Edgar Filing: PIONEER DRILLING CO

FORM 10-K

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, 2007

¨	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)

1250 N.E. Loop 410, Suite 1000 San Antonio, Texas		78209
(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 if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes ¨ No þ

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Exchange Act. Yes ¨ No þ

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 þ No ¨

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. þ

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of “accelerated filer and large accelerated filer” in Rule 12b-2 of the Exchange Act. (Check one):

Large accelerated filer ¨ Accelerated filer þ Non-accelerated filer ¨

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ¨ No þ

The aggregate market value of the registrant’s common stock held by nonaffiliates of the registrant on the last business day of the registrant’s most recently completed second fiscal quarter (based on the closing sales price on the American Stock Exchange on September 30, 2006) was approximately $634,000,000.

As of May 11, 2007, there were 49,628,478 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 2007 Annual Meeting of Shareholders are incorporated by reference into Part III of this report.

TABLE OF CONTENTS


		Page

PART I

Item 1.	Business	1
Item 1A.	Risk Factors	11
Item 1B.	Unresolved Staff Comments	16
Item 2.	Properties	16
Item 3.	Legal Proceedings	16
Item 4.	Submission of Matters to a Vote of Security Holders	16

PART II

Item 5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	17
Item 6.	Selected Financial Data	19
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	20
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk	31
Item 8.	Financial Statements and Supplementary Data	32
Item 9.	Changes in and Disagreements With Accountants on Accounting and Financial Disclosure	51
Item 9A.	Controls and Procedures	51
Item 9B.	Other Information	51

PART III

Item 10.	Directors, Executive Officers and Corporate Governance	52
Item 11.	Executive Compensation	52
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	52
Item 13.	Certain Relationships and Related Transactions, and Director Independence	52
Item 14.	Principal Accountant Fees and Services	52

PART IV

Item 15.	Exhibits and Financial Statement Schedules	53

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’’ following Item 1 of Part I of this report.

Item 1.

Business

General

Since September 1999, we have significantly expanded our fleet of drilling rigs through acquisitions, construction of new rigs and 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 25 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 11, 2007, our rig fleet consisted of 66 operating drilling rigs, 17 of which were operating in our South Texas division, 20 of which were operating in our East Texas division, 10 of which were operating in our North Texas division, six of which were operating in our western Oklahoma division and 13 of which were operating in our Rocky Mountain divisions in Utah and North Dakota. In April 2007, we acquired a 1500-horsepower diesel electric rig that is ideally suited for certain international markets that we are considering for possible expansion. This rig is not included in our 66 operating rig count as of May 11, 2007.

We conduct our operations primarily in South, East and North Texas, western Oklahoma, North Louisiana and the Rocky Mountains. Our customers remain primarily focused on drilling for natural gas. During fiscal 2007, substantially all the wells we drilled for our customers were drilled in search of natural gas, except for wells we drilled using five rigs employed in search of oil in the Williston Basin of the Rocky Mountains.

For many years, the U.S. 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. For information on our consolidated revenues and income from operations for the years ended March 31, 2007, 2006 and 2005 and our consolidated total assets as of March 31, 2007 and 2006, see our consolidated financial statements in 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 or constructing 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;

•

maintaining an aggressive safety program;

•

expanding into other market areas, possibly including one or more international markets; and

•

potentially expanding into other sectors within the oilfield services industry.

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 cost incurred and equipment used in 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 11, 2007, our rig fleet consists of 66 operating drilling rigs. In addition, we acquired a rig in April 2007 that is ideally suited for certain international markets that we are considering for possible expansion. We own all the rigs in our fleet. The following table sets forth information regarding utilization for our fleet of operating drilling rigs:


	Years Ended March 31,
	2007		2006		2005		2004		2003		2002
Average number of rigs for the period	60.8		52.3		40.1		27.3		22.3		18.0
Average utilization rate	95	%	95	%	96	%	88	%	79	%	82	%

The following table sets forth information regarding our operating drilling rigs (rig numbers 13, 66 and 67 have not been used):


Rig Number	Rig Design	Approximate Drilling Depth Capability (feet)	Current Division 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	Skytop Brewster N-46	12,000	North Texas	Mechanical	1,000
6	Brewster DH-4610	13,000	East Texas	Mechanical	950
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	12,500	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


Rig Number	Rig Design	Approximate Drilling Depth Capability (feet)	Current Division Location	Type	Horsepower
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	1,400
27	IRI Cabot 1200 M	13,500	South Texas	Mechanical	1,300
28	National 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
31	RMI 1000	13,500	East Texas	Mechanical	1,000
32	Brewster N-75	13,500	East Texas	Mechanical	1,000
33	Brewster N-95	13,500	East Texas	Mechanical	1,200
34	RMI 1000	13,500	East Texas	Mechanical	1,000
35	National 610	12,500	East Texas	Mechanical	750
36	Brewster N-7	11,500	East Texas	Mechanical	750
37	Brewster N-95	13,000	East Texas	Mechanical	1,200
38	Ideco H 1000	10,500	Utah	Electric	1,000
39	Brewster N-7	11,500	North Texas	Mechanical	750
40	National 370	9,000	Oklahoma	Mechanical	550
41	National 610	12,500	Utah	Mechanical	750
42	Brewster N-46	12,500	North Dakota	Mechanical	1,000
43	National 610	12,500	North Dakota	Mechanical	750
44	National 80B	14,000	North Dakota	Mechanical	1,000
45	Skytop Brewster N75	15,000	East Texas	Mechanical	1,000
46	RMI 550	9,000	Oklahoma	Mechanical	550
47	Ideco 525	8,000	Oklahoma	Mechanical	600
48	National 370	8,000	Oklahoma	Mechanical	550
49	Ideco 525	9,000	Oklahoma	Mechanical	600
50	Ideco 725	11,000	Oklahoma	Mechanical	800
51	National 110 UE	18,000	East Texas	Electric	1,500
52	National 80 UE	15,000	Utah	Electric	1,000
53	National 80 UE	15,000	Utah	Electric	1,000
54	RMI 1000	15,000	Utah	Mechanical	1,000
55	OIME SD7E	18,000	North Texas	Electric	1,500
56	OIME SD7E	18,000	North Dakota	Electric	1,500
57	Gardner-Denver 800 E	15,000	North Dakota	Electric	1,000
58	National 80 UE	15,000	South Texas	Electric	1,000
59	HRI 1000	12,500	Utah	Mechanical	1,000
60	HRI 1000 E	12,500	North Texas	Electric	1,000
61	HRI 1000 E	12,500	North Texas	Electric	1,000
62	HRI 1000 E	12,500	South Texas	Electric	1,000
63	HRI 1000 E	12,500	North Texas	Electric	1,000
64	HRI 1000 E	12,500	North Texas	Electric	1,000
65	HRI 1000 E	12,500	East Texas	Electric	1,000
68	HRI 1000	12,500	Utah	Mechanical	1,000
69	HRI 1000	12,500	Utah	Mechanical	1,000

As of May 11, 2007, we owned a fleet of 70 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 or excess rig capacity, price competition tends to increase and results in decreases in the profitability of daywork contracts. In this 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,
	2007	2006	2005
Daywork	742	565	264
Turnkey	2	19	134
Footage	60	106	48

Total number of wells	804	690	446

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 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 2007, we drilled wells for 92 different customers, compared to 128 customers in fiscal 2006 and 102 customers in fiscal 2005. 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 2007
EOG Resources, Inc.	9.7	%
Chesapeake Operating Inc.	9.1	%
Anadarko Petroleum Corporation (1)	6.1	%

Fiscal 2006
Chesapeake Operating Inc.	10.1	%
Kerr-McGee Oil & Gas (1)	6.1	%
Chinn Exploration	4.4	%

Fiscal 2005
Chinn Exploration	6.5	%
Goodrich Petroleum Corp.	5.0	%
Medicine Bow Energy Corporation	4.6	%

(1)	Anadarko Petroleum Corporation acquired Kerr-McGee Oil and Gas in fiscal year 2007.

During fiscal 2005, substantially all the wells drilled for Chinn Exploration, Goodrich Petroleum Corp. and Medicine Bow Energy Corporation were turnkey contracts. Revenues generated by turnkey contracts are considerably greater as compared to daywork contracts as we provide supplies and materials such as fuel, drill bits, casing and drilling fluids.

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.

We can also enter into term contracts 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 or when building new rigs. As of May 11, 2007, we had 30 contracts with terms of six months to two years in duration, of which 14 will expire by November 11, 2007, six have a remaining term of six to 12 months, six have a remaining term of 12 to 18 months and four have a remaining term in excess of 18 months. Due to the current excess supply of drilling rigs within our industry, some of these term contracts may not be renewed when the initial contract period expires.

Since our company’s inception, we have earned all of our revenue from contract drilling services we have performed in the United States. All of our property and equipment is located in the United States.

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. In addition to pricing and rig availability, we believe the following factors are also important to our customers in determining which drilling contractors to select:

•

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

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the mobility and efficiency of the rigs;

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the quality of service and experience of the rig crews;

•

the safety records of the rigs;

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the offering of ancillary services; and

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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:

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blowouts;

•

fires and explosions;

•

loss of well control;

•

collapse of the borehole;

•

lost or stuck drill strings; and

•

damage or loss from natural disasters.

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

•

suspension of drilling operations;

•

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

•

personal injury and loss of life;

•

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

•

environmental damage.

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

Our current insurance coverage includes property insurance on our rigs, drilling equipment and real property. Our insurance coverage for property damage to our rigs and to our drilling equipment is based on our estimates of the cost of comparable used equipment to replace the insured property. The policy provides for a deductible on rigs of $250,000 per occurrence. Our third-party liability insurance coverage is $51 million per occurrence and in the aggregate, with a deductible of $260,000 per occurrence. We believe that we are adequately insured for public liability and property damage to others with respect to our operations. However, such insurance may not be sufficient to protect us against liability for all consequences of well disasters, extensive fire damage or damage to the environment.

In addition, we generally carry insurance coverage to protect against certain hazards inherent in our turnkey contract drilling operations. This insurance covers “control-of-well,” including blowouts above and below the surface, redrilling, seepage and pollution. This policy provides coverage of $3 million, $5 million or $10 million, depending on the area in which the well is drilled and its target depth, subject to a deductible of the greater of 15% of the well’s anticipated dry hole cost or $150,000. This policy also provides care, custody and control insurance, with a limit of $1,000,000, subject to a $100,000 deductible.

Employees

We currently have approximately 1,700 employees. Approximately 240 of these employees are salaried administrative or supervisory employees. The rest of our employees are hourly employees who operate or maintain our drilling rigs and rig-hauling trucks. The number of hourly employees fluctuates depending on the number of drilling projects we are engaged in at any particular time. None of our employment arrangements are subject to collective bargaining arrangements.

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

Facilities

We own:

•

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 four-acre trucking department office, storage and maintenance yard in Kilgore, Texas;

•

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

•

a 10-acre division office, rig storage and maintenance yard in Williston, North Dakota;

•

a five-acre division office, storage and maintenance yard in Paradise, Texas; and

•

a five-acre trucking department office, storage and maintenance yard in Springtown, Texas.

