UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D. C. 20549

FORM 10-K

(Mark one)

~~(Mark one)~~x		ý		ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended March 31, 2006

¨		~~For the fiscal year ended March 31, 2004~~

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

Commission File Number: 1-8182

PIONEER DRILLING COMPANY

(Exact name of registrant as specified in its charter)


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

~~9310 Broadway, Bldg. I~~ 1250 N.E. Loop 410, Suite 1000 San Antonio, Texas		~~78217~~78209
(Address of principal executive offices)		(Zip Code)

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

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 x No ¨

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 x

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 ýx No o¨

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

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 x Accelerated filer ¨ Non-accelerated filer ¨

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

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

September 30, 2005) was approximately $747,000,000.

As of ~~June 25, 2004,~~May 12, 2006, there were ~~27,300,126~~49,591,978 shares of common stock, par value $0.10 per share, of the registrant issued and outstanding.

DOCUMENTS INCORPORATED BY REFERENCE

Portions of the proxy statement related to the registrant’s ~~2004~~2006 Annual Meeting of Shareholders are incorporated by reference into Part III of this report.

TABLE OF CONTENTS


		Page
PART I

~~Items 1 and 2.~~ Item 1.	Business ~~and Properties~~	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	16
Item 6.	Selected Financial Data	17
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	18
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk	28
Item 8.	Financial Statements and Supplementary Data	29
Item 9.	Changes in and Disagreements With Accountants on Accounting and Financial Disclosure	49
Item 9A.	Controls and Procedures	49
Item 9B.	Other Information	49

PART III

Item 10.	Directors and Executive Officers of the Registrant	50
Item 11.	Executive Compensation	50
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related ~~Stock holder~~Stockholder Matters	50
Item 13.	Certain Relationships and Related Transactions	50
Item 14.	Principal Accountant Fees and Services	50

PART IV

Item 15.	Exhibits and Financial Statement Schedules ~~and Reports on Form 8-K~~	51

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~~“Cautionary Statement Concerning Forward-Looking ~~Statements and Risk Factors’’~~Statements” following ~~Items~~Item 1 ~~and 2~~ of Part I of this report.

ItemsItem 1 and 2.. Business and Properties**

General

Pioneer Drilling Company provides contract land drilling services to independent and major oil and gas exploration and production companies. In addition to our drilling rigs, we provide the drilling crews and most of the ancillary equipment needed to operate our drilling rigs. We have focused our operations in ~~the~~select oil and natural gas production regions ~~of South Texas, East Texas and North Texas.~~in the United States. Our company was incorporated in 1979 as the successor to a business that had been operating since 1968. We conduct our operations through our principal operating subsidiary, Pioneer Drilling Services, Ltd. Our common stock trades on the American Stock Exchange under the symbol “PDC.”

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


Date	Acquisition (1)	~~Acquisition~~Market		~~Market~~	Number of Rigs ~~Rigs~~ Acquired

September 1999	Howell Drilling, Inc. ~~— Asset Purchase~~	South Texas	2

August 2000	Pioneer Drilling Co. ~~— Stock Purchase~~	South Texas	4

March 2001	Mustang Drilling, Ltd. ~~— Asset Purchase~~	East Texas	4

May 2002	United Drilling Company ~~— Asset Purchase~~	South Texas	2

August 2003	Texas Interstate Drilling Company, L. P. ~~— Asset Purchase~~	North Texas	2

March 2004	Sawyer Drilling & Service, Inc. ~~— Asset Purchase~~	East Texas	7

March 2004	SEDCO Drilling Co., Ltd. ~~— Asset Purchase~~	North Texas	1

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 17 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 ~~June 28, 2004,~~May 12, 2006, our rig fleet ~~consists~~consisted of 3657 operating drilling rigs, 15 of which ~~are~~were operating in our South Texas 17 of which are operating in East Texas and four of which are operating in North Texas. During our fiscal year ended March 31, 2002, we added four rigs, consisting of two newly constructed rigs and two refurbished rigs, increasing our rig fleet to a total of 20 rigs at March 31, 2002. During our fiscal year ended March 31, 2003, we added two additional refurbished rigs and two rigs we acquired from United Drilling Company, increasing our rig fleet to a total of 24 rigs at March 31, 2003. During our fiscal year ended March 31, 2004, we added two refurbished rigs, acquired two rigs from Texas Interstate Drilling Company, L.P., acquired seven rigs from Sawyer Drilling & Service, Inc. and acquired one rig from SEDCO Drilling Co., Ltd. (which we named Rig 5 in place of our old Rig 5, which was retired and the componentsdivision, 18 of which were ~~moved~~operating in our East Texas division, seven of which were operating in our North Texas division, five of which were operating in our western Oklahoma division and 12 of which were operating in our Rocky Mountain divisions. We are also constructing seven additional rigs, which we expect to add to our inventory of spare equipment). In December 2003, we acquired the one rig we had previously been leasing under an operating lease since August 2000. As a result, we now own all 36 of the operating rigs in our fleet.

fleet at varying times prior to March 31, 2007.

We conduct our operations primarily in South, East and North ~~Texas.~~Texas, western Oklahoma and the Rocky Mountains. During fiscal ~~2004,~~2006, substantially all the wells we drilled for our customers were drilled in search of natural ~~gas. Natural~~ gas ~~reserves are typically found~~except for five rigs employed in ~~deep geological formations and generally require premium equipment and quality crews to drill~~search of oil in the ~~wells.~~

Williston Basin of the Rocky Mountains. Our ~~business strategy is to own and operate a high quality fleet of land drilling rigs in active drilling markets. We intend to continue making additions to our drilling fleet,~~customers remain primarily ~~through prudent acquisitions of businesses or selected drilling rig assets. As we add to our fleet, we intend to focus~~focused on ~~the addition of rigs capable of performing deep~~ drilling for natural gas.

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

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

in Our Industry” in Item 7 of Part II of this report. For information on our consolidated revenues and income from operations for the years ended March 31, 2006, 2005 and 2004 and our consolidated total assets as of March 31, 2006 and 2005, 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; and

maintaining an aggressive safety program.

Drilling Equipment

General

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

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

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

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

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

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

Our Fleet of Drilling Rigs

As of ~~June 28, 2004,~~May 12, 2006, our rig fleet consists of 3657 drilling rigs. We own all the rigs in our fleet. The following table sets forth information regarding utilization for our fleet of drilling rigs:

Years ended March 31,

2004

2003

2002

2001

2000

1999

Average number of rigs for the period

27.3

22.3

18.0

10.5

6.6

6.0

Average utilization rate

88
%
79
%
82
%
91
%
66
%
66
%


	Years Ended March 31,
	2006		2005		2004		2003		2002		2001
Average number of rigs for the period	52.3		40.1		27.3		22.3		18.0		10.5
Average utilization rate	95	%	96	%	88	%	79	%	82	%	91	%

The following table sets forth information regarding our drilling fleet:


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

1	Cabot 750E	9,500	South Texas	Electric	750	Cabot 750E	9,500	South Texas	Electric	750
2	Cabot 750E	9,500	South Texas	Electric	750	Cabot 750E	9,500	South Texas	Electric	750
3	National 110 UE	18,000	South Texas	Electric	1500	National 110 UE	18,000	South Texas	Electric	1,500
4	RMI 1000 E	15,000	South Texas	Electric	1000	RMI 1000 E	15,000	South Texas	Electric	1,000
5	Brewster N-46	12,000	North Texas	Mechanical	1000	Brewster N-46	12,000	North Texas	Mechanical	1,000
6	Brewster DH-4610	13,000	East Texas	Mechanical	750	Brewster DH-4610	13,000	East Texas	Mechanical	750
7	National 110 UE	18,000	South Texas	Electric	1500	National 110 UE	18,000	South Texas	Electric	1,500
8	National 110 UE	18,000	East Texas	Electric	1500	National 110 UE	18,000	East Texas	Electric	1,500
9	Gardner-denver 500	11,000	East Texas	Mechanical	700	Gardner-Denver 500	11,000	East Texas	Mechanical	700
10	Brewster N-46	12,000	East Texas	Mechanical	1000	Brewster N-46	12,000	East Texas	Mechanical	1,000
11	Brewster N-46	12,000	South Texas	Mechanical	1000	Brewster N-46	12,000	South Texas	Mechanical	1,000
12	IRI Cabot 900	12,500	South Texas	Mechanical	900	IRI Cabot 900	10,500	South Texas	Mechanical	900
14	Brewster N-46	12,000	South Texas	Mechanical	1000	Brewster N-46	12,000	South Texas	Mechanical	1,000
15	Cabot 750	9,500	South Texas	Mechanical	750	Cabot 750	9,500	South Texas	Mechanical	750
16	Cabot 750	9,500	South Texas	Mechanical	750	Cabot 750	9,500	South Texas	Mechanical	750
17	Ideco 725	12,000	East Texas	Mechanical	750	Ideco 725	12,000	East Texas	Mechanical	800
18	Brewster N-75	12,000	East Texas	Mechanical	1000	Brewster N-75	12,000	East Texas	Mechanical	1,000
19	Brewster N-75	12,000	East Texas	Mechanical	1000	Brewster N-75	12,000	East Texas	Mechanical	1,000
20	BDW 800	13,500	East Texas	Mechanical	1000	BDW 800	13,500	East Texas	Mechanical	1,000
21	National 110 UE	18,000	South Texas	Electric	1500
22	Ideco 725	12,000	East Texas	Mechanical	750
23	Ideco 725	12,000	North Texas	Mechanical	750
24	National 110 UE	18,000	South Texas	Electric	1500
25	National 110 UE	18,000	East Texas	Electric	1500
26	Oilwell 840 E	18,000	South Texas	Electric	1500
27	IRI Cabot 1200 M	13,500	South Texas	Mechanical	1300
28	Oilwell 760 E	15,000	South Texas	Electric	1000
29	Brewster N-46	12,000	North Texas	Mechanical	1000
30	Mid Cont U36A	11,000	North Texas	Mechanical	750
31	Brewster N-7	11,500	East Texas	Mechanical	750
32	Brewster N-75	13,500	East Texas	Mechanical	1000
33	Brewster N-95	13,500	East Texas	Mechanical	1200
34	All-Rig 900	12,000	East Texas	Mechanical	900
35	RMI 1000	13,500	East Texas	Mechanical	1000
36	Brewster N-7	11,500	East Texas	Mechanical	750
37	Brewster N-95	13,500	East Texas	Mechanical	1200


Rig Number	Rig Design	Approximate Drilling Depth Capability (feet)	Current Division Location	Type	Horsepower
21	National 110 UE	18,000	South Texas	Electric	1,500
22	Ideco 725	12,000	East Texas	Mechanical	800
23	Ideco 725	12,000	North Texas	Mechanical	800
24	National 110 UE	18,000	South Texas	Electric	1,500
25	National 110 UE	18,000	East Texas	Electric	1,500
26	Oilwell 840 E	18,000	South Texas	Electric	1,500
27	IRI Cabot 1200 M	13,500	South Texas	Mechanical	1,300
28	Oilwell 760 E	15,000	South Texas	Electric	1,000
29	Brewster N-46	12,000	North Texas	Mechanical	1,000
30	Mid Cont U36A	11,000	North Texas	Mechanical	750
31	Brewster N-7	11,500	East Texas	Mechanical	750
32	Brewster N-75	13,500	East Texas	Mechanical	1,000
33	Brewster N-95	13,500	East Texas	Mechanical	1,200
34	All-Rig 900	12,000	East Texas	Mechanical	900
35	National 610	13,500	East Texas	Mechanical	750
36	Brewster N-7	11,500	East Texas	Mechanical	750
37	Brewster N-95	13,500	East Texas	Mechanical	1,200
38	Ideco H-1000 E	11,000	Utah	Electric	1,000
39	National 370	10,000	North Texas	Mechanical	550
40	National 370	8,500	North Dakota	Mechanical	550
41	National 610	11,000	Utah	Mechanical	750
42	Brewster N-46	12,500	North Dakota	Mechanical	1,000
43	National 610	11,000	North Dakota	Mechanical	750
44	National 80B	15,000	North Dakota	Mechanical	1,000
46	RMI 550	9,000	Oklahoma	Mechanical	550
47	Ideco 525	8,000	Oklahoma	Mechanical	600
48	National 370	8,500	Oklahoma	Mechanical	550
49	Ideco 525	9,000	Oklahoma	Mechanical	600
50	Ideco 725	11,000	Oklahoma	Mechanical	800
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	14,000	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	Utah	Electric	1,000
59	HRI 1000	12,500	Utah	Mechanical	1,000
60	HRI 1000 E	12,500	North Texas	Electric	1,000

As of ~~June 28, 2004,~~May 12, 2006, we owned a fleet of 5253 trucks and related transportation equipment that we use to transport our drilling rigs to and from drilling sites. By owning our own trucks, we reduce the cost of rig moves and reduce downtime between rig moves.

