Edgar Filing: PIONEER DRILLING CO

Use these links to rapidly review the document
TABLE OF CONTENTS
TABLE OF CONTENTS 2

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

FORM 10-K/A

(Mark one)
ý	ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended March 31, 2003
o	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

Commission File Number: 1-8182

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

TEXAS (State or other jurisdiction of incorporation or organization)		74-2088619 (I.R.S. Employer Identification Number)
9310 Broadway, Bldg. I San Antonio, Texas (Address of principal executive offices)		78217 (Zip Code)
Registrant's telephone number, including area code: (210) 828-7689

Securities registered pursuant to Section 12(b) of the Act:

Title of each class		Name of each exchange on which registered
Common Stock $0.10 par value		American Stock Exchange

Securities registered pursuant to Section 12(g) of the Act: None

Indicate by check mark whether the Registrant: (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ý No o

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. o

Indicate by check mark whether the registrant is an accelerated filer (as defined in Rule 12b-2 of the Securities Exchange Act of 1934). Yes o No ý

The aggregate market value of the registrant's voting and nonvoting common equity held by non-affiliates of the registrant as of the last business day of the registrant's most recently completed second fiscal quarter for the fiscal year covered by this report (September 30, 2002) was $16,645,254, based on the last sales price of the registrant's common stock reported on the American Stock Exchange on that date.

As of March 31, 2004, there were 27,300,126 shares of common stock, par value $0.10 per share, of the registrant issued and outstanding.

DOCUMENTS INCORPORATED BY REFERENCE

Portions of the proxy statement related to the registrant's 2003 Annual Meeting of Shareholders are incorporated by reference into Part III of this report.

TABLE OF CONTENTS


PART I
Items 1 and 2.		Business and Properties
Item 3.		Legal Proceedings
Item 4.		Submission of Matters to a Vote of Security Holders
PART II
Item 5.		Market for Registrant's Common Equity and Related Stockholder Matters
Item 6.		Selected Financial Data
Item 7.		Management's Discussion and Analysis of Financial Condition and Results of Operations
Item 7A.		Quantitative and Qualitative Disclosures About Market Risk
Item 8.		Financial Statements and Supplementary Data
Item 9.		Change in and Disagreements with Accountants on Accounting and Financial Disclosure
PART III
Item 10.		Directors and Executive Officers of the Registrant
Item 11.		Executive Compensation
Item 12.		Security Ownership of Certain Beneficial Owners and Management
Item 13.		Certain Relationships and Related Transactions
Item 14.		Controls and Procedures
PART IV
Item 15.		Exhibits, Financial Statement Schedules and Reports on Form 8-K

PART I

Statements we make in this Annual Report on Form 10-K which express a belief, expectation or intention, as well as those that are not historical fact, are forward-looking statements under the Private Securities Litigation Reform Act of 1995. These forward-looking statements are subject to various risks, uncertainties and assumptions, including those to which we refer under the heading "Cautionary Statement Concerning Forward-Looking Statements" following Items 1 and 2 of Part I of this report.

Items 1 and 2. Business and Properties

General

Pioneer Drilling Company provides contract land drilling services to independent and major oil and gas exploration and production companies. In addition to our drilling rigs, we provide the drilling crews and most of the ancillary equipment needed to operate our drilling rigs. We have focused our operations in the natural gas production regions of South Texas and East Texas. 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."

Over the past four fiscal years, we have significantly expanded our fleet of drilling rigs through acquisitions and the construction of new and refurbished rigs. The following table summarizes these acquisitions:

Date	Acquisition	Market	Number of Rigs Acquired
September 1999	Howell Drilling, Inc.—Assets	South Texas	2
August 2000	Pioneer Drilling Co.—Stock	South Texas	4	(1)
March 2001	Mustang Drilling, Ltd.—Assets	East Texas	4
May 2002	United Drilling Company—Assets	South Texas	2

(1): Includes one drilling rig under a lease agreement.

As of May 16, 2003, our rig fleet consists of 25 drilling rigs, 15 of which are operating in South Texas and ten of which are operating in East Texas. During our fiscal year ended March 31, 2002, we added four rigs, including two newly constructed rigs and two refurbished rigs, increasing us 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 the two rigs acquired from United Drilling Company, increasing us to a total of 24 rigs at March 31, 2003. In May 2003, we took delivery of another refurbished rig. We own all the rigs in our fleet except for one rig that we operate under a lease agreement expiring in February 2004. The lease agreement includes an option to acquire this rig.

We conduct our operations primarily in South Texas and East Texas. We believe that these markets have historically experienced greater utilization rates and dayrates versus other domestic markets, due in large part to the heavy concentration of natural gas reserves located in these markets. During fiscal 2003, substantially all the wells we drilled for our customers were drilled in search of natural gas. Natural gas reserves are typically found in deeper geological formations and generally require premium equipment and quality crews to drill the wells.

Our business strategy is to own and operate a high quality fleet of land drilling rigs in active drilling markets and position ourselves as the contractor of choice for our customers in order to maximize rig utilization and dayrates and enhance shareholder value. We intend to continue making additions to our drilling fleet, either through acquisitions of businesses or selected assets or through the construction of new or refurbished drilling rigs. As we add to our fleet, we intend to focus on the addition of rigs capable of performing deep drilling for natural gas.

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. However, since 1996, 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" in Item 7 of Part II of this report.

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 gear, 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 cock, 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 triangle, 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, then back to the mud pits, which are usually steel tanks. The so-called 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 May 16, 2003, our rig fleet consists of 25 drilling rigs. We own all the rigs in our fleet except for one that we operate under a lease/purchase agreement expiring in February 2004.

The following table sets forth information regarding utilization for our fleet of drilling rigs:

	Years ended March 31,
	2003		2002		2001		2000		1999		1998
Average number of rigs for the period	22.3		18.0		10.5		6.6		6.0		6.0
Average utilization rate	79	%	82	%	91	%	66	%	66	%	86	%

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		IRI Cabot 750E	11,500	South Texas	Electric	700
2		IRI Cabot 750E	11,500	South Texas	Electric	700
3		National 110-UE	18,000	South Texas	Electric	1500
4	(1)	RMI 1000E	15,000	South Texas	Electric	1000
5		RMI 1000	15,000	South Texas	Mechanical	1000
6		Brewster N4610	12,000	East Texas	Mechanical	900
7		IRI 1700E	18,000	South Texas	Electric	1700
8		IRI 1700E	18,000	South Texas	Electric	1700
9		Gardner-Denver 500M	10,000	East Texas	Mechanical	750
10		Skytop Brewster N46	12,000	East Texas	Mechanical	950
11		Skytop Brewster N46	12,000	South Texas	Mechanical	950
12		IRI Cabot 900	10,500	South Texas	Mechanical	900
14		Skytop Brewster N46	12,000	South Texas	Mechanical	950
15		IRI Cabot 750	11,000	South Texas	Mechanical	700
16		IRI Cabot 750	11,000	South Texas	Mechanical	700
17		Ideco H-725	12,000	East Texas	Mechanical	750
18		Brewster N-75	12,500	East Texas	Mechanical	1000
19		Brewster N-75	12,500	East Texas	Mechanical	1000
20		BDW 800	13,500	East Texas	Mechanical	1000
21		National 110-UE	18,000	South Texas	Electric	1500
22		Ideco H-725	12,000	East Texas	Mechanical	750
23		Ideco H-725	12,000	East Texas	Mechanical	750
24		National 110-UE	18,000	South Texas	Electric	1500
25		National 110-UE	18,000	East Texas	Electric	1500
26		Oilwell 840E	18,000	South Texas	Electric	1500
27	(2)	IRI Cabot 1200	15,000	South Texas	Mechanical	1200

(1): We are leasing this rig under a lease agreement which expires in February 2004 and has an option to purchase the rig between January 1, 2004 and February 1, 2004.
(2): Expected delivery date of July or August 2003.

We also own a fleet of 16 trucks and related transportation equipment that we use to transport our drilling rigs to and from drilling sites.

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 were 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 an 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.

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, usually on payment of a fee.

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

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

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

The following table presents, by type of contract, information about the total number of wells we completed for our customers during each of the last three fiscal years.

	2003	2002	2001
Daywork	119	150	54
Turnkey	78	9	42
Footage	5	6	4

Total number of wells	202	165	100

Customers And Marketing

We market our rigs to a number of customers. In fiscal 2003, we drilled wells for 64 different customers, compared to 48 customers in fiscal 2002 and to 58 customers in fiscal 2001. Thirty-six of our customers in fiscal 2003 were customers for whom we had not drilled any wells in fiscal 2002. 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 2003:
Gulf Coast Energy Associates	10.8	%
Apache Corporation	6.5	%
Suemaur Exploration & Production, LLC	5.4	%
Fiscal 2002:
Dominion Exploration & Production, Inc.	13.7	%
Kerr-McGee Oil & Gas Onshore, L.L.C.	12.2	%
Pogo Producing Company	11.1	%
Fiscal 2001:
Dominion Exploration & Production, Inc.	13.6	%
Conoco, Inc.	8.8	%
Pure Resources, Inc.	6.3	%

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 East Texas and South Texas 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 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

We encounter substantial competition from other drilling contractors. Our primary market areas of South Texas and East Texas 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 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 2002, of the cost of comparable used equipment to replace the insured property. The policy provides for a deductible on rigs of $50,000 or $100,000 (depending on the rig) per occurrence. Our third-party liability insurance coverage is $26 million per occurrence and in the aggregate, with a deductible of $110,000 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, re-drilling, seepage and pollution. This policy provides coverage of either $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 565 employees. Approximately 85 of these employees are salaried administrative or supervisory employees. The rest of our employees are hourly employees who operate or maintain our drilling rigs. 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.

