UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

ý		QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15 (d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended June 30, 2005

OR

o		TRANSITION REPORT PURSUANT TO SECTION 13 OR 15 (D) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from to

Commission File Number 1-8182

PIONEER DRILLING COMPANY

(Exact name of registrant as specified in its charter)

TEXAS		74-2088619
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification Number)

1250 N.E. Loop 410, Suite 1000, San Antonio, Texas		78209
(Address of principal executive offices)		(Zip Code)

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

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 August 4, 2005, there were 46,294,312 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

	June 30,		March 31,
	2005		2005
	(unaudited)
ASSETS
Current assets:
Cash and cash equivalents	$	64,621,995	$	69,673,279
Marketable securities	—		1,000,000
Receivables:
Trade, net	30,664,502		26,108,291
Contract drilling in progress	7,629,848		5,364,529
Current deferred income taxes	2,689,123		569,548
Prepaid expenses	1,432,859		1,876,843
Total current assets	107,038,327		104,592,490

Property and equipment, at cost:	242,820,978		225,447,939
Less accumulated depreciation and amortization	59,873,879		54,881,488
Net property and equipment	182,947,099		170,566,451
Intangible and other assets	810,774		850,381
Total assets	$	290,796,200	$	276,009,322

LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities:
Notes payable	$	137,393	$	681,975
Current installments of long-term debt and capital lease obligations	4,725,913		4,733,026
Accounts payable	14,220,323		15,621,647
Income tax payable	232,493		195,949
Prepaid drilling contracts	345,043		172,750
Accrued expenses:
Payroll and payroll taxes	4,576,592		2,706,623
Other	4,399,188		4,153,851
Total current liabilities	28,636,945		28,265,821
Long-term debt and capital lease obligations, less current installments	12,261,894		13,445,017
Non-current liability	400,000		400,000
Deferred income taxes	17,448,691		12,283,070
Total liabilities	58,747,530		54,393,908
Commitments and contingencies	—		—
Shareholders’ equity:
Preferred stock, 10,000,000 shares authorized; none issued and outstanding	—		—
Common stock $.10 par value; 100,000,000 shares authorized; 46,294,312 shares and 45,893,311 shares issued and outstanding at June 30, 2005 and March 31, 2005, respectively	4,629,431		4,589,331
Additional paid-in capital	222,900,265		220,232,520
Retained earnings (accumulated deficit)	4,518,974		(3,206,437		)
Total shareholders’ equity	232,048,670		221,615,414
Total liabilities and shareholders’ equity	$	290,796,200	$	276,009,322

See accompanying notes to condensed consolidated financial statements.

PIONEER DRILLING COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(Unaudited)

	Three Months Ended June 30,
	2005			2004

Contract drilling revenues	$	59,876,763		$	40,718,811

Costs and expenses:
Contract drilling	39,158,198			33,854,370
Depreciation and amortization	7,329,520			5,048,317
General and administrative	1,486,672			770,141
Total operating costs and expenses	47,974,390			39,672,828

Income from operations	11,902,373			1,045,983

Other income (expense):
Interest expense	(155,135		)	(718,232		)
Interest income	501,629			23,837
Other	13,977			3,389
Total other income (expense)	360,471			(691,006		)

Income before income taxes	12,262,844			354,977
Income tax expense	(4,537,434		)	(138,449		)
Net earnings	$	7,725,410		$	216,528

Earnings per common share - Basic	$	0.17		$	0.01

Earnings per common share - Diluted	$	0.17		$	0.01

Weighted average number of shares outstanding - Basic	46,012,015			27,300,126

Weighted average number of shares outstanding - Diluted	46,765,224			28,273,561

See accompanying notes to condensed consolidated financial statements.

PIONEER DRILLING COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

	Three Months Ended June 30,
	2005			2004
Cash flows from operating activities:
Net earnings	$	7,725,410		$	216,528
Adjustments to reconcile net earnings to net cash provided by operating activities:
Depreciation and amortization	7,329,520			5,048,317
Loss on sale of properties and equipment	527,038			117,298
Change in deferred income taxes	3,046,046			168,449
Changes in current assets and liabilities:
Receivables	(4,556,211		)	(1,669,355		)
Contract drilling in progress	(2,265,319		)	(1,330,429		)
Prepaid expenses	443,984			364,188
Accounts payable	(1,401,324		)	4,502,705
Prepaid drilling contracts	172,293			—
Federal income tax payable	36,544			—
Accrued expenses	2,115,306			1,789,132
Net cash provided by operating activities	13,173,287			9,206,833

Cash flows from financing activities:
Payments of debt	(1,734,819		)	(1,299,699		)
Proceeds from exercise of options	2,707,844			—
Net cash provided by (used in) financing activities	973,025			(1,299,699		)

Cash flows from investing activities:
Purchase of property and equipment	(20,874,416		)	(8,415,522		)
Purchase of marketable securities	(49,150,000		)	(2,500,000		)
Proceeds from sale of marketable securities	50,150,000			4,000,000
Proceeds from sale of property and equipment	676,820			62,377
Net cash used in investing activities	(19,197,596		)	(6,853,145		)

Net decrease in cash and cash equivalents	(5,051,284		)	1,053,989

Beginning cash and cash equivalents	69,673,279			1,815,759
Ending cash and cash equivalents	$	64,621,995		$	2,869,748

Supplementary Disclosure:
Interest paid	$	272,761		$	242,738
Income taxes paid (refunded)	$	153,599		$	(30,000	)
Tax benefit from exercise of nonqualified options	$	1,301,245		$	—

See accompanying notes to condensed consolidated financial statements.