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

Drilling Contracts

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

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

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


	Year Ended March 31,			Year Ended March 31,
	2004	2003	2002	2006	2005	2004
Daywork	205	119	150	565	264	205
Turnkey	92	78	9	19	134	92
Footage	13	5	6	106	48	13

Total number of wells	310	202	165	690	446	310

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

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

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

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

Customers and Marketing

We market our rigs to a number of customers. In fiscal ~~2004,~~2006, we drilled wells for 88128 different customers, compared to 64102 customers in fiscal ~~2003~~2005 and 4883 customers in fiscal ~~2002. Forty-nine of our customers in fiscal 2004 were customers for whom we had not drilled any wells in fiscal 2003.~~2004. 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 2006
~~Fiscal 2004~~Chesapeake Operating Inc.		10.1	%
Kerr-McGee Oil & Gas		6.1	%
Chinn Exploration		11 4.4	%

Fiscal 2005
~~Dale Operating Company~~Chinn Exploration		6.5	%
Goodrich Petroleum Corp.	6	5.0	%
Medicine Bow Energy Corporation		5 4.6	%

Fiscal 2004
Chinn Exploration		10.5	%
~~Fiscal 2003~~Dale Operating Company		6.4	%
~~Gulf Coast~~Medicine Bow Energy ~~Associates~~		11	%
~~Apache~~ Corporation		7 4.9	%
~~Suemaur Exploration & Production, L.L.C.~~		5	%

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

During fiscal 2005 and 2004, substantially all the wells drilled for Chinn Exploration, Goodrich Petroleum Corp., Medicine Bow Energy Corporation and Dale Operating Company were turnkey contracts.

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

From time to time, we also enter into informal, nonbinding commitments with our customers to provide drilling rigs for future periods at specified rates plus fuel and mobilization charges, if applicable, and escalation provisions. This practice is customary in the contract land drilling services business during times of tightening rig supply. As demand for drilling rigs has improved during the past year, we have entered into more longer-term drilling contracts. As of May 12, 2006, we had 39 contracts with terms of six months to two years in duration, of which 27 have a remaining term in excess of six months. We also have term contracts of one to two years for the seven rigs currently under construction.

Competition

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

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

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

Our operations consist of drilling oil and gas wells for our customers under daywork, turnkey or footage contracts usually on a well-to-well basis. Daywork contracts are the ~~easiest~~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 ~~margins.~~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. This is primarily~~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.

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

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

For the years ended March 31, ~~2004, 2003~~2006, 2005 and ~~2002,~~2004, the percentages of our drilling revenues by type of contract were as follows:

~~While current demand for drilling rigs has increased, we continue to bid on~~We had no turnkey contracts in ~~an effort~~progress at March 31, 2006, compared to ~~improve margins and maintain rig utilization. Although oil and natural gas prices have improved, we anticipate only a moderate change~~six turnkey contracts in ~~the mix~~progress at March 31, 2005. We had two footage contracts in progress at March 31, 2006, compared to six footage contracts in progress at March 31, 2005.

On March 31, 2005, Chesapeake Energy Corporation (“Chesapeake”) owned 16.78% of our ~~types of contracts in fiscal 2005.~~

~~In our quarter~~outstanding common stock. Chesapeake’s ownership percentage remained approximately the same until they sold their entire interest on February 10, 2006. During the years ended March 31, ~~2004,~~2006 and 2005, we recognized revenues of approximately ~~$924,000~~$28,705,000 and $4,885,000, respectively, and recorded contract drilling costs, excluding depreciation, of approximately ~~$745,000, excluding depreciation,~~$18,121,000 and $3,263,000, respectively, on ~~one daywork contract~~drilling contracts with ~~Chesapeake Energy Corporation, who owns approximately 19.5% of our outstanding common stock.~~Chesapeake.

The following table provides information about our operations for the years ended March 31, ~~2004,~~2006, March 31, ~~2003,~~2005, and March 31, ~~2002.~~2004.

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 Securities and Exchange Commission, we included a reconciliation of drilling margin to net earnings, which is the nearest comparable GAAP financial measure.

Our contract drilling revenues grew by approximately ~~35%~~$98,902,000, or 53%, in fiscal ~~2004~~year 2006 from fiscal ~~2003,~~year 2005, primarily due to an improvement of $2,310 per day in average rig revenue rates ~~a 37%~~resulting from an increase in demand for drilling rigs and the 31% increase in revenue days a 9% increase in rig utilization and an increase in the number of rigs in our fleet. Approximately 52% of the increase in revenue days was an increase in daywork revenue days resulting in a $183 decrease in average contract drilling revenue per day.

~~Our contract drilling revenue in fiscal 2003 grew by $11,556,000, or 17%,~~that primarily resulted from ~~fiscal 2002 due to a 19% increase in revenue days,~~ an increase in the number of rigs in our fleet, which was partially offset by a 1% decrease in rig utilization.

Our contract drilling revenues grew by approximately $77,000,000, or 72%, in fiscal year 2005 from fiscal year 2004, primarily due to the 59% increase in revenue days and ~~a higher percentage of turnkey contracts.~~

the approximately $1,000 increase in revenue per revenue day, which was attributable to improving market conditions in our industry.

Our contract drilling costs grew by approximately ~~$17,681,000,~~$27,998,000, or ~~25%~~20%, in fiscal ~~2004~~year 2006 from fiscal ~~2003~~year 2005, primarily due to an increase in the number of revenue days resulting from the increase in ~~revenue days, rig utilization and~~ the number of rigs in our ~~fleet.~~fleet, which was partially offset by the 1% decrease in rig utilization discussed above. The ~~increase~~$802 decline in average contract drilling cost per revenue day was primarily due to the shift to more daywork revenue days ~~resulted~~as a percentage of total revenue days. Daywork days represented 89% of revenue days in ~~a $934 decrease~~the fiscal year 2006, compared to 63% in ~~contract drilling costs per revenue day because costs associated with the drilling of daywork contracts is less than costs associated with~~fiscal year 2005. Under turnkey and footage ~~contracts. Under daywork~~ contracts, ~~our customer provides~~we provide supplies and materials such as fuel, drill bits, casing and drilling fluids, ~~etc.~~

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 contract drilling costs in fiscal ~~2003~~year 2005 grew by approximately ~~$24,678,000,~~$50,000,000, or ~~53%~~56%, primarily due ~~primarily~~ to the ~~increase~~increases in 2005 in revenue days and rig utilization referred to above. The $132 decrease in average cost per revenue day was primarily due to the greater increase in ~~number of rigs and additional costs associated with~~daywork revenue days (3,059 days) in fiscal 2005 over the increase in turnkey ~~contracts. The increase in contract drilling costs per day of $2,462 in 2003 from 2002 is due to the increase in turnkey contracts.~~

Our depreciation and amortization expense in ~~2004~~fiscal year 2006 increased by approximately ~~$4,200,000,~~$10,297,000, or ~~35%~~45%, from ~~2003. Depreciation and amortization expense in 2003 increased approximately $3,534,000, or 42%, from 2002.~~fiscal year 2005. The increase in ~~2004~~2006 over ~~2003~~2005 resulted from our addition of ~~eleven~~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.

Our depreciation and amortization expense in fiscal year 2005 increased approximately $7,000,000, or 43%, from 2004. The increase in ~~2003~~2005 over ~~2002~~2004 resulted from our addition of ~~four~~15 drilling rigs and related equipment ~~during 2003.~~

in 2005 at a cost of approximately $52,600,000 and rig upgrade costs $5,512,000.

Our general and administrative expenses increased by approximately ~~$541,000,~~$1,866,000, or ~~24%~~40%, 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 $975,000, 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 ~~ended March 31, 2004~~2005. Professional fees increased by approximately $453,000, office rent increased by approximately $142,000 and insurance costs increased by approximately $119,000.

Our general and administrative expenses increased by approximately $1,900,000, or 68%, in fiscal year 2005 from ~~the corresponding period of 2003.~~fiscal year 2004. The increase resulted from increased payroll costs, ~~employment fees, loan fees,~~professional and consulting costs, insurance costs and director fees. ~~In 2004, payroll cost~~Payroll related costs increased by approximately ~~$310,000~~$894,000 due to pay ~~raises~~increases, staff additions and ~~the~~an increase ~~from 12 to 17 employees~~ in ~~our corporate office. Employment~~bonus costs of approximately $610,000. Professional and ~~loan fees~~consulting costs increased ~~by $61,000~~approximately $587,000, with much of this increase due to the ~~employee additions~~implementation of Sarbanes-Oxley compliance procedures. Director fees increased approximately $142,000. Insurance costs increased approximately $89,000, due to an increase in the cost of directors and ~~fees associated with the Merrill Lynch Capital loan. In addition, our directors’~~officers liability insurance coverage.

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 ~~officers’ liability~~cash equivalents balances and ~~employment practices insurance~~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 other expense decreased by approximately ~~$60,000 and directors’ fees increased by approximately $93,000.~~

~~The approximately $623,000~~$1,042,000 in fiscal year 2005 from fiscal year 2004 primarily due to the decrease in ~~general and administrative expenses in 2003~~interest expense that resulted from ~~2002 is due~~decreased outstanding debt balances. Long-term debt outstanding decreased from $48,511,222 at March 31, 2004 to reduced payroll costs of approximately $269,000 and lower legal and professional fees of approximately $520,000, offset by other increases of approximately $166,000. The higher payroll costs in 2002 were due to bonuses paid in that year.

Our contract land drilling operations are subject to various federal and state laws and regulations designed to protect the environment. Maintaining compliance with these regulations is part of our day-to-day operating procedures. We monitor each of our yard facilities and each of our rig locations on a day-to-day basis for potential environmental spill risks. In addition, we maintain a spill prevention control and countermeasures plan for each yard facility and each rig location. The costs of these procedures represent only a small portion of our routine employee training, equipment maintenance and job site maintenance costs. We estimate the annual compliance costs for this program is approximately ~~$143,000.~~$292,000. 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 ~~19.2%, 30.4%~~36.6% for fiscal year 2006, 37.0% for fiscal year 2005 and ~~35.1%~~19.2% for fiscal year 2004, ~~2003 and 2002, respectively,~~ differ from the federal statutory rate of 35% for fiscal year 2006 and 34% for fiscal year 2005 and fiscal year 2004, due to permanent ~~differences.~~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. At March 31, 2005, we had a net operating loss carryforwards for income tax purposes of approximately $16,500,000, which was fully utilized in fiscal year 2006.

Due to the increased rig count in each of our market areas, availability of personnel to operate our rigs is limited. In April 2005 and January 2006, we raised wage rates for our rig personnel in most of our areas of operation by an average of 6% at both dates. We have been able to pass these wage rate increases on to our customers based on contract terms. Availability of personnel in each of our market areas continues to be very constrained. Therefore, it is likely that we will experience additional wage rate increases. We anticipate that we will be able to pass any such increases for rig personnel on to our customers.

~~As a result~~We are experiencing increases in costs for rig repairs and maintenance and costs of rig upgrades and new rig construction due to the ~~relatively low levels of inflation during the past two years, inflation did not significantly affect~~increased industry-wide rig count. We estimate these costs increased between 10% and 15% in fiscal year 2006, and we expect similar cost increases in fiscal year 2007. We anticipate that we will be able to recover these cost increases through improvements in our ~~results of operations in any of the periods reported.~~daywork revenue rates.

In December 2004, the Financial Accounting Standards Board (the “FASB”) issued SFAS No. 123R (revised 2004),Share-Based Payment. SFAS No. 123R is a revision of SFAS No. 123,Accounting for Stock-Based Compensation,and supersedes APB Opinion No. 25,Accounting for Stock Issued to Employees,and its related implementation guidance. SFAS No. 123R established standards for the accounting for transactions in which an entity exchanges its equity instruments for goods or services. It also addresses transactions in which an entity incurs liabilities in exchange for goods or services that are based on the fair value of the entity’s equity instruments or that may be settled by the issuance of those equity instruments. SFAS No. 123R focuses primarily on accounting for transactions in which an entity obtains employee services in share-based payment transactions. SFAS No. 123R requires a public entity to measure the cost of employee services received in exchange for an award of equity instruments based on the grant-date fair value of the award (with limited exceptions). That cost will be recognized over the period during which an employee is required to provide service in exchange for the award. The provisions of SFAS No. 123R are effective for public entities that do not file as small business issuers as of the beginning of the first annual reporting period that begins after June 15, 2005. We will adopt SFAS No. 123R effective April 1, 2006 using the modified prospective method. The modified prospective method requires us to recognize compensation cost for unvested awards that are outstanding on the effective date based on the fair value originally estimated for our SFAS No. 123 pro forma disclosures. SFAS No. 123R will have a negative impact on our financial position and results of operations in fiscal year 2007 and in subsequent periods. The negative impact of SFAS No. 123R to net earnings (loss) and net earnings (loss) per share for the years ended March 31, 2006, 2005 and 2004 is presented in our SFAS 123 pro forma disclosures in the notes to the consolidated financial statements.

In May 2005, the FASB issued SFAS No. 154,Accounting Changes and Error Corrections, which supersedes APB Opinion No. 20,Accounting Changesand SFAS No. 3,Reporting Accounting Changes in Interim Financial Statements.SFAS No. 154 changes the requirements for the accounting for and reporting of changes in accounting principles. The statement requires the retroactive application to prior periods’ financial statements of changes in accounting principles, unless it is impracticable to determine either the period-specific effects or the cumulative effect of the change. SFAS No. 154 does not change the guidance for reporting the correction of an error in previously issued financial statements or the change in an accounting estimate. SFAS No. 154 is effective for accounting changes and corrections of errors made in fiscal years beginning after December 15, 2005. We do not expect the adoption of SFAS No. 154 to have a material impact on our financial position and results of operations and financial condition.

