UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D. C. 20549

 


FORM 10-K

 


(Mark one)

(Mark one)x

ý

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

For the fiscal year ended March 31, 2006

 

¨

For the fiscal year ended March 31, 2004

o

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

Commission File Number: 1-8182

 


PIONEER DRILLING COMPANY

(Exact name of registrant as specified in its charter)

 


TEXAS

74-2088619

(State or other jurisdiction
of

incorporation or organization)

(I.R.S. Employer

Identification Number)

9310 Broadway, Bldg. I
1250 N.E. Loop 410, Suite 1000

San Antonio, Texas

7821778209

(Address of principal executive offices)

(Zip Code)

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

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

 


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

 

Title of each class

Name of each exchange on which registered

Common Stock $0.10 par value

American Stock Exchange

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

 


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

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

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

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

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

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

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

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

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

As of June 25, 2004,May 12, 2006, there were 27,300,12649,591,978 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 20042006 Annual Meeting of Shareholders are incorporated by reference into Part III of this report.

 




TABLE OF CONTENTS

 

Page
PART I

Items 1 and 2.

Item 1.

Business and Properties

1

Item 1A.

Risk Factors11
Item 1B.Unresolved Staff Comments16
Item 2.Properties16
Item 3.

Legal Proceedings

16

Item 4.

Submission of Matters to a Vote of Security Holders

16

PART II

Item 5.

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

16

Item 6.

Selected Financial Data

17

Item 7.

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

18

Item 7A.

Quantitative and Qualitative Disclosures About Market Risk

28

Item 8.

Financial Statements and Supplementary Data

29

Item 9.

Changes in and Disagreements With Accountants on Accounting and Financial Disclosure

49

Item 9A.

Controls and Procedures

49

Item 9B.

Other Information
49

PART III

Item 10.

Directors and Executive Officers of the Registrant

50

Item 11.

Executive Compensation

50

Item 12.

Security Ownership of Certain Beneficial Owners and Management and Related Stock holderStockholder Matters

50

Item 13.

Certain Relationships and Related Transactions

50

Item 14.

Principal Accountant Fees and Services

50

PART IV

Item 15.

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

51



PART I

Statements we make in this Annual Report on Form 10-K that express a belief, expectation or intention, as well as those that are not historical fact, are forward-looking statements under the Private Securities Litigation Reform Act of 1995. These forward-looking statements are subject to various risks, uncertainties and assumptions, including those to which we refer under the heading ‘‘Cautionary“Cautionary Statement Concerning Forward-Looking Statements and Risk Factors’’Statements” following ItemsItem 1 and 2 of Part I of this report.

ItemsItem 1 and 2.. Business and Properties

General

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

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

 

Date

Acquisition (1)

AcquisitionMarket

Market

Number of

Rigs
Rigs Acquired

September 1999

Howell Drilling, Inc. —  Asset Purchase

South Texas

2

August 2000

Pioneer Drilling Co. —  Stock Purchase

South Texas

4

March 2001

Mustang Drilling, Ltd. — Asset Purchase

East Texas

4

May 2002

United Drilling Company —  Asset Purchase

South Texas

2

August 2003

Texas Interstate Drilling Company, L. P. — Asset Purchase

North Texas

2

March 2004

Sawyer Drilling & Service, Inc. — Asset Purchase

East Texas

7

March 2004

SEDCO Drilling Co., Ltd. — Asset Purchase

North Texas

1

November 2004Wolverine Drilling, Inc.Rocky Mountains7
December 2004Allen Drilling CompanyWestern Oklahoma5

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

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

fleet at varying times prior to March 31, 2007.

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

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

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

1



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

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

Our Strategy

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

 

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

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

positioning ourselves to maximize rig utilization and dayrates;

training and maintaining high-quality, experienced crews; and

maintaining an aggressive safety program.

Drilling Equipment

General

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

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

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

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

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

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

2



Our Fleet of Drilling Rigs

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

 

 

 

Years ended March 31,

 

 

 

2004

 

2003

 

2002

 

2001

 

2000

 

1999

 

Average number of rigs for the period

 

27.3

 

22.3

 

18.0

 

10.5

 

6.6

 

6.0

 

Average utilization rate

 

88

%

79

%

82

%

91

%

66

%

66

%

   Years Ended March 31, 
   2006  2005  2004  2003  2002  2001 

Average number of rigs for the period

  52.3  40.1  27.3  22.3  18.0  10.5 

Average utilization rate

  95% 96% 88% 79% 82% 91%

The following table sets forth information regarding our drilling fleet:

 

Rig
Number

 

Rig Design

 

Approximate
Drilling Depth
Capability
(feet)

 

Current
Location

 

Type

 

Horse Power

 

  

Rig Design

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

 

 

 

 

 

 

 

 

 

 

 

1

 

Cabot 750E

 

9,500

 

South Texas

 

Electric

 

750

 

  Cabot 750E  9,500  South Texas  Electric  750

2

 

Cabot 750E

 

9,500

 

South Texas

 

Electric

 

750

 

  Cabot 750E  9,500  South Texas  Electric  750

3

 

National 110 UE

 

18,000

 

South Texas

 

Electric

 

1500

 

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

4

 

RMI 1000 E

 

15,000

 

South Texas

 

Electric

 

1000

 

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

5

 

Brewster N-46

 

12,000

 

North Texas

 

Mechanical

 

1000

 

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

6

 

Brewster DH-4610

 

13,000

 

East Texas

 

Mechanical

 

750

 

  Brewster DH-4610  13,000  East Texas  Mechanical  750

7

 

National 110 UE

 

18,000

 

South Texas

 

Electric

 

1500

 

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

8

 

National 110 UE

 

18,000

 

East Texas

 

Electric

 

1500

 

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

9

 

Gardner-denver 500

 

11,000

 

East Texas

 

Mechanical

 

700

 

  Gardner-Denver 500  11,000  East Texas  Mechanical  700

10

 

Brewster N-46

 

12,000

 

East Texas

 

Mechanical

 

1000

 

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

11

 

Brewster N-46

 

12,000

 

South Texas

 

Mechanical

 

1000

 

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

12

 

IRI Cabot 900

 

12,500

 

South Texas

 

Mechanical

 

900

 

  IRI Cabot 900  10,500  South Texas  Mechanical  900

14

 

Brewster N-46

 

12,000

 

South Texas

 

Mechanical

 

1000

 

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

15

 

Cabot 750

 

9,500

 

South Texas

 

Mechanical

 

750

 

  Cabot 750  9,500  South Texas  Mechanical  750

16

 

Cabot 750

 

9,500

 

South Texas

 

Mechanical

 

750

 

  Cabot 750  9,500  South Texas  Mechanical  750

17

 

Ideco 725

 

12,000

 

East Texas

 

Mechanical

 

750

 

  Ideco 725  12,000  East Texas  Mechanical  800

18

 

Brewster N-75

 

12,000

 

East Texas

 

Mechanical

 

1000

 

  Brewster N-75  12,000  East Texas  Mechanical  1,000

19

 

Brewster N-75

 

12,000

 

East Texas

 

Mechanical

 

1000

 

  Brewster N-75  12,000  East Texas  Mechanical  1,000

20

 

BDW 800

 

13,500

 

East Texas

 

Mechanical

 

1000

 

  BDW 800  13,500  East Texas  Mechanical  1,000

21

 

National 110 UE

 

18,000

 

South Texas

 

Electric

 

1500

 

22

 

Ideco 725

 

12,000

 

East Texas

 

Mechanical

 

750

 

23

 

Ideco 725

 

12,000

 

North Texas

 

Mechanical

 

750

 

24

 

National 110 UE

 

18,000

 

South Texas

 

Electric

 

1500

 

25

 

National 110 UE

 

18,000

 

East Texas

 

Electric

 

1500

 

26

 

Oilwell 840 E

 

18,000

 

South Texas

 

Electric

 

1500

 

27

 

IRI Cabot 1200 M

 

13,500

 

South Texas

 

Mechanical

 

1300

 

28

 

Oilwell 760 E

 

15,000

 

South Texas

 

Electric

 

1000

 

29

 

Brewster N-46

 

12,000

 

North Texas

 

Mechanical

 

1000

 

30

 

Mid Cont U36A

 

11,000

 

North Texas

 

Mechanical

 

750

 

31

 

Brewster N-7

 

11,500

 

East Texas

 

Mechanical

 

750

 

32

 

Brewster N-75

 

13,500

 

East Texas

 

Mechanical

 

1000

 

33

 

Brewster N-95

 

13,500

 

East Texas

 

Mechanical

 

1200

 

34

 

All-Rig 900

 

12,000

 

East Texas

 

Mechanical

 

900

 

35

 

RMI 1000

 

13,500

 

East Texas

 

Mechanical

 

1000

 

36

 

Brewster N-7

 

11,500

 

East Texas

 

Mechanical

 

750

 

37

 

Brewster N-95

 

13,500

 

East Texas

 

Mechanical

 

1200

 

Rig
Number

  

Rig Design

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

21

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

22

  Ideco 725  12,000  East Texas  Mechanical  800

23

  Ideco 725  12,000  North Texas  Mechanical  800

24

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

25

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

26

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

27

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

28

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

29

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

30

  Mid Cont U36A  11,000  North Texas  Mechanical  750

31

  Brewster N-7  11,500  East Texas  Mechanical  750

32

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

33

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

34

  All-Rig 900  12,000  East Texas  Mechanical  900

35

  National 610  13,500  East Texas  Mechanical  750

36

  Brewster N-7  11,500  East Texas  Mechanical  750

37

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

38

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

39

  National 370  10,000  North Texas  Mechanical  550

40

  National 370  8,500  North Dakota  Mechanical  550

41

  National 610  11,000  Utah  Mechanical  750

42

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

43

  National 610  11,000  North Dakota  Mechanical  750

44

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

46

  RMI 550  9,000  Oklahoma  Mechanical  550

47

  Ideco 525  8,000  Oklahoma  Mechanical  600

48

  National 370  8,500  Oklahoma  Mechanical  550

49

  Ideco 525  9,000  Oklahoma  Mechanical  600

50

  Ideco 725  11,000  Oklahoma  Mechanical  800

51

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

52

  National 80 UE  15,000  Utah  Electric  1,000

53

  National 80 UE  15,000  Utah  Electric  1,000

54

  RMI 1000  14,000  Utah  Mechanical  1,000

55

  OIME SD7E  18,000  North Texas  Electric  1,500

56

  OIME SD7E  18,000  North Dakota  Electric  1,500

57

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

59

  HRI 1000  12,500  Utah  Mechanical  1,000

60

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

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

3



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

Drilling Contracts

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

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

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

 

 

Year Ended March 31,

 

  Year Ended March 31,

 

2004

 

2003

 

2002

 

  2006  2005  2004

Daywork

 

205

 

119

 

150

 

  565  264  205

Turnkey

 

92

 

78

 

9

 

  19  134  92

Footage

 

13

 

5

 

6

 

  106  48  13
         

Total number of wells

 

310

 

202

 

165

 

  690  446  310
         

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

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

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

4



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

Customers and Marketing

We market our rigs to a number of customers. In fiscal 2004,2006, we drilled wells for 88128 different customers, compared to 64102 customers in fiscal 20032005 and 4883 customers in fiscal 2002.  Forty-nine of our customers in fiscal 2004 were customers for whom we had not drilled any wells in fiscal 2003.2004. The following table shows our three largest customers as a percentage of our total contract drilling revenue for each of our last three fiscal years.

 

Customer

Total
Contract
Drilling
Revenue
Percentage

Fiscal 2006

Fiscal 2004Chesapeake Operating Inc.

10.1%

Kerr-McGee Oil & Gas

6.1
%

Chinn Exploration

11

4.4

%

Fiscal 2005

Dale Operating CompanyChinn Exploration

6.5%

Goodrich Petroleum Corp.

6

5.0

%

Medicine Bow Energy Corporation

5

4.6

%

Fiscal 2004

Chinn Exploration

10.5

%

Fiscal 2003Dale Operating Company

6.4

%

Gulf CoastMedicine Bow Energy Associates

11

%

Apache Corporation

7

4.9

%

Suemaur Exploration & Production, L.L.C.

5

%

Fiscal 2002

Dominion Exploration & Production, Inc.

14

%

Kerr-McGee Oil & Gas Onshore, L.L.C.

12

%

Pogo Producing Company

11

%

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

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

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

Competition

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

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

 

5



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

 

the mobility and efficiency of the rigs;

 

the quality of service and experience of the rig crews;

 

the safety records of the rigs;

 

the offering of ancillary services; and

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

 

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

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

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

 

better withstand industry downturns;

 

compete more effectively on the basis of price and technology;

 

better retain skilled rig personnel; and

 

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

Raw Materials

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

Operating Risks and Insurance

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

 

blowouts;

 

fires and explosions;

 

loss of well control;

 

collapse of the borehole;

 

lost or stuck drill strings; and

 

damage or loss from natural disasters.

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

 

suspension of drilling operations;

 

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

 

personal injury and loss of life;

 

6



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

 

environmental damage.

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

Our current insurance coverage includes property insurance on our rigs, drilling equipment and real property. Our insurance coverage for property damage to our rigs and to our drilling equipment is based on our estimate, as of October 2003,2006, of the cost of comparable used equipment to replace the insured property. The policy provides for a deductible on rigs of $50,000 or $100,000 (depending on the rig)$250,000 per occurrence. Our third-party liability insurance coverage is $26$51 million per occurrence and in the aggregate, with a deductible of $110,000$260,000 per occurrence. We believe that we are adequately insured for public liability and property damage to others with respect to our operations. However, such insurance may not be sufficient to protect us against liability for all consequences of well disasters, extensive fire damage or damage to the environment.

In addition, we generally carry insurance coverage to protect against certain hazards inherent in our turnkey and footage contract drilling operations. This insurance covers “control-of-well,” 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.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 $250,000.$1,000,000, subject to a $50,000 deductible.

