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PIONEER ENERGY SERVICES CORP 10-K 2006
Form 10-K
Table of Contents

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D. C. 20549

 


FORM 10-K

 


(Mark one)

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

For the fiscal year ended March 31, 2006

 

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

Commission File Number: 1-8182

 


PIONEER DRILLING COMPANY

(Exact name of registrant as specified in its charter)

 


 

TEXAS   74-2088619

(State or other jurisdiction of

incorporation or organization)

 

(I.R.S. Employer

Identification Number)

1250 N.E. Loop 410, Suite 1000

San Antonio, Texas

  78209
(Address of principal executive offices)   (Zip Code)

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

 


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

 

Title of each class

 

Name of each exchange on which registered

Common Stock $0.10 par value   American Stock Exchange

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

 


Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.    Yes  x    No  ¨

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

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

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

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

Large accelerated filer  x    Accelerated filer  ¨    Non-accelerated filer  ¨

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

The aggregate market value of the registrant’s common stock held by nonaffiliates of the registrant on the last business day of the registrant’s most recently completed second fiscal quarter (based on the closing sales price on the American Stock Exchange on September 30, 2005) was approximately $747,000,000.

As of May 12, 2006, there were 49,591,978 shares of common stock, par value $0.10 per share, of the registrant issued and outstanding.

DOCUMENTS INCORPORATED BY REFERENCE

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

 



Table of Contents

TABLE OF CONTENTS

 

 

 

          Page
PART I   
Item 1.    Business    1
Item 1A.    Risk Factors    11
Item 1B.    Unresolved Staff Comments    16
Item 2.    Properties    16
Item 3.    Legal Proceedings    16
Item 4.    Submission of Matters to a Vote of Security Holders    16
PART II   
Item 5.    Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities    16
Item 6.    Selected Financial Data    17
Item 7.    Management’s Discussion and Analysis of Financial Condition and Results of Operations    18
Item 7A.    Quantitative and Qualitative Disclosures About Market Risk    28
Item 8.    Financial Statements and Supplementary Data    29
Item 9.    Changes in and Disagreements With Accountants on Accounting and Financial Disclosure    49
Item 9A.    Controls and Procedures    49
Item 9B.    Other Information    49
PART III   
Item 10.    Directors and Executive Officers of the Registrant    50
Item 11.    Executive Compensation    50
Item 12.    Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters    50
Item 13.    Certain Relationships and Related Transactions    50
Item 14.    Principal Accountant Fees and Services    50
PART IV   
Item 15.    Exhibits and Financial Statement Schedules    51


Table of Contents

PART I

Statements we make in this Annual Report on Form 10-K that express a belief, expectation or intention, as well as those that are not historical fact, are forward-looking statements under the Private Securities Litigation Reform Act of 1995. These forward-looking statements are subject to various risks, uncertainties and assumptions, including those to which we refer under the heading “Cautionary Statement Concerning Forward-Looking Statements” following Item 1 of Part I of this report.

Item 1. Business

General

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

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

 

Date

  

Acquisition (1)

   Market   

Number of

Rigs
Acquired

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

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

During that same period, we also added 17 rigs to our fleet through construction of new rigs and construction of rigs from new and used components. In addition, in August 2003, we acquired a rig that had been operating in Trinidad and integrated it into our operations in Texas. As of May 12, 2006, our rig fleet consisted of 57 operating drilling rigs, 15 of which were operating in our South Texas division, 18 of which were operating in our East Texas division, seven of which were operating in our North Texas division, five of which were operating in our western Oklahoma division and 12 of which were operating in our Rocky Mountain divisions. We are also constructing seven additional rigs, which we expect to add to our fleet at varying times prior to March 31, 2007.

We conduct our operations primarily in South, East and North Texas, western Oklahoma and the Rocky Mountains. During fiscal 2006, substantially all the wells we drilled for our customers were drilled in search of natural gas except for five rigs employed in search of oil in the Williston Basin of the Rocky Mountains. Our customers remain primarily focused on drilling for natural gas.

For many years, the United States contract land drilling services industry has been characterized by an oversupply of drilling rigs and a large number of drilling contractors. Since 1996, however, there has been significant consolidation within the industry. We believe continued consolidation in the industry will generate more stability in dayrates, even during industry downturns. However, although consolidation in the industry is continuing, the industry is still highly fragmented and remains very competitive. For a discussion of market conditions in our industry, see “Management’s Discussion and Analysis of Financial Condition and Results of Operations – Market Conditions

 

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

Our Strategy

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

 

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

 

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

 

    positioning ourselves to maximize rig utilization and dayrates;

 

    training and maintaining high-quality, experienced crews; and

 

    maintaining an aggressive safety program.

Drilling Equipment

General

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

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

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

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

 

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

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

Our Fleet of Drilling Rigs

As of May 12, 2006, our rig fleet consists of 57 drilling rigs. We own all the rigs in our fleet. The following table sets forth information regarding utilization for our fleet of drilling rigs:

 

     Years Ended March 31,  
     2006     2005     2004     2003     2002     2001  

Average number of rigs for the period

   52.3     40.1     27.3     22.3     18.0     10.5  

Average utilization rate

   95 %   96 %   88 %   79 %   82 %   91 %

The following table sets forth information regarding our drilling fleet:

 

Rig
Number

  

Rig Design

   Approximate
Drilling Depth
Capability
(feet)
   Current Division
Location
   Type    Horsepower

1

   Cabot 750E    9,500    South Texas    Electric    750

2

   Cabot 750E    9,500    South Texas    Electric    750

3

   National 110 UE    18,000    South Texas    Electric    1,500

4

   RMI 1000 E    15,000    South Texas    Electric    1,000

5

   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

 

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Rig
Number

  

Rig Design

   Approximate
Drilling Depth
Capability
(feet)
   Current Division
Location
   Type    Horsepower

21

   National 110 UE    18,000    South Texas    Electric    1,500

22

   Ideco 725    12,000    East Texas    Mechanical    800

23

   Ideco 725    12,000    North Texas    Mechanical    800

24

   National 110 UE    18,000    South Texas    Electric    1,500

25

   National 110 UE    18,000    East Texas    Electric    1,500

26

   Oilwell 840 E    18,000    South Texas    Electric    1,500

27

   IRI Cabot 1200 M    13,500    South Texas    Mechanical    1,300

28

   Oilwell 760 E    15,000    South Texas    Electric    1,000

29

   Brewster N-46    12,000    North Texas    Mechanical    1,000

30

   Mid Cont U36A    11,000    North Texas    Mechanical    750

31

   Brewster N-7    11,500    East Texas    Mechanical    750

32

   Brewster N-75    13,500    East Texas    Mechanical    1,000

33

   Brewster N-95    13,500    East Texas    Mechanical    1,200

34

   All-Rig 900    12,000    East Texas    Mechanical    900

35

   National 610    13,500    East Texas    Mechanical    750

36

   Brewster N-7    11,500    East Texas    Mechanical    750

37

   Brewster N-95    13,500    East Texas    Mechanical    1,200

38

   Ideco H-1000 E    11,000    Utah    Electric    1,000

39

   National 370    10,000    North Texas    Mechanical    550

40

   National 370    8,500    North Dakota    Mechanical    550

41

   National 610    11,000    Utah    Mechanical    750

42

   Brewster N-46    12,500    North Dakota    Mechanical    1,000

43

   National 610    11,000    North Dakota    Mechanical    750

44

   National 80B    15,000    North Dakota    Mechanical    1,000

46

   RMI 550    9,000    Oklahoma    Mechanical    550

47

   Ideco 525    8,000    Oklahoma    Mechanical    600

48

   National 370    8,500    Oklahoma    Mechanical    550

49

   Ideco 525    9,000    Oklahoma    Mechanical    600

50

   Ideco 725    11,000    Oklahoma    Mechanical    800

51

   National 110 UE    18,000    East Texas    Electric    1,500

52

   National 80 UE    15,000    Utah    Electric    1,000

53

   National 80 UE    15,000    Utah    Electric    1,000

54

   RMI 1000    14,000    Utah    Mechanical    1,000

55

   OIME SD7E    18,000    North Texas    Electric    1,500

56

   OIME SD7E    18,000    North Dakota    Electric    1,500

57

   Gardner-Denver 800 E    15,000    Utah    Electric    1,000

59

   HRI 1000    12,500    Utah    Mechanical    1,000

60

   HRI 1000 E    12,500    North Texas    Electric    1,000

As of May 12, 2006, we owned a fleet of 53 trucks and related transportation equipment that we use to transport our drilling rigs to and from drilling sites. By owning our own trucks, we reduce the cost of rig moves and reduce downtime between rig moves.

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

 

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Drilling Contracts

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

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

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

 

     Year Ended March 31,
     2006    2005    2004

Daywork

   565    264    205

Turnkey

   19    134    92

Footage

   106    48    13
              

Total number of wells

   690    446    310
              

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

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

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

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

 

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Customers and Marketing

We market our rigs to a number of customers. In fiscal 2006, we drilled wells for 128 different customers, compared to 102 customers in fiscal 2005 and 83 customers in fiscal 2004. The following table shows our three largest customers as a percentage of our total contract drilling revenue for each of our last three fiscal years.

 

Customer

   Total
Contract
Drilling
Revenue
Percentage
 
Fiscal 2006   

Chesapeake Operating Inc.

   10.1 %

Kerr-McGee Oil & Gas

   6.1 %

Chinn Exploration

   4.4 %
Fiscal 2005   

Chinn Exploration

   6.5 %

Goodrich Petroleum Corp.

   5.0 %

Medicine Bow Energy Corporation

   4.6 %
Fiscal 2004   

Chinn Exploration

   10.5 %

Dale Operating Company

   6.4 %

Medicine Bow Energy Corporation

   4.9 %

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

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

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

Competition

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

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

 

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

 

    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

 

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

 

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

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

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

 

    better withstand industry downturns;

 

    compete more effectively on the basis of price and technology;

 

    better retain skilled rig personnel; and

 

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

Raw Materials

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

Operating Risks and Insurance

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

 

    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.

 

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

Our current insurance coverage includes property insurance on our rigs, drilling equipment and real property. Our insurance coverage for property damage to our rigs and to our drilling equipment is based on our estimate, as of October 2006, of the cost of comparable used equipment to replace the insured property. The policy provides for a deductible on rigs of $250,000 per occurrence. Our third-party liability insurance coverage is $51 million per occurrence and in the aggregate, with a deductible of $260,000 per occurrence. We believe that we are adequately insured for public liability and property damage to others with respect to our operations. However, such insurance may not be sufficient to protect us against liability for all consequences of well disasters, extensive fire damage or damage to the environment.

In addition, we generally carry insurance coverage to protect against certain hazards inherent in our turnkey contract drilling operations. This insurance covers “control-of-well,” including blowouts above and below the surface, redrilling, seepage and pollution. This policy provides coverage of $3 million, $5 million or $10 million, depending on the area in which the well is drilled and its target depth, subject to a deductible of the greater of 15% of the well’s anticipated dry hole cost or $150,000. This policy also provides care, custody and control insurance, with a limit of $1,000,000, subject to a $50,000 deductible.