Item ~~7A.~~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 ~~most of~~ our outstanding floating rate debt. AtHowever, at March 31, ~~2004,~~2006, we had no outstanding debt ~~of approximately $20,511,000 that was~~ subject to variable interest rates, in each case based on an agreed percentage-point spread from the lender’s prime interest rate. An increase or decrease of 1% in the interest rate would have a corresponding decrease or increase in our net income (loss) of approximately $135,000 annually. We did not enter into any of these debt arrangements for trading purposes.rates.

Item 8.8. Financial Statements and Supplementary Data

PIONEER DRILLING COMPANY

INDEX TO CONSOLIDATED FINANCIAL STATEMENTS


		Page
~~Report~~Reports of Independent Registered Public Accounting Firm		30

Consolidated Balance Sheets as of March 31, ~~2004~~2006 and ~~2003~~2005		32

Consolidated Statements of Operations for the Years Ended March 31, ~~2004, 2003~~2006, 2005 and ~~2002~~2004		33

Consolidated Statements of Shareholders’ Equity and Comprehensive Income for the Years Ended March 31, ~~2004, 2003~~2006, 2005 and ~~2002~~2004		34

Consolidated Statements of Cash Flows for the Years Ended March 31, ~~2004, 2003~~2006, 2005 and ~~2002~~2004		35

Notes to Consolidated Financial Statements		36

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Shareholders

Pioneer Drilling Company:

We have audited the accompanying consolidated balance sheets of Pioneer Drilling Company and subsidiaries as of March 31, ~~2004~~2006 and ~~2003~~2005, and the related consolidated statements of operations, ~~shareholders’~~stockholders’ equity, ~~and comprehensive income~~ and cash flows for each of the years in the three-year period ended March 31, ~~2004.~~2006. 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) (PCAOB). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material ~~misstatements.~~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, ~~2004~~2006 and ~~2003,~~2005, and the results of their operations and their cash flows for each of the years in the three-year period ended March 31, ~~2004,~~2006, in conformity with ~~U. S.~~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.

~~KPMG LLP~~

~~San Antonio, Texas~~

~~June 23, 2004~~

We also have audited, in accordance with the standards of the PCAOB, the effectiveness of Pioneer Drilling Company’s internal control over financial reporting as of March 31, 2006, 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 24, 2006 expressed an unqualified opinion on management’s assessment of, and the effective operation of, internal control over financial reporting.

KPMG LLP

San Antonio, Texas

May 24, 2006

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

The Board of Directors and Stockholders

Pioneer Drilling Company:

We have audited management’s assessment, included in Management’s Report on Internal Control over Financial Reporting in Item 9A of Pioneer Drilling Company’s Annual Report on Form 10-K for the year ended March 31, 2006, that Pioneer Drilling Company and subsidiaries maintained effective internal control over financial reporting as of March 31, 2006, 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 the Company’s internal control over financial reporting, evaluating management’s assessment, testing and evaluating the design and operating effectiveness of the Company’s internal control over financial reporting, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

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

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

In our opinion, management’s assessment that Pioneer Drilling Company maintained effective internal control over financial reporting as of March 31, 2006, 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, 2006, 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 PCAOB, the consolidated balance sheets of Pioneer Drilling Company and subsidiaries as of March 31, 2006 and 2005, and the related consolidated statements of operations, stockholders’ equity, and cash flows for each of the years in the three-year period ended March 31, 2006, and our report dated May 24, 2006 expressed an unqualified opinion on those consolidated financial statements.

KPMG LLP

San Antonio, Texas

May 24, 2006

PIONEER DRILLING COMPANY AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS


	March 31,						March 31,
	2004			2003			2006		2005
ASSETS
Current assets:
Cash and cash equivalents	$	6,365,759		$	21,002,913		$	91,173,764	$	69,673,279
Marketable securities								—		1,000,000
Receivables:
Trade, net	10,901,991			4,499,378				35,544,543		26,108,291
Contract drilling in progress	9,130,794			4,429,545				9,620,179		5,364,529
Federal income tax receivable	—			444,900
Current deferred income taxes	285,384			180,991				989,895		569,548
Prepaid expenses	1,336,337			914,187				2,207,853		1,876,843

Total current assets	28,020,265			31,471,914				139,536,234		104,592,490

Property and equipment, at cost:
Drilling rigs and equipment	145,758,913			106,728,573				328,673,207		216,286,747
Transportation, office, land and other	5,427,637			3,494,657
Transportation equipment								9,169,461		6,469,519
Land, buildings and other								3,925,614		2,691,673

	151,186,550			110,223,230				341,768,282		225,447,939
Less accumulated depreciation and amortization	35,844,938			22,367,327				80,984,991		54,881,488

Net property and equipment	115,341,612			87,855,903				260,783,291		170,566,451
Other assets	369,278			366,500
Intangible and other assets								358,180		850,381

Total assets	$	143,731,155		$	119,694,317		$	400,677,705	$	276,009,322

LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities:
Notes payable	$	558,070		$	587,177		$	—	$	681,975
Current installments of long-term debt	3,724,302			2,671,269				—		4,666,667
Current installments of capital lease obligations	140,934			140,717				—		66,359
Accounts payable	13,270,989			14,206,586				16,040,568		15,621,647
Income tax payable								6,834,877		195,949
Prepaid drilling contracts								139,769		172,750
Accrued expenses:
Payroll and payroll taxes	1,499,151			847,163				3,383,435		2,706,623
Other	2,798,801			1,874,693				6,233,479		4,153,851

Total current liabilities	21,992,247			20,327,605				32,632,128		28,265,821
Long-term debt, less current installments	44,786,920			45,594,517				—		13,411,111
Capital lease obligations, less current installments	104,754			260,025				—		33,906
Non-current liabilities								387,524		400,000
Deferred income taxes	6,010,916			5,839,908				26,982,526		12,283,070

Total liabilities	72,894,837			72,022,055				60,002,178		54,393,908

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; 27,300,126 shares and 21,700,792 shares issued and outstanding at March 31, 2004 and March 31, 2003, respectively	2,730,012			2,170,079
Common stock $.10 par value; 100,000,000 shares authorized; 49,591,978 shares and 45,893,311 shares issued and outstanding at March 31, 2006 and March 31, 2005, respectively								4,959,197		4,589,331
Additional paid-in capital	82,124,368			57,730,188				288,356,164		220,232,520
Accumulated deficit	(14,018,062		)	(12,228,005		)
Accumulated earnings (deficit)								47,360,166		(3,206,437	)

Total shareholders’ equity	70,836,318			47,672,262				340,675,527		221,615,414

Total liabilities and shareholders’ equity	$	143,731,155		$	119,694,317		$	400,677,705	$	276,009,322

See accompanying notes to consolidated financial statements.

PIONEER DRILLING COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

	Years Ended March 31,
	2004			2003			2002			Years Ended March 31,
										2006			2005			2004
Contract drilling revenues	$	107,875,533		$	80,183,486		$	68,627,486		$	284,147,974		$	185,246,448		$	107,875,533

Costs and expenses:
Contract drilling	88,504,102			70,823,310			46,145,364				166,480,570			138,482,759			88,504,102
Depreciation and amortization	16,160,494			11,960,387			8,426,082				33,387,523			23,090,909			16,160,494
General and administrative	2,772,730			2,232,390			2,855,274				6,522,842			4,657,013			2,772,730
Bad debt expense	—			110,000			—
Bad debt expense (recovery)											(152,000	)		242,000			—

Total operating costs and expenses	107,437,326			85,126,087			57,426,720				206,238,935			166,472,681			107,437,326
Income (loss) from operations	438,207			(4,942,601		)	11,200,766

Income from operations											77,909,039			18,773,767			438,207

Other income (expense):
Interest expense	(2,807,822		)	(2,698,529		)	(1,616,984		)		(236,012	)		(1,722,393	)		(2,807,822	)
Interest income	101,584			94,235			80,932				2,068,767			173,318			101,584
Other	51,675			37,614			72,096				71,426			37,267			51,675
Gain on sale of securities	—			203,887			—
Loss from early extinguishment of debt											—			(100,833	)		—

Total other income (expense)	(2,654,563		)	(2,362,793		)	(1,463,956		)		1,904,181			(1,612,641	)		(2,654,563	)

Income (loss) before income taxes	(2,216,356		)	(7,305,394		)	9,736,810
Income before income taxes											79,813,220			17,161,126			(2,216,356	)
Income tax (expense) benefit	426,299			2,219,776			(3,418,525		)		(29,246,617	)		(6,349,501	)		426,299

Net earnings (loss)	(1,790,057		)	(5,085,618		)	6,318,285			$	50,566,603		$	10,811,625		$	(1,790,057	)
Preferred stock dividend requirement	—			—			92,814
Net earnings (loss) applicable to common shareholders	$	(1,790,057	)	$	(5,085,618	)	$	6,225,471

Earnings (loss) per common share - Basic	$	(0.08	)	$	(0.31	)	$	0.41		$	1.08		$	0.31		$	(0.08	)

Earnings (loss) per common share - Diluted	$	(0.08	)	$	(0.31	)	$	0.35		$	1.06		$	0.30		$	(0.08	)

Weighted average number of shares outstanding - Basic	22,585,612			16,163,098			15,112,272				46,808,323			34,543,695			22,585,612

Weighted average number of shares outstanding - Diluted	22,585,612			16,163,098			19,221,256				47,505,885			37,577,927			22,585,612

See accompanying notes to consolidated financial statements.

PIONEER DRILLING COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF SHAREHOLDERS’ EQUITY AND COMPREHENSIVE INCOME

	Shares Common	Shares Preferred		Amount Common		Preferred			Additional Paid In Capital		Accumulated Deficit			Accumulated Other Comprehensive Income			Total Shareholders’ Equity
																				Shares Common	Amount Common		Additional Paid In Capital		Accumulated Deficit			Total Shareholders’ Equity
Balance as of March 31, 2001	12,145,921	184,615		$	1,214,592	$	2,999,994		$	26,869,916	$	(13,367,858	)	$	110,118		$	17,826,762
Comprehensive income:
Net earnings	—	—		—		—			—		6,318,285			—			6,318,285
Net unrealized change in securites available for sale, net of tax of $384	—	—		—		—			—		—			(702		)	(702		)
Total comprehensive income	—	—		—		—			—		—			—			6,317,583
Issuance of common stock for:
Sale, net of related expenses	2,400,000	—		240,000		—			8,808,000		—			—			9,048,000
Conversion of preferred	1,199,038	(184,615	)	119,903		(2,999,994		)	2,880,091		—			—			—
Exercise of options	177,500	—		17,750		—			225,724		—			—			243,474
Preferred stock dividend	—	—		—		—			—		(92,814		)	—			(92,814		)
Balance as of March 31, 2002	15,922,459	—		1,592,245		—			38,783,731		(7,142,387		)	109,416			33,343,005
Comprehensive income:
Net loss	—	—		—		—			—		(5,085,618		)	—			(5,085,618		)
Net unrealized change in securites available for sale, net of tax of $56,366	—	—		—		—			—		—			(109,416		)	(109,416		)
Total comprehensive loss	—	—		—		—			—		—			—			(5,195,034		)
Issuance of common stock for:
Sale, net of related expenses of $657,499	5,333,333	—		533,334		—			18,809,167		—			—			19,342,501
Exercise of options	445,000	—		44,500		—			137,290		—			—			181,790
Balance as of March 31, 2003	21,700,792	—		2,170,079		—			57,730,188		(12,228,005		)	—			47,672,262			21,700,792		2,170,079		57,730,188		(12,228,005	)		47,672,262
Comprehensive income:
Net loss	—	—		—		—			—		(1,790,057		)	—			(1,790,057		)	—		—		—		(1,790,057	)		(1,790,057	)

Total comprehensive loss	—	—		—		—			—		—			—			(1,790,057		)	—		—		—		—			(1,790,057	)

Issuance of common stock for:
Sale, net of related expenses of $1,654,753	4,400,000	—		440,000		—			21,665,247		—			—			22,105,247			4,400,000		440,000		21,665,247		—			22,105,247
Equipment acquisitions	477,000	—		47,700		—			2,074,950		—			—			2,122,650			477,000		47,700		2,074,950		—			2,122,650
Exercise of options and related income tax benefits	722,334	—		72,233		—			653,983		—			—			726,216
Exercise of options and related income tax benefits of $52,423																				722,334		72,233		653,983		—			726,216

Balance as of March 31, 2004	27,300,126	—		$	2,730,012	$	—		$	82,124,368	$	(14,018,062	)	$	—		$	70,836,318		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

																				49,591,978	$	4,959,197	$	288,356,164	$	47,360,166		$	340,675,527

See accompanying notes to consolidated financial statements.