We lease:

•

our corporate office facilities, at a cost escalating from $10,880 per month to $18,805 per month over 102 months, pursuant to a lease extending through December 2013;

•

a trucking department office, storage and maintenance yard in Alice, Texas, at a cost of $5,200 per month, pursuant to a lease extending through August 2009; and

•

a 2.2-acre division office and storage yard in Vernal, Utah, at a cost of $6,000 per month, pursuant to a lease extending through October 2007.

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 Web site address is www.pioneerdrlg.com. We make available on this Web site 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 Securities and Exchange Commission. We have also posted on our Web site our: Charters for the Audit, Compensation, and Nominating and Corporate Governance Committees of our Board; Code of Conduct and Ethics; Rules of Conduct; and Company Contact Information.

CAUTIONARY STATEMENT CONCERNING FORWARD-LOOKING STATEMENTS

We are including the following discussion to inform our existing and potential security holders generally of some of the risks and uncertainties that can affect our company and to take advantage of the “safe harbor” protection for forward-looking statements that applicable federal securities law affords.

From time to time, our management or persons acting on our behalf make forward-looking statements to inform existing and potential security holders about our company. These statements may include projections and estimates concerning the timing and success of specific projects and our future backlog, revenues, income and capital spending. Forward-looking statements are generally accompanied by words such as “estimate,” “project,” “predict,” “believe,” “expect,” “anticipate,” “plan,” “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 Item 1 – “Business” 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,” 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 supply of marketable drilling rigs within the industry;

•

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

•

the continued availability of drilling rig components;

•

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, except as required by applicable securities laws and regulations. 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.

Item 1A.

Risk Factors

Set forth below are various risks and uncertainties that could adversely impact our business, financial condition, results of operations and cash flows.

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:

•

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

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the discovery rate of new oil and gas reserves;

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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;

•

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;

•

weather conditions in the United States and elsewhere;

•

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; and

•

the overall supply and demand for oil and gas.

Risks Relating to Our Business

Reduced demand for or excess capacity of drilling rigs can adversely affect our profitability.

Our profitability in the future will depend on many factors, but largely on utilization rates and dayrates for our drilling rigs. A reduction in the demand for drilling rigs or an increase in the supply of drilling rigs, whether through new construction or refurbishment, could decrease our dayrates and utilization rates, which would adversely affect our revenues and profitability.

Our acquisition strategy exposes us to various risks, including those relating to difficulties in identifying suitable acquisition opportunities and integrating businesses, assets and personnel, as well as difficulties in obtaining financing for targeted acquisitions and the potential for increased leverage or debt service requirements.

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 66 drilling rigs, primarily as a result of acquisitions. Acquisitions involve numerous inherent risks, including:

•

unanticipated costs and assumption of liabilities and exposure to unforeseen liabilities of acquired businesses, including environmental liabilities;

•

difficulties in integrating the operations and assets of the acquired business and the acquired personnel;

•

limitations on our ability to properly assess and maintain an effective internal control environment over an acquired business, in order to comply with applicable periodic reporting requirements;

•

potential losses of key employees and customers of the acquired businesses;

•

risks of entering markets in which we have limited prior experience; and

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increases in our expenses and working capital requirements.

The process of integrating an acquired business may involve unforeseen costs and delays or other operational, technical and financial difficulties that 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 previous 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.

Our strategy of constructing drilling rigs during periods of peak demand requires that we maintain an adequate supply of drilling rig components to complete our rig building program. Our suppliers may be unable to continue providing us the needed drilling rig components if their manufacturing sources are unable to fulfill their commitments.

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 or convertible securities could be dilutive to our existing stockholders. Furthermore, we may not be able to obtain additional financing on satisfactory terms.

Even if we have access to the necessary capital, we may be unable to continue to identify additional suitable acquisition opportunities, negotiate acceptable terms or successfully acquire identified targets.

We operate in a highly competitive, fragmented industry in which price competition could reduce our profitability.

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

•

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

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the mobility and efficiency of the rigs;

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the quality of service and experience of the rig crews;

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the safety records of the rigs;

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the offering of ancillary services; and

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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 or an oversupply of drilling rigs 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 oversupply of rigs can cause greater price competition, which can reduce our profitability.

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:

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better withstand industry downturns;

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compete more effectively on the basis of price and technology;

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retain skilled rig personnel; and

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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 operations.

We have historically derived a significant portion of our revenues from turnkey drilling contracts, and turnkey contracts may 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 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 operations.

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:

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blowouts;

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fires and explosions;

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loss of well control;

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collapse of the borehole;

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lost or stuck drill strings; and

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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;

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

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personal injury and loss of life;

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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 risks 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 operations 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 federal, state and local laws and regulations governing the protection of the environment and human health and safety. Some of those laws and regulations relate to the disposal of hazardous oilfield waste substances and restrict the types, quantities and concentrations of those substances that can be released into the environment. Several of those laws also require removal and remedial action and other cleanup under certain circumstances, commonly regardless of fault. Planning, implementation and maintenance of

protective measures are required to prevent accidental discharges. Spills of oil, natural gas liquids, drilling fluids and other substances may subject us to penalties and cleanup requirements. Handling, storage and disposal of both hazardous and non-hazardous wastes are also subject to these regulatory requirements. 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, contaminated water or other substances, or for noncompliance with other aspects of applicable laws and regulations.

The federal Clean Water Act, as amended by the Oil Pollution Act, the federal Clean Air Act, the federal Resource Conservation and Recovery Act, the federal Comprehensive Environmental Response, Compensation, and Liability Act, or CERCLA, the Safe Drinking Water Act, the Occupational Safety and Health Act, or OSHA, and their state counterparts and similar statutes are the primary statutes that impose those requirements and provide for civil, criminal and administrative penalties and other sanctions for violation of their requirements. 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, CERCLA, also known as the “Superfund” law, and similar state statutes impose strict liability, without regard to fault or the legality of the original conduct, on certain classes of persons who are considered responsible for the release or threatened release of hazardous substances into the environment. These persons include the current owner or operator of a facility where a release has occurred, the owner or operator of a facility at the time a release occurred, and companies that disposed of or arranged for the disposal of hazardous substances found at a particular site. This liability may be joint and several. Such liability, which may be imposed for the conduct of others and for conditions others have caused, includes the cost of removal and remedial action as well as damages to natural resources. Few defenses exist to the liability imposed by environmental laws and regulations. It is also common for third parties to file claims for personal injury and property damage caused by substances released into the environment.

Environmental laws and regulations are complex and subject to frequent change. Failure to comply with governmental requirements or inadequate cooperation with governmental authorities could subject a responsible party to administrative, civil or criminal action. We may also be exposed to environmental or other liabilities originating from businesses and assets which we acquired from others. Our compliance with amended, new or more stringent requirements, stricter interpretations of existing requirements or the future discovery of contamination or regulatory noncompliance may require us to make material expenditures or subject us to liabilities that we currently do not anticipate.

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

We do not intend to pay dividends on our common stock in the foreseeable future, and therefore only appreciation of the price of our common stock will provide a return to our stockholders.

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 nominate candidates for election as directors or 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 1B.

Unresolved Staff Comments

None.

Item 2.

Properties

For a description of our significant properties, see “Business – Drilling Equipment” and “Business – Facilities” in Item 1 of this report. We consider each of our significant properties to be suitable for its intended use.

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 stockholders during the fourth quarter of fiscal year 2007.

PART II

Item 5.

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

As of May 11, 2007, 49,628,478 shares of our common stock were outstanding, held by 470 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, 2007:
First Quarter	$	12.60	$	18.00
Second Quarter		10.79		15.70
Third Quarter		11.57		14.65
Fourth Quarter		11.46		13.47

Fiscal Year Ended March 31, 2006:
First Quarter	$	10.57	$	16.30
Second Quarter		14.00		19.93
Third Quarter		14.25		19.98
Fourth Quarter		13.10		23.06

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

The last reported sales price for our common stock on the American Stock Exchange on May 11, 2007 was $14.08 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.

Performance Graph

The following graph compares, for the periods from March 31, 2002 to March 31, 2007, the cumulative shareholder return on our common stock with the (1) cumulative total return on the companies that comprise the AMEX Composite Index, (2) an old peer group index that includes three companies within our industry, and (3) a new peer group index that includes the three companies from the old peer group and two additional companies within our industry. The comparison assumes that $100 was invested on March 31, 2002 in our common stock, the companies that compose the AMEX Composite Index and the companies that compose the old and new peer group indexes, and further assumes all dividends were reinvested.

The companies that comprise the old peer group index are Helmerich & Payne, Inc., Grey Wolf, Inc. and Patterson-UTI Energy, Inc. The companies that comprise the new peer group index are Helmerich & Payne, Inc., Grey Wolf, Inc., Patterson-UTI Energy, Inc., Nabors Industries Ltd. and Unit Corp.

LOGO

Equity Compensation Plan Information

The following table provides information on our equity compensation plans as of March 31, 2007:


Plan category	Number of securities to be issued upon exercise of outstanding options, warrants and rights *(a)*	Weighted-average exercise price per share of outstanding options, warrants and rights *(b)*		Number of securities remaining available for future issuance under equity compensation plans (excluding securities reflected in column (a)) *(c)*
Equity compensation plans approved by security holders	1,946,500	$	9.29	1,228,333
Equity compensation plans not approved by security holders	—		—	—

Total	1,946,500	$	9.29	1,228,333

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,
	2007		2006		2005		2004			2003
	(In thousands, except per share amounts)
Contract drilling revenues	$	416,178	$	284,148	$	185,246	$	107,876		$	80,183
Income (loss) from operations		126,976		77,909		18,774		438			(4,943	)
Income (loss) before income taxes		130,788		79,813		17,161		(2,216	)		(7,305	)
Net earnings (loss) applicable to common stockholders		84,179		50,567		10,812		(1,790	)		(5,086	)
Earnings (loss) per common share-basic		1.70		1.08		0.31		(0.08	)		(0.31	)
Earnings (loss) per common share-diluted		1.68		1.06		0.30		(0.08	)		(0.31	)
Long-term debt and capital lease obligations, excluding current installments		—		—		13,445		44,892			45,855
Shareholders’ equity		428,109		340,676		221,615		70,836			47,672
Total assets		501,496		400,678		276,009		143,731			119,694
Capital expenditures		147,229		128,871		80,388		44,845			33,589

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 that are not historical fact, are forward-looking statements that are subject to risks, uncertainties and assumptions. Our actual results, performance or achievements, or industry results, could differ materially from those we express in the following discussion as a result of a variety of factors, including general economic and business conditions and industry trends, the continued strength or weakness of the contract land drilling industry in the geographic areas in which we operate, decisions about onshore exploration and development projects to be made by oil and gas companies, the highly competitive nature of our business, our future financial performance, including availability, terms and deployment of capital, the continued availability of qualified personnel, and changes in, or our failure or inability to comply with, government regulations, including those relating to the environment. We have discussed many of these factors in more detail elsewhere in this report, including under the headings “Cautionary Statement Concerning Forward-Looking Statements” in Item 1 and “Risk Factors” in Item 1A. 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, except as required by applicable securities laws and regulations. We advise our shareholders 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.