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. Although we have not 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 and lease a six-acre division office, storage and maintenance yard in Henderson, Texas, at a cost of $3,700 per month, pursuant to a lease extending through March 2006. 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 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. 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.

Available Information

Our website address is www.pioneerdrlg.com. We make available on this website under "Investor Relations-SEC Filings," free of charge, our annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and amendments to those reports as soon as reasonable practicable after we electronically file those materials with, or furnish those materials to, the SEC.

CAUTIONARY STATEMENT CONCERNING FORWARD-LOOKING STATEMENTS

We are including the following discussion to inform our existing and potential security holders 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.

From time to time, our management or persons acting on our behalf make forward-looking statements to inform existing and potential security holders about our company. These statements may 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," "goal" or other words that convey the uncertainty of future events or outcomes. Sometimes we will specifically describe a statement as being a forward-looking statement and refer to this cautionary statement.

In addition, various statements this Annual Report on Form 10-K contains, including those that express a belief, expectation or intention, as well as those that are not statements of historical fact, are forward-looking statements. Those forward-looking statements appear in Items 1 and 2—"Business and Properties" and Item 3—"Legal Proceedings" in Part I of this report and in Item 7—"Management's Discussion and Analysis of Financial Condition and Results of Operations," Item 7A—"Quantitative and Qualitative Disclosures About Market Risk" and in the Notes to Consolidated Financial Statements we have included in Item 8 of Part II of this report and elsewhere in this report. These forward-looking statements speak only as of the date of this report. 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;

•: decisions about onshore exploration and development projects to be made by oil and gas companies;
•: the highly competitive nature of our businesses;
•: 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 made in this report or elsewhere by us or on our behalf. We have discussed many of these factors in more detail elsewhere in this report. These factors are not necessarily all the important factors that could affect us. Unpredictable or unknown factors we have not discussed in this report 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 our security holders that they should (1) be aware that important factors not referred to above could affect the accuracy of our forward-looking statements and (2) use caution and common sense when considering our forward-looking statements.

Item 3. Legal Proceedings

On May 17, 2002, Deborah Sutton and other working interest owners in a well that we drilled in May 2000 filed an amended petition naming us as a defendant in the 37^th Judicial District Court in Bexar County, Texas, Cause No. 2001-CI-06701. Other defendants included: the operator, Sutton Producing Corp.; the casing installer, Jens' Oil Field Service, Inc.; the seller of the subject casing and collars, Exploreco, Ltd.; and the casing and collar manufacturer, Baoshan Iron & Steel Corp. The operator and the casing installer later filed cross-claims against us, alleging they were entitled to contribution or indemnity from us in the event plaintiffs recover against them.

Plaintiffs dropped all claims against us on August 8, 2002. The operator then abandoned its cross claims against us on or about May 19, 2003. Then, on May 20, 2003, the casing crew operator non-suited its affirmative cross claims against us. We remain in the suit only because the casing crew operator joined us as a responsible third party in an effort to reduce its own percentage of responsibility to the plaintiffs. However, in our position as a mere responsible third party, we are not liable to the plaintiffs or the other defendants in this suit.

We understand the remaining parties to the suit have subsequently reached a compromise and settlement which they will be finalizing in the near future.

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 or results of operations.

Item 4. Submission of Matters to a Vote of Security Holders

We did not submit any matter to a vote of our security holders during the fourth quarter of fiscal 2003.

PART II

Item 5. Market for Registrant's Common Equity and Related Stockholder Matters

As of May 16, 2003, 21,710,792 shares of our common stock were outstanding, held by approximately 618 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 began trading on the American Stock Exchange on March 8, 2001 under the symbol "PDC." Previously, our common stock was traded in the over-the-counter market and quoted in the National Quotation Bureau's "Pink Sheets" for more than 10 years. The following table sets forth, for each of the periods indicated, the high and low sales prices per share on the American Stock Exchange:

		Low		High
Fiscal Year Ended March 31, 2003:
	First Quarter	$	4.00	5.05
	Second Quarter		2.85	4.20
	Third Quarter		2.86	3.85
	Fourth Quarter		3.10	3.64
Fiscal Year Ended March 31, 2002:
	First Quarter	$	4.20	6.30
	Second Quarter		3.10	5.35
	Third Quarter		2.90	4.00
	Fourth Quarter		3.10	4.10

The last reported sales price for our common stock on the American Stock Exchange on May 16, 2003 was $4.60 per share.

We have not paid or declared any dividends on our common stock 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 credit facilities then impose. Our debt arrangements include provisions that generally prohibit us from paying dividends, other than dividends on our preferred stock. In October 2000, we paid $160,614 in dividends to the sole holder of our Series A preferred stock. The holder of those shares then converted them into 800,000 shares of our common stock in accordance with the terms of the Series A preferred stock. In May and August of 2001, we paid a total of $859,395 in dividends to the holders of our Series B preferred stock. In August 2001, the holders of those shares converted them into 1,199,038 shares of our common stock in accordance with the terms of the Series B preferred stock.

Equity Compensation Plan Information

The following table provides information on our equity compensation plans as of March 31, 2003:

Plan category	Number of securities to be issued upon exercise of outstanding options, warrants and rights	Weighted-average exercise price of outstanding options, warrants and rights	Number of securities remaining available for future issuance under equity compensation plans (excluding securities reflected in column (a))
	(a)	(b)	(c)
Equity compensation plans approved by security holders	1,825,000	1.63	360,413
Equity compensation plans not approved by security holders	—	—	—

Total	1,825,000	1.63	360,413

Recent Sales of Unregistered Securities

In May 2000, we completed a private placement of 3,768,161 shares of our common stock to WEDGE Energy Services, L.L.C. ("WEDGE") for $8,000,000, or $2.175 per share. We issued those shares without registration under the Securities Act of 1933 in reliance on the exemption Section 4(2) of that Act provides for transactions not involving any public offering.

In August 2000, we issued 341,576 shares of our common stock at $2.25 per share as part of the consideration we paid in connection with our acquisition of Pioneer Drilling Co. We issued those shares without registration under the Securities Act of 1933 in reliance on the exemption Section 4(2) of that Act provides for transactions not involving any public offering.

In October 2000, the T.L.L. Temple Foundation converted its 400,000 shares of Series A convertible preferred stock into 800,000 shares of our common stock at $1.00 per share. We issued those shares without registration under the Securities Act of 1933 in reliance on the exemption Section 4(2) of that Act provides for transactions not involving any public offering.

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. 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 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. In August 2001, the 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. We issued those shares without registration under the Securities Act of 1933 in reliance on the exemption 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 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 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 6,500,000 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 and the President of WEDGE, purchased the remaining $1,000,000 on July 29, 2002. Unlike the cancelled debenture, which was not redeemable by Pioneer, the new debentures are redeemable at a scheduled premium. We used $7,000,000 of the proceeds to pay down bank debt and $3,000,000 for the purchase of drilling equipment. WEDGE currently owns approximately 33.4% of our outstanding common stock. If WEDGE were to convert the new debentures, it would own approximately 48.3% of our outstanding common stock. We issued those securities without registration under the Securities Act of 1933 in reliance on the exemption 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 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. Chesapeake Energy owns approximately 24.6% of our outstanding common stock, or approximately 17.8% assuming the conversion of all outstanding options and convertible subordinated debentures. We issued those shares without registration under the Securities Act of 1933 in reliance on the exemption Section 4(2) of that Act provides for transactions not involving any public offering.

Item 6. Selected Financial Data

The following information derives from our audited financial statements. You should review this information in conjunction with "Management's Discussion and Analysis of Financial Condition and Results of Operations" in Item 7 of this report and the historical financial statements and related notes this report contains.

	Years Ended March 31,
	2003			2002		2001		2000			1999
	(In thousands, except per share amounts)
Contract drilling revenues	$	80,183		$	68,627	$	50,345	$	19,391		$	12,659
Earnings (loss) from operations		(4,943	)		11,201		3,803		149			(1,254	)
Earnings (loss) before income taxes		(7,305	)		9,737		3,838		(65	)		(1,278	)
Preferred dividends		—			93		275		304			304
Net earnings (loss) applicable to common stockholders		(5,086	)		6,225		2,428		(384	)		(1,612	)
Earnings (loss) per common share—basic		(0.31	)		0.41		0.22		(0.06	)		(0.27	)
Earnings (loss) per common share—diluted		(0.31	)		0.35		0.19		(0.06	)		(0.27	)
Long-term debt and capital lease obligations, excluding current installments		45,855			26,119		10,056		267			2,354
Shareholders' equity		47,672			33,343		17,827		6,783			5,322
Total assets		119,694			83,450		56,493		15,670			10,007
Capital expenditures		33,589			27,597		41,628		5,069			856

Refer to Note 2 of the consolidated financial statements for information on acquisitions.

Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations

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

Market Conditions in Our Industry

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

Beginning in 1998 and extending into 1999, the domestic contract land drilling industry was adversely affected by an extended period of low oil and gas prices and a domestic natural gas surplus. The price of West Texas Intermediate crude dropped to a low of $10.83 per barrel in December 1998 and the price of natural gas dropped to a low of $1.03 per mmbtu in December 1998. These conditions led to significant reductions in the overall level of domestic land drilling activity, resulting in a historically low domestic land rig count of 380 rigs on April 23, 1999. Prior to this industry downturn, during 1997, the contract land drilling industry experienced a significant level of drilling activity, with a domestic land rig count of 881 rigs on September 5, 1997.

