PIONEER DRILLING CO - 10-K Annual Report

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

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

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

The aggregate market value of the registrant's common stock held by non-affiliates of the registrant was $36,800,897 as of June 5, 2002.

As of June 5, 2002, there were 15,922,459 shares of common stock, par value $0.10 per share, of the registrant issued and outstanding.

Portions of the proxy statement related to the registrant's 2002 Annual Meeting of Shareholders are incorporated by reference into Part III of this report.

		Page
PART I
Items 1 and 2.	Business and Properties	1
Item 3.	Legal Proceedings	12
Item 4.	Submission of Matters to a Vote of Security Holders	12
PART II
Item 5.	Market for Registrant's Common Equity and Related Stockholder Matters	12
Item 6.	Selected Financial Data	14
Item 7.	Management's Discussion and Analysis of Financial Condition and Results of Operations	14
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk	21
Item 8.	Financial Statements and Supplementary Data	22
Item 9.	Change in and Disagreements with Accountants on Accounting and Financial Disclosure	41
PART III
Item 10.	Directors and Executive Officers of the Registrant	41
Item 11.	Executive Compensation	41
Item 12.	Security Ownership of Certain Beneficial Owners and Management	41
Item 13.	Certain Relationships and Related Transactions	41
PART IV
Item 14.	Exhibits, Financial Statement Schedules and Reports on Form 8-K	41

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.

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 three 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

As of June 5, 2002, our rig fleet consists of 22 drilling rigs, 15 of which are operating in South Texas and seven of which are operating in East Texas. During the fiscal year ended March 31, 2002, we added four rigs, including two newly constructed rigs (described in the following paragraph) and two refurbished rigs. In May 2002, we commissioned the building of two additional refurbished to like new rigs. We own all the rigs in our fleet except for one rig that we operate under a two year lease agreement expiring in February 2004. The lease agreement includes an option to acquire this rig.

In fiscal 2002, we acquired the principal components of the two newly constructed rigs from National Oilwell, Inc., a leading manufacturer of drilling rigs and other equipment used in oil and gas drilling and production operations. Both of these rigs are capable of drilling wells as deep as 18,000 feet. In addition to their deep-drilling capabilities, these rigs employ several technological advancements that have been developed in recent years, including alternating-current drive motors to power their hoisting systems. With these technological advancements, we believe these rigs provide us the following advantages over other rigs operating in our markets:

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 2002, 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 in 2002, 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.

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.

As of June 5, 2002, our rig fleet consists of 22 drilling rigs. We own all the rigs in our fleet except for one that we operate under a two year lease/purchase agreement expiring in February 2004.

In fiscal 2002, we placed in service two newly constructed rigs from National Oilwell, Inc., a leading manufacturer of drilling rigs and other equipment used in oil and gas drilling and production operations. Both of these rigs are capable of drilling wells as deep as 18,000 feet. In addition to their deep-drilling capabilities, these rigs employ several technological advancements that have been developed in recent years. These advancements include alternating-current ("AC") motors, which provide an electric braking mechanism that gives the hoisting system the capability of holding a full load in a stationary position and eliminates the need for the drilling personnel to operate an auxiliary brake. The AC technology also provides significantly greater control in the drilling process and improves the efficiency in "tripping" operations when the drill stem is being lowered into or raised from the borehole for various reasons, including cleaning the borehole, changing the drill bit or coming

out of the hole to install casing. The AC technology also requires a reduced number of diesel engines, which can generate fuel savings and reduce maintenance requirements. These new rigs also employ computerized "auto-driller" technology that increases the rate of penetration into the formation by more closely monitoring the total weight on the drill bit and automatically lowering the drill stem to maintain a constant pressure on the drill bit. These rigs also have features that, as compared to other rigs, reduce the time and expense associated with transporting the rig, installing it on location and removing it when drilling operations are complete. They also require less land clearing for installation and operation and are equipped with drain lines that permit them to operate without discharging cuttings or other drilling material into the environment.

With these technological advancements, we believe these rigs provide us the following advantages over other rigs operating in our markets:

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

	Years ended March 31,
	2002	2001	2000	1999	1998	1997
Average number of operational rigs for the period	18.0	10.5	6.6	6.0	6.0	4.0
Average utilization rate	82%	91%	66%	66%	86%	90%

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	16,000	South Texas	Electric	1000
5	Gardner-Denver 500M	10,000	South Texas	Mechanical	750
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	Emsco 500	10,000	East Texas	Mechanical	500
10	Skytop Brewster N46	12,000	South 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	South Texas	Mechanical	750
24	National 110-UE	18,000	Under Construction	Electric	1500
25	National 110-UE	18,000	Under Construction	Electric	1500

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. We have not experienced any substantial downtime as the result of repair or overhaul of our equipment in the past three years.

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.

During the year ended March 31, 2002, we drilled 165 wells, with 90% of our contract drilling revenue attributable to daywork contracts, 7% attributable to turnkey contracts and 3% attributable to footage contracts. During the year ended March 31, 2001, we drilled 101 wells, with 42% of our contract drilling revenue attributable to daywork contracts, 57% attributable to turnkey contracts and 1% attributable to footage contracts. As of March 31, 2002, we had 20 rigs of which 10 were operating under daywork contracts, three under turnkey contracts, two under footage contracts and five were not under contract. Due to the current reduced demand for drilling rigs, we have returned to bidding on turnkey contracts in an effort to improve profitability and rig utilization. Consequently, the trend away from turnkey contracts to daywork contracts we experienced during fiscal 2002 may not continue.

Our contract drilling customers include independent and major oil and gas exploration production companies. We completed contracts for 48 customers in fiscal 2002 compared to 58 customers in fiscal 2001 and 38 customers in fiscal 2000. During the fiscal year ended March 31, 2002, our three largest customers, Dominion Exploration & Production, Inc., Kerr-McGee Oil & Gas Onshore L.L.C. and Pogo Producing Company, accounted for 13.7%, 12.2% and 11.1%, 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.

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.

During late fiscal 2001, we entered into a number of term contracts with our customers ranging in length from six months to one year. The practical effect of these term contracts was to protect us for the duration of the contract from having the rig become idle and from unexpected declines in dayrates for our rigs. Conversely, our customers benefit from term contracts by the assured availability of a rig to meet their drilling schedule, and from contractual protection against exposure to rapid increases in dayrates. These term contracts are priced on a fixed dayrate basis which allow us to earn an acceptable rate of return on the capital we are employing. To the extent possible, we intend to continue entering into additional term contracts from time to time based on market conditions. Under current market conditions these term contracts are not being renewed at their expiration date. Most of our rigs are now being contracted on a well-by-well basis.