PIONEER DRILLING COMPANY AND SUBSIDARIES

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 select oil and natural gas exploration and production regions in the United States. 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.

Income Taxes

Pursuant to Statement of Financial Accounting Standards (“SFAS”) No. 109, 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.

We believe it is more likely than not that our taxable income for the year ending March 31, 2006 will be sufficient to utilize our net operating loss carryforwards recorded at June 30, 2005. As a result, we classified the deferred income tax benefit of these net operating loss carryforwards as current deferred income tax assets on our balance sheet as of June 30, 2005. Additionally, we believe our federal income tax rate for the year ending March 31, 2006 will increase to 35%, as compared to 34% for the year ended March 31, 2005. The effect of this expected increase in our federal income tax rate is reflected in our estimated annual income tax rate utilized for the three months ended June 30, 2005.

Stock-based Compensation

We have adopted SFAS No. 123, Accounting for Stock-Based Compensation. SFAS No. 123 allows a company to adopt a fair-value-based method of accounting for a stock-based employee compensation plan or to continue to use the intrinsic-value-based method of accounting prescribed by Accounting Principles Board (“APB”) Opinion No. 25, Accounting for Stock Issued to Employees. We have elected to continue accounting for stock-based compensation under the intrinsic-value-based 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) and net earnings (loss) per share would have been reduced to the pro forma amounts the table below indicates:

	Three Months Ended June 30,
	2005			2004
Net earnings - as reported	$	7,725,410		$	216,528
Deduct: Total stock-based employee compensation expense determined under fair-value-based method for all awards, net of related tax effect	(514,850		)	(347,091		)
Net earnings (loss) - pro forma	$	7,210,560		$	(130,563	)
Net earnings per share - as reported - basic	$	0.17		$	0.01
Net earnings per share - as reported - diluted	$	0.17		$	0.01
Net earnings per share - pro forma - basic	$	0.16		$	—
Net earnings per share - pro forma - diluted	$	0.15		$	—
Weighted-average fair value of options granted during the period	$	7.52		$	4.19

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 the three months ended June 30, 2005 and 2004:

	Three Months Ended June 30,
	2005		2004
Expected volatility	59	%	88	%
Weighted-average risk-free interest rates	3.8	%	4.0	%
Expected life in years	5		5
Options granted	30,000		35,000

As we have not declared dividends since we became a public company, we did not use a dividend yield. In each case, the actual value that will be realized, if any, will depend on the future performance of our common stock and overall stock market conditions. There is no assurance the value an optionee actually realizes will be at or near the value we have estimated using the Black-Scholes model.

Related Party Transactions

As of June 30, 2005, Chesapeake Energy Corporation (“Chesapeake”) owned 16.64% of our outstanding common stock. During the three months ended June 30, 2005 and 2004, we recognized revenues of approximately $6,637,000 and $9,000, and recorded contract drilling costs, excluding depreciation, of approximately $4,422,000 and $13,000 respectively, on drilling contracts with Chesapeake. Our accounts receivable at June 30, 2005 include approximately $5,022,000 due from Chesapeake.

We purchased services from R&B Answering Service and Frontier Services, Inc. during the three months ended June 30, 2005 and 2004. These companies are more than 5% owned by our Chief Operating Officer and an immediate family member of our Vice President and Operations Manager, respectively. The following summarizes the transactions with these companies in each period.

	Three Months Ended June 30,
	2005		2004
R&B Answering Service
Purchases	$	4,881	$	3,858
Payments	4,733		4,553

