Edgar Filing: PIONEER DRILLING CO

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Table of Contents

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

Registration No. 333-

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

FORM S-1
REGISTRATION STATEMENT
UNDER
THE SECURITIES ACT OF 1933

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

Texas (State or other jurisdiction of incorporation or organization)	1381 (Primary Standard Industrial Classification Code Number)	74-2088619 (I.R.S. Employer Identification No.)
9310 Broadway, Bldg. I San Antonio, Texas 78217 Phone: (210) 828-7689 (Address, including zip code, and telephone number, including area code, of registrant's principal executive offices)
WM. STACY LOCKE President and Chief Executive Officer Pioneer Drilling Company 9310 Broadway, Bldg. I San Antonio, Texas 78217 Phone: (210) 828-7689 Fax: (210) 828-8228 (Name, address, including zip code, and telephone number, including area code, of agent for service)

Copies to:
TED W. PARIS, Esq. Baker Botts L.L.P. 3000 One Shell Plaza Houston, TX 77002-4995 Phone: (713) 229-1234 Fax: (713) 229-1522		CHARLES L. STRAUSS, Esq. Fulbright & Jaworski L.L.P. 1301 McKinney, Suite 5100 Houston, TX 77010 Phone: (713) 651-5151 Fax: (713) 651-5246

Approximate date of commencement of proposed sale to the public: As soon as practicable after the effective date of this registration statement.

If any of the securities being registered on this Form are to be offered on a delayed or continuous basis pursuant to Rule 415 under the Securities Act of 1933, check the following box. o

If this Form is filed to register additional securities for an offering pursuant to Rule 462(b) under the Securities Act, please check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering. o

If this Form is a post-effective amendment filed pursuant to Rule 462(c) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering. o

If this Form is a post-effective amendment filed pursuant to Rule 462(d) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering. o

If delivery of the prospectus is expected to be made pursuant to Rule 434, please check the following box. o

CALCULATION OF REGISTRATION FEE

Title of each class of securities to be registered	Amount to be Registered(1)	Proposed Maximum per Offering Price Share(2)	Proposed Maximum Aggregate Offering Price(1)(2)	Amount of Registration Fee


Common Stock, par value $0.10 per share	12,075,000	$10.385	$125,398,875	$14,759

(1): Includes 1,575,000 shares of Common Stock subject to an over-allotment option granted to the Underwriters.
(2): Estimated in accordance with Rule 457(c) of the Securities Act of 1933, as amended, solely for the purpose of computing the amount of the registration fee, based on the average of the high and low sales prices of the Registrant's Common Stock as reported on the American Stock Exchange on February 1, 2005.

The Registrant hereby amends this registration statement on such date or dates as may be necessary to delay its effective date until the Registrant shall file a further amendment which specifically states that this registration statement shall thereafter become effective in accordance with Section 8(a) of the Securities Act of 1933 or until the registration statement shall become effective on such date as the Securities and Exchange Commission, acting pursuant to said Section 8(a), may determine.

The information in this prospectus is not complete and may be changed. A registration statement relating to these securities has been filed with the Securities and Exchange Commission. These securities may not be sold until the registration statement filed with the Securities and Exchange Commission is effective. This prospectus is not an offer to sell these securities and neither we nor the selling shareholders are soliciting an offer to buy these securities in any jurisdiction where the offer or sale is not permitted.

SUBJECT TO COMPLETION, DATED February 7, 2005

PROSPECTUS

10,500,000 Shares

Common Stock

We are offering 5,000,000 shares of our common stock and the selling shareholders identified on page 59 of this prospectus are offering a total of 5,500,000 shares of our common stock. We will not receive any of the proceeds from the shares of our common stock sold by the selling shareholders.

WEDGE Energy Services, L.L.C., one of the selling shareholders, acquired the 5,000,000 shares of common stock it is offering by this prospectus directly from us in private placements. We are registering the offer and sale of those shares to satisfy registration rights we have granted to WEDGE. See "Selling Shareholders."

Our common stock trades on The American Stock Exchange under the symbol "PDC." On February 4, 2005, the last reported sale price for our common stock was $10.62 per share.

Investing in our common stock involves a high degree of risk. See "Risk Factors" beginning on page 7 of this prospectus.

		Price to Public			Underwriting Discounts and Commissions			Proceeds to Pioneer Drilling Company (Before Expenses)			Proceeds to Selling Shareholders (Before Expenses)
Per Share		$			$			$			$
Total		$			$			$			$

Neither the Securities and Exchange Commission nor any state securities commission has approved or disapproved of these securities or determined if this prospectus is truthful or complete. Any representation to the contrary is a criminal offense.

Delivery of the shares of common stock is expected to be made on or about , 2005. The underwriters have an option to purchase an additional 787,500 shares from us and an additional 787,500 shares from WEDGE to cover over-allotments of shares.

Jefferies & Company, Inc. Sole Book-Running Manager		Raymond James
Johnson Rice & Company L.L.C.		Pritchard Capital Partners, LLC

The date of this Prospectus is , 2005.

Table of Contents

PROSPECTUS SUMMARY

RISK FACTORS

FORWARD-LOOKING STATEMENTS

USE OF PROCEEDS

PRICE RANGE OF COMMON STOCK

DIVIDEND POLICY

CAPITALIZATION

SELECTED FINANCIAL DATA

MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

BUSINESS

MANAGEMENT

EXECUTIVE COMPENSATION

SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT

CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS

SELLING SHAREHOLDERS

DESCRIPTION OF CAPITAL STOCK

UNDERWRITING

LEGAL MATTERS

EXPERTS

WHERE YOU CAN FIND MORE INFORMATION

INDEX TO FINANCIAL STATEMENTS

You should rely only on the information in this prospectus. We have not, and the selling shareholders and the underwriters have not, authorized anyone to provide you with information that is different. This document may only be used where it is legal to sell these securities.

PROSPECTUS SUMMARY

This summary highlights selected information described more fully elsewhere in this prospectus. This summary may not contain all the information that is important to you. You should read the entire prospectus, including the risks of investing in our common stock discussed in the "Risk Factors" section and our consolidated financial statements and related notes, before making an investment decision with respect to this common stock offering. References in this prospectus to "we," "our," "us," "Pioneer" or similar terms mean Pioneer Drilling Company and its subsidiaries, unless the context indicates otherwise.

Our Business

We provide 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 conduct our operations primarily in South, East and North Texas, Western Oklahoma and the Rocky Mountains. During our fiscal year ended March 31, 2004 and through the third quarter of fiscal 2005, substantially all the wells we drilled for our customers were drilled in search of natural gas. Although we have recently diversified our operations somewhat with the November 2004 acquisition of seven drilling rigs from Wolverine Drilling, Inc., with five 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 deep geological formations and generally require premium equipment and experienced crews to increase drilling success. In addition, the regions in which we operate are natural gas rich areas. Our rig fleet is capable of achieving the depths required to develop the natural gas reserves and our crews have significant operating experience in these regions.

Since September 1999, we have significantly expanded our fleet of drilling rigs from six to a current fleet of 49 drilling rigs through acquisitions, construction of new rigs and the refurbishment of older rigs we owned or acquired. As of January 31, 2005, we had 15 rigs operating in South Texas, 17 rigs operating in East Texas, four rigs operating in North Texas, five rigs operating in Western Oklahoma and eight rigs operating in the Rocky Mountains. We own all the rigs in our fleet. The following table summarizes information relating to acquisitions in which we acquired rigs and related operations since September 1999:

Date	Acquisition(1)	Market	Number of Rigs Acquired
September 1999	Howell Drilling, Inc.	South Texas	2
August 2000	Pioneer Drilling Co.	South Texas	4
March 2001	Mustang Drilling, Ltd.	East Texas	4
May 2002	United Drilling Company	South Texas	2
August 2003	Texas Interstate Drilling Company, L.P.	North Texas	2
March 2004	Sawyer Drilling & Service, Inc.	East Texas	7
March 2004	SEDCO Drilling Co., Ltd.	North Texas	1
November 2004	Wolverine Drilling, Inc.	Rocky Mountains	7
December 2004	Allen Drilling Company	Western Oklahoma	5

(1): The August 2000 acquisition of Pioneer Drilling Co. involved our acquisition of all the outstanding capital stock of that entity. Each other acquisition reflected in this table involved our acquisition of assets from the indicated entity.

We obtain our contracts for drilling oil and gas wells either through competitive bidding or through direct negotiations with customers. Our drilling contracts generally provide for compensation on either a daywork, turnkey or footage basis. Contract terms we offer generally depend on the complexity and risk of operations, the on-site drilling conditions, the type of equipment used and the anticipated duration of the work to be performed. 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. 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. 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. The following table presents, by type of contract, information about the total number of wells we completed for our customers during the nine months ended December 31, 2004 and each of the last three fiscal years.

		Year Ended March 31,
	Nine Months Ended December 31, 2004	Year Ended March 31,
	Nine Months Ended December 31, 2004	2004	2003	2002
Daywork	167	205	119	150
Turnkey	110	92	78	9
Footage	18	13	5	6

Total number of wells	295	310	202	165

Our Strategy

Our goal is to continue to build on our strong market position and reputation as a quality contract drilling company in a way that enhances shareholder value. We intend to accomplish this goal by:

•: continuing to own and operate a high-quality fleet of land drilling rigs, primarily in active natural gas drilling markets;
•: acquiring high-quality rigs capable of generating our targeted returns on investment;
•: positioning ourselves to maximize rig utilization and dayrates;
•: training and maintaining high-quality, experienced crews; and
•: maintaining the recent improvements in our safety record.

Our Industry

We operate in the United States contract land drilling services industry, providing products and services to oil and natural gas exploration and production companies engaged in the drilling for and production of oil and natural gas. Demand for our products and services depends primarily on our customers' willingness to spend capital on exploration and development activities. Our customers' capital spending decisions are driven by their perspectives on current and future oil and natural gas prices, their access to capital and available exploration and development opportunities.

We believe capital spent on incremental natural gas production will be driven by an increase in hydrocarbon demand as well as shortages in supply of natural gas. The Energy Information Agency recently estimated that U.S. consumption of natural gas exceeded U.S. domestic productive capacity by 15% in 2003 and forecasts that U.S. consumption of natural gas will exceed U.S. domestic productive capacity by 25% by 2010. Most of this difference is expected to be driven by the growth in consumption by electric power generators, as a significant amount of natural gas-fired power generation capacity has been constructed within the last five years and older, less-efficient power generation capacity, not fired by natural gas, is expected to be decommissioned. In addition, a study published by the National Petroleum Council in September 2003 concluded from drilling and production data over the preceding 10 years that average "initial production rates from new wells have been sustained through the use of advanced technology; however, production declines from these initial rates have increased significantly; and recoverable volumes from new wells drilled in mature producing basins have declined over time. Without the benefit of new drilling, indigenous supplies have reached a point at which U.S. production declines by 25% to 30% each year. Eighty percent of gas production in 10 years will be from wells yet to be drilled." We believe all of these factors tend to support a higher natural gas price environment, which should create strong incentives for oil and natural gas exploration and production companies to increase drilling activity in North America. Consequently, these factors may result in higher rig dayrates and rig utilization.

Recent Developments

New Credit Facility. On October 29, 2004, we entered into a $47 million credit facility with a group of lenders. The new credit facility provides us with a $7 million revolving line and letter of credit facility and a $40 million acquisition facility for the acquisition of drilling rigs, rig transportation equipment and associated equipment. Borrowings under the new credit facility bear interest at a rate equal to Frost National Bank's prime rate (5.25% at January 31, 2005) and are secured by most of our assets, including all our drilling rigs, associated equipment and receivables.

Wolverine Drilling Asset Acquisition. On November 30, 2004, we completed the acquisition of seven drilling rigs and related equipment from Wolverine Drilling, based in Kenmare, North Dakota. We paid $28 million for the fleet of seven mechanical 500 to 1,000 horsepower drilling rigs, capable of drilling to depths of 7,000 to 15,000 feet, and related assets, including a 4.7-acre rig storage and maintenance yard in Kenmore, North Dakota and noncompetition agreements with the two stockholders of Wolverine Drilling.

Allen Drilling Asset Acquisition. On December 15, 2004, we completed the acquisition of five drilling rigs and related equipment from Allen Drilling, based in Woodward, Oklahoma. We paid $7.2 million for the fleet of five mechanical 550 to 800 horsepower drilling rigs, capable of drilling to depths of 6,000 to 11,000 feet, and a 17-acre rig storage and maintenance yard located in Woodward, Oklahoma. We also entered into a noncompetition agreement with Mr. Dixon Allen, President of Allen Drilling.

Our principal executive offices are located at 9310 Broadway, Bldg. I, San Antonio, Texas 78217 and our phone number at that address is (210) 828-7689. Our website can be found at www.pioneerdrlg.com. Information contained in our website is not incorporated by reference into this prospectus and you should not consider information contained in our website as part of this prospectus.

The Offering

Common stock offered by Pioneer		5,000,000 shares (excluding up to 787,500 shares that may be issued by Pioneer on exercise of the underwriters' over-allotment option).
Common stock offered by the selling shareholders		5,500,000 shares (excluding up to 787,500 shares that may be sold by WEDGE on exercise of the underwriters' over-allotment option).
Common stock outstanding after the offering(1)		43,914,978 shares. If the underwriters exercise their over-allotment option in full, we will issue an additional 787,500 shares, which will result in 44,702,478 shares outstanding.
Use of proceeds		We intend to use our net proceeds from this offering to (1) fund the completion of the construction of two rigs from new and used components to be added to our fleet and (2) repay approximately $20 million of indebtedness we incurred under the acquisition facility portion of the new credit facility we entered into in October 2004. We expect to use our remaining net proceeds from this offering for general corporate purposes, which may include funding capital expenditures for rig upgrades. We will not receive any of the proceeds from the sale of common stock by the selling shareholders. See "Use of Proceeds."
Dividend policy		We have not paid or declared any dividends on any common stock and currently intend to retain earnings to fund our working capital needs and growth opportunities. Our current debt arrangements include provisions that generally prohibit us from paying dividends on our common stock.
Risk factors		Please read "Risk Factors" and other information included in this prospectus for a discussion of factors you should carefully consider before deciding to invest in shares of our common stock.
American Stock Exchange Symbol		"PDC"

(1): The number of shares of our common stock outstanding after the offering set forth above is based on 38,914,978 shares of common stock outstanding as of January 31, 2005 and includes the shares to be sold by us in this offering, excluding 787,500 shares that we may sell upon exercise of the underwriters' over-allotment option. The number of shares outstanding after the offering does not include an aggregate of 3,944,746 shares of common stock reserved for issuance under our equity compensation plans, of which 2,028,333 shares were subject to outstanding stock options as of January 31, 2005, at a weighted average exercise price of $4.85 per share.

Summary Financial Data

The following table sets forth our summary historical financial data as of and for each of the fiscal years and interim periods indicated and is derived from our historical audited consolidated financial statements for the fiscal years indicated and from our historical unaudited consolidated financial statements for the interim periods indicated. You should review this information together with "Management's Discussion and Analysis of Financial Condition and Results of Operations" beginning on page 20 of this prospectus and our historical financial statements and related notes included in this prospectus.

		Nine Months Ended December 31,						Year Ended March 31,
		2004			2003			2004			2003			2002
		(Unaudited)
		(In thousands, except per share amounts)
Consolidated Statements of Operations Information:
Contract drilling revenues		$	129,889		$	74,509		$	107,876		$	80,183		$	68,627
Costs and expenses:
	Contract drilling		100,802			61,757			88,504			70,823			46,145
	Depreciation and amortization		16,124			11,671			16,161			11,960			8,426
	General and administrative		2,911			2,027			2,773			2,233			2,855
	Bad debt expense		342			—			—			110			—

	Total operating costs and expenses		120,179			75,455			107,438			85,126			57,426

Income (loss) from operations			9,710			(946	)		438			(4,943	)		11,201

Other income (expense):
	Interest expense		(1,275	)		(2,117	)		(2,808	)		(2,699	)		(1,617	)
	Loss from early extinguishment of debt		(101	)		—			—			—			—
	Interest income		119			87			102			94			81
	Other		22			65			52			38			72
	Gain on sale of securities		—			—			—			204			—

	Total other income (expense)		(1,235	)		(1,965	)		(2,654	)		(2,363	)		(1,464	)

Income (loss) before income taxes			8,475			(2,911	)		(2,216	)		(7,306	)		9,737
Income tax (expense) benefit			(3,157	)		712			426			2,220			(3,419	)

Net earnings (loss)			5,318			(2,199	)		(1,790	)		(5,086	)		6,318
Preferred stock dividend requirement			—			—			—			—			93

Net earnings (loss) applicable to common shareholders		$	5,318		$	(2,199	)	$	(1,790	)	$	(5,086	)	$	6,225

Earnings (loss) per common share—Basic		$	0.16		$	(0.10	)	$	(0.08	)	$	(0.31	)	$	0.41

Earnings (loss) per common share—Diluted		$	0.16		$	(0.10	)	$	(0.08	)	$	(0.31	)	$	0.35

Consolidated Cash Flow Information:
Net cash provided by operating activities			17,040			5,054			4,865			14,389			11,045
Net cash provided by (used in) financing activities			44,896			(649	)		22,800			34,130			18,767
Net cash used in investing activities			(61,589	)		(22,577	)		(42,302	)		(32,899	)		(26,922	)

	December 31,				March 31,
	2004		2003		2004		2003		2002
	(Unaudited)
	(In thousands)
Consolidated Balance Sheet Information:
Total current assets	$	36,475	$	19,470	$	28,020	$	31,472	$	16,516
Total assets		198,074		120,209		143,731		119,694		83,450
Total liabilities		63,528		72,528		72,895		72,022		50,107
Total shareholders' equity		134,546		47,681		70,836		47,672		33,343

		Nine Months Ended December 31,						Year Ended March 31,
		2004			2003			2004			2003			2002
		(Unaudited)
		(In thousands)
Other Information:
Revenue days by type of contract:
	Daywork contracts		5,680			4,072			5,626			3,681			4,959
	Turnkey contracts		3,667			1,913			2,827			2,619			289
	Footage contracts		340			283			311			119			136

	Total revenue days		9,687			6,268			8,764			6,419			5,384

Contract drilling revenue per revenue day		$	13,409		$	11,887		$	12,309		$	12,492		$	12,747
Contract drilling cost per revenue day			10,406			9,853			10,099			11,033			8,571
Rig utilization rates			96	%		87	%		88	%		79	%		82	%
Number of rigs at end of period			49			28			35			24			20

RISK FACTORS

Investment in our common stock involves a high degree of risk. You should carefully consider the following risk factors as well as other information in this prospectus before making your investment decision. The risks described below are not the only risks we face. Additional risks that we do not yet know of or that we currently think are immaterial may also impair our business operations. If any of the events or circumstances described below actually occurs, our business, financial condition or results of operations could be materially adversely affected. In such case, the trading price of our common stock could decline, and you may lose all or part of your investment.

Risks Relating to the Oil and Gas Industry

We derive all our revenues from companies in the oil and gas exploration and production industry, a historically cyclical industry with levels of activity that are significantly affected by the levels and volatility of oil and gas prices.

As a provider of contract land drilling services, our business depends on the level of drilling activity by oil and gas exploration and production companies operating in the geographic markets where we operate. The oil and gas exploration and production industry is a historically cyclical industry characterized by significant changes in the levels of exploration and development activities. Oil and gas prices, and market expectations of potential changes in those prices, significantly affect the levels of those activities. Worldwide political, economic and military events have contributed to oil and gas price volatility and are likely to continue to do so in the future. Any prolonged reduction in the overall level of exploration and development activities, whether resulting from changes in oil and gas prices or otherwise, can materially and adversely affect us in many ways by negatively impacting:

•: our revenues, cash flows and profitability;
•: the fair market value of our rig fleet;
•: our ability to maintain or increase our borrowing capacity;
•: our ability to obtain additional capital to finance our business and make acquisitions, and the cost of that capital; and
•: our ability to retain skilled rig personnel whom we would need in the event of an upturn in the demand for our services.

Depending on the market prices of oil and gas, oil and gas exploration and production companies may cancel or curtail their drilling programs, thereby reducing demand for our services. Oil and gas prices have been volatile historically and, we believe, will continue to be so in the future. Many factors beyond our control affect oil and gas prices, including:

•: weather conditions in the United States and elsewhere;
•: economic conditions in the United States and elsewhere;
•: actions by OPEC, the Organization of Petroleum Exporting Countries;
•: political instability in the Middle East and other major oil and gas producing regions;
•: governmental regulations, both domestic and foreign;
•: domestic and foreign tax policy;
•: the pace adopted by foreign governments for the exploration, development and production of their national reserves;
•: the price of foreign imports of oil and gas;

•: the cost of exploring for, producing and delivering oil and gas;
•: the discovery rate of new oil and gas reserves;
•: the rate of decline of existing and new oil and gas reserves;
•: available pipeline and other oil and gas transportation capacity;
•: the ability of oil and gas companies to raise capital; and
•: the overall supply and demand for oil and gas.

Risks Relating to Our Business

We have a history of losses and may experience losses in the future.

We have a history of losses. We incurred net losses of $1.8 million, $5.1 million and $0.4 million 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. Our current utilization rates and dayrates may decline and we may experience losses in the future.

Our acquisition strategy exposes us to various risks, including those relating to difficulties in identifying suitable acquisition opportunities and integrating businesses, assets and personnel, as well as difficulties in obtaining financing for targeted acquisitions and the potential for increased leverage or debt service requirements.

As a key component of our business strategy, we have pursued and intend to continue to pursue acquisitions of complementary assets and businesses. For example, since March 31, 2003, our rig fleet increased from 24 to 49 drilling rigs, primarily as a result of acquisitions. We may be unable to continue to identify additional suitable acquisition opportunities, negotiate acceptable terms or successfully acquire identified targets. In addition, the success of any completed acquisition will depend in part on our ability to integrate effectively the acquired business into our operations. The process of integrating an acquired business may involve unforeseen difficulties and may require a disproportionate amount of management attention and financial and other resources. Our failure to achieve consolidation savings, to incorporate the acquired businesses and assets into our existing operations successfully or to minimize any unforeseen operational difficulties could have a material adverse effect on our financial condition and results of operations.

In addition, we may not have sufficient capital resources to complete additional acquisitions. Historically, we have funded the growth of our rig fleet through a combination of debt and equity financing. We may incur substantial additional indebtedness to finance future acquisitions and also may issue equity securities or convertible securities in connection with such acquisitions. Debt service requirements could represent a significant burden on our results of operations and financial condition and the issuance of additional equity could be dilutive to our existing stockholders. Furthermore, we may not be able to obtain additional financing on satisfactory terms.

We operate in a highly competitive, fragmented industry in which price competition is intense.

We encounter substantial competition from other drilling contractors. Our primary market areas are highly fragmented and competitive. The fact that drilling rigs are mobile and can be moved from one market to another in response to market conditions heightens the competition in the industry.

The drilling contracts we compete for are usually awarded on the basis of competitive bids. We believe pricing and rig availability are the primary factors our potential customers consider in

determining which drilling contractor to select. In addition, we believe the following factors are also important:

•: the type and condition of each of the competing drilling rigs;
•: the mobility and efficiency of the rigs;
•: the quality of service and experience of the rig crews;
•: the safety records of the rigs;
•: the offering of ancillary services; and
•: the ability to provide drilling equipment adaptable to, and personnel familiar with, new technologies and drilling techniques.

While we must be competitive in our pricing, our competitive strategy generally emphasizes the quality of our equipment, the safety record of our rigs and the quality of service and experience of our rig crews to differentiate us from our competitors. This strategy is less effective as lower demand for drilling services intensifies price competition and makes it more difficult for us to compete on the basis of factors other than price. In all of the markets in which we compete, an over-supply of rigs can cause greater price competition.

Contract drilling companies compete primarily on a regional basis, and the intensity of competition may vary significantly from region to region at any particular time. If demand for drilling services improves in a region where we operate, our competitors might respond by moving in suitable rigs from other regions. An influx of rigs from other regions could rapidly intensify competition and reduce profitability and make any improvement in demand for drilling rigs short-lived.

We face competition from many competitors with greater resources which may harm our ability to compete.

Many of our competitors have greater financial, technical and other resources than we do. Their greater capabilities in these areas may enable them to:

•: better withstand industry downturns;
•: compete more effectively on the basis of price and technology;
•: retain skilled rig personnel; and
•: build new rigs or acquire and refurbish existing rigs so as to be able to place rigs into service more quickly than us in periods of high drilling demand.

Unexpected cost overruns on our turnkey drilling jobs and our footage contracts could adversely affect our financial position and our results of operations.

We have historically derived a significant portion of our revenues from turnkey drilling contracts and we expect that they will represent a significant component of our future revenues. The occurrence of uninsured or under-insured losses or operating cost overruns on our turnkey jobs could have a material adverse effect on our financial position and results of operations. Under a typical turnkey drilling contract, we agree to drill a well for our customer to a specified depth and under specified conditions for a fixed price. 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 paid by our customer only after we have performed the terms of the drilling contract in full. For these reasons, the risk to us under a turnkey drilling contract is substantially greater than for a well drilled on a daywork basis, because we must

assume most of the risks associated with drilling operations that the operator generally assumes under a daywork contract, including the risks of blowout, loss of hole, stuck drill pipe, machinery breakdowns, abnormal drilling conditions and risks associated with subcontractors' services, supplies, cost escalations and personnel. Similar to our 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.

Although we attempt to obtain insurance coverage to reduce certain of the risks inherent in our turnkey and footage drilling operations, adequate coverage may be unavailable in the future and we might have to bear the full cost of such risks, which could have an adverse effect on our financial condition and results of operation.

Our operations involve operating hazards, which if not insured or indemnified against, could adversely affect our results of operations and financial condition.

Our operations are subject to the many hazards inherent in the contract land drilling business, including the risks of:

•: blowouts;
•: fires and explosions;
•: loss of well control;
•: collapse of the borehole;
•: lost or stuck drill strings; and
•: damage or loss from natural disasters.

Any of these hazards can result in substantial liabilities or losses to us from, among other things:

•: suspension of drilling operations;
•: damage to, or destruction of, our property and equipment and that of others;
•: personal injury and loss of life;
•: damage to producing or potentially productive oil and gas formations through which we drill; and
•: environmental damage.

We seek to protect ourselves from some but not all operating hazards through insurance coverage. However, some risks are either not insurable or insurance is available only at rates that we consider uneconomical. Those risks include pollution liability in excess of relatively low limits. Depending on competitive conditions and other factors, we attempt to obtain contractual protection against uninsured operating risks from our customers. However, customers who provide contractual indemnification protection may not in all cases maintain adequate insurance to support their indemnification obligations. Our insurance or indemnification arrangements may not adequately protect us against liability or loss from all the hazards of our operations. The occurrence of a significant event that we have not fully insured or indemnified against or the failure of a customer to meet its indemnification obligations to us could materially and adversely affect our results of operations and financial condition. Furthermore, we may be unable to maintain adequate insurance in the future at rates we consider reasonable.

We face increased exposure to operating difficulties because we primarily focus on drilling for natural gas.

Most of our drilling contracts are with exploration and production companies in search of natural gas. Drilling on land for natural gas generally occurs at deeper drilling depths than drilling for oil. Although deep-depth drilling exposes us to risks similar to risks encountered in shallow-depth drilling, the magnitude of the risk for deep-depth drilling is greater because of the higher costs and greater complexities involved in drilling deep wells. We generally do not insure risks related to operating difficulties other than blowouts. If we do not adequately insure the increased risk from blowouts or if our contractual indemnification rights are insufficient or unfulfilled, our profitability and other results of operation and our financial condition could be adversely affected in the event we encounter blowouts or other significant operating difficulties while drilling at deeper depths.

Our current primary focus on drilling for natural gas could place us at a competitive disadvantage if we changed our primary focus to drilling for oil.

Our rig fleet consists of rigs capable of drilling on land at drilling depths of 6,000 to 18,000 feet because most of our contracts are with customers drilling in search of natural gas, which generally occurs at deeper drilling depths than drilling in search of oil, which often occurs at drilling depths less than 6,000 feet. Generally, larger drilling rigs capable of deep drilling generally incur higher mobilization costs than smaller drilling rigs drilling at shallower depths. If our primary focus shifts from drilling for customers in search of natural gas to drilling for customers in search of oil, the majority of our rig fleet would be disadvantaged in competing for new oil drilling projects as compared to competitors that primarily use shallower drilling depth rigs when drilling in search of oil.

Our operations are subject to various laws and governmental regulations that could restrict our future operations and increase our operating costs.

Many aspects of our operations are subject to various federal, state and local laws and governmental regulations, including laws and regulations governing:

•: environmental quality;
•: pollution control;
•: remediation of contamination;
•: preservation of natural resources; and
•: worker safety.

Our operations are subject to stringent laws and regulations relating to containment, disposal and controlling the discharge of hazardous oilfield waste and other non hazardous waste material into the environment, requiring removal and cleanup under certain circumstances, or otherwise relating to the protection of the environment. In addition, our operations are often conducted in or near ecologically sensitive areas, such as wetlands, which are subject to special protective measures and which may expose us to additional operating costs and liabilities for accidental discharges of oil, gas, drilling fluids or contaminated water or for noncompliance with other aspects of applicable laws. We are also subject to the requirements of the federal Occupational Safety and Health Act ("OSHA") and comparable state statutes. The OSHA hazard communication standard, the Environmental Protection Agency "community right-to-know" regulations under Title III of the Federal Superfund Amendment and Reauthorization Act and comparable state statutes require us to organize and report information about the hazardous materials we use in our operations to employees, state and local government authorities and local citizens.

Environmental laws and regulations are complex and subject to frequent change. In some cases, they can impose liability for the entire cost of cleanup on any responsible party without regard to negligence or fault and can impose liability on us for the conduct of others or conditions others have caused, or for our acts that complied with all applicable requirements when we performed them. We may also be exposed to environmental or other liabilities originating from businesses and assets which we purchased from others. Our compliance with amended, new or more stringent requirements, stricter interpretations of existing requirements or the future discovery of contamination may require us to make material expenditures or subject us to liabilities that we currently do not anticipate.

In addition, our business depends on the demand for land drilling services from the oil and gas industry and, therefore, is affected by tax, environmental and other laws relating to the oil and gas industry generally, by changes in those laws and by changes in related administrative regulations. It is also possible that these laws and regulations may in the future add significantly to our operating costs or those of our customers or otherwise directly or indirectly affect our operations.

We could be adversely affected if shortages of equipment, supplies or personnel occur.

From time to time there have been shortages of drilling equipment and supplies during periods of high demand which we believe could reoccur. Shortages could result in increased prices for drilling equipment or supplies that we may be unable to pass on to customers. In addition, during periods of shortages, the delivery times for equipment and supplies can be substantially longer. Any significant delays in our obtaining drilling equipment or supplies could limit drilling operations and jeopardize our relations with customers. In addition, shortages of drilling equipment or supplies could delay and adversely affect our ability to obtain new contracts for our rigs, which could have a material adverse effect on our financial condition and results of operations.

Our operations require the services of employees having the technical training and experience necessary to obtain the proper operational results. As a result, our operations depend, to a considerable extent, on the continuing availability of such personnel. Shortages of qualified personnel are occurring in our industry. If we should suffer any material loss of personnel to competitors or be unable to employ additional or replacement personnel with the requisite level of training and experience to adequately operate our equipment, our operations could be materially and adversely affected. A significant increase in the wages paid by other employers could result in a reduction in our workforce, increases in wage rates, or both. The occurrence of either of these events for a significant period of time could have a material and adverse effect on our financial condition and results of operations.

If our independent auditor is unable to provide us with an unqualified attestation report as to the adequacy of our internal control over financial reporting as required by Section 404 of the Sarbanes-Oxley Act of 2002, investors could lose confidence in the reliability of our financial statements, which could result in a decrease in the value of our common stock.

Under Section 404 of the Sarbanes-Oxley Act of 2002, we will be required to include in each of our future annual reports on Form 10-K a report containing our management's assessment of the effectiveness of our internal control over financial reporting and a related attestation of our independent auditors. This requirement will first apply to our annual report on Form 10-K for the fiscal year ending March 31, 2005. We are currently undertaking a comprehensive effort in preparation for compliance with Section 404. This effort includes the documentation, testing and review of our internal controls under the direction of our management. We have been making various changes to our internal control over financial reporting as a result of our review efforts. Although we have not identified any material weaknesses in our internal control over financial reporting, as defined by the Public Company Accounting Oversight Board, due to the number of controls to be examined, the complexity of the project, as well as the subjectivity involved in determining effectiveness of controls,

we cannot be certain that all our controls will be considered effective. In addition, the guidelines for the evaluation and attestation of internal control over financial reporting have only recently been finalized, and the evaluation and attestation processes are new and untested. Therefore, we can give no assurances that our internal control over financial reporting will satisfy the new regulatory requirements. If our independent auditor is unable to provide us with an unqualified attestation report on a timely basis as required by Section 404, investors could lose confidence in the reliability of our financial statements, which could result in a decrease in the value of our common stock.

Risk Relating to Our Capitalization and Organizational Documents

Our largest shareholders and our management control a significant percentage of our common stock, and their interests may conflict with those of our other shareholders.

As of January 31, 2005, our largest shareholder, WEDGE, beneficially owned 19.71% of our outstanding common stock and, together with Chesapeake Energy Corporation ("Chesapeake") and our officers and directors as a group, beneficially owned a total of approximately 41.47% of our outstanding common stock. WEDGE is selling 5,000,000 shares of our common stock in this offering (5,787,500 shares if the underwriters exercise their over-allotment option in full). The following table shows, as of January 31, 2005, the beneficial ownership of these persons:

Shareholder	Shares	Percent
WEDGE(1)	7,668,206	19.71	%
Chesapeake	6,536,136	16.80	%
All executive officers and directors as a group(2)	2,198,421	5.56	%

(1): Does not reflect the sale by WEDGE of shares of our common stock pursuant to this offering.
(2): Includes options to purchase 633,668 shares of common stock which are exercisable within 60 days of January 31, 2005.

In some circumstances, if WEDGE were to act in concert with these or other shareholders, they would be able to exercise substantial control over our affairs. WEDGE currently has the right to nominate one person for election to our board of directors, which as of the date of this prospectus consists of seven members. The interests of WEDGE and these other persons with respect to matters potentially or actually involving or affecting us, such as future acquisitions, financings and other corporate opportunities and attempts to acquire us, may conflict with the interests of our other shareholders.

Limited trading volume of our common stock may contribute to its price volatility.

Our common stock is traded on the American Stock Exchange. During the three-month period ended December 31, 2004, the average daily trading volume of our common stock as reported by the American Stock Exchange was 144,531 shares. There can be no assurance that a more active trading market in our common stock will develop as a result of this offering. As a result, relatively small trades may have a significant impact on the price of our common stock and, therefore, may contribute to the price volatility of our common stock. As a result, our common stock may be subject to greater price volatility than the stock market as a whole and comparable securities of other contract drilling service providers.

The market price of our common stock has been, and may continue to be, volatile. For example, from April 1, 2004 through January 31, 2005, the trading price of our common stock has ranged from $5.60 to $10.50 per share.

Because of the limited trading market of our common stock and the price volatility of our common stock, you may be unable to sell shares of common stock when you desire or at a price you desire. The inability to sell your shares in a declining market because of such illiquidity or at a price you desire may substantially increase your risk of loss.

The market price of our common stock could decline following sales of substantial amounts of our common stock in the public markets.