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 and forecasted future price of oil and natural gas. During the quarter ended December 31, 2006 and through the quarter ended March 31, 2007, we experienced a decline in the demand for drilling rigs and revenue rates on some contract renewals due to an excess supply of drilling rigs within the industry, which is due to the substantial addition of new and refurbished drilling rigs during the past year. Any continued slowdown in the demand for drilling rigs will likely result in lower revenue rates for our rigs as existing contracts expire.

Our business strategy is to own and operate a high-quality fleet of land drilling rigs in active drilling markets, to 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 as opportunities arise. We may also explore acquiring businesses in other sectors within the oilfield services industry or expanding into one or more international markets.

Since September 1999, we have significantly expanded our fleet of drilling rigs through acquisitions and the construction of new and refurbished rigs. As of May 11, 2007, our rig fleet consisted of 66 operating drilling rigs, of which 25 are premium electric rigs that drill in depth ranges between 6,000 and 18,000 feet. Seventeen of our rigs are operating in our South Texas division, 20 in our East Texas division, ten in our North Texas division, six in our western Oklahoma division and 13 in our Rocky Mountains divisions in Utah and North Dakota. We actively market all of these rigs. In April 2007, we acquired a 1500-horsepower diesel electric rig that is ideally suited for certain international markets that we are considering for possible expansion. This rig is not included in our 66 operating rig count as of May 11, 2007.

We earn our revenues by drilling oil and gas wells for our customers, as our rigs can be used by our customers to drill for either oil or natural gas. 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. Historically, our contracts provide for the drilling of a single well and typically permit the customer to terminate on short notice. As demand for drilling rigs improved during the past two years, we entered into more longer-term drilling contracts. As of May 11, 2007, we had 30 contracts with terms of six months to two years in duration, of which 14 will expire by November 11, 2007, six have a remaining term of six to 12 months, six have a remaining term of 12 to 18 months and four have a remaining term in excess of 18 months.

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 each period presented below, all of our rigs were capable of working and are included in our rig utilization calculations.

For the years ended March 31, 2006, 2005 and 2004 our rig utilization, revenue days and number of rigs were as follows:


	Years Ended March 31,
	2007		2006		2005
Utilization Rates	95	%	95	%	96	%
Revenue Days	20,930		18,164		13,894
Number of rigs at period end	65		56		50

The primary reason for the increase in the number of revenue days in 2007 over 2006 and 2005 is the increase in size of our rig fleet. Due to the current excess supply of drilling rigs available for work, we currently expect a 5% to 10% decrease in utilization rates for fiscal year 2008 as compared to fiscal year 2007.

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 during periods of reduced demand for drilling rigs.

We devote substantial resources to maintaining and upgrading our rig fleet. In the short term, these actions result in fewer revenue days and slightly lower utilization; however, in the long term, we believe the upgrades will help the marketability of our rigs and improve their operating performance. During the fiscal year ended March 31, 2007, we expended approximately $15,700,000 upgrading 15 rigs, using over 391 potential revenue days in the upgrade process. Upgrades for the fiscal year ending March 31, 2008 will primarily focus on: replacing older engines with more modern, efficient engines; upgrading to higher horsepower mud pumps; and upgrading to modern mud cleaning systems on some of our drilling rigs.

Market Conditions in Our Industry

The U.S. 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.

In addition, the availability of drilling rigs capable of working affects our revenue rates and utilization rates. For much of the past two years, our industry experienced a shortage of drilling rigs leading to revenue rates and utilization rates that were at historically high levels. However, our industry is currently experiencing an excess drilling rig supply due to new construction and refurbishments. This condition may correct itself over time if older drilling rigs are retired and if the outlook for oil and gas pricing improves and results in an increase in drilling activity.

On May 11, 2007, the spot price for West Texas Intermediate crude oil was $62.37, the spot price for Henry Hub natural gas was $7.54 and the Baker Hughes land rig count was 1,635, a 9% increase from 1,503 on May 12, 2006. Since September 1, 2006, the Baker Hughes land rig count has been between 1,586 and 1,662.

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, 2007 were:


	Years Ended March 31,
	2007		2006		2005		2004		2003		2002
Oil (West Texas Intermediate)	$	64.96	$	59.94	$	45.04	$	31.47	$	29.27	$	24.31
Natural Gas (Henry Hub)	$	6.53	$	9.10	$	5.99	$	5.27	$	4.24	$	2.96
U.S. Land Rig Count		1,589		1,329		1,110		964		723		912

Most of our customers drill in search of natural gas; however, we currently operate five rigs in the Williston Basin of the Rocky Mountains, where our customers drill in search of oil.

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 the American Institute of Certified Public Accountants’ Statement of Position 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.

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

We accrue estimated contract costs on turnkey and footage contracts for each day of work completed based on our estimate of the total costs to complete the contract divided by our estimate of the number of days to complete the contract. Contract costs include labor, materials, supplies, repairs and maintenance, operating overhead allocations and allocations of depreciation and amortization expense. In addition, the occurrence of uninsured or under-insured losses or operating cost overruns on our turnkey and footage contracts could have a material adverse effect on our financial position and results of operations. Therefore, our actual results for a contract could differ significantly if our cost estimates for that contract are later revised from our original cost estimates for a contract in progress at the end of a reporting period which was 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 utilization rates, cash flows from our drilling rigs, current oil and gas prices and 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, 2007, would have resulted in a corresponding decrease in our net earnings of approximately $2,867,000 for the fiscal year ended March 31, 2007.

Deferred taxes – We provide deferred taxes for the basis differences in our property and equipment between financial reporting and tax reporting purposes and other costs such as compensation, employee benefit and other accrued liabilities which are deducted in different periods for 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 five to 15 years and refurbishments over three to five 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 to be critical accounting estimates. On these types of contracts, we are required to estimate the number of days needed 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 increase our cost estimate 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 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 2007, we experienced losses on 13 of the 62 turnkey and footage contracts completed, with losses exceeding $25,000 each on five contracts. During fiscal year 2006, we experienced losses on 16 of the 124 turnkey and footage contracts completed, with losses exceeding $25,000 each on five contracts, and a loss exceeding $100,000 on one contract. We are more likely to encounter losses on turnkey and footage contracts in periods 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. We had two footage contracts in progress at March 31, 2007, which were completed prior to the release of the financial statements included in this report. Our contract drilling in progress totaled approximately $9,837,000 at March 31, 2007. Of that amount accrued, footage contract revenues were approximately $329,000. The remaining balance of approximately $9,508,000 related to the revenue recognized but not yet billed on daywork contracts in progress at March 31, 2007. At March 31, 2006, drilling in progress totaled $9,620,000, of which $599,000 related to footage contracts and $9,021,000 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 90 days for any of our contracts in the last three fiscal years. We had an allowance for doubtful accounts of $1,000,000 and $200,000 at March 31, 2007 and March 31, 2006, respectively.

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 insurance premiums and deductibles as of March 31, 2007 include accruals of approximately $591,000 and $4,439,000 for costs incurred under the self-insurance portion of our health insurance and under our workers’ compensation insurance, respectively. We have a deductible of (1) $125,000 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 we do not have a deductible. We accrue for these costs as claims are incurred based on historical claim development data, and we accrue the costs of administrative services associated with claims processing. We also evaluate our claim cost estimates based on estimates provided by the insurance companies that provide claims processing services.

Liquidity and Capital Resources

Sources of Capital Resources

Our rig fleet has grown from eight rigs in August 2000 to 66 rigs as of May 11, 2007. We have financed this growth with a combination of debt and equity financing. We have raised additional equity or used equity for growth nine times since January 2000. We plan to continue to grow our rig fleet and we may pursue other business opportunities that are complementary to our U.S. contract land drilling business. We may finance these growth opportunities through the issuance of debt and the issuance of additional shares of our common stock.

On February 10, 2006, we sold 3,000,000 shares of our common stock, at approximately $20.63 per share, net of underwriters’ commissions, in a public offering we registered with the U.S. Securities and Exchange Commission (the “SEC”).

We have a $20,000,000 credit facility with Frost National Bank consisting of a $10,000,000 revolving line and letter of credit facility and a $10,000,000 acquisition facility for the acquisition of drilling rigs, drilling rig transportation equipment and associated equipment. Borrowings under the credit facility bear interest at a rate equal to Frost National Bank’s prime rate (8.25% at March 31, 2007) or, at our option, at LIBOR plus a percentage ranging from 1.5% to 2.25%, based on our operating leverage ratio. Borrowings are secured by most of our assets, including all our drilling rigs and associated equipment and receivables. At March 31, 2007, we had no borrowings under the acquisition facility and we had used approximately $4,267,000 of availability under the revolving line and letter of credit facility through the issuance of letters of credit in the ordinary course of business. The remaining availability under the revolving line and letter of credit facility is $5,733,000. Both the revolving line and letter of credit facility and acquisition facility are scheduled to mature in October 2008.

Uses of Capital Resources

For the years ended March 31, 2007 and 2006, the additions to our property and equipment consisted of the following:


	Years Ended March 31,
	2007		2006
Drilling rigs (1)	$	74,456,906	$	72,311,690
Other drilling equipment		63,659,639		51,403,189
Transportation equipment		7,597,250		3,491,554
Other		1,515,508		1,665,014

	$	147,229,303	$	128,871,447

(1)	Includes capitalized interest costs of $194,500 in 2006. No capitalized interest costs in 2007.

Property and equipment additions for the year ended March 31, 2007 include $2,722,424 of purchases recorded in accounts payable at March 31, 2007.

As of March 31, 2007, we were constructing one 1000-horsepower mechanical rig. We placed this rig into service in April 2007. As of March 31, 2007, we had incurred approximately $8,567,000 of the approximately $9,600,000 of construction costs for this rig. We do not currently have any plans to build additional new rigs. In April 2007, we acquired a 1500-horsepower diesel electric rig for approximately $10,700,000 that is ideally suited for certain international markets that we are considering for possible expansion.

For fiscal year 2008, we project capital expenditures excluding new rig construction and acquisitions to be approximately $77,750,000, comprised of routine rig capital expenditures of approximately $32,000,000, rig upgrade expenditures of approximately $33,650,000 (including approximately $12,350,000 for iron roughnecks and $5,900,000 for top drives), spare equipment expenditures of approximately $6,700,000, transportation equipment expenditures of approximately $4,000,000, and other capital expenditures of approximately $1,400,000. We expect to fund these capital expenditures primarily from operating cash flow in excess of our working capital and other normal cash flow requirements.

Working Capital

Our working capital was $124,088,849 at March 31, 2007, compared to $106,904,106 at March 31, 2006. Our current ratio, which we calculate by dividing our current assets by our current liabilities, was 4.6 at March 31, 2007, compared to 4.3 at March 31, 2006.

