UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, D. C. 20549

FORM 10-K

(Mark one)	ý	ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
		For the fiscal year ended March 31, 2004

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

Commission File Number: 1-8182

PIONEER DRILLING COMPANY

(Exact name of registrant as specified in its charter)

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

9310 Broadway, Bldg. I San Antonio, Texas		78217
(Address of principal executive offices)		(Zip Code)

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

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

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

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

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

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

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

The aggregate market value of the registrant’s voting and nonvoting common equity held by non-affiliates of the registrant as of the last business day of the registrant’s most recently completed second fiscal quarter (September 30, 2003) was $23,354,178, based on the last sales price of the registrant’s common stock reported on the American Stock Exchange on that date.

As of June 25, 2004, there were 27,300,126 shares of common stock, par value $0.10 per share, of the registrant issued and outstanding.

DOCUMENTS INCORPORATED BY REFERENCE

Portions of the proxy statement related to the registrant’s 2004 Annual Meeting of Shareholders are incorporated by reference into Part III of this report.

TABLE OF CONTENTS

PART I

Items 1 and 2.	Business and Properties
Item 3.	Legal Proceedings
Item 4.	Submission of Matters to a Vote of Security Holders

PART II

Item 5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
Item 6.	Selected Financial Data
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk
Item 8.	Financial Statements and Supplementary Data
Item 9.	Changes in and Disagreements With Accountants on Accounting and Financial Disclosure
Item 9A.	Controls and Procedures

PART III

Item 10.	Directors and Executive Officers of the Registrant
Item 11.	Executive Compensation
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stock holder Matters
Item 13.	Certain Relationships and Related Transactions
Item 14.	Principal Accountant Fees and Services

PART IV

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

PART I

Statements we make in this Annual Report on Form 10-K that 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 and Risk Factors’’ following Items 1 and 2 of Part I of this report.

Items 1 and 2. Business and Properties

General

Pioneer Drilling Company provides contract land drilling services to independent and major oil and gas exploration and production companies. In addition to our drilling rigs, we provide the drilling crews and most of the ancillary equipment needed to operate our drilling rigs. We have focused our operations in the natural gas production regions of South Texas, East Texas and North 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 five fiscal years, we have significantly expanded our fleet of drilling rigs through acquisitions and the construction of new rigs and the refurbishment of older rigs we acquired. The following table summarizes these acquisitions:

Date	Acquisition	Market	Number of Rigs Acquired

September 1999	Howell Drilling, Inc. — Asset Purchase	South Texas	2
August 2000	Pioneer Drilling Co. — Stock Purchase	South Texas	4
March 2001	Mustang Drilling, Ltd. — Asset Purchase	East Texas	4
May 2002	United Drilling Company — Asset Purchase	South Texas	2
August 2003	Texas Interstate Drilling Company, L. P. — Asset Purchase	North Texas	2
March 2004	Sawyer Drilling & Service, Inc. — Asset Purchase	East Texas	7
March 2004	SEDCO Drilling Co., Ltd. — Asset Purchase	North Texas	1

As of June 28, 2004, our rig fleet consists of 36 operating drilling rigs, 15 of which are operating in South Texas, 17 of which are operating in East Texas and four of which are operating in North Texas. During our fiscal year ended March 31, 2002, we added four rigs, consisting of two newly constructed rigs and two refurbished rigs, increasing our rig fleet to a total of 20 rigs at March 31, 2002. During our fiscal year ended March 31, 2003, we added two additional refurbished rigs and two rigs we acquired from United Drilling Company, increasing our rig fleet to a total of 24 rigs at March 31, 2003. During our fiscal year ended March 31, 2004, we added two refurbished rigs, acquired two rigs from Texas Interstate Drilling Company, L.P., acquired seven rigs from Sawyer Drilling & Service, Inc. and acquired one rig from SEDCO Drilling Co., Ltd. (which we named Rig 5 in place of our old Rig 5, which was retired and the components of which were moved to our inventory of spare equipment). In December 2003, we acquired the one rig we had previously been leasing under an operating lease since August 2000. As a result, we now own all 36 of the operating rigs in our fleet.

We conduct our operations primarily in South, East and North Texas. During fiscal 2004, substantially all the wells we drilled for our customers were drilled in search of natural gas. Natural gas reserves are typically found in deep 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. We intend to continue making additions to our drilling fleet, primarily through prudent acquisitions of businesses or selected drilling rig assets. 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. Since 1996, however, there has been significant consolidation within the industry. We believe continued consolidation in the industry will generate more stability in dayrates, even during industry downturns. However,

although consolidation in the industry is continuing, the industry is still highly fragmented and remains very competitive. For a discussion of market conditions in our industry, see “Management’s Discussion and Analysis of Financial Condition and Results of Operations – Market Conditions in Our Industry” in Item 7 of Part II of this report.

Drilling Equipment

General

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

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

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

The rotating equipment from top to bottom consists of a swivel, the kelly 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 triangular, square or hexagonal opening in a device called the kelly bushing. The kelly bushing, in turn, fits into a part of the rotary table called the master bushing. As the master bushing rotates, the kelly bushing also rotates, turning the kelly, which rotates the drill pipe and thus the drill bit. Drilling fluid is pumped through the kelly on its way to the bottom. The rotary table, equipped with its master bushing and kelly bushing, supplies the necessary torque to turn the drill stem. The drill pipe and drill collars are both steel tubes through which drilling fluid can be pumped. Drill pipe, sometimes called drill string, comes in 30-foot sections, or joints, with threaded sections on each end. Drill collars are heavier than drill pipe and are also threaded on the ends. Collars are used on the bottom of the drill stem to apply weight to the drilling bit. At the end of the drill stem is the bit, which chews up the formation rock and dislodges it so that drilling fluid can circulate the fragmented material back up to the surface where the circulating system filters it out of the fluid.

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

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

Our Fleet of Drilling Rigs

As of June 28, 2004, our rig fleet consists of 36 drilling rigs. We own all the rigs in our fleet. The following table sets forth information regarding utilization for our fleet of drilling rigs:

	Years ended March 31,
	2004		2003		2002		2001		2000		1999
Average number of rigs for the period	27.3		22.3		18.0		10.5		6.6		6.0
Average utilization rate	88	%	79	%	82	%	91	%	66	%	66	%

The following table sets forth information regarding our drilling fleet:

Rig Number	Rig Design	Approximate Drilling Depth Capability (feet)	Current Location	Type	Horse Power

1	Cabot 750E	9,500	South Texas	Electric	750
2	Cabot 750E	9,500	South Texas	Electric	750
3	National 110 UE	18,000	South Texas	Electric	1500
4	RMI 1000 E	15,000	South Texas	Electric	1000
5	Brewster N-46	12,000	North Texas	Mechanical	1000
6	Brewster DH-4610	13,000	East Texas	Mechanical	750
7	National 110 UE	18,000	South Texas	Electric	1500
8	National 110 UE	18,000	East Texas	Electric	1500
9	Gardner-denver 500	11,000	East Texas	Mechanical	700
10	Brewster N-46	12,000	East Texas	Mechanical	1000
11	Brewster N-46	12,000	South Texas	Mechanical	1000
12	IRI Cabot 900	12,500	South Texas	Mechanical	900
14	Brewster N-46	12,000	South Texas	Mechanical	1000
15	Cabot 750	9,500	South Texas	Mechanical	750
16	Cabot 750	9,500	South Texas	Mechanical	750
17	Ideco 725	12,000	East Texas	Mechanical	750
18	Brewster N-75	12,000	East Texas	Mechanical	1000
19	Brewster N-75	12,000	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 725	12,000	East Texas	Mechanical	750
23	Ideco 725	12,000	North Texas	Mechanical	750
24	National 110 UE	18,000	South Texas	Electric	1500
25	National 110 UE	18,000	East Texas	Electric	1500
26	Oilwell 840 E	18,000	South Texas	Electric	1500
27	IRI Cabot 1200 M	13,500	South Texas	Mechanical	1300
28	Oilwell 760 E	15,000	South Texas	Electric	1000
29	Brewster N-46	12,000	North Texas	Mechanical	1000
30	Mid Cont U36A	11,000	North Texas	Mechanical	750
31	Brewster N-7	11,500	East Texas	Mechanical	750
32	Brewster N-75	13,500	East Texas	Mechanical	1000
33	Brewster N-95	13,500	East Texas	Mechanical	1200
34	All-Rig 900	12,000	East Texas	Mechanical	900
35	RMI 1000	13,500	East Texas	Mechanical	1000
36	Brewster N-7	11,500	East Texas	Mechanical	750
37	Brewster N-95	13,500	East Texas	Mechanical	1200

As of June 28, 2004, we owned a fleet of 52 trucks and related transportation equipment that we use to transport our drilling rigs to and from drilling sites. By owning our own trucks, we reduce the cost of rig moves and reduce downtime between rig moves.

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

Drilling Contracts

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

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. The 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 an agreed fee.

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

	Year Ended March 31,
	2004	2003	2002
Daywork	205	119	150
Turnkey	92	78	9
Footage	13	5	6
Total number of wells	310	202	165

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

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

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

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

Customers and Marketing

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

Customer	Total Contract Drilling Revenue Percentage
Fiscal 2004
Chinn Exploration	11	%
Dale Operating Company	6	%
Medicine Bow Energy Corporation	5	%

Fiscal 2003
Gulf Coast Energy Associates	11	%
Apache Corporation	7	%
Suemaur Exploration & Production, L.L.C.	5	%

Fiscal 2002
Dominion Exploration & Production, Inc.	14	%
Kerr-McGee Oil & Gas Onshore, L.L.C.	12	%
Pogo Producing Company	11	%

We primarily market our drilling rigs through employee marketing representatives. These marketing representatives use personal contacts and industry periodicals and publications to determine which operators are planning to drill oil and gas wells in the near future in our South, East and North 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 in which we operate. Our rigs are typically contracted on a well-by-well basis.

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

Competition

We encounter substantial competition from other drilling contractors. Our primary market areas of South, East and North 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. Our principal competitors are Grey Wolf, Inc., Helmerich & Payne, Inc. and Patterson-UTI Energy, Inc. We believe pricing and rig availability are the primary factors our potential customers consider in determining which drilling contractor to select. In addition, we believe the following factors are also important:

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

• the mobility and efficiency of the rigs;

• the quality of service and experience of the rig crews;

• the safety records of the rigs;

• the offering of ancillary services; and

• the ability to provide drilling equipment adaptable to, and personnel familiar with, new technologies and drilling techniques.

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

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

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

• better withstand industry downturns;

• compete more effectively on the basis of price and technology;

• better retain skilled rig personnel; and

• build new rigs or acquire and refurbish existing rigs so as to be able to place rigs into service more quickly than us in periods of high drilling demand.

Raw Materials

The materials and supplies we use in our drilling operations include fuels to operate our drilling equipment, drilling mud, drill pipe, drill collars, drill bits and cement. We do not rely on a single source of supply for any of these items. While we are not currently experiencing any shortages, from time to time there have been shortages of drilling equipment and supplies during periods of high demand. Shortages could result in increased prices for drilling equipment or supplies that we may be unable to pass on to customers. In addition, during periods of shortages, the delivery times for equipment and supplies can be substantially longer. Any significant delays in our obtaining drilling equipment or supplies could limit drilling operations and jeopardize our relations with customers. In addition, shortages of drilling equipment or supplies could delay and adversely affect our ability to obtain new contracts for our rigs, which could have a material adverse effect on our financial condition and results of operations.