In addition to the 5,000,000 shares to be sold by WEDGE in this offering (5,787,500 shares if the underwriters exercise their over-allotment option in full), our largest shareholders, WEDGE and Chesapeake, could sell a substantial number of shares of our common stock in the public market under exemptions afforded to affiliates under Rule 144 of the Securities Act of 1933, as amended, under a resale registration statement or over the American Stock Exchange. Such sales by our largest shareholders, sales by other securityholders or the perception that such sales might occur could have a material adverse effect on the price of our common stock or could impair our ability to obtain capital through an offering of equity securities.

We may issue preferred stock whose terms could adversely affect the voting power or value of our common stock.

Our articles of incorporation authorize us to issue, without the approval of our shareholders, one or more classes or series of preferred stock having such designations, preferences, limitations and relative rights, including preferences over our common stock respecting dividends and distributions, as our board of directors may determine. The terms of one or more classes or series of preferred stock could adversely impact the voting power or value of our common stock. For example, we might grant holders of preferred stock the right to elect some number of our directors in all events or on the happening of specified events or the right to veto specified transactions. Similarly, the repurchase or redemption rights or liquidation preferences we might assign to holders of preferred stock could affect the residual value of the common stock.

Provisions in our organizational documents could delay or prevent a change in control of our company, even if that change would be beneficial to our shareholders.

The existence of some provisions in our organizational documents could delay or prevent a change in control of our company, even if that change would be beneficial to our shareholders. Our articles of incorporation and bylaws contain provisions that may make acquiring control of our company difficult, including:

•: provisions regulating the ability of our shareholders to bring matters for action at annual meetings of our shareholders;
•: limitations on the ability of our shareholders to call a special meeting and act by written consent;
•: provisions dividing our board of directors into three classes elected for staggered terms; and
•: the authorization given to our board of directors to issue and set the terms of preferred stock.

FORWARD-LOOKING STATEMENTS

We are including the following discussion to inform you generally of some of the risks and uncertainties that can affect our company and to take advantage of the "safe harbor" protection for forward-looking statements that applicable federal securities law affords.

This prospectus contains forward-looking statements, including statements that include projections and estimates concerning the timing and success of specific projects and our future backlog, revenues, income and capital spending. Forward-looking statements are generally accompanied by words such as "estimate," "project," "predict," "believe," "expect," "anticipate," "plan," "intend," "seek," "will," "should," "goal" or other words that convey the uncertainty of future events or outcomes. These forward-looking statements speak only as of the date of this prospectus. We disclaim any obligation to update these statements, and we caution you not to rely on them unduly. We have based these forward-looking statements on our current expectations and assumptions about future events. While our management considers these expectations and assumptions to be reasonable, they are inherently subject to significant business, economic, competitive, regulatory and other risks, contingencies and uncertainties, most of which are difficult to predict and many of which are beyond our control. These risks, contingencies and uncertainties relate to, among other matters, the following:

•: general economic and business conditions and industry trends;
•: the continued strength of the contract land drilling industry in the geographic areas where we operate;
•: levels and volatility of oil an gas prices;
•: decisions about onshore exploration and development projects to be made by oil and gas companies;
•: the highly competitive nature of our businesses;
•: the success or failure of our acquisition strategy, including our ability to finance acquisitions and manage growth;
•: 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 believe the items we have outlined above are important factors that could cause our actual results to differ materially from those expressed in a forward-looking statement contained in this prospectus. We have discussed many of these factors in more detail elsewhere in this prospectus. These factors are not necessarily all the important factors that could affect us. Unpredictable or unknown factors we have not discussed in this prospectus 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. We advise you that you 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. Also, please read the "Risk Factors" section of this prospectus.

USE OF PROCEEDS

We estimate that we will receive net proceeds of $ million from our sale of 5,000,000 shares of common stock, after deducting the underwriting discount and the estimated expenses of this offering. See "Underwriting—Commissions and Expenses." If the underwriters' over-allotment option to purchase an additional 787,500 shares from us is exercised in full, we estimate that our net proceeds will be $ million. We will not receive any of the proceeds from the sale of our common stock by the selling shareholders.

We intend to use our net proceeds from this offering to (1) fund the completion of the construction of two rigs from new and used components to be added to our fleet and (2) repay approximately $20 million of indebtedness we incurred under the acquisition facility portion of the new credit facility we entered into in October 2004. We expect to use our remaining net proceeds from this offering for general corporate purposes, which may include funding capital expenditures for rig upgrades.

We expect the total amount to be spent on completion of construction of the two rigs to be added to our fleet to be approximately $12.2 million. We anticipate completing construction of these rigs in May and June 2005.

Of the indebtedness outstanding under the acquisition facility, we incurred:

•: $28.0 million in November 2004 to fund our acquisition of the assets of Wolverine Drilling and payment of the cash consideration under two related noncompetition agreements; and
•: $7.2 million in December 2004 to fund our acquisition of the assets of Allen Drilling.

The indebtedness we incurred under the acquisition facility in November and December 2004 is due in monthly installments, which commenced on the first business day of January 2005, based on a 72-month amortization schedule, with all remaining unpaid principal being due on December 1, 2007. All the indebtedness under the acquisition facility bears interest at Frost National Bank's prime rate (5.25% as of January 31, 2005). For additional information regarding our new credit facility, see "Management's Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources."

PRICE RANGE OF COMMON STOCK

As of January 31, 2005, 38,914,978 shares of our common stock were outstanding, held by approximately 590 shareholders of record. The number of record holders does not necessarily bear any relationship to the number of beneficial owners of our common stock.

Our common stock trades on The American Stock Exchange under the symbol "PDC." The following table sets forth, for each of the periods indicated, the high and low sales prices per share on The American Stock Exchange:

		Price
		High		Low
Fiscal Year Ending March 31, 2005
	First Quarter	$	7.99	$	5.60
	Second Quarter		8.90		6.75
	Third Quarter		10.50		7.63
	Fourth Quarter (through February 4, 2005)		10.75		9.05
Fiscal Year Ended March 31, 2004:
	First Quarter	$	5.24	$	3.57
	Second Quarter		4.99		3.65
	Third Quarter		5.20		3.30
	Fourth Quarter		7.35		4.75
Fiscal Year Ended March 31, 2003:
	First Quarter	$	5.05	$	4.00
	Second Quarter		4.20		2.85
	Third Quarter		3.85		2.86
	Fourth Quarter		3.64		3.10

The last reported sale price for our common stock on the American Stock Exchange on February 4, 2005 was $10.62 per share.

DIVIDEND POLICY

We have not paid or declared any dividends on our common stock since our inception and currently intend to retain earnings to fund our working capital needs and growth opportunities. Any future dividends will be at the discretion of our board of directors after taking into account various factors it deems relevant, including our financial condition and performance, cash needs, income tax consequences and the restrictions Texas and other applicable laws and our debt arrangements then impose. Our current debt arrangements include provisions that (1) generally prohibit us from paying dividends on our common stock and (2) limit our subsidiaries' ability to pay dividends or make loans or advances to us.

CAPITALIZATION

The following table sets forth our cash and cash equivalents, debt and total capitalization as of December 31, 2004 on an actual basis, and as adjusted for (1) our sale of 5,000,000 shares of common stock in this offering, assuming the underwriters' over-allotment option is not exercised and (2) the application of the estimated (based on the current market prices of our common stock) net proceeds from this offering after deducting the underwriting discount and commissions and our estimated offering expenses. You should read this table together with "Management's Discussion and Analysis of Financial Condition and Results of Operations" beginning on page 20 of this prospectus and the historical consolidated financial statements and related notes included in this prospectus.

			As of December 31, 2004
			Actual			As Adjusted
			(Unaudited)
			(In thousands)
Cash and cash equivalents			$	6,713		$

Notes payable and current installments of long term debt and capital lease obligations				7,037
Long term debt and capital lease obligations, less current installments				29,380
Shareholders' equity:
	Common stock			3,851
	Additional paid-in capital			139,395
	Accumulated deficit			(8,700	)

	Total shareholders' equity			134,546

		Total Capitalization		170,963

SELECTED FINANCIAL DATA

The following table sets forth our selected financial data as of and for each of the fiscal years and interim periods indicated and is derived from our historical audited consolidated financial statements for the fiscal years indicated and from our historical unaudited consolidated financial statements for the interim periods indicated. You should review this information in conjunction with "Management's Discussion and Analysis of Financial Condition and Results of Operations" beginning on page 20 of this prospectus and our historical financial statements and related notes included in this prospectus.

	As of and for the Nine Months Ended December 31,					As of and for the Year Ended March 31,
	2004		2003			2004			2003			2002		2001		2000
	(Unaudited)					(In thousands, except per share amounts)
Contract drilling revenues	$	129,889	$	74,509		$	107,876		$	80,183		$	68,627	$	50,345	$	19,391
Income (loss) from operations		9,710		(946	)		438			(4,943	)		11,201		3,803		108
Income (loss) before income taxes		8,475		(2,911	)		(2,216	)		(7,305	)		9,737		3,838		(65	)
Preferred dividends		—		—			—			—			93		275		304
Net earnings (loss) applicable to common shareholders		5,318		(2,199	)		(1,790	)		(5,086	)		6,225		2,428		(384	)
Earnings (loss) per common share—basic		0.16		(0.10	)		(0.08	)		(0.31	)		0.41		0.22		(0.06	)
Earnings (loss) per common share—diluted		0.16		(0.10	)		(0.08	)		(0.31	)		0.35		0.19		(0.06	)
Long-term debt and capital lease obligations, excluding current installments		29,380		44,023			44,892			45,855			26,119		10,056		267
Shareholders' equity		134,546		47,681			70,836			47,672			33,343		17,827		6,783
Total assets		198,074		120,209			143,731			119,694			83,450		56,493		15,670
Capital expenditures		62,339		25,059			44,845			33,589			27,597		41,628		5,069

Refer to Note 2 of our historical consolidated financial statements for information on acquisitions and the pro forma financial statements (and notes thereto) reflecting our acquisitions of the assets of Wolverine Drilling and Allen Drilling contained in this prospectus.

MANAGEMENT'S DISCUSSION AND ANALYSIS
OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Statements we make in the following discussion which express a belief, expectation or intention, as well as those that are not historical fact, are forward-looking statements that are subject to risks, uncertainties and assumptions. Our actual results, performance or achievements, or industry results, could differ materially from those we express in the following discussion as a result of a variety of factors, including general economic and business conditions and industry trends, the continued strength or weakness of the contract land drilling industry in the geographic areas in which we operate, decisions about onshore exploration and development projects to be made by oil and gas companies, the highly competitive nature of our business, our future financial performance, including availability, terms and deployment of capital, the continued availability of qualified personnel, and changes in, or our failure or inability to comply with, government regulations, including those relating to the environment.

Company Overview

Pioneer provides contract land drilling services to independent and major oil and gas exploration and production companies. In addition to our drilling rigs, we provide the drilling crews and most of the ancillary equipment needed to operate our drilling rigs. We have focused our operations in selected oil and natural gas production regions in the United States. Our company was incorporated in 1979 as the successor to a business that had been operating since 1968. We conduct our operations through our principal operating subsidiary, Pioneer Drilling Services, Ltd. We are an oil and gas services company. We do not invest in oil and natural gas properties. The drilling activity of our customers is highly dependent on the current price of oil and natural gas.

Our business strategy is to own and operate a high-quality fleet of land drilling rigs in active drilling markets, and position ourselves to maximize rig utilization and dayrates and to enhance shareholder value. We intend to continue making additions to our drilling fleet, either through acquisitions of businesses or selected assets or through the construction of refurbished drilling rigs.

Since September 1999, we have significantly expanded our fleet of drilling rigs through acquisitions and the construction of new and refurbished rigs. As of December 31, 2004, our rig fleet consisted of 49 land drilling rigs that drill in depth ranges between 6,000 and 18,000 feet. As of January 31, 2005, we had 15 rigs operating in South Texas, 17 in East Texas, four in North Texas, five in Western Oklahoma and eight in the Rocky Mountains. We actively market all of these rigs. Subject to obtaining satisfactory financing, we anticipate continued growth of our rig fleet in fiscal 2006. We are currently constructing a 1,000-horse power mechanical rig from new and used components.

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 we offer generally depend on the complexity and risk of operations, the on-site drilling conditions, the type of equipment used and the anticipated duration of the work to be performed. Generally, our contracts provide for the drilling of a single well and typically permit the customer to terminate on short notice.

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

For the nine months ended December 31, 2004 and 2003 and for the three years ended March 31, 2004, our rig utilization, revenue days and number of rigs were as follows:

	Nine Months Ended December 31,				Year Ended March 31,
	2004		2003		2004		2003		2002
Utilization Rates	96	%	87	%	88	%	79	%	82	%
Revenue Days	9,687		6,268		8,764		6,419		5,384
Number of rigs (at end of period)	49		28		35		24		20

The reasons for the increase in the number of revenue days in 2004 over 2003 and 2002 are the increase in size of our rig fleet and the improvement in our overall rig utilization rate due to improved market conditions. The reasons for the increase in the number of revenue days in the first nine months of 2004 over the first nine months of 2003 are the increase in size of our rig fleet from 28 at December 31, 2003 to 49 at December 31, 2004 and the improvement in our overall rig utilization rate. For the remainder of fiscal 2005 and through fiscal 2006, we anticipate continued growth in revenue days and maintaining relatively high utilization rates.

In addition to high commodity prices, we attribute our relatively high utilization rates to a strong sales effort, quality equipment, good field and operations personnel, a disciplined safety approach, and our generally successful performance of turnkey operations. Turnkey contracts currently account for approximately 25% of our contracts. Turnkey contracts provide us with the opportunity to keep our rigs working in periods of lower demand and improve our profitability, but at an increased risk. As was the case for several turnkey contracts under which we performed during the nine months ended December 31, 2004, a turnkey contract may not be profitable if it cannot be completed successfully without unanticipated complications.

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

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

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

			Year Ended March 31,
	Nine Months Ended December 31, 2004		Year Ended March 31,
	Nine Months Ended December 31, 2004		2004		2003		2002		2001		2000
Oil (West Texas Intermediate)	$	43.51	$	31.47	$	29.27	$	24.31	$	30.40	$	23.23
Gas (Henry Hub)	$	5.99	$	5.27	$	4.24	$	2.96	$	5.27	$	2.46
U.S. Land Rig Count		1,097		964		723		912		841		550

On January 31, 2005, the spot price for West Texas Intermediate crude oil was $48.20 and the spot price for Henry Hub natural gas was $6.16. For the week of January 28, 2005, the Baker Hughes land rig count was 1,130, a 16% increase from 973 as of the corresponding week in 2004.

During fiscal 2004, 2003 and 2002 and the first nine months of fiscal 2005, substantially all the wells we drilled for our customers were drilled in search of natural gas because of the depth capacity of our rigs and the gas rich areas in which we operate. Although we have recently diversified our operations somewhat with the November 2004 acquisition of seven drilling rigs from Wolverine Drilling, with five of those rigs employed in search of oil in the Williston Basin of the Rocky Mountains, our customers remain primarily focused on drilling for natural gas. Natural gas reserves are typically found in deeper geological formations and generally require premium equipment and quality crews to drill the wells.

Critical Accounting Policies and Estimates

Revenue and Cost Recognition—We earn our revenues by drilling oil and gas wells for our customers under daywork, turnkey or footage contracts, which usually provide for the drilling of a single well. We recognize revenues on daywork contracts for the days completed based on the dayrate each contract specifies. We recognize revenues from our turnkey and footage contracts on the percentage-of-completion method for the days completed, based on the contract amount divided by our estimate of the number of days to complete each contract. Contract drilling in progress represents revenues we have recognized in excess of amounts billed on contracts in progress. Individual contracts are usually completed in less than 60 days. The risks to us under a turnkey contract, and to a lesser extent under footage contracts, are substantially greater than on a contract drilled on a daywork basis.

This is primarily because, under a turnkey contract, we assume most of the risks associated with drilling operations generally assumed by the operator in a daywork contract, including the risks of blowout, loss of hole, stuck drill pipe, machinery breakdowns and abnormal drilling conditions, as well as risks associated with subcontractors' services, supplies, cost escalations and personnel operations.

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

If a customer defaults on its payment obligation to us under a turnkey or footage contract, we would need to rely on applicable law to enforce our lien rights, because our turnkey and footage 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 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 March 31, 2004, would have resulted in a corresponding increase in our net loss of approximately $962,000 for our fiscal year ended March 31, 2004. A one percent write-down in the cost of our drilling equipment, at December 31, 2004, would have resulted in a corresponding decrease in our net earnings of approximately $1,324,000 for the nine months ended December 31, 2004.

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

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

We receive payment under turnkey and footage contracts when we deliver to our customer a well completed to the depth specified in the contract, unless the customer authorizes us to drill to a shallower depth. Since 1995, when current management joined our company, we have completed all our turnkey or footage contracts. Although our initial cost estimates for turnkey and footage contracts do not include cost estimates for risks such as stuck drill pipe or loss of circulation, we believe that our experienced management team, our knowledge of geologic formations in our areas of operations, the condition of our drilling equipment and our experienced crews enable us to make reasonably dependable cost estimates and complete contracts according to our drilling plan. While we do bear the risk of loss for cost overruns and other events that are not specifically provided for in our initial cost estimates, our pricing of turnkey and footage contracts takes such risks into consideration. When we encounter, during the course of our drilling operations, conditions unforeseen in the preparation of our original cost estimate, we immediately increase our cost estimate for the additional costs to complete the contracts. If we anticipate a loss on a contract in progress at the end of a reporting period due to a change in our cost estimate, we immediately accrue the entire amount of the estimated loss including all costs that are included in our revised estimated cost to complete that contract in our consolidated statement of operations for that reporting period. During fiscal 2004, we experienced losses on eight of the 105 turnkey and footage contracts completed, with losses exceeding $25,000 on six contracts, including two contracts with losses exceeding $100,000. During the nine months ended December 31, 2004, we experienced losses on 14 of the 128 turnkey and footage contracts completed, with losses exceeding $25,000 on nine contracts and losses exceeding $100,000 on four contracts. We are more likely to encounter losses on turnkey and footage contracts in years in which revenue rates are lower for all types of contracts. During periods of reduced demand for drilling rigs, our overall profitability on turnkey and footage contracts has historically exceeded our profitability on daywork contracts.

Revenues and costs during a reporting period could be affected for contracts in progress at the end of a reporting period which have not been completed before our financial statements for that period are released. All but one of our turnkey contracts in progress at March 31, 2004 were completed prior to the release of our fiscal 2004 financial statements included in this prospectus. All our turnkey and footage contracts in progress at December 31, 2004 were completed prior to the release of the most recent interim-period financial statements included in this prospectus. At March 31, 2004, our contract drilling in progress totaled approximately $9,131,000. Of that amount accrued, turnkey and footage contract revenues were approximately $7,683,000. The remaining balance of approximately $1,448,000 relates to the revenue recognized but not yet billed on daywork contracts in progress at March 31, 2004. At December 31, 2004, our contract drilling in progress totaled approximately

$7,351,000, of which turnkey and footage contract revenues were approximately $2,547,000 and daywork contract revenues were approximately $4,804,000.

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 $452,000 at December 31, 2004, an increase of $342,000 from $110,000 at March 31, 2004.

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

Our other accrued expenses as of December 31, 2004 and March 31, 2004 include accruals of approximately $1,232,000 and $680,000, respectively, for costs incurred under the self-insurance portion of our health insurance and under our workers' compensation insurance. We have a deductible of (1) $100,000 per covered individual per year under the health insurance and (2) $250,000 per occurrence under our workers' compensation insurance, except in North Dakota where the deductible is $100,000. We accrue for these costs as claims are incurred based on cost estimates established for each claim by the insurance companies providing the administrative services for processing the claims, including an estimate for incurred but not reported claims, estimates for claims paid directly by us, our estimate of the administrative costs associated with these claims and our historical experience with these types of claims.

Liquidity and Capital Resources

Sources of Capital Resources

Our rig fleet has grown from six rigs in September 1999 to 49 rigs as of December 31, 2004. We have financed this growth with a combination of debt and equity financing. At March 31, 2004, our total debt to total capitalization was approximately 41% (21% at December 31, 2004). We plan to continue to grow our rig fleet. We believe that our growth will require the use of equity financing, in addition to debt. 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 February 20, 2004, we sold 4,400,000 shares of our common stock at $5.40 per share in a private placement to accredited investors for $23,760,000 in proceeds, before related offering expenses.

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

shares of our common stock at approximately $6.61 per share, net of underwriters' commissions, pursuant to the underwriters' exercise of an over-allotment option granted in connection with that public offering.

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

Uses of Capital Resources

In May 2003, we added one refurbished 18,000-foot SCR land drilling rig at a cost of approximately $7,300,000. On August 1, 2003, we purchased two land drilling rigs, associated spare parts and equipment and vehicles from Texas Interstate Drilling Company, L. P. for $2,500,000 in cash and the issuance of 477,000 shares of our common stock valued at $4.45 per share. On August 26, 2003, we purchased a 14,000-foot mechanical rig for $2,925,661 in cash. After accepting delivery of the rig, we spent approximately $2,400,000 upgrading the rig before placing it in service. On December 15, 2003, we acquired a rig for approximately $3,770,000 that we had previously been leasing.

On March 2, 2004, we acquired 23 used rig hauling trucks and associated trailers and equipment from A&R Trejo Trucking for $1,200,000. On March 4, 2004, we acquired a seven-rig drilling fleet from Sawyer Drilling & Service, Inc. for $12,000,000. On March 12, 2004, we acquired one drilling rig from SEDCO Drilling Co., Ltd. for $2,015,000. These acquisitions were funded with proceeds from the February 20, 2004 sale of our common stock.

In late May 2004, we completed constructing, primarily from used components, a 1,000-hp electric drilling rig. We incurred approximately $4,900,000 of construction costs on this rig.

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

In December 2004 we also completed constructing, from new and used components, a 1000-horse power electric drilling rig, which we have designated as Rig No. 38. We incurred approximately $5,800,000 in rig construction costs for that rig. We mobilized Rig No. 38 to Utah in December 2004, where it began operating under a one-year daywork contract in January 2005.

In January 2005, we began constructing, from new and used components, a 1,000-horse power mechanical drilling rig. We estimate we will incur approximately $5,500,000 of construction costs for

that rig. We expect to complete construction of the rig in March 2005. We have also begun ordering components for the construction of two 1000-horse power SCR electric rigs at an estimated cost of $6,100,000 each. Construction of these rigs is subject to obtaining adequate financing.

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

	Three Months Ended December 31, 2004		Nine Months Ended December 31, 2004
Drilling rigs(1)	$	39,027,318	$	43,269,599
Other drilling equipment		4,833,961		15,426,472
Transportation equipment		750,411		2,404,792
Other		387,698		1,238,338

	$	44,999,388	$	62,339,201

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

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

Working Capital

Our working capital decreased to $6,028,018 at March 31, 2004 from $11,144,309 at March 31, 2003. Our current ratio, which we calculate by dividing our current assets by our current liabilities, was 1.27 at March 31, 2004 compared to 1.55 at March 31, 2003. The principal reason for the decrease in our working capital at March 31, 2004 was our use of approximately $3,400,000 of working capital toward the purchase of drilling equipment. We used substantially all the $20,000,000 in proceeds from the shares of common stock we sold in a private placement to Chesapeake on March 31, 2003 to expand our rig fleet or reduce debt we incurred to expand our rig fleet. We used the funds we raised in February 2004 to expand our rig fleet or acquire other equipment.

Our working capital increased to $11,842,627 at December 31, 2004 from $6,028,018 at March 31, 2004. Our current ratio, which we calculate by dividing our current assets by our current liabilities, was 1.48 at December 31, 2004, compared to 1.27 at March 31, 2004. The principal reason for the increase in our working capital at December 31, 2004 was our August 2004 public offering of common stock, in which we raised proceeds of approximately $29,700,000. Approximately $18,800,000 of those proceeds was used to retire substantially all our long-term debt as of August 2004.

Our operations have historically generated sufficient cash flow to meet our requirements for debt service and equipment expenditures (excluding rig and other major equipment acquisitions). However, during periods when a higher percentage of our contracts are turnkey and footage contracts, our short-term working capital needs could increase. The significant improvement in operating cash flow for the nine months ended December 31, 2004 over December 31, 2003 is due primarily to the approximately $7,500,000 overall improvement in net earnings, components of which are discussed in "—Results of Operations." That improvement was net of approximately $4,500,000 increase in noncash depreciation and amortization expense. If necessary, we can defer rig upgrades to improve our cash position. We believe our cash generated by operations and our ability to borrow the currently unused portion of our line of credit and letter of credit facility of approximately $4,200,000, which takes into account reductions for approximately $2,800,000 of outstanding letters of credit as of January 31, 2004, should allow us to meet our routine financial obligations.

The changes in the components of our working capital at March 31, 2004 from March 31, 2003 were as follows:

	March 31,
	2004		2003		Change
Cash and cash equivalents	$	6,365,759	$	21,002,913	$	(14,637,154	)
Receivables		20,032,785		8,928,923		11,103,862
Income tax receivable		—		444,900		(444,900	)
Deferred tax receivable		285,384		180,991		104,393
Prepaid expenses		1,336,337		914,187		422,150

Current assets		28,020,265		31,471,914		(3,451,649	)

Current debt		4,423,306		3,399,163		1,024,143
Accounts payable		13,270,989		14,206,586		(935,597	)
Accrued payroll		1,499,151		847,163		651,988
Accrued expenses		2,798,801		1,874,693		924,108

Current liabilities		21,992,247		20,327,605		1,664,642

Working capital	$	6,028,018	$	11,144,309	$	(5,116,291	)

The large cash balance at March 31, 2003 was due to our sale of $20,000,000 of equity on March 31, 2003, of which $14,000,000 was in the March 31, 2003 cash balance. The $14,000,000 was used during fiscal 2004 to purchase drilling rigs and equipment.

The increase in our receivables at March 31, 2004 from March 31, 2003 was due to our operating eleven additional rigs in the quarter ended March 31, 2004, including an approximately $3,693,000 increase in contract drilling in progress related to turnkey contracts, and an improvement in revenue rates in fiscal 2004 over fiscal 2003.

Substantially all our prepaid expenses at March 31, 2004 consisted of prepaid insurance. The increase in prepaid insurance was due to the increase in the size of our drilling rig fleet from 24 rigs at March 31, 2003 to 35 rigs at March 31, 2004.

The increase in accrued payroll was due to the approximately 50% increase in our number of employees and the increase in the number of payroll days included in the accrual from seven at March 31, 2003 to nine at March 31, 2004.

The total increase in accrued expenses at March 31, 2004 from March 31, 2003 was due to an increase of approximately $477,000 in the accrual for our insurance deductibles and additional insurance premiums, expense accruals of approximately $250,000 related to the sale of common stock in February and accrued property taxes of approximately $205,000 due to increases in rig valuations and the size of our rig fleet.

The changes in the components of our working capital as of December 31, 2004 compared to March 31, 2004 were as follows:

	December 31, 2004		March 31, 2004		Change
Cash and cash equivalents	$	6,712,945	$	6,365,759	$	347,186
Receivables		19,924,122		10,901,991		9,022,131
Contract drilling in progress		7,350,085		9,130,794		(1,780,109	)
Deferred income taxes		426,056		285,384		140,672
Prepaid expenses		2,060,974		1,336,337		724,637

Current assets		36,474,782		28,020,265		8,454,517

Current debt		7,037,300		4,423,306		2,613,994
Accounts payable		11,206,903		13,270,989		(2,064,086	)
Federal income taxes payable		69,568		—		69,568
Accrued payroll		1,721,341		1,499,151		222,190
Accrued expenses		4,597,043		2,798,801		1,798,242

Current liabilities		24,632,155		21,992,247		2,639,908

Working capital	$	11,842,627	$	6,028,018	$	5,814,609

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

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

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

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

The increase in accrued payroll was due to the increase in our number of employees due to the rig additions, partially offset by only four days of payroll accrual at December 31, 2004 compared to nine days at March 31, 2004.

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

Long-term Debt

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

Term loans under a credit facility, secured by drilling equipment, due in monthly payments of $488,889 plus interest at prime (5.25% at December 31, 2004), due December 1, 2007	$	35,200,000
Capital lease obligations		130,835

	$	35,330,835

Contractual Obligations

We do not have any routine purchase obligations. The following table excludes interest payments on long-term debt and capital lease obligations. The following table includes all of our contractual obligations of the types specified below at December 31, 2004.

	Payments Due by Period
Contractual Obligations	Total		Less than 1 year		1-3 years		4-5 years		More than 5 years
Long-term Debt	$	35,200,000	$	5,866,667	$	29,333,333	$	—	$	—
Capital Lease Obligations		130,835		84,307		46,528		—		—
Operating Lease Obligations		130,142		84,644		45,498		—		—

Total	$	35,460,977	$	6,035,618	$	29,425,359	$	—	$	—

Debt Requirements

The $35,200,000 aggregate amount of indebtedness we incurred in November and December 2004 under the acquisition facility portion of our new credit facility is due in monthly installments of $488,889 plus interest, which we began paying on the first business day of January 2005, based on a 72-month amortization schedule, with all remaining unpaid principal being due on December 1, 2007. All the indebtedness under the acquisition facility bears interest at Frost National Bank's prime rate (5.25% as of January 31, 2005). We intend to prepay $20,000,000 of the indebtedness under the acquisition facility with proceeds from this offering. See "Use of Proceeds."

The sum of (1) the draws under and (2) the amount of all outstanding letters of credit issued for our account under the revolving line and letter of credit facility portion of our new credit facility are limited to 75% of our eligible accounts receivable, not to exceed $7,000,000. Therefore, if 75% of our eligible accounts receivable was less than $7,000,000, our ability to draw under this line would be reduced. At December 31, 2004, we had no outstanding advances under this line of credit, outstanding letters of credit were $2,505,000 and 75% of our eligible accounts receivable was approximately $12,379,000. The letters of credit are issued to two workers' compensation insurance companies to secure possible future claims under the deductibles on these policies. It is our practice to pay any amounts due under these deductibles as they are incurred. Therefore, we do not anticipate that the lenders will be required to fund any draws under these letters of credit. The termination date of the revolving line and letter of credit facility portion of our new credit facility is October 28, 2005.

Our new credit facility contains various covenants pertaining to a debt to total capitalization ratio, operating leverage ratio and fixed charge coverage ratio and restricts us from paying dividends. We determine compliance with the ratios on a quarterly basis, based on the previous four quarters. Events of default, which could trigger an early repayment requirement, include, among others:

•: our failure to make required payments;
•: any sale of assets by us not permitted by the agreement;
•: our failure to comply with financial covenants related to a debt to total capitalization ratio not to exceed 0.3 to 1, an operating leverage ratio 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 agreement;
•: any event which results in a change in the ownership of at least 40% of all classes of our outstanding capital stock; and
•: any payment of cash dividends on our common stock.

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

Contracts

Our operations consist of drilling oil and gas wells for our customers under daywork, turnkey, or footage contracts usually on a well-to-well basis. Daywork contracts are the easiest for us to perform and involve the least risk. Turnkey contracts are the most difficult to perform and involve much greater risk but provide the opportunity for higher operating profits.

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

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

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

Comparison of Three and Nine Months Ended December 31, 2004 and 2003 (Unaudited)

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

	Three Months Ended December 31,				Nine Months Ended December 31,
	2004		2003		2004		2003
Daywork contracts	58	%	55	%	46	%	49	%
Turnkey contracts	40	%	40	%	51	%	47	%
Footage contracts	2	%	5	%	3	%	4	%

While demand for drilling rigs has been increasing, we continue to bid on turnkey contracts in an effort to improve profitability and maintain rig utilization. With the improvements in daywork rates, we anticipate a gradual decline in the number of turnkey contracts. We had seven turnkey contracts in

progress at December 31, 2004, compared to 16 turnkey contracts in progress at March 31, 2004. We also had four footage contracts in progress at December 31, 2004 and none at March 31, 2004.

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

Statement of Operations Analysis

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

			Three Months Ended December 31,						Nine Months Ended December 31,
			2004			2003			2004			2003
Contract drilling revenues:
	Daywork contracts		$	26,823,504		$	14,524,293		$	59,277,124		$	36,152,177
	Turnkey contracts			18,544,371			10,623,649			66,235,119			35,185,428
	Footage contracts			1,019,750			1,266,420			4,377,092			3,171,222

	Total contract drilling revenues		$	46,387,624		$	26,414,362		$	129,889,335		$	74,508,827

Contract drilling costs:
	Daywork contracts		$	18,146,355		$	11,912,444		$	44,400,934		$	30,761,320
	Turnkey contracts			13,582,177			8,575,019			53,152,744			28,443,917
	Footage contracts			628,212			1,112,256			3,248,410			2,552,029

		Total contract drilling costs	$	32,356,744		$	21,599,719		$	100,802,088		$	61,757,266

Depreciation and amortization			$	5,769,959		$	4,118,811		$	16,124,317		$	11,670,538
General and administrative expense			$	1,215,189		$	687,286		$	2,910,879		$	2,027,132
Revenue days by type of contract:
	Daywork contracts			2,421			1,524			5,680			4,072
	Turnkey contracts			1,024			594			3,667			1,913
	Footage contracts			79			128			340			283

		Total revenue days		3,524			2,246			9,687			6,268

Contract drilling revenue per revenue day			$	13,163		$	11,761		$	13,409		$	11,887
Contract drilling cost per revenue day			$	9,182		$	9,617		$	10,406		$	9,853
Rig utilization rates				98	%		88	%		96	%		87	%
Average number of rigs during the period				39.7			27.7			37.1			26.2

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

Our contract drilling costs grew by approximately $10,757,000, or 50%, in the quarter ended December 31, 2004 from the corresponding quarter of 2003 due to the increase in the number of rigs in our fleet, the increase in rig utilization and the increase in revenue days in 2004 compared to 2003. The decline in average contract drilling cost per revenue day is due to the shift to more daywork

revenue days as a percentage of total revenue days. Under turnkey and footage contracts, we provide supplies and materials such as fuel, drill bits, casing and drilling fluids, which significantly adds to drilling costs for turnkey and footage contracts. These costs are also included in the revenues we recognize for turnkey and footage contracts, resulting in higher revenue rates per day for turnkey and footage contracts compared to daywork contracts which do not include such costs.

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

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

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

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

Our effective income tax rates of 37% and 18% for the three-month periods ended December 31, 2004 and 2003, respectively, and 37% and 24% for the nine-month periods ended December 31, 2004 and 2003, respectively, differ from the federal statutory rate of 34% due to permanent differences. Permanent differences are costs included in results of operations in the accompanying financial statements which are not fully deductible for federal income tax purposes.

Comparison of Fiscal Years 2004, 2003 and 2002

For the years ended March 31, 2004, 2003 and 2002, the percentages of our drilling revenues by type of contract were as follows:

	Year Ended March 31,
	2004		2003		2002
Daywork Contracts	47	%	41	%	91	%
Turnkey Contracts	50	%	58	%	7	%
Footage Contracts	3	%	1	%	2	%

While current demand for drilling rigs has increased, we continue to bid on turnkey contracts in an effort to improve profitability and maintain rig utilization.

In our quarter ended March 31, 2004, we recognized revenues of approximately $924,000 and recorded contract drilling costs of approximately $747,000, excluding depreciation, on one daywork contract with Chesapeake, who owns approximately 16.8% of our outstanding common stock as of January 31, 2005.

Statement of Operations Analysis

The following table provides information about our operations for the years ended March 31, 2004, March 31, 2003, and March 31, 2002.

