follows:

We had no turnkey contracts in progress at December 31, 2006June 30, 2007 or December 31, 2005.June 30, 2006. We had twoone footage contractscontract in progress at December 31, 2006both June 30, 2007 and three footage contracts in progress at December 31, 2005.June 30, 2006.

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Statement of Operations Analysis

The following table provides information for our operations for the three and nine months ended December 31, 2006June 30, 2007 and 2005.2006.

We present drilling margin information, defined as contract drilling revenues less contract drilling costs, because we believe it provides investors and our management additional information to assist them in assessing our business and performance in comparison to other companies in our industry. Since drilling margin is a “non-GAAP” financial measure under the rules and regulations of the SEC, we have included below a reconciliation of drilling margin to net earnings, which is the nearest comparable GAAP financial measure.

Our contract drilling revenues grew by approximately $37,963,000,$9,286,000, or 51%10%, in the quarter ended December 31, 2006June 30, 2007 from the quarter ended December 31, 2005,June 30, 2006, due to an improvement of $4,381 per day, or 28%, in average rig revenue rates

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resulting from an increase in demand for drilling rigs, an 18%a 10% increase in revenue days due tothat resulted from an increase in the number of rigs in our fleet, and a 2% increase in rig utilization. Our contract drilling revenues grew by approximately $111,523,000, or 55%, for the nine months ended December 31, 2006 from the nine months ended December 31, 2005, due to an improvement of $4,938 per day, or 33%, in average rig revenue rates resulting from an increase in demand for drilling rigs, a 17% increase in revenue days due to an increase in the number of rigs in our fleet, and a 2% increase in rig utilization.fleet.

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Our contract drilling costs grew by approximately $15,723,000,$14,249,000, or 37%29%, in the quarter ended December 31, 2006June 30, 2007 from the corresponding quarter of 2005, primarilyin 2006 due to the increase in the number of revenue days resulting from theand a $1,692 increase in the number of rigs in our fleet and the increase in rig utilization. Our contractaverage drilling costs per revenue day, increased by $1,419, or 16%, in the quarter ended December 31, 2006 from the corresponding quarter in 2005,which was primarily due to higher wages, and higher repairs and maintenance expenses. The overall increase in contract drilling costs was partially offset by decreases in contract drilling costs due to a shift toexpenses and more daywork revenue days as a percentage of total revenue days. Daywork days represented 95% of revenue days in the quarter ended December 31, 2006, compared to 91% in the quarter ended December 31, 2005.turnkey and footage costs. Under turnkey and footage contracts, we provide supplies and materials such as fuel, drill bits, casing and drilling fluids, which significantly add to drilling costs when compared to daywork 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.

Our contract drilling costs grew by approximately $41,779,000, or 34%, during the nine months ended December 31, 2006 from the corresponding period in 2005, primarily due to the increase in the number of revenue days resulting from the increase in the number of rigs in our fleet. Our contract drilling costs per revenue day increased by $1,349, or 15%, during the nine months ended December 31, 2006 from the corresponding period in 2005, primarily due to higher wages and higher repairs and maintenance expenses. The overall increase in contract drilling costs was partially offset by decreases in contract drilling costs due to a shift to more daywork revenue days as a percentage of total revenue days. Daywork days represented 96% of revenue days during the nine months ended December 31, 2006, compared to 86% during the nine months ended December 31, 2005.

Our depreciation and amortization expenses for the quarter ended December 31, 2006June 30, 2007 increased by approximately $5,371,000,$4,528,000, or 62%39%, compared to the corresponding quarter in 2005. Our depreciation and amortization expenses for the nine months ended December 31,2006. The increase in 2007 over 2006 increased by approximately $14,252,000, or 60%, compared to the corresponding period in 2005. These increases in 2006 over 2005 resulted primarily from an increase in the average size of our rig fleet, which increasesincrease consisted entirely of newly constructed rigs. The higher costs of our new rigs increased our average depreciation costs per revenue day by $683$618 to $2,507 from $1,824$2,988 in the quarter ended December 31, 2006, compared toJune 30, 2007 from $2,370 in the corresponding quarter in 2005, and by $651 to $2,424 from $1,773 during the nine months ended December 31, 2006, compared to the corresponding period in 2005.June 30, 2006.