Employees

We currently have approximately 1,540 employees. Approximately 190 of these employees are salaried administrative or supervisory employees. The rest of our employees are hourly employees who operate or maintain our drilling rigs and rig-hauling trucks. The number of hourly employees fluctuates depending on the number of drilling projects we are engaged in at any particular time. None of our employment arrangements are subject to collective bargaining arrangements.

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

 

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Facilities

We own:

 

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

 

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

 

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

 

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

 

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

We lease:

 

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

 

    a 4-acre division storage yard in Decatur, Texas, at a cost of $800 per month, pursuant to a lease extending through September 2006;

 

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

 

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

 

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

Governmental Regulation

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

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

 

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

Available Information

Our website address is www.pioneerdrlg.com. We make available on this website under “Investor Relations-SEC Filings,” free of charge, our annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and amendments to those reports as soon as reasonably practicable after we electronically file those materials with, or furnish those materials to, the SEC. We have also posted on our website our: Charters for the Audit, Compensation, and Nominating and Corporate Governance Committees of our Board; Code of Ethical Conduct for our Chief Executive Officer and other Officers; and Company Contact Information.

CAUTIONARY STATEMENT CONCERNING FORWARD-LOOKING STATEMENTS

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

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

In addition, various statements that this Annual Report on Form 10-K contains, including those that express a belief, expectation or intention, as well as those that are not statements of historical fact, are forward-looking statements. Those forward-looking statements appear in Item 1 – “Business” and Item 3 – “Legal Proceedings” in Part I of this report and in Item 5 – “Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities,” and in Item 7 – “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” Item 7A – “Quantitative and Qualitative Disclosures About Market Risk” and in the Notes to Consolidated Financial Statements we have included in Item 8 of Part II of this report and elsewhere in this report. These forward-looking statements speak only as of the date of this report. We disclaim any obligation to update these statements, and we caution you not to rely on them unduly. We have based these forward-looking statements on our current expectations and assumptions about future events. While our management considers these expectations and assumptions to be reasonable, they are inherently subject to significant business, economic, competitive, regulatory and other risks, contingencies and uncertainties, most of which are difficult to predict and many of which are beyond our control. These risks, contingencies and uncertainties relate to, among other matters, the following:

 

    general economic and business conditions and industry trends;

 

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

 

    levels and volatility of oil and gas prices;

 

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

 

    the highly competitive nature of our business;

 

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

 

    the continued availability of drilling rig components to complete our rig building program;

 

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

 

    the continued availability of qualified personnel; and

 

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

We believe the items we have outlined above are important factors that could cause our actual results to differ materially from those expressed in a forward-looking statement contained in this report or elsewhere. We have discussed many of these factors in more detail elsewhere in this report. These factors are not necessarily all the important factors that could affect us. Unpredictable or unknown factors we

 

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have not discussed in this report could also have material adverse effects on actual results of matters that are the subject of our forward-looking statements. We do not intend to update our description of important factors each time a potential important factor arises, except as required by applicable securities laws and regulations. We advise our security holders that they should (1) be aware that important factors not referred to above could affect the accuracy of our forward-looking statements and (2) use caution and common sense when considering our forward-looking statements. Also, please read the risk factors set forth below.

Item 1A. Risk Factors

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

Risks Relating to the Oil and Gas Industry

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

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

 

    our revenues, cash flows and profitability;

 

    the fair market value of our rig fleet;

 

    our ability to maintain or increase our borrowing capacity;

 

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

 

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

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

 

    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.

 

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Risks Relating to Our Business

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

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

Our acquisition strategy involves various risks.

As a key component of our business strategy, we have pursued and intend to continue to pursue acquisitions of complementary assets and businesses. For example, since March 31, 2003, our rig fleet has increased from 24 to 57 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 previous acquisitions. We may be unable to continue to identify additional suitable acquisition opportunities, negotiate acceptable terms, obtain financing for acquisitions on satisfactory terms or successfully acquire identified targets. Our failure to achieve consolidation savings, to incorporate the acquired businesses and assets into our existing operations successfully or to minimize any unforeseen operational difficulties could have a material adverse effect on our financial condition and results of operations.

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

In addition, we may not have sufficient capital resources to complete additional acquisitions. Historically, we have funded the growth of our rig fleet through a combination of debt and equity financing. We may incur substantial additional indebtedness to finance future acquisitions and also may issue equity securities or convertible securities in connection with such acquisitions. Debt service requirements could represent a significant burden on our results of operations and financial condition and the issuance of additional equity 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 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. In addition to pricing and rig availability, we believe the following factors are also important to our customers in determining which drilling contractor to select:

 

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

 

    the mobility and efficiency of the rigs;

 

    the quality of service and experience of the rig crews;

 

    the safety records of the rigs;

 

    the offering of ancillary services; and

 

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

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

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

 

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We face competition from many competitors with greater resources.

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

 

    better withstand industry downturns;

 

    compete more effectively on the basis of price and technology;

 

    retain skilled rig personnel; and

 

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

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

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 drilling operations, adequate coverage may be unavailable in the future and we might have to bear the full cost of such risks, which could have an adverse effect on our financial condition and results of operations.

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

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

 

    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.

 

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

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

Most of our drilling contracts are with exploration and production companies in search of natural gas. Drilling on land for natural gas generally occurs at deeper drilling depths than drilling for oil. Although deep-depth drilling exposes us to risks similar to risks encountered in shallow-depth drilling, the magnitude of the risk for deep-depth drilling is greater because of the higher costs and greater complexities involved in drilling deep wells. We generally do not insure risks related to operating difficulties other than blowouts. If we do not adequately insure the increased risk from blowouts or if our contractual indemnification rights are insufficient or unfulfilled, our profitability and other results of 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 the federal Occupational Safety and Health Act (“OSHA”) and comparable state statutes. The OSHA hazard communication standard, the Environmental Protection Agency “community right-to-know” regulations under Title III of the Federal Superfund Amendment and Reauthorization Act and comparable state statutes require us to organize and report information about the hazardous materials we use in our operations to employees, state and local government authorities and local citizens.

Environmental laws and regulations are complex and subject to frequent change. In some cases, they can impose liability for the entire cost of cleanup on any responsible party without regard to negligence or fault and can impose liability on us for the conduct of others or conditions others have caused, or for our acts that complied with all applicable requirements when we performed them. We may also be exposed to environmental or other liabilities originating from businesses and assets 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.

 

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

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

From time to time there have been shortages of drilling equipment and supplies during periods of high demand which we believe could reoccur. Shortages could result in increased prices for drilling equipment or supplies that we may be unable to pass on to customers. In addition, during periods of shortages, the delivery times for equipment and supplies can be substantially longer. Any significant delays in our obtaining drilling equipment or supplies could limit drilling operations and jeopardize our relations with customers. In addition, shortages of drilling equipment or supplies could delay and adversely affect our ability to obtain new contracts for our rigs, which could have a material adverse effect on our financial condition and results of operations.

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

Risk Relating to Our Capitalization and Organizational Documents

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

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

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

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

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

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

 

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

 

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

 

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

 

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

 

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Item 1B. Unresolved Staff Comments

None.

Item 2. Properties

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

Item 3. Legal Proceedings

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

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

We did not submit any matter to a vote of our stockholders during the fourth quarter of fiscal 2006.

PART II

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

As of May 12, 2006, 49,591,978 shares of our common stock were outstanding, held by 512 shareholders of record. The number of record holders does not necessarily bear any relationship to the number of beneficial owners of our common stock.

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

 

     Low    High
Fiscal Year Ended March 31, 2006:      

First Quarter

   $ 10.57    $ 16.30

Second Quarter

     14.00      19.93

Third Quarter

     14.25      19.98

Fourth Quarter

     13.10      23.06
Fiscal Year Ended March 31, 2005:      

First Quarter

   $ 5.60    $ 7.99

Second Quarter

     6.75      8.90

Third Quarter

     7.63      10.50

Fourth Quarter

     9.05      14.21
Fiscal Year Ended March 31, 2004:      

First Quarter

   $ 3.57    $ 5.24

Second Quarter

     3.65      4.99

Third Quarter

     3.30      5.20

Fourth Quarter

     4.75      7.35

The last reported sales price for our common stock on the American Stock Exchange on May 12, 2006 was $15.39 per share.

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

 

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Equity Compensation Plan Information

The following table provides information on our equity compensation plans as of March 31, 2006:

 

Plan category

  

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

(a)

  

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

(b)

  

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

(c)

Equity compensation plans approved by security holders

   1,592,833    $ 7.71    1,618,500

Equity compensation plans not approved by security holders

   —        —      —  
                

Total

   1,592,833    $ 7.71    1,618,500
                

Item 6. Selected Financial Data

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

 

     Years Ended March 31,
     2006    2005    2004     2003     2002
     (In thousands, except per share amounts)

Contract drilling revenues

   $ 284,148    $ 185,246    $ 107,876     $ 80,183     $ 68,627

Income (loss) from operations

     77,909      18,774      438       (4,943 )     11,201

Income (loss) before income taxes

     79,813      17,161      (2,216 )     (7,305 )     9,737

Preferred dividends

     —        —        —         —         93

Net earnings (loss) applicable to common stockholders

     50,567      10,812      (1,790 )     (5,086 )     6,225

Earnings (loss) per common share-basic

     1.08      0.31      (0.08 )     (0.31 )     0.41

Earnings (loss) per common share-diluted

     1.06      0.30      (0.08 )     (0.31 )     0.35

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

     —        13,445      44,892       45,855       26,119

Shareholders’ equity

     340,676      221,615      70,836       47,672       33,343

Total assets

     400,678      276,009      143,731       119,694       83,450

Capital expenditures

     128,871      80,388      44,845       33,589       27,597

 

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

Statements we make in the following discussion that express a belief, expectation or intention, as well as those that are not historical fact, are forward-looking statements that are subject to risks, uncertainties and assumptions. Our actual results, performance or achievements, or industry results, could differ materially from those we express in the following discussion as a result of a variety of factors, including general economic and business conditions and industry trends, the continued strength or weakness of the contract land drilling industry in the geographic areas in which we operate, decisions about onshore exploration and development projects to be made by oil and gas companies, the highly competitive nature of our business, our future financial performance, including availability, terms and deployment of capital, the continued availability of qualified personnel, and changes in, or our failure or inability to comply with, government regulations, including those relating to the environment. We have discussed many of these factors in more detail elsewhere in this report, including under the headings “Cautionary Statement Concerning Forward-Looking Statements” in Item 1 and “Risk Factors” in Item 1A. These factors are not necessarily all the important factors that could affect us. Unpredictable or unknown factors we have not discussed in this report could also have material adverse effects on actual results of matters that are the subject of our forward-looking statements. We do not intend to update our description of important factors each time a potential important factor arises, except as required by applicable securities laws and regulations. We advise our shareholders that they should (1) be aware that important factors not referred to above could affect the accuracy of our forward-looking statements and (2) use caution and common sense when considering our forward-looking statements.