Operating Risks and Insurance

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

• blowouts;

• fires and explosions;

• loss of well control;

• collapse of the borehole;

• lost or stuck drill strings; and

• damage or loss from natural disasters.

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

• suspension of drilling operations;

• damage to, or destruction of, our property and equipment and that of others;

• personal injury and loss of life;

• damage to producing or potentially productive oil and gas formations through which we drill; and

• environmental damage.

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

Our current insurance coverage includes property insurance on our rigs, drilling equipment and real property. Our insurance coverage for property damage to our rigs and to our drilling equipment is based on our estimate, as of October 2003, of the cost of comparable used equipment to replace the insured property. The policy provides for a deductible on rigs of $50,000 or $100,000 (depending on the rig) per occurrence. Our third-party liability insurance coverage is $26 million per occurrence and in the aggregate, with a deductible of $110,000 per occurrence. We believe that we are adequately insured for public liability and property damage to others with respect to our operations. However, such insurance may not be sufficient to protect us against liability for all consequences of well disasters, extensive fire damage or damage to the environment.

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

Employees

We currently have approximately 900 employees. Approximately 123 of these employees are salaried administrative or supervisory employees. The rest of our employees are hourly employees who operate or maintain our drilling rigs and rig-hauling trucks. The number of hourly employees fluctuates depending on the number of drilling projects we are engaged in at any particular time. None of our employment arrangements are subject to collective bargaining arrangements.

Our operations require the services of employees having the technical training and experience necessary to obtain the proper operational results. As a result, our operations depend, to a considerable extent, on the continuing availability of such personnel. Although we have not encountered material difficulty in hiring and retaining qualified rig crews, shortages of qualified personnel are occurring in our industry. If we should suffer any material loss of personnel to competitors or be unable to employ additional or replacement personnel with the requisite level of training and experience to adequately operate our equipment, our operations could be materially and adversely affected. While we believe our wage rates are competitive and our relationships with our employees are satisfactory, a significant increase in the wages paid by other employers could result in a reduction in our workforce, increases in wage rates, or both. The occurrence of either of these events for a significant period of time could have a material and adverse effect on our financial condition and results of operations.

Facilities

We own our headquarters building in San Antonio, Texas. We also own a 15-acre division office, rig storage and maintenance yard in Corpus Christi, Texas and own a 4-acre trucking department office, storage and maintenance yard in Kilgore, Texas. We 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 also lease a 43-acre division office and storage yard in Decatur, Texas, at a cost of $800 per month, pursuant to a lease extending through September 2006, and a trucking department office, storage and maintenance yard in Alice, Texas at a cost of $4,500 per month, pursuant to a lease extending through July 2006. We believe these facilities are adequate to serve our current and anticipated needs.

Governmental Regulation

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

Environmental laws and regulations are complex and subject to frequent change. In some cases, they can impose liability for the entire cost of cleanup on any responsible party without regard to negligence or fault and can impose liability on us for the conduct of others or conditions others have caused, or for our acts that complied with all applicable requirements when we performed them. We may also be exposed to environmental or other liabilities originating from businesses and assets that we purchased from others. Compliance with applicable environmental laws and regulations has not, to date, materially affected our capital expenditures, earnings or competitive position, although compliance measures have added to our costs of operating drilling equipment in some instances. We do not expect to incur material capital expenditures in our next fiscal year in order to comply with current environment control regulations. However, our compliance with amended, new or more stringent requirements, stricter interpretations of existing requirements or the future discovery of contamination may require us to make material expenditures or subject us to liabilities that we currently do not anticipate.

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

Available Information

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

CAUTIONARY STATEMENT CONCERNING FORWARD-LOOKING STATEMENTS AND RISK FACTORS

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. These forward-looking statements speak only as of the date on which they are first made, which in the case of forward-looking statements made in this report is the date of this report. Sometimes we will specifically describe a statement as being a forward-looking statement and refer to this cautionary statement.

In addition, various statements that 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 5 – “Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities,” 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 unduly rely on them. We have based these forward-looking statements on our current expectations and assumptions about future events. While our management considers these expectations and assumptions to be reasonable, they are inherently subject to significant business, economic, competitive, regulatory and other risks, contingencies and uncertainties, most of which are difficult to predict and many of which are beyond our control. These risks, contingencies and uncertainties relate to, among other matters, the following:

• general economic and business conditions and industry trends;

• the continued strength of the contract land drilling industry in the geographic areas where we operate;

• decisions about onshore exploration and development projects to be made by oil and gas companies;

• the highly competitive nature of our business;

• our future financial performance, including availability, terms and deployment of capital;

• the continued availability of qualified personnel; and

• changes in, or our failure or inability to comply with, governmental regulations, including those relating to the environment.

We believe the items we have outlined above are important factors that could cause our actual results to differ materially from those expressed in a forward-looking statement made in this report or elsewhere by us or on our behalf. We have discussed many of these factors in more detail elsewhere in this report. These factors are not necessarily all the important factors that could affect us. Unpredictable or unknown factors we have not discussed in this report could also have material adverse effects on actual results of matters that are the subject of our forward-looking statements. We do not intend to update our description of important factors each time a potential important factor arises. We advise our security holders that they should (1) be aware that important factors not referred to above could affect the accuracy of our forward-looking statements and (2) use caution and common sense when considering our forward-looking statements. Also, please read the risk factors set forth below.

Risks Relating to the Oil and Gas Industry

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

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

• our revenues, cash flows and profitability;

• the fair market value of our rig fleet;

• our ability to maintain or increase our borrowing capacity;

• our ability to obtain additional capital to finance our business and make acquisitions, and the cost of that capital; and

• our ability to retain skilled rig personnel whom we would need in the event of an upturn in the demand for our services.

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

• weather conditions in the United States and elsewhere;

• economic conditions in the United States and elsewhere;

• actions by OPEC, the Organization of Petroleum Exporting Countries;

• political instability in the Middle East and other major oil and gas producing regions;

• governmental regulations, both domestic and foreign;

• domestic and foreign tax policy;

• the pace adopted by foreign governments for the exploration, development and production of their national reserves;

• the price of foreign imports of oil and gas;

• the cost of exploring for, producing and delivering oil and gas;

• the discovery rate of new oil and gas reserves;

• available pipeline and other oil and gas transportation capacity;

• the ability of oil and gas companies to raise capital; and

• the overall supply and demand for oil and gas.

Risks Relating to Our Business

We have a history of losses.

We have a history of losses. We incurred net losses of $1.8 million, $5.1 million, and $0.4 million in the fiscal years ended March 31, 2004, 2003 and 2000, respectively. Our profitability in the future will depend on many factors, but largely on utilization rates and dayrates for our drilling rigs. Our current utilization rates and dayrates may decline and we may experience losses in the future.

Our acquisition strategy involves various risks.

As a key component of our business strategy, we have pursued and intend to continue to pursue acquisitions of complementary assets and businesses. Certain risks are inherent in an acquisition strategy, such as increasing leverage and debt service requirements and combining disparate company cultures and facilities, which could adversely affect our operating results. The success of any completed acquisition will depend in part on our ability to integrate effectively the acquired business into our operations. The process of integrating an acquired business may involve unforeseen difficulties and may require a disproportionate amount of management attention and financial and other resources. Possible future acquisitions may be for purchase prices significantly higher than those we paid for recent acquisitions. We may be unable to continue to identify additional suitable acquisition opportunities, negotiate acceptable terms, obtain financing for acquisitions on satisfactory terms or successfully acquire identified targets. Our failure to achieve consolidation savings, to incorporate the acquired businesses and assets into our existing operations successfully or to minimize any unforeseen operational difficulties could have a material adverse effect on our financial condition and results of operations.

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

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

The drilling contracts we compete for are usually awarded on the basis of competitive bids. We believe pricing and rig availability are the primary factors our potential customers consider in determining which drilling contractor to select. In addition, we believe the following factors are also important:

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

• the mobility and efficiency of the rigs;

• the quality of service and experience of the rig crews;

• the safety records of the rigs;

• the offering of ancillary services; and

• the ability to provide drilling equipment adaptable to, and personnel familiar with, new technologies and drilling techniques.

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

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

We face competition from many competitors with greater resources.

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

• better withstand industry downturns;

• compete more effectively on the basis of price and technology;

• retain skilled rig personnel; and

• build new rigs or acquire and refurbish existing rigs so as to be able to place rigs into service more quickly than us in periods of high drilling demand.

Unexpected cost overruns on our turnkey drilling jobs and our footage contracts could adversely affect us.

We have historically derived a significant portion of our revenues from turnkey drilling contracts and we expect that they will represent a significant component of our future revenues. The occurrence of uninsured or under-insured losses or operating cost overruns on our turnkey jobs could have a material adverse effect on our financial position and results of operations. Under a typical turnkey drilling contract, we agree to drill a well for our customer to a specified depth and under specified conditions for a fixed price. We provide technical expertise and engineering services, as well as most of the equipment and drilling supplies required to drill the well. We often subcontract for related services, such as the provision of casing crews, cementing and well logging. Under typical turnkey drilling arrangements, we do not receive progress payments and are paid by our customer only after we have performed the terms of the drilling contract in full. For these reasons, the risk to us under a turnkey drilling contract is substantially greater than for a well drilled on a daywork basis, because we must assume most of the risks associated with drilling operations that the operator generally assumes under a daywork contract, including the 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. Similar to our turnkey contracts, under a footage contract we assume most of the risks associated with drilling operations that the operator generally assumes under a daywork contract. Although we attempt to obtain insurance coverage to reduce certain of the risks inherent in our turnkey and footage drilling operations, adequate coverage may be unavailable in the future and we might have to bear the full cost of such risks, which could have an adverse effect on our financial condition and results of operation.

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

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

• blowouts;

• fires and explosions;

• loss of well control;

• collapse of the borehole;

• lost or stuck drill strings; and

• damage or loss from natural disasters.

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

• suspension of drilling operations;

• damage to, or destruction of, our property and equipment and that of others;

• personal injury and loss of life;

• damage to producing or potentially productive oil and gas formations through which we drill; and

• environmental damage.

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

Our operations are subject to various laws and governmental regulations that may adversely affect our future operations.

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

• environmental quality;

• pollution control;

• remediation of contamination;

• preservation of natural resources; and

• worker safety.

Our operations are subject to stringent laws and regulations relating to containment, disposal and controlling the discharge of hazardous oilfield waste and other non-hazardous waste material into the environment, requiring removal and cleanup under certain circumstances, or otherwise relating to the protection of the environment. In addition, our operations are often conducted in or near ecologically sensitive areas, such as wetlands, which are subject to special protective measures and which may expose us to additional operating costs and liabilities for accidental discharges of oil, gas, drilling fluids or contaminated water or for noncompliance with other aspects of applicable laws. We are also subject to the requirements of 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.

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

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

From time to time there have been shortages of drilling equipment and supplies during periods of high demand which we believe could reoccur. Shortages could result in increased prices for drilling equipment or supplies that we may be unable to pass on to customers. In addition, during periods of shortages, the delivery times for equipment and supplies can be substantially longer. Any

significant delays in our obtaining drilling equipment or supplies could limit drilling operations and jeopardize our relations with customers. In addition, shortages of drilling equipment or supplies could delay and adversely affect our ability to obtain new contracts for our rigs, which could have a material adverse effect on our financial condition and results of operations.