Employees

We currently have approximately 9001,540 employees. Approximately 123190 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 the proper operational results.standards. As a result, our operations depend, to a considerable extent, on the continuing availability of such personnel. Although we have not encountered material difficulty in hiring and retaining qualified rig crews, shortages of qualified personnel are occurring in our industry. If we should suffer any material loss of personnel to competitors or be unable to employ additional or replacement personnel with the requisite level of training and experience to adequately operate our equipment, our operations could be materially and adversely affected. While we believe our wage rates are competitive and our relationships with our employees are satisfactory, a significant increase in the wages paid by other employers could result in a reduction in our workforce, increases in wage rates, or both. The occurrence of either of these events for a significant period of time could have a material and adverse effect on our financial condition and results of operations.

Facilities

We own:

 

We own our headquarters building in San Antonio, Texas.  We also own

a 15-acre division office, rig storage and maintenance yard in Corpus Christi, Texas and own a 4-acre trucking department office, storage and maintenance yard in Kilgore, Texas.  We lease Texas;

a six-acre division office, storage and maintenance yard in Henderson, Texas,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 of $3,700escalating from $10,880 per month to $18,805 per month over 102 months, pursuant to a lease extending through March 2006.  We also lease December 2013;

a 43-acre4-acre division office and storage yard in Decatur, Texas, at a cost of $800 per month, pursuant to a lease extending through September 2006, and 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.   We believe these facilities are adequate2006;

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

 

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.

7



Governmental Regulation

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

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

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

Available Information

Our website address is www.pioneerdrlg.com.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 AND RISK FACTORS

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

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

In addition, various statements that this Annual Report on Form 10-K contains, including those that express a belief, expectation or intention, as well as those that are not statements of historical fact, are forward-looking statements. Those forward-looking statements appear in ItemsItem 1 and 2 “Business and Properties”“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

8



obligation to update these statements, and we caution you not to unduly rely on them.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 madecontained in this report or elsewhere by us or on our behalf.elsewhere. We have discussed many of these factors in more detail elsewhere in this report. These factors are not necessarily all the important factors that could affect us. Unpredictable or unknown factors we

have not discussed in this report could also have material adverse effects on actual results of matters that are the subject of our forward-looking statements. We do not intend to update our description of important factors each time a potential important factor arises.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;

 

9



governmental regulations, both domestic and foreign;

 

domestic and foreign tax policy;

 

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

 

the price of foreign imports of oil and gas;

 

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

 

the discovery rate of new oil and gas reserves;

 

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

available pipeline and other oil and gas transportation capacity;

 

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

 

the overall supply and demand for oil and gas.

Risks Relating to Our Business

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

We have a history of losses.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 risksrisks..

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 recentprevious 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 of South Texas, East Texas and North Texas are highly fragmented and competitive. The fact that drilling rigs are mobile and can be moved from one market to another in response to market conditions heightens the competition in the industry.

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

10



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

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

We face competition from many competitors with greater resources.

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

 

better withstand industry downturns;

 

compete more effectively on the basis of price and technology;

 

retain skilled rig personnel; and

 

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

Unexpected cost overruns on our turnkey drilling jobs and our footage contracts could adversely affect us.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 riskrisks of blowout, loss of hole, stuck drill pipe, machinery breakdowns, abnormal drilling conditions and risks associated with subcontractors’ services, supplies, cost escalations and personnel. Similar to our turnkey contracts, under a footage contract we assume most of the risks associated with drilling operations that the operator generally assumes under a daywork contract.

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

 

11



suspension of drilling operations;

 

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

 

personal injury and loss of life;

 

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

 

environmental damage.

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

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

Most of our drilling contracts are with exploration and production companies in search of natural gas. Drilling on land for natural gas generally occurs at deeper drilling depths than drilling for oil. Although deep-depth drilling exposes us to 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 may adversely affectcould restrict our future operations.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 non-hazardousnonhazardous 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 OSHAthe 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.

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

12



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 CorporateOrganizational Documents

Our largest shareholders and our management control a majority of our common stock, and their interests may conflict with those of our other shareholders.

As of June 18, 2004, our largest shareholder, WEDGE Energy Services, L.L.C. (“WEDGE”), beneficially owned 40.24% of our outstanding common stock, and together with our other largest shareholders and our officers and directors as a group beneficially owned a total of 68.73% of our outstanding common stock.  For each shareholder or group of shareholders, beneficial ownership includes shares of our common stock issuable on conversion of our convertible subordinated debentures and on exercise of outstanding stock options held by that shareholder or group of shareholders.  The following table shows, as of June 18, 2004, the beneficial ownership of these persons:

Shareholder

 

Shares

 

Percentage

 

 

 

 

 

 

 

WEDGE (1)

 

13,508,864

 

40.2

%

 

 

 

 

 

 

Chesapeake Energy Corporation (“Chesapeake”)

 

5,333,333

 

19.5

%

 

 

 

 

 

 

T.L.L. Temple Foundation and Temple Interests, L.P. (collectively, “Temple”)

 

1,999,038

 

7.3

%

 

 

 

 

 

 

Officers and directors as a group

 

2,857,142

 

10.1

%


(1)                                  The number of shares and percentage shown for WEDGE reflect 6,267,857 shares that WEDGE currently has the right to acquire on conversion of the $27,000,000 aggregate principal amount of our 6.75% convertible debentures that WEDGE current holds.  The percentages shown for the other stockholders have not been adjusted to reflect the possible conversion of those debentures.

In some circumstances, if WEDGE were to act alone or in concert with a small number of these or other shareholders, they would be able to exercise control over our affairs, including the election of our entire board of directors and, subject to the applicable provisions of the Texas Business Corporation Act, the disposition of any matter submitted to a vote of our shareholders.  Wedge currently has the right to nominate three persons for election to our board of directors, which as of the date of this annual report consists of seven members.  The interests of Wedge and these other persons with respect to matters potentially or actually involving or affecting us, such as future acquisitions, financings and other corporate opportunities and attempts to acquire us, may conflict with the interests of our other shareholders.

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

Our common stock is traded on the American Stock Exchange.  During the period from January 1, 2003 through May 31, 2004, the average daily trading volume of our common stock as reported by the American Stock Exchange was 17,986 shares.  Even if we achieve a wider dissemination of our common stock, a more active trading market in our common stock may not develop.  As a result, relatively small trades may have a significant impact on the price of our common stock and, therefore, may contribute to the price volatility of our common stock.  As a result, our common stock may be subject to greater price volatility than the stock market as a whole.

13



The market price of our common stock has been, and may continue to be, volatile.  For example, during our 2004 fiscal year, the trading price of our common stock ranged from $3.30 to $7.35 per share.

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

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

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

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

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

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

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

 

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

 

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

 

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

 

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

Item 3.1B. 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 4.4. Submission of Matters to a Vote of Security Holders

We did not submit any matter to a vote of our security holdersstockholders during the fourth quarter of fiscal 2004.2006.

PART II

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

As of June 25, 2004, 27,300,126May 12, 2006, 49,591,978 shares of our common stock were outstanding, held by approximately 700512 shareholders of record. The number of record holders does not necessarily bear any relationship to the number of beneficial owners of our common stock.

14



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, 2004:

 

 

 

 

 

First Quarter

 

$

3.57

 

$

5.24

 

Second Quarter

 

3.65

 

4.99

 

Third Quarter

 

3.30

 

5.20

 

Fourth Quarter

 

4.75

 

7.35

 

 

 

 

 

 

 

Fiscal Year Ended March 31, 2003:

 

 

 

 

 

First Quarter

 

$

4.00

 

$

5.05

 

Second Quarter

 

2.85

 

4.20

 

Third Quarter

 

2.86

 

3.85

 

Fourth Quarter

 

3.10

 

3.64

 

   Low  High
Fiscal Year Ended March 31, 2006:    

First Quarter

  $10.57  $16.30

Second Quarter

   14.00   19.93

Third Quarter

   14.25   19.98

Fourth Quarter

   13.10   23.06
Fiscal Year Ended March 31, 2005:    

First Quarter

  $5.60  $7.99

Second Quarter

   6.75   8.90

Third Quarter

   7.63   10.50

Fourth Quarter

   9.05   14.21
Fiscal Year Ended March 31, 2004:    

First Quarter

  $3.57  $5.24

Second Quarter

   3.65   4.99

Third Quarter

   3.30   5.20

Fourth Quarter

   4.75   7.35

The last reported sales price for our common stock on the American Stock Exchange on June 25, 2004May 12, 2006 was $7.45$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.

Equity Compensation Plan Information

The following table provides information on our equity compensation plans as of March 31, 2004:2006:

 

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)

 

  

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

(a)

  

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

(b)

  

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

(c)

Equity compensation plans approved by security holders

 

2,056,666

 

$

3.24

 

2,406,413

 

  1,592,833  $7.71  1,618,500

 

 

 

 

 

 

 

Equity compensation plans not approved by security holders

 

 

 

 

  —     —    —  

 

 

 

 

 

 

 

         

Total

 

2,056,666

 

$

3.24

 

2,406,413

 

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

Recent Sales of Unregistered Securities

On March 31, 2003, we sold 5,333,333 shares of our common stock to Chesapeake Energy Corporation for $20,000,000 ($3.75 per share), before related offering expenses including $600,000 in commissions paid to Jefferies & Company, Inc.  In connection with that sale, we granted Chesapeake Energy a preemptive right to acquire equity securities that we may issue in the future, under specified circumstances, in order to permit Chesapeake Energy to maintain its proportionate ownership of our outstanding shares of common stock.  We also granted Chesapeake Energy a right, under certain circumstances, to request registration of the acquired shares under the Securities Act of 1933.  Chesapeake Energy owns approximately 19.5% of our outstanding common stock, or approximately 14.9% assuming the conversion of all outstanding options and convertible subordinated debentures.  We issued those shares without registration under the Securities Act of 1933 in reliance on the exemption that Section 4(2) of that Act provides for transactions not involving any public offering.

On August 1, 2003, we issued 477,000 shares of our common stock valued at $4.45 per share to Texas Interstate Drilling Company, L.P. in connection with our purchase of two land drilling rigs, associated spare parts and equipment and vehicles.  We issued

15



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

On February 20, 2004, we sold 4,400,000 shares of our common stock at $5.40 per share in a private placement to various individuals and institutional investors, all of whom were accredited investors.  This private placement resulted in $23,760,000 in proceeds, before related offering expenses, which included $1,188,000 in commissions paid to Jefferies & Company, Inc., Raymond James & Associates, Inc. and Pritchard Capital Partners, LLC.   Although we issued those shares without registration under the Securities Act of 1933 in reliance on the exemption that Section 4(2) of that Act provides for transactions not involving any public offering, we filed a registration statement on Form S-3 to register those shares.  The registration statement became effective on June 22, 2004.

Item 6.6. 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,

 

  Years Ended March 31,

 

2004

 

2003

 

2002

 

2001

 

2000

 

  2006  2005  2004 2003 2002

 

(In thousands, except per share amounts)

 

  (In thousands, except per share amounts)

Contract drilling revenues

 

$

107,876

 

$

80,183

 

$

68,627

 

$

50,345

 

$

19,391

 

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

Income (loss) from operations

 

438

 

(4,943

)

11,201

 

3,803

 

108

 

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

Income (loss) before income taxes

 

(2,216

)

(7,305

)

9,737

 

3,838

 

(65

)

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

Preferred dividends

 

 

 

93

 

275

 

304

 

   —     —     —     —     93

Net earnings (loss) applicable to common stockholders

 

(1,790

)

(5,086

)

6,225

 

2,428

 

(384

)

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

Earnings (loss) per common share-basic

 

(0.08

)

(0.31

)

0.41

 

0.22

 

(0.06

)

   1.08   0.31   (0.08)  (0.31)  0.41

Earnings (loss) per common share-diluted

 

(0.08

)

(0.31

)

0.35

 

0.19

 

(0.06

)

   1.06   0.30   (0.08)  (0.31)  0.35

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

 

44,892

 

45,855

 

26,119

 

10,056

 

267

 

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

Shareholders’ equity

 

70,836

 

47,672

 

33,343

 

17,827

 

6,783

 

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

Total assets

 

143,731

 

119,694

 

83,450

 

56,493

 

15,670

 

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

Capital expenditures

 

44,845

 

33,589

 

27,597

 

41,628

 

5,069

 

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

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

Item 7.7. 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 whichthat 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 theselected oil and natural gas production regions of South Texas, East Texas and North Texas.in the United States. Our company was incorporated in 1979 as the successor to a business that had been operating since 1968. We conduct our operations through our principal operating subsidiary, Pioneer Drilling Services, Ltd. 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.

16



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.

Over the past five fiscal years,Since September 1999, we have significantly expanded our fleet of drilling rigs through acquisitions and the construction of new and refurbished rigs. As of March 31, 2004,May 12, 2006 our rig fleet consisted of 3557 land drilling rigs that drill in depth ranges between 8,0006,000 and 18,000 feet. FourteenFifteen of our rigs are operating in our South Texas 17division, 18 in our East Texas division, seven in our North Texas division, five in our western Oklahoma division and four12 in North Texas.our Rocky Mountains divisions. We actively market all of these rigs. We completed construction of our 36th rig in late May 2004 and began moving it to its first drilling location on May 28, 2004.  Subject to obtaining satisfactory financing, we anticipate continued growth of our rig fleet in fiscal 2005.  However,year 2007. As of May 12, 2006, we are not currently committedwere constructing seven 1000-horsepower diesel electric rigs from new and used components. We expect these rigs to any acquisitions.

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.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 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,Historically, our contracts provide for the drilling of a single well and typically permit the customer to terminate on short notice, usually on paymentnotice. As demand for drilling rigs has improved during the past year, we have entered into more longer-term drilling contracts. As of an agreed fee.

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.  On daywork contracts, during the mobilization period we 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.

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

 

 

 

Year Ended March 31,

 

 

 

2004

 

2003

 

2002

 

Utilization Rates

 

88

%

79

%

82

%

Revenue Days

 

8,764

 

6,419

 

5,384

 

Number of rigs

 

35

 

24

 

20

 

   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 reasonsprimary reason for the increase in the number of revenue days in 2006 over 2005 and 2004 over 2003 and 2002 areis the increase in size of our rig fleet and the improvement in our overall rig utilization rate.fleet. For 2005,2007, we anticipate continued growth in revenue days as we continue to construct more rigs and maintaining relativelyput them into operation. We expect utilization rates for 2007 to be comparable to 2006.