PIONEER DRILLING COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS


	Years Ended March 31,									Years Ended March 31,
	2004			2003			2002			2006			2005			2004
Cash flows from operating activities:
Net earnings (loss)	$	(1,790,057	)	$	(5,085,618	)	$	6,318,285		$	50,566,603		$	10,811,627		$	(1,790,057	)
Adjustments to reconcile net earnings (loss) to net cash provided by operating activities:
Depreciation and amortization	16,160,494			11,960,387			8,426,082				33,387,523			23,090,909			16,160,494
Allowance for doubtful accounts	—			110,000			—				(152,000	)		242,000			—
Gain on sale of securities	—			(203,887		)	—
Loss (gain) on dispositions of properties and equipment	816,104			279,054			(2,237		)
Change in deferred income taxes	119,038			(1,511,744		)	1,991,458
Loss on dispositions of property and equipment											2,895,752			696,345			816,104
Deferred income taxes											14,279,109			5,987,991			119,038
Change in other assets											209,525			(123,263	)		(40,000	)
Change in non-current liabilities											(12,476	)		—			—
Changes in current assets and liabilities:
Receivables	(11,103,862		)	242,126			(4,172,470		)		(13,539,902	)		(11,682,035	)		(11,103,862	)
Prepaid expenses	(422,150		)	(279,440		)	(322,471		)		(331,010	)		(540,507	)		(422,150	)
Accounts payable	(935,597		)	7,699,417			(1,099,813		)		418,921			2,350,658			(935,597	)
Federal income taxes	444,900			435,168			(930,266		)
Income tax payable											6,638,928			195,949			444,900
Prepaid drilling contracts											(32,981	)		172,750			—
Accrued expenses	1,576,096			743,814			836,321				2,756,442			2,462,523			1,576,096

Net cash provided by operating activities	4,864,966			14,389,277			11,044,889				97,084,434			33,664,947			4,824,966

Cash flows from financing activities:
Proceeds from notes payable	4,110,019			23,573,501			19,556,286				—			41,354,367			4,110,019
Proceeds from subordinated debenture	—			10,000,000			18,000,000
Increase in other assets	(40,000		)	(253,698		)	(195,000		)
Payment of preferred dividends	—			—			(859,395		)
Proceeds from exercise of options and warrants	673,794			181,790			243,474
Proceeds from common stock, net of offering cost of $1,654,753 in 2004 and $657,499 in 2003	22,105,247			19,342,501			9,048,000
Proceeds from exercise of options											6,791,871			958,412			673,794
Proceeds from common stock, net of offering cost of $968,361 in 2006, of $5,807,193 in 2005 and $1,654,753 in 2004											61,701,639			111,009,058			22,105,247
Payments of debt	(4,048,744		)	(18,714,311		)	(27,026,538		)		(18,860,018	)		(43,809,329	)		(4,048,744	)

Net cash provided by financing activities	22,800,316			34,129,783			18,766,827				49,633,492			109,512,508			22,840,316

Cash flows from investing activities:
Business acquisitions											—			(35,200,000	)		(14,500,000	)
Purchases of property and equipment	(42,722,094		)	(33,588,972		)	(27,597,265		)		(128,871,447	)		(45,188,484	)		(28,222,094	)
Proceeds from sale of marketable securities	—			375,414			—
Proceeds from sale (purchase) of marketable securities, net											1,000,000			3,550,000			(1,900,000	)
Proceeds from sale of property and equipment	419,658			314,366			675,660				2,654,006			1,518,549			419,658

Net cash used in investing activities	(42,302,436		)	(32,899,192		)	(26,921,605		)		(125,217,441	)		(75,319,935	)		(44,202,436	)

Net increase (decrease) in cash and cash equivalents	(14,637,154		)	15,619,868			2,890,111				21,500,485			67,857,520			(16,537,154	)
Beginning cash and cash equivalents	21,002,913			5,383,045			2,492,934				69,673,279			1,815,759			18,352,913

Ending cash and cash equivalents	$	6,365,759		$	21,002,913		$	5,383,045		$	91,173,764		$	69,673,279		$	1,815,759

Supplementary disclosure:
Interest paid	$	2,821,041		$	2,785,177		$	1,046,943		$	407,158		$	2,407,193		$	2,821,041
Income taxes paid (refunded)	(990,237		)	(1,143,200		)	2,342,006
Dividends accrued	—			—			92,814
Conversion of preferred stock	—			—			2,999,994
Income tax paid (refunded)										$	4,321,619		$	(30,000	)	$	(990,237	)
Debenture conversion - common stock issued										$	—		$	28,000,000		$	—
Acquisition - common stock issued	2,122,650			—			—			$	—		$	—		$	2,122,650
Tax benefit from exercise of nonqualified options	52,423			2,720			—			$	4,009,945		$	204,964		$	52,423

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 ~~companies~~regions in the ~~North,~~United States. As of March 31, 2006, our rig fleet consisted of 56 operating drilling rigs, 15 of which were operating in our South ~~and~~Texas division, 18 of which were operating in our East Texas ~~markets.~~division, six of which were operating in our North Texas division, five of which were operating in our western Oklahoma division and 12 of which were operating in our Rocky Mountain divisions. We conduct our operations through our principal operating subsidiary, Pioneer Drilling Services, Ltd. The accompanying consolidated financial statements include our accounts and the accounts of our wholly owned subsidiaries. We have eliminated all intercompany accounts and transactions in consolidation.

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

Income Taxes

Pursuant to Statement of Financial Accounting Standards (“SFAS”) No. 109, “Accounting for Income Taxes,” we follow the asset and liability method of accounting for income taxes, under which we recognize deferred tax assets and liabilities for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax ~~bases.~~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 (Loss) Per Common Share

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

Stock-based Compensation

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

Year Ended March 31,

2004

2003

2002

Net earnings (loss)-as reported

$
(1,790,057
)
$
(5,085,618
)
$
6,318,285

Deduct: Total stock-based employee compensation expense determined under fair value based method for all awards net of related tax effect

(662,933
)
(385,671
)
(582,258
)
Net earnings (loss)-pro forma

$
(2,452,990
)
$
(5,471,289
)
$
5,736,027

Net earnings (loss) per share-as reported-basic

$
(0.08
)
$
(0.31
)
$
(0.41
)
Net earnings (loss) per share-as reported-diluted

(0.08
)
(0.31
)
(0.35
)
Net earnings (loss) per share-pro forma-basic

$
(0.11
)
$
(0.34
)
$
(0.38
)
Net earnings (loss) per share-pro forma diluted

(0.11
)
(0.34
)
(0.32
)
Weighted-average fair value of options granted during the year

$
4.46

$
3.50

$
3.11


	Years Ended March 31,
	2006			2005			2004
Net earnings (loss)-as reported	$	50,566,603		$	10,811,625		$	(1,790,057	)
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	)		(662,933	)

Net earnings (loss)-pro forma	$	48,672,818		$	9,636,434		$	(2,452,990	)

Net earnings (loss) per share-as reported-basic	$	1.08		$	0.31		$	(0.08	)
Net earnings (loss) per share-as reported-diluted	$	1.06		$	0.30		$	(0.08	)
Net earnings (loss) per share-pro forma-basic	$	1.04		$	0.28		$	(0.11	)
Net earnings (loss) per share-pro forma-diluted	$	1.02		$	0.27		$	(0.11	)
Weighted-average fair value of options granted during the year	$	6.47		$	8.85		$	4.46

We estimate the fair value of each option grant on the date of grant using a Black-Scholes options-pricing model. ~~This~~The model assumed, ~~expected volatility of 94%, 69%~~for the years ended March 31, 2006, 2005 and ~~90% and weighted average risk-free interest rates of 3.3%, 3.2% and 4.5% for grants in 2004, 2003 and 2002, respectively, and an expected life of five years.~~ 2004:


	2006		2005		2004
Expected volatility	52	%	86	%	94	%
Weighted-average risk-free interest rates	4.0	%	3.7	%	3.3	%
Expected life in years	4.1		5		5

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 that the value an optionee actually realizes will be at or near the value we have estimated using the Black-Scholes model.

Revenue and Cost Recognition

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

Our management has determined that it is appropriate to use the percentage-of-completion method, as defined in SOP 81-1, 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, ultimate recovery of that value, in the event we were unable to drill to the agreed on depth in breach of the contract, would be subject to negotiations with the customer and the possibility of litigation.

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

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

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

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

Prepaid Expenses

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

Property and Equipment

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

We charge our expenses for maintenance and repairs to operations. We charge our expenses for renewals and betterments to the appropriate property and equipment accounts. Our gains and losses on the sale of our property and equipment are recorded in drilling costs. During fiscal ~~2004~~2006 and ~~2003,~~2005, we capitalized ~~$106,395~~$194,500 and ~~$96,079,~~$86,819, respectively, of interest costs incurred during the construction periods of certain drilling equipment. At March 31, ~~2004~~2006 and ~~2003,~~2005, costs incurred on rigs under construction were approximately ~~$2,800,000~~$26,172,000 and ~~$2,415,000,~~$3,300,000, respectively.

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

Cash and Cash Equivalents

We maintain cash accounts at several financial institutions. These account balances are insured by the Federal Deposit Insurance Corporation up to $100,000. At March 31, 2006, we had cash account balances of approximately $9,147,000, exceeding the $100,000 insurance threshold.

For purposes of the statements of cash flows, we consider all highly liquid debt instruments purchased with a maturity of three months or less to be cash equivalents. Cash equivalents consist of investments in corporate and government money market ~~accounts and auction rate seven day taxable preferred securities.~~accounts. Cash equivalents at March 31, ~~2004~~2006 and ~~2003~~2005 were ~~$6,118,000~~$85,618,000 and ~~$1,060,000,~~$65,046,000, respectively.

Marketable Securities

~~Investment Securities~~

~~We carry our available-for-sale investment securities at their fair values. Investment~~Marketable securities consist of ~~common stock. Unrealized holding~~auction rate seven-day preferred securities whose market value is equal to their cost. The objective of investing in these securities is to improve our yield on short-term investments of cash. There were no realized or unrealized gains ~~and~~or losses ~~net of~~relating to marketable securities during the related tax effect, on available-for-sale securities are excluded from earnings and are reported as a separate component of other comprehensive income until realized. Realized gains and losses from the sale of available-for-sale securities are determined on a specific identification basis. As ofyears ended March 31, ~~2002, these securities had an aggregate cost of $171,527, a gross unrealized gain of $165,782~~2006, 2005 and ~~an aggregate fair value of $337,309. We sold all of our investment securities in April 2002, realizing a gain of $203,887.~~2004.

Trade Accounts Receivable

We record trade accounts receivable at the amount we invoice our customers. These accounts do not bear interest. The allowance for doubtful accounts is our best estimate of the amount of probable credit losses in our accounts receivable as of the balance sheet date. We determine the allowance based on the credit worthiness of our customers and general economic conditions. Consequently, an adverse change in those factors could affect our estimate of our allowance for doubtful accounts. We review our allowance for doubtful accounts monthly. Balances more than 90 days past due are reviewed individually for collectibility. We charge off account balances against the allowance after we have exhausted all reasonable means of collection and determined that the potential for recovery is remote. We do not have any ~~off-balance-sheet~~off-balance sheet credit exposure related to our customers. At March 31, ~~2004~~2006 and ~~2003~~2005 our allowance for doubtful accounts was ~~$110,000.~~$200,000 and $352,000.

Intangible and Other Assets

~~Other~~Intangible and other assets consist of cash deposits related to the deductibles on our workers compensation insurance policies, loan fees net of amortization and intangibles related to acquisitions, net of amortization. Loan fees ~~are~~were fully amortized ~~over~~when we paid the ~~terms~~outstanding balance of the ~~related debt.~~acquisition facility in August 2005. Intangibles related to ~~acquisitions, primarily~~ customer lists ~~are~~were amortized over their estimated benefit periods of up to 18 ~~months.~~months and were fully amortized by December 2005. Intangibles related to non-compete agreements are amortized over the period of the non-compete agreements of three to five years. Depreciation and amortization expense includes amortization of intangibles of $65,000, $142,157 and $39,341 during the years ended March 31, 2006, 2005 and 2004, 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

On March 31, 2005, Chesapeake Energy Corporation (“Chesapeake”) owned 16.78% of our outstanding common stock. Chesapeake’s ownership percentage remained approximately the same until they sold their entire interest on February 10, 2006. During the years ended March 31, 2006 and 2005, we recognized revenues of approximately $28,705,000 and $4,885,000, respectively, and recorded contract drilling costs, excluding depreciation, of approximately $18,121,000 and $3,263,000, respectively, on drilling contracts with Chesapeake. Our accounts receivable at March 31, 2006 and 2005, included $4,699,000 and $2,939,000, respectively, due from Chesapeake.

We purchased services from R&B Answering Service and Frontier Service, Inc. during 2006, 2005 and 2004. These companies are more than 5% owned by our Chief Operating Officer and an immediate family member of our Vice President and Operations Manager, respectively. The following summarizes the purchases and payments to these companies in each period.


	2006		2005		2004
R&B Answering Service
Purchases	$	16,915	$	18,218	$	13,526
Payments	$	19,965	$	17,112	$	12,544
Frontier Services, Inc.
Purchases	$	5,953	$	81,254	$	118,660
Payments	$	9,302	$	93,709	$	136,818

Our Chief Operating Officer, Senior Vice President of Marketing, and 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. We recognized contract drilling revenues of approximately $455,000, $508,000 and $228,000 on these wells during fiscal years 2006, 2005 and 2004, respectively.