Oil and natural gas prices rose sharply in calendar year 2000 and through mid-2001. Natural gas prices began falling in mid-2001 to a low of approximately $2.00 per mmbtu before returning to current levels of between $5.25 and $6.25 per mmbtu. Oil prices are currently in the $25.00 to $30.00 per barrel range. The average spot prices of natural gas and crude oil and the average domestic land rig count for each of our previous six fiscal years ended March 31, 2003 were:

	2003		2002		2001		2000		1999		1998
Oil (West Texas Intermediate)	$	29.27	$	24.31	$	30.40	$	23.23	$	13.69	$	18.92
Gas (Henry Hub)	$	4.24	$	2.96	$	5.27	$	2.46	$	1.97	$	2.39
U. S. Land Rig Count		723		912		841		560		592		821

Primarily as a result of the increase in oil and natural gas prices, exploration and production companies increased their capital spending budgets in 2000 and early 2001. These increased spending budgets increased the demand for contract drilling services. The domestic land rig count climbed to 1,095 on June 22, 2001, representing an increase in the domestic land rig count of 188% from the low in April 1999. The decline in oil and natural gas prices from mid-2001 to mid-2002 resulted in a reduction in the demand for contract land drilling services, which resulted in a substantial reduction in the rates land drilling companies have been able to obtain for their services. While oil and natural gas prices have recovered in recent months, drilling activity has not yet recovered to a level at which we are able to improve our revenue rates and drilling margins. The Baker Hughes domestic land rig count was 915 on May 16, 2003, a 29% increase from 709 on May 17, 2002.

Critical Accounting Policies and Estimates

Revenue and cost recognition—We earn our revenues by drilling oil and gas wells for our customers under daywork, turnkey or footage contracts, which usually provide for the drilling of a single well. See "Results of Operations" below for a general description of these contracts. We recognize revenues on daywork contracts for the days completed based on the dayrate each contract specifies. We recognize revenues from our turnkey and footage contracts on the percentage-of-completion method based on our estimate of the number of days to complete each 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, because 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 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 obligations 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 costs incurred to drill a well 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 cost to complete the contract divided by our estimate of the number of days to complete the contract. Contract costs include labor, materials, supplies, repairs and maintenance and operating overhead allocations. Changes in job performance, job conditions and estimated profitability on uncompleted contracts may result in revisions to costs and income, including losses, which we recognize in the period in which we determine the revisions. In addition, the occurrence of uninsured or under-insured losses or operating cost overruns on our turnkey and footage contracts could have a material adverse effect on our financial position and results of operations. Therefore, our actual results could differ significantly if our cost estimates are later revised from our original estimates.

Asset impairments—We assess the impairment of property and equipment whenever events or circumstances indicate that the carrying value may not be recoverable. Factors that we consider important and which could trigger an impairment review would be our customers' financial condition and any significant negative industry or economic trends. More specifically, among other things, we consider our contract revenue rates, our rig utilization rates, cash flows from our drilling rigs, current oil and gas prices, 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 value of our drilling equipment, at March 31, 2003, would have resulted in a corresponding increase in our net loss of approximately $704,000 for our fiscal year ended March 31, 2003.

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 drilling rigs over 10 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 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 our current management team 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 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. At March 31, 2003, we accrued an estimated loss of $227,000 on one of our turnkey contracts in progress. During fiscal 2003, we experienced losses on 17 of the 83 turnkey and footage contracts completed, with losses exceeding $25,000 on 7 contracts and losses exceeding $100,000 on two contracts. We are more likely to encounter losses on turnkey and footage contracts in years in which revenue rates are lower for all types of contracts. During periods of reduced demand for drilling rigs, our overall profitability on turnkey and footage contracts has historically exceeded our profitability on daywork contracts.

Revenues and costs during a reporting period could be affected for contracts in progress at the end of a reporting period which have not been completed before our financial statements for that period are released. All of our turnkey contracts in progress at March 31, 2003 were completed prior to

the release of these financial statements. At March 31, 2003 our Contract Drilling in Progress totaled approximately $4,429,000. Of that amount accrued, turnkey contract revenues were approximately $3,940,000. The remaining balance of approximately $489,000 relates to the revenue recognized but not yet billed on daywork contracts in progress at March 31, 2003.

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 to date have not extended payment terms beyond 60 days.

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 estimate of the useful lives of drilling, transportation and other equipment are based on our more than 35 years of experience in the drilling industry with similar equipment.

Other accrued expenses in our March 31, 2003 financial statements include an accrual of a total of $525,000 for costs incurred under the self-insurance portion of our health insurance and under our workers' compensation insurance. We have a deductible of (1) $100,000 per covered individual per year under the health insurance and (2) $250,000 per occurrence under our workers' compensation insurance. 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 to be 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

Our working capital increased to $11,144,309 at March 31, 2003 from a deficit of $268,478 at March 31, 2002. Our current ratio, which we calculate by dividing our current assets by our current liabilities, was 1.55 at March 31, 2003 compared to 0.98 at March 31, 2002. The principal reason for the improvement in our working capital at March 31, 2003 was our sale of common stock to Chesapeake Energy. Our operations have historically generated, even during periods of industry downturns, sufficient cash flow to meet our requirements for debt service and equipment expenditures. During

periods when a higher percentage of our contracts are turnkey and footage contracts our short-term working capital needs could increase. We have available a $1,000,000 line of credit for short-term cash requirements. We did not have to use the line of credit during fiscal 2003. We have used debt and equity to finance our long-term growth strategy to increase the size of our rig fleet. During periods of improved rig revenue rates, we believe we can generate cash flows in excess of our normal requirements.

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

	March 31,
	2003		2002			Change
Cash, cash equivalents and securities	$	21,002,913	$	5,720,354		$	15,282,559
Receivables		8,928,923		9,281,049			(352,126	)
Income tax receivable		444,900		880,068			(435,168	)
Deferred tax receivable		180,991		—			180,991
Prepaid expenses		914,187		634,747			279,440

Current assets		31,471,914		16,516,218			14,955,696

Current debt		3,399,163		8,275,914			(4,876,751	)
Accounts payable		14,206,586		6,507,169			7,699,417
Deferred taxes		—		23,571			(23,571	)
Accrued expenses		2,721,856		1,978,042			743,814

		20,327,605		16,784,696			3,542,909

Working capital	$	11,144,309		(268,478	)		11,412,787

The increase in cash is due to the sale of common stock described above. The decrease in current debt resulted from our repayment of a $6,000,000 bank loan on March 31, 2003, partially offset by increases in current installments of other debt obligations.

In March 2003, we completed or had in progress 20 turnkey contracts. Approximately 68% of our receivables at March 31, 2003 result from turnkey and footage contracts compared to approximately 26% of receivables at March 31, 2002.

The increase in accounts payable at March 31, 2003 over March 31, 2002 is primarily attributable to the increase in our turnkey contract work. Under turnkey contracts, we are responsible for many of the costs which are the responsibility of our customer under daywork contracts. Some of the increase in accounts payable is also due to the increase in the size of our rig fleet.

The increase in accrued expenses results from an increase in accrued payroll of $54,000 resulting from an increase in the number of employees; an increase of approximately $422,000 in the accrual for deductibles related to our health and workers' compensation insurance primarily as a result of our switching to the deductible health insurance plan in June 2002; and an increase of approximately $247,000 in accrued well control insurance, due to the increase in turnkey contracts.

Our cash flows from operating activities for the year ended March 31, 2003 were $14,389,277, compared to $11,044,889 for the year ended March 31, 2002. Our cash flows from operating activities are affected by a number of factors, including rig utilization rates, the types of contracts we are performing, revenue rates we are able to obtain for our services, collection of receivables and the timing of expenditures. The primary reason for the increase in cash flows from operating activities in fiscal 2003 is the increase in payables at March 31, 2003 over March 31, 2002.

Since March 31, 2002, the additions to our property and equipment were $33,588,972. Additions consisted of the following:

Drilling rigs(1)	$	24,667,710
Other drilling equipment		8,504,588
Transportation equipment		383,650
Other		33,024

	$	33,588,972

(1): Includes capitalized interest costs of $96,079.

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

In November and December of 2002, we added two refurbished 18,000-foot SCR land drilling rigs at a cost of approximately $7,000,000 each. As of March 31, 2003, we were constructing an additional refurbished 18,000-foot SCR land drilling rig. We estimate the total cost of this rig will be approximately $7,000,000, of which approximately $2,415,000 had been incurred as of March 31, 2003. We accepted delivery of this rig on May 2, 2003. On September 30, 2002, we signed an agreement to purchase another 14,000-foot mechanical drilling rig, located in Trinidad, for $3,150,000, which we expect to be delivered to the Port of Houston in July or August 2003. On October 7, 2002, we made a $315,000 deposit toward the purchase of this rig. In March 2003, we signed an amended asset purchase agreement reducing the purchase price for this rig to $2,850,000 and made an additional $300,000 deposit.