In addition to high utilization rates.

Wecommodity prices, we attribute our relatively high utilization rates to a strong sales effort, quality equipment, good field and operations personnel, a disciplined safety approach, and our generally successful performance of turnkey operations.  Turnkey contracts account for approximately one-fourth of our contracts.  Turnkey contracts provide us with the opportunity to keep our rigs working inoperations during periods of lowerreduced demand and improve ourfor drilling margin, but at an increased risk.  Over the long term, turnkey margins per revenue day have been greater than daywork margins; however, occasionally, a turnkey contract will not be profitable if the contract cannot be completed successfully without unanticipated complications.

rigs.

We devote substantial resources to maintaining and upgrading our rig fleet. During 2004, we removed three rigs from service for approximately three weeks each, in order to perform upgrades.  In the short term, these actions resultedresult in fewer revenue days and slightly lower utilization; however, in the long term, we believe the upgrades will help the marketability of theour 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.

17



For the three months ended March 31, 2004, the average weekly spot price for West Texas Intermediate crude oil was $35.08, the average weekly spot price for Henry Hub natural gas was $5.56 and the average weekly Baker Hughes land rig count was 1,002.  On June 11, 2004,May 12, 2006, the spot price for West Texas Intermediate crude oil was $38.45,$72.04, the spot price for Henry Hub natural gas was $6.00$6.26 and the Baker Hughes land rig count was 1,070,1,503, a 13%26% increase from 9481,196 on JuneMay 13, 2003.

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, 20042006 were:

 

 

 

Year Ended March 31,

 

 

 

2004

 

2003

 

2002

 

2001

 

2000

 

1999

 

Oil (West Texas Intermediate)

 

$

31.47

 

$

29.27

 

$

24.31

 

$

30.40

 

$

23.23

 

$

13.69

 

Gas (Henry Hub)

 

$

5.27

 

$

4.24

 

$

2.96

 

$

5.27

 

$

2.46

 

$

1.97

 

U.S. Land Rig Count

 

964

 

723

 

912

 

841

 

550

 

592

 

The decline in oil and natural gas prices from mid-2001 to mid-2002 resulted in a reduction in the demand for contract land drilling services, which resulted in a substantial reduction in the rates land drilling companies were able to obtain for their services.  While oil and natural gas prices have recovered in recent months, drilling activity has not yet recovered to a level at which we are able to significantly improve our revenue rates and drilling margins.

   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, 2003 and 2002, substantially allmost of the wells we drilled for our customers were drilled in search of natural gas becausegas. We diversified our operations somewhat in November 2004, when we began operating in the Williston Basin of the depth capacityRocky Mountains where our customers drill in search of our rigs and the gas rich areas in which we operate.  Natural gas reserves are typically found in deeper geological formations and generally require premium equipment and quality crews to drill the wells.oil.

Critical Accounting Policies and Estimates

Revenue and cost recognitionWe earn our revenues by drilling oil and gas wells for our customers under daywork, turnkey or footage contracts, which usually provide for the drilling of a single well. 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. This is primarily because underUnder a turnkey contract, we assume most of the risks associated with drilling operations that are generally assumed by the operator in a daywork contract, including the risks of blowout, loss of hole, stuck drill pipe, machinery breakdowns and abnormal drilling conditions, as well as risks associated with subcontractors’ services, supplies, cost escalations and personnel operations.

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

We accrue estimated 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,operations.Therefore, our actual results for a contract could

18



differ significantly if our cost estimates for that contract are later revised from our original cost estimates for contractsa contract in progress at the end of a reporting period which werewas not completed prior to the release of our financial statements.

Asset impairments –We – 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, 2004,2006, would have resulted in a corresponding increasedecrease in our net lossearnings of approximately $962,000$2,136,000 for our fiscal year ended March 31, 2004.2006.

Deferred taxes –We– We provide deferred taxes for net operating loss carryforwards and for the basis differencedifferences 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 eightfive 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 – We consider the recognition of revenues and costs on turnkey and footage contracts critical accounting estimates. On these types of contracts, we are required to estimate the number of days it will requireneeded for us to complete the contract and our total cost to complete the contract. Our actual costs could substantially exceed our estimated costs if we encounter problems such as lost circulation, stuck drill pipe or an underground blowout on contracts still in progress subsequent to the release of the financial statements.

We receive payment under turnkey and footage contracts when we deliver to our customer a well completed to the depth specified in the contract, unless the customer authorizes us to drill to a shallower depth. Since 1995, when current management joined our company, we have completed all our turnkey or footage contracts. Although our initial cost estimates for turnkey and footage contracts do not include cost estimates for risks such as stuck drill pipe or loss of circulation, we believe that our experienced management team, our knowledge of geologic formations in our areas of operations, the condition of our drilling equipment and our experienced crews enable us to make reasonably dependable cost estimates and complete contracts according to our drilling plan. While we do bear the risk of loss for cost overruns and other events that are not specifically provided for in our initial cost estimates, our pricing of turnkey and footage contracts takes such risks into consideration. When we encounter, during the course of our drilling operations, conditions unforeseen in the preparation of our original cost estimate, we immediately increase our cost estimate for the additional costs to complete the contracts.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. During fiscal 2004,year 2006, we experienced losses on eight16 of the 105124 turnkey and footage contracts completed, with losses

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 sixten contracts and losses exceeding $100,000 on twofour contracts. We are more likely to encounter losses on turnkey and footage contracts in years in which revenue rates are lower for all types of contracts. During periods of reduced demand for drilling rigs, our overall profitability on turnkey and footage contracts has historically exceeded our profitability on daywork contracts.

Revenues and costs during a reporting period could be affected for contracts in progress at the end of a reporting period which have not been completed before our financial statements for that period are released. All but one of ourWe had no turnkey contracts and two footage contracts in progress at March 31, 2004 were2006, each of which was completed prior to the release of the financial statements included in this report. At March 31, 2004 ourOur contract drilling in progress totaled approximately $9,131,000.$9,620,000 at March 31, 2006. Of that amount accrued, turnkey and footage contract revenues were approximately $7,683,000.$599,000. The remaining balance of approximately $1,448,000$9,021,000 relates to the revenue recognized but not yet billed on daywork contracts in progress at March 31, 2004.

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

19



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 estimateestimates of the useful lives of our drilling, transportation and other equipment are based on our more than 35 years of experience in the drilling industry with similar equipment.

OtherOur other accrued expenses in ouras of March 31, 2004 financial statements2006 include an accrualaccruals of approximately $680,000$643,000 and $1,829,000 for costs incurred under the self-insurance portion of our health insurance and under our workers’ compensation insurance.insurance, respectively. We have a deductible of (1) $100,000$125,000 per covered individual per year under the health insurance and (2) $250,000 per occurrence under our workers’ compensation insurance.insurance, except in North Dakota, where the deductible is $100,000. We accrue for these costs as claims are incurred based on historical claim development data, and we accrue the costs of administrative services associated with claims processing. We also evaluate our claim cost estimates established for each claimbased on estimates provided by the insurance companies providing the administrative services forthat provide claims processing the claims, including an estimate for incurred but not reported claims, estimates for claims paid directly by us, our estimate of the administrative costs associated with these claims and our historical experience with these types of claims.services.

Liquidity and Capital Resources

Sources of Capital Resources

Our rig fleet has grown from eight rigs in August 2000 to 3557 rigs as of March 31, 2004.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 sixnine times since January 2000 and have increased our long-term debt from approximately $3,909,000 at June 30, 2000 to approximately $48,500,000 at March 31, 2004.2000. We plan to continue to grow our rig fleet. We believe that near-termOver 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 will require the use of equity financing rather than additional debt.  At March 31, 2004, our total debt to total capital was approximately 41%.  Due to the volatility in our industry, we are reluctant to take on substantial additional debt at this time.  However, our ability to continue funding our growthopportunities through the issuance of shares of our common stock is uncertain, as our common stock is not heavily traded and the market price for our common stock has been volatile in recent periods.

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

Uses of Capital Resources

In May 2003, we added one refurbished 18,000-foot SCR land drilling rig at a cost of approximately $7,300,000.  On August 1, 2003, we purchased two land drilling rigs, associated spare parts and equipment and vehicles from Texas Interstate Drilling Company, L. P. for $2,500,000 in cashdebt and the issuance of 477,000additional shares of our common stock valued at $4.45 per share.  On August 26, 2003, we purchased a 14,000-foot mechanical rig for $2,925,661 in cash.  After accepting delivery of the rig, we spent approximately $2,400,000 upgrading the rig before placing it in service.  On December 15, 2003, we acquired a rig for approximately $3,770,000 that we had previously been leasing.

On March 2, 2004, we acquired 23 used rig hauling trucks and associated trailers and equipment from A & R Trejo Trucking for $1,200,000.  On March 4, 2004, we acquired a seven-rig drilling fleet from Sawyer Drilling & Service, Inc. for $12,000,000.  On March 12, 2004, we acquired one drilling rig from SEDCO Drilling Co., Ltd. for $2,015,000.  These acquisitions were funded with proceeds from the February 20, 2004 sale of our common stock.

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

In late May 2004, we completed constructing, primarily from used components,

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.

We have a 1000-hp electric$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 rig.  Asrigs, 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, 2004,2006) 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 incurredno borrowings under the acquisition facility and we had used approximately $2,800,000$3,050,000 of construction costs on this rigavailability under the revolving line and anticipate additional related construction costsletter of approximately $2,100,000.credit facility through the issuance of letters of credit in the ordinary course of business. We began moving itexpect to its first drilling location on May 28, 2004.  renew both the revolving line and letter of credit facility and acquisition facility when they mature in October 2006.

Uses of Capital Resources

For fiscal 2005, we project regular capital expenditures to be approximately $10,200,000 and rig upgrade expenditures to be approximately $4,500,000.  These regular capital expenditures and rig upgrade capital expenditures are expected to be funded primarily from operating cash flow.

20



Sincethe years ended March 31, 2003,2006 and 2005, the additions to our property and equipment have totaled $44,844,745.  Additions consisted of the following:

 

Drilling rigs (1)

 

$

34,961,004

 

Other drilling equipment

 

7,642,968

 

Transportation equipment

 

2,160,838

 

Other

 

79,935

 

 

 

$

44,844,745

 

   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)
(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 $106,395.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 decreasedincreased to $6,028,018$106,904,106 at March 31, 20042006 from $11,144,309$76,326,669 at March 31, 2003.2005. Our current ratio, which we calculate by dividing our current assets by our current liabilities, was 1.274.28 at March 31, 20042006, compared to 1.553.70 at March 31, 2003.  The principal reason for the decrease in our working capital at March 31, 2004 was our use of approximately $3,400,000 of working capital toward the purchase of drilling equipment.  We used substantially all the $20,000,000 in proceeds from the shares of common stock we sold to Chesapeake Energy Corporation on March 31, 2003 to expand our rig fleet or reduce debt we incurred to expand our rig fleet.  We have used approximately $17,000,000 of the funds we raised in February 2004 to expand our rig fleet or acquire other equipment.  2005.

Our operations have historically generated cash flows sufficient cash flow to at least meet our requirements for debt service and equipment expenditures, evennormal capital expenditures. However, during periods of industry downturns.  During periods when a higher percentagepercentages 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 have available a $2,500,000believe our cash generated by operations and our ability to borrow under the currently unused portion of our line of credit for short-term cash requirements.  We did not make any borrowings under the lineand letter of credit during fiscal 2004. We have used debt and equityfacility 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 financemeet our long-term growth strategy to increaseroutine financial obligations for the size of our rig fleet.  During periods of improved revenue rates, we believe we can generate cash flows in excess of our normal cash requirements.foreseeable future.

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

 

 

 

March 31,

 

 

 

 

 

2004

 

2003

 

Change

 

Cash and cash equivalents

 

$

6,365,759

 

$

21,002,913

 

$

(14,637,154

)

Receivables

 

20,032,785

 

8,928,923

 

11,103,862

 

Income tax receivable

 

 

444,900

 

(444,900

)

Deferred tax receivable

 

285,384

 

180,991

 

104,393

 

Prepaid expenses

 

1,336,337

 

914,187

 

422,150

 

Current assets

 

28,020,265

 

31,471,914

 

(3,451,649

)

 

 

 

 

 

 

 

 

Current debt

 

4,423,306

 

3,399,163

 

1,024,143

 

Accounts payable

 

13,270,989

 

14,206,586

 

(935,597

)

Accrued payroll

 

1,499,151

 

847,163

 

651,988

 

Accrued expenses

 

2,798,801

 

1,874,693

 

924,108

 

 

 

21,992,247

 

20,327,605

 

1,664,642

 

 

 

 

 

 

 

 

 

Working capital

 

$

6,028,018

 

$

11,144,309

 

$

(5,116,291

)

   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, 20032006 was primarily due to our sale of $20,000,000shares of equitycommon 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 31, 2003,22, 2005 for net proceeds of approximately $81,300,000, of which $14,000,000$20,000,000 was used to reduce long-term debt and $61,300,000 was included in the March 31, 20032005 cash balance.  The $14,000,000 was used during fiscal 2004 to purchase drilling rigs and equipment.

The increase in our receivables and contract drilling in progress at March 31, 20042006 from March 31, 20032005 was due to our operating elevensix additional rigs and the increase of approximately $4,500 per day in the quarter ended March 31, 2004, including an approximately $3,693,000 increase in contract drilling in progress related to turnkey contracts, and an improvement inaverage revenue rates in fiscal 2004 over fiscal 2003.

21



rates.

Substantially all our prepaid expenses at March 31, 20042006 consisted of prepaid insurance. The increase in prepaid insurance iswas primarily due to an increase in insurance premiums resulting from the increase in the size of our drilling rig fleet from 2450 rigs at March 31, 20032005 to 3556 rigs at March 31, 2004.2006 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 iswas primarily due to the approximately 50% 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 seventen days at March 31, 20032005 to nine11 days at March 31, 2004.2006.