Our operations have historically generated cash flows sufficient to at least meet our requirements for debt service and normal capital expenditures. However, during periods when higher percentages of our contracts are turnkey and footage contracts, our short-term working capital needs could increase. If necessary, we can defer rig upgrades to improve our cash position. The significant improvement in operating cash flow for the fiscal year ended March 31, 2007 over March 31, 2006 is due primarily to the approximately $33,613,000 improvement in net earnings, plus the increase of approximately $19,469,000 in depreciation and amortization expense, as a result of the additions to our rig fleet in fiscal year 2007. We believe our cash generated by operations and our ability to borrow under the currently unused portion of our line of credit and letter of credit facility 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,
	2007		2006		Change
Cash and cash equivalents	$	84,945,210	$	91,173,764	$	(6,228,554	)
Trade receivables, net		54,205,696		35,544,543		18,661,153
Contract drilling in progress		9,837,323		9,620,179		217,144
Income tax receivable		3,491,846		—		3,491,846
Deferred income taxes		2,174,947		989,895		1,185,052
Prepaid expenses		3,653,096		2,207,853		1,445,243

Current assets		158,308,118		139,536,234		18,771,884

Accounts payable		18,625,737		16,040,568		2,585,169
Income tax payable		—		6,834,877		(6,834,877	)
Prepaid drilling contracts		—		139,769		(139,769	)
Accrued payroll and related employee costs		7,086,450		4,974,602		2,111,848
Accrued insurance premiums and deductibles		6,754,331		3,850,325		2,904,006
Other accrued expenses		1,752,751		791,987		960,764

Current liabilities		34,219,269		32,632,128		1,587,141

Working capital	$	124,088,849	$	106,904,106	$	17,184,743

The large cash balance at March 31, 2006 was primarily due to our sale of shares of common stock on February 10, 2006 for net proceeds of approximately $61,700,000. The decrease in cash and cash equivalents at March 31, 2007 as compared to March 31, 2006 was primarily due to an increase in property and equipment expenditures from approximately $128,871,000 for the year ended March 31, 2006 to $147,229,000 for the year ended March 31, 2007. The decrease in cash and cash equivalents was partially offset by an increase due to an increase in net cash provided by operating activities from approximately $97,084,000 for the year ended March 31, 2006 to $131,530,000 for the year ended March 31, 2007.

The increase in our trade receivables and contract drilling in progress at March 31, 2007 from March 31, 2006 was due to our operating nine additional rigs and the increase of approximately $2,200 per day in average revenue rates for the fourth quarter of fiscal year 2007 compared to the fourth quarter of fiscal year 2006.

The income tax receivable at March 31, 2007 was primarily due to our March 15, 2007 estimated federal income tax deposit being based on annualized taxable income for the first nine months of fiscal year 2007, which resulted in an over-payment of the March 15, 2007 income tax deposit.

Substantially all our prepaid expenses at March 31, 2007 and March 31, 2006 consisted of prepaid insurance. The increase in prepaid insurance was primarily due to an increase in insurance premiums resulting from the increase in the size of our drilling rig fleet from 56 rigs at March 31, 2006 to 65 rigs at March 31, 2007.

The increase in accounts payable was primarily due to our operating nine additional rigs and the increase of approximately $2,200 per day in average drilling costs for the fourth quarter of fiscal year 2007 compared to the fourth quarter of fiscal year 2006. The increase was partially offset by a decrease in accounts payable due to one rig under construction at March 31, 2007, as compared to nine rigs under construction at March 31, 2006.

The increase in accrued payroll and related employee costs was primarily due to the increase in the number of our employees due to the rig additions, an increase in rig employee wage rates, an increase in bonus accruals of approximately $618,000 and an increase in vacation accruals of approximately $124,000.

The increase in accrued insurance deductibles at March 31, 2007 from March 31, 2006 was due to an increase in our estimates of claims incurred but not reported for health insurance, workers’ compensation and general liability insurance policies.

The increase in other accrued expenses at March 31, 2007 from March 31, 2006 was due to an increase of approximately $740,000 in sales and use taxes accruals and an increase of approximately $299,000 in property tax accruals.

Long-term Debt

We had no long-term debt outstanding at March 31, 2007. See “Sources of Capital Resources” for a description of our credit facility.

Contractual Obligations

The following table includes all our contractual obligations of the types specified below at March 31, 2007.


	Payments Due by Period
Contractual Obligations	Total		Less than 1 year		1-3 years		4-5 years		More than 5 years
Purchase Obligations	$	17,863,153	$	17,863,153	$	—	$	—	$	—
Operating Lease Obligations		1,657,855		305,785		527,023		435,567		389,480

Total	$	19,521,008	$	18,168,938	$	527,023	$	435,567	$	389,480

Debt Requirements

The sum of (1) the draws 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 credit facility is limited to 75% of our eligible accounts receivable, not to exceed $10,000,000. Therefore, if 75% of our eligible accounts receivable was less than $10,000,000, our ability to draw under this line would be reduced. At March 31, 2007, we had no outstanding advances under this line of credit, we had outstanding letters of credit of approximately $4,267,000 and 75% of our eligible accounts receivable was approximately $36,052,000. The letters of credit have been 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.

Our 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 0.2 to 1, an operating leverage ratio of not more than 2.5 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, to the extent not otherwise 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, 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.

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 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.

During periods of reduced demand for drilling rigs or excess capacity of drilling rigs in the industry, revenue rates and utilization rates may be significantly lower than the rates we are currently experiencing. Our profitability in the future will depend on many factors, but largely on utilization rates and revenue rates for our drilling rigs.

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

For the fiscal years ended March 31, 2007, 2006 and 2005, the percentages of our drilling revenues by type of contract were as follows:


	Years Ended March 31,
	2007		2006		2005
Daywork Contracts	96	%	89	%	52	%
Turnkey Contracts	1	%	4	%	43	%
Footage Contracts	3	%	7	%	5	%

We had no turnkey contracts in progress at March 31, 2007 or at March 31, 2006. We had two footage contracts in progress at both March 31, 2007 and March 31, 2006.

Statements of Operations Analysis

The following table provides information about our operations for the years ended March 31, 2007, March 31, 2006, and March 31, 2005.


	Years Ended March 31,
	2007			2006			2005
Contract drilling revenues:
Daywork contracts	$	399,188,247		$	252,103,112		$	95,997,451
Turnkey contracts		3,444,732			10,829,977			80,210,813
Footage contracts		13,545,202			21,214,885			9,038,184

Total contract drilling revenues	$	416,178,181		$	284,147,974		$	185,246,448

Contract drilling costs:
Daywork contracts	$	211,334,348		$	143,129,634		$	68,307,797
Turnkey contracts		2,614,988			7,449,088			63,313,296
Footage contracts		10,473,644			15,632,438			6,646,045

Total contract drilling costs	$	224,422,980		$	166,211,160		$	138,267,138

Drilling margin:
Daywork contracts	$	187,853,899		$	108,973,478		$	27,689,654
Turnkey contracts		829,744			3,380,889			16,897,517
Footage contracts		3,071,558			5,582,447			2,392,139

Total drilling margin	$	191,755,201		$	117,936,814		$	46,979,310

Revenue days by type of contract:
Daywork contracts		19,995			16,138			8,685
Turnkey contracts		81			558			4,471
Footage contracts		854			1,468			738

Total revenue days		20,930			18,164			13,894

Contract drilling revenue per revenue day	$	19,884		$	15,643		$	13,333
Contract drilling costs per revenue day	$	10,723		$	9,151		$	9,952
Drilling margin per revenue day	$	9,161		$	6,492		$	3,381
Rig utilization rates		95	%		95	%		96	%
Average number of rigs during the period		60.8			52.3			40.1

We present drilling margin information because we believe it provides investors and our management additional information to assist them in assessing our business and performance in comparison to other companies in our industry. Since drilling margin is a “non-GAAP” financial measure under the rules and regulations of the SEC, we are providing the following reconciliation of drilling margin to net earnings, which is the nearest comparable GAAP financial measure.


	Years Ended March 31,
	2007			2006			2005
Reconciliation of drilling margin to net earnings:
Drilling margin	$	191,755,201		$	117,936,814		$	46,979,310
Depreciation and amortization		(52,856,467	)		(33,387,523	)		(23,090,909	)
General and administrative expense		(11,122,950	)		(6,792,252	)		(4,872,634	)
Bad debt (expense) recovery		(800,000	)		152,000			(242,000	)
Other income (expense)		3,812,611			1,904,181			(1,612,641	)
Income tax (expense) benefit		(46,609,188	)		(29,246,617	)		(6,349,501	)

Net earnings	$	84,179,207		$	50,566,603		$	10,811,625

Our contract drilling revenues grew by approximately $132,030,000, or 46%, in fiscal year 2007 from fiscal year 2006, primarily due to an improvement of $4,241 per day in average rig revenue rates resulting from an increase in demand for drilling rigs and the 15% increase in revenue days that primarily resulted from an increase in the number of rigs in our fleet.

Our contract drilling revenues grew by approximately $98,902,000, or 53%, in fiscal year 2006 from fiscal year 2005, primarily due to an improvement of $2,310 per day in average rig revenue rates resulting from an increase in demand for drilling rigs and the 31% increase in revenue days that primarily resulted from an increase in the number of rigs in our fleet, which was partially offset by a 1% decrease in rig utilization.

Our contract drilling costs grew by approximately $58,212,000, or 35%, in fiscal year 2007 from fiscal year 2006, primarily due to an increase in average drilling costs per revenue day of $1,572, and an increase in the number of revenue days resulting from the increase in the number of rigs in our fleet. The increase in average drilling costs per revenue day was primarily attributable to an increase in wage rates for rig personnel and an increase in supplies, repairs and maintenance expenses.

Our contract drilling costs grew by approximately $27,944,000, or 20%, in fiscal year 2006 from fiscal year 2005, primarily due to an increase in the number of revenue days resulting from the increase in the number of rigs in our fleet, which was partially offset by the 1% decrease in rig utilization discussed above. The $801 decline in average contract drilling cost per revenue day was primarily due to the shift to more daywork revenue days as a percentage of total revenue days. Daywork days represented 89% of revenue days in the fiscal year 2006, compared to 63% in fiscal year 2005. Under turnkey and footage contracts, we provide supplies and materials such as fuel, drill bits, casing and drilling fluids, which significantly adds to drilling costs for turnkey and footage contracts. These costs are also included in the revenues we recognize for turnkey and footage contracts, resulting in higher revenue rates per day for turnkey and footage contracts compared to daywork contracts which do not include such costs.

Our depreciation and amortization expense in fiscal year 2007 increased by approximately $19,469,000, or 58%, from fiscal year 2006. The increase in 2007 over 2006 resulted from our addition of ten drilling rigs and related equipment in 2007 at a cost of approximately $91,410,000 and rig upgrade costs of approximately $19,917,000. The higher costs of our new rigs increased our average depreciation costs per revenue day by $687 to $2,525 in fiscal year 2007 from $1,838 in fiscal year 2006.

Our depreciation and amortization expense in fiscal year 2006 increased by approximately $10,297,000, or 45%, from fiscal year 2005. The increase in 2006 over 2005 resulted from our addition of six drilling rigs and related equipment in 2006 at a cost of approximately $48,724,000 and rig upgrade costs of approximately $21,446,000. The higher costs of our new rigs increased our average depreciation costs per revenue day by $176 to $1,838 in fiscal year 2006 from $1,662 in fiscal year 2005.