Company Overview

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

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 May 12, 2006 our rig fleet consisted of 57 land drilling rigs that drill in depth ranges between 6,000 and 18,000 feet. Fifteen of our rigs are operating in our South Texas division, 18 in our East Texas division, seven in our North Texas division, five in our western Oklahoma division and 12 in our Rocky Mountains divisions. We actively market all of these rigs. We anticipate continued growth of our rig fleet in fiscal year 2007. As of May 12, 2006, we were constructing seven 1000-horsepower diesel electric rigs from new and used components. We expect these rigs to be completed and become available for operation at varying times prior to March 31, 2007. On April 21, 2006, we sold Rig 45 which was a low-horsepower rig that was designed for casing re-entry work and was the least utilized in our rig fleet.

We earn our revenues by drilling oil and gas wells for our customers as our rigs can be used by our customers to drill for either oil or natural gas. We obtain our contracts for drilling oil and gas wells either through competitive bidding or through direct negotiations with customers. Our drilling contracts generally provide for compensation on either a daywork, turnkey or footage basis. Contract terms generally depend on the complexity and risk of operations, the on-site drilling conditions, the type of equipment used and the anticipated duration of the work to be performed. Historically, our contracts provide for the drilling of a single well and typically permit the customer to terminate on short notice. As demand for drilling rigs has improved during the past year, we have entered into more longer-term drilling contracts. As of May 12, 2006, we had 39 contracts with terms of six months to two years in duration, of which 27 have a remaining term in excess of six months. We also have term contracts of one to two years for the seven rigs currently under construction.

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.

 

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

 

     Years Ended March 31,  
     2006     2005     2004  

Utilization Rates

   95 %   96 %   88 %

Revenue Days

   18,164     13,894     8,764  

Number of rigs at period end

   56     50     35  

The primary reason for the increase in the number of revenue days in 2006 over 2005 and 2004 is the increase in size of our rig fleet. For 2007, we anticipate continued growth in revenue days as we continue to construct more rigs and put them into operation. We expect utilization rates for 2007 to be comparable to 2006.

In addition to high commodity prices, we attribute our relatively high utilization rates to a strong sales effort, quality equipment, good field and operations personnel, a disciplined safety approach, and our generally successful performance of turnkey operations during periods of reduced demand for drilling rigs.

We devote substantial resources to maintaining and upgrading our rig fleet. In the short term, these actions result in fewer revenue days and slightly lower utilization; however, in the long term, we believe the upgrades help the marketability of our rigs and improve their operating performance. We expended approximately $21,446,000 on rig upgrades during the year ended March 31, 2006. We have been and are currently performing, between contracts or as necessary, safety and equipment upgrades to the eight rigs we acquired in March 2004 and to 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.

On May 12, 2006, the spot price for West Texas Intermediate crude oil was $72.04, the spot price for Henry Hub natural gas was $6.26 and the Baker Hughes land rig count was 1,503, a 26% increase from 1,196 on May 13, 2005.

The average weekly spot prices of West Texas Intermediate crude oil and Henry Hub natural gas and the average weekly domestic land rig count, per the Baker Hughes land rig count, for each of the previous six years ended March 31, 2006 were:

 

     Years Ended March 31,
     2006    2005    2004    2003    2002    2001

Oil (West Texas Intermediate)

   $ 59.94    $ 45.04    $ 31.47    $ 29.27    $ 24.31    $ 30.40

Natural Gas (Henry Hub)

   $ 9.10    $ 5.99    $ 5.27    $ 4.24    $ 2.96    $ 5.27

U.S. Land Rig Count

     1,329      1,110      964      723      912      841

During fiscal years 2006, 2005 and 2004, most of the wells we drilled for our customers were drilled in search of natural gas. We diversified our operations somewhat in November 2004, when we began operating in the Williston Basin of the Rocky Mountains where our customers drill in search of oil.

Critical Accounting Policies and Estimates

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

 

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

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

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

Asset impairments – We assess the impairment of property and equipment whenever events or circumstances indicate that the carrying value may not be recoverable. Factors that we consider important and which could trigger an impairment review would be our customers’ financial condition and any significant negative industry or economic trends. More specifically, among other things, we consider our contract revenue rates, our rig utilizations rates, cash flows from our drilling rigs, current oil and gas prices, industry analysts’ outlook for the industry and their view of our customers’ access to debt or equity, discussions with major industry suppliers, discussions with officers of our primary lender regarding their experiences and expectations for oil and gas operators in our areas of operations and the trends in the price of used drilling equipment observed by our management. If a review of our drilling rigs indicates that our carrying value exceeds the estimated undiscounted future net cash flows, we are required under applicable accounting standards to write down the drilling equipment to its fair market value. A one percent write-down in the cost of our drilling equipment, at March 31, 2006, would have resulted in a corresponding decrease in our net earnings of approximately $2,136,000 for our fiscal year ended March 31, 2006.

Deferred taxes – We provide deferred taxes for the basis differences in our property and equipment between financial reporting and tax reporting purposes and other costs such as compensation, employee benefit and other accrued liabilities which are deducted in different periods for financial reporting and tax reporting purposes. For property and equipment, basis differences arise from differences in depreciation periods and methods and the value of assets acquired in a business acquisition where we acquire an entity rather than just its assets. For financial reporting purposes, we depreciate the various components of our drilling rigs over five to 15 years and refurbishments over three 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 needed for us to complete the contract and our total cost to complete the contract. Our actual costs could substantially exceed our estimated costs if we encounter problems such as lost circulation, stuck drill pipe or an underground blowout on contracts still in progress subsequent to the release of the financial statements.

We receive payment under turnkey and footage contracts when we deliver to our customer a well completed to the depth specified in the contract, unless the customer authorizes us to drill to a shallower depth. Since 1995, when current management joined our company, we have completed all our turnkey or footage contracts. Although our initial cost estimates for turnkey and footage contracts do not include cost estimates for risks such as stuck drill pipe or loss of circulation, we believe that our experienced management team, our knowledge of geologic formations in our areas of operations, the condition of our drilling equipment and our experienced crews enable us to make reasonably dependable cost estimates and complete contracts according to our drilling plan. While we do bear the risk of loss for cost overruns and other events that are not specifically provided for in our initial cost estimates, our pricing of turnkey and footage contracts takes such risks into consideration. When we encounter, during the course of our drilling operations, conditions unforeseen in the preparation of our original cost estimate, we increase our cost estimate to complete the contract. If we anticipate a loss on a contract in progress at the end of a reporting period due to a change in our cost estimate, we accrue the entire amount of the estimated loss including all costs that are included in our revised estimated cost to complete that contract in our consolidated statement of operations for that reporting period. During fiscal year 2006, we experienced losses on 16 of the 124 turnkey and footage contracts completed, with losses

 

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

Revenues and costs during a reporting period could be affected for contracts in progress at the end of a reporting period which have not been completed before our financial statements for that period are released. We had no turnkey contracts and two footage contracts in progress at March 31, 2006, each of which was completed prior to the release of the financial statements included in this report. Our contract drilling in progress totaled approximately $9,620,000 at March 31, 2006. Of that amount accrued, footage contract revenues were approximately $599,000. The remaining balance of approximately $9,021,000 relates to the revenue recognized but not yet billed on daywork contracts in progress at March 31, 2006. At March 31, 2005, drilling in progress totaled $5,365,000, of which $2,344,000 related to turnkey and footage contracts and $3,021,000 related to daywork contracts.

We estimate an allowance for doubtful accounts based on the creditworthiness of our customers as well as general economic conditions. We evaluate the creditworthiness of our customers based on information obtained from major industry suppliers, current prices of oil and gas and any past experience we have with the customer. Consequently, an adverse change in those factors could affect our estimate of our allowance for doubtful accounts. In some instances, we require new customers to establish escrow accounts or make prepayments. We typically invoice our customers at 15-day intervals during the performance of daywork contracts and upon completion of the daywork contract. Turnkey and footage contracts are invoiced upon completion of the contract. Our typical contract provides for payment of invoices in 10 to 30 days. We generally do not extend payment terms beyond 30 days and have not extended payment terms beyond 60 days for any of our contracts in the last three fiscal years. We had an allowance for doubtful accounts of $200,000 at March 31, 2006, a decrease of $152,000 from $352,000 at March 31, 2005.

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

Our other accrued expenses as of March 31, 2006 include accruals of approximately $643,000 and $1,829,000 for costs incurred under the self-insurance portion of our health insurance and under our workers’ compensation insurance, respectively. We have a deductible of (1) $125,000 per covered individual per year under the health insurance and (2) $250,000 per occurrence under our workers’ compensation insurance, except in North Dakota, where the deductible is $100,000. We accrue for these costs as claims are incurred based on historical claim development data, and we accrue the costs of administrative services associated with claims processing. We also evaluate our claim cost estimates based on estimates provided by the insurance companies that provide claims processing services.

Liquidity and Capital Resources

Sources of Capital Resources

Our rig fleet has grown from eight rigs in August 2000 to 57 rigs as of May 12, 2006. We have financed this growth with a combination of debt and equity financing. We have raised additional equity or used equity for growth nine times since January 2000. We plan to continue to grow our rig fleet. Over the next 12 months, we expect to finance the construction of seven additional rigs from existing cash and cash flows from operations. However, we may finance other growth opportunities through the issuance of debt and the issuance of additional shares of our common stock.

We issued common stock during fiscal years 2005 and 2006 as follows:

 

Description

   Date    Number
of Shares
   Price
Per Share

Conversion of $28,000,000 6.75% convertible subordinated debentures to common stock

   August 11, 2004    6,496,519    $ 4.31

Public offering of common stock (1)

   August 11, 2004    4,000,000    $ 6.61

Public offering of common stock - over allotment option (1)

   August 31, 2004    600,000    $ 6.61

Public offering of common stock (1)

   March 22, 2005    6,945,000    $ 11.78

Public offering of common stock (1)

   February 10, 2006    3,000,000    $ 20.63

(1) Price per share is net of underwriter’s commission.

 

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We have a $57,000,000 credit facility with a group of lenders consisting of a $7,000,000 revolving line and letter of credit facility and a $50,000,000 acquisition facility for the acquisition of drilling rigs, drilling rig transportation equipment and associated equipment. Frost National Bank is the administrative agent and lead arranger under the credit facility, and the lenders include Frost National Bank, the Bank of Scotland and Zions First National Bank. Borrowings under the credit facility bear interest at a rate equal to Frost National Bank’s prime rate (7.75% at March 31, 2006) or, at our option, at LIBOR plus a percentage ranging from 1.75% to 2.5%, based on our operating leverage ratio. Borrowings are secured by most of our assets, including all our drilling rigs and associated equipment and receivables. At March 31, 2006, we had no borrowings under the acquisition facility and we had used approximately $3,050,000 of availability under the revolving line and letter of credit facility through the issuance of letters of credit in the ordinary course of business. We expect to renew both the revolving line and letter of credit facility and acquisition facility when they mature in October 2006.