Our debt obligations in the form of notes payable, capital leases and convertible subordinated debentures increased by a net of $14,859,191 from March 31, 2002 to March 31, 2003. This increase resulted from a $10,000,000 increase in our subordinated debt, $14,500,000 of new debt from Merrill Lynch Capital, a division of Merrill Lynch Business Financial Services, Inc. ("MLC"), $1,239,535 to finance the premiums on insurance policies, $448,475 from our line of credit and $385,492 in capital leases for crew quarters and vehicles. In addition, on May 28, 2002, we obtained a $7,000,000 short-term loan from Frost National Bank, which we repaid on July 3, 2002 with $7,000,000 of proceeds from the issuance of new convertible subordinated debt as described below. We made payments of $18,714,311 on our debt, including the $6,000,000, $7,000,000 and $2,130,503 loan repayments. Borrowings from Frost National Bank, on an installment loan due August 2004, and MLC are secured by drilling equipment. Our bank loan and MLC Loan contain various covenants pertaining to leverage, cash flow coverage, fixed charge coverage and net worth ratios and restrict us from paying dividends. Under these credit arrangements, we determine compliance with the ratios on a quarterly basis based on the previous four quarters. As of March 31, 2003, we were in compliance with all covenants applicable to our outstanding debt.

On December 23, 2002, we borrowed $14,500,000 from MLC. Under the terms of the MLC loan, we make monthly interest payments until August 1, 2003, when we begin making equal monthly installment payments of principal of $172,619, plus interest. The unpaid balance of the MLC loan will be due at maturity on December 22, 2007. Interest accrues at a floating rate equal to the three month LIBOR rate plus 385 basis points until our election to convert the interest rate to a fixed rate, at which time interest will accrue at the greater of (1) 6.975%, or (2) the sum of the swap rate published on the Bloomberg Screen "USSW" on the conversion date plus 367 basis points. The MLC loan is secured by

a first priority security interest in certain of our drilling rigs. We may prepay the MLC loan at any time in whole, but not in part, subject to certain exceptions and payment of specified prepayment premium requirements. We used $2,130,503 of the proceeds of the Loan to retire all of our outstanding debt to one of our bank lenders, $5,106,321 to make a final payment on the new/refurbished, 18,000 foot rig added in December, $7,190,676 to replenish our working capital and $72,500 to pay associated loan fees.

On October 9, 2001, we issued a 6.75% five-year $18,000,000 convertible subordinated debenture, Series A, to WEDGE Energy Services, L.L.C. ("WEDGE"). The debenture was convertible into 4,500,000 shares of common stock at $4.00 per share. We used approximately $9,000,000 of the proceeds to complete the construction of two drilling rigs. Approximately $6,000,000 was used to reduce a $12,000,000 credit facility. The balance of the proceeds 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 6,500,000 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 and the President of WEDGE, purchased the remaining $1,000,000 on July 29, 2002. Unlike the cancelled debenture, which was not redeemable by Pioneer, the new debentures are redeemable at a scheduled premium. We used $7,000,000 of the proceeds to pay down bank debt and $3,000,000 for the purchase of drilling equipment. If WEDGE were to convert the new debentures, it would own approximately 48.3 percent of our outstanding common stock.

We have a $1,000,000 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 (4.25% at March 31, 2003) 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 $1,000,000 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, 2003, we had no outstanding advances under this line of credit, letters of credit were $1,450,000 and eligible accounts receivable were $4,299,179. 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 the lender will be required to fund any draws under these letters of credit.

We do not have any routine purchase obligations. However, we are obligated under two asset purchase agreements for the purchase and construction of two drilling rigs as previously described. The following table excludes interest payments on long-term debt and capital lease obligations. The following table includes all of our contractual obligations at March 31, 2003.

	Payments due by period
Contractual obligations	Total		2004		2005		2006		2007		2008		More than 5 years
Long Term Debt Obligations	$	48,265,786	$	2,671,269	$	6,468,524	$	2,076,690	$	2,077,054	$	34,910,777	$	61,472
Capital Lease Obligations		400,742		140,717		148,283		78,172		33,570		—		—
Operating Lease Obligations		474,738		358,008		58,008		56,010		2,712		—		—

Total	$	49,141,266	$	3,169,994	$	6,674,815	$	2,210,872	$	2,113,336	$	34,910,777	$	61,472

Events of default in our loan agreements, which could trigger an early repayment requirement, include among others:

•: our failure to make required payments;
•: our failure to comply with financial covenants related to the maintenance of a ratio of debt to tangible net worth, a leverage ratio, a cash flow coverage ratio and a senior cash flow coverage ratio;
•: our incurrence of any additional indebtedness in excess of $2,000,000 not already allowed by the loan agreements without the lenders approval;
•: any payment of cash dividends on our common stock.

The limitation on additional indebtedness has not affected our operations or liquidity and we do not expect it to affect us in the future as we expect to continue to generate adequate cash flow from operations. We also have a $1,000,000 line of credit to supplement our short-term cash needs.

Results of Operations

We earn our revenues by drilling oil and gas wells. We obtain our contracts for drilling oil and gas wells either through competitive bidding or through direct negotiations with customers. Our drilling contracts generally provide for compensation on either a daywork, turnkey or footage basis. Contract terms we offer generally depend on the complexity and risk of operations, the on-site drilling conditions, the type of equipment used and the anticipated duration of the work to be performed. Generally, our contracts provide for the drilling of a single well.

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

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

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

For each of the three years ended March 31, 2003, our rig utilization and revenue days were as follows:

		2003		2002		2001
Utilization Rates		79	%	82	%	91	%
Revenue Days		6,419		5,384		3,466

The primary reason for the increase in the number of revenue days in 2003 over 2002 and 2002 over 2001 is the increase in size of our rig fleet from 16 at March 31, 2001 to 20 at March 31, 2002 to 24 at March 31, 2003.

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

	2003		2002		2001
Turnkey Contracts	58	%	7	%	57	%
Footage Contracts	1	%	2	%	1	%
Daywork Contracts	41	%	91	%	42	%

Due to the current reduced demand for drilling rigs, we have returned to bidding on turnkey contracts in an effort to improve margins and rig utilization. In spite of improvements in oil and natural gas prices, we anticipate only a moderate change in the mix of our type of contracts in the near future.

In accordance with Emerging Issues Task Force issue No. 01-14 "Income Statement Characterization of Reimbursements Received for Out-of-Pocket Expenses Incurred," we have revised the presentation of reimbursements received for certain expenses in the periods presented. These reimbursements are now included in contract drilling revenues in the consolidated statements of operations versus previously being recorded net of the incurred expense in contract drilling costs. These reclassifications had no effect on net income or cash flows for any of the three years ended March 31, 2003.

Our contract drilling revenues for the fiscal year ended March 31, 2003 increased to $80,183,486 from $68,627,486 for the fiscal year ended March 31, 2002. This increase primarily resulted from an approximately 19% increase in revenue days and a higher percentage of turnkey contracts, partially offset by a decrease in rig revenue rates. Our contract drilling revenues increased to $68,627,486 for fiscal 2002 from $50,344,909 for fiscal 2001 principally due to an increase in revenue rates and a 55% increase in revenue days due to more rigs.

Our contract drilling costs for the fiscal year ended March 31, 2003 increased to $70,823,310 from $46,145,364 for the 2002 fiscal year. The percentage increase in revenue days and the additional costs associated with turnkey contracts account for the substantial increase in our drilling costs in 2003. Our contract drilling costs increased to $46,145,364 for fiscal 2002 from $41,687,893 for fiscal 2001. Contract

drilling costs for the year ended March 31, 2002 include a $275,000 charge related to severance costs for a corporate officer. In addition, as previously reported, one of our former employees, Jesse J. Sanchez, filed a petition against us in the District Court for the 341st District in Webb County, Texas. The petition asserted a claim for injuries resulting from an accident involving one of our drilling rigs. On December 19, 2001, we settled this claim for $500,000. The cost of this settlement is also included in our contract drilling costs for the fiscal year ended March 31, 2002.

Our depreciation and amortization expense in 2003 increased to approximately $11,960,000 from approximately $8,426,000 in 2002 and approximately $3,738,000 in 2001. The increases in 2003 over 2002 and 2002 over 2001 resulted from our addition of four drilling rigs and related equipment in each of the years ended March 31, 2003 and 2002.

Our general and administrative expenses decreased to approximately $2,232,000 in 2003 from approximately $2,855,000 in 2002. The decrease resulted from reduced payroll costs, legal and professional fees and investor relation costs. The increase in 2002 from approximately $1,117,000 in 2001 resulted from increased payroll costs, legal and professional fees and investor relations costs.

Our contract land drilling operations are subject to various federal and state laws and regulations designed to protect the environment. Maintaining compliance with these regulations is part of our day-to-day operating procedures. We monitor each of our yard facilities and each of our rig locations on a daily 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 cost of these procedures represent only a small portion our routine employee training, equipment and job site maintenance costs. We estimate our annual compliance costs for this program is approximately $116,000. 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 expense rates of 30.4%, 35.1% and 29.6% for 2003, 2002 and 2001 differ from the federal statutory rate of 34% due to permanent differences. Permanent differences are costs included in results of operations in the accompanying financial statements which are not fully deductible for federal income tax purposes.

Accounting Matters

In June 2001, the Financial Accounting Standards Board issued Statement of Financial Accounting Standards ("SFAS") No. 143, "Accounting for Asset Retirement Obligations," which addresses financial accounting and reporting for obligations associated with the retirement of tangible long-lived assets and the associated asset retirement costs. The standard applies to legal obligations associated with the retirement of long-lived assets that result from the acquisition, construction, development and/or normal use of the asset. We are required to adopt the provisions of SFAS No. 143 beginning April 1, 2003. In that connection, we must identify all our legal obligations relating to asset retirements and determine the fair value of these obligations on the date of adoption. We do not expect the adoption of SFAS No. 143 to have a material effect on our financial position or results of operations.