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, 20042006 from March 31, 20032005 was due to an increase of approximately $477,000$1,611,000 in the accrual for our insurance deductibles and additional insurance premiums expenseand an increase in bonus accruals of approximately $250,000 related to the sale$721,000. These increases were partially offset by a decrease of common stockapproximately $252,000 in February and accrued property taxes of approximately $205,000 due to increases in rig valuations and the size of our rig fleet.other accrued expense items.

Long-term Debt

OurWe had no long-term debt outstanding at March 31, 2004 consisted2006. See “Sources of the following:

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

 

$

28,000,000

 

 

 

 

 

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

 

13,119,048

 

 

 

 

 

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

 

4,392,174

 

 

 

 

 

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

 

3,000,000

 

 

 

48,511,222

 

 

 

 

 

Less current installments

 

(3,724,302

)

 

 

$

44,786,920

 


(1)          Wedge Energy Services, LLC (“WEDGE”) holds $27,000,000 of the convertible subordinated debentures and William H. White,Capital Resources” for a former directordescription of our company, holds $1,000,000.  WEDGE owns 26.5% of our common stock (40.2% if the debentures were converted).  Beginning July 3, 2004, we have the option to redeem all or part of the debentures by paying a premium of 5% through July 2, 2005, 4% through July 2, 2006, 3% through July 2, 2007 and 0% thereafter.

$57,000,000 credit facility.

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

22



Contractual Obligations

We do not have any routine purchase obligations. However, as of March 31, 2004,2006, we were in the process of constructing anine drilling rig,rigs, as described above.   The following table excludes interest payments on long-term debt and capital lease obligations. The following table includes all of our contractual obligations at March 31, 2004.2006:

 

 

 

Payments Due by Period

 

Contractual
Obligations

 

Total

 

Less than 1
year

 

1-3
years

 

4-5
years

 

More than
5 years

 

Long-Term Debt Obligations

 

$

48,511,222

 

$

3,724,302

 

$

9,347,127

 

$

35,439,793

 

$

 

Capital Lease Obligations

 

245,688

 

140,934

 

104,754

 

 

 

Operating Lease Obligations

 

314,460

 

121,608

 

192,852

 

 

 

Total

 

$

49,071,370

 

$

3,986,844

 

$

9,644,733

 

$

35,439,793

 

$

 

   Payments Due by Period

Contractual Obligations

  Total  Less than 1
year
  

1-3

years

  

4-5

years

  More than 5
years

Operating Lease Obligations

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

Total

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

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.”

Borrowings from Frost National BankThe sum of (1) the draws and Merrill Lynch Capital, a division(2) the amount of Merrill Lynch Business Financial Services, Inc. (“MLC”), containall 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 cash flow coverage,ratio and fixed charge coverage ratio and net worth ratios and restrictrestricts us from paying dividends. Under these credit arrangements, weWe determine compliance with the ratios on a quarterly basis, based on the previous four quarters. As of March 31, 2004, we were in compliance with all covenants applicable to our outstanding debt.

Events of default, in our loan agreements, which could trigger an early repayment requirement, include, among others:

 

our failure to make required payments;

 

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

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

of not less than 1.5 to 1;

 

our incurrence of additional indebtedness in excess of $2,000,000$3,000,000, to the extent not alreadyotherwise allowed by the loan agreements without each lender’s approval; and

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 us in theour future operations or liquidity, as we expect to continue to generate adequate cash flow from operations.

We also have a $2,500,000 line of credit from Frost National Bank to supplement our short-term cash needs.  Any borrowings under this line of credit are secured by our trade receivables and bear interest at a rate of prime (4.00% at March 31, 2004) plus 1.0%.   The sum of draws under this line and the amount of all outstanding letters of credit issued by the bank for our account are limited to 75% of eligible accounts receivable.  Therefore, if 75% of our eligible accounts receivable is less than $2,500,000 plus any outstanding letters of credit issued by the bank on our behalf, our ability to draw under this line would be reduced.  At March 31, 2004, we had no outstanding advances under this line of credit, letters of credit were $1,664,000 and 75% of eligible accounts receivable was approximately $8,030,000.  The letters of credit are issued to two workers’ compensation insurance companies to secure possible future claims that do not exceed the deductibles on these policies.  It is our practice to pay any amounts due that do not exceed these deductibles as they are incurred.  Therefore, we do not anticipate the lender will be requiredoperations to fund any draws under these letters of credit.our anticipated working capital and other normal cash flow requirements.

23



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

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

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

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

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

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

For the years ended March 31, 2004, 20032006, 2005 and 2002,2004, the percentages of our drilling revenues by type of contract were as follows:

 

 

Year Ended March 31,

 

 

2004

 

2003

 

2002

 

  Years Ended March 31, 
  2006 2005 2004 

Daywork Contracts

  89% 52% 47%

Turnkey Contracts

 

50

%

58

%

7

%

  4% 43% 50%

Footage Contracts

 

3

%

1

%

2

%

  7% 5% 3%

Daywork Contracts

 

47

%

41

%

91

%

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

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

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

24



StatementStatements of Operations Analysis

The following table provides information about our operations for the years ended March 31, 2004,2006, March 31, 2003,2005, and March 31, 2002.2004.

 

 

Year Ended March 31,

 

 

2004

 

2003

 

2002

 

  Years Ended March 31, 

Contract drilling revenues

 

$

107,875,533

 

$

80,183,486

 

$

68,627,486

 

Contract drilling costs

 

88,504,102

 

70,823,310

 

46,145,364

 

Depreciation and amortization

 

16,160,494

 

11,960,387

 

8,426,082

 

General and administrative expenses

 

2,772,730

 

2,232,390

 

2,855,274

 

Revenue days by type of contract:

 

 

 

 

 

 

 

  2006 2005 2004 

Contract drilling revenues:

    

Daywork contracts

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

Turnkey contracts

 

2,827

 

2,619

 

289

 

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

Footage contracts

 

311

 

119

 

136

 

   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

 

5,626

 

3,681

 

4,959

 

  $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

 

8,764

 

6,419

 

5,384

 

   18,164   13,894   8,764 

 

 

 

 

 

 

 

          

Contract drilling revenue per revenue day

 

$

12,309

 

$

12,492

 

$

12,747

 

  $15,643  $13,333  $12,309 

Contract drilling cost per revenue day

 

$

10,099

 

$

11,033

 

$

8,571

 

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

 

88

%

79

%

82

%

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

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

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

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

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

which significantly adds to drilling costs for turnkey and footage contracts. These costs are also included in the revenues we recognize for turnkey and footage contracts, resulting in higher revenue rates per day for turnkey and footage contracts compared to daywork contracts which do not include such costs.

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

and footage revenue days (2,071).

Our depreciation and amortization expense in 2004fiscal year 2006 increased by approximately $4,200,000,$10,297,000, or 35%45%, from 2003. Depreciation and amortization expense in 2003 increased approximately $3,534,000, or 42%, from 2002.fiscal year 2005. The increase in 20042006 over 20032005 resulted from our addition of elevensix 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 20032005 over 20022004 resulted from our addition of four15 drilling rigs and related equipment during 2003.

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

Our general and administrative expenses increased by approximately $541,000,$1,866,000, or 24%40%, in fiscal year 2006 from fiscal year 2005. The increase resulted primarily from increases in payroll costs, bonus accrual costs, professional fees, office rent and insurance costs. During fiscal year 2006, payroll costs increased by approximately $975,000, due to pay raises, an increase in the number of employees in our corporate office and an increase in bonus costs of approximately $256,000 as compared to fiscal year ended March 31, 20042005. Professional fees increased by approximately $453,000, office rent increased by approximately $142,000 and insurance costs increased by approximately $119,000.

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

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

Our other expense decreased by approximately $60,000 and directors’ fees increased by approximately $93,000.

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

25



$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 $143,000.$292,000. We are not aware of any potential environmental clean-up obligations that would have a material adverse effect on our financial condition or results of operations.

Our effective income tax rates of 19.2%, 30.4%36.6% for fiscal year 2006, 37.0% for fiscal year 2005 and 35.1%19.2% for fiscal year 2004, 2003 and 2002, respectively, differ from the federal statutory rate of 35% for fiscal year 2006 and 34% for fiscal year 2005 and fiscal year 2004, due to permanent differences.differences and state income taxes. Permanent differences are costs included in results of operations in the accompanying financial statements which are not fully deductible for federal income tax purposes. At March 31, 2005, we had a net operating loss carryforwards for income tax purposes of approximately $16,500,000, which was fully utilized in fiscal year 2006.

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.

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

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

Item 7A.7A. Quantitative and Qualitative Disclosures About Market Risk

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

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

26


Item 8.8. Financial Statements and Supplementary Data

PIONEER DRILLING COMPANY

INDEX TO CONSOLIDATED FINANCIAL STATEMENTS

 

Page

ReportReports of Independent Registered Public Accounting Firm

30

Consolidated Balance Sheets as of March 31, 20042006 and 20032005

32

Consolidated Statements of Operations for the Years Ended March 31, 2004, 20032006, 2005 and 20022004

33

Consolidated Statements of Shareholders’ Equity and Comprehensive Income for the Years Ended March 31, 2004, 20032006, 2005 and 20022004

34

Consolidated Statements of Cash Flows for the Years Ended March 31, 2004, 20032006, 2005 and 20022004

35

Notes to Consolidated Financial Statements

36

27



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, 20042006 and 20032005, and the related consolidated statements of operations, shareholders’stockholders’ equity, and comprehensive income and cash flows for each of the years in the three-year period ended March 31, 2004.2006. In connection with our audits of the consolidated financial statements, we also have audited the financial statement schedule II. These consolidated financial statements and financial statement schedule are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated financial statements and financial statement schedule based on our audits.

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

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Pioneer Drilling Company and subsidiaries as of March 31, 20042006 and 2003,2005, and the results of their operations and their cash flows for each of the years in the three-year period ended March 31, 2004,2006, in conformity with U. S.U.S. generally accepted accounting principles. Also in our opinion, the related financial statement schedule, when considered in relation to the basic consolidated financial statements taken as a whole, presents fairly, in all material respects, the information set forth therein.

KPMG LLP

San Antonio, Texas

June 23, 2004

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

28



KPMG LLP

San Antonio, Texas

May 24, 2006

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

The Board of Directors and Stockholders

Pioneer Drilling Company:

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

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

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

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

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

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

KPMG LLP

San Antonio, Texas

May 24, 2006

PIONEER DRILLING COMPANY AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

 

 

March 31,

 

  March 31, 

 

2004

 

2003

 

  2006  2005 

ASSETS

 

 

 

 

 

    

Current assets:

 

 

 

 

 

    

Cash and cash equivalents

 

$

6,365,759

 

$

21,002,913

 

  $91,173,764  $69,673,279 

Marketable securities

   —     1,000,000 

Receivables:

 

 

 

 

 

    

Trade, net

 

10,901,991

 

4,499,378

 

   35,544,543   26,108,291 

Contract drilling in progress

 

9,130,794

 

4,429,545

 

   9,620,179   5,364,529 

Federal income tax receivable

 

 

444,900

 

Current deferred income taxes

 

285,384

 

180,991

 

   989,895   569,548 

Prepaid expenses

 

1,336,337

 

914,187

 

   2,207,853   1,876,843 
       

Total current assets

 

28,020,265

 

31,471,914

 

   139,536,234   104,592,490 
       

Property and equipment, at cost:

 

 

 

 

 

    

Drilling rigs and equipment

 

145,758,913

 

106,728,573

 

   328,673,207   216,286,747 

Transportation, office, land and other

 

5,427,637

 

3,494,657

 

Transportation equipment

   9,169,461   6,469,519 

Land, buildings and other

   3,925,614   2,691,673 
       

 

151,186,550

 

110,223,230

 

   341,768,282   225,447,939 

Less accumulated depreciation and amortization

 

35,844,938

 

22,367,327

 

   80,984,991   54,881,488 
       

Net property and equipment

 

115,341,612

 

87,855,903

 

   260,783,291   170,566,451 

Other assets

 

369,278

 

366,500

 

Intangible and other assets

   358,180   850,381 
       

Total assets

 

$

143,731,155

 

$

119,694,317

 

  $400,677,705  $276,009,322 

 

 

 

 

 

       

LIABILITIES AND SHAREHOLDERS’ EQUITY

 

 

 

 

 

    

Current liabilities:

 

 

 

 

 

    

Notes payable

 

$

558,070

 

$

587,177

 

  $—    $681,975 

Current installments of long-term debt

 

3,724,302

 

2,671,269

 

   —     4,666,667 

Current installments of capital lease obligations

 

140,934

 

140,717

 

   —     66,359 

Accounts payable

 

13,270,989

 

14,206,586

 

   16,040,568   15,621,647 

Income tax payable

   6,834,877   195,949 

Prepaid drilling contracts

   139,769   172,750 

Accrued expenses:

 

 

 

 

 

    

Payroll and payroll taxes

 

1,499,151

 

847,163

 

   3,383,435   2,706,623 

Other

 

2,798,801

 

1,874,693

 

   6,233,479   4,153,851 
       

Total current liabilities

 

21,992,247

 

20,327,605

 

   32,632,128   28,265,821 

Long-term debt, less current installments

 

44,786,920

 

45,594,517

 

   —     13,411,111 

Capital lease obligations, less current installments

 

104,754

 

260,025

 

   —     33,906 

Non-current liabilities

   387,524   400,000 

Deferred income taxes

 

6,010,916

 

5,839,908

 

   26,982,526   12,283,070 
       

Total liabilities

 

72,894,837

 

72,022,055

 

   60,002,178   54,393,908 
       

Commitments and contingencies

    

Shareholders’ equity:

 

 

 

 

 

    

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

 

 

 

 

 

   —     —   

Common stock $.10 par value; 100,000,000 shares authorized; 27,300,126 shares and 21,700,792 shares issued and outstanding at March 31, 2004 and March 31, 2003, respectively

 

2,730,012

 

2,170,079

 

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

   4,959,197   4,589,331 

Additional paid-in capital

 

82,124,368

 

57,730,188

 

   288,356,164   220,232,520 

Accumulated deficit

 

(14,018,062

)

(12,228,005

)

Accumulated earnings (deficit)

   47,360,166   (3,206,437)
       

Total shareholders’ equity

 

70,836,318

 

47,672,262

 

   340,675,527   221,615,414 
       

Total liabilities and shareholders’ equity

 

$

143,731,155

 

$

119,694,317

 

  $400,677,705  $276,009,322 
       

See accompanying notes to consolidated financial statements.