Uses of Capital Resources

For the years ended March 31, 2006 and 2005, the additions to our property and equipment consisted of the following:

 

     Years Ended March 31,
     2006    2005

Drilling rigs (1)

   $ 72,311,690    $ 53,341,421

Other drilling equipment

     51,403,189      22,674,774

Transportation equipment

     3,491,554      2,717,181

Other

     1,665,014      1,655,108
             
   $ 128,871,447    $ 80,388,484
             

(1) Includes capitalized interest costs of $194,500 in 2006 and $86,819 in 2005.

As of March 31, 2006, we were constructing, from new and used components, nine 1000-horsepower diesel electric rigs. We placed two of these rigs into service in April and May 2006 and we expect to place the remaining seven rigs into service at varying times prior to March 31, 2007. As of March 31, 2006, we had incurred approximately $26,172,000 of the approximately $74,100,000 of construction costs on these rigs.

For fiscal year 2007, we project capital expenditures excluding new rig construction to be approximately $76,500,000, comprised of routine rig capital expenditures of approximately $43,700,000, rig upgrade expenditures of approximately $21,900,000, transportation equipment capital expenditures of approximately $9,600,000 and other capital expenditures of approximately $1,300,000. We expect to fund these capital expenditures primarily from operating cash flow in excess of our working capital and other normal cash flow requirements.

Working Capital

Our working capital increased to $106,904,106 at March 31, 2006 from $76,326,669 at March 31, 2005. Our current ratio, which we calculate by dividing our current assets by our current liabilities, was 4.28 at March 31, 2006, compared to 3.70 at March 31, 2005.

Our operations have historically generated cash flows sufficient to at least meet our requirements for debt service and normal capital expenditures. However, during periods when higher percentages of our contracts are turnkey and footage contracts, our short-term working capital needs could increase. If necessary, we can defer rig upgrades to improve our cash position. The significant improvement in operating cash flow for the year ended March 31, 2006 over March 31, 2005 is due primarily to the approximately $39,755,000 improvement in net earnings, plus the increase of approximately $10,297,000 in depreciation and amortization expense. We believe our cash generated by operations and our ability to borrow under the currently unused portion of our line of credit and letter of credit facility of approximately $3,950,000, net of reductions of approximately $3,050,000 for outstanding letters of credit as of March 31, 2006, should allow us to meet our routine financial obligations for the foreseeable future.

 

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

 

     March 31,    Change  
     2006    2005   

Cash and cash equivalents

   $ 91,173,764    $ 69,673,279    $ 21,500,485  

Marketable securities

     —        1,000,000      (1,000,000 )

Receivables

     35,544,543      26,108,291      9,436,252  

Contract drilling

     9,620,179      5,364,529      4,255,650  

Deferred tax receivable

     989,895      569,548      420,347  

Prepaid expenses

     2,207,853      1,876,843      331,010  
                      

Current assets

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

Current debt

     —        5,415,001      (5,415,001 )

Accounts payable

     16,040,568      15,621,647      418,921  

Accrued payroll

     3,383,435      2,706,623      676,812  

Income tax payable

     6,834,877      195,949      6,638,928  

Prepaid drilling contracts

     139,769      172,750      (32,981 )

Accrued expenses

     6,233,479      4,153,851      2,079,628  
                      
     32,632,128      28,265,821      4,366,307  
                      

Working capital

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

The large cash balance at March 31, 2006 was primarily due to our sale of shares of common stock on February 10, 2006 for net proceeds of approximately $61,700,000. The large cash balance at March 31, 2005 was primarily due to our sale of shares of common stock on March 22, 2005 for net proceeds of approximately $81,300,000, of which $20,000,000 was used to reduce long-term debt and $61,300,000 was included in the March 31, 2005 cash balance.

The increase in our receivables and contract drilling in progress at March 31, 2006 from March 31, 2005 was due to our operating six additional rigs and the increase of approximately $4,500 per day in average revenue rates.

Substantially all our prepaid expenses at March 31, 2006 consisted of prepaid insurance. The increase in prepaid insurance was primarily due to an increase in insurance premiums resulting from the increase in the size of our drilling rig fleet from 50 rigs at March 31, 2005 to 56 rigs at March 31, 2006 and an increase in liability insurance coverage limits.

The increase in accounts payable was due to nine drilling rigs under construction at March 31, 2006, as compared to two drilling rigs under construction at March 31, 2005. As of March 31, 2006, we had incurred approximately $26,172,000 of construction costs on these rigs. This increase was partially offset by a decrease in accounts payable due to fewer turnkey and footage contracts completed during March 2006 and in progress at March 31, 2006. We had no turnkey and two footage contracts in progress at March 31, 2006, compared to six turnkey and six footage contracts in progress at March 31, 2005.

The increase in accrued payroll was primarily due to the increase in our number of employees due to the rig additions, the increase in rig employee wage rates and the increase in the number of payroll days included in the accrual from ten days at March 31, 2005 to 11 days at March 31, 2006.

The increase in income tax payable at March 31, 2006 was due to the increase in income before income taxes, which was $79,813,220 for the year ended March 31, 2006, as compared to $17,161,126 for the year ended March 31, 2005. This increase was partially offset by use of all of our net operating loss carryforwards during the year ended March 31, 2006. Income tax payable at March 31, 2005 only included an accrual for alternative minimum taxes.

The total increase in accrued expenses at March 31, 2006 from March 31, 2005 was due to an increase of approximately $1,611,000 in the accrual for our insurance deductibles and additional insurance premiums and an increase in bonus accruals of approximately $721,000. These increases were partially offset by a decrease of approximately $252,000 in accrued property taxes and other accrued expense items.

 

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Long-term Debt

We had no long-term debt outstanding at March 31, 2006. See “Sources of Capital Resources” for a description of our $57,000,000 credit facility.

Contractual Obligations

We do not have any routine purchase obligations. However, as of March 31, 2006, we were in the process of constructing nine drilling rigs, as described above. The following table includes all of our contractual obligations at March 31, 2006:

 

     Payments Due by Period

Contractual Obligations

   Total    Less than 1
year
  

1-3

years

  

4-5

years

   More than 5
years

Operating Lease Obligations

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

Total

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

Debt Requirements

Our long-term debt at March 31, 2005 consisted of borrowings under our credit facility aggregating to $18,077,778. In August 2005, we repaid the then remaining outstanding balance of approximately $16,500,000 under our acquisition facility. See “Sources of Capital Resources.”

The sum of (1) the draws and (2) the amount of all outstanding letters of credit issued for our account under the revolving line and letter of credit facility portion of our credit facility are limited to 75% of our eligible accounts receivable, not to exceed $7,000,000. Therefore, if 75% of our eligible accounts receivable was less than $7,000,000, our ability to draw under this line would be reduced. At March 31, 2006, we had no outstanding advances under this line of credit, we had outstanding letters of credit of approximately $3,050,000 and 75% of our eligible accounts receivable was approximately $25,682,000. The letters of credit have been issued to three workers’ compensation insurance companies to secure possible future claims under the deductibles on these policies. It is our practice to pay any amounts due under these deductibles as they are incurred. Therefore, we do not anticipate that the lenders will be required to fund any draws under these letters of credit. The scheduled termination date of the revolving line and letter of credit facility portion of our new credit facility is October 27, 2006.

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

 

    our failure to make required payments;

 

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

 

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

 

    our incurrence of additional indebtedness in excess of $3,000,000, to the extent not otherwise allowed by the credit facility;

 

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

 

    any payment of cash dividends on our common stock.

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

 

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Results of Operations

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

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

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

Footage Contracts. Under footage contracts, we are paid a fixed amount for each foot drilled, regardless of the time required or the problems encountered in drilling the well. We typically pay more of the out-of-pocket costs associated with footage contracts as compared to daywork contracts. Similar to turnkey contracts, under a footage contract we assume most of the risks associated with drilling operations that the operator generally assumes under a daywork contract.

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

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

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

 

     Years Ended March 31,  
     2006     2005     2004  

Daywork Contracts

   89 %   52 %   47 %

Turnkey Contracts

   4 %   43 %   50 %

Footage Contracts

   7 %   5 %   3 %

We had no turnkey contracts in progress at March 31, 2006, compared to six turnkey contracts in progress at March 31, 2005. We had two footage contracts in progress at March 31, 2006, compared to six footage contracts in progress at March 31, 2005.

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

 

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Statements of Operations Analysis

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

 

     Years Ended March 31,  
     2006     2005     2004  

Contract drilling revenues:

      

Daywork contracts

   $ 252,103,112     $ 95,997,451     $ 50,144,773  

Turnkey contracts

     10,829,977       80,210,813       54,234,756  

Footage contracts

     21,214,885       9,038,184       3,496,004  
                        

Total contract drilling revenues

   $ 284,147,974     $ 185,246,448     $ 107,875,533  
                        

Contract drilling costs:

      

Daywork contracts

   $ 143,399,044     $ 68,415,608     $ 42,903,525  

Turnkey contracts

     7,449,088       63,421,106       42,761,928  

Footage contracts

     15,632,438       6,646,045       2,838,649  
                        

Total contract drilling costs

   $ 166,480,570     $ 138,482,759     $ 88,504,102  
                        

Drilling margin:

      

Daywork contracts

   $ 108,704,068     $ 27,581,843     $ 7,241,248  

Turnkey contracts

     3,380,889       16,789,707       11,472,828  

Footage contracts

     5,582,447       2,392,139       657,355  
                        

Total drilling margin

   $ 117,667,404     $ 46,763,689     $ 19,371,431  
                        

Revenue days by type of contract:

      

Daywork contracts

     16,138       8,685       5,626  

Turnkey contracts

     558       4,471       2,827  

Footage contracts

     1,468       738       311  
                        

Total revenue days

     18,164       13,894       8,764  
                        

Contract drilling revenue per revenue day

   $ 15,643     $ 13,333     $ 12,309  

Contract drilling costs per revenue day

   $ 9,165     $ 9,967     $ 10,099  

Drilling margin per revenue day

   $ 6,478     $ 3,366     $ 2,210  

Rig utilization rates

     95 %     96 %     88 %

Average number of rigs during the period

     52.3       40.1       27.3  

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

 

     Years Ended March 31,  
     2006     2005     2004  

Reconciliation of drilling margin to net earnings:

      

Drilling margin

   $ 117,667,404     $ 46,763,689     $ 19,371,431  

Depreciation and amortization

     (33,387,523 )     (23,090,909 )     (16,160,494 )

General and administrative expense

     (6,522,842 )     (4,657,013 )     (2,772,730 )

Bad debt (expense) recovery

     152,000       (242,000 )     —    

Other income (expense)

     1,904,181       (1,612,641 )     (2,654,563 )

Income tax (expense) benefit

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

Net earnings

   $ 50,566,603     $ 10,811,625     $ (1,790,057 )
                        

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

 

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

Our contract drilling costs grew by approximately $27,998,000, or 20%, in fiscal year 2006 from fiscal year 2005, primarily due to an increase in the number of revenue days resulting from the increase in the number of rigs in our fleet, which was partially offset by the 1% decrease in rig utilization discussed above. The $802 decline in average contract drilling cost per revenue day was primarily due to the shift to more daywork revenue days as a percentage of total revenue days. Daywork days represented 89% of revenue days in the fiscal year 2006, compared to 63% in fiscal year 2005. Under turnkey and footage contracts, we provide supplies and materials such as fuel, drill bits, casing and drilling fluids, which significantly adds to drilling costs for turnkey and footage contracts. These costs are also included in the revenues we recognize for turnkey and footage contracts, resulting in higher revenue rates per day for turnkey and footage contracts compared to daywork contracts which do not include such costs.