Recently Issued Accounting Standards

~~On April 1, 2003, we adopted~~In December 2004, the Financial Accounting Standards Board (the “FASB”) issued SFAS No. ~~143,~~ 123R (revised 2004),Share-Based Payment. SFAS No. 123R is a revision of SFAS No. 123,Accounting for ~~Asset Retirement Obligations~~Stock-Based Compensation,,and supersedes APB Opinion No. 25,Accounting for Stock Issued to Employees,and its related implementation guidance. SFAS No. 123R established standards for the accounting for transactions in which an entity exchanges its equity instruments for goods or services. It also addresses ~~financial accounting and reporting~~transactions in which an entity incurs liabilities in exchange for obligations associated with the retirement of tangible long-lived assets and the associated asset retirement costs. The standard applies to legal obligations associated with the retirement of long-lived assetsgoods or services that result from the acquisition, construction, development and/or normal use of the asset. In that connection, we were required to identify all our legal obligations relating to asset retirements and determineare based on the fair value of ~~these obligations as~~the entity’s equity instruments or that may be settled by the issuance of ~~April 1, 2003. Our adoption~~those equity instruments. SFAS No. 123R focuses primarily on accounting for transactions in which an entity obtains employee services in share-based payment transactions. SFAS No. 123R requires a public entity to measure the cost of employee services received in exchange for an award of equity instruments based on the grant-date fair value of the award (with limited exceptions). That cost will be recognized over the period during which an employee is required to provide service in exchange for the award. The provisions of SFAS No. ~~143 did not have a material effect on our financial position or results of operations.~~

~~On July 1, 2003, we adopted SFAS No. 149,~~ ~~Amendment of Statement 133 on Derivative Instruments and Hedging Activities.~~ This statement amends and clarifies financial accounting and reporting for derivative instruments, including certain derivative instruments in other contracts (collectively referred to as derivatives) and for hedging activities under SFAS No. 133, ~~Accounting for Derivative Instrument and Hedging Activities~~~~. The provisions of this statement~~123R are effective for contracts entered into or modified after June 30, 2003 and hedging relationships designated after June 30, 2003. Except for the provisions related to SFAS No. 133, all provisions of this statement will be applied prospectively. In addition, paragraphs 7(a) and 23(a) of this statement, which relate to forward purchases or sales of when-issued securities or other securitiespublic entities that do not ~~yet exist, should be applied to both existing contracts and new contracts entered into after June 30, 2003. Our adoption~~file as small business issuers as of ~~SFAS No. 149 did not have a material effect on our financial position or results of operations.~~

~~On July 1, 2003, we adopted SFAS No. 150,~~ ~~Accounting for Certain Financial Instruments with Characteristics of Both Liabilities and Equity.~~ This statement requires issuers to classify as liabilities (or assets in some circumstance) three classes of freestanding financial instruments that embody obligations of the issuer. The provisions of this statement are effective for financial instruments entered into or modified after May 31, 2003, and otherwise are effective at the beginning of the first ~~interim~~annual reporting period ~~beginning~~that begins after June 15, ~~2003. Our~~2005. We will adopt SFAS No. 123R effective April 1, 2006 using the modified prospective method. The modified prospective method requires us to recognize compensation cost for unvested awards that are outstanding on the effective date based on the fair value originally estimated for our SFAS No. 123 pro forma disclosures. SFAS No. 123R will have a negative impact on our financial position and results of operations in fiscal year 2007 and in subsequent periods. The negative impact of SFAS No. 123R to net earnings (loss) and net earnings (loss) per share for the years ended March 31, 2006, 2005 and 2004 is presented in our SFAS 123 pro forma disclosures in the table above.

In May 2005, the FASB issued SFAS No. 154,Accounting Changes and Error Corrections, which supersedes APB Opinion No. 20,Accounting Changesand SFAS No. 3,Reporting Accounting Changes in Interim Financial Statements.SFAS No. 154 changes the requirements for the accounting for and reporting of changes in accounting principles. The statement requires the retroactive application to prior periods’ financial statements of changes in accounting principles, unless it is impracticable to determine either the period-specific effects or the cumulative effect of the change. SFAS No. 154 does not change the guidance for reporting the correction of an error in previously issued financial statements or the change in an accounting estimate. SFAS No. 154 is effective for accounting changes and corrections of errors made in fiscal years beginning after December 15, 2005. We do not expect the adoption of SFAS No. ~~150 did not~~154 to have a material ~~effect~~impact on our financial position orand results of ~~operations.~~operations and financial condition.

Reclassifications

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

2.Acquisitions

On ~~May 28, 2002,~~November 30, 2004, we acquired all the ~~land~~ contract drilling assets and a 4.7-acre rig storage and maintenance yard of ~~United~~Wolverine Drilling, ~~Company and U-D Holdings, L.P.~~Inc., a land drilling contractor based in Kenmare, North Dakota. The ~~assets~~equipment included ~~two~~seven mechanical land drilling rigs ~~associated~~and related assets, including trucks, trailers, vehicles, spare ~~parts~~drill pipe and ~~equipment and vehicles.~~yard equipment. We paid ~~$7,000,000~~$28,000,000 in cash for these ~~assets. The purchase was accounted for as an acquisition of~~ assets and non-competition agreements with the ~~purchase price was allocated to drilling equipment and related assets based on their relative fair values at the date~~two owners of ~~acquisition.~~

~~On August 1, 2003, we purchased two land drilling rigs, associated spare parts and equipment and vehicles from Texas Interstate Drilling Company, L. P. for $2,500,000~~Wolverine. We funded this acquisition with $28,000,000 of bank debt which has subsequently been paid in ~~cash and the issuance of 477,000 shares of our common stock at $4.45 per share. The~~full. This purchase was accounted for as an acquisition of a business, and we have included the results of ~~operations~~operation of ~~these assets~~the acquired business in our statement of operations since the date of acquisition. We allocated the purchase price to ~~drilling~~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, ~~2003, we acquired for approximately $3,770,000 a rig we had previously been leasing from International Drilling Services, Inc. This purchase was accounted for as an acquisition of assets.~~

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

~~On March 4, 2004, we acquired a seven-rig drilling fleet from Sawyer~~Allen Drilling ~~& Services, Inc.~~which provides for ~~$12,000,000.~~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 ~~these assets~~the acquired business in our statement of operations since the date of acquisition. We allocated the purchase price to ~~drilling~~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 March 12, 2004, we acquired one drilling rig from SEDCO Drilling Co., Ltd. for $2,015,000. This purchase was accounted for as an acquisition~~

The following table summarizes the allocation of ~~assets, and we have included the results of operations of these assets in our statement of operations since the date of acquisition. We allocated the~~ purchase price to ~~drilling~~property and equipment and ~~related~~other assets ~~including intangibles, based on their relative fair values at~~acquired in the ~~date of acquisition.~~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 obligation		—		(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 and 2004. Pro forma adjustments primarily relate to additional depreciation, amortization and interest costs. The information reflects our historical data and historical data from these acquired businesses for the periods indicated. The pro forma data may not be indicative of the results we would have achieved had we completed these acquisitions on April 1, 2003 or 2004, or that we may achieve in the future. The pro forma financial information should be read in conjunction with the accompanying historical financial statements.

Pro Forma
Years Ended March 31,

   2005    2004
Total revenues
   $ 208,394,551    $ 132,287,140
Net earnings (loss)
   $ 11,943,137    $ (2,100,116 )
Earnings (loss) per common share:

Basic
   $ 0.35    $ (0.09 )
Diluted
   $ 0.33    $ (0.09 )

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

Our long-term debt is described below:

March 31,

2004

2003

Convertible subordinated debentures due July 2007 at 6.75% (1)

$
28,000,000

$
28,000,000

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

13,119,048

14,500,000

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

4,392,174

5,677,889

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

—

87,897

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

3,000,000

—

48,511,222

48,265,786

Less current installments

(3,724,302
)
(2,671,269
)

$
44,786,920

$
45,594,517


	March 31,
	2006		2005
Indebtedness under $57,000,000 credit facility, secured by drilling equipment, interest at prime (7.75% at March 31, 2006) or LIBOR plus a percentage ranging from 1.75% to 2.5%, maturity in October 2006	$	—	$	18,077,778

		—		18,077,778

Less current installments		—		(4,666,667	)

	$	—	$	13,411,111

~~(1)~~ ~~Wedge Energy Services, LLC (“WEDGE”) holds $27,000,000~~We have a $57,000,000 credit facility with a group of lenders consisting of a $7,000,000 revolving line and letter of credit facility and a $50,000,000 acquisition facility for the acquisition of drilling rigs, drilling rig transportation equipment and associated equipment. Frost National Bank is the administrative agent and lead arranger under the credit facility, and the lenders include Frost National Bank, the Bank of Scotland and Zions First National Bank. Borrowings under the credit facility bear interest at a rate equal to Frost National Bank’s prime rate (7.75% at March 31, 2006) or, at our option, at LIBOR plus a percentage ranging from 1.75% to 2.5%, based on our operating leverage ratio. Borrowings are secured by most of our assets, including all our drilling rigs and associated equipment and receivables. In August 2005, we repaid the then remaining outstanding balance of approximately $16,500,000 under the acquisition facility. At March 31, 2006, we had no borrowings under the acquisition facility and we had used approximately $3,050,000 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 $3,950,000. Both the revolving line and letter of credit facility and acquisition facility are scheduled to mature in October 2006.

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 are limited to 75% of our eligible accounts receivable, not to exceed $7,000,000. Therefore, if 75% of our eligible accounts receivable was less than $7,000,000, our ability to draw under this line would be reduced. At March 31, 2006, we had no outstanding advances under this line of credit, we had outstanding letters of credit of approximately $3,050,000 and 75% of our eligible accounts receivable was approximately $25,682,000. 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.

At March 31, 2006, 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 0.3 to 1, a fixed charged coverage ratio of not less than 1.5 to 1 and an operating leverage ratio of not more than 3 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.

In October 2001, we issued $18,000,000 of 6.75% convertible subordinated debentures and William H. White, a former director of our company, holds $1,000,000. WEDGE owns 26.5% of our common stock (40.2% if the debentures were converted). Beginning July 3, 2004, we have the option to redeem all or part of the debentures by paying a premium of 5% through July 2, 2005, 4% through July 2, 2006, 3% through July 2, 2007 and 0% thereafter.

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

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

Year Ended
March 31,

2005

$
3,724,302

2006

3,743,087

2007

5,604,040

2008

35,439,793

2009

—

2010 and thereafter

—

~~On October 9, 2001, we issued a 6.75% five-year $18,000,000 convertible subordinated debenture, Series A,~~ to WEDGE Energy Services, L.L.C. (“WEDGE”). The debenture was convertible into 4,500,000 shares of common stock at $4.00 per share. We used approximately $9,000,000 of the proceeds to complete the construction of two drilling rigs. Approximately $6,000,000 was used to reduce a $12,000,000 credit facility. The balance of the proceeds was used for drilling equipment and working capital. OnIn July 3, 2002, we issued ~~an additional $10,000,000~~$9,000,000 and $1,000,000 of 6.75% convertible subordinated ~~debt~~debentures to WEDGE with an effective conversion rate of $5.00 per share. The transaction was effected by an agreement between Pioneer and WEDGE under which WEDGE agreed to provide the additional $10,000,000 in financing and to cancel the previously issued debenture in the principal amount of $18,000,000 in exchange for $28,000,000 in new 6.75% convertible subordinated debentures. The new debentures are convertible into 6,500,000 shares of common stock at $4.31 per share, which resulted from a pro rata blending of the $5.00 conversion rate of the new $10,000,000 financing and the $4.00 conversion rate of the $18,000,000 debenture being cancelled. WEDGE funded $7,000,000 of the $10,000,000 on July 3, 2002 and $2,000,000 on July 29, 2002. William H. White, a former Director of our Company and the former President of WEDGE, ~~purchased the remaining $1,000,000 on~~respectively. These debentures were due by July ~~29, 2002. Unlike the cancelled debenture, which was not redeemable by Pioneer, the new~~2007. In addition, these debentures ~~are~~were convertible into 6,496,519 shares of common stock at $4.31 per share and redeemable at a scheduled premium. ~~We used $7,000,000 of the proceeds to pay down bank debt and $3,000,000 for the purchase of drilling equipment.~~

We have a $2,500,000 line of credit available from Frost National Bank. Any borrowings under this line of credit are secured by our trade receivables and bear interest at a rate of prime (4.00% at March 31, 2004) plus 1.0%. The sum of draws under this line and the amount of all outstanding letters of credit issued by the bank for our account are limited to 75% of eligible accounts receivable. Therefore, if 75%On August 11, 2004, we converted these debentures in accordance with their terms into 6,496,519 shares of our eligible accounts receivable is less than $2,500,000 plus any outstanding letters of credit issued by the bank on our behalf, our ability to draw under this line would be reduced. At March 31, 2004, we had no outstanding advances under this line of credit, letters of credit were $1,664,000 and 75% of eligible accounts receivable was approximately $8,030,000. The letters of credit are issued to two workers’ compensation insurance companies to secure possible future claims that do not exceed the deductibles on these policies. It is our practice to pay any amounts due that do not exceed these deductibles as they are incurred. Therefore, we do not anticipate the lender will be required to fund any draws under these letters of credit.