In December 2002, the FASB issued SFAS No. 148, "Accounting for Stock-Based Compensation—Transition and Disclosure, an amendment of FASB Statement No. 123." This Statement amends FASB Statement No. 123, "Accounting for Stock-Based Compensation," to provide alternative methods of transition for a voluntary change to the fair value method of accounting for stock-based employee compensation. In addition, this Statement amends the disclosure requirements of Statement No. 123 to require prominent disclosures in both annual and interim financial statements. Certain of the disclosure modifications are required for fiscal years ending after December 15, 2002 and are included in the notes to the consolidated financial statements included in this report.

Inflation

As a result of the relatively low levels of inflation during the past three years, inflation did not significantly affect our results of operations in any of our last three fiscal years.

Item 7A. Quantitative and Qualitative Disclosures About Market Risk

We are subject to market risk exposure related to changes in interest rates on most of our outstanding debt. At March 31, 2003, we had outstanding debt of approximately $20,178,000 that was subject to variable interest rates, in each case based on an agreed percentage-point spread from the lender's prime interest rate. An increase or decrease of 1% in the interest rate would have a corresponding decrease or increase in our net income (loss) of approximately $133,000 annually. We did not enter into any of these debt arrangements for trading purposes.

Item 8. Financial Statements and Supplementary Data

PIONEER DRILLING COMPANY
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS


Report of Independent Registered Public Accounting Firm
Consolidated Balance Sheets as of March 31, 2003 and 2002
Consolidated Statements of Operations for the Years Ended March 31, 2003, 2002 and 2001
Consolidated Statements of Shareholders' Equity and Comprehensive Income for the Years Ended March 31, 2003, 2002 and 2001
Consolidated Statements of Cash Flows for the Years Ended March 31, 2003, 2002 and 2001
Notes to Consolidated Financial Statements

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, 2003 and 2002 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, 2003. 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, 2003 and 2002, and the results of their operations and their cash flows for each of the years in the three-year period ended March 31, 2003, in conformity with U.S. generally accepted accounting principles.

KPMG LLP

San Antonio, Texas
May 20, 2003

PIONEER DRILLING COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS

			March 31,
			2003			2002
ASSETS
Current assets:
	Cash and cash equivalents		$	21,002,913		$	5,383,045
	Securities available for sale			—			337,309
	Receivables:
		Trade, net of allowance for doubtful accounts of $110,000 in 2003		4,499,378			6,160,797
		Contract drilling in progress		4,429,545			3,120,252
	Federal income tax receivable			444,900			880,068
	Current deferred income taxes			180,991			—
	Prepaid expenses			914,187			634,747

Total current assets				31,471,914			16,516,218

Property and equipment, at cost:
	Drilling rigs and equipment			106,728,573			77,149,043
	Transportation, office, land and other			3,494,657			3,203,979

				110,223,230			80,353,022
Less accumulated depreciation and amortization				22,367,327			13,621,396

Net property and equipment				87,855,903			66,731,626
Other assets				366,500			201,914

Total assets			$	119,694,317		$	83,449,758

LIABILITIES AND SHAREHOLDERS' EQUITY
Current liabilities:
	Notes payable		$	587,177		$	6,329,925
	Current installments of long-term debt			2,671,269			1,836,860
	Current installments of capital lease obligations			140,717			109,129
	Accounts payable			14,206,586			6,507,169
	Current deferred income taxes			—			23,571
	Accrued expenses:
		Payroll and payroll taxes		847,163			792,805
		Other		1,874,693			1,185,237

Total current liabilities				20,327,605			16,784,696
Long-term debt, less current installments				45,594,517			25,829,610
Capital lease obligations, less current installments				260,025			288,991
Deferred income taxes				5,839,908			7,203,456

Total liabilities				72,022,055			50,106,753

Shareholders' equity:
	Preferred stock, 10,000,000 shares authorized; none issued and outstanding
	Common stock $.10 par value; 100,000,000 shares authorized; 21,700,792 shares and 15,922,459 shares issued and outstanding at March 31, 2003 and March 31,2002, respectively			2,170,079			1,592,245
	Additional paid-in capital			57,730,188			38,783,731
	Accumulated deficit			(12,228,005	)		(7,142,387	)
	Accumulated other comprehensive income-unrealized gain on securities available for sale			—			109,416

Total shareholders' equity				47,672,262			33,343,005

Total liabilities and shareholders' equity			$	119,694,317		$	83,449,758

See accompanying notes to consolidated financial statements.

PIONEER DRILLING COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS

		Years Ended March 31,
		2003			2002			2001
Contract drilling Revenues		$	80,183,486		$	68,627,486		$	50,344,909

Costs and expenses:
	Contract drilling		70,823,310			46,145,364			41,687,893
	Depreciation and amortization		11,960,387			8,426,082			3,737,533
	General and administrative		2,232,390			2,855,274			1,116,727
	Bad debt expense		110,000			—			—

	Total operating costs and expenses		85,126,087			57,426,720			46,542,153

Earnings (loss) from operations			(4,942,601	)		11,200,766			3,802,756

Other income (expense):
	Interest expense		(2,698,529	)		(1,616,984	)		(888,863	)
	Interest income		94,235			80,932			316,025
	Other		37,614			72,096			71,559
	Gain on sale of securities		203,887			—			536,486

	Total other income (expense)		(2,362,793	)		(1,463,956	)		35,207

Earnings (loss) before income taxes			(7,305,394	)		9,736,810			3,837,963
Income tax (expense) benefit			2,219,776			(3,418,525	)		(1,135,174	)

Net earnings (loss)			(5,085,618	)		6,318,285			2,702,789
Preferred stock dividend requirement			—			92,814			274,630

Net earnings (loss) applicable to common shareholders		$	(5,085,618	)	$	6,225,471		$	2,428,159

Earnings (loss) per common share—Basic		$	(0.31	)	$	0.41		$	0.22

Earnings (loss) per common share—Diluted		$	(0.31	)	$	0.35		$	0.19

Weighted average number of shares outstanding—Basic			16,163,098			15,112,272			11,137,171

Weighted average number of shares outstanding—Diluted			16,163,098			19,221,256			13,901,101

See accompanying notes to consolidated financial statements.

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, 2000		7,274,684	584,615		$	727,468	$	3,799,994		$	17,723,569	$	(15,796,017	)	$	328,478		$	6,783,492
Comprehensive income:
	Net earnings	—	—			—		—			—		2,702,789			—			2,702,789
	Net unrealized change in securities available for sale, net of tax of $56,750	—	—			—		—			—		—			(218,360	)		(218,360	)

Total comprehensive income		—	—			—		—			—		—			—			2,484,429

Issuance of common stock for:
	Sale, net of related expenses	3,678,161	—			367,816		—			7,632,184		—			—			8,000,000
	Acquisition	341,576	—			34,158		—			734,387		—			—			768,545
	Conversion of preferred	800,000	(400,000	)		80,000		(800,000	)		720,000		—			—			—
	Exercise of options	51,500	—			5,150		—			59,776		—			—			64,926
Preferred stock dividend		—	—			—		—			—		(274,630	)		—			(274,630	)

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	5,333,333	—			533,334		—			18,809,167		—			—			19,342,501
	Exercise of options and related income tax benefits	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

See accompanying notes to consolidated financial statements.

PIONEER DRILLING COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS

				Years Ended March 31,
				2003			2002			2001
Cash flows from operating activities:
	Net earnings (loss)			$	(5,085,618	)	$	6,318,285		$	2,702,789
		Adjustments to reconcile net earnings (loss) to net cash provided by operating activities:
		Depreciation and amortization			11,960,387			8,426,082			3,737,533
		Allowance for doubtful accounts			110,000			—			—
		Gain on sale of securities			(203,887	)		—			(536,486	)
		Loss (gain) on sale of properties and equipment			279,054			(2,237	)		—
		Change in deferred income taxes			(1,511,744	)		1,991,458			965,008
		Changes in current assets and liabilities:
			Receivables		242,126			(4,172,470	)		(3,157,961	)
			Prepaid expenses		(279,440	)		(322,471	)		177,676
			Accounts payable		7,699,417			(1,099,813	)		3,642,048
			Federal income taxes		435,168			(930,266	)		50,198
			Accrued expenses		743,814			836,321			853,045

	Net cash provided by operating activities				14,389,277			11,044,889			8,433,850

Cash flows from financing activities:
	Proceeds from notes payable				23,573,501			19,556,286			15,547,477
	Proceeds from subordinated debenture				10,000,000			18,000,000			9,000,000
	Increase in other assets				(253,698	)		(195,000	)		(46,322	)
	Payment of preferred dividends				—			(859,395	)		(160,614	)
	Proceeds from exercise of options and warrants				181,790			243,474			64,926
	Proceeds from common stock, net				19,342,501			9,048,000			8,000,000
	Payments of debt				(18,714,311	)		(27,026,538	)		(6,336,803	)

Net cash provided by financing activities					34,129,783			18,766,827			26,068,664

Cash flows from investing activities:
	Purchases of property and equipment:
		Acquisitions			—			—			(22,806,456	)
		Other			(33,588,972	)		(27,597,265	)		(12,165,178	)
	Proceeds from sale of marketable securities				375,414			—			1,039,597
	Proceeds from sale of property and equipment				314,366			675,660			—

Net cash used in investing activities					(32,899,192	)		(26,921,605	)		(33,932,037	)

Net increase in cash and cash equivalents					15,619,868			2,890,111			570,477
Beginning cash and cash equivalents					5,383,045			2,492,934			1,922,457

Ending cash and cash equivalents				$	21,002,913		$	5,383,045		$	2,492,934

Supplementary disclosure:
	Interest paid			$	2,785,177		$	1,046,943		$	760,821
	Income taxes paid (refunded)				(1,143,200	)		2,342,006			140,655
	Dividends accrued				—			92,814			274,630
	Conversion of preferred stock				—			2,999,994			800,000
	Pioneer Drilling Co. acquisition:
		Common Stock issued			—			—			768,545
		Debt assumed			—			—			1,673,533
		Deferred taxes assumed			—			—			4,214,195

See accompanying notes to consolidated financial statements.

