UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D. C. 20549

FORM 10-K

(Mark one)	x	ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
		For the fiscal year ended March 31, 2005

	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 ý No o

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, 2004) was $189,796,564, based on the last sales price of the registrant’s common stock reported on the American Stock Exchange on that date.

As of May 20, 2005, there were 45,931,646 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 2005 Annual Meeting of Shareholders are incorporated by reference into Part III of this report.

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 select oil and natural gas production regions in the United States. Our company was incorporated in 1979 as the successor to a business that had been operating since 1968. We conduct our operations through our principal operating subsidiary, Pioneer Drilling Services, Ltd. Our common stock trades on the American Stock Exchange under the symbol “PDC.”

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

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

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

During that same period, we also added nine rigs to our fleet through construction of new rigs and construction of rigs from new and used components. In addition, in August 2003, we acquired a rig that had been operating in Trinidad and integrated it into our operations in Texas. As of May 20, 2005, our rig fleet consisted of 50 operating drilling rigs, 15 of which were operating in South Texas, 17 of which were operating in East Texas, four of which were operating in North Texas, five of which were operating in western Oklahoma and nine of which were operating in the Rocky Mountain region. We are also constructing two additional rigs, which we expect to add to our fleet in June and August of 2005.

We conduct our operations primarily in South, East and North Texas, western Oklahoma and the Rocky Mountains. During fiscal 2005, substantially all the wells we drilled for our customers were drilled in search of natural gas. Although we have recently diversified our operations somewhat with the acquisition of drilling rigs from Wolverine Drilling, with five of those rigs employed in search of oil in the Williston Basin of the Rocky Mountains, our customers remain primarily focused on drilling for natural gas. Natural gas reserves are typically found in deep geological formations and generally require premium equipment and quality crews to drill the wells.

For many years, the United States contract land drilling services industry has been characterized by an oversupply of drilling rigs and a large number of drilling contractors. Since 1996, however, there has been significant consolidation within the industry. We believe continued consolidation in the industry will generate more stability in dayrates, even during industry downturns. However, although

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

Our Strategy

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

• continuing to own and operate a high-quality fleet of land drilling rigs, primarily in active natural gas drilling markets;

• acquiring high-quality rigs capable of generating our targeted returns on investment;

• positioning ourselves to maximize rig utilization and dayrates;

• training and maintaining high-quality, experienced crews; and

• maintaining the recent improvements in our safety record.

Drilling Equipment

General

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

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

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

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

Drilling fluid, often called mud, is a mixture of clays, chemicals and water or oil, which is carefully formulated for the particular well being drilled. Drilling mud accounts for a major portion of the equipment and cost of drilling a well. Bulk storage of drilling fluid materials,

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

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

Our Fleet of Drilling Rigs

As of May 26, 2005, our rig fleet consists of 50 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,
	2005		2004		2003		2002		2001		2000
Average number of rigs for the period	40.1		27.3		22.3		18.0		10.5		6.6
Average utilization rate	96	%	88	%	79	%	82	%	91	%	66	%

The following table sets forth information regarding our drilling fleet:

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

1	Cabot 750E	9,500	South Texas	Electric	750
2	Cabot 750E	9,500	South Texas	Electric	750
3	National 110 UE	18,000	South Texas	Electric	1,500
4	RMI 1000 E	15,000	South Texas	Electric	1,000
5	Brewster N-46	12,000	North Texas	Mechanical	1,000
6	Brewster DH-4610	13,000	East Texas	Mechanical	750
7	National 110 UE	18,000	South Texas	Electric	1,500
8	National 110 UE	18,000	East Texas	Electric	1,500
9	Gardner-denver 500	11,000	East Texas	Mechanical	700
10	Brewster N-46	12,000	East Texas	Mechanical	1,000
11	Brewster N-46	12,000	South Texas	Mechanical	1,000
12	IRI Cabot 900	10,500	South Texas	Mechanical	900
14	Brewster N-46	12,000	South Texas	Mechanical	1,000
15	Cabot 750	9,500	South Texas	Mechanical	750
16	Cabot 750	9,500	South Texas	Mechanical	750
17	Ideco 725	12,000	East Texas	Mechanical	800
18	Brewster N-75	12,000	East Texas	Mechanical	1,000
19	Brewster N-75	12,000	East Texas	Mechanical	1,000
20	BDW 800	13,500	East Texas	Mechanical	1,000
21	National 110 UE	18,000	South Texas	Electric	1,500
22	Ideco 725	12,000	East Texas	Mechanical	800
23	Ideco 725	12,000	North Texas	Mechanical	800
24	National 110 UE	18,000	South Texas	Electric	1,500
25	National 110 UE	18,000	East Texas	Electric	1,500
26	Oilwell 840 E	18,000	South Texas	Electric	1,500
27	IRI Cabot 1200 M	13,500	South Texas	Mechanical	1,300
28	Oilwell 760 E	15,000	South Texas	Electric	1,000
29	Brewster N-46	12,000	North Texas	Mechanical	1,000
30	Mid Cont U36A	11,000	North Texas	Mechanical	750

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

31	Brewster N-7	11,500	East Texas	Mechanical	750
32	Brewster N-75	13,500	East Texas	Mechanical	1,000
33	Brewster N-95	13,500	East Texas	Mechanical	1,200
34	All-Rig 900	12,000	East Texas	Mechanical	900
35	RMI 1000	13,500	East Texas	Mechanical	1,000
36	Brewster N-7	11,500	East Texas	Mechanical	750
37	Brewster N-95	13,500	East Texas	Mechanical	1,200
38	Ideco H-1000 E	11,000	Utah	Electric	1,000
39	National 370	7,500	North Dakota	Mechanical	550
40	National 370	8,500	North Dakota	Mechanical	550
41	National 610	11,000	Utah	Mechanical	750
42	Brewster N-46	12,500	North Dakota	Mechanical	1,000
43	National 610	11,000	North Dakota	Mechanical	750
44	National 80B	15,000	North Dakota	Mechanical	1,000
45	Brewster N-4	7,500	North Dakota	Mechanical	500
46	RMI 550	9,000	Oklahoma	Mechanical	550
47	Ideco 525	8,000	Oklahoma	Mechanical	600
48	National 370	8,500	Oklahoma	Mechanical	550
49	Ideco 525	9,000	Oklahoma	Mechanical	600
50	Ideco 725	11,000	Oklahoma	Mechanical	800
54	RMI 1000	14,000	Utah	Mechanical	1,000

As of May 20, 2005, we owned a fleet of 58 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,
	2005	2004	2003
Daywork	264	205	119
Turnkey	134	92	78
Footage	48	13	5
Total number of wells	446	310	202

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 2005, we drilled wells for 102 different customers, compared to 83 customers in fiscal 2004 and 64 customers 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 2005
Chinn Exploration	7	%
Goodrich Petroleum Corp.	5	%
Medicine Bow Energy Corporation	5	%

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	%

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

From time to time we also enter into informal, nonbinding commitments with our customers to provide drilling rigs for future periods at specified rates plus fuel and mobilization charges, if applicable, and escalation provisions. This practice is customary in the contract land drilling services business during times of tightening rig supply. We currently have thirteen contracts of six months to two years in duration, including the contracts for the two rigs currently under construction.

Competition

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

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

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

• the mobility and efficiency of the rigs;

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

• the safety records of the rigs;

• the offering of ancillary services; and

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

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

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

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

• better withstand industry downturns;

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

• better retain skilled rig personnel; and

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

Raw Materials

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

Operating Risks and Insurance

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

• blowouts;

• fires and explosions;

• loss of well control;

• collapse of the borehole;

• lost or stuck drill strings; and

• damage or loss from natural disasters.

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

• suspension of drilling operations;

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

• personal injury and loss of life;

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

• environmental damage.

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

Facilities

We own our headquarters building in San Antonio, Texas and our office building in Kenmare, North Dakota. We also own:

• a 15-acre division office, rig storage and maintenance yard in Corpus Christi, Texas;

• a six-acre division office, storage and maintenance yard in Henderson, Texas;

• a 4-acre trucking department office, storage and maintenance yard in Kilgore, Texas;

• a 17-acre rig storage and maintenance yard in Woodward, Oklahoma; and

• a 4.7-acre division rig storage and maintenance yard in Kenmare, North Dakota.

We lease:

• a 43-acre division office and storage yard in Decatur, Texas, at a cost of $800 per month, pursuant to a lease extending through September 2006;

• a trucking department office, storage and maintenance yard in Alice, Texas, at a cost of $4,500 per month, pursuant to a lease extending through July 2006;

• a division office in Denver, Colorado, at a cost of $1,210 per month, pursuant to a lease extending through June 2005;

• a yard office in Kenmare, North Dakota, at a cost of $700 per month, pursuant to a lease extending through March 31, 2006; and

• part of a 2.2-acre division office and storage yard in Vernal, Utah, at a cost of $2,000 per month, pursuant to a lease extending through October 2005.

In four to six months, we will take over the entire division office and storage yard in Vernal, Utah and will enter into a two year lease at a cost of $6,000 per month.

In July 2005, we will be moving our corporate headquarters to new office space in San Antonio, Texas. We have entered into a 102-month lease with monthly payments of approximately $12,300 for the first two years increasing to an average of approximately $20,000 per month thereafter. We plan to sell our current corporate headquarters building in San Antonio, Texas.