		Year Ended March 31,
		2004			2003			2002
Contract drilling revenues		$	107,875,533		$	80,183,486		$	68,627,486
Contract drilling costs			88,504,102			70,823,310			46,145,364
Depreciation and amortization			16,160,494			11,960,387			8,426,082
General and administrative expenses			2,772,730			2,232,390			2,855,274
Revenue days by type of contract:
	Turnkey contracts		2,827			2,619			289
	Footage contracts		311			119			136
	Daywork contracts		5,626			3,681			4,959

	Total revenue days		8,764			6,419			5,384

Contract drilling revenue per revenue day		$	12,309		$	12,492		$	12,747
Contract drilling cost per revenue day			10,099			11,033			8,571
Rig utilization rates			88	%		79	%		82	%

Our contract drilling revenues grew by approximately 35% in fiscal 2004 from fiscal 2003, due to an improvement in rig revenue rates, a 37% increase in revenue days, a 9% increase in rig utilization and an increase in the number of rigs in our fleet. Approximately 52% of the increase in revenue days was an increase in daywork revenue days resulting in a $183 decrease in average contract drilling revenue per day. Revenue rates on daywork contracts are lower than on turnkey and footage contracts because we incur fewer costs on daywork contracts.

Our contract drilling revenue in fiscal 2003 grew by approximately $11,556,000, or 17%, from fiscal 2002 due to a 19% increase in revenue days, an increase in the number of rigs in our fleet and a higher percentage of turnkey contracts.

Our contract drilling costs grew by approximately $17,681,000, or 25%, in fiscal 2004 from fiscal 2003 due to the increase in revenue days, rig utilization and the number of rigs in our fleet. The increase in daywork revenue days resulted in a $934 decrease in contract drilling costs per revenue day because costs associated with the drilling of daywork contracts is less than costs associated with turnkey and footage contracts. Under daywork contracts, our customer provides supplies and materials such as fuel, drill bits, casing, drilling fluids, etc.

Our contract drilling costs in fiscal 2003 grew by approximately $24,678,000, or 53% from fiscal 2002, due primarily to the increase in revenue days, increase in number of rigs and additional costs associated with the increase in turnkey contracts. The increase in contract drilling costs per day of $2,462 in 2003 from 2002 is due to the increase in turnkey contracts.

Our depreciation and amortization expense in 2004 increased by approximately $4,200,000, or 35%, from 2003. Depreciation and amortization expense in 2003 increased approximately $3,534,000, or 42%, from 2002. The increase in 2004 over 2003 resulted from our addition of eleven drilling rigs and related equipment in 2004. The increase in 2003 over 2002 resulted from our addition of four drilling rigs and related equipment during 2003.

Our general and administrative expenses increased by approximately $541,000, or 24%, in the year ended March 31, 2004 from the corresponding period of 2003. The increase resulted from increased payroll costs, employment fees, loan fees, insurance costs and director fees. In 2004, payroll costs increased by approximately $310,000 due to pay raises and the increase from 12 to 17 employees in our corporate office. Employment and loan fees increased by $61,000 due to the employee additions and fees associated with the Merrill Lynch Capital loan. In addition, our directors' and officers' liability and employment practices insurance increased by approximately $60,000 and directors' fees increased by approximately $93,000.

The approximately $623,000 decrease in general and administrative expenses in 2003 from 2002 is due to reduced payroll costs of approximately $269,000 and lower legal and professional fees of approximately $520,000, offset by other increases of approximately $166,000. The higher payroll costs in 2002 were due to bonuses paid in that year.

Our contract land drilling operations are subject to various federal and state laws and regulations designed to protect the environment. Maintaining compliance with these regulations is part of our day-to-day operating procedures. We monitor each of our yard facilities and each of our rig locations on a day-to-day basis for potential environmental spill risks. In addition, we maintain a spill prevention control and countermeasures plan for each yard facility and each rig location. The costs of these procedures represent only a small portion of our routine employee training, equipment maintenance and job site maintenance costs. We estimate the annual compliance costs for this program is approximately $143,000. We are not aware of any potential clean-up obligations that would have a material adverse effect on our financial condition or results of operations.

Our effective income tax rates of 19.2%, 30.4% and 35.1% for 2004, 2003 and 2002, respectively, differ from the federal statutory rate of 34% due to permanent differences. Permanent differences are costs included in results of operations in the accompanying financial statements which are not fully deductible for federal income tax purposes.

Inflation

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

Off Balance Sheet Arrangements

We do not currently have any off balance sheet arrangements.

Quantitative and Qualitative Disclosures About Market Risk

We are usually subject to market risk exposure related to changes in interest rates on our outstanding floating rate debt. Our new credit facility provides for interest on borrowings under the facility at a floating rate equal to Frost National Bank's prime rate, which was 5.25% as of January 31, 2005. An increase or decrease of 1% in the interest rate would have a corresponding decrease or increase in our net income (loss) of approximately $232,000 annually, based on the $35,200,000 outstanding as of December 31, 2004. We have not entered into any debt arrangements for trading purposes.

BUSINESS

General

Pioneer 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 select 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. Our common stock trades on the American Stock Exchange under the symbol "PDC."

Since September 1999, we have significantly expanded our fleet of drilling rigs through acquisitions and the construction of new rigs and the refurbishment of older rigs we acquired. The following table summarizes acquisitions in which we acquired rigs and related operations since September 1999:

Date	Acquisition(1)	Market	Number of Rigs Acquired
September 1999	Howell Drilling, Inc.	South Texas	2
August 2000	Pioneer Drilling Co.	South Texas	4
March 2001	Mustang Drilling, Ltd.	East Texas	4
May 2002	United Drilling Company	South Texas	2
August 2003	Texas Interstate Drilling Company, L.P.	North Texas	2
March 2004	Sawyer Drilling & Service, Inc.	East Texas	7
March 2004	SEDCO Drilling Co., Ltd.	North Texas	1
November 2004	Wolverine Drilling, Inc.	Rocky Mountains	7
December 2004	Allen Drilling Company	Western Oklahoma	5

(1): The August 2000 acquisition of Pioneer Drilling Co. involved our acquisition of all the outstanding capital stock of that entity. Each other acquisition reflected in this table involved our acquisition of assets from the indicated entity.

During that same period, we also added eight rigs to our fleet through construction of new rigs and construction of rigs from new and used components. In addition, in August 2003, we acquired a rig that had been operating in Trinidad and integrated it into our operations in Texas. As of January 31, 2005, our rig fleet consisted of 49 operating drilling rigs, 15 of which were operating in South Texas, 17 of which were operating in East Texas, four of which were operating in North Texas, five of which were operating in Western Oklahoma and eight of which were operating in the Rocky Mountain region. As of that date, Rig No. 38 was preparing to commence operations under a new one-year daywork contract in Utah. During our fiscal year ended March 31, 2002, we added four rigs, consisting of two newly constructed rigs and two refurbished rigs, increasing our rig fleet to a total of 20 rigs at March 31, 2002. During our fiscal year ended March 31, 2003, we added two additional refurbished rigs and two rigs we acquired from United Drilling Company, increasing our rig fleet to a total of 24 rigs at March 31, 2003. During our fiscal year ended March 31, 2004, we added two refurbished rigs, acquired two rigs from Texas Interstate Drilling Company, L.P., acquired seven rigs from Sawyer Drilling & Service, Inc. and acquired one rig from SEDCO Drilling Co., Ltd. (which we named Rig 5 in place of our old Rig 5, which was retired and the components of which were moved to our inventory of spare equipment). In December 2003, we acquired the one rig (Rig No. 4) we had previously been leasing under an operating lease since August 2000. In November 2004, we acquired seven rigs from Wolverine Drilling and, in December 2004, we acquired five rigs from Allen Drilling. We now own all the drilling rigs in our fleet.

We conduct our operations primarily in South, East and North Texas, Western Oklahoma and the Rocky Mountains. During fiscal 2004 and through the third quarter of fiscal 2005, substantially all the

wells we drilled for our customers were drilled in search of natural gas. Although we have recently diversified our operations somewhat with the acquisition of drilling rigs from Wolverine Drilling, with five 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 deep geological formations and generally require premium equipment and quality crews to drill the wells.

For many years, the United States contract land drilling services industry has been characterized by an oversupply of drilling rigs and a large number of drilling contractors. Since 1996, however, there has been significant consolidation within the industry. We believe continued consolidation in the industry will generate more stability in dayrates, even during industry downturns. However, although consolidation in the industry is continuing, the industry is still highly fragmented and remains very competitive. For a discussion of market conditions in our industry, see "Management's Discussion and Analysis of Financial Condition and Results of Operations—Market Conditions in Our Industry."

Our Strategy

Our goal is to continue to build on our strong market position and reputation as a quality contract drilling company in a way that enhances shareholder value. We intend to accomplish this goal by:

•: continuing to own and operate a high-quality fleet of land drilling rigs, primarily in active natural gas drilling markets;
•: acquiring high-quality rigs capable of generating our targeted returns on investment;
•: positioning ourselves to maximize rig utilization and dayrates;
•: training and maintaining high-quality, experienced crews; and
•: maintaining the recent improvements in our safety record.

Drilling Equipment

General

A land drilling rig consists of engines, a hoisting system, a rotating system, pumps and related equipment to circulate drilling fluid, blowout preventers and related equipment.

Diesel or gas engines are typically the main power sources for a drilling rig. Power requirements for drilling jobs may vary considerably, but most land drilling rigs employ two or more engines to generate between 500 and 2,000 horsepower, depending on well depth and rig design. Most drilling rigs capable of drilling in deep formations, involving depths greater than 15,000 feet, use diesel-electric power units to generate and deliver electric current through cables to electrical switch gears, then to direct-current electric motors attached to the equipment in the hoisting, rotating and circulating systems.

Drilling rigs use long strings of drill pipe and drill collars to drill wells. Drilling rigs are also used to set heavy strings of large-diameter pipe, or casing, inside the borehole. Because the total weight of the drill string and the casing can exceed 500,000 pounds, drilling rigs require significant hoisting and braking capacities. Generally, a drilling rig's hoisting system is made up of a mast, or derrick, a traveling block and hook assembly that attaches to the rotating system, a mechanism known as the drawworks, a drilling line and ancillary equipment. The drawworks mechanism consists of a revolving drum, around which the drilling line is wound, and a series of shafts, clutches and chain and gear drives for generating speed changes and reverse motion. The drawworks also houses the main brake, which has the capacity to stop and sustain the weights used in the drilling process. When heavy loads are being lowered, a hydraulic or electric auxiliary brake assists the main brake to absorb the great amount

of energy developed by the mass of the traveling block, hook assembly, drill pipe, drill collars and drill bit or casing being lowered into the well.

The rotating equipment from top to bottom consists of a swivel, the kelly bushing, the kelly, the rotary table, drill pipe, drill collars and the drill bit. We refer to the equipment between the swivel and the drill bit as the drill stem. The swivel assembly sustains the weight of the drill stem, permits its rotation and affords a rotating pressure seal and passageway for circulating drilling fluid into the top of the drill string. The swivel also has a large handle that fits inside the hook assembly at the bottom of the traveling block. Drilling fluid enters the drill stem through a hose, called the rotary hose, attached to the side of the swivel. The kelly is a triangular, square or hexagonal piece of pipe, usually 40 feet long, that transmits torque from the rotary table to the drill stem and permits its vertical movement as it is lowered into the hole. The bottom end of the kelly fits inside a corresponding triangular, square or hexagonal opening in a device called the kelly bushing. The kelly bushing, in turn, fits into a part of the rotary table called the master bushing. As the master bushing rotates, the kelly bushing also rotates, turning the kelly, which rotates the drill pipe and thus the drill bit. Drilling fluid is pumped through the kelly on its way to the bottom. The rotary table, equipped with its master bushing and kelly bushing, supplies the necessary torque to turn the drill stem. The drill pipe and drill collars are both steel tubes through which drilling fluid can be pumped. Drill pipe, sometimes called drill string, comes in 30-foot sections, or joints, with threaded sections on each end. Drill collars are heavier than drill pipe and are also threaded on the ends. Collars are used on the bottom of the drill stem to apply weight to the drilling bit. At the end of the drill stem is the bit, which chews up the formation rock and dislodges it so that drilling fluid can circulate the fragmented material back up to the surface where the circulating system filters it out of the fluid.

Drilling fluid, often called mud, is a mixture of clays, chemicals and water or oil, which is carefully formulated for the particular well being drilled. Drilling mud accounts for a major portion of the equipment and cost of drilling a well. Bulk storage of drilling fluid materials, the pumps and the mud-mixing equipment are placed at the start of the circulating system. Working mud pits and reserve storage are at the other end of the system. Between these two points the circulating system includes auxiliary equipment for drilling fluid maintenance and equipment for well pressure control. Within the system, the drilling mud is typically routed from the mud pits to the mud pump and from the mud pump through a standpipe and the rotary hose to the drill stem. The drilling mud travels down the drill stem to the bit, up the annular space between the drill stem and the borehole and through the blowout preventer stack to the return flow line. It then travels to a shale shaker for removal of rock cuttings, and then back to the mud pits, which are usually steel tanks. The reserve pits, usually one or two fairly shallow excavations, are used for waste material and excess water around the location.

There are numerous factors that differentiate land drilling rigs, including their power generation systems and their drilling depth capabilities. The actual drilling depth capability of a rig may be less than or more than its rated depth capability due to numerous factors, including the size, weight and amount of the drill pipe on the rig. The intended well depth and the drill site conditions determine the amount of drill pipe and other equipment needed to drill a well. Generally, land rigs operate with crews of five to six persons.

Our Fleet of Drilling Rigs

As of December 31, 2004, our rig fleet consists of 49 drilling rigs. We own all the rigs in our fleet. The following table sets forth information regarding utilization for our fleet of drilling rigs:

			Year Ended March 31,
	Nine Months Ended December 31, 2004		Year Ended March 31,
	Nine Months Ended December 31, 2004		2004		2003		2002		2001		2000
Average number of rigs for the period	37.1		27.3		22.3		18.0		10.5		6.6
Average utilization rate	96	%	88	%	79	%	82	%	91	%	66	%

The following table sets forth information regarding our drilling fleet:

Rig Number	Rig Design	Approximate Drilling Depth Capability (feet)	Current Location	Type	Horse Power
1	Cabot 750E	9,500	South Texas	Electric	750
2	Cabot 750E	9,500	South Texas	Electric	750
3	National 110 UE	18,000	South Texas	Electric	1,500
4	RMI 1000 E	15,000	South Texas	Electric	1,000
5	Brewster N-46	12,000	North Texas	Mechanical	1,000
6	Brewster DH-4610	13,000	East Texas	Mechanical	750
7	National 110 UE	18,000	South Texas	Electric	1,500
8	National 110 UE	18,000	East Texas	Electric	1,500
9	Gardner-Denver 500	11,000	East Texas	Mechanical	700
10	Brewster N-46	12,000	East Texas	Mechanical	1,000
11	Brewster N-46	12,000	South Texas	Mechanical	1,000
12	Cabot 900	12,500	South Texas	Mechanical	900
14	Brewster N-46	12,000	South Texas	Mechanical	1,000
15	Cabot 750	9,500	South Texas	Mechanical	750
16	Cabot 750	9,500	South Texas	Mechanical	750
17	Ideco 725	12,000	East Texas	Mechanical	750
18	Brewster N-75	12,000	East Texas	Mechanical	1,000
19	Brewster N-75	12,000	East Texas	Mechanical	1,000
20	BDW 800	13,500	East Texas	Mechanical	1,000
21	National 110 UE	18,000	South Texas	Electric	1,500
22	Ideco 725	12,000	East Texas	Mechanical	750
23	Ideco 725	12,000	North Texas	Mechanical	750
24	National 110 UE	18,000	South Texas	Electric	1,500
25	National 110 UE	18,000	East Texas	Electric	1,500
26	Oilwell 840 E	18,000	South Texas	Electric	1,500
27	Cabot 1200	13,500	South Texas	Mechanical	1,300
28	Oilwell 760 E	15,000	South Texas	Electric	1,000
29	Brewster N-46	12,000	North Texas	Mechanical	1,000
30	Mid Cont U36A	11,000	North Texas	Mechanical	750
31	Brewster N-7	11,500	East Texas	Mechanical	750
32	Brewster N-75	13,500	East Texas	Mechanical	1,000
33	Brewster N-95	13,500	East Texas	Mechanical	1,200
34	All-Rig 900	12,000	East Texas	Mechanical	900
35	RMI 1000	13,500	East Texas	Mechanical	1,000
36	Brewster N-7	11,500	East Texas	Mechanical	750
37	Brewster N-95	13,500	East Texas	Mechanical	1,200
38	Ideco H-1000 E	11,000	North Dakota	Electric	1,000

39	National 370	7,500	North Dakota	Mechanical	550
40	National 370	8,500	North Dakota	Mechanical	550
41	National 610	11,000	North Dakota	Mechanical	750
42	Brewster N-46	12,500	North Dakota	Mechanical	1,000
43	National 610	11,000	North Dakota	Mechanical	750
44	National 80B	15,000	North Dakota	Mechanical	1,000
45	Brewster N-4	7,500	North Dakota	Mechanical	500
46	RMI 550	9,000	Oklahoma	Mechanical	550
47	Ideco 525	8,000	Oklahoma	Mechanical	500
48	National 370	8,500	Oklahoma	Mechanical	550
49	Ideco 525	9,000	Oklahoma	Mechanical	600
50	Ideco 725	11,000	Oklahoma	Mechanical	800

As of January 31, 2005, we owned a fleet of 59 trucks and related transportation equipment that we use to transport our drilling rigs to and from drilling sites. By owning our own trucks, we reduce the cost of rig moves and reduce downtime between rig moves.

We believe that our drilling rigs and other related equipment are in good operating condition. Our employees perform periodic maintenance and minor repair work on our drilling rigs. We rely on various oilfield service companies for major repair work and overhaul of our drilling equipment when needed. We also engage in periodic improvement of our drilling equipment. In the event of major breakdowns or mechanical problems, our rigs could be subject to significant idle time and a resulting loss of revenue if the necessary repair services are not immediately available.

Drilling Contracts

As a provider of contract land drilling services, our business and the profitability of our operations depend on the level of drilling activity by oil and gas exploration and production companies operating in the geographic markets where we operate. The oil and gas exploration and production industry is a historically cyclical industry characterized by significant changes in the levels of exploration and development activities. During periods of lower levels of drilling activity, price competition tends to increase and results in decreases in the profitability of daywork contracts. In this lower level drilling activity and competitive price environment, we may be more inclined to enter into turnkey and footage contracts that expose us to greater risk of loss without commensurate increases in potential contract profitability.

The following table presents, by type of contract, information about the total number of wells we completed for our customers during the nine months ended December 31, 2004 and each of the last three fiscal years.

		Year Ended March 31,
	Nine Months Ended December 31, 2004	Year Ended March 31,
	Nine Months Ended December 31, 2004	2004	2003	2002
Daywork	167	205	119	150
Turnkey	110	92	78	9
Footage	18	13	5	6

Total number of wells	295	310	202	165

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

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

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

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

our footage jobs could have a material adverse effect on our financial position and results of operations.

Customers and Marketing

We market our rigs to a number of customers. In fiscal 2004, we drilled wells for 88 different customers, compared to 64 customers in fiscal 2003 and 48 customers in fiscal 2002. Forty-nine of our customers in fiscal 2004 were customers for whom we had not drilled any wells in fiscal 2003. The following table shows our three largest customers as a percentage of our total contract drilling revenue for each of our last three fiscal years.

Customer	Total Contract Drilling Revenue Percentage
Fiscal 2004
Chinn Exploration	11	%
Dale Operating Company	6	%
Medicine Bow Energy Corporation	5	%
Fiscal 2003
Gulf Coast Energy Associates	11	%
Apache Corporation	7	%
Suemaur Exploration & Production, L.L.C.	5	%
Fiscal 2002
Dominion Exploration & Production, Inc.	14	%
Kerr-McGee Oil & Gas Onshore, L.L.C.	12	%
Pogo Producing Company	11	%

We primarily market our drilling rigs through employee marketing representatives. These marketing representatives use personal contacts and industry periodicals and publications to determine which operators are planning to drill oil and gas wells in the near future in our market areas. Once we have been placed on the "bid list" for an operator, we will typically be given the opportunity to bid on most future wells for that operator in the areas in which we operate. Our rigs are typically contracted on a well-by-well basis.

From time to time we also enter into informal, nonbinding commitments with our customers to provide drilling rigs for future periods at specified rates plus fuel and mobilization charges, if applicable, and escalation provisions. This practice is customary in the contract land drilling services business during times of tightening rig supply.

Competition

The drilling contracts we compete for are usually awarded on the basis of competitive bids. Our principal competitors are Grey Wolf, Inc., Helmerich & Payne, Inc., Nabors Industries, Inc. and Patterson-UTI Energy, Inc. We believe pricing and rig availability are the primary factors our potential customers consider in determining which drilling contractor to select. In addition, we believe the following factors are also important:

•: the type and condition of each of the competing drilling rigs;

•: the mobility and efficiency of the rigs;
•: the quality of service and experience of the rig crews;
•: the safety records of the rigs;
•: the offering of ancillary services; and
•: the ability to provide drilling equipment adaptable to, and personnel familiar with, new technologies and drilling techniques.

While we must be competitive in our pricing, our competitive strategy generally emphasizes the quality of our equipment, the safety record of our rigs and the experience of our rig crews to differentiate us from our competitors.

Contract drilling companies compete primarily on a regional basis, and the intensity of competition may vary significantly from region to region at any particular time. If demand for drilling services improves in a region where we operate, our competitors might respond by moving in suitable rigs from other regions. An influx of rigs from other regions could rapidly intensify competition and make any improvement in demand for drilling rigs in a particular region short-lived.

Many of our competitors have greater financial, technical and other resources than we do. Their greater capabilities in these areas may enable them to:

•: better withstand industry downturns;
•: compete more effectively on the basis of price and technology;
•: better retain skilled rig personnel; and
•: build new rigs or acquire and refurbish existing rigs so as to be able to place rigs into service more quickly than us in periods of high drilling demand.

Raw Materials

The materials and supplies we use in our drilling operations include fuels to operate our drilling equipment, drilling mud, drill pipe, drill collars, drill bits and cement. We do not rely on a single source of supply for any of these items. While we are not currently experiencing any shortages, from time to time there have been shortages of drilling equipment and supplies during periods of high demand.

Shortages could result in increased prices for drilling equipment or supplies that we may be unable to pass on to customers. In addition, during periods of shortages, the delivery times for equipment and supplies can be substantially longer. Any significant delays in our obtaining drilling equipment or supplies could limit drilling operations and jeopardize our relations with customers. In addition, shortages of drilling equipment or supplies could delay and adversely affect our ability to obtain new contracts for our rigs, which could have a material adverse effect on our financial condition and results of operations.

Operating Risks and Insurance

Our operations are subject to the many hazards inherent in the contract land drilling business, including the risks of:

•: blowouts;
•: fires and explosions;
•: loss of well control;
•: collapse of the borehole;

•: lost or stuck drill strings; and
•: damage or loss from natural disasters.

Any of these hazards can result in substantial liabilities or losses to us from, among other things:

•: suspension of drilling operations;
•: damage to, or destruction of, our property and equipment and that of others;
•: personal injury and loss of life;
•: damage to producing or potentially productive oil and gas formations through which we drill; and
•: environmental damage.

We seek to protect ourselves from some but not all operating hazards through insurance coverage. However, some risks are either not insurable or insurance is available only at rates that we consider uneconomical. Those risks include pollution liability in excess of relatively low limits. Depending on competitive conditions and other factors, we attempt to obtain contractual protection against uninsured operating risks from our customers. However, customers who provide contractual indemnification protection may not in all cases maintain adequate insurance to support their indemnification obligations. We can offer no assurance that our insurance or indemnification arrangements will adequately protect us against liability or loss from all the hazards of our operations. The occurrence of a significant event that we have not fully insured or indemnified against or the failure of a customer to meet its indemnification obligations to us could materially and adversely affect our results of operations and financial condition. Furthermore, we may not be able to maintain adequate insurance in the future at rates we consider reasonable.

Our current insurance coverage includes property insurance on our rigs, drilling equipment and real property. Our insurance coverage for property damage to our rigs and to our drilling equipment is based on our estimate, as of October 2004, of the cost of comparable used equipment to replace the insured property. The policy provides for a deductible on rigs of $100,000 per occurrence. Our third-party liability insurance coverage is $26 million per occurrence and in the aggregate, with a deductible of $260,000 per occurrence. We believe that we are adequately insured for public liability and property damage to others with respect to our operations. However, such insurance may not be sufficient to protect us against liability for all consequences of well disasters, extensive fire damage or damage to the environment.

In addition, we generally carry insurance coverage to protect against certain hazards inherent in our turnkey and footage contract drilling operations. This insurance covers "control-of-well," including blowouts above and below the surface, redrilling, seepage and pollution. This policy provides coverage of $3 million, $5 million or $10 million, depending on the area in which the well is drilled and its target depth. This policy also provides care, custody and control insurance, with a limit of $250,000.

Employees

We currently have approximately 1,250 employees. Approximately 160 of these employees are salaried administrative or supervisory employees. The rest of our employees are hourly employees who operate or maintain our drilling rigs and rig-hauling trucks. The number of hourly employees fluctuates depending on the number of drilling projects we are engaged in at any particular time. None of our employment arrangements are subject to collective bargaining arrangements.

encountered material difficulty in hiring and retaining qualified rig crews, shortages of qualified personnel are occurring in our industry. If we should suffer any material loss of personnel to competitors or be unable to employ additional or replacement personnel with the requisite level of training and experience to adequately operate our equipment, our operations could be materially and adversely affected. While we believe our wage rates are competitive and our relationships with our employees are satisfactory, a significant increase in the wages paid by other employers could result in a reduction in our workforce, increases in wage rates, or both. The occurrence of either of these events for a significant period of time could have a material and adverse effect on our financial condition and results of operations.

Facilities

We own our headquarters building in San Antonio, Texas. We also own:

•: a 15-acre division office, rig storage and maintenance yard in Corpus Christi, Texas;
•: a six-acre division office, storage and maintenance yard in Henderson, Texas;
•: a 4-acre trucking department office, storage and maintenance yard in Kilgore, Texas;
•: a 17-acre rig storage and maintenance yard in Woodward, Oklahoma; and
•: a 4.7-acre division rig storage and maintenance yard in Kenmore, North Dakota.

We lease:

•: a 43-acre division office and storage yard in Decatur, Texas, at a cost of $800 per month, pursuant to a lease extending through September 2006;
•: a trucking department office, storage and maintenance yard in Alice, Texas at a cost of $4,500 per month, pursuant to a lease extending through July 2006; and
•: a division office in Denver, Colorado, at a cost of $1,210 per month, pursuant to a lease extending through June 2005.

We believe these facilities are adequate to serve our current and anticipated needs.

Governmental Regulation

Our operations are subject to stringent laws and regulations relating to containment, disposal and controlling the discharge of hazardous oilfield waste and other non-hazardous waste material into the environment, requiring removal and cleanup under certain circumstances, or otherwise relating to the protection of the environment. In addition, our operations are often conducted in or near ecologically sensitive areas, such as wetlands, which are subject to special protective measures and which may expose us to additional operating costs and liabilities for accidental discharges of oil, natural gas, drilling fluids or contaminated water or for noncompliance with other aspects of applicable laws. We are also subject to the requirements of OSHA and comparable state statutes. The OSHA hazard communication standard, the Environmental Protection Agency "community right-to-know" regulations under Title III of the Federal Superfund Amendment and Reauthorization Act and comparable state statutes require us to organize and report information about the hazardous materials we use in our operations to employees, state and local government authorities and local citizens.

purchased from others. Compliance with applicable environmental laws and regulations has not, to date, materially affected our capital expenditures, earnings or competitive position, although compliance measures have added to our costs of operating drilling equipment in some instances. We do not expect to incur material capital expenditures in our next fiscal year in order to comply with current environment control regulations. However, our compliance with amended, new or more stringent requirements, stricter interpretations of existing requirements or the future discovery of contamination may require us to make material expenditures or subject us to liabilities that we currently do not anticipate.

In addition, our business depends on the demand for land drilling services from the oil and gas industry and, therefore, is affected by tax, environmental and other laws relating to the oil and gas industry generally, by changes in those laws and by changes in related administrative regulations. It is possible that these laws and regulations may in the future add significantly to our operating costs or those of our customers or otherwise directly or indirectly affect our operations.

Legal Proceedings

We have recently been notified that we may become subject to a claim by Venus Exploration, Inc., one of our former customers. Our former CEO and current Chairman of the Board, Michael Little, previously served on the board of directors of Venus Exploration from June 1999 to August 2002. Venus Exploration is currently the debtor in an involuntary bankruptcy proceeding that we, along with others, initiated under Chapter 11 of the federal bankruptcy code. As of the date of this prospectus, we are not aware of any legal proceeding commenced against us relating to Venus Exploration, and we do not have sufficient information to determine whether we would ultimately be named a party with respect to any such proceeding.

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 the pending litigation, disputes or claims against us will have a material adverse effect on our financial condition or results of operations.

MANAGEMENT

Executive Officers and Directors

The following table sets forth the name, age and position of each of our executive officers and directors as of January 31, 2005:

Name	Age	Position Held
Wm. Stacy Locke(2)	49	Director, President and Chief Executive Officer
Franklin C. West	65	Executive Vice President and Chief Operating Officer
William D. Hibbetts	56	Senior Vice President, Chief Financial Officer and Secretary
Donald G. Lacombe	51	Senior Vice President—Marketing
Michael E. Little(3)	49	Chairman of the Board
C. Robert Bunch(3)(4)(5)(6)	50	Director
Dean A. Burkhardt(1)(4)(5)	54	Director
James M. Tidwell(1)(5)	58	Director
C. John Thompson(2)(4)(5)(6)	51	Director
Michael F. Harness(1)(4)(6)	50	Director

(1): Class I director whose term expires at the 2005 Annual Meeting of the Shareholders.
(2): Class II director whose term expires at the 2006 Annual Meeting of the Shareholders.
(3): Class III director whose term expires at the 2007 Annual Meeting of the Shareholders.
(4): Member of the Audit Committee.
(5): Member of the Compensation Committee.
(6): Member of the Nominating and Corporate Governance Committee.

Wm. Stacy Locke has served as one of our directors since May 1995. He has been our President and Chief Executive Officer since December 2003 and was our President and Chief Financial Officer from August 2000 to December 2003. He previously served as our President and Chief Operating Officer from November 1998 to August 2000 and as our President and Chief Executive Officer from May 1995 to November 1998. Prior to joining Pioneer, Mr. Locke was Vice President—Investment Banking with Arneson, Kercheville, Ehrenberg & Associates, Inc. from January 1993 to April 1995. He was Vice President—Investment Banking with Chemical Banking Corporation's Texas Commerce Bank from 1988 to 1992. He was Senior Geologist with Huffco Petroleum Corporation from 1982 to 1986. From 1979 to 1982, Mr. Locke worked for Tesoro Petroleum Corporation and Valero Energy as a Geologist.

Franklin C. West has served as our Executive Vice President and Chief Operating Officer since January 2002. Prior to joining Pioneer, he was Vice President for Flournoy Drilling Company from 1967 until it was acquired by Grey Wolf, Inc. in 1997, and continued in the same capacity for Grey Wolf, Inc. until December 2001. Mr. West has over 40 years of experience in the drilling industry.

William D. Hibbetts has served as our Senior Vice President, Chief Financial Officer and Secretary since December 2003 and served as one of our directors from June 1984 to May 2004. He previously served as our Senior Vice President, Chief Accounting Officer and Secretary from May 2002 to December 2003 and served as our Vice President, Chief Accounting Officer and Secretary from December 2000 to May 2002. He served as the Chief Financial Officer of International Cancer Screening Laboratories from March 2000 to December 2000. International Cancer Screening Laboratories filed for bankruptcy in February 2001. He worked as a consultant from June 1999 to

March 2000. He served as the Chief Accounting Officer of Southwest Venture Management Company from July 1988 to May 1999. Mr. Hibbetts was the Treasurer/Controller of Gary Pools, Inc. from May 1986 to July 1988. He previously served as an officer of our company from January 1982 until May 1986. Before initially joining our company, Mr. Hibbetts served in various positions as an accountant with KPMG Peat Marwick LLP from June 1971 to December 1981, including as an audit manager from July 1978 to December 1981.

Donald G. Lacombe has served as our Senior Vice President—Marketing since May 2002 and served as our Vice President—Marketing from August 2000 to May 2002. Prior to joining Pioneer, he was Contracts and Sales Manager for Grey Wolf, Inc.'s South Texas Division and for Flournoy Drilling Company from April 1993 to August 2000. Mr. Lacombe was an engineer with Dresser Magcobar from 1978 to 1993. He was an assistant geologist for TransOcean Oil from 1972 to 1975. Mr. Lacombe is a past President of the South Texas Chapter of the American Petroleum Institute and a past Chairman of the South Texas Chapter of the International Association of Drilling Contractors.

Michael E. Little has served as one of our directors and as our Chairman of the Board since November 1998. From November 1998 to December 2003 he served as our Chief Executive Officer. Mr. Little currently serves as President and Chief Executive Officer of WEDGE Group Incorporated, a position he has held since December 2003. Mr. Little served as President and Chief Executive Officer and as a director of Dawson Production Services, Inc. from March 1982 until it was acquired by Key Energy Services, Inc. in October 1998. He also served as Chairman of the board of Dawson Production Services, Inc. from March 1983 to October 1998. From 1980 to 1982, Mr. Little was Vice President of Cambern Engineering, Inc., a company that provided drilling and completion consulting services in the Texas Gulf Coast area. From 1976 to 1980, he was employed by Chevron USA as a drilling foreman and as a drilling engineer. From June 1999 through August 2002, Mr. Little was a director of Venus Exploration, Inc. In October 2002, approximately two months after Mr. Little resigned from the board of Venus Exploration, Inc., creditors of Venus Exploration, including Pioneer, filed an involuntary bankruptcy petition against Venus Exploration under chapter 11 of the federal bankruptcy code. Mr. Little is also a director of Intercontinental Bank Shares Corporation, a bank holding company.

C. Robert Bunch has served as one of our directors since May 2004. Mr. Bunch has been President and Chief Executive Officer of Maverick Tube Corporation since October 2004. He was an independent oil service consultant from June 2003 to October 2004. Mr. Bunch served as President and Chief Operating Officer of Input/Output, Inc., a leading provider of geophysical equipment and services, from January 2003 to May 2003. Mr. Bunch served as Vice President and Chief Operating Officer of Input/Output, Inc. from October 2002 to December 2002. He served as Vice President and Chief Administrative Officer of Input/Output, Inc. from November 1999 to September 2002 and was a partner in the law firm of King & Pennington, L.L.P. from May 1997 to November 1999. He previously served as an associate in that law firm from April 1996 to May 1997. He served as an associate in the law firm of Scott, Douglas & McConnico, L.L.P. from June 1994 to June 1995. He served as Executive Vice President and Chief Operating Officer of OYO GeoSpace Corp. from December 1995 to April 1996 and as Senior Vice President and Chief Financial Officer from June 1995 to December 1995. He served as Senior Vice President and Chief Administrative Officer of Siberian American Oil Company from June 1992 to June 1994. He served as President and Chief Operating Officer of Tescorp, Inc. from November 1989 to March 1992 and as Senior Vice President and Chief Financial Officer from June 1985 to November 1989. He served as assistant controller of Hughes Tool Company from April 1981 to June 1985. He served on the audit staff of Deloitte & Touche from July 1977 to April 1981. Mr. Bunch has served as a director for Maverick Tube Corporation, since 1992.