Our general and administrative expenses increased by approximately $4,331,000, or 64%, in fiscal year 2007 from fiscal year 2006. The increase resulted primarily from stock-based compensation costs and an increase in payroll and bonus accrual costs. Effective April 1, 2006, we adopted Statement of Financial Accounting Standards (“SFAS”) No. 123 (Revised), Share-Based Payment, and, as a result, recognized approximately $2,536,000 of stock-based compensation expense in general and administrative expense in fiscal year 2007. See the “Stock-based Compensation” section of Note 1 to the consolidated financial statements included in this report for additional information. Payroll and bonus accrual costs increased by approximately $1,433,000 in fiscal year 2007, due to pay raises and an increase in the number of employees in our corporate office as compared to fiscal year 2006.

Our general and administrative expenses increased by approximately $1,920,000, or 39%, in fiscal year 2006 from fiscal year 2005. The increase resulted primarily from increases in payroll costs, bonus accrual costs, professional fees, office rent and insurance costs. During fiscal year 2006, payroll costs increased by approximately $1,029,000, due to pay raises, an increase in the number of employees in our corporate office and an increase in bonus costs of approximately $256,000 as compared to fiscal year 2005. Professional fees increased by approximately $453,000, office rent increased by approximately $142,000 and insurance costs increased by approximately $119,000.

Other income increased by approximately $1,908,000, or 100%, in fiscal year 2007 from fiscal year 2006 due to increased interest income that resulted from higher average cash and cash equivalents balances during fiscal year 2007 as compared to fiscal year 2006. Average cash and cash equivalents balances were approximately $85,700,000 in fiscal year 2007 and $56,500,000 in fiscal year 2006.

We recognized other income of approximately $1,904,000 in fiscal year 2006, as compared to other expense of approximately $1,613,000 in fiscal year 2005, primarily due to increased interest income that resulted from increased cash and cash equivalents balances and decreased interest expense that resulted from decreased outstanding debt balances. Cash and cash equivalents increased from $69,673,279 at March 31, 2005 to $91,173,764 at March 31, 2006. We had no debt outstanding at March 31, 2006 compared to long-term debt outstanding of $18,077,778 at March 31, 2005 after making a long-term debt payment of $20,000,000 on March 29, 2005.

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 $332,000. We are not aware of any potential environmental clean-up obligations that would have a material adverse effect on our financial condition or results of operations.

Our effective income tax rates of 35.6% for the year ended March 31, 2007, 36.6% for the year ended March 31, 2006 and 37% for the year ended March 31, 2005, differ from the federal statutory rate of 35% for fiscal years 2007 and 2006 and 34% for fiscal year 2005, due to permanent differences and state income taxes. Permanent differences are costs included in results of operations in the accompanying financial statements which are not fully deductible for federal income tax purposes. During the quarter ended June 30, 2006, we recognized a nonrecurring increase in income tax expense and deferred income taxes of approximately $362,000, due to the effects of changes in Texas franchise taxes on the future reversals of temporary differences. The Texas franchise tax changes became effective June 1, 2006. At March 31, 2005, we had net operating loss carryforwards for income tax purposes of approximately $16,500,000, which were fully utilized in fiscal year 2006.

Inflation

Due to the increased rig count in each of our market areas, availability of personnel to operate our rigs is limited. In April 2005, January 2006 and May 2006, we raised wage rates for our rig personnel by an average of 6%, 6% and 14%, respectively. We were able to pass these wage rate increases on to our customers based on contract terms. We currently do not anticipate additional wage rate increases in fiscal year 2008.

We are experiencing increases in costs for rig repairs and maintenance and costs of rig upgrades and new rig construction, due to the increased industry-wide demand. We estimate these costs increased between 10% and 15% in fiscal year 2007, and we may experience similar cost increases in fiscal year 2008 if the rig count continues to increase. We may not be able to recover these cost increases through improvements in our daywork revenue rates.

Off Balance Sheet Arrangements

We do not currently have any off balance sheet arrangements.

Recently Issued Accounting Standards

In July 2006, the Financial Accounting Standards Board (the “FASB”) issued FASB Interpretation No. 48, Accounting for Uncertainty in Income Taxes-An Interpretation of FASB Statement No. 109 (“FIN 48”). FIN 48 clarifies the accounting for uncertainty in income taxes recognized in a company’s financial statements in accordance with SFAS No. 109. FIN 48 also prescribes a recognition threshold and measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. The new FASB standard also provides guidance on derecognition, classification, interest and penalties, accounting in interim periods, disclosure and transition. FIN 48 is effective for fiscal years beginning after December 15, 2006. We do not expect the adoption of FIN 48 to have a material impact on our financial position or results of operations and financial condition.

In September 2006, the FASB issued SFAS No. 157, Fair Value Measurements. SFAS No. 157 defines fair value, establishes a framework for measuring fair value and expands disclosure of fair value measurements. SFAS No. 157 applies under other accounting pronouncements that require or permit fair value measurements and, accordingly, does not require any new fair value measurements. SFAS No. 157 is effective for financial statements issued for fiscal years beginning after November 15, 2007. We do not expect the adoption of SFAS No. 157 to have a material impact on our financial position or results of operations and financial condition.

In September 2006, the FASB issued Staff Position AUG AIR-1, Accounting for Planned Major Maintenance Activities, which eliminates the acceptability of the accrue-in-advance method of accounting for planned major maintenance activities. This FASB Staff Position is effective for fiscal years beginning after December 15, 2006. We do not use the accrue-in-advance method of accounting for rig refurbishments. We use a “built-in overhaul” method of accounting for rig refurbishments, whereby these expenditures are recognized as capital asset additions when incurred. The application of this FASB Staff Position will not have a material impact on our financial position or results of operations and financial condition.

In September 2006, the SEC released Staff Accounting Bulletin No. 108, Considering the Effects of Prior Year Misstatements When Quantifying Misstatements in Current Year Financial Statements, (“SAB 108”), which provides interpretive guidance on the SEC’s views regarding the process of quantifying materiality of financial statement misstatements. SAB 108 is effective for fiscal years ending after November 15, 2006, with early application for the first interim period ending after November 15, 2006. Since we had no prior-year misstatements during the year ended March 31, 2007, the application of SAB 108 did not have a material effect on our financial position or results of operations and financial condition.

In February 2007, the FASB issued SFAS No. 159, The Fair Value Option for Financial Assets and Financial Liabilities — Including an amendment of FASB Statement No. 115. This statement permits entities to choose to measure many financial instruments and certain other items at fair value that are not currently required to be measured at fair value and establishes presentation and disclosure requirements designed to facilitate comparisons between entities that choose different measurement attributes for similar types of assets and liabilities. SFAS No. 159 is effective for fiscal years beginning after November 15, 2007. Early adoption is permitted as of the beginning of a

fiscal year that begins on or before November 15, 2007, provided the entity also elects to apply the provisions of SFAS No. 157. We do not expect the adoption of SFAS No. 159 to have a material impact on our financial position or results of operations and financial condition.

Item 7A.

Quantitative and Qualitative Disclosures About Market Risk

Our exposure to market risk from changes in interest rates primarily relates to our cash equivalents, which consist of investments in highly liquid debt instruments denominated in U.S. dollars. We are averse to principal loss and ensure the safety and preservation of our invested funds by limiting default risk, market risk and reinvestment risk.

We are subject to market risk exposure related to changes in interest rates on floating rate debt we may incur under our credit facility. However, at March 31, 2007, we had no outstanding borrowings under our credit facility.

Item 8.

Financial Statements and Supplementary Data

PIONEER DRILLING COMPANY

INDEX TO CONSOLIDATED FINANCIAL STATEMENTS


		Page

Reports of Independent Registered Public Accounting Firm		33

Consolidated Balance Sheets as of March 31, 2007 and 2006		35

Consolidated Statements of Operations for the Years Ended March 31, 2007, 2006 and 2005		36

Consolidated Statements of Shareholders’ Equity and Comprehensive Income for the Years Ended March 31, 2007, 2006 and 2005		37

Consolidated Statements of Cash Flows for the Years Ended March 31, 2007, 2006 and 2005		38

Notes to Consolidated Financial Statements		39

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Shareholders

Pioneer Drilling Company:

We have audited the accompanying consolidated balance sheets of Pioneer Drilling Company and subsidiaries (the Company) as of March 31, 2007 and 2006, and the related consolidated statements of operations, stockholders’ equity and comprehensive income, and cash flows for each of the years in the three-year period ended March 31, 2007. In connection with our audits of the consolidated financial statements, we also have audited the financial statement schedule II. These consolidated financial statements and financial statement schedule are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated financial statements and financial statement schedule based on our audits.

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

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Pioneer Drilling Company and subsidiaries as of March 31, 2007 and 2006, and the results of their operations and their cash flows for each of the years in the three-year period ended March 31, 2007, in conformity with U.S. generally accepted accounting principles. Also in our opinion, the related financial statement schedule, when considered in relation to the basic consolidated financial statements taken as a whole, presents fairly, in all material respects, the information set forth therein.

As discussed in Note 1 to the consolidated financial statements, the Company adopted the provisions of Statement of Financial Accounting Standards No. 123 (Revised 2004), Share-Based Payment, effective April 1, 2006.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the effectiveness of Pioneer Drilling Company’s internal control over financial reporting as of March 31, 2007, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), and our report dated May 16, 2007 expressed an unqualified opinion on management’s assessment of, and the effective operation of, internal control over financial reporting.

/s/ KPMG LLP

San Antonio, Texas

May 16, 2007

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

The Board of Directors and Stockholders

Pioneer Drilling Company:

We have audited management’s assessment, included in the accompanying Management’s Report on Internal Control over Financial Reporting that Pioneer Drilling Company and subsidiaries (the Company) maintained effective internal control over financial reporting as of March 31, 2007, 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) (PCAOB). 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 internal control over financial reporting, evaluating management’s assessment, testing and evaluating the design and operating effectiveness of internal control, 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, 2007, 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, 2007, 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, 2007 and 2006, and the related consolidated statements of operations, stockholders’ equity and comprehensive income, and cash flows for each of the years in the three-year period ended March 31, 2007, and our report dated May 16, 2007 expressed an unqualified opinion on those consolidated financial statements.

/s/ KPMG LLP

San Antonio, Texas

May 16, 2007

PIONEER DRILLING COMPANY AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS


	March 31,
	2007		2006
ASSETS
Current assets:
Cash and cash equivalents	$	84,945,210	$	91,173,764
Receivables:
Trade, net		54,205,696		35,544,543
Contract drilling in progress		9,837,323		9,620,179
Income tax receivable		3,491,846		—
Deferred income taxes		2,174,947		989,895
Prepaid expenses		3,653,096		2,207,853

Total current assets		158,308,118		139,536,234

Property and equipment, at cost:
Drilling rigs and equipment		441,071,812		328,673,207
Transportation equipment		15,940,615		9,169,461
Land, buildings and other		5,736,459		3,925,614

		462,748,886		341,768,282
Less accumulated depreciation and amortization		119,847,687		80,984,991

Net property and equipment		342,901,199		260,783,291
Intangible and other assets		286,307		358,180

Total assets	$	501,495,624	$	400,677,705


LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities:
Accounts payable	$	18,625,737	$	16,040,568
Income tax payable		—		6,834,877
Prepaid drilling contracts		—		139,769
Accrued expenses:
Payroll and related employee costs		7,086,450		4,974,602
Insurance premiums and deductibles		6,754,331		3,850,325
Other		1,752,751		791,987

Total current liabilities		34,219,269		32,632,128
Non-current liabilities		346,196		387,524
Deferred income taxes		38,820,868		26,982,526

Total liabilities		73,386,333		60,002,178

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; 49,628,478 shares and 49,591,978 shares issued and outstanding at March 31, 2007 and March 31, 2006, respectively		4,962,847		4,959,197
Additional paid-in capital		291,607,071		288,356,164
Accumulated earnings		131,539,373		47,360,166

Total shareholders’ equity		428,109,291		340,675,527

Total liabilities and shareholders’ equity	$	501,495,624	$	400,677,705

See accompanying notes to consolidated financial statements.