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

Risk Relating to Our Capitalization and Corporate Documents

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

As of June 18, 2004, our largest shareholder, WEDGE Energy Services, L.L.C. (“WEDGE”), beneficially owned 40.24% of our outstanding common stock, and together with our other largest shareholders and our officers and directors as a group beneficially owned a total of 68.73% of our outstanding common stock. For each shareholder or group of shareholders, beneficial ownership includes shares of our common stock issuable on conversion of our convertible subordinated debentures and on exercise of outstanding stock options held by that shareholder or group of shareholders. The following table shows, as of June 18, 2004, the beneficial ownership of these persons:

Shareholder	Shares	Percentage

WEDGE (1)	13,508,864	40.2	%

Chesapeake Energy Corporation (“Chesapeake”)	5,333,333	19.5	%

T.L.L. Temple Foundation and Temple Interests, L.P. (collectively, “Temple”)	1,999,038	7.3	%

Officers and directors as a group	2,857,142	10.1	%

(1) The number of shares and percentage shown for WEDGE reflect 6,267,857 shares that WEDGE currently has the right to acquire on conversion of the $27,000,000 aggregate principal amount of our 6.75% convertible debentures that WEDGE current holds. The percentages shown for the other stockholders have not been adjusted to reflect the possible conversion of those debentures.

In some circumstances, if WEDGE were to act alone or in concert with a small number of these or other shareholders, they would be able to exercise control over our affairs, including the election of our entire board of directors and, subject to the applicable provisions of the Texas Business Corporation Act, the disposition of any matter submitted to a vote of our shareholders. Wedge currently has the right to nominate three persons for election to our board of directors, which as of the date of this annual report consists of seven members. The interests of Wedge and these other persons with respect to matters potentially or actually involving or affecting us, such as future acquisitions, financings and other corporate opportunities and attempts to acquire us, may conflict with the interests of our other shareholders.

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

Our common stock is traded on the American Stock Exchange. During the period from January 1, 2003 through May 31, 2004, the average daily trading volume of our common stock as reported by the American Stock Exchange was 17,986 shares. Even if we achieve a wider dissemination of our common stock, a more active trading market in our common stock may not develop. As a result, relatively small trades may have a significant impact on the price of our common stock and, therefore, may contribute to the price volatility of our common stock. As a result, our common stock may be subject to greater price volatility than the stock market as a whole.

The market price of our common stock has been, and may continue to be, volatile. For example, during our 2004 fiscal year, the trading price of our common stock ranged from $3.30 to $7.35 per share.

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

Under our existing dividend policy, we do not pay dividends on our common stock.

We have not paid or declared any dividends on our common stock and currently intend to retain any 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 imposed by the Texas Business Corporation Act and other applicable laws and by our credit facilities. Our debt arrangements include provisions that generally prohibit us from paying dividends on our capital stock, including our common stock.

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

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

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

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

• provisions regulating the ability of our shareholders to bring matters for action at annual meetings of our shareholders;

• limitations on the ability of our shareholders to call a special meeting and act by written consent;

• provisions dividing our board of directors into three classes elected for staggered terms; and

• the authorization given to our board of directors to issue and set the terms of preferred stock.

Item 3. Legal Proceedings

Due to the nature of our business, we are, from time to time, involved in routine litigation or subject to disputes or claims related to our business activities, including workers’ compensation claims and employment-related disputes. In the opinion of our management, none of the pending litigation, disputes or claims against us will have a material adverse effect on our financial condition or results of operations.

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

We did not submit any matter to a vote of our security holders during the fourth quarter of fiscal 2004.

PART II

Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities

As of June 25, 2004, 27,300,126 shares of our common stock were outstanding, held by approximately 700 shareholders of record. The number of record holders does not necessarily bear any relationship to the number of beneficial owners of our common stock.

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

	Low		High
Fiscal Year Ended March 31, 2004:
First Quarter	$	3.57	$	5.24
Second Quarter	3.65		4.99
Third Quarter	3.30		5.20
Fourth Quarter	4.75		7.35

Fiscal Year Ended March 31, 2003:
First Quarter	$	4.00	$	5.05
Second Quarter	2.85		4.20
Third Quarter	2.86		3.85
Fourth Quarter	3.10		3.64

The last reported sales price for our common stock on the American Stock Exchange on June 25, 2004 was $7.45 per share.

We have not paid or declared any dividends on our common stock and currently intend to retain earnings to fund our working capital needs and growth opportunities. Any future dividends will be at the discretion of our board of directors after taking into account various factors it deems relevant, including our financial condition and performance, cash needs, income tax consequences and the restrictions Texas and other applicable laws and our credit facilities then impose. Our debt arrangements include provisions that generally prohibit us from paying dividends, other than dividends on our preferred stock. We currently have no preferred stock outstanding.

Equity Compensation Plan Information

The following table provides information on our equity compensation plans as of March 31, 2004:

Plan category	Number of securities to be issued upon exercise of outstanding options, warrants and rights (a)	Weighted-average exercise price per share of outstanding options, warrants and rights (b)		Number of securities remaining available for future issuance under equity compensation plans (excluding securities reflected in column (a)) (c)
Equity compensation plans approved by security holders	2,056,666	$	3.24	2,406,413

Equity compensation plans not approved by security holders	—	—		—

Total	2,056,666	$	3.24	2,406,413

Recent Sales of Unregistered Securities

On March 31, 2003, we sold 5,333,333 shares of our common stock to Chesapeake Energy Corporation for $20,000,000 ($3.75 per share), before related offering expenses including $600,000 in commissions paid to Jefferies & Company, Inc. In connection with that sale, we granted Chesapeake Energy a preemptive right to acquire equity securities that we may issue in the future, under specified circumstances, in order to permit Chesapeake Energy to maintain its proportionate ownership of our outstanding shares of common stock. We also granted Chesapeake Energy a right, under certain circumstances, to request registration of the acquired shares under the Securities Act of 1933. Chesapeake Energy owns approximately 19.5% of our outstanding common stock, or approximately 14.9% assuming the conversion of all outstanding options and convertible subordinated debentures. We issued those shares without registration under the Securities Act of 1933 in reliance on the exemption that Section 4(2) of that Act provides for transactions not involving any public offering.

On August 1, 2003, we issued 477,000 shares of our common stock valued at $4.45 per share to Texas Interstate Drilling Company, L.P. in connection with our purchase of two land drilling rigs, associated spare parts and equipment and vehicles. We issued

those shares without registration under the Securities Act of 1933 in reliance on the exemption that Section 4(2) of that Act provides for transactions not involving any public offering.

On February 20, 2004, we sold 4,400,000 shares of our common stock at $5.40 per share in a private placement to various individuals and institutional investors, all of whom were accredited investors. This private placement resulted in $23,760,000 in proceeds, before related offering expenses, which included $1,188,000 in commissions paid to Jefferies & Company, Inc., Raymond James & Associates, Inc. and Pritchard Capital Partners, LLC. Although we issued those shares without registration under the Securities Act of 1933 in reliance on the exemption that Section 4(2) of that Act provides for transactions not involving any public offering, we filed a registration statement on Form S-3 to register those shares. The registration statement became effective on June 22, 2004.

Item 6. Selected Financial Data

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

	Years Ended March 31,
	2004			2003			2002		2001		2000
	(In thousands, except per share amounts)
Contract drilling revenues	$	107,876		$	80,183		$	68,627	$	50,345	$	19,391
Income (loss) from operations	438			(4,943		)	11,201		3,803		108
Income (loss) before income taxes	(2,216		)	(7,305		)	9,737		3,838		(65		)
Preferred dividends	—			—			93		275		304
Net earnings (loss) applicable to common stockholders	(1,790		)	(5,086		)	6,225		2,428		(384		)
Earnings (loss) per common share-basic	(0.08		)	(0.31		)	0.41		0.22		(0.06		)
Earnings (loss) per common share-diluted	(0.08		)	(0.31		)	0.35		0.19		(0.06		)
Long-term debt and capital lease obligations, excluding current installments	44,892			45,855			26,119		10,056		267
Shareholders’ equity	70,836			47,672			33,343		17,827		6,783
Total assets	143,731			119,694			83,450		56,493		15,670
Capital expenditures	44,845			33,589			27,597		41,628		5,069

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

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

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

Company Overview

Pioneer 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, East Texas and North 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. We are an oil and gas services company. We do not invest in oil and natural gas properties. The drilling activity of our customers is highly dependent on the current price of oil and natural gas.

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

Over the past five fiscal years, we have significantly expanded our fleet of drilling rigs through acquisitions and the construction of new and refurbished rigs. As of March 31, 2004, our rig fleet consisted of 35 land drilling rigs that drill in depth ranges between 8,000 and 18,000 feet. Fourteen of our rigs are operating in South Texas, 17 in East Texas and four in North Texas. We actively market all of these rigs. We completed construction of our 36^th rig in late May 2004 and began moving it to its first drilling location on May 28, 2004. Subject to obtaining satisfactory financing, we anticipate continued growth of our rig fleet in fiscal 2005. However, we are not currently committed to any acquisitions.

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

A significant performance measurement in our industry is rig utilization. We compute rig utilization rates by dividing revenue days by total available days during a period. Total available days are the number of calendar days during the period that we have owned the rig. Revenue days for each rig are days when the rig is earning revenues under a contract, which is usually a period from the date the rig begins moving to the drilling location until the rig is released from the contract. On daywork contracts, during the mobilization period we earn a fixed amount of revenue based on the mobilization rate stated in the contract. We attempt to set the mobilization rate at an amount equal to our external costs for the move plus our internal costs during the mobilization period. We begin earning our contracted daywork rate when we begin drilling the well.

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

	Year Ended March 31,
	2004		2003		2002
Utilization Rates	88	%	79	%	82	%
Revenue Days	8,764		6,419		5,384
Number of rigs	35		24		20

The reasons for the increase in the number of revenue days in 2004 over 2003 and 2002 are the increase in size of our rig fleet and the improvement in our overall rig utilization rate. For 2005, we anticipate continued growth in revenue days and maintaining relatively high utilization rates.

We attribute our relatively high utilization rates to a strong sales effort, quality equipment, good field and operations personnel, a disciplined safety approach, and our generally successful performance of turnkey operations. Turnkey contracts account for approximately one-fourth of our contracts. Turnkey contracts provide us with the opportunity to keep our rigs working in periods of lower demand and improve our drilling margin, but at an increased risk. Over the long term, turnkey margins per revenue day have been greater than daywork margins; however, occasionally, a turnkey contract will not be profitable if the contract cannot be completed successfully without unanticipated complications.

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

Market Conditions in Our Industry

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

For the three months ended March 31, 2004, the average weekly spot price for West Texas Intermediate crude oil was $35.08, the average weekly spot price for Henry Hub natural gas was $5.56 and the average weekly Baker Hughes land rig count was 1,002. On June 11, 2004, the spot price for West Texas Intermediate crude oil was $38.45, the spot price for Henry Hub natural gas was $6.00 and the Baker Hughes land rig count was 1,070, a 13% increase from 948 on June 13, 2003.

The average weekly spot prices of West Texas Intermediate crude oil, Henry Hub natural gas and the average weekly domestic land rig count, per the Baker Hughes land rig count, for each of the previous six years ended March 31, 2004 were:

	Year Ended March 31,
	2004		2003		2002		2001		2000		1999
Oil (West Texas Intermediate)	$	31.47	$	29.27	$	24.31	$	30.40	$	23.23	$	13.69
Gas (Henry Hub)	$	5.27	$	4.24	$	2.96	$	5.27	$	2.46	$	1.97
U.S. Land Rig Count	964		723		912		841		550		592

The decline in oil and natural gas prices from mid-2001 to mid-2002 resulted in a reduction in the demand for contract land drilling services, which resulted in a substantial reduction in the rates land drilling companies were able to obtain for their services. While oil and natural gas prices have recovered in recent months, drilling activity has not yet recovered to a level at which we are able to significantly improve our revenue rates and drilling margins.