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,” “intend,” “seek,” “will,” “should,” “goal” or other words that convey the uncertainty of future events or outcomes. These forward-looking statements speak only as of the date 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 rely on them unduly. We have based these forward-looking statements on our current expectations and assumptions about future events. While our management considers these expectations and assumptions to be reasonable, they are inherently subject to significant business, economic, competitive, regulatory and other risks, contingencies and uncertainties, most of which are difficult to predict and many of which are beyond our control. These risks, contingencies and uncertainties relate to, among other matters, the following:

• general economic and business conditions and industry trends;

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

• levels and volatility of oil and gas prices;

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

• the highly competitive nature of our business;

• the success or failure of our acquisition strategy, including our ability to finance acquisitions and manage growth;

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

• the continued availability of qualified personnel; and

• changes in, or our failure or inability to comply with, 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 contained in this report or elsewhere. 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;

• the rate of decline of existing and new oil and gas reserves;

• available pipeline and other oil and gas transportation capacity;

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

• the overall supply and demand for oil and gas.

Risks Relating to Our Business

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

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

Our acquisition strategy 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. For example, since March 31, 2003, our rig fleet has increased from 24 to 50 drilling rigs, primarily as a result of acquisitions. 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.

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

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

We encounter substantial competition from other drilling contractors. Our primary market areas of 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 our financial position and our results of operation.

We have historically derived a significant portion of our revenues from turnkey drilling contracts and we expect that they will represent a significant component of our future revenues. The occurrence of uninsured or under-insured losses or operating cost overruns on our turnkey jobs could have a material adverse effect on our financial position and results of operations. Under a typical turnkey drilling contract, we agree to drill a well for our customer to a specified depth and under specified conditions for a fixed price. We provide technical expertise and engineering services, as well as most of the equipment and drilling supplies required to drill the well. We often subcontract for related services, such as the provision of casing crews, cementing and well logging. Under typical turnkey drilling arrangements, we do not receive progress payments and are paid by our customer only after we have performed the terms of the drilling contract in full. For these reasons, the risk to us under a turnkey drilling contract is substantially greater than for a well drilled on a daywork basis, because we must assume most of the risks associated with drilling operations that the operator generally assumes under a daywork contract, including the risks of blowout, loss of hole, stuck drill pipe, machinery breakdowns, abnormal drilling conditions and risks associated with subcontractors’ services, supplies, cost escalations and personnel. Similar to our turnkey contracts, under a footage contract we assume most of the risks associated with drilling operations that the operator generally assumes under a daywork contract.

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

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

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

• blowouts;

• fires and explosions;

• loss of well control;

• collapse of the borehole;

• lost or stuck drill strings; and

• damage or loss from natural disasters.

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

• suspension of drilling operations;

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

• personal injury and loss of life;

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

• environmental damage.

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

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

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

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

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

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

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

• environmental quality;

• pollution control;

• remediation of contamination;

• preservation of natural resources; and

• worker safety.

Our operations are subject to stringent laws and regulations relating to containment, disposal and controlling the discharge of hazardous oilfield waste and other nonhazardous waste material into the environment, requiring removal and cleanup under certain circumstances, or otherwise relating to the protection of the environment. In addition, our operations are often conducted in or near ecologically sensitive areas, such as wetlands, which are subject to special protective measures and which may expose us to additional operating costs and liabilities for accidental discharges of oil, 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 Organizational Documents

Our largest shareholder and our management control approximately 20% of our common stock, and their interests may conflict with those of our other shareholders.

As of May 20, 2005, our largest shareholder, Chesapeake Energy Corporation, beneficially owned 16.78% of our outstanding common stock, and together with our officers and directors as a group beneficially owned a total of 20.46% of our outstanding common stock. For each shareholder or group of shareholders, beneficial ownership includes shares of our common stock issuable on exercise of outstanding stock options held by that shareholder or group of shareholders. In some circumstances, if these shareholders were to act in concert, they would be able to exercise substantial control over our affairs. The interests of Chesapeake 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, 2005 through May 20, 2005, the average daily trading volume of our common stock as reported by the American Stock Exchange was 366,154 shares. There can be no assurance that a more active trading market in our common stock will 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 and comparable securities of other contract drilling service providers.

The market price of our common stock has been, and may continue to be, volatile. For example, during our 2005 fiscal year, the trading price of our common stock ranged from $5.60 to $14.21 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 organizational documents could delay or prevent a change in control of our company, even if that change would be beneficial to our shareholders. Our articles of incorporation and bylaws contain provisions that may make acquiring control of our company difficult, including:

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

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

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

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

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 2005.

PART II

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

As of May 20, 2005, 45,931,646 shares of our common stock were outstanding, held by approximately 561 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, 2005:
First Quarter	$	5.60	$	7.99
Second Quarter	6.75		8.90
Third Quarter	7.63		10.50
Fourth Quarter	9.05		14.21

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

The last reported sales price for our common stock on the American Stock Exchange on May 27, 2005 was $14.00 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, 2005:

Plan category	Number of securities to be issued upon exercise of outstanding options, warrants and rights	Weighted-average exercise price per share of outstanding options, warrants and rights		Number of securities remaining available for future issuance under equity compensation plans (excluding securities reflected in column (a))
	(a)	(b)		(c)
Equity compensation plans approved by security holders	2,005,000	$	5.30	1,906,413

Equity compensation plans not approved by security holders	—	—		—
Total	2,005,000	$	5.30	1,906,413

Recent Sales of Unregistered Securities

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

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,
	2005		2004			2003			2002		2001
	(In thousands, except per share amounts)

Contract drilling revenues	$	185,246	$	107,876		$	80,183		$	68,627	$	50,345
Income (loss) from operations	18,774		438			(4,943		)	11,201		3,803
Income (loss) before income taxes	17,161		(2,216		)	(7,305		)	9,737		3,838
Preferred dividends	—		—			—			93		275
Net earnings (loss) applicable to common stockholders	10,812		(1,790		)	(5,086		)	6,225		2,428
Earnings (loss) per common share-basic	0.31		(0.08		)	(0.31		)	0.41		0.22
Earnings (loss) per common share-diluted	0.30		(0.08		)	(0.31		)	0.35		0.19
Long-term debt and capital lease obligations, excluding current installments	13,445		44,892			45,855			26,119		10,056
Shareholders' equity	221,615		70,836			47,672			33,343		17,827
Total assets	276,009		143,731			119,694			83,450		56,493
Capital expenditures	80,388		44,845			33,589			27,597		41,628

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 selected oil and natural gas production regions in the United States. Our company was incorporated in 1979 as the successor to a business that had been operating since 1968. We conduct our operations through our principal operating subsidiary, Pioneer Drilling Services, Ltd. We are an oil and gas services company. We do not invest in oil and natural gas properties. The drilling activity of our customers is highly dependent on the current price of oil and natural gas.

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

Since September 1999, we have significantly expanded our fleet of drilling rigs through acquisitions and the construction of new and refurbished rigs. As of March 31, 2005 our rig fleet consisted of 50 land drilling rigs that drill in depth ranges between 6,000 and 18,000 feet. Fifteen of our rigs are operating in South Texas, 17 in East Texas, four in North Texas, five in western Oklahoma and nine in the Rocky Mountains. We actively market all of these rigs. We completed construction of our 50^th rig in late March 2005 and began moving it to its first drilling location. We anticipate continued growth of our rig fleet in fiscal year 2006. We are currently constructing two 1000 horsepower electric rigs from new and used components.

We earn our revenues by drilling oil and gas wells for our customers. We obtain our contracts for drilling oil and gas wells either through competitive bidding or through direct negotiations with customers. Our drilling contracts generally provide for compensation on either a daywork, turnkey or footage basis. Contract terms 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. However, we currently have thirteen contracts with terms of six months to two years in duration, including the contracts for the two rigs currently under construction.

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.

For the three years ended March 31, 2005, our rig utilization, revenue days and number of rigs were as follows:

	Years Ended March 31,
	2005		2004		2003
Utilization Rates	96	%	88	%	79	%
Revenue Days	13,894		8,764		6,419
Number of rigs	50		35		24

The reasons for the increase in the number of revenue days in 2005 over 2004 and 2003 are the increase in size of our rig fleet and the improvement in our overall rig utilization rate due to improved market conditions. For 2006, we anticipate continued growth in revenue days and utilization rates comparable to 2005.

In addition to high commodity prices, we attribute our relatively high utilization rates to a strong sales effort, quality equipment, good field and operations personnel, a disciplined safety approach, and our generally successful performance of turnkey operations. Turnkey contracts currently account for approximately 12% of our contracts. Turnkey contracts provide us with the opportunity to keep our rigs working in periods of lower demand and improve our profitability, but at an increased risk. During periods of reduced demand for drilling

rigs, turnkey operating profit per revenue day has been greater than daywork operating profit; however, occasionally, a turnkey contract will be unprofitable if the contract cannot be completed successfully without unanticipated complications.

We devote substantial resources to maintaining and upgrading our rig fleet. During fiscal 2004, we removed three rigs from service for approximately three weeks each, 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. We are currently performing or have recently performed, between contracts or as necessary, safety and equipment upgrades to the eight rigs we acquired in March 2004 and the 12 rigs we acquired in November and December 2004.

Market Conditions in Our Industry

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

For the three months ended March 31, 2005, the average weekly spot price for West Texas Intermediate crude oil was $49.87, the average weekly spot price for Henry Hub natural gas was $6.39 and the average weekly Baker Hughes land rig count was 1,153. On May 20, 2005, the spot price for West Texas Intermediate crude oil was $46.80, the spot price for Henry Hub natural gas was $6.36 and the Baker Hughes land rig count was 1,202, a 14% increase from 1,056 on May 21, 2004.