29



PIONEER DRILLING COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

 

 

Years Ended March 31,

 

 

2004

 

2003

 

2002

 

  Years Ended March 31, 

 

 

 

 

 

 

 

  2006 2005 2004 

Contract drilling revenues

 

$

107,875,533

 

$

80,183,486

 

$

68,627,486

 

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

 

 

 

 

 

 

 

          

Costs and expenses:

 

 

 

 

 

 

 

    

Contract drilling

 

88,504,102

 

70,823,310

 

46,145,364

 

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

Depreciation and amortization

 

16,160,494

 

11,960,387

 

8,426,082

 

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

General and administrative

 

2,772,730

 

2,232,390

 

2,855,274

 

   6,522,842   4,657,013   2,772,730 

Bad debt expense

 

 

110,000

 

 

Bad debt expense (recovery)

   (152,000)  242,000   —   

 

 

 

 

 

 

 

          

Total operating costs and expenses

 

107,437,326

 

85,126,087

 

57,426,720

 

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

Income (loss) from operations

 

438,207

 

(4,942,601

)

11,200,766

 

          

Income from operations

   77,909,039   18,773,767   438,207 

 

 

 

 

 

 

 

          

Other income (expense):

 

 

 

 

 

 

 

    

Interest expense

 

(2,807,822

)

(2,698,529

)

(1,616,984

)

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

Interest income

 

101,584

 

94,235

 

80,932

 

   2,068,767   173,318   101,584 

Other

 

51,675

 

37,614

 

72,096

 

   71,426   37,267   51,675 

Gain on sale of securities

 

 

203,887

 

 

Loss from early extinguishment of debt

   —     (100,833)  —   
          

Total other income (expense)

 

(2,654,563

)

(2,362,793

)

(1,463,956

)

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

 

 

 

 

 

 

 

          

Income (loss) before income taxes

 

(2,216,356

)

(7,305,394

)

9,736,810

 

Income before income taxes

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

Income tax (expense) benefit

 

426,299

 

2,219,776

 

(3,418,525

)

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

 

 

 

 

 

 

 

          

Net earnings (loss)

 

(1,790,057

)

(5,085,618

)

6,318,285

 

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

Preferred stock dividend requirement

 

 

 

92,814

 

Net earnings (loss) applicable to common shareholders

 

$

(1,790,057

)

$

(5,085,618

)

$

6,225,471

 

 

 

 

 

 

 

 

          

Earnings (loss) per common share - Basic

 

$

(0.08

)

$

(0.31

)

$

0.41

 

  $1.08  $0.31  $(0.08)

 

 

 

 

 

 

 

          

Earnings (loss) per common share - Diluted

 

$

(0.08

)

$

(0.31

)

$

0.35

 

  $1.06  $0.30  $(0.08)

 

 

 

 

 

 

 

          

Weighted average number of shares outstanding - Basic

 

22,585,612

 

16,163,098

 

15,112,272

 

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

 

 

 

 

 

 

 

          

Weighted average number of shares outstanding - Diluted

 

22,585,612

 

16,163,098

 

19,221,256

 

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

See accompanying notes to consolidated financial statements.

30



PIONEER DRILLING COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF SHAREHOLDERS’ EQUITY AND COMPREHENSIVE INCOME

 

 

Shares
Common

 

Shares
Preferred

 

Amount
Common

 

Preferred

 

Additional
Paid In
Capital

 

Accumulated
Deficit

 

Accumulated
Other
Comprehensive
Income

 

Total
Shareholders’
Equity

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

  Shares
Common
  Amount
Common
  

Additional

Paid In

Capital

  Accumulated
Deficit
 Total
Shareholders’
Equity
 

Balance as of March 31, 2001

 

12,145,921

 

184,615

 

$

1,214,592

 

$

2,999,994

 

$

26,869,916

 

$

(13,367,858

)

$

110,118

 

$

17,826,762

 

Comprehensive income:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Net earnings

 

 

 

 

 

 

6,318,285

 

 

6,318,285

 

Net unrealized change in securites available for sale, net of tax of $384

 

 

 

 

 

 

 

(702

)

(702

)

Total comprehensive income

 

 

 

 

 

 

 

 

6,317,583

 

Issuance of common stock for:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Sale, net of related expenses

 

2,400,000

 

 

240,000

 

 

8,808,000

 

 

 

9,048,000

 

Conversion of preferred

 

1,199,038

 

(184,615

)

119,903

 

(2,999,994

)

2,880,091

 

 

 

 

Exercise of options

 

177,500

 

 

17,750

 

 

225,724

 

 

 

243,474

 

Preferred stock dividend

 

 

 

 

 

 

(92,814

)

 

(92,814

)

Balance as of March 31, 2002

 

15,922,459

 

 

1,592,245

 

 

38,783,731

 

(7,142,387

)

109,416

 

33,343,005

 

Comprehensive income:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Net loss

 

 

 

 

 

 

(5,085,618

)

 

(5,085,618

)

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

 

 

 

 

 

 

 

(109,416

)

(109,416

)

Total comprehensive loss

 

 

 

 

 

 

 

 

(5,195,034

)

Issuance of common stock for:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Sale, net of related expenses of $657,499

 

5,333,333

 

 

533,334

 

 

18,809,167

 

 

 

19,342,501

 

Exercise of options

 

445,000

 

 

44,500

 

 

137,290

 

 

 

181,790

 

Balance as of March 31, 2003

 

21,700,792

 

 

2,170,079

 

 

57,730,188

 

(12,228,005

)

 

47,672,262

 

  21,700,792   2,170,079   57,730,188   (12,228,005)  47,672,262 

Comprehensive income:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

         

Net loss

 

 

 

 

 

 

(1,790,057

)

 

(1,790,057

)

  —     —     —     (1,790,057)  (1,790,057)
           

Total comprehensive loss

 

 

 

 

 

 

 

 

(1,790,057

)

  —     —     —     —     (1,790,057)
           

Issuance of common stock for:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

         

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

 

4,400,000

 

 

440,000

 

 

21,665,247

 

 

 

22,105,247

 

  4,400,000   440,000   21,665,247   —     22,105,247 

Equipment acquisitions

 

477,000

 

 

47,700

 

 

2,074,950

 

 

 

2,122,650

 

  477,000   47,700   2,074,950   —     2,122,650 

Exercise of options and related income tax benefits

 

722,334

 

 

72,233

 

 

653,983

 

 

 

726,216

 

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

  722,334   72,233   653,983   —     726,216 
                

Balance as of March 31, 2004

 

27,300,126

 

 

$

2,730,012

 

$

 

$

82,124,368

 

$

(14,018,062

)

$

 

$

70,836,318

 

  27,300,126   2,730,012   82,124,368   (14,018,062)  70,836,318 

Comprehensive income:

         

Net earnings

  —     —     —     10,811,625   10,811,625 
           

Total comprehensive income

  —     —     —     —     10,811,625 
           

Issuance of common stock for:

         

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

  11,545,000   1,154,500   109,854,558   —     111,009,058 

Debenture conversion

  6,496,519   649,652   27,350,348   —     28,000,000 

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

  551,666   55,167   903,246   —     958,413 
                

Balance as of March 31, 2005

  45,893,311   4,589,331   220,232,520   (3,206,437)  221,615,414 

Comprehensive income:

         

Net earnings

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

Total comprehensive income

  —     —     —     —     50,566,603 
           

Issuance of common stock for:

         

Sale, net of related expenses of $968,361

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

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

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

See accompanying notes to consolidated financial statements.

31



PIONEER DRILLING COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

 

 

Years Ended March 31,

 

  Years Ended March 31, 

 

2004

 

2003

 

2002

 

  2006 2005 2004 

Cash flows from operating activities:

 

 

 

 

 

 

 

    

Net earnings (loss)

 

$

(1,790,057

)

$

(5,085,618

)

$

6,318,285

 

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

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

 

 

 

 

 

 

 

    

Depreciation and amortization

 

16,160,494

 

11,960,387

 

8,426,082

 

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

Allowance for doubtful accounts

 

 

110,000

 

 

   (152,000)  242,000   —   

Gain on sale of securities

 

 

(203,887

)

 

Loss (gain) on dispositions of properties and equipment

 

816,104

 

279,054

 

(2,237

)

Change in deferred income taxes

 

119,038

 

(1,511,744

)

1,991,458

 

Loss on dispositions of property and equipment

   2,895,752   696,345   816,104 

Deferred income taxes

   14,279,109   5,987,991   119,038 

Change in other assets

   209,525   (123,263)  (40,000)

Change in non-current liabilities

   (12,476)  —     —   

Changes in current assets and liabilities:

 

 

 

 

 

 

 

    

Receivables

 

(11,103,862

)

242,126

 

(4,172,470

)

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

Prepaid expenses

 

(422,150

)

(279,440

)

(322,471

)

   (331,010)  (540,507)  (422,150)

Accounts payable

 

(935,597

)

7,699,417

 

(1,099,813

)

   418,921   2,350,658   (935,597)

Federal income taxes

 

444,900

 

435,168

 

(930,266

)

Income tax payable

   6,638,928   195,949   444,900 

Prepaid drilling contracts

   (32,981)  172,750   —   

Accrued expenses

 

1,576,096

 

743,814

 

836,321

 

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

Net cash provided by operating activities

 

4,864,966

 

14,389,277

 

11,044,889

 

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

 

 

 

 

 

 

 

          

Cash flows from financing activities:

 

 

 

 

 

 

 

    

Proceeds from notes payable

 

4,110,019

 

23,573,501

 

19,556,286

 

   —     41,354,367   4,110,019 

Proceeds from subordinated debenture

 

 

10,000,000

 

18,000,000

 

Increase in other assets

 

(40,000

)

(253,698

)

(195,000

)

Payment of preferred dividends

 

 

 

(859,395

)

Proceeds from exercise of options and warrants

 

673,794

 

181,790

 

243,474

 

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

 

22,105,247

 

19,342,501

 

9,048,000

 

Proceeds from exercise of options

   6,791,871   958,412   673,794 

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

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

Payments of debt

 

(4,048,744

)

(18,714,311

)

(27,026,538

)

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

Net cash provided by financing activities

 

22,800,316

 

34,129,783

 

18,766,827

 

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

Cash flows from investing activities:

 

 

 

 

 

 

 

    

Business acquisitions

   —     (35,200,000)  (14,500,000)

Purchases of property and equipment

 

(42,722,094

)

(33,588,972

)

(27,597,265

)

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

Proceeds from sale of marketable securities

 

 

375,414

 

 

Proceeds from sale (purchase) of marketable securities, net

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

Proceeds from sale of property and equipment

 

419,658

 

314,366

 

675,660

 

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

Net cash used in investing activities

 

(42,302,436

)

(32,899,192

)

(26,921,605

)

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

Net increase (decrease) in cash and cash equivalents

 

(14,637,154

)

15,619,868

 

2,890,111

 

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

Beginning cash and cash equivalents

 

21,002,913

 

5,383,045

 

2,492,934

 

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

Ending cash and cash equivalents

 

$

6,365,759

 

$

21,002,913

 

$

5,383,045

 

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

Supplementary disclosure:

 

 

 

 

 

 

 

    

Interest paid

 

$

2,821,041

 

$

2,785,177

 

$

1,046,943

 

  $407,158  $2,407,193  $2,821,041 

Income taxes paid (refunded)

 

(990,237

)

(1,143,200

)

2,342,006

 

Dividends accrued

 

 

 

92,814

 

Conversion of preferred stock

 

 

 

2,999,994

 

Income tax paid (refunded)

  $4,321,619  $(30,000) $(990,237)

Debenture conversion - common stock issued

  $—    $28,000,000  $—   

Acquisition - common stock issued

 

2,122,650

 

 

 

  $—    $—    $2,122,650 

Tax benefit from exercise of nonqualified options

 

52,423

 

2,720

 

 

  $4,009,945  $204,964  $52,423 

See accompanying notes to consolidated financial statements.

32



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

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

Income Taxes

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

Earnings (Loss) Per Common Share

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

33



Stock-based Compensation

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

 

 

 

Year Ended March 31,

 

 

 

2004

 

2003

 

2002

 

Net earnings (loss)-as reported

 

$

(1,790,057

)

$

(5,085,618

)

$

6,318,285

 

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

 

(662,933

)

(385,671

)

(582,258

)

Net earnings (loss)-pro forma

 

$

(2,452,990

)

$

(5,471,289

)

$

5,736,027

 

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

 

$

(0.08

)

$

(0.31

)

$

(0.41

)

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

 

(0.08

)

(0.31

)

(0.35

)

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

 

$

(0.11

)

$

(0.34

)

$

(0.38

)

Net earnings (loss) per share-pro forma diluted

 

(0.11

)

(0.34

)

(0.32

)

Weighted-average fair value of options granted during the year

 

$

4.46

 

$

3.50

 

$

3.11

 

   Years Ended March 31, 
   2006  2005  2004 

Net earnings (loss)-as reported

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

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

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

Net earnings (loss)-pro forma

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

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

  $1.08  $0.31  $(0.08)

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

  $1.06  $0.30  $(0.08)

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

  $1.04  $0.28  $(0.11)

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

  $1.02  $0.27  $(0.11)

Weighted-average fair value of options granted during the year

  $6.47  $8.85  $4.46 

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

   2006  2005  2004 

Expected volatility

  52% 86% 94%

Weighted-average risk-free interest rates

  4.0% 3.7% 3.3%

Expected life in years

  4.1  5  5 

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

Revenue and Cost Recognition

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

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

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

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

34



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

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

Prepaid Expenses

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

Property and Equipment

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

We charge our expenses for maintenance and repairs to operations. We charge our expenses for renewals and betterments to the appropriate property and equipment accounts. Our gains and losses on the sale of our property and equipment are recorded in drilling costs. During fiscal 20042006 and 2003,2005, we capitalized $106,395$194,500 and $96,079,$86,819, respectively, of interest costs incurred during the construction periods of certain drilling equipment. At March 31, 20042006 and 2003,2005, costs incurred on rigs under construction were approximately $2,800,000$26,172,000 and $2,415,000,$3,300,000, respectively.