During fiscal 2004, 2003 and 2002, substantially all the wells we drilled for our customers were drilled in search of natural gas because of the depth capacity of our rigs and the gas rich areas in which we operate. Natural gas reserves are typically found in deeper geological formations and generally require premium equipment and quality crews to drill the wells.

Critical Accounting Policies and Estimates

Revenue and cost recognition – We earn our revenues by drilling oil and gas wells for our customers under daywork, turnkey or footage contracts, which usually provide for the drilling of a single well. We recognize revenues on daywork contracts for the days completed based on the dayrate each contract specifies. We recognize revenues from our turnkey and footage contracts on the percentage-of-completion method based on our estimate of the number of days to complete each contract. Contract drilling in progress represents revenues we have recognized in excess of amounts billed on contracts in progress. Individual contracts are usually completed in less than 60 days. The risks to us under a turnkey contract, and to a lesser extent under footage contracts, are substantially greater than on a contract drilled on a daywork basis. This is primarily because under a turnkey contract we assume most of the risks associated with drilling operations generally assumed by the operator in a daywork contract, including the risks of blowout, loss of hole, stuck drill pipe, machinery breakdowns and abnormal drilling conditions, as well as risks associated with subcontractors’ services, supplies, cost escalations and personnel operations.

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

If a customer defaults on its payment obligation to us under a turnkey or footage contract, we would need to rely on applicable law to enforce our lien rights, because our turnkey and footage contracts do not expressly grant to us a security interest in the work we have completed under the contract and we have no ownership rights in the work-in-progress or completed drilling work, except any rights arising under the applicable lien statute on foreclosure. If we were unable to drill to the agreed on depth in breach of the contract, we also would need to rely on equitable remedies outside of the contract, including quantum meruit, available in applicable courts to recover the fair value of our work-in-progress under a turnkey or footage contract.

We accrue estimated contract costs on turnkey and footage contracts for each day of work completed based on our estimate of the total costs to complete the contract divided by our estimate of the number of days to complete the contract. Contract costs include labor, materials, supplies, repairs and maintenance, operating overhead allocations and allocations of depreciation and amortization expense. In addition, the occurrence of uninsured or under-insured losses or operating cost overruns on our turnkey and footage contracts could have a material adverse effect on our financial position and results of operations. Therefore, our actual results could

differ significantly if our cost estimates are later revised from our original estimates for contracts in progress at the end of a reporting period which were not completed prior to the release of our financial statements.

Asset impairments –We assess the impairment of property and equipment whenever events or circumstances indicate that the carrying value may not be recoverable. Factors that we consider important and which could trigger an impairment review would be our customers’ financial condition and any significant negative industry or economic trends. More specifically, among other things, we consider our contract revenue rates, our rig utilizations rates, cash flows from our drilling rigs, current oil and gas prices, industry analysts’ outlook for the industry and their view of our customers’ access to debt or equity, discussions with major industry suppliers, discussions with officers of our primary lender regarding their experiences and expectations for oil and gas operators in our areas of operations and the trends in the price of used drilling equipment observed by our management. If a review of our drilling rigs indicates that our carrying value exceeds the estimated undiscounted future cash flows, we are required under applicable accounting standards to write down the drilling equipment to its fair market value. A one percent write-down in the cost of our drilling equipment, at March 31, 2004, would have resulted in a corresponding increase in our net loss of approximately $962,000 for our fiscal year ended March 31, 2004.

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

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

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

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

We estimate an allowance for doubtful accounts based on the creditworthiness of our customers as well as general economic conditions. We evaluate the creditworthiness of our customers based on information obtained from major industry suppliers, current prices of oil and gas and any past experience we have with the customer. Consequently, an adverse change in those factors could affect our estimate of our allowance for doubtful accounts. In some instances, we require new customers to establish escrow accounts or make

prepayments. We typically invoice our customers at 15-day intervals during the performance of daywork contracts and upon completion of the daywork contract. Turnkey and footage contracts are invoiced upon completion of the contract. Our typical contract provides for payment of invoices in 10 to 30 days. We generally do not extend payment terms beyond 30 days and have not extended payment terms beyond 60 days for any of our contracts in the last three fiscal years.

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

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

Liquidity and Capital Resources

Sources of Capital Resources

Our rig fleet has grown from eight rigs in August 2000 to 35 rigs as of March 31, 2004. We have financed this growth with a combination of debt and equity financing. We have raised additional equity or used equity for growth six times since January 2000 and have increased our long-term debt from approximately $3,909,000 at June 30, 2000 to approximately $48,500,000 at March 31, 2004. We plan to continue to grow our rig fleet. We believe that near-term growth will require the use of equity financing rather than additional debt. At March 31, 2004, our total debt to total capital was approximately 41%. Due to the volatility in our industry, we are reluctant to take on substantial additional debt at this time. However, our ability to continue funding our growth through the issuance of shares of our common stock is uncertain, as our common stock is not heavily traded and the market price for our common stock has been volatile in recent periods.

On February 20, 2004, we sold 4,400,000 shares of our common stock at $5.40 per share in a private placement for $23,760,000 in proceeds, before related offering expenses.

Uses of Capital Resources

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

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

In late May 2004, we completed constructing, primarily from used components, a 1000-hp electric drilling rig. As of March 31, 2004, we had incurred approximately $2,800,000 of construction costs on this rig and anticipate additional related construction costs of approximately $2,100,000. We began moving it to its first drilling location on May 28, 2004. For fiscal 2005, we project regular capital expenditures to be approximately $10,200,000 and rig upgrade expenditures to be approximately $4,500,000. These regular capital expenditures and rig upgrade capital expenditures are expected to be funded primarily from operating cash flow.

Since March 31, 2003, the additions to our property and equipment have totaled $44,844,745. Additions consisted of the following:

Drilling rigs (1)	$	34,961,004
Other drilling equipment	7,642,968
Transportation equipment	2,160,838
Other	79,935
	$	44,844,745

(1) Includes capitalized interest costs of $106,395.

Working Capital

Our working capital decreased to $6,028,018 at March 31, 2004 from $11,144,309 at March 31, 2003. Our current ratio, which we calculate by dividing our current assets by our current liabilities, was 1.27 at March 31, 2004 compared to 1.55 at March 31, 2003. The principal reason for the decrease in our working capital at March 31, 2004 was our use of approximately $3,400,000 of working capital toward the purchase of drilling equipment. We used substantially all the $20,000,000 in proceeds from the shares of common stock we sold to Chesapeake Energy Corporation on March 31, 2003 to expand our rig fleet or reduce debt we incurred to expand our rig fleet. We have used approximately $17,000,000 of the funds we raised in February 2004 to expand our rig fleet or acquire other equipment. Our operations have historically generated sufficient cash flow to meet our requirements for debt service and equipment expenditures, even during periods of industry downturns. During periods when a higher percentage of our contracts are turnkey and footage contracts, our short-term working capital needs could increase. We have available a $2,500,000 line of credit for short-term cash requirements. We did not make any borrowings under the line of credit during fiscal 2004. We have used debt and equity to finance our long-term growth strategy to increase the size of our rig fleet. During periods of improved revenue rates, we believe we can generate cash flows in excess of our normal cash requirements.

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

	March 31,
	2004		2003		Change
Cash and cash equivalents	$	6,365,759	$	21,002,913	$	(14,637,154	)
Receivables	20,032,785		8,928,923		11,103,862
Income tax receivable	—		444,900		(444,900		)
Deferred tax receivable	285,384		180,991		104,393
Prepaid expenses	1,336,337		914,187		422,150
Current assets	28,020,265		31,471,914		(3,451,649		)

Current debt	4,423,306		3,399,163		1,024,143
Accounts payable	13,270,989		14,206,586		(935,597		)
Accrued payroll	1,499,151		847,163		651,988
Accrued expenses	2,798,801		1,874,693		924,108
	21,992,247		20,327,605		1,664,642

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

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

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

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

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

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

Long-term Debt

Our long-term debt at March 31, 2004 consisted of the following:

Convertible subordinated debentures due July 2007 at 6.75% (1)	$	28,000,000

Note payable to Merrill Lynch Capital, secured by drilling equipment, due in monthly payments of $172,619 plus interest at a floating rate equal to the three month LIBOR rate (1.1% at March 31, 2004) plus 385 basis points, due December 2007	13,119,048

Note payable to Frost National Bank, secured by drilling equipment, due in monthly payments of $107,143 plus interest at prime (4.0% at March 31, 2004) plus 1.00%, due August 2007	4,392,174

Note payable to Frost National Bank, secured by drilling equipment, due in monthly payments of $42,401, including interest at prime (4.0% at March 31, 2004) plus 1.0%, beginning April 15, 2004, due March 15, 2007 (2)	3,000,000
	48,511,222

Less current installments	(3,724,302		)
	$	44,786,920

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

(2) We incurred this debt to finance the purchase of the rig we were previously leasing.

Contractual Obligations

We do not have any routine purchase obligations. However, as of March 31, 2004, we were in the process of constructing a drilling rig, as described above. The following table excludes interest payments on long-term debt and capital lease obligations. The following table includes all of our contractual obligations at March 31, 2004.

	Payments Due by Period
Contractual Obligations	Total		Less than 1 year		1-3 years		4-5 years		More than 5 years
Long-Term Debt Obligations	$	48,511,222	$	3,724,302	$	9,347,127	$	35,439,793	$	—
Capital Lease Obligations	245,688		140,934		104,754		—		—
Operating Lease Obligations	314,460		121,608		192,852		—		—
Total	$	49,071,370	$	3,986,844	$	9,644,733	$	35,439,793	$	—

Debt Requirements

Borrowings from Frost National Bank and Merrill Lynch Capital, a division of Merrill Lynch Business Financial Services, Inc. (“MLC”), contain various covenants pertaining to leverage, cash flow coverage, fixed charge coverage and net worth ratios and restrict us from paying dividends. Under these credit arrangements, we determine compliance with the ratios on a quarterly basis, based on the previous four quarters. As of March 31, 2004, we were in compliance with all covenants applicable to our outstanding debt.

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

• our failure to make required payments;

• our failure to comply with financial covenants related to the maintenance of a ratio of debt to tangible net worth, a leverage ratio, a cash flow coverage ratio and a senior cash flow coverage ratio;

• our incurrence of additional indebtedness in excess of $2,000,000 not already allowed by the loan agreements without each lender’s approval; and

• any payment of cash dividends on our common stock.

The limitation on additional indebtedness has not affected our operations or liquidity and we do not expect it to affect us in the future as we expect to continue to generate adequate cash flow from operations.

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

Results of Operations

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

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.

We have a history of losses. We incurred net losses of approximately $1,800,000, $5,100,000 and $400,000 in the fiscal years ended March 31, 2004, 2003 and 2000, respectively. Our profitability in the future will depend on many factors, but largely on utilization rates and dayrates for our drilling rigs.

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

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

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

While current demand for drilling rigs has increased, we continue to bid on turnkey contracts in an effort to improve margins and maintain rig utilization. Although oil and natural gas prices have improved, we anticipate only a moderate change in the mix of our types of contracts in fiscal 2005.