PIONEER DRILLING COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS


	Years Ended March 31,
	2007			2006			2005
Contract drilling revenues	$	416,178,181		$	284,147,974		$	185,246,448

Costs and expenses:
Contract drilling		224,422,980			166,211,160			138,267,138
Depreciation and amortization		52,856,467			33,387,523			23,090,909
General and administrative		11,122,950			6,792,252			4,872,634
Bad debt expense (recovery)		800,000			(152,000	)		242,000

Total operating costs and expenses		289,202,397			206,238,935			166,472,681

Income from operations		126,975,784			77,909,039			18,773,767


Other income (expense):
Interest expense		(73,158	)		(236,012	)		(1,722,393	)
Interest income		3,827,988			2,068,767			173,318
Other		57,781			71,426			37,267
Loss from early extinguishment of debt		—			—			(100,833	)

Total other income (expense)		3,812,611			1,904,181			(1,612,641	)

Income before income taxes		130,788,395			79,813,220			17,161,126
Income tax expense		(46,609,188	)		(29,246,617	)		(6,349,501	)

Net earnings	$	84,179,207		$	50,566,603		$	10,811,625

Earnings per common share - Basic	$	1.70		$	1.08		$	0.31

Earnings per common share - Diluted	$	1.68		$	1.06		$	0.30

Weighted average number of shares outstanding - Basic		49,602,999			46,808,323			34,543,695

Weighted average number of shares outstanding - Diluted		50,131,895			47,505,885			37,577,927

See accompanying notes to consolidated financial statements.

PIONEER DRILLING COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF SHAREHOLDERS’ EQUITY AND COMPREHENSIVE INCOME


	Shares Common	Amount Common		Additional Paid In Capital		Accumulated Earnings (Deficit)			Total Shareholders’ Equity
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
Comprehensive income:
Net earnings	—		—		—		50,566,603			50,566,603

Total comprehensive income	—		—		—		—			50,566,603

Issuance of common stock for:
Sale, net of related expenses of $968,361	3,000,000		300,000		61,401,639		—			61,701,639
Exercise of options and related income tax benefits of $4,009,945	698,667		69,866		6,722,005		—			6,791,871

Balance as of March 31, 2006	49,591,978		4,959,197		288,356,164		47,360,166			340,675,527
Comprehensive income:
Net earnings	—		—		—		84,179,207			84,179,207

Total comprehensive income	—		—		—		—			84,179,207

Issuance of common stock for:
Exercise of options and related income tax benefits of $24,287	36,500		3,650		189,726		—			193,376
Stock-based compensation expense	—		—		3,061,181		—			3,061,181

Balance as of March 31, 2007	49,628,478	$	4,962,847	$	291,607,071	$	131,539,373		$	428,109,291

See accompanying notes to consolidated financial statements.

PIONEER DRILLING COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS


	Years Ended March 31,
	2007			2006			2005
Cash flows from operating activities:
Net earnings	$	84,179,207		$	50,566,603		$	10,811,627
Adjustments to reconcile net earnings to net cash provided by operating activities:
Depreciation and amortization		52,856,467			33,387,523			23,090,909
Allowance for doubtful accounts		800,000			(152,000	)		242,000
Loss on dispositions of property and equipment		5,759,900			2,895,752			696,345
Stock-based compensation expense		3,061,181			—			—
Deferred income taxes		10,653,290			14,279,109			5,987,991
Change in other assets		20,000			209,525			(123,263	)
Change in non-current liabilities		(41,326	)		(12,476	)		—
Changes in current assets and liabilities:
Receivables		(23,170,143	)		(13,539,902	)		(11,682,035	)
Prepaid expenses		(1,445,243	)		(331,010	)		(540,507	)
Accounts payable		(137,255	)		418,921			2,350,658
Income tax payable		(6,842,507	)		6,638,928			195,949
Prepaid drilling contracts		(139,769	)		(32,981	)		172,750
Accrued expenses		5,976,618			2,756,442			2,462,523

Net cash provided by operating activities		131,530,420			97,084,434			33,664,947

Cash flows from financing activities:
Proceeds from notes payable		—			—			41,354,367
Proceeds from exercise of options		174,419			6,791,871			958,412
Proceeds from common stock, net of offering cost of $968,361 in 2006 and $5,807,193 in 2005		—			61,701,639			111,009,058
Payments of debt		—			(18,860,018	)		(43,809,329	)
Excess tax benefit of stock option exercises		26,588			—			—

Net cash provided by financing activities		201,007			49,633,492			109,512,508

Cash flows from investing activities:
Business acquisitions		—			—			(35,200,000	)
Purchases of property and equipment		(144,506,881	)		(128,871,447	)		(45,188,484	)
Proceeds from sale (purchase) of marketable securities, net		—			1,000,000			3,550,000
Proceeds from sale of property and equipment		6,546,900			2,654,006			1,518,549

Net cash used in investing activities		(137,959,981	)		(125,217,441	)		(75,319,935	)

Net increase (decrease) in cash and cash equivalents		(6,228,554	)		21,500,485			67,857,520
Beginning cash and cash equivalents		91,173,764			69,673,279			1,815,759

Ending cash and cash equivalents	$	84,945,210		$	91,173,764		$	69,673,279

Supplementary disclosure:
Interest paid	$	104,395		$	407,158		$	2,407,193
Income tax paid (refunded)	$	46,258,335		$	4,321,619		$	(30,000	)
Debenture conversion - common stock issued	$	—		$	—		$	28,000,000
Tax benefit from exercise of nonqualified options	$	—		$	4,009,945		$	204,964

See accompanying notes to consolidated financial statements.

PIONEER DRILLING COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1.	Organization and Summary of Significant Accounting Policies

Business and Principles of Consolidation

Pioneer Drilling Company provides contract land drilling services to its customers in select oil and natural gas exploration and production regions in the United States. As of March 31, 2007, our rig fleet consisted of 65 operating drilling rigs, 17 of which were operating in our South Texas division, 20 of which were operating in our East Texas division, ten of which were operating in our North Texas division, six of which were operating in our Western Oklahoma division and 12 of which were operating in our Rocky Mountain divisions in Utah and North Dakota. In April 2007, we completed construction of a rig that was placed in service in our Utah division. In addition, we acquired a rig in April 2007 that is ideally suited for certain international markets that we are considering for possible expansion. We conduct our operations through our principal operating subsidiary, Pioneer Drilling Services, Ltd. The accompanying consolidated financial statements include our accounts and the accounts of our wholly owned subsidiaries. All intercompany balances and transactions have been eliminated in consolidation.

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

Drilling Contracts

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, during periods of high rig demand, we enter into more longer-term drilling contracts. In addition, we have entered into longer-term drilling contracts for our newly constructed rigs. As of May 11, 2007, we had 30 contracts with terms of six months to two years in duration, of which 14 will expire by November 11, 2007, six have a remaining term of six to 12 months, six have a remaining term of 12 to 18 months and four have a remaining term in excess of 18 months.

Income Taxes

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

Earnings Per Common Share

We compute and present earnings per common share in accordance with SFAS No. 128, “Earnings per Share.” This standard requires dual presentation of basic and diluted earnings per share on the face of our statement of operations.

Stock-based Compensation

Effective April 1, 2006, we adopted SFAS No. 123 (Revised), Share-Based Payment (“SFAS 123R”), utilizing the modified prospective approach. Prior to the adoption of SFAS 123R, we accounted for stock option grants in accordance with the intrinsic-value-based method prescribed by Accounting Principles Board Opinion No. 25, Accounting for Stock Issued to Employees (“APB 25”), and related interpretations, as permitted by SFAS No. 123, Accounting for Stock-Based Compensation (“SFAS 123”). Accordingly, we recognized no compensation expense for stock options granted, as all stock options were granted at an exercise price equal to the closing market value of the underlying common stock on the date of grant. Under the modified prospective approach, compensation cost for the fiscal year ended March 31, 2007 includes compensation cost for all stock options granted prior to, but not yet vested as of, April 1, 2006, based on the grant-date fair value estimated in accordance with SFAS 123, and compensation cost for all stock options granted subsequent

to April 1, 2006, based on the grant-date fair value estimated in accordance with SFAS 123R. We use the graded vesting method for recognizing compensation costs for stock options. Prior periods were not restated to reflect the impact of adopting this new standard.

As a result of adopting SFAS 123R on April 1, 2006, our income before income taxes, net earnings and basic and diluted earnings per common share for the fiscal year ended March 31, 2007 were $3,060,937, $1,989,609 and $.04 per share lower, respectively, than if we had continued to account for stock-based compensation under APB 25 for our stock option grants. Compensation costs of approximately $2,536,000 and $525,000 for stock options were recognized in general and administrative expense and contract drilling costs, respectively, for the fiscal year ended March 31, 2007. Approximately $260,000 of the compensation costs included in general and administrative expense relate to stock options granted to outside directors that vested immediately upon grant pursuant to our stock option plans. The entire compensation cost must be recognized for stock options that are fully vested at the grant date.

The following table illustrates the pro forma effect on operating results and per share information had we accounted for stock-based compensation in accordance with SFAS 123R for the fiscal years presented:


	2006			2005
Net earnings - as reported	$	50,566,603		$	10,811,625
Deduct: Total stock-based employee compensation expense determined under fair-value-based method for all awards, net of related tax effect		(1,893,785	)		(1,175,191	)

Net earnings - pro forma	$	48,672,818		$	9,636,434

Net earnings per share - as reported - basic	$	1.08		$	0.31
Net earnings per share - as reported - diluted	$	1.06		$	0.30
Net earnings per share - pro forma - basic	$	1.04		$	0.28
Net earnings per share - pro forma - diluted	$	1.02		$	0.27

We receive a tax deduction for certain stock option exercises during the period the options are exercised, generally for the excess of the price at which the options are sold over the exercise price of the options. Prior to adoption of SFAS 123R, we reported all tax benefits resulting from the exercise of stock options as operating cash flows in our consolidated statement of cash flows. In accordance with SFAS 123R, we reported all excess tax benefits resulting from the exercise of stock options as financing cash flows in our consolidated statement of cash flows. There were 36,500 stock options exercised during the fiscal year ended March 31, 2007.

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.

Our management has determined that it is appropriate to use the percentage-of-completion method, as defined in the American Institute of Certified Public Accountants’ Statement of Position 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 we 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.

labor, materials, supplies, repairs and 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.

Cash and Cash Equivalents

For purposes of the statements of cash flows, we consider all highly liquid debt instruments purchased with a maturity of three months or less to be cash equivalents. Cash equivalents consist of investments in corporate and government money market accounts. Cash equivalents at March 31, 2007 and 2006 were $84,880,000 and $85,618,000, respectively.