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

common stock.

Notes payable at March 31, ~~2004 consists~~2005 consisted of a ~~$558,070~~$681,975 insurance premium note due ~~in monthly installments of $112,355 through~~on August 26, ~~2004 which bears~~2005, plus interest at the rate of ~~2.65%~~3.15% per year.

4.Leases

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

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

~~leases were as follows:~~

March 31,

2004

2003

Transportation equipment

$
665,195

$
647,822

Less accumulated amortization

413,797

248,070

$
251,398

$
399,752

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

We lease ~~real estate in Henderson, Texas; Alice, Texas; and Decatur, Texas and~~ various office equipment under non-cancelable operating leases expiring through ~~2006.~~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 4-acre division storage yard in Decatur, Texas, at a cost of $800 per month, pursuant to a lease extending through September 2006;

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

a marketing office in Denver, Colorado, at a cost of $1,210 per month, pursuant to a lease extending through October 2006;

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 these operating leases for the years ended March 31, 2006, 2005 and 2004 ~~2003~~was $283,628, $102,077 and ~~2002 was~~ $278,746, ~~$344,752 and $208,150,~~ respectively.

Future lease obligations ~~and minimum capital lease payments~~ as of March 31, ~~2004~~2006 were as follows:

Year Ended
March 31,

Operating
Leases

Capital
Leases

2005

$
121,608

$
166,604

2006

122,940

70,446

2007

69,912

34,106

2008

—

—

Total minimum lease payments

$
314,460

$
271,156

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

(25,468
)
Present value of net minimum capital lease payments

245,688

Less current installments of capital lease obligations

(140,934
)
Capital lease obligations, excluding current installments

$
104,754


Year Ended March 31,
2007	$	243,104
2008		234,930
2009		212,073
2010		215,238
2011		213,913
Thereafter		607,006

	$	1,726,264

5.Income Taxes

Our provision for income taxes consists of the following:

	Years Ended March 31,
	2004			2003			2002		Years Ended March 31,
									2006		2005		2004
Current tax - state									$	701,124	$	56,400	$	—
Current tax - federal	$	—		$	(708,032	)	$	1,427,067		14,266,384		335,109		—
Deferred tax - state										312,510		55,164		—
Deferred tax - federal	(426,299		)	(1,511,744		)	1,991,458			13,966,599		5,902,828		(426,299	)

Income tax expense (benefit)	$	(426,299	)	$	(2,219,776	)	$	3,418,525	$	29,246,617	$	6,349,501	$	(426,299	)

~~In fiscal years 2004, 2003 and 2002, our expected~~

The following is a reconciliation of income tax ~~which we compute~~expense (benefit) to income taxes computed by applying the federal statutory income tax rate of(35% for fiscal year 2006 and 34% for fiscal years 2005 and 2004) to income (loss) before income ~~taxes, differs from our income tax expense as follows:~~taxes:

Years Ended March 31,

2004

2003

2002

Expected tax expense (benefit)

$
(753,561
)
$
(2,483,834
)
$
3,310,515

Non taxable interest income

—

(10,400
)
(9,429
)
Club dues, meals and entertainment

13,941

10,443

10,115

Reimbursement of food costs for rig employees

314,622

275,338

270,000

Other

(1,301
)
(11,323
)
(162,676
)

$
(426,299
)
$
(2,219,776
)
$
3,418,525


	Years Ended March 31,
	2006			2005		2004
Expected tax expense (benefit)	$	27,934,627		$	5,834,783	$	(753,561	)
Tax basis adjustment to 35% for prior year deferred tax components		813,936			—		—
Club dues, meals and entertainment		32,344			24,050		13,941
State income taxes		658,862			92,388		—
Other		(193,152	)		398,280		313,321

	$	29,246,617		$	6,349,501	$	(426,299	)

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

March 31,

2004

2003

Deferred tax assets:

Workers compensation and vacation expense accruals

$
224,985

$
94,972

Bad debt expense

37,400

37,400

Net operating loss carryforwards

7,825,126

5,105,730

Alternative minimum tax credit

181,770

181,770

Loss accrual on turnkey contracts

23,000

48,619

Total deferred tax assets

8,292,281

5,468,491

Deferred tax liabilities:

Property and equipment, principally due to differences in depreciation

14,017,813

11,127,408

Total deferred tax liabilities

14,017,813

11,127,408

Net deferred tax liabilities

$
5,725,532

$
5,658,917


	March 31,
	2006		2005
Deferred tax assets:
Vacation expense accruals	$	104,338	$	71,446
Workers compensation and health insurance accruals		812,038		378,423
Bad debt expense		73,520		119,680
Net operating loss carryforwards		—		5,616,861
Alternative minimum tax credit		—		311,915
Deferred lease liability		32,966		—

Total deferred tax assets		1,022,862		6,498,325

Deferred tax liabilities:
Property and equipment, principally due to differences in depreciation		25,926,429		16,924,919
Other		1,089,064		1,286,928

Total deferred tax liabilities		27,015,493		18,211,847

Net deferred tax liabilities	$	25,992,631	$	11,713,522

In assessing our ability to realize deferred tax assets, we consider whether it is more likely than not that some portion or all of the deferred tax assets will not be realized. Our ultimate realization of deferred tax assets depends on the generation of future taxable income during the periods in which those temporary differences become deductible. We consider the scheduled reversal of deferred tax liabilities, projected future taxable income, and tax planning strategies in making this assessment. Based on the level of historical taxable income and projections for future taxable income over the periods during which the deferred tax assets are deductible, we ~~believe~~believed at March 31, 2005 it iswas more likely than not that we ~~will~~would realize the benefits of these deductible differences.

At March 31, ~~2004,~~2005, we had net operating loss carryforwards for federal income tax purposes of approximately ~~$25,500,000 which will expire if not utilized as of~~$16,500,000. Taxable income for the ~~end of our fiscal years ending as follows:~~year ended March 31, 2006 was sufficient to fully utilize these net operating loss carryforwards.

Year

Amount

2023

15,000,000

2024

10,500,000

6.Fair Value of Financial Instruments

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

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

~~Long-term debt:~~

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

7.Earnings (Loss) Per Common Share

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

Years Ended March 31,

2004

2003

2002

Basic

Net earnings (loss)

$
(1,790,057
)
$
(5,085,618
)
$
6,318,285

Less: Preferred stock dividends

—

—

92,814

Earnings (loss) applicable to common shareholders

$
(1,790,057
)
$
(5,085,618
)
$
6,225,471

Weighted average shares

22,585,612

16,163,098

15,112,272

Earning (loss) per share

$
(0.08
)
$
(0.31
)
$
0.41

Diluted

Earnings (loss) applicable to common shareholders

$
(1,790,057
)
$
(5,085,618
)
$
6,225,471

Effect of dilutive securities:

Convertible subordinated debenture

—

—

385,358

Preferred stock

—

—

92,814

Earnings (loss) available to common shareholders and assumed conversion

$
(1,790,057
)
$
(5,085,618
)
$
6,703,643

Weighted average shares:

Outstanding

22,585,612

16,163,098

15,112,272

Options

—

—

1,500,589

Convertible subordinated debenture

—

—

2,145,205

Preferred stock

—

—

463,190

22,585,612

16,163,098

19,221,256

Earnings (loss) per share

$
(0.08
)
$
(0.31
)
$
0.35


	Years Ended March 31,
	2006		2005		2004
Basic
Net earnings (loss)	$	50,566,603	$	10,811,625	$	(1,790,057	)

Weighted average shares		46,808,323		34,543,695		22,585,612

Earning (loss) per share	$	1.08	$	0.31	$	(0.08	)

Diluted
Earnings (loss) applicable to common shareholders	$	50,566,603	$	10,811,625	$	(1,790,057	)
Effect of dilutive securities - Convertible subordinated debenture		—		459,483		—

Earnings (loss) available to common shareholders and assumed conversion	$	50,566,603	$	11,271,108	$	(1,790,057	)

Weighted average shares:
Outstanding		46,808,323		34,543,695		22,585,612
Options		697,562		684,806		—
Convertible subordinated debenture		—		2,349,426		—

		47,505,885		37,577,927		22,585,612

Earnings (loss) per share	$	1.06	$	0.30	$	(0.08	)

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

8.Equity Transactions

On ~~May 18, 2001, we retired~~August 11, 2004, the ~~4.86% subordinated debenture we issued to WEDGE on March 30, 2001~~entire $28,000,000 in ~~connection with the Mustang Drilling, Ltd. acquisition. We funded the repayment of the $9,000,000 face~~aggregate principal amount of ~~the debenture, together with the payment of $59,535 of accrued interest, with a short-term bank borrowing. We then sold 2,400,000 shares of~~ our ~~common stock to~~6.75% convertible subordinated debentures held by WEDGE Energy Services, L.L.C. and William H. White was converted in ~~a private placement for $9,048,000, or $3.77 per share. We used the proceeds from this sale to fund the repayment of the short-term bank borrowing.~~

In accordance with the terms of ~~the Series B Preferred Stock Agreement that we entered~~those debentures into on January 20, 1998, the conversion price for our Series B convertible preferred stock was revised from $3.25 per share to $2.50 per share as of January 20, 2001. This revision was based on the average trading price6,496,519 shares of our common ~~stock for the 30 trading days preceding that date. In~~stock.

On August ~~2001, the holders converted all of their 184,615 shares of our Series B convertible preferred stock into 1,199,038~~11, 2004, we sold 4,000,000 shares of our common stock at ~~$2.50~~approximately $6.61 per ~~share.~~

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

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

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

~~On February 20, 2004, we~~ sold ~~4,400,000~~600,000 additional shares of our common stock at ~~$5.40~~approximately $6.61 per share, net of underwriters’ commissions, pursuant to the underwriters’ exercise of an over-allotment option granted in ~~a private placement for $23,760,000 in proceeds, before related offering expenses. Although~~connection with that public offering.

On March 22, 2005, we ~~issued those~~sold 6,945,000 shares ~~without registration under~~of our common stock, including shares we sold pursuant to the ~~Securities Act~~underwriters’ exercise of ~~1933 in reliance on the exemption that Section 4(2)~~an over-allotment option, at approximately $11.78 per share, net of ~~that Act provides for transactions not involving any~~underwriters’ commissions, pursuant to a public offering we ~~filed~~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 ~~registration statement on Form S-3 to register those shares. The registration statement became effective on June 22, 2004.~~

public offering we registered with the SEC.

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, 551,666 shares of common stock at prices ranging from $.375 to $6.44 per share during the fiscal year ended March 31, 2005 and 722,334 shares of common stock at prices ranging from $.625 to $3.20 per share during the fiscal year ended March 31, 2004, 445,000 shares of common stock at prices ranging from $.375 to $2.50 per share during the year ended March 31, 2003 and 27,500 shares of common stock at prices ranging from $0.375 to $1.00 per share during the year ended March 31, 2002.2004.

9.Stock Options, Warrants and Stock Option Plan

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

The following table provides information relating to our outstanding stock options at March 31, ~~2004, 2003~~2006, 2005 and ~~2002:~~2004:

2004

2003

2002

Shares
Issuable on
Exercise of
Options

Exercise
Price per
Share

Shares
Issuable on
Exercise of
Options

Exercise
Price per
Share

Shares
Issuable on
Exercise of
Options

Exercise
Price per
Share

Balance Outstanding

Beginning of year

1,825,000

$
.375-5.15

2,320,000

$
0.375-5.15

2,177,500

$
0.375-4.60

Granted

1,000,000

$
3.67-4.99

65,000

$
3.20-4.50

585,000

$
3.00-5.15

Exercised

(722,334
)
$
.625-3.20

(445,000
)
$
0.375-2.50

(177,500
)
$
0.375-1.50

Canceled

(46,000
)
$
2.25

(115,000
)
$
2.25-4.60

(265,000
)
$
2.25

Balance Outstanding

End of year

2,056,666

$
.375-5.15

1,825,000

$
0.375-5.15

2,320,000

$
0.375-5.15

Options Exercisable

End of year

884,001

1,437,334

1,734,000


	2006				2005				2004
	Shares Issuable on Exercise of Options		Weighted Average Price		Shares Issuable on Exercise of Options		Weighted Average Price		Shares Issuable on Exercise of Options		Weighted Average Price
Balance Outstanding Beginning of year	2,005,000		$	5.30	2,056,666		$	3.24	1,825,000		$	1.63
Granted	336,500		$	14.53	510,000		$	8.85	1,000,000		$	4.46
Exercised	(698,667	)	$	3.94	(551,666	)	$	1.37	(722,334	)	$	0.93
Canceled	(50,000	)	$	9.65	(10,000	)	$	4.52	(46,000	)	$	2.25

Balance Outstanding End of year	1,592,833		$	7.71	2,005,000		$	5.30	2,056,666		$	3.24

Options Exercisable End of year	546,666		$	5.40	798,002		$	3.58	884,001		$	1.95

As of March 31, ~~2004,~~2006, there were no outstanding warrants.