Our general and administrative expense for the quarter ended December 31, 2006June 30, 2007 increased by approximately $1,106,000,$395,000, or 68%13%, compared to the corresponding quarter in 2005.2006. The increase resulted primarily from compensation expense recognized for stock options and increases in payroll costs, bonus accruals, rent expenses, insurance expensesprofessional and director fees. Effective April 1, 2006, we adopted SFAS No. 123 (Revised),Share-Based Payment,and recognized approximately $584,000 of compensation expense for stock options in general and administrative expense for the quarter ended December 31, 2006. Also during the quarter ended December 31, 2006, payroll costs and bonus accrual costs increased by approximately $435,000, due to pay raises and an increase in the number of employees in our corporate offices, as compared to the quarter ended December 31, 2005. Insurance expenses, rent expenses and travel expenses increased by approximately $61,000 in the aggregate.consulting costs. We expect compensation costs for stock options to be approximately $590,000$2,665,000 for the remainder of fiscal year 2007,2008, of which approximately $446,000$1,967,000 will be recognized as general and administrative expense.

Our general and administrative expense for the nine months ended December 31, 2006 increased by approximately $3,676,000, or 76%, compared to the corresponding period in 2005. The increase resulted primarily from compensation expense recognized for stock options and increases in payroll costs, bonus accruals, travel expenses, rent expenses, insurance expenses and director fees. We recognized approximately $2,071,000 of compensation expense for stock options in general and administrative expense for the nine months ended December 31, 2006. Also during the nine months ended December 31, 2006, payroll costs and bonus accrual costs increased by approximately $1,161,000, due to pay raises and an increase in the number of employees in our corporate offices, as compared to the nine months ended December 31, 2005. Director fees, insurance expenses, rent expenses and travel expenses increased by approximately $398,000 in the aggregate.

Our other income for the quarter ended December 31, 2006 increasedJune 30, 2007 decreased by approximately $434,000,$177,000, or 107%17%, compared to the corresponding quarter in 2005. Our other income for the nine months ended December 31, 2006 increased by approximately $1,739,000, or 147%, compared to the corresponding period in 2005.2006. The increasedecrease was primarily due to

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increased decreased interest income that resulted from increaseddecreased cash and cash equivalents and marketable security balances. Cash and cash equivalents increaseddecreased from $32,579,272$93,493,000 at December 31, 2005June 30, 2006 to $74,754,205$79,884,000 at December 31, 2006.June 30, 2007.

Our effective income tax ratesrate of 35.3% and 35.8%36% for the threequarters ended June 30, 2007 and nine months ended December 31, 2006 respectively, and 36.3% and 36.7% for the three and nine months ended December 31, 2005, respectively, differdiffers from the federal statutory rate of 35%, due to permanent differences and state income taxes. Permanent differences are costs included in results of operations in the accompanying financial statements which are not fully deductible for federal income tax purposes. During the quarter ended June 30, 2006, we recognized a nonrecurring increase in income tax expense and deferred income taxes of approximately $362,000, due to the effects of changes in Texas franchise taxes on the future reversals of temporary differences. The Texas franchise tax changes became effective June 1, 2006. We estimate our effective tax rate for fiscal year 2007 to be approximately 35.8%.

Inflation

Due to the increased rig count in each of our market areas, availability of personnel to operate our rigs is limited. In April 2005, January 2006 and May 2006, we raised wage rates for our rig personnel by an average of 6%, 6% and 14%, respectively. We were able to pass these wage rate increases on to our customers based on contract terms. Availability of personnel in each of our market areas should improve if we continue experiencing a decline in the demand for drilling rigs. Therefore, it isWe currently do not likely that we will experienceanticipate additional wage rate increases until we have increased demand for drilling rigs.in fiscal year 2008.

We are experiencing increases in costs for rig repairs and maintenance and costs of rig upgrades and new rig construction, due to the increased industry-wide demand. We estimate these costs increased between 10% and 15% in fiscal year 2007, and we expectmay experience similar cost increases in fiscal year 2008.2008 if the rig count continues to increase. We may not be able to recover these cost increases through improvements in our daywork revenue rates.

Off Balance Sheet Arrangements

We do not currently have any off balance sheet arrangements.

Recently Issued Accounting Standards

Effective April 1, 2006, we adopted SFAS No. 123 (Revised),Share-Based Payment,utilizing the modified prospective approach. See the “Stock-based Compensation” section of Note 1 to the condensed consolidated financial statements included in this report for additional information.