In our quarter ended March 31, 2004, we recognized revenues of approximately $924,000 and recorded contract drilling costs of approximately $745,000, excluding depreciation, on one daywork contract with Chesapeake Energy Corporation, who owns approximately 19.5% of our outstanding common stock.

Statement of Operations Analysis

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

	Year Ended March 31,
	2004			2003			2002
Contract drilling revenues	$	107,875,533		$	80,183,486		$	68,627,486
Contract drilling costs	88,504,102			70,823,310			46,145,364
Depreciation and amortization	16,160,494			11,960,387			8,426,082
General and administrative expenses	2,772,730			2,232,390			2,855,274
Revenue days by type of contract:
Turnkey contracts	2,827			2,619			289
Footage contracts	311			119			136
Daywork contracts	5,626			3,681			4,959
Total revenue days	8,764			6,419			5,384

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

Our contract drilling revenues grew by approximately 35% in fiscal 2004 from fiscal 2003, due to an improvement in rig revenue rates, a 37% increase in revenue days, a 9% increase in rig utilization and an increase in the number of rigs in our fleet. Approximately 52% of the increase in revenue days was an increase in daywork revenue days resulting in a $183 decrease in average contract drilling revenue per day.

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

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

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

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

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

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

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

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

Inflation

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

Off Balance Sheet Arrangements

We do not currently have any off balance sheet arrangements.

Item 7A. Quantitative and Qualitative Disclosures About Market Risk

We are subject to market risk exposure related to changes in interest rates on most of our outstanding debt. At March 31, 2004, we had outstanding debt of approximately $20,511,000 that was subject to variable interest rates, in each case based on an agreed percentage-point spread from the lender’s prime interest rate. An increase or decrease of 1% in the interest rate would have a corresponding decrease or increase in our net income (loss) of approximately $135,000 annually. We did not enter into any of these debt arrangements for trading purposes.

Item 8. Financial Statements and Supplementary Data

PIONEER DRILLING COMPANY

INDEX TO CONSOLIDATED FINANCIAL STATEMENTS

Report of Independent Registered Public Accounting Firm

Consolidated Balance Sheets as of March 31, 2004 and 2003

Consolidated Statements of Operations for the Years Ended March 31, 2004, 2003 and 2002

Consolidated Statements of Shareholders’ Equity and Comprehensive Income for the Years Ended March 31, 2004, 2003 and 2002

Consolidated Statements of Cash Flows for the Years Ended March 31, 2004, 2003 and 2002

Notes to Consolidated Financial Statements

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Shareholders
Pioneer Drilling Company:

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

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

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

KPMG LLP

San Antonio, Texas

June 23, 2004

PIONEER DRILLING COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS

	March 31,
	2004			2003
ASSETS
Current assets:
Cash and cash equivalents	$	6,365,759		$	21,002,913
Receivables:
Trade, net	10,901,991			4,499,378
Contract drilling in progress	9,130,794			4,429,545
Federal income tax receivable	—			444,900
Current deferred income taxes	285,384			180,991
Prepaid expenses	1,336,337			914,187
Total current assets	28,020,265			31,471,914
Property and equipment, at cost:
Drilling rigs and equipment	145,758,913			106,728,573
Transportation, office, land and other	5,427,637			3,494,657
	151,186,550			110,223,230
Less accumulated depreciation and amortization	35,844,938			22,367,327
Net property and equipment	115,341,612			87,855,903
Other assets	369,278			366,500
Total assets	$	143,731,155		$	119,694,317

LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities:
Notes payable	$	558,070		$	587,177
Current installments of long-term debt	3,724,302			2,671,269
Current installments of capital lease obligations	140,934			140,717
Accounts payable	13,270,989			14,206,586
Accrued expenses:
Payroll and payroll taxes	1,499,151			847,163
Other	2,798,801			1,874,693
Total current liabilities	21,992,247			20,327,605
Long-term debt, less current installments	44,786,920			45,594,517
Capital lease obligations, less current installments	104,754			260,025
Deferred income taxes	6,010,916			5,839,908
Total liabilities	72,894,837			72,022,055
Shareholders’ equity:
Preferred stock, 10,000,000 shares authorized; none issued and outstanding
Common stock $.10 par value; 100,000,000 shares authorized; 27,300,126 shares and 21,700,792 shares issued and outstanding at March 31, 2004 and March 31, 2003, respectively	2,730,012			2,170,079
Additional paid-in capital	82,124,368			57,730,188
Accumulated deficit	(14,018,062		)	(12,228,005		)
Total shareholders’ equity	70,836,318			47,672,262
Total liabilities and shareholders’ equity	$	143,731,155		$	119,694,317

See accompanying notes to consolidated financial statements.

PIONEER DRILLING COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS

	Years Ended March 31,
	2004			2003			2002

Contract drilling revenues	$	107,875,533		$	80,183,486		$	68,627,486

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

Total operating costs and expenses	107,437,326			85,126,087			57,426,720
Income (loss) from operations	438,207			(4,942,601		)	11,200,766

Other income (expense):
Interest expense	(2,807,822		)	(2,698,529		)	(1,616,984		)
Interest income	101,584			94,235			80,932
Other	51,675			37,614			72,096
Gain on sale of securities	—			203,887			—
Total other income (expense)	(2,654,563		)	(2,362,793		)	(1,463,956		)

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

Net earnings (loss)	(1,790,057		)	(5,085,618		)	6,318,285
Preferred stock dividend requirement	—			—			92,814
Net earnings (loss) applicable to common shareholders	$	(1,790,057	)	$	(5,085,618	)	$	6,225,471

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

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

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

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

See accompanying notes to consolidated financial statements.

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

	Shares Common	Shares Preferred		Amount Common		Preferred			Additional Paid In Capital		Accumulated Deficit			Accumulated Other Comprehensive Income			Total Shareholders’ Equity

Balance as of March 31, 2001	12,145,921	184,615		$	1,214,592	$	2,999,994		$	26,869,916	$	(13,367,858	)	$	110,118		$	17,826,762
Comprehensive income:
Net earnings	—	—		—		—			—		6,318,285			—			6,318,285
Net unrealized change in securites available for sale, net of tax of $384	—	—		—		—			—		—			(702		)	(702		)
Total comprehensive income	—	—		—		—			—		—			—			6,317,583
Issuance of common stock for:
Sale, net of related expenses	2,400,000	—		240,000		—			8,808,000		—			—			9,048,000
Conversion of preferred	1,199,038	(184,615	)	119,903		(2,999,994		)	2,880,091		—			—			—
Exercise of options	177,500	—		17,750		—			225,724		—			—			243,474
Preferred stock dividend	—	—		—		—			—		(92,814		)	—			(92,814		)
Balance as of March 31, 2002	15,922,459	—		1,592,245		—			38,783,731		(7,142,387		)	109,416			33,343,005
Comprehensive income:
Net loss	—	—		—		—			—		(5,085,618		)	—			(5,085,618		)
Net unrealized change in securites available for sale, net of tax of $56,366	—	—		—		—			—		—			(109,416		)	(109,416		)
Total comprehensive loss	—	—		—		—			—		—			—			(5,195,034		)
Issuance of common stock for:
Sale, net of related expenses of $657,499	5,333,333	—		533,334		—			18,809,167		—			—			19,342,501
Exercise of options	445,000	—		44,500		—			137,290		—			—			181,790
Balance as of March 31, 2003	21,700,792	—		2,170,079		—			57,730,188		(12,228,005		)	—			47,672,262
Comprehensive income:
Net loss	—	—		—		—			—		(1,790,057		)	—			(1,790,057		)
Total comprehensive loss	—	—		—		—			—		—			—			(1,790,057		)
Issuance of common stock for:
Sale, net of related expenses of $1,654,753	4,400,000	—		440,000		—			21,665,247		—			—			22,105,247
Equipment acquisitions	477,000	—		47,700		—			2,074,950		—			—			2,122,650
Exercise of options and related income tax benefits	722,334	—		72,233		—			653,983		—			—			726,216
Balance as of March 31, 2004	27,300,126	—		$	2,730,012	$	—		$	82,124,368	$	(14,018,062	)	$	—		$	70,836,318

See accompanying notes to consolidated financial statements.

PIONEER DRILLING COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS

	Years Ended March 31,
	2004			2003			2002
Cash flows from operating activities:
Net earnings (loss)	$	(1,790,057	)	$	(5,085,618	)	$	6,318,285
Adjustments to reconcile net earnings (loss) to net cash provided by operating activities:
Depreciation and amortization	16,160,494			11,960,387			8,426,082
Allowance for doubtful accounts	—			110,000			—
Gain on sale of securities	—			(203,887		)	—
Loss (gain) on dispositions of properties and equipment	816,104			279,054			(2,237		)
Change in deferred income taxes	119,038			(1,511,744		)	1,991,458
Changes in current assets and liabilities:
Receivables	(11,103,862		)	242,126			(4,172,470		)
Prepaid expenses	(422,150		)	(279,440		)	(322,471		)
Accounts payable	(935,597		)	7,699,417			(1,099,813		)
Federal income taxes	444,900			435,168			(930,266		)
Accrued expenses	1,576,096			743,814			836,321
Net cash provided by operating activities	4,864,966			14,389,277			11,044,889

Cash flows from financing activities:
Proceeds from notes payable	4,110,019			23,573,501			19,556,286
Proceeds from subordinated debenture	—			10,000,000			18,000,000
Increase in other assets	(40,000		)	(253,698		)	(195,000		)
Payment of preferred dividends	—			—			(859,395		)
Proceeds from exercise of options and warrants	673,794			181,790			243,474
Proceeds from common stock, net of offering cost of $1,654,753 in 2004 and $657,499 in 2003	22,105,247			19,342,501			9,048,000
Payments of debt	(4,048,744		)	(18,714,311		)	(27,026,538		)
Net cash provided by financing activities	22,800,316			34,129,783			18,766,827
Cash flows from investing activities:
Purchases of property and equipment	(42,722,094		)	(33,588,972		)	(27,597,265		)
Proceeds from sale of marketable securities	—			375,414			—
Proceeds from sale of property and equipment	419,658			314,366			675,660
Net cash used in investing activities	(42,302,436		)	(32,899,192		)	(26,921,605		)
Net increase (decrease) in cash and cash equivalents	(14,637,154		)	15,619,868			2,890,111
Beginning cash and cash equivalents	21,002,913			5,383,045			2,492,934
Ending cash and cash equivalents	$	6,365,759		$	21,002,913		$	5,383,045
Supplementary disclosure:
Interest paid	$	2,821,041		$	2,785,177		$	1,046,943
Income taxes paid (refunded)	(990,237		)	(1,143,200		)	2,342,006
Dividends accrued	—			—			92,814
Conversion of preferred stock	—			—			2,999,994
Acquisition - common stock issued	2,122,650			—			—
Tax benefit from exercise of nonqualified options	52,423			2,720			—

See accompanying notes to consolidated financial statements.

PIONEER DRILLING COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1. Organization and Summary of Significant Accounting Policies

Business and Principles of Consolidation

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

We have prepared the accompanying consolidated financial statements in accordance with accounting principles generally accepted in the United States of America. In preparing the financial statements, we make various estimates and assumptions that affect the amounts of assets and liabilities we report as of the dates of the balance sheets and income and expenses we report for the periods shown in the income statements and statements of cash flows. Our actual results could differ significantly from those estimates. Material estimates that are particularly susceptible to significant changes in the near term relate to our recognition of revenues and costs for turnkey contracts, our estimate of the allowance for doubtful accounts, our estimate of the self-insurance portion of our health and workers’ compensation insurance, our estimate of asset impairments, our estimate of deferred taxes and our determination of depreciation and amortization expense.