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:

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:

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.

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

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

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 coverages include 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 2001, of the cost of comparable used equipment to replace the insured property. The policy provides for a deductible on rigs of $50,000 per occurrence. Our third party liability insurance coverage is $26 million per occurrence and in the aggregate, with a deductible of $60,000 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 $3 million or $5 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.

We currently have approximately 410 employees. Approximately 67 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.

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.

Our operations are subject to stringent laws and regulations relating to containment, disposal and controlling the discharge of hazardous oilfield waste and other nonhazardous 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.

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:

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.

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 included in our results of operations for the fiscal year ended March 31, 2002.

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 Plantiffs seek damages not to exceed $7,500,000 for loss of income from the well. We deny responsibility for any alleged loss sustained by the working interest owners as we were working in accordance with our contract under the operator's direct control and supervision at the time of the alleged loss. In addition, we believe the contract obligates the operator to indemnify and defend us against the loss alleged in this suit. Accordingly, we are making a demand upon the contractor under the contract's indemnity and defense provision. Otherwise, we plan to vigorously defend against this claim.

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.

We did not submit any matter to a vote of our security holders during the fourth quarter of fiscal 2002.

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

As of June 5, 2002, 15,922,459 shares of our common stock were outstanding, held by approximately 626 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 closing prices per share as reported in the Pink

Sheets for the period through March 7, 2001 and the high and low sales prices per share on the American Stock Exchange since that date:

The last reported sales price for our common stock on the American Stock Exchange on June 5, 2002 was $4.70 per share. The Pink Sheets quotations reflect interdealer prices, without retail mark-up, markdown or commission and may not necessarily represent actual transactions.

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. See "Management's Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources" in Item 7 of this report.

On March 30, 2001, we issued and sold for cash a $9,000,000 principal amount, 4.86% subordinated debenture to WEDGE Energy Services, L.L.C. The debenture had a maturity date of March 29, 2002 and was subordinated to all our outstanding bank debt or debt incurred under our then current bank credit facilities or any extension or renewal of any of those facilities. If we had obtained shareholder approval of the conversion feature, the debenture would have become convertible at our option or at the option of WEDGE into 2,400,000 shares of our common stock, at a conversion price of $3.75 per share. We did not engage an underwriter and did not pay any commission to any third party in connection with that sale. We used the proceeds from that sale to partially fund our acquisition of the contract drilling assets of Mustang Drilling, Ltd. We sold the debenture to WEDGE without registration under the Securities Act in reliance on the exemption Section 4(2) of the Securities Act provides for transactions not involving any public offering. We repurchased this debenture on May 18, 2001. 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 an additional 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.

See "Management's Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources" in Item 7 of this report.

On May 31, 2001, San Patricio Corporation exercised an option to acquire 150,000 shares of our common stock at a price of $1.50 per share. We issued that option in connection with our acquisition of the contract land drilling operations of San Patricio in fiscal 1998. We issued that option, and the shares of common stock on exercise of that option, without registration under the Securities Act in reliance on the exemption Section 4(2) of the Securities Act provides for transactions not involving any public offering.

On October 9, 2001, we issued a 6.75% convertible subordinated debenture, Series A, in the principal amount of $18,000,000 to WEDGE for $18,000,000 in cash. The debenture is due and payable on October 9, 2006, and is subordinated to our outstanding bank debt. The debenture is convertible, at the option of the holder of the debenture, into 4,500,000 shares of our common stock, at a conversion price of $4.00 per share. We issued the debenture without registration under the Securities Act in reliance on the exemption Section 4(2) of the Securities Act provides for transactions not involving any public offering. We used approximately $9,000,000 of the proceeds from the sale of the debenture for the construction and refurbishment of two drilling rigs and approximately $6,000,000 of the proceeds to reduce a $12,000,000 credit facility with our primary bank lender to $6,000,000. We used the balance of the proceeds for drilling equipment and working capital requirements.

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.

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 the risks and uncertainties we have referred to under the heading "Cautionary Statement Concerning Forward-Looking Statements" following Items 1 and 2 of Part I of this report.

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. 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 $10.76 in December 1998 and the price of natural gas dropped to a low of $1.66 in February 1999. These conditions led to significant reductions in the overall level of domestic land drilling activity resulting in an historical low domestic land rig count of 393 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 899 rigs on December 26, 1997. Also in 1997, the average price of natural gas delivered at Henry Hub, Louisiana was approximately $2.48 per mmbtu and the average price of West Texas Intermediate crude was approximately $20.59 per barrel.

Oil and natural gas prices rose sharply in calendar year 2000 and through mid 2001. The average price of natural gas for 2000 was $4.32 per mmbtu and for the period from January 1, 2001 through May 31, 2001 was $5.70. The average price of West Texas Intermediate crude for 2000 was $30.38 per barrel and for the period from January 1, 2001 through May 31, 2001 was $28.46. The average prices of natural gas and crude oil for the fiscal year ended March 31, 2002 were $3.00 per mmbtu and $24.00 per barrel, respectively. Natural gas prices began falling in mid 2001 to a low of approximately $2.00 per mmbtu before returning to current levels of $3.25 to $3.75 per mmbtu. Oil prices are currently in the $24.00 to $26.00 per barrel range.

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 1,105 on May 31, 2001, representing an increase in the domestic land rig count of 181% since the low in April 1999 and of 23% since December 31, 1997. While market conditions improved in 2000 and into mid 2001, demand for contract land drilling services has declined since mid 2001 and into the Spring 2002, along with natural gas prices leading to a substantial reduction in the rates land drilling companies have been able to obtain for their services. The domestic land rig count was 731 as of May 24, 2002, a 34% decrease from May 31, 2001. While natural gas prices have firmed up in recent months, we exepect dayrates and rig utilization rates to remain depressed in our industry until demand for land drilling services begins to recover from current levels.

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 "Business and Properties—Drilling Contracts" in item 1 of Part I of this report 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 well. Contract drilling in progress represents revenues we have recognized in excess of amounts billed on contracts in progress. Individual wells 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 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 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 significantly from our original estimates.

Asset impairments—We assess the impairment of assets such as receivables and drilling equipment whenever events or circumstances indicate that the carrying value may not be recoverable. Factors which 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 accounting standards to write-down the drilling equipment to its fair market value.

Deferred taxes—We provide deferred taxes for the basis difference in our property and equipment between financial reporting and tax reporting purposes. 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 12 to 15 years, while federal income tax rules require that we depreciate drilling rigs 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.