The average weekly spot prices of West Texas Intermediate crude oil and Henry Hub natural gas and the average weekly domestic land rig count, per the Baker Hughes land rig count, for each of the previous six years ended March 31, 2005 were:

	Years Ended March 31,
	2005		2004		2003		2002		2001		2000
Oil (West Texas Intermediate)	$	45.04	$	31.47	$	29.27	$	24.31	$	30.40	$	23.23
Natural Gas (Henry Hub)	$	5.99	$	5.27	$	4.24	$	2.96	$	5.27	$	2.46
U.S. Land Rig Count	1,110		964		723		912		841		550

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

Critical Accounting Policies and Estimates

Revenue and cost recognition – We earn our revenues by drilling oil and gas wells for our customers under daywork, turnkey or footage contracts, which usually provide for the drilling of a single well. We recognize revenues on daywork contracts for the days completed based on the dayrate each contract specifies. We recognize revenues from our turnkey and footage contracts on the percentage-of-completion method 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. Under a turnkey contract, we assume most of the risks associated with drilling operations that are 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 as defined in SOP 81-1 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, in the event we were unable to drill to the agreed on depth in breach of the contract, ultimate recovery of that value would be subject to negotiations with the customer and the possibility of litigation.

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 net 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, 2005, would have resulted in a corresponding decrease in our net earnings of approximately $1,427,000 for our fiscal year ended March 31, 2005.

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 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 year 2005, we experienced losses on 17 of the 182 turnkey and footage contracts completed, with losses exceeding $25,000 on ten contracts and losses exceeding $100,000 on four contracts. We are more likely to encounter losses on turnkey and footage contracts in years in which revenue rates are lower for all types of contracts. During periods of reduced demand for drilling rigs, our overall profitability on turnkey and footage contracts has historically exceeded our profitability on daywork contracts.

Revenues and costs during a reporting period could be affected for contracts in progress at the end of a reporting period which have not been completed before our financial statements for that period are released. All of our turnkey contracts in progress at March 31, 2005 were completed prior to the release of the financial statements included in this report. At March 31, 2005 our contract drilling in progress totaled approximately $5,365,000. Of that amount accrued, turnkey and footage contract revenues were approximately $2,344,000. The remaining balance of approximately $3,021,000 relates to the revenue recognized but not yet billed on daywork contracts in progress at March 31, 2005. At March 31, 2004, drilling in progress totaled $9,131,000 of which $7,683,000 related to turnkey contracts and $1,488,000 related to daywork contracts.

We estimate an allowance for doubtful accounts based on the creditworthiness of our customers as well as general economic conditions. We evaluate the creditworthiness of our customers based on information obtained from major industry suppliers, current prices of oil and gas and any past experience we have with the customer. Consequently, an adverse change in those factors could affect our estimate of our allowance for doubtful accounts. In some instances, we require new customers to establish escrow accounts or make prepayments. We typically invoice our customers at 15-day intervals during the performance of daywork contracts and upon completion of the daywork contract. Turnkey and footage contracts are invoiced upon completion of the contract. Our typical contract provides for payment of invoices in 10 to 30 days. We generally do not extend payment terms beyond 30 days and have not extended payment terms beyond 60 days for any of our contracts in the last three fiscal years. We established an allowance for doubtful accounts of $352,000 at March 31, 2005, an increase of $242,000 from $110,000 at March 31, 2004.

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

Our other accrued expenses as of March 31, 2005 include an accrual of approximately $1,334,000 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, except in North Dakota where the deductible is $100,000. We accrue for these costs as claims are incurred based on cost estimates established for each claim by the insurance companies providing the administrative services for processing the claims, including an estimate for incurred but not reported claims, estimates for claims paid directly by us, our estimate of the administrative costs associated with these claims and our historical experience with these types of claims. Management evaluates these cost estimates by the insurance companies based on historical claim information and adjusts the accrued claim costs if deemed necessary.

Liquidity and Capital Resources

Sources of Capital Resources

Our rig fleet has grown from eight rigs in August 2000 to 50 rigs as of March 31, 2005. We have financed this growth with a combination of debt and equity financing. We have raised additional equity or used equity for growth eight times since January 2000 and have increased our long-term debt from approximately $3,909,000 at June 30, 2000 to approximately $18,200,000 at March 31, 2005. We plan to continue to grow our rig fleet. At March 31, 2005, our total debt to total capital was approximately 7.6%. Due to the volatility in our industry, we are reluctant to take on substantial additional debt in excess of the $20,000,000 of remaining availability under our acquisition credit facility. However, our ability to continue funding our growth through the issuance of shares of our common stock is uncertain, as our common stock is not heavily traded and the market price for our common stock has been volatile in recent periods.

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

On August 11, 2004, we also sold 4,000,000 shares of our common stock at approximately $6.61 per share, net of underwriters’ commissions, pursuant to a public offering we registered with the SEC. On August 31, 2004, we sold 600,000 additional shares of our common stock at approximately $6.61 per share, net of underwriters’ commissions, pursuant to the underwriters’ exercise of an over-allotment option granted in connection with that public offering.

On March 22, 2005, we sold 6,945,000 shares of our common stock, including shares we sold pursuant to the underwriters’ exercise of an over-allotment option, at approximately $11.78 per share, net of underwriters’ commissions, pursuant to a public offering we registered with the SEC.

business. On March 29, 2005, we repaid $20,000,000 of the borrowings under the acquisition facility. On May 11, 2005, the lenders agreed to an amendment to the acquisition facility to provide us with the ability to draw an additional $20,000,000 for future acquisitions. The remaining approximately $20,0000,000 and $4,175,000 of availability under the acquisition facility and the revolving line and letter of credit facility, respectively, should remain available to us until those facilities mature in October 2006 and October 2005, respectively.

Uses of Capital Resources

In late May 2004 and late December 2004, we completed constructing, primarily from used components, two 1000 horsepower electric drilling rigs, at a cost of approximately $5,000,000 and $6,500,000, respectively. In late March 2005, we completed the construction, primarily from used components, of a 1000 horsepower mechanical rig, at a cost of approximately $5,700,000.

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

We have also begun constructing, from new and used components, two 1000 horsepower electric rigs at an estimated cost of $6,500,000 each. We expect to place one of these rigs in service in June 2005 and the second in August 2005. As of March 31, 2005, we have incurred approximately $3,300,000 of construction costs on these rigs.

For fiscal year 2006, we project regular rig capital expenditures to be approximately $20,200,000, rig upgrade expenditures to be approximately $9,000,000, transportation equipment capital expenditures of approximately $2,900,000 and other capital expenditures of approximately $1,400,000. These capital expenditures are expected to be funded primarily from operating cash flow in excess of cash flow necessary to meet routine contractual obligations.

For the years ended March 31, 2005 and 2004, the additions to our property and equipment consisted of the following:

	Years Ended March 31,
	2005		2004

Drilling rigs (1)	$	53,341,420	$	34,961,004
Other drilling equipment	22,674,774		7,642,968
Transportation equipment	2,717,181		2,160,838
Other	1,655,108		79,935
	$	80,388,483	$	44,844,745

(1) Includes capitalized interest costs of $86,819 in 2005 and $106,395 in 2004.

Working Capital

Our working capital increased to $76,326,669 at March 31, 2005 from $6,028,018 at March 31, 2004. Our current ratio, which we calculate by dividing our current assets by our current liabilities, was 3.70 at March 31, 2005 compared to 1.27 at March 31, 2004. The principal reason for the increase in our working capital at March 31, 2005 was the approximately $61,300,000 in proceeds, after the payment of $20,000,000 of long-term debt, from the shares of common stock we sold in a public offering on March 22, 2005. Approximately $13,000,000 of the proceeds from that offering will be used for the construction of the two rigs described above. We anticipate that the remaining proceeds will be used for future rig and equipment acquisitions.

Our operations have historically generated sufficient cash flow to meet our requirements for debt service and equipment expenditures (excluding rig and other major equipment acquisitions). However, during periods when a higher percentage of our contracts are turnkey and footage contracts, our short-term working capital needs could increase. The significant improvement in operating cash flow for the year ended March 31, 2005 over March 31, 2004 is due primarily to the approximately $12,600,000 overall improvement in net earnings, components of which are discussed in “Results of Operations.” That improvement was net of approximately $6,900,000 in noncash depreciation and amortization expense. If necessary, we can defer rig upgrades to improve our cash position. We believe our cash generated by operations and our ability to borrow the currently unused portion of our line of credit and letter of credit facility of approximately $4,175,000, which takes into account reductions for approximately $2,825,000 of outstanding letters of credit as of March 31, 2005, should allow us to meet our routine financial obligations for the foreseeable future.

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

	March 31,
	2005		2004		Change
Cash and cash equivalents	$	69,673,279	$	1,815,759	$	67,857,520
Marketable securities	1,000,000		4,550,000		(3,550,000		)
Receivables	26,108,291		10,901,991		15,206,300
Contract drilling	5,364,529		9,130,794		(3,766,265		)
Deferred tax receivable	569,548		285,384		284,164
Prepaid expenses	1,876,843		1,336,337		540,506
Current assets	104,592,490		28,020,265		76,572,225

Current debt	5,415,001		4,423,306		991,695
Accounts payable	15,621,647		13,270,989		2,350,658
Accrued payroll	2,706,623		1,499,151		1,207,472
Income tax payable	195,949		—		195,949
Prepaid drilling contracts	172,750		—		172,750
Accrued expenses	4,153,851		2,798,801		1,355,050
	28,265,821		21,992,247		6,273,574

Working capital	$	76,326,669	$	6,028,018	$	70,298,651

The large cash balance at March 31, 2005 was due to our sale of shares of common stock on March 22, 2005 for net proceeds of approximately $81,300,000, of which $20,000,000 was used to reduce long-term debt and $61,300,000 was in the March 31, 2005 cash balance.