Dean A. Burkhardt has served as one of our directors since October 26, 2001. Mr. Burkhardt has been an investor and consultant in the energy service industry during the last five years as well as a co-owner of Dubina Rose Ranch, Ltd, a ranch business engaged in the breeding and selling of American Quarter Horse Association registered horses and coastal hay. Since 1997, Mr. Burkhardt has

provided consulting services regarding oil and gas projects in Bolivia and Argentina to Frontera Resources Corporation, a developer and operator of oil and gas projects in emerging markets, consulting services regarding investments in fuel cells and workover services to WEDGE from 1997-1998, and consulting services relating to the marketing of technical drilling engineering and quality management services to T. H. Hill & Associates, Inc., a drilling engineering and quality management services provider. Mr. Burkhardt co-founded Cheyenne Services, Inc. in 1979, a provider of oilfield tubular make-up, tubular inspection, and third-party quality assurance services, and Applied Petroleum Software, Inc. in 1983, a provider of production engineering software. From 1981 to 1982, Mr. Burkhardt was President and CEO of Tescorp Energy Services, a provider of hydraulic workover services, rental tools and tubular services.

James M. Tidwell has served as one of our directors since March 2001. Mr. Tidwell currently serves as Vice President and Chief Financial Officer of WEDGE Group Incorporated, a position he has held since January 2000. From June 1999 to January 2000, Mr. Tidwell served as President of Daniel Measurement and Control, a division of Emerson Electric Company. From August 1996 to June 1999, he was Executive Vice President and Chief Financial Officer of Daniel Industries, Inc., a leading supplier of specialized equipment and systems to oil, gas and process operators and plants to measure and control the flow of fluids. For more than five years prior to joining Daniel Industries, Inc., Mr. Tidwell served as Senior Vice President and Chief Financial Officer of Hydril Company, a worldwide leader in engineering, manufacturing and marketing of premium tubular connections and pressure control devices for oil and gas drilling and production. Mr. Tidwell is also a director of T-3 Energy Services, Inc., Stewart & Stevenson Services, Inc. and Link Energy LLC.

C. John Thompson has served as one of our directors since May 2001. Mr. Thompson currently serves as Chairman and Chief Executive Officer of Ventana Capital Advisors, Inc., a company he founded in June 2004 to provide capital advisory services to upstream oil and gas producers. Mr. Thompson served as a Vice President of Constellation Energy, a position he held from August 2003 to May 2004. Mr. Thompson was a consultant from December 2001 to August 2003. He was Vice President and Co-Manager of Enron Energy Capital Resources from February 2000 to December 2001. From September 1997 to February 2000, Mr. Thompson was a principal in Sagestone Capital Partners, which provided investment banking services to the oil and gas industry and portfolio management services to various institutional investors. From December 1990 to May 1997, Mr. Thompson held various positions with Enron Energy Capital Resources and its predecessor companies. From 1977 until 1990, Mr. Thompson worked in the energy banking industry.

Michael F. Harness has served as one of our directors since May 2004. He replaced Mr. Hibbetts, who resigned as a director so we could add an independent director as required by The American Stock Exchange, or the AMEX. Mr. Harness currently serves as President and CEO of Osyka Corporation, an independent oil and gas company, which he founded, headquartered in Houston, Texas, a position he has held since August 1989. He served as Manager of Engineering for the Exploration and Production Group of Texas Eastern Corporation from January 1984 to July 1989. Mr. Harness served in various engineering positions for Amoco Production Company from January 1977 to April 1982.

There are no family relations, of first cousin or closer, among the Company's directors or executive officers by blood, marriage or adoption. The board has determined that each of Messrs. Bunch, Burkhardt, Thompson and Harness are independent directors as defined by the AMEX. Mr. Locke is not independent because he is an employee of the Company, Mr. Little is not independent because he was an employee of the Company until December 2003 and is an officer of WEDGE Group Incorporated and Mr. Tidwell is not independent because he is an officer of WEDGE Group Incorporated.

In connection with our sale of various securities to WEDGE, we have agreed that, as long as WEDGE owns at least 10% of our outstanding capital stock, we will support and cause to be placed on the ballot at any election of directors one person designated by WEDGE who shall be a nominee to our board of directors, but only if it is necessary to cause at least one WEDGE board nominee to continue as a director after such election. As long as WEDGE owned at least 25% of our outstanding capital stock, we agreed to support and cause to be placed on the ballot at any election of directors up to three persons designated by WEDGE as nominees to our board of directors, but only if necessary to cause at least three WEDGE board nominees to continue as directors after such election. In addition, Messrs. Little and Locke have executed a voting agreement which obligates them to vote the shares of common stock they own in favor of any WEDGE director nominee or nominees. The August 2004 offering of shares by WEDGE and us decreased WEDGE's ownership percentage below the 25% threshold described above. WEDGE currently holds more than 10% of our outstanding capital stock, but will hold less than 10% immediately after this offering. See "Certain Relationships and Related Transactions—Transactions with WEDGE Energy Services, L.L.C." Messrs. Burkhardt, Little and Tidwell were WEDGE nominees to our board of directors. Mr. Burkhardt is not affiliated with WEDGE.

Director Compensation

We pay to each of our nonemployee directors fees for service on our board or committees of our board as follows:

Board Member Fees:
Chairman's annual retainer	$	30,000
Member's annual retainer	$	20,000
Each meeting attended in person	$	1,000
Each meeting attended by telephone	$	500
Subcommittee meeting attended in person	$	500
Subcommittee meeting attended by telephone	$	250
Audit Committee Fees:
Chairman's annual retainer	$	10,000
Member's annual retainer	$	4,000
Each meeting attended in person	$	1,000
Each meeting attended by telephone	$	500
Subcommittee meeting attended in person	$	1,000
Subcommittee meeting attended by telephone	$	500
Compensation Committee Fees:
Chairman's annual retainer	$	2,000
Member's annual retainer	$	1,000
Each meeting attended in person	$	500
Each meeting attended by telephone	$	250
Nominating and Corporate Governance Committee Fees:
Chairman's annual retainer	$	2,000
Member's annual retainer	$	1,000
Each meeting attended in person	$	500
Each meeting attended by telephone	$	250

If a board meeting and a committee meeting are held on the same day, the committee meeting fee is one-half of the regular committee meeting fee. We also grant nonemployee directors options to purchase 10,000 shares of common stock upon initially becoming a director and 5,000 shares of

common stock in each subsequent year pursuant to our 2003 Incentive Plan. We reimburse all directors for out-of-pocket expenses they incur in connection with attending board and board committee meetings or otherwise in their capacity as directors.

We expect each director to make every effort to attend each board meeting, each meeting of any committee on which he sits and the annual meeting of shareholders. Attendance in person at board and committee meetings is preferred but not required and attendance by teleconference is permitted if necessary. All of our directors attended last year's annual meeting.

Compensation Committee Interlocks and Insider Participation

Messrs. Thompson, Burkhardt and Tidwell served on our compensation committee over the last fiscal year. No member of the compensation committee was (1) an officer or employee of the Company or a subsidiary of the Company during that period, (2) formerly an officer of the Company or a subsidiary of the Company or (3) had any relationship required to be disclosed pursuant to Item 404 of Regulation S-K, except that Mr. Tidwell serves as the Vice President and Chief Financial Officer of WEDGE Group Incorporated, an affiliate of WEDGE. Mr. Tidwell is also Vice President of WEDGE. Mr. Tidwell is not independent because he is an officer of WEDGE Group Incorporated and was appointed to our compensation committee as a WEDGE nominee in connection with our sale of various securities to WEDGE. See also "Certain Relationships and Related Transactions" below for further information regarding the transactions with WEDGE.

During the 2004 fiscal year, none of our executive officers (1) served as a member of a compensation committee of another company, one of whose executive officers served on our compensation committee; (2) a director of another company, one of whose executive officers served on our compensation committee; or (3) a member of a compensation committee of another company, one of whose executive officers served as one of our directors.

EXECUTIVE COMPENSATION

Summary Compensation Table

The following table sets forth the compensation we paid or accrued for services performed during the fiscal years ended March 31, 2004, 2003 and 2002 by our Chief Executive Officer, our former Chief Executive Officer and our three other most highly compensated executive officers (the "named executive officers"). No other officer was paid compensation in excess of $100,000 during any of those fiscal years.

		Annual Compensation
Name and Principal Position	Fiscal Year	Annual Compensation				Securities Underlying Options
Name and Principal Position	Fiscal Year	Salary(1)		Bonus		Securities Underlying Options
Michael E. Little(2) Chief Executive Officer (November 1998 through December 2003)	2004 2003 2002	$ $ $	180,956 164,340 162,440	$	— — 78,843	250,000 — —
Wm. Stacy Locke President and Chief Executive Officer (December 2003—current)	2004 2003 2002	$ $ $	250,057 164,340 162,440	$	— — 78,843	110,000 — —
Franklin C. West Executive Vice President and Chief Operating Officer(3)	2004 2003 2002	$ $ $	187,000 185,500 41,885	$ $ $	50,000 50,000 50,000	100,000 — 450,000
William D. Hibbetts Senior Vice President, Chief Financial Officer and Secretary	2004 2003 2002	$ $ $	138,654 117,854 108,840	$	— — 27,210	125,000 — —
Donald G. Lacombe Senior Vice President—Marketing	2004 2003 2002	$ $ $	120,000 120,000 112,703	$	— — 19,047	100,000 — 50,000

(1): Includes vehicle allowances, when applicable, included in annual compensation, but excludes the value of perquisites and other personal benefits for the named executive officers because the aggregate amounts did not exceed 10% of the total annual salary and bonus reported for the named executive officers.
(2): Mr. Little's employment as Chief Executive Officer of our company terminated on December 8, 2003. However, he still serves as the chairman of our board of directors.
(3): Mr. West's employment with our company began on January 1, 2002.

Option Grants in Last Fiscal Year

Options were granted to the named executive officers during the fiscal year ended March 31, 2004 as follows:

	Individual Grants						Potential Realized Value at Assumed Annual Rates of Stock Price Appreciation For Option Term
	Number of Securities Underlying Options/SARs Granted	% of Total Options/SARs Granted to Employees in Fiscal Year
Name				Exercise or Base Price Per Share		Expiration Date
Name				Exercise or Base Price Per Share		Expiration Date	5%		10%
Michael E. Little	250,000	25.0	%	$	4.65	8/28/2013	$	731,090	$	1,852,726
Wm. Stacy Locke	100,000 10,000	10.0 1.0	% %	$ $	3.67 4.77	11/29/2013 1/4/2014	$ $	230,804 29,998	$ $	584,903 76,022
Franklin C. West	100,000	10.0	%	$	4.77	1/4/2014	$	299,983	$	760,215
William D. Hibbetts	50,000 75,000	5.0 7.5	% %	$ $	3.70 4.77	4/20/2013 1/4/2014	$ $	116,346 224,987	$ $	294,842 570,161
Donald G. Lacombe	50,000 50,000	5.0 5.0	% %	$ $	3.70 4.77	4/20/2013 1/4/2014	$ $	116,346 149,991	$ $	294,842 380,108

Stock Option Exercises and 2004 Fiscal Year-End Option Values

The following table details the number and value of securities exercised during the year ended March 31, 2004 by the named executive officers and of securities underlying unexercised options held by the named executive officers at March 31, 2004.

				Number of Securities Underlying Unexercised Options at Fiscal Year-End
						Value of Unexercised In-the-Money Options at Fiscal Year End(1)
Name	Shares Acquired on Exercise	Value Realized
Name	Shares Acquired on Exercise	Value Realized		Exercisable	Unexercisable	Exercisable		Unexercisable
Michael E. Little	650,000	$	4,062,500	—	250,000		—	$	500,000
Wm. Stacy Locke	—		—	400,000	110,000	$	2,510,000	$	316,800
Franklin C. West	—		—	350,000	200,000	$	1,277,500	$	553,000
William D. Hibbetts	15,000	$	29,400	—	135,000		—	$	332,500
Donald G. Lacombe	10,000	$	25,996	38,334	76,666	$	120,335	$	187,165

(1): Based on the closing price per share for our common stock on the AMEX on March 31, 2004.

Employment Agreements

On April 25, 1995, we entered into an employment agreement with Mr. Locke and have since amended it twice. Mr. Locke signed the second amendment to his employment agreement on August 21, 2000, with an initial term ending April 30, 2003; however, the agreement is automatically renewed after each one-year employment term. The agreement, as amended, specifies a minimum annual base salary of $150,000 and provides for a discretionary incentive bonus.

Under the agreement, if Mr. Locke were to resign as one of our directors, the agreement provides that, upon Mr. Locke's request, we would reappoint him to serve on our board of directors until the next annual meeting. Furthermore, following such reappointment, we would take all reasonable steps to make certain that Mr. Locke appeared on the authorized slate of nominees for our board of directors at all annual or special meetings of shareholders to vote for the election of directors.

If we were to terminate Mr. Locke without cause, as defined in the agreement, Mr. Locke would be entitled to be paid $150,000. In the event of Mr. Locke's death, we would pay his estate any and all

of his unpaid annual base salary and accrued benefits due to Mr. Locke through the date of his death. In addition, we would also pay his estate the annual base salary he would have earned for a period of ninety days following the date of his death and a pro rata amount of any discretionary bonus and any other amounts attributable to any bonus, incentive or similar program paid to Mr. Locke for the prior contract year, in the time and the manner that Mr. Locke would have been paid such compensation.

We entered into an employment agreement with Mr. West effective as of January 1, 2002, which expired pursuant to its terms on January 1, 2005. The agreement specified a minimum annual base salary of $175,000, provided various severance benefits and provided for a company-provided vehicle, including fuel, insurance, repair and maintenance. It also provided for a quarterly incentive bonus ranging from $12,500 to $43,750 and the grant of options to purchase an aggregate of 450,000 shares of our common stock. Mr. West's employment with us has continued since the expiration of his employment agreement. In connection with the continuation of Mr. West's employment, we increased Mr. West's annual salary effective as of January 1, 2005 and, on January 10, 2005, granted him options to acquire an additional 300,000 shares at an exercise price of $9.53 per share. Those options will become exercisable in 100,000 share increments on the first, second and third anniversaries of the date of grant.

SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT

The following table shows the beneficial ownership of our common stock as of January 31, 2005 by (1) each person we know who beneficially owns more than 5% of the outstanding shares of our common stock, (2) each of our directors, (3) our chief executive officer and each of our other executive officers named in the summary compensation table in this prospectus and (4) all our directors and executive officers as a group. All persons listed in the table below have sole voting and investment power with respect to their shares unless otherwise indicated. As of January 31, 2005, there were 38,914,978 shares of common stock outstanding. The number of shares and percentage of ownership for each person or entity listed assumes that options exercisable within 60 days of January 31, 2005 are outstanding, unless otherwise indicated. For all executive officers and directors, as a group, the table assumes all the options for the group that are exercisable within 60 days of January 31, 2005 are outstanding, unless otherwise indicated.

	Shares of Common Stock Beneficially Owned
Name and Address of Beneficial Owner	Number		Percent of Class
WEDGE Energy Services, L.L.C. and Mr. Issam M. Fares 1415 Louisiana, Suite 3000 Houston, Texas 77002	7,668,206	(1)	19.71	%
Chesapeake Energy Corporation 6100 N. Western Ave. Oklahoma City, OK 73154-0496	6,536,136	(2)	16.80	%
Wm. Stacy Locke	767,093	(3)	1.97	%
Michael E. Little	666,382		1.71	%
William D. Hibbetts	173,279	(4)	*
James M. Tidwell	25,000	(5)	*
C. John Thompson	—		—
Dean A. Burkhardt	—		—
C. Robert Bunch	10,000	(6)	*
Michael F. Harness	10,000	(7)	*
Franklin C. West	470,000	(8)	1.19	%
Donald G. Lacombe	76,667	(9)	*
All executive officers and directors as a group (10 persons)	2,198,421	(10)	5.56	%

*: Less than 1%
(1): Based on information included in a Schedule 13D that WEDGE Energy Services, L.L.C. and Mr. Issam M. Fares filed, as amended on September 14, 2004, as well as a review of our records. WEDGE has advised us that Mr. Fares is the ultimate beneficial owner of all the outstanding ownership interests of WEDGE. The Schedule 13D states that Mssrs. Tidwell and Little are officers of WEDGE.
(2): Based on information included in a Form 4 that Chesapeake filed on September 2, 2004.

(3): Includes 22,000 shares of common stock issuable under options that may be exercised within 60 days of January 31, 2005.
(4): Includes 20,001 shares of our common stock issuable under options that may be exercised within 60 days of January 31, 2005.
(5): Includes 25,000 shares of common stock issuable under options that may be exercised within 60 days of January 31, 2005.
(6): Includes 10,000 shares of common stock issuable under options that may be exercised within 60 days of January 31, 2005.
(7): Includes 10,000 shares of common stock issuable under options that may be exercised within 60 days of January 31, 2005.
(8): Includes 470,000 shares of common stock issuable under options that may be exercised within 60 days of January 31, 2005.
(9): Includes 76,667 shares of common stock issuable under options that may be exercised within 60 days of January 31, 2005.
(10): Includes 633,668 shares of common stock issuable under options that may be exercised within 60 days of January 31, 2005.

CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS

Transactions with WEDGE Energy Services, L.L.C.

On October 9, 2001, we issued a 6.75% five-year $18 million convertible subordinated debenture due July 3, 2007, Series A, to WEDGE. The debenture was convertible into 4,500,000 shares of common stock at $4.00 per share. We used approximately $9 million of the proceeds to complete the construction of two drilling rigs. We used approximately $6 million to reduce a $12 million credit facility. We used the balance of the proceeds for drilling equipment and working capital. On July 3, 2002, we issued an additional $10 million of 6.75% convertible subordinated debt to WEDGE with an effective conversion rate of $5.00 per share. The transaction was effected by an agreement between us and WEDGE under which WEDGE agreed to provide the additional $10 million in financing and to cancel the previously issued debenture in the principal amount of $18 million in exchange for $28 million in new 6.75% convertible subordinated debentures. The new debentures were convertible into 6,496,519 shares of common stock at $4.31 per share, which resulted from a pro rata blending of the $5.00 conversion rate of the new $10 million financing and the $4.00 conversion rate of the $18 million debenture being cancelled. WEDGE funded $7 million of the $10 million on July 3, 2002 and $2 million on July 29, 2002. William H. White, one of our former directors and the then President of WEDGE, purchased the remaining $1 million on July 29, 2002. We used $7 million of the proceeds from the new debt to pay down other outstanding bank debt and $3 million for the purchase of drilling equipment. The new debentures were subject to call provisions under which we could, at our option, prepay the new debentures after July 3, 2004, at 105% of principal through July 2, 2005, 104% through July 2, 2006, 103% through July 2, 2007, and 100% thereafter. On August 11, 2004, WEDGE and Mr. White converted all their new debentures into 6,496,519 shares of our common stock, immediately prior to the closing of our underwritten public offering of common stock on that date. Following exercise of demand registration rights by WEDGE, WEDGE, Michael E. Little and William H. White sold an aggregate of 6,419,320 shares of our common stock in that offering, including 837,302 shares which WEDGE sold pursuant to the underwriters' over-allotment option.

At our 2001 annual meeting, we adopted a proposal to institute a staggered board of directors. As a result, we have modified our voting agreement with WEDGE so that, as long as WEDGE owns at least 10% of our outstanding capital stock, we will support and cause to be placed on the ballot at any election of directors, one person designated by WEDGE who shall be a nominee to our board of directors, but only if it is necessary to cause at least one WEDGE board nominee to continue as a director after such election. We also agreed that, for as long as WEDGE owned at least 25% of our outstanding capital stock, we would support and cause to be placed on the ballot at any election of directors up to three persons designated by WEDGE as nominees to our board of directors, but only if necessary to cause at least three WEDGE board nominees to continue as directors after such election. If WEDGE had three nominees on the board of directors, at least one was required to be an individual with no affiliation to WEDGE or its affiliates. That nominee, if elected, would serve as an independent outside director. The August 2004 offering of shares of common stock by WEDGE and us reduced WEDGE's ownership percentage below this 25% threshold. WEDGE currently holds more than 10% of our outstanding capital stock. The offering of shares of common stock by WEDGE and us in this offering will reduce WEDGE's ownership percentage below the 10% threshold described above.

As of January 31, 2005, WEDGE owned 7,668,206 shares of our common stock, which constituted approximately 19.71% of our issued and outstanding common stock. WEDGE is selling 5,000,000 shares of our common stock (5,787,500 if the underwriters exercise their over-allotment option in full) which it holds pursuant to the offering described in this prospectus. Assuming WEDGE sells 5,000,000 shares of our common stock and we also sell 5,000,000 shares of our common stock, WEDGE will beneficially own 2,668,206 shares of our common stock, which would constitute approximately 6.1% of our outstanding common stock.

We have granted WEDGE demand registration rights and piggyback registration rights in connection with our sales of shares of common stock and convertible debentures to WEDGE. These rights generally obligate us to cause the registration of the shares of common stock that WEDGE holds upon WEDGE's request; however, while WEDGE can cause us to effect the registration of its shares an unlimited number of times under its piggyback registration rights, WEDGE can only cause us to effect the registration of its shares a total of four times under its demand registration rights. We effected the registration of the offering of the shares of common stock that WEDGE made in the August 2004 public offering pursuant to its demand registration rights. We are effecting the registration of the offering of the shares of common stock that WEDGE is making in this offering pursuant to its piggyback registration rights.

We have also granted WEDGE a preemptive right to acquire equity securities we may issue in the future under specified circumstances, in order to permit WEDGE to maintain its proportionate ownership of our outstanding shares of common stock. WEDGE has waived its preemptive rights with respect to this offering.

Transactions with Chesapeake Energy Corporation

On March 31, 2003, we sold 5,333,333 shares of our common stock to Chesapeake for $20,000,000 ($3.75 per share), before related offering expenses. In connection with that sale, we granted Chesapeake a preemptive right to acquire equity securities we may issue in the future, under specified circumstances, in order to permit Chesapeake to maintain its proportionate ownership of our outstanding shares of common stock. Chesapeake exercised its preemptive right to acquire a total of 725,803 shares in connection with our August 2004 public offering. Promptly after we file the registration statement of which this prospectus is a part with the SEC, we intend to provide Chesapeake with notice of our intent to sell shares of our common stock in this offering. Chesapeake may then be able to exercise its preemptive right with respect to shares we offer in this offering, provided that it gives us notice of its intent to exercise within 10 days and certain other conditions are met.

In connection with the March 31, 2003 sale transaction, we also granted Chesapeake a right, under certain circumstances, to request registration of its shares under the Securities Act of 1933. In accordance with the provisions of our agreement with Chesapeake, we have obtained a written waiver from Chesapeake of its right to include shares in this offering.

Based on a Form 4 filed on September 2, 2004, as of January 31, 2005, Chesapeake owned approximately 16.80% of our outstanding common stock. In addition to being one of our shareholders, Chesapeake is, from time to time, one of our customers. During the year ended March 31, 2004, we recognized revenues of approximately $924,000 and recorded contract drilling costs of approximately $745,000, excluding depreciation, on one daywork contract with Chesapeake. During the nine-month period ended December 31, 2004, we recognized revenues of approximately $1,349,000 and recorded contract drilling costs of approximately $837,000, excluding depreciation, on 2 daywork contracts and four footage contracts with Chesapeake.

SELLING SHAREHOLDERS

This prospectus covers the resale of 5,500,000 shares of our common stock held by the selling shareholders identified below. The selling shareholders acquired the shares from us in private placements. We are registering the resale of the shares offered by WEDGE to satisfy piggyback registration rights held by WEDGE. We will bear the expenses incurred in connection with the registration of the shares of our common stock being offered by WEDGE pursuant to this prospectus. The following table sets forth:

•: the names of the selling shareholders;
•: the number and percent of shares of our common stock that each of the selling shareholders beneficially owned as of January 31, 2005, before the offering for resale of the shares under this prospectus;
•: the number of shares of our common stock that may be offered for resale for the account of the selling shareholders under this prospectus; and
•: the number and percent of shares of our common stock to be beneficially owned by the selling shareholders after the offering of the resale shares (assuming all of the offered resale shares are sold by the selling shareholders and the underwriters' over-allotment option is not exercised).

The number of shares in the column "Number of Shares Offered" represents all of the shares that each selling shareholder may offer under this prospectus assuming no exercise of the underwriters' over-allotment option. Neither of the selling shareholders has, within the past three years, had any position, office or other material relationship with us or any of our predecessors or affiliates, except as noted in the footnotes to the table below. This table is prepared solely based on information supplied to us by the selling shareholders. The applicable percentages of beneficial ownership are based on an aggregate of shares of our common stock issued and outstanding on January 31, 2005, adjusted as may be required by rules of the SEC.

	Shares Beneficially Owned Before Offering				Shares Beneficially Owned After Offering
Selling Shareholders	Shares Beneficially Owned Before Offering			Number of Shares Offered	Shares Beneficially Owned After Offering
Selling Shareholders	Number	Percent		Number of Shares Offered	Number	Percent
WEDGE Energy Services(1)(2)	7,668,206	19.71	%	5,000,000	2,668,206	6.1	%
Michael E. Little(3)	666,382	1.71	%	500,000	166,382	*

*: Less than 1%.
(1): WEDGE has granted the underwriters the right to purchase up to 787,500 additional shares of common stock to cover over-allotments.
(2): See "Certain Relationships and Related Transactions—Transactions with WEDGE Energy Services, L.L.C." for a description of a voting agreement between WEDGE and us.
(3): Mr. Little is the chairman of our board of directors and was chief executive officer from November 1998 until December 2003. He is also the President and Chief Executive Officer of WEDGE Group Incorporated, one of our affiliates.

DESCRIPTION OF CAPITAL STOCK

The following description of our common stock, Articles of Incorporation, as amended, and our Amended and Restated Bylaws are summaries thereof and are qualified by reference to Articles of Incorporation, as amended, and our Amended and Restated Bylaws, copies of which have been filed with the Securities and Exchange Commission as exhibits to the registration statement of which this prospectus is a part.

Our authorized capital stock consists of 100,000,000 shares of common stock, par value $0.10 per share and 10,000,000 shares of preferred stock, par value $1.00 per share. Our shares of common stock are listed on the AMEX.

Common Stock

Holders of shares of common stock are entitled to one vote per share on all matters submitted to a vote of shareholders. Shares of common stock do not have cumulative voting rights, which means that the holders of more than 50% of the shares voting for the election of the board of directors can elect all the directors to be elected at that time, and, in such event, the holders of the remaining shares will be unable to elect any directors to be elected at that time. Our Articles of Incorporation deny shareholders any preemptive rights to acquire or subscribe for any stock, obligation, warrant or other securities of ours. Holders of shares of our common stock have no redemption or conversion rights nor are they entitled to the benefits of any sinking fund provisions.

In the event of our liquidation, dissolution or winding up, holders of shares of common stock shall be entitled to receive, pro rata, all the remaining assets of our company available for distribution to our shareholders after payment of our debts and after there shall have been paid to or set aside for the holders of capital stock ranking senior to common stock in respect of rights upon liquidation, dissolution or winding up the full preferential amounts to which they are respectively entitled.

Holders of record of shares of common stock are entitled to receive dividends when and if declared by the board of directors out of any assets legally available for such dividends, subject to both the rights of all outstanding shares of capital stock ranking senior to the common stock in respect of dividends and to any dividend restrictions contained in debt agreements.

Preferred Stock

We are authorized to issue up to 10,000,000 shares of preferred stock, par value $1.00 per share, which may be divided into and issued in one or more series, the relative rights and preferences of which series may vary in any and all respects. Our board of directors has the authority, without shareholder approval, to issue shares of preferred stock in one or more series and to determine the number of shares, designations, dividend rights, voting power, redemption rights, liquidation preferences, sinking funds, conversion rights, repurchase options and other terms of any such series.

The issuance of preferred stock, while providing flexibility in connection with possible acquisitions and other corporate purposes, could adversely affect the voting power of holders of common stock and the likelihood that such holders will receive dividend payments and payments on liquidation and could have the effect of delaying, deferring or preventing a change in control of us.

Classification of Board of Directors and Certain Potential Anti-takeover Effects

Our board of directors is divided into three classes, as nearly equal in number as possible, serving staggered three-year terms and until their successors are elected and qualified. The term of a member of our board of directors may be shortened by death, resignation, or removal from office.

Classification of our board of directors could:

•: make it more difficult for a substantial shareholder to rapidly change control of us;
•: entrench management;
•: make it more difficult to effect a merger or similar transaction even if the transaction is favored by a majority of independent shareholders; and
•: discourage actions to acquire control of us by extending the time needed to effect a change in control of the board of directors because only a minority of the directors are elected at each annual meeting.

Advance Notice Requirement for Shareholder Meetings

Our bylaws establish advance-notice and other procedural requirements that apply to shareholder nominations of persons for election to our board of directors at any annual or special meeting of shareholders and to shareholder proposals that shareholders take any other action at any annual meeting. In the case of any annual meeting, subject to some exceptions, a shareholder proposing to nominate a person for election to our board of directors or proposing that any other action be taken must give our corporate secretary proper written notice of the proposal not later than the close of business on the 90th day and not earlier than the 180th day before the anniversary date of the immediately preceding annual meeting. If the chairman of our board of directors, a majority of our board of directors or our chief executive officer calls a special meeting of shareholders for the election of directors, a shareholder proposing to nominate a person for that election must give our corporate secretary written notice of the proposal not earlier than 180 days prior to that special meeting and not later than the last to occur of the close of business on (1) the 90th day prior to that special meeting or (2) the 10th day following the day we publicly disclose the date of the special meeting.

The advance-notice procedure may have the effect of precluding a contest for the election of directors or the consideration of shareholder proposals if the proper procedures are not followed, and of discouraging or deterring a third party from conducting a solicitation of proxies to elect its own slate of directors or to approve its own proposal, without regard to whether consideration of those nominees or proposals might be harmful or beneficial to us and our shareholders.

Transfer Agent and Registrar

Registrar & Transfer Company is the transfer agent and registrar for our common stock.

UNDERWRITING

Subject to the terms and conditions set forth in an underwriting agreement among us, the selling shareholders and the underwriters named below, each of the underwriters named below have severally agreed to purchase from us and the selling shareholders the respective number of shares of common stock indicated in the following table.

Underwriters		Number of Shares
Jefferies & Company, Inc.
Raymond James & Associates, Inc.
Johnson Rice & Company L.L.C.
Pritchard Capital Partners, LLC

Total		10,500,000

The underwriting agreement provides that the underwriters' obligation to purchase shares of our common stock from us and the selling shareholders depends on the satisfaction of the conditions contained in the underwriting agreement, including:

•: the representations and warranties made by us and the selling shareholders to the underwriters are true;
•: there has been no material adverse change in our condition or in the financial markets; and
•: we and the selling shareholders deliver to the underwriters the customary closing documents.

Over-Allotment Option

The underwriters have a 30-day option after the date of the underwriting agreement to purchase, in whole or in part, an additional 787,500 shares of common stock from us and an additional 787,500 shares of common stock from one of the selling shareholders, WEDGE, at the public offering price less the underwriting discounts and commissions. Such option may be exercised to cover over-allotments, if any, made in connection with the common stock offering. To the extent that the option is exercised, each underwriter will be obligated, subject to certain conditions, to purchase its pro rata portion of these additional shares of common stock based on the underwriter's percentage underwriting commitment in the offering as indicated in the preceding table.

Commission and Expenses

We have been advised by the underwriters that they propose to offer the common stock directly to the public at the public offering price set forth on the front cover page of this prospectus and to selected dealers (who may include the underwriters) at the offering price less a selling concession not in excess of $ per share. The underwriters may allow, and the selected dealers may reallow, a discount from the concession not in excess of $ per share to other dealers. After the common stock offering, the underwriters may change the offering price and other selling terms.

The following table shows the underwriting fees to be paid to the underwriters by us and the selling shareholders in connection with this offering. These amounts are shown assuming both no exercise and full exercise of the underwriters' over-allotment option to purchase additional shares of

our common stock from us and WEDGE. The underwriting fee is the difference between the initial price to the public and the amount the underwriters pay to us to purchase the shares.

	No Exercise	Full Exercise
Per share	$	$
Total underwriting fees to be paid by us	$	$
Total underwriting fees to be paid by the selling shareholders	$	$

We estimate the total expenses payable by us in connection with the offering, excluding underwriting discounts and commissions, will be approximately $400,000. The selling shareholders will not bear any portion of these expenses.

Stabilization, Short Positions and Penalty Bids

In connection with this offering, the underwriters may engage in stabilizing transactions, over-allotment transactions, syndicate covering transactions and penalty bids or purchases for the purpose of pegging, fixing or maintaining the price of the common stock in accordance with Regulation M under the Exchange Act.

•: Stabilizing transactions permit bids to purchase the underlying security so long as the stabilizing bids do not exceed a specified maximum.
•: Over-allotment transactions involve sales by the underwriters of the shares of common stock in excess of the number of shares the underwriters are obligated to purchase, which create a syndicate short position. The short position may be either a covered short position or a naked short position. In a covered short position, the number of shares of common stock over-allotted by the underwriters is not greater than the number of shares of common stock that they may purchase in the over-allotment option. In a naked short position, the number of shares of common stock involved is greater than the number of shares in the over-allotment option. The underwriters may close out any short position by either exercising their over-allotment option and/or purchasing the shares in the open market.
•: Syndicate covering transactions involve purchases of shares of common stock in the open market after the distribution has been completed in order to cover syndicate short positions. In determining the source of the shares of common stock to close out the short position, the underwriters will consider, among other things, the price of shares of common stock available for purchase in the open market as compared to the price at which they may purchase shares through the over-allotment option. If the underwriters sell more shares of common stock than could be covered by the over-allotment option, a naked short position, the position can only be closed out by buying shares in the open market. A naked short position is more likely to be created if the underwriters are concerned that there could be downward pressure on the price of the shares of common stock in the open market after pricing that could adversely affect investors who purchase in the offering.
•: Penalty bids permit the representatives to reclaim a selling concession from a syndicate member when the shares of common stock originally sold by the syndicate member are purchased in a stabilizing or syndicate covering transaction to cover a syndicate short position.

These stabilizing transactions, syndicate covering transactions and penalty bids may have the effect of raising or maintaining the market price of our common stock or preventing or retarding a decline in the market price of the common stock. As a result, the price of the common stock may be higher than the price that might otherwise exist in the open market. These transactions may be effected on the American Stock Exchange or otherwise and, if commenced, may be discontinued at any time.

Neither we nor any of the underwriters make any representation or prediction as to the direction or magnitude of any effect that the transactions described above may have on the price of the common stock. In addition, neither we nor any of the underwriters make any representation that the underwriters will engage in these stabilizing transactions or that any transaction, once commenced, will not be discontinued without notice.

Indemnification

We and the selling shareholders have agreed to indemnify the underwriters against certain liabilities, including liabilities under the Securities Act, or to contribute payments that may be required to be made in respect thereof.

Lock-up Agreements

Our directors and executive officers, the selling shareholders and other significant shareholders have agreed, with limited exceptions, for a period of 60 days after the date of this prospectus not to, directly or indirectly, offer, sell or otherwise dispose of any shares of common stock or securities convertible into or exchangeable or exercisable for any shares of common stock or enter into any derivative transaction with similar effect as a sale of common stock, otherwise than (1) as a bona fide gift or gifts, provided the donee or donees thereof agree in writing to be bound by the lock-up restrictions; (2) as a distribution to members or shareholders, provided that the distributees agree in writing to be bound by the lock-up restrictions; (3) with respect to dispositions of common stock acquired in the open market; or (4) with the prior written consent of Jefferies & Company, Inc.

We have also agreed, with limited exceptions, for a period of 60 days after the date of this prospectus not to, directly or indirectly, offer, sell or otherwise dispose of any shares of common stock or securities convertible into or exchangeable or exercisable for any shares of common stock or enter into any derivative transaction with similar effect as a sale of common stock, except that we may issue shares of common stock (1) in connection with acquisitions and (2) under employee benefit plans, including stock option plans, existing as of the date of this prospectus.