Our cash and cash equivalents at March 31, 2002 were $5,383,045, compared to $2,492,934 at March 31, 2001. Our current ratio, which we calculate by dividing our current assets by our current liabilities, at March 31, 2002 was 0.98, compared to 0.35 at March 31, 2001. Our working capital deficit decreased to $301,273 at March 31, 2002 from $15,179,194 at March 31, 2001. The primary reasons for the improvement in our current ratio and the decrease in our working capital deficit were (1) the $6,000,000 reduction in borrowings from the $12,000,000 in outstanding borrowings as of March 30, 2001 relating to our acquisition of the contract drilling assets of Mustang Drilling, Ltd., (2) an increase of approximately $7,000,000 in cash and receivables at March 31, 2002 and (3) the reduction in accounts payable of approximately $800,000 relating to equipment purchases for a new rig. Our trade accounts receivable increased to $6,160,797 at March 31, 2002 from $2,777,167 at March 31, 2001, and contract drilling in progress increased to $3,120,252 at March 31, 2002 from $2,331,112 at March 31, 2001. The substantial increases in accounts receivable and contract drilling in progress were due to the additional drilling rigs in 2002 and the related increase in the number of drilling contracts at our fiscal year end.

Our cash flows from operating activities for the year ended March 31, 2001 were $11,044,889 compared to $8,433,850 for 2001 and $3,532,145 for 2000. Our cash flows from operating activities are affected by a number of factors. Some of the significant factors that affect our cash flows from operations are rig utilization rates, the types of contracts we are able to obtain and revenue rates we are able to obtain for our services.

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 was $11,500,000, consisting of a cash payment of $10,731,456 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 net liabilities and a deferred tax liability of $4,214,195 to working capital and property and equipment based on their relative fair values.

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 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 the assets based on their relative fair values.

Since March 31, 2001, the additions to our property and equipment were $27,597,265. Additions consisted of the following:

Our debt obligations in the form of notes payable increased by a net of $10,542,884 from March 31, 2001 to March 31, 2002. This increase principally resulted from our issuance of a new convertible subordinated debenture in the principal amount of $18,000,000 partially offset by our repayment of $7,457,116 of debt to our lenders. In addition, we repaid the $9,000,000 of subordinated debt, included on our March 31, 2001 balance sheet, on May 18, 2001 with a short-term bank borrowing that we subsequently repaid with the proceeds from our May 18, 2001 issuance and sale of 2,400,000 shares of common stock to WEDGE Energy Services, L.L.C., our largest shareholder, at a purchase price of $3.77 per share. Notes payable at March 31, 2002 includes a $6,000,000 bridge loan facility with our primary lender due September 29, 2002. Interest is payable monthly at prime (4.75% at March 31, 2002) plus one percent. We intend to either extend the maturity date of this bridge loan facility or to convert it to a term loan payable in monthly installments.

In August 2000, we obtained two bank loans of $9,000,000 and $3,000,000 each in connection with our acquisition of Pioneer Drilling Co. The $9,000,000 bank debt is payable in monthly principal payments of $107,143, based on a seven-year amortization, plus interest at prime (4.75% at March 31, 2002) plus one percent. The final maturity of this debt is August 11, 2003. The $3,000,000 bank debt is payable in 87 monthly installments, the first three installments being for interest only, with interest at prime (4.75% at March 31, 2002) plus one percent; the fourth through 86^th installments are in the amount of $50,585 each, including interest; and the final installment, due on November 15, 2007, will be in the amount of the remaining principal balance plus accrued interest. Our bank loans contain various covenants pertaining to leverage ratios, cash flow coverage ratios and capitalization or net worth ratios. Under these credit arrangements, we determine compliance with the ratios on an annual basis, except for the capitalization and net worth ratios, which we determine on a quarterly basis. As of March 31, 2002, we were in compliance with all covenants applicable to our outstanding debt.

On October 9, 2001, we issued a 6.75% five year $18,000,000 convertible subordinated debenture, Series A, to WEDGE. The debenture is convertible into 4,500,000 shares of our common stock at a

conversion price of $4.00 per share. We used approximately $9,000,000 of the proceeds for the construction and refurbishment of two drilling rigs and approximately $6,000,000 to reduce a $12,000,000 credit facility with our primary bank lender to $6,000,000. Our primary bank lender then released a $6,000,000 letter of credit that WEDGE had provided as additional collateral for our credit facility. The balance of the proceeds have been used for drilling equipment and working capital.

We have a $1,000,000 line of credit with our primary bank lender. Draws are limited to 75% of eligible accounts receivable. Therefore, if our eligible accounts receivable should fall below $1,333,334 our ability to draw under this line would be reduced. At March 31, 2002, there was no balance outstanding on this line and eligible accounts receivable were $4,253,132. In addition, our primary bank lender has issued on our behalf two letters of credit totaling $1,450,000 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 these letters of credit. We increased the deductibles on our workers' compensation insurance policies to better manage the overall cost of workers' compensation insurance. We feel our safety policies and procedures justify our assumption of additional risks with regard to workers' compensation insurance.

Our long-term debt and capital and operating lease obligations maturing each year subsequent to March 31, 2002 are as follows:

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

In February 2000, we completed a private placement of our common stock to WEDGE. WEDGE paid us an aggregate of $1,500,000 for 1,153,846 shares of common stock, or $1.30 per share. We used the proceeds from that sale for general corporate purposes and to better position our company for future growth. In May 2000, we completed a second private placement of our common stock to WEDGE. WEDGE paid us an aggregate of $8,000,000 for 3,678,161 shares of common stock, or $2.175 per share. We used the proceeds from that sale to partially fund the construction of the two new-build rigs and to partially fund the purchase of Pioneer Drilling Co. As we discussed above, in May 2001, we sold an additional 2,400,000 shares of our common stock to WEDGE for $9,048,000, or $3.77 per share.

In October 2000, the sole holder of our Series A preferred stock converted those shares into 800,000 shares of our common stock in accordance with the terms of the Series A preferred stock agreement. In August 2001, the holders of our Series B preferred stock converted those shares into

1,199,038 shares of our common stock in accordance with the terms of an agreement between us and the holder of the Series B preferred stock.

Subsequent to the end of fiscal 2002, we acquired 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. We accounted for the acquisition as a purchase and allocated the purchase price to the assets based on their relative fair values. We financed the acquisition of United Drilling's and U-D Holding's assets with a $7,000,000 loan with our primary bank lender due November 24, 2002. Interest on the loan is payable monthly at prime. The loan is collateralized by the assets that we purchased and a $7,000,000 letter of credit that WEDGE provided.

