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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D. C.  20549


FORM 10-K/A10-K

(Mark one)


ýx


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


For the fiscal year ended March 31, 20032005


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)

74-2088619

(I.R.S. Employer
Identification Number)


9310 Broadway, Bldg. I
San Antonio, Texas

78217

(Address of principal executive offices)



78217

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

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant'sregistrant’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.  oý

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

 

The aggregate market value of the registrant'sregistrant’s voting and nonvoting common equity held by non-affiliates of the registrant as of the last business day of the registrant'sregistrant’s most recently completed second fiscal quarter for the fiscal year covered by this report (September 30, 2002)2004) was $16,645,254,$189,796,564, based on the last sales price of the registrant'sregistrant’s common stock reported on the American Stock Exchange on that date.

 

As of March 31, 2004,May 20, 2005, there were 27,300,12645,931,646 shares of common stock, par value $0.10 per share, of the registrant issued and outstanding.

DOCUMENTS INCORPORATED BY REFERENCE

 

Portions of the proxy statement related to the registrant's 2003registrant’s 2005 Annual Meeting of Shareholders are incorporated by reference into Part III of this report.






TABLE OF CONTENTS



PART I


Items 1 and 2.



Business and Properties

Item 3.

Legal Proceedings

Item 4.

Submission of Matters to a Vote of Security Holders


PART II


PART II

Item 5.



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

Item 6.

Selected Financial Data

Item 7.

Management'sManagement’s Discussion and Analysis of Financial Condition and Results of Operations

Item 7A.

Quantitative and Qualitative Disclosures About Market Risk

Item 8.

Financial Statements and Supplementary Data

Item 9.

ChangeChanges in and Disagreements withWith Accountants on Accounting and Financial Disclosure


Item 9A.

PART IIIControls and Procedures


PART III

Item 10.



Directors and Executive Officers of the Registrant

Item 11.

Executive Compensation

Item 12.

Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters

Item 13.

Certain Relationships and Related Transactions

Item 14.

Principal Accountant Fees and Services

Controls and Procedures


PART IV


PART IV

Item 15.



Exhibits and Financial Statement Schedules and Reports on Form 8-K




PART I

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


Items 1 and 2.Business and Properties

General

 

Pioneer Drilling Company provides contract land drilling services to independent and major oil and gas exploration and production companies.  In addition to our drilling rigs, we provide the drilling crews and most of the ancillary equipment needed to operate our drilling rigs. We have focused our operations in theselect oil and natural gas production regions of South Texas and East 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."“PDC.”

 Over the past four fiscal years,

Since September 1999, we have significantly expanded our fleet of drilling rigs through acquisitions and the construction of new rigs and refurbished rigs.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)

Market

Number of
Rigs
Acquired

September 1999

Howell Drilling, Inc.

South Texas

2

August 2000

Pioneer Drilling Co.

South Texas

4

March 2001

Mustang Drilling, Ltd.

East Texas

4

May 2002

United Drilling Company

South Texas

2

August 2003

Texas Interstate Drilling Company, L. P.

North Texas

2

March 2004

Sawyer Drilling & Service, Inc.

East Texas

7

March 2004

SEDCO Drilling Co., Ltd.

North Texas

1

November 2004

Wolverine Drilling, Inc.

Rocky Mountains

7

December 2004

Allen Drilling Company

Western Oklahoma

5

Date

 Acquisition
 Market
 Number of Rigs
Acquired

 

September 1999

 

Howell Drilling, Inc.—Assets

 

South Texas

 

2

 

August 2000

 

Pioneer Drilling Co.—Stock

 

South Texas

 

4

(1)

March 2001

 

Mustang Drilling, Ltd.—Assets

 

East Texas

 

4

 

May 2002

 

United Drilling Company—Assets

 

South Texas

 

2

 


(1)

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

During that same period, we also added nine rigs to our fleet through construction of new rigs and construction of rigs from new and used components.  In addition, in August 2003, we acquired a rig under a lease agreement.

that had been operating in Trinidad and integrated it into our operations in Texas.  As of May 16, 2003,20, 2005, our rig fleet consistsconsisted of 2550 operating drilling rigs, 15 of which arewere operating in South Texas, and ten17 of which arewere operating in East Texas. During our fiscal year ended March 31, 2002, we addedTexas, four rigs, including two newly constructed rigsof which were operating in North Texas, five of which were operating in western Oklahoma and two refurbished rigs, increasing us to a totalnine of 20 rigs at March 31, 2002. During our fiscal year ended March 31, 2003, we addedwhich were operating in the Rocky Mountain region.  We are also constructing two additional refurbished rigs, and the two rigs acquired from United Drilling Company, increasing uswhich we expect to a total of 24 rigs at March 31, 2003. In May 2003, we took delivery of another refurbished rig. We own all the rigs inadd to our fleet except for one rig that we operate under a lease agreement expiring in February��2004. The lease agreement includes an option to acquire this rig.June and August of 2005.

 

We conduct our operations primarily in South, East and North Texas, western Oklahoma and East Texas. We believe that these markets have historically experienced greater utilization rates and dayrates versus other domestic markets, due in large part to the heavy concentration of natural gas reserves located in these markets.Rocky Mountains.  During fiscal 2003,2005, substantially all the wells we drilled for our customers were drilled in search of natural gas.  Although we have recently diversified our operations somewhat with the acquisition of drilling rigs from Wolverine Drilling, with five of those rigs employed in search of oil in the Williston Basin of the Rocky Mountains, our customers remain primarily focused on drilling for natural gas.  Natural gas reserves are typically found in deeperdeep geological formations and generally require premium equipment and quality crews to drill the wells.



 Our business strategy is to own and operate a high quality fleet of land drilling rigs in active drilling markets and position ourselves as the contractor of choice for our customers in order to maximize rig utilization and dayrates and enhance shareholder value. We intend to continue making additions to our drilling fleet, either through acquisitions of businesses or selected assets or through the construction of new or refurbished drilling rigs. As we add to our fleet, we intend to focus on the addition of rigs capable of performing deep drilling for natural gas.

For many years, the United States contract land drilling services industry has been characterized by an oversupply of drilling rigs and a large number of drilling contractors.  However, sinceSince 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

1



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“Management’s Discussion and Analysis of Financial Condition and Results of Operations—Operations – Market Conditions in Our Industry"Industry” in Item 7 of Part II of this report.

Our Strategy

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

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

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

positioning ourselves to maximize rig utilization and dayrates;

training and maintaining high-quality, experienced crews; and

maintaining the recent improvements in our safety record.

Drilling Equipment

General

 

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 gear,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'srig’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 triangle,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 foot30-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,

2



the pumps and the mud mixingmud-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 so-called reserve pits, usually one or two fairly shallow excavations, are used for waste material and excess water around the location.

 

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

Our Fleet of Drilling Rigs

As of May 16, 2003,26, 2005, our rig fleet consists of 2550 drilling rigs.  We own all the rigs in our fleet except for one that we operate under a lease/purchase agreement expiring in February 2004.

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

 
 Years ended March 31,
 
 
 2003
 2002
 2001
 2000
 1999
 1998
 
Average number of rigs for the period 22.3 18.0 10.5 6.6 6.0 6.0 
Average utilization rate 79%82%91%66%66%86%

 

 

 

Years Ended March 31,

 

 

 

2005

 

2004

 

2003

 

2002

 

2001

 

2000

 

Average number of rigs for the period

 

40.1

 

27.3

 

22.3

 

18.0

 

10.5

 

6.6

 

Average utilization rate

 

96

%

88

%

79

%

82

%

91

%

66

%

The following table sets forth information regarding our drilling fleet:

Rig
Number

 Rig Design
 Approximate
Drilling Depth
Capability (feet)

 Current
Location

 Type
 Horse Power
1 IRI Cabot 750E 11,500 South Texas Electric 700
2 IRI Cabot 750E 11,500 South Texas Electric 700
3 National 110-UE 18,000 South Texas Electric 1500
4(1)RMI 1000E 15,000 South Texas Electric 1000
5 RMI 1000 15,000 South Texas Mechanical 1000
6 Brewster N4610 12,000 East Texas Mechanical 900
7 IRI 1700E 18,000 South Texas Electric 1700
8 IRI 1700E 18,000 South Texas Electric 1700
9 Gardner-Denver 500M 10,000 East Texas Mechanical 750
10 Skytop Brewster N46 12,000 East Texas Mechanical 950
11 Skytop Brewster N46 12,000 South Texas Mechanical 950
12 IRI Cabot 900 10,500 South Texas Mechanical 900
14 Skytop Brewster N46 12,000 South Texas Mechanical 950
15 IRI Cabot 750 11,000 South Texas Mechanical 700
16 IRI Cabot 750 11,000 South Texas Mechanical 700
17 Ideco H-725 12,000 East Texas Mechanical 750
18 Brewster N-75 12,500 East Texas Mechanical 1000
19 Brewster N-75 12,500 East Texas Mechanical 1000
20 BDW 800 13,500 East Texas Mechanical 1000
21 National 110-UE 18,000 South Texas Electric 1500
22 Ideco H-725 12,000 East Texas Mechanical 750
23 Ideco H-725 12,000 East 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 840E 18,000 South Texas Electric 1500
27(2)IRI Cabot 1200 15,000 South Texas Mechanical 1200

Rig
Number

 

Rig Design

 

Approximate
Drilling Depth
Capability
(feet)

 

Current Location

 

Type

 

Horsepower

 

 

 

 

 

 

 

 

 

 

 

 

 

1

 

Cabot 750E

 

9,500

 

South Texas

 

Electric

 

750

 

2

 

Cabot 750E

 

9,500

 

South Texas

 

Electric

 

750

 

3

 

National 110 UE

 

18,000

 

South Texas

 

Electric

 

1,500

 

4

 

RMI 1000 E

 

15,000

 

South Texas

 

Electric

 

1,000

 

5

 

Brewster N-46

 

12,000

 

North Texas

 

Mechanical

 

1,000

 

6

 

Brewster DH-4610

 

13,000

 

East Texas

 

Mechanical

 

750

 

7

 

National 110 UE

 

18,000

 

South Texas

 

Electric

 

1,500

 

8

 

National 110 UE

 

18,000

 

East Texas

 

Electric

 

1,500

 

9

 

Gardner-denver 500

 

11,000

 

East Texas

 

Mechanical

 

700

 

10

 

Brewster N-46

 

12,000

 

East Texas

 

Mechanical

 

1,000

 

11

 

Brewster N-46

 

12,000

 

South Texas

 

Mechanical

 

1,000

 

12

 

IRI Cabot 900

 

10,500

 

South Texas

 

Mechanical

 

900

 

14

 

Brewster N-46

 

12,000

 

South Texas

 

Mechanical

 

1,000

 

15

 

Cabot 750

 

9,500

 

South Texas

 

Mechanical

 

750

 

16

 

Cabot 750

 

9,500

 

South Texas

 

Mechanical

 

750

 

17

 

Ideco 725

 

12,000

 

East Texas

 

Mechanical

 

800

 

18

 

Brewster N-75

 

12,000

 

East Texas

 

Mechanical

 

1,000

 

19

 

Brewster N-75

 

12,000

 

East Texas

 

Mechanical

 

1,000

 

20

 

BDW 800

 

13,500

 

East Texas

 

Mechanical

 

1,000

 

21

 

National 110 UE

 

18,000

 

South Texas

 

Electric

 

1,500

 

22

 

Ideco 725

 

12,000

 

East Texas

 

Mechanical

 

800

 

23

 

Ideco 725

 

12,000

 

North Texas

 

Mechanical

 

800

 

24

 

National 110 UE

 

18,000

 

South Texas

 

Electric

 

1,500

 

25

 

National 110 UE

 

18,000

 

East Texas

 

Electric

 

1,500

 

26

 

Oilwell 840 E

 

18,000

 

South Texas

 

Electric

 

1,500

 

27

 

IRI Cabot 1200 M

 

13,500

 

South Texas

 

Mechanical

 

1,300

 

28

 

Oilwell 760 E

 

15,000

 

South Texas

 

Electric

 

1,000

 

29

 

Brewster N-46

 

12,000

 

North Texas

 

Mechanical

 

1,000

 

30

 

Mid Cont U36A

 

11,000

 

North Texas

 

Mechanical

 

750

 

3


(1)
We are leasing this rig under a lease agreement which expires in February 2004 and has an option to purchase the rig between January 1, 2004 and February 1, 2004.


(2)
Expected delivery date

Rig
Number

 

Rig Design

 

Approximate
Drilling Depth
Capability
(feet)

 

Current Location

 

Type

 

Horsepower

 

 

 

 

 

 

 

 

 

 

 

 

 

31

 

Brewster N-7

 

11,500

 

East Texas

 

Mechanical

 

750

 

32

 

Brewster N-75

 

13,500

 

East Texas

 

Mechanical

 

1,000

 

33

 

Brewster N-95

 

13,500

 

East Texas

 

Mechanical

 

1,200

 

34

 

All-Rig 900

 

12,000

 

East Texas

 

Mechanical

 

900

 

35

 

RMI 1000

 

13,500

 

East Texas

 

Mechanical

 

1,000

 

36

 

Brewster N-7

 

11,500

 

East Texas

 

Mechanical

 

750

 

37

 

Brewster N-95

 

13,500

 

East Texas

 

Mechanical

 

1,200

 

38

 

Ideco H-1000 E

 

11,000

 

Utah

 

Electric

 

1,000

 

39

 

National 370

 

7,500

 

North Dakota

 

Mechanical

 

550

 

40

 

National 370

 

8,500

 

North Dakota

 

Mechanical

 

550

 

41

 

National 610

 

11,000

 

Utah

 

Mechanical

 

750

 

42

 

Brewster N-46

 

12,500

 

North Dakota

 

Mechanical

 

1,000

 

43

 

National 610

 

11,000

 

North Dakota

 

Mechanical

 

750

 

44

 

National 80B

 

15,000

 

North Dakota

 

Mechanical

 

1,000

 

45

 

Brewster N-4

 

7,500

 

North Dakota

 

Mechanical

 

500

 

46

 

RMI 550

 

9,000

 

Oklahoma

 

Mechanical

 

550

 

47

 

Ideco 525

 

8,000

 

Oklahoma

 

Mechanical

 

600

 

48

 

National 370

 

8,500

 

Oklahoma

 

Mechanical

 

550

 

49

 

Ideco 525

 

9,000

 

Oklahoma

 

Mechanical

 

600

 

50

 

Ideco 725

 

11,000

 

Oklahoma

 

Mechanical

 

800

 

54

 

RMI 1000

 

14,000

 

Utah

 

Mechanical

 

1,000

 

As of July or August 2003.


        We also ownMay 20, 2005, we owned a fleet of 1658 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 wereare 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 ana 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.  ContractThe 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 aan agreed fee.

4



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

 

 

Year Ended March 31,

 

 

 

2005

 

2004

 

2003

 

Daywork

 

264

 

205

 

119

 

Turnkey

 

134

 

92

 

78

 

Footage

 

48

 

13

 

5

 

Total number of wells

 

446

 

310

 

202

 

Daywork Contracts.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 of drilling and we generally bear no part of the usual risks associated with drilling, such as time delays and unanticipated costs.

Turnkey Contracts.Under a turnkey contract, we agree to drill a well for our customer to a specified depth and under specified conditions for a fixed price, regardless of the time required or the problems encountered in drilling the well.  We provide technical expertise and engineering services, as well as most of the equipment and drilling supplies required to drill the well.  We often subcontract for related services, such as the provision of casing crews, cementing and well logging.  Under typical turnkey drilling arrangements, we do not receive progress payments and are 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,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'subcontractors’ services, supplies, cost escalations and personnel.  We employ or contract for engineering expertise to analyze seismic, geologic and drilling data to identify and reduce some of the drilling risks assumed by us.we 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 partythird-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.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 withto 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'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.

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Customers and Marketing

 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.

 
 2003
 2002
 2001
Daywork 119 150 54
Turnkey 78 9 42
Footage 5 6 4
  
 
 
Total number of wells 202 165 100
  
 
 

Customers And Marketing

We market our rigs to a number of customers.  In fiscal 2003,2005, we drilled wells for 64102 different customers, compared to 4883 customers in fiscal 20022004 and to 5864 customers in fiscal 2001. Thirty-six of our customers in fiscal 2003 were customers for whom we had not drilled any wells in fiscal 2002.2003.  The following table shows our three largest customers as a percentage of our total contract drilling revenue for each of our last three fiscal years.

Customer

Customer


Total
Contract
Drilling
Revenue
Percentage


Fiscal 2003:

Fiscal 2005

Chinn Exploration

7

%

Goodrich Petroleum Corp.

5

%

Medicine Bow Energy Corporation

5

%

Fiscal 2004

Chinn Exploration

11

%

Dale Operating Company

6

%

Medicine Bow Energy Corporation

5

%

Fiscal 2003

Gulf Coast Energy Associates

10.8

11

%

Apache Corporation

6.5

7

%

Suemaur Exploration & Production, LLCL.L.C.

5.4

5

%


Fiscal 2002:



Dominion Exploration & Production, Inc.13.7%
Kerr-McGee Oil & Gas Onshore, L.L.C.12.2%
Pogo Producing Company11.1%

Fiscal 2001:



Dominion Exploration & Production, Inc.13.6%
Conoco, Inc.8.8%
Pure Resources, Inc.6.3%

 

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

 

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

Competition

 

We encounter substantial competition from other drilling contractors. Our primary market areas of South Texas and East Texas are highly fragmented and competitive.  The fact that drilling rigs are



mobile and can be moved from one market to another in response to market conditions heightens the competition in the industry.

 

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

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

    the mobility and efficiency of the rigs;

    the quality of service and experience of the rig crews;

    the safety records of the rigs;

    the offering of ancillary services; and

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

 

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

 

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

 

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

    better withstand industry downturns;

    compete more effectively on the basis of price and technology;

    better retain skilled rig personnel; and

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

Raw Materials

 

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



Operating Risks and Insurance

 

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

    blowouts;

    fires and explosions;

    loss of well control;

    collapse of the borehole;

    lost or stuck drill strings; and

    damage or loss from natural disasters.

 

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

    suspension of drilling operations;

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

    personal injury and loss of life;

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

    environmental damage.

 

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

7



and adversely affect our results of operations and financial condition.  Furthermore, we may not be able to maintain adequate insurance in the future at rates we consider reasonable.

 

Our current insurance coverage includes property insurance on our rigs, drilling equipment and real property.  Our insurance coverage for property damage to our rigs and to our drilling equipment is based on our estimate, as of October 2002,2005, of the cost of comparable used equipment to replace the insured property.  The policy provides for a deductible on rigs of $50,000 or $100,000 (depending on the rig) per occurrence.  Our third-party liability insurance coverage is $26 million per occurrence and in the aggregate, with a deductible of $110,000$260,000 per occurrence.  We believe that we are adequately insured for public liability and property damage to others with respect to our operations.  However, such insurance may not be sufficient to protect us against liability for all consequences of well disasters, extensive fire damage or damage to the environment.

 

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



Employees

 

We currently have approximately 5651,370 employees.  Approximately 85186 of these employees are salaried administrative or supervisory employees.  The rest of our employees are hourly employees who operate or maintain our drilling rigs.rigs and rig-hauling trucks.  The number of hourly employees fluctuates depending on the number of drilling projects we are engaged in at any particular time.  None of our employment arrangements are subject to collective bargaining arrangements.

 

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

8



Facilities

 

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

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

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

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

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

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

We lease:

a 43-acre division office and storage yard in Decatur, Texas, at a cost of $3,700$800 per month, pursuant to a lease extending through September 2006;

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

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

a yard office in Kenmare, North Dakota, at a cost of $700 per month, pursuant to a lease extending through March 2006.31, 2006; and

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

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

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

Governmental Regulation

 

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

 

Environmental laws and regulations are complex and subject to frequent change.  In some cases, they can impose liability for the entire cost of cleanup on any responsible party without regard to negligence or fault and can impose liability on us for the conduct of others or conditions others have caused, or for our acts that complied with all applicable requirements when we performed them.  We may also be exposed to environmental or other liabilities originating from businesses and assets whichthat we purchased from others.  Compliance with applicable environmental laws and regulations has not, to date, materially affected our capital expenditures, earnings or competitive position, although compliance measures have added to our costs of operating drilling equipment in some instances.  We do not expect



to incur material capital expenditures in our next fiscal year in order to comply with current environment control regulations.  However, our compliance with amended, new or more stringent requirements, stricter interpretations of existing requirements or the future discovery of contamination may require us to make material expenditures or subject us to liabilities that we currently do not anticipate.

 

9



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

Available Information

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


CAUTIONARY STATEMENT CONCERNING FORWARD-LOOKING STATEMENTS
AND RISK FACTORS

 

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

 

From time to time, our management or persons acting on our behalf make forward-looking statements to inform existing and potential security holders about our company.  These statements may include projections and estimates concerning the timing and success of specific projects and our future backlog, revenues, income and capital spending.  Forward-looking statements are generally accompanied by words such as "estimate," "project," "predict," "believe," "expect," "anticipate," "plan," "goal"“estimate,” “project,” “predict,” “believe,” “expect,” “anticipate,” “plan,” “intend,” “seek,” “will,” “should,” “goal” or other words that convey the uncertainty of future events or outcomes. These forward-looking statements speak only as of the date on which they are first made, which in the case of forward-looking statements made in this report is the date of this report.   Sometimes we will specifically describe a statement as being a forward-looking statement and refer to this cautionary statement.

 

In addition, various statements that this Annual Report on Form 10-K contains, including those that express a belief, expectation or intention, as well as those that are not statements of historical fact, are forward-looking statements.  Those forward-looking statements appear in Items 1 and 2—"Business2 – “Business and Properties"Properties” and Item 3—"Legal Proceedings"3 – “Legal Proceedings” in Part I of this report and in Item 7—"Management's5 – “Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities,” and in Item 7 – “Management’s Discussion and Analysis of Financial Condition and Results of Operations," Item 7A—"Quantitative7A – “Quantitative and Qualitative Disclosures About Market Risk"Risk” and in the Notes to Consolidated Financial Statements we have included in Item 8 of Part II of this report and elsewhere in this report.  These forward-looking statements speak only as of the date of this report.  We disclaim any obligation to update these statements, and we caution you not to rely on them unduly.  We have based these forward-looking statements on our current expectations and assumptions about future events.  While our management considers these expectations and assumptions to be reasonable, they are inherently subject to significant business, economic, competitive, regulatory and other risks, contingencies and uncertainties, most of which are difficult to predict and many of which are beyond our control.  These risks, contingencies and uncertainties relate to, among other matters, the following:

    general economic and business conditions and industry trends;

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

      levels and volatility of oil and gas prices;

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

      the highly competitive nature of our businesses;

      business;

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

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

      the continued availability of qualified personnel; and

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

     

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

    10



    accuracy of our forward-looking statements and (2) use caution and common sense when considering our forward-looking statements.  Also, please read the risk factors set forth below.