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

Cash and Cash Equivalents

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

For purposes of the statements of cash flows, we consider all highly liquid debt instruments purchased with a maturity of three months or less to be cash equivalents. Cash equivalents consist of investments in corporate and government money market accounts and auction rate seven day taxable preferred securities.accounts. Cash equivalents at March 31, 20042006 and 20032005 were $6,118,000$85,618,000 and $1,060,000,$65,046,000, respectively.

Marketable Securities

Investment Securities

We carry our available-for-sale investment securities at their fair values.  InvestmentMarketable securities consist of common stock.  Unrealized holdingauction rate seven-day preferred securities whose market value is equal to their cost. The objective of investing in these securities is to improve our yield on short-term investments of cash. There were no realized or unrealized gains andor losses net ofrelating to marketable securities during the related tax effect, on available-for-sale securities are excluded from earnings and are reported as a separate component of other comprehensive income until realized.  Realized gains and losses from the sale of available-for-sale securities are determined on a specific identification basis. As ofyears ended March 31, 2002, these securities had an aggregate cost of $171,527, a gross unrealized gain of $165,7822006, 2005 and an aggregate fair value of $337,309.  We sold all of our investment securities in April 2002, realizing a gain of $203,887.2004.

Trade Accounts Receivable

We record trade accounts receivable at the amount we invoice our customers. These accounts do not bear interest. The allowance for doubtful accounts is our best estimate of the amount of probable credit losses in our accounts receivable as of the balance sheet date. We determine the allowance based on the credit worthiness of our customers and general economic conditions. Consequently, an adverse change in those factors could affect our estimate of our allowance for doubtful accounts. We review our allowance for doubtful accounts monthly. Balances more than 90 days past due are reviewed individually for collectibility. We charge off account balances against the allowance after we have exhausted all reasonable means of collection and determined that the potential for recovery is remote. We do not have any off-balance-sheetoff-balance sheet credit exposure related to our customers. At March 31, 20042006 and 20032005 our allowance for doubtful accounts was $110,000.$200,000 and $352,000.

35



Intangible and Other Assets

OtherIntangible 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 arewere fully amortized overwhen we paid the termsoutstanding balance of the related debt.acquisition facility in August 2005. Intangibles related to acquisitions, primarily customer lists arewere amortized over their estimated benefit periods of up to 18 months.months and were fully amortized by December 2005. Intangibles related to non-compete agreements are amortized over the period of the non-compete agreements of three to five years. Depreciation and amortization expense includes amortization of intangibles of $65,000, $142,157 and $39,341 during the years ended March 31, 2006, 2005 and 2004, respectively.

Derivative Instruments and Hedging Activities

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

Related Party Transactions

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

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

   2006  2005  2004

R&B Answering Service

      

Purchases

  $16,915  $18,218  $13,526

Payments

  $19,965  $17,112  $12,544

Frontier Services, Inc.

      

Purchases

  $5,953  $81,254  $118,660

Payments

  $9,302  $93,709  $136,818

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

Recently Issued Accounting Standards

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

On July 1, 2003, we adopted SFAS No. 149, Amendment of Statement 133 on Derivative Instruments and Hedging Activities.  This statement amends and clarifies financial accounting and reporting for derivative instruments, including certain derivative instruments in other contracts (collectively referred to as derivatives) and for hedging activities under SFAS No. 133, Accounting for Derivative Instrument and Hedging Activities. The provisions of this statement123R are effective for contracts entered into or modified after June 30, 2003 and hedging relationships designated after June 30, 2003.  Except for the provisions related to SFAS No. 133, all provisions of this statement will be applied prospectively.  In addition, paragraphs 7(a) and 23(a) of this statement, which relate to forward purchases or sales of when-issued securities or other securitiespublic entities that do not yet exist, should be applied to both existing contracts and new contracts entered into after June 30, 2003.  Our adoptionfile as small business issuers as of SFAS No. 149 did not have a material effect on our financial position or results of operations.

On July 1, 2003, we adopted SFAS No. 150, Accounting for Certain Financial Instruments with Characteristics of Both Liabilities and Equity.  This statement requires issuers to classify as liabilities (or assets in some circumstance) three classes of freestanding financial instruments that embody obligations of the issuer. The provisions of this statement are effective for financial instruments entered into or modified after May 31, 2003, and otherwise are effective at the beginning of the first interimannual reporting period beginningthat begins after June 15, 2003.  Our2005. We will adopt SFAS No. 123R effective April 1, 2006 using the modified prospective method. The modified prospective method requires us to recognize compensation cost for unvested awards that are outstanding on the effective date based on the fair value originally estimated for our SFAS No. 123 pro forma disclosures. SFAS No. 123R will have a negative impact on our financial position and results of operations in fiscal year 2007 and in subsequent periods. The negative impact of SFAS No. 123R to net earnings (loss) and net earnings (loss) per share for the years ended March 31, 2006, 2005 and 2004 is presented in our SFAS 123 pro forma disclosures in the table above.

In May 2005, the FASB issued SFAS No. 154,Accounting Changes and Error Corrections, which supersedes APB Opinion No. 20,Accounting Changesand SFAS No. 3,Reporting Accounting Changes in Interim Financial Statements.SFAS No. 154 changes the requirements for the accounting for and reporting of changes in accounting principles. The statement requires the retroactive application to prior periods’ financial statements of changes in accounting principles, unless it is impracticable to determine either the period-specific effects or the cumulative effect of the change. SFAS No. 154 does not change the guidance for reporting the correction of an error in previously issued financial statements or the change in an accounting estimate. SFAS No. 154 is effective for accounting changes and corrections of errors made in fiscal years beginning after December 15, 2005. We do not expect the adoption of SFAS No. 150 did not154 to have a material effectimpact on our financial position orand results of operations.operations and financial condition.

Reclassifications

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

2.Acquisitions

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

  On August 1, 2003, we purchased two land drilling rigs, associated spare parts and equipment and vehicles from Texas Interstate Drilling Company, L. P. for $2,500,000Wolverine. We funded this acquisition with $28,000,000 of bank debt which has subsequently been paid in cash and the issuance of 477,000 shares of our common stock at $4.45 per share.  Thefull. This purchase was accounted for as an acquisition of a business, and we have included the results of operationsoperation of these assetsthe acquired business in our statement of operations since the date of acquisition. We allocated the purchase price to drillingproperty and equipment and related assets, including the non-competition agreements and other intangibles, based on their relative fair values at the date of acquisition.

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

36



On March 2, 2004, we acquired 23 used rig hauling trucks and associated trailers and equipment from A & R Trejo Trucking for $1,200,000.  This purchase was accounted for as an acquisition ofall the contract drilling assets and the purchase price was allocated to the trucksa 17-acre rig storage and maintenance yard of Allen Drilling Company, a land drilling contractor based in Woodward, Oklahoma. The equipment included five mechanical drilling rigs and related assets, based on their relative fair values atincluding 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 datePresident of acquisition.

On March 4, 2004, we acquired a seven-rig drilling fleet from SawyerAllen Drilling & Services, Inc.which provides for $12,000,000.the payment of $500,000 due in annual installments of $100,000 each beginning December 15, 2005. We funded this acquisition with $7,200,000 of bank debt which has subsequently been paid in full. This purchase was accounted for as an acquisition of a business, and we have included the results of operations of these assetsthe acquired business in our statement of operations since the date of acquisition. We allocated the purchase price to drillingproperty and equipment and related assets, including the non-competition agreements and other intangibles, based on their relative fair values at the date of acquisition.

On March 12, 2004, we acquired one drilling rig from SEDCO Drilling Co., Ltd. for $2,015,000. This purchase was accounted for as an acquisition

The following table summarizes the allocation of assets, and we have included the results of operations of these assets in our statement of operations since the date of acquisition.  We allocated the purchase price to drillingproperty and equipment and relatedother assets including intangibles, based on their relative fair values atacquired in the date of acquisition.Wolverine and Allen Drilling acquisitions:

 

   Wolverine  Allen  Total 

Assets acquired:

     

Drilling equipment

  $27,620,214  $7,057,500  $34,677,714 

Vehicles

   214,786   230,000   444,786 

Buildings

   30,000   260,000   290,000 

Land

   20,000   40,000   60,000 

Intangibles, primarily non-compete agreements

   115,000   112,500   227,500 
             
  $28,000,000  $7,700,000  $35,700,000 

Less non-compete obligation

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

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

   

Pro Forma

Years Ended March 31,

 
   2005  2004 

Total revenues

  $208,394,551  $132,287,140 

Net earnings (loss)

  $11,943,137  $(2,100,116)

Earnings (loss) per common share:

    

Basic

  $0.35  $(0.09)

Diluted

  $0.33  $(0.09)

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

Our long-term debt is described below:

 

 

 

March 31,

 

 

 

2004

 

2003

 

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

 

$

28,000,000

 

$

28,000,000

 

 

 

 

 

 

 

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

 

13,119,048

 

14,500,000

 

 

 

 

 

 

 

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

 

4,392,174

 

5,677,889

 

 

 

 

 

 

 

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

 

 

87,897

 

 

 

 

 

 

 

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

 

3,000,000

 

 

 

 

48,511,222

 

48,265,786

 

 

 

 

 

 

 

Less current installments

 

(3,724,302

)

(2,671,269

)

 

 

$

44,786,920

 

$

45,594,517

 

   March 31, 
   2006  2005 

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

  $

        —  

 

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

Less current installments

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


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

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

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

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

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

37



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

Year Ended
March 31,

 

 

 

2005

 

$

3,724,302

 

2006

 

3,743,087

 

2007

 

5,604,040

 

2008

 

35,439,793

 

2009

 

 

2010 and thereafter

 

 

On October 9, 2001, we issued a 6.75% five-year $18,000,000 convertible subordinated debenture, Series A, to WEDGE Energy Services, L.L.C. (“WEDGE”). The debenture was convertible into 4,500,000 shares of common stock at $4.00 per share.  We used approximately $9,000,000 of the proceeds to complete the construction of two drilling rigs.  Approximately $6,000,000 was used to reduce a $12,000,000 credit facility.  The balance of the proceeds was used for drilling equipment and working capital. OnIn July 3, 2002, we issued an additional $10,000,000$9,000,000 and $1,000,000 of 6.75% convertible subordinated debtdebentures to WEDGE with an effective conversion rate of $5.00 per share.  The transaction was effected by an agreement between Pioneer and WEDGE under which WEDGE agreed to provide the additional $10,000,000 in financing and to cancel the previously issued debenture in the principal amount of $18,000,000 in exchange for $28,000,000 in new 6.75% convertible subordinated debentures.  The new debentures are convertible into 6,500,000 shares of common stock at $4.31 per share, which resulted from a pro rata blending of the $5.00 conversion rate of the new $10,000,000 financing and the $4.00 conversion rate of the $18,000,000 debenture being cancelled.  WEDGE funded $7,000,000 of the $10,000,000 on July 3, 2002 and $2,000,000 on July 29, 2002. William H. White, a former Director of our Company and the former President of WEDGE, purchased the remaining $1,000,000 onrespectively. These debentures were due by July 29, 2002.  Unlike the cancelled debenture, which was not redeemable by Pioneer, the new2007. In addition, these debentures arewere convertible into 6,496,519 shares of common stock at $4.31 per share and redeemable at a scheduled premium. We used $7,000,000 of the proceeds to pay down bank debt and $3,000,000 for the purchase of drilling equipment.

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

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

common stock.

Notes payable at March 31, 2004 consists2005 consisted of a $558,070$681,975 insurance premium note due in monthly installments of $112,355 throughon August 26, 2004 which bears2005, plus interest at the rate of 2.65%3.15% per year.