Our 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).

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

Our depreciation and amortization expense in fiscal year 2005 increased approximately $7,000,000, or 43%, from 2004. The increase in 2005 over 2004 resulted from our addition of 15 drilling rigs and related equipment in 2005 at a cost of approximately $52,600,000 and rig upgrade costs $5,512,000.

Our general and administrative expenses increased by approximately $1,866,000, or 40%, in fiscal year 2006 from fiscal year 2005. The increase resulted primarily from increases in payroll costs, bonus accrual costs, professional fees, office rent and insurance costs. During fiscal year 2006, payroll costs increased by approximately $975,000, due to pay raises, an increase in the number of employees in our corporate office and an increase in bonus costs of approximately $256,000 as compared to fiscal year 2005. Professional fees increased by approximately $453,000, office rent increased by approximately $142,000 and insurance costs increased by approximately $119,000.

Our general and administrative expenses increased by approximately $1,900,000, or 68%, in fiscal year 2005 from fiscal year 2004. The increase resulted from increased payroll costs, professional and consulting costs, insurance costs and director fees. Payroll related costs increased by approximately $894,000 due to pay increases, staff additions and an increase in bonus costs of approximately $610,000. 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 directors and officers liability insurance coverage.

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

Our other expense decreased by approximately $1,042,000 in fiscal year 2005 from fiscal year 2004 primarily due to the decrease in interest expense that resulted from decreased outstanding debt balances. Long-term debt outstanding decreased from $48,511,222 at March 31, 2004 to $18,077,078 at March 31, 2005.

Our contract land drilling operations are subject to various federal and state laws and regulations designed to protect the environment. Maintaining compliance with these regulations is part of our day-to-day operating procedures. We monitor each of our yard facilities and each of our rig locations on a day-to-day basis for potential environmental spill risks. In addition, we maintain a spill prevention control and countermeasures plan for each yard facility and each rig location. The costs of these procedures represent only a small portion of our routine employee training, equipment maintenance and job site maintenance costs. We estimate the annual compliance costs for this program is approximately $292,000. We are not aware of any potential environmental clean-up obligations that would have a material adverse effect on our financial condition or results of operations.

Our effective income tax rates of 36.6% for fiscal year 2006, 37.0% for fiscal year 2005 and 19.2% for fiscal year 2004, differ from the federal statutory rate of 35% for fiscal year 2006 and 34% for fiscal year 2005 and fiscal year 2004, due to permanent differences and state income taxes. Permanent differences are costs included in results of operations in the accompanying financial statements which are not fully deductible for federal income tax purposes. At March 31, 2005, we had a net operating loss carryforwards for income tax purposes of approximately $16,500,000, which was fully utilized in fiscal year 2006.

 

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Inflation

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

We are experiencing increases in costs for rig repairs and maintenance and costs of rig upgrades and new rig construction due to the increased industry-wide rig count. We estimate these costs increased between 10% and 15% in fiscal year 2006, and we expect similar cost increases in fiscal year 2007. We anticipate that we will be able to recover these cost increases through improvements in our daywork revenue rates.

Off Balance Sheet Arrangements

We do not currently have any off balance sheet arrangements.

Recently Issued Accounting Standards

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

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

Item 7A. Quantitative and Qualitative Disclosures About Market Risk

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

We are subject to market risk exposure related to changes in interest rates on our outstanding floating rate debt. However, at March 31, 2006, we had no outstanding debt subject to variable interest rates.

 

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Item 8. Financial Statements and Supplementary Data

PIONEER DRILLING COMPANY

INDEX TO CONSOLIDATED FINANCIAL STATEMENTS

 

     Page

Reports of Independent Registered Public Accounting Firm

   30

Consolidated Balance Sheets as of March 31, 2006 and 2005

   32

Consolidated Statements of Operations for the Years Ended March 31, 2006, 2005 and 2004

   33

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

   34

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

   35

Notes to Consolidated Financial Statements

   36

 

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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, 2006 and 2005, and the related consolidated statements of operations, stockholders’ equity, and cash flows for each of the years in the three-year period ended March 31, 2006. In connection with our audits of the consolidated financial statements, we also have audited the financial statement schedule II. These consolidated financial statements and financial statement schedule are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated financial statements and financial statement schedule based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material 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, 2006 and 2005, and the results of their operations and their cash flows for each of the years in the three-year period ended March 31, 2006, in conformity with U.S. generally accepted accounting principles. Also in our opinion, the related financial statement schedule, when considered in relation to the basic consolidated financial statements taken as a whole, presents fairly, in all material respects, the information set forth therein.

We also have audited, in accordance with the standards of the PCAOB, the effectiveness of Pioneer Drilling Company’s internal control over financial reporting as of March 31, 2006, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), and our report dated May 24, 2006 expressed an unqualified opinion on management’s assessment of, and the effective operation of, internal control over financial reporting.

KPMG LLP

San Antonio, Texas

May 24, 2006

 

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

The Board of Directors and Stockholders

Pioneer Drilling Company:

We have audited management’s assessment, included in Management’s Report on Internal Control over Financial Reporting in Item 9A of Pioneer Drilling Company’s Annual Report on Form 10-K for the year ended March 31, 2006, that Pioneer Drilling Company and subsidiaries maintained effective internal control over financial reporting as of March 31, 2006, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Pioneer Drilling Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting. Our responsibility is to express an opinion on management’s assessment and an opinion on the effectiveness of the Company’s internal control over financial reporting based on our audit.

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

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

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

In our opinion, management’s assessment that Pioneer Drilling Company maintained effective internal control over financial reporting as of March 31, 2006, is fairly stated, in all material respects, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Also, in our opinion, Pioneer Drilling Company maintained, in all material respects, effective internal control over financial reporting as of March 31, 2006, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).

We also have audited, in accordance with the standards of the PCAOB, the consolidated balance sheets of Pioneer Drilling Company and subsidiaries as of March 31, 2006 and 2005, and the related consolidated statements of operations, stockholders’ equity, and cash flows for each of the years in the three-year period ended March 31, 2006, and our report dated May 24, 2006 expressed an unqualified opinion on those consolidated financial statements.

KPMG LLP

San Antonio, Texas

May 24, 2006

 

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PIONEER DRILLING COMPANY AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

 

     March 31,  
     2006    2005  
ASSETS      

Current assets:

     

Cash and cash equivalents

   $ 91,173,764    $ 69,673,279  

Marketable securities

     —        1,000,000  

Receivables:

     

Trade, net

     35,544,543      26,108,291  

Contract drilling in progress

     9,620,179      5,364,529  

Current deferred income taxes

     989,895      569,548  

Prepaid expenses

     2,207,853      1,876,843  
               

Total current assets

     139,536,234      104,592,490  
               

Property and equipment, at cost:

     

Drilling rigs and equipment

     328,673,207      216,286,747  

Transportation equipment

     9,169,461      6,469,519  

Land, buildings and other

     3,925,614      2,691,673  
               
     341,768,282      225,447,939  

Less accumulated depreciation and amortization

     80,984,991      54,881,488  
               

Net property and equipment

     260,783,291      170,566,451  

Intangible and other assets

     358,180      850,381  
               

Total assets

   $ 400,677,705    $ 276,009,322  
               
LIABILITIES AND SHAREHOLDERS’ EQUITY      

Current liabilities:

     

Notes payable

   $ —      $ 681,975  

Current installments of long-term debt

     —        4,666,667  

Current installments of capital lease obligations

     —        66,359  

Accounts payable

     16,040,568      15,621,647  

Income tax payable

     6,834,877      195,949  

Prepaid drilling contracts

     139,769      172,750  

Accrued expenses:

     

Payroll and payroll taxes

     3,383,435      2,706,623  

Other

     6,233,479      4,153,851  
               

Total current liabilities

     32,632,128      28,265,821  

Long-term debt, less current installments

     —        13,411,111  

Capital lease obligations, less current installments

     —        33,906  

Non-current liabilities

     387,524      400,000  

Deferred income taxes

     26,982,526      12,283,070  
               

Total liabilities

     60,002,178      54,393,908  
               

Commitments and contingencies

     

Shareholders’ equity:

     

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

     —        —    

Common stock $.10 par value; 100,000,000 shares authorized; 49,591,978 shares and 45,893,311 shares issued and outstanding at March 31, 2006 and March 31, 2005, respectively

     4,959,197      4,589,331  

Additional paid-in capital

     288,356,164      220,232,520  

Accumulated earnings (deficit)

     47,360,166      (3,206,437 )
               

Total shareholders’ equity

     340,675,527      221,615,414  
               

Total liabilities and shareholders’ equity

   $ 400,677,705    $ 276,009,322  
               

See accompanying notes to consolidated financial statements.

 

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PIONEER DRILLING COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

 

     Years Ended March 31,  
     2006     2005     2004  

Contract drilling revenues

   $ 284,147,974     $ 185,246,448     $ 107,875,533  
                        

Costs and expenses:

      

Contract drilling

     166,480,570       138,482,759       88,504,102  

Depreciation and amortization

     33,387,523       23,090,909       16,160,494  

General and administrative

     6,522,842       4,657,013       2,772,730  

Bad debt expense (recovery)

     (152,000 )     242,000       —    
                        

Total operating costs and expenses

     206,238,935       166,472,681       107,437,326  
                        

Income from operations

     77,909,039       18,773,767       438,207  
                        

Other income (expense):

      

Interest expense

     (236,012 )     (1,722,393 )     (2,807,822 )

Interest income

     2,068,767       173,318       101,584  

Other

     71,426       37,267       51,675  

Loss from early extinguishment of debt

     —         (100,833 )     —    
                        

Total other income (expense)

     1,904,181       (1,612,641 )     (2,654,563 )
                        

Income before income taxes

     79,813,220       17,161,126       (2,216,356 )

Income tax (expense) benefit

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

Net earnings (loss)

   $ 50,566,603     $ 10,811,625     $ (1,790,057 )
                        

Earnings (loss) per common share - Basic

   $ 1.08     $ 0.31     $ (0.08 )
                        

Earnings (loss) per common share - Diluted

   $ 1.06     $ 0.30     $ (0.08 )
                        

Weighted average number of shares outstanding - Basic

     46,808,323       34,543,695       22,585,612  
                        

Weighted average number of shares outstanding - Diluted

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

See accompanying notes to consolidated financial statements.

 

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PIONEER DRILLING COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF SHAREHOLDERS’ EQUITY AND COMPREHENSIVE INCOME

 

     Shares
Common
   Amount
Common
  

Additional

Paid In

Capital

   Accumulated
Deficit
    Total
Shareholders’
Equity
 

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  

Comprehensive income:

             

Net earnings

   —        —        —        50,566,603       50,566,603  
                   

Total comprehensive income

   —        —        —        —         50,566,603  
                   

Issuance of common stock for:

             

Sale, net of related expenses of $968,361

   3,000,000      300,000      61,401,639      —         61,701,639  

Exercise of options and related income tax benefits of $4,009,945

   698,667      69,866      6,722,005      —         6,791,871  
                                   
   49,591,978    $ 4,959,197    $ 288,356,164    $ 47,360,166     $ 340,675,527  
                                   

See accompanying notes to consolidated financial statements.