    Item 3. Legal Proceedings

            On May 17, 2002, Deborah SuttonRisks Relating to the Oil and other working interest owners in a well that we drilled in May 2000 filed an amended petition naming us as a defendantGas Industry

    We derive all our revenues from companies in the 37th Judicial District Courtoil and gas exploration and production industry, a historically cyclical industry with levels of activity that are significantly affected by the levels and volatility of oil and gas prices.

    As a provider of contract land drilling services, our business depends on the level of drilling activity by oil and gas exploration and production companies operating in Bexar County, Texas, Cause No. 2001-CI-06701. Other defendants included: the operator, Sutton Producing Corp.;geographic markets where we operate. The oil and gas exploration and production industry is a historically cyclical industry characterized by significant changes in the casing installer, Jens'levels of exploration and development activities.  Oil Field Service, Inc.;and gas prices, and market expectations of potential changes in those prices, significantly affect the sellerlevels of those activities. Worldwide political, economic and military events have contributed to oil and gas price volatility and are likely to continue to do so in the subject casingfuture.  Any prolonged reduction in the overall level of exploration and collars, Exploreco, Ltd.;development activities, whether resulting from changes in oil and gas prices or otherwise, can materially and adversely affect us in many ways by negatively impacting:

    our revenues, cash flows and profitability;

    the fair market value of our rig fleet;

    our ability to maintain or increase our borrowing capacity;

    our ability to obtain additional capital to finance our business and make acquisitions, and the casingcost of that capital; and collar manufacturer, Baoshan Iron & Steel Corp. The operator and the casing installer later filed cross-claims against us, alleging they were entitled

    our ability to contribution or indemnity from usretain skilled rig personnel whom we would need in the event plaintiffs recover against them.of an upturn in the demand for our services.

     Plaintiffs dropped

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

    weather conditions in the United States and elsewhere;

    economic conditions in the United States and elsewhere;

    actions by OPEC, the Organization of Petroleum Exporting Countries;

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

    governmental regulations, both domestic and foreign;

    domestic and foreign tax policy;

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

    the price of foreign imports of oil and gas;

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

    the discovery rate of new oil and gas reserves;

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

    available pipeline and other oil and gas transportation capacity;

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

    the overall supply and demand for oil and gas.

    Risks Relating to Our Business

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

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

    11



    Our acquisition strategy involves various risks.

    As a key component of our business strategy, we have pursued and intend to continue to pursue acquisitions of complementary assets and businesses.    For example, since March 31, 2003, our rig fleet has increased from 24 to 50 drilling rigs, primarily as a result of acquisitions.  Certain risks are inherent in an acquisition strategy, such as increasing leverage and debt service requirements and combining disparate company cultures and facilities, which could adversely affect our operating results.  The success of any completed acquisition will depend in part on our ability to integrate effectively the acquired business into our operations.  The process of integrating an acquired business may involve unforeseen difficulties and may require a disproportionate amount of management attention and financial and other resources.  Possible future acquisitions may be for purchase prices significantly higher than those we paid for recent acquisitions.  We may be unable to continue to identify additional suitable acquisition opportunities, negotiate acceptable terms, obtain financing for acquisitions on satisfactory terms or successfully acquire identified targets.  Our failure to achieve consolidation savings, to incorporate the acquired businesses and assets into our existing operations successfully or to minimize any unforeseen operational difficulties could have a material adverse effect on our financial condition and results of operations.

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

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

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

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

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

    the mobility and efficiency of the rigs;

    the quality of service and experience of the rig crews;

    the safety records of the rigs;

    the offering of ancillary services; and

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

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

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

    We face competition from many competitors with greater resources.

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

    better withstand industry downturns;

    compete more effectively on the basis of price and technology;

    retain skilled rig personnel; and

    12



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

    Unexpected cost overruns on our turnkey drilling jobs and our footage contracts could adversely affect our financial position and our results of operation.

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

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

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

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

    blowouts;

    fires and explosions;

    loss of well control;

    collapse of the borehole;

    lost or stuck drill strings; and

    damage or loss from natural disasters.

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

    suspension of drilling operations;

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

    personal injury and loss of life;

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

    environmental damage.

    We seek to protect ourselves from some but not all operating hazards through insurance coverage. However, some risks are either not insurable or insurance is available only at rates that we consider uneconomical.  Those risks include pollution liability in excess of relatively low limits.  Depending on August 8, 2002.competitive conditions and other factors, we attempt to obtain contractual protection against uninsured operating risks from our customers.  However, customers who provide contractual indemnification protection may not in all cases maintain adequate insurance to support their indemnification obligations.  Our insurance or indemnification arrangements may not adequately protect us against liability or loss from all the hazards of our operations. The operator then abandonedoccurrence of a significant event that we have not fully insured or indemnified against or the failure of a customer to meet its cross claims againstindemnification obligations to us could materially and adversely affect our results of operations and financial condition.  Furthermore, we may be unable to maintain adequate insurance in the future at rates we consider reasonable.

    13



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

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

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

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

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

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

    environmental quality;

    pollution control;

    remediation of contamination;

    preservation of natural resources; and

    worker safety.

    Our operations are subject to stringent laws and regulations relating to containment, disposal and controlling the discharge of hazardous oilfield waste and other nonhazardous waste material into the environment, requiring removal and cleanup under certain circumstances, or otherwise relating to the protection of the environment.  In addition, our operations are often conducted in or near ecologically sensitive areas, such as wetlands, which are subject to special protective measures and which may expose us to additional operating costs and liabilities for accidental discharges of oil, gas, drilling fluids or contaminated water or for noncompliance with other aspects of applicable laws.  We are also subject to the requirements of OSHA and comparable state statutes.  The OSHA hazard communication standard, the Environmental Protection Agency “community right-to-know” regulations under Title III of the Federal Superfund Amendment and Reauthorization Act and comparable state statutes require us to organize and report information about May 19, 2003. Then,the hazardous materials we use in our operations to employees, state and local government authorities and local citizens.

    Environmental laws and regulations are complex and subject to frequent change.  In some cases, they can impose liability for the entire cost of cleanup on any responsible party without regard to negligence or fault and can impose liability on us for the conduct of others or conditions others have caused, or for our acts that complied with all applicable requirements when we performed them.  We may also be exposed to environmental or other liabilities originating from businesses and assets which we purchased from others. Our compliance with amended, new or more stringent requirements, stricter interpretations of existing requirements or the future discovery of contamination may require us to make material expenditures or subject us to liabilities that we currently do not anticipate.

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

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

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

    14



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

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

    Risk Relating to Our Capitalization and Organizational Documents

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

    As of May 20, 2003, the casing crew operator non-suited its affirmative cross claims against us. We remain in the suit only because the casing crew operator joined us2005, our largest shareholder, Chesapeake Energy Corporation, beneficially owned 16.78% of our outstanding common stock, and together with our officers and directors as a responsible third partygroup beneficially owned a total of 20.46% of our outstanding common stock.  For each shareholder or group of shareholders, beneficial ownership includes shares of our common stock issuable on exercise of outstanding stock options held by that shareholder or group of shareholders.  In some circumstances, if these shareholders were to act in an effortconcert, they would be able to reduceexercise substantial control over our affairs.  The interests of Chesapeake and these other persons with respect to matters potentially or actually involving or affecting us, such as future acquisitions, financings and other corporate opportunities and attempts to acquire us, may conflict with the interests of our other shareholders.

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

    Our common stock is traded on the American Stock Exchange.  During the period from January 1, 2005 through May 20, 2005, the average daily trading volume of responsibilityour common stock as reported by the American Stock Exchange was366,154 shares.  There can be no assurance that a more active trading market in our common stock will develop.  As a result, relatively small trades may have a significant impact on the price of our common stock and, therefore, may contribute to the plaintiffs. However,price volatility of our common stock.  As a result, our common stock may be subject to greater price volatility than the stock market as a whole and comparable securities of other contract drilling service providers.

    The market price of our common stock has been, and may continue to be, volatile.  For example, during our 2005 fiscal year, the trading price of our common stock ranged from $5.60 to $14.21 per share.

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

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

    We have not paid or declared any dividends on our common stock and currently intend to retain any earnings to fund our working capital needs and growth opportunities.  Any future dividends will be at the discretion of our board of directors after taking into account various factors it deems relevant, including our financial condition and performance, cash needs, income tax consequences and the restrictions imposed by the Texas Business Corporation Act and other applicable laws and by our credit facilities.  Our debt arrangements include provisions that generally prohibit us from paying dividends on our capital stock, including our common stock.

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

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

    15



    Provisions in our position asorganizational documents could delay or prevent a mere responsible third party, we are not liablechange in control of our company, even if that change would be beneficial to the plaintiffs or the other defendants in this suit.our shareholders.

     We understand

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

    provisions regulating the remaining partiesability of our shareholders to the suit have subsequently reached a compromise and settlement which they will be finalizing in the near future.bring matters for action at annual meetings of our shareholders;

     In addition, due

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

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

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

    Item 3.       Legal Proceedings

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


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

    We did not submit any matter to a vote of our security holders during the fourth quarter of fiscal 2003.


    2005.


    PART II

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

    As of May 16, 2003, 21,710,79220, 2005,45,931,646 shares of our common stock were outstanding, held by approximately 618561 shareholders of record. The number of record holders does not necessarily bear any relationship to the number of beneficial owners of our common stock.

     

    Our common stock began tradingtrades on the American Stock Exchange on March 8, 2001 under the symbol "PDC." Previously, our common stock was traded in the over-the-counter market and quoted in the National Quotation Bureau's "Pink Sheets" for more than 10 years.“PDC.”  The following table sets forth, for each of the periods indicated, the high and low sales prices per share on the American Stock Exchange:

     
     Low
     High
    Fiscal Year Ended March 31, 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

    Fiscal Year Ended March 31, 2002:

     

     

     

     

     
     First Quarter $4.20 6.30
     Second Quarter  3.10 5.35
     Third Quarter  2.90 4.00
     Fourth Quarter  3.10 4.10

     

     

    Low

     

    High

     

    Fiscal Year Ended March 31, 2005:

     

     

     

     

     

    First Quarter

     

    $

    5.60

     

    $

    7.99

     

    Second Quarter

     

    6.75

     

    8.90

     

    Third Quarter

     

    7.63

     

    10.50

     

    Fourth Quarter

     

    9.05

     

    14.21

     

     

     

     

     

     

     

    Fiscal Year Ended March 31, 2004:

     

     

     

     

     

    First Quarter

     

    $

    3.57

     

    $

    5.24

     

    Second Quarter

     

    3.65

     

    4.99

     

    Third Quarter

     

    3.30

     

    5.20

     

    Fourth Quarter

     

    4.75

     

    7.35

     

     

    The last reported sales price for our common stock on the American Stock Exchange on May 16, 200327, 2005 was $4.60$14.00 per share.

     

    We have not paid or declared any dividends on our common stock and currently intend to retain earnings to fund our working capital needs and growth opportunities.  Any future dividends will be at the discretion of our board of directors after taking into account various factors it deems relevant, including our financial condition and performance, cash needs, income tax consequences and the restrictions Texas and other applicable laws and our credit facilities then impose.  Our debt arrangements include provisions that generally prohibit us from paying dividends, other than dividends on our preferred stock.  In October 2000, we paid $160,614 in dividends to the sole holder of our Series AWe currently have no preferred stock. The holder of those shares then converted them into 800,000 shares of our common stock in accordance with the terms of the Series A preferred stock. In May and August of 2001, we paid a total of $859,395 in dividends to the holders of our Series B preferred stock. In August 2001, the holders of those shares converted them into 1,199,038 shares of our common stock in accordance with the terms of the Series B preferred stock.outstanding.

    16



    Equity Compensation Plan Information

     

    The following table provides information on our equity compensation plans as of March 31, 2003:2005:

    Plan category

     Number of securities to
    be issued upon exercise
    of outstanding options,
    warrants and rights

     Weighted-average
    exercise price of
    outstanding options,
    warrants and rights

     Number of securities
    remaining available for
    future issuance under
    equity compensation
    plans (excluding
    securities reflected
    in column (a))

     
     (a)

     (b)

     (c)

    Equity compensation plans approved by security holders 1,825,000 1.63 360,413
    Equity compensation plans not approved by security holders   
      
     
     
    Total 1,825,000 1.63 360,413
      
     
     

    Plan category

     

    Number of securities to be
    issued upon exercise of
    outstanding options,
    warrants and rights

     

    Weighted-average
    exercise price per share
    of outstanding options,
    warrants and rights

     

    Number of securities
    remaining available for
    future issuance under equity
    compensation plans
    (excluding securities
    reflected in column (a))

     

     

     

    (a)

     

    (b)

     

    (c)

     

    Equity compensation plans approved by security holders

     

    2,005,000

     

    $

    5.30

     

    1,906,413

     

     

     

     

     

     

     

     

     

    Equity compensation plans not approved by security holders

     

     

     

     

    Total

     

    2,005,000

     

    $

    5.30

     

    1,906,413

     

    Recent Sales of Unregistered Securities

            In May 2000, we completed a private placementOn August 11, 2004, the entire $28,000,000 in aggregate principal amount of 3,768,161our 6.75% convertible subordinated debentures held by WEDGE Energy Services, L.L.C. and William H. White was converted in accordance with the terms of those debentures into 6,496,519 shares of our common stock to WEDGE Energy Services, L.L.C. ("WEDGE") for $8,000,000, or $2.175 per share.stock.  We issued those shares without registration under the Securities Act of 1933 in reliance on the exemption that Section 4(2) of that Act provides for transactions not involving any public offering.

     In August 2000, we issued 341,576 shares of our common stock at $2.25 per share as part of the consideration we paid in connection with our acquisition of Pioneer Drilling Co. We issued those shares without registration under the Securities Act of 1933 in reliance on the exemption Section 4(2) of that Act provides for transactions not involving any public offering.

            In October 2000, the T.L.L. Temple Foundation converted its 400,000 shares of Series A convertible preferred stock into 800,000 shares of our common stock at $1.00 per share. We issued those shares without registration under the Securities Act of 1933 in reliance on the exemption Section 4(2) of that Act provides for transactions not involving any public offering.

            On May 18, 2001, we retired the 4.86% subordinated debenture we issued to WEDGE on March 30, 2001 in connection with the Mustang Drilling, Ltd. acquisition. We funded the repayment of the $9,000,000 face amount of the debenture, together with the payment of $59,535 of accrued interest, with a short-term bank borrowing. We then sold 2,400,000 shares of our common stock to WEDGE in a private placement for $9,048,000, or $3.77 per share. We used the proceeds from this sale to fund the repayment of the short-term bank borrowing. We issued those shares, as well as the 4.86% subordinated debenture, without registration under the Securities Act of 1933 in reliance on the exemption Section 4(2) of that Act provides for transactions not involving any public offering.

            In accordance with the terms of the Series B Preferred Stock Agreement that we entered into on January 20, 1998, the conversion price for our Series B convertible preferred stock was revised from $3.25 per share to $2.50 per share as of January 20, 2001. This revision was based on the average trading price of our common stock for the 30 trading days preceding that date. In August 2001, the holders converted all of their 184,615 shares of our Series B convertible preferred stock into 1,199,038 shares of our common stock at $2.50 per share. We issued those shares without registration under the Securities Act of 1933 in reliance on the exemption Section 4(2) of that Act provides for transactions not involving any public offering.

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

            On October 9, 2001, we issued a 6.75% five-year $18,000,000 convertible subordinated debenture, Series A, to WEDGE. The debenture was convertible into 4,500,000 shares of common stock at $4.00


    per share. We used approximately $9,000,000 of the proceeds to complete the construction of two drilling rigs. Approximately $6,000,000 was used to reduce a $12,000,000 credit facility. The balance of the proceeds was used for drilling equipment and working capital. On July 3, 2002, we issued an additional $10,000,000 of 6.75% convertible subordinated debt to WEDGE with an effective conversion rate of $5.00 per share. The transaction was effected by an agreement between Pioneer and WEDGE under which WEDGE agreed to provide the additional $10,000,000 in financing and to cancel the previously issued debenture in the principal amount of $18,000,000 in exchange for $28,000,000 in new 6.75% convertible subordinated debentures. The new debentures are convertible into 6,500,000 shares of common stock at $4.31 per share, which resulted from a pro rata blending of the $5.00 conversion rate of the new $10,000,000 financing and the $4.00 conversion rate of the $18,000,000 debenture being cancelled. WEDGE funded $7,000,000 of the $10,000,000 on July 3, 2002 and $2,000,000 on July 29, 2002. William H. White, one of our Directors and the President of WEDGE, purchased the remaining $1,000,000 on July 29, 2002. Unlike the cancelled debenture, which was not redeemable by Pioneer, the new debentures are redeemable at a scheduled premium. We used $7,000,000 of the proceeds to pay down bank debt and $3,000,000 for the purchase of drilling equipment. WEDGE currently owns approximately 33.4% of our outstanding common stock. If WEDGE were to convert the new debentures, it would own approximately 48.3% of our outstanding common stock. We issued those securities without registration under the Securities Act of 1933 in reliance on the exemption Section 4(2) of that Act provides for transactions not involving any public offering.

            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. Chesapeake Energy owns approximately 24.6% of our outstanding common stock, or approximately 17.8% assuming the conversion of all outstanding options and convertible subordinated debentures. We issued those shares without registration under the Securities Act of 1933 in reliance on the exemption Section 4(2) of that Act provides for transactions not involving any public offering.


    Item 6.      
    Selected Financial Data

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

     
     Years Ended March 31,
     
     
     2003
     2002
     2001
     2000
     1999
     
     
     (In thousands, except per share amounts)

      
      
     
    Contract drilling revenues $80,183 $68,627 $50,345 $19,391 $12,659 
    Earnings (loss) from operations  (4,943) 11,201  3,803  149  (1,254)
    Earnings (loss) before income taxes  (7,305) 9,737  3,838  (65) (1,278)
    Preferred dividends    93  275  304  304 
    Net earnings (loss) applicable to common stockholders  (5,086) 6,225  2,428  (384) (1,612)
    Earnings (loss) per common share—basic  (0.31) 0.41  0.22  (0.06) (0.27)
    Earnings (loss) per common share—diluted  (0.31) 0.35  0.19  (0.06) (0.27)
    Long-term debt and capital lease obligations, excluding current installments  45,855  26,119  10,056  267  2,354 
    Shareholders' equity  47,672  33,343  17,827  6,783  5,322 
    Total assets  119,694  83,450  56,493  15,670  10,007 
    Capital expenditures  33,589  27,597  41,628  5,069  856 

     

     

     

    Years Ended March 31,

     

     

     

    2005

     

    2004

     

    2003

     

    2002

     

    2001

     

     

     

    (In thousands, except per share amounts)

     

     

     

     

     

     

     

     

     

     

     

     

     

    Contract drilling revenues

     

    $

    185,246

     

    $

    107,876

     

    $

    80,183

     

    $

    68,627

     

    $

    50,345

     

    Income (loss) from operations

     

    18,774

     

    438

     

    (4,943

    )

    11,201

     

    3,803

     

    Income (loss) before income taxes

     

    17,161

     

    (2,216

    )

    (7,305

    )

    9,737

     

    3,838

     

    Preferred dividends

     

     

     

     

    93

     

    275

     

    Net earnings (loss) applicable to common stockholders

     

    10,812

     

    (1,790

    )

    (5,086

    )

    6,225

     

    2,428

     

    Earnings (loss) per common share-basic

     

    0.31

     

    (0.08

    )

    (0.31

    )

    0.41

     

    0.22

     

    Earnings (loss) per common share-diluted

     

    0.30

     

    (0.08

    )

    (0.31

    )

    0.35

     

    0.19

     

    Long-term debt and capital lease obligations, excluding current installments

     

    13,445

     

    44,892

     

    45,855

     

    26,119

     

    10,056

     

    Shareholders' equity

     

    221,615

     

    70,836

     

    47,672

     

    33,343

     

    17,827

     

    Total assets

     

    276,009

     

    143,731

     

    119,694

     

    83,450

     

    56,493

     

    Capital expenditures

     

    80,388

     

    44,845

     

    33,589

     

    27,597

     

    41,628

     

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

    17




    Item 7. Management's7
    .Management’s Discussion and Analysis of Financial Condition and Results of Operations

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

    Company Overview

    Pioneer Drilling Company provides contract land drilling services to independent and major oil and gas exploration and production companies.  In addition to our drilling rigs, we provide the drilling crews and most of the ancillary equipment needed to operate our drilling rigs.  We have focused our operations in selected oil and natural gas production regions in the United States.  Our company was incorporated in 1979 as the successor to a business that had been operating since 1968.  We conduct our operations through our principal operating subsidiary, Pioneer Drilling Services, Ltd.  We are an oil and gas services company.  We do not invest in oil and natural gas properties.  The drilling activity of our customers is highly dependent on the current price of oil and natural gas.

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

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

    We earn our revenues by drilling oil and gas wells for our customers.  We obtain our contracts for drilling oil and gas wells either through competitive bidding or through direct negotiations with customers.  Our drilling contracts generally provide for compensation on either a daywork, turnkey or footage basis.  Contract terms generally depend on the complexity and risk of operations, the on-site drilling conditions, the type of equipment used and the anticipated duration of the work to be performed.  Generally, our contracts provide for the drilling of a single well and typically permit the customer to terminate on short notice. However, we currently have thirteen contracts with terms of six months to two years in duration, including the contracts for the two rigs currently under construction.

    A significant performance measurement in our industry is rig utilization.  We compute rig utilization rates by dividing revenue days by total available days during a period.  Total available days are the number of calendar days during the period that we have owned the rig.  Revenue days for each rig are days when the rig is earning revenues under a contract, which is usually a period from the date the rig begins moving to the drilling location until the rig is released from the contract.