Frontier Services, Inc.
Purchases	$	4,432	$	31,583
Payments	4,107		34,467

Recently Issued Accounting Standards

In December 2004, the Financial Accounting Standards Board (the”FASB”) issued SFAS No. 123R (revised 2004), Share-Based Payment. SFAS No. 123R is a revision of FASB SFAS No. 123, Accounting for Stock-Based Compensation, and supersedes APB Opinion No. 25, Accounting for Stock Issued to Employees, and its related implementation guidance. SFAS No. 123R established standards for the accounting for transactions in which an entity exchanges its equity instruments for goods or services. It also addresses transactions in which an entity incurs liabilities in exchange for goods or services that are based on the fair value of the entity’s equity instruments or that may be settled by the issuance of those equity instruments. SFAS No. 123R focuses primarily on accounting for transactions in which an entity obtains employee services in share-based payment transactions. SFAS No. 123R requires a public entity to measure the cost of employee services received in exchange for an award of equity instruments based on the grant-date fair value of the award (with limited exceptions). That cost will be recognized over the period during which an employee is required to provide service in exchange for the award. The provisions of SFAS No. 123R are effective for public entities that do not file as small business issuers as of the beginning of the first annual reporting period that begins after June 15, 2005. We are currently evaluating the negative impact SFAS No. 123R will have on our financial position and results of operations in fiscal year 2007. The negative impact will be created due to the fact that we previously issued employee stock options for which no expense has been recognized, as those options will not be fully vested as of the effective date of SFAS No. 123R.

In May 2005, the FASB issued SFAS No. 154, Accounting Changes and Error Corrections, which supersedes APB Opinion No. 20, Accounting Changes, and SFAS No. 3, Reporting Accounting Changes in Interim Financial Statements. SFAS No. 154 changes the requirements for the accounting for and reporting of changes in accounting principle. The statement requires the retroactive application to prior periods’ financial statements of changes in accounting principles, unless it is impracticable to determine either the period-specific effects or the cumulative effect of the change. SFAS No. 154 does not change the guidance for reporting the correction of an error in previously issued financial statements or the change in an accounting estimate. SFAS No.154 is effective for accounting changes and corrections of errors made in fiscal years beginning after December 15, 2005. We do not expect the adoption of SFAS No. 154 to have a material impact on our financial position and results of operations and financial condition.

Reclassifications

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

2. Long-term Debt and Notes Payable

Notes payable at June 30, 2005 consist of a $137,393 insurance premium note due on August 26, 2005, plus interest at the rate of 3.15% per year.

Long-term debt at June 30, 2004 included two notes payable to Frost National Bank of $4,070,746 and $2,911,248, a note payable to Merrill Lynch Capital of $12,601,190 and subordinated debt payable to WEDGE Energy Services, LLC and William H. White of $28,000,000. In August and September 2004, we repaid the two notes payable to Frost National Bank and the note payable to Merrill Lynch Capital. On August 11, 2004, the entire $28,000,000 in aggregate principal amount of our 6.75% convertible subordinated debentures was converted in accordance with the terms of those debentures into 6,496,519 shares of our common stock.

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 (6.25% at June 30, 2005) and are secured by most of our assets, including all our drilling rigs and associated equipment and receivables. We borrowed the entire $40,000,000 available under the acquisition facility and we have used approximately $2,825,000 of availability under the revolving line and letter of credit facility through the issuance of letters of credit in the ordinary course of business. On March 29, 2005, we repaid $20,000,000 of the borrowings under the acquisition facility. On May 11, 2005, the lender amended the acquisition facility to provide us with the ability to again draw $20,000,000 for future acquisitions. The acquisition facility and the revolving line and letter of credit facility have availability of approximately $20,000,000 and $4,175,000, respectively, that should remain available to us until those facilities mature in October 2006 and October 2005, respectively. The acquisition facility loan balance of $16,911,111 at June 30, 2005 is due in monthly installments of $388,889 plus interest at Frost National Bank’s floating prime rate. The remaining unpaid balance is due December 1, 2007. The

$16,911,111 matures as follows: $4,666,667 by June 1, 2006; $4,666,667 by June 1, 2007; and $7,577,777 by December 1, 2007.

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 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 June 30, 2005, we had no outstanding advances under this line of credit, letters of credit were $2,825,000 and 75% of our eligible accounts receivable was approximately $22,167,000. The letters of credit are 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. The termination date of the revolving line and letter of credit facility portion of our new credit facility is October 28, 2005.

At June 30, 2005, we were in compliance with all covenants applicable to our outstanding debt. Those covenants include, among others, requirements that we maintain a debt to total capitalization ratio of not greater than 0.3 to 1, a fixed charged coverage ratio of not less than 1.5 to 1 and an operating leverage ratio of less than 3 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 not already allowed by the credit facility.

3. Commitments and Contingencies

Due to the nature of our business, we are, from time to time, involved in routine litigation or subject to disputes or claims related to our business activities, including workers’ compensation claims and employment-related disputes. In the opinion of our management, none of such pending litigation, disputes or claims against us will have a material adverse effect on our financial condition, results of operations or cash flow from operations, and there is only a remote possibility that any such matter will require any additional loss accrual.

At June 30, 2005, we were in the process of constructing four drilling rigs and had incurred approximately $12,500,000 of the approximately $29,500,000 of construction costs.

4. Equity Transactions

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 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 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 March 22, 2005, we sold 6,945,000 shares of our common stock, including shares we sold pursuant to the underwriters’ exercise of an over-allotment option, at approximately $11.78 per share, net of underwriters’ commissions, pursuant to a public offering we registered with the SEC.