The increase in our receivables at March 31, 2005 from March 31, 2004 was due to our operating 15 additional rigs in the quarter ended March 31, 2005, and an improvement in utilization and revenue rates in the fourth quarter of fiscal year 2005 over fiscal year 2004.

Substantially all our prepaid expenses at March 31, 2005 consisted of prepaid insurance. The increase in prepaid insurance was primarily due to the increase in the size of our drilling rig fleet from 35 rigs at March 31, 2004 to 50 rigs at March 31, 2005.

The increase in payables at March 31, 2005 from March 31, 2004 was primarily due to the increase in the size of our drilling rig fleet.

The increase in accrued payroll was primarily due to the approximately 49% increase in our number of employees and the increase in the number of payroll days included in the accrual from nine days at March 31, 2004 to ten days at March 31, 2005.

The total increase in accrued expenses at March 31, 2005 from March 31, 2004 was due to an increase of approximately $685,000 in the accrual for our insurance deductibles and additional insurance premiums, an increase in bonus accruals of approximately $525,000, an increase in vacation pay accruals of approximately $101,000 and an increase in accrued property taxes of approximately $171,000 due to increases in rig valuations and the size of our rig fleet. These increases were offset by a decrease of approximately $127,000 in other accrued expense items.

Although, we have not been required to make income tax payments for the last three years, it is likely we will be in a current taxable position during fiscal year 2006 due to improving market conditions and the reversal of deferred tax liabilities.

Long-term Debt

Our long-term debt at March 31, 2005 and 2004 consisted of the following:

	2005			2004

Indebtedness incurred under $47,000,000 credit facility, secured by drilling equipment, due in monthly payments of $388,889 plus interest at prime (5.75% at March 31, 2005), with final maturity on December 1, 2007	$	18,077,778		$	—

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 plus 385 basis points, due December 2007 (2)	—			13,119,048

Note payable to Frost National Bank, secured by drilling equipment, due in monthly payments of $107,143 plus interest at prime plus 1.00%, due August 2007 (2)	—			4,392,174

Note payable to Frost National Bank, secured by drilling equipment, due in monthly payments of $42,401, including interest at prime plus 1.0%, beginning April 15, 2004, due March 15, 2007 (2)	—			3,000,000
	18,077,778			48,511,222

Less current installments	(4,666,667		)	(3,724,302		)
	$	13,411,111		$	44,786,920

(1) Wedge Energy Services, LLC (“WEDGE”) held $27,000,000 of the convertible subordinated debentures and William H. White, a former director of our company, held $1,000,000 of the convertible subordinated debentures. The convertible subordinate debentures were converted into 6,496,519 shares of our common stock on August 11, 2004.

(2) These notes were repaid in August and September 2004 with proceeds from our August 2004 common stock offering.

Contractual Obligations

We do not have any routine purchase obligations. However, as of March 31, 2005, we were in the process of constructing two drilling rigs, 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 of the type specified below at March 31, 2005:

	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	$	18,077,778	$	4,666,667	$	13,411,111	$	—	$	—
Capital Lease Obligations	100,265		66,359		33,906		—		—
Operating Lease Obligations	1,991,934		224,873		391,427		472,196		903,438
Total	$	20,169,977	$	4,957,899	$	13,836,444	$	472,196	$	903,438

Debt Requirements

The $18,077,778 amount of indebtedness outstanding under the acquisition facility portion of our new credit facility is due in monthly installments of $388,889 plus interest, based on a 72-month amortization schedule, with all remaining unpaid principal being due on December 1, 2007. All the indebtedness under the acquisition facility bears interest at Frost National Bank’s prime rate (5.75% as of March 31, 2005).

The sum of (1) the draws under and (2) the amount of all outstanding letters of credit issued for our account under the revolving line and letter of credit facility portion of our new credit facility are limited to 75% of our eligible accounts receivable, not to exceed $7,000,000. Therefore, if 75% of our eligible accounts receivable was less than $7,000,000, our ability to draw under this line would be reduced. At March 31, 2005, we had no outstanding advances under this line of credit, outstanding letters of credit were $2,825,000 and 75% of our eligible accounts receivable was approximately $19,084,000. The letters of credit are issued to three workers’ compensation insurance companies to secure possible future claims under the deductibles on these policies. It is our practice to pay any amounts due under these deductibles as they are incurred. Therefore, we do not anticipate that the lenders will be required to fund any draws under these letters of credit. The termination date of the revolving line and letter of credit facility portion of our new credit facility is October 28, 2005.

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

• our failure to make required payments;

• any sale of assets by us not permitted by the credit facility;

• our failure to comply with financial covenants related to a debt to total capitalization ratio not to exceed 0.3 to 1, an operating leverage ratio not to exceed 3 to 1, and a fixed charge coverage ratio of not less than 1.5 to 1;

• our incurrence of additional indebtedness in excess of $3,000,000 not already allowed by the credit facility;

• any event which results in a change in the ownership of at least 40% of all classes of our outstanding capital stock; and

• any payment of cash dividends on our common stock.

The limitation on additional indebtedness described above has not affected our operations or liquidity and we do not expect it to affect our future operations or liquidity, as we expect to continue to generate adequate cash flow from operations to fund our anticipated working capital and other normal cash flow requirements.

Results of Operations

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 least complex for us to perform and involve the least risk. Turnkey contracts are the most difficult to perform and involve much greater risk but provide the opportunity for higher operating profits.

Daywork Contracts. Under daywork drilling contracts, we provide a drilling rig with required personnel to our customer, who supervises the drilling of the well. We are paid based on a negotiated fixed rate per day while the rig is used. During the mobilization period we typically earn a fixed amount of revenue based on the mobilization rate stated in the contract. We attempt to set the mobilization rate at an amount equal to our external costs for the move plus our internal costs during the mobilization period. We begin earning our contracted daywork rate when we begin drilling the well. Occasionally, in periods of increased demand, some of our contracts will provide for the trucking costs to be paid by the customer and we will receive a reduced dayrate during the mobilization period.

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

Statements of Operations Analysis

The following table provides information about our operations for the years ended March 31, 2005, March 31, 2004, and March 31, 2003.

	Years Ended March 31,
	2005			2004			2003
Contract drilling revenues:
Daywork contracts	$	95,997,451		$	50,144,773		$	33,203,385
Turnkey contracts	80,210,813			54,234,756			45,889,585
Footage contracts	9,038,184			3,496,004			1,090,516
Total contract drilling revenues	$	185,246,448		$	107,875,533		$	80,183,486
Contract drilling costs:
Daywork contracts	$	68,415,608		$	42,903,525		$	29,289,493
Turnkey contracts	63,421,106			42,761,928			40,482,547
Footage contracts	6,646,045			2,838,649			1,051,270
Total contract drilling costs	$	138,482,759		$	88,504,102		$	70,823,310

Depreciation and amortization	$	23,090,909		$	16,160,494		$	11,960,387
General and administrative expense	$	4,657,013		$	2,772,730		$	2,232,390
Revenue days by type of contract:
Daywork contracts	8,685			5,626			3,681
Turnkey contracts	4,471			2,827			2,619
Footage contracts	738			311			119
Total Revenue days	13,894			8,764			6,419

Contract drilling revenue per revenue day	$	13,333		$	12,309		$	12,492
Contract drilling cost per revenue day	$	9,967		$	10,099		$	11,033
Rig utilization rates	96		%	88		%	79		%
Average number of rigs during the period	40.1			27.3			22.3

Our contract drilling revenues grew by approximately $77,000,000, or 72%, in fiscal year 2005 from fiscal year 2004, primarily due to the 59% increase in revenue days (approximately $63,000,000) and the approximately $1,000 increase in revenue per revenue day (approximately $14,000,000), which was attributable to improving market conditions in our industry.

Our contract drilling revenues grew by approximately $28,000,000, or 35%, in fiscal year 2004 from fiscal year 2003, primarily due to a 37% increase in revenue days, which was mostly attributable to the 22% increase in the average number of rigs in our rig fleet, and a 9% increase in rig utilization. The $183 per day decrease in average contract drilling revenue is due to the decrease in turnkey and footage revenue days as a percentage of total revenue days.

Our contract drilling costs in fiscal year 2005 grew by approximately $50,000,000, or 56%, primarily due to the increases in 2005 in revenue days and rig utilization referred to above. The $132 decrease in average cost per revenue day was primarily due to the greater increase in daywork revenue days (3,059 days) in fiscal 2005 over the increase in turnkey and footage revenue days (2,071). Under daywork contracts, our customer provides supplies and materials, such as fuel, drill bits, casing and drilling fluids, which we are required to provide under turnkey contracts.

Our contract drilling costs grew by approximately $18,000,000, or 25%, in fiscal year 2004 from fiscal year 2003 due to the increase in revenue days and rig utilization. The increase in daywork revenue days by 1,945 revenue days in fiscal year 2004 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 which only increased by 400 revenue days in fiscal year 2004.

Our depreciation and amortization expense in 2005 increased by approximately $7,000,000, or 43%, from 2004. Depreciation and amortization expense in 2004 increased approximately $4,000,000, or 35%, from 2003. The increase in 2005 over 2004 resulted from our addition of 15 drilling rigs and related equipment in 2005. The increase in 2004 over 2003 resulted from our addition of 11 drilling rigs and related equipment during 2004.