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

     

     

    Years Ended March 31,

     

     

     

    2005

     

    2004

     

    2003

     

    Utilization Rates

     

    96

    %

    88

    %

    79

    %

    Revenue Days

     

    13,894

     

    8,764

     

    6,419

     

    Number of rigs

     

    50

     

    35

     

    24

     

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

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

    18



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

    We devote substantial resources to maintaining and upgrading our rig fleet.  During fiscal 2004, we removed three rigs from service for approximately three weeks each, to perform upgrades.  In the short term, these actions resulted in fewer revenue days and slightly lower utilization; however, in the long term, we believe the upgrades will help the marketability of the rigs and improve their operating performance.  We are currently performing or have recently performed, between contracts or as necessary, safety and equipment upgrades to the eight rigs we acquired in March 2004 and the 12 rigs we acquired in November and December 2004.

    Market Conditions in Our Industry

     

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

     Beginning in 1998 and extending into 1999,

    For the domestic contract land drilling industrythree months ended March 31, 2005, the average weekly spot price for West Texas Intermediate crude oil was adversely affected by an extended period of low oil and gas prices and a domestic$49.87, the average weekly spot price for Henry Hub natural gas surplus. was $6.39 and the average weekly Baker Hughes land rig count was 1,153.  On May 20, 2005, the spot price for West Texas Intermediate crude oil was $46.80, the spot price for Henry Hub natural gas was $6.36 and the Baker Hughes land rig count was 1,202, a 14% increase from 1,056 on May 21, 2004.

    The priceaverage weekly spot prices of West Texas Intermediate crude dropped to a low of $10.83 per barrel in December 1998oil and Henry Hub natural gas and the price of natural gas dropped to a low of $1.03 per mmbtu in December 1998. These conditions led to significant reductions in the overall level of domestic land drilling activity, resulting in a historically lowaverage weekly domestic land rig count, of 380 rigs on April 23, 1999. Prior to this industry downturn, during 1997,per the contract land drilling industry experienced a significant level of drilling activity, with a domestic land rig count of 881 rigs on September 5, 1997.

            Oil and natural gas prices rose sharply in calendar year 2000 and through mid-2001. Natural gas prices began falling in mid-2001 to a low of approximately $2.00 per mmbtu before returning to current levels of between $5.25 and $6.25 per mmbtu. Oil prices are currently in the $25.00 to $30.00 per barrel range. The average spot prices of natural gas and crude oil and the average domesticBaker Hughes land rig count, for each of ourthe previous six fiscal years ended March 31, 2005 were:

     

     

    Years Ended March 31,

     

     

     

    2005

     

    2004

     

    2003

     

    2002

     

    2001

     

    2000

     

    Oil (West Texas Intermediate)

     

    $

    45.04

     

    $

    31.47

     

    $

    29.27

     

    $

    24.31

     

    $

    30.40

     

    $

    23.23

     

    Natural Gas (Henry Hub)

     

    $

    5.99

     

    $

    5.27

     

    $

    4.24

     

    $

    2.96

     

    $

    5.27

     

    $

    2.46

     

    U.S. Land Rig Count

     

    1,110

     

    964

     

    723

     

    912

     

    841

     

    550

     

    During fiscal 2005, 2004 and 2003, were:

     
     2003
     2002
     2001
     2000
     1999
     1998
    Oil (West Texas Intermediate) $29.27 $24.31 $30.40 $23.23 $13.69 $18.92
    Gas (Henry Hub) $4.24 $2.96 $5.27 $2.46 $1.97 $2.39
    U. S. Land Rig Count  723  912  841  560  592  821

            Primarily as a resultsubstantially all the wells we drilled for our customers were drilled in search of natural gas because of the increase in oildepth capacity of our rigs and the natural gas prices, exploration and production companies increased their capital spending budgetsrich areas in 2000 and early 2001. These increased spending budgets increasedwhich we operate.  Although we have recently diversified our operations somewhat with the demand for contractNovember 2004 acquisition of seven drilling services. The domestic land rig count climbed to 1,095 on June 22, 2001, representing an increaserigs from Wolverine Drilling, with six of those rigs employed in search of oil in the domestic land rig countWilliston Basin of 188% from the lowRocky Mountains, our customers remain primarily focused on drilling for natural gas.  Natural gas reserves are typically found in April 1999. The decline in oildeeper geological formations and natural gas prices from mid-2001generally require premium equipment and quality crews to mid-2002 resulted in a reduction indrill the demand for contract land drilling services, which resulted in a substantial reduction in the rates land drilling companies have been able to obtain for their services. While oil and natural gas prices have recovered in recent months, drilling activity has not yet recovered to a level at which we are able to improve our revenue rates and drilling margins. The Baker Hughes domestic land rig count was 915 on May 16, 2003, a 29% increase from 709 on May 17, 2002.wells.



    Critical Accounting Policies and Estimates

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

     

    Our management has determined that it is appropriate to use the percentage-of-completion method as defined in SOP 81-1 to recognize revenue on our turnkey and footage contracts.  Although our turnkey and footage contracts do not have express terms that provide us with rights to receive payment for the work that we perform prior to drilling wells to the agreed onagreed-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 onagreed-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, ultimate recovery of that value would be subject to negotiations with the customer and the possibility of litigation.

    If a customer defaults on its payment obligationsobligation 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

    19



    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 costs incurred to drill a wellwork-in-progress under a turnkey or footage contract.

     

    We accrue estimated contract costs on turnkey and footage contracts for each day of work completed based on our estimate of the total costcosts to complete the contract divided by our estimate of the number of days to complete the contract.  Contract costs include labor, materials, supplies, repairs and maintenance, and operating overhead allocations. Changes in job performance, job conditionsallocations and estimated profitability on uncompleted contracts may result in revisions to costsallocations of depreciation and income, including losses, which we recognize in the period in which we determine the revisions.amortization expense.  In addition, the occurrence of uninsured or under-insured losses or operating cost overruns on our turnkey and footage contracts could have a material adverse effect on our financial position and results of operations.Therefore, our actual results could differ significantly if our cost estimates are later revised from our original estimates.estimates for contracts in progress at the end of a reporting period which were not completed prior to the release of our financial statements.

    Asset impairmentsWe assess the impairment of property and equipment whenever events or circumstances indicate that the carrying value may not be recoverable.  Factors that we consider important and which could trigger an impairment review would be our customers'customers’ financial condition and any significant negative industry or economic trends.  More specifically, among other things, we consider our contract revenue rates, our rig utilizationutilizations rates, cash flows from our drilling rigs, current oil and gas prices, industry analysts'analysts’ outlook for the industry and their view of our customerscustomers’ access to



    debt or equity, discussions with major industry suppliers, discussions with officers of our primary lender regarding their experiences and expectations for oil and gas operators in our areas of operations and the trends in the price of used drilling equipment observed by our management.  If a review of our drilling rigs indicates that our carrying value exceeds the estimated undiscounted future net cash flows, we are required under applicable accounting standards to write down the drilling equipment to its fair market value.  A one percent write-down in the valuecost of our drilling equipment, at March 31, 2003,2005, would have resulted in a corresponding increasedecrease in our net lossearnings of approximately $704,000$1,427,000 for our fiscal year ended March 31, 2003.2005.

    Deferred taxesWe provide deferred taxes for net operating loss carryforwards and for the basis difference in our property and equipment between financial reporting and tax reporting purposes.  For property and equipment, basis differences arise from differences in depreciation periods and methods and the value of assets acquired in a business acquisition where we acquire an entity rather than just its assets.  For financial reporting purposes, we depreciate the various components of our drilling rigs over 10eight to 15 years and refurbishments over three years, while federal income tax rules require that we depreciate drilling rigs and refurbishments over five years.  Therefore, in the first five years of our ownership of a drilling rig, our tax depreciation exceeds our financial reporting depreciation, resulting in our providing deferred taxes on this depreciation difference.  After five years, financial reporting depreciation exceeds tax depreciation, and the deferred tax liability begins to reverse.

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

     

    We receive payment under turnkey and footage contracts when we deliver to our customer a well completed to the depth specified in the contract, unless the customer authorizes us to drill to a shallower depth. Since 1995, when our current management team joined our company, we have completed all our turnkey or footage contracts.  Although our initial cost estimates for turnkey and footage contracts do not include cost estimates for risks such as stuck drill pipe or loss of circulation, we believe that our experienced management team, our knowledge of geologic formations in our areas of operations, the condition of our drilling equipment and our experienced crews enable us to make reasonably dependable cost estimates and complete contracts according to our drilling plan.  While we do bear the risk of loss for cost overruns and other events that are not specifically provided for in our initial cost estimates, our pricing of turnkey and footage contracts takes such risks into consideration.  When we encounter, during the course of our drilling operations, conditions unforeseen in the preparation of our original cost estimate, we immediately increase our cost estimate for the additional costs to complete the contract.contracts.  If we anticipate a loss on a contract in progress at the end of a reporting period due to a change in our cost estimate, we immediately accrue the entire amount of the estimated loss including all costs that are included in our revised estimated cost to complete that contract in our consolidated statement of operations for that reporting period.  At March 31, 2003, we accrued an estimated loss of $227,000 on one of our turnkey contracts in progress. During fiscal 2003,year 2005, we experienced losses on 17 of the 83182 turnkey and footage contracts completed, with losses exceeding $25,000 on 7ten contracts and losses exceeding $100,000 on twofour contracts.  We are more likely to encounter losses on turnkey and footage contracts in years in which revenue rates are lower for all types of contracts.  During periods of reduced demand for drilling rigs, our overall profitability on turnkey and footage contracts has historically exceeded our profitability on daywork contracts.

     

    Revenues and costs during a reporting period could be affected for contracts in progress at the end of a reporting period which have not been completed before our financial statements for that period are released.  All of our turnkey contracts in progress at March 31, 20032005 were completed prior to



    the release of thesethe financial statements.statements included in this report.  At March 31, 20032005 our Contract Drillingcontract drilling in Progressprogress totaled approximately $4,429,000.$5,365,000.  Of that amount accrued, turnkey and footage contract revenues were approximately $3,940,000.$2,344,000.  The remaining balance of approximately $489,000$3,021,000 relates to the revenue recognized but not yet billed on daywork contracts in progress at March 31, 2003.2005.  At March 31, 2004, drilling in progress totaled $9,131,000 of which $7,683,000 related to turnkey contracts and $1,488,000 related to daywork contracts.

     

    20



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

     

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

     Other

    Our other accrued expenses in ouras of March 31, 2003 financial statements2005 include an accrual of a total of $525,000approximately $1,334,000 for costs incurred under the self-insurance portion of our health insurance and under our workers'workers’ compensation insurance.  We have a deductible of (1) $100,000 per covered individual per year under the health insurance and (2) $250,000 per occurrence under our workers'workers’ compensation insurance.insurance, except in North Dakota where the deductible is $100,000.  We accrue for these costs as claims are incurred based on cost estimates established for each claim by the insurance companies providing the administrative services for processing the claims, including an estimate for incurred but not reported claims, estimates for claims to be paid directly by us, our estimate of the administrative costs associated with these claims and our historical experience with these types of claims.  Management evaluates these cost estimates by the insurance companies based on historical claim information and adjusts the accrued claim costs if deemed necessary.

    Liquidity and Capital Resources

     On

    Sources of Capital Resources

    Our rig fleet has grown from eight rigs in August 2000 to 50 rigs as of March 31, 2003,2005.  We have financed this growth with a combination of debt and equity financing.  We have raised additional equity or used equity for growth eight times since January 2000 and have increased our long-term debt from approximately $3,909,000 at June 30, 2000 to approximately $18,200,000 at March 31, 2005.  We plan to continue to grow our rig fleet.  At March 31, 2005, our total debt to total capital was approximately 7.6%.  Due to the volatility in our industry, we sold 5,333,333are reluctant to take on substantial additional debt in excess of the $20,000,000 of remaining availability under our acquisition credit facility.  However, our ability to continue funding our growth through the issuance of shares of our common stock is uncertain, as our common stock is not heavily traded and the market price for our common stock has been volatile in recent periods.

    On February 20, 2004, we sold 4,400,000 shares of our common stock at $5.40 per share in a private placement to Chesapeake Energy Corporationaccredited investors for $20,000,000 ($3.75 per share),$23,760,000 in proceeds, before related offering expenses. In

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

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

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

    On October 29, 2004, we entered into a $47,000,000 credit facility with a group of lenders consisting of a $7,000,000 revolving line and letter of credit facility and a $40,000,000 acquisition facility for the acquisition of drilling rigs, rig transportation equipment and associated equipment. Frost National Bank is the administrative agent and lead arranger under the new credit facility, and the lenders include Frost National Bank, the Bank of Scotland and Zions First National Bank. Borrowings under the new credit facility bear interest at a rate equal to acquire equity securitiesFrost National Bank’s prime rate (5.75% at March 31, 2005) and are secured by most of our assets, including all our drilling rigs, associated equipment and receivables. As described below, we may issueborrowed the entire $40,000,000 available under the acquisition facility and we have used approximately $2,825,000 of availability under the revolving line and letter of credit facility through the issuance of letters of credit in the ordinary course of

    21



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

    Uses of our outstanding sharesCapital Resources

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

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

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

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

    For the years ended March 31, 2005 and 2004, the additions to our property and equipment consisted of the acquired shares under the Securities Actfollowing:

     

     

    Years Ended March 31,

     

     

     

    2005

     

    2004

     

     

     

     

     

     

     

    Drilling rigs (1)

     

    $

    53,341,420

     

    $

    34,961,004

     

    Other drilling equipment

     

    22,674,774

     

    7,642,968

     

    Transportation equipment

     

    2,717,181

     

    2,160,838

     

    Other

     

    1,655,108

     

    79,935

     

     

     

    $

    80,388,483

     

    $

    44,844,745

     


    (1) Includes capitalized interest costs of 1933. Chesapeake Energy owns approximately 24.6% of our outstanding common stock, or approximately 17.8% assuming the conversion of all outstanding options$86,819 in 2005 and convertible subordinated debentures.$106,395 in 2004.

     

    Working Capital

    Our working capital increased to $11,144,309$76,326,669 at March 31, 20032005 from a deficit of $268,478$6,028,018 at March 31, 2002.2004.  Our current ratio, which we calculate by dividing our current assets by our current liabilities, was 1.553.70 at March 31, 20032005 compared to 0.981.27 at March 31, 2002.2004.  The principal reason for the improvementincrease in our working capital at March 31, 20032005 was our salethe approximately $61,300,000 in proceeds, after the payment of $20,000,000 of long-term debt, from the shares of common stock to Chesapeake Energy. we sold in a public offering on March 22, 2005.  Approximately $13,000,000 of the proceeds from that offering will be used for the construction of the two rigs described above.  We anticipate that the remaining proceeds will be used for future rig and equipment acquisitions.

    Our operations have historically generated even during periods of industry downturns, sufficient cash flow to meet our requirements for debt service and equipment expenditures. During



    expenditures (excluding rig and other major equipment acquisitions).  However, during periods when a higher percentage of our contracts are turnkey and footage contracts, our short-term working capital needs could increase.  The significant improvement in operating cash flow for the year ended March 31, 2005 over March 31, 2004 is due primarily to the approximately $12,600,000 overall improvement in net earnings, components of which are discussed in “Results of Operations.”  That improvement was net of approximately $6,900,000 in noncash depreciation and amortization expense.  If necessary, we can defer rig upgrades to improve our cash position.  We have available a $1,000,000believe our cash generated by operations and our ability to borrow the currently unused portion of our line of credit for short-term cash requirements. We did not have to use the lineand letter of credit during fiscal 2003. We have used debt and equityfacility of approximately $4,175,000, which takes into account reductions for approximately $2,825,000 of outstanding letters of credit as of March 31, 2005, should allow us to financemeet our long-term growth strategy to increaseroutine financial obligations for the size of our rig fleet. During periods of improved rig revenue rates, we believe we can generate cash flows in excess of our normal requirements.foreseeable future.

     

    22



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

     
     March 31,
      
     
     
     2003
     2002
     Change
     
    Cash, cash equivalents and securities $21,002,913 $5,720,354 $15,282,559 
    Receivables  8,928,923  9,281,049  (352,126)
    Income tax receivable  444,900  880,068  (435,168)
    Deferred tax receivable  180,991    180,991 
    Prepaid expenses  914,187  634,747  279,440 
      
     
     
     
    Current assets  31,471,914  16,516,218  14,955,696 
      
     
     
     
    Current debt  3,399,163  8,275,914  (4,876,751)
    Accounts payable  14,206,586  6,507,169  7,699,417 
    Deferred taxes    23,571  (23,571)
    Accrued expenses  2,721,856  1,978,042  743,814 
      
     
     
     
       20,327,605  16,784,696  3,542,909 
      
     
     
     
    Working capital $11,144,309  (268,478) 11,412,787 
      
     
     
     

     

     

     

    March 31,

     

     

     

    2005

     

    2004

     

    Change

     

    Cash and cash equivalents

     

    $

    69,673,279

     

    $

    1,815,759

     

    $

    67,857,520

     

    Marketable securities

     

    1,000,000

     

    4,550,000

     

    (3,550,000

    )

    Receivables

     

    26,108,291

     

    10,901,991

     

    15,206,300

     

    Contract drilling

     

    5,364,529

     

    9,130,794

     

    (3,766,265

    )

    Deferred tax receivable

     

    569,548

     

    285,384

     

    284,164

     

    Prepaid expenses

     

    1,876,843

     

    1,336,337

     

    540,506

     

    Current assets

     

    104,592,490

     

    28,020,265

     

    76,572,225

     

     

     

     

     

     

     

     

     

    Current debt

     

    5,415,001

     

    4,423,306

     

    991,695

     

    Accounts payable

     

    15,621,647

     

    13,270,989

     

    2,350,658

     

    Accrued payroll

     

    2,706,623

     

    1,499,151

     

    1,207,472

     

    Income tax payable

     

    195,949

     

     

    195,949

     

    Prepaid drilling contracts

     

    172,750

     

    ��

     

    172,750

     

    Accrued expenses

     

    4,153,851

     

    2,798,801

     

    1,355,050

     

     

     

    28,265,821

     

    21,992,247

     

    6,273,574

     

     

     

     

     

     

     

     

     

    Working capital

     

    $

    76,326,669

     

    $

    6,028,018

     

    $

    70,298,651

     

    The increase inlarge cash isbalance at March 31, 2005 was due to theour sale of shares of common stock described above. The decrease in current debt resulted from our repayment of a $6,000,000 bank loan on March 22, 2005 for net proceeds of approximately $81,300,000, of which $20,000,000 was used to reduce long-term debt and $61,300,000 was in the March 31, 2003, partially offset by increases in current installments of other debt obligations.2005 cash balance.

     In March 2003, we completed or had

    The increase in progress 20 turnkey contracts. Approximately 68% of our receivables at March 31, 2003 result2005 from turnkeyMarch 31, 2004 was due to our operating 15 additional rigs in the quarter ended March 31, 2005, and footage contracts compared to approximately 26%an improvement in utilization and revenue rates in the fourth quarter of receivablesfiscal year 2005 over fiscal year 2004.

    Substantially all our prepaid expenses at March 31, 2002.

    2005 consisted of prepaid insurance.  The increase in accounts payable at March 31, 2003 over March 31, 2002 isprepaid insurance was primarily attributable to the increase in our turnkey contract work. Under turnkey contracts, we are responsible for many of the costs which are the responsibility of our customer under daywork contracts. Some of the increase in accounts payable is also due to the increase in the size of our drilling rig fleet.

            The increase in accrued expenses resultsfleet from an increase in accrued payroll of $54,000 resulting from an increase in the number of employees; an increase of approximately $422,000 in the accrual for deductibles related to our health and workers' compensation insurance primarily as a result of our switching to the deductible health insurance plan in June 2002; and an increase of approximately $247,000 in accrued well control insurance, due to the increase in turnkey contracts.

            Our cash flows from operating activities for the year ended35 rigs at March 31, 2003 were $14,389,277, compared2004 to $11,044,889 for the year ended50 rigs at March 31, 2002. Our cash flows from operating activities are affected by a number of factors, including rig utilization rates, the types of contracts we are performing, revenue rates we are able to obtain for our services, collection of receivables and the timing of expenditures. 2005.

    The primary reason for the increase in cash flows from operating activities in fiscal 2003 is the increase in payables at March 31, 2003 over2005 from March 31, 2002.2004 was primarily due to the increase in the size of our drilling rig fleet.



     Since

    The increase in accrued payroll was primarily due to the approximately 49% increase in our number of employees and the increase in the number of payroll days included in the accrual from nine days at March 31, 2002,2004 to ten days at March 31, 2005.

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

    Although, we have not been required to make income tax payments for the last three years, it is likely we will be in a current taxable position during fiscal year 2006 due to improving market conditions and equipment were $33,588,972. Additionsthe reversal of deferred tax liabilities.

    23



    Long-term Debt

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

    Drilling rigs(1) $24,667,710
    Other drilling equipment  8,504,588
    Transportation equipment  383,650
    Other  33,024
      
      $33,588,972
      

    (1)
    Includes capitalized interest costs of $96,079.

     On May 28, 2002, we purchased from United Drilling Company and U-D Holdings, L.P. two land drilling rigs, associated spare parts and vehicles for $7,000,000 in cash. We financed the acquisition of those assets with a $7,000,000 loan from Frost National Bank. Interest on the loan was payable monthly at prime. The loan was collateralized by the assets that we purchased and a $7,000,000 letter of credit that WEDGE provided. We repaid this loan on July 3, 2002 with $7,000,000

     

     

    2005

     

    2004

     

     

     

     

     

     

     

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

     

    $

    18,077,778

     

    $

     

     

     

     

     

     

     

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

     

     

    28,000,000

     

     

     

     

     

     

     

    Note payable to Merrill Lynch Capital, secured by drilling equipment, due in monthly payments of $172,619 plus interest at a floating rate equal to the three month LIBOR rate plus 385 basis points, due December 2007 (2)

     

     

    13,119,048

     

     

     

     

     

     

     

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

     

     

    4,392,174

     

     

     

     

     

     

     

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

     

     

    3,000,000

     

     

     

    18,077,778

     

    48,511,222

     

     

     

     

     

     

     

    Less current installments

     

    (4,666,667

    )

    (3,724,302

    )

     

     

    $

    13,411,111

     

    $

    44,786,920

     


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

    (2)          These notes were repaid in August and September 2004 with proceeds from the issuance of the subordinated debt as described below.our August 2004 common stock offering.