Directors and employees exercised stock options for the purchase of 401,001 shares of common stock during the three months ended June 30, 2005, at prices ranging from $3.00 to $6.44 per share. There were no director and employee stock options exercised during the three months ended June 30, 2004.

5. Earnings 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:

	Three Months Ended June 30,
	2005		2004
Basic
Net earnings	$	7,725,410	$	216,528
Weighted average shares	46,012,015		27,300,126
Earnings per share	$	0.17	$	0.01

		Three Months Ended June 30,
		2005		2004
Diluted
Net earnings		$	7,725,410	$	216,528
Effect of dilutive securities:
Convertible debentures	(1)	—		—


Net earnings and assumed conversion		$	7,725,410	$	216,528
Weighted average shares:
Outstanding		46,012,015		27,300,126
Options		753,209		973,435
Convertible debentures	(1)	—		—
		46,765,224		28,273,561
Earnings per share		$	0.17	$	0.01

(1) The computation of diluted earnings per share for the three months ended June 30, 2004 excluded 6,496,519 shares from convertible debentures because they were antidilutive.

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. 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 year ended March 31, 2005. 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 10-K 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 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 new or 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 August 1, 2005, our rig fleet consisted of 51 land drilling rigs that drill in depth ranges between 6,000 and 18,000 feet. Fifteen of our rigs are operating in South Texas, 17 in East Texas, four in North Texas, five in western Oklahoma and 10 in the Rocky Mountains. We actively market all of these rigs. We anticipate continued growth of our rig fleet in fiscal year 2006. We are currently constructing a 1000-horsepower diesel electric rig and two 1500-horsepower diesel electric rigs from new and used components. In addition, we plan to construct three additional rigs subject to obtaining satisfactory contracts with minimum terms of one year.

We earn our revenues by drilling oil and gas wells for our customers. 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. Generally, our contracts provide for the drilling of a single well and typically permit the customer to terminate on short notice. As demand for drilling rigs has improved during the past year, we have entered into more longer term drilling contracts. Currently, we have 16 contracts with terms of six months to two years in duration. In addition, we have one- or two-year term contracts for the three rigs currently under construction.

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 for a rig 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 the three months ended June 30, 2005 and 2004, our rig utilization and revenue days were as follows:

	2005		2004
Utilization Rates	95	%	93	%
Revenue Days	4,303		2,997

The reasons for the increase in the number of revenue days in 2005 over 2004 are the increase in size of our rig fleet from 36 rigs at June 30, 2004 to 50 rigs at June 30, 2005 and the improvement in our overall rig utilization rate due to the improved market conditions. For the remainder of fiscal year 2006, we anticipate continued growth in revenue days and comparable utilization rates to fiscal year 2005.

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 three months ended June 30, 2005, turnkey contracts accounted for approximately 9% 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 three months ended June 30, 2004, a turnkey contract may not be profitable if it cannot be completed successfully without unanticipated complications.

We devote substantial resources to maintaining and upgrading our rig fleet. 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 expended approximately $4,315,000 on rig upgrades during the three months ended June 30, 2005. We are currently performing, between contracts or as necessary, safety and equipment upgrades to the eight rigs we acquired in March 2004 and the 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 July 22, 2005, the spot price for West Texas Intermediate crude oil was $56.65, the spot price for Henry Hub natural gas was $7.42 and the Baker Hughes land rig count was 1,282, a 17% increase from 1,097 on July 23, 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 three months ended June 30, 2005 and each of the previous five years ended June 30, were:

	Three Months Ended June 30,		Years Ended June 30,
	2005		2005		2004		2003		2002		2001
Oil (West Texas
Intermediate)	$	53.09	$	48.74	$	33.78	$	29.96	$	23.88	$	30.08

Natural Gas (Henry Hub)	$	6.93	$	6.20	$	5.39	$	4.81	$	2.73	$	5.40

U.S. Land Rig Count	1,218		1,153		1,000		778		821		930

During fiscal year 2005, 2004 and 2003, 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 natural 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 six of those rigs employed 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 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 SOP 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, including quantum meruit, available in applicable courts to recover the fair value of our work-in-progress under a turnkey or footage contract.

We accrue estimated contract costs on turnkey and footage contracts for each day of work completed based on our estimate of the total costs to complete the contract divided by our estimate of the number of days to complete the contract. Contract costs include labor, materials, supplies, repairs and maintenance, operating overhead allocations and allocations of depreciation and amortization expense. In addition, the occurrence of uninsured or under-insured losses or operating cost overruns on our turnkey and footage contracts could have a material adverse effect on our financial position and results of operations. Therefore, our actual results could differ significantly if our cost estimates are later revised from our original estimates for contracts in progress at the end of a reporting period which were not completed prior to the release of our financial statements.

Asset impairments – We assess the impairment of property and equipment whenever events or circumstances indicate that the carrying value may not be recoverable. Factors that we consider important and which could trigger an impairment review would be our customers’ financial condition and any significant negative industry or economic trends. More specifically, among other things, we 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 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 June 30, 2005, would have resulted in a corresponding decrease in our net earnings of approximately $1,466,000 for the three months ended June 30, 2005.