Jefferies & Company, Inc. may, however, in its sole discretion and at any time or from time to time before the termination of the 60-day period, without notice, release all or any portion of the securities subject to lock-up agreements.

Listing

Our shares of common stock are traded on the American Stock Exchange under the symbol "PDC."

Prior Transactions

The underwriters from time to time have provided and in the future may provide investment banking and financial advisory services to us and our affiliates in the ordinary course of their business. In the past few years, one or more of the underwriters have performed various services for us, including acting as (1) underwriters in our August 2004 public offering of common stock, (2) placement agents in our February 2004 private placement of common stock, and (3) placement agent in our March 2003 private placement of common stock to Chesapeake, in each case for which they received customary cash compensation.

Discretionary Sales

No sales to accounts over which the underwriters have discretionary authority may be made without the prior written approval of the customer.

Electronic Distribution

A prospectus in electronic format may be made available on Internet sites or through other online services maintained by one or more of the underwriters and/or selling group members participating in this common stock offering, or by their affiliates. In those cases, prospective investors may view offering terms online and, depending on the particular underwriter or selling group member, prospective investors may be allowed to place orders online. The underwriters may agree with us to allocate a specific number of shares of common stock for sale to online brokerage account holders. Any such allocation for online distributions will be made by the representatives on the same basis as other allocations.

Other than the prospectus in electronic format, the information on any underwriter's or selling group member's website and any information contained in any other website maintained by any underwriter or selling group member is not part of this prospectus or the registration statement of which this prospectus forms a part, has not been approved and/or endorsed by us or any underwriter or selling group member in its capacity as underwriter or selling group member and should not be relied upon by investors.

LEGAL MATTERS

Baker Botts L.L.P., Houston, Texas, will pass on certain legal matters for us in connection with the common stock offered by this prospectus. Fulbright & Jaworski L.L.P. will pass on certain legal matters for the underwriters in connection with the common stock offered by this prospectus.

EXPERTS

The consolidated financial statements of Pioneer and subsidiaries as of March 31, 2004 and 2003, and for each of the years in the three-year period ended March 31, 2004, appearing in this prospectus and the registration statement of which this prospectus is a part, have been audited by KPMG LLP, independent registered public accounting firm, as set forth in their report thereon appearing in this prospectus, and are included in reliance upon such report given on the authority of said firm as experts in accounting and auditing.

The audited financial statements for Wolverine Drilling, Inc. as of and for the year ended December 31, 2003 appearing in this prospectus and the registration statement of which this prospectus is a part, have been audited by Brady, Martz & Associates, P.C., independent registered public accounting firm, as set forth in their report thereon appearing in this prospectus, and are included in reliance upon the authority of said firm as experts in accounting and auditing.

The consolidated financial statements for Allen Drilling Company as of and for the year ended September 30, 2004 appearing in this prospectus and the registration statement of which this prospectus is a part, have been audited by Kennedy and Coe, LLC, public accounting firm, as set forth in their report thereon appearing in this prospectus, and are included in reliance upon the authority of said firm as experts in accounting and auditing.

WHERE YOU CAN FIND MORE INFORMATION

We have filed with the SEC a registration statement on Form S-1 under the Securities Act of 1933 with respect to the shares of common stock offered hereby. This prospectus does not contain all of the information set forth in the registration statement, certain portions of which are omitted as permitted by the rules and regulations of the SEC. For further information pertaining to us and the common stock to be sold in this offering, reference is made to the registration statement, including the exhibits thereto and the financial statements, notes and schedules filed as a part of that registration statement. Statements contained in this prospectus regarding the contents of any contract or other document referred to in those documents are not necessarily complete, and in each instance reference is made to the copy of the contract or other document filed as an exhibit to the registration statement or other document, each statement being qualified in all respects by that reference.

You may read and copy all or any portion of the registration statement and the exhibits at the SEC's public reference room at 450 Fifth Street N.W., Washington, D.C. 20549. You can request copies of these documents, upon payment of a duplication fee, by writing to the SEC. You may call the SEC at 1-800-SEC-0330 for further information on the operation of the SEC's public reference rooms. In addition, the SEC maintains a website on the Internet at http://www.sec.gov that contains reports, proxy and information statements and other information regarding registrants that file electronically with the SEC.

We are subject to the information and periodic reporting requirements of the Securities Exchange Act of 1934, as amended and, in accordance with those requirements, file periodic reports, proxy and information statements and other information with the SEC. These periodic reports, proxy and information statements and other information are not incorporated herein by reference but are available on our web site, http://www.pioneerdrlg.com, and are available for inspection and copying at the public reference facility and SEC's website referred to above. Information contained in our website is not incorporated by reference into this prospectus and you should not consider information contained in our website as part of this prospectus.

INDEX TO FINANCIAL STATEMENTS

Unaudited Pro Forma Combined Financial Statements
	Basis of Presentation	F-2
	Unaudited Pro Forma Combined Statement of Operations for the Year Ended March 31, 2004	F-3
	Unaudited Pro Forma Combined Statement of Operations for the Nine Months Ended December 31, 2004	F-4
	Unaudited Pro Forma Combined Statement of Operations for the Nine Months Ended December 31, 2003	F-5
	Notes to Unaudited Pro Forma Combined Financial Statements	F-6
Historical Financial Statements
Pioneer Drilling Company
	Report of Independent Registered Public Accounting Firm	F-8
	Consolidated Balance Sheets as of March 31, 2004 and 2003	F-9
	Consolidated Statements of Operations for the Years Ended March 31, 2004, 2003 and 2002	F-10
	Consolidated Statements of Shareholders' Equity and Comprehensive Income for the Years Ended March 31, 2004, 2003 and 2002	F-11
	Consolidated Statements of Cash Flows for the Years Ended March 31, 2004, 2003 and 2002	F-12
	Notes to Consolidated Financial Statements	F-13
	Unaudited Condensed Consolidated Balance Sheet as of December 31, 2004	F-28
	Unaudited Condensed Consolidated Statements of Operations for the Nine Months Ended December 31, 2004 and 2003	F-29
	Unaudited Condensed Consolidated Statements of Cash Flows for the Nine Months Ended December 31, 2004 and 2003	F-30
	Notes to Unaudited Condensed Consolidated Financial Statements	F-31
Wolverine Drilling, Inc.
	Report of Independent Auditors of Wolverine Drilling, Inc.	F-38
	Balance Sheet as of December 31, 2003	F-39
	Statement of Operations for the Year Ended December 31, 2003	F-40
	Statement of Stockholders' Equity for the Year Ended December 31, 2003	F-41
	Statement of Cash Flows for the Year Ended December 31, 2003	F-42
	Notes to Financial Statements	F-43
	Accountant's Compilation Report of Wolverine Drilling, Inc.	F-48
	Balance Sheet as of September 30, 2004	F-49
	Statement of Operations for the Nine Months Ended September 30, 2004	F-50
	Statement of Stockholders' Equity for the Nine Months Ended September 30, 2004	F-51
	Statement of Cash Flows for the Nine Months Ended September 30, 2004	F-52
	Notes to Financial Statements	F-53
Allen Drilling Company
	Report of Independent Auditors of Allen Drilling Company	F-57
	Balance Sheets as of September 30, 2003 and 2004	F-58
	Statements of Income for the Years Ended September 30, 2004 and 2003	F-60
	Statements of Changes in Stockholders' Equity for the Years Ended September 30, 2004 and 2003	F-61
	Statements of Cash Flows for the Years Ended September 30, 2004 and 2003	F-62
	Notes to Financial Statements	F-64

F-1

PIONEER DRILLING COMPANY AND SUBSIDIARIES

UNAUDITED PRO FORMA COMBINED FINANCIAL STATEMENTS

BASIS OF PRESENTATION

On November 30, 2004, we acquired a fleet of seven drilling rigs and related equipment from Wolverine Drilling, Inc., obtained noncompetition agreements from the two stockholders of Wolverine and purchased a 4.7-acre rig storage and maintenance yard in Kenmore, North Dakota for total consideration of $28,000,000 in cash. On December 15, 2004, we acquired a fleet of five drilling rigs and related equipment and a 17-acre rig storage and maintenance yard located in Woodward, Oklahoma from Allen Drilling Company for total consideration of $7,200,000 in cash. We also obtained a noncompetition agreement from the President of Allen Drilling for additional consideration to be paid over the next five years. We funded the purchase price for each of these acquisitions with borrowings under our new credit facility aggregating $35,200,000.

The accompanying combined pro forma statements of operations combine the operations of (1) Pioneer Drilling Company and its consolidated subsidiaries, (2) Wolverine and (3) Allen Drilling, and reflect the interest on the borrowings we made to fund our acquisitions of the assets of those two companies, for the nine months ended December 31, 2004 and 2003 and the year ended March 31, 2004. The statements include pro forma adjustments to reflect increases in interest expense and depreciation expense assuming the acquisitions had occurred at the beginning of each period presented and to adjust income tax expense (benefit) for the effects of the other pro forma adjustments. The unaudited pro forma combined financial statements should be read in conjunction with (i) the audited historical consolidated financial statements of Pioneer Drilling Company for the year ended December 31, 2004; (ii) the audited historical financial statements of Wolverine for the year ended December 31, 2003; and (iii) the historical financial statements of Allen Drilling for the year ended September 30, 2004.

The unaudited pro forma combined statements of operations are not necessarily indicative of the operating results that would have occurred if the acquisitions had been consummated at the beginning of the periods presented nor are they indicative of any future operating results.

F-2

PIONEER DRILLING COMPANY AND SUBSIDIARIES
UNAUDITED PRO FORMA COMBINED STATEMENTS OF OPERATIONS
FOR THE YEAR ENDED MARCH 31, 2004

		Historical
		Pioneer Drilling Company			Wolverine Drilling, Inc.(1)			Allen Drilling Company(2)			Pro Forma Adjustments			Pro Forma Combined
Contract drilling revenues		$	107,875,533		$	11,212,051		$	13,199,556		$	—		$	132,287,140

Costs & Expenses:
	Contract drilling		88,504,102			8,710,109			10,166,123			—			107,380,334
	Depreciation and amortization		16,160,494			1,198,106			680,249	(A)		2,652,892			20,691,741
	General and administrative		2,772,730			30,551			356,393			—			3,159,674

	Total operating costs and expenses		107,437,326			9,938,766			11,202,765			2,652,892			131,231,749

Earnings (loss) from operations			438,207			1,273,285			1,996,791			(2,652,892	)		1,055,391

Other income (expense):
	Interest expense		(2,807,822	)		(214,594	)		(49,898	) (B)		(1,067,976	)		(4,140,290	)
	Interest income		101,584			—			28,181			—			129,765
	Other		51,675			48,885			16,580			—			117,140

	Total other income (expense)		(2,654,563	)		(165,709	)		(5,137	)		(1,067,976	)		(3,893,385	)

Earnings (loss) before tax			(2,216,356	)		1,107,576			1,991,654			(3,720,868	)		(2,837,994	)
Income tax (expense) benefit			426,299			—			(696,077	) (C)		1,007,656			737,878

Net earnings (loss)		$	(1,790,057	)	$	1,107,576		$	1,295,577		$	(2,713,212	)	$	(2,100,116	)

Earnings (loss) per common:
	Basic	$	(0.08	)										$	(0.09	)

	Diluted	$	(0.08	)										$	(0.09	)

Weighted average number of shares outstanding:
	Basic		22,585,612												22,585,612

	Diluted		22,585,612												22,585,612

(1): The financial statements for Wolverine for the year ended March 31, 2004 were derived by adding the three months ended March 31, 2004 to Wolverine's year ended December 31, 2003 and removing the three months ended March 31, 2003.
(2): The financial statements for Allen Drilling for the year ended March 31, 2004 were derived by adding the six months ended March 31, 2004 to Allen Drilling's year ended September 30, 2003 and removing the six months ended March 31, 2003.

F-3

PIONEER DRILLING COMPANY AND SUBSIDIARIES
UNAUDITED PRO FORMA COMBINED STATEMENTS OF OPERATIONS
FOR THE NINE MONTHS ENDED DECEMBER 31, 2004

		Historical
		Pioneer Drilling Company			Wolverine Drilling, Inc.(1)			Allen Drilling Company(2)			Pro Forma Adjustments			Pro Forma Combined
Contract drilling revenues		$	129,889,335		$	11,642,362		$	11,071,009		$	—		$	152,602,706

Costs & Expenses:
	Contract drilling		100,802,087			8,297,902			8,496,004			—			117,595,993
	Depreciation and amortization		16,124,316			740,086			449,506	(A)		1,870,347			19,184,255
	General and administrative		2,910,880			256,195			369,177						3,536,252
	Bad debt expense		342,000			—			—			—			342,000

	Total operating costs and expenses		120,179,283			9,294,183			9,314,687			1,870,347			140,658,500

Earnings (loss) from operations			9,710,052			2,348,179			1,756,322			(1,870,347	)		11,944,206

Other income (expense):
	Interest expense		(1,275,110	)		(103,352	)		(51,142	) (B)		(585,626	)		(2,015,230	)
	Loss from early extinguishment of debt		(100,833	)		—			—			—			(100,833	)
	Interest income		118,756			—			7,038			—			125,794
	Other		22,310			16,758			3,838			—			42,906

	Total other income (expense)		(1,234,877	)		(86,594	)		(40,266	)		(585,626	)		(1,947,363	)

Earnings (loss) before tax			8,475,175			2,261,585			1,716,056			(2,455,973	)		9,996,843
Income tax (expense) benefit			(3,157,003	)		—			(621,046	) (C)		54,225			(3,723,824	)

Net earnings (loss)		$	5,318,172		$	2,261,585		$	1,095,010		$	(2,401,748	)	$	6,273,019

Earnings (loss) per common:
	Basic	$	0.16											$	0.19

	Diluted	$	0.16											$	0.18

Weighted average number of shares outstanding:
	Basic		33,000,547												33,000,547

	Diluted		37,167,050												37,167,050

(1): The financial statements for Wolverine for the interim period ended December 31, 2004 were derived by adding the two months ended November 30, 2004 to Wolverine's nine-months ending September 30, 2004 and removing the three months ending March 31, 2004.
(2): The financial statements for Allen Drilling for the interim period ended December 31, 2004 were derived by adding the period from October 1, 2004 to December 15, 2004 to Allen Drilling's year ended September 30, 2004 and removing the three months ended March 31, 2004.

F-4

PIONEER DRILLING COMPANY AND SUBSIDIARIES
UNAUDITED PRO FORMA COMBINED STATEMENTS OF OPERATIONS
FOR THE NINE MONTHS ENDED DECEMBER 31, 2003

		Historical
		Pioneer Drilling Company			Wolverine Drilling, Inc.(1)			Allen Drilling Company(2)			Pro Forma Adjustments			Pro Forma Combined
Contract drilling revenues		$	74,508,827		$	8,207,985		$	9,777,767		$	—		$	92,494,579

Costs & Expenses:
	Contract drilling		61,757,266			6,220,381			7,374,509			—			75,352,156
	Depreciation and amortization		11,670,538			846,025			484,103	(A)		2,068,307			15,068,973
	General and administrative		2,027,132			22,646			261,227			—			2,311,005

	Total operating costs and expenses		75,454,936			7,089,052			8,119,839			2,068,307			92,732,134

Earnings (loss) from operations			(946,109	)		1,118,933			1,657,928			(2,068,307	)		(237,555	)

Other income (expense):
	Interest expense		(2,117,226	)		(164,400	)		(38,086	) (B)		(822,911	)		(3,142,623	)
	Interest income		86,776			—			26,062			—			112,838
	Other		65,056			21,118			16,234			—			102,408

	Total other income (expense)		(1,965,394	)		(143,282	)		4,210			(822,911	)		(2,927,377	)

Earnings (loss) before tax			(2,911,503	)		975,651			1,662,138			(2,891,218	)		(3,164,932	)
Income tax (expense) benefit			712,453			—			(568,555	) (C)		678,984			822,882

Net earnings (loss)		$	(2,199,050	)	$	975,651		$	1,093,583		$	(2,212,234	)	$	(2,342,050	)

Earnings (loss) per common:
	Basic	$	(0.10	)										$	(0.11	)

	Diluted	$	(0.10	)										$	(0.11	)

Weighted average number of shares outstanding:
	Basic		21,983,730												21,983,730

	Diluted		21,983,730												21,983,730

(1): The financial statements for Wolverine for the interim period ended December 31, 2003 were derived by adding the three months ended December 31, 2003 to Wolverine's nine-months ended September 30, 2003 and removing the three months ending March 31, 2003.
(2): The financial statements for Allen Drilling for the interim period ended December 31, 2003 were derived by adding the three months ended December 31, 2003 to Allen Drilling's year ended September 30, 2003 and removing the three months ended March 31, 2003.

F-5

PIONEER DRILLING COMPANY AND SUBSIDIARIES
NOTES TO UNAUDITED PRO FORMA COMBINED STATEMENTS OF OPERATIONS

The accompanying pro forma combined statements of operations combine the operations of Pioneer Drilling Company and its consolidated subsidiaries, Wolverine Drilling, Inc. and Allen Drilling Company for the nine months ended December 31, 2004 and 2003 and the year ended March 31, 2004. The following notes include pro forma adjustments to the pro forma combined statements of operations to reflect increases in interest expense and depreciation expense assuming our acquisitions of the assets of these two companies had occurred at the beginning of each period presented and to adjust income tax expense/benefit for the effect of the other proforma adjustments.

A.: To reflect the increase in amortization of intangible assets due to non-compete agreements and customer lists:

						Nine Months Ended December 31,
		Wolverine Amount		Allen Drilling Amount		Nine Months Ended December 31,				Year Ended March 31, 2004
		Wolverine Amount		Allen Drilling Amount		2004		2003		Year Ended March 31, 2004
Non-compete agreement	3 years	$	50,000	$	—	$	11,111	$	12,500	$	16,667
Non-compete agreement	5 years		50,000		475,114		73,974		78,767		105,023
Customer lists	1 year		15,000		12,500		18,856		20,625		27,500

Amortization adjustment						$	103,941	$	111,892	$	149,189

To reflect the increase in depreciation expense resulting from the purchase price allocation of property and equipment depreciated on a straight line basis over three to 10 years for the purchased drilling equipment and 20 years for the purchased building:

						Nine Months Ended December 31,
		Wolverine Amount		Allen Drilling Amount		Nine Months Ended December 31,						Year Ended March 31, 2004
		Wolverine Amount		Allen Drilling Amount		2004			2003			Year Ended March 31, 2004
Rigs	10 years	$	24,494,233	$	6,943,164	$	2,124,756		$	2,357,805		$	3,143,740
Yard equipment and pipe	3 years		3,171,327		233,255		759,813			851,146			1,134,861
Vehicles	5 years		214,786		230,000		61,221			66,718			88,957
Building	20 years		30,000		260,000		10,208			10,875			14,500

							2,955,998			3,286,543			4,382,057
Less amount recorded by Wolverine and Allen Drilling							(1,189,592	)		(1,330,128	)		(1,878,355	)

Depreciation adjustment							1,766,406			1,956,415			2,503,702

Total depreciation and amortization adjustment						$	1,870,347		$	2,068,307		$	2,652,892

B.: To reflect the increase in interest expense resulting from the issuance of debt to finance the purchase of Wolverine and Allen Drilling:

	Nine Months Ended December 31,
	Nine Months Ended December 31,						Year Ended March 31, 2004
	2004			2003			Year Ended March 31, 2004
Interest on bank debt and discount on non-compete agreement	$	740,120		$	1,025,397		$	1,332,468
Less interest recorded by Wolverine and Allen Drilling		(154,494	)		(202,486	)		(264,492	)

Interest expense adjustment	$	585,626		$	822,911		$	1,067,976

F-6

C.: To reflect the income tax effects of the other pro forma adjustments for Wolverine and Allen Drilling, including adjustments to reflect tax on historical income of Wolverine, which historically was a Subchapter S Corporation:

	Nine Months Ended December 31,
	Nine Months Ended December 31,						Year Ended March 31, 2004
	2004			2003			Year Ended March 31, 2004
Pro forma earnings (loss) before tax	$	9,996,843		$	(3,164,932	)	$	(2,837,994	)
Effective tax rate		37.25	%		26.00	%		26.00	%

Pro forma income tax (expense) benefit		(3,723,824	)		822,882			737,878
Less historical income tax (expense) benefit		(3,778,049	)		143,898			(269,778	)

Income tax adjustment	$	54,225		$	678,984		$	1,007,656

F-7

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Shareholders
Pioneer Drilling Company:

We have audited the accompanying consolidated balance sheets of Pioneer Drilling Company and subsidiaries as of March 31, 2004 and 2003 and the related consolidated statements of operations, shareholders' equity and comprehensive income and cash flows for each of the years in the three-year period ended March 31, 2004. These consolidated financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatements. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Pioneer Drilling Company and subsidiaries as of March 31, 2004 and 2003, and the results of their operations and their cash flows for each of the years in the three-year period ended March 31, 2004, in conformity with U. S. generally accepted accounting principles.

KPMG LLP

San Antonio, Texas
June 23, 2004

F-8

PIONEER DRILLING COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS

			March 31,
			2004			2003
ASSETS
Current assets:
	Cash and cash equivalents		$	6,365,759		$	21,002,913
	Receivables:
		Trade, net		10,901,991			4,499,378
		Contract drilling in progress		9,130,794			4,429,545
	Federal income tax receivable			—			444,900
	Current deferred income taxes			285,384			180,991
	Prepaid expenses			1,336,337			914,187

Total current assets				28,020,265			31,471,914

Property and equipment, at cost:
	Drilling rigs and equipment			145,758,913			106,728,573
	Transportation, office, land and other			5,427,637			3,494,657

				151,186,550			110,223,230
Less accumulated depreciation and amortization				35,844,938			22,367,327

Net property and equipment				115,341,612			87,855,903
Other assets				369,278			366,500

Total assets			$	143,731,155		$	119,694,317

LIABILITIES AND SHAREHOLDERS' EQUITY
Current liabilities:
	Notes payable		$	558,070		$	587,177
	Current installments of long-term debt			3,724,302			2,671,269
	Current installments of capital lease obligations			140,934			140,717
	Accounts payable			13,270,989			14,206,586
	Accrued expenses:
		Payroll and payroll taxes		1,499,151			847,163
		Other		2,798,801			1,874,693

Total current liabilities				21,992,247			20,327,605
Long-term debt, less current installments				44,786,920			45,594,517
Capital lease obligations, less current installments				104,754			260,025
Deferred income taxes				6,010,916			5,839,908

Total liabilities				72,894,837			72,022,055

Shareholders' equity:
	Preferred stock, 10,000,000 shares authorized; none issued and outstanding
	Common stock $.10 par value; 100,000,000 shares authorized; 27,300,126 shares and 21,700,792 shares issued and outstanding at March 31, 2004 and March 31, 2003, respectively			2,730,012			2,170,079
	Additional paid-in capital			82,124,368			57,730,188
	Accumulated deficit			(14,018,062	)		(12,228,005	)

Total shareholders' equity				70,836,318			47,672,262

Total liabilities and shareholders' equity			$	143,731,155		$	119,694,317

See accompanying notes to consolidated financial statements.

F-9

PIONEER DRILLING COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS

		Years Ended March 31,
		2004			2003			2002
Contract drilling revenues		$	107,875,533		$	80,183,486		$	68,627,486

Costs and expenses:
	Contract drilling		88,504,102			70,823,310			46,145,364
	Depreciation and amortization		16,160,494			11,960,387			8,426,082
	General and administrative		2,772,730			2,232,390			2,855,274
	Bad debt expense		—			110,000			—

	Total operating costs and expenses		107,437,326			85,126,087			57,426,720

Income (loss) from operations			438,207			(4,942,601	)		11,200,766

Other income (expense):
	Interest expense		(2,807,822	)		(2,698,529	)		(1,616,984	)
	Interest income		101,584			94,235			80,932
	Other		51,675			37,614			72,096
	Gain on sale of securities		—			203,887			—

	Total other income (expense)		(2,654,563	)		(2,362,793	)		(1,463,956	)

Income (loss) before income taxes			(2,216,356	)		(7,305,394	)		9,736,810
Income tax (expense) benefit			426,299			2,219,776			(3,418,525	)

Net earnings (loss)			(1,790,057	)		(5,085,618	)		6,318,285
Preferred stock dividend requirement			—			—			92,814

Net earnings (loss) applicable to common shareholders		$	(1,790,057	)	$	(5,085,618	)	$	6,225,471

Earnings (loss) per common share—Basic		$	(0.08	)	$	(0.31	)	$	0.41

Earnings (loss) per common share—Diluted		$	(0.08	)	$	(0.31	)	$	0.35

Weighted average number of shares outstanding—Basic			22,585,612			16,163,098			15,112,272

Weighted average number of shares outstanding—Diluted			22,585,612			16,163,098			19,221,256

See accompanying notes to consolidated financial statements.

F-10

PIONEER DRILLING COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF SHAREHOLDERS' EQUITY AND COMPREHENSIVE INCOME

		Shares Common	Shares Preferred		Amount Common		Preferred			Additional Paid In Capital		Accumulated Deficit			Accumulated Other Comprehensive Income			Total Shareholders' Equity
Balance as of March 31, 2001		12,145,921	184,615		$	1,214,592	$	2,999,994		$	26,869,916	$	(13,367,858	)	$	110,118		$	17,826,762
Comprehensive income:
	Net earnings	—	—			—		—			—		6,318,285			—			6,318,285
	Net unrealized change in securities available for sale, net of tax of $384	—	—			—		—			—		—			(702	)		(702	)

Total comprehensive income		—	—			—		—			—		—			—			6,317,583

Issuance of common stock for:
	Sale, net of related expenses	2,400,000	—			240,000		—			8,808,000		—			—			9,048,000
	Conversion of preferred	1,199,038	(184,615	)		119,903		(2,999,994	)		2,880,091		—			—			—
	Exercise of options	177,500	—			17,750		—			225,724		—			—			243,474
Preferred stock dividend		—	—			—		—			—		(92,814	)		—			(92,814	)

Balance as of March 31, 2002		15,922,459	—			1,592,245		—			38,783,731		(7,142,387	)		109,416			33,343,005
Comprehensive income:
	Net loss	—	—			—		—			—		(5,085,618	)		—			(5,085,618	)
	Net unrealized change in securities available for sale, net of tax of $56,366	—	—			—		—			—		—			(109,416	)		(109,416	)

Total comprehensive loss		—	—			—		—			—		—			—			(5,195,034	)

Issuance of common stock for:
	Sale, net of related expenses of $657,499	5,333,333	—			533,334		—			18,809,167		—			—			19,342,501
	Exercise of options	445,000	—			44,500		—			137,290		—			—			181,790

Balance as of March 31, 2003		21,700,792	—			2,170,079		—			57,730,188		(12,228,005	)		—			47,672,262
Comprehensive income:
	Net loss	—	—			—		—			—		(1,790,057	)		—			(1,790,057	)

Total comprehensive loss		—	—			—		—			—		—			—			(1,790,057	)

Issuance of common stock for:
	Sale, net of related expenses of $1,654,753	4,400,000	—			440,000		—			21,665,247		—			—			22,105,247
	Equipment acquisitions	477,000	—			47,700		—			2,074,950		—			—			2,122,650
	Exercise of options and related income tax benefits	722,334	—			72,233		—			653,983		—			—			726,216

Balance as of March 31, 2004		27,300,126	—		$	2,730,012	$	—		$	82,124,368	$	(14,018,062	)	$	—		$	70,836,318

See accompanying notes to consolidated financial statements.

F-11

PIONEER DRILLING COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS

				Years Ended March 31,
				2004			2003			2002
Cash flows from operating activities:
	Net earnings (loss)			$	(1,790,057	)	$	(5,085,618	)	$	6,318,285
		Adjustments to reconcile net earnings (loss) to net cash provided by operating activities:
		Depreciation and amortization			16,160,494			11,960,387			8,426,082
		Allowance for doubtful accounts			—			110,000			—
		Gain on sale of securities			—			(203,887	)		—
		Loss (gain) on dispositions of properties and equipment			816,104			279,054			(2,237	)
		Change in deferred income taxes			119,038			(1,511,744	)		1,991,458
		Changes in current assets and liabilities:
			Receivables		(11,103,862	)		242,126			(4,172,470	)
			Prepaid expenses		(422,150	)		(279,440	)		(322,471	)
			Accounts payable		(935,597	)		7,699,417			(1,099,813	)
			Federal income taxes		444,900			435,168			(930,266	)
			Accrued expenses		1,576,096			743,814			836,321

	Net cash provided by operating activities				4,864,966			14,389,277			11,044,889

Cash flows from financing activities:
	Proceeds from notes payable				4,110,019			23,573,501			19,556,286
	Proceeds from subordinated debenture				—			10,000,000			18,000,000
	Increase in other assets				(40,000	)		(253,698	)		(195,000	)
	Payment of preferred dividends				—			—			(859,395	)
	Proceeds from exercise of options and warrants				673,794			181,790			243,474
	Proceeds from common stock, net of offering cost of $1,654,753 in 2004 and $657,499 in 2003				22,105,247			19,342,501			9,048,000
	Payments of debt				(4,048,744	)		(18,714,311	)		(27,026,538	)

Net cash provided by financing activities					22,800,316			34,129,783			18,766,827

Cash flows from investing activities:
	Purchases of property and equipment				(42,722,094	)		(33,588,972	)		(27,597,265	)
	Proceeds from sale of marketable securities				—			375,414			—
	Proceeds from sale of property and equipment				419,658			314,366			675,660

Net cash used in investing activities					(42,302,436	)		(32,899,192	)		(26,921,605	)

Net increase (decrease) in cash and cash equivalents					(14,637,154	)		15,619,868			2,890,111
Beginning cash and cash equivalents					21,002,913			5,383,045			2,492,934

Ending cash and cash equivalents				$	6,365,759		$	21,002,913		$	5,383,045

Supplementary disclosure:
	Interest paid			$	2,821,041		$	2,785,177		$	1,046,943
	Income taxes paid (refunded)				(990,237	)		(1,143,200	)		2,342,006
	Dividends accrued				—			—			92,814
	Conversion of preferred stock				—			—			2,999,994
	Acquisition—common stock issued				2,122,650			—			—
	Tax benefit from exercise of nonqualified options				52,423			2,720			—

See accompanying notes to consolidated financial statements.

F-12

PIONEER DRILLING COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1. Organization and Summary of Significant Accounting Policies

Business and Principles of Consolidation

Pioneer Drilling Company provides contract land drilling services to oil and gas exploration and production companies in the North, South and East Texas markets. We conduct our operations through our principal operating subsidiary, Pioneer Drilling Services, Ltd. The accompanying consolidated financial statements include our accounts and the accounts of our wholly owned subsidiaries. We have eliminated all intercompany accounts and transactions in consolidation.

We have prepared the accompanying consolidated financial statements in accordance with accounting principles generally accepted in the United States of America. In preparing the 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.

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 bases. 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.

Earnings (Loss) Per Common Share

We compute and present earnings (loss) per common share in accordance with SFAS No. 128 "Earnings per Share." This standard requires dual presentation of basic and diluted earnings (loss) per share on the face of our statement of operations. For fiscal 2004 and 2003, we did not include the effects of convertible subordinated debt and stock options on loss per common share because they were antidilutive.

Stock-based Compensation

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

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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:

	Year Ended March 31,
	2004			2003			2002
Net earnings (loss)—as reported	$	(1,790,057	)	$	(5,085,618	)	$	6,318,285
Deduct: Total stock-based employee compensation expense determined under fair value based method for all awards net of related tax effect		(662,933	)		(385,671	)		(582,258	)

Net earnings (loss)—pro forma	$	(2,452,990	)	$	(5,471,289	)	$	5,736,027

Net earnings (loss) per share—as reported—basic	$	(0.08	)	$	(0.31	)	$	0.41
Net earnings (loss) per share—as reported—diluted		(0.08	)		(0.31	)		0.35
Net earnings (loss) per share—pro forma—basic	$	(0.11	)	$	(0.34	)	$	0.38
Net earnings (loss) per share—pro forma—diluted		(0.11	)		(0.34	)		0.32
Weighted-average fair value of options granted during the year	$	4.46		$	3.50		$	3.11

We estimate the fair value of each option grant on the date of grant using a Black-Scholes options-pricing model. This model assumed expected volatility of 94%, 69% and 90% and weighted average risk-free interest rates of 3.3%, 3.2% and 4.5% for grants in 2004, 2003 and 2002, respectively, and an expected life of five years. As we have not declared dividends since we became a public company, we did not use a dividend yield. In each case, the actual value that will be realized, if any, will depend on the future performance of our common stock and overall stock market conditions. There is no assurance the value an optionee actually realizes will be at or near the value we have estimated using the Black-Scholes model.

Revenue and Cost Recognition

We earn our contract drilling revenues under daywork, turnkey and footage contracts. We recognize revenues on daywork contracts for the days completed based on the dayrate each contract specifies. We recognize revenues from our turnkey and footage contracts on the percentage-of-completion method based on our estimate of the number of days to complete each well. Individual wells are usually completed in less than 60 days.

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

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We accrue estimated costs on turnkey and footage contracts for each day of work completed based on our estimate of the total cost to complete the contract divided by our estimate of the number of days to complete the contract. Contract costs include labor, materials, supplies, repairs, maintenance, operating overhead allocations and allocations of depreciation and amortization expense. We charge general and administrative expenses to expense as we incur them. Changes in job performance, job conditions and estimated profitability on uncompleted contracts may result in revisions to costs and income. When we encounter, during the course of our drilling operations, conditions unforeseen in the preparation of our original cost estimate, we immediately increase our cost estimate for the additional costs to complete the 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 immediately accrue the entire amount of the estimated loss including all costs that are included in our revised estimated cost to complete that contract in our consolidated statement of operations for that reporting period.

The asset "contract drilling in progress" represents revenues we have recognized in excess of amounts billed on contracts in progress.

Prepaid Expenses

Prepaid expenses include items such as insurance and licenses. We routinely expense these items in the normal course of business over the periods these expenses benefit.

Property and Equipment

We provide for depreciation of our drilling, transportation and other equipment using the 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.

We charge our expenses for maintenance and repairs to operations. We charge our expenses for renewals and betterments to the appropriate property and equipment accounts. Our gains and losses on the sale of our property and equipment are recorded in drilling costs. During fiscal 2004 and 2003, we capitalized $106,395 and $96,079, respectively, of interest costs incurred during the construction periods of certain drilling equipment. At March 31, 2004 and 2003, costs incurred on rigs under construction were approximately $2,800,000 and $2,415,000, respectively.

We review our long-lived assets and intangible assets for impairment whenever events or circumstances provide evidence that suggests that we may not recover the carrying amounts of any of these assets. In performing the review for recoverability, we estimate the future cash flows we expect to obtain from the use of each asset and its eventual disposition. If the sum of these estimated future cash flows is less than the carrying amount of the asset, we recognize an impairment loss.

F-15

Cash Equivalents

For purposes of the statements of cash flows, we consider all highly liquid debt instruments purchased with a maturity of three months or less to be cash equivalents. Cash equivalents consist of investments in corporate and government money market accounts and auction rate seven day taxable preferred securities. Cash equivalents at March 31, 2004 and 2003 were $6,118,000 and $1,060,000, respectively.