Our general and administrative expenses increased by approximately $1,900,000, or 68%, in fiscal year 2005 from fiscal year 2004. The increase resulted from increased payroll costs, professional and consulting costs, insurance costs and director fees. Payroll related costs

increased by approximately $894,000 due to pay increases, staff additions and an approximately $610,000 increase in bonus costs. Professional and consulting costs increased approximately $587,000, with much of this increase due to the implementation of Sarbanes-Oxley compliance procedures. Director fees increased approximately $142,000. Insurance costs increased approximately $89,000, due to an increase in the cost of director and officer liability insurance coverage.

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

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 $212,000. 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 37.0%, 19.2% and 30.4% for 2005, 2004 and 2003, respectively, differ from the federal statutory rate of 34% due to permanent differences. Permanent differences are costs included in results of operations in the accompanying financial statements which are not fully deductible for federal income tax purposes. At March 31, 2005, we had a net operating loss carryforwards for income tax purposes of approximately $16,500,000, of which approximately $6,600,000 will expire in 2023 and $9,900,000 in 2024. We feel that it is more likely than not that we will realize the benefits of these deductible differences. Therefore, we have established a deferred tax asset applicable to these net operating loss carryforwards of approximately $4,300,000.

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.

Recently Issued Accounting Standards

In December 2004, the FASB issued SFAS No. 123 (revised 2004), Share-Based Payment. SFAS No. 123R is a revision of FASB SFAS No. 123, Accounting for Stock-Based Compensation and supersedes APB Opinion No. 25, Accounting for Stock Issued to Employees, and its related implementation guidance. SFAS No. 123R established standards for the accounting for transactions in which an entity exchanges its equity instruments for goods or services. It also addresses transactions in which an entity incurs liabilities in exchange for goods or services that are based on the fair value of the entity’s equity instruments or that may be settled by the issuance of those equity instruments. SFAS No. 123R focuses primarily on accounting for transactions in which an entity obtains employee services in share-based payment transactions. SFAS No. 123R requires a public entity to measure the cost of employee services received in exchange for an award of equity instruments based on the grant-date fair value of the award (with limited exceptions). That cost will be recognized over the period during which an employee is required to provide service in exchange for the award. The provisions of SFAS No. 123R are effective for public entities that do not file as small business issuers as of the beginning of the first annual reporting period that begins after June 15, 2005. We are currently evaluating the negative impact SFAS No. 123R will have on our financial position and results of operations in fiscal year 2007. The negative impact will be created due to the fact that we previously issued employee stock options for which no expense has been recognized, as these options will not be fully vested as of the effective date of SFAS No. 123R.

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, 2005, we had outstanding debt of approximately $18,078,000 that was subject to variable interest rates, based on Frost National Bank’s prime interest rate. An increase or decrease of 1% in that interest rate would have a corresponding decrease or increase in our net income (loss) of approximately $120,000 annually. We did not enter into this debt arrangement for trading purposes.

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

The Board of Directors and Stockholders

Pioneer Drilling Company:

We have audited management’s assessment, included in Management’s Report on Internal Control over Financial Reporting in Item 9A of Pioneer Drilling Company’s Annual Report on Form 10-K for the year ended March 31, 2005, that Pioneer Drilling Company and subsidiaries maintained effective internal control over financial reporting as of March 31, 2005, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Pioneer Drilling Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting. Our responsibility is to express an opinion on management’s assessment and an opinion on the effectiveness of the Company’s internal control over financial reporting based on our audit.

We conducted our audit 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 effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of the Company’s internal control over financial reporting, evaluating management’s assessment, testing and evaluating the design and operating effectiveness of the Company’s internal control over financial reporting, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

In our opinion, management’s assessment that Pioneer Drilling Company maintained effective internal control over financial reporting as of March 31, 2005, is fairly stated, in all material respects, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Also, in our opinion, Pioneer Drilling Company maintained, in all material respects, effective internal control over financial reporting as of March 31, 2005, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of Pioneer Drilling Company and subsidiaries as of March 31, 2005 and 2004, and the related consolidated statements of operations, stockholders’ equity, and cash flows for each of the years in the three-year period ended March 31, 2005, and our report dated May 27, 2005 expressed an unqualified opinion on those consolidated financial statements.

KPMG LLP

San Antonio, Texas

May 27, 2005

PIONEER DRILLING COMPANY AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

	March 31,
	2005			2004
ASSETS
Current assets:
Cash and cash equivalents	$	69,673,279		$	1,815,759
Marketable securities	1,000,000			4,550,000
Receivables:
Trade, net	26,108,291			10,901,991
Contract drilling in progress	5,364,529			9,130,794
Current deferred income taxes	569,548			285,384
Prepaid expenses	1,876,843			1,336,337
Total current assets	104,592,490			28,020,265
Property and equipment, at cost:
Drilling rigs and equipment	216,286,747			145,758,913
Transportation equipment	6,469,519			4,282,349
Land, buildings and other	2,691,673			1,145,288
	225,447,939			151,186,550
Less accumulated depreciation and amortization	54,881,488			35,844,938
Net property and equipment	170,566,451			115,341,612
Intangible and other assets	850,381			369,278
Total assets	$	276,009,322		$	143,731,155

LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities:
Notes payable	$	681,975		$	558,070
Current installments of long-term debt	4,666,667			3,724,302
Current installments of capital lease obligations	66,359			140,934
Accounts payable	15,621,647			13,270,989
Income tax payable	195,949			—
Prepaid drilling contracts	172,750			—
Accrued expenses:
Payroll and payroll taxes	2,706,623			1,499,151
Other	4,153,851			2,798,801
Total current liabilities	28,265,821			21,992,247
Long-term debt, less current installments	13,411,111			44,786,920
Capital lease obligations, less current installments	33,906			104,754
Non-current liability	400,000			—
Deferred income taxes	12,283,070			6,010,916
Total liabilities	54,393,908			72,894,837
Commitments and contingencies	—			—
Shareholders’ equity:
Preferred stock, 10,000,000 shares authorized; none issued and outstanding	—			—
Common stock $.10 par value; 100,000,000 shares authorized; 45,893,311 shares and 27,300,126 shares issued and outstanding at March 31, 2005 and March 31, 2004, respectively	4,589,331			2,730,012
Additional paid-in capital	220,232,520			82,124,368
Accumulated deficit	(3,206,437		)	(14,018,062		)
Total shareholders’ equity	221,615,414			70,836,318
Total liabilities and shareholders’ equity	$	276,009,322		$	143,731,155

See accompanying notes to consolidated financial statements.

PIONEER DRILLING COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

	Years Ended March 31,
	2005			2004			2003

Contract drilling revenues	$	185,246,448		$	107,875,533		$	80,183,486

Costs and expenses:
Contract drilling	138,482,759			88,504,102			70,823,310
Depreciation and amortization	23,090,909			16,160,494			11,960,387
General and administrative	4,657,013			2,772,730			2,232,390
Bad debt expense	242,000			—			110,000

Total operating costs and expenses	166,472,681			107,437,326			85,126,087
Income (loss) from operations	18,773,767			438,207			(4,942,601		)

Other income (expense):
Interest expense	(1,722,393		)	(2,807,822		)	(2,698,529		)
Interest income	173,318			101,584			94,235
Other	37,267			51,675			37,614
Loss from early extinguishment of debt	(100,833		)	—			203,887
Total other income (expense)	(1,612,641		)	(2,654,563		)	(2,362,793		)

Income (loss) before income taxes	17,161,126			(2,216,356		)	(7,305,394		)
Income tax (expense) benefit	(6,349,501		)	426,299			2,219,776

Net earnings (loss)	$	10,811,625		$	(1,790,057	)	$	(5,085,618	)

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

Earnings (loss) per common share - Diluted	$	0.30		$	(0.08	)	$	(0.31	)

Weighted average number of shares outstanding - Basic	34,543,695			22,585,612			16,163,098

Weighted average number of shares outstanding - Diluted	37,577,927			22,585,612			16,163,098

See accompanying notes to consolidated financial statements.

PIONEER DRILLING COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF SHAREHOLDERS’ EQUITY AND COMPREHENSIVE INCOME

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

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 and related tax benefits of $2,720	445,000	44,500		137,290		—			—			181,790
Preferred stock dividend	—	—		—		—			—			—
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 of $52,423	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
Comprehensive income:
Net earnings	—	—		—		10,811,625			—			10,811,625
Total comprehensive income	—	—		—		—			—			10,811,625
Issuance of common stock for:
Sale, net of related expenses of $5,807,193	11,545,000	1,154,500		109,854,558		—			—			111,009,058
Debenture conversion	6,496,519	649,652		27,350,348		—			—			28,000,000
Exercise of options and related income tax benefits of $204,964	551,666	55,167		903,246		—			—			958,413
Balance as of March 31, 2005	45,893,311	$	4,589,331	$	220,232,520	$	(3,206,437	)	$	—		$	221,615,414

See accompanying notes to consolidated financial statements.