In addition to purchasing the rigs and related assets from United Drilling and U-D Holdings, we commissioned the building of two National 110-UE 18,000 foot capacity, premium quality SCR (electric) rigs. The first rig will be ready to commence operations by October 2002 and the second by January 2003. Each of these rigs will be similar to the new build rigs and refurbished rigs we added to our fleet during fiscal 2002. To finance the purchase of the two 18,000 foot capacity rigs and to refinance our primary bank lenders short term loan, we plan a private placement of debt or equity securities. In additions, we plan to continue adding rigs and/or purchase companies which fit our strategic objectives.

Our rig utilization rates for the years ended March 31, 2002, 2001and 2000 were 82%, 91% and 66%, respectively. In fiscal 2002, we completed 5,384 revenue days, as compared to 3,463 revenue days in fiscal 2001, an increase of 55%. This increase reflects the increased demand for drilling rigs we experienced in the first half of fiscal 2002 and the increase in our drilling rig fleet from 16 to 20 rigs by the end of fiscal 2002.

During the years ended March 31, 2002, 2001 and 2000, 7%, 57% and 77%, respectively, of our drilling revenues were derived from turnkey contracts, 3%, 1% and 1%, respectively, from footage contracts and 90%, 42% and 22%, respectively, from daywork contracts. Costs associated with the drilling of turnkey wells include items such as drilling fluids, casing, cementing, fuel and drill bits which are not provided under daywork contracts. Much more of these types of costs are reflected in revenues and drilling costs in our 2001 and 2000 fiscal years as compared to fiscal 2002. Because these costs are in both revenues and costs, our drilling margin percentage will be lower in years in which a greater percentage of our revenues are from turnkey contracts. Due to the current reduced demand for drilling rigs, we have returned to bidding on turnkey contracts in an effort to improve our profitability and rig utilization.

During fiscal 2002, our drilling margin increased to approximately $22,009,000 from $8,459,000 in fiscal 2001 and $2,575,000 in fiscal 2000. The increases in fiscal 2002 over fiscal 2001 and 2001 over 2000, principally resulted from the 55% and 117% increases in the number of revenue days we completed in fiscal 2002 and 2001, respectively, and an increase in drilling rates we charged under our drilling contracts. As a percentage of contract drilling revenue, our drilling margin was 32%, 17% and 13% in fiscal 2002, fiscal 2001 and fiscal 2000, respectively. The margins in the 2001 and 2000 fiscal years are affected by the additional costs associated with turnkey contracts as described in the previous paragraph. Consequently, the additional costs associated with turnkey contracts may negatively affect our margin percentage for future periods.

Contract drilling costs for the year ended March 31, 2002 include a charge of $500,000 related to the settlement of a lawsuit from 1998 involving an injury to a former employee and a $275,000 charge related to severance costs for a corporate officer. For more information about the lawsuit see "Legal Proceedings" in Item 3 of Part I of this report.

We market our rigs to a number of customers. In fiscal 2002, we drilled wells for 48 different customers, compared to 58 customers in fiscal 2001 and 38 customers in fiscal 2000. Twenty five of our customers in fiscal 2002 were customers for whom we had not drilled any wells in fiscal 2001. During the fiscal year ended March 31, 2002, our three largest customers accounted for 13.7%, 12.2% and 11.1%, respectively, 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%, respectively, of our total contract drilling revenue. None of those customers were customers of ours in fiscal 2000. In fiscal 2000, our largest customers accounted for 7.4%, 7.2% and 7.0%, respectively, of our total contract drilling revenue.

Our depreciation and amortization expense in fiscal 2002 increased to approximately $8,426,000 from $3,738,000 and $1,809,000 in fiscal years 2001 and 2000, respectively. The increase in fiscal 2002 resulted from a combination of increased depreciation expense due to the Pioneer Drilling Co. and Mustang Drilling, Ltd. acquisitions, the major refurbishment of four rigs in 2001 and the acquisition of four rigs in 2002.

Our general and administrative expenses increased to approximately $2,428,000 in fiscal 2002 from $1,117,000 in fiscal 2001 and $658,000 in fiscal 2000. The increase in fiscal 2002 resulted from increased payroll costs, legal and other professional fees and investor relations costs. The increase in fiscal 2001 resulted from increased payroll costs, expenses related to our acquisitions and our re-listing on the American Stock Exchange.

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.

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 July 2001, the Financial Accounting Standards Board issued SFAS No. 141, "Business Combinations" and SFAS No. 142, "Goodwill and Other Intangible Assets." SFAS No. 141 requires the use of the purchase method of accounting for all business combinations initiated after June 30, 2001. SFAS No. 141 also specifies criteria intangible assets acquired in a purchase method business combination must meet to be recognized and reported apart from goodwill. SFAS No. 142 provides that goodwill and intangible assets with indefinite useful lives no longer be amortized, but instead must be tested for impairment at least annually using a fair-value based approach. SFAS No. 142 also requires that intangible assets with definite useful lives be amortized over their respective estimated useful lives to their estimated residual values and reviewed for impairment in accordance with SFAS No. 121, "Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed Of." We are required to apply these new standards beginning April 1, 2002, except that for any business combinations initiated after June 30, 2001 the new standards were already effective. We do not expect the adoption of SFAS Nos. 141 and 142 to have a material effect on our financial position or results of operations.

In August 2001, the Financial Accounting Standards Board issued SFAS No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets". This Statement addresses financial accounting and reporting for the impairment or disposal of long-lived assets. This Statement supersedes SFAS No. 121, "Accounting for the Impairment of Long-Lived Assets to Be Disposed Of." However, it retains the fundamental provisions of Statement 121 for (1) recognition and measurement of the impairment of long-lived assets to be held and used and (2) measurement of long-lived assets to be disposed of by sale. We will be required to apply this standard beginning April 1, 2002. We do not expect the adoption of SFAS No. 144 to have a material effect on our financial position or results of operations.

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

We are subject to market risk exposure related to changes in interest rates on most of our outstanding debt. At March 31, 2002, we had outstanding debt of $15,516,000 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 of approximately $101,000 annually. We did not enter into these debt arrangements for trading purposes.

		Page
Independent Auditors' Report		23
Consolidated Balance Sheets as of March 31, 2002 and 2001		24
Consolidated Statements of Operations for the Years Ended March 31, 2002, 2001 and 2000		25
Consolidated Statements of Shareholders' Equity and Comprehensive Income for the Years Ended March 31, 2002, 2001 and 2000		26
Consolidated Statements of Cash Flows for the Years Ended March 31, 2002, 2001 and 2000		27
Notes to Consolidated Financial Statements		28

We have audited the accompanying consolidated balance sheets of Pioneer Drilling Company and subsidiaries as of March 31, 2002 and 2001 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, 2002. 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, 2002 and 2001, and the results of their operations and their cash flows for each of the years in the three-year period ended March 31, 2002, in conformity with accounting principles generally accepted in the United States of America.