Investment Securities

We carry our available-for-sale investment securities at their fair values. Investment securities consist of common stock. Unrealized holding gains and losses, net of the related tax effect, on available-for-sale securities are excluded from earnings and are reported as a separate component of other comprehensive income until realized. Realized gains and losses from the sale of available-for-sale securities are determined on a specific identification basis. As of March 31, 2002, these securities had an aggregate cost of $171,527, a gross unrealized gain of $165,782 and an aggregate fair value of $337,309. We sold all of our investment securities in April 2002, realizing a gain of $203,887.

Trade Accounts Receivable

We record trade accounts receivable at the amount we invoice our customers. These accounts do not bear interest. The allowance for doubtful accounts is our best estimate of the amount of probable credit losses in our accounts receivable as of the balance sheet date. We determine the allowance based on the credit worthiness of our customers and general economic conditions. Consequently, an adverse change in those factors could affect our estimate of our allowance for doubtful accounts. We review our allowance for doubtful accounts monthly. Balances more than 90 days past due are reviewed individually for collectibility. We charge off account balances against the allowance after we have exhausted all reasonable means of collection and determined that the potential for recovery is remote. We do not have any off-balance-sheet credit exposure related to our customers. At March 31, 2004 and 2003 our allowance for doubtful accounts was $110,000.

Other Assets

Other assets consist of cash deposits related to the deductibles on our workers compensation insurance policies, loan fees net of amortization and intangibles related to acquisitions, net of amortization. Loan fees are amortized over the terms of the related debt. Intangibles related to acquisitions, primarily customer lists, are amortized over their estimated benefit periods of up to 18 months.

Derivative Instruments and Hedging Activities

We do not have any free standing derivative instruments and we do not engage in hedging activities.

Recently Issued Accounting Standards

On April 1, 2003, we adopted SFAS No. 143, "Accounting for Asset Retirement Obligations," which addresses financial accounting and reporting for obligations associated with the retirement of

F-16

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

On July 1, 2003, we adopted SFAS No. 149, "Amendment of Statement 133 on Derivative Instruments and Hedging Activities." This statement amends and clarifies financial accounting and reporting for derivative instruments, including certain derivative instruments in other contracts (collectively referred to as derivatives) and for hedging activities under SFAS No. 133, "Accounting for Derivative Instrument and Hedging Activities." The provisions of this statement are effective for contracts entered into or modified after June 30, 2003 and hedging relationships designated after June 30, 2003. Except for the provisions related to SFAS No. 133, all provisions of this statement will be applied prospectively. In addition, paragraphs 7(a) and 23(a) of this statement, which relate to forward purchases or sales of when-issued securities or other securities that do not yet exist, should be applied to both existing contracts and new contracts entered into after June 30, 2003. Our adoption of SFAS No. 149 did not have a material effect on our financial position or results of operations.

On July 1, 2003, we adopted SFAS No. 150, "Accounting for Certain Financial Instruments with Characteristics of Both Liabilities and Equity." This statement requires issuers to classify as liabilities (or assets in some circumstance) three classes of freestanding financial instruments that embody obligations of the issuer. The provisions of this statement are effective for financial instruments entered into or modified after May 31, 2003, and otherwise are effective at the beginning of the first interim period beginning after June 15, 2003. Our adoption of SFAS No. 150 did not have a material effect on our financial position or results of operations.

Reclassifications

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

2. Acquisitions

On May 28, 2002, we acquired all the land contract drilling assets of United Drilling Company and U-D Holdings, L.P. The assets included two land drilling rigs, associated spare parts and equipment and vehicles. We paid $7,000,000 in cash for these assets. The purchase was accounted for as an acquisition of assets, and the purchase price was allocated to drilling equipment and related assets based on their relative fair values at the date of acquisition.

On August 1, 2003, we purchased two land drilling rigs, associated spare parts and equipment and vehicles from Texas Interstate Drilling Company, L. P. for $2,500,000 in cash and the issuance of 477,000 shares of our common stock at $4.45 per share. The purchase was accounted for as an acquisition of a business, and we have included the results of operations of these assets in our statement of operations since the date of acquisition. We allocated the purchase price to drilling equipment and related assets, including intangibles, based on their relative fair values at the date of acquisition.

F-17

On December 15, 2003, we acquired for approximately $3,770,000 a rig we had previously been leasing from International Drilling Services, Inc. This purchase was accounted for as an acquisition of assets.

On March 2, 2004, we acquired 23 used rig hauling trucks and associated trailers and equipment from A & R Trejo Trucking for $1,200,000. This purchase was accounted for as an acquisition of assets, and the purchase price was allocated to the trucks and related assets based on their relative fair values at the date of acquisition.

On March 4, 2004, we acquired a seven-rig drilling fleet from Sawyer Drilling & Services, Inc. for $12,000,000. This purchase was accounted for as an acquisition of a business, and we have included the results of operations of these assets in our statement of operations since the date of acquisition. We allocated the purchase price to drilling equipment and related assets, including intangibles, based on their relative fair values at the date of acquisition.

On March 12, 2004, we acquired one drilling rig from SEDCO Drilling Co., Ltd. for $2,015,000. This purchase was accounted for as an acquisition of assets, and we have included the results of operations of these assets in our statement of operations since the date of acquisition. We allocated the purchase price to drilling equipment and related assets, including intangibles, based on their relative fair values at the date of acquisition.

F-18

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

Our long-term debt is described below:

	March 31,
	2004			2003
Convertible subordinated debentures due July 2007 at 6.75%(1)	$	28,000,000		$	28,000,000
Note payable to Merrill Lynch Capital, secured by drilling equipment, due in monthly payments of $172,619 plus interest at a floating rate equal to the 3-month LIBOR rate (1.1% at March 31, 2004) plus 385 basis points, due December 2007		13,119,048			14,500,000
Note payable to Frost National Bank, secured by drilling equipment, due in monthly payments of $107,143 plus interest at prime (4.0% at March 31, 2004) plus 1.0%, due August 2007		4,392,174			5,677,889
Note payable to Small Business Administration, secured by second lien on land and improvements, due in monthly payments of $912 including interest at 6.71%, due November 2015 (paid off April 2003)		—			87,897
Note payable to Frost National Bank, secured by drilling equipment, due in monthly payments of $42,401, including interest at prime (4.0% at March 31, 2004) plus 1.0% beginning April 15, 2004, due March 15, 2007(2)		3,000,000			—

		48,511,222			48,265,786
Less current installments		(3,724,302	)		(2,671,269	)

	$	44,786,920		$	45,594,517

(1): WEDGE Energy Services, LLC ("WEDGE") holds $27,000,000 of the convertible subordinated debentures and William H. White, a former director of our company, holds $1,000,000. WEDGE owns 26.5% of our common stock (40.2% if the debentures were converted). Beginning July 3, 2004, we have the option to redeem all or part of the debentures by paying a premium of 5% through July 2, 2005, 4% through July 2, 2006, 3% through July 2, 2007 and 0% thereafter.
(2): We incurred this debt to finance the purchase of the rig we were previously leasing.

Long-term debt maturing each year subsequent to March 31, 2004 is as follows:


2005	$	3,724,302
2006		3,743,087
2007		5,604,040
2008		35,439,793
2009		—
2010 and thereafter		—

F-19

On October 9, 2001, we issued a 6.75% five-year $18,000,000 convertible subordinated debenture, Series A, to WEDGE. The debenture was convertible into 4,500,000 shares of common stock at $4.00 per share. We used approximately $9,000,000 of the proceeds to complete the construction of two drilling rigs. Approximately $6,000,000 was used to reduce a $12,000,000 credit facility. The balance of the proceeds was used for drilling equipment and working capital. On July 3, 2002, we issued an additional $10,000,000 of 6.75% convertible subordinated debt to WEDGE with an effective conversion rate of $5.00 per share. The transaction was effected by an agreement between Pioneer and WEDGE under which WEDGE agreed to provide the additional $10,000,000 in financing and to cancel the previously issued debenture in the principal amount of $18,000,000 in exchange for $28,000,000 in new 6.75% convertible subordinated debentures. The new debentures are convertible into 6,496,519 shares of common stock at $4.31 per share, which resulted from a pro rata blending of the $5.00 conversion rate of the new $10,000,000 financing and the $4.00 conversion rate of the $18,000,000 debenture being cancelled. WEDGE funded $7,000,000 of the $10,000,000 on July 3, 2002 and $2,000,000 on July 29, 2002. William H. White, a former Director of our Company and the former President of WEDGE, purchased the remaining $1,000,000 on July 29, 2002. Unlike the cancelled debenture, which was not redeemable by Pioneer, the new debentures are redeemable at a scheduled premium. We used $7,000,000 of the proceeds to pay down bank debt and $3,000,000 for the purchase of drilling equipment.

We have a $2,500,000 line of credit available from Frost National Bank. Any borrowings under this line of credit are secured by our trade receivables and bear interest at a rate of prime (4.00% at March 31, 2004) plus 1.0%. The sum of draws under this line and the amount of all outstanding letters of credit issued by the bank for our account are limited to 75% of eligible accounts receivable. Therefore, if 75% of our eligible accounts receivable is less than $2,500,000 plus any outstanding letters of credit issued by the bank on our behalf, our ability to draw under this line would be reduced. At March 31, 2004, we had no outstanding advances under this line of credit, letters of credit were $1,664,000 and 75% of eligible accounts receivable was approximately $8,030,000. The letters of credit are issued to two workers' compensation insurance companies to secure possible future claims that do not exceed the deductibles on these policies. It is our practice to pay any amounts due that do not exceed these deductibles as they are incurred. Therefore, we do not anticipate the lender will be required to fund any draws under these letters of credit.

At March 31, 2004, we were in compliance with all covenants applicable to our outstanding debt. Those covenants include, among others, leverage, cash flow coverage, fixed charge coverage, net worth ratios and restrict us from paying dividends.

Notes payable at March 31, 2004 consists of a $558,070 insurance premium note due in monthly installments of $112,355 through August 26, 2004 which bears interest at the rate of 2.65% per year.

F-20

4. Leases

We are obligated under capital leases covering several trucks that expire at various dates through January 2007. At March 31, 2004 and 2003, the gross amount of transportation equipment and related amortization recorded under capital leases were as follows:

	2004		2003
Transportation equipment	$	665,195	$	647,822
Less accumulated amortization		413,797		248,070

	$	251,398	$	399,752

Amortization of assets held under capital leases is included with depreciation expense.

We lease real estate in Henderson, Texas; Alice, Texas; and Decatur, Texas and various office equipment under non-cancelable operating leases expiring through 2006.

Rent expense under these operating leases for the years ended March 31, 2004, 2003 and 2002 was $278,746, $344,752 and $208,150, respectively.

Future lease obligations and minimum capital lease payments as of March 31, 2004 were as follows:

	Year Ended March 31,	Operating Leases		Capital Leases
	2005	$	121,608	$	166,604
	2006		122,940		70,446
	2007		69,912		34,106
	2008		—		—

Total minimum lease payments		$	314,460	$	271,156

Less amounts representing interest (at rates ranging from 5.8% to 9.5%)					(25,468	)

Present value of net minimum capital lease payments					245,688
Less current installments of capital lease obligations					(140,934	)

Capital lease obligations, excluding current installments				$	104,754

5. Income Taxes

Our provision for income taxes consists of the following:

	Years Ended March 31,
	2004			2003			2002
Current tax—federal	$	—		$	(708,032	)	$	1,427,067
Deferred tax—federal		(426,299	)		(1,511,744	)		1,991,458

Income tax expense (benefit)	$	(426,299	)	$	(2,219,776	)	$	3,418,525

F-21

In fiscal years 2004, 2003 and 2002, our expected tax, which we compute by applying the federal statutory rate of 34% to income (loss) before income taxes, differs from our income tax expense as follows:

	Years Ended March 31,
	2004			2003			2002
Expected tax expense (benefit)	$	(753,561	)	$	(2,483,834	)	$	3,310,515
Non taxable interest income		—			(10,400	)		(9,429	)
Club dues, meals and entertainment		13,941			10,443			10,115
Reimbursement of food costs for rig employees		314,622			275,338			270,000
Other		(1,301	)		(11,323	)		(162,676	)

	$	(426,299	)	$	(2,219,776	)	$	3,418,525

Deferred income taxes arise from temporary differences between the tax basis of assets and liabilities and their reported amounts in the consolidated financial statements. The components of our deferred income tax liabilities were as follows:

		March 31,
		2004		2003
Deferred tax assets:
	Workers compensation and vacation expense accruals	$	224,985	$	94,972
	Bad debt expense		37,400		37,400
	Net operating loss carryforwards		7,825,126		5,105,730
	Alternative minimum tax credit		181,770		181,770
	Other		23,000		48,619

	Total deferred tax assets		8,292,281		5,468,491

Deferred tax liabilities:
	Property and equipment, principally due to differences in depreciation		14,017,813		11,127,408

	Total deferred tax liabilities		14,017,813		11,127,408

	Net deferred tax liabilities	$	5,725,532	$	5,658,917

In assessing our ability to realize deferred tax assets, we consider whether it is more likely than not that some portion or all of the deferred tax assets will not be realized. Our ultimate realization of deferred tax assets depends on the generation of future taxable income during the periods in which those temporary differences become deductible. We consider the scheduled reversal of deferred tax liabilities, projected future taxable income, and tax planning strategies in making this assessment. Based on the level of historical taxable income and projections for future taxable income over the periods during which the deferred tax assets are deductible, we believe it is more likely than not that we will realize the benefits of these deductible differences.

F-22

At March 31, 2004, we had net operating loss carryforwards for federal income tax purposes of approximately $25,500,000 which will expire if not utilized as of the end of our fiscal years ending as follows:

Year		Amount
2023		$	15,000,000
2024		$	10,500,000

6. Fair Value of Financial Instruments

Cash and cash equivalents, trade receivables and payables and short-term debt:

The carrying amounts of our cash and cash equivalents, trade receivables, payables and short-term debt approximate their fair values.

Long-term debt:

The carrying amount of our long-term debt approximates its fair value, as supported by the recent issuance of the debt and because the rates and terms currently available to us approximate the rates and terms on the existing debt.

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7. Earnings (Loss) Per Common Share

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

		Years Ended March 31,
		2004			2003			2002
Basic
Net earnings (loss)		$	(1,790,057	)	$	(5,085,618	)	$	6,318,285
Less: Preferred stock dividends			—			—			92,814

Earnings (loss) applicable to common shareholders		$	(1,790,057	)	$	(5,085,618	)	$	6,225,471

Weighted average shares			22,585,612			16,163,098			15,112,272

Earning (loss) per share		$	(0.08	)	$	(0.31	)	$	0.41

Diluted
Earnings (loss) applicable to common shareholders		$	(1,790,057	)	$	(5,085,618	)	$	6,225,471
Effect of dilutive securities:
	Convertible subordinated debenture		—			—			385,358
	Preferred stock		—			—			92,814

Earnings (loss) available to common shareholders and assumed conversion		$	(1,790,057	)	$	(5,085,618	)	$	6,703,643

Weighted average shares:
	Outstanding		22,585,612			16,163,098			15,112,272
	Options		—			—			1,500,589
	Convertible subordinated debenture		—			—			2,145,205
	Preferred stock		—			—			463,190

			22,585,612			16,163,098			19,221,256

Earnings (loss) per share		$	(0.08	)	$	(0.31	)	$	0.35

The weighted average number of diluted shares in 2004 and 2003 excludes 7,612,924 and 7,185,995, respectively, of shares for options and convertible debt due to their antidilutive effect.

8. Equity Transactions

On May 18, 2001, we retired the 4.86% subordinated debenture we issued to WEDGE on March 30, 2001 in connection with the Mustang Drilling, Ltd. acquisition. We funded the repayment of the $9,000,000 face amount of the debenture, together with the payment of $59,535 of accrued interest, with a short-term bank borrowing. We then sold 2,400,000 shares of our common stock to WEDGE in a private placement for $9,048,000, or $3.77 per share. We used the proceeds from this sale to fund the repayment of the short-term bank borrowing.

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holders converted all of their 184,615 shares of our Series B convertible preferred stock into 1,199,038 shares of our common stock at $2.50 per share.

On May 31, 2001, San Patricio Corporation exercised its option to acquire 150,000 shares of our common stock for $225,000 ($1.50 per share).

On March 31, 2003, we sold 5,333,333 shares of our common stock to Chesapeake Energy Corporation for $20,000,000 ($3.75 per share), before related offering expenses. In connection with that sale, we granted Chesapeake Energy a preemptive right to acquire equity securities we may issue in the future, under specified circumstances, in order to permit Chesapeake Energy to maintain its proportionate ownership of our outstanding shares of common stock. We also granted Chesapeake Energy a right, under certain circumstances, to request registration of the acquired shares under the Securities Act of 1933. At March 31, 2004, Chesapeake Energy owned 19.54% of our outstanding common stock. During the year ended March 31, 2004, we recognized revenues of approximately $924,000 and recorded contract drilling costs of approximately $745,000, excluding depreciation, on one daywork contract with Chesapeake Energy Corporation. Although our normal payment terms are 30 days from date of invoice, Chesapeake Energy Corporation requires 60 day payment terms.

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

Directors and employees exercised stock options for the purchase of 722,334 shares of common stock at prices ranging from $.625 to $3.20 per share during the year ended March 31, 2004, 445,000 shares of common stock at prices ranging from $.375 to $2.50 per share during the year ended March 31, 2003 and 27,500 shares of common stock at prices ranging from $0.375 to $1.00 per share during the year ended March 31, 2002.

9. Stock Options, Warrants and Stock Option Plan

Under our stock option plans, employee stock options generally become exercisable over three to five-year periods, and all options generally expire 10 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. Accordingly, as we discussed in Note 1, we do not recognize any compensation expense relating to these options in our results of operations.

F-25

The following table provides information relating to our outstanding stock options at March 31, 2004, 2003 and 2002:

			2004				2003				2002
			Shares Issuable on Exercise of Options		Exercise Price per Share		Shares Issuable on Exercise of Options		Exercise Price per Share		Shares Issuable on Exercise of Options		Exercise Price per Share
Balance Outstanding
	Beginning of year		1,825,000		$	.375-5.15	2,320,000		$	0.375-5.15	2,177,500		$	0.375-4.60
		Granted	1,000,000		$	3.67-4.99	65,000		$	3.20-4.50	585,000		$	3.00-5.15
		Exercised	(722,334	)	$	.625-3.20	(445,000	)	$	0.375-2.50	(177,500	)	$	0.375-1.50
		Canceled	(46,000	)	$	2.25	(115,000	)	$	2.25-4.60	(265,000	)	$	2.25

Balance Outstanding End of year			2,056,666		$	.375-5.15	1,825,000		$	0.375-5.15	2,320,000		$	0.375-5.15

Options Exercisable
	End of year		884,001				1,437,334				1,734,000

As of March 31, 2004, there were no outstanding warrants.

At March 31, 2004, the weighted average exercise price of our outstanding options was $3.24 per share and the weighted average exercise price of our exercisable options was $1.95 per share.

10. Employee Benefit Plans and Insurance

We maintain a 401(k) retirement plan for our eligible employees. Under this plan, we may contribute, on a discretionary basis, a percentage of an eligible employee's annual contribution, which we determine annually. Our contributions for fiscal 2004, 2003 and 2002 were approximately $76,000, $92,000 and $153,000, respectively.

We maintain a self-insurance program, for major medical, hospitalization and dental coverage for employees and their dependents, which is partially funded by payroll deductions. We have provided for both reported and incurred but not reported medical costs in the accompanying consolidated balance sheets. We have a maximum liability of $100,000 per employee/dependent per year. Amounts in excess of the stated maximum are covered under a separate policy provided by an insurance company. Accrued expenses at March 31, 2004 include approximately $280,000 for our estimate of incurred but unpaid costs related to the self-insurance portion of our health insurance.

We are self-insured for up to $250,000 for all workers' compensation claims submitted by employees for on-the-job injuries. We have provided for both reported and incurred but not reported costs of workers' compensation coverage in the accompanying consolidated balance sheets. Accrued expenses at March 31, 2004 include approximately $400,000 for our estimate of incurred but unpaid costs related to workers' compensation claims. Based upon our past experience, management believes that we have adequately provided for potential losses. However, future multiple occurrences of serious injuries to employees could have a material adverse effect on our financial position and results of operations.

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11. Business Segments and Supplementary Earnings Information

Substantially all our operations relate to contract drilling of oil and gas wells. Accordingly, we classify all our operations in a single segment.

During the fiscal year ended March 31, 2004, our three largest customers accounted for 10.5%, 6.4% and 4.9%, respectively, of our total contract drilling revenue. Two of these customers were customers of ours in 2003. In fiscal 2003, our three largest customers accounted for 10.8%, 6.5% and 5.4%, of our total contract drilling revenue. Two of these customers were customers of ours in fiscal 2002. In fiscal 2002, our three largest customers accounted for 13.7%, 12.2% and 11.1% of our total contract drilling revenue.

12. Commitments and Contingencies

We are in the process of constructing, primarily from used components, a 1000-hp electric drilling rig. As of March 31, 2004, we have incurred approximately $2,800,000 of construction costs. We anticipate additional construction costs of $1,200,000 to $1,700,000. The rig began moving to its first drilling location on May 28, 2004.

In addition, due to the nature of our business, we are, from time to time, involved in routine litigation or subject to disputes or claims related to our business activities, including workers' compensation claims and employment-related disputes. In the opinion of our management, none of the 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.

13. Quarterly Results of Operations (unaudited)

The following table summarizes quarterly financial data for our fiscal years ended March 31, 2004 and 2003 (in thousands, except per share data):

		First Quarter			Second Quarter			Third Quarter			Fourth Quarter			Total
2004
Revenues		$	23,850		$	24,244		$	26,414		$	33,368		$	107,876
Income (loss) from operations			(789	)		(166	)		9			1,384			438
Net earnings (loss)			(1,056	)		(621	)		(522	)		409			(1,790	)
Earnings (loss) per share)
	Basic		(.05	)		(.03	)		(.02	)		.02			(.08	)
	Diluted		(.05	)		(.03	)		(.02	)		.02			(.08	)
2003
Revenues		$	18,452		$	17,042		$	19,795		$	24,894		$	80,183
Income (loss) from operations			153			(1,251	)		(1,840	)		(2,005	)		(4,943	)
Net earnings (loss)			(172	)		(1,302	)		(1,704	)		(1,908	)		(5,086	)
Earnings (loss) per share
	Basic		(.01	)		(.08	)		(.11	)		(.11	)		(.31	)
	Diluted		(.01	)		(.08	)		(.11	)		(.11	)		(.31	)

F-27

PIONEER DRILLING COMPANY AND SUBSIDIARIES
UNAUDITED CONDENSED CONSOLIDATED BALANCE SHEET

			December 31, 2004			March 31, 2004
			(Unaudited)
ASSETS
Current assets:
	Cash and cash equivalents		$	6,712,945		$	6,365,759
	Receivables, net			19,924,122			10,901,991
	Contract drilling in progress			7,350,685			9,130,794
	Current deferred income taxes			426,056			285,384
	Prepaid expenses			2,060,974			1,336,337

		Total current assets		36,474,782			28,020,265

Property and equipment, at cost				209,415,934			151,186,550
Less accumulated depreciation and amortization				49,153,381			35,844,938

	Net property and equipment			160,262,553			115,341,612

Intangible and other assets, net of amortization				1,336,797			369,278

		Total assets	$	198,074,132		$	143,731,155

LIABILITIES AND SHAREHOLDERS' EQUITY
Current liabilities:
	Notes payable		$	1,086,326		$	558,070
	Current installments of long-term debt and capital lease obligations			5,950,974			3,865,236
	Accounts payable			11,206,903			13,270,989
	Federal income tax payable			69,568			—
	Accrued payroll			1,721,341			1,499,151
	Accrued expenses			4,597,043			2,798,801

		Total current liabilities		24,632,155			21,992,247
Long-term debt and capital lease obligations, less current installments				29,379,861			44,891,674
Other non-current liability				400,000			—
Deferred income taxes				9,115,740			6,010,916

		Total liabilities		63,527,756			72,894,837

Shareholders' equity:
	Preferred stock, 10,000,000 shares authorized; none issued and outstanding			—			—
	Common stock, $.10 par value, 100,000,000 shares authorized; 38,514,978 shares issued and outstanding at December 31, 2004 and 27,300,126 shares issued and outstanding at March 31, 2004			3,851,497			2,730,012
	Additional paid-in capital			139,394,769			82,124,368
	Accumulated deficit			(8,699,890	)		(14,018,062	)

		Total shareholders' equity		134,546,376			70,836,318

		Total liabilities and shareholders' equity	$	198,074,132		$	143,731,155

See accompanying notes to condensed consolidated financial statements.

F-28

PIONEER DRILLING COMPANY AND SUBSIDIARIES
UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

			Three Months Ended December 31,						Nine Months Ended December 31,
			2004			2003			2004			2003
Contract drilling revenues			$	46,387,624		$	26,414,362		$	129,889,335		$	74,508,827

Operating costs and expenses:
	Contract drilling			32,356,744			21,599,719			100,802,088			61,757,266
	Depreciation and amortization			5,769,959			4,118,811			16,124,317			11,670,538
	General and administrative			1,215,189			687,286			2,910,879			2,027,132
	Bad debt expense			342,000			—			342,000			—

		Total operating costs and expenses		39,683,892			26,405,816			120,179,284			75,454,936

Income (loss) from operations				6,703,732			8,546			9,710,051			(946,109	)

Other income (expense):
	Interest expense			(158,871	)		(683,496	)		(1,275,111	)		(2,117,226	)
	Loss from early extinguishment of debt			—			—			(100,833	)		—
	Interest income			54,988			10,358			118,757			86,776
	Other			7,192			25,184			22,311			65,056

		Total other income (expense)		(96,691	)		(647,954	)		(1,234,876	)		(1,965,394	)

Income (loss) before income taxes				6,607,041			(639,408	)		8,475,175			(2,911,503	)
Income tax benefit (expense)				(2,428,430	)		117,862			(3,157,003	)		712,453

	Net earnings (loss)		$	4,178,611		$	(521,546	)	$	5,318,172		$	(2,199,050	)

Earnings (loss) per common share—Basic			$	0.11		$	(0.02	)	$	0.16		$	(0.10	)

Earnings (loss) per common share—Diluted			$	0.11		$	(0.02	)	$	0.16		$	(0.10	)

Weighted average number of shares outstanding—Basic				38,428,112			22,203,194			33,000,547			21,983,730

Weighted average number of shares outstanding—Diluted				39,534,723			22,203,194			37,167,050			21,983,730

See accompanying notes to condensed consolidated financial statements.

F-29

PIONEER DRILLING COMPANY AND SUBSIDIARIES
UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

				Nine Months Ended December 31,
				2004			2003
Cash flows from operating activities:
	Net earnings (loss)			$	5,318,172		$	(2,199,050	)
	Adjustments to reconcile net earnings (loss) to net cash provided by operating activities:
		Depreciation and amortization			16,124,317			11,670,538
		Allowance for doubtfull accounts			342,000			—
		Loss on sale of properties and equipment			520,855			516,306
		Change in deferred income taxes			3,117,435			(175,955	)
		Changes in current assets and liabilities:
			Receivables		(9,364,131	)		(6,708,520	)
			Contract drilling in progress		1,780,109			750,583
			Prepaid expenses		(724,637	)		(706,524	)
			Accounts payable		(2,064,086	)		(135,125	)
			Federal income tax payable		69,568			444,900
			Accrued expenses		1,920,432			1,596,464

Net cash provided by operating activities					17,040,034			5,053,617

Cash flows from financing activities:
	Proceeds from notes payable				36,554,367			2,110,019
	Payments of debt				(21,452,186	)		(2,840,708	)
	Increase in other assets				(444,793	)		(3,787	)
	Proceeds from exercise of options/warrants				496,783			85,339
	Proceeds from sale of common stock, net of offering costs of $1,998,180				29,741,820			—

Net cash provided by (used in) financing activities					44,895,991			(649,137	)

Cash flows from investing activities:
	Business acquisitions				(35,200,000	)		(2,500,000	)
	Purchase of property and equipment				(27,266,701	)		(20,436,033	)
	Proceeds from sale of property and equipment				877,862			358,600

Net cash used in investing activities					(61,588,839	)		(22,577,433	)

Net increase (decrease) in cash and cash equivalents					347,186			(18,172,953	)
Beginning cash and cash equivalents					6,365,759			21,002,913

Ending cash and cash equivalents				$	6,712,945		$	2,829,960

Supplementary Disclosure:
	Common stock issued on conversion of debentures			$	28,000,000		$	—
	Common stock issued for acquisition				—			2,122,650
	Interest paid				1,653,973			1,655,047
	Income taxes refunded				(30,000	)		(990,237	)
	Tax benefit from exercise of nonqualified options				153,283			—

See accompanying notes to condensed consolidated financial statements.

F-30

PIONEER DRILLING COMPANY AND SUBSIDIARIES
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

1. Organization and Basis of Presentation

Business and Principles of Consolidation

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

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

Income Taxes

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

Stock-based Compensation

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

F-31

and net earnings (loss) per share would have been reduced to the pro forma amounts the table below indicates:

	Three Months Ended December 31,						Nine Months Ended December 31,
	2004			2003			2004			2003
Net earnings (loss)—as reported	$	4,178,611		$	(521,546	)	$	5,318,172		$	(2,199,050	)
Deduct: Total stock-based employee compensation expense determined under fair value based method for all awards net of related tax effect		(217,710	)		(171,870	)		(795,755	)		(380,217	)

Net earnings (loss)—pro forma	$	3,960,901		$	(693,416	)	$	4,522,417		$	(2,579,267	)

Net earnings (loss) per share, as reported—basic	$	0.11		$	(0.02	)	$	0.16		$	(0.10	)
Net earnings (loss) per share, as reported—diluted		0.11			(0.02	)		0.16			(0.10	)
Net earnings (loss) per share, pro forma—basic		0.10			(0.03	)		0.14			(0.12	)
Net earnings (loss) per share, pro forma—diluted		0.10			(0.03	)		0.13			(0.12	)
Weighted-average fair value of options granted during the period	$	9.49		$	3.67		$	8.71		$	4.23

We estimate the fair value of each option grant on the date of grant using a Black-Scholes options-pricing model. The model assumed for each of the three-month and nine-month periods ended December 31, 2004 and 2003:

	Three Months		Nine Months
	2004	2003	2004	2003
Expected volatility	85%	61%	86%	65%
Weighted-average risk-free interest rates	3.6%	3.36%	3.7%	3.3%
Expected life in years	5	5	5	5
Options granted	155,000	100,000	190,000	395,000

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.

In December 2004, the Financial Accounting Standards Board issued SFAS No. 123 (revised 2004), Share-Based Payment ("SFAS No. 123R"), which will require the compensation costs related to share-based payment transactions to be recognized in financial statements. With limited exceptions, the amount of compensation cost will be measured based on the grant-date fair value of the equity instruments issued. Compensation cost will be recognized over the vesting period during which an employee provides service in exchange for the award. SFAS No. 123R will be effective for us July 1, 2005. Two alternative methods of adoption will be available to us. Under the modified prospective method, unvested equity-classified awards would continue to be accounted for in accordance with SFAS No. 123 as disclosed above except that amounts would be recognized in the statement of operations, beginning July 1, 2005. Under the modified retrospective method, previously reported amounts would be restated for all periods presented to reflect the SFAS No. 123 amounts in the statements of

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operations. We have not quantified the effect SFAS No. 123R will have on future reporting periods or chosen the transition adoption method we will use.

Related Party Transactions

On August 11, 2004 and August 31, 2004, Chesapeake Energy Corporation ("Chesapeake") purchased 631,133 shares and 94,670 shares of our common stock, respectively, at $6.90 per share pursuant to the preemptive rights we granted to Chesapeake in the stock purchase agreement we entered into in March 2003 when we sold shares of common stock to Chesapeake. As of December 31, 2004, Chesapeake owned 16.97% of our outstanding common stock. During the three and nine months ended December 31, 2004, we recognized revenues of approximately $1,340,000 and $1,349,000, respectively, and recorded contract drilling costs of approximately $823,000 and $837,000, respectively, excluding depreciation, on contracts with Chesapeake. Accounts receivable at December 31, 2004 include $973,920 due from Chesapeake.

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

		Three Months				Nine Months				December 31, 2004
		2004		2003		2004		2003		Amount Owed
R&B Answering Service
	Purchases	$	4,761	$	4,053	$	12,055	$	10,252	$	3,334
	Payments		4,690		3,040		10,665		9,239		—
Frontier Services, Inc.
	Purchases	$	10,704	$	26,554	$	93,709	$	87,041	$	—
	Payments		35,975		15,437		93,709		102,793		—

Reclassifications

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

2. Acquisitions

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

F-33

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

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

		Wolverine		Allen			Total
Assets acquired:
	Drilling equipment	$	27,620,214	$	6,657,500		$	34,277,714
	Vehicles		214,786		230,000			444,786
	Buildings		30,000		260,000			290,000
	Land		20,000		40,000			60,000
	Intangibles, primarily non-compete agreements		115,000		512,500			627,500

		$	28,000,000	$	7,700,000		$	35,700,000
Less non-compete obligation			—		(500,000	)		(500,000	)

		$	28,000,000	$	7,200,000		$	35,200,000

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

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

F-34

pro forma financial information should be read in conjunction with the accompanying historical financial statements.

		Pro Forma Three Months Ended December 31,					Nine Months Ended December 31,
		2004		2003			2004		2003
Total revenues		$	52,868,024	$	33,982,935		$	152,602,706	$	92,494,579
Net earnings (loss)		$	4,389,305	$	(119,634	)	$	6,273,019	$	(2,342,050	)
Earnings (loss) per common share:
	Basic	$	0.11	$	(0.01	)	$	0.19	$	(0.11	)
	Diluted	$	0.11	$	(0.01	)	$	0.18	$	(0.11	)

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

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

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

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

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

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

The sum of draws under our revolving line and letter of credit facility and the amount of all outstanding letters of credit issued by the banks for our account are limited to 75% of eligible accounts receivable not to exceed $7,000,000. Therefore, if 75% of our eligible accounts receivable was less than

F-35

$7,000,000 our ability to draw under this line would be reduced. At December 31, 2004, we had no outstanding advances under this line of credit, letters of credit were $2,505,000 and 75% of our eligible accounts receivable was approximately $12,379,000. The letters of credit are issued to two workers' compensation insurance companies to secure possible future claims under the deductibles on these policies. It is our practice to pay any amounts due under these deductibles as they are incurred. Therefore, we do not anticipate that the lenders will be required to fund any draws under these letters of credit. The termination date for the revolving line and letter of credit facility is October 28, 2005.

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

4. Commitments and Contingencies

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

5. Equity Transactions

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

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

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 the public offering we referred to above.

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

F-36

6. Earnings (Loss) Per Common Share

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

	Three Months Ended December 31,					Nine Months Ended December 31,
	2004		2003			2004		2003
Basic
Net earnings (loss)	$	4,178,611	$	(521,546	)	$	5,318,172	$	(2,199,050	)

Weighted average shares		38,428,112		22,203,194			33,000,547		21,983,730

Earnings (loss) per share	$	0.11	$	(0.02	)	$	0.16	$	(0.10	)

		Three Months Ended December 31,					Nine Months Ended December 31,
		2004		2003			2004		2003
Diluted
Net earnings (loss)		$	4,178,611	$	(521,546	)	$	5,318,172	$	(2,199,050	)
Effect of dilutive securities:
	Convertible debentures(1)		—		—			459,483		—

Net earnings (loss) and assumed conversion		$	4,178,611	$	(521,546	)	$	5,777,655	$	(2,199,050	)

Weighted average shares:
	Outstanding		38,428,112		22,203,194			33,000,547		21,983,730
	Options(1)		1,106,611		—			1,024,550		—
	Convertible debentures(1)		—		—			3,141,953		—

			39,534,723		22,203,194			37,167,050		21,983,730

Earnings (loss) per share		$	0.11	$	(0.02	)	$	0.16	$	(0.10	)

(1): Employee stock options to purchase 2,310,000 shares and 6,496,519 shares from convertible debentures were not included in the computation of diluted loss per share for the three months and nine months ended December 31, 2003, because they were antidilutive.