Income Taxes

Pursuant to Statement of Financial Accounting Standards (“SFAS”) No. 109, “Accounting for Income Taxes,” we follow the asset and liability method of accounting for income taxes, under which we recognize deferred tax assets and liabilities for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases. We measure our deferred tax assets and liabilities by using the enacted tax rates we expect to apply to taxable income in the years in which we expect to recover or settle those temporary differences. Under SFAS No. 109, we reflect in income the effect of a change in tax rates on deferred tax assets and liabilities in the period during which the change occurs.

Earnings (Loss) Per Common Share

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

Stock-based Compensation

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

	Year Ended March 31,
	2004			2003			2002
Net earnings (loss)-as reported	$	(1,790,057	)	$	(5,085,618	)	$	6,318,285
Deduct: Total stock-based employee compensation expense determined under fair value based method for all awards net of related tax effect	(662,933		)	(385,671		)	(582,258		)
Net earnings (loss)-pro forma	$	(2,452,990	)	$	(5,471,289	)	$	5,736,027
Net earnings (loss) per share-as reported-basic	$	(0.08	)	$	(0.31	)	$	(0.41	)
Net earnings (loss) per share-as reported-diluted	(0.08		)	(0.31		)	(0.35		)
Net earnings (loss) per share-pro forma-basic	$	(0.11	)	$	(0.34	)	$	(0.38	)
Net earnings (loss) per share-pro forma diluted	(0.11		)	(0.34		)	(0.32		)
Weighted-average fair value of options granted during the year	$	4.46		$	3.50		$	3.11

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

Revenue and Cost Recognition

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

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

We accrue estimated costs on turnkey and footage contracts for each day of work completed based on our estimate of the total cost to complete the contract divided by our estimate of the number of days to complete the contract. Contract costs include labor, materials, supplies, repairs, maintenance, operating overhead allocations and allocations of depreciation and amortization

expense. We charge general and administrative expenses to expense as we incur them. Changes in job performance, job conditions and estimated profitability on uncompleted contracts may result in revisions to costs and income. When we encounter, during the course of our drilling operations, conditions unforeseen in the preparation of our original cost estimate, we immediately increase our cost estimate for the additional costs to complete the contract. If we anticipate a loss on a contract in progress at the end of a reporting period due to a change in our cost estimate, we immediately accrue the entire amount of the estimated loss including all costs that are included in our revised estimated cost to complete that contract in our consolidated statement of operations for that reporting period.

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

Prepaid Expenses

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

Property and Equipment

We provide for depreciation of our drilling, transportation and other equipment using the straight-line method over useful lives that we have estimated and that range from three to 15 years. We record the same depreciation expense whether a rig is idle or working.

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

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

Cash Equivalents

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

Investment Securities

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

Trade Accounts Receivable

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

Other Assets

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

Derivative Instruments and Hedging Activities

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

Recently Issued Accounting Standards

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

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

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

Reclassifications

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

2. Acquisitions

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

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

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

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

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

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

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

Our long-term debt is described below:

	March 31,
	2004			2003
Convertible subordinated debentures due July 2007 at 6.75% (1)	$	28,000,000		$	28,000,000

Note payable to Merrill Lynch Capital, secured by drilling equipment, due in monthly payments of $172,619 plus interest at a floating rate equal to the 3-month LIBOR rate (1.1% at March 31, 2004) plus 385 basis points, due December 2007	13,119,048			14,500,000

Note payable to Frost National Bank, secured by drilling equipment, due in monthly payments of $107,143 plus interest at prime (4.0% at March 31, 2004) plus 1.0%, due August 2007	4,392,174			5,677,889

Note payable to Small Business Administration, secured by second lien on land and improvements, due in monthly payments of $912 including interest at 6.71%, due November 2015 (paid off April, 2003)	—			87,897

Note payable to Frost National Bank, secured by drilling equipment, due in monthly payments of $42,401, including interest at prime plus (4.0% at March 31, 2004) plus 1.0%, beginning April 15, 2004, due March 15, 2007 (2)	3,000,000			—
	48,511,222			48,265,786

Less current installments	(3,724,302		)	(2,671,269		)
	$	44,786,920		$	45,594,517

(2) We incurred this debt to finance the purchase of the rig we were previously leasing.

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

Year Ended March 31,
2005	$	3,724,302
2006	3,743,087
2007	5,604,040
2008	35,439,793
2009	—
2010 and thereafter	—

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

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

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

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

4. Leases

We are obligated under capital leases covering several trucks that expire at various dates through January 2007. At

March 31, 2004 and 2003, the gross amount of transportation equipment and related amortization recorded under capital

leases were as follows:

	March 31,
	2004		2003
Transportation equipment	$	665,195	$	647,822
Less accumulated amortization	413,797		248,070
	$	251,398	$	399,752

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

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

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

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

Year Ended March 31,	Operating Leases		Capital Leases
2005	$	121,608	$	166,604
2006	122,940		70,446
2007	69,912		34,106
2008	—		—
Total minimum lease payments	$	314,460	$	271,156

Less amounts representing interest (at rates ranging from 5.8% to 9.5%)			(25,468		)
Present value of net minimum capital lease payments			245,688
Less current installments of capital lease obligations			(140,934		)
Capital lease obligations, excluding current installments			$	104,754

5. Income Taxes

Our provision for income taxes consists of the following:

	Years Ended March 31,
	2004			2003			2002

Current tax - federal	$	—		$	(708,032	)	$	1,427,067
Deferred tax - federal	(426,299		)	(1,511,744		)	1,991,458
Income tax expense (benefit)	$	(426,299	)	$	(2,219,776	)	$	3,418,525

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

	Years Ended March 31,
	2004			2003			2002

Expected tax expense (benefit)	$	(753,561	)	$	(2,483,834	)	$	3,310,515
Non taxable interest income	—			(10,400		)	(9,429		)
Club dues, meals and entertainment	13,941			10,443			10,115
Reimbursement of food costs for rig employees	314,622			275,338			270,000
Other	(1,301		)	(11,323		)	(162,676		)
	$	(426,299	)	$	(2,219,776	)	$	3,418,525

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

	March 31,
	2004		2003

Deferred tax assets:
Workers compensation and vacation expense accruals	$	224,985	$	94,972
Bad debt expense	37,400		37,400
Net operating loss carryforwards	7,825,126		5,105,730
Alternative minimum tax credit	181,770		181,770
Loss accrual on turnkey contracts	23,000		48,619
Total deferred tax assets	8,292,281		5,468,491
Deferred tax liabilities:
Property and equipment, principally due to differences in depreciation	14,017,813		11,127,408
Total deferred tax liabilities	14,017,813		11,127,408
Net deferred tax liabilities	$	5,725,532	$	5,658,917

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

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

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

6. Fair Value of Financial Instruments

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

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

Long-term debt:

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

7. Earnings (Loss) Per Common Share

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

	Years Ended March 31,
	2004			2003			2002

Basic
Net earnings (loss)	$	(1,790,057	)	$	(5,085,618	)	$	6,318,285
Less: Preferred stock dividends	—			—			92,814
Earnings (loss) applicable to common shareholders	$	(1,790,057	)	$	(5,085,618	)	$	6,225,471
Weighted average shares	22,585,612			16,163,098			15,112,272
Earning (loss) per share	$	(0.08	)	$	(0.31	)	$	0.41


Diluted
Earnings (loss) applicable to common shareholders	$	(1,790,057	)	$	(5,085,618	)	$	6,225,471
Effect of dilutive securities:
Convertible subordinated debenture	—			—			385,358
Preferred stock	—			—			92,814
Earnings (loss) available to common shareholders and assumed conversion	$	(1,790,057	)	$	(5,085,618	)	$	6,703,643
Weighted average shares:
Outstanding	22,585,612			16,163,098			15,112,272
Options	—			—			1,500,589
Convertible subordinated debenture	—			—			2,145,205
Preferred stock	—			—			463,190
	22,585,612			16,163,098			19,221,256
Earnings (loss) per share	$	(0.08	)	$	(0.31	)	$	0.35

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

8. Equity Transactions

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

In accordance with the terms of the Series B Preferred Stock Agreement that we entered into on January 20, 1998, the conversion price for our Series B convertible preferred stock was revised from $3.25 per share to $2.50 per share as of January 20, 2001. This revision was based on the average trading price of our common stock for the 30 trading days preceding that date. In August 2001, the holders converted all of their 184,615 shares of our Series B convertible preferred stock into 1,199,038 shares of our common stock at $2.50 per share.

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

On March 31, 2003, we sold 5,333,333 shares of our common stock to Chesapeake Energy Corporation for $20,000,000 ($3.75 per share), before related offering expenses. In connection with that sale, we granted Chesapeake Energy a preemptive right

to acquire equity securities we may issue in the future, under specified circumstances, in order to permit Chesapeake Energy to maintain its proportionate ownership of our outstanding shares of common stock. We also granted Chesapeake Energy a right, under certain circumstances, to request registration of the acquired shares under the Securities Act of 1933. At March 31, 2004, Chesapeake Energy owned 19.54% of our outstanding common stock. During the year ended March 31, 2004, we recognized revenues of approximately $924,000 and recorded contract drilling costs of approximately $745,000, excluding depreciation, on one daywork contract with Chesapeake Energy Corporation. Although our normal payment terms are 30 days from date of invoice, Chesapeake Energy Corporation requires 60 day payment terms.

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

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

9. Stock Options, Warrants and Stock Option Plan

Under our stock option plans, employee stock options generally become exercisable over three to five-year periods, and all options generally expire 10 years after the date of grant. Our plans provide that all options must have an exercise price not less than the fair market value of our common stock on the date of grant. Accordingly, as we discussed in Note 1, we do not recognize any compensation expense relating to these options in our results of operations.

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

	2004				2003				2002
	Shares Issuable on Exercise of Options		Exercise Price per Share		Shares Issuable on Exercise of Options		Exercise Price per Share		Shares Issuable on Exercise of Options		Exercise Price per Share
Balance Outstanding
Beginning of year	1,825,000		$	.375-5.15	2,320,000		$	0.375-5.15	2,177,500		$	0.375-4.60
Granted	1,000,000		$	3.67-4.99	65,000		$	3.20-4.50	585,000		$	3.00-5.15
Exercised	(722,334	)	$	.625-3.20	(445,000	)	$	0.375-2.50	(177,500	)	$	0.375-1.50
Canceled	(46,000	)	$	2.25	(115,000	)	$	2.25-4.60	(265,000	)	$	2.25
Balance Outstanding
End of year	2,056,666		$	.375-5.15	1,825,000		$	0.375-5.15	2,320,000		$	0.375-5.15
Options Exercisable
End of year	884,001				1,437,334				1,734,000

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

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

10. Employee Benefit Plans and Insurance

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

We maintain a self-insurance program, for major medical, hospitalization and dental coverage for employees and their dependents, which is partially funded by payroll deductions. We have provided for both reported and incurred but not reported medical costs in the accompanying consolidated balance sheets. We have a maximum liability of $100,000 per employee/dependent per year. Amounts in excess of the stated maximum are covered under a separate policy provided by an insurance company.