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 South Texas 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 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

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,
	2003			2002			2001
Net earnings (loss)—as reported	$	(5,085,618	)	$	6,318,285		$	2,702,789
Deduct: Total stock-based employee compensation expense determined under fair value based method for all awards net of related tax effect		(385,671	)		(582,258	)		(359,224	)

Net earnings (loss)—pro forma	$	(5,471,289	)	$	5,736,027		$	2,343,565

Net earnings (loss) per share—as reported—basic	$	(0.31	)	$	0.41		$	0.22
Net earnings (loss) per share—as reported—diluted		(0.31	)		0.35			0.19
Net earnings (loss) per share—pro forma—basic		(0.34	)		0.38			0.19
Net earnings (loss) per share—pro forma—diluted		(0.34	)		0.32			0.17
Weighted-average fair value of options granted during the year		3.50			3.11			2.29

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 69%, 90% and 117% and weighted average risk-free interest rates of 3.2%, 4.5% and 5.4% for grants in 2003, 2002 and 2001, 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.

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. 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. At March 31, 2003, we accrued an estimated loss of $227,000 on one of our turnkey contracts in progress.

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 2003 and 2002, we capitalized $96,079 and $328,285, respectively, of interest costs incurred during the construction periods of certain drilling equipment.

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.

In April 2003, we sold a rig yard in Kenedy, Texas which we were no longer using. We realized proceeds from the sale of approximately $115,000 and recognized a gain of approximately $25,000.

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 seven day tax exempt municipal preferred securities. Cash equivalents at March 31, 2003 and 2002 were $1,060,000 and $4,435,000, 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. Past due balances over 90 days 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, 2003 our allowance for doubtful accounts was $110,000. No allowance for doubtful accounts was necessary at March 31, 2002.

Other Assets

Other assets consist of cash deposits related to the deductibles on our workers compensation insurance policies and loan fees net of amortization. Loan fees are amortized over the terms of the related debt.

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

Reclassifications

2. Acquisitions

On August 21, 2000, we acquired all the outstanding stock of Pioneer Drilling Co., a Corpus Christi, Texas-based land drilling contractor. Pioneer Drilling Co.'s assets included four land drilling rigs and associated machinery and equipment. Pioneer Drilling Co. owned three of its rigs and leased the fourth rig. The consideration we paid for the acquisition, after giving effect to a purchase price adjustment, was $11,500,000, consisting of a cash payment of $10,731,456, which we financed with long-term debt as described in Note 3, and the issuance of 341,576 restricted shares of our common stock at $2.25 per share. This purchase was accounted for as the acquisition of a business, and we have included the results of operations of Pioneer Drilling Co. in our statement of operations since the date of acquisition. We allocated the purchase price plus assumed liabilities and deferred tax liability of $4,214,195 to working capital and property and equipment based on their relative fair values at the date of acquisition.

On March 30, 2001, we acquired all the contract drilling equipment of Mustang Drilling, Ltd., a land drilling contractor based in Henderson, Texas. The equipment included four land drilling rigs and associated yard equipment. We paid $12,000,000 in cash for these assets. We financed this acquisition with $3,000,000 of the bank debt and the $9,000,000 subordinated debt described in Note 8. This purchase was accounted for as the acquisition of a business, and we have included the results of its operations of in our statement of operations since the date of acquisition. We allocated the purchase price to property and equipment based on their relative fair values at the date of acquisition.

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. This 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.

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

Our long-term debt is described below:

	March 31,
	2003			2002
Convertible subordinated debentures due July 2007 at 6.75%	$	28,000,000		$	18,000,000
Note payable, secured by drilling equipment, due in monthly payments of $172,619 beginning August 1, 2003 plus interest at a floating rate equal to the 3 month LIBOR rate plus 385 basis points, due December 2007		14,500,000			—
Note payable, secured by drilling equipment, due in monthly payments of $107,143 plus interest at prime (4.25% at March 31, 2003) plus 1.00%, due August 2004		5,677,889			6,963,603
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		87,897			92,201
Note payable, secured by drilling equipment, land and improvements, due in monthly payments of $50,585, including interest at prime plus 1%, due November 2007 (paid off December 2002)		—			2,483,411
Note payable to bank, secured by land and improvements, due in monthly payments of $1,900 including interest at the bank's prime rate plus 0.5% due in September 2005 (paid off March 2003)		—			52,249
Notes payable, secured by vehicles, due in monthly payments of $2,150 including interest, due through December 2004 (paid off March 2003)		—			50,006
Note payable to seller, secured by drilling equipment, due in monthly installments of $5,000 plus interest at 10%, due June 2002		—			25,000

		48,265,786			27,666,470
Less current installments		(2,671,269	)		(1,836,860	)

	$	45,594,517		$	25,829,610

Long-term debt maturing each year subsequent to March 31, 2003 is as follows:

Year Ended March 31,
2004	$	2,671,269
2005		6,468,524
2006		2,076,690
2007		2,077,054
2008		34,910,777
2009 and thereafter		61,472

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 6,500,000 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 and the President of WEDGE, purchased the remaining $1,000,000 on July 29, 2002. Unlike the cancelled debenture, which was not redeemable by Pioneer, the new debentures are redeemable at a scheduled premium. 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 $1,000,000 line of credit available from a bank. Any borrowings under this line of credit are secured by our trade receivables and bear interest at a rate of prime (4.25% at March 31, 2003) 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 $1,000,000 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, 2003, we had no outstanding advances under this line of credit, letters of credit were $1,450,000 and eligible accounts receivable were $4,299,179. 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 the lender will be required to fund any draws under these letters of credit.

At March 31, 2003, we were in compliance with all covenants applicable to our outstanding debt. Those covenants include, among others, the maintenance of ratios of debt to net worth, leverage, cash flow and fixed cost coverage. The covenants also restrict the payment of dividends on common stock.

Current notes payable at March 31, 2003 consists of a $587,177 insurance premium note due August 26, 2003 which bears interest at the rate of 2.8% per year.

4. Leases

We are obligated under capital leases covering several trucks that expire at various dates through January 2007. At March 31, 2003 and 2002, the gross amount of transportation equipment and related amortization recorded under capital leases were as follows:

	2003		2002
Transportation equipment	$	647,822	$	519,363
Less accumulated amortization		248,070		136,435

	$	399,752	$	382,928

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

In February 2002, we renewed for two years an operating lease on one of our drilling rigs. The lease renewal includes an option to acquire the rig for $4,000,000, its estimated market value on the renewal date of the lease, which we can exercise between January 1, 2004 and February 1, 2004. If we exercise the option, approximately 50% of the rentals we pay during the lease term can be applied to the purchase price. We also lease real estate in Henderson, Texas and various equipment under noncancelable operating leases expiring through 2006.

Rent expense under these operating leases for the years ended March 31, 2003, 2002 and 2001 was $344,752, $208,150 and $20,000, respectively.

Future lease obligations and minimum capital lease payments as of March 31, 2003 were as follows:

Year Ended March 31,		Operating Leases		Capital Leases
	2004	$	358,008	$	170,910
	2005		58,008		164,997
	2006		56,010		70,446
	2007		2,712		34,626

Total minimum lease payments		$	474,738	$	440,979

Less amounts representing interest (at rates ranging from 5.8% to 9.5%)					(40,237	)

Present value of net minimum capital lease payments					400,742
Less current installments of capital lease obligations					(140,717	)

Capital lease obligations, excluding current installments				$	260,025

5. Income Taxes

Our provision for income taxes consisted of the following:

	Years Ended March 31,
	2003			2002		2001
Current tax—federal	$	(708,032	)	$	1,427,067	$	49,593
Current tax—state		—			—		120,573
Deferred tax—federal		(1,511,744	)		1,991,458		965,008

Income tax expense (benefit)	$	(2,219,776	)	$	3,418,525	$	1,135,174

In fiscal years 2003, 2002 and 2001, 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,
	2003			2002			2001
Expected tax expense (benefit)	$	(2,483,834	)	$	3,310,515		$	1,304,907
Net operating loss carry forwards and valuation allowances		—			—			(335,422	)
Non taxable interest income		(10,400	)		(9,429	)		—
Club dues, meals and entertainment		10,443			10,115			34,729
State taxes		—			—			79,578
Other		264,015			107,324			51,382

	$	(2,219,776	)	$	3,418,525		$	1,135,174

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

		March 31,
		2003		2002
Deferred tax assets:
	Workers compensation and vacation expense accruals	$	94,972	$	32,795
	Bad debt expense		37,400		—
	Net operating loss carryforwards		5,105,730		—
	Alternative minimum tax credit		181,770		—
	Other		48,619		—

	Total deferred tax assets		5,468,491		32,795

Deferred tax liabilities:
	Property and equipment, principally due to differences in depreciation		11,127,408		7,203,456
	Unrealized gain on securities available for sale		—		56,366

	Total deferred tax liabilities		11,127,408		7,259,822

	Net deferred tax liabilities	$	5,658,917	$	7,227,027

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.