     In November and December of 2002, we added two refurbished 18,000-foot SCR land drilling rigs at a cost of approximately $7,000,000 each. As of March 31, 2003, we were constructing an additional refurbished 18,000-foot SCR land drilling rig.

    Contractual Obligations

    We estimate the total cost of this rig will be approximately $7,000,000, of which approximately $2,415,000 had been incurreddo not have any routine purchase obligations.  However, as of March 31, 2003. We accepted delivery of this rig on May 2, 2003. On September 30, 2002,2005, we signed an agreement to purchase another 14,000-foot mechanical drilling rig, located in Trinidad, for $3,150,000, which we expect to be delivered to the Port of Houston in July or August 2003. On October 7, 2002, we made a $315,000 deposit toward the purchase of this rig. In March 2003, we signed an amended asset purchase agreement reducing the purchase price for this rig to $2,850,000 and made an additional $300,000 deposit.

            Our debt obligationswere in the formprocess of notes payable,constructing two drilling rigs, as described above.  The following table excludes interest payments on long-term debt and capital leases and convertible subordinated debentures increased by a netlease obligations.  The following table includes all of $14,859,191 fromour contractual obligations of the type specified below at March 31, 2002 to March 31, 2003. This increase resulted from2005:

     

     

    Payments Due by Period

     

    Contractual
    Obligations

     

    Total

     

    Less than 1
    year

     

    1-3 years

     

    4-5
    years

     

    More than 5
    years

     

     

     

     

     

     

     

     

     

     

     

     

     

    Long-Term Debt Obligations

     

    $

    18,077,778

     

    $

    4,666,667

     

    $

    13,411,111

     

    $

     

    $

     

    Capital Lease Obligations

     

    100,265

     

    66,359

     

    33,906

     

     

     

    Operating Lease Obligations

     

    1,991,934

     

    224,873

     

    391,427

     

    472,196

     

    903,438

     

    Total

     

    $

    20,169,977

     

    $

    4,957,899

     

    $

    13,836,444

     

    $

    472,196

     

    $

    903,438

     

    24



    Debt Requirements

    The $18,077,778 amount of indebtedness outstanding under the acquisition facility portion of our new credit facility is due in monthly installments of $388,889 plus interest, based on a $10,000,000 increase in our subordinated debt, $14,500,000 of new debt from Merrill Lynch Capital, a division of Merrill Lynch Business Financial Services, Inc. ("MLC"), $1,239,535 to finance72-month amortization schedule, with all remaining unpaid principal being due on December 1, 2007. All the premiums on insurance policies, $448,475 from our line of credit and $385,492 in capital leases for crew quarters and vehicles. In addition, on May 28, 2002, we obtained a $7,000,000 short-term loan fromindebtedness under the acquisition facility bears interest at Frost National Bank, which we repaid on July 3, 2002 with $7,000,000 of proceeds from the issuance of new convertible subordinated debtBank’s prime rate (5.75% as described below. We made payments of $18,714,311 on our debt, including the $6,000,000, $7,000,000 and $2,130,503 loan repayments. Borrowings from Frost National Bank, on an installment loan due August 2004, and MLC are secured by drilling equipment. Our bank loan and MLC Loan contain various covenants pertaining to leverage, cash flow coverage, fixed charge coverage and net worth ratios and restrict us from paying dividends. Under these credit arrangements, we determine compliance with the ratios on a quarterly basis based on the previous four quarters. As of March 31, 2003, we were in compliance with all covenants applicable to our outstanding debt.2005).

     On December 23, 2002, we borrowed $14,500,000 from MLC. Under the terms of the MLC loan, we make monthly interest payments until August 1, 2003, when we begin making equal monthly installment payments of principal of $172,619, plus interest. The unpaid balance of the MLC loan will be due at maturity on December 22, 2007. Interest accrues at a floating rate equal to the three month LIBOR rate plus 385 basis points until our election to convert the interest rate to a fixed rate, at which time interest will accrue at the greater of (1) 6.975%, or (2) the sum of the swap rate published on the Bloomberg Screen "USSW" on the conversion date plus 367 basis points. The MLC loan is secured by



    a first priority security interest in certain of our drilling rigs. We may prepay the MLC loan at any time in whole, but not in part, subject to certain exceptions and payment of specified prepayment premium requirements. We used $2,130,503 of the proceeds of the Loan to retire all of our outstanding debt to one of our bank lenders, $5,106,321 to make a final payment on the new/refurbished, 18,000 foot rig added in December, $7,190,676 to replenish our working capital and $72,500 to pay associated loan fees.

            On October 9, 2001, we issued a 6.75% five-year $18,000,000 convertible subordinated debenture, Series A, to WEDGE Energy Services, L.L.C. ("WEDGE"). The debenture was convertible into 4,500,000 shares of common stock at $4.00 per share. We used approximately $9,000,000 of the proceeds to complete the construction of two drilling rigs. Approximately $6,000,000 was used to reduce a $12,000,000 credit facility. The balance of the proceeds was used for drilling equipment and working capital. On July 3, 2002, we issued an additional $10,000,000 of 6.75% convertible subordinated debt to WEDGE with an effective conversion rate of $5.00 per share. The transaction was effected by an agreement between Pioneer and WEDGE under which WEDGE agreed to provide the additional $10,000,000 in financing and to cancel the previously issued debenture in the principal amount of $18,000,000 in exchange for $28,000,000 in new 6.75% convertible subordinated debentures. The new debentures are convertible into 6,500,000 shares of common stock at $4.31 per share, which resulted from a pro rata blending of the $5.00 conversion rate of the new $10,000,000 financing and the $4.00 conversion rate of the $18,000,000 debenture being cancelled. WEDGE funded $7,000,000 of the $10,000,000 on July 3, 2002 and $2,000,000 on July 29, 2002. William H. White, one of our Directors and the President of WEDGE, purchased the remaining $1,000,000 on July 29, 2002. Unlike the cancelled debenture, which was not redeemable by Pioneer, the new debentures are redeemable at a scheduled premium. We used $7,000,000 of the proceeds to pay down bank debt and $3,000,000 for the purchase of drilling equipment. If WEDGE were to convert the new debentures, it would own approximately 48.3 percent of our outstanding common stock.

            We have a $1,000,000 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 (4.25% at March 31, 2003) plus 1.0%. The sum of (1) the draws under this line and (2) the amount of all outstanding letters of credit issued by the bank for our account under the revolving line and letter of credit facility portion of our new credit facility are limited to 75% of our eligible accounts receivable.receivable, not to exceed $7,000,000. Therefore, if 75% of our eligible accounts receivable iswas less than $1,000,000 plus any outstanding letters of credit issued by the bank on our behalf,$7,000,000, our ability to draw under this line would be reduced. At March 31, 2003,2005, we had no outstanding advances under this line of credit, outstanding letters of credit were $1,450,000$2,825,000 and 75% of our eligible accounts receivable were $4,299,179.was approximately $19,084,000. The letters of credit are issued to two workers'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 lenderlenders will be required to fund any draws under these letters of credit.

            We do not have any routine purchase obligations. However, we are obligated under two asset purchase agreements for The termination date of the purchaserevolving line and constructionletter of two drilling rigs as previously described. The following table excludes interest payments on long-term debt and capital lease obligations. The following table includes allcredit facility portion of our contractual obligations at March 31, 2003.

     
     Payments due by period
    Contractual obligations

     Total
     2004
     2005
     2006
     2007
     2008
     More than
    5 years

    Long Term Debt Obligations $48,265,786 $2,671,269 $6,468,524 $2,076,690 $2,077,054 $34,910,777 $61,472
    Capital Lease Obligations  400,742  140,717  148,283  78,172  33,570    
    Operating Lease Obligations  474,738  358,008  58,008  56,010  2,712    
      
     
     
     
     
     
     
    Total $49,141,266 $3,169,994 $6,674,815 $2,210,872 $2,113,336 $34,910,777 $61,472
      
     
     
     
     
     
     

    new credit facility is October 28, 2005.

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

      our failure to make required payments;

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

      our failure to comply with financial covenants related to the maintenance of a debt to total capitalization ratio not to exceed 0.3 to 1, an operating leverage ratio not to exceed 3 to 1, and a fixed charge coverage ratio of debtnot less than 1.5 to tangible net worth, a leverage ratio, a cash flow coverage ratio and a senior cash flow coverage ratio;

      1;

      our incurrence of any additional indebtedness in excess of $2,000,000$3,000,000 not already allowed by the loan agreements withoutcredit facility;

      any event which results in a change in the lenders approval;

      ownership of at least 40% of all classes of our outstanding capital stock; and

      any payment of cash dividends on our common stock.

     

    The limitation on additional indebtedness described above has not affected our operations or liquidity and we do not expect it to affect us in theour future operations or liquidity, as we expect to continue to generate adequate cash flow from operations. We also have a $1,000,000 line of creditoperations to supplementfund our short-termanticipated working capital and other normal cash needs.flow requirements.

    Results of Operations

     We earn our revenues by drilling oil and gas wells. We obtain our contracts for

    Our operations consist of drilling oil and gas wells either through competitive bidding or through direct negotiations with customers. Our drilling contracts generally provide for compensation on either aour customers under daywork, turnkey, or footage contracts usually on a well-to-well basis.  Contract terms we offer generally depend onDaywork contracts are the complexityleast complex for us to perform and involve the least risk.  Turnkey contracts are the most difficult to perform and involve much greater risk of operations,but provide the on-site drilling conditions, the type of equipment used and the anticipated duration of the work to be performed. Generally, our contracts provideopportunity for the drilling of a single well.higher operating profits.

    Daywork        Daywork Contracts. 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.  DayworkDuring the mobilization period we typically earn a fixed amount of revenue based on the mobilization rate stated in the contract.  We attempt to set the mobilization rate at an amount equal to our external costs for the move plus our internal costs during the mobilization period.  We begin earning our contracted daywork rate when we begin drilling the well.  Occasionally, in periods of increased demand, some of our contracts specifywill provide for the equipmenttrucking costs to be used, the size of the hole and the depth of the well. Under a daywork drilling contract,paid by the customer bears a large portion of out-of-pocket costs of drilling and we generally bear no part ofwill receive a reduced dayrate during the usual risks associated with drilling, such as time delays and unanticipated costs.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 to us under a turnkey contract are substantially greater than on a well drilled onthose under a daywork basis,contract, because under a turnkey contract we assume most of the risks associated with drilling operations generally assumed bythat the operator ingenerally assumes under a daywork contract, including the risks of blowout, loss of hole, stuck drill pipe, machinery breakdowns and abnormal drilling conditions, as well as risks associated with subcontractors' services, supplies, cost escalations and personnel. We employ or contract for engineering expertise to analyze seismic, geologic and drilling data to identify and reduce some of the drilling risks assumed by us. We use the results of this analysis to evaluate the risks of a proposed contract and seek to account for such risks in our bid preparation. We believe that our operating experience, qualified drilling personnel, risk management program, internal engineering expertise and access to proficient third-party engineering contractors have allowed us to reduce some of the risks inherent in turnkey drilling operations. We also maintain insurance coverage against some but not all drilling hazards. However, the occurrence of uninsured or under-insured losses or operating cost overruns on our turnkey jobs could have a material adverse effect on our financial position and results of operations.contract.

    25




    Footage Contracts.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 withto daywork contracts.  Similar to a turnkey contract, the risks to us oncontracts, under a footage contract are greater because we assume most of the risks associated with drilling operations generally assumed bythat the operator ingenerally assumes under a daywork contract. As with turnkey contracts, we manage these additional risks 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

    We have a material adverse effect on our financial positionhistory of losses.  We incurred net losses of approximately $1,800,000, $5,100,000 and results of operations.

            For each of$400,000 in the threefiscal years ended March 31, 2004, 2003 our rig utilization and revenue days were as follows:

     
     2003
     2002
     2001
     
    Utilization Rates 79%82%91%
    Revenue Days 6,419 5,384 3,466 

            The primary reason for the increase2000, respectively.  Our profitability in the numberfuture 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 revenue days in 2003 over 2002contracts we are able to obtain.  As the demand for rigs increases, daywork rates move up and 2002 over 2001 is the increase in size of our rig fleet from 16 at March 31, 2001we are able to 20 at March 31, 2002switch primarily to 24 at March 31, 2003.daywork contracts.

     

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

     
     2003
     2002
     2001
     
    Turnkey Contracts 58%7%57%
    Footage Contracts 1%2%1%
    Daywork Contracts 41%91%42%

     Due to the current reduced

     

     

    Years Ended March 31,

     

     

     

    2005

     

    2004

     

    2003

     

    Daywork Contracts

     

    52

    %

    47

    %

    41

    %

    Turnkey Contracts

     

    43

    %

    50

    %

    58

    %

    Footage Contracts

     

    5

    %

    3

    %

    1

    %

    While demand for drilling rigs has been increasing, we have returnedcontinue to biddingbid on turnkey contracts in an effort to improve marginsmeet our customer demand and maintain rig utilization.  In spite ofWith the improvements in oil and natural gas prices,daywork contract rates, we anticipate only a moderate changegradual decline in the mixnumber of our type ofturnkey contracts.  We had 6 turnkey contracts in the near future.progress at March 31, 2005 compared to 16 turnkey contracts in progress at March 31, 2004.  We also had 6 footage contracts in progress at March 31, 2005 compared to none in progress at March 31, 2004.

     

    In accordance with Emerging Issues Task Force issue No. 01-14 "Income Statement Characterization of Reimbursements Received for Out-of-Pocket Expenses Incurred," we have revised the presentation of reimbursements received for certain expenses in the periods presented. These reimbursements are now included in contract drilling revenues in the consolidated statements of operations versus previously being recorded net of the incurred expense in contract drilling costs. These reclassifications had no effect on net income or cash flows for any of the threeour years ended March 31, 2005 and 2004, we recognized revenues of approximately $4,885,000 and $924,000, respectively, and recorded contract drilling costs of approximately $3,263,000 and $745,000, respectively, excluding depreciation, on contracts with Chesapeake Energy Corporation.  At March 31, 2005, Chesapeake owned 16.78% of our outstanding common stock.

    26



    Statements of Operations Analysis

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

     

     

     

    Years Ended March 31,

     

     

     

    2005

     

    2004

     

    2003

     

    Contract drilling revenues:

     

     

     

     

     

     

     

    Daywork contracts

     

    $

    95,997,451

     

    $

    50,144,773

     

    $

    33,203,385

     

    Turnkey contracts

     

    80,210,813

     

    54,234,756

     

    45,889,585

     

    Footage contracts

     

    9,038,184

     

    3,496,004

     

    1,090,516

     

    Total contract drilling revenues

     

    $

    185,246,448

     

    $

    107,875,533

     

    $

    80,183,486

     

    Contract drilling costs:

     

     

     

     

     

     

     

    Daywork contracts

     

    $

    68,415,608

     

    $

    42,903,525

     

    $

    29,289,493

     

    Turnkey contracts

     

    63,421,106

     

    42,761,928

     

    40,482,547

     

    Footage contracts

     

    6,646,045

     

    2,838,649

     

    1,051,270

     

    Total contract drilling costs

     

    $

    138,482,759

     

    $

    88,504,102

     

    $

    70,823,310

     

     

     

     

     

     

     

     

     

    Depreciation and amortization

     

    $

    23,090,909

     

    $

    16,160,494

     

    $

    11,960,387

     

    General and administrative expense

     

    $

    4,657,013

     

    $

    2,772,730

     

    $

    2,232,390

     

    Revenue days by type of contract:

     

     

     

     

     

     

     

    Daywork contracts

     

    8,685

     

    5,626

     

    3,681

     

    Turnkey contracts

     

    4,471

     

    2,827

     

    2,619

     

    Footage contracts

     

    738

     

    311

     

    119

     

    Total Revenue days

     

    13,894

     

    8,764

     

    6,419

     

     

     

     

     

     

     

     

     

    Contract drilling revenue per revenue day

     

    $

    13,333

     

    $

    12,309

     

    $

    12,492

     

    Contract drilling cost per revenue day

     

    $

    9,967

     

    $

    10,099

     

    $

    11,033

     

    Rig utilization rates

     

    96

    %

    88

    %

    79

    %

    Average number of rigs during the period

     

    40.1

     

    27.3

     

    22.3

     

     

     

     

     

     

     

     

     

    Our contract drilling revenues for thegrew by approximately $77,000,000, or 72%, in fiscal year ended March 31, 2003 increased to $80,183,4862005 from $68,627,486 for the fiscal year ended March 31, 2002. This2004, primarily due to the 59% increase in revenue days (approximately $63,000,000) and the approximately $1,000 increase in revenue per revenue day (approximately $14,000,000), which was attributable to improving market conditions in our industry.

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

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

    Our contract drilling costs grew by approximately $18,000,000, or 25%, in fiscal year 2004 from an approximately 19%fiscal year 2003 due to the increase in revenue days and rig utilization. The increase in daywork revenue days by 1,945 revenue days in fiscal year 2004 resulted in a higher percentage of turnkey contracts, partially offset by a$934 decrease in rig revenue rates. Our contract drilling revenues increased to $68,627,486 for fiscal 2002 from $50,344,909 for fiscal 2001 principally due to an increase in revenue rates and a 55% increase in revenue days due to more rigs.

            Our contract drilling costs forper revenue day because costs associated with the fiscal year ended March 31, 2003 increased to $70,823,310 from $46,145,364 for the 2002 fiscal year. The percentage increase in revenue days and the additionaldrilling of daywork contracts is less than costs associated with turnkey and footage contracts account for the substantial increasewhich only increased by 400 revenue days in our drilling costs in 2003. Our contract drilling costs increased to $46,145,364 for fiscal 2002 from $41,687,893 for fiscal 2001. Contract



    drilling costs for the year ended March 31, 2002 include a $275,000 charge related to severance costs for a corporate officer. In addition, as previously reported, one of our former employees, Jesse J. Sanchez, filed a petition against us in the District Court for the 341st District in Webb County, Texas. The petition asserted a claim for injuries resulting from an accident involving one of our drilling rigs. On December 19, 2001, we settled this claim for $500,000. The cost of this settlement is also included in our contract drilling costs for the fiscal year ended March 31, 2002.2004.

     

    Our depreciation and amortization expense in 20032005 increased toby approximately $11,960,000$7,000,000, or 43%, from 2004. Depreciation and amortization expense in 2004 increased approximately $8,426,000$4,000,000, or 35%, from 2003.  The increase in 2002 and approximately $3,738,000 in 2001. The increases in 20032005 over 2002 and 2002 over 20012004 resulted from our addition of four15 drilling rigs and related equipment in each2005.  The increase in 2004 over 2003 resulted from our addition of the years ended March 31, 200311 drilling rigs and 2002.related equipment during 2004.

     

    Our general and administrative expenses decreased toincreased by approximately $2,232,000$1,900,000, or 68%, in 2003fiscal year 2005 from approximately $2,855,000 in 2002.fiscal year 2004.  The decrease resulted from reduced payroll costs, legal and professional fees and investor relation costs. The increase in 2002 from approximately $1,117,000 in 2001 resulted from increased payroll costs, legalprofessional and professionalconsulting costs, insurance costs and director fees.  Payroll related costs

    27



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

     

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

    Our contract land drilling operations are subject to various federal and state laws and regulations designed to protect the environment.  Maintaining compliance with these regulations is part of our day-to-day operating procedures.  We monitor each of our yard facilities and each of our rig locations on a dailyday-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 costcosts of these procedures represent only a small portion of our routine employee training, equipment maintenance and job site maintenance costs.  We estimate ourthe annual compliance costs for this program is approximately $116,000.$212,000.  We are not aware of any potential clean-up obligations that would have a material adverse effect on our financial condition or results of operations.

     

    Our effective income tax expense rates of 30.4%37.0%, 35.1%19.2% and 29.6%30.4% for 2005, 2004 and 2003, 2002 and 2001respectively, differ from the federal statutory rate of 34% due to permanent differences.  Permanent differences are costs included in results of operations in the accompanying financial statements which are not fully deductible for federal income tax purposes.

    Accounting Matters

            In June 2001,  At March 31, 2005, we had a net operating loss carryforwards for income tax purposes of approximately $16,500,000, of which approximately $6,600,000 will expire in 2023 and $9,900,000 in 2024.  We feel that it is more likely than not that we will realize the Financial Accounting Standards Board issued Statement of Financial Accounting Standards ("SFAS") No. 143, "Accounting for Asset Retirement Obligations," which addresses financial accounting and reporting for obligations associated with the retirement of tangible long-lived assets and the associated asset retirement costs. The standard applies to legal obligations associated with the retirement of long-lived assets that result from the acquisition, construction, development and/or normal use of the asset. We are required to adopt the provisions of SFAS No. 143 beginning April 1, 2003. In that connection, we must identify all our legal obligations relating to asset retirements and determine the fair valuebenefits of these obligations on the datedeductible differences.  Therefore, we have established a deferred tax asset applicable to these net operating loss carryforwards of adoption. We do not expect the adoption of SFAS No. 143 to have a material effect on our financial position or results of operations.approximately $4,300,000.

     In December 2002, the FASB issued SFAS No. 148, "Accounting for Stock-Based Compensation—Transition and Disclosure, an amendment of FASB Statement No. 123." This Statement amends FASB Statement No. 123, "Accounting for Stock-Based Compensation," to provide alternative methods of transition for a voluntary change to the fair value method of accounting for stock-based employee compensation. In addition, this Statement amends the disclosure requirements of Statement No. 123 to require prominent disclosures in both annual and interim financial statements. Certain of the disclosure modifications are required for fiscal years ending after December 15, 2002 and are included in the notes to the consolidated financial statements included in this report.



    Inflation

     

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

    Off Balance Sheet Arrangements

    We do not currently have any off balance sheet arrangements.

    Recently Issued Accounting Standards

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


    Item 7A.Quantitative and Qualitative Disclosures About Market Risk

    We are subject to market risk exposure related to changes in interest rates on most of our outstanding debt.  At March 31, 2003,2005, we had outstanding debt of approximately $20,178,000$18,078,000 that was subject to variable interest rates, in each case based on an agreed percentage-point spread from the lender'sFrost National Bank’s prime interest rate.  An increase or decrease of 1% in thethat interest rate would have a corresponding decrease or increase in our net income (loss) of approximately $133,000$120,000 annually.  We did not enter into any of thesethis debt arrangementsarrangement for trading purposes.