PIONEER DRILLING COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

PIONEER DRILLING COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF SHAREHOLDERS' EQUITY AND COMPREHENSIVE INCOME

PIONEER DRILLING COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

PIONEER DRILLING COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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 the determination of depreciation and amortization expense.

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.

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 2000, we did not include the effect of preferred stock on loss per common share because it was antidilutive.

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. We have disclosed the pro forma effects of our adoption of SFAS No. 123 in Note 8.

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.

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

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.

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. During the fiscal year ended March 31, 2000, we increased the estimated useful lives of our drilling rigs to reflect our historical experience with regard to our drilling rigs. The change in estimated useful lives reduced our depreciation expense in fiscal 2000 by approximately $144,000 and our loss per common share, basic and diluted, by $0.02.

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 gain and losses on the sale of our property and equipment are recorded in drilling costs. During fiscal 2002 and 2001, we capitalized $328,285 and $55,896, 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.

For purposes of the statements of cash flows, we consider all highly liquid debt instruments purchased with 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, 2002 and 2001 were $4,435,000 and $2,405,000, respectively.

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. As of March 31, 2001, these securities had an aggregate cost of $171,527, a gross unrealized gain of $166,868 and a fair value of $338,395. We sold all of our investment securities in April 2002, realizing a gain of $203,887.

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.

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

In August 2001, the Financial Accounting Standards Board issued SFAS No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets". This Statement addresses financial accounting and

reporting for the impairment or disposal of long-lived assets. This Statement supersedes SFAS No. 121, "Accounting for the Impairment of Long-Lived Assets to Be Disposed Of." However, it retains the fundamental provisions of Statement 121 for (1) recognition and measurement of the impairment of long-lived assets to be held and used and (2) measurement of long-lived assets to be disposed of by sale. We will be required to apply this standard beginning April 1, 2002. We do not expect the adoption of SFAS No. 144 to have a material effect on our financial position or results of operations.

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

On September 29, 1999, we acquired the drilling operations of Howell Drilling, Inc., a San Antonio, Texas-based land drilling contractor. The acquisition included two drilling rigs, a Cabot 900 and a Cabot 750, drill pipe and drill collars, assorted spare drilling equipment, transportation equipment and office furniture and fixtures. We paid $2,513,000 for the Howell Drilling assets, including related professional fees, of which we financed $1,750,000 with a commercial loan. We accounted for the transaction as a purchase, and we have included the results of operations of the Howell Drilling assets in our statement of operations since the acquisition date. We allocated the purchase price to property and equipment based on its relative fair market values at the date of acquisition.

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 3. 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.

The following pro forma financial information gives effect to the Pioneer Drilling Co. and Mustang Drilling, Ltd. acquisitions as though they were effective as of the beginning of fiscal 2001. The information reflects our historical data and historical data from these acquired businesses for the twelve months ended March 31, 2001. The pro forma information may not be indicative of the results we would have achieved had we completed these acquisitions on April 1, 2000, or of the results that we

may achieve in the future. The pro forma information should be read in conjunction with the accompanying historical financial statements and the other notes to these financial statements.

	Pro Forma (Unaudited) Year Ended March 31,
	2001
Total revenues	$	71,362,826
Net earnings		2,544,362
Net earnings applicable to common shareholders		2,269,732
Earnings per common share—Basic		.17
Earnings per common share—Diluted		.15

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 will be accounted for as a purchase and the purchase price will be allocated to property and equipment based on its relative fair values at the date of acquisition. We financed the acquisition of United Drilling's and U-D Holding's assets with a $7,000,000 loan with our primary bank lender due November 24, 2002. Interest on the loan is payable monthly at prime. The loan is collateralized by the assets that we purchased and a letter of credit that WEDGE provided.

Year Ended March 31,
2003	$	1,836,860
2004		6,224,738
2005		559,038
2006		571,386
2007 and thereafter		18,474,448

On March 30, 2001, we issued a $9,000,000, 4.86% subordinated debenture to WEDGE Energy Services, L.L.C. (WEDGE). We repaid this debenture on May 18, 2001 with short-term bank debt that we subsequently repaid with the proceeds from a sale of common stock to WEDGE. See Note 7.

On October 9, 2001, we issued a 6.75% five year $18,000,000 convertible subordinated debenture, Series A, to WEDGE. The debenture is convertible into 4,500,000 shares of our common stock at a conversion price of $4.00 per share. We used approximately $9,000,000 of the proceeds to complete our second IRI 1700E rig and another rig which we accepted delivery of in October 2001. Approximately $6,000,000 was used to reduce a $12,000,000 credit facility provided by our bank lender. Our bank lender then released a $6,000,000 letter of credit that WEDGE had provided as additional collateral for our credit facility. The balance of the proceeds have been used for drilling equipment and working capital.

The notes payable at March 31, 2002 include a $6,000,000 bank credit facility due September 29, 2002. Interest is at prime (4.75% at March 31, 2002) plus 1% due monthly.

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 (4.75% at March 31, 2002) plus 1.0%. At March 31, 2002, we had no outstanding advances under this line of credit.

At March 31, 2002, 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 capitalization. The covenants also restrict the payment of dividends on common stock.

In addition, our primary bank lender has issued on our behalf two letters of credit totaling $2,100,000 as of March 31, 2002 (subsequently reduced to $1,450,000 in May 2002) 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. As a result, we do not anticipate the lender will be required to fund these letters of credit.

We are obligated under capital leases covering several trucks that expire at various dates through November 2007. At March 31, 2002 and 2001, the gross amount of transportation equipment and related amortization recorded under capital leases were as follows:

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, 2002, 2001 and 2000 was $208,150, $20,000 and $0 respectively

Future lease obligations and minimum capital lease payments as of March 31, 2002 were as follows:

In fiscal years 2002, 2001 and 2000, 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:

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:

In assessing the realizability of 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. The 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.

The following table presents a reconciliation of the numerators and denominators of the basic EPS and diluted EPS comparisons as required by SFAS 128:

In February 2000, we sold in a private placement, 1,153,846 shares of common stock to WEDGE for $1,500,000, or $1.30 per share. In May 2000, we completed a second private placement of 3,678,161 shares of common stock to WEDGE for $8,000,000, or $2.175 per share.