 

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PIONEER DRILLING COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

 

     Years Ended March 31,  
     2006     2005     2004  

Cash flows from operating activities:

      

Net earnings (loss)

   $ 50,566,603     $ 10,811,627     $ (1,790,057 )

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

      

Depreciation and amortization

     33,387,523       23,090,909       16,160,494  

Allowance for doubtful accounts

     (152,000 )     242,000       —    

Loss on dispositions of property and equipment

     2,895,752       696,345       816,104  

Deferred income taxes

     14,279,109       5,987,991       119,038  

Change in other assets

     209,525       (123,263 )     (40,000 )

Change in non-current liabilities

     (12,476 )     —         —    

Changes in current assets and liabilities:

      

Receivables

     (13,539,902 )     (11,682,035 )     (11,103,862 )

Prepaid expenses

     (331,010 )     (540,507 )     (422,150 )

Accounts payable

     418,921       2,350,658       (935,597 )

Income tax payable

     6,638,928       195,949       444,900  

Prepaid drilling contracts

     (32,981 )     172,750       —    

Accrued expenses

     2,756,442       2,462,523       1,576,096  
                        

Net cash provided by operating activities

     97,084,434       33,664,947       4,824,966  
                        

Cash flows from financing activities:

      

Proceeds from notes payable

     —         41,354,367       4,110,019  

Proceeds from exercise of options

     6,791,871       958,412       673,794  

Proceeds from common stock, net of offering cost of $968,361 in 2006, of $5,807,193 in 2005 and $1,654,753 in 2004

     61,701,639       111,009,058       22,105,247  

Payments of debt

     (18,860,018 )     (43,809,329 )     (4,048,744 )
                        

Net cash provided by financing activities

     49,633,492       109,512,508       22,840,316  
                        

Cash flows from investing activities:

      

Business acquisitions

     —         (35,200,000 )     (14,500,000 )

Purchases of property and equipment

     (128,871,447 )     (45,188,484 )     (28,222,094 )

Proceeds from sale (purchase) of marketable securities, net

     1,000,000       3,550,000       (1,900,000 )

Proceeds from sale of property and equipment

     2,654,006       1,518,549       419,658  
                        

Net cash used in investing activities

     (125,217,441 )     (75,319,935 )     (44,202,436 )
                        

Net increase (decrease) in cash and cash equivalents

     21,500,485       67,857,520       (16,537,154 )

Beginning cash and cash equivalents

     69,673,279       1,815,759       18,352,913  
                        

Ending cash and cash equivalents

   $ 91,173,764     $ 69,673,279     $ 1,815,759  
                        

Supplementary disclosure:

      

Interest paid

   $ 407,158     $ 2,407,193     $ 2,821,041  

Income tax paid (refunded)

   $ 4,321,619     $ (30,000 )   $ (990,237 )

Debenture conversion - common stock issued

   $ —       $ 28,000,000     $ —    

Acquisition - common stock issued

   $ —       $ —       $ 2,122,650  

Tax benefit from exercise of nonqualified options

   $ 4,009,945     $ 204,964     $ 52,423  

See accompanying notes to consolidated financial statements.

 

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PIONEER DRILLING COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1. Organization and Summary of Significant Accounting Policies

Business and Principles of Consolidation

Pioneer Drilling Company provides contract land drilling services to its customers in select oil and natural gas exploration and production regions in the United States. As of March 31, 2006, our rig fleet consisted of 56 operating drilling rigs, 15 of which were operating in our South Texas division, 18 of which were operating in our East Texas division, six of which were operating in our North Texas division, five of which were operating in our western Oklahoma division and 12 of which were operating in our Rocky Mountain divisions. We conduct our operations through our principal operating subsidiary, Pioneer Drilling Services, Ltd. The accompanying consolidated financial statements include our accounts and the accounts of our wholly owned subsidiaries. We have eliminated all intercompany accounts and transactions in consolidation.

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

Income Taxes

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

Earnings (Loss) Per Common Share

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

 

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Stock-based Compensation

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

 

     Years Ended March 31,  
     2006     2005     2004  

Net earnings (loss)-as reported

   $ 50,566,603     $ 10,811,625     $ (1,790,057 )

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

     (1,893,785 )     (1,175,191 )     (662,933 )
                        

Net earnings (loss)-pro forma

   $ 48,672,818     $ 9,636,434     $ (2,452,990 )
                        

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

   $ 1.08     $ 0.31     $ (0.08 )

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

   $ 1.06     $ 0.30     $ (0.08 )

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

   $ 1.04     $ 0.28     $ (0.11 )

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

   $ 1.02     $ 0.27     $ (0.11 )

Weighted-average fair value of options granted during the year

   $ 6.47     $ 8.85     $ 4.46  

We estimate the fair value of each option grant on the date of grant using a Black-Scholes options-pricing model. The model assumed, for the years ended March 31, 2006, 2005 and 2004:

 

     2006     2005     2004  

Expected volatility

   52 %   86 %   94 %

Weighted-average risk-free interest rates

   4.0 %   3.7 %   3.3 %

Expected life in years

   4.1     5     5  

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

Revenue and Cost Recognition

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

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

 

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

We accrue estimated costs on turnkey and footage contracts for each day of work completed based on our estimate of the total cost to complete the contract divided by our estimate of the number of days to complete the contract. Contract costs include labor, materials, supplies, repairs, maintenance, operating overhead allocations and allocations of depreciation and amortization expense. We charge general and administrative expenses to expense as we incur them. Changes in job performance, job conditions and estimated profitability on uncompleted contracts may result in revisions to costs and income. When we encounter, during the course of our drilling operations, conditions unforeseen in the preparation of our original cost estimate, we immediately increase our cost estimate for the additional costs to complete the contract. If we anticipate a loss on a contract in progress at the end of a reporting period due to a change in our cost estimate, we immediately accrue the entire amount of the estimated loss including all costs that are included in our revised estimated cost to complete that contract in our consolidated statement of operations for that reporting period.

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

Prepaid Expenses

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

Property and Equipment

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

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

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

Cash and Cash Equivalents

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

For purposes of the statements of cash flows, we consider all highly liquid debt instruments purchased with a maturity of three months or less to be cash equivalents. Cash equivalents consist of investments in corporate and government money market accounts. Cash equivalents at March 31, 2006 and 2005 were $85,618,000 and $65,046,000, respectively.

Marketable Securities

Marketable securities consist of auction rate seven-day preferred securities whose market value is equal to their cost. The objective of investing in these securities is to improve our yield on short-term investments of cash. There were no realized or unrealized gains or losses relating to marketable securities during the years ended March 31, 2006, 2005 and 2004.

 

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Trade Accounts Receivable

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

Intangible and Other Assets

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

Derivative Instruments and Hedging Activities

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

Related Party Transactions

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

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

 

     2006    2005    2004

R&B Answering Service

        

Purchases

   $ 16,915    $ 18,218    $ 13,526

Payments

   $ 19,965    $ 17,112    $ 12,544

Frontier Services, Inc.

        

Purchases

   $ 5,953    $ 81,254    $ 118,660

Payments

   $ 9,302    $ 93,709    $ 136,818

Our Chief Operating Officer, Senior Vice President of Marketing, and Vice President and Operations Manager occasionally acquire a 1% to 5% minority working interest in oil and gas wells that we drill for one of our customers. We recognized contract drilling revenues of approximately $455,000, $508,000 and $228,000 on these wells during fiscal years 2006, 2005 and 2004, respectively.

 

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Recently Issued Accounting Standards

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

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

Reclassifications

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

2. Acquisitions

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

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

 

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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 obligation

     —        (500,000 )     (500,000 )
                       
   $ 28,000,000    $ 7,200,000     $ 35,200,000  
                       

The following pro forma information gives effect to the Wolverine and Allen Drilling acquisitions as though they were effective as of the beginning of fiscal year 2005 and 2004. Pro forma adjustments primarily relate to additional depreciation, amortization and interest costs. The information reflects our historical data and historical data from these acquired businesses for the periods indicated. The pro forma data may not be indicative of the results we would have achieved had we completed these acquisitions on April 1, 2003 or 2004, or that we may achieve in the future. The pro forma financial information should be read in conjunction with the accompanying historical financial statements.

 

    

Pro Forma

Years Ended March 31,

 
     2005    2004  

Total revenues

   $ 208,394,551    $ 132,287,140  

Net earnings (loss)

   $ 11,943,137    $ (2,100,116 )

Earnings (loss) per common share:

     

Basic

   $ 0.35    $ (0.09 )

Diluted

   $ 0.33    $ (0.09 )

 

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

Our long-term debt is described below:

 

     March 31,  
     2006    2005  

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

   $

        —  

 

   $ 18,077,778  
               
     —        18,077,778  

Less current installments

     —        (4,666,667 )
               
   $ —      $ 13,411,111  
               

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

The sum of (1) the draws and (2) the amount of all outstanding letters of credit issued for our account under the revolving line and letter of credit facility portion of our credit facility are limited to 75% of our eligible accounts receivable, not to exceed $7,000,000. Therefore, if 75% of our eligible accounts receivable was less than $7,000,000, our ability to draw under this line would be reduced. At March 31, 2006, we had no outstanding advances under this line of credit, we had outstanding letters of credit of approximately $3,050,000 and 75% of our eligible accounts receivable was approximately $25,682,000. The letters of credit have been issued to three workers’ compensation insurance companies to secure possible future claims under the deductibles on these policies. It is our practice to pay any amounts due under these deductibles as they are incurred. Therefore, we do not anticipate that the lenders will be required to fund any draws under these letters of credit.

At March 31, 2006, we were in compliance with all covenants contained in the credit agreement related to our credit facility. Those covenants include, among others, requirements that we maintain a debt to total capitalization ratio of not greater than 0.3 to 1, a fixed charged coverage ratio of not less than 1.5 to 1 and an operating leverage ratio of not more than 3 to 1. The covenants also restrict us from paying dividends, restrict us from the sale of assets not permitted by the credit facility and restrict us from the incurrence of additional indebtedness in excess of $3,000,000, to the extent not otherwise allowed by the credit facility.

In October 2001, we issued $18,000,000 of 6.75% convertible subordinated debentures to WEDGE Energy Services, L.L.C. (“WEDGE”). In July 2002, we issued $9,000,000 and $1,000,000 of 6.75% convertible subordinated debentures to WEDGE and to William H. White, a former Director of our Company and the former President of WEDGE, respectively. These debentures were due by July 2007. In addition, these debentures were convertible into 6,496,519 shares of common stock at $4.31 per share and redeemable at a scheduled premium. On August 11, 2004, we converted these debentures in accordance with their terms into 6,496,519 shares of our common stock.

Notes payable at March 31, 2005 consisted of a $681,975 insurance premium note due on August 26, 2005, plus interest at the rate of 3.15% per year.

