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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D. C. 20549
FORM 10-K/A10-K
(Mark one) | ||||
ý | ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES | |||
For the fiscal year ended March 31, | ||||
o | TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES |
Commission File Number: 1-8182
PIONEER DRILLING COMPANY
(Exact name of registrant as specified in its charter)
TEXAS |
| |
(State or other jurisdiction | (I.R.S. Employer | |
9310 Broadway, Bldg. I | 78217 | |
(Address of principal executive offices) | (Zip Code) | |
|
Securities registered pursuant to Section 12(b) of the Act:
Title of each class | Name of each exchange on which registered | ||||
Common Stock $0.10 par value | American Stock Exchange |
Securities registered pursuant to Section 12(g) of the Act: None
Indicate by check mark whether the Registrant: (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ý No o
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant'sregistrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. oý
Indicate by check mark whether the registrant is an accelerated filer (as defined in Rule 12b-2 of the Securities Exchange Act of 1934). Yes o No ý
The aggregate market value of the registrant'sregistrant’s voting and nonvoting common equity held by non-affiliates of the registrant as of the last business day of the registrant'sregistrant’s most recently completed second fiscal quarter for the fiscal year covered by this report (September 30, 2002)2003) was $16,645,254,$23,354,178, based on the last sales price of the registrant'sregistrant’s common stock reported on the American Stock Exchange on that date.
As of March 31,June 25, 2004, there were 27,300,126 shares of common stock, par value $0.10 per share, of the registrant issued and outstanding.
DOCUMENTS INCORPORATED BY REFERENCE
Portions of the proxy statement related to the registrant's 2003registrant’s 2004 Annual Meeting of Shareholders are incorporated by reference into Part III of this report.
Statements we make in this Annual Report on Form 10-K whichthat express a belief, expectation or intention, as well as those that are not historical fact, are forward-looking statements under the Private Securities Litigation Reform Act of 1995. These forward-looking statements are subject to various risks, uncertainties and assumptions, including those to which we refer under the heading "Cautionary‘‘Cautionary Statement Concerning Forward-Looking Statements"Statements and Risk Factors’’ following Items 1 and 2 of Part I of this report.
General
Pioneer Drilling Company provides contract land drilling services to independent and major oil and gas exploration and production companies. In addition to our drilling rigs, we provide the drilling crews and most of the ancillary equipment needed to operate our drilling rigs. We have focused our operations in the natural gas production regions of South Texas, East Texas and EastNorth Texas. Our company was incorporated in 1979 as the successor to a business that had been operating since 1968. We conduct our operations through our principal operating subsidiary, Pioneer Drilling Services, Ltd. Our common stock trades on the American Stock Exchange under the symbol "PDC."“PDC.”
Over the past fourfive fiscal years, we have significantly expanded our fleet of drilling rigs through acquisitions and the construction of new rigs and refurbished rigs.the refurbishment of older rigs we acquired. The following table summarizes these acquisitions:
Date | Acquisition | Market | Number of Rigs Acquired | ||||
---|---|---|---|---|---|---|---|
September 1999 | Howell Drilling, Inc.—Assets | South Texas | 2 | ||||
August 2000 | Pioneer Drilling Co.—Stock | South Texas | 4 | (1) | |||
March 2001 | Mustang Drilling, Ltd.—Assets | East Texas | 4 | ||||
May 2002 | United Drilling Company—Assets | South Texas | 2 |
Date | Acquisition | Market | Number of | |||
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 |
As of May 16, 2003,June 28, 2004, our rig fleet consists of 2536 operating drilling rigs, 15 of which are operating in South Texas, and ten17 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, includingconsisting of two newly constructed rigs and two refurbished rigs, increasing usour 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 the two rigs we acquired from United Drilling Company, increasing usour 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 components of which were moved to our inventory of spare equipment). In MayDecember 2003, we took delivery of another refurbished rig. Weacquired 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 except for one rig that we operate under a lease agreement expiring in February��2004. The lease agreement includes an option to acquire this rig.fleet.
We conduct our operations primarily in South, TexasEast and EastNorth Texas. We believe that these markets have historically experienced greater utilization rates and dayrates versus other domestic markets, due in large part to the heavy concentration of natural gas reserves located in these markets. During fiscal 2003,2004, substantially all the wells we drilled for our customers were drilled in search of natural gas. Natural gas reserves are typically found in deeperdeep geological formations and generally require premium equipment and quality crews to drill the wells.
Our business strategy is to own and operate a high quality fleet of land drilling rigs in active drilling markets and position ourselves as the contractor of choice for our customers in order to maximize rig utilization and dayrates and enhance shareholder value.markets. We intend to continue making additions to our drilling fleet, eitherprimarily through prudent acquisitions of businesses or selected assets or through the construction of new or refurbished drilling rigs.rig assets. As we add to our fleet, we intend to focus on the addition of rigs capable of performing deep drilling for natural gas.
For many years, the United States contract land drilling services industry has been characterized by an oversupply of drilling rigs and a large number of drilling contractors. However, sinceSince 1996, however, there has been significant consolidation within the industry. We believe continued consolidation in the industry will generate more stability in dayrates, even during industry downturns. However,
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“Management’s Discussion and Analysis of Financial Condition and Results of Operations—Operations – Market Conditions in Our Industry"Industry” in Item 7 of Part II of this report.
Drilling Equipment
General
General
A land drilling rig consists of engines, a hoisting system, a rotating system, pumps and related equipment to circulate drilling fluid, blowout preventers and related equipment.
Diesel or gas engines are typically the main power sources for a drilling rig. Power requirements for drilling jobs may vary considerably, but most land drilling rigs employ two or more engines to generate between 500 and 2,000 horsepower, depending on well depth and rig design. Most drilling rigs capable of drilling in deep formations, involving depths greater than 15,000 feet, use diesel-electric power units to generate and deliver electric current through cables to electrical switch gear,gears, then to direct-current electric motors attached to the equipment in the hoisting, rotating and circulating systems.
Drilling rigs use long strings of drill pipe and drill collars to drill wells. Drilling rigs are also used to set heavy strings of large-diameter pipe, or casing, inside the borehole. Because the total weight of the drill string and the casing can exceed 500,000 pounds, drilling rigs require significant hoisting and braking capacities. Generally, a drilling rig'srig’s hoisting system is made up of a mast, or derrick, a traveling block and hook assembly that attaches to the rotating system, a mechanism known as the drawworks, a drilling line and ancillary equipment. The drawworks mechanism consists of a revolving drum, around which the drilling line is wound, and a series of shafts, clutches and chain and gear drives for generating speed changes and reverse motion. The drawworks also houses the main brake, which has the capacity to stop and sustain the weights used in the drilling process. When heavy loads are being lowered, a hydraulic or electric auxiliary brake assists the main brake to absorb the great amount of energy developed by the mass of the traveling block, hook assembly, drill pipe, drill collars and drill bit or casing being lowered into the well.
The rotating equipment from top to bottom consists of a swivel, the kelly cock, the kelly, the rotary table, drill pipe, drill collars and the drill bit. We refer to the equipment between the swivel and the drill bit as the drill stem. The swivel assembly sustains the weight of the drill stem, permits its rotation and affords a rotating pressure seal and passageway for circulating drilling fluid into the top of the drill string. The swivel also has a large handle that fits inside the hook assembly at the bottom of the traveling block. Drilling fluid enters the drill stem through a hose, called the rotary hose, attached to the side of the swivel. The kelly is a triangular, square or hexagonal piece of pipe, usually 40 feet long, that transmits torque from the rotary table to the drill stem and permits its vertical movement as it is lowered into the hole. The bottom end of the kelly fits inside a corresponding triangle,triangular, square or hexagonal opening in a device called the kelly bushing. The kelly bushing, in turn, fits into a part of the
rotary table called the master bushing. As the master bushing rotates, the kelly bushing also rotates, turning the kelly, which rotates the drill pipe and thus the drill bit. Drilling fluid is pumped through the kelly on its way to the bottom. The rotary table, equipped with its master bushing and kelly bushing, supplies the necessary torque to turn the drill stem. The drill pipe and drill collars are both steel tubes through which drilling fluid can be pumped. Drill pipe, sometimes called drill string, comes in 30 foot30-foot sections, or joints, with threaded sections on each end. Drill collars are heavier than drill pipe and are also threaded on the ends. Collars are used on the bottom of the drill stem to apply weight to the drilling bit. At the end of the drill stem is the bit, which chews up the formation rock and dislodges it so that drilling fluid can circulate the fragmented material back up to the surface where the circulating system filters it out of the fluid.