4.Leases

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

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

leases were as follows:

 

 

March 31,

 

 

 

2004

 

2003

 

Transportation equipment

 

$

665,195

 

$

647,822

 

Less accumulated amortization

 

413,797

 

248,070

 

 

 

$

251,398

 

$

399,752

 

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

38



We lease real estate in Henderson, Texas; Alice, Texas; and Decatur, Texas and various office equipment under non-cancelable operating leases expiring through 2006.2010 and real estate under non-cancelable operating leases as follows:

 

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

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

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

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

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

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

Future lease obligations and minimum capital lease payments as of March 31, 20042006 were as follows:

 

Year Ended
March 31,

 

Operating
Leases

 

Capital
Leases

 

2005

 

$

121,608

 

$

166,604

 

2006

 

122,940

 

70,446

 

2007

 

69,912

 

34,106

 

2008

 

 

 

Total minimum lease payments

 

$

314,460

 

$

271,156

 

 

 

 

 

 

 

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

 

(25,468

)

Present value of net minimum capital lease payments

 

245,688

 

Less current installments of capital lease obligations

 

(140,934

)

Capital lease obligations, excluding current installments

 

$

104,754

 

Year Ended

March 31,

   

2007

  $243,104

2008

   234,930

2009

   212,073

2010

   215,238

2011

   213,913

Thereafter

   607,006
    
  $1,726,264
    

5.Income Taxes

Our provision for income taxes consists of the following:

 

 

Years Ended March 31,

 

 

2004

 

2003

 

2002

 

  Years Ended March 31, 

 

 

 

 

 

 

 

  2006  2005  2004 

Current tax - state

  $701,124  $56,400  $—   

Current tax - federal

 

$

 

$

(708,032

)

$

1,427,067

 

   14,266,384   335,109   —   

Deferred tax - state

   312,510   55,164   —   

Deferred tax - federal

 

(426,299

)

(1,511,744

)

1,991,458

 

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

Income tax expense (benefit)

 

$

(426,299

)

$

(2,219,776

)

$

3,418,525

 

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

In fiscal years 2004, 2003 and 2002, our expected

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

 

 

 

Years Ended March 31,

 

 

 

2004

 

2003

 

2002

 

 

 

 

 

 

 

 

 

Expected tax expense (benefit)

 

$

(753,561

)

$

(2,483,834

)

$

3,310,515

 

Non taxable interest income

 

 

(10,400

)

(9,429

)

Club dues, meals and entertainment

 

13,941

 

10,443

 

10,115

 

Reimbursement of food costs for rig employees

 

314,622

 

275,338

 

270,000

 

Other

 

(1,301

)

(11,323

)

(162,676

)

 

 

$

(426,299

)

$

(2,219,776

)

$

3,418,525

 

39



   Years Ended March 31, 
   2006  2005  2004 

Expected tax expense (benefit)

  $27,934,627  $5,834,783  $(753,561)

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

   813,936   —     —   

Club dues, meals and entertainment

   32,344   24,050   13,941 

State income taxes

   658,862   92,388   —   

Other

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

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

 

 

 

March 31,

 

 

 

2004

 

2003

 

 

 

 

 

 

 

Deferred tax assets:

 

 

 

 

 

Workers compensation and vacation expense accruals

 

$

224,985

 

$

94,972

 

Bad debt expense

 

37,400

 

37,400

 

Net operating loss carryforwards

 

7,825,126

 

5,105,730

 

Alternative minimum tax credit

 

181,770

 

181,770

 

Loss accrual on turnkey contracts

 

23,000

 

48,619

 

Total deferred tax assets

 

8,292,281

 

5,468,491

 

Deferred tax liabilities:

 

 

 

 

 

Property and equipment, principally due to differences in depreciation

 

14,017,813

 

11,127,408

 

Total deferred tax liabilities

 

14,017,813

 

11,127,408

 

Net deferred tax liabilities

 

$

5,725,532

 

$

5,658,917

 

   March 31,
   2006  2005

Deferred tax assets:

    

Vacation expense accruals

  $104,338  $71,446

Workers compensation and health insurance accruals

   812,038   378,423

Bad debt expense

   73,520   119,680

Net operating loss carryforwards

   —     5,616,861

Alternative minimum tax credit

   —     311,915

Deferred lease liability

   32,966   —  
        

Total deferred tax assets

   1,022,862   6,498,325
        

Deferred tax liabilities:

    

Property and equipment, principally due to differences in depreciation

   25,926,429   16,924,919

Other

   1,089,064   1,286,928
        

Total deferred tax liabilities

   27,015,493   18,211,847
        

Net deferred tax liabilities

  $25,992,631  $11,713,522
        

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

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

Year

 

Amount

 

2023

 

15,000,000

 

2024

 

10,500,000

 

6.Fair Value of Financial Instruments

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

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

Long-term debt:

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

40



7.Earnings (Loss) Per Common Share

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

 

 

 

Years Ended March 31,

 

 

 

2004

 

2003

 

2002

 

 

 

 

 

 

 

 

 

Basic

 

 

 

 

 

 

 

Net earnings (loss)

 

$

(1,790,057

)

$

(5,085,618

)

$

6,318,285

 

Less:  Preferred stock dividends

 

 

 

92,814

 

Earnings (loss) applicable to common shareholders

 

$

(1,790,057

)

$

(5,085,618

)

$

6,225,471

 

Weighted average shares

 

22,585,612

 

16,163,098

 

15,112,272

 

Earning (loss) per share

 

$

(0.08

)

$

(0.31

)

$

0.41

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Diluted

 

 

 

 

 

 

 

Earnings (loss) applicable to common shareholders

 

$

(1,790,057

)

$

(5,085,618

)

$

6,225,471

 

Effect of dilutive securities:

 

 

 

 

 

 

 

Convertible subordinated debenture

 

 

 

385,358

 

Preferred stock

 

 

 

92,814

 

Earnings (loss) available to common shareholders and assumed conversion

 

$

(1,790,057

)

$

(5,085,618

)

$

6,703,643

 

Weighted average shares:

 

 

 

 

 

 

 

Outstanding

 

22,585,612

 

16,163,098

 

15,112,272

 

Options

 

 

 

1,500,589

 

Convertible subordinated debenture

 

 

 

2,145,205

 

Preferred stock

 

 

 

463,190

 

 

 

22,585,612

 

16,163,098

 

19,221,256

 

Earnings (loss) per share

 

$

(0.08

)

$

(0.31

)

$

0.35

 

   Years Ended March 31, 
   2006  2005  2004 
Basic      

Net earnings (loss)

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

Weighted average shares

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

Earning (loss) per share

  $1.08  $0.31  $(0.08)
             
Diluted      

Earnings (loss) applicable to common shareholders

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

Effect of dilutive securities - Convertible subordinated debenture

   —     459,483   —   
             

Earnings (loss) available to common shareholders and assumed conversion

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

Weighted average shares:

      

Outstanding

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

Options

   697,562   684,806   —   

Convertible subordinated debenture

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

Earnings (loss) per share

  $1.06  $0.30  $(0.08)
             

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

8.Equity Transactions

On May 18, 2001, we retiredAugust 11, 2004, the 4.86% subordinated debenture we issued to WEDGE on March 30, 2001entire $28,000,000 in connection with the Mustang Drilling, Ltd. acquisition.  We funded the repayment of the $9,000,000 faceaggregate principal amount of the debenture, together with the payment of $59,535 of accrued interest, with a short-term bank borrowing.  We then sold 2,400,000 shares of our common stock to6.75% convertible subordinated debentures held by WEDGE Energy Services, L.L.C. and William H. White was converted in a private placement for $9,048,000, or $3.77 per share.  We used the proceeds from this sale to fund the repayment of the short-term bank borrowing.

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

On August 2001, the holders converted all of their 184,615 shares of our Series B convertible preferred stock into 1,199,03811, 2004, we sold 4,000,000 shares of our common stock at $2.50approximately $6.61 per share.

share, net of underwriters’ commissions, pursuant to a public offering we registered with the SEC under a registration statement filed on Form S-1. On May 31, 2001, San Patricio Corporation exercised its option to acquire 150,000 shares of our common stock for $225,000 ($1.50 per share).

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

41



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

On February 20, 2004, we sold 4,400,000600,000 additional shares of our common stock at $5.40approximately $6.61 per share, net of underwriters’ commissions, pursuant to the underwriters’ exercise of an over-allotment option granted in a private placement for $23,760,000 in proceeds, before related offering expenses.  Althoughconnection with that public offering.

On March 22, 2005, we issued thosesold 6,945,000 shares without registration underof our common stock, including shares we sold pursuant to the Securities Actunderwriters’ exercise of 1933 in reliance on the exemption that Section 4(2)an over-allotment option, at approximately $11.78 per share, net of that Act provides for transactions not involving anyunderwriters’ commissions, pursuant to a public offering we filedregistered with the SEC.

On February 10, 2006, we sold 3,000,000 shares of our common stock, at approximately $20.63 per share, net of underwriters’ commissions, pursuant to a registration statement on Form S-3 to register those shares.  The registration statement became effective on June 22, 2004.

public offering we registered with the SEC.

Directors and employees exercised stock options for the purchase of 698,667 shares of common stock at prices ranging from $2.25 to $10.31 per share during the fiscal year ended March 31, 2006, 551,666 shares of common stock at prices ranging from $.375 to $6.44 per share during the fiscal year ended March 31, 2005 and 722,334 shares of common stock at prices ranging from $.625 to $3.20 per share during the fiscal year ended March 31, 2004, 445,000 shares of common stock at prices ranging from $.375 to $2.50 per share during the year ended March 31, 2003 and 27,500 shares of common stock at prices ranging from $0.375 to $1.00 per share during the year ended March 31, 2002.2004.

9.Stock Options, Warrants and Stock Option Plan

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

The following table provides information relating to our outstanding stock options at March 31, 2004, 20032006, 2005 and 2002:2004:

 

 

 

2004

 

2003

 

2002

 

 

 

Shares
Issuable on
Exercise of
Options

 

Exercise
Price per
Share

 

Shares
Issuable on
Exercise of
Options

 

Exercise
Price per
Share

 

Shares
Issuable on
Exercise of
Options

 

Exercise
Price per
Share

 

Balance Outstanding

 

 

 

 

 

 

 

 

 

 

 

 

 

Beginning of year

 

1,825,000

 

$

.375-5.15

 

2,320,000

 

$

0.375-5.15

 

2,177,500

 

$

0.375-4.60

 

Granted

 

1,000,000

 

$

3.67-4.99

 

65,000

 

$

3.20-4.50

 

585,000

 

$

3.00-5.15

 

Exercised

 

(722,334

)

$

.625-3.20

 

(445,000

)

$

0.375-2.50

 

(177,500

)

$

0.375-1.50

 

Canceled

 

(46,000

)

$

2.25

 

(115,000

)

$

2.25-4.60

 

(265,000

)

$

2.25

 

Balance Outstanding

 

 

 

 

 

 

 

 

 

 

 

 

 

End of year

 

2,056,666

 

$

.375-5.15

 

1,825,000

 

$

0.375-5.15

 

2,320,000

 

$

0.375-5.15

 

Options Exercisable

 

 

 

 

 

 

 

 

 

 

 

 

 

End of year

 

884,001

 

 

 

1,437,334

 

 

 

1,734,000

 

 

 

   2006  2005  2004
   

Shares

Issuable on

Exercise of
Options

  

Weighted
Average

Price

  

Shares

Issuable on

Exercise of

Options

  

Weighted
Average

Price

  

Shares

Issuable on

Exercise of
Options

  

Weighted

Average

Price

Balance Outstanding Beginning of year

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

Granted

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

Exercised

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

Canceled

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

Balance Outstanding End of year

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

Options Exercisable End of year

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

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

At

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

 

   Options Outstanding  Options Exercisable

Range of

Exercise Prices

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

$3.00 - $4.77

  841,333  7.19  $4.12  401,666  $3.67

$5.95 - $9.65

  399,000  8.62  $9.42  115,000  $9.22

$10.31 - $14.58

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

10.Employee BenefitPlans and Insurance

We maintain a 401(k) retirement plan for our eligible employees. Under this plan, we may contribute, on a discretionary basis, a percentage of an eligible employee’s annual contribution, which we determine annually. Our contributions for fiscal 2004, 20032006, 2005 and 20022004 were approximately $643,000, $399,000 and $76,000, $92,000 and $153,000, respectively.

We maintain a self-insurance program, for major medical, hospitalization and dental coverage for employees and their dependents, which is partially funded by payroll deductions. We have provided for both reported and incurred but not reported medical costs in the accompanying consolidated balance sheets. We have a maximum liability of $100,000$125,000 per employee/dependent per year. Amounts in excess of the stated maximum are covered under a separate policy provided by an insurance company.

42



Accrued expenses at March 31, 20042006 and 2005 include approximately $280,000$553,000 and $489,000, respectively, for our estimate of incurred but unpaid costs related to the self-insurance portion of our health insurance.

We are self-insured for up to $250,000 for all workers’ compensation claims submitted by employees for on-the-job injuries.injuries, except in North Dakota where the deductible is $100,000. We have provided for both reported and incurred but not reported costs of workers’ compensation coverage in the accompanying consolidated balance sheets. Accrued expenses at March 31, 20042006 and 2005 include approximately $400,000$1,829,000 and $845,000, respectively, for our estimate of incurred but unpaid costs related to workers’ compensation claims. Based upon our past experience, management believes that we have adequately provided for potential losses. However, future multiple occurrences of serious injuries to employees could have a material adverse effect on our financial position and results of operations.

11.Business Segments and Supplementary Earnings InformationConcentrations

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

During the fiscal year ended March 31, 2006, our three largest customers accounted for 10.1%, 6.1% and 4.4% respectively, of our total contract drilling revenue. All three of these customers were customers of ours in 2005. In fiscal 2005, our three largest customers accounted for 6.5%, 5.0% and 4.6%, respectively, of our total contract drilling revenue. All three of these customers were customers of ours in 2004. In fiscal 2004, our three largest customers accounted for 10.5%, 6.4% and 4.9%, respectively, of our total contract drilling revenue.  Two of these customers were customers of ours in 2003.  In fiscal 2003, our three largest customers accounted for 10.8%, 6.5% and 5.4%, of our total contract drilling revenue.  Two of these customers were customers of ours in fiscal 2002.  In fiscal 2002, our three largest customers accounted for 13.7%, 12.2% and 11.1% of our total contract drilling revenue.

12.Commitments and Contingencies

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

these rigs.

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

13.Quarterly Results of Operations (unaudited)

The following table summarizes quarterly financial data for our fiscal years ended March 31, 20042006 and 20032005 (in thousands, except per share data):

 

 

 

First
Quarter

 

Second
Quarter

 

Third
Quarter

 

Fourth
Quarter

 

Total

 

2004

 

 

 

 

 

 

 

 

 

 

 

Revenues

 

$

23,850

 

$

24,244

 

$

26,414

 

$

33,368

 

$

107,876

 

Income (loss) from operations

 

(789

)

(166

)

9

 

1,384

 

438

 

Net earnings (loss)

 

(1,056

)

(621

)

(522

)

409

 

(1,790

)

Earnings (loss) per share:

 

 

 

 

 

 

 

 

 

 

 

Basic

 

(.05

)

(.03

)

(.02

)

.02

 

(.08

)

Diluted

 

(.05

)

(.03

)

(.02

)

.02

 

(.08

)

 

 

 

 

 

 

 

 

 

 

 

 

2003

 

 

 

 

 

 

 

 

 

 

 

Revenues

 

$

18,452

 

$

17,042

 

$

19,795

 

$

24,894

 

$

80,183

 

Income (loss) from operations

 

153

 

(1,251

)

(1,840

)

(2,005

)

(4,943

)

Net earnings (loss)

 

(172

)

(1,302

)

(1,704

)

(1,908

)

(5,086

)

Earnings (loss) per share:

 

 

 

 

 

 

 

 

 

 

 

Basic

 

(.01

)

(.08

)

(.11

)

(.11

)

(.31

)

Diluted

 

(.01

)

(.08

)

(.11

)

(.11

)

(.31

)

   

First

Quarter

  

Second

Quarter

  

Third

Quarter

  

Fourth

Quarter

  Total 
2006      

Revenues

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

Income from operations

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

Income tax expense

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

Net earnings

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

Earnings per share:

      

Basic

   .17   .24   .30   .37   1.08 

Diluted

   .17   .24   .29   .36   1.06 
2005      

Revenues

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

Income from operations

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

Income tax expense

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

Net earnings

   216   923   4,179   5,494   10,812 

Earnings per share:

      

Basic

   .01   .03   .11   .14   .31 

Diluted

   .01   .03   .11   .14   .30 

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

43



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

Not applicable.