    28




    REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
    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, 20032005 and 20022004, 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, 2003.2005. 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'sCompany’s management. Our responsibility is to express an opinion on these consolidated financial statements and financial statement schedule based on our audits.

     

    We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States).  Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material 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, 20032005 and 2002,2004, and the results of their operations and their cash flows for each of the years in the three-year period ended March 31, 2003,2005, in conformity with U.S. generally accepted accounting principles.  Also in our opinion, the related financial statement schedule, when considered in relation to the basic consolidated financial statements taken as a whole, present fairly, in all material respects, the information set forth therein.

    We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the effectiveness of Pioneer Drilling Company’s internal control over financial reporting as of March 31, 2005, 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 27, 2005 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 20, 200327, 2005

    30



    REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

    The Board of Directors and Stockholders

    Pioneer Drilling Company:

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

    We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of the Company’s internal control over financial reporting, evaluating management’s assessment, testing and evaluating the design and operating effectiveness of the Company’s internal control over financial reporting, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

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

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

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

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

    KPMG LLP

    San Antonio, Texas

    May 27, 2005

    31



    PIONEER DRILLING COMPANY AND SUBSIDIARIES

    CONSOLIDATED BALANCE SHEETS

     
     March 31,
     
     
     2003
     2002
     
    ASSETS       
    Current assets:       
     Cash and cash equivalents $21,002,913 $5,383,045 
     Securities available for sale    337,309 
     Receivables:       
      Trade, net of allowance for doubtful accounts of $110,000 in 2003  4,499,378  6,160,797 
      Contract drilling in progress  4,429,545  3,120,252 
     Federal income tax receivable  444,900  880,068 
     Current deferred income taxes  180,991   
     Prepaid expenses  914,187  634,747 
      
     
     
    Total current assets  31,471,914  16,516,218 
      
     
     
    Property and equipment, at cost:       
     Drilling rigs and equipment  106,728,573  77,149,043 
     Transportation, office, land and other  3,494,657  3,203,979 
      
     
     
       110,223,230  80,353,022 
    Less accumulated depreciation and amortization  22,367,327  13,621,396 
      
     
     
    Net property and equipment  87,855,903  66,731,626 
    Other assets  366,500  201,914 
      
     
     
    Total assets $119,694,317 $83,449,758 
      
     
     

    LIABILITIES AND SHAREHOLDERS' EQUITY

     

     

     

     

     

     

     
    Current liabilities:       
     Notes payable $587,177 $6,329,925 
     Current installments of long-term debt  2,671,269  1,836,860 
     Current installments of capital lease obligations  140,717  109,129 
     Accounts payable  14,206,586  6,507,169 
     Current deferred income taxes    23,571 
     Accrued expenses:       
      Payroll and payroll taxes  847,163  792,805 
      Other  1,874,693  1,185,237 
      
     
     
    Total current liabilities  20,327,605  16,784,696 
    Long-term debt, less current installments  45,594,517  25,829,610 
    Capital lease obligations, less current installments  260,025  288,991 
    Deferred income taxes  5,839,908  7,203,456 
      
     
     
    Total liabilities  72,022,055  50,106,753 
      
     
     
    Shareholders' equity:       
     Preferred stock, 10,000,000 shares authorized; none issued and outstanding       
     Common stock $.10 par value; 100,000,000 shares authorized; 21,700,792 shares and 15,922,459 shares issued and outstanding at March 31, 2003 and March 31,2002, respectively  2,170,079  1,592,245 
     Additional paid-in capital  57,730,188  38,783,731 
     Accumulated deficit  (12,228,005) (7,142,387)
     Accumulated other comprehensive income-unrealized gain on securities available for sale    109,416 
      
     
     
    Total shareholders' equity  47,672,262  33,343,005 
      
     
     
    Total liabilities and shareholders' equity $119,694,317 $83,449,758 
      
     
     

     

     

    March 31,

     

     

     

    2005

     

    2004

     

    ASSETS

     

     

     

     

     

    Current assets:

     

     

     

     

     

    Cash and cash equivalents

     

    $

    69,673,279

     

    $

    1,815,759

     

    Marketable securities

     

    1,000,000

     

    4,550,000

     

    Receivables:

     

     

     

     

     

    Trade, net

     

    26,108,291

     

    10,901,991

     

    Contract drilling in progress

     

    5,364,529

     

    9,130,794

     

    Current deferred income taxes

     

    569,548

     

    285,384

     

    Prepaid expenses

     

    1,876,843

     

    1,336,337

     

    Total current assets

     

    104,592,490

     

    28,020,265

     

    Property and equipment, at cost:

     

     

     

     

     

    Drilling rigs and equipment

     

    216,286,747

     

    145,758,913

     

    Transportation equipment

     

    6,469,519

     

    4,282,349

     

    Land, buildings and other

     

    2,691,673

     

    1,145,288

     

     

     

    225,447,939

     

    151,186,550

     

    Less accumulated depreciation and amortization

     

    54,881,488

     

    35,844,938

     

    Net property and equipment

     

    170,566,451

     

    115,341,612

     

    Intangible and other assets

     

    850,381

     

    369,278

     

    Total assets

     

    $

    276,009,322

     

    $

    143,731,155

     

     

     

     

     

     

     

    LIABILITIES AND SHAREHOLDERS’ EQUITY

     

     

     

     

     

    Current liabilities:

     

     

     

     

     

    Notes payable

     

    $

    681,975

     

    $

    558,070

     

    Current installments of long-term debt

     

    4,666,667

     

    3,724,302

     

    Current installments of capital lease obligations

     

    66,359

     

    140,934

     

    Accounts payable

     

    15,621,647

     

    13,270,989

     

    Income tax payable

     

    195,949

     

     

    Prepaid drilling contracts

     

    172,750

     

     

    Accrued expenses:

     

     

     

     

     

    Payroll and payroll taxes

     

    2,706,623

     

    1,499,151

     

    Other

     

    4,153,851

     

    2,798,801

     

    Total current liabilities

     

    28,265,821

     

    21,992,247

     

    Long-term debt, less current installments

     

    13,411,111

     

    44,786,920

     

    Capital lease obligations, less current installments

     

    33,906

     

    104,754

     

    Non-current liability

     

    400,000

     

     

    Deferred income taxes

     

    12,283,070

     

    6,010,916

     

    Total liabilities

     

    54,393,908

     

    72,894,837

     

    Commitments and contingencies

     

     

     

    Shareholders’ equity:

     

     

     

     

     

    Preferred stock, 10,000,000 shares authorized; none issued and outstanding

     

     

     

    Common stock $.10 par value; 100,000,000 shares authorized; 45,893,311 shares and 27,300,126 shares issued and outstanding at March 31, 2005 and March 31, 2004, respectively

     

    4,589,331

     

    2,730,012

     

    Additional paid-in capital

     

    220,232,520

     

    82,124,368

     

    Accumulated deficit

     

    (3,206,437

    )

    (14,018,062

    )

    Total shareholders’ equity

     

    221,615,414

     

    70,836,318

     

    Total liabilities and shareholders’ equity

     

    $

    276,009,322

     

    $

    143,731,155

     

    See accompanying notes to consolidated financial statements.

    32




    PIONEER DRILLING COMPANY AND SUBSIDIARIES

    CONSOLIDATED STATEMENTS OF OPERATIONS

     
     Years Ended March 31,
     
     
     2003
     2002
     2001
     
    Contract drilling Revenues $80,183,486 $68,627,486 $50,344,909 
      
     
     
     
    Costs and expenses:          
     Contract drilling  70,823,310  46,145,364  41,687,893 
     Depreciation and amortization  11,960,387  8,426,082  3,737,533 
     General and administrative  2,232,390  2,855,274  1,116,727 
     Bad debt expense  110,000     
      
     
     
     
     Total operating costs and expenses  85,126,087  57,426,720  46,542,153 
      
     
     
     
    Earnings (loss) from operations  (4,942,601) 11,200,766  3,802,756 
      
     
     
     
    Other income (expense):          
     Interest expense  (2,698,529) (1,616,984) (888,863)
     Interest income  94,235  80,932  316,025 
     Other  37,614  72,096  71,559 
     Gain on sale of securities  203,887    536,486 
      
     
     
     
     Total other income (expense)  (2,362,793) (1,463,956) 35,207 
      
     
     
     
    Earnings (loss) before income taxes  (7,305,394) 9,736,810  3,837,963 
    Income tax (expense) benefit  2,219,776  (3,418,525) (1,135,174)
      
     
     
     
    Net earnings (loss)  (5,085,618) 6,318,285  2,702,789 
    Preferred stock dividend requirement    92,814  274,630 
      
     
     
     
    Net earnings (loss) applicable to common shareholders $(5,085,618)$6,225,471 $2,428,159 
      
     
     
     
    Earnings (loss) per common share—Basic $(0.31)$0.41 $0.22 
      
     
     
     
    Earnings (loss) per common share—Diluted $(0.31)$0.35 $0.19 
      
     
     
     
    Weighted average number of shares outstanding—Basic  16,163,098  15,112,272  11,137,171 
      
     
     
     
    Weighted average number of shares outstanding—Diluted  16,163,098  19,221,256  13,901,101 
      
     
     
     

     

     

    Years Ended March 31,

     

     

     

    2005

     

    2004

     

    2003

     

     

     

     

     

     

     

     

     

    Contract drilling revenues

     

    $

    185,246,448

     

    $

    107,875,533

     

    $

    80,183,486

     

     

     

     

     

     

     

     

     

    Costs and expenses:

     

     

     

     

     

     

     

    Contract drilling

     

    138,482,759

     

    88,504,102

     

    70,823,310

     

    Depreciation and amortization

     

    23,090,909

     

    16,160,494

     

    11,960,387

     

    General and administrative

     

    4,657,013

     

    2,772,730

     

    2,232,390

     

    Bad debt expense

     

    242,000

     

     

    110,000

     

     

     

     

     

     

     

     

     

    Total operating costs and expenses

     

    166,472,681

     

    107,437,326

     

    85,126,087

     

    Income (loss) from operations

     

    18,773,767

     

    438,207

     

    (4,942,601

    )

     

     

     

     

     

     

     

     

    Other income (expense):

     

     

     

     

     

     

     

    Interest expense

     

    (1,722,393

    )

    (2,807,822

    )

    (2,698,529

    )

    Interest income

     

    173,318

     

    101,584

     

    94,235

     

    Other

     

    37,267

     

    51,675

     

    37,614

     

    Loss from early extinguishment of debt

     

    (100,833

    )

     

    203,887

     

    Total other income (expense)

     

    (1,612,641

    )

    (2,654,563

    )

    (2,362,793

    )

     

     

     

     

     

     

     

     

    Income (loss) before income taxes

     

    17,161,126

     

    (2,216,356

    )

    (7,305,394

    )

    Income tax (expense) benefit

     

    (6,349,501

    )

    426,299

     

    2,219,776

     

     

     

     

     

     

     

     

     

    Net earnings (loss)

     

    $

    10,811,625

     

    $

    (1,790,057

    )

    $

    (5,085,618

    )

     

     

     

     

     

     

     

     

    Earnings (loss) per common share - Basic

     

    $

    0.31

     

    $

    (0.08

    )

    $

    (0.31

    )

     

     

     

     

     

     

     

     

    Earnings (loss) per common share - Diluted

     

    $

    0.30

     

    $

    (0.08

    )

    $

    (0.31

    )

     

     

     

     

     

     

     

     

    Weighted average number of shares outstanding - Basic

     

    34,543,695

     

    22,585,612

     

    16,163,098

     

     

     

     

     

     

     

     

     

    Weighted average number of shares outstanding - Diluted

     

    37,577,927

     

    22,585,612

     

    16,163,098

     

    See accompanying notes to consolidated financial statements.

    33




    PIONEER DRILLING COMPANY AND SUBSIDIARIES

    CONSOLIDATED STATEMENTS OF SHAREHOLDERS'SHAREHOLDERS’ EQUITY AND COMPREHENSIVE INCOME

     
     Shares
    Common

     Shares
    Preferred

     Amount
    Common

     Preferred
     Additional
    Paid In
    Capital

     Accumulated
    Deficit

     Accumulated
    Other
    Comprehensive
    Income

     Total Shareholders' Equity
     
    Balance as of March 31, 2000 7,274,684 584,615 $727,468 $3,799,994 $17,723,569 $(15,796,017)$328,478 $6,783,492 
    Comprehensive income:                       
     Net earnings          2,702,789    2,702,789 
     Net unrealized change in securities available for sale, net of tax of $56,750            (218,360) (218,360)
                         
     
    Total comprehensive income              2,484,429 
                         
     
    Issuance of common stock for:                       
     Sale, net of related expenses 3,678,161   367,816    7,632,184      8,000,000 
     Acquisition 341,576   34,158    734,387      768,545 
     Conversion of preferred 800,000 (400,000) 80,000  (800,000) 720,000       
     Exercise of options 51,500   5,150    59,776      64,926 
    Preferred stock dividend          (274,630)   (274,630)
      
     
     
     
     
     
     
     
     
    Balance as of March 31, 2001 12,145,921 184,615  1,214,592  2,999,994  26,869,916  (13,367,858) 110,118  17,826,762 
    Comprehensive income:                       
     Net earnings          6,318,285    6,318,285 
     Net unrealized change in securities 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 securities 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 5,333,333   533,334    18,809,167      19,342,501 
     Exercise of options and related income tax benefits 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 
      
     
     
     
     
     
     
     
     

     

     

     

     

     

     

     

     

     

     

    Accumulated

     

     

     

     

     

     

     

     

     

    Additional

     

     

     

    Other

     

    Total

     

     

     

    Shares

     

    Amount

     

    Paid In

     

    Accumulated

     

    Comprehensive

     

    Shareholders’

     

     

     

    Common

     

    Common

     

    Capital

     

    Deficit

     

    Income

     

    Equity

     

     

     

     

     

     

     

     

     

     

     

     

     

     

     

    Balance as of March 31, 2002

     

    15,922,459

     

    $

    1,592,245

     

    $

    38,783,731

     

    $

    (7,142,387

    )

    $

    109,416

     

    $

    33,343,005

     

    Comprehensive income:

     

     

     

     

     

     

     

     

     

     

     

     

     

    Net loss

     

     

     

     

    (5,085,618

    )

     

    (5,085,618

    )

    Net unrealized change in securites available for sale, net of tax of $56,366

     

     

     

     

     

    (109,416

    )

    (109,416

    )

    Total comprehensive loss

     

     

     

     

     

     

    (5,195,034

    )

    Issuance of common stock for:

     

     

     

     

     

     

     

     

     

     

     

     

     

    Sale, net of related expenses of $657,499

     

    5,333,333

     

    533,334

     

    18,809,167

     

     

     

    19,342,501

     

    Exercise of options and related tax benefits of $2,720

     

    445,000

     

    44,500

     

    137,290

     

     

     

    181,790

     

    Preferred stock dividend

     

     

     

     

     

     

     

    Balance as of March 31, 2003

     

    21,700,792

     

    2,170,079

     

    57,730,188

     

    (12,228,005

    )

     

    47,672,262

     

    Comprehensive income:

     

     

     

     

     

     

     

     

     

     

     

     

     

    Net loss

     

     

     

     

    (1,790,057

    )

     

    (1,790,057

    )

    Total comprehensive loss

     

     

     

     

     

     

    (1,790,057

    )

    Issuance of common stock for:

     

     

     

     

     

     

     

     

     

     

     

     

     

    Sale, net of related expenses of $1,654,753

     

    4,400,000

     

    440,000

     

    21,665,247

     

     

     

    22,105,247

     

    Equipment acquisitions

     

    477,000

     

    47,700

     

    2,074,950

     

     

     

    2,122,650

     

    Exercise of options and related income tax benefits of $52,423

     

    722,334

     

    72,233

     

    653,983

     

     

     

    726,216

     

    Balance as of March 31, 2004

     

    27,300,126

     

    2,730,012

     

    82,124,368

     

    (14,018,062

    )

     

    70,836,318

     

    Comprehensive income:

     

     

     

     

     

     

     

     

     

     

     

     

     

    Net earnings

     

     

     

     

    10,811,625

     

     

    10,811,625

     

    Total comprehensive income

     

     

     

     

     

     

    10,811,625

     

    Issuance of common stock for:

     

     

     

     

     

     

     

     

     

     

     

     

     

    Sale, net of related expenses of $5,807,193

     

    11,545,000

     

    1,154,500

     

    109,854,558

     

     

     

    111,009,058

     

    Debenture conversion

     

    6,496,519

     

    649,652

     

    27,350,348

     

     

     

    28,000,000

     

    Exercise of options and related income tax benefits of $204,964

     

    551,666

     

    55,167

     

    903,246

     

     

     

    958,413

     

    Balance as of March 31, 2005

     

    45,893,311

     

    $

    4,589,331

     

    $

    220,232,520

     

    $

    (3,206,437

    )

    $

     

    $

    221,615,414

     

    See accompanying notes to consolidated financial statements.

    34




    PIONEER DRILLING COMPANY AND SUBSIDIARIES
    CONSOLIDATED

    CONSOLIDATED STATEMENTS OF CASH FLOWS

     
     Years Ended March 31,
     
     
     2003
     2002
     2001
     
    Cash flows from operating activities:          
     Net earnings (loss) $(5,085,618)$6,318,285 $2,702,789 
      Adjustments to reconcile net earnings (loss) to net cash provided by operating activities:          
      Depreciation and amortization  11,960,387  8,426,082  3,737,533 
      Allowance for doubtful accounts  110,000     
      Gain on sale of securities  (203,887)   (536,486)
      Loss (gain) on sale of properties and equipment  279,054  (2,237)  
      Change in deferred income taxes  (1,511,744) 1,991,458  965,008 
      Changes in current assets and liabilities:          
       Receivables  242,126  (4,172,470) (3,157,961)
       Prepaid expenses  (279,440) (322,471) 177,676 
       Accounts payable  7,699,417  (1,099,813) 3,642,048 
       Federal income taxes  435,168  (930,266) 50,198 
       Accrued expenses  743,814  836,321  853,045 
      
     
     
     
     Net cash provided by operating activities  14,389,277  11,044,889  8,433,850 
      
     
     
     
    Cash flows from financing activities:          
     Proceeds from notes payable  23,573,501  19,556,286  15,547,477 
     Proceeds from subordinated debenture  10,000,000  18,000,000  9,000,000 
     Increase in other assets  (253,698) (195,000) (46,322)
     Payment of preferred dividends    (859,395) (160,614)
     Proceeds from exercise of options and warrants  181,790  243,474  64,926 
     Proceeds from common stock, net  19,342,501  9,048,000  8,000,000 
     Payments of debt  (18,714,311) (27,026,538) (6,336,803)
      
     
     
     
    Net cash provided by financing activities  34,129,783  18,766,827  26,068,664 
      
     
     
     
    Cash flows from investing activities:          
     Purchases of property and equipment:          
      Acquisitions      (22,806,456)
      Other  (33,588,972) (27,597,265) (12,165,178)
     Proceeds from sale of marketable securities  375,414    1,039,597 
     Proceeds from sale of property and equipment  314,366  675,660   
      
     
     
     
    Net cash used in investing activities  (32,899,192) (26,921,605) (33,932,037)
      
     
     
     
    Net increase in cash and cash equivalents  15,619,868  2,890,111  570,477 
    Beginning cash and cash equivalents  5,383,045  2,492,934  1,922,457 
      
     
     
     
    Ending cash and cash equivalents $21,002,913 $5,383,045 $2,492,934 
      
     
     
     
    Supplementary disclosure:          
     Interest paid $2,785,177 $1,046,943 $760,821 
     Income taxes paid (refunded)  (1,143,200) 2,342,006  140,655 
     Dividends accrued    92,814  274,630 
     Conversion of preferred stock    2,999,994  800,000 
     Pioneer Drilling Co. acquisition:          
      Common Stock issued      768,545 
      Debt assumed      1,673,533 
      Deferred taxes assumed      4,214,195 

     

     

    Years Ended March 31,

     

     

     

    2005

     

    2004

     

    2003

     

    Cash flows from operating activities:

     

     

     

     

     

     

     

    Net earnings (loss)

     

    $

    10,811,627

     

    $

    (1,790,057

    )

    $

    (5,085,618

    )

    Adjustments to reconcile net earnings (loss) to net cash provided by operating activities:

     

     

     

     

     

     

     

    Depreciation and amortization

     

    23,090,909

     

    16,160,494

     

    11,960,387

     

    Allowance for doubtful accounts

     

    242,000

     

     

    110,000

     

    Gain on sale of securities

     

     

     

    (203,887

    )

    Loss on dispositions of property and equipment

     

    696,345

     

    816,104

     

    279,054

     

    Change in deferred income taxes

     

    5,987,991

     

    119,038

     

    (1,511,744

    )

    Changes in current assets and liabilities:

     

     

     

     

     

     

     

    Receivables

     

    (11,682,035

    )

    (11,103,862

    )

    242,126

     

    Prepaid expenses

     

    (540,507

    )

    (422,150

    )

    (279,440

    )

    Accounts payable

     

    2,350,658

     

    (935,597

    )

    7,699,417

     

    Income tax payable

     

    195,949

     

     

     

    Prepaid drilling contracts

     

    172,750

     

     

     

    Federal income taxes

     

     

    444,900

     

    435,168

     

    Accrued expenses

     

    2,462,523

     

    1,576,096

     

    743,814

     

    Net cash provided by operating activities

     

    33,788,210

     

    4,864,966

     

    14,389,277

     

     

     

     

     

     

     

     

     

    Cash flows from financing activities:

     

     

     

     

     

     

     

    Proceeds from notes payable

     

    41,354,367

     

    4,110,019

     

    23,573,501

     

    Proceeds from subordinated debenture

     

     

     

    10,000,000

     

    Increase in other assets

     

    (123,263

    )

    (40,000

    )

    (253,698

    )

    Proceeds from exercise of options

     

    958,412

     

    673,794

     

    181,790

     

    Proceeds from common stock, net of offering cost of $5,807,193 in 2005, of $1,654,753 in 2004 and $657,499 in 2003

     

    111,009,058

     

    22,105,247

     

    19,342,501

     

    Payments of debt

     

    (43,809,329

    )

    (4,048,744

    )

    (18,714,311

    )

    Net cash provided by financing activities

     

    109,389,245

     

    22,800,316

     

    34,129,783

     

    Cash flows from investing activities:

     

     

     

     

     

     

     

    Business acquisitions

     

    (35,200,000

    )

    (14,500,000

    )

     

    Purchases of property and equipment

     

    (45,188,484

    )

    (28,222,094

    )

    (33,588,972

    )

    Purchase of marketable securities, net

     

    (17,525,000

    )

    (25,400,000

    )

    (19,925,000

    )

    Proceeds from sale of marketable securities

     

    21,075,000

     

    23,500,000

     

    21,500,414

     

    Proceeds from sale of property and equipment

     

    1,518,549

     

    419,658

     

    314,366

     

    Net cash used in investing activities

     

    (75,319,935

    )

    (44,202,436

    )

    (31,699,192

    )

    Net increase (decrease) in cash and cash equivalents

     

    67,857,520

     

    (16,537,154

    )

    16,819,868

     

    Beginning cash and cash equivalents

     

    1,815,759

     

    18,352,913

     

    1,533,045

     

    Ending cash and cash equivalents

     

    $

    69,673,279

     

    $

    1,815,759

     

    $

    18,352,913

     

    Supplementary disclosure:

     

     

     

     

     

     

     

    Interest paid

     

    $

    2,407,193

     

    $

    2,821,041

     

    $

    2,785,177

     

    Income tax refunded

     

    (30,000

    )

    (990,237

    )

    (1,143,200

    )

    Debenture conversion - common stock issued

     

    28,000,000

     

     

     

    Acquisition - common stock issued

     

     

    2,122,650

     

     

    Tax benefit from exercise of nonqualified options

     

    204,964

     

    52,423

     

    2,720

     

    See accompanying notes to consolidated financial statements.