Accrued expenses at March 31, 2004 include approximately $280,000 for our estimate of incurred but unpaid costs related to the self-insurance portion of our health insurance.

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

11. Business Segments and Supplementary Earnings Information

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

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

12. Commitments and Contingencies

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

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

13. Quarterly Results of Operations (unaudited)

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

	First Quarter			Second Quarter			Third Quarter			Fourth Quarter			Total
2004
Revenues	$	23,850		$	24,244		$	26,414		$	33,368		$	107,876
Income (loss) from operations	(789		)	(166		)	9			1,384			438
Net earnings (loss)	(1,056		)	(621		)	(522		)	409			(1,790		)
Earnings (loss) per share:
Basic	(.05		)	(.03		)	(.02		)	.02			(.08		)
Diluted	(.05		)	(.03		)	(.02		)	.02			(.08		)

2003
Revenues	$	18,452		$	17,042		$	19,795		$	24,894		$	80,183
Income (loss) from operations	153			(1,251		)	(1,840		)	(2,005		)	(4,943		)
Net earnings (loss)	(172		)	(1,302		)	(1,704		)	(1,908		)	(5,086		)
Earnings (loss) per share:
Basic	(.01		)	(.08		)	(.11		)	(.11		)	(.31		)
Diluted	(.01		)	(.08		)	(.11		)	(.11		)	(.31		)

Item 9. Changes in and Disagreements With Accountants on Accounting and Financial Disclosure

Not applicable.

Item 9A. Controls and Procedures

In accordance with Exchange Act Rules 13a-15 and 15d-15, we carried out an evaluation, under the supervision and with the participation of management, including our Chief Executive Officer and Chief Financial Officer, of the effectiveness of our disclosure controls and procedures as of the end of the period covered by this report. Based upon that evaluation, our Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures were effective as of March 31, 2004 to provide reasonable assurance that information required to be disclosed in our reports filed or submitted under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the Securities and Exchange Commission’s rules and forms.

There has been no change in our internal controls over financial reporting that occurred during the three months ended March 31, 2004 that has materially affected, or is likely to materially affect, our internal controls over financial reporting.

PART III

In Items 10, 11, 12 and 13 below, we are incorporating by reference the information we refer to in those Items from the definitive proxy statement for our 2004 Annual Meeting of Shareholders. We intend to file that definitive proxy statement with the SEC by July 15, 2004.

Item 10. Directors and Executive Officers of the Registrant

Please see the information appearing under the headings “Proposal No. 1—Election of Directors” and “Executives and Executive Compensation” in the definitive proxy statement for our 2004 Annual Meeting of Shareholders for the information this Item 10 requires.

Item 11. Executive Compensation

Please see the information appearing under the heading “Executives and Executive Compensation” in the definitive proxy statement for our 2004 Annual Meeting of Shareholders for the information this Item 11 requires.

Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters

Please see the information appearing (1) under the heading “Equity Compensation Plan Information” in Item 5 of this report and (2) under the heading “Security Ownership of Certain Beneficial Owners and Management” in the definitive proxy statement for our 2004 Annual Meeting of Shareholders for the information this Item 12 requires.

Item 13. Certain Relationships and Related Transactions

Please see the information appearing under the heading “Certain Transactions” in the definitive proxy statement for our 2004 Annual Meeting of Shareholders for the information this Item 13 requires.

Item 14. Principal Accountant Fees and Services

Please see the information appearing under the heading “Ratification of Appointment of Independent Auditors” in the definitive proxy statement for our 2004 Annual Meeting of Shareholders for the information this Item 14 requires.

PART IV

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

(a)(1)		Financial Statements.

		See Index to Consolidated Financial Statements on page 27.

(2)		Financial Statement Schedules:

		Financial statement schedules are omitted because they are not required or the required information is shown in our consolidated financial statements or the notes thereto.

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

Exhibit Number		Description

2.1*	-	Asset Purchase Agreement dated February 14, 2001 between Mustang Drilling, Ltd., Michael T. Wilhite, Sr., Andrew D. Mills and Michael T. Wilhite, Jr. (Form 10-K for the year ended March 31, 2001 (File No. 1-8182, Exhibit 2.2)).

2.2*	-	Stock Purchase Agreement dated July 21, 2000 between Pioneer Drilling Company and the Shareholders of Pioneer Drilling Co., Inc. (Form 10-K for the year ended March 31, 2001 (File No. 1-8182, Exhibit 2.3)).

2.3*	-	Purchase Agreement dated the 30th of April 2001 by and between Pioneer Drilling Co., Ltd. (now known as Pioneer Drilling Services, Ltd.) and IDM Equipment, Ltd. (Form 10-K for the year ended March 31, 2002 (File No. 1-8182, Exhibit 2.4))

2.4*	-	Asset Purchase Agreement dated the 28th of May, 2002 by and between United Drilling Company, U-D Holdings, L.P. and Pioneer Drilling Services, Ltd., a Texas limited partnership. (Form 10-K for the year ended March 31, 2002 (File No. 1-8182, Exhibit 2.5))

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

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

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

4.1*	-	Debenture Agreement Dated July 3, 2002 by and between WEDGE Energy Service, L.L.C. and Pioneer Drilling Company (Form 8-K filed July 18, 2002 (File No. 1-8182, Exhibit 4.1)).

4.2*	-	Debenture Purchase Agreement dated July 3, 2002 by and between WEDGE Energy Services, L.L.C. and Pioneer Drilling Company (Form 8-K filed July 18, 2002 (File No. 1-8182, Exhibit 4.2)).

4.3*	-	Subordination Agreement dated July 3, 2002 by and between The Frost National Bank, WEDGE Energy Services, L.L.C., Pioneer Drilling Company and Pioneer Drilling Services, Ltd. (Form 8-K filed July 18, 2002 (File No 1-8182, Exhibit 4.3)).

4.4 *	-	First Amendment to Debenture Purchase Agreement dated December 23, 2002 between WEDGE Energy Services, L.L.C., and Pioneer Drilling Company (Form 10-Q for quarter ended December 31, 2002 (File No. 1-8182, Exhibit 4.18)).

4.5*	-	First Amendment to Debenture Agreement dated December 23, 2002 between William H.White and Pioneer Drilling Company (Form 10-Q for quarter ended December 31, 2002 (File No. 1-8182, Exhibit 4.19)).

4.6*	-	Term Loan and Security Agreement dated December 23, 2002 by and between Pioneer Drilling Services, Ltd. and Merrill Lynch Capital, a division of Merrill Lynch Business Financial Services, Inc. (Form 8-K filed January 3, 2003 (File No. 1-8182, Exhibit 5.1)).

4.7*	-	Collateral Installment Note dated December 23, 2002 by and between Pioneer Drilling Services, Ltd. and Merrill Lynch Capital, a division of Merrill Lynch Business Financial Services, Inc. (Form 8-K filed January 3, 2003 (File No. 1-8182, Exhibit 5.2)).

4.8*	-	Consolidated Loan Agreement dated March 18, 2003 between Pioneer Drilling Services, Ltd, Pioneer Drilling Company and The Frost National Bank. (Form 10-K for year ended March 31, 2003 (File No. 1-8182, Exhibit 4.9)).

4.9*	-	Promissory Note dated March 18, 2003 between Pioneer Drilling Services, Ltd. and The Frost National Bank. (Form 10-K for year ended March 31, 2003 (File No. 1-8182, Exhibit 4.10)).

4.10*	-	Revolving Promissory Note dated March 18, 2003 between Pioneer Drilling Services, Ltd. and The Frost National Bank. (Form 10-K for year ended March 31, 2003 (File No. 1-8182, Exhibit 4.11)).

4.11*	-	Amendment No. 1 dated March 31, 2003 to the Term Loan and Security Agreement dated December 23, 2002 between Pioneer Drilling Services, Ltd. and Merrill Lynch Capital, a division of Merrill Lynch Business Financial Services, Inc. (Form 10-K for year ended March 31, 2003 (File No. 1-8182, Exhibit 4.12)).

4.12*	-	Amended and Restated Loan Agreement dated December 15, 2003, between Pioneer Drilling Services, Ltd., Pioneer Drilling Company and The Frost National Bank (Form 10-Q for the quarter ended December 31, 2003 (File No. 1-8182, Exhibit 4.1)).

4.13*	-	First Amendment to Amended and Restated Loan Agreement dated January 29, 2004 between Pioneer Drilling Services, Ltd., Pioneer Drilling Company and The Frost National Bank (Form 10-Q for the quarter ended December 31, 2003 (File No. 1-8182, Exhibit 4.1)).

4.14*	-	Common Stock Purchase agreement dated March 31, 2003, between Pioneer Drilling Company and Chesapeake Energy Corporation (Form 8-K filed March 31, 2003 (File No. 1-8182, Exhibit 4.1)).

4.15*	-	Registration Rights Agreement dated March 31, 2003, among Pioneer Drilling Company, WEDGE Energy Service, L.L.C., William H. White, an individual, and Chesapeake Energy Corporation (Form 8-K filed March 31, 2003 (File No. 1-8182, Exhibit 4.2)).

4.16*	-	Note Modification Agreement dated September 29, 2003, between Pioneer Drilling Services, Ltd. and The Frost National Bank (Form 8-K filed November 6, 2003 (File No. 1-8182, Exhibit 4.3)).

4.17*	-	Form of Certificate representing Common Stock of Pioneer Drilling Company (Form S-8 filed November 18, 2003 (Reg. No. 333-110569, Exhibit 4.3)).

4.18*	-	Form of Purchase Agreement dated February 13, 2004 between Pioneer Drilling Company and the several purchasers (Form S-3 filed February 24, 2004 (Reg. No. 333-113036, Exhibit 4.1)).

10.1*	-	Voting Agreement dated June 18, 1997 between Robert R. Marmor, William D. Hibbetts, Wm. Stacy Locke, Alvis L. Dowell, Charles B Tichenor and Richard Phillips (Form 10-K for the year ended March 31, 2001 (File No. 1-8182, Exhibit 9.1)).

10.2*	-	Voting Agreement dated May 11, 2000 between Wm. Stacy Locke, Michael E. Little, Pioneer Drilling Company and WEDGE Energy Services, L.L.C. (Form 10-K for the year ended March 31, 2001 (File No. 1-8182, Exhibit 9.2)).

10.3*	-	Voting Agreement dated October 9, 2001 between Pioneer Drilling Company and WEDGE Energy Service, L.L.C. (See Section 1.3 of the Debenture Purchase Agreement referenced above as Exhibit 4.5). (Form 10-K for year ended March 31, 2003 (File No. 1-8182, Exhibit 10.3)).

10.4+*	-	Executive Employment Agreement dated May 1, 1995 between Pioneer Drilling Company and Wm. Stacy Locke (Form 10-K for the year ended March 31, 2001 (File No. 1-8182, Exhibit 10.1+)).

10.5+*	-	Second Amendment to Executive Employment Agreement dated August 21, 2000 between Pioneer Drilling Company and Wm. Stacy Locke (Form 10-K for the year ended March 31, 2001 (File No. 1-8182, Exhibit 10.4+)).

10.6+*	-	Pioneer Drilling Company’s 1995 Stock Plan and form of Stock Option Agreement (Form 10-K for the year ended March 31, 2001 (File No. 1-8182, Exhibit 10.5+)).

10.7+*	-	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. 1-8182, 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. 1-8182, 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. 1-8182, 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. 1-8182, Exhibit 10.10)).