At March 31, 2003, we had net operating loss carryforwards for federal income tax purposes of approximately $15,000,000 which will expire if not utilized by March 31, 2023.

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.

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,
		2003			2002		2001
Basic
Net earnings (loss)		$	(5,085,618	)	$	6,318,285	$	2,702,789
Less: Preferred stock dividends			—			92,814		274,630

Earnings (loss) applicable to common shareholders		$	(5,085,618	)	$	6,225,471	$	2,428,159

Weighted average shares			16,163,098			15,112,272		11,137,171

Earning (loss) per share		$	(0.31	)	$	0.41	$	0.22

Diluted
Earnings (loss) applicable to common shareholders		$	(5,085,618	)	$	6,225,471	$	2,428,159
Effect of dilutive securities:
	Convertible subordinated debenture		—			385,358		—
	Preferred stock		—			92,814		274,630

	Earnings (loss) available to common shareholders and assumed conversion	$	(5,085,618	)	$	6,703,643	$	2,702,789

Weighted average shares:
	Outstanding		16,163,098			15,112,272		11,137,171
	Options		—			1,500,589		1,771,864
	Convertible subordinated debenture		—			2,145,205		—
	Preferred stock					463,190		992,066

			16,163,098			19,221,256		13,901,101

Earnings (loss) per share		$	(0.31	)	$	0.35	$	0.19

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

8. Equity Transactions

In May 2000, we completed a private placement of 3,768,161 shares of our common stock to WEDGE for $8,000,000, or $2.175 per share.

In August 2000, we issued 341,576 shares of our common stock at $2.25 per share as part of the consideration we paid in connection with our acquisition of Pioneer Drilling Co.

In October 2000, the T.L.L. Temple Foundation converted its 400,000 shares of Series A convertible preferred stock into 800,000 shares of our common stock at $1.00 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).

Directors and employees exercised stock options for the purchase of 445,000 shares of common stock at prices ranging from $.375 to $2.50 per share during the year ended March 31, 2003, 27,500 shares of common stock at prices ranging from $.375 to $1.00 per share during the year ended March 31, 2002 and 51,500 shares of common stock at prices ranging from $0.15 to $2.50 per share during the year ended March 31, 2001. On May 1, 2003, one of our officers exercised stock options for the purchase of 10,000 shares of common stock at a price of $2.25 per share.

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.

The following table provides information relating to our outstanding stock options at March 31, 2003, 2002 and 2001:

			2003				2002				2001
			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		2,320,000		$	0.375-5.15	2,177,500		$	0.375-4.60	1,759,000		$	0.15-1.50
		Granted	65,000		$	3.20-4.50	585,000		$	3.00-5.15	515,000		$	2.25-4.60
		Exercised	(445,000	)	$	0.375-2.50	(177,500	)	$	0.375-1.50	(51,500	)	$	0.15-2.50
		Canceled	(115,000	)	$	2.25-4.60	(265,000	)	$	2.25	(45,000	)	$	0.375-1.50

Balance Outstanding
	End of year		1,825,000		$	0.375-5.15	2,320,000		$	0.375-5.15	2,177,500		$	0.379-4.60

Options Exercisable
	End of year		1,437,334				1,734,000				1,172,500

As of March 31, 2003, there are no outstanding warrants.

At March 31, 2003, the weighted average exercise price of our outstanding options was $1.63 per share and the weighted average exercise price of our exercisable options was $1.28 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 2003, 2002 and 2001 were approximately $92,000, $153,000 and $101,000, 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, 2003 include approximately $270,000 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, 2003 include approximately $255,000 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.

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, 2003, our three largest customers accounted for 10.8%, 6.5% and 5.4%, respectively, of our total contract drilling revenue. All three of these customers were customers of ours in 2002. In fiscal 2002, our three largest customers accounted for 13.7%, 12.2% and 11.1%, of our total contract drilling revenue. Two of these customers were customers of ours in fiscal 2001. In fiscal 2001, our three largest customers accounted for 13.6%, 8.8% and 6.3% of our total contract drilling revenue.

12. Commitments and Contingencies

As of March 31, 2003, we were constructing one refurbished 18,000-foot SCR land drilling rig. We estimate the total cost of this rig will be approximately $7,000,000, of which approximately $2,415,000 had been incurred as of March 31, 2003. We accepted delivery of this rig on May 2, 2003. On September 30, 2002, we signed an agreement to purchase another 14,000-foot mechanical drilling rig, located in Trinidad, for $3,150,000, which we expect to be delivered to the Port of Houston in July or August 2003. On October 7, 2002, we made a $315,000 deposit toward the purchase of this rig. In March 2003, we signed an amended asset purchase agreement reducing the purchase price for this rig to $2,850,000 and made an additional $300,000 deposit.

collars, Exploreco, Ltd.; and the casing and collar manufacturer, Baoshan Iron & Steel Corp. The operator and the casing installer later filed cross-claims against us, alleging they were entitled to contribution or indemnity from us in the event plaintiffs recover against them. Plaintiffs dropped all claims against us on August 8, 2002. The operator then abandoned its cross claims against us on or about May 19, 2003. Then, on May 20, 2003, the casing crew operator non-suited its affirmative cross claims against us. We remain in the suit only because the casing crew operator joined us as a responsible third party in an effort to reduce its own percentage of responsibility to the plaintiffs. However, in our position as a mere responsible third party, we are not liable to the plaintiffs or the other defendants in this suit. We understand the remaining parties to the suit have subsequently reached a compromise and settlement which they will be finalizing in the near future.

13. Quarterly Results of Operations (unaudited)

The following table summarizes quarterly financial data for our fiscal years ended March 31, 2003 and 2002 (in thousands, except per share data):

		First Quarter			Second Quarter			Third Quarter			Fourth Quarter			Total
2003
Revenues		$	18,443		$	16,978		$	19,727		$	25,073		$	80,221
Earnings (loss) from operations			165			(1,241	)		(1,827	)		(2,002	)		(4,905	)
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	)
2002
Revenues		$	18,298		$	17,691		$	16,539		$	16,172		$	68,700
Earnings from operations			5,292			4,232			1,293			456			11,273
Net earnings (loss)			3,174			2,612			551			(19	)		6,318
Net earnings (loss) applicable to common shareholders			3,114			2,579			551			(19	)		6,225
Earnings (loss) per share
	Basic		0.23			0.17			0.03			(0.00	)		0.41
	Diluted		0.20			0.15			0.03			(0.00	)		0.35

The sum of the quarterly earnings per share amounts do not necessarily agree with the year end amounts due to the dilutive effects of convertible instruments.

Item 9. Change in and Disagreements with Accountants on Accounting and Financial Disclosure

Not applicable.

PART III

In Items 12 and 13 below, we are incorporating by reference the information we refer to in those Items from the definitive proxy statement for our 2003 Annual Meeting of Shareholders that we filed with the SEC on July 8, 2003.

Item 10. Directors and Executive Officers of the Registrant

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 the 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 (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. (1979), a provider of oilfield tubular make-up, tubular inspection, and third-party quality assurance services, and Applied Petroleum Software, Inc. (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.

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. Mr. Little is also a director of Intercontinental Bank Shares Corporation, a bank holding company.

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 Drilling Company, 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.

C. John Thompson has served as one of our directors since May 2001. Mr. Thompson has been a consultant since December 2001. 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.

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., TGC Industries, Inc. and EOTT Energy LLC.

William D. Hibbetts has served as one of our directors since June 1984 and as our Sr. Vice President, Chief Financial Officer and Secretary since December 2003. He previously served as our Sr. 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. 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.

Franklin C. West has served as our Executive Vice President and Chief Operating Officer since January 2002. Prior to joining Pioneer Drilling Company, 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 H. White has served as one of our directors since May 2000. Mr. White has been the President and Chief Executive Officer of WEDGE Group Incorporated since April 1997. WEDGE is a diversified firm with subsidiaries in engineering and construction, hotel, oil and gas services and real estate businesses. Mr. White served as Deputy Secretary of Energy and Chief Operating Officer of the United States Department of Energy from 1993 to 1995. Prior to his service with the Department of Energy, Mr. White practiced law and served on the management committee of the law firm of Susman Godfrey, L.L.P. From December 1995 to June 1998, Mr. White served as Chairman of the Democratic Party of Texas. He also served as an adjunct professor at the University of Texas School of Law. Mr. White currently serves on the board of BJ Services and numerous non-profit organizations, including Baylor College of Medicine.

Section 16(a) Beneficial Ownership Reporting Compliance

Section 16(a) of the Securities Exchange Act of 1934, as amended, requires our directors, executive officers and any persons beneficially owning more than 10% of our common stock to report their initial ownership of our common stock and any subsequent changes in that ownership to the SEC. Specific due dates for these reports have been established, and we are required to disclose in this annual report on Form 10-K/A any failure to file by these dates. All required filings for the 2003 fiscal year were made on a timely basis.