    35




    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 select oil and natural gas exploration and production companiesregions in the South Texas and East Texas markets.United States.  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'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"(“SFAS”) No. 109, "Accounting“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“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 years 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.

    36



    Stock-based Compensation

     

    We have adopted SFAS No. 123, "Accounting“Accounting for Stock-Based Compensation."  SFAS No. 123 allows a company to adopt a fair value based method of accounting for a stock-based employee compensation plan or to continue to use the intrinsic value based method of accounting prescribed by Accounting Principles Board ("APB"(“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 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,
     
     
     2003
     2002
     2001
     
    Net earnings (loss)—as reported $(5,085,618)$6,318,285 $2,702,789 
    Deduct: Total stock-based employee compensation expense determined under fair value based method for all awards net of related tax effect  (385,671) (582,258) (359,224)
      
     
     
     
    Net earnings (loss)—pro forma $(5,471,289)$5,736,027 $2,343,565 
      
     
     
     
    Net earnings (loss) per share—as reported—basic $(0.31)$0.41 $0.22 
    Net earnings (loss) per share—as reported—diluted  (0.31) 0.35  0.19 
    Net earnings (loss) per share—pro forma—basic  (0.34) 0.38  0.19 
    Net earnings (loss) per share—pro forma—diluted  (0.34) 0.32  0.17 
    Weighted-average fair value of options granted during the year  3.50  3.11  2.29 

     We estimate the fair value of each option grant on the date of grant using a Black-Scholes options-pricing model. This model assumed expected volatility of 69%, 90% and 117% and weighted average risk-free interest rates of 3.2%, 4.5% and 5.4% for grants in 2003, 2002 and 2001, respectively, and an expected life of five years.

     

     

    Years Ended March 31,

     

     

     

    2005

     

    2004

     

    2003

     

     

     

     

     

     

     

     

     

    Net earnings (loss)-as reported

     

    $

    10,811,625

     

    $

    (1,790,057

    )

    $

    (5,085,618

    )

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

     

    (1,175,191

    )

    (662,933

    )

    (385,671

    )

    Net earnings (loss)-pro forma

     

    $

    9,636,434

     

    $

    (2,452,990

    )

    $

    (5,471,289

    )

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

     

    $

    0.31

     

    $

    (0.08

    )

    $

    (0.31

    )

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

     

    $

    0.30

     

    $

    (0.08

    )

    $

    (0.31

    )

    Net earnings (loss) per share-pro forma-basic

     

    $

    0.28

     

    $

    (0.11

    )

    $

    (0.34

    )

    Net earnings (loss) per share-pro forma-diluted

     

    $

    0.27

     

    $

    (0.11

    )

    $

    (0.34

    )

    Weighted-average fair value of options  granted during the year

     

    $

    8.85

     

    $

    4.46

     

    $

    3.50

     

     

     

    2005

     

    2004

     

    2003

     

    Expected volatility

     

    86%

     

    94%

     

    69%

     

    Weighted-average risk-free interest rates

     

    3.7%

     

    3.3%

     

    3.2%

     

    Expected life in years

     

    5

     

    5

     

    5

     

    Options granted

     

    510,000

     

    1,000,000

     

    65,000

     

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

    Revenue and Cost Recognition

     

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

     

    Our management has determined that it is appropriate to use the percentage-of-completion method toas defined in SOP 81-1to recognize revenue on our turnkey and footage contracts.  Although our turnkey and footage contracts do not have express terms that provide us with rights to receive payment for the work that we perform prior to drilling wells to the agreed on depth, we use this method because, as provided in applicable accounting literature, we believe we achieve a continuous sale for our work-in-progress and believe, under applicable state law, we ultimately could recover the fair value of our work-in-progress even in the event we were unable to drill to the agreed on depth in breach of the applicable contract.  However, ultimate recovery of that value, in the event we were unable to drill to the agreed on depth in breach of the contract, would be subject to negotiations with the customer and the possibility of litigation.

    If a customer defaults on its payment obligationsobligation 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 costs incurred to drill a wellwork-in-progress under a turnkey or footage contract.



     

    37



    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.  CostsContract 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. At March 31, 2003, we accrued an estimated loss of $227,000 on one of our turnkey contracts in progress.

     

    The asset "contract“contract drilling in progress"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 20032005 and 2002,2004, we capitalized $96,079$86,819 and $328,285,$106,395, respectively, of interest costs incurred during the construction periods of certain drilling equipment.  At March 31, 2005 and 2004, costs incurred on rigs under construction were approximately $3,300,000 and $2,800,000, respectively.

     

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

     In April 2003,

    Cash and Cash Equivalents

    We maintain cash accounts at several financial institutions.  These account balances are insured by the Federal Deposit Insurance Corporation up to $100,000.  At March 31, 2005, we sold a rig yard in Kenedy, Texas which we were no longer using. We realized proceeds from the salehad cash account balances of approximately $115,000 and recognized a gain of approximately $25,000.

    Cash Equivalents$1,200,000 exceeding the $100,000 insurance threshold.

     

    For purposes of the statements of cash flows, we consider all highly liquid debt instruments purchased with a maturity of three months or less to be cash equivalents.  Cash equivalents consist of investments in corporate and government money market accounts and seven day tax exempt municipal preferred securities.accounts.  Cash equivalents at March 31, 20032005 and 20022004 were $1,060,000$65,046,000 and $4,435,000,$1,568,000, respectively.

    InvestmentMarketable Securities

     We carry our available-for-sale investment securities at their fair values. Investment

    Marketable securities consist of common stock. Unrealized holdingauction 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 andor losses net ofrelating 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 $165,7822005 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.  Past due balances overBalances 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-sheetoff-balance sheet credit exposure related to our customers.  At March 31, 20032005 and 2004 our allowance for doubtful accounts was $352,000 and $110,000. No allowance for doubtful accounts was necessary at March 31, 2002.

    38



    Intangible and Other Assets

     Other

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

    Derivative Instruments and Hedging Activities

     

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

    Related Party Transactions

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

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

     

     

    2005

     

    2004

     

    2003

     

    R&B Answering Service

     

     

     

     

     

     

     

    Purchases

     

    $

    18,218

     

    $

    13,526

     

    $

    10,465

     

    Payments

     

    $

    17,112

     

    $

    12,544

     

    $

    9,678

     

    Frontier Services, Inc.

     

     

     

     

     

     

     

    Purchases

     

    $

    81,254

     

    $

    118,660

     

    $

    130,513

     

    Payments

     

    $

    93,709

     

    $

    136,818

     

    $

    107,719

     

    Recently Issued Accounting Standards

     In June 2001, the Financial Accounting Standards Board issued Statement of Financial Accounting Standards ("SFAS") No. 143, "Accounting for Asset Retirement Obligations," which addresses financial accounting and reporting for obligations associated with the retirement of tangible long-lived assets and the associated asset retirement costs. The standard applies to legal obligations associated with the retirement of long-lived assets that result from the acquisition, construction, development and/or normal use of the asset. We are required to adopt the provisions of SFAS No. 143 beginning April 1, 2003. In that connection, we must identify all our legal obligations relating to asset retirements and determine the fair value of these obligations on the date of adoption. We do not expect the adoption of SFAS No. 143 to have a material effect on our financial position or results of operations.

    In December 2002,2004, the FASB issued SFAS No. 148, "Accounting123 (revised 2004), Share-Based Payment.  SFAS No. 123R is a revision of FASB SFAS No. 123, Accounting for Stock-Based Compensation—Transition Compensation and Disclosure,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 amendment of FASB Statement No. 123." This Statement amends FASB Statement No. 123, "Accountingentity exchanges its equity instruments for Stock-Based Compensation," to provide alternative methods of transitiongoods or services.  It also addresses transactions in which an entity incurs liabilities in exchange for a voluntary change togoods or services that are based on the fair value method 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 stock-basedtransactions in which an entity obtains employee compensation. In addition, this Statement amendsservices in share-based payment transactions.  SFAS No. 123R requires a public entity to measure the disclosure requirementscost of Statement No. 123 to require prominent disclosuresemployee services received in both annual and interim financial statements. Certainexchange for an award of equity instruments based on the grant-date fair value of the disclosure modificationsaward (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 requiredeffective for public entities that do not file as small business issuers as of the beginning of the first annual reporting period that begins after June 15, 2005.  We are currently evaluating the negative impact SFAS No. 123R will have on our financial position and results of operations in fiscal years ending after December 15, 2002 and are included inyear 2007.  The negative impact will be created due to the notes to these consolidated financial statements.



    Reclassificationsfact that we previously issued employee stock options for which no expense has been recognized,  as those options will not be fully vested as of the effective date of SFAS No. 123R.

     In accordance with Emerging Issues Task Force issue No. 01-14 "Income Statement Characterization of Reimbursements Received for Out-of-Pocket Expenses Incurred," we have revised the presentation of reimbursements received for certain expenses in the periods presented. These reimbursements are now included in contract drilling revenues in the consolidated statements of operations versus previously being recorded net of the incurred expense in contract drilling costs. These reclassifications had no effect on net income or cash flows for any of the three years ended March 31, 2003.

    Reclassifications

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

    39



    2.Acquisitions

     

    On August 21, 2000,November 30, 2004, we acquired all the outstanding stockcontract drilling assets and a 4.7-acre rig storage and maintenance yard of PioneerWolverine Drilling, Co.Inc., a Corpus Christi, Texas-based land drilling contractor. Pioneer Drilling Co.'s assetscontractor based in Kenmare, North Dakota.  The equipment included fourseven mechanical land drilling rigs and associated machineryrelated assets, including trucks, trailers, vehicles, spare drill pipe and yard equipment.  Pioneer Drilling Co. owned threeWe paid $28,000,000 in cash for these assets and non-competition agreements with the two owners of its rigs and leased the fourth rig. The consideration we paid for theWolverine.  We funded this acquisition after giving effect to a purchase price adjustment, was $11,500,000, consistingwith $28,000,000 of a cash payment of $10,731,456, which we financed with long-termbank debt as described in Note 3, and the issuance of 341,576 restricted shares of our common stock at $2.25 per share.note 3.  This purchase was accounted for as thean acquisition of a business, and we have included the results of operations of Pioneer Drilling Co. in our statement of operations since the date of acquisition. We allocated the purchase price plus assumed liabilities and deferred tax liability of $4,214,195 to working capital and property and equipment based on their relative fair values at the date of acquisition.

            On March 30, 2001, we acquired all the contract drilling equipment of Mustang Drilling, Ltd., a land drilling contractor based in Henderson, Texas. The equipment included four land drilling rigs and associated yard equipment. We paid $12,000,000 in cash for these assets. We financed this acquisition with $3,000,000operation of the bank debt and the $9,000,000 subordinated debt described in Note 8. This purchase was accounted for as the acquisition of aacquired business and we have included the results of its operations of in our statement of operations since the date of acquisition.  We allocated the purchase price to property and equipment and related assets, including the non-competition agreements and other intangibles, based on their relative fair values at the date of acquisition.

     

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

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

     

     

    Wolverine

     

    Allen

     

    Total

     

    Assets acquired:

     

     

     

     

     

     

     

    Drilling equipment

     

    $

    27,620,214

     

    $

    7,057,500

     

    $

    34,677,714

     

    Vehicles

     

    214,786

     

    230,000

     

    444,786

     

    Buildings

     

    30,000

     

    260,000

     

    290,000

     

    Land

     

    20,000

     

    40,000

     

    60,000

     

    Intangibles, primarily non-compete agreements

     

    115,000

     

    112,500

     

    227,500

     

     

     

    $

    28,000,000

     

    $

    7,700,000

     

    $

    35,700,000

     

    Less non-compete obilgation

     

     

    (500,000

    )

    (500,000

    )

     

     

    $

    28,000,000

     

    $

    7,200,000

     

    $

    35,200,000

     

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

     

     

    Pro Forma
    Years Ended March 31,

     

     

     

    2005

     

    2004

     

    Total revenues

     

    $

    208,394,551

     

    $

    132,287,140

     

    Net earnings (loss)

     

    $

    11,943,137

     

    $

    (2,100,116

    )

    Earnings (loss) per common share:

     

     

     

     

     

    Basic

     

    $

    0.35

     

    $

    (0.09

    )

    Diluted

     

    $

    0.33

     

    $

    (0.09

    )

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

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

    40




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

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

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

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

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

     

    Our long-term debt is described below:

     
     March 31,
     
     
     2003
     2002
     
    Convertible subordinated debentures due July 2007 at 6.75% $28,000,000 $18,000,000 

    Note payable, secured by drilling equipment, due in monthly payments of $172,619 beginning August 1, 2003 plus interest at a floating rate equal to the 3 month LIBOR rate plus 385 basis points, due December 2007

     

     

    14,500,000

     

     


     

    Note payable, secured by drilling equipment, due in monthly payments of $107,143 plus interest at prime (4.25% at March 31, 2003) plus 1.00%, due August 2004

     

     

    5,677,889

     

     

    6,963,603

     

    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

     

     

    87,897

     

     

    92,201

     

    Note payable, secured by drilling equipment, land and improvements, due in monthly payments of $50,585, including interest at prime plus 1%, due November 2007 (paid off December 2002)

     

     


     

     

    2,483,411

     

    Note payable to bank, secured by land and improvements, due in monthly payments of $1,900 including interest at the bank's prime rate plus 0.5% due in September 2005 (paid off March 2003)

     

     


     

     

    52,249

     

    Notes payable, secured by vehicles, due in monthly payments of $2,150 including interest, due through December 2004 (paid off March 2003)

     

     


     

     

    50,006

     

    Note payable to seller, secured by drilling equipment, due in monthly installments of $5,000 plus interest at 10%, due June 2002

     

     


     

     

    25,000

     
      
     
     
       48,265,786  27,666,470 

    Less current installments

     

     

    (2,671,269

    )

     

    (1,836,860

    )
      
     
     
      $45,594,517 $25,829,610 
      
     
     

     

     

     

    March 31,

     

     

     

    2005

     

    2004

     

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

     

    $

    18,077,778

     

    $

     

     

     

     

     

     

     

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

     

     

    28,000,000

     

     

     

     

     

     

     

    Note payable to Merrill Lynch Capital, secured by drilling equipment, due in monthly payments of $172,619 plus interest at a floating rate equal to the 3-month LIBOR rate plus 385 basis points, remaining balance due December 2007 (2)

     

     

    13,119,048

     

     

     

     

     

     

     

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

     

     

    4,392,174

     

     

     

     

     

     

     

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

     

     

    3,000,000

     

     

     

    18,077,778

     

    48,511,222

     

     

     

     

     

     

     

    Less current installments

     

    (4,666,667

    )

    (3,724,302

    )

     

     

    $

    13,411,111

     

    $

    44,786,920

     


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

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

    41



    Long-term debt maturing each year subsequent to March 31, 20032005 is as follows:

    Year Ended March 31,

      
    2004 $2,671,269
    2005  6,468,524
    2006  2,076,690
    2007  2,077,054
    2008  34,910,777
    2009 and thereafter  61,472

     

    Year Ended
    March 31,

     

     

     

    2006

     

    $

    4,666,667

     

    2007

     

    4,666,667

     

    2008

     

    8,744,444

     

    2009

     

     

    2010

     

     

    2010 and thereafter

     

     

    On October 9, 2001, we issued a 6.75% five-year $18,000,000 convertible subordinated debenture, Series A, to WEDGE Energy Services, L.L.C. ("WEDGE"(“WEDGE”). The debenture was convertible into 4,500,000 shares of common stock at $4.00 per share.  We used approximately $9,000,000 of the proceeds to complete the construction of two drilling rigs.  Approximately $6,000,000 was used to reduce a $12,000,000 credit facility.  The balance of the proceeds was used for drilling equipment and working capital. On July 3, 2002, we issued an additional $10,000,000 of 6.75% convertible subordinated debt to WEDGE with an effective conversion rate of $5.00 per share.  The transaction was effected by



    an agreement between Pioneer and WEDGE under which WEDGE agreed to provide the additional $10,000,000 in financing and to cancel the previously issued debenture in the principal amount of $18,000,000 in exchange for $28,000,000 in new 6.75% convertible subordinated debentures.  The new debentures arewas convertible into 6,500,0006,496,519 shares of common stock at $4.31 per share, which resulted from a pro rata blending of the $5.00 conversion rate of the new $10,000,000 financing and the $4.00 conversion rate of the $18,000,000 debenture being cancelled.  WEDGE funded $7,000,000 of the $10,000,000 on July 3, 2002 and $2,000,000 on July 29, 2002.   William H. White, onea former Director of our DirectorsCompany and the former President of WEDGE, purchased the remaining $1,000,000 on July 29, 2002.  Unlike the cancelled debenture, which was not redeemable by Pioneer, the new debentures arewere redeemable at a scheduled premium.  We used $7,000,000 of the proceeds to pay down bank debt and $3,000,000 for the purchase of drilling equipment.  On August 11, 2004, these debentures were converted in accordance with their terms into 6,496,519 shares of our common stock.

     We have

    On October 29, 2004, we entered into a $1,000,000$47,000,000 credit facility with a group of lenders consisting of a $7,000,000 revolving line and letter of credit available fromfacility and a bank. Any borrowings$40,000,000 acquisition facility for the acquisition of drilling rigs, drilling rig transportation equipment and associated equipment. Frost National Bank is the administrative agent and lead arranger under this linethe new credit facility, and the lenders include Frost National Bank, the Bank of Scotland and Zions First National Bank. Borrowings under the new credit are secured by our trade receivables andfacility bear interest at a rate ofequal to Frost National Bank’s prime (4.25%rate (5.75% at March 31, 2003) plus 1.0%. 2005) and are secured by most of our assets, including all our drilling rigs and associated equipment and receivables. We borrowed the entire $40,000,000 available under the acquisition facility and we have used approximately $2,825,000 of availability under the revolving line and letter of credit facility through the issuance of letters of credit in the ordinary course of business. On March 29, 2005, we repaid $20,000,000 of the borrowings under the acquisition facility.  On May 11, 2005, the lenders amended the acquisition facility to provide us with the ability to again draw the $20,000,000 for future acquisitions.  The remaining approximately $20,0000,000 and $4,175,000 of availability under the acquisition facility and the revolving line and letter of credit facility, respectively, should remain available to us until those facilities mature in October 2006 and October 2005, respectively.

    The sum of (1) the draws under this line and (2) the amount of all outstanding letters of credit issued by the bank for our account under the revolving line and letter of credit facility portion of our new credit facility are limited to 75% of our eligible accounts receivable.receivable, not to exceed $7,000,000. Therefore, if 75% of our eligible accounts receivable iswas less than $1,000,000 plus any outstanding letters of credit issued by the bank on our behalf,$7,000,000, our ability to draw under this line would be reduced. At March 31, 2003,2005, we had no outstanding advances under this line of credit, outstanding letters of credit were $1,450,000$2,825,000 and 75% of our eligible accounts receivable were $4,299,179.was approximately $19,084,000. The letters of credit are issued to two workers'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 lenderlenders will be required to fund any draws under these letters of credit. The termination date of the revolving line and letter of credit facility portion of our new credit facility is October 28, 2005.

     

    At March 31, 2003,2005, we were in compliance with all covenants applicable to our outstanding debt.  Those covenants include, among others, the maintenance of ratios ofa debt to net worth,total capitalization ratio of not greater than ..3 to 1, a fixed charged coverage ratio of not less than 1.5 to 1, an operating leverage cash flowratio of less than 3 to 1, restrict us from paying dividends, restrict us from the sale of assets not permitted by the credit facility and fixed cost coverage. The covenants also restrict us from the paymentincurrence of dividends on common stock.additional indebtedness in excess of $3,000,000 not already allowed by the credit facility.

     Current notes

    Notes payable at March 31, 20032005 consists of a $587,177$681,975 insurance premium note due in monthly installments of $137,400, including interest, through August 26, 20032005, which bears interest at the rate of 2.8%3.15% per year.

    42



    4.Leases

     

    We are obligated under capital leases covering several trucks that expire at various dates through January 2007.  At March 31, 20032005 and 2002,2004, the gross amount of transportation equipment and related amortization recorded under capital leases were as follows:

     
     2003
     2002
    Transportation equipment $647,822 $519,363
    Less accumulated amortization  248,070  136,435
      
     
      $399,752 $382,928
      
     

     

     

     

    March 31,

     

     

     

    2005

     

    2004

     

    Transportation equipment

     

    $

    405,320

     

    $

    665,195

     

    Less accumulated amortization

     

    299,861

     

    413,797

     

     

     

    $

    105,459

     

    $

    251,398

     

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

     In February 2002, we renewed for two years an operating

    We lease on one of our drilling rigs. The lease renewal includes an option to acquire the rig for $4,000,000, its estimated market value on the renewal date of the lease, which we can exercise between January 1, 2004 and February 1, 2004. If we exercise the option, approximately 50% of the rentals we pay during the lease term can be applied to the purchase price. We also lease real estate in Henderson, Texas and various office equipment under noncancelablenon-cancelable operating leases expiring through 2006.2008 and real estate as follows:

     

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

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

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

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

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

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

    Rent expense under these operating leases for the years ended March 31, 2005, 2004 and 2003 2002was $102,077, $278,746 and 2001 was $344,752, $208,150respectively.