In August 2000, we issued 341,576 shares of 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 common stock at $1.00 per share.

In accordance with the terms of our Series B Preferred Stock Agreement, the conversion price was revised from $3.25 per share to $2.50 per share as of January 20, 2001, the third anniversary of the date we entered into the Preferred Stock Agreement. This revision was based on the average trading price of our common stock for the 30 trading days preceding that anniversary 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 common stock at $2.50 per share.

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 an additional 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.

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 and warrants for the purchase of 27,500 shares of common stock at prices ranging from $.0375 to $1.00 per share during the year ended March 31, 2002, 51,500 shares of common stock at prices ranging from $0.15 to $2.50 per share during the year ended March 31, 2001 and 5,000 shares of common stock at $0.375 per share during the year ended March 31, 2000.

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 and warrants at March 31, 2002, 2001 and 2000:

At March 31, 2002, the weighted average exercise price of our outstanding options was $1.47 per share and the weighted average exercise price of our exercisable options was $0.92 per share.

We have adopted the disclosure-only provisions of SFAS No. 123, "Accounting for Stock-Based Compensation." Accordingly, we have not recognized any compensation expense attributable to our stock option plan. 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,
	2002		2001		2000
Net earnings (loss)—as reported	$	6,318,285	$	2,702,789	$	(79,618	)
Net earnings (loss)—pro forma		5,736,027		2,343,565		(232,664	)
Net earnings (loss) per share—as reported—basic		0.41		0.22		(0.06	)
Net earnings (loss) per share—as reported—diluted		0.35		0.19		(0.06	)
Net earnings (loss) per share—pro forma—basic		0.38		0.19		(0.09	)
Net earnings (loss) per share—pro forma—diluted		0.32		0.17		(0.09	)
Weighted-average fair value of options, granted during the year		3.11		2.29		0.47

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 90%, 117% and 72% and weighted average risk-free interest rates of 4.5%, 5.4% and 6.0% for grants in 2002, 2001 and 2000, 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.

During October 1999, we adopted a 401(k) retirement plan for our eligible employees. We may contribute, on a discretionary basis, a percentage of an eligible employee's annual contribution, which we determine annually. Our contributions for fiscal 2002, 2001 and 2000 were approximately $153,000, $101,000 and $18,000, respectively.

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, 2002, our three largest customers accounted for 13.7%, 12.2% and 11.1%, respectively, 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%, respectively, of our total contract drilling revenue. None of those customers were customers of ours in fiscal 2000. In fiscal 2000, our three largest customers accounted for 7.4%, 7.2% and 7% of our total contract drilling revenue.

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

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.

On May 17, 2002, the working interest owners in a well that we drilled in May 2000 filed a petition, in the 37^th Judicial District Court in Bexar County, Texas, against us, the operator and several of the operator's vendors working at the well location at the time of the alleged loss. The Plantiffs seek damages not to exceed $7,500,000 for loss of income from the well. We deny responsibility for any alleged loss sustained by the working interest owners as we were working in accordance with our contract under the operator's direct control and supervision at the time of the alleged loss. In addition, we believe the contract obligates the operator to indemnify and defend us against the loss alleged in this suit. Accordingly, we are making a demand upon the contractor and contract's indemnity and defense provision. Otherwise, we plan to vigorously defend against this claim. Accordingly, as of March 31, 2002, no provision has been recorded in connection with this matter.

Subsequent to March 31, 2002, we commissioned the building of two National 110-UE 1500HP diesel electric rigs from IDM Equipment, Ltd for approximately $6,000,000 each. We anticipate that the first rig will be available by October 2002 and the second by January 2003.

We have increased the deductibles on our workers' compensation insurance policies to better manage the overall cost of workers' compensation insurance.

The following table summarizes quarterly financial data for our fiscal years ended March 31, 2002 and 2001 (in thousands, except per share data):

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

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 2002 Annual Meeting of Shareholders. We intend to file that definitive proxy statement with the SEC by July 29, 2002.

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 2002 Annual Meeting of Shareholders for the information this Item 10 requires.

Please see the information appearing under the heading "Executives and Executive Compensation" in the definitive proxy statement for our 2002 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 under the heading "Security Ownership of Certain Beneficial Owners and Management" in the definitive proxy statement for our 2002 Annual Meeting of Shareholders for the information this Item 12 requires.

Please see the information appearing under the heading "Certain Transactions" in the definitive proxy statement for our 2002 Annual Meeting of Shareholders for the information this Item 13 requires.

Item 14. Exhibits, Financial Statement Schedules and Reports on Form 8-K

Exhibit Number				Description
2.1*		—		Asset Purchase Agreement dated September 29, 1999 between Howell Drilling, Inc. and Pioneer Drilling Company (Form 10-K for the year ended March 31, 2001 (File No. 2-70145, Exhibit 2.1).

2.2*	—	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).
2.3*	—	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).
2.4	—	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.
2.5	—	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.
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*	—	Loan Agreement dated August 11, 2000 between Pioneer Drilling Company and The Frost National Bank. (Form 10-K for the year ended March 31, 2001 (File No. 2-70145, Exhibit 4.1).
4.2*	—	First Amendment to Loan Agreement dated December 31, 2000 between South Texas Drilling Co., Ltd. and The Frost National Bank. (Form 10-K for the year ended March 31, 2001 (File No. 2-70145, Exhibit 4.2).
4.3*	—	Loan Agreement dated March 30, 2001 between Pioneer Drilling Co., Ltd. and The Frost National Bank. (Form 10-K for the year ended March 31, 2001 (File No. 2-70145, Exhibit 4.3).
4.4*	—	Promissory Note dated June 18, 1997 between Pioneer Drilling Company and San Patricio Corporation. (Form 10-K for the year ended March 31, 2001 (File No. 2-70145, Exhibit 4.4).
4.5 *	—	Debenture Purchase Agreement dated March 30, 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 4.5).
4.6*	—	Debenture Agreement dated March 30, 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 4.6).
4.7*	—	Subordination Agreement dated March 30, 2001 between Pioneer Drilling Company and American Bank, N.A. regarding loan of $3,000,000. (Form 10-K for the year ended March 31, 2001 (File No. 2-70145, Exhibit 4.7).