Deferred taxes – We provide deferred taxes for net operating loss carryforwards and for the basis differences 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 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 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 accrue the entire amount of the estimated loss, including all costs that are included in our revised estimated cost to complete that contract, in our consolidated statement of operations for that reporting period. During the three months ended June 30, 2005, we experienced losses of less than $25,000 each on two of the 47 turnkey and footage contracts completed. During the three months ended June 30, 2004, we experienced losses on five of the 45 turnkey and footage contracts completed, with losses exceeding $25,000 on four contracts and losses exceeding $100,000 on one contract. We are more likely to encounter losses on turnkey and footage contracts in 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. All of our turnkey contracts in progress at June 30, 2005 were completed prior to the release of the financial statements included in this report. At June 30, 2005, our contract drilling in progress totaled approximately $7,630,000. Of that amount accrued, turnkey and footage contract revenues were approximately $2,851,000. The remaining balance of approximately $4,779,000 related to the revenue recognized but not yet billed on daywork contracts in progress at June 30, 2005. At March 31, 2005, drilling in progress totaled $5,365,000, of which $2,344,000 related to turnkey and footage contracts and $3,021,000 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 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 $352,000 at June 30, 2005.

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.

Our other accrued expenses as of June 30, 2005 include an accrual of approximately $1,428,000 for costs incurred under the self-insurance portion of our health insurance and under our workers’ compensation insurance. We have a deductible of (1) $100,000 per covered individual per year under the health insurance and (2) $250,000 per occurrence under our workers’ compensation insurance, 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. Management evaluates these cost estimates by the insurance companies based on historical claim information and adjusts the accrued claim costs if deemed necessary.

Liquidity and Capital Resources

Sources of Capital Resources

Our rig fleet has grown from eight rigs in August 2000 to 51 rigs as of August 1, 2005. We have financed this growth with a combination of debt and equity financing. We have raised additional equity or used equity for growth eight times since January 2000 and have increased our long-term debt from approximately $3,909,000 at June 30, 2000 to approximately $16,988,000 at June 30, 2005. We plan to continue to grow our rig fleet. At June 30, 2005, our total debt to total capital was approximately 6.8%. Due to the volatility in our industry, we are reluctant to take on substantial additional debt in excess of the $20,000,000 of remaining availability under our acquisition credit facility. 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 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 (6.25% at June 30, 2005) and are secured by most of our assets, including all our drilling rigs and associated equipment and receivables. We borrowed the entire $40,000,000 available under the acquisition facility, and we have used approximately $2,825,000 of availability under the revolving line and letter of credit facility through the issuance of letters of credit in the ordinary course of business. On March 29, 2005, we repaid $20,000,000 of the borrowings under the acquisition facility. On May 11, 2005, the lender amended the acquisition facility to provide us with the ability to again draw $20,000,000 for future acquisitions. The acquisition facility and the revolving line and letter of credit facility have availability of approximately $20,000,000 and $4,175,000, respectively, that should remain available to us until those facilities mature in October 2006 and October 2005, respectively.

Uses of Capital Resources

For the three months ended June 30, 2005, the additions to our property and equipment consisted of the following:

Drilling rigs (1)	$	9,317,382
Other drilling equipment	10,030,576
Transportation equipment	1,051,746
Other	474,712
	$	20,874,416

(1) Includes capitalized interest costs of $115,694

As of June 30, 2005, we were constructing, from new and used components, two 1000-horsepower diesel electric rigs and two 1500-horsepower diesel electric rigs. We placed one of the 1000-horsepower rigs in service in August 2005 and expect to place the second in service in September 2005. We expect to place the 1500-horsepower rigs in service in September 2005 and November 2005. As of June 30, 2005, we have incurred approximately $12,500,000 of the approximately $29,500,000 of construction costs on these rigs. Subject to obtaining satisfactory contracts with minimum terms of one year, we expect to construct three additional rigs resulting in approximately $22,500,000 of construction costs.

For the remainder of fiscal year 2006, we project regular rig capital expenditures (excluding construction costs to complete the construction of the seven rigs referred to above) to be approximately $14,400,000, rig upgrade expenditures to be approximately $6,000,000, transportation equipment capital expenditures of approximately $1,900,000 and other capital

expenditures of approximately $900,000. These capital expenditures are expected to be funded primarily from operating cash flow in excess of cash flow necessary to meet routine contractual obligations.

Working Capital

Our working capital was $78,401,382 at June 30, 2005, compared to $76,326,669 at March 31, 2005. Our current ratio, which we calculate by dividing our current assets by our current liabilities, was 3.74 at June 30, 2005, compared to 3.70 at March 31, 2005.