Drilling fluid, often called mud, is a mixture of clays, chemicals and water or oil, which is carefully formulated for the particular well being drilled. Drilling mud accounts for a major portion of the equipment and cost of drilling a well. Bulk storage of drilling fluid materials, the pumps and the mud mixingmud-mixing equipment are placed at the start of the circulating system. Working mud pits and reserve storage are at the other end of the system. Between these two points the circulating system includes auxiliary equipment for drilling fluid maintenance and equipment for well pressure control. Within the system, the drilling mud is typically routed from the mud pits to the mud pump and from the mud pump through a standpipe and the rotary hose to the drill stem. The drilling mud travels down the drill stem to the bit, up the annular space between the drill stem and the borehole and through the blowout preventer stack to the return flow line. It then travels to a shale shaker for removal of rock cuttings, and then back to the mud pits, which are usually steel tanks. The so-called reserve pits, usually one or two fairly shallow excavations, are used for waste material and excess water around the location.
There are numerous factors that differentiate land drilling rigs, including their power generation systems and their drilling depth capabilities. The actual drilling depth capability of a rig may be less than or more than its rated depth capability due to numerous factors, including the size, weight and amount of the drill pipe on the rig. The intended well depth and the drill site conditions determine the amount of drill pipe and other equipment needed to drill a well. Generally, land rigs operate with crews of five to six persons.
2
Our Fleet of Drilling Rigs
As of May 16, 2003,June 28, 2004, our rig fleet consists of 2536 drilling rigs. We own all the rigs in our fleet except for one that we operate under a lease/purchase agreement expiring in February 2004.
fleet. The following table sets forth information regarding utilization for our fleet of drilling rigs:
| Years ended March 31, | ||||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| 2003 | 2002 | 2001 | 2000 | 1999 | 1998 | |||||||
Average number of rigs for the period | 22.3 | 18.0 | 10.5 | 6.6 | 6.0 | 6.0 | |||||||
Average utilization rate | 79 | % | 82 | % | 91 | % | 66 | % | 66 | % | 86 | % |
|
| Years ended March 31, |
| ||||||||||
|
| 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 | % |
The following table sets forth information regarding our drilling fleet:
Rig Number | Rig Design | Approximate Drilling Depth Capability (feet) | Current Location | Type | Horse Power | |||||
---|---|---|---|---|---|---|---|---|---|---|
1 | IRI Cabot 750E | 11,500 | South Texas | Electric | 700 | |||||
2 | IRI Cabot 750E | 11,500 | South Texas | Electric | 700 | |||||
3 | National 110-UE | 18,000 | South Texas | Electric | 1500 | |||||
4 | (1) | RMI 1000E | 15,000 | South Texas | Electric | 1000 | ||||
5 | RMI 1000 | 15,000 | South Texas | Mechanical | 1000 | |||||
6 | Brewster N4610 | 12,000 | East Texas | Mechanical | 900 | |||||
7 | IRI 1700E | 18,000 | South Texas | Electric | 1700 | |||||
8 | IRI 1700E | 18,000 | South Texas | Electric | 1700 | |||||
9 | Gardner-Denver 500M | 10,000 | East Texas | Mechanical | 750 | |||||
10 | Skytop Brewster N46 | 12,000 | East Texas | Mechanical | 950 | |||||
11 | Skytop Brewster N46 | 12,000 | South Texas | Mechanical | 950 | |||||
12 | IRI Cabot 900 | 10,500 | South Texas | Mechanical | 900 | |||||
14 | Skytop Brewster N46 | 12,000 | South Texas | Mechanical | 950 | |||||
15 | IRI Cabot 750 | 11,000 | South Texas | Mechanical | 700 | |||||
16 | IRI Cabot 750 | 11,000 | South Texas | Mechanical | 700 | |||||
17 | Ideco H-725 | 12,000 | East Texas | Mechanical | 750 | |||||
18 | Brewster N-75 | 12,500 | East Texas | Mechanical | 1000 | |||||
19 | Brewster N-75 | 12,500 | East Texas | Mechanical | 1000 | |||||
20 | BDW 800 | 13,500 | East Texas | Mechanical | 1000 | |||||
21 | National 110-UE | 18,000 | South Texas | Electric | 1500 | |||||
22 | Ideco H-725 | 12,000 | East Texas | Mechanical | 750 | |||||
23 | Ideco H-725 | 12,000 | East Texas | Mechanical | 750 | |||||
24 | National 110-UE | 18,000 | South Texas | Electric | 1500 | |||||
25 | National 110-UE | 18,000 | East Texas | Electric | 1500 | |||||
26 | Oilwell 840E | 18,000 | South Texas | Electric | 1500 | |||||
27 | (2) | IRI Cabot 1200 | 15,000 | South Texas | Mechanical | 1200 |
Rig |
| Rig Design |
| Approximate |
| Current |
| Type |
| Horse Power |
|
|
|
|
|
|
|
|
|
|
|
|
|
1 |
| Cabot 750E |
| 9,500 |
| South Texas |
| Electric |
| 750 |
|
2 |
| Cabot 750E |
| 9,500 |
| South Texas |
| Electric |
| 750 |
|
3 |
| National 110 UE |
| 18,000 |
| South Texas |
| Electric |
| 1500 |
|
4 |
| RMI 1000 E |
| 15,000 |
| South Texas |
| Electric |
| 1000 |
|
5 |
| Brewster N-46 |
| 12,000 |
| North Texas |
| Mechanical |
| 1000 |
|
6 |
| Brewster DH-4610 |
| 13,000 |
| East Texas |
| Mechanical |
| 750 |
|
7 |
| National 110 UE |
| 18,000 |
| South Texas |
| Electric |
| 1500 |
|
8 |
| National 110 UE |
| 18,000 |
| East Texas |
| Electric |
| 1500 |
|
9 |
| Gardner-denver 500 |
| 11,000 |
| East Texas |
| Mechanical |
| 700 |
|
10 |
| Brewster N-46 |
| 12,000 |
| East Texas |
| Mechanical |
| 1000 |
|
11 |
| Brewster N-46 |
| 12,000 |
| South Texas |
| Mechanical |
| 1000 |
|
12 |
| IRI Cabot 900 |
| 12,500 |
| South Texas |
| Mechanical |
| 900 |
|
14 |
| Brewster N-46 |
| 12,000 |
| South Texas |
| Mechanical |
| 1000 |
|
15 |
| Cabot 750 |
| 9,500 |
| South Texas |
| Mechanical |
| 750 |
|
16 |
| Cabot 750 |
| 9,500 |
| South Texas |
| Mechanical |
| 750 |
|
17 |
| Ideco 725 |
| 12,000 |
| East Texas |
| Mechanical |
| 750 |
|
18 |
| Brewster N-75 |
| 12,000 |
| East Texas |
| Mechanical |
| 1000 |
|
19 |
| Brewster N-75 |
| 12,000 |
| East Texas |
| Mechanical |
| 1000 |
|
20 |
| BDW 800 |
| 13,500 |
| East Texas |
| Mechanical |
| 1000 |
|
21 |
| National 110 UE |
| 18,000 |
| South Texas |
| Electric |
| 1500 |
|
22 |
| Ideco 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 |
|
As of June 28, 2004, and has an option to purchase the rig between January 1, 2004 and February 1, 2004.
We also ownwe owned a fleet of 1652 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 wereare not immediately available.
Drilling Contracts
As a provider of contract land drilling services, our business and the profitability of our operations depend on the level of drilling activity by oil and gas exploration and production companies operating in the geographic markets where we operate. The oil and gas exploration and production industry is ana historically cyclical industry characterized by significant changes in the levels of exploration and
development activities. During periods of lower levels of drilling activity, price competition tends to increase and results in decreases in the profitability of daywork contracts. In this lower level drilling activity and competitive price environment, we may be more inclined to enter into turnkey and footage contracts that expose us to greater risk of loss without commensurate increases in potential contract profitability.
