UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D. C. 20549

FORM 10-K

(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: 2-70145

PIONEER DRILLING COMPANY

(Exact name of registrant as specified in its charter)

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

9310 Broadway, Bldg. I San Antonio, Texas		78217
(Address of principal executive offices)		(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 (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 May 16, 2003, there were 21,710,792 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

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 entitled to be paid by our customer only after we have performed the terms of the drilling contract in full. Turnkey contracts generally afford an opportunity to earn a higher return than would normally be available on daywork contracts if the contract can be completed successfully without complications.

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	101

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 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. During the fiscal year ended March 31, 2003, our three largest customers, Gulf Coast Energy Associates, Apache Corporation and Suemaur Exploration & Production, L.L.C. 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 fiscal 2002. In fiscal 2002, our three largest customers accounted for 13.7%, 12.2% and 11.1%, respectively, of our total contract drilling revenue. Two of those customers were customers of ours in fiscal 2001. In fiscal 2001, our largest customers accounted for 13.6%, 8.8% and 6.3%, respectively, of our total contract drilling revenue.

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

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 (a)	Weighted-average exercise price of outstanding options, warrants and rights (b)	Number of securities remaining available for future issuance under equity compensation plans (excluding securities reflected in column (a)) (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)
Total operating revenues	$	80,221		$	68,700	$	50,416	$	19,483		$	12,908
Earnings (loss) from operations	(4,905		)	11,273		3,874		241			(1,005		)
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.

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. 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.

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. Revenues and costs during a reporting period could be affected for contracts in progress at the end of that reporting period which have not been completed before our financial statements for that period are released. Turnkey contract revenues we had accrued in “Contract Drilling in Progress” at March 31, 2003 were approximately $3,940,000. All of our turnkey contracts in progress at March 31, 2003 were completed prior to the release of these financial statements.

We estimate an allowance for doubtful accounts based on the creditworthiness of our customers as well as general economic conditions. Consequently, an adverse change in those factors could affect our estimate of our allowance for doubtful accounts.

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.

Our financial statements include accruals for costs incurred under the $100,000 self-insurance portion of our health insurance and the $250,000 deductible under our workers’ compensation insurance. These accruals of approximately $525,000 at March 31, 2003 are based on information provided by the insurance companies and our historical experience with these types of insurance costs.

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.

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 increase in accounts payable was primarily the result of an increased level of turnkey contracts during the quarter ended March 31, 2003 compared to the quarter ended March 31, 2002 and the increase in the number of rigs in our rig fleet. 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.

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.

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.

Our long-term debt, capital lease and operating lease obligations in the years subsequent to March 31, 2003 are as follows:

	Long term debt		Capital Leases		Operating Leases
2004	$	2,671,269	$	140,717	$	358,008
2005	6,468,524		148,283		58,008
2006	2,076,690		78,172		56,010
2007	2,077,054		33,570		2,712
2008	34,910,777		—		—
After 2009	61,472		—		—
	$	48,265,786	$	400,742	$	474,738

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;

• our incurrence of any additional indebtedness in excess of $2,000,000 not already allowed by the loan agreements; and

• any payment of cash dividends on our common stock.

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 drilling margins, which we compute by subtracting contract drilling costs from contract drilling revenues, margin percentages, which we compute by dividing the drilling margin by contract drilling revenues, and drilling margin per revenue day, which we compute by dividing the drilling margin by revenue days, for each of the three years ended March 31, 2003 were:

	2003			2002			2001
Contract drilling revenues	$	80,183,486		$	68,627,486		$	50,344,909
Contract drilling costs	70,823,310			46,145,364			41,687,893
Drilling margin	$	9,360,176		$	22,482,122		$	8,657,016
Drilling margin percent	12		%	33		%	17		%
Drilling margin per revenue day	$	1,458		$	4,176		$	2,498

The drilling margin decrease in 2003 from 2002 principally resulted from decreases in rig revenue rates we charged under our drilling contracts while the increase in 2002 from 2001 principally resulted from increased revenue rates and the 55% increase in revenue days, due to more rigs. The additional costs associated with turnkey contracts accounts for the substantial increase in

our drilling costs in 2003. Consequently, these additional costs negatively effect our margin percentage in years in which turnkey contracts make up a higher percentage of our revenues.

Drilling margin per revenue day is a measure of profitability from drilling operations, before taxes, depreciation, general and administrative expenses and other income (expense), for each day a rig is earning revenue. Rigs earn revenue while moving, drilling, waiting on standby or cleaning up at the end of a contract. Drilling margin per revenue day is a good index to compare our drilling operations from year to year as well as against competitors in our peer group. Drilling margin per revenue day was down substantially in 2003 compared to 2002 due to the significantly lower dayrate environment we experienced in 2003.

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 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

Independent Auditors’ Report

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

INDEPENDENT AUDITORS’ REPORT

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 auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material 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 accounting principles generally accepted in the United States of America.

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
Revenues:
Contract drilling	$	80,183,486		$	68,627,486		$	50,344,909
Other	37,614			72,096			71,559

Total operating revenues	80,221,100			68,699,582			50,416,468

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	(4,904,987		)	11,272,862			3,874,315

Other income (expense):
Interest expense	(2,698,529		)	(1,616,984		)	(888,863		)
Interest income	94,235			80,932			316,025
Gain on sale of securities	203,887			—			536,486
Total other income (expense)	(2,400,407		)	(1,536,052		)	(36,352		)

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 securites 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 securites 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 significant 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 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. 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, including losses, which we recognize in the period in which we determine the revisions.