The following table summarizes information about our employee stock options outstanding and exercisable at March 31, ~~2004, the weighted average exercise price of our outstanding options was $3.24 per share and the weighted average exercise price of our exercisable options was $1.95 per share.~~2006:


	Options Outstanding				Options Exercisable
Range of Exercise Prices	Number Outstanding	Weighted Average Remaining Contractual Life	Weighted Average Exercise Price		Number Exercisable	Weighted Average Exercise Price
$3.00 - $4.77	841,333	7.19	$	4.12	401,666	$	3.67
$5.95 - $9.65	399,000	8.62	$	9.42	115,000	$	9.22
$10.31 - $14.58	352,500	8.92	$	14.34	30,000	$	13.98

	1,592,833	7.93	$	7.71	546,666	$	5.40

10.Employee BenefitPlans and Insurance

We maintain a 401(k) retirement plan for our eligible employees. Under this plan, we may contribute, on a discretionary basis, a percentage of an eligible employee’s annual contribution, which we determine annually. Our contributions for fiscal ~~2004, 2003~~2006, 2005 and ~~2002~~2004 were approximately $643,000, $399,000 and $76,000, ~~$92,000 and $153,000,~~ respectively.

We maintain a self-insurance program, for major medical, hospitalization and dental coverage for employees and their dependents, which is partially funded by payroll deductions. We have provided for both reported and incurred but not reported medical costs in the accompanying consolidated balance sheets. We have a maximum liability of ~~$100,000~~$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, ~~2004~~2006 and 2005 include approximately ~~$280,000~~$553,000 and $489,000, 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 for all workers’ compensation claims submitted by employees for on-the-job ~~injuries.~~injuries, except in North Dakota where the deductible is $100,000. We have provided for both reported and incurred but not reported costs of workers’ compensation coverage in the accompanying consolidated balance sheets. Accrued expenses at March 31, ~~2004~~2006 and 2005 include approximately ~~$400,000~~$1,829,000 and $845,000, 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 ~~Supplementary Earnings Information~~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, 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 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 2004. In fiscal 2004, our three largest customers accounted for 10.5%, 6.4% and 4.9%, respectively, of our total contract drilling revenue. Two of these customers were customers of ours in 2003. In fiscal 2003, our three largest customers accounted for 10.8%, 6.5% and 5.4%, of our total contract drilling revenue. Two of these customers were customers of ours in fiscal 2002. In fiscal 2002, our three largest customers accounted for 13.7%, 12.2% and 11.1% of our total contract drilling revenue.

12.Commitments and Contingencies

~~We are in the process of constructing, primarily from used components, a 1000-hp electric drilling rig.~~ As of March 31, ~~2004,~~2006, we ~~have~~were constructing, from new and used components, nine 1000-horsepower diesel electric rigs at an estimated cost ranging from $7,600,000 to $9,500,000 each. We placed two of these rigs into service in April and May 2006 and we expect to place the remaining seven rigs into service at varying times prior to March 31, 2007. As of March 31, 2006, we had incurred approximately ~~$2,800,000~~$26,172,000 of the approximately $74,100,000 of construction ~~costs. We anticipate additional construction~~ costs ~~of $1,200,000 to $1,700,000. The rig began moving to its first drilling location~~ on ~~May 28, 2004.~~

these rigs.

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.Quarterly Results of Operations (unaudited)

The following table summarizes quarterly financial data for our fiscal years ended March 31, ~~2004~~2006 and ~~2003~~2005 (in thousands, except per share data):

First
Quarter

Second
Quarter

Third
Quarter

Fourth
Quarter

Total

2004

Revenues

$
23,850

$
24,244

$
26,414

$
33,368

$
107,876

Income (loss) from operations

(789
)
(166
)
9

1,384

438

Net earnings (loss)

(1,056
)
(621
)
(522
)
409

(1,790
)
Earnings (loss) per share:

Basic

(.05
)
(.03
)
(.02
)
.02

(.08
)
Diluted

(.05
)
(.03
)
(.02
)
.02

(.08
)

2003

Revenues

$
18,452

$
17,042

$
19,795

$
24,894

$
80,183

Income (loss) from operations

153

(1,251
)
(1,840
)
(2,005
)
(4,943
)
Net earnings (loss)

(172
)
(1,302
)
(1,704
)
(1,908
)
(5,086
)
Earnings (loss) per share:

Basic

(.01
)
(.08
)
(.11
)
(.11
)
(.31
)
Diluted

(.01
)
(.08
)
(.11
)
(.11
)
(.31
)


	First Quarter			Second Quarter			Third Quarter			Fourth Quarter			Total
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
2005
Revenues	$	40,719		$	42,783		$	46,387		$	55,357		$	185,246
Income from operations		1,046			1,960			6,704			9,064			18,774
Income tax expense		(139	)		(590	)		(2,428	)		(3,192	)		(6,349	)
Net earnings		216			923			4,179			5,494			10,812
Earnings per share:
Basic		.01			.03			.11			.14			.31
Diluted		.01			.03			.11			.14			.30

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

***Item 9.9*. Changes in and Disagreements With Accountants on Accounting and Financial Disclosure**

Not applicable.

Item 9A9A.. Controls and Procedures

In accordance with Exchange Act Rules 13a-15 and 15d-15, we carried out an evaluation, under the supervision and with the participation of management, including our Chief Executive Officer and Chief Financial Officer, of the effectiveness of our disclosure controls and procedures as of the end of the period covered by this report. Based upon that evaluation, our Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures were effective as of March 31, ~~2004~~2006 to provide reasonable assurance that information required to be disclosed in our reports filed or submitted under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the Securities and Exchange Commission’s rules and forms.

There has been no change in our internal controls over financial reporting that occurred during the three months ended March 31, ~~2004~~2006 that has materially affected, or is reasonably likely to materially affect, our internal controls over financial reporting.

Management’s Report on Internal Control over Financial Reporting

The management of Pioneer Drilling Company is responsible for establishing and maintaining adequate internal control over financial reporting. Pioneer Drilling Company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. Pioneer Drilling Company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that: (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
Pioneer Drilling Company’s management assessed the effectiveness of Pioneer Drilling Company’s internal control over financial reporting as of March 31, 2006. 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, 2006, 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, 2006, as stated in their report which appears herein. That report appears on page 31.
***Item 9B*. Other Information
Not applicable.
PART III**

In Items 10, 11, 12, 13 and 1314 below, we are incorporating by reference the information we refer to in those Items from the definitive proxy statement for our ~~2004~~2006 Annual Meeting of Shareholders. We intend to file that definitive proxy statement with the SEC by July 15, ~~2004.~~2006.

***Item 10.10*. Directors and Executive Officers of the Registrant**

Please see the information appearing under the headings “Proposal No. 1—Election of Directors” and “Executives and Executive Compensation” in the definitive proxy statement for our ~~2004~~2006 Annual Meeting of Shareholders for the information this Item 10 requires.

***Item 11.11*. Executive Compensation**

Please see the information appearing under the heading “Executives and Executive Compensation” in the definitive proxy statement for our ~~2004~~2006 Annual Meeting of Shareholders for the information this Item 11 requires.

***Item 12.12*. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters**

Please see the information appearing (1) under the heading “Equity Compensation Plan Information” in Item 5 of this report and (2) under the heading “Security Ownership of Certain Beneficial Owners and Management” in the definitive proxy statement for our ~~2004~~2006 Annual Meeting of Shareholders for the information this Item 12 requires.

***Item 13.13*. Certain Relationships and Related Transactions**

Please see the information appearing under the heading “Certain Transactions” in the definitive proxy statement for our ~~2004~~2006 Annual Meeting of Shareholders for the information this Item 13 requires.

***Item 14.14*. Principal Accountant Fees and Services**

Please see the information appearing under the heading “Ratification of Appointment of Independent Auditors” in the definitive proxy statement for our ~~2004~~2006 Annual Meeting of Shareholders for the information this Item 14 requires.

PART IV

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

(1)Financial Statements.

See Index to Consolidated Financial Statements on page 29.

(2) Financial Statement Schedules:

Schedule II 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, 2004
Allowance for doubtful receivables	$	110,000	$	—		$	—	$	110,000

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

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


~~(a)(1)~~Exhibit Number		~~Financial Statements.~~Description
2.1*
-	~~See Index to Consolidated Financial Statements on page 27.~~

~~(2)~~	~~Financial Statement Schedules:~~

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

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

~~Exhibit~~ ~~Number~~		~~Description~~

2.1*	-	Asset Purchase Agreement dated ~~February 14, 2001~~November 11, 2004 between ~~Mustang~~Wolverine Drilling, ~~Ltd., Michael T. Wilhite, Sr., Andrew D. Mills~~Inc. and ~~Michael T. Wilhite, Jr. (Form 10-K for the year ended March 31, 2001 (File No. 1-8182, Exhibit 2.2)).~~

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

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

2.4*	-	~~Asset Purchase Agreement dated the 28th of May, 2002 by and between United Drilling Company, U-D Holdings, L.P.~~Robert Mau, Robert S. Blackford and Pioneer Drilling Services, Ltd.~~, a Texas limited partnership.~~ (Form ~~10-K for the year ended March 31, 2002~~8-K dated November 11, 2004 (File No. 1-8182, Exhibit ~~2.5)~~2.1)) .

3.1* 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*	-	~~Debenture Agreement Dated July 3, 2002 by and between WEDGE Energy Service, L.L.C. and Pioneer Drilling Company (Form 8-K filed July 18, 2002 (File No. 1-8182, Exhibit 4.1)).~~
-
4.2*	-	~~Debenture Purchase Agreement dated July 3, 2002 by and between WEDGE Energy Services, L.L.C. and Pioneer Drilling Company (Form 8-K filed July 18, 2002 (File No. 1-8182, Exhibit 4.2)).~~

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

4.18* 4.2*	-	~~Form of Purchase~~-	Credit Agreement ~~dated February 13, 2004~~ between Pioneer Drilling ~~Company~~Services, Ltd. and ~~the several purchasers~~Frost National Bank, as Administrative Agent, Agent, Lead Arranger and Lender dated October 29, 2004 (Form ~~S-3 filed February 24,~~8-K dated October 29, 2004 ~~(Reg. No. 333-113036, Exhibit 4.1)).~~

10.1*	-	Voting Agreement dated June 18, 1997 between Robert R. Marmor, William D. Hibbetts, Wm. Stacy Locke, Alvis L. Dowell, Charles B Tichenor and Richard Phillips (Form 10-K for the year ended March 31, 2001 (File No. 1-8182, Exhibit ~~9.1)~~4.1)).

10.2* 4.3*	-	~~Voting Agreement~~-	Second Amendment, dated May 11, ~~2000~~2005, to Credit Agreement between ~~Wm. Stacy Locke, Michael E. Little,~~ Pioneer Drilling ~~Company~~Services, Ltd. And Frost National Bank, as Administrative Agent, Lead Arranger and ~~WEDGE Energy Services, L.L.C.~~Lender dated October 29, 2004 (Form ~~10-K for the year ended March 31, 2001~~8-K dated May 12, 2005 (File No. 1-8182, Exhibit ~~9.2)~~4.1)).

10.3* 4.4*	-	~~Voting Agreement~~-	Third Amendment, dated October ~~9, 2001~~25, 2005, to Credit Agreement between Pioneer Drilling ~~Company~~Services, Ltd. And Frost National Bank, as Administrative Agent, Lead Arranger and ~~WEDGE Energy Service, L.L.C. (See Section 1.3 of the Debenture Purchase~~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 ~~referenced above~~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 ~~4.5)~~4.1)).

10.1+*		-	Pioneer Drilling Services, Ltd. Annual Incentive Compensation Plan dated August 5, 2005 (Form ~~10-K for year ended March 31, 2003~~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)).

~~10.4+~~10.3+*	-	~~Executive Employment Agreement dated May 1, 1995 between Pioneer Drilling Company and Wm. Stacy Locke (Form 10-K for the year ended March 31, 2001 (File No. 1-8182, Exhibit 10.1+)).~~
-
10.5+*	-	Second Amendment to Executive Employment Agreement dated August 21, 2000 between Pioneer Drilling Company and Wm. Stacy Locke (Form 10-K for the year ended March 31, 2001 (File No. 1-8182, Exhibit 10.4+)).

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

~~10.7+~~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+*
10.8+*
-
-
~~Subscription Agreement dated February 17, 2000 between WEDGE Energy Services, L.L.C. and Pioneer Drilling Company (Form 10-K for the year ended March 31, 2001 (File No. 1-8182, Exhibit 10.8)).~~
10.9*
-
~~Common Stock Purchase Agreement dated May 11, 2000 between WEDGE Energy Services, L.L.C. and Pioneer Drilling Company(Form 10-K for the year ended March 31, 2001 (File No. 1-8182, Exhibit 10.9)).~~
10.10*
-
~~Common Stock Purchase Agreement dated May 18, 2001 between Pioneer Drilling Company and WEDGE Energy Services, L.L.C. (Form 10-K for the year ended March 31, 2001 (File No. 1-8182, Exhibit 10.10)).~~

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

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

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

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

21.1	-	-	Subsidiaries of Pioneer Drilling Company.

23.1	-	-	Consent of KPMG LLP.

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

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

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

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

*
* Incorporated by reference to the filing indicated.
+ Management contract or compensatory plan or arrangement.