We obtain our contracts for drilling oil and gas wells either through competitive bidding or through direct negotiations with customers. Our drilling contracts generally provide for compensation on either a daywork, turnkey or footage basis. ContractThe contract terms we offer generally depend on the complexity and risk of operations, the on-site drilling conditions, the type of equipment used and the anticipated duration of the work to be performed. Generally, our contracts provide for the drilling of a single well and typically permit the customer to terminate on short notice, usually on payment of aan agreed fee.
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, |
| ||||
|
| 2004 |
| 2003 |
| 2002 |
|
Daywork |
| 205 |
| 119 |
| 150 |
|
Turnkey |
| 92 |
| 78 |
| 9 |
|
Footage |
| 13 |
| 5 |
| 6 |
|
Total number of wells |
| 310 |
| 202 |
| 165 |
|
Daywork Contracts.Contracts. Under daywork drilling contracts, we provide a drilling rig with required personnel to our customer who supervises the drilling of the well. We are paid based on a negotiated fixed rate per day while the rig is used. Daywork drilling contracts specify the equipment to be used, the size of the hole and the depth of the well. Under a daywork drilling contract, the customer bears a large portion of the out-of-pocket drilling costs of drilling and we generally bear no part of the usual risks associated with drilling, such as time delays and unanticipated costs.
Turnkey Contracts.Under a turnkey contract, we agree to drill a well for our customer to a specified depth and under specified conditions for a fixed price, regardless of the time required or the problems encountered in drilling the well. We provide technical expertise and engineering services, as well as most of the equipment and drilling supplies required to drill the well. We often subcontract for related services, such as the provision of casing crews, cementing and well logging. Under typical turnkey drilling arrangements, we do not receive progress payments and are paid by our customer only after we have performed the terms of the drilling contract in full.
The risks to us under a turnkey contract are substantially greater than on a well drilled on a daywork basis,basis. This is primarily because under a turnkey contract we assume most of the risks associated with drilling operations generally assumed by the operator in a daywork contract, including the risk of blowout, loss of hole, stuck drill pipe, machinery breakdowns, abnormal drilling conditions and risks associated with subcontractors'subcontractors’ services, supplies, cost escalations and personnel. We employ or contract for engineering expertise to analyze seismic, geologic and drilling data to identify and reduce some of the drilling risks assumed by us.we assume. We use the results of this analysis to evaluate the risks of a proposed contract and seek to account for such risks in our bid preparation. We believe that our operating experience, qualified drilling personnel, risk management program, internal engineering expertise and access to proficient third partythird-party engineering contractors have allowed us to reduce some of the risks inherent in turnkey drilling operations. We also maintain insurance coverage against some, but not all, drilling hazards. However, the occurrence of uninsured or under-insured losses or operating cost overruns on our turnkey jobs could have a material adverse effect on our financial position and results of operations.
4
Footage Contracts.Contracts. Under footage contracts, we are paid a fixed amount for each foot drilled, regardless of the time required or the problems encountered in drilling the well. We typically pay more of the out-of-pocket costs associated with footage contracts as compared withto daywork contracts. Similar to a turnkey contract, the risks to us on a footage contract are greater because we assume most of the risks associated with drilling operations generally assumed by the operator in a daywork contract, including the risk of blowout, loss of hole, stuck drill pipe, machinery breakdowns, abnormal drilling conditions and risks associated with subcontractors'subcontractors’ services, supplies, cost escalation and personnel. As with turnkey contracts, we manage this additional risk through the use of engineering expertise and bid the footage contracts accordingly, and we maintain insurance coverage against some, but not all, drilling hazards. However, the occurrence of uninsured or under-insured losses or operating cost overruns on our footage jobs could have a material adverse effect on our financial position and results of operations.
The following table presents, by type of contract, information about the total number of wells we completed for our customers during each of the last three fiscal years.
| 2003 | 2002 | 2001 | |||
---|---|---|---|---|---|---|
Daywork | 119 | 150 | 54 | |||
Turnkey | 78 | 9 | 42 | |||
Footage | 5 | 6 | 4 | |||
Total number of wells | 202 | 165 | 100 | |||
Customers Andand Marketing
We market our rigs to a number of customers. In fiscal 2003,2004, we drilled wells for 6488 different customers, compared to 64 customers in fiscal 2003 and 48 customers in fiscal 2002 and to 58 customers in fiscal 2001. Thirty-six2002. Forty-nine of our customers in fiscal 20032004 were customers for whom we had not drilled any wells in fiscal 2002.2003. The following table shows our three largest customers as a percentage of our total contract drilling revenue for each of our last three fiscal years.
Customer |
| Total Contract Drilling Revenue Percentage | ||||
---|---|---|---|---|---|---|
Fiscal 2004 | ||||||
Chinn Exploration | 11 | % | ||||
Dale Operating Company | 6 | % | ||||
Medicine Bow Energy Corporation | 5 | % | ||||
Fiscal 2003 | ||||||
Gulf Coast Energy Associates | 11 | % | ||||
Apache Corporation | 7 | % | ||||
Suemaur Exploration & Production, | 5 | % | ||||
Fiscal 2002 | ||||||
Dominion Exploration & Production, Inc. | 14 | % | ||||
Kerr-McGee Oil & Gas Onshore, L.L.C. | 12 | % | ||||
Pogo Producing Company | 11 | % | ||||
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 Texas and SouthNorth Texas market areas. Once we have been placed on the "bid list"“bid list” for an operator, we will typically be given the opportunity to bid on most future wells for that operator in the areas in which we operate. Our rigs are typically contracted on a well-by-well basis.
From time to time we also enter into informal, nonbinding commitments with our customers to provide drilling rigs for future periods at specified rates plus fuel and mobilization charges, if applicable, and escalation provisions. This practice is customary in the contract land drilling services business during times of tightening rig supply.
Competition
We encounter substantial competition from other drilling contractors. Our primary market areas of South, TexasEast and EastNorth 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. and Patterson-UTI Energy, Inc. We believe pricing and rig availability are the primary factors our potential customers consider in determining which drilling contractor to select. In addition, we believe the following factors are also important:
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•
•
•
•
•
While we must be competitive in our pricing, our competitive strategy generally emphasizes the quality of our equipment, the safety record of our rigs and the experience of our rig crews to differentiate us from our competitors.
Contract drilling companies compete primarily on a regional basis, and the intensity of competition may vary significantly from region to region at any particular time. If demand for drilling services improves in a region where we operate, our competitors might respond by moving in suitable rigs from other regions. An influx of rigs from other regions could rapidly intensify competition and make any improvement in demand for drilling rigs in a particular region short-lived.
Many of our competitors have greater financial, technical and other resources than we do. Their greater capabilities in these areas may enable them to:
•
•
•
•
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:
•
•
•
•
•
•
• Any of these hazards can result in substantial liabilities or losses to us from, among other things:
•
•
•
6
•
•
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 2002,2003, of the cost of comparable used equipment to replace the insured property. The policy provides for a deductible on rigs of $50,000 or $100,000 (depending on the rig) per occurrence. Our third-party liability insurance coverage is $26 million per occurrence and in the aggregate, with a deductible of $110,000 per occurrence. We believe that we are adequately insured for public liability and property damage to others with respect to our operations. However, such insurance may not be sufficient to protect us against liability for all consequences of well disasters, extensive fire damage or damage to the environment.
In addition, we generally carry insurance coverage to protect against certain hazards inherent in our turnkey and footage contract drilling operations. This insurance covers "control-of-well,"“control-of-well,” including blowouts above and below the surface, re-drilling,redrilling, seepage and pollution. This policy provides coverage of either$3 million, $5 million or $10 million, depending on the area in which the well is drilled and its target depth. This policy also provides care, custody and control insurance, with a limit of $250,000.
Employees
We currently have approximately 565900 employees. Approximately 85123 of these employees are salaried administrative or supervisory employees. The rest of our employees are hourly employees who operate or maintain our drilling rigs.rigs and rig-hauling trucks. The number of hourly employees fluctuates depending on the number of drilling projects we are engaged in at any particular time. None of our employment arrangements are subject to collective bargaining arrangements.