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 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

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 these consolidated financial statements.

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. We accounted for this acquisition as a purchase, 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 assets of Mustang Drilling, Ltd., a land drilling contractor based in Henderson, Texas. These assets included four land drilling rigs and associated 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. We accounted for this acquisition as a purchase, and we have included the results of operations of these assets in our statement of operations since the date of acquisition. We allocated the purchase price to property and equipment based on its 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. The acquisition was accounted for as a purchase and the purchase price was allocated to property and equipment based on its 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 pluse 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

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.

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. This lease includes an option to acquire the rig 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 financial statements. The components of our deferred income tax liabilities were as follows:

	March 31,
	2003		2002

Deferred tax assets:
Worker 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. Our utilization of the net operating loss carryforwards may be limited under section 382 of the Internal Revenue Code, which is related to changes in ownership.

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		$	0.375-4.60
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.

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, results of operations or cash flow from operations.

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 10, 11, 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. We intend to file that definitive proxy statement with the SEC by July 29, 2003.

Item 10. Directors and Executive Officers of the Registrant

Please see the information appearing under the headings “Proposal No. 1—Election of Directors” and “Executives and Executive Compensation” in the definitive proxy statement for our 2003 Annual Meeting of Shareholders for the information this Item 10 requires.

Item 11. Executive Compensation

Please see the information appearing under the heading “Executives and Executive Compensation” in the definitive proxy statement for our 2003 Annual Meeting of Shareholders for the information this Item 11 requires.

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 IV

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. 2-70145, 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. 2-70145, 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. 2-70145, 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. 2-70145, 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. 2-70145, Exhibit 3.1)).

3.2*	-	Bylaws of Pioneer Drilling Company (Form 10-K for the year ended March 31, 2001 (File No. 2-70145, 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. 2-70145, 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. 2-70145, 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. 2-70145, 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. 2-70145, 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. 2-70145, 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. 2-70145, 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. 2-70145, 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. 2-70145, 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.

4.10	-	Promissory Note dated March 18, 2003 between Pioneer Drilling Services, Ltd. and The Frost National Bank.

4.11	-	Revolving Promissory Note dated March 18, 2003 between Pioneer Drilling Services, Ltd. and The Frost National Bank.

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.

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. 2-70145, 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. 2-70145, 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. 2-70145, 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. 2-70145, 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. 2-70145, 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. 2-70145, 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. 2-70145, 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. 2-70145, 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. 2-70145, 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. 2-70145, 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. 2-70145, 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. 2-70145, 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. 2-70145, 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. 2-70145, Exhibit 4.2)).

21.1	-	Subsidiaries of Pioneer Drilling Company

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 3, 2003	By:	/s/ Michael E. Little
		Michael E. Little
		Chairman of the Board and Chief Executive Officer

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.

Signature	Title	Date

/s/ Michael E. Little
Michael E. Little	Chairman, Chief Executive Officer and Director (Principal Executive Officer)	June 3, 2003

/s/ Wm. Stacy Locke
Wm. Stacy Locke	President, Chief Financial Officer and Director (Principal Financial Officer)	June 3, 2003

/s/ William D. Hibbetts
William D. Hibbetts	Senior Vice President, Chief Accounting Officer, Secretary and Director (Principal Accounting Officer)	June 3, 2003

/s/ C. John Thompson
C. John Thompson	Director	June 3, 2003

/s/ James M. Tidwell
James M. Tidwell	Director	June 3, 2003

/s/ William H. White
William H. White	Director	June 3, 2003

/s/ Dean A. Burkhardt
Dean A. Burkhardt	Director	June 3, 2003

CERTIFICATIONS

I, Michael E. Little, chief executive officer of Pioneer Drilling Company, certify that:

1. I have reviewed this annual report on Form 10-K of Pioneer Drilling Company;

2. Based on my knowledge, this annual report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this annual report;

3. Based on my knowledge, the financial statements, and other financial information included in this annual report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this annual report;

4. The registrant’s other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have:

a) designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this annual report is being prepared;

b) evaluated the effectiveness of the registrant’s disclosure controls and procedures as of a date within 90 days prior to the filing date of this annual report (the “Evaluation Date”); and

c) presented in this annual report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date;

5. The registrant’s other certifying officers and I have disclosed, based on our most recent evaluation, to the registrant’s auditors and the audit committee of registrant’s board of directors (or persons performing the equivalent functions):

a) all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant’s ability to record, process, summarize and report financial data and have identified for the registrant’s auditors any material weaknesses in internal controls; and

b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal controls; and

6. The registrant’s other certifying officers and I have indicated in this annual report whether or not there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses.

June 3, 2003

	/s/ Michael E. Little
	Michael E. Little
	Chief Executive Officer

I, Wm. Stacy Locke, president and chief financial officer of Pioneer Drilling Company, certify that:

1. I have reviewed this annual report on Form 10-K of Pioneer Drilling Company;

b) evaluated the effectiveness of the registrant’s disclosure controls and procedures as of a date within 90 days prior to the filing date of this annual report (the “Evaluation Date”); and

c) presented in this annual report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date;

b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal controls; and

June 3, 2003

	/s/ Wm. Stacy Locke
	Wm. Stacy Locke
	President and Chief Financial Officer