F-37

INDEPENDENT AUDITOR'S REPORT

To the Board of Directors
Wolverine Drilling, Inc.
Kenmare, North Dakota 58746

We have audited the accompanying balance sheet of Wolverine Drilling, Inc. (an S Corporation) as of December 31, 2003, and the related statements of operations, stockholders' equity and cash flows for the year then ended. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audit.

We conducted our audit in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for our opinion.

In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Wolverine Drilling, Inc. as of December 31, 2003, and the results of its operations, changes in stockholders' equity and cash flows for the year then ended, in conformity with accounting principles generally accepted in the United States of America.

Our audit was made for the purpose of forming an opinion on the basic financial statements taken as a whole. The supplementary information included in the accompanying pages is presented for purposes of additional analysis and is not a required part of the basic financial statements. The supplementary information has been subjected to the auditing procedures applied in the audit of the basic financial statements and, in our opinion, is fairly stated in all material respects in relation to the basic financial statements taken as a whole.

BRADY, MARTZ & ASSOCIATES, P.C.

Minot, North Dakota
October 20, 2004

F-38

WOLVERINE DRILLING, INC.
BALANCE SHEET
DECEMBER 31, 2003

ASSETS
Current assets
	Cash and cash equivalents	$	285,071
	Receivables (net of allowance for doubtful accounts of $15,000)		1,069,338
	Contract drilling in progress		730,725
	Prepaid expenses		465,749

Total current assets		$	2,550,883

Property and equipment
	Land	$	24,401
	Equipment		10,279,305
	Less accumulated depreciation		3,431,361

Net property and equipment		$	6,872,345

Other assets
	Capital credits	$	13,415

Total assets		$	9,436,643

LIABILITIES AND SHAREHOLDERS' EQUITY
Current liabilities
	Accounts payable	$	757,201
	Accrued payroll		273,709
	Payroll taxes payable		54,037
	Stockholder payable		40,606
	Short-term notes payable		1,998,560
	Current portion of notes payable		421,329

Total current liabilities		$	3,545,442

Long-term liabilities
	Notes payable	$	2,564,787
	Less current portion		421,329

Total long-term liabilities		$	2,143,458

Total Liabilities		$	5,688,900

Stockholders' equity
	Common stock—250,000 shares authorized, $1.00 par value; 74,100 shares issued and outstanding	$	74,100
	Additional paid-in capital		14,150
	Retained earnings		3,659,493

Total stockholders' equity		$	3,747,743

Total liabilities and stockholders' equity		$	9,436,643

See accompanying notes and Independent Auditor's Report

F-39

WOLVERINE DRILLING, INC.
STATEMENT OF OPERATIONS
FOR THE YEAR ENDED DECEMBER 31, 2003

OPERATIONS
Earned revenues		$	10,673,644

Drilling costs
	Direct		6,090,931
	Indirect		3,260,610

Total drilling costs			9,351,541

Gross profit		$	1,322,103
Other revenue (expenses)			(91,760	)

Gross profit and other revenue (expenses)		$	1,230,343

Expenses
	General and administrative	$	254,115
	Interest		208,433
	Depreciation		2,975

Total expenses		$	465,523

Net earnings		$	764,820

See accompanying notes and Independent Auditor's Report

F-40

WOLVERINE DRILLING, INC.
STATEMENT OF STOCKHOLDERS' EQUITY
FOR THE YEAR ENDED DECEMBER 31, 2003

		Common Stock		Additional Paid- In Capital			Retained Earnings			Treasury Stock			Total Stockholders' Equity
Balance, January 1, 2003		$	7,410	$	80,840		$	3,184,244		$	(177,325	)	$	3,095,169
	Prior period adjustment		66,690		(66,690	)		98,338			177,325			275,663

Balance, January 1, 2003 (restated)		$	74,100	$	14,150		$	3,282,582		$	0		$	3,370,832
	Distributions		0		0			(387,909	)		0			(387,909	)
	Net earnings		0		0			764,820			0			764,820

Balance, December 31, 2003		$	74,100	$	14,150		$	3,659,493		$	0		$	3,747,743

See accompanying notes and Independent Auditor's Report

F-41

WOLVERINE DRILLING, INC.
STATEMENT OF CASH FLOWS
FOR THE YEAR ENDED DECEMBER 31, 2003

Cash flows from operating activities
	Net earnings			$	764,820
	Adjustments to reconcile net earnings to net cash provided by operating activities:
		Depreciation			1,271,771
		Loss on disposal of equipment			151,167
		Effects on operating cash flows due to changes in:
			Receivables and contract drilling in progress		3,200
			Prepaid expenses		(219,212	)
			Accounts payable		514,034
			Accrued payroll		172,923
			Payroll taxes payable		24,927

	Net cash provided by operating activities			$	2,683,630

Cash flows from investing activities
	Purchase of property and equipment			$	(2,332,040	)
	Proceeds from sale of equipment				6,375
	Investment in capital credits				(1,143	)

	Net cash used by investing activities			$	(2,326,808	)

Cash flows from financing activities
	Proceeds from issuance of short-term debt			$	850,001
	Reduction of long-term debt				(706,017	)
	Increase in stockholder payable				29,671
	Stockholder distributions				(387,909	)

	Net cash used by financing activities			$	(214,254	)

Net increase in cash and cash equivalents				$	142,568
Cash and cash equivalents at beginning of year					142,503

Cash and cash equivalents at end of year				$	285,071

Supplementary disclosures of cash flow information
	Cash paid during the year for:
		Interest		$	208,433

See accompanying notes and Independent Auditor's Report

F-42

WOLVERINE DRILLING, INC.
NOTES TO FINANCIAL STATEMENTS
DECEMBER 31, 2003

Note 1—Summary of Significant Accounting Policies

See Independent Auditor's Report

Nature of operations—Wolverine Drilling, Inc. is a contract drilling company that specializes in oil and gas wells. The principal markets are oil and gas companies that are developing oil and gas prospects in Western North Dakota, Montana and Colorado.

Revenue and cost recognition—The Company earns revenues under daywork and turnkey contracts. Daywork contract revenues are recognized for the days completed based on the day rate each contract specifies. Revenues from turnkey contracts are recognized on the percentage-of-completion method based on management's estimate of the number of days to complete each well. Turnkey contracts are usually completed in less than 60 days.

The estimated costs on turnkey contracts are accrued based on management's estimate of the total cost to complete the contract divided by the estimated number of days to complete the contract. The significant components of contract costs include salaries and benefits, supplies, repairs and maintenance, subcontractors, operating overhead and depreciation. General and administrative expenses are expensed as incurred. Management reviews the status of contracts in progress and revises the contract revenues and costs for changes or conditions unforeseen at the contract's inception. If a loss on a contract in progress is anticipated, the entire estimated loss is accrued.

The asset "contract drilling in progress" represents revenues that have been recognized in excess of amounts billed on contracts in progress.

Cash and cash equivalents—For purposes of the statement of cash flows, all highly liquid debt investments purchased with a maturity of three months or less are considered as cash equivalents.

Trade receivables are carried at original invoice amount less an estimate made for doubtful receivables based on a review of all outstanding amounts on a monthly basis. Interest is not charged on trade receivables. Management determines the allowance for doubtful accounts by regularly evaluating individual customer receivables and considering a customer's financial condition, credit history, and current economic conditions. Trade receivables are written off when deemed uncollectible. Recoveries of trade receivables previously written off are recorded when received. A trade receivable is considered to be past due if any portion of the receivable balance is outstanding for more than 30 days.

Prepaid expenses—Prepaid expenses include items such as insurance and prepaid contract costs. The prepaid expenses are recognized as an operating expense in the period they benefit.

Equipment and vehicles are stated at cost less accumulated depreciation using straight-line methods. The estimated lives used to compute depreciation are as follows:

Equipment		5-15 years
Vehicles		5 years

Use of estimates—The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. Material estimates that are susceptible to significant changes in the near term relate to the recognition of revenues and costs on turnkey contracts and the estimate for depreciation.

F-43

See Independent Auditor's Report

Advertising—Advertising costs, which were expensed as incurred totaled $22,722 for the year ended December 31, 2003.

Note 2—Prepaid Expenses

Prepaid expenses as of the year ended December 31, 2003, consisted of the following:

Insurance and workers compensation	$	447,391
Drilling costs		18,358

	$	465,749

Note 3—Related Party Transactions

The Company has a payable to Robert Mau, a major stockholder, in the amount of $40,606. The payable is due on demand and has no stated interest rate or repayment terms.

The Company leases office space from Dakota Holdings, LLP at $750 per month. Dakota Holdings, LLP and the Company have common owners. The rental agreement is on a month-to-month basis and total rent expense for the year ended December 31, 2003 was $9,000.

The Company provides drilling and repair services to Eagle Operating, Inc. Eagle Operating, Inc. and the Company have common stockholders. Total sales to Eagle Operating, Inc. for the year ended December 31, 2003 were $123,748. As of December 31, 2003, the Company had no related party receivable from Eagle Operating, Inc.

The Company conducts business with Incabar USA, Inc. Incabar USA, Inc. and the Company have common owners. The Company paid $17,714 in contract labor to Incabar USA, Inc. in 2003. As of December 31, 2003, the Company owed Incabar USA, Inc. $2,487, which is included in the Company's trade accounts payable.

The Company conducts business with Dresser Oil Tools, Inc. Dresser Oil Tools, Inc. and the Company have common owners. The Company paid $45,374 for various parts and supplies to Dresser Oil Tools, Inc. in 2003. As of December 31, 2003, the Company owed Dresser Oil Tools, Inc. $9,765, which is included in the Company's trade accounts payable.

The Company leases various vehicles from NPS Leasing, LLC. NPS Leasing, LLC and the Company have common owners. The lease agreements are each for 36 months and total lease expense for the year ended December 31, 2003 was $29,306.

F-44

See Independent Auditor's Report

The aggregate amount of required future payments on the above lease agreements at December 31, 2003 is as follows:

Year ending December 31,
2004	$	19,800
2005		18,600
2006		6,600

Total due	$	45,000

Note 4—Notes Payable

Details pertaining to notes payable and assets assigned as collateral thereon are as follows:

Payee / Collateral		Interest Rate		Maturity Date	Current Portion			Total Due 2003
Short-term:
First Western Bank/
	accounts receivable and personal guarantees of stockholders	4.50	%	02/1/04			(1)	$	1,498,560
First Western Bank/
	accounts receivable and personal guarantees of stockholders	4.50	%	02/1/04			(2)		500,000

								$	1,998,560

Long-term:
First Western Bank/
	equipment and personal guarantees of stockholders	5.00	%	06/1/09	$	421,329		$	2,564,787

(1): This note payable is a general operating line of credit. The maximum line of credit is $1,500,000.
(2): This note payable is a general operating line of credit. The maximum line of credit is $500,000.

F-45

See Independent Auditor's Report

The aggregate amount of required future principal payments on the above long-term debt at December 31, 2003 is as follows:

Year ending December 31,
2004	$	421,329
2005		442,885
2006		465,544
2007		489,362
2008		514,399
Thereafter		231,268

Total due	$	2,564,787

Note 5—Concentration of Credit Risk and Major Customer

The Company works principally in North Dakota, Montana and Colorado. Oil field development companies constitute the majority of the Company's receivables as of December 31, 2003. During 2003, 31% of the Company's revenue was generated from one customer.

As of December 31, 2003, the Company has cash deposits of $221,589 in financial institutions in excess of the FDIC coverage.

Note 6—Income Taxes

Wolverine Drilling, Inc. is an S-Corporation and as such is not a tax paying entity for federal and state income tax purposes. Income from the Company is passed through to the stockholders and taxed at the individual level. Therefore, no provision or liability for federal and state income taxes is reflected in the financial statements.

Note 7—Contract Backlog

As of December 31, 2003, the Company had signed drilling contracts of approximately $2,135,000. Drilling on these contracts is expected to start and be completed in the first quarter of 2004.

Note 8—Change in Accounting Estimate

Effective January 1, 2003, the Company elected to change the estimated depreciable lives for financial reporting purposes for various drilling equipment. The Company believes the new estimated lives more closely reflect the economic service potential of the various drilling equipment. The impact of this change in estimate resulted in increasing 2003 net earnings by approximately $552,000.

F-46

Note 9—Prior Period Adjustment

See Independent Auditor's Report

The Company's stockholders' equity as of January 1, 2003 has been increased by $275,663. The adjustment was necessary to properly account for the following items:

Revenue for contracts in progress not recognized in correct period	$	123,693
Costs for contracts in progress not recorded in correct period		(45,320	)
Insurance and workers compensation expensed in incorrect period		246,537
Accrued payroll recognized in incorrect period		(100,786	)
Depreciation recorded in incorrect period		51,539

	$	275,663

F-47

ACCOUNTANT'S COMPILATION REPORT

Wolverine Drilling, Inc.
Kenmare, North Dakota

We have compiled the accompanying balance sheet of Wolverine Drilling, Inc. (an S Corporation) as of September 30, 2004, and the related statements of operations, stockholders' equity and cash flows for the nine months then ended, and the accompanying supplementary information contained on pages 10-11, which is presented only for supplementary analysis purposes, in accordance with Statements on Standards for Accounting and Review Services issued by the American Institute of Certified Public Accountants.

A compilation is limited to presenting in the form of financial statements and supplementary schedules information that is the representation of management. We have not audited or reviewed the accompanying financial statements and supplementary schedules and, accordingly, do not express an opinion or any other form of assurance on them.

BRADY, MARTZ & ASSOCIATES, P.C.

January 13, 2005

F-48

WOLVERINE DRILLING, INC.
BALANCE SHEET
SEPTEMBER 30, 2004

ASSETS
Current assets
	Cash and cash equivalents	$	560,255
	Receivables (net of allowance for doubtful accounts of $15,000)		1,418,349
	Contract drilling in progress		155,208
	Prepaid expenses		579,112

Total current assets		$	2,712,924

Property and equipment
	Land	$	24,401
	Equipment		11,772,401
	Less accumulated depreciation		4,471,688

Net property and equipment		$	7,325,114

Other assets
	Capital credits	$	14,620

Total assets		$	10,052,658

LIABILITIES AND SHAREHOLDERS' EQUITY
Current liabilities
	Accounts payable	$	1,281,490
	Accrued payroll		134,025
	Payroll taxes payable		112,959
	Short-term notes payable		998,560
	Current portion of notes payable		437,288

Total current liabilities		$	2,964,322

Long-term liabilities
	Notes payable	$	2,252,852
	Less current portion		437,288

Total long-term liabilities		$	1,815,564

Total liabilities		$	4,779,886

Stockholders' equity
	Common stock—250,000 shares authorized, $1.00 par value; 74,100 shares issued and outstanding	$	74,100
	Additional paid-in capital		14,150
	Retained earnings		5,184,522

Total stockholders' equity		$	5,272,772

Total liabilities and stockholders' equity		$	10,052,658

See Accountant's Compilation Report and Notes to Financial Statements

F-49

WOLVERINE DRILLING, INC.
STATEMENT OF OPERATIONS
FOR THE NINE MONTHS ENDED SEPTEMBER 30, 2004

OPERATIONS
Earned revenues		$	11,799,413

Drilling costs
	Direct	$	6,557,819
	Indirect		2,979,241

Total drilling costs		$	9,537,060

Gross profit		$	2,262,353
Other revenue			83,868

Gross profit and other revenue		$	2,346,221

Expenses
	General and administrative	$	434,199
	Interest		138,529
	Depreciation		2,547

Total expenses		$	575,275

Net earnings		$	1,770,946

See Accountant's Compilation Report and Notes to Financial Statements

F-50

WOLVERINE DRILLING, INC.
STATEMENT OF STOCKHOLDERS' EQUITY
FOR THE NINE MONTHS ENDED SEPTEMBER 30, 2004

		Common Stock		Additional Paid-Inn Capital		Retained Earnings			Total Stockholders' Equity
Balance, January 1, 2004		$	74,100	$	14,150	$	3,659,493		$	3,747,743
	Distributions		0		0		(245,917	)		(245,917	)
	Net earnings		0		0		1,770,946			1,770,946

Balance, September 30, 2004		$	74,100	$	14,150	$	5,184,522		$	5,272,772

See Accountant's Compilation Report and Notes to Financial Statements

F-51

WOLVERINE DRILLING, INC.
STATEMENTS OF CASH FLOWS
FOR THE NINE MONTHS ENDED SEPTEMBER 30, 2004

Cash flows from operating activities
	Net earnings			$	1,770,946
	Adjustments to reconcile net earnings to net cash provided by operating activities:
		Depreciation			1,092,167
		Gain on disposal of equipment			(39,342	)
		Effects on operating cash flows due to changes in:
			Receivables and contract drilling in progress		226,506
			Prepaid expenses		(113,363	)
			Accounts payable		524,289
			Accrued payroll		(139,684	)
			Payroll taxes payable		58,922

	Net cash provided by operating activities			$	3,380,441

Cash flows from investing activities
	Purchase of property and equipment			$	(1,558,732	)
	Proceeds from sale of equipment				53,138
	Investment in capital credits				(1,205	)

	Net cash used by investing activities			$	(1,506,799	)

Cash flows from financing activities
	Reduction of short-term debt			$	(1,000,000	)
	Reduction of long-term debt				(311,935	)
	Decrease in stockholder payable				(40,606	)
	Stockholder distributions				(245,917	)

	Net cash used by financing activities			$	(1,598,458	)

Net increase in cash and cash equivalents				$	275,184
Cash and cash equivalents at beginning of year					285,071

Cash and cash equivalents at end of year				$	560,255

Supplementary disclosures of cash flow information
	Cash paid during the year for:
		Interest		$	138,529

See Accountant's Compilation Report and Notes to Financial Statements

F-52

WOLVERINE DRILLING, INC.
NOTES TO FINANCIAL STATEMENTS
SEPTEMBER 30, 2004

Note 1—Summary of Significant Accounting Policies

See Accountant's Compilation Report

The estimated costs on turnkey contracts are accrued based on management's estimate of the total cost to complete the contract divided by the estimated number of days to complete the contract. The significant components of contract costs include salaries and benefits, supplies, repairs and maintenance, subcontractors, operating overhead and depreciation. General and administrative expenses are expensed as incurred. Management reviews the status of contracts in progress and revises the contract revenues and costs for changes of conditions unforeseen at the contract's inception. If a loss on a contract in progress is anticipated, the entire estimated loss is accrued.

The asset "contract drilling in progress" represents revenues that have been recognized in excess of amounts billed on contracts in progress.

Cash and cash equivalents—For purposes of the statement of cash flows, all highly liquid debt investments purchased with maturity of three months or less are considered as cash equivalents.

Trade receivables are carried at original invoice amount less an estimate made for doubtful receivables based on a review of all outstanding amounts on a monthly basis. Management determines the allowance for doubtful accounts by regularly evaluating individual customer receivables and considering a customer's financial condition, credit history, and current economic conditions. Trade receivables are written off when deemed uncollectible. Recoveries of trade receivables previously written off are recorded when received. A trade receivable is considered to be past due if any portion of the receivable balance is outstanding for more than 30 days.

Prepaid expenses—Prepaid expenses include items such as insurance and prepaid contract costs. The prepaid expenses are recognized as an operating expense in the period they benefit.

Equipment and vehicles are stated at cost less accumulated depreciation using straight-line methods. The estimated lives used to compute depreciation are as follows:

Equipment		5-15 years
Vehicles		5 years

F-53

See Accountant's Compilation Report

Advertising—Advertising costs which were expensed as incurred totaled $13,464 for the nine months ended September 30, 2004.

Note 2—Prepaid Expenses

Prepaid expenses as of the nine months ended September 30, 2004, consisted of the following:

Insurance and workers compensation	$	497,610
Drilling costs		81,502

	$	579,112

Note 3—Related Party Transactions

The Company provides drilling and repair services to Eagle Operating, Inc. Eagle Operating, Inc. and the Company have common stockholders. Total sales to Eagle Operating, Inc. for the nine months ended September 30, 2004 were $136,453. As of September 30, 2004, Eagle Operating, Inc. owed the Company $104.

The Company conducts business with Incabar USA, Inc. Incabar USA, Inc. and the Company have common owners. The Company paid $2,750 in contract labor to Incabar USA, Inc. during the nine months ended September 30, 2004. As of September 30, 2004, the Company had no related party payable to Incabar USA, Inc.

The Company conducts business with Dresser Oil Tools, Inc. Dresser Oil Tools, Inc. and the Company have common owners. The Company paid $27,606 for various parts and supplies to Dresser Oil Tools, Inc. during the nine months ended September 30, 2004. As of September 30, 2004, the Company owed Dresser Oil Tools, Inc. $3,793, which is included in the Company's trade accounts payable.

F-54

See Accountant's Compilation Report

The aggregate amount of required future payments on the above lease agreements at September 30, 2004 is as follows:

Year ending December 31,
2004	$	3,672
2005		18,600
2006		6,600

Total due	$	28,872

Note 3—Notes Payable

Details pertaining to notes payable and assets assigned as collateral thereon are as follows:

Payee / Collateral		Interest Rate		Maturity Date	Current Portion			2004
Short-term:
First Western Bank/
	accounts receivable and personal guarantees of stockholders	4.50	%	2/1/05			(1)	$	998,560

Long-term:
First Western Bank/
	equipment and personal guarantees of stockholders	5.00	%	6/1/09	$	437,288		$	2,252,852

(1): This note payable is a general operating line of credit. The maximum line of credit is $1,500,000.

The aggregate amount of required future principal payments on the above long-term debt at September 30, 2004 is as follows:

Year ending September 30,
2005	$	437,288
2006		459,661
2007		483,178
2008		507,898
2009		364,827

Total due	$	2,252,852

F-55

Note 4—Concentration of Credit Risk and Major Customer

See Accountant's Compilation Report

The Company works principally in North Dakota, Montana and Colorado. Oil field development companies constitute the majority of the Company's receivables as of September 30, 2004. During the nine months ended September 30, 2004, 61% of the Company's revenue was generated from four customers.

As of September 30, 2004, the Company had cash deposits of $559,723 in financial institutions in excess of the FDIC coverage.

Note 5—Income Taxes

Note 6—Subsequent Event

On November 11, 2004, Pioneer Drilling Services, Ltd. Entered into an Asset Purchase Agreement providing for the acquisition of the Company's seven mechanical land drilling rigs and related assets, including trucks, trailers, vehicles, spare drill pipe, land and yard equipment. The sale of those assets was completed on November 30, 2004.

F-56

INDEPENDENT AUDITORS' REPORT

To the Board of Directors
Allen Drilling Company:

We have audited the accompanying balance sheets of Allen Drilling Company as of September 30, 2004 and 2003, and the related statements of income, changes in stockholder's equity and cash flows for the years then ended. These financial statements are the responsibility of the management of Allen Drilling Company. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with U.S. generally accepted auditing standards. Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Allen Drilling Company as of September 30, 2004 and 2003, and the results of its operations and its cash flows for the years then ended in conformity with U.S. generally accepted accounting principles.

		Respectfully submitted,

Great Bend, Kansas January 21, 2005

1910 18^th STREET, BOX 929, GREAT BEND, KS 67530. PHONE (316) 792-5275. FAX (316) 792-5077. WWW.KCOE.COM
Members of: American Institute of Certified Public Accountants. Offices in Kansas, Oklahoma and Colorado

F-57

ALLEN DRILLING COMPANY

BALANCE SHEETS

					September 30,
					2004		2003
ASSETS
Current Assets
	Cash and cash equivalents				$	481,615	$	891,109
	Certificate of deposit					—		317,332
	Receivables
		Trade, less allowance for doubtful accounts				2,720,434		2,116,039
		Other				—		8,620
	Prepaid income taxes					114,896		—
	Contract drilling in progress					154,072		314,985
	Prepaid expenses					247,625		61,734
	Inventory					39,179		50,647

			Total Current Assets			3,757,821		3,760,466

Property and Equipment, at cost
	Land					10,305		2,805
	Buildings					506,333		247,543
	Drilling rigs					6,659,134		5,093,350
	Mobile equipment					785,853		635,136
	Shop equipment					29,030		21,475
	Office equipment					57,273		51,951

						8,047,928		6,052,260
	Deduct accumulated depreciation					4,701,772		4,169,087

			Total Property and Equipment			3,346,156		1,883,173

Other Assets
	Certificate of deposit					317,332		—
	Oil and gas properties, less accumulated depreciation, depletion and amortization					3,065		4,467
	Other investments					15,654		20,499

			Total Other Assets			336,051		24,966

				Totals	$	7,440,028	$	5,668,605

The accompanying notes are an integral part
of these financial statements.

F-58

					September 30,
					2004		2003
LIABILITIES AND EQUITY
Current Liabilities
	Accounts payable—Trade				$	1,071,740	$	903,700
	Customer deposit					120,000		—
	Accrued expenses
		Income taxes				41,300		97,177
		Other				1,402		198,735
	Deferred income tax liability					5,900		10,375
	Note payable—Stockholder					523,431		600,334
	Notes payable—Bank					—		33,871
	Current portion of long-term obligations					563,901		271,738

			Total Current Liabilities			2,327,674		2,115,930

Long-Term Obligations, less current portion						—		35,464

Deferred Income Tax Liability						392,100		88,500

Stockholder's Equity
	Capital stock
	Common—$1 par value, Authorized—1,000,000 shares, Issued—415,000 shares					415,000		415,000
	Additional paid-in capital					110,418		110,418
	Retained earnings					5,794,835		4,503,292

						6,320,253		5,028,710
	Less: Treasury stock, at cost, 225,035 shares					1,599,999		1,599,999

			Total Stockholder's Equity			4,720,254		3,428,711

				Totals	$	7,440,028	$	5,668,605

F-59

ALLEN DRILLING COMPANY
STATEMENTS OF INCOME

			Year Ended September 30,
			2004			2003
Operating Revenues
	Drilling		$	14,439,575		$	9,752,534
	Oil and gas sales			2,400			61,968

		Total Operating Revenues		14,441,975			9,814,502

Operating Costs and Expenses
	Direct rig			11,797,492			8,616,157
	Oil and gas			1,664			52,266
	Engineering			92,404			88,241
	General and administrative			415,358			355,560

		Total Operating Expenses		12,306,918			9,112,224

Operating Income				2,135,057			702,278

Other Income (Expense)
	Investment income			7,958			46,117
	Gain on sale of assets			21,901			34,982
	Interest expense			(61,898	)		(73,948	)
	Other			4,574			19,255

		Total Other Income (Expense)		(27,465	)		26,406

Net Income before Income Taxes				2,107,592			728,684
Income Taxes				816,049			284,977

Net Income			$	1,291,543		$	443,707

The accompanying notes are an integral part
of these financial statements.

F-60

ALLEN DRILLING COMPANY
STATEMENTS OF CHANGES IN STOCKHOLDER'S EQUITY

	Common Stock		Additional Paid-In Capital		Retained Earnings		Treasury Stock			Total
Balances, September 30, 2002	$	415,000	$	110,418	$	4,059,585	$	(1,599,999	)	$	2,985,004
Net income for the year ended September 30, 2003		—		—		443,707		—			443,707

Balances, September 30, 2003		415,000		110,418		4,503,292		(1,599,999	)		3,428,711
Net income for the year ended September 30, 2004		—		—		1,291,543		—			1,291,543

Balances, September 30, 2004	$	415,000	$	110,418	$	5,794,835	$	(1,599,999	)	$	4,720,254

The accompanying notes are an integral part
of these financial statements.

F-61

ALLEN DRILLING COMPANY
STATEMENTS OF CASH FLOWS
Increase (Decrease) in Cash and Cash Equivalents

						Year Ended September 30,
						2004			2003
Cash Flows From Operating Activities
	Net income					$	1,291,543		$	443,707

		Adjustments to reconcile net income to net cash provided by operating activities
			Depreciation, depletion, and amortization				622,249			662,832
			(Gain) on sale of assets				(21,901	)		(34,982	)
			Deferred income taxes				299,125			157,800
			(Increase) decrease in:
				Receivables			(595,775	)		(767,720	)
				Prepaid income taxes			(114,896	)		69,933
				Contract drilling in progress			160,913			(144,332	)
				Prepaid expenses			(185,891	)		153,395
				Inventory			11,468			3,451
				Other investments			4,845			725
			Increase (decrease) in:
				Accounts payable—Trade			139,644			483,080
				Customer deposit			120,000			—
				Accrued income taxes			(55,877	)		78,542
				Other accrued expenses			(197,333	)		97,177

					Total Adjustments		186,571			759,901

				Net Cash Provided by Operating Activities			1,478,114			1,203,608

Cash Flows From Investing Activities
	Addition to certificate of deposit						—			(17,332	)
	Proceeds from sale of property and equipment						30,551			452,852
	Acquisition of property and equipment and oil and gas properties						(2,018,218	)		(1,346,635	)

				Net Cash (Used in) Investing Activities			(1,987,667	)		(911,115	)

Cash Flows From Financing Activities
	Payments on accounts payable for equipment additions						(45,866	)		—
	Net payments on short-term borrowing						(110,774	)		(90,551	)
	Borrowing on long-term debt						687,055			52,193
	Principal payments on long-term debt						(430,356	)		(367,510	)

				Net Cash Provided by (Used in) Financing Activities			100,059			(405,868	)

F-62

		Year Ended September 30,
		2004			2003
Net (Decrease) in Cash and Cash Equivalents		$	(409,494	)	$	(113,375	)
Cash and Cash Equivalents at Beginning of Period			891,109			1,004,484

Cash and Cash Equivalents at End of Period		$	481,615		$	891,109

SUPPLEMENTAL DISCLOSURES OF CASH FLOW INFORMATION
Cash Paid (Received) During the Period for:
	Interest	$	61,898		$	73,948
	Income taxes (refunds)		687,697			(39,933	)
Supplemental Schedule of Noncash Financing and Investing Activities
Property and Equipment Additions Financed by Increases in Accounts Payable at End of Period		$	74,262		$	45,866

The accompanying notes are an integral part
of these financial statements.

F-63

ALLEN DRILLING COMPANY

NOTES TO FINANCIAL STATEMENTS

September 30, 2004 and 2003

1. Summary of Significant Accounting Policies

a.: Nature of Operations: Allen Drilling Company (the Company) is a Kansas corporation incorporated on April 15, 1977. The Company is an independent oil and gas well drilling contractor. Its principal customers are independent U.S. oil and gas producers. The Company primarily conducts its drilling operations in the States of Kansas and Oklahoma. The Company also invests in the acquisition, development, and production of oil and gas, primarily through working interest arrangements.
b.: Use of Estimates: The preparation of financial statements in conformity with U.S. generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.
c.: Cash and Cash Equivalents: Cash and cash equivalents include cash in banks and money market accounts.
d.: Accounts Receivable and Allowance for Uncollectible Accounts: Accounts receivable are stated at face value less the allowance for uncollectible accounts. The allowance is established based on the Company's assessment of economic conditions and an analysis of specific customer accounts. The Company considers accounts receivable to be fully collectible; accordingly, the allowance is set at zero at September 30, 2004 and 2003. Accounts receivable are considered past due based on the payment terms, but interest is not normally charged on past due accounts. The Company has one account that is past due over 90 days as of September 30, 2004, in the amount of $49,331.
e.: Inventory: Inventory of supplies is stated at lower of cost or market, with cost determined on a first-in, first-out basis.
f.: Property and Equipment: Property and equipment is recorded at cost. Depreciation is provided using accelerated methods over the estimated useful lives of the assets as follows:

Buildings		15 years
Drilling rigs		5 to 10 years
Mobile equipment		5 years
Shop equipment		5 years
Office equipment		7 years

Upon sale or retirement, the cost and related accumulated depreciation are eliminated from the respective accounts and the resulting gain or loss is included in results of operations.

Repairs and maintenance charges that do not increase the useful lives of the assets are charged to operations as incurred.

Long-lived assets to be held and used are reviewed for impairment whenever events or changes in circumstances indicate that the related carrying amount may not be recoverable.

When required, impairment losses on assets to be held and used are recognized based on the fair value of the asset, and long-lived assets to be disposed of are reported at the lower of carrying amount or fair value less cost to sell.

F-64

g.: Revenue and Cost Recognition: Drilling revenues are earned under daywork and footage contracts. Revenues are recognized for each day of work completed using the percentage of completion method based on the estimated number of days to complete each well. Individual wells are generally completed in less than 30 days.

The asset "contract drilling in progress" represents revenues recognized in excess of amounts billed on contracts in progress.

Direct rig costs on wells are accrued over each day of work completed based on the estimated total cost to complete each well over the estimated number of days to complete each well. Direct drilling costs include labor, materials, supplies, repairs, maintenance, and allocations of depreciation. If a loss on a contract in progress at the end of a reporting period is anticipated, the entire amount of the estimated loss is accrued. Engineering and general and administrative expenses are expensed as incurred.

h.: Oil and Gas Properties: The Company uses the successful efforts method of accounting for oil and gas producing activities. Costs to acquire mineral interests in oil and gas properties, to drill and equip exploratory wells that find proved reserves, and to drill and equip development wells are capitalized.

Capitalized costs of producing oil and gas properties are depreciated and depleted over the estimated production period of the property, generally four to seven years. Support equipment and other property and equipment are depreciated over their estimated useful lives, generally seven years.

i.: Income Taxes: Income taxes are provided for the tax effects of transactions reported in the financial statements and consist of taxes currently due plus deferred taxes. Deferred taxes are recognized for differences between the bases of assets and liabilities for financial statement and income tax purposes. The differences relate primarily to investments, contract drilling in progress, different depreciation methods and lives used for property and equipment, and accrued expenses (deductible for income tax purposes when paid). The deferred tax assets and liabilities represent the future tax return consequences of those differences, which will either be deductible or taxable when the assets and liabilities are recovered or settled. Deferred taxes also are recognized for operating losses that are available to offset future taxable income.

F-65

2. Oil and Gas Properties

Oil and gas properties are summarized as follows:

	September 30,
	2004		2003
Leasehold costs—proved properties	$	6,983	$	6,983
Wells and related equipment		11,104		11,104

		18,087		18,087
Less: Accumulated depreciation, depletion, and amortization		15,022		13,620

Net Oil and Gas Properties	$	3,065	$	4,467

3. Notes Payable

The Company has an operating line of credit with Bank of America, N.A. The maximum borrowing available under this agreement is $500,000 as of September 30, 2004, of which $0 is borrowed at September 30, 2004. The line of credit bears a variable interest rate (which was 5.75% as of September 30, 2004). The line of credit is collateralized by the Company's equipment. The note is presently due on demand.

The Company has an unsecured note payable to the stockholder in the amount of $523,431 as of September 30, 2004. The note bears interest at 7% as of September 30, 2004. Interest expense was $36,400 and $46,542 for the years ended September 30, 2004 and 2003, respectively. This note was paid in December 2004 (see Note 9).