PIONEER DRILLING COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

	Years Ended March 31,
	2005			2004			2003
Cash flows from operating activities:
Net earnings (loss)	$	10,811,627		$	(1,790,057	)	$	(5,085,618	)
Adjustments to reconcile net earnings (loss) to net cash provided by operating activities:
Depreciation and amortization	23,090,909			16,160,494			11,960,387
Allowance for doubtful accounts	242,000			—			110,000
Gain on sale of securities	—			—			(203,887		)
Loss on dispositions of property and equipment	696,345			816,104			279,054
Change in deferred income taxes	5,987,991			119,038			(1,511,744		)
Changes in current assets and liabilities:
Receivables	(11,682,035		)	(11,103,862		)	242,126
Prepaid expenses	(540,507		)	(422,150		)	(279,440		)
Accounts payable	2,350,658			(935,597		)	7,699,417
Income tax payable	195,949			—			—
Prepaid drilling contracts	172,750			—			—
Federal income taxes	—			444,900			435,168
Accrued expenses	2,462,523			1,576,096			743,814
Net cash provided by operating activities	33,788,210			4,864,966			14,389,277

Cash flows from financing activities:
Proceeds from notes payable	41,354,367			4,110,019			23,573,501
Proceeds from subordinated debenture	—			—			10,000,000
Increase in other assets	(123,263		)	(40,000		)	(253,698		)
Proceeds from exercise of options	958,412			673,794			181,790
Proceeds from common stock, net of offering cost of $5,807,193 in 2005, of $1,654,753 in 2004 and $657,499 in 2003	111,009,058			22,105,247			19,342,501
Payments of debt	(43,809,329		)	(4,048,744		)	(18,714,311		)
Net cash provided by financing activities	109,389,245			22,800,316			34,129,783
Cash flows from investing activities:
Business acquisitions	(35,200,000		)	(14,500,000		)	—
Purchases of property and equipment	(45,188,484		)	(28,222,094		)	(33,588,972		)
Purchase of marketable securities, net	(17,525,000		)	(25,400,000		)	(19,925,000		)
Proceeds from sale of marketable securities	21,075,000			23,500,000			21,500,414
Proceeds from sale of property and equipment	1,518,549			419,658			314,366
Net cash used in investing activities	(75,319,935		)	(44,202,436		)	(31,699,192		)
Net increase (decrease) in cash and cash equivalents	67,857,520			(16,537,154		)	16,819,868
Beginning cash and cash equivalents	1,815,759			18,352,913			1,533,045
Ending cash and cash equivalents	$	69,673,279		$	1,815,759		$	18,352,913
Supplementary disclosure:
Interest paid	$	2,407,193		$	2,821,041		$	2,785,177
Income tax refunded	(30,000		)	(990,237		)	(1,143,200		)
Debenture conversion - common stock issued	28,000,000			—			—
Acquisition - common stock issued	—			2,122,650			—
Tax benefit from exercise of nonqualified options	204,964			52,423			2,720

See accompanying notes to consolidated financial statements.

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:

	Years Ended March 31,
	2005			2004			2003

Net earnings (loss)-as reported	$	10,811,625		$	(1,790,057	)	$	(5,085,618	)
Deduct: Total stock-based employee compensation expense determined under fair value based method for all awards net of related tax effect	(1,175,191		)	(662,933		)	(385,671		)
Net earnings (loss)-pro forma	$	9,636,434		$	(2,452,990	)	$	(5,471,289	)
Net earnings (loss) per share-as reported-basic	$	0.31		$	(0.08	)	$	(0.31	)
Net earnings (loss) per share-as reported-diluted	$	0.30		$	(0.08	)	$	(0.31	)
Net earnings (loss) per share-pro forma-basic	$	0.28		$	(0.11	)	$	(0.34	)
Net earnings (loss) per share-pro forma-diluted	$	0.27		$	(0.11	)	$	(0.34	)
Weighted-average fair value of options granted during the year	$	8.85		$	4.46		$	3.50

	2005	2004	2003
Expected volatility	86%	94%	69%
Weighted-average risk-free interest rates	3.7%	3.3%	3.2%
Expected life in years	5	5	5
Options granted	510,000	1,000,000	65,000

As we have not declared dividends since we became a public company, we did not use a dividend yield. In each case, the actual value that will be realized, if any, will depend on the future performance of our common stock and overall stock market conditions. There is no assurance the value an optionee actually realizes will be at or near the value we have estimated using the Black-Scholes model.

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 as defined in SOP 81-1to 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 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. The liability “prepaid drilling contracts” represents amounts collected on contracts in excess of revenues recognized.

Prepaid Expenses

Prepaid expenses include items such as insurance, rent deposits and fees. 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 2005 and 2004, we capitalized $86,819 and $106,395, respectively, of interest costs incurred during the construction periods of certain drilling equipment. At March 31, 2005 and 2004, costs incurred on rigs under construction were approximately $3,300,000 and $2,800,000, 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 net cash flows we expect to obtain from the use of each asset and its eventual disposition. If the sum of these estimated future undiscounted net cash flows is less than the carrying amount of the asset, we recognize an impairment loss.

Cash and Cash Equivalents

We maintain cash accounts at several financial institutions. These account balances are insured by the Federal Deposit Insurance Corporation up to $100,000. At March 31, 2005, we had cash account balances of approximately $1,200,000 exceeding the $100,000 insurance threshold.

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. Cash equivalents at March 31, 2005 and 2004 were $65,046,000 and $1,568,000, respectively.

Marketable Securities

Marketable securities consist of auction rate seven-day preferred securities whose market value is equal to their cost. The objective of investing in these securities is to improve our yield on short-term investments of cash. There were no realized or unrealized gains or losses relating to marketable securities during the years ended March 31, 2005 and 2004.

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, 2005 and 2004 our allowance for doubtful accounts was $352,000 and $110,000.

Intangible and Other Assets

Intangible and 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 three-year term of the related debt. Customer lists are amortized over their estimated benefit periods of up to 18 months. Intangibles related to non-compete agreements are amortized over the period of the non-compete agreements of three to five years. Depreciation and amortization expense includes amortization of intangibles of $142,157, $39,341 and $82,141 during the years ended March 31, 2005, 2004 and 2003 respectively. Amortization of intangibles is not expected to exceed $150,000 per year over the next five years. Total cost and accumulated amortization of intangibles at March 31, 2005 was $480,284 and $59,831, respectively, and $162,500 and $43,222, respectively at March 31, 2004.

Derivative Instruments and Hedging Activities

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

Related Party Transactions

On August 11, 2004 and August 31, 2004, Chesapeake Energy Corporation (“Chesapeake”) purchased 631,133 shares and 94,670 shares of our common stock, respectively, at $6.90 per share pursuant to the preemptive rights we granted to Chesapeake in the stock purchase agreement we entered into in March 2003 when we sold shares of common stock to Chesapeake in a private placement transaction. On March 29, 2005, we sold Chesapeake an additional 1,165,769 shares pursuant to the preemptive rights agreement. At March 31, 2005, Chesapeake owned 16.78% of our outstanding common stock, and its preemptive rights have expired. During the years ended March 31, 2005 and 2004, we recognized revenues of approximately $4,885,000 and $924,000, respectively, and recorded contract drilling costs of approximately $3,263,000 and $745,000, respectively, excluding depreciation, on contracts with Chesapeake. Our accounts receivable at March 31, 2005 and 2004 include $2,939,000 and $532,000, respectively, due from Chesapeake.

We purchased services from R&B Answering Service and Frontier Service, Inc. during 2005, 2004 and 2003. These companies are more than 5% owned by our Chief Operating Officer and an immediate family member of our Vice President, South Texas Division, respectively. The following summarizes the transactions with these companies in each period.

	2005			2004		2003
R&B Answering Service
Purchases	$	18,218		$	13,526	$			10,465
Payments	$	17,112		$	12,544	$			9,678
Frontier Services, Inc.
Purchases	$	81,254		$	118,660	$		130,513
Payments	$		93,709	$	136,818	$	107,719

Recently Issued Accounting Standards

In December 2004, the FASB issued SFAS No. 123 (revised 2004), Share-Based Payment. SFAS No. 123R is a revision of FASB SFAS No. 123, Accounting for Stock-Based Compensation and supersedes APB Opinion No. 25, Accounting for Stock Issued to Employees, and its related implementation guidance. SFAS No. 123R established standards for the accounting for transactions in which an entity exchanges its equity instruments for goods or services. It also addresses transactions in which an entity incurs liabilities in exchange for goods or services that are based on the fair value of the entity’s equity instruments or that may be settled by the issuance of those equity instruments. SFAS No. 123R focuses primarily on accounting for transactions in which an entity obtains employee services in share-based payment transactions. SFAS No. 123R requires a public entity to measure the cost of employee services received in exchange for an award of equity instruments based on the grant-date fair value of the award (with limited exceptions). That cost will be recognized over the period during which an employee is required to provide service in exchange for the award. The provisions of SFAS No. 123R are effective for public entities that do not file as small business issuers as of the beginning of the first annual reporting period that begins after June 15, 2005. We are currently evaluating the negative impact SFAS No. 123R will have on our financial position and results of operations in fiscal year 2007. The negative impact will be created due to the fact that we previously issued employee stock options for which no expense has been recognized, as those options will not be fully vested as of the effective date of SFAS No. 123R.