Our operations require the services of employees having the technical training and experience necessary to obtain the proper operational results. As a result, our operations depend, to a considerable extent, on the continuing availability of such personnel. Although we have not encountered material difficulty in hiring and retaining qualified rig crews, shortages of qualified personnel are occurring in our industry. If we should suffer any material loss of personnel to competitors or be unable to employ additional or replacement personnel with the requisite level of training and experience to adequately operate our equipment, our operations could be materially and adversely affected. While we believe our wage rates are competitive and our relationships with our employees are satisfactory, a significant increase in the wages paid by other employers could result in a reduction in our workforce, increases in wage rates, or both. The occurrence of either of these events for a significant period of time could have a material and adverse effect on our financial condition and results of operations.
Facilities
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 a six-acre division office, storage and maintenance yard in Henderson, Texas, at a cost of $3,700 per month, pursuant to a lease extending through March 2006. We also lease a 43-acre division office and storage yard in Decatur, Texas, at a cost of $800 per month, pursuant to a lease extending through September 2006, and 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 adequate to serve our current and anticipated needs.
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Governmental Regulation
Our operations are subject to stringent laws and regulations relating to containment, disposal and controlling the discharge of hazardous oilfield waste and other non hazardousnon-hazardous waste material into the environment, requiring removal and cleanup under certain circumstances, or otherwise relating to the protection of the environment. In addition, our operations are often conducted in or near ecologically sensitive areas, such as wetlands, which are subject to special protective measures and which may expose us to additional operating costs and liabilities for accidental discharges of oil, natural gas, drilling fluids or contaminated water or for noncompliance with other aspects of applicable laws. We are also subject to the requirements of the federal Occupational Safety and Health Act ("OSHA"(“OSHA”) and comparable state statutes. The OSHA hazard communication standard, the Environmental Protection Agency "community right-to-know"“community right-to-know” regulations under Title III of the Federal Superfund Amendment and Reauthorization Act and comparable state statutes require us to organize and report information about the hazardous materials we use in our operations to employees, state and local government authorities and local citizens.
Environmental laws and regulations are complex and subject to frequent change. In some cases, they can impose liability for the entire cost of cleanup on any responsible party without regard to negligence or fault and can impose liability on us for the conduct of others or conditions others have caused, or for our acts that complied with all applicable requirements when we performed them. We may also be exposed to environmental or other liabilities originating from businesses and assets whichthat we purchased from others. Compliance with applicable environmental laws and regulations has not, to date, materially affected our capital expenditures, earnings or competitive position, although compliance measures have added to our costs of operating drilling equipment in some instances. We do not expect
to incur material capital expenditures in our next fiscal year in order to comply with current environment control regulations. However, our compliance with amended, new or more stringent requirements, stricter interpretations of existing requirements or the future discovery of contamination may require us to make material expenditures or subject us to liabilities that we currently do not anticipate.
In addition, our business depends on the demand for land drilling services from the oil and gas industry and, therefore, is affected by tax, environmental and other laws relating to the oil and gas industry generally, by changes in those laws and by changes in related administrative regulations. It is possible that these laws and regulations may in the future add significantly to our operating costs or those of our customers or otherwise directly or indirectly affect our operations.
Available Information
Our website address iswww.pioneerdrlg.com.We make available on this website under "Investor“Investor Relations-SEC Filings,"” free of charge, our annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and amendments to those reports as soon as reasonablereasonably practicable after we electronically file those materials with, or furnish those materials to, the SEC.
CAUTIONARY STATEMENT CONCERNING FORWARD-LOOKING STATEMENTS
AND RISK FACTORS
We are including the following discussion to inform our existing and potential security holders generally of some of the risks and uncertainties that can affect our company and to take advantage of the "safe harbor"“safe harbor” protection for forward-looking statements that applicable federal securities law affords.
From time to time, our management or persons acting on our behalf make forward-looking statements to inform existing and potential security holders about our company. These statements may include projections and estimates concerning the timing and success of specific projects and our future backlog, revenues, income and capital spending. Forward-looking statements are generally accompanied by words such as "estimate," "project," "predict," "believe," "expect," "anticipate," "plan," "goal"“estimate,” “project,” “predict,” “believe,” “expect,” “anticipate,” “plan,” “goal” or other words that convey the uncertainty of future events or outcomes. These forward-looking statements speak only as of the date on which they are first made, which in the case of forward-looking statements made in this report is the date of this report. Sometimes we will specifically describe a statement as being a forward-looking statement and refer to this cautionary statement.
In addition, various statements that this Annual Report on Form 10-K contains, including those that express a belief, expectation or intention, as well as those that are not statements of historical fact, are forward-looking statements. Those forward-looking statements appear in Items 1 and 2—"Business2 – “Business and Properties"Properties” and Item 3—"Legal Proceedings"3 – “Legal Proceedings” in Part I of this report and in Item 7—"Management's5 – “Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities,” and in Item 7 – “Management’s Discussion and Analysis of Financial Condition and Results of Operations,"” Item 7A—"Quantitative7A – “Quantitative and Qualitative Disclosures About Market Risk"Risk” and in the Notes to Consolidated Financial Statements we have included in Item 8 of Part II of this report and elsewhere in this report. These forward-looking statements speak only as of the date of this report. We disclaim any
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obligation to update these statements, and we caution you not to unduly rely on them unduly.them. 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:
•
•
•
•
•
•
•
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 made in this report or elsewhere by us or on our behalf. We have discussed many of these factors in more detail elsewhere in this report. These factors are not necessarily all the important factors that could affect us. Unpredictable or unknown factors we have not discussed in this report could also have material adverse effects on actual results of matters that are the subject of our forward-looking statements. We do not intend to update our description of important factors each time a potential important factor arises. We advise our security holders that they should (1) be aware that important factors not referred to above could affect the 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.
On May 17, 2002, Deborah SuttonRisks Relating to the Oil and other working interest owners in a well that we drilled in May 2000 filed an amended petition naming us as a defendantGas Industry
We derive all our revenues from companies in the 37th Judicial District Courtoil and gas exploration and production industry, a historically cyclical industry with levels of activity that are significantly affected by the levels and volatility of oil and gas prices.
As a provider of contract land drilling services, our business depends on the level of drilling activity by oil and gas exploration and production companies operating in Bexar County, Texas, Cause No. 2001-CI-06701. Other defendants included: the operator, Sutton Producing Corp.;geographic markets where we operate. The oil and gas exploration and production industry is a historically cyclical industry characterized by significant changes in the casing installer, Jens'levels of exploration and development activities. Oil Field Service, Inc.;and gas prices, and market expectations of potential changes in those prices, significantly affect the sellerlevels of those activities. Worldwide political, economic and military events have contributed to oil and gas price volatility and are likely to continue to do so in the subject casingfuture. Any prolonged reduction in the overall level of exploration and collars, Exploreco, Ltd.;development activities, whether resulting from changes in oil and gas prices or otherwise, can materially and adversely affect us in many ways by negatively impacting:
• our revenues, cash flows and profitability;
• the fair market value of our rig fleet;
• our ability to maintain or increase our borrowing capacity;
• our ability to obtain additional capital to finance our business and make acquisitions, and the casingcost of that capital; and collar manufacturer, Baoshan Iron & Steel Corp. The operator and the casing installer later filed cross-claims against us, alleging they were entitled
• our ability to contribution or indemnity from usretain skilled rig personnel whom we would need in the event plaintiffs recover against them.
Plaintiffs dropped all claims against us on August 8, 2002. The operator then abandoned its cross claims against us on or about May 19, 2003. Then, on May 20, 2003, the casing crew operator non-suited its affirmative cross claims against us. We remainof an upturn in the suitdemand 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;
• 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.
We have a history of losses. We incurred net losses of $1.8 million, $5.1 million, and $0.4 million in the fiscal years ended March 31, 2004, 2003 and 2000, respectively. Our profitability in the future will depend on many factors, but largely on utilization rates and dayrates for our drilling rigs. Our current utilization rates and dayrates may decline and we may experience losses in the future.
Our acquisition strategy involves various risks.