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 three months ended June 30, 2005 over June 30, 2004 is primarily due to the approximately $7,500,000 improvement in net earnings, plus the approximately $2,300,000 increase in 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 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 $4,175,000, after reductions for approximately $2,825,000 of outstanding letters of credit as of June 30, 2005, should allow us to meet our routine financial obligations.

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

	June 30,		March 31,
	2005		2005		Change

Cash and cash equivalents	$	64,621,995	$	69,673,279	$	(5,051,284	)
Marketable securities	—		1,000,000		(1,000,000		)
Receivables	30,664,502		26,108,291		4,556,211
Contract drilling in progress	7,629,848		5,364,529		2,265,319
Deferred income taxes	2,689,123		569,548		2,119,575
Prepaid expenses	1,432,859		1,876,843		(443,984		)
Current assets	107,038,327		104,592,490		2,445,837

Current debt	4,863,306		5,415,001		(551,695		)
Accounts payable	14,220,323		15,621,647		(1,401,324		)
Accrued payroll	4,576,592		2,706,623		1,869,969
Income tax payable	232,493		195,949		36,544
Prepaid drilling contracts	345,043		172,750		172,293
Accrued expenses	4,399,188		4,153,851		245,337
	28,636,945		28,265,821		371,124

Working capital	$	78,401,382	$	76,326,669	$	2,074,713

The increase in our receivables and contract drilling in progress at June 30, 2005 from March 31, 2005 was due to our operating one additional rig and the improvement of revenue rates.

The increase in deferred income taxes was due to the classification of our net operating loss carryforwards as current deferred income taxes at June 30, 2005. At March 31, 2004, these net operating loss carryforwards were classified as long-term deferred income taxes. We believe it is more likely than not that our taxable income for the year ending March 31, 2006 will be sufficient to utilize our net operating loss carryforwards recorded at June 30, 2005.

Substantially all our prepaid expenses at June 30, 2005 consisted of prepaid insurance. We renew and pay our insurance premium in late October of each year. At March 31, 2005, we had amortized five months of the premiums, compared to eight months of amortization as of June 30, 2005.

The decrease in accounts payable was due to the decrease in turnkey contracts completed during June and in progress at June 30, 2005. We had two turnkey and five footage contracts in progress at June 30, 2005, compared to six turnkey and six footage contracts in progress at March 31, 2005.

The increase in accrued payroll was due to the increase in the number of our employees due to the rig addition and the increase in the number of payroll days included in the accrual from 17 days at June 30, 2005, compared to 10 days at March 31, 2005.

The increase in accrued expenses at June 30, 2005 compared to March 31, 2005 was principally due to increases in the accrual for property taxes and self-insurance costs, partially offset by a decrease in the accrual for management bonuses.

Although we have not been required to make income tax payments for the last three years, it is likely we will be in a current taxable position during fiscal year 2006, due to improving market conditions and the reversal of deferred tax liabilities.

Long-term Debt

Our long-term debt consisted of:

	June 30, 2005		March 31, 2005
Indebtedness incurred under $47,000,000 credit facility, secured by drilling equipment, due in monthly payments of $388,889 plus interest at prime (6.25% at June 30, 2005), with final maturity on December 1, 2007	$	16,911,111	$	18,077,778

Capital lease obligations	76,696		100,265
	$	16,987,807	$	18,178,043

Contractual Obligations

We do not have any routine purchase obligations. However, as of June 30, 2005, we were in the process of constructing four drilling rigs, as described above. 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 June 30, 2005.

	Payments Due by Period
Contractual Obligations	Total		Less than 1 year		1-3 years		4-5 years		More than 5 years
Long-term Debt	$	16,911,111	$	4,666,667	$	12,244,444	$	—	$	—
Capital Lease Obligations	76,696		54,817		21,879		—		—
Operating Lease Obligations	1,731,796		200,318		344,569		418,791		768,118
Office Construction Obligation	103,232		103,232		—		—		—

Total	$	18,822,835	$	5,025,034	$	12,610,892	$	418,791	$	768,118

Debt Requirements

The $16,911,111 amount of indebtedness outstanding under the acquisition facility portion of our new credit facility is due in monthly installments of $388,889, plus interest, 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 (6.25% as of June 30, 2005).

outstanding letters of credit were $2,825,000 and 75% of our eligible accounts receivable was approximately $22,167,000. The letters of credit are 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. The termination date of the revolving line and letter of credit facility portion of our new credit facility is October 28, 2005.

Our 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:

• our failure to make required payments;

• any sale of assets by us not permitted by the credit facility;

• 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 not to exceed 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 facility;

• 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.

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.

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, 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.

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.

We have a history of losses. 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. Our profitability in the future will depend on many factors, but largely on utilization rates and dayrates for our drilling rigs.