+ ~~Management contract or compensatory plan or arrangement.~~

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

SIGNATURES

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


		PIONEER DRILLING COMPANY

~~June 28, 2004~~ May 25, 2006	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	~~Title~~		Date

/s/ Michael E. Little
Michael E. Little	Chairman	~~Chairman~~		~~June 28, 2004~~ May 25, 2006

/s/ Wm. Stacy Locke
Wm. Stacy Locke		President, Chief Executive Officer and Director ~~(Principal~~ (Principal Executive Officer)		~~June 28, 2004~~ May 25, 2006

/s/ William D. Hibbetts
William D. Hibbetts		Senior Vice President, Chief Financial Officer and Secretary (Principal Financial ~~and~~Officer)		May 25, 2006

/s/ Kurt M. Forkheim
Kurt M. Forkheim	Vice President, Chief Accounting Officer (Principal Accounting Officer)		~~June 28, 2004~~ May 25, 2006

/s/ C. John Thompson
C. John Thompson	Director	~~Director~~		~~June 28, 2004~~ May 25, 2006


/s/ James M. Tidwell
James M. Tidwell	Director	~~Director~~		~~June 28, 2004~~ May 25, 2006


/s/ C. Robert Bunch
C. Robert Bunch	Director	~~Director~~		~~June 28, 2004~~ May 25, 2006


/s/ Dean A. Burkhardt
Dean A. Burkhardt	Director	~~Director~~		~~June 28, 2004~~ May 25, 2006


/s/ Michael F. Harness
Michael F. Harness	Director	~~Director~~		~~June 28, 2004~~ May 25, 2006

Index To Exhibits

2.1*	-
2.1*		-	Asset Purchase Agreement dated ~~February 14, 2001~~November 11, 2004 between ~~Mustang~~Wolverine Drilling, ~~Ltd., Michael T. Wilhite, Sr., Andrew D. Mills~~Inc. and ~~Michael T. Wilhite, Jr. (Form 10-K for the year ended March 31, 2001 (File No. 1-8182, Exhibit 2.2)).~~

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

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

2.4*	-	~~Asset Purchase Agreement dated the 28th of May, 2002 by and between United Drilling Company, U-D Holdings, L.P.~~Robert Mau, Robert S. Blackford and Pioneer Drilling Services, Ltd.~~, a Texas limited partnership.~~ (Form ~~10-K for the year ended March 31, 2002~~8-K dated November 11, 2004 (File No. 1-8182, Exhibit ~~2.5)~~2.1)) .

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

4.18* 4.2*		~~Form of Purchase~~-	Credit Agreement ~~dated February 13, 2004~~ between Pioneer Drilling ~~Company~~Services, Ltd. and ~~the several purchasers~~Frost National Bank, as Administrative Agent, Agent, Lead Arranger and Lender dated October 29, 2004 (Form ~~S-3 filed February 24,~~8-K dated October 29, 2004 ~~(Reg. No. 333-113036, Exhibit 4.1)).~~

10.1*	-	Voting Agreement dated June 18, 1997 between Robert R. Marmor, William D. Hibbetts, Wm. Stacy Locke, Alvis L. Dowell, Charles B Tichenor and Richard Phillips (Form 10-K for the year ended March 31, 2001 (File No. 1-8182, Exhibit ~~9.1)~~4.1)).

10.2* 4.3*	-	~~Voting Agreement~~-	Second Amendment, dated May 11, ~~2000~~2005, to Credit Agreement between ~~Wm. Stacy Locke, Michael E. Little,~~ Pioneer Drilling ~~Company~~Services, Ltd. And Frost National Bank, as Administrative Agent, Lead Arranger and ~~WEDGE Energy Services, L.L.C.~~Lender dated October 29, 2004 (Form ~~10-K for the year ended March 31, 2001~~8-K dated May 12, 2005 (File No. 1-8182, Exhibit ~~9.2)~~4.1)).

10.3* 4.4*	-	~~Voting Agreement~~-	Third Amendment, dated October ~~9, 2001~~25, 2005, to Credit Agreement between Pioneer Drilling ~~Company~~Services, Ltd. And Frost National Bank, as Administrative Agent, Lead Arranger and ~~WEDGE Energy Service, L.L.C. (See Section 1.3 of the Debenture Purchase~~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 ~~referenced above~~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 ~~4.5)~~4.1)).

10.1+*		-	Pioneer Drilling Services, Ltd. Annual Incentive Compensation Plan dated August 5, 2005 (Form ~~10-K for year ended March 31, 2003~~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)).

~~10.4+~~10.3+*	-	~~Executive Employment Agreement dated May 1, 1995 between Pioneer Drilling Company and Wm. Stacy Locke (Form 10-K for the year ended March 31, 2001 (File No. 1-8182, Exhibit 10.1+)).~~
-
10.5+*	-	Second Amendment to Executive Employment Agreement dated August 21, 2000 between Pioneer Drilling Company and Wm. Stacy Locke (Form 10-K for the year ended March 31, 2001 (File No. 1-8182, Exhibit 10.4+)).

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

~~10.7+~~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+)).

~~10.8+~~10.5+*	-	~~Subscription Agreement dated February 17, 2000 between WEDGE Energy Services, L.L.C. and Pioneer Drilling Company (Form 10-K for the year ended March 31, 2001 (File No. 1-8182, Exhibit 10.8)).~~
-
10.9*	-	~~Common Stock Purchase Agreement dated May 11, 2000 between WEDGE Energy Services, L.L.C. and Pioneer Drilling Company(Form 10-K for the year ended March 31, 2001 (File No. 1-8182, Exhibit 10.9)).~~

10.10*	-	~~Common Stock Purchase Agreement dated May 18, 2001 between Pioneer Drilling Company and WEDGE Energy Services, L.L.C. (Form 10-K for the year ended March 31, 2001 (File No. 1-8182, Exhibit 10.10)).~~


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

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

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

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

21.1
~~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.

* ~~Incorporated by reference to the filing indicated.~~56

+ ~~Management contract or compensatory plan or arrangement.~~

Shareholder	Shares	Percentage

WEDGE (1)	13,508,864	40.2	%

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

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

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

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

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


	Low		High
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

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

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


	Years Ended March 31,
	2006		2005		2004		2003		2002		2001
Oil (West Texas Intermediate)	$	59.94	$	45.04	$	31.47	$	29.27	$	24.31	$	30.40
Natural Gas (Henry Hub)	$	9.10	$	5.99	$	5.27	$	4.24	$	2.96	$	5.27
U.S. Land Rig Count		1,329		1,110		964		723		912		841

PART I

ItemsItem 1 and 2.. Business and Properties**

***Item 4.4*. Submission of Matters to a Vote of Security Holders**

PART II

***Item 5.5*. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities**

***Item 6.6*. Selected Financial Data**

***Item 7.7*. Management’s Discussion and Analysis of Financial Condition and Results of Operations**

***Item 9.9*. Changes in and Disagreements With Accountants on Accounting and Financial Disclosure**

***Item 10.10*. Directors and Executive Officers of the Registrant**

***Item 11.11*. Executive Compensation**

***Item 12.12*. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters**

***Item 13.13*. Certain Relationships and Related Transactions**

***Item 14.14*. Principal Accountant Fees and Services**


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)	Number of securities to be issued upon exercise of outstanding options, warrants and rights *(a)*	Weighted-average exercise price per share of outstanding options, warrants and rights *(b)*		Number of securities remaining available for future issuance under equity compensation plans (excluding securities reflected in column (a)) *(c)*
Equity compensation plans approved by security holders	2,056,666	$	3.24	2,406,413	1,592,833	$	7.71	1,618,500

Equity compensation plans not approved by security holders	—	—		—	—		—	—

Total	2,056,666	$	3.24	2,406,413	1,592,833	$	7.71	1,618,500


	Years Ended March 31,													Years Ended March 31,
	2004			2003			2002		2001		2000			2006		2005		2004			2003			2002
	(In thousands, except per share amounts)													(In thousands, except per share amounts)
Contract drilling revenues	$	107,876		$	80,183		$	68,627	$	50,345	$	19,391		$	284,148	$	185,246	$	107,876		$	80,183		$	68,627
Income (loss) from operations	438			(4,943		)	11,201		3,803		108				77,909		18,774		438			(4,943	)		11,201
Income (loss) before income taxes	(2,216		)	(7,305		)	9,737		3,838		(65		)		79,813		17,161		(2,216	)		(7,305	)		9,737
Preferred dividends	—			—			93		275		304				—		—		—			—			93
Net earnings (loss) applicable to common stockholders	(1,790		)	(5,086		)	6,225		2,428		(384		)		50,567		10,812		(1,790	)		(5,086	)		6,225
Earnings (loss) per common share-basic	(0.08		)	(0.31		)	0.41		0.22		(0.06		)		1.08		0.31		(0.08	)		(0.31	)		0.41
Earnings (loss) per common share-diluted	(0.08		)	(0.31		)	0.35		0.19		(0.06		)		1.06		0.30		(0.08	)		(0.31	)		0.35
Long-term debt and capital lease obligations, excluding current installments	44,892			45,855			26,119		10,056		267				—		13,445		44,892			45,855			26,119
Shareholders’ equity	70,836			47,672			33,343		17,827		6,783				340,676		221,615		70,836			47,672			33,343
Total assets	143,731			119,694			83,450		56,493		15,670				400,678		276,009		143,731			119,694			83,450
Capital expenditures	44,845			33,589			27,597		41,628		5,069				128,871		80,388		44,845			33,589			27,597


Description	Date	Number of Shares	Price Per Share
Conversion of $28,000,000 6.75% convertible subordinated debentures to common stock	August 11, 2004	6,496,519	$	4.31
Public offering of common stock (1)	August 11, 2004	4,000,000	$	6.61
Public offering of common stock - over allotment option (1)	August 31, 2004	600,000	$	6.61
Public offering of common stock (1)	March 22, 2005	6,945,000	$	11.78
Public offering of common stock (1)	February 10, 2006	3,000,000	$	20.63

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


	March 31,				Change
	2006		2005		Change
Cash and cash equivalents	$	91,173,764	$	69,673,279	$	21,500,485
Marketable securities		—		1,000,000		(1,000,000	)
Receivables		35,544,543		26,108,291		9,436,252
Contract drilling		9,620,179		5,364,529		4,255,650
Deferred tax receivable		989,895		569,548		420,347
Prepaid expenses		2,207,853		1,876,843		331,010

Current assets		139,536,234		104,592,490		34,943,744

Current debt		—		5,415,001		(5,415,001	)
Accounts payable		16,040,568		15,621,647		418,921
Accrued payroll		3,383,435		2,706,623		676,812
Income tax payable		6,834,877		195,949		6,638,928
Prepaid drilling contracts		139,769		172,750		(32,981	)
Accrued expenses		6,233,479		4,153,851		2,079,628

		32,632,128		28,265,821		4,366,307

Working capital	$	106,904,106	$	76,326,669	$	30,577,437

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

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

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

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

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

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


	Payments Due by Period
Contractual Obligations	Total		Less than 1 year		1-3 years		4-5 years		More than 5 years
Operating Lease Obligations	$	1,726,264	$	243,104	$	447,003	$	429,151	$	607,006

Total	$	1,726,264	$	243,104	$	447,003	$	429,151	$	607,006


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

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

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


10.5+*
10.8+* -	-	~~Subscription Agreement dated February 17, 2000 between WEDGE Energy Services, L.L.C. and Pioneer Drilling Company (Form 10-K for the year ended March 31, 2001 (File No. 1-8182, Exhibit 10.8)).~~

10.9*	-	~~Common Stock Purchase Agreement dated May 11, 2000 between WEDGE Energy Services, L.L.C. and Pioneer Drilling Company(Form 10-K for the year ended March 31, 2001 (File No. 1-8182, Exhibit 10.9)).~~

10.10*	-	~~Common Stock Purchase Agreement dated May 18, 2001 between Pioneer Drilling Company and WEDGE Energy Services, L.L.C. (Form 10-K for the year ended March 31, 2001 (File No. 1-8182, Exhibit 10.10)).~~


21.1
~~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).

PART I

ItemsItem 1 and 2.. Business and Properties

Item 4.4. Submission of Matters to a Vote of Security Holders

PART II

Item 5.5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities

Item 6.6. Selected Financial Data

Item 7.7. Management’s Discussion and Analysis of Financial Condition and Results of Operations

Item 9.9. Changes in and Disagreements With Accountants on Accounting and Financial Disclosure

Item 10.10. Directors and Executive Officers of the Registrant

Item 11.11. Executive Compensation

Item 12.12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters

Item 13.13. Certain Relationships and Related Transactions

Item 14.14. Principal Accountant Fees and Services

ItemsItem 1 and 2.. Business and Properties**

***Item 4.4*. Submission of Matters to a Vote of Security Holders**

***Item 5.5*. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities**

***Item 6.6*. Selected Financial Data**

***Item 7.7*. Management’s Discussion and Analysis of Financial Condition and Results of Operations**

***Item 9.9*. Changes in and Disagreements With Accountants on Accounting and Financial Disclosure**

***Item 10.10*. Directors and Executive Officers of the Registrant**

***Item 11.11*. Executive Compensation**

***Item 12.12*. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters**

***Item 13.13*. Certain Relationships and Related Transactions**

***Item 14.14*. Principal Accountant Fees and Services**