10.11*	-	Contract dated May 5, 2000 between IRI International Corporation and Pioneer Drilling Company for the purchase of two drilling rigs (Form 10-K for the year ended March 31, 2001 (File No. 1-8182, Exhibit 10.12)).

10.12*	-	Equipment Lease dated effective the 8th of February, 2002 between Pioneer Drilling Services, Ltd. and International Drilling Services, Inc. (Form 10-K for the year ended March 31, 2002 (File No. 1-8182, Exhibit 10.13)).

10.13*	-	Common Stock Purchase Agreement dated March 31, 2003, between Pioneer Drilling Company and Chesapeake Energy Corporation (Form 8-K filed March 31, 2003 (File No. 1-8182, Exhibit 4.1)).

10.14*	-	Pioneer Drilling Company 2003 Stock Plan (Form S-8 filed November 18, 2003 (File No. 333-110569, Exhibit 4.4)).

21.1	-	Subsidiaries of Pioneer Drilling Company.

23.1	-	Consent of KPMG LLP.

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

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

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

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

* Incorporated by reference to the filing indicated.

+ Management contract or compensatory plan or arrangement.

(b) Reports on Form 8-K. On February 5, 2004 we filed a current report on Form 8-K (information furnished not filed) relating to the press release we issued on February 5, 2004 with respect to our results of operations for the third quarter (ended December 31, 2003) of our fiscal year ending March 31, 2004. On February 24, 2004, we filed a current report on Form 8-K relating to our sale of 4,400,000 shares of our common stock on February 20, 2004 at $5.40 per share in a private placement for $23.8 million in gross proceeds and the press release we issued on February 23, 2004 for the private placement.

SIGNATURES

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

	PIONEER DRILLING COMPANY

June 28, 2004	By:	/s/ Wm. Stacy Locke
		Wm. Stacy Locke
		Chief Executive Officer and President

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

Signature	Title	Date

/s/ Michael E. Little
Michael E. Little	Chairman	June 28, 2004

/s/ Wm. Stacy Locke
Wm. Stacy Locke	President, Chief Executive Officer and Director (Principal Executive Officer)	June 28, 2004

/s/ William D. Hibbetts
William D. Hibbetts	Senior Vice President, Chief Financial Officer and Secretary (Principal Financial and Accounting Officer)	June 28, 2004

/s/ C. John Thompson
C. John Thompson	Director	June 28, 2004


/s/ James M. Tidwell
James M. Tidwell	Director	June 28, 2004


/s/ C. Robert Bunch
C. Robert Bunch	Director	June 28, 2004


/s/ Dean A. Burkhardt
Dean A. Burkhardt	Director	June 28, 2004


/s/ Michael F. Harness
Michael F. Harness	Director	June 28, 2004

Index To Exhibits

2.1*	-	Asset Purchase Agreement dated February 14, 2001 between Mustang Drilling, Ltd., Michael T. Wilhite, Sr., Andrew D. Mills and Michael T. Wilhite, Jr. (Form 10-K for the year ended March 31, 2001 (File No. 1-8182, Exhibit 2.2)).

2.2*	-	Stock Purchase Agreement dated July 21, 2000 between Pioneer Drilling Company and the Shareholders of Pioneer Drilling Co., Inc. (Form 10-K for the year ended March 31, 2001 (File No. 1-8182, Exhibit 2.3)).

2.3*	-	Purchase Agreement dated the 30th of April 2001 by and between Pioneer Drilling Co., Ltd. (now known as Pioneer Drilling Services, Ltd.) and IDM Equipment, Ltd. (Form 10-K for the year ended March 31, 2002 (File No. 1-8182, Exhibit 2.4))

2.4*	-	Asset Purchase Agreement dated the 28th of May, 2002 by and between United Drilling Company, U-D Holdings, L.P. and Pioneer Drilling Services, Ltd., a Texas limited partnership. (Form 10-K for the year ended March 31, 2002 (File No. 1-8182, Exhibit 2.5))

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

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

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

4.1*	-	Debenture Agreement Dated July 3, 2002 by and between WEDGE Energy Service, L.L.C. and Pioneer Drilling Company (Form 8-K filed July 18, 2002 (File No. 1-8182, Exhibit 4.1)).

4.2*	-	Debenture Purchase Agreement dated July 3, 2002 by and between WEDGE Energy Services, L.L.C. and Pioneer Drilling Company (Form 8-K filed July 18, 2002 (File No. 1-8182, Exhibit 4.2)).

4.3*	-	Subordination Agreement dated July 3, 2002 by and between The Frost National Bank, WEDGE Energy Services, L.L.C., Pioneer Drilling Company and Pioneer Drilling Services, Ltd. (Form 8-K filed July 18, 2002 (File No 1-8182, Exhibit 4.3)).

4.4 *	-	First Amendment to Debenture Purchase Agreement dated December 23, 2002 between WEDGE Energy Services, L.L.C., and Pioneer Drilling Company (Form 10-Q for quarter ended December 31, 2002 (File No. 1-8182, Exhibit 4.18)).

4.5*	-	First Amendment to Debenture Agreement dated December 23, 2002 between William H.White and Pioneer Drilling Company (Form 10-Q for quarter ended December 31, 2002 (File No. 1-8182, Exhibit 4.19)).

4.6*	-	Term Loan and Security Agreement dated December 23, 2002 by and between Pioneer Drilling Services, Ltd. and Merrill Lynch Capital, a division of Merrill Lynch Business Financial Services, Inc. (Form 8-K filed January 3, 2003 (File No. 1-8182, Exhibit 5.1)).

4.7*	-	Collateral Installment Note dated December 23, 2002 by and between Pioneer Drilling Services, Ltd. and Merrill Lynch Capital, a division of Merrill Lynch Business Financial Services, Inc. (Form 8-K filed January 3, 2003 (File No. 1-8182, Exhibit 5.2)).

4.8*	-	Consolidated Loan Agreement dated March 18, 2003 between Pioneer Drilling Services, Ltd, Pioneer Drilling Company and The Frost National Bank. (Form 10-K for year ended March 31, 2003 (File No. 1-8182, Exhibit 4.9)).

4.9*	-	Promissory Note dated March 18, 2003 between Pioneer Drilling Services, Ltd. and The Frost National Bank. (Form 10-K for year ended March 31, 2003 (File No. 1-8182, Exhibit 4.10)).

4.10*	-	Revolving Promissory Note dated March 18, 2003 between Pioneer Drilling Services, Ltd. and The Frost National Bank. (Form 10-K for year ended March 31, 2003 (File No. 1-8182, Exhibit 4.11)).

4.11*	-	Amendment No. 1 dated March 31, 2003 to the Term Loan and Security Agreement dated December 23, 2002 between Pioneer Drilling Services, Ltd. and Merrill Lynch Capital, a division of Merrill Lynch Business Financial Services, Inc. (Form 10-K for year ended March 31, 2003 (File No. 1-8182, Exhibit 4.12)).

4.12*	-	Amended and Restated Loan Agreement dated December 15, 2003, between Pioneer Drilling Services, Ltd., Pioneer Drilling Company and The Frost National Bank (Form 10-Q for the quarter ended December 31, 2003 (File No. 1-8182, Exhibit 4.1)).

4.13*	-	First Amendment to Amended and Restated Loan Agreement dated January 29, 2004 between Pioneer Drilling Services, Ltd., Pioneer Drilling Company and The Frost National Bank (Form 10-Q for the quarter ended December 31, 2003 (File No. 1-8182, Exhibit 4.1)).

4.14*	-	Common Stock Purchase agreement dated March 31, 2003, between Pioneer Drilling Company and Chesapeake Energy Corporation (Form 8-K filed March 31, 2003 (File No. 1-8182, Exhibit 4.1)).

4.15*	-	Registration Rights Agreement dated March 31, 2003, among Pioneer Drilling Company, WEDGE Energy Service, L.L.C., William H. White, an individual, and Chesapeake Energy Corporation (Form 8-K filed March 31, 2003 (File No. 1-8182, Exhibit 4.2)).

4.16*	-	Note Modification Agreement dated September 29, 2003, between Pioneer Drilling Services, Ltd. and The Frost National Bank (Form 8-K filed November 6, 2003 (File No. 1-8182, Exhibit 4.3)).

4.17*		Form of Certificate representing Common Stock of Pioneer Drilling Company (Form S-8 filed November 18, 2003 (Reg. No. 333-110569, Exhibit 4.3)).

4.18*		Form of Purchase Agreement dated February 13, 2004 between Pioneer Drilling Company and the several purchasers (Form S-3 filed February 24, 2004 (Reg. No. 333-113036, Exhibit 4.1)).

10.1*	-	Voting Agreement dated June 18, 1997 between Robert R. Marmor, William D. Hibbetts, Wm. Stacy Locke, Alvis L. Dowell, Charles B Tichenor and Richard Phillips (Form 10-K for the year ended March 31, 2001 (File No. 1-8182, Exhibit 9.1)).

10.2*	-	Voting Agreement dated May 11, 2000 between Wm. Stacy Locke, Michael E. Little, Pioneer Drilling Company and WEDGE Energy Services, L.L.C. (Form 10-K for the year ended March 31, 2001 (File No. 1-8182, Exhibit 9.2)).

10.3*	-	Voting Agreement dated October 9, 2001 between Pioneer Drilling Company and WEDGE Energy Service, L.L.C. (See Section 1.3 of the Debenture Purchase Agreement referenced above as Exhibit 4.5). (Form 10-K for year ended March 31, 2003 (File No. 1-8182, Exhibit 10.3)).

10.4+*	-	Executive Employment Agreement dated May 1, 1995 between Pioneer Drilling Company and Wm. Stacy Locke (Form 10-K for the year ended March 31, 2001 (File No. 1-8182, Exhibit 10.1+)).

10.5+*	-	Second Amendment to Executive Employment Agreement dated August 21, 2000 between Pioneer Drilling Company and Wm. Stacy Locke (Form 10-K for the year ended March 31, 2001 (File No. 1-8182, Exhibit 10.4+)).

10.6+*	-	Pioneer Drilling Company’s 1995 Stock Plan and form of Stock Option Agreement (Form 10-K for the year ended March 31, 2001 (File No. 1-8182, Exhibit 10.5+)).

10.7+*	-	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. 1-8182, 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. 1-8182, 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. 1-8182, 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. 1-8182, Exhibit 10.10)).


10.11*	-	Contract dated May 5, 2000 between IRI International Corporation and Pioneer Drilling Company for the purchase of two drilling rigs (Form 10-K for the year ended March 31, 2001 (File No. 1-8182, Exhibit 10.12)).

10.12*	-	Equipment Lease dated effective the 8th of February, 2002 between Pioneer Drilling Services, Ltd. and International Drilling Services, Inc. (Form 10-K for the year ended March 31, 2002 (File No. 1-8182, Exhibit 10.13)).

10.13*	-	Common Stock Purchase Agreement dated March 31, 2003, between Pioneer Drilling Company and Chesapeake Energy Corporation (Form 8-K filed March 31, 2003 (File No. 1-8182, Exhibit 4.1)).

10.14*	-	Pioneer Drilling Company 2003 Stock Plan (Form S-8 filed November 18, 2003 (File No. 333-110569, Exhibit 4.4)).

21.1	-	Subsidiaries of Pioneer Drilling Company.

23.1	-	Consent of KPMG LLP.

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

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

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

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

* Incorporated by reference to the filing indicated.

+ Management contract or compensatory plan or arrangement.