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

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

    43




     

    Future lease obligations, including our new corporate headquarters, and minimum capital lease payments as of March 31, 20032005 were as follows:

    Year Ended March 31,

     Operating
    Leases

     Capital
    Leases

     
     2004 $358,008 $170,910 
     2005  58,008  164,997 
     2006  56,010  70,446 
     2007  2,712  34,626 
      
     
     
    Total minimum lease payments $474,738 $440,979 
      
        
    Less amounts representing interest (at rates ranging from 5.8% to 9.5%)     (40,237)
         
     
    Present value of net minimum capital lease payments     400,742 
    Less current installments of capital lease obligations     (140,717)
         
     
    Capital lease obligations, excluding current installments    $260,025 
         
     

    Year Ended

     

    Operating

     

    Capital

     

    March 31,

     

    Leases

     

    Leases

     

     

    2006

     

    $

    224,873

     

    $

    70,446

     

     

    2007

     

    173,935

     

    34,106

     

     

    2008

     

    217,492

     

     

     

    2009

     

    234,291

     

     

     

    2010

     

    237,905

     

     

     

    Thereafter

     

    903,438

     

     

    Total minimum lease payments

     

    $

    1,991,934

     

    $

    104,552

     

     

     

     

     

     

     

    Less amounts representing interest (at rates ranging from 5.7% to 8.4%)

     

     

     

    (4,287

    )

    Present value of net minimum capital lease payments

     

     

     

    100,265

     

    Less current installments of capital lease obligations

     

     

     

    (66,359

    )

    Capital lease obligations, excluding current installments

     

     

     

    $

    33,906

     

    5.Income Taxes

     

    Our provision for income taxes consistedconsists of the following:

     
     Years Ended March 31,
     
     2003
     2002
     2001
    Current tax—federal $(708,032)$1,427,067 $49,593
    Current tax—state      120,573
    Deferred tax—federal  (1,511,744) 1,991,458  965,008
      
     
     
    Income tax expense (benefit) $(2,219,776)$3,418,525 $1,135,174
      
     
     

     

     

     

    Years Ended March 31,

     

     

     

    2005

     

    2004

     

    2003

     

     

     

     

     

     

     

     

     

    Current tax - state

     

    $

    56,400

     

    $

     

    $

     

    Current tax - federal

     

    335,109

     

     

    (708,032

    )

    Deferred tax - state

     

    55,164

     

     

     

    Deferred tax - federal

     

    5,902,828

     

    (426,299

    )

    (1,511,744

    )

    Income tax expense (benefit)

     

    $

    6,349,501

     

    $

    (426,299

    )

    $

    (2,219,776

    )

    In fiscal years 2003, 20022005, 2004 and 2001,2003, our expected tax, which we compute by applying the federal statutory rate of  34% to income (loss) before income taxes, differs from our income tax expense as follows:

     
     Years Ended March 31,
     
     
     2003
     2002
     2001
     
    Expected tax expense (benefit) $(2,483,834)$3,310,515 $1,304,907 
    Net operating loss carry forwards and valuation allowances      (335,422)
    Non taxable interest income  (10,400) (9,429)  
    Club dues, meals and entertainment  10,443  10,115  34,729 
    State taxes      79,578 
    Other  264,015  107,324  51,382 
      
     
     
     
      $(2,219,776)$3,418,525 $1,135,174 
      
     
     
     

     

     

    Years Ended March 31,

     

     

     

    2005

     

    2004

     

    2003

     

     

     

     

     

     

     

     

     

    Expected tax expense (benefit)

     

    $

    5,834,783

     

    $

    (753,561

    )

    $

    (2,483,834

    )

    Non taxable interest income

     

     

     

    (10,400

    )

    Club dues, meals and entertainment

     

    24,050

     

    13,941

     

    10,443

     

    State income taxes

     

    92,388

     

     

     

    Reimbursement of food costs for rig employees

     

    396,968

     

    314,622

     

    275,338

     

    Other

     

    1,312

     

    (1,301

    )

    (11,323

    )

     

     

    $

    6,349,501

     

    $

    (426,299

    )

    $

    (2,219,776

    )

    44



    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,
     
     2003
     2002
    Deferred tax assets:      
     Workers compensation and vacation expense accruals $94,972 $32,795
     Bad debt expense  37,400  
     Net operating loss carryforwards  5,105,730  
     Alternative minimum tax credit  181,770  
     Other  48,619  
      
     
     Total deferred tax assets  5,468,491  32,795
      
     
    Deferred tax liabilities:      
     Property and equipment, principally due to differences in depreciation  11,127,408  7,203,456
     Unrealized gain on securities available for sale    56,366
      
     
     Total deferred tax liabilities  11,127,408  7,259,822
      
     
     Net deferred tax liabilities $5,658,917 $7,227,027
      
     

     

     

     

    March 31,

     

     

     

    2005

     

    2004

     

     

     

     

     

     

     

    Deferred tax assets:

     

     

     

     

     

    Vacation expense accruals

     

    $

    71,446

     

    $

    37,233

     

    Workers compensation and health insurance accruals

     

    378,423

     

    187,752

     

    Bad debt expense

     

    119,680

     

    37,400

     

    Net operating loss carryforwards

     

    4,329,933

     

    7,825,126

     

    Alternative minimum tax credit

     

    311,915

     

    181,770

     

    Loss accrual on turnkey contracts

     

     

    23,000

     

    Total deferred tax assets

     

    5,211,397

     

    8,292,281

     

    Deferred tax liabilities:

     

     

     

     

     

    Property and equipment, principally due to differences in depreciation

     

    16,924,919

     

    14,017,813

     

    Total deferred tax liabilities

     

    16,924,919

     

    14,017,813

     

    Net deferred tax liabilities

     

    $

    11,713,522

     

    $

    5,725,532

     

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

     

    At March 31, 2003,2005, we had net operating loss carryforwards for federal income tax purposes of approximately $15,000,000$16,500,000, which will expire if not utilized by March 31, 2023.as of the end of our fiscal years ending as follows:

    Year

     

    Amount

     

    2023

     

    $

    6,600,000

     

    2024

     

    9,900,000

     

    6.Fair Value of Financial Instruments

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

     

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

      Long-term debt:

     

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

    45



    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,
     
     2003
     2002
     2001
    Basic         
    Net earnings (loss) $(5,085,618)$6,318,285 $2,702,789
    Less: Preferred stock dividends    92,814  274,630
      
     
     
    Earnings (loss) applicable to common shareholders $(5,085,618)$6,225,471 $2,428,159
      
     
     
    Weighted average shares  16,163,098  15,112,272  11,137,171
      
     
     
    Earning (loss) per share $(0.31)$0.41 $0.22
      
     
     

    Diluted

     

     

     

     

     

     

     

     

     
    Earnings (loss) applicable to common shareholders $(5,085,618)$6,225,471 $2,428,159
    Effect of dilutive securities:         
     Convertible subordinated debenture    385,358  
     Preferred stock    92,814  274,630
      
     
     
     Earnings (loss) available to common shareholders and assumed conversion $(5,085,618)$6,703,643 $2,702,789
      
     
     
    Weighted average shares:         
     Outstanding  16,163,098  15,112,272  11,137,171
     Options    1,500,589  1,771,864
     Convertible subordinated debenture    2,145,205  
     Preferred stock     463,190  992,066
      
     
     
       16,163,098  19,221,256  13,901,101
      
     
     
    Earnings (loss) per share $(0.31)$0.35 $0.19
      
     
     

     

     

     

    Years Ended March 31,

     

     

     

    2005

     

    2004

     

    2003

     

     

     

     

     

     

     

     

     

    Basic

     

     

     

     

     

     

     

    Net earnings (loss)

     

    $

    10,811,625

     

    $

    (1,790,057

    )

    $

    (5,085,618

    )

     

     

     

     

     

     

     

     

    Weighted average shares

     

    34,543,695

     

    22,585,612

     

    16,163,098

     

     

     

     

     

     

     

     

     

    Earning (loss) per share

     

    $

    0.31

     

    $

    (0.08

    )

    $

    (0.31

    )

     

     

     

     

     

     

     

     

    Diluted

     

     

     

     

     

     

     

    Earnings (loss) applicable to common shareholders

     

    $

    10,811,625

     

    $

    (1,790,057

    )

    $

    (5,085,618

    )

    Effect of dilutive securities - Convertible subordinated debenture

     

    459,483

     

     

     

    Earnings (loss) available to common shareholders and assumed conversion

     

    $

    11,271,108

     

    $

    (1,790,057

    )

    $

    (5,085,618

    )

    Weighted average shares:

     

     

     

     

     

     

     

    Outstanding

     

    34,543,695

     

    22,585,612

     

    16,163,098

     

    Options

     

    684,806

     

     

     

    Convertible subordinated debenture

     

    2,349,426

     

     

     

     

     

    37,577,927

     

    22,585,612

     

    16,163,098

     

    Earnings (loss) per share

     

    $

    0.30

     

    $

    (0.08

    )

    $

    (0.31

    )

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

    8.Equity Transactions

     In May 2000, we completed a private placement of 3,768,161 shares of our common stock to WEDGE for $8,000,000, or $2.175 per share.

            In August 2000, we issued 341,576 shares of our common stock at $2.25 per share as part of the consideration we paid in connection with our acquisition of Pioneer Drilling Co.

            In October 2000, the T.L.L. Temple Foundation converted its 400,000 shares of Series A convertible preferred stock into 800,000 shares of our common stock at $1.00 per share.

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



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

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

    On March 31, 2003, we sold 5,333,333 shares of our common stock to Chesapeake Energy Corporation for $20,000,000 ($3.75 per share), before related offering expenses.  In connection with that sale, we granted Chesapeake Energy a preemptive right to acquire equity securities we may issue in the future, under specified circumstances, in order to permit Chesapeake Energy to maintain its proportionate ownership of 24.6% of our outstanding shares of common stock.  We also granted Chesapeake Energy a right, under certain circumstances, to request registration of the acquired shares under the Securities Act of 1933.  At March 31, 2005, Chesapeake Energy owned 16.78% of our outstanding common stock and its preemptive rights have expired.

     

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

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

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

    46



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

    Directors and employees exercised stock options for the purchase of 445,000551,666 shares of common stock at prices ranging from $.375 to $2.50$6.44 per share during the fiscal year ended March 31, 2003, 27,5002005, 722,334 shares of common stock at prices ranging from $.375$.625 to $1.00$3.20 per share during the fiscal year ended March 31, 20022004 and 51,500445,000 shares of common stock at prices ranging from $0.15$0.375 to $2.50 per share during the fiscal year ended March 31, 2001. On May 1, 2003, one of our officers exercised stock options for the purchase of 10,000 shares of common stock at a price of $2.25 per share.2003.

    9.Stock Options, Warrants and Stock Option Plan

     

    Under our stock option plans, employee stock options generally become exercisable over threethree- 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, 2003, 20022005, 2004 and 2001:2003:

     
     2003
     2002
     2001
     
     Shares
    Issuable on
    Exercise of
    Options

     
    Exercise
    Price per
    Share

     Shares
    Issuable on
    Exercise of
    Options

     
    Exercise
    Price per
    Share

     Shares
    Issuable on
    Exercise of
    Options

     Exercise
    Price per
    Share

    Balance Outstanding               
     Beginning of year 2,320,000 $0.375-5.15 2,177,500 $0.375-4.60 1,759,000 $0.15-1.50
      Granted 65,000 $3.20-4.50 585,000 $3.00-5.15 515,000 $2.25-4.60
      Exercised (445,000)$0.375-2.50 (177,500)$0.375-1.50 (51,500)$0.15-2.50
      Canceled (115,000)$2.25-4.60 (265,000)$2.25 (45,000)$0.375-1.50
      
     
     
     
     
     
    Balance Outstanding               
     End of year 1,825,000 $0.375-5.15 2,320,000 $0.375-5.15 2,177,500 $0.379-4.60
      
     
     
     
     
     
    Options Exercisable               
     End of year 1,437,334    1,734,000    1,172,500   
      
        
        
       

     

     

     

    2005

     

    2004

     

    2003

     

     

     

    Shares
    Issuable on
    Exercise of
    Options

     

    Weighted
    Average
    Price

     

    Shares
    Issuable on
    Exercise of
    Options

     

    Weighted
    Average
    Price

     

    Shares
    Issuable on
    Exercise of
    Options

     

    Weighted
    Average
    Price

     

    Balance Outstanding Beginning of year

     

    2,056,666

     

    $

    3.24

     

    1,825,000

     

    $

    1.63

     

    2,320,000

     

    $

    1.47

     

    Granted

     

    510,000

     

    $

    8.85

     

    1,000,000

     

    $

    4.46

     

    65,000

     

    $

    1.72

     

    Exercised

     

    (551,666

    )

    $

    1.37

     

    (722,334

    )

    $

    0.93

     

    (445,000

    )

    $

    0.40

     

    Canceled

     

    (10,000

    )

    $

    4.52

     

    (46,000

    )

    $

    2.25

     

    (115,000

    )

    $

    4.29

     

    Balance Outstanding End of year

     

    2,005,000

     

    $

    5.30

     

    2,056,666

     

    $

    3.24

     

    1,825,000

     

    $

    1.63

     

    Options Exercisable End of year

     

    798,002

     

    $

    3.58

     

    884,001

     

    $

    1.95

     

    1,437,334

     

    $

    1.28

     

    As of March 31, 2003,2005, there arewere no outstanding warrants.



     At

    The following table summarizes information about our employee stock options outstanding and exercisable at March 31, 2003, the weighted average exercise price of our outstanding options was $1.63 per share and the weighted average exercise price of our exercisable options was $1.28 per share.2005:

     

     

    Options Outstanding

     

    Options Exercisable

     

    Range of
    Exercise Prices

     

    Number
    Outstanding

     

    Weighted
    Average
    Remaining
    Contractual
    Life

     

    Weighted
    Average
    Exercise
    Price

     

    Number
    Exercisable

     

    Weighted
    Average
    Exercise
    Price

     

     

     

     

     

     

     

     

     

     

     

     

     

    $2.25 - $4.65

     

    1,065,000

     

    7.45

     

    $

    3.60

     

    681,002

     

    $

    3.32

     

     

     

     

     

     

     

     

     

     

     

     

     

    $4.77 - $10.31

     

    940,000

     

    9.11

     

    $

    7.22

     

    117,000

     

    $

    5.05

     

     

     

     

     

     

     

     

     

     

     

     

     

     

     

    2,005,000

     

    8.23

     

    $

    5.30

     

    798,002

     

    $

    3.58

     

    10.Employee 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'semployee’s annual contribution, which we determine annually.  Our contributions for fiscal 2003, 20022005, 2004 and 20012003 were approximately $92,000, $153,000$399,000, $76,000 and $101,000,$92,000, respectively.

     

    47



    We maintain a self-insurance program, for major medical, hospitalization and dental coverage for employees and their dependents, which is partially funded by payroll deductions.  We have provided for both reported and incurred but not reported medical costs in the accompanying consolidated balance sheets.  We have a maximum liability of $100,000 per employee/dependent per year.  Amounts in excess of the stated maximum are covered under a separate policy provided by an insurance company.  Accrued expenses at March 31, 20032005 include approximately $270,000$489,000 for our estimate of incurred but unpaid costs related to the self-insurance portion of our health insurance.

     

    We are self-insured for up to $250,000 for all workers'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'workers’ compensation coverage in the accompanying consolidated balance sheets.  Accrued expenses at March 31, 20032005 include approximately $255,000$845,000 for our estimate of incurred but unpaid costs related to workers'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 InformationConcentrations

     

    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, 2003,2005, our three largest customers accounted for 10.8%6.5%, 6.5%5.0% and 5.4%4.6%, respectively, of our total contract drilling revenue.   All three of these customers were customers of ours in 2002.2004.  In fiscal 2002,2004, our three largest customers accounted for 13.7%10.5%, 12.2%6.4% and 11.1%4.9%, of our total contract drilling revenue.  Two of these customers were customers of ours in fiscal 2001.2003.   In  fiscal  2001,2003,  our  three  largest  customers  accounted  for 13.6%10.8%, 8.8%6.5% and 6.3%5.4% of our total contract drilling revenue.

    12.Commitments and Contingencies

    We are in the process of constructing, primarily from new and used components, two 1000 horsepower electric rigs at an estimated cost of $6,500,000 each.  We expect to place one of these rigs in service in June 2005 and the second in August 2005.  As of March 31, 2003,2005, we were constructing one refurbished 18,000-foot SCR land drilling rig. We estimate the totalhave incurred approximately $3,300,000 of construction cost of this rig will be approximately $7,000,000, of which approximately $2,415,000 had been incurred as of March 31, 2003. We accepted delivery of this rig on May 2, 2003. On September 30, 2002, we signed an agreement to purchase another 14,000-foot mechanical drilling rig, located in Trinidad, for $3,150,000, which we expect to be delivered to the Port of Houston in July or August 2003. On October 7, 2002, we made a $315,000 deposit toward the purchase of this rig. In March 2003, we signed an amended asset purchase agreement reducing the purchase price for this rig to $2,850,000 and made an additional $300,000 deposit.

            On May 17, 2002, Deborah Sutton and other working interest owners in a well that we drilled in May 2000 filed an amended petition naming us as a defendant in the 37th Judicial District Court in Bexar County, Texas, Cause No. 2001-CI-06701. Other defendants included: the operator, Sutton Producing Corp.; the casing installer, Jens' Oil Field Service, Inc.; the seller of the subject casing and



    collars, Exploreco, Ltd.; and the casing and collar manufacturer, Baoshan Iron & Steel Corp. The operator and the casing installer later filed cross-claims against us, alleging they were entitled to contribution or indemnity from us in the event plaintiffs recover against them. Plaintiffs dropped all claims against us on August 8, 2002. The operator then abandoned its cross claims against us on or about May 19, 2003. Then, on May 20, 2003, the casing crew operator non-suited its affirmative cross claims against us. We remain in the suit only because the casing crew operator joined us as a responsible third party in an effort to reduce its own percentage of responsibility to the plaintiffs. However, in our position as a mere responsible third party, we are not liable to the plaintiffs or the other defendants in this suit. We understand the remaining parties to the suit have subsequently reached a compromise and settlement which they will be finalizing in the near future.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'workers’ compensation claims and employment-related disputes.  In the opinion of our management, none of the pending litigation, disputes or claims against us will have a material adverse effect on our financial condition, results of operations or cash flow from operations and there is only a remote possibility that any such mattersmatter will require any additional loss accrual.

    48



    13.Quarterly Results of Operations (unaudited)

     

    The following table summarizes quarterly financial data for our fiscal years ended March 31, 20032005 and 20022004 (in thousands, except per share data):

     
     First
    Quarter

     Second
    Quarter

     Third
    Quarter

     Fourth
    Quarter

     Total
     
    2003                
    Revenues $18,443 $16,978 $19,727 $25,073 $80,221 
    Earnings (loss) from operations  165  (1,241) (1,827) (2,002) (4,905)
    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)
    2002                
    Revenues $18,298 $17,691 $16,539 $16,172 $68,700 
    Earnings from operations  5,292  4,232  1,293  456  11,273 
    Net earnings (loss)  3,174  2,612  551  (19) 6,318 
    Net earnings (loss) applicable to common shareholders  3,114  2,579  551  (19) 6,225 
    Earnings (loss) per share                
     Basic  0.23  0.17  0.03  (0.00) 0.41 
     Diluted  0.20  0.15  0.03  (0.00) 0.35 

     

     

     

    First
    Quarter

     

    Second
    Quarter

     

    Third
    Quarter

     

    Fourth
    Quarter

     

    Total

     

    2005

     

     

     

     

     

     

     

     

     

     

     

    Revenues

     

    $

    40,719

     

    $

    42,783

     

    $

    46,387

     

    $

    55,357

     

    $

    185,246

     

    Income from operations

     

    1,046

     

    1,960

     

    6,704

     

    9,064

     

    18,774

     

    Income tax expense

     

    (139

    )

    (590

    )

    (2,428

    )

    (3,192

    )

    (6,349

    )

    Net earnings

     

    216

     

    923

     

    4,179

     

    5,494

     

    10,812

     

    Earnings per share:

     

     

     

     

     

     

     

     

     

     

     

    Basic

     

    .01

     

    .03

     

    .11

     

    .14

     

    .31

     

    Diluted

     

    .01

     

    .03

     

    .11

     

    .14

     

    .30

     

    2004

     

     

     

     

     

     

     

     

     

     

     

    Revenues

     

    $

    23,850

     

    $

    24,244

     

    $

    26,414

     

    $

    33,368

     

    $

    107,876

     

    Income (loss) from operations

     

    (789

    )

    (166

    )

    9

     

    1,384

     

    438

     

    Income tax expense (benefit)

     

    409

     

    185

     

    118

     

    (286

    )

    426

     

    Net earnings (loss)

     

    (1,056

    )

    (621

    )

    (522

    )

    409

     

    (1,790

    )

    Earnings (loss) per share:

     

     

     

     

     

     

     

     

     

     

     

    Basic

     

    (.05

    )

    (.03

    )

    (.02

    )

    .02

     

    (.08

    )

    Diluted

     

    (.05

    )

    (.03

    )

    (.02

    )

    .02

     

    (.08

    )

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

    49




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

    Not applicable.



    PART III

            In Items 12 and 13 below, we are incorporating by reference the information we refer to in those Items from the definitive proxy statement for our 2003 Annual Meeting of Shareholders that we filed with the SEC on July 8, 2003.


    Item 10. Directors and Executive Officers of the Registrant
    9A.