As a key component of our business strategy, we have pursued and intend to continue to pursue acquisitions of complementary assets and businesses. Certain risks are inherent in an acquisition strategy, such as increasing leverage and debt service requirements and combining disparate company cultures and facilities, which could adversely affect our operating results. The success of any completed acquisition will depend in part on our ability to integrate effectively the acquired business into our operations. The process of integrating an acquired business may involve unforeseen difficulties and may require a disproportionate amount of management attention and financial and other resources. Possible future acquisitions may be for purchase prices significantly higher than those we paid for recent acquisitions. We may be unable to continue to identify additional suitable acquisition opportunities, negotiate acceptable terms, obtain financing for acquisitions on satisfactory terms or successfully acquire identified targets. Our failure to achieve consolidation savings, to incorporate the acquired businesses and assets into our existing operations successfully or to minimize any unforeseen operational difficulties could have a material adverse effect on our financial condition and results of operations.
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 believe pricing and rig availability are the primary factors our potential customers consider in determining which drilling contractor to select. In addition, we believe the following factors are also important:
• the type and condition of each of the competing drilling rigs;
• the mobility and efficiency of the rigs;
• the quality of service and experience of the rig crews;
• the safety records of the rigs;
• the offering of ancillary services; and
• the ability to provide drilling equipment adaptable to, and personnel familiar with, new technologies and drilling techniques.
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While we must be competitive in our pricing, our competitive strategy generally emphasizes the quality of our equipment, the safety record of our rigs and the 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.
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 casing crewrisks associated with drilling operations that the operator joinedgenerally assumes under 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. Similar to our turnkey contracts, under a footage contract we assume most of the risks associated with drilling operations that the operator generally assumes under a daywork contract. Although we attempt to obtain insurance coverage to reduce certain of the risks inherent in our turnkey and footage drilling operations, adequate coverage may be unavailable in the future and we might have to bear the full cost of such risks, which could have an adverse effect on our financial condition and results of operation.
Our operations involve operating hazards, which if not insured or indemnified against could adversely affect our results of operations and financial condition.
Our operations are subject to the many hazards inherent in the contract land drilling business, including the risks of:
• blowouts;
• fires and explosions;
• loss of well control;
• collapse of the borehole;
• lost or stuck drill strings; and
• damage or loss from natural disasters.
Any of these hazards can result in substantial liabilities or losses to us from, among other things:
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• 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.
Our operations are subject to various laws and governmental regulations that may adversely affect our future operations.
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-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, gas, drilling fluids or contaminated water or for noncompliance with other aspects of applicable laws. We are also subject to the requirements of OSHA and comparable state statutes. The OSHA hazard communication standard, the Environmental Protection Agency “community right-to-know” regulations under Title III of the Federal Superfund Amendment and Reauthorization Act and comparable state statutes require us to organize and report information about 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
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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 Corporate 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 responsible third partygroup 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 an effortconcert with a small number of these or other shareholders, they would be able to reduce its own percentageexercise control over our affairs, including the election of responsibilityour entire board of directors and, subject to the plaintiffs. However,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 positioncommon 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 mere responsible third party,whole.
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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 aredo not liablepay 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 plaintiffsdiscretion 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 other defendantsright 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 this suit.our organizational documents could delay or prevent a change in control of our company, even if that change would be beneficial to our shareholders.
We understand
The existence of some provisions in our corporate documents could delay or prevent a change in control of our company, even if that change would be beneficial to our shareholders. Our articles of incorporation and bylaws contain provisions that may make acquiring control of our company difficult, including:
• provisions regulating the remaining partiesability of our shareholders to the suit have subsequently reached a compromise and settlement which they will be finalizing in the near future.bring matters for action at annual meetings of our shareholders;
In addition, due
• limitations on the ability of our shareholders to call a special meeting and act by written consent;
• provisions dividing our board of directors into three classes elected for staggered terms; and
• the authorization given to our board of directors to issue and set the terms of preferred stock.
Due to the nature of our business, we are, from time to time, involved in routine litigation or subject to disputes or claims related to our business activities, including workers'workers’ compensation claims and employment-related disputes. In the opinion of our management, none of the pending litigation, disputes or claims against us will have a material adverse effect on our financial condition or results of operations.
We did not submit any matter to a vote of our security holders during the fourth quarter of fiscal 2003.
As of May 16, 2003, 21,710,792June 25, 2004, 27,300,126 shares of our common stock were outstanding, held by approximately 618700 shareholders of record. The number of record holders does not necessarily bear any relationship to the number of beneficial owners of our common stock.
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Our common stock began tradingtrades on the American Stock Exchange on March 8, 2001 under the symbol "PDC." Previously, our common stock was traded in the over-the-counter market and quoted in the National Quotation Bureau's "Pink Sheets" for more than 10 years.“PDC.” The following table sets forth, for each of the periods indicated, the high and low sales prices per share on the American Stock Exchange:
| Low | High | ||||
---|---|---|---|---|---|---|
Fiscal Year Ended March 31, 2003: | ||||||
First Quarter | $ | 4.00 | 5.05 | |||
Second Quarter | 2.85 | 4.20 | ||||
Third Quarter | 2.86 | 3.85 | ||||
Fourth Quarter | 3.10 | 3.64 | ||||
Fiscal Year Ended March 31, 2002: | ||||||
First Quarter | $ | 4.20 | 6.30 | |||
Second Quarter | 3.10 | 5.35 | ||||
Third Quarter | 2.90 | 4.00 | ||||
Fourth Quarter | 3.10 | 4.10 |
|
| Low |
| High |
| ||
Fiscal Year Ended March 31, 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 |
|
The last reported sales price for our common stock on the American Stock Exchange on May 16, 2003June 25, 2004 was $4.60$7.45 per share.
We have not paid or declared any dividends on our common stock and currently intend to retain earnings to fund our working capital needs and growth opportunities. Any future dividends will be at the discretion of our board of directors after taking into account various factors it deems relevant, including our financial condition and performance, cash needs, income tax consequences and the restrictions Texas and other applicable laws and our credit facilities then impose. Our debt arrangements include provisions that generally prohibit us from paying dividends, other than dividends on our preferred stock. In October 2000, we paid $160,614 in dividends to the sole holder of our Series AWe currently have no preferred stock. The holder of those shares then converted them into 800,000 shares of our common stock in accordance with the terms of the Series A preferred stock. In May and August of 2001, we paid a total of $859,395 in dividends to the holders of our Series B preferred stock. In August 2001, the holders of those shares converted them into 1,199,038 shares of our common stock in accordance with the terms of the Series B preferred stock.outstanding.
Equity Compensation Plan Information
The following table provides information on our equity compensation plans as of March 31, 2003:2004:
Plan category | Number of securities to be issued upon exercise of outstanding options, warrants and rights | Weighted-average exercise price of outstanding options, warrants and rights | Number of securities remaining available for future issuance under equity compensation plans (excluding securities reflected in column (a)) | |||
---|---|---|---|---|---|---|
| (a) | (b) | (c) | |||
Equity compensation plans approved by security holders | 1,825,000 | 1.63 | 360,413 | |||
Equity compensation plans not approved by security holders | — | — | — | |||
Total | 1,825,000 | 1.63 | 360,413 | |||
Plan category |
| Number of securities to be |
| Weighted-average |
| Number of securities |
| |
Equity compensation plans approved by security holders |
| 2,056,666 |
| $ | 3.24 |
| 2,406,413 |
|
|
|
|
|
|
|
|
| |
Equity compensation plans not approved by security holders |
| — |
| — |
| — |
| |
|
|
|
|
|
|
|
| |
Total |
| 2,056,666 |
| $ | 3.24 |
| 2,406,413 |
|
Recent Sales of Unregistered Securities
In May 2000, we completed a private placement of 3,768,161 shares of our common stock to WEDGE Energy Services, L.L.C. ("WEDGE") for $8,000,000, or $2.175 per share. We issued those shares without registration under the Securities Act of 1933 in reliance on the exemption Section 4(2) of that Act provides for transactions not involving any public offering.
In August 2000, we issued 341,576 shares of our common stock at $2.25 per share as part of the consideration we paid in connection with our acquisition of Pioneer Drilling Co. We issued those shares without registration under the Securities Act of 1933 in reliance on the exemption Section 4(2) of that Act provides for transactions not involving any public offering.