We maintain cash accounts at two banking institutions. These account balances are insured by the Federal Deposit Insurance Corporation up to $100,000. At March 31, 2007, we had bank account balances of approximately $1,181,000 exceeding the $100,000 deposit insurance limitation.

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, 2007 and 2006, our allowance for doubtful accounts was $1,000,000 and $200,000.

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. We recorded losses on disposition of our property and equipment of approximately $5,760,000, $2,896,000 and $696,000 during the years ended March 31, 2007, 2006 and 2005, respectively, in drilling costs. During the fiscal year ended March 31, 2006, we capitalized $194,500 of interest costs incurred during the construction periods of certain drilling equipment. We did not capitalize any interest costs during the fiscal year ended March 31, 2007. At March 31, 2007 and 2006, costs incurred on rigs under construction were approximately $8,567,000 and $26,172,000, 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.

Intangibles 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 non-compete agreements relating to acquisitions, net of amortization. Loan fees are being amortized over the two-year term of the related credit facility described in Note 3. Non-compete agreements are amortized over the term of the non-compete agreements of three to five years. Depreciation and amortization expense includes amortization of intangibles and other assets of $52,000, $65,000 and $142,157 during the years ended March 31, 2007, 2006 and 2005, respectively.

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

We purchased services from R&B Answering Service and Frontier Services, Inc. during the fiscal years ended March 31, 2007, 2006 and 2005. R&B Answering Service was more than 5% owned by our Chief Operating Officer until August 2006, when he sold his interest in that company. Frontier Services, Inc. is more than 5% owned by an immediate family member of a Vice President and Operations Manager of our company. The following summarizes the transactions with these companies in each period.


	2007		2006		2005
R&B Answering Service
Purchases	$	7,542	$	16,915	$	18,218
Payments	$	7,542	$	19,965	$	17,112

Frontier Services, Inc.
Purchases	$	12,551	$	5,953	$	81,254
Payments	$	12,551	$	9,302	$	93,709

In July 2005, we began leasing a portion of our corporate office space on a month-to-month basis to Wedge Oil and Gas Services Incorporated for $370 per month for one of its employees located in San Antonio. Wedge Oil and Gas Services Incorporated is an affiliate of WEDGE Group Incorporated. An officer of WEDGE Group Incorporated is a member of our Board of Directors.

Our Chief Executive Officer, Chief Operating Officer, Senior Vice President of Marketing, and a Vice President and Operations Manager occasionally acquire a 1% to 5% minority working interest in oil and gas wells that we drill for one of our customers. These individuals acquired a minority working interest in three, one and two wells that we drilled for this customer during the fiscal years ended March 31, 2007, 2006 and 2005, respectively. We recognized contract drilling revenues of approximately $1,884,000, $455,000 and $508,000 on these wells during the fiscal years ended March 31, 2007, 2006 and 2005, respectively.

Recently Issued Accounting Standards

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 which has subsequently been paid in full. 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 which has subsequently been paid in full. 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 fiscal year 2005. 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, 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 Year Ended March 31, 2005
Total revenues	$	208,394,551
Net earnings	$	11,943,137
Earnings per common share:
Basic	$	0.35
Diluted	$	0.33

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

We have a $20,000,000 credit facility with Frost National Bank, consisting of a $10,000,000 revolving line and letter of credit facility and a $10,000,000 acquisition facility for the acquisition of drilling rigs, drilling rig transportation equipment and associated equipment. Borrowings under the credit facility bear interest at a rate equal to Frost National Bank’s prime rate (8.25% at March 31, 2007) or, at our option, at LIBOR plus a percentage ranging from 1.5% to 2.25%, based on our operating leverage ratio. Borrowings are secured by most of our assets, including all our drilling rigs and associated equipment and receivables. At March 31, 2007, we had no borrowings under the acquisition facility and we had used approximately $4,267,000 of availability under the revolving line and letter of credit facility through the issuance of letters of credit in the ordinary course of business. The remaining availability under the revolving line and letter of credit facility is $5,733,000. Both the revolving line and letter of credit facility and acquisition facility are scheduled to mature in October 2008.

At March 31, 2007, we were in compliance with all covenants contained in the credit agreement related to our credit facility. Those covenants include, among others, requirements that we maintain a debt to total capitalization ratio of not greater than 0.2 to 1, a fixed charged coverage ratio of not less than 1.5 to 1 and an operating leverage ratio of not more than 2.5 to 1. The covenants also 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, to the extent not otherwise allowed by the credit facility.

4.	Leases

We lease various office equipment under non-cancelable operating leases expiring through 2010 and real estate under non-cancelable operating leases as follows:

•

our corporate office facilities, at a cost escalating from $10,880 per month to $18,805 per month over 102 months, pursuant to a lease extending through December 2013;

•

a trucking department office, storage and maintenance yard in Alice, Texas, at a cost of $5,200 per month, pursuant to a lease extending through July 2009; and

•

a 2.2-acre division office and storage yard in Vernal, Utah, at a cost of $6,000 per month, pursuant to a lease extending through October 2007.

Rent expense under operating leases for the years ended March 31, 2007, 2006 and 2005 was $346,292, $283,628, and $102,077, respectively.

Future lease obligations as of March 31, 2007 were as follows:


Year Ended March 31,
2008	$	305,785
2009		282,729
2010		244,294
2011		218,041
2012		217,526
Thereafter		389,480

	$	1,657,855

5.	Income Taxes

Our provision for income taxes consists of the following:


	Years Ended March 31,
	2007		2006		2005
Current tax- state	$	1,703,724	$	701,124	$	56,400
Current tax - federal		34,252,174		14,266,384		335,109
Deferred tax - state		1,458,370		312,510		55,164
Deferred tax - federal		9,194,920		13,966,599		5,902,828

Income tax expense	$	46,609,188	$	29,246,617	$	6,349,501

The following is a reconciliation of income tax expense to income taxes computed by applying the federal statutory income tax rate (35% for fiscal years 2007 and 2006 and 34% for fiscal years 2005) to income before income taxes:


	Years Ended March 31,
	2007			2006			2005
Expected tax expense	$	45,775,939		$	27,934,627		$	5,834,783
Tax basis adjustment to 35% for prior year deferred tax components		—			813,936			—
Club dues, meals and entertainment		47,710			32,344			24,050
Tax-exempt interest income		(421,822	)		—			—
Incentive stock options		546,921			—			—
State income taxes		2,417,179			658,862			92,388
Domestic production activities deduction		(1,387,603	)		—			—
Other		(369,136	)		(193,152	)		398,280

	$	46,609,188		$	29,246,617		$	6,349,501

Deferred income taxes arise from temporary differences between the tax bases 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,
	2007		2006
Deferred tax assets:
Vacation expense accruals	$	142,127	$	104,338
Workers compensation and health insurance accruals		1,679,300		812,038
Bad debt expense		353,520		73,520
Non qualifying stock options		510,041		—
Deferred lease liability		57,658		32,966

Total deferred tax assets		2,742,646		1,022,862

Deferred tax liabilities:
Property and equipment, principally due to differences in depreciation		38,671,585		25,926,429
Other		716,982		1,089,064

Total deferred tax liabilities		39,388,567		27,015,493

Net deferred tax liabilities	$	36,645,921	$	25,992,631

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 believed at March 31, 2007 it was more likely than not that we would 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. Taxable income for the year ended March 31, 2006 was sufficient to fully utilize these net operating loss carryforwards.

6.	Fair Value of Financial Instruments

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

7.	Earnings Per Common Share

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


	Years Ended March 31,
	2007		2006		2005
Basic
Net earnings	$	84,179,207	$	50,566,603	$	10,811,625

Weighted average shares		49,602,999		46,808,323		34,543,695

Earnings per share	$	1.70	$	1.08	$	0.31


Diluted
Earnings applicable to common shareholders	$	84,179,207	$	50,566,603	$	10,811,625
Effect of dilutive securities - Convertible subordinated debenture		—		—		459,483

Earnings available to common shareholders after assumed conversion	$	84,179,207	$	50,566,603	$	11,271,108

Weighted average shares:
Outstanding		49,602,999		46,808,323		34,543,695
Options		528,896		697,562		684,806
Convertible subordinated debenture		—		—		2,349,426

		50,131,895		47,505,885		37,577,927

Earnings per share	$	1.68	$	1.06	$	0.30

8.	Equity Transactions

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.

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.

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.

On February 10, 2006, we sold 3,000,000 shares of our common stock, at approximately $20.63 per share, net of underwriters’ commissions, pursuant to a public offering we registered with the SEC.

Employees exercised stock options for the purchase of 36,500 shares of common stock at prices ranging from $3.20 to $4.77 per share during the fiscal year ended March 31, 2007. Directors and employees exercised stock options for the purchase of 698,667 shares of common stock at prices ranging from $2.25 to $10.31 per share during the fiscal year ended March 31, 2006 and 551,666 shares of common stock at prices ranging from $.375 to $6.44 per share during the fiscal year ended March 31, 2005.

9.	Stock Options, Warrants and Stock Option Plan

We have stock option plans that are administered by the compensation committee of our Board of Directors, which selects persons eligible to receive awards and determines the number of stock options subject to each award and the terms, conditions and other provisions of the awards. Employee stock options generally become exercisable over three- to five-year periods, and generally expire 10 years after the date of grant. Stock options granted to outside directors vest immediately and expire five 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.

We estimate the fair value of each option grant on the date of grant using a Black-Scholes options-pricing model. The following table summarizes the assumptions used in the Black-Scholes option-pricing model for the fiscal years ended March 31, 2007, 2006 and 2005:


	2007			2006			2005
Expected volatility		49	%		52	%		86	%
Weighted-average risk-free interest rates		5.0	%		4.0	%		3.7	%
Weighted-average expected life in years		2.86			4.10			5.00
Options granted		482,000			336,500			510,000
Weighted-average grant-date fair value	$	5.36		$	6.47		$	8.85

The assumptions above are based on multiple factors, including historical exercise patterns of homogeneous groups with respect to exercise and post-vesting employment termination behaviors, expected future exercising patterns for these same homogeneous groups and volatility of our stock price. 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 options-pricing model.

At March 31, 2007, there was approximately $1,855,000 of unrecognized compensation cost relating to stock options which are expected to be recognized over a weighted-average period of 1.64 years.

The following table represents stock option activity for the fiscal year ended March 31, 2007:


	Number of Shares		Weighted-Average Exercise Price		Weighted-Average Remaining Contract Life
Outstanding options at beginning of period	1,592,833		$	7.71
Granted	482,000			14.53
Exercised	(36,500	)		4.63
Canceled	—			—
Forfeited	(91,833	)		11.09

Outstanding options at end of period	1,946,500		$	9.29	7.29

Options exercisable at end of period	1,065,834		$	7.00	6.39

Shares available for future stock option grants to employees and directors under existing plans were 1,228,333 at March 31, 2007. At March 31, 2007, the aggregate intrinsic value of stock options outstanding was approximately $8,046,000 and the aggregate intrinsic value of stock options exercisable was approximately $6,403,000. Intrinsic value is the difference between the exercise price of a stock option and the closing market price of our common stock, which was $12.69 on March 31, 2007.