In July 2006, the Financial Accounting Standards Board (the “FASB”) issued FASB Interpretation No. 48,Accounting for Uncertainty in Income Taxes -— An Interpretation of FASB Statement No. 109 (“FIN 48”). FIN 48 clarifies the accounting for uncertainty in income taxes recognized in a company’s financial statements in accordance with SFAS No. 109. FIN 48 also prescribes a recognition threshold and measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. The new FASB standard also provides guidance on derecognition, classification, interest and penalties, accounting in interim periods, disclosure and transition. We adopted the provisions of FIN 48 is effective for fiscal years beginning after December 15, 2006. We do not expect theApril 1, 2007. The adoption of FIN 48 to have ahad no material impact on our financial position or results of operations and financial condition.

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In September 2006, the FASB issued SFAS No. 157,Fair Value Measurements. SFAS No. 157 defines fair value, establishes a framework for measuring fair value and expands disclosure of fair value measurements. SFAS No. 157 applies under other accounting pronouncements that require or permit fair value measurements and, accordingly, does not require any new fair value measurements. SFAS No. 157 is effective for financial statements issued for fiscal years beginning after November 15, 2007. We do not expect the adoption of SFAS No. 157 to have a material impact on our financial position or results of operations and financial condition.

In September 2006, the FASB issued Staff Position AUG AIR-1,Accounting for Planned Major Maintenance Activities, which eliminates the acceptability of the accrue-in-advance method of accounting for planned major maintenance activities. This FASB Staff Position is effective for fiscal years beginning after December 15, 2006. We do not use the accrue-in-advance method of accounting for rig refurbishments. We use a “built-in overhaul” method of accounting for rig refurbishments, whereby these expenditures are recognized as capital asset additions when incurred. The application of this FASB Staff Position will not have ahad no material impact on our financial position or results of operations and financial condition.

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In September 2006, the SEC released Staff Accounting Bulletin No. 108,Considering the Effects of Prior Year Misstatements When Quantifying Misstatements in Current Year Financial Statements, (“SAB 108”), which provides interpretive guidance on the SEC’s views regarding the process of quantifying materiality of financial statement misstatements. SAB 108 is effective for fiscal years ending after November 15, 2006, with early application for the first interim period ending after November 15, 2006. We do not expectSince we had no prior-year misstatements during the year ended March 31, 2007, the application of SAB 108 willdid not have a material effect on our financial position or results of operations and financial condition.

In February 2007, the FASB issued SFAS No. 159,The Fair Value Option for Financial Assets and Financial Liabilities — Including an amendment of FASB Statement No. 115. This statement permits entities to choose to measure many financial instruments and certain other items at fair value that are not currently required to be measured at fair value and establishes presentation and disclosure requirements designed to facilitate comparisons between entities that choose different measurement attributes for similar types of assets and liabilities. SFAS No. 159 is effective for fiscal years beginning after November 15, 2007. We do not expect the adoption of SFAS No. 159 to have a material impact on our financial position or results of operations and financial condition.

ITEM 3.QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Our exposure to market risk from changes in interest rates primarily relates to our cash equivalents, and marketable securities, which consist of investments in highly liquid debt instruments denominated in U.S. dollars. We are averse to principal loss and ensure the safety and preservation of our invested funds by limiting default risk, market risk and reinvestment risk.

We are subject to market risk exposure related to changes in interest rates on our outstanding floating rate debt.debt we may incur under our credit facility. However, at December 31, 2006June 30, 2007, we had no outstanding debt subject to variable interest rates.borrowings under our credit facility.

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, 2006June 30, 2007 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 nine months ended December 31, 2006June 30, 2007 which has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

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PART II. OTHER INFORMATION

The following should be considered by investors in our securities, in addition to the risk factors we included under the heading “Risk Factors” in Item 1 of our annual report on Form 10-K for the year ended March 31, 2007:

As we expand into international markets, our international operations will be subject to political, economic and other uncertainties not encountered in our domestic operations.

As we continue to implement our strategy of expanding into areas outside the United States, our international operations will be subject to political, economic and other uncertainties not generally encountered in our U.S. operations. These will include:

Our international operations may also face the additional risks of fluctuating currency values, hard currency shortages and controls of foreign currency exchange. Additionally, in some jurisdictions, we may be subject to foreign governmental regulations favoring or requiring the awarding of contracts to local contractors or requiring foreign contractors to employ citizens of, or purchase supplies from, a particular jurisdiction. These regulations could adversely affect our ability to compete.

ITEM 6.EXHIBITS

The following exhibits are filed as part of this report or incorporated by reference herein:

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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: February 1,August 2, 2007

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Index to Exhibits