Reclassifications

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

2. Acquisitions

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

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

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

	Wolverine		Allen			Total
Assets acquired:
Drilling equipment	$	27,620,214	$	7,057,500		$	34,677,714
Vehicles	214,786		230,000			444,786
Buildings	30,000		260,000			290,000
Land	20,000		40,000			60,000
Intangibles, primarily non-compete agreements	115,000		112,500			227,500
	$	28,000,000	$	7,700,000		$	35,700,000
Less non-compete obilgation	—		(500,000		)	(500,000		)
	$	28,000,000	$	7,200,000		$	35,200,000

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

	Pro Forma Years Ended March 31,
	2005		2004
Total revenues	$	208,394,551	$	132,287,140
Net earnings (loss)	$	11,943,137	$	(2,100,116	)
Earnings (loss) per common share:
Basic	$	0.35	$	(0.09	)
Diluted	$	0.33	$	(0.09	)

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,
	2005			2004
Indebtedness under $47,000,000 credit facility, secured by drilling equipment, due in monthly payments of $388,889 plus interest at prime (5.75% at March 31, 2005), with final maturity on December 1, 2007	$	18,077,778		$	—

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 3-month LIBOR rate plus 385 basis points, remaining balance due December 2007 (2)	—			13,119,048

Note payable to Frost National Bank, secured by drilling equipment, due in monthly payments of $107,143 plus interest at prime plus 1.0%, due August 2007 (2)	—			4,392,174

Note payable to Frost National Bank, secured by drilling equipment, due in monthly payments of $42,401, including interest at prime plus 1.0%, beginning April 15, 2004, due March 15, 2007 (2)	—			3,000,000
	18,077,778			48,511,222

Less current installments	(4,666,667		)	(3,724,302		)
	$	13,411,111		$	44,786,920

(1) WEDGE Energy Services, LLC (“WEDGE”) held $27,000,000 of the convertible subordinated debentures and William H. White, a former director of our company, held $1,000,000 of the convertible subordinated debentures. The convertible subordinate debentures were converted into 6,496,519 shares of our common stock on August 11, 2004.

(2) These notes were repaid in August and September 2004 with proceeds from our August 2004 common stock offering.

Long-term debt maturing each year subsequent to March 31, 2005 is as follows:

Year Ended March 31,
2006	$	4,666,667
2007	4,666,667
2008	8,744,444
2009	—
2010	—
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 was convertible into 6,496,519 shares of common stock at $4.31 per share, which resulted from a pro rata blending of the $5.00 conversion rate of the new $10,000,000 financing and the $4.00 conversion rate of the $18,000,000 debenture being cancelled. WEDGE funded $7,000,000 of the $10,000,000 on July 3, 2002 and $2,000,000 on July 29, 2002. William H. White, a former Director of our Company and the former President of WEDGE, purchased the remaining $1,000,000 on July 29, 2002. Unlike the cancelled debenture, which was not redeemable by Pioneer, the new debentures were redeemable at a scheduled premium. We used $7,000,000 of the proceeds to pay down bank debt and $3,000,000 for the purchase of drilling equipment. On August 11, 2004, these debentures were converted in accordance with their terms into 6,496,519 shares of our common stock.

On October 29, 2004, we entered into a $47,000,000 credit facility with a group of lenders consisting of a $7,000,000 revolving line and letter of credit facility and a $40,000,000 acquisition facility for the acquisition of drilling rigs, drilling rig transportation equipment and associated equipment. Frost National Bank is the administrative agent and lead arranger under the new credit facility, and the lenders include Frost National Bank, the Bank of Scotland and Zions First National Bank. Borrowings under the new credit facility bear interest at a rate equal to Frost National Bank’s prime rate (5.75% at March 31, 2005) and are secured by most of our assets, including all our drilling rigs and associated equipment and receivables. We borrowed the entire $40,000,000 available under the acquisition facility and we have used approximately $2,825,000 of availability under the revolving line and letter of credit facility through the issuance of letters of credit in the ordinary course of business. On March 29, 2005, we repaid $20,000,000 of the borrowings under the acquisition facility. On May 11, 2005, the lenders amended the acquisition facility to provide us with the ability to again draw the $20,000,000 for future acquisitions. The remaining approximately $20,0000,000 and $4,175,000 of availability under the acquisition facility and the revolving line and letter of credit facility, respectively, should remain available to us until those facilities mature in October 2006 and October 2005, respectively.

At March 31, 2005, we were in compliance with all covenants applicable to our outstanding debt. Those covenants include, among others, a debt to total capitalization ratio of not greater than ..3 to 1, a fixed charged coverage ratio of not less than 1.5 to 1, an operating leverage ratio of less than 3 to 1, restrict us from paying dividends, restrict us from the sale of assets not permitted by the credit facility and restrict us from the incurrence of additional indebtedness in excess of $3,000,000 not already allowed by the credit facility.

Notes payable at March 31, 2005 consists of a $681,975 insurance premium note due in monthly installments of $137,400, including interest, through August 26, 2005, which bears interest at the rate of 3.15% per year.

4. Leases

We are obligated under capital leases covering several trucks that expire at various dates through January 2007. At March 31, 2005 and 2004, the gross amount of transportation equipment and related amortization recorded under capital leases were as follows:

	March 31,
	2005		2004
Transportation equipment	$	405,320	$	665,195
Less accumulated amortization	299,861		413,797
	$	105,459	$	251,398

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

We lease various office equipment under non-cancelable operating leases expiring through 2008 and real estate as follows:

• a 43-acre division office and storage yard in Decatur, Texas, at a cost of $800 per month, pursuant to a lease extending through September 2006;

• a trucking department office, storage and maintenance yard in Alice, Texas, at a cost of $4,500 per month, pursuant to a lease extending through July 2006;

• a division office in Denver, Colorado, at a cost of $1,210 per month, pursuant to a lease extending through June 2005;

• a yard office in Kenmare, North Dakota, at a cost of $700 per month, pursuant to a lease extending through March 31, 2006; and

• part of a 2.2-acre division office and storage yard in Vernal, Utah at a cost of $2,000 per month pursuant to a lease extending through October 2005.

In August 2004, we purchased the real estate we had previously been leasing in Henderson, Texas.

Rent expense under these operating leases for the years ended March 31, 2005, 2004 and 2003 was $102,077, $278,746 and $344,752, respectively.

In four to six months we will take over the entire division office and storage yard in Vernal, Utah and will enter into a two year lease at a cost of $6,000 per month.

In June 2005, we are moving our corporate headquarters to new office space in San Antonio, Texas. We have entered into a 102 month lease, beginning upon occupancy, with monthly payments of approximately $12,300 for the first two years increasing to an average of approximately $20,000 per month thereafter. The lease grants two options to renew the lease for a renewal term of five years each. We plan to sell our current corporate headquarters building in San Antonio, Texas.

Future lease obligations, including our new corporate headquarters, and minimum capital lease payments as of March 31, 2005 were as follows:

Year Ended		Operating		Capital
March 31,		Leases		Leases
	2006	$	224,873	$	70,446
	2007	173,935		34,106
	2008	217,492		—
	2009	234,291		—
	2010	237,905		—
	Thereafter	903,438		—
Total minimum lease payments		$	1,991,934	$	104,552

Less amounts representing interest (at rates ranging from 5.7% to 8.4%)				(4,287		)
Present value of net minimum capital lease payments				100,265
Less current installments of capital lease obligations				(66,359		)
Capital lease obligations, excluding current installments				$	33,906

5. Income Taxes

Our provision for income taxes consists of the following:

	Years Ended March 31,
	2005		2004			2003

Current tax - state	$	56,400	$	—		$	—
Current tax - federal	335,109		—			(708,032		)
Deferred tax - state	55,164		—			—
Deferred tax - federal	5,902,828		(426,299		)	(1,511,744		)
Income tax expense (benefit)	$	6,349,501	$	(426,299	)	$	(2,219,776	)

In fiscal years 2005, 2004 and 2003, 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,
	2005		2004			2003

Expected tax expense (benefit)	$	5,834,783	$	(753,561	)	$	(2,483,834	)
Non taxable interest income	—		—			(10,400		)
Club dues, meals and entertainment	24,050		13,941			10,443
State income taxes	92,388		—			—
Reimbursement of food costs for rig employees	396,968		314,622			275,338
Other	1,312		(1,301		)	(11,323		)
	$	6,349,501	$	(426,299	)	$	(2,219,776	)

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,
	2005		2004

Deferred tax assets:
Vacation expense accruals	$	71,446	$	37,233
Workers compensation and health insurance accruals	378,423		187,752
Bad debt expense	119,680		37,400
Net operating loss carryforwards	4,329,933		7,825,126
Alternative minimum tax credit	311,915		181,770
Loss accrual on turnkey contracts	—		23,000
Total deferred tax assets	5,211,397		8,292,281
Deferred tax liabilities:
Property and equipment, principally due to differences in depreciation	16,924,919		14,017,813
Total deferred tax liabilities	16,924,919		14,017,813
Net deferred tax liabilities	$	11,713,522	$	5,725,532

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, 2005, we had net operating loss carryforwards for federal income tax purposes of approximately $16,500,000, which will expire if not utilized as of the end of our fiscal years ending as follows:

Year	Amount
2023	$	6,600,000
2024	9,900,000

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,
	2005		2004			2003

Basic
Net earnings (loss)	$	10,811,625	$	(1,790,057	)	$	(5,085,618	)

Weighted average shares	34,543,695		22,585,612			16,163,098

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

Diluted
Earnings (loss) applicable to common shareholders	$	10,811,625	$	(1,790,057	)	$	(5,085,618	)
Effect of dilutive securities - Convertible subordinated debenture	459,483		—			—
Earnings (loss) available to common shareholders and assumed conversion	$	11,271,108	$	(1,790,057	)	$	(5,085,618	)
Weighted average shares:
Outstanding	34,543,695		22,585,612			16,163,098
Options	684,806		—			—
Convertible subordinated debenture	2,349,426		—			—
	37,577,927		22,585,612			16,163,098
Earnings (loss) per share	$	0.30	$	(0.08	)	$	(0.31	)

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 effects.

8. Equity Transactions

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, 2005, Chesapeake Energy owned 16.78% of our outstanding common stock and its preemptive rights have expired.

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. 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 subsequently filed a registration statement on Form S-3 to register the resales of those shares. The registration statement became effective on June 22, 2004.