Item 9A9A.. Controls and Procedures

In accordance with Exchange Act Rules 13a-15 and 15d-15, we carried out an evaluation, under the supervision and with the participation of management, including our Chief Executive Officer and Chief Financial Officer, of the effectiveness of our disclosure controls and procedures as of the end of the period covered by this report. Based upon that evaluation, our Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures were effective as of March 31, 20042006 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, 20042006 that has materially affected, or is reasonably likely to materially affect, our internal controls over financial reporting.

Management’s Report on Internal Control over Financial Reporting

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

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

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

Item 9B. Other Information

Not applicable.

PART III

In Items 10, 11, 12, 13 and 1314 below, we are incorporating by reference the information we refer to in those Items from the definitive proxy statement for our 20042006 Annual Meeting of Shareholders. We intend to file that definitive proxy statement with the SEC by July 15, 2004.2006.

Item 10.10. Directors and Executive Officers of the Registrant

Please see the information appearing under the headings “Proposal No. 1—Election of Directors” and “Executives and Executive Compensation” in the definitive proxy statement for our 20042006 Annual Meeting of Shareholders for the information this Item 10 requires.

Item 11.11. Executive Compensation

Please see the information appearing under the heading “Executives and Executive Compensation” in the definitive proxy statement for our 20042006 Annual Meeting of Shareholders for the information this Item 11 requires.

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

Please see the information appearing (1) under the heading “Equity Compensation Plan Information” in Item 5 of this report and (2) under the heading “Security Ownership of Certain Beneficial Owners and Management” in the definitive proxy statement for our 20042006 Annual Meeting of Shareholders for the information this Item 12 requires.

Item 13.13. Certain Relationships and Related Transactions

Please see the information appearing under the heading “Certain Transactions” in the definitive proxy statement for our 20042006 Annual Meeting of Shareholders for the information this Item 13 requires.

Item 14.14. Principal Accountant Fees and Services

Please see the information appearing under the heading “Ratification of Appointment of Independent Auditors” in the definitive proxy statement for our 20042006 Annual Meeting of Shareholders for the information this Item 14 requires.

44



PART IV

Item 15.15. Exhibits, Financial Statement Schedules and Reports on Form 8-K

(1)Financial Statements.

See Index to Consolidated Financial Statements on page 29.

(2) Financial Statement Schedules:

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

Schedule II

   Valuation and Qualifying Accounts
   

Balance

at
Beginning
of Year

  

Charged

to Costs
and
Expenses

  Deductions
from
Accounts
  

Balance

at

Year End

Year ended March 31, 2004

       

Allowance for doubtful receivables

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

Year ended March 31, 2005

       

Allowance for doubtful receivables

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

Year ended March 31, 2006

       

Allowance for doubtful receivables

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

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

 

(a)(1)Exhibit

Number

Financial Statements.Description

  2.1*

-

See Index to Consolidated Financial Statements on page 27.

(2)

Financial Statement Schedules:

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

(3)

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

Exhibit
Number

Description

2.1*

-

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

2.2*

-

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

2.3*

-

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

2.4*

-

Asset Purchase Agreement dated the 28th of May, 2002 by and between United Drilling Company, U-D Holdings, L.P.Robert Mau, Robert S. Blackford and Pioneer Drilling Services, Ltd., a Texas limited partnership. (Form 10-K for the year ended March 31, 20028-K dated November 11, 2004 (File No. 1-8182, Exhibit 2.5)2.1))

.

3.1*

  2.2*

-

-

Asset Purchase Agreement dated November 29,2004, by and among Allen Drilling Company, the Earl Allen Family Trust dated April 1, 1979, the sole shareholder of Allen Drilling Company, Dixon Allen, Paula K. Hoisington and Lisa D. Johonnesson, all of the beneficiaries of the Trust, and Pioneer Drilling Services, Ltd. (Form 8-K dated November 30, 2004 (File No. 1-8182m Exhibit 2.1)).
  3.1*-Articles of Incorporation of Pioneer Drilling Company, as amended (Form 10-K for the year ended March 31, 2001 (File No. 1-8182, Exhibit 3.1)).

3.2*

-

-

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

3.3*

-

-

Amended and Restated Bylaws of Pioneer Drilling Company (Form 10-Q for the quarter ended December 31, 2003 (File No. 1-8182, Exhibit 3.3)).

4.1*

-

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

-

4.2*

-

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

4.3*

-

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

45



4.4 *

-

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

4.5*

-

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

4.6*

-

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

4.7*

-

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

4.8*

-

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

4.9*

-

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

4.10*

-

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

4.11*

-

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

4.12*

-

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

4.13*

-

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

4.14*

-

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

4.15*

-

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

46



4.16*

-

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

4.17*

-

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

4.18*

  4.2*

-

Form of Purchase-

Credit Agreement dated February 13, 2004 between Pioneer Drilling CompanyServices, Ltd. and the several purchasersFrost National Bank, as Administrative Agent, Agent, Lead Arranger and Lender dated October 29, 2004 (Form S-3 filed February 24,8-K dated October 29, 2004 (Reg. No. 333-113036, Exhibit 4.1)).

10.1*

-

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

10.2*

  4.3*

-

Voting Agreement-

Second Amendment, dated May 11, 20002005, to Credit Agreement between Wm. Stacy Locke, Michael E. Little, Pioneer Drilling CompanyServices, Ltd. And Frost National Bank, as Administrative Agent, Lead Arranger and WEDGE Energy Services, L.L.C.Lender dated October 29, 2004 (Form 10-K for the year ended March 31, 20018-K dated May 12, 2005 (File No. 1-8182, Exhibit 9.2)4.1)).

10.3*

  4.4*

-

Voting Agreement-

Third Amendment, dated October 9, 200125, 2005, to Credit Agreement between Pioneer Drilling CompanyServices, Ltd. And Frost National Bank, as Administrative Agent, Lead Arranger and WEDGE Energy Service, L.L.C. (See Section 1.3 of the Debenture PurchaseLender dated October 29, 2004 (Form 8-K dated October 28, 2005 (File No. 1-8182, Exhibit 4.1)).
  4.5*-Fourth Amendment, dated December 15, 2005, to Credit Agreement referenced abovebetween Pioneer Drilling Services, Ltd. And Frost National Bank, as Administrative Agent, Lead Arranger and Lender dated October 29, 2004 (Form 8-K dated December 16, 2005 (File No. 1-8182, Exhibit 4.5)4.1)).
10.1+*-Pioneer Drilling Services, Ltd. Annual Incentive Compensation Plan dated August 5, 2005 (Form 10-K for year ended March 31, 20038-K Dated August 5, 2005 (File No. 1-8182, Exhibit 10.1)).
10.2+*-Pioneer Drilling Services, Ltd. Executive Severance Plan dated August 5, 2005 (Form 8-K Dated August 5, 2005 (File No. 1-8182, Exhibit 10.3)).

10.4+10.3+*

-

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

-

10.5+*

-

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

10.6+*

-

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

10.7+10.4+*

-

-

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

10.5+*

10.8+*

-

-

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

10.9*

-

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

10.10*

-

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

47



10.11*

-

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

10.12*

-

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

10.13*

-

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

10.14*

-

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

21.1

-

-

Subsidiaries of Pioneer Drilling Company.

23.1

-

-

Consent of KPMG LLP.

31.1

-

-

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

31.2

-

-

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

32.1

-

-

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

32.2

-

-

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


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

+                                         Management contract or compensatory plan or arrangement.

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

48



SIGNATURES

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

 

PIONEER DRILLING COMPANY

June 28, 2004

May 25, 2006

By:

/s/ Wm. Stacy Locke

Wm. Stacy Locke

Chief Executive Officer and President

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

 

Signature

Title

Title

Date

/s/ Michael E. Little

Michael E. Little

Chairman

Chairman

June 28, 2004

May 25, 2006

/s/ Wm. Stacy Locke

Wm. Stacy Locke

President, Chief Executive Officer and Director (Principal

(Principal Executive Officer)

June 28, 2004

May 25, 2006

/s/ William D. Hibbetts

William D. Hibbetts

Senior Vice President, Chief Financial

Officer and Secretary (Principal Financial andOfficer)

May 25, 2006

/s/ Kurt M. Forkheim

Kurt M. Forkheim

Vice President, Chief Accounting Officer

(Principal Accounting Officer)

June 28, 2004

May 25, 2006

/s/ C. John Thompson

C. John Thompson

Director

Director

June 28, 2004

May 25, 2006

/s/ James M. Tidwell

James M. Tidwell

Director

Director

June 28, 2004

May 25, 2006

/s/ C. Robert Bunch

C. Robert Bunch

Director

Director

June 28, 2004

May 25, 2006

/s/ Dean A. Burkhardt

Dean A. Burkhardt

Director

Director

June 28, 2004

May 25, 2006

/s/ Michael F. Harness

Michael F. Harness

Director

Director

June 28, 2004

May 25, 2006

49



Index To Exhibits

 

2.1*

-

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

2.2*

-

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

2.3*

-

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

2.4*

-

Asset Purchase Agreement dated the 28th of May, 2002 by and between United Drilling Company, U-D Holdings, L.P.Robert Mau, Robert S. Blackford and Pioneer Drilling Services, Ltd., a Texas limited partnership. (Form 10-K for the year ended March 31, 20028-K dated November 11, 2004 (File No. 1-8182, Exhibit 2.5)2.1))

.

3.1*

  2.2*

-

-

Asset Purchase Agreement dated November 29,2004, by and among Allen Drilling Company, the Earl Allen Family Trust dated April 1, 1979, the sole shareholder of Allen Drilling Company, Dixon Allen, Paula K. Hoisington and Lisa D. Johonnesson, all of the beneficiaries of the Trust, and Pioneer Drilling Services, Ltd. (Form 8-K dated November 30, 2004 (File No. 1-8182m Exhibit 2.1)).
  3.1*-Articles of Incorporation of Pioneer Drilling Company, as amended (Form 10-K for the year ended March 31, 2001 (File No. 1-8182, Exhibit 3.1)).

3.2*

-

-

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

3.3*

-

-

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

4.1*

-

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

4.2*

-

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

4.3*

-

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

4.4 *

-

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

50



4.5*

-

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

4.6*

-

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

4.7*

-

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

4.8*

-

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

4.9*

-

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

4.10*

-

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

4.11*

-

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

4.12*

-

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

4.13*

-

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

4.14*

-

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

4.15*

-

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

4.16*

-

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

51



4.17*

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

4.18*

  4.2*

Form of Purchase-

Credit Agreement dated February 13, 2004 between Pioneer Drilling CompanyServices, Ltd. and the several purchasersFrost National Bank, as Administrative Agent, Agent, Lead Arranger and Lender dated October 29, 2004 (Form S-3 filed February 24,8-K dated October 29, 2004 (Reg. No. 333-113036, Exhibit 4.1)).

10.1*

-

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

10.2*

  4.3*

-

Voting Agreement-

Second Amendment, dated May 11, 20002005, to Credit Agreement between Wm. Stacy Locke, Michael E. Little, Pioneer Drilling CompanyServices, Ltd. And Frost National Bank, as Administrative Agent, Lead Arranger and WEDGE Energy Services, L.L.C.Lender dated October 29, 2004 (Form 10-K for the year ended March 31, 20018-K dated May 12, 2005 (File No. 1-8182, Exhibit 9.2)4.1)).

10.3*

  4.4*

-

Voting Agreement-

Third Amendment, dated October 9, 200125, 2005, to Credit Agreement between Pioneer Drilling CompanyServices, Ltd. And Frost National Bank, as Administrative Agent, Lead Arranger and WEDGE Energy Service, L.L.C. (See Section 1.3 of the Debenture PurchaseLender dated October 29, 2004 (Form 8-K dated October 28, 2005 (File No. 1-8182, Exhibit 4.1)).
  4.5*-Fourth Amendment, dated December 15, 2005, to Credit Agreement referenced abovebetween Pioneer Drilling Services, Ltd. And Frost National Bank, as Administrative Agent, Lead Arranger and Lender dated October 29, 2004 (Form 8-K dated December 16, 2005 (File No. 1-8182, Exhibit 4.5)4.1)).
10.1+*-Pioneer Drilling Services, Ltd. Annual Incentive Compensation Plan dated August 5, 2005 (Form 10-K for year ended March 31, 20038-K Dated August 5, 2005 (File No. 1-8182, Exhibit 10.1)).
10.2+*-Pioneer Drilling Services, Ltd. Executive Severance Plan dated August 5, 2005 (Form 8-K Dated August 5, 2005 (File No. 1-8182, Exhibit 10.3)).

10.4+10.3+*

-

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

-

10.5+*

-

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

10.6+*

-

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

10.7+10.4+*

-

-

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

10.8+10.5+*

-

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

-

10.9*

-

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

10.10*

-

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

10.11*

-

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

10.12*

-

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

52



10.13*

-

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

10.14*

-

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

21.1

21.1

-

-

Subsidiaries of Pioneer Drilling Company.

23.1

-

-

Consent of KPMG LLP.

31.1

-

-

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

31.2

-

-

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

32.1

-

-

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

32.2

-

-

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


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

 


*                                         Incorporated by reference to the filing indicated.56

+                                         Management contract or compensatory plan or arrangement.

53