4.8*	—	Subordination Agreement dated March 30, 2001 between Pioneer Drilling Company and The Frost National Bank regarding loans of $1,000,000 and $9,000,000. (Form 10-K for the year ended March 31, 2001 (File No. 2-70145, Exhibit 4.8).
4.9*	—	Subordination Agreement dated March 30, 2001 between Pioneer Drilling Company and The Frost National Bank regarding loans of $12,000,000. (Form 10-K for the year ended March 31, 2001 (File No. 2-70145, Exhibit 4.9).
4.10*	—	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).
4.11	—	First Amendment to Loan Agreement dated March 19, 2002 between Pioneer Drilling Service, Ltd. and The Frost National Bank.
4.12*	—	Debenture Purchase Agreement dated October 9, 2001 between Pioneer Drilling Company and WEDGE Energy Services, L.L.C. (Form 8-K dated October 22, 2001 (File No. 2-70145, Exhibit 4.2)
4.13*	—	Debenture Agreement dated October 9, 2001 between Pioneer Drilling Company and WEDGE Energy Services, L.L.C. (Form 8-K dated October 22, 2001 (File No. 2-70145, Exhibit 4.1)
4.14	—	Loan Agreement dated May 24, 2002 between Pioneer Drilling Services, Ltd. and The Frost National Bank.
4.15	—	Promissory Note dated March 29, 2002 between Pioneer Drilling Services, Ltd. And The Frost National Bank.
		Pioneer Drilling Company and some of its subsidiaries are parties to debt instruments under which the total amount of securities authorized does not exceed 10% of the total assets of Pioneer Drilling Company and its subsidiaries on a consolidated basis. Pursuant to paragraph 4(iii)(A) of Item 601(b) of Regulation S-K, Pioneer Drilling Company agrees to furnish a copy of those instruments to the SEC on request.
9.1*	—	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).
9.2*	—	Voting Agreement dated May 11, 2000 between Wm. Stacey 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).
9.3	—	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)

10.1+*	—	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+).
10.2+*	—	First Amendment to Executive Employment Agreement dated November 16, 1998 between Pioneer Drilling Company and Wm. Stacy Locke. (Form 10-K for the year ended March 31, 2001 (File No. 2-70145, Exhibit 10.2+).
10.3+*	—	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+).
10.4+*	—	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+).
10.5+*	—	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+).
10.6+*	—	Non-Statutory Stock Option Agreement dated June 18, 1997 between Pioneer Drilling Company and San Patricio Corporation. (Form 10-K for the year ended March 31, 2001 (File No. 2-70145, Exhibit 10.6+).
10.7+*	—	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+).
10.8*	—	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).
10.9*	—	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).
10.10*	—	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).
10.11*	—	Registration Rights Agreement dated May 18, 2001 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 10.11).
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.
21.1	—	Subsidiaries of Pioneer Drilling Company

We did not file any current reports on Form 8-K during the last quarter of the fiscal year covered by this report.

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.

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.

TEXAS (State or other jurisdiction of incorporation or organization)		74-2088619 (I.R.S. Employer Identification Number)
9310 Broadway, Bldg. I San Antonio, Texas (Address of principal executive offices)		78217 (Zip Code)

		Low		High
Fiscal Year Ended March 31, 2002:
	First Quarter	$	4.2000	6.3000
	Second Quarter		3.1000	5.3500
	Third Quarter		2.9000	4.0000
	Fourth Quarter		3.1000	4.1000
Fiscal Year Ended March 31, 2001:
	First Quarter	$	1.3120	2.5310
	Second Quarter		1.9680	3.1250
	Third Quarter		1.7700	2.8750
	Fourth Quarter		2.3750	5.1880

	Years Ended March 31,
	2002		2001		2000			1999			1998
	(In thousands, except per share amounts)
Total operating revenues	$	68,242	$	50,205	$	19,483		$	12,908		$	17,091
Earnings before taxes, depreciation and amortization and other income (expense)		19,699		7,612		2,050			725			2,236
Earnings (loss) before income taxes		9,737		3,838		(65	)		(1,278	)		894
Preferred dividends		93		275		304			304			109
Net earnings (loss) applicable to common stockholders		6,225		2,428		(384	)		(1,612	)		722
Earnings (loss) per common share—basic		0.41		0.22		(0.06	)		(0.27	)		0.13
Earnings (loss) per common share—diluted		0.35		0.19		(0.06	)		(0.27	)		0.11
Long-term debt, excluding current installments		25,830		9,728		267			2,354			2,697
Shareholders' equity		33,343		17,827		6,783			5,322			6,816
Total assets		83,450		56,493		15,670			10,007			12,502
Capital expenditures		27,597		41,628		5,069			856			3,561

• Drilling rigs	$	18,893,502
• Other drilling equipment		7,837,782
• Transportation equipment		686,812
• Other		179,169

	$	27,597,265

	Long term debt		Capital Leases		Operating Leases
2003	$	1,836,860	$	109,129	$	355,296
2004		6,224,738		116,995		312,296
2005		559,038		122,026		55,296
2006		571,386		41,376		53,297
2007		18,406,960		8,594		—
After 2007		67,488		—		—

	$	27,666,470	$	398,120	$	776,185

			March 31,
			2002			2001
ASSETS
Current assets:
	Cash and cash equivalents		$	5,383,045		$	2,492,934
	Securities available for sale			337,309			338,395
	Receivables:
		Trade		6,160,797			2,777,167
		Contract drilling in progress		3,120,252			2,331,112
		Employees and officers		—			300
	Federal income tax receivable			880,068			—
	Prepaid expenses			634,747			312,276

Total current assets				16,516,218			8,252,184

Property and equipment, at cost:
	Drilling rigs and equipment			77,149,043			57,527,976
	Transportation, office, land and other			3,203,979			2,781,750

				80,353,022			60,309,726
Less accumulated depreciation and amortization				13,621,396			12,115,268

Net property and equipment				66,731,626			48,194,458
Other assets				201,914			46,322

Total assets			$	83,449,758		$	56,492,964

LIABILITIES AND SHAREHOLDERS' EQUITY
Current liabilities:
	Notes payable		$	6,329,925		$	3,030,000
	Subordinated debenture			—			9,000,000
	Current installments of long-term debt			1,836,860			1,695,839
	Current installments of capital lease obligations			109,129			83,307
	Accounts payable			6,507,169			7,606,982
	Federal income tax			—			50,198
	Current deferred income taxes			56,366			56,750
	Accrued expenses:
		Payroll and payroll taxes		792,805			736,195
		Dividends payable		—			766,581
		Other		1,185,237			405,526

Total current liabilities				16,817,491			23,431,378
Long-term debt, less current installments				25,829,610			9,727,672
Capital lease obligations, less current installments				288,991			327,949
Deferred income taxes				7,170,661			5,179,203