 

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4. Leases

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

 

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

 

    a 4-acre division storage yard in Decatur, Texas, at a cost of $800 per month, pursuant to a lease extending through September 2006;

 

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

 

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

 

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

Rent expense under these operating leases for the years ended March 31, 2006, 2005 and 2004 was $283,628, $102,077 and $278,746, respectively.

Future lease obligations as of March 31, 2006 were as follows:

 

Year Ended

March 31,

    

2007

   $ 243,104

2008

     234,930

2009

     212,073

2010

     215,238

2011

     213,913

Thereafter

     607,006
      
   $ 1,726,264
      

5. Income Taxes

Our provision for income taxes consists of the following:

 

     Years Ended March 31,  
     2006    2005    2004  

Current tax - state

   $ 701,124    $ 56,400    $ —    

Current tax - federal

     14,266,384      335,109      —    

Deferred tax - state

     312,510      55,164      —    

Deferred tax - federal

     13,966,599      5,902,828      (426,299 )
                      

Income tax expense (benefit)

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

 

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The following is a reconciliation of income tax expense (benefit) to income taxes computed by applying the federal statutory income tax rate (35% for fiscal year 2006 and 34% for fiscal years 2005 and 2004) to income (loss) before income taxes:

 

     Years Ended March 31,  
     2006     2005    2004  

Expected tax expense (benefit)

   $ 27,934,627     $ 5,834,783    $ (753,561 )

Tax basis adjustment to 35% for prior year deferred tax components

     813,936       —        —    

Club dues, meals and entertainment

     32,344       24,050      13,941  

State income taxes

     658,862       92,388      —    

Other

     (193,152 )     398,280      313,321  
                       
   $ 29,246,617     $ 6,349,501    $ (426,299 )
                       

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

 

     March 31,
     2006    2005

Deferred tax assets:

     

Vacation expense accruals

   $ 104,338    $ 71,446

Workers compensation and health insurance accruals

     812,038      378,423

Bad debt expense

     73,520      119,680

Net operating loss carryforwards

     —        5,616,861

Alternative minimum tax credit

     —        311,915

Deferred lease liability

     32,966      —  
             

Total deferred tax assets

     1,022,862      6,498,325
             

Deferred tax liabilities:

     

Property and equipment, principally due to differences in depreciation

     25,926,429      16,924,919

Other

     1,089,064      1,286,928
             

Total deferred tax liabilities

     27,015,493      18,211,847
             

Net deferred tax liabilities

   $ 25,992,631    $ 11,713,522
             

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

At March 31, 2005, we had net operating loss carryforwards for federal income tax purposes of approximately $16,500,000. Taxable income for the year ended March 31, 2006 was sufficient to fully utilize these net operating loss carryforwards.

 

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6. Fair Value of Financial Instruments

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

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,  
     2006    2005    2004  
Basic         

Net earnings (loss)

   $ 50,566,603    $ 10,811,625    $ (1,790,057 )
                      

Weighted average shares

     46,808,323      34,543,695      22,585,612  
                      

Earning (loss) per share

   $ 1.08    $ 0.31    $ (0.08 )
                      
Diluted         

Earnings (loss) applicable to common shareholders

   $ 50,566,603    $ 10,811,625    $ (1,790,057 )

Effect of dilutive securities - Convertible subordinated debenture

     —        459,483      —    
                      

Earnings (loss) available to common shareholders and assumed conversion

   $ 50,566,603    $ 11,271,108    $ (1,790,057 )
                      

Weighted average shares:

        

Outstanding

     46,808,323      34,543,695      22,585,612  

Options

     697,562      684,806      —    

Convertible subordinated debenture

     —        2,349,426      —    
                      
     47,505,885      37,577,927      22,585,612  
                      

Earnings (loss) per share

   $ 1.06    $ 0.30    $ (0.08 )
                      

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

 

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8. Equity Transactions

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

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

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

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

Directors and employees exercised stock options for the purchase of 698,667 shares of common stock at prices ranging from $2.25 to $10.31 per share during the fiscal year ended March 31, 2006, 551,666 shares of common stock at prices ranging from $.375 to $6.44 per share during the fiscal year ended March 31, 2005 and 722,334 shares of common stock at prices ranging from $.625 to $3.20 per share during the fiscal year ended March 31, 2004.

9. Stock Options, Warrants and Stock Option Plan

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

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

 

     2006    2005    2004
    

Shares

Issuable on

Exercise of
Options

   

Weighted
Average

Price

  

Shares

Issuable on

Exercise of

Options

   

Weighted
Average

Price

  

Shares

Issuable on

Exercise of
Options

   

Weighted

Average

Price

Balance Outstanding Beginning of year

   2,005,000     $ 5.30    2,056,666     $ 3.24    1,825,000     $ 1.63

Granted

   336,500     $ 14.53    510,000     $ 8.85    1,000,000     $ 4.46

Exercised

   (698,667 )   $ 3.94    (551,666 )   $ 1.37    (722,334 )   $ 0.93

Canceled

   (50,000 )   $ 9.65    (10,000 )   $ 4.52    (46,000 )   $ 2.25
                                      

Balance Outstanding End of year

   1,592,833     $ 7.71    2,005,000     $ 5.30    2,056,666     $ 3.24
                                      

Options Exercisable End of year

   546,666     $ 5.40    798,002     $ 3.58    884,001     $ 1.95
                                      

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

 

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The following table summarizes information about our employee stock options outstanding and exercisable at March 31, 2006:

 

     Options Outstanding    Options Exercisable

Range of

Exercise Prices

   Number
Outstanding
   Weighted
Average
Remaining
Contractual
Life
   Weighted
Average
Exercise
Price
   Number
Exercisable
   Weighted
Average
Exercise
Price

$3.00 - $4.77

   841,333    7.19    $ 4.12    401,666    $ 3.67

$5.95 - $9.65

   399,000    8.62    $ 9.42    115,000    $ 9.22

$10.31 - $14.58

   352,500    8.92    $ 14.34    30,000    $ 13.98
                  
   1,592,833    7.93    $ 7.71    546,666    $ 5.40
                  

10. Employee Benefit Plans and Insurance

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

We maintain a self-insurance program, for major medical, hospitalization and dental coverage for employees and their dependents, which is partially funded by payroll deductions. We have provided for both reported and incurred but not reported medical costs in the accompanying consolidated balance sheets. We have a maximum liability of $125,000 per employee/dependent per year. Amounts in excess of the stated maximum are covered under a separate policy provided by an insurance company. Accrued expenses at March 31, 2006 and 2005 include approximately $553,000 and $489,000, respectively, for our estimate of incurred but unpaid costs related to the self-insurance portion of our health insurance.

We are self-insured for up to $250,000 for all workers’ compensation claims submitted by employees for on-the-job injuries, except in North Dakota where the deductible is $100,000. We have provided for both reported and incurred but not reported costs of workers’ compensation coverage in the accompanying consolidated balance sheets. Accrued expenses at March 31, 2006 and 2005 include approximately $1,829,000 and $845,000, respectively, for our estimate of incurred but unpaid costs related to workers’ compensation claims. Based upon our past experience, management believes that we have adequately provided for potential losses. However, future multiple occurrences of serious injuries to employees could have a material adverse effect on our financial position and results of operations.

11. Business Segments and Concentrations

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

During the fiscal year ended March 31, 2006, our three largest customers accounted for 10.1%, 6.1% and 4.4% respectively, of our total contract drilling revenue. All three of these customers were customers of ours in 2005. In fiscal 2005, our three largest customers accounted for 6.5%, 5.0% and 4.6%, respectively, of our total contract drilling revenue. All three of these customers were customers of ours in 2004. In fiscal 2004, our three largest customers accounted for 10.5%, 6.4% and 4.9%, of our total contract drilling revenue.

 

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12. Commitments and Contingencies

As of March 31, 2006, we were constructing, from new and used components, nine 1000-horsepower diesel electric rigs at an estimated cost ranging from $7,600,000 to $9,500,000 each. We placed two of these rigs into service in April and May 2006 and we expect to place the remaining seven rigs into service at varying times prior to March 31, 2007. As of March 31, 2006, we had incurred approximately $26,172,000 of the approximately $74,100,000 of construction costs on these rigs.

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

13. Quarterly Results of Operations (unaudited)

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

 

    

First

Quarter

   

Second

Quarter

   

Third

Quarter

   

Fourth

Quarter

    Total  
2006           

Revenues

   $ 59,877     $ 66,973     $ 74,459     $ 82,839     $ 284,148  

Income from operations

     11,902       17,171       21,262       27,573       77,909  

Income tax expense

     (4,537 )     (6,508 )     (7,876 )     (10,325 )     (29,247 )

Net earnings

     7,725       11,080       13,792       17,968       50,567  

Earnings per share:

          

Basic

     .17       .24       .30       .37       1.08  

Diluted

     .17       .24       .29       .36       1.06  
2005           

Revenues

   $ 40,719     $ 42,783     $ 46,387     $ 55,357     $ 185,246  

Income from operations

     1,046       1,960       6,704       9,064       18,774  

Income tax expense

     (139 )     (590 )     (2,428 )     (3,192 )     (6,349 )

Net earnings

     216       923       4,179       5,494       10,812  

Earnings per share:

          

Basic

     .01       .03       .11       .14       .31  

Diluted

     .01       .03       .11       .14       .30  

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

 

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

Not applicable.

Item 9A. Controls and Procedures

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

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

Management’s Report on Internal Control over Financial Reporting

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

Pioneer Drilling Company’s management assessed the effectiveness of Pioneer Drilling Company’s internal control over financial reporting as of March 31, 2006. In making this assessment, it used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control-Integrated Framework. Based on our assessment we have concluded that, as of March 31, 2006, Pioneer Drilling Company’s internal control over financial reporting was effective based on those criteria.

Pioneer Drilling Company’s independent registered public accounting firm has audited management’s assessment of the effectiveness of Pioneer Drilling Company’s internal control over financial reporting as of March 31, 2006, as stated in their report which appears herein. That report appears on page 31.

Item 9B. Other Information

Not applicable.

 

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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 2006 Annual Meeting of Shareholders. We intend to file that definitive proxy statement with the SEC by July 15, 2006.

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 2006 Annual Meeting of Shareholders for the information this Item 10 requires.

Item 11. Executive Compensation

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

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

Please see the information appearing (1) under the heading “Equity Compensation Plan Information” in Item 5 of this report and (2) under the heading “Security Ownership of Certain Beneficial Owners and Management” in the definitive proxy statement for our 2006 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 2006 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 2006 Annual Meeting of Shareholders for the information this Item 14 requires.

 

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PART IV

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

(1) Financial Statements.

See Index to Consolidated Financial Statements on page 29.