F-66

4. Long-Term Debt

Long-term debt consists of the following:

	September 30,
Description	2004		2003
Note payable to Bank of America, N.A., dated April 23, 2004, in the original principal amount of $350,000, due in monthly installments of $29,976 beginning May 23, 2004 through May 23, 2005, including interest at a variable rate (which was 5.75% at September 30, 2004), collateralized by equipment	$	206,561	$	—
Note payable to Bank of America, N.A., dated May 7, 2004, in the original principal amount of $200,000, due in monthly installments of $1,764 beginning June 7, 2004 through May 7, 2019, including interest at 6.60%, collateralized by property acquired in Woodward, Oklahoma		196,754		—
Notes payable to Bank of America, N.A., paid in full during the year ended September 30, 2004		—		230,399

	September 30,
Description	2004		2003
Notes payable to General Motors Acceptance Corporation, due in various monthly installments bearing interest at 0%, collateralized by vehicles	$	160,586	$	76,803

		563,901		307,202
Less: Current maturities		563,901		271,738

Total Long-Term Obligations	$	—	$	35,464

The President of the Company and the stockholder have provided guarantees of all of the Company's borrowings payable to Bank of America, N.A. All notes payable to Bank of America, N.A. and General Motors Acceptance Corporation were paid in December 2004 (see Note 9).

F-67

5. Income Taxes

The provision (benefit) for income taxes includes income taxes currently payable and those deferred because of temporary differences between the financial statement and tax bases of assets and liabilities. The provision for income taxes consists of the following:

				Year Ended September 30,
				2004			2003
Federal Income Taxes
	Current			$	458,664		$	110,234
	Deferred				58,260			16,943

					516,924			127,177

Deferred
	Benefit of net operating loss carryforwards used
		States		$	36,700		$	10,700
		Change in valuation allowance			(14,575	)		(2,800	)
	Other
		Federal			240,700			130,200
		States			36,300			19,700

					299,125			157,800

			Totals	$	816,049		$	284,977

The reconciliation of income tax computed at statutory rates to income tax expense is as follows:

		Year Ended September 30,
		2004		2003
Federal income taxes at statutory rates (34%)		$	716,582	$	247,753
State income taxes, net of federal benefit			96,877		38,782
Other			2,590		(1,558	)

	Totals	$	816,049	$	284,977

F-68

Under Financial Accounting Standards Board Statement No. 109, deferred income taxes reflect the net tax effects of temporary differences between the carrying amounts of assets and liabilities for financial statement purposes and the amounts used for income tax purposes. Significant components of the Company's deferred income tax assets (liabilities) are as follows:

			September 30,
			2004			2003
Deferred Income Tax Assets
	Net operating loss carryforwards		$	19,400		$	58,300
	Other			8,800			27,000

				28,200			85,300
Valuation allowance				—			14,575

				28,200			70,725

Deferred Income Tax Liabilities
	Contract drilling in progress			26,600			54,100
	Property and equipment			399,600			115,500

				426,200			169,600

		Net	$	(398,000	)	$	(98,875	)

Current			$	(5,900	)	$	(10,375	)
Noncurrent				(392,100	)		(88,500	)

		Totals	$	(398,000	)	$	(98,875	)

As of September 30, 2004, expiration of state net operating loss carryforwards available for income tax purposes are as follows for the years ending September 30:

	Kansas		Colorado
2006	$	71,700	$	—
2008		—		98,500
2010		—		400
2011		—		1,900
2012		44,000		—
2022		—		2,700

	$	115,700	$	103,500

F-69

6. Major Customers and Concentrations of Credit Risk

A material part of the Company's business is dependent on a few customers, the loss of which could have a material effect on the Company. Revenues attributable to customers comprising over 10% of drilling revenues during each period are as follows:

		Year Ended September 30,
		2004			2003
Customer #1		$	6,086,460		$	4,160,519

The Company contracts to drill oil and gas wells with customers within the oil and gas industry and grants credit to these customers. Financial instruments that potentially subject the Company to credit risk consist principally of trade receivables.

The Company maintains cash balances at various financial institutions. Accounts at each institution are insured by the Federal Deposit Insurance Corporation up to $100,000. The Company has uninsured cash balances at various times throughout the periods.

7. Profit Sharing Plan

All employees who are at least age 21 and have one year of service are eligible to participate in the Company 401(k) profit sharing plan. The Company made the following contributions to the plan.

		Year Ended September 30,
		2004			2003
Matching		$	23,383		$	18,611

8. Gain Contingency

The Company has filed suit against a customer requesting reimbursement for estimated damages incurred when a rig fell over at the customer job site in April 2004. The customer has filed a counterclaim seeking reduction of the amount of damages claimed by the Company. The ultimate outcome of this lawsuit cannot presently be determined.

9. Subsequent Events

The Company sold substantially all property and equipment and uncompleted drilling contracts for $6.9 million in December 2004 to Pioneer Drilling Services, Ltd. At closing the Company paid off all notes payable to the stockholder, Bank of America, N.A., and General Motors Acceptance Corporation. The sale represents the disposition of the major segment of the business, which represents substantially all net income of the Company.

Management expects to liquidate the Company in the future, although no timeline has been established. Adjustments to the values of assets and liabilities in the accompanying balance sheets have not been revised to reflect liquidation values due to the lack of a definite plan of liquidation. No loss upon liquidation is expected to be recognized.

F-70

10,500,000 Shares

Common Stock

PROSPECTUS

Jefferies & Company, Inc. Sole Book-Running Manager		Raymond James
Johnson Rice & Company L.L.C.		Pritchard Capital Partners, LLC

, 2005

PART II
INFORMATION NOT REQUIRED IN PROSPECTUS

Item 13. Other Expenses of Issuance and Distribution.

The following table sets forth all expenses payable in connection with the sale of common stock being registered. The selling shareholders will not bear any portion of such expenses. All the amounts shown are estimates except for the registration fee.

SEC Registration Fee		$	14,759
NASD filing fee			13,040
AMEX filing fee			45,000
Legal fees and expenses			130,000
Printer fees			100,000
Accounting fees and expenses			85,000
Transfer Agent fees and expenses			5,000
Miscellaneous			7,201

	Total	$	400,000

Item 14. Indemnification of Officers and Directors.

Our Articles of Incorporation, as amended, provide that a director will not be liable to the corporation or its shareholders for monetary damages for an act or omission in such director's capacity as director, except in the case of (1) breach of such director's duty of loyalty to the corporation or its shareholders, (2) an act or omission not in good faith or that involves intentional misconduct or a knowing violation of the law, (3) a transaction from which the director received an improper benefit, whether or not the benefit resulted from an action taken within the scope of the director's office or (4) an act or omission for which the liability of a director is expressly provided for by statute. Our Amended and Restated Bylaws provide that the corporation will indemnify, and advance expenses to, any executive officer or director to the fullest extent permitted by Article 2.02-1 of the Texas Business Corporation Act (the "TBCA").

Under Article 2.02-1 of the TBCA, directors, officers, employees or agents are entitled to indemnification against expenses (including attorneys' fees) whenever they successfully defend legal proceedings brought against them by reason of the fact that they hold such a position with the corporation. In addition, in situations involving actions not brought by or in the right of the corporation, the TBCA permits indemnification for expenses (including attorneys' fees), judgments, fines, penalties and reasonable settlement if it is determined that the person seeking indemnification acted in good faith and in a manner he or she reasonably believed to be in or not opposed to the best interests of the corporation or its shareholders and, with respect to criminal proceedings, he or she had no reasonable cause to believe that his or her conduct was unlawful. In cases involving actions brought by or in the right of the corporation, the TBCA permits indemnification for expenses (including attorneys' fees) and reasonable settlements, if it is determined that the person seeking indemnification acted in good faith and in a manner he or she reasonably believed to be in or not opposed to the best interests of the corporation or its shareholders; provided, indemnification is not permitted if the person is found liable to the corporation, unless the court in which the court or suit was brought has determined that indemnification is fair and reasonable in view of all the circumstances of the case.

Under an insurance policy maintained by us, our directors and executive officers are insured within the limits and subject to the limitations of the policy, against certain expenses in connection with the defense of certain claims, actions, suits or proceedings and certain liabilities which might be imposed as

II-1

a result of such claims, action, suits or proceedings, which may be brought against them by reason of being or having been such directors and executive officers.

This discussion of Article 2.02-1 of the Texas Business Corporation Act, our Articles of Incorporation, as amended, and our Amended and Restated Bylaws is not intended to be exhaustive and is qualified in its entirety by reference to the statute, our Articles of Incorporation, as amended, and our Amended and Restated Bylaws.

Item 15. Recent Sales of Unregistered Securities

Set forth below is certain information concerning all sales of securities we issued during the past three years that were not registered under the Securities Act.

Recent Sales of Unregistered Securities

On May 18, 2001, we retired the 4.86% subordinated debenture we issued to WEDGE on March 30, 2001 in connection with our acquisition of the assets of Mustang Drilling, Ltd. We funded the repayment of the $9,000,000 face amount of the debenture, together with the payment of $59,535 of accrued interest, with a short-term bank borrowing. On May 18, 2001, we sold 2,400,000 shares of our common stock to WEDGE in a private placement for $9,048,000, or $3.77 per share. We used the proceeds from that sale to fund the repayment of the short-term bank borrowing. We issued those shares, as well as the 4.86% subordinated debenture, without registration under the Securities Act of 1933 in reliance on the exemption that Section 4(2) of that Act provides for transactions not involving any public offering.

On May 31, 2001, San Patricio Corporation exercised its option to acquire 150,000 shares of our common stock for $225,000 ($1.50 per share). We issued those shares without registration under the Securities Act of 1933 in reliance on the exemption that Section 4(2) of that Act provides for transactions not involving any public offering.

In accordance with the terms of the Series B Preferred Stock Agreement that we entered into on January 20, 1998, the conversion price for our Series B convertible preferred stock was revised from $3.25 per share to $2.50 per share as of January 20, 2001. This revision was based on the average trading price of our common stock for the 30 trading days preceding that date. On August 20, 2001, the holders, T.L.L. Temple Foundation and Temple Interests L.P., converted all of their 184,615 shares of our Series B convertible preferred stock into 1,199,038 shares of our common stock at $2.50 per share. We issued those shares without registration under the Securities Act of 1933 in reliance on the exemption that Section 4(2) of that Act provides for transactions not involving any public offering.

On October 9, 2001, we issued a 6.75% five-year $18,000,000 convertible subordinated debenture, Series A, to WEDGE. The debenture was convertible into 4,500,000 shares of common stock at $4.00 per share. We used approximately $9,000,000 of the proceeds to complete the construction of two drilling rigs. Approximately $6,000,000 was used to reduce a $12,000,000 credit facility. The balance of the proceeds was used for drilling equipment and working capital. On July 3, 2002, we issued an additional $10,000,000 of 6.75% convertible subordinated debt to WEDGE with an effective conversion rate of $5.00 per share. The transaction was effected by an agreement between us and WEDGE under which WEDGE agreed to provide the additional $10,000,000 in financing and to cancel the previously issued debenture in the principal amount of $18,000,000 in exchange for $28,000,000 in new 6.75% convertible subordinated debentures. The new debentures were convertible into 6,496,519 shares of common stock at $4.31 per share, which resulted from a pro rata blending of the $5.00 conversion rate of the new $10,000,000 financing and the $4.00 conversion rate of the $18,000,000 debenture being cancelled. WEDGE funded $7,000,000 of the $10,000,000 on July 3, 2002 and $2,000,000 on July 29, 2002. William H. White, one of our Directors until May 17, 2004, and then President of WEDGE, purchased the remaining $1,000,000 on July 29, 2002. Unlike the cancelled debenture, which was not

II-2

redeemable by Pioneer, the new debentures were redeemable at a scheduled premium. We used $7,000,000 of the proceeds to pay down bank debt and $3,000,000 for the purchase of drilling equipment. On August 11, 2004, WEDGE and Mr. White converted all the debentures in accordance with their terms into a total of 6,496,519 shares of our common stock. We issued all those securities to WEDGE and Mr. White without registration under the Securities Act of 1933 in reliance on the exemption that Section 4(2) of that Act provides for transactions not involving any public offering.

On March 31, 2003, we sold 5,333,333 shares of our common stock to Chesapeake for $20,000,000 ($3.75 per share), before related offering expenses including $600,000 in commissions paid to Jefferies & Company, Inc. We issued those shares without registration under the Securities Act of 1933 in reliance on the exemption that Section 4(2) of that Act provides for transactions not involving any public offering. In connection with that sale, we granted Chesapeake a preemptive right to acquire equity securities that we may issue in the future, under specified circumstances, in order to permit Chesapeake to maintain its proportionate ownership of our outstanding shares of common stock. Chesapeake exercised its preemptive right to acquire a total of 725,803 shares in connection with a public of our common stock in August 2004. Promptly after we file the registration statement of which this prospectus is a part with the SEC, we intend to provide Chesapeake with notice of our intent to sell shares of our common stock in this offering. Chesapeake may then be able to exercise its preemptive right with respect to shares we offer in the offering, provided that it gives us notice of its intent to exercise within 10 days and certain other conditions are met.

In connection with the March 31, 2003 sale transaction, we also granted Chesapeake a right, under certain circumstances, to request registration of the acquired shares under the Securities Act of 1933. In accordance with the provisions of our agreement with Chesapeake, we have obtained a written waiver from Chesapeake of its right to include shares in this offering. Chesapeake currently owns approximately 16.80% of our outstanding common stock.

On August 1, 2003, we issued 477,000 shares of our common stock at $4.45 per share to Texas Interstate Drilling Company, L.P. in connection with our purchase of two land drilling rigs, associated spare parts and equipment and vehicles. We issued those shares without registration under the Securities Act of 1933 in reliance on the exemption that Section 4(2) of that Act provides for transactions not involving any public offering.

On February 20, 2004, we sold 4,400,000 shares of our common stock at $5.40 per share in a private placement to various individuals and institutional investors, all of whom were accredited investors. This private placement resulted in $23,760,000 in proceeds to us, before related offering expenses, which included $1,188,000 in commissions paid to Jefferies & Company, Inc., Raymond James & Associates, Inc. and Pritchard Capital Partners, LLC. Although we issued those shares without registration under the Securities Act of 1933 in reliance on the exemption that Section 4(2) of that Act provides for transactions not involving any public offering, we filed a registration statement on Form S-3 to register those shares. The registration statement became effective on June 22, 2004.

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Item 16. Exhibits and Financial Statement Schedules

(A): Exhibits:

Exhibit Number		Description
1.1		Form of Underwriting Agreement.
2.1*		Asset Purchase Agreement dated February 14, 2001 between Mustang Drilling, Ltd., Michael T. Wilhite, Sr., Andrew D. Mills and Michael T. Wilhite, Jr. (Form 10-K for the year ended March 31, 2001 (File No. 1-8182, Exhibit 2.2)).
2.2*		Stock Purchase Agreement dated July 21, 2000 between Pioneer Drilling Company and the Shareholders of Pioneer Drilling Co., Inc. (Form 10-K for the year ended March 31, 2001 (File No. 1-8182, Exhibit 2.3)).
2.3*		Purchase Agreement dated April 30, 2001 by and between Pioneer Drilling Co., Ltd. (now known as Pioneer Drilling Services, Ltd.) and IDM Equipment, Ltd. (Form 10-K for the year ended March 31, 2002 (File No. 1-8182, Exhibit 2.4)).
2.4*		Asset Purchase Agreement dated May 28, 2002 by and between United Drilling Company, U-D Holdings, L.P. and Pioneer Drilling Services, Ltd., a Texas limited partnership (Form 10-K for the year ended March 31, 2002 (File No. 1-8182, Exhibit 2.5)).
2.5*		Asset Purchase Agreement dated November 11, 2004, by and among Wolverine Drilling, Inc., Robert Mau, Robert S. Blackford and Pioneer Drilling Services, Ltd. (Form 8-K filed November 12, 2004 (File No. 1-8182, Exhibit 2.1)).
2.6*		Asset Purchase Agreement dated November 29, 2004, by and among Allen Drilling Company, the Earl Allen Family Trust dated April 1, 1979, the sole shareholder of Allen Drilling Company, Dixon Allen, Paula K. Hoisington and Lisa D. Johonnesson, all of the beneficiaries of the Trust, and Pioneer Drilling Services, Ltd. (Form 8-K filed December 2, 2004 (File No. 1-8182, Exhibit 2.1)).
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*		Debenture Agreement dated July 3, 2002 by and between WEDGE Energy Services, L.L.C. and Pioneer Drilling Company (Form 8-K filed July 18, 2002 (File No. 1-8182, Exhibit 4.1)).
4.2*		Debenture Purchase Agreement dated July 3, 2002 by and between WEDGE Energy Services, L.L.C. and Pioneer Drilling Company (Form 8-K filed July 18, 2002 (File No. 1-8182, Exhibit 4.2)).
4.3*		Subordination Agreement dated July 3, 2002 by and between The Frost National Bank, WEDGE Energy Services, L.L.C., Pioneer Drilling Company and Pioneer Drilling Services, Ltd. (Form 8-K filed July 18, 2002 (File No. 1-8182, Exhibit 4.3)).
4.4*		First Amendment to Debenture Purchase Agreement dated December 23, 2002 between WEDGE Energy Services, L.L.C., and Pioneer Drilling Company (Form 10-Q for quarter ended December 31, 2002 (File No. 1-8182, Exhibit 4.18) ).

II-4

4.5*		First Amendment to Debenture Agreement dated December 23, 2002 between William H. White and Pioneer Drilling Company (Form 10-Q for quarter ended December 31, 2002 (File No. 1-8182, Exhibit 4.19)).
4.6*		Registration Rights Agreement dated March 31, 2003, among Pioneer Drilling Company, WEDGE Energy Services, L.L.C., William H. White, an individual, and Chesapeake Energy Corporation (Form 8-K filed April 9, 2003 (File No. 1-8182, Exhibit 4.2)).
4.7*		Form of Certificate representing Common Stock of Pioneer Drilling Company (Form S-8 filed November 18, 2003 (File No. 333-110569, Exhibit 4.3)).
4.8*		Credit Agreement between Pioneer Drilling Services, Ltd. and Frost National Bank, as Administrative Agent, Agent, Lead Arranger and Lender dated October 29, 2004 (Form 8-K filed November 2, 2004 (File No. 1-8182, Exhibit 4.1) ).
4.9*		Irrevocable Conversion Notice and Agreement between Pioneer Drilling Company and William H. White dated July 9, 2004 (Form S-1 filed July 9, 2004 (Reg. No. 333-117279, Exhibit 4.19)).
4.10*		Irrevocable Conversion Notice and Agreement between Pioneer Drilling Company and WEDGE Energy Services, L.L.C. dated July 9, 2004 (Form S-1 filed July 9, 2004 (Reg. No. 333-117279, Exhibit 4.20)).
4.11*		Agreement Regarding Preemptive Rights dated July 26, 2004 between Pioneer Drilling Company and Chesapeake Energy Corporation (Form S-1 filed July 9, 2004 (Reg. No. 333-117279, Exhibit 4.21)).
5.1		Opinion of Baker Botts L.L.P. regarding validity of securities being offered.
10.1*		Voting Agreement dated June 18, 1997 between Robert R. Marmor, William D. Hibbetts, Wm. Stacy Locke, Alvis L. Dowell, Charles B. Tichenor and Richard Phillips (Form 10-K for the year ended March 31, 2001 (File No. 1-8182, Exhibit 9.1)).
10.2*		Voting Agreement dated May 11, 2000 between Wm. Stacy Locke, Michael E. Little, Pioneer Drilling Company and WEDGE Energy Services, L.L.C. (Form 10-K for the year ended March 31, 2001 (File No. 1-8182, Exhibit 9.2) ).
10.3*		Voting Agreement dated July 3, 2002 between Pioneer Drilling Company and WEDGE Energy Service, L.L.C. (See Section 1.3 of the Debenture Purchase Agreement referenced above as Exhibit 4.2)(Form 8-K filed July 18, 2002 (File No. 1-8182, Exhibit 4.2)).
10.4*+		Executive Employment Agreement dated April 25, 1995 between Pioneer Drilling Company and Wm. Stacy Locke (Form 10-K for the year ended March 31, 2001 (File No. 1-8182, Exhibit 10.1)).
10.5*+		First Amendment to Executive Employment Agreement dated November 16, 1998 between Pioneer Drilling Company and Wm. Stacy Locke (Form 10-K for the year ended March 31, 2001 (File No. 1-8182, Exhibit 10.2)).
10.6*+		Second Amendment to Executive Employment Agreement dated August 21, 2000 between Pioneer Drilling Company and Wm. Stacy Locke (Form 10-K for the year ended March 31, 2001 (File No. 1-8182, Exhibit 10.4)).
10.7*+		Pioneer Drilling Company's 1995 Stock Plan and form of Stock Option Agreement (Form 10-K for the year ended March 31, 2001 (File No. 1-8182, Exhibit 10.5)).

II-5

10.8*+		Pioneer Drilling Company's 1999 Stock Plan and form of Stock Option Agreement (Form 10-K for the year ended March 31, 2001 (File No. 1-8182, Exhibit 10.7)).
10.9*		Subscription Agreement dated February 17, 2000 between WEDGE Energy Services, L.L.C. and Pioneer Drilling Company (Form 10-K for the year ended March 31, 2001 (File No. 1-8182, Exhibit 10.8)).
10.10*		Common Stock Purchase Agreement dated May 11, 2000 between WEDGE Energy Services, L.L.C. and Pioneer Drilling Company (Form 10-K for the year ended March 31, 2001 (File No. 1-8182, Exhibit 10.9)).
10.11*		Common Stock Purchase Agreement dated May 18, 2001 between Pioneer Drilling Company and WEDGE Energy Services, L.L.C. (Form 10-K for the year ended March 31, 2001 (File No. 1-8182, Exhibit 10.10)).
10.12*		Contract dated May 5, 2000 between IRI International Corporation and Pioneer Drilling Company for the purchase of two drilling rigs (Form 10-K for the year ended March 31, 2001 (File No. 1-8182, Exhibit 10.12)).
10.13*		Equipment Lease dated effective the 8th of February, 2002 between Pioneer Drilling Services, Ltd. and International Drilling Services, Inc. (Form 10-K for the year ended March 31, 2002 (File No. 1-8182, Exhibit 10.13) ).
10.14*		Common Stock Purchase Agreement dated March 31, 2003, between Pioneer Drilling Company and Chesapeake Energy Corporation (Form 8-K filed March 31, 2003 (File No. 1-8182, Exhibit 4.1)).
10.15*		Pioneer Drilling Company 2003 Stock Plan (Form S-8 filed November 18, 2003 (File No. 333-110569, Exhibit 4.3)).
10.16*		Form of Purchase Agreement dated February 13, 2004 between Pioneer Drilling Company and the several purchasers (Form S-3 filed February 24, 2004 (Reg. No. 333-113036, Exhibit 4.1)).
21.1*		Subsidiaries of Pioneer Drilling Company (Form 10-K filed June 28, 2004 (File No. 1-8182, Exhibit 21.1)).
23.1		Consent of KPMG LLP.
23.2		Consent of Brady, Martz & Associates, P.C.
23.3		Consent of Kennedy and Coe, LLC.
23.4		Consent of Baker Botts L.L.P. (included in Exhibit 5.1).
24.1		Powers of Attorney (included on signature pages of this registration statement).

*

Incorporated by reference to the filing indicated.

+

Management contract or compensatory plan or arrangement.

(B): Financial Statement Schedules:

Financial statement schedules are omitted because they are not required or the required information is shown in our consolidated financial statements or the notes thereto.

II-6

Item 17. Undertakings

(a) Insofar as indemnification for liabilities arising under the Securities Act may be permitted to directors, officers and controlling persons of the registrant pursuant to the foregoing provisions, or otherwise, the registrant has been advised that in the opinion of the Securities and Exchange Commission, such indemnification is against public policy as expressed in the Securities Act and is, therefore, unenforceable. In the event that a claim for indemnification against such liabilities (other than the payment by the registrant of expenses incurred or paid by a director, officer or controlling person of the registrant in the successful defense of any action, suit or proceeding) is asserted by such director, officer or controlling person in connection with the securities being registered, the registrant will, unless in the opinion of its counsel the matter has been settled by controlling precedent, submit to a court of appropriate jurisdiction the question whether such indemnification by it is against public policy as expressed in the Securities Act and will be governed by the final adjudication of such issue.

(b) The undersigned registrant hereby undertakes that:

(1) For purposes of determining any liability under the Securities Act, the information omitted from the form of prospectus filed as part of this Registration Statement in reliance upon Rule 430A and contained in a form of prospectus filed by the registrant pursuant to Rule 424(b)(1) or (4) or 497(h) under the Securities Act shall be deemed to be part of this Registration Statement as of the time it was declared effective.

(2) For purposes of determining any liability under the Securities Act, each post-effective amendment that contains a form of prospectus shall be deemed to be a new registration statement relating to the securities offered therein, and the offering of such securities at that time shall be deemed to be the initial bona fide offering thereof.

II-7

SIGNATURES

Pursuant to the requirements of the Securities Act of 1933, the Registrant has duly caused this registration statement to be signed on its behalf by the undersigned, thereunto duly authorized, in the City of San Antonio, State of Texas, on February 7, 2005.

		PIONEER DRILLING COMPANY
		By:		/s/ WM. STACY LOCKE Wm. Stacy Locke President and Chief Executive Officer

KNOW ALL PERSONS BY THESE PRESENTS, that each person whose signature appears below constitutes and appoints Wm. Stacy Locke and William D. Hibbetts, and each of them, as his true and lawful attorneys-in-fact and agents, with full power of substitution and resubstitution, for the undersigned and in his name place and stead, in any and all capacities, to sign (i) any or all amendments (including post-effective amendments) to the Registration Statement and (ii) any registration statement of the type contemplated by Rule 462(b) under the Securities Act of 1933, as amended, and to file the same, with all exhibits thereto, and all documents in connection therewith, with the Securities and Exchange Commission, granting unto said attorneys-in-fact and agents, full power and authority to do and perform each and every act and thing requisite and necessary to be done in connection therewith, as fully to all intents and purposes as he might or could do in person, hereby ratifying and confirming all that said attorneys-in-fact and agents, or any of them or their or his substitute or substitutes, may lawfully do or cause to be done by virtue hereof.

Pursuant to the requirements of the Securities Act of 1933, this registration statement has been signed by the following persons in the capacities indicated on February 7, 2005.

Signature				Title

/s/ WM. STACY LOCKE Wm. Stacy Locke				President, Chief Executive Officer and Director (Principal Executive Officer)
/s/ WILLIAM D. HIBBETTS William D. Hibbetts				Senior Vice President, Chief Financial Officer and Secretary (Principal Financial and Accounting Officer)
/s/ MICHAEL E. LITTLE Michael E. Little				Chairman of the Board of Directors
/s/ DEAN A. BURKHARDT Dean A. Burkhardt				Director
/s/ JAMES M. TIDWELL James M. Tidwell				Director

II-8

/s/ C. ROBERT BUNCH C. Robert Bunch				Director
/s/ C. JOHN THOMPSON C. John Thompson				Director
/s/ MICHAEL F. HARNESS Michael F. Harness				Director

II-9

INDEX TO EXHIBITS

Exhibit Number		Description
1.1		Form of Underwriting Agreement.
2.1*		Asset Purchase Agreement dated February 14, 2001 between Mustang Drilling, Ltd., Michael T. Wilhite, Sr., Andrew D. Mills and Michael T. Wilhite, Jr. (Form 10-K for the year ended March 31, 2001 (File No. 1-8182, Exhibit 2.2)).
2.2*		Stock Purchase Agreement dated July 21, 2000 between Pioneer Drilling Company and the Shareholders of Pioneer Drilling Co., Inc. (Form 10-K for the year ended March 31, 2001 (File No. 1-8182, Exhibit 2.3)).
2.3*		Purchase Agreement dated April 30, 2001 by and between Pioneer Drilling Co., Ltd. (now known as Pioneer Drilling Services, Ltd.) and IDM Equipment, Ltd. (Form 10-K for the year ended March 31, 2002 (File No. 1-8182, Exhibit 2.4)).
2.4*		Asset Purchase Agreement dated May 28, 2002 by and between United Drilling Company, U-D Holdings, L.P. and Pioneer Drilling Services, Ltd., a Texas limited partnership (Form 10-K for the year ended March 31, 2002 (File No. 1-8182, Exhibit 2.5)).
2.5*		Asset Purchase Agreement dated November 11, 2004, by and among Wolverine Drilling, Inc., Robert Mau, Robert S. Blackford and Pioneer Drilling Services, Ltd. (Form 8-K filed November 12, 2004 (File No. 1-8182, Exhibit 2.1)).
2.6*		Asset Purchase Agreement dated November 29, 2004, by and among Allen Drilling Company, the Earl Allen Family Trust dated April 1, 1979, the sole shareholder of Allen Drilling Company, Dixon Allen, Paula K. Hoisington and Lisa D. Johonnesson, all of the beneficiaries of the Trust, and Pioneer Drilling Services, Ltd. (Form 8-K filed December 2, 2004 (File No. 1-8182, Exhibit 2.1)).
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*		Debenture Agreement dated July 3, 2002 by and between WEDGE Energy Services, L.L.C. and Pioneer Drilling Company (Form 8-K filed July 18, 2002 (File No. 1-8182, Exhibit 4.1)).
4.2*		Debenture Purchase Agreement dated July 3, 2002 by and between WEDGE Energy Services, L.L.C. and Pioneer Drilling Company (Form 8-K filed July 18, 2002 (File No. 1-8182, Exhibit 4.2)).
4.3*		Subordination Agreement dated July 3, 2002 by and between The Frost National Bank, WEDGE Energy Services, L.L.C., Pioneer Drilling Company and Pioneer Drilling Services, Ltd. (Form 8-K filed July 18, 2002 (File No. 1-8182, Exhibit 4.3)).
4.4*		First Amendment to Debenture Purchase Agreement dated December 23, 2002 between WEDGE Energy Services, L.L.C., and Pioneer Drilling Company (Form 10-Q for quarter ended December 31, 2002 (File No. 1-8182, Exhibit 4.18) ).
4.5*		First Amendment to Debenture Agreement dated December 23, 2002 between William H. White and Pioneer Drilling Company (Form 10-Q for quarter ended December 31, 2002 (File No. 1-8182, Exhibit 4.19)).

4.6*		Registration Rights Agreement dated March 31, 2003, among Pioneer Drilling Company, WEDGE Energy Services, L.L.C., William H. White, an individual, and Chesapeake Energy Corporation (Form 8-K filed April 9, 2003 (File No. 1-8182, Exhibit 4.2)).
4.7*		Form of Certificate representing Common Stock of Pioneer Drilling Company (Form S-8 filed November 18, 2003 (File No. 333-110569, Exhibit 4.3)).
4.8**		Credit Agreement between Pioneer Drilling Services, Ltd. and Frost National Bank, as Administrative Agent, Agent, Lead Arranger and Lender dated October 29, 2004 (Form 8-K filed November 2, 2004 (File No. 1-8182, Exhibit 4.1)).
4.9*		Irrevocable Conversion Notice and Agreement between Pioneer Drilling Company and William H. White dated July 9, 2004 (Form S-1 filed July 9, 2004 (Reg. No. 333-117279, Exhibit 4.19)).
4.10*		Irrevocable Conversion Notice and Agreement between Pioneer Drilling Company and WEDGE Energy Services, L.L.C. dated July 9, 2004 (Form S-1 filed July 9, 2004 (Reg. No. 333-117279, Exhibit 4.20)).
4.11*		Agreement Regarding Preemptive Rights dated July 26, 2004 between Pioneer Drilling Company and Chesapeake Energy Corporation (Form S-1 filed July 9, 2004 (Reg. No. 333-117279, Exhibit 4.21)).
5.1		Opinion of Baker Botts L.L.P. regarding validity of securities being offered.
10.1*		Voting Agreement dated June 18, 1997 between Robert R. Marmor, William D. Hibbetts, Wm. Stacy Locke, Alvis L. Dowell, Charles B. Tichenor and Richard Phillips (Form 10-K for the year ended March 31, 2001 (File No. 1-8182, Exhibit 9.1)).
10.2*		Voting Agreement dated May 11, 2000 between Wm. Stacy Locke, Michael E. Little, Pioneer Drilling Company and WEDGE Energy Services, L.L.C. (Form 10-K for the year ended March 31, 2001 (File No. 1-8182, Exhibit 9.2) ).
10.3*		Voting Agreement dated July 3, 2002 between Pioneer Drilling Company and WEDGE Energy Service, L.L.C. (See Section 1.3 of the Debenture Purchase Agreement referenced above as Exhibit 4.2) (Form 8-K filed July 18, 2002(File No. 1-8182, Exhibit 4.2)).
10.4*+		Executive Employment Agreement dated April 25, 1995 between Pioneer Drilling Company and Wm. Stacy Locke (Form 10-K for the year ended March 31, 2001 (File No. 1-8182, Exhibit 10.1)).
10.5*+		First Amendment to Executive Employment Agreement dated November 16, 1998 between Pioneer Drilling Company and Wm. Stacy Locke (Form 10-K for the year ended March 31, 2001 (File No. 1-8182, Exhibit 10.2)).
10.6*+		Second Amendment to Executive Employment Agreement dated August 21, 2000 between Pioneer Drilling Company and Wm. Stacy Locke (Form 10-K for the year ended March 31, 2001 (File No. 1-8182, Exhibit 10.4)).
10.7*+		Pioneer Drilling Company's 1995 Stock Plan and form of Stock Option Agreement (Form 10-K for the year ended March 31, 2001 (File No. 1-8182, Exhibit 10.5)).
10.8*+		Pioneer Drilling Company's 1999 Stock Plan and form of Stock Option Agreement (Form 10-K for the year ended March 31, 2001 (File No. 1-8182, Exhibit 10.7)).
10.9*		Subscription Agreement dated February 17, 2000 between WEDGE Energy Services, L.L.C. and Pioneer Drilling Company (Form 10-K for the year ended March 31, 2001 (File No. 1-8182, Exhibit 10.8)).

10.10*		Common Stock Purchase Agreement dated May 11, 2000 between WEDGE Energy Services, L.L.C. and Pioneer Drilling Company (Form 10-K for the year ended March 31, 2001 (File No. 1-8182, Exhibit 10.9)).
10.11*		Common Stock Purchase Agreement dated May 18, 2001 between Pioneer Drilling Company and WEDGE Energy Services, L.L.C. (Form 10-K for the year ended March 31, 2001 (File No. 1-8182, Exhibit 10.10)).
10.12*		Contract dated May 5, 2000 between IRI International Corporation and Pioneer Drilling Company for the purchase of two drilling rigs (Form 10-K for the year ended March 31, 2001 (File No. 1-8182, Exhibit 10.12)).
10.13*		Equipment Lease dated effective the 8th of February, 2002 between Pioneer Drilling Services, Ltd. and International Drilling Services, Inc. (Form 10-K for the year ended March 31, 2002 (File No. 1-8182, Exhibit 10.13) ).
10.14*		Common Stock Purchase Agreement dated March 31, 2003, between Pioneer Drilling Company and Chesapeake Energy Corporation (Form 8-K filed March 31, 2003 (File No. 1-8182, Exhibit 4.1)).
10.15*		Pioneer Drilling Company 2003 Stock Plan (Form S-8 filed November 18, 2003 (File No. 333-110569, Exhibit 4.3)).
10.16*		Form of Purchase Agreement dated February 13, 2004 between Pioneer Drilling Company and the several purchasers (Form S-3 filed February 24, 2004 (Reg. No. 333-113036, Exhibit 4.1)).
21.1*		Subsidiaries of Pioneer Drilling Company (Form 10-K filed June 28, 2004 (File No. 1-8182, Exhibit 21.1)).
23.1		Consent of KPMG LLP.
23.2		Consent of Brady, Martz & Associates, P.C.
23.3		Consent of Kennedy and Coe, LLC.
23.4		Consent of Baker Botts L.L.P. (included in Exhibit 5.1).
24.1		Powers of Attorney (included on signature pages of this registration statement).

*: Incorporated by reference to the filing indicated.
+: Management contract or compensatory plan or arrangement.