In October 2000, the T.L.L. Temple Foundation converted its 400,000 shares of Series A convertible preferred stock into 800,000 shares of our common stock at $1.00 per share. We issued those shares without registration under the Securities Act of 1933 in reliance on the exemption Section 4(2) of that Act provides for transactions not involving any public offering.
On May 18, 2001, we retired the 4.86% subordinated debenture we issued to WEDGE on March 30, 2001 in connection with the Mustang Drilling, Ltd. acquisition. We funded the repayment of the $9,000,000 face amount of the debenture, together with the payment of $59,535 of accrued interest, with a short-term bank borrowing. We then sold 2,400,000 shares of our common stock to WEDGE in a private placement for $9,048,000, or $3.77 per share. We used the proceeds from this sale to fund the repayment of the short-term bank borrowing. We issued those shares, as well as the 4.86% subordinated debenture, without registration under the Securities Act of 1933 in reliance on the exemption Section 4(2) of that Act provides for transactions not involving any public offering.
In accordance with the terms of the Series B Preferred Stock Agreement that we entered into on January 20, 1998, the conversion price for our Series B convertible preferred stock was revised from $3.25 per share to $2.50 per share as of January 20, 2001. This revision was based on the average trading price of our common stock for the 30 trading days preceding that date. In August 2001, the holders converted all of their 184,615 shares of our Series B convertible preferred stock into 1,199,038 shares of our common stock at $2.50 per share. We issued those shares without registration under the Securities Act of 1933 in reliance on the exemption Section 4(2) of that Act provides for transactions not involving any public offering.
On May 31, 2001, San Patricio Corporation exercised its option to acquire 150,000 shares of our common stock for $225,000 ($1.50 per share). We issued those shares without registration under the Securities Act of 1933 in reliance on the exemption Section 4(2) of that Act provides for transactions not involving any public offering.
On October 9, 2001, we issued a 6.75% five-year $18,000,000 convertible subordinated debenture, Series A, to WEDGE. The debenture was convertible into 4,500,000 shares of common stock at $4.00
per share. We used approximately $9,000,000 of the proceeds to complete the construction of two drilling rigs. Approximately $6,000,000 was used to reduce a $12,000,000 credit facility. The balance of the proceeds was used for drilling equipment and working capital. On July 3, 2002, we issued an additional $10,000,000 of 6.75% convertible subordinated debt to WEDGE with an effective conversion rate of $5.00 per share. The transaction was effected by an agreement between Pioneer and WEDGE under which WEDGE agreed to provide the additional $10,000,000 in financing and to cancel the previously issued debenture in the principal amount of $18,000,000 in exchange for $28,000,000 in new 6.75% convertible subordinated debentures. The new debentures are convertible into 6,500,000 shares of common stock at $4.31 per share, which resulted from a pro rata blending of the $5.00 conversion rate of the new $10,000,000 financing and the $4.00 conversion rate of the $18,000,000 debenture being cancelled. WEDGE funded $7,000,000 of the $10,000,000 on July 3, 2002 and $2,000,000 on July 29, 2002. William H. White, one of our Directors and the President of WEDGE, purchased the remaining $1,000,000 on July 29, 2002. Unlike the cancelled debenture, which was not redeemable by Pioneer, the new debentures are redeemable at a scheduled premium. We used $7,000,000 of the proceeds to pay down bank debt and $3,000,000 for the purchase of drilling equipment. WEDGE currently owns approximately 33.4% of our outstanding common stock. If WEDGE were to convert the new debentures, it would own approximately 48.3% of our outstanding common stock. We issued those securities without registration under the Securities Act of 1933 in reliance on the exemption Section 4(2) of that Act provides for transactions not involving any public offering.
On March 31, 2003, we sold 5,333,333 shares of our common stock to Chesapeake Energy Corporation for $20,000,000 ($3.75 per share), before related offering expenses.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 24.6%19.5% of our outstanding common stock, or approximately 17.8%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.
The following information derives from our audited financial statements. You should review this information in conjunction with "Management's“Management’s Discussion and Analysis of Financial Condition and Results of Operations"Operations” in Item 7 of this report and the historical financial statements and related notes this report contains.
| Years Ended March 31, | |||||||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| 2003 | 2002 | 2001 | 2000 | 1999 | |||||||||||
| (In thousands, except per share amounts) | | | |||||||||||||
Contract drilling revenues | $ | 80,183 | $ | 68,627 | $ | 50,345 | $ | 19,391 | $ | 12,659 | ||||||
Earnings (loss) from operations | (4,943 | ) | 11,201 | 3,803 | 149 | (1,254 | ) | |||||||||
Earnings (loss) before income taxes | (7,305 | ) | 9,737 | 3,838 | (65 | ) | (1,278 | ) | ||||||||
Preferred dividends | — | 93 | 275 | 304 | 304 | |||||||||||
Net earnings (loss) applicable to common stockholders | (5,086 | ) | 6,225 | 2,428 | (384 | ) | (1,612 | ) | ||||||||
Earnings (loss) per common share—basic | (0.31 | ) | 0.41 | 0.22 | (0.06 | ) | (0.27 | ) | ||||||||
Earnings (loss) per common share—diluted | (0.31 | ) | 0.35 | 0.19 | (0.06 | ) | (0.27 | ) | ||||||||
Long-term debt and capital lease obligations, excluding current installments | 45,855 | 26,119 | 10,056 | 267 | 2,354 | |||||||||||
Shareholders' equity | 47,672 | 33,343 | 17,827 | 6,783 | 5,322 | |||||||||||
Total assets | 119,694 | 83,450 | 56,493 | 15,670 | 10,007 | |||||||||||
Capital expenditures | 33,589 | 27,597 | 41,628 | 5,069 | 856 |
|
| Years Ended |
| |||||||||||||
|
| 2004 |
| 2003 |
| 2002 |
| 2001 |
| 2000 |
| |||||
|
| (In thousands, except per share amounts) |
| |||||||||||||
Contract drilling revenues |
| $ | 107,876 |
| $ | 80,183 |
| $ | 68,627 |
| $ | 50,345 |
| $ | 19,391 |
|
Income (loss) from operations |
| 438 |
| (4,943 | ) | 11,201 |
| 3,803 |
| 108 |
| |||||
Income (loss) before income taxes |
| (2,216 | ) | (7,305 | ) | 9,737 |
| 3,838 |
| (65 | ) | |||||
Preferred dividends |
| — |
| — |
| 93 |
| 275 |
| 304 |
| |||||
Net earnings (loss) applicable to common stockholders |
| (1,790 | ) | (5,086 | ) | 6,225 |
| 2,428 |
| (384 | ) | |||||
Earnings (loss) per common share-basic |
| (0.08 | ) | (0.31 | ) | 0.41 |
| 0.22 |
| (0.06 | ) | |||||
Earnings (loss) per common share-diluted |
| (0.08 | ) | (0.31 | ) | 0.35 |
| 0.19 |
| (0.06 | ) | |||||
Long-term debt and capital lease obligations, excluding current installments |
| 44,892 |
| 45,855 |
| 26,119 |
| 10,056 |
| 267 |
| |||||
Shareholders’ equity |
| 70,836 |
| 47,672 |
| 33,343 |
| 17,827 |
| 6,783 |
| |||||
Total assets |
| 143,731 |
| 119,694 |
| 83,450 |
| 56,493 |
| 15,670 |
| |||||
Capital expenditures |
| 44,845 |
| 33,589 |
| 27,597 |
| 41,628 |
| 5,069 |
| |||||
Refer to Note 2 of the consolidated financial statements for information on acquisitions.
Statements we make in the following discussion whichthat express a belief, expectation or intention, as well as those thatwhich are not historical fact, are forward-looking statements that are subject to risks, uncertainties and assumptions. Our actual results, performance or achievements, or industry results, could differ materially from those we express in the following discussion as a result of a variety of factors, including general economic and business conditions and industry trends, the continued strength or weakness of the contract land drilling industry in the geographic areas in which we operate, decisions about onshore exploration and development projects to be made by oil and gas companies, the highly competitive nature of our business, our future financial performance, including availability, terms and deployment of capital, the continued availability of qualified personnel, and changes in, or our failure or inability to comply with, government regulations, including those relating to the environment.