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 months ended June 30, 2005 and 2004, the percentages of our drilling revenues by type of contract were as follows:

	2005		2004

Daywork contracts	77	%	35	%
Turnkey contracts	14	%	60	%
Footage contracts	9	%	5	%

While demand for drilling rigs has been increasing, we continue to bid on turnkey contracts in an effort to meet our customer demand and maintain rig utilization. With the improvements in daywork contract rates, we anticipate a gradual decline in the number of turnkey contracts. We had two turnkey contracts in progress at June 30, 2005 compared to 16 turnkey contracts in progress at June 30, 2004. We also had five footage contracts in progress at June 30, 2005 compared to one footage contract in progress at June 30, 2004.

At June 30, 2005, Chesapeake Energy Corporation owned 16.64% of our outstanding common stock. During the three months ended June 30, 2005 and 2004, we recognized revenues of approximately $6,637,000 and $9,000, respectively, and recorded contract drilling costs, excluding depreciation, of approximately $4,422,000 and $13,000, respectively, on contracts with Chesapeake.

Statement of Operations Analysis

The following table provides information for our operations for the three months ended June 30, 2005 and 2004.

	2005			2004
Contract drilling revenues:
Daywork contracts	$	45,874,532		$	14,140,756
Turnkey contracts	8,592,632			24,619,333
Footage contracts	5,409,599			1,958,722
Total contract drilling revenues	$	59,876,763		$	40,718,811
Contract drilling costs:
Daywork contracts	$	29,114,313		$	11,529,238
Turnkey contracts	6,160,579			20,860,520
Footage contracts	3,883,306			1,464,612
Total contract drilling costs	$	39,158,198		$	33,854,370

Depreciation and amortization	$	7,329,520		$	5,048,317
General and administrative expense	$	1,486,672		$	770,141
Revenue days by type of contract:
Daywork contracts	3,424			1,477
Turnkey contracts	462			1,376
Footage contracts	417			144
Total Revenue days	4,303			2,997

Contract drilling revenue per revenue day	$	13,915		$	13,587
Contract drilling cost per revenue day	$	9,100		$	11,296
Rig utilization rates	95		%	93		%
Average number of rigs during the period	50			35.3

Our contract drilling revenues grew by approximately $19,158,000, or 47%, in the quarter ended June 30, 2005 from the quarter ended June 30, 2004, due to an improvement in rig revenue rates resulting from an increase in demand for drilling rigs and the 43% increase in revenue days due to an increase in the number of rigs in our fleet and a 2% increase in rig utilization. The improvement in contract drilling revenues per day is due to the improvement in revenue rates. Although contract drilling revenues per revenue day only increased by $328, contract drilling revenues per day for daywork contracts increased over $3,800 in the quarter ended June 30, 2005 compared to the corresponding quarter in 2004 and daywork revenue days increased 132%.

Our contract drilling costs grew by approximately $5,304,000, or 16%, in the quarter ended June 30, 2005 from the corresponding quarter of 2004 due to the increase in the number of revenue days resulting from the increase in the number of rigs in our fleet and the increase in rig utilization. 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.

Our depreciation and amortization expenses for the quarter ended June 30, 2005 increased by approximately $2,281,000, or 45%, compared to the corresponding quarter in 2004. The increases in 2005 over 2004 resulted primarily from the 42% increase in the average size of our rig fleet.

Our general and administrative expense for the quarter ended June 30, 2005 increased by approximately $717,000, or 93%, compared to the corresponding quarter in 2004. The increase resulted primarily from increases in payroll costs, bonus accrual costs and professional fees. During the quarter ended June 30, 2005, payroll cost increased by approximately $197,000, due to pay raises and an increase in the number of employees in our corporate offices as compared to the quarter ended June 30, 2004. Bonus accrual costs increased by approximately $104,000 and professional fees increased by approximately $332,000.

Our effective income tax rates of 37% and 39% for the quarters ended June 30, 2005 and 2004, respectively, differ from the federal statutory rates of 35% and 34% for the quarters ended June 30, 2005 and 2004, respectively, 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 (the “FASB”) issued SFAS No. 123R (revised 2004), Share-Based Payment. SFAS No. 123R is a revision of FASB SFAS No. 123, Accounting for Stock-Based Compensation, and supersedes APB Opinion No. 25, Accounting for Stock Issued to Employees, and its related implementation guidance. SFAS No. 123R established standards for the accounting for transactions in which an entity exchanges its equity instruments for goods or services. It also addresses transactions in which an entity incurs liabilities in exchange for goods or services that are based on the fair value of the entity’s equity instruments or that may be settled by the issuance of those equity instruments. SFAS No. 123R focuses primarily on accounting for transactions in which an entity obtains employee services in share-based payment transactions. SFAS No. 123R requires a public entity to measure the cost of employee services received in exchange for an award of equity instruments based on the grant-date fair value of the award (with limited exceptions). That cost will be recognized over the period during which an employee is required to provide service in exchange for the award. The provisions of SFAS No. 123R are effective for public entities that do not file as small business issuers as of the beginning of the first annual reporting period that begins after June 15, 2005. We are currently evaluating the negative impact SFAS No. 123R will have on our financial position and results of operations in fiscal year 2007. The negative impact will be created due to the fact that we previously issued employee stock options for which no expense has been recognized, as these options will not be fully vested as of the effective date of SFAS No. 123R.