In making these disclosures, we relied solely on written statements of directors, executive officers and shareholders and copies of the reports that they have filed with the SEC.

Item 11. 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, 2003, 2002 and 2001 by our Chief Executive Officer and our four other most highly compensated executive officers (the "named executive officers").

	Annual Compensation
Name and Principal Position	Fiscal Year	Salary(1)		Bonus		Securities Underlying Options
Michael E. Little Director, Chairman and Chief Executive Officer	2003 2002 2001	$ $ $	164,340 162,440 66,052	$	— 78,843 —	— — —
Wm. Stacy Locke Director, President and Chief Financial Officer	2003 2002 2001	$ $ $	164,340 162,440 142,321	$	— 78,843 —	— — —
Franklin C. West Executive Vice President and Chief Operating Officer(2)	2003 2002 2001	$ $	185,500 41,885 —	$ $	50,000 50,000 —	— 450,000 —
William D. Hibbetts Director, Senior Vice President, Chief Accounting Officer and Secretary(3)	2003 2002 2001	$ $ $	117,854 108,840 24,231	$	— 27,210 —	— — 25,000
Donald G. Lacombe Senior Vice President-Marketing(4)	2003 2002 2001	$ $ $	120,000 112,703 34,485	$	— 19,047 —	— 50,000 25,000

(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. West's employment with our company began on January 1, 2002. Mr. West joined our company as Executive Vice President and Chief Operating Officer. Mr. West was paid $91,885 during fiscal year 2002, which amount included a $50,000 signing bonus. He was also issued options under our 1999 Stock Option Plan to purchase 450,000 shares of our common stock at an exercise price of $3.00 per share.
(3): Mr. Hibbetts' employment with our company began on December 7, 2000.
(4): Mr. Lacombe's employment with our company began on August 18, 2000.

Option Grants in Last Fiscal Year

No options were granted to the named executive officers during the fiscal year ended March 31, 2003.

Stock Option Exercises and 2003 Fiscal Year-End Option Values

The following table details the number and value of securities exercised during the year ended March 31, 2003 by the named executive officers and of securities underlying unexercised options held by the named executive officers at March 31, 2003.

				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
Name	Shares Acquired on Exercise	Value Realized		Exercisable	Unexercisable	Exercisable		Unexercisable
Michael E. Little	—		—	650,000	—	$	2,268,500		—
Wm. Stacy Locke	400,000	$	1,404,000	400,000	—	$	1,396,000		—
Franklin C. West	—		—	250,000	200,000	$	872,500	$	698,000
William D. Hibbetts	5,000	$	8,000	10,000	15,000	$	34,900	$	52,350
Donald G. Lacombe	—		—	26,667	48,333	$	93,068	$	168,682

(1): Based on the closing price of $3.49 per share for our common stock on the AMEX on March 31, 2003.

Equity Compensation Plan Information

The following table provides information on our equity compensation plans as of June 25, 2003. This table does not include shares that would be issuable under the 2003 Stock Incentive Plan if that plan is approved by our shareholders.

Plan Category	Number of securities to be issued upon exercise of outstanding options, warrants and rights	Weighted-average exercise price of outstanding options, warrants and rights		Number of securities remaining available for future issuance under equity compensation plans (excluding securities reflected in column (a))
Equity compensation plans approved by security holders	1,951,000	$	1.76	224,413
Equity compensation plans not approved by security holders	N/A		N/A	N/A
Total	1,951,000	$	1.76	224,413

Compensation Committee Interlocks and Insider Participation

During fiscal year 2003, the Compensation Committee consisted of C. John Thompson, James M. Tidwell and William H. White. In July 2002, Mr. White participated in our $10,000,000 convertible subordinated debenture financing to the extent described in the next paragraph.

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. We used approximately $6,000,000 to reduce a $12,000,000 credit facility. We used the balance of the proceeds 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 are convertible into 6,500,000 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 canceled. WEDGE funded $7,000,000 of the $10,000,000 on July 3, 2002 and $2,000,000 on July 29, 2002. William H. White, one of our directors and Compensation Committee members, and the then President of WEDGE, purchased the remaining $1,000,000 on July 29, 2002. We used $7,000,000 of the proceeds from the new debt to pay down other outstanding bank debt and $3,000,000 for the purchase of drilling equipment. The new debentures are subject to call provisions under which we may, at our option, prepay the new debentures after July 2004, at 105% of principal during 2004, 104% during 2005, 103% during 2006, and 100% during 2007 and thereafter.

Item 12. Security Ownership of Certain Beneficial Owners and Management

Please see the information appearing (1) under the heading "Equity Compensation Plan Information" in Item 5 of this report and (2) under the heading "Security Ownership of Certain Beneficial Owners and Management" in the definitive proxy statement for our 2003 Annual Meeting of Shareholders for the information this Item 12 requires.

Item 13. Certain Relationships and Related Transactions

Please see the information appearing under the heading "Certain Transactions" in the definitive proxy statement for our 2003 Annual Meeting of Shareholders for the information this Item 13 requires.

Item 14. Controls and Procedures

Within 90 days prior to the filing of this report, we carried out an evaluation, under the supervision and with the participation of management, including our Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of our disclosure controls and procedures pursuant to Exchange Act Rule 13a-15. Based upon that evaluation, our Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures were effective as of the date of that evaluation. Disclosure controls and procedures are controls and procedures that are designed to ensure that information required to be disclosed in our reports filed or submitted under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the Securities and Exchange Commission's rules and forms.

There have been no significant changes in our internal controls and in other factors that could significantly affect internal controls subsequent to the date we carried out this evaluation.

PART VI

Item 15. Exhibits, Financial Statement Schedules and Reports on Form 8-K

(a): (1) Financial Statements.

See Index to Consolidated Financial Statements on page 20.

(2): 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.

(3): Exhibits. The following exhibits are filed as part of this report:

Exhibit Number	Description
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 the 30^th of April 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 the 28^th of May, 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))
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*	—	Bylaws of Pioneer Drilling Company (Form 10-K for the year ended March 31, 2001 (File No. 1-8182, Exhibit 3.2)).
4.1*	—	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 4.10)).
4.2*	—	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)).
4.3*	—	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)).
4.4*	—	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)).
4.5*	—	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)).

4.6*	—	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)).
4.7*	—	Term Loan and Security Agreement dated December 23, 2002 by and between Pioneer Drilling Services, Ltd. and Merrill Lynch Capital, a division of Merrill Lynch Business Financial Services, Inc. (Form 8-K filed January 3, 2003 (File No. 1-8182, Exhibit 5.1)).
4.8*	—	Collateral Installment Note dated December 23, 2002 by and between Pioneer Drilling Services, Ltd. and Merrill Lynch Capital, a division of Merrill Lynch Business Financial Services, Inc. (Form 8-K filed January 3, 2003 (File No. 1-8182, Exhibit 5.2)).
4.9*	—	Consolidated Loan Agreement dated March 18, 2003 between Pioneer Drilling Services, Ltd., Pioneer Drilling Company and The Frost National Bank (Form 10-K for the year ended March 31, 2002 (File No. 1-8182, Exhibit 4.9)).
4.10*	—	Promissory Note dated March 18, 2003 between Pioneer Drilling Services, Ltd. and The Frost National Bank (Form 10-K for the year ended March 31, 2002 (File No. 1-8182, Exhibit 4.10)).
4.11*	—	Revolving Promissory Note dated March 18, 2003 between Pioneer Drilling Services, Ltd. and The Frost National Bank (Form 10-K for the year ended March 31, 2002 (File No. 1-8182, Exhibit 4.11)).
4.12*	—	Amendment No. 1 dated March 31, 2003 to the Term Loan and Security Agreement dated December 23, 2002 between Pioneer Drilling Services, Ltd. and Merrill Lynch Capital, a division of Merrill Lynch Business Financial Services, Inc. (Form 10-K for the year ended March 31, 2002 (File No. 1-8182, Exhibit 4.12)).
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 October 9, 2001 between Pioneer Drilling Company and WEDGE Energy Service, L.L.C. (See Section 1.3 of the Debenture Purchase Agreement referenced above as Exhibit 4.5)).
10.4+*	—	Executive Employment Agreement dated May 1, 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+*	—	Executive Employment Agreement dated November 16, 1998 between Pioneer Drilling Company and Michael E. Little (Form 10-K for the year ended March 31, 2001 (File No. 1-8182, Exhibit 10.3+)).
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 8^th 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*	—	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 March 31, 2003 (File No. 1-8182, Exhibit 4.2)).
21.1*	—	Subsidiaries of Pioneer Drilling Company (Form 10-K for the year ended March 31, 2002 (File No. 1-8182, Exhibit 21.1)).
23.1	—	Consent of KPMG LLP.
99.1	—	Certification by Pioneer Drilling Company's Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of Sarbanes-Oxley Act of 2002.
99.2	—	Certification by Pioneer Drilling Company's Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of Sarbanes-Oxley Act of 2002.

*

Incorporated by reference to the filing indicated.

+

Management contract or compensatory plan or arrangement.

(b): Reports on Form 8-K.

On January 3, 2003, we filed a current report on Form 8-K, dated December 23, 2002, to report our borrowing of $14.5 million from Merrill Lynch Capital. We did not file any other current reports on Form 8-K during the last quarter of the fiscal year covered by this report.

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

		PIONEER DRILLING COMPANY
June 22, 2004		By:	/s/ WM. STACY LOCKE Wm. Stacy Locke President and Chief Executive Officer