Total liabilities				50,106,753			38,666,202

Shareholders' equity:
	Preferred stock, Series B, 8%, cumulative, convertible, $16.25 redemption and liquidation value; 184,615 shares authorized; issued and outstanding at March 31, 2001			—			2,999,994
	Common stock $.10 par value; 100,000,000 shares authorized; 15,922,459 shares and 12,145,921 shares issued and outstanding at March 31, 2002 and March 31, 2001, respectively			1,592,245			1,214,592
	Additional paid-in capital			38,783,731			26,869,916
	Accumulated deficit			(7,142,387	)		(13,367,858	)
	Accumulated other comprehensive income-unrealized gain on securities available for sale			109,416			110,118

Total shareholders' equity				33,343,005			17,826,762

Total liabilities and shareholders' equity			$	83,449,758		$	56,492,964

		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, 1999		6,100,784	584,615		$	610,078	$	3,799,994		$	16,324,031	$	(15,412,400	)		—		$	5,321,703
Comprehensive income:
	Net Loss	—	—			—		—			—		(79,618	)		—			(79,618	)
	Net unrealized change in securites available for sale	—	—			—		—			—		—			328,478			328,478

Total comprehensive income		—	—			—		—			—		—			—			248,860

Issuance of common stock for:
	Sale	1,153,846	—			115,385		—			1,384,615		—			—			1,500,000
	Exercise of options	5,000	—			500		—			1,375		—			—			1,875
	Employee compensation	15,054	—			1,505		—			13,548		—			—			15,053
Preferred stock dividend		—	—			—		—			—		(303,999	)		—			(303,999	)

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	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	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

	March 31,
	2002			2001
Convertible subordinated debenture due October 2006 at 6.75%	$	18,000,000		$	—
Note payable, secured by drilling equipment, due in monthly payments of $107,143 plus interest at prime (4.75% at March 31, 2002) plus 1.00%, due August 2003		6,963,603			8,250,000
Note payable, secured by drilling equipment, land and improvements, due in monthly payments of $50,585, including interest at prime (4.75% at March 31, 2002) plus 1%, due November 2007		2,483,411			2,895,511
Note payable to bank, secured by land and improvements, due in monthly payments of $1,900 including interest at the bank's prime rate (5.75% at March 31, 2002) plus 0.5%, due in September 2005		52,249			68,283
Note payable to Small Business Administration, secured by second lien on land and improvements, due in monthly payments of $912 including interest at 7.41%, due November 2015		92,201			96,227
Notes payable, secured by vehicles, due in monthly payments of $2,150 including interest, due through December 2004		50,006			28,490
Note payable to seller, secured by drilling equipment, due in monthly installments of $5,000 plus interest at 10%, due June 2002		25,000			85,000

		27,666,470			11,423,511
Less current installments		(1,836,860	)		(1,695,839	)

	$	25,829,610		$	9,727,672

	2002		2001
Transportation	$	519,363	$	443,901
Less accumulated amortization		136,435		42,605

	$	382,928	$	401,296

Year Ended March 31,	Operating Leases		Capital Leases
2003	$	355,296	$	142,126
2004		312,296		142,126
2005		55,296		135,291
2006		53,298		30,599
2007 and thereafter		—		8,901

Total minimum lease payments	$	776,186	$	459,043

Less amounts representing interest (at rates ranging from 5.8% to 9.5%)				(60,923	)

Present value of net minimum capital lease payments				398,120
Less current installments of capital lease obligations				(109,129	)

Capital lease obligations, excluding current installments			$	288,991

		March 31,
		2002		2001
Deferred tax asset—
	Workers compensation accruals	$	32,795	$	—

Deferred tax liabilities:
	Property and equipment, principally due to differences in depreciation		7,203,456		5,179,203
	Unrealized gain on securities available for sale		56,366		56,750

	Total deferred tax liabilities		7,259,822		5,235,953

	Net deferred tax liabilities	$	7,227,027	$	5,235,953

			2002				2001				2000
			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		2,177,500		$	0.375-4.60	1,759,000		$	0.15-1.50	1,694,000		$	0.15-1.50
		Granted	585,000		$	3.00-5.15	515,000		$	2.25-4.60	720,000		$	0.625-1.50
		Exercised	(177,500	)	$	0.375-1.50	(51,500	)	$	0.15-2.50	(5,000	)	$	0.375
		Canceled	(265,000	)	$	2.25	(45,000	)	$	0.375-1.50	(650,000	)	$	0.75

Balance Outstanding
	End of year		2,320,000		$	0.375-5.15	2,177,500		$	0.375-4.60	1,759,000		$	0.15-1.50

Options Exercisable
	End of year		1,734,000				1,172,500				1,175,500

		First Quarter		Second Quarter		Third Quarter		Fourth Quarter			Total
2002
Revenues		$	18,367	$	17,702	$	16,539	$	15,634		$	68,242
Earnings from operations			5,292		4,232		1,293		456			11,273
Net earnings			3,174		2,612		551		(19	)		6,318
Net earnings applicable to common shareholders			3,114		2,579		551		(19	)		6,225
Earnings per share:
	Basic		0.23		0.17		0.03		(0.00	)		0.41
	Diluted		0.20		0.15		0.03		(0.00	)		0.35
2001
Revenues		$	8,868	$	12,215	$	14,682	$	14,440		$	50,205
Earnings from operations			684		491		665		2,034			3,874
Net earnings			649		383		258		1,413			2,703
Net earnings applicable to common shareholders			573		307		196		1,352			2,428
Earnings per share
	Basic		0.06		0.03		0.02		0.11			0.22
	Diluted		0.05		0.03		0.02		0.09			0.19

		PIONEER DRILLING COMPANY
June 10, 2002		By:		/s/ MICHAEL E. LITTLE Michael E. Little Chairman of the Board and Chief Executive Officer

Signature	Title	Date

/s/ MICHAEL E. LITTLE Michael E. Little	Chairman, Chief Executive Officer and Director (Principal Executive Officer)	June 10, 2002
/s/ WM. STACY LOCKE Wm. Stacy Locke	President, Chief Financial Officer and Director (Principal Financial Officer)	June 10, 2002
/s/ WILLIAM D. HIBBETTS William D. Hibbetts	Vice President, Chief Accounting Officer, Secretary and Director (Principal Accounting Officer)	June 10, 2002
/s/ C. JOHN THOMPSON C. John Thompson	Director	June 10, 2002
/s/ JAMES M. TIDWELL James M. Tidwell	Director	June 10, 2002
/s/ WILLIAM H. WHITE William H. White	Director	June 10, 2002
/s/ DEAN A. BURKHARDT Dean A. Burkhardt	Director	June 10, 2002