    Dean A. Burkhardt has served as one of our directors since October 26, 2001. Mr. Burkhardt has been an investor and consultant in the energy service industry during the last five years as well as a co-owner of the Dubina Rose Ranch, Ltd, a ranch business engaged in the breeding and selling of American Quarter Horse Association registered horses and coastal hay. Since 1997, Mr. Burkhardt has provided consulting services regarding oil and gas projects in Bolivia and Argentina to Frontera Resources Corporation, a developer and operator of oil and gas projects in emerging markets, consulting services regarding investments in fuel cells and workover services to WEDGE (1997-1998), and consulting services relating to the marketing of technical drilling engineering and quality management services to T. H. Hill & Associates, Inc., a drilling engineering and quality management services provider. Mr. Burkhardt co-founded Cheyenne Services, Inc. (1979), a provider of oilfield tubular make-up, tubular inspection, and third-party quality assurance services, and Applied Petroleum Software, Inc. (1983), a provider of production engineering software. From 1981 to 1982, Mr. Burkhardt was President and CEO of Tescorp Energy Services, a provider of hydraulic workover services, rental tools and tubular services.

    Michael E. Little has served as one of our directors and as our Chairman of the board since November 1998. From November 1998 to December 2003 he served as our Chief Executive Officer. Mr. Little currently serves as President and Chief Executive officer of WEDGE Group Incorporated, a position he has held since December 2003. Mr. Little served as President and Chief Executive Officer and as a director of Dawson Production Services, Inc. from March 1982 until it was acquired by Key Energy Services, Inc. in October 1998. He also served as Chairman of the board of Dawson Production Services, Inc. from March 1983 to October 1998. From 1980 to 1982, Mr. Little was Vice President of Cambern Engineering, Inc., a company that provided drilling and completion consulting services in the Texas Gulf Coast area. From 1976 to 1980, he was employed by Chevron USA as a drilling foreman and as a drilling engineer. Mr. Little is also a director of Intercontinental Bank Shares Corporation, a bank holding company.

    Wm. Stacy Locke has served as one of our directors since May 1995. He has been our President and Chief Executive Officer since December 2003 and was our President and Chief Financial Officer from August 2000 to December 2003. He previously served as our President and Chief Operating Officer from November 1998 to August 2000 and as our President and Chief Executive Officer from May 1995 to November 1998. Prior to joining Pioneer Drilling Company, Mr. Locke was Vice President—Investment Banking with Arneson, Kercheville, Ehrenberg & Associates, Inc. from January 1993 to April 1995. He was Vice President—Investment Banking with Chemical Banking Corporation's Texas Commerce Bank from 1988 to 1992. He was Senior Geologist with Huffco Petroleum Corporation from 1982 to 1986. From 1979 to 1982, Mr. Locke worked for Tesoro Petroleum Corporation and Valero Energy as a Geologist.

    C. John Thompson has served as one of our directors since May 2001. Mr. Thompson has been a consultant since December 2001. He was Vice President and Co-Manager of Enron Energy Capital Resources from February 2000 to December 2001. From September 1997 to February 2000, Mr. Thompson was a principal in Sagestone Capital Partners, which provided investment banking services to the oil and gas industry and portfolio management services to various institutional investors. From December 1990 to May 1997, Mr. Thompson held various positions with Enron Energy Capital



    Resources and its predecessor companies. From 1977 until 1990, Mr. Thompson worked in the energy banking industry.

    James M. Tidwell has served as one of our directors since March 2001. Mr. Tidwell currently serves as Vice President and Chief Financial Officer of WEDGE Group Incorporated, a position he has held since January 2000. From June 1999 to January 2000, Mr. Tidwell served as President of Daniel Measurement and Control, a division of Emerson Electric Company. From August 1996 to June 1999, he was Executive Vice President and Chief Financial Officer of Daniel Industries, Inc., a leading supplier of specialized equipment and systems to oil, gas and process operators and plants to measure and control the flow of fluids. For more than five years prior to joining Daniel Industries, Inc., Mr. Tidwell served as Senior Vice President and Chief Financial Officer of Hydril Company, a worldwide leader in engineering, manufacturing and marketing of premium tubular connections and pressure control devices for oil and gas drilling and production. Mr. Tidwell is also a director of T-3 Energy Services, Inc., TGC Industries, Inc. and EOTT Energy LLC.

    William D. Hibbetts has served as one of our directors since June 1984 and as our Sr. Vice President, Chief Financial Officer and Secretary since December 2003. He previously served as our Sr. Vice President, Chief Accounting Officer and Secretary from May 2002 to December 2003, and served as our Vice President, Chief Accounting Officer and Secretary from December 2000 to May 2002. He served as the Chief Financial Officer of International Cancer Screening Laboratories from March 2000 to December 2000. He worked as a consultant from June 1999 to March 2000. He served as the Chief Accounting Officer of Southwest Venture Management Company from July 1988 to May 1999. Mr. Hibbetts was the Treasurer/Controller of Gary Pools, Inc. from May 1986 to July 1988. He previously served as an officer of our company from January 1982 until May 1986. Before initially joining our company, Mr. Hibbetts served in various positions as an accountant with KPMG Peat Marwick LLP from June 1971 to December 1981, including as an audit manager from July 1978 to December 1981.

    Franklin C. West has served as our Executive Vice President and Chief Operating Officer since January 2002. Prior to joining Pioneer Drilling Company, he was Vice President for Flournoy Drilling Company from 1967 until it was acquired by Grey Wolf, Inc. in 1997, and continued in the same capacity for Grey Wolf, Inc. until December 2001. Mr. West has over 40 years of experience in the drilling industry.

    William H. White has served as one of our directors since May 2000. Mr. White has been the President and Chief Executive Officer of WEDGE Group Incorporated since April 1997. WEDGE is a diversified firm with subsidiaries in engineering and construction, hotel, oil and gas services and real estate businesses. Mr. White served as Deputy Secretary of Energy and Chief Operating Officer of the United States Department of Energy from 1993 to 1995. Prior to his service with the Department of Energy, Mr. White practiced law and served on the management committee of the law firm of Susman Godfrey, L.L.P. From December 1995 to June 1998, Mr. White served as Chairman of the Democratic Party of Texas. He also served as an adjunct professor at the University of Texas School of Law. Mr. White currently serves on the board of BJ Services and numerous non-profit organizations, including Baylor College of Medicine.

    Section 16(a) Beneficial Ownership Reporting Compliance

            Section 16(a) of the Securities Exchange Act of 1934, as amended, requires our directors, executive officers and any persons beneficially owning more than 10% of our common stock to report their initial ownership of our common stock and any subsequent changes in that ownership to the SEC. Specific due dates for these reports have been established, and we are required to disclose in this annual report on Form 10-K/A any failure to file by these dates. All required filings for the 2003 fiscal year were made on a timely basis.



            In making these disclosures, we relied solely on written statements of directors, executive officers and shareholders and copies of the reports that they have filed with the SEC.


    Item 11. Executive Compensation

    Summary Compensation Table

            The following table sets forth the compensation we paid or accrued for services performed during the fiscal years ended March 31, 2003, 2002 and 2001 by our Chief Executive Officer and our four other most highly compensated executive officers (the "named executive officers").


    Annual Compensation
    Name and Principal Position

    Fiscal Year
    Salary(1)
    Bonus
    Securities
    Underlying
    Options

    Michael E. Little
    Director, Chairman and Chief Executive Officer
    2003
    2002
    2001
    $
    $
    $
    164,340
    162,440
    66,052

    $

    78,843



    Wm. Stacy Locke
    Director, President and Chief Financial Officer


    2003
    2002
    2001


    $
    $
    $

    164,340
    162,440
    142,321



    $


    78,843





    Franklin C. West
    Executive Vice President and Chief Operating Officer(2)


    2003
    2002
    2001


    $
    $

    185,500
    41,885


    $
    $

    50,000
    50,000



    450,000

    William D. Hibbetts
    Director, Senior Vice President, Chief Accounting Officer and Secretary(3)


    2003
    2002
    2001


    $
    $
    $

    117,854
    108,840
    24,231



    $


    27,210




    25,000

    Donald G. Lacombe
    Senior Vice President-Marketing(4)


    2003
    2002
    2001


    $
    $
    $

    120,000
    112,703
    34,485



    $


    19,047



    50,000
    25,000
    (1)
    Includes vehicle allowances, when applicable, included in annual compensation, but excludes the value of perquisites and other personal benefits for the named executive officers because the aggregate amounts did not exceed 10% of the total annual salary and bonus reported for the named executive officers.

    (2)
    Mr. West's employment with our company began on January 1, 2002. Mr. West joined our company as Executive Vice President and Chief Operating Officer. Mr. West was paid $91,885 during fiscal year 2002, which amount included a $50,000 signing bonus. He was also issued options under our 1999 Stock Option Plan to purchase 450,000 shares of our common stock at an exercise price of $3.00 per share.

    (3)
    Mr. Hibbetts' employment with our company began on December 7, 2000.

    (4)
    Mr. Lacombe's employment with our company began on August 18, 2000.

    Option Grants in Last Fiscal Year

            No options were granted to the named executive officers during the fiscal year ended March 31, 2003.



    Stock Option Exercises and 2003 Fiscal Year-End Option Values

            The following table details the number and value of securities exercised during the year ended March 31, 2003 by the named executive officers and of securities underlying unexercised options held by the named executive officers at March 31, 2003.

     
      
      
     Number of Securities
    Underlying Unexercised
    Options at Fiscal Year-End

     Value of Unexercised
    In-the-Money Options
    at Fiscal Year End(1)

    Name

     Shares Acquired on Exercise
      
     Value Realized
     Exercisable
     Unexercisable
     Exercisable
     Unexercisable
    Michael E. Little    650,000  $2,268,500  
    Wm. Stacy Locke 400,000 $1,404,000 400,000  $1,396,000  
    Franklin C. West    250,000 200,000 $872,500 $698,000
    William D. Hibbetts 5,000 $8,000 10,000 15,000 $34,900 $52,350
    Donald G. Lacombe    26,667 48,333 $93,068 $168,682

    (1)
    Based on the closing price of $3.49 per share for our common stock on the AMEX on March 31, 2003.

    Equity Compensation Plan Information

            The following table provides information on our equity compensation plans as of June 25, 2003. This table does not include shares that would be issuable under the 2003 Stock Incentive Plan if that plan is approved by our shareholders.

    Plan Category

     Number of securities to
    be issued upon exercise
    of outstanding options,
    warrants and rights

     Weighted-average
    exercise price of
    outstanding options,
    warrants and rights

     Number of securities
    remaining available for
    future issuance under
    equity compensation
    plans (excluding
    securities reflected
    in column (a))

    Equity compensation plans approved by security holders 1,951,000 $1.76 224,413
    Equity compensation plans not approved by security holders N/A  N/A N/A
    Total 1,951,000 $1.76 224,413

    Compensation Committee Interlocks and Insider Participation

            During fiscal year 2003, the Compensation Committee consisted of C. John Thompson, James M. Tidwell and William H. White. In July 2002, Mr. White participated in our $10,000,000 convertible subordinated debenture financing to the extent described in the next paragraph.

            On October 9, 2001, we issued a 6.75% five-year $18,000,000 convertible subordinated debenture, Series A, to 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. We used approximately $6,000,000 to reduce a $12,000,000 credit facility. We used the balance of the proceeds for drilling equipment and working capital. On July 3, 2002, we issued an additional $10,000,000 of 6.75% convertible subordinated debt to WEDGE with an effective conversion rate of $5.00 per share. The transaction was effected by an agreement between us 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 canceled. 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, one of our directors and Compensation Committee members, and the then President of WEDGE, purchased the remaining $1,000,000 on July 29, 2002. We used $7,000,000 of the proceeds from the new debt to pay down other outstanding bank debt and $3,000,000 for the purchase of drilling equipment. The new debentures are subject to call provisions under which we may, at our option, prepay the new debentures after July 2004, at 105% of principal during 2004, 104% during 2005, 103% during 2006, and 100% during 2007 and thereafter.


    Item 12. Security Ownership of Certain Beneficial Owners and Management

            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 2003 Annual Meeting of Shareholders for the information this Item 12 requires.


    Item 13. Certain Relationships and Related Transactions

            Please see the information appearing under the heading "Certain Transactions" in the definitive proxy statement for our 2003 Annual Meeting of Shareholders for the information this Item 13 requires.


    Item 14. Controls and Procedures

     Within 90 days prior to the filing of this report,

    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 the design and operation of our disclosure controls and procedures pursuant to Exchange Act Rule 13a-15.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 the date of that evaluation. Disclosure controls and procedures are controls and procedures that are designedMarch 31, 2005 to ensureprovide 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'sCommission’s rules and forms.

     

    There havehas been no significant changeschange in our internal controls over financial reporting that occurred during the three months ended March 31, 2005 that has materially affected, or is likely to materially affect, our internal controls over financial reporting.

    Management’s Report on Internal Control over Financial Reporting

    The management of Pioneer Drilling Company is responsible for establishing and maintaining adequate internal control over financial reporting.  Pioneer Drilling Company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in other factorsaccordance 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 significantly affecthave a material effect on the financial statements. Because of its inherent limitations, internal controls subsequentcontrol over financial reporting may not prevent or detect misstatements.  Also, projections of any evaluation of effectiveness to future periods are subject to the daterisk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

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

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

    PART III

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

    Item 10.Directors and Executive Officers of the Registrant

    Please see the information appearing under the headings “Proposal No. 1—Election of Directors” and “Executives and Executive Compensation” in the definitive proxy statement for our 2005 Annual Meeting of Shareholders for the information this evaluation.Item 10 requires.

    Item 11.Executive Compensation

    Please see the information appearing under the heading “Executives and Executive Compensation” in the definitive proxy statement for our 2005 Annual Meeting of Shareholders for the information this Item 11 requires.

    50



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

    Please see the information appearing (1) under the heading “Equity Compensation Plan Information” in Item 5 of this report and (2) under the heading “Security Ownership of Certain Beneficial Owners and Management” in the definitive proxy statement for our 2005 Annual Meeting of Shareholders for the information this Item 12 requires.

    Item 13.Certain Relationships and Related Transactions

    Please see the information appearing under the heading “Certain Transactions” in the definitive proxy statement for our 2005 Annual Meeting of Shareholders for the information this Item 13 requires.

    Item 14.Principal Accountant Fees and Services

    Please see the information appearing under the heading “Ratification of Appointment of Independent Auditors” in the definitive proxy statement for our 2005 Annual Meeting of Shareholders for the information this Item 14 requires.


    PART VI
    IV

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

      (a)

    (1)Financial Statements.

     

    See Index to Consolidated Financial Statements on page 20.29.

    (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.

      Schedule II

       

       

      Valuation and Qualifying Accounts

       

       

       

      Balance
      at
      Beginning
      of Year

       

      Charged
      to Costs
      and
      Expenses

       

      Deductions
      from
      Accounts

       

      Balance
      at
      Year End

       

       

       

       

       

       

       

       

       

       

       

      Year ended March 31, 2003
      Allowance for doubtful receivables

       

      $

       

      $

      110,000

       

      $

       

      $

      110,000

       

       

       

       

       

       

       

       

       

       

       

      Year ended March 31, 2004
      Allowance for doubtful receivables

       

      $

      110,000

       

      $

       

      $

       

      $

      110,000

       

       

       

       

       

       

       

       

       

       

       

      Year ended March 31, 2005
      Allowance for doubtful receivables

       

      $

      110,000

       

      $

      242,000

       

      $

       

      $

      342,000

       

      51



    (3)

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

    Exhibit
    Number


    Description


    2.1*

    2.1

    -

    Asset Purchase Agreement dated February 14, 2001November 11, 2004 between MustangWolverine Drilling, Ltd., Michael T. Wilhite, Sr., Andrew D. MillsInc. 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, 20028-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, 1079, the sole shareholder of Allen Drilling Company, Dixon Allen, Paula K. Hoisington and Lisa D. Johonnesson, all of the beneficiaries of the Trust, and Pioneer Drilling Services, Ltd. (Form 8-K dated November 30, 2004 (File No. 1-8182m Exhibit 2.1)).

    3.1*

    -

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


    3.2*




    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-K10-Q for the yearquarter ended March 31, 2001December, 2003 (File No. 1-8182, Exhibit 3.2)3.3)).


    4.1*




    4.1*

    -

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

    4.2*

    -

    Form of Purchase Agreement dated May 18, 2001February 13, 2004 between Pioneer Drilling Company and WEDGE Energy Services, L.L.C.the several purchasers (Form 10-K for the year ended March 31, 2001 (File No.1-8182, Exhibit 4.10)).


    4.2*



    Debenture Agreement dated July 3, 2002 by and between WEDGE Energy Services, L.L.C. and Pioneer Drilling Company (Form 8-Ks-3 filed July 18, 2002 (FileFebruary 24, 3004 (Reg. No. 1-8182,333-113036, Exhibit 4.1)).


    4.3*




    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)).


    4.4*

    4.3*



    -


    Subordination

    Credit 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)).


    4.5*



    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)).


    4.6*



    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)).

    4.7*



    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.Frost National Bank, as Administrative Agent, Agent, Lead Arranger and Lender dated October 29, 2004 (Form 8-K filed January 3, 2003dated October 29, 2004 (File No. 1-8182, Exhibit 5.1)4.1)).


    4.8*




    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)).


    4.9*

    10.1+*



    -


    Consolidated Loan Agreement dated March 18, 2003 between Pioneer Drilling Services, Ltd., Pioneer Drilling Company and The Frost National Bank (Form 10-K for the year ended March 31, 2002 (File No. 1-8182, Exhibit 4.9)).

    4.10*




    Promissory Note dated March 18, 2003 between Pioneer Drilling Services, Ltd. and The Frost National Bank (Form 10-K for the year ended March 31, 2002 (File No. 1-8182, Exhibit 4.10)).

    4.11*



    Revolving Promissory Note dated March 18, 2003 between Pioneer Drilling Services, Ltd. and The Frost National Bank (Form 10-K for the year ended March 31, 2002 (File No. 1-8182, Exhibit 4.11)).

    4.12*



    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 the year ended March 31, 2002 (File No. 1-8182, Exhibit 4.12)).

    10.1*



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

    10.2*



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

    10.3*



    Voting Agreement dated October 9, 2001 between Pioneer Drilling Company and WEDGE Energy Service, L.L.C. (See Section 1.3 of the Debenture Purchase Agreement referenced above as Exhibit 4.5)).

    10.4+*



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


    10.5+*




    Executive Employment Agreement dated November 16, 1998 between Pioneer Drilling Company and Michael E. Little (Form 10-K for the year ended March 31, 2001 (File No. 1-8182, Exhibit 10.3+)).


    10.6+

    10.2+*



    -


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


    10.7+*




    10.3+*

    -

    Pioneer Drilling Company'sCompany’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+)).




    10.8+

    10.4+*



    -


    Pioneer Drilling Company 'sCompany’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+)).


    10.9+*




    Subscription Agreement dated February 17, 2000 between WEDGE Energy Services, L.L.C. and

    10.5*

    -

    Pioneer Drilling Company 2003 Stock Plan (Form 10-K for the year ended March 31, 2001S-8 filed November 18, 2003 (File No. 1-8182,333-110569, Exhibit 10.8)4.4)).


    10.10*




    Common Stock Purchase

    10.6

    -

    Termination Agreement dated May 11, 200026, 2005 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)).


    10.11*



    Common Stock Purchase Agreement dated May 18, 2001 betweenMichael E. Little, Wm. Stacy Locke, 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)).

    52




    10.12*

    21.1



    -


    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)).

    10.13*




    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)).

    10.14*



    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)).

    10.15*



    Registration Rights Agreement dated March 31, 2003, among Pioneer Drilling Company, WEDGE Energy Services, 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)).

    21.1*



    Subsidiaries of Pioneer Drilling Company (Form 10-K for the year ended March 31, 2002 (File No. 1-8182, Exhibit 21.1)).Company.


    23.1




    23.1

    -

    Consent of KPMG LLP.


    99.1




    31.1

    -

    Certification by Pioneer Drilling Company'sWm. Stacy Locke, President and Chief Executive Officer, pursuant to 18 U.S.C. Section 1350, as adoptedRule 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 2002.2002 (Subsections (a) and (b) of Section 1350, Chapter 63 of Title 18, United States Code).


    99.2




    ��

    32.2

    -

    Certification by Pioneer Drilling Company'sWilliam D. Hibbetts, Senior Vice President and Chief Financial Officer, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.2002 (Subsections (a) and (b) of Section 1350, Chapter 63 of Title 18, United States Code).


    *

    Incorporated by reference to the filing indicated.

    +

    Management contract or compensatory plan or arrangement.

    (b)
    Reports on Form 8-K.

            On January 3, 2003, we filed a current report on Form 8-K, dated December 23, 2002, to report our borrowing of $14.5 million from Merrill Lynch Capital. We did not file any other current reports on Form 8-K during the last quarter of the fiscal year covered by this report.



    SIGNATURES

     

    53



    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 22, 20041, 2005


    By:


    By:

    /s/ WM. STACY LOCKE      


    Wm. Stacy Locke

       Wm. Stacy Locke

       Chief Executive Officer and President

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

    Signature

    Title

    Date

    /s/ Michael E. Little

    Michael E. Little

    Chairman

    June 1, 2005

    /s/ Wm. Stacy Locke

    Wm. Stacy Locke

    President, Chief Executive Officer and
    Director (Principal Executive Officer)

    June 1, 2005

    /s/ William D. Hibbetts

    William D. Hibbetts

    Senior Vice President, Chief Financial
    Officer and Secretary (Principal Financial
    and Accounting Officer)

    June 1, 2005

    C. John Thompson

    Director

    June 1, 2005

    /s/ James M. Tidwell

    James M. Tidwell

    Director

    June 1, 2005

    /s/ C. Robert Bunch

    C. Robert Bunch

    Director

    June 1, 2005

    /s/ Dean A. Burkhardt

    Dean A. Burkhardt

    Director

    June 1, 2005

    /s/ Michael F. Harness

    Michael F. Harness

    Director

    June 1, 2005

    54



    Index To Exhibits

    2.1

    -

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

    2.2

    -

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

    3.1*

    -

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

    3.2*

    -

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

    3.3*

    -

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

    4.1*

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

    4.2*

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

    4.3

    -

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

    10.1+*

    -

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

    10.2+*

    -

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

    10.3+*

    -

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

    10.4+*

    -

    Pioneer Drilling Company’s 1999 Stock Plan and form of Stock Option Agreement (Form 10-K for the year ended March 31, 2001 (File No. 1-8182, Exhibit 10.7+)).

    10.5*

    -

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

    10.6

    -

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

    21.1

    -

    Subsidiaries of Pioneer Drilling Company.

    23.1

    -

    Consent of KPMG LLP.

    55



    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.

    56