In May 2005, the FASB issued SFAS No. 154, Accounting Changes and Error Corrections, which supersedes APB Opinion No. 20, Accounting Changes and SFAS No. 3, Reporting Accounting Changes in Interim Financial Statements. SFAS No. 154 changes the requirements for the accounting for and reporting of changes in accounting principle. The statement requires the retroactive application to prior periods’ financial statements of changes in accounting principles, unless it is impracticable to determine either the period-specific effects or the cumulative effect of the change. SFAS No. 154 does not change the guidance for reporting the correction of an error in previously issued financial statements or the change in an accounting estimate. SFAS No. 154 is effective for accounting changes and corrections of errors made in fiscal years beginning after December 15, 2005. We do not expect the adoption of SFAS No. 154 to have a material impact on our financial position and results of operations and financial condition.

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 subject to market risk exposure related to changes in interest rates on our outstanding floating rate debt. At June 30, 2005 we had outstanding debt of $16,911,111 that was subject to variable interest rates 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 of approximately $107,000 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 June 30, 2005 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 June 30, 2005 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

PART II. OTHER INFORMATION

ITEM 6. EXHIBITS

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

3.1 *	-	Articles of Incorporation of Pioneer Drilling Company, as amended (Form 10-K for the year ended March 31, 2001 (File No. 1-8182, Exhibit 3.1)).

3.2 *	-	Articles of Amendment to the Articles of Incorporation of Pioneer Drilling Company (Form 10-Q for the quarter ended September 30, 2001 (File No. 1-8182, Exhibit 3.1)).

3.3 *	-	Amended and Restated Bylaws of Pioneer Drilling Company (Form 10-Q for the quarter ended December 31, 2003 (File No. 1-8182, Exhibit 3.3))

4.1 *		Second Amendment dated May 11, 2005 to Credit Agreement between Pioneer Drilling Services, Ltd. and Frost National Bank, as Administrative Agent, Lead Arranger and Lender dated October 29, 2004 (Form 8-K filed May 13, 2005 (File No. 1-8182, Exhibit 4.1))

31.1	-	Certification by Wm. Stacy Locke, President and Chief Executive Officer, pursuant to Rule 13a-14(a) or 15d-14(a) under the Securities Act of 1934.

31.2	-	Certification by William D. Hibbetts, Senior Vice President and Chief Financial Officer, pursuant to Rule 13a-14(a) or 15d-14(a) under the Securities Act of 1934.

32.1	-	Certification by Wm. Stacy Locke, President and Chief Executive Officer, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (Subsections (a) and (b) of Section 1350, Chapter 63 of Title 18, United States Code).

32.2	-	Certification by William D. Hibbetts, Senior Vice President and Chief Financial Officer, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (Subsections (a) and (b) of Section 1350, Chapter 63 of Title 18, United States Code).

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

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.

		PIONEER DRILLING COMPANY


		/s/ William D. Hibbetts
		William D. Hibbetts
		Senior Vice President and Chief Financial Officer
		(Principal Financial Officer and Duly Authorized Representative)

Dated:	August 4, 2005

Index to Exhibits

3.1 *	-	Articles of Incorporation of Pioneer Drilling Company, as amended (Form 10-K for the year ended March 31, 2001 (File No. 1-8182, Exhibit 3.1)).

3.2 *	-	Articles of Amendment to the Articles of Incorporation of Pioneer Drilling Company (Form 10-Q for the quarter ended September 30, 2001 (File No. 1-8182, Exhibit 3.1)).

3.3 *	-	Amended and Restated Bylaws of Pioneer Drilling Company ((Form 10-Q for the quarter ended December 31, 2003 (File No. 1-8182, Exhibit 3.3)).

4.1 *		Second Amendment dated May 11, 2005 to Credit Agreement between Pioneer Drilling Services, Ltd. and Frost National Bank, as Administrative Agent, Lead Arranger and Lender dated October 29, 2004 (Form 8-K filed May 13, 2005 (File No. 1-8182, Exhibit 4.1))

31.1	-	Certification by Wm. Stacy Locke, President and Chief Executive Officer, pursuant to Rule 13a-14(a) or 15d-14(a) under the Securities Act of 1934.

31.2	-	Certification by William D. Hibbetts, Senior Vice President and Chief Financial Officer, pursuant to Rule 13a-14(a) or 15d-14(a) under the Securities Act of 1934.

32.1	-	Certification by Wm. Stacy Locke, President and Chief Executive Officer, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (Subsections (a) and (b) of Section 1350, Chapter 63 of Title 18, United States Code).

32.2	-	Certification by William D. Hibbetts, Senior Vice President and Chief Financial Officer, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (Subsections (a) and (b) of Section 1350, Chapter 63 of Title 18, United States Code).

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