(2) Financial Statement Schedules:

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

Schedule II

 

     Valuation and Qualifying Accounts
    

Balance

at
Beginning
of Year

  

Charged

to Costs
and
Expenses

    Deductions
from
Accounts
  

Balance

at

Year End

Year ended March 31, 2004

          

Allowance for doubtful receivables

   $ 110,000    $ —       $ —      $ 110,000
                            

Year ended March 31, 2005

          

Allowance for doubtful receivables

   $ 110,000    $ 242,000     $ —      $ 352,000
                            

Year ended March 31, 2006

          

Allowance for doubtful receivables

   $ 352,000    $ (152,000 )   $ —      $ 200,000
                            

 

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Table of Contents

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

 

Exhibit

Number

       

Description

  2.1*    -    Asset Purchase Agreement dated November 11, 2004 between Wolverine Drilling, Inc. and Robert Mau, Robert S. Blackford and Pioneer Drilling Services, Ltd. (Form 8-K dated November 11, 2004 (File No. 1-8182, Exhibit 2.1)).
  2.2*    -    Asset Purchase Agreement dated November 29,2004, by and among Allen Drilling Company, the Earl Allen Family Trust dated April 1, 1979, the sole shareholder of Allen Drilling Company, Dixon Allen, Paula K. Hoisington and Lisa D. Johonnesson, all of the beneficiaries of the Trust, and Pioneer Drilling Services, Ltd. (Form 8-K dated November 30, 2004 (File No. 1-8182m Exhibit 2.1)).
  3.1*    -    Articles of Incorporation of Pioneer Drilling Company, as amended (Form 10-K for the year ended March 31, 2001 (File No. 1-8182, Exhibit 3.1)).
  3.2*    -    Articles of Amendment to the Articles of Incorporation of Pioneer Drilling Company (Form 10-Q for the quarter ended September 30, 2001 (File No. 1-8182, Exhibit 3.1)).
  3.3*    -    Amended and Restated Bylaws of Pioneer Drilling Company (Form 10-Q for the quarter ended December 31, 2003 (File No. 1-8182, Exhibit 3.3)).
  4.1*    -    Form of Certificate representing Common Stock of Pioneer Drilling Company (Form S-8 filed November 18, 2003 (Reg. No. 333-110569, Exhibit 4.3)).
  4.2*    -    Credit Agreement between Pioneer Drilling Services, Ltd. and Frost National Bank, as Administrative Agent, Agent, Lead Arranger and Lender dated October 29, 2004 (Form 8-K dated October 29, 2004 (File No. 1-8182, Exhibit 4.1)).
  4.3*    -    Second Amendment, dated May 11, 2005, to Credit Agreement between Pioneer Drilling Services, Ltd. And Frost National Bank, as Administrative Agent, Lead Arranger and Lender dated October 29, 2004 (Form 8-K dated May 12, 2005 (File No. 1-8182, Exhibit 4.1)).
  4.4*    -    Third Amendment, dated October 25, 2005, to Credit Agreement between Pioneer Drilling Services, Ltd. And Frost National Bank, as Administrative Agent, Lead Arranger and Lender dated October 29, 2004 (Form 8-K dated October 28, 2005 (File No. 1-8182, Exhibit 4.1)).
  4.5*    -    Fourth Amendment, dated December 15, 2005, to Credit Agreement between Pioneer Drilling Services, Ltd. And Frost National Bank, as Administrative Agent, Lead Arranger and Lender dated October 29, 2004 (Form 8-K dated December 16, 2005 (File No. 1-8182, Exhibit 4.1)).
10.1+*    -    Pioneer Drilling Services, Ltd. Annual Incentive Compensation Plan dated August 5, 2005 (Form 8-K Dated August 5, 2005 (File No. 1-8182, Exhibit 10.1)).
10.2+*    -    Pioneer Drilling Services, Ltd. Executive Severance Plan dated August 5, 2005 (Form 8-K Dated August 5, 2005 (File No. 1-8182, Exhibit 10.3)).
10.3+*    -    Pioneer Drilling Company’s 1995 Stock Plan and form of Stock Option Agreement (Form 10-K for the year ended March 31, 2001 (File No. 1-8182, Exhibit 10.5+)).
10.4+*    -    Pioneer Drilling Company’s 1999 Stock Plan and form of Stock Option Agreement (Form 10-K for the year ended March 31, 2001 (File No. 1-8182, Exhibit 10.7+)).

 

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10.5+*    -    Pioneer Drilling Company 2003 Stock Plan (Form S-8 filed November 18, 2003 (File No. 333-110569, Exhibit 4.4)).
21.1    -    Subsidiaries of Pioneer Drilling Company.
23.1    -    Consent of KPMG LLP.
31.1    -    Certification by Wm. Stacy Locke, President and Chief Executive Officer, pursuant to Rule 13a-14(a) or Rule 15d-14(a) under the Securities Exchange Act of 1934.
31.2    -    Certification by William D. Hibbetts, Senior Vice President and Chief Financial Officer, pursuant to Rule 13a-14(a) or Rule 15d-14(a) under the Securities Exchange Act of 1934.
32.1    -    Certification by Wm. Stacy Locke, President and Chief Executive Officer, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (Subsections (a) and (b) of Section 1350, Chapter 63 of Title 18, United States Code).
32.2    -    Certification by William D. Hibbetts, Senior Vice President and Chief Financial Officer, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (Subsections (a) and (b) of Section 1350, Chapter 63 of Title 18, United States Code).

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

 

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Table of Contents

SIGNATURES

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

 

    PIONEER DRILLING COMPANY
May 25, 2006   By:  

/s/ Wm. Stacy Locke

    Wm. Stacy Locke
    Chief Executive Officer and President

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

 

Signature

  

Title

 

Date

/s/ Michael E. Little

    
Michael E. Little    Chairman   May 25, 2006

/s/ Wm. Stacy Locke

    
Wm. Stacy Locke   

President, Chief Executive Officer and Director

(Principal Executive Officer)

  May 25, 2006

/s/ William D. Hibbetts

    
William D. Hibbetts   

Senior Vice President, Chief Financial

Officer and Secretary (Principal Financial Officer)

  May 25, 2006

/s/ Kurt M. Forkheim

    
Kurt M. Forkheim   

Vice President, Chief Accounting Officer

(Principal Accounting Officer)

  May 25, 2006

/s/ C. John Thompson

    
C. John Thompson    Director   May 25, 2006

/s/ James M. Tidwell

    
James M. Tidwell    Director   May 25, 2006

/s/ C. Robert Bunch

    
C. Robert Bunch    Director   May 25, 2006

/s/ Dean A. Burkhardt

    
Dean A. Burkhardt    Director   May 25, 2006

/s/ Michael F. Harness

    
Michael F. Harness    Director   May 25, 2006

 

54


Table of Contents

Index To Exhibits

 

  2.1*    -    Asset Purchase Agreement dated November 11, 2004 between Wolverine Drilling, Inc. and Robert Mau, Robert S. Blackford and Pioneer Drilling Services, Ltd. (Form 8-K dated November 11, 2004 (File No. 1-8182, Exhibit 2.1)).
  2.2*    -    Asset Purchase Agreement dated November 29,2004, by and among Allen Drilling Company, the Earl Allen Family Trust dated April 1, 1979, the sole shareholder of Allen Drilling Company, Dixon Allen, Paula K. Hoisington and Lisa D. Johonnesson, all of the beneficiaries of the Trust, and Pioneer Drilling Services, Ltd. (Form 8-K dated November 30, 2004 (File No. 1-8182m Exhibit 2.1)).
  3.1*    -    Articles of Incorporation of Pioneer Drilling Company, as amended (Form 10-K for the year ended March 31, 2001 (File No. 1-8182, Exhibit 3.1)).
  3.2*    -    Articles of Amendment to the Articles of Incorporation of Pioneer Drilling Company (Form 10-Q for the quarter ended September 30, 2001 (File No. 1-8182, Exhibit 3.1)).
  3.3*    -    Amended and Restated Bylaws of Pioneer Drilling Company (Form 10-Q for the quarter ended December, 2003 (File No. 1-8182, Exhibit 3.3)).
  4.1*       Form of Certificate representing Common Stock of Pioneer Drilling Company (Form S-8 filed November 18, 2003 (Reg. No. 333-110569, Exhibit 4.3)).
  4.2*    -    Credit Agreement between Pioneer Drilling Services, Ltd. and Frost National Bank, as Administrative Agent, Agent, Lead Arranger and Lender dated October 29, 2004 (Form 8-K dated October 29, 2004 (File No. 1-8182, Exhibit 4.1)).
  4.3*    -    Second Amendment, dated May 11, 2005, to Credit Agreement between Pioneer Drilling Services, Ltd. And Frost National Bank, as Administrative Agent, Lead Arranger and Lender dated October 29, 2004 (Form 8-K dated May 12, 2005 (File No. 1-8182, Exhibit 4.1)).
  4.4*    -    Third Amendment, dated October 25, 2005, to Credit Agreement between Pioneer Drilling Services, Ltd. And Frost National Bank, as Administrative Agent, Lead Arranger and Lender dated October 29, 2004 (Form 8-K dated October 28, 2005 (File No. 1-8182, Exhibit 4.1)).
  4.5*    -    Fourth Amendment, dated December 15, 2005, to Credit Agreement between Pioneer Drilling Services, Ltd. And Frost National Bank, as Administrative Agent, Lead Arranger and Lender dated October 29, 2004 (Form 8-K dated December 16, 2005 (File No. 1-8182, Exhibit 4.1)).
10.1+*    -    Pioneer Drilling Services, Ltd. Annual Incentive Compensation Plan dated August 5, 2005 (Form 8-K Dated August 5, 2005 (File No. 1-8182, Exhibit 10.1)).
10.2+*    -    Pioneer Drilling Services, Ltd. Executive Severance Plan dated August 5, 2005 (Form 8-K Dated August 5, 2005 (File No. 1-8182, Exhibit 10.3)).
10.3+*    -    Pioneer Drilling Company’s 1995 Stock Plan and form of Stock Option Agreement (Form 10-K for the year ended March 31, 2001 (File No. 1-8182, Exhibit 10.5+)).
10.4+*    -    Pioneer Drilling Company’s 1999 Stock Plan and form of Stock Option Agreement (Form 10-K for the year ended March 31, 2001 (File No. 1-8182, Exhibit 10.7+)).
10.5+*    -    Pioneer Drilling Company 2003 Stock Plan (Form S-8 filed November 18, 2003 (File No. 333-110569, Exhibit 4.4)).

 

55


Table of Contents
21.1    -    Subsidiaries of Pioneer Drilling Company.
23.1    -    Consent of KPMG LLP.
31.1    -    Certification by Wm. Stacy Locke, President and Chief Executive Officer, pursuant to Rule 13a-14(a) or Rule 15d-14(a) under the Securities Exchange Act of 1934.
31.2    -    Certification by William D. Hibbetts, Senior Vice President and Chief Financial Officer, pursuant to Rule 13a-14(a) or Rule 15d-14(a) under the Securities Exchange Act of 1934.
32.1    -    Certification by Wm. Stacy Locke, President and Chief Executive Officer, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (Subsections (a) and (b) of Section 1350, Chapter 63 of Title 18, United States Code).
32.2    -    Certification by William D. Hibbetts, Senior Vice President and Chief Financial Officer, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (Subsections (a) and (b) of Section 1350, Chapter 63 of Title 18, United States Code).

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

 

56

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