Company Overview
Pioneer Drilling Company provides contract land drilling services to independent and major oil and gas exploration and production companies. In addition to our drilling rigs, we provide the drilling crews and most of the ancillary equipment needed to operate our drilling rigs. We have focused our operations in the natural gas production regions of South Texas, East Texas and North Texas. Our company was incorporated in 1979 as the successor to a business that had been operating since 1968. We conduct our operations through our principal operating subsidiary, Pioneer Drilling Services, Ltd. We are an oil and gas services company. We do not invest in oil and natural gas properties. The drilling activity of our customers is highly dependent on the current price of oil and natural gas.
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 refurbished drilling rigs.
Over the past five fiscal years, we have significantly expanded our fleet of drilling rigs through acquisitions and the construction of new and refurbished rigs. As of March 31, 2004, our rig fleet consisted of 35 land drilling rigs that drill in depth ranges between 8,000 and 18,000 feet. Fourteen of our rigs are operating in South Texas, 17 in East Texas and four in North Texas. 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, we are not currently committed to any acquisitions.
We earn our revenues by drilling oil and gas wells. 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, 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.
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, 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 |
|
The reasons for the increase in the number of revenue days in 2004 over 2003 and 2002 are the increase in size of our rig fleet and the improvement in our overall rig utilization rate. For 2005, we anticipate continued growth in revenue days and maintaining relatively high utilization rates.
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 in periods of lower demand and improve our 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.
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 resulted in fewer revenue days and slightly lower utilization; however, in the long term, we believe the upgrades will help the marketability of the rigs and improve their operating performance.
Market Conditions in Our Industry
The United States contract land drilling services industry is highly cyclical. Volatility in oil and gas prices can produce wide swings in the levels of overall drilling activity in the markets we serve and affect the demand for our drilling services and the dayrates we can charge for our rigs. The availability of financing sources, past trends in oil and gas prices and the outlook for future oil and gas prices strongly influence the number of wells oil and gas exploration and production companies decide to drill.
Beginning in 1998 and extending into 1999,
17
For the domestic contract land drilling industrythree months ended March 31, 2004, the average weekly spot price for West Texas Intermediate crude oil was adversely affected by an extended period of low oil and gas prices and a domestic$35.08, the average weekly spot price for Henry Hub natural gas surplus. was $5.56 and the average weekly Baker Hughes land rig count was 1,002. On June 11, 2004, the spot price for West Texas Intermediate crude oil was $38.45, the spot price for Henry Hub natural gas was $6.00 and the Baker Hughes land rig count was 1,070, a 13% increase from 948 on June 13, 2003.
The priceaverage weekly spot prices of West Texas Intermediate crude dropped to a low of $10.83 per barrel in December 1998oil, Henry Hub natural gas and the price of natural gas dropped to a low of $1.03 per mmbtu in December 1998. These conditions led to significant reductions in the overall level of domestic land drilling activity, resulting in a historically lowaverage weekly domestic land rig count, of 380 rigs on April 23, 1999. Prior to this industry downturn, during 1997,per the contract land drilling industry experienced a significant level of drilling activity, with a domestic land rig count of 881 rigs on September 5, 1997.
Oil and natural gas prices rose sharply in calendar year 2000 and through mid-2001. Natural gas prices began falling in mid-2001 to a low of approximately $2.00 per mmbtu before returning to current levels of between $5.25 and $6.25 per mmbtu. Oil prices are currently in the $25.00 to $30.00 per barrel range. The average spot prices of natural gas and crude oil and the average domesticBaker Hughes land rig count, for each of ourthe previous six fiscal years ended March 31, 20032004 were:
| 2003 | 2002 | 2001 | 2000 | 1999 | 1998 | ||||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
Oil (West Texas Intermediate) | $ | 29.27 | $ | 24.31 | $ | 30.40 | $ | 23.23 | $ | 13.69 | $ | 18.92 | ||||||
Gas (Henry Hub) | $ | 4.24 | $ | 2.96 | $ | 5.27 | $ | 2.46 | $ | 1.97 | $ | 2.39 | ||||||
U. S. Land Rig Count | 723 | 912 | 841 | 560 | 592 | 821 |
Primarily as a result of the increase in oil and natural gas prices, exploration and production companies increased their capital spending budgets in 2000 and early 2001. These increased spending budgets increased the demand for contract drilling services. The domestic land rig count climbed to 1,095 on June 22, 2001, representing an increase in the domestic land rig count of 188% from the low in April 1999.
|
| 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 have beenwere 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. The Baker Hughes domestic land rig count was 915 on May 16,
During fiscal 2004, 2003 a 29% increase from 709 on May 17, 2002.and 2002, substantially all the wells we drilled for our customers were drilled in search of natural gas because of the depth capacity 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.
Critical Accounting Policies and Estimates
Revenue and cost recognition – —We earn our revenues by drilling oil and gas wells for our customers under daywork, turnkey or footage contracts, which usually provide for the drilling of a single well. See "Results of Operations" below for a general description of these contracts. We recognize revenues on daywork contracts for the days completed based on the dayrate each contract specifies. We recognize revenues from our turnkey and footage contracts on the percentage-of-completion method based on our estimate of the number of days to complete each contract. Contract drilling in progress represents revenues we have recognized in excess of amounts billed on contracts in progress. Individual contracts are usually completed in less than 60 days. The risks to us under a turnkey contract, and to a lesser extent under footage contracts, are substantially greater than on a contract drilled on a daywork basis,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 risks of blowout, loss of hole, stuck drill pipe, machinery breakdowns and abnormal drilling conditions, as well as risks associated with subcontractors'subcontractors’ services, supplies, cost escalations and personnel operations.
Our management has determined that it is appropriate to use the percentage-of-completion method 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 obligationsobligation to us under a turnkey or footage contract, we would need to rely on applicable law to enforce our lien rights, because our turnkey and footage contracts do not expressly grant to us a security interest in the work we have completed under the contract and we have no ownership rights in the work-in-progress or completed drilling work, except any rights arising under the applicable lien statute on foreclosure. If we were unable to drill to the agreed on depth in breach of the contract, we also would need to rely on equitable remedies outside of the contract, includingquantum meruit, available in applicable courts to recover the fair value of our costs incurred to drill a wellwork-in-progress under a turnkey or footage contract.
We accrue estimated contract costs on turnkey and footage contracts for each day of work completed based on our estimate of the total costcosts to complete the contract divided by our estimate of the number of days to complete the contract. Contract costs include labor, materials, supplies, repairs and maintenance, and operating overhead allocations. Changes in job performance, job conditionsallocations and estimated profitability on uncompleted contracts may result in revisions to costsallocations of depreciation and income, including losses, which we recognize in the period in which we determine the revisions.amortization expense. In addition, the occurrence of uninsured or under-insured losses or operating cost overruns on our turnkey and footage contracts could have a material adverse effect on our financial position and results of operations.Therefore, our actual results could
18
differ significantly if our cost estimates are later revised from our original estimates.estimates for contracts in progress at the end of a reporting period which were not completed prior to the release of our financial statements.
Asset 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'customers’ financial condition and any significant negative industry or economic trends. More specifically, among other things, we consider our contract revenue rates, our rig utilizationutilizations rates, cash flows from our drilling rigs, current oil and gas prices, industry analysts'analysts’ outlook for the industry and their view of our customerscustomers’ access to
debt or equity, discussions with major industry suppliers, discussions with officers of our primary lender regarding their experiences and expectations for oil and gas operators in our areas of operations and the trends in the price of used drilling equipment observed by our management. If a review of our drilling rigs indicates that our carrying value exceeds the estimated undiscounted future cash flows, we are required under applicable accounting standards to write down the drilling equipment to its fair market value. A one percent write-down in the valuecost of our drilling equipment, at March 31, 2003,2004, would have resulted in a corresponding increase in our net loss of approximately $704,000$962,000 for our fiscal year ended March 31, 2003.2004.