On August 11, 2004, we sold 4,000,000 shares of our common stock at approximately $6.61 per share, net of underwriters’ commissions, pursuant to a public offering we registered with the SEC under a registration statement filed on Form S-1. On August 31, 2004, we sold 600,000 additional shares of our common stock at approximately $6.61 per share, net of underwriters’ commissions, pursuant to the underwriters’ exercise of an over-allotment option granted in connection with that public offering.

Directors and employees exercised stock options for the purchase of 551,666 shares of common stock at prices ranging from $.375 to $6.44 per share during the fiscal year ended March 31, 2005, 722,334 shares of common stock at prices ranging from $.625 to $3.20 per share during the fiscal year ended March 31, 2004 and 445,000 shares of common stock at prices ranging from $0.375 to $2.50 per share during the fiscal year ended March 31, 2003.

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, 2005, 2004 and 2003:

	2005				2004				2003
	Shares Issuable on Exercise of Options		Weighted Average Price		Shares Issuable on Exercise of Options		Weighted Average Price		Shares Issuable on Exercise of Options		Weighted Average Price
Balance Outstanding Beginning of year	2,056,666		$	3.24	1,825,000		$	1.63	2,320,000		$	1.47
Granted	510,000		$	8.85	1,000,000		$	4.46	65,000		$	1.72
Exercised	(551,666	)	$	1.37	(722,334	)	$	0.93	(445,000	)	$	0.40
Canceled	(10,000	)	$	4.52	(46,000	)	$	2.25	(115,000	)	$	4.29
Balance Outstanding End of year	2,005,000		$	5.30	2,056,666		$	3.24	1,825,000		$	1.63
Options Exercisable End of year	798,002		$	3.58	884,001		$	1.95	1,437,334		$	1.28

As of March 31, 2005, there were no outstanding warrants.

The following table summarizes information about our employee stock options outstanding and exercisable at March 31, 2005:

	Options Outstanding				Options Exercisable
Range of Exercise Prices	Number Outstanding	Weighted Average Remaining Contractual Life	Weighted Average Exercise Price		Number Exercisable	Weighted Average Exercise Price

$2.25 - $4.65	1,065,000	7.45	$	3.60	681,002	$	3.32

$4.77 - $10.31	940,000	9.11	$	7.22	117,000	$	5.05

	2,005,000	8.23	$	5.30	798,002	$	3.58

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 2005, 2004 and 2003 were approximately $399,000, $76,000 and $92,000, respectively.

13. Quarterly Results of Operations (unaudited)

The following table summarizes quarterly financial data for our fiscal years ended March 31, 2005 and 2004 (in thousands, except per share data):

	First Quarter			Second Quarter			Third Quarter			Fourth Quarter			Total
2005
Revenues	$	40,719		$	42,783		$	46,387		$	55,357		$	185,246
Income from operations	1,046			1,960			6,704			9,064			18,774
Income tax expense	(139		)	(590		)	(2,428		)	(3,192		)	(6,349		)
Net earnings	216			923			4,179			5,494			10,812
Earnings per share:
Basic	.01			.03			.11			.14			.31
Diluted	.01			.03			.11			.14			.30
2004
Revenues	$	23,850		$	24,244		$	26,414		$	33,368		$	107,876
Income (loss) from operations	(789		)	(166		)	9			1,384			438
Income tax expense (benefit)	409			185			118			(286		)	426
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		)

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

Item 9. 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, 2005 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, 2005 that has materially affected, or is likely to materially affect, our internal controls over financial reporting.

Management’s Report on Internal Control over Financial Reporting

The management of Pioneer Drilling Company is responsible for establishing and maintaining adequate internal control over financial reporting. Pioneer Drilling Company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. Pioneer Drilling Company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

Pioneer Drilling Company’s management assessed the effectiveness of the Company’s internal control over financial reporting as of March 31, 2005. In making this assessment, it used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control-Integrated Framework. Based on our assessment we have concluded that, as of March 31, 2005, Pioneer Drilling Company’s internal control over financial reporting was effective based on those criteria.

Pioneer Drilling Company’s independent registered public accounting firm has audited management’s assessment of the effectiveness of Pioneer Drilling Company’s internal control over financial reporting as of March 31, 2005, as stated in their report which appears herein. That report appears on page 31.

PART III

In Items 10, 11, 12, 13 and 14 below, we are incorporating by reference the information we refer to in those Items from the definitive proxy statement for our 2005 Annual Meeting of Shareholders. We intend to file that definitive proxy statement with the SEC by July 15, 2005.

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 2005 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 2005 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 2005 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 2005 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 2005 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

(1) Financial Statements.

See Index to Consolidated Financial Statements on page 29.

(2) Financial Statement Schedules:

Schedule II

	Valuation and Qualifying Accounts
	Balance at Beginning of Year		Charged to Costs and Expenses		Deductions from Accounts		Balance at Year End

Year ended March 31, 2003 Allowance for doubtful receivables	$	—	$	110,000	$	—	$	110,000

Year ended March 31, 2004 Allowance for doubtful receivables	$	110,000	$	—	$	—	$	110,000

Year ended March 31, 2005 Allowance for doubtful receivables	$	110,000	$	242,000	$	—	$	342,000

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

Exhibit Number		Description

2.1	-	Asset Purchase Agreement dated November 11, 2004 between Wolverine Drilling, Inc. and Robert Mau, Robert S. Blackford and Pioneer Drilling Services, Ltd. (Form 8-K dated November 11, 2004 (File No. 1-8182, Exhibit 2.1)).

2.2	-	Asset Purchase Agreement dated November 29,2004, by and among Allen Drilling Company, the Earl Allen Family Trust dated April 1, 1079, the sole shareholder of Allen Drilling Company, Dixon Allen, Paula K. Hoisington and Lisa D. Johonnesson, all of the beneficiaries of the Trust, and Pioneer Drilling Services, Ltd. (Form 8-K dated November 30, 2004 (File No. 1-8182m Exhibit 2.1)).

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

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

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

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

4.2*	-	Form of Purchase Agreement dated February 13, 2004 between Pioneer Drilling Company and the several purchasers (Form s-3 filed February 24, 3004 (Reg. No. 333-113036, Exhibit 4.1)).

4.3*	-	Credit Agreement between Pioneer Drilling Services, Ltd. and Frost National Bank, as Administrative Agent, Agent, Lead Arranger and Lender dated October 29, 2004 (Form 8-K dated October 29, 2004 (File No. 1-8182, Exhibit 4.1)).

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

10.2+*	-	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+)).

10.3+*	-	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+)).

10.4+*	-	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+)).

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

10.6	-	Termination Agreement dated May 26, 2005 between Michael E. Little, Wm. Stacy Locke, Pioneer Drilling Company and WEDGE Energy Services, L.L.C.

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 1, 2005	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 1, 2005

/s/ Wm. Stacy Locke
Wm. Stacy Locke	President, Chief Executive Officer and Director (Principal Executive Officer)	June 1, 2005

/s/ William D. Hibbetts
William D. Hibbetts	Senior Vice President, Chief Financial Officer and Secretary (Principal Financial and Accounting Officer)	June 1, 2005


C. John Thompson	Director	June 1, 2005


/s/ James M. Tidwell
James M. Tidwell	Director	June 1, 2005


/s/ C. Robert Bunch
C. Robert Bunch	Director	June 1, 2005


/s/ Dean A. Burkhardt
Dean A. Burkhardt	Director	June 1, 2005


/s/ Michael F. Harness
Michael F. Harness	Director	June 1, 2005

Index To Exhibits

2.1	-	Asset Purchase Agreement dated November 11, 2004 between Wolverine Drilling, Inc. and Robert Mau, Robert S. Blackford and Pioneer Drilling Services, Ltd. (Form 8-K dated November 11, 2004 (File No. 1-8182, Exhibit 2.1)).

2.2	-	Asset Purchase Agreement dated November 29,2004, by and among Allen Drilling Company, the Earl Allen Family Trust dated April 1, 1079, the sole shareholder of Allen Drilling Company, Dixon Allen, Paula K. Hoisington and Lisa D. Johonnesson, all of the beneficiaries of the Trust, and Pioneer Drilling Services, Ltd. (Form 8-K dated November 30, 2004 (File No. 1-8182m Exhibit 2.1)).

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

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

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

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

4.2*		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)).

4.3	-	Credit Agreement between Pioneer Drilling Services, Ltd. and Frost National Bank, as Administrative Agent, Agent, Lead Arranger and Lender dated October 29, 2004 (Form 8-K dated October 29, 2004 (File No. 1-8182, Exhibit 4.1)).

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

10.2+*	-	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+)).

10.3+*	-	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+)).

10.4+*	-	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+)).

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

10.6	-	Termination Agreement date May 26, 2005 between Michael E. Little, Wm. Stacy Locke, Pioneer Drilling Company and WEDGE Energy Services, L.L.C.

21.1	-	Subsidiaries of Pioneer Drilling Company.

23.1	-	Consent of KPMG LLP.

Reports of Independent Registered Public Accounting Firm

Consolidated Balance Sheets as of March 31, 2005 and 2004

Consolidated Statements of Operations for the Years Ended March 31, 2005, 2004 and 2003

Consolidated Statements of Shareholders’ Equity and Comprehensive Income for the Years Ended March 31, 2005, 2004 and 2003

Consolidated Statements of Cash Flows for the Years Ended March 31, 2005, 2004 and 2003

Notes to Consolidated Financial Statements

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).

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).

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 Stockholder Matters
Item 13.	Certain Relationships and Related Transactions
Item 14.	Principal Accountant Fees and Services

PART IV

Item 15.	Exhibits and Financial Statement Schedules