The following table summarizes our nonvested stock option activity for the fiscal year ended March 31, 2007:


	Number of Shares		Weighted-Average Grant-Date Fair Value
Nonvested options at beginning of period	1,046,167		$	4.90
Granted	422,000			5.51
Vested	(495,668	)		4.70
Forfeited	(91,833	)		5.88

Nonvested options at end of period	880,666		$	5.48

As of March 31, 2007, there were no outstanding warrants.

10.

Employee Benefit Plans and Insurance

We maintain a 401(k) retirement plan for our eligible employees. Under this plan, we may make a matching contribution, on a discretionary basis, equal to a percentage of each eligible employee’s annual contribution, which we determine annually. Our contributions for fiscal 2007, 2006 and 2005 were approximately $983,000, $643,000 and $399,000, respectively.

We maintain a self-insurance program, for major medical, hospitalization and dental coverage for employees and their dependents, which is partially funded by payroll deductions. We have provided for both reported and incurred but not reported medical costs in the accompanying consolidated balance sheets. We have a maximum liability of $125,000 per employee/dependent per year. Amounts in excess of the stated maximum are covered under a separate policy provided by an insurance company. Accrued expenses at March 31, 2007 and 2006 include approximately $591,000 and $553,000, respectively, for our estimate of incurred but unpaid costs related to the self-insurance portion of our health insurance.

We are self-insured for up to $250,000 per incident for all workers’ compensation claims submitted by employees for on-the-job injuries, except in North Dakota where there is no deductible. We have provided for both reported and incurred but not reported costs of workers’ compensation coverage in the accompanying consolidated balance sheets. Accrued insurance premiums and deductibles at March 31, 2007 and 2006 include approximately $4,439,000 and $1,829,000, respectively, for our estimate of incurred but unpaid costs related to workers’ compensation claims. Based upon our past experience, management believes that we have adequately provided for potential losses. However, future multiple occurrences of serious injuries to employees could have a material adverse effect on our financial position and results of operations.

11.

Business Segments and Concentrations

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

During the fiscal year ended March 31, 2007, our three largest customers accounted for 9.7%, 9.1% and 6.1% respectively, of our total contract drilling revenue. All three of these customers were customers of ours in 2006. During the fiscal year ended March 31, 2006, our three largest customers accounted for 10.1%, 6.1% and 4.4% respectively, of our total contract drilling revenue. All three of these customers were customers of ours in 2005. In fiscal year 2005, our three largest customers accounted for 6.5%, 5.0% and 4.6%, respectively, of our total contract drilling revenue. All three of these customers were customers of ours in fiscal year 2004.

12.

Commitments and Contingencies

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

13.

Subsequent Events

In April 2007, we acquired a 1500-horsepower diesel electric rig that is ideally suited for certain international markets that we are considering for possible expansion.

14.

Quarterly Results of Operations (unaudited)

The following table summarizes quarterly financial data for our fiscal years ended March 31, 2007 and 2006 (in thousands, except per share data):


	First Quarter			Second Quarter			Third Quarter			Fourth Quarter			Total
2007
Revenues	$	93,493		$	106,917		$	112,421		$	103,347		$	416,178
Income from operations		29,455			35,674			36,250			25,597			126,976
Income tax expense		(11,026	)		(13,213	)		(13,102	)		(9,268	)		(46,609	)
Net earnings		19,486			23,486			23,988			17,219			84,179
Earnings per share:
Basic		.39			.47			.48			.36			1.70
Diluted		.39			.47			.48			.34			1.68

2006
Revenues	$	59,877		$	66,973		$	74,459		$	82,839		$	284,148
Income from operations		11,902			17,171			21,262			27,573			77,909
Income tax expense		(4,537	)		(6,508	)		(7,876	)		(10,325	)		(29,247	)
Net earnings		7,725			11,080			13,792			17,968			50,567
Earnings per share:
Basic		.17			.24			.30			.37			1.08
Diluted		.17			.24			.29			.36			1.06

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, 2007 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 control over financial reporting that occurred during the three months ended March 31, 2007 that has materially affected, or is reasonably likely to materially affect, our internal control 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 Pioneer Drilling Company’s internal control over financial reporting as of March 31, 2007. 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, 2007, 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, 2007, as stated in their report which appears herein. That report appears on page 34.

Item 9B.

Other Information

Not applicable.

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 2007 Annual Meeting of Shareholders. We intend to file that definitive proxy statement with the SEC by June 29, 2007.

Item 10.

Directors, Executive Officers and Corporate Governance

Please see the information appearing under the headings “Proposal 1—Election of Directors,” “Executive Officers,” “Information Concerning Meetings and Committees of the Board of Directors,” “Code of Conduct and Ethics” and “Section 16(a) Beneficial Ownership Reporting Compliance” in the definitive proxy statement for our 2007 Annual Meeting of Shareholders for the information this Item 10 requires.

Item 11.

Executive Compensation

Please see the information appearing under the headings “Compensation Discussion and Analysis,” “Compensation of Directors,” “Compensation of Executive Officers,” “Compensation Committee Interlocks and Insider Participation” and “Compensation Committee Report” in the definitive proxy statement for our 2007 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 Part II of this report and (2) under the heading “Security Ownership of Certain Beneficial Owners and Management” in the definitive proxy statement for our 2007 Annual Meeting of Shareholders for the information this Item 12 requires.

Item 13.

Certain Relationships and Related Transactions, and Director Independence

Please see the information appearing under the headings “Proposal 1—Election of Directors” and “Certain Relationships and Related Transactions” in the definitive proxy statement for our 2007 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 “Proposal 2—Ratification of Appointment of Independent Auditors” in the definitive proxy statement for our 2007 Annual Meeting of Shareholders for the information this Item 14 requires.

PART IV

Item 15.

Exhibits and Financial Statement Schedules

(1)

Financial Statements.

See Index to Consolidated Financial Statements on page 30.

(2)

Financial Statement Schedules:

Schedule II is filed with this report. All other schedules for which provision is made in the applicable regulations of the SEC have been omitted because they are not required under the relevant instructions or because the required information is included in the financial statements or the related footnotes contained in this report.

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, 2005
Allowance for doubtful receivables	$	110,000	$	242,000		$	—	$	352,000


Year ended March 31, 2006
Allowance for doubtful receivables	$	352,000	$	(152,000	)	$	—	$	200,000


Year ended March 31, 2007
Allowance for doubtful receivables	$	200,000	$	800,000		$	—	$	1,000,000

(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, 1979, 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 31, 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*	-	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)).

4.3*	-	Second Amendment, dated May 11, 2005, to Credit Agreement between Pioneer Drilling Services, Ltd. And Frost National Bank, as Administrative Agent, Lead Arranger and Lender dated October 29, 2004 (Form 8-K dated May 12, 2005 (File No. 1-8182, Exhibit 4.1)).

4.4*	-	Third Amendment, dated October 25, 2005, to Credit Agreement between Pioneer Drilling Services, Ltd. And Frost National Bank, as Administrative Agent, Lead Arranger and Lender dated October 29, 2004 (Form 8-K dated October 28, 2005 (File No. 1-8182, Exhibit 4.1)).

4.5*	-	Fourth Amendment, dated December 15, 2005, to Credit Agreement between Pioneer Drilling Services, Ltd. And Frost National Bank, as Administrative Agent, Lead Arranger and Lender dated October 29, 2004 (Form 8-K dated December 16, 2005 (File No. 1-8182, Exhibit 4.1)).

4.6*	-	Fifth Amendment, dated October 30, 2006, to Credit Agreement between Pioneer Drilling Services, Ltd. and Frost National Bank, as Administrative Agent, Lead Arranger and Lender dated October 29, 2004 (Form 8-K filed October 31, 2006 (File No. 1-8182, Exhibit 4.1)).

10.1+*	-	Pioneer Drilling Services, Ltd. Annual Incentive Compensation Plan dated August 5, 2005 (Form 8-K Dated August 5, 2005 (File No. 1-8182, Exhibit 10.1)).

10.2+*	-	Pioneer Drilling Services, Ltd. Executive Severance Plan dated August 5, 2005 (Form 8-K Dated August 5, 2005 (File No. 1-8182, Exhibit 10.3)).


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)).

21.1	-	Subsidiaries of Pioneer Drilling Company.

23.1	-	Consent of KPMG LLP.

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

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

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

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

*	Incorporated by reference to the filing indicated.

+	Management contract or compensatory plan or arrangement.

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

May 17, 2007	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/ C. Robert Bunch C. Robert Bunch	Chairman	May 17, 2007

/s/ Wm. Stacy Locke Wm. Stacy Locke	President, Chief Executive Officer and Director (Principal Executive Officer)	May 17, 2007

/s/ William D. Hibbetts William D. Hibbetts	Senior Vice President, Chief Financial Officer and Secretary (Principal Financial Officer)	May 17, 2007

/s/ Kurt M. Forkheim Kurt M. Forkheim	Vice President, Chief Accounting Officer (Principal Accounting Officer)	May 17, 2007

/s/ C. John Thompson C. John Thompson	Director	May 17, 2007

/s/ James M. Tidwell James M. Tidwell	Director	May 17, 2007

/s/ Dean A. Burkhardt Dean A. Burkhardt	Director	May 17, 2007

/s/ Michael F. Harness Michael F. Harness	Director	May 17, 2007

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, 1979, 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*	-	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)).

4.3*	-	Second Amendment, dated May 11, 2005, to Credit Agreement between Pioneer Drilling Services, Ltd. And Frost National Bank, as Administrative Agent, Lead Arranger and Lender dated October 29, 2004 (Form 8-K dated May 12, 2005 (File No. 1-8182, Exhibit 4.1)).

4.4*	-	Third Amendment, dated October 25, 2005, to Credit Agreement between Pioneer Drilling Services, Ltd. And Frost National Bank, as Administrative Agent, Lead Arranger and Lender dated October 29, 2004 (Form 8-K dated October 28, 2005 (File No. 1-8182, Exhibit 4.1)).

4.5*	-	Fourth Amendment, dated December 15, 2005, to Credit Agreement between Pioneer Drilling Services, Ltd. And Frost National Bank, as Administrative Agent, Lead Arranger and Lender dated October 29, 2004 (Form 8-K dated December 16, 2005 (File No. 1-8182, Exhibit 4.1)).

4.6*	-	Fifth Amendment, dated October 30, 2006, to Credit Agreement between Pioneer Drilling Services, Ltd. and Frost National Bank, as Administrative Agent, Lead Arranger and Lender dated October 29, 2004 (Form 8-K filed October 31, 2006 (File No. 1-8182, Exhibit 4.1)).

10.1+*	-	Pioneer Drilling Services, Ltd. Annual Incentive Compensation Plan dated August 5, 2005 (Form 8-K Dated August 5, 2005 (File No. 1-8182, Exhibit 10.1)).

10.2+*	-	Pioneer Drilling Services, Ltd. Executive Severance Plan dated August 5, 2005 (Form 8-K Dated August 5, 2005 (File No. 1-8182, Exhibit 10.3)).

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)).

21.1	-	Subsidiaries of Pioneer Drilling Company.

23.1	-	Consent of KPMG LLP.

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

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

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

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

*	Incorporated by reference to the filing indicated.

+	Management contract or compensatory plan or arrangement.