Deferred taxes—We –We provide deferred taxes for net operating loss carryforwards and for the basis difference in our property and equipment between financial reporting and tax reporting purposes. For property and equipment, basis differences arise from differences in depreciation periods and methods and the value of assets acquired in a business acquisition where we acquire an entity rather than just its assets. For financial reporting purposes, we depreciate the various components of our drilling rigs over 10eight to 15 years and refurbishments over three years, while federal income tax rules require that we depreciate drilling rigs and refurbishments over five years. Therefore, in the first five years of our ownership of a drilling rig, our tax depreciation exceeds our financial reporting depreciation, resulting in our providing deferred taxes on this depreciation difference. After five years, financial reporting depreciation exceeds tax depreciation, and the deferred tax liability begins to reverse.
Accounting estimates���We –We consider the recognition of revenues and costs on turnkey and footage contracts critical accounting estimates. On these types of contracts, we are required to estimate the number of days it will require for us to complete the contract and our total cost to complete the contract. Our actual costs could substantially exceed our estimated costs if we encounter problems such as lost circulation, stuck drill pipe or an underground blowout on contracts still in progress subsequent to the release of the financial statements.
We receive payment under turnkey and footage contracts when we deliver to our customer a well completed to the depth specified in the contract, unless the customer authorizes us to drill to a shallower depth. Since 1995, when our current management team joined our company, we have completed all our turnkey or footage contracts. Although our initial cost estimates for turnkey and footage contracts do not include cost estimates for risks such as stuck drill pipe or loss of circulation, we believe that our experienced management team, our knowledge of geologic formations in our areas of operations, the condition of our drilling equipment and our experienced crews enable us to make reasonably dependable cost estimates and complete contracts according to our drilling plan. While we do bear the risk of loss for cost overruns and other events that are not specifically provided for in our initial cost estimates, our pricing of turnkey and footage contracts takes such risks into consideration. When we encounter, during the course of our drilling operations, conditions unforeseen in the preparation of our original cost estimate, we immediately increase our cost estimate for the additional costs to complete the contract.contracts. If we anticipate a loss on a contract in progress at the end of a reporting period due to a change in our cost estimate, we immediately accrue the entire amount of the estimated loss including all costs that are included in our revised estimated cost to complete that contract in our consolidated statement of operations for that reporting period. At March 31, 2003, we accrued an estimated loss of $227,000 on one of our turnkey contracts in progress. During fiscal 2003,2004, we experienced losses on 17eight of the 83105 turnkey and footage contracts completed, with losses exceeding $25,000 on 7six contracts and losses exceeding $100,000 on two 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 our turnkey contracts in progress at March 31, 20032004 were completed prior to
the release of thesethe financial statements.statements included in this report. At March 31, 20032004 our Contract Drillingcontract drilling in Progressprogress totaled approximately $4,429,000.$9,131,000. Of that amount accrued, turnkey and footage contract revenues were approximately $3,940,000.$7,683,000. The remaining balance of approximately $489,000$1,448,000 relates to the revenue recognized but not yet billed on daywork contracts in progress at March 31, 2003.2004.
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 to date have not extended payment terms beyond 60 days.days for any of our contracts in the last three fiscal years.
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 estimate of the useful lives of our drilling, transportation and other equipment are based on our more than 35 years of experience in the drilling industry with similar equipment.
Other accrued expenses in our March 31, 20032004 financial statements include an accrual of a total of $525,000approximately $680,000 for costs incurred under the self-insurance portion of our health insurance and under our workers'workers’ compensation insurance. We have a deductible of (1) $100,000 per covered individual per year under the health insurance and (2) $250,000 per occurrence under our workers'workers’ compensation insurance. We accrue for these costs as claims are incurred based on cost estimates established for each claim by the insurance companies providing the administrative services for processing the claims, including an estimate for incurred but not reported claims, estimates for claims to be paid directly by us, our estimate of the administrative costs associated with these claims and our historical experience with these types of claims.
Liquidity and Capital Resources
On
Sources of Capital Resources
Our rig fleet has grown from eight rigs in August 2000 to 35 rigs as of March 31, 2003,2004. We have financed this growth with a combination of debt and equity financing. We have raised additional equity or used equity for growth six 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. We plan to continue to grow our rig fleet. We believe that near-term 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 sold 5,333,333are reluctant to take on substantial additional debt at this time. However, our ability to continue funding our growth through the issuance of shares of our common stock to Chesapeake Energy Corporationis uncertain, as our common stock is not heavily traded and the market price for $20,000,000 ($3.75our 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),share in a private placement for $23,760,000 in proceeds, before related offering expenses.
Uses of Capital Resources
In connection with that sale,May 2003, we granted Chesapeake Energyadded one refurbished 18,000-foot SCR land drilling rig at a preemptive right to acquire equity securitiescost of approximately $7,300,000. On August 1, 2003, we may issuepurchased two land drilling rigs, associated spare parts and equipment and vehicles from Texas Interstate Drilling Company, L. P. for $2,500,000 in cash and the future, under specified circumstances, in order to permit Chesapeake Energy to maintain its proportionate ownershipissuance of 477,000 shares of our outstanding shares of common stock. We also granted Chesapeake Energystock valued at $4.45 per share. On August 26, 2003, we purchased a right, under certain circumstances, to request registration14,000-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 shares undera 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 Securities Act of 1933. Chesapeake Energy owns approximately 24.6%February 20, 2004 sale of our outstanding common stock, or approximately 17.8% assuming the conversion of all outstanding options and convertible subordinated debentures.stock.
In late May 2004, we completed constructing, primarily from used components, a 1000-hp electric drilling rig. As of March 31, 2004, we had incurred approximately $2,800,000 of construction costs on this rig and anticipate additional related construction costs of approximately $2,100,000. We began moving it to its first drilling location on May 28, 2004. 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
Since March 31, 2003, 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 |
|
(1) Includes capitalized interest costs of $106,395.
Working Capital
Our working capital increaseddecreased to $6,028,018 at March 31, 2004 from $11,144,309 at March 31, 2003 from a deficit of $268,478 at March 31, 2002.2003. Our current ratio, which we calculate by dividing our current assets by our current liabilities, was 1.27 at March 31, 2004 compared to 1.55 at March 31, 2003 compared to 0.98 at March 31, 2002.2003. The principal reason for the improvementdecrease in our working capital at March 31, 20032004 was our saleuse 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.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. Our operations have historically generated even during periods of industry downturns, sufficient cash flow to meet our requirements for debt service and equipment expenditures.expenditures, even during periods of industry downturns. During
periods when a higher percentage of our contracts are turnkey and footage contracts, our short-term working capital needs could increase. We have available a $1,000,000$2,500,000 line of credit for short-term cash requirements. We did not have to usemake any borrowings under the line of credit during fiscal 2003.2004. We have used debt and equity to finance our long-term growth strategy to increase the size of our rig fleet. During periods of improved rig revenue rates, we believe we can generate cash flows in excess of our normal cash requirements.
The changes in the components of our working capital were as follows:
| March 31, | | ||||||||
---|---|---|---|---|---|---|---|---|---|---|
| 2003 | 2002 | Change | |||||||
Cash, cash equivalents and securities | $ | 21,002,913 | $ | 5,720,354 | $ | 15,282,559 | ||||
Receivables | 8,928,923 | 9,281,049 | (352,126 | ) | ||||||
Income tax receivable | 444,900 | 880,068 | (435,168 | ) | ||||||
Deferred tax receivable | 180,991 | — | 180,991 | |||||||
Prepaid expenses | 914,187 | 634,747 | 279,440 | |||||||
Current assets | 31,471,914 | 16,516,218 | 14,955,696 | |||||||
Current debt | 3,399,163 | 8,275,914 | (4,876,751 | ) | ||||||
Accounts payable | 14,206,586 | 6,507,169 | 7,699,417 | |||||||
Deferred taxes | — | 23,571 | (23,571 | ) | ||||||
Accrued expenses | 2,721,856 | 1,978,042 | 743,814 | |||||||
20,327,605 | 16,784,696 | 3,542,909 | ||||||||
Working capital | $ | 11,144,309 | (268,478 | ) | 11,412,787 | |||||
|
| March 31, |
|
|
| |||||
|
| 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 | ) |
The increase inlarge cash isbalance at March 31, 2003 was due to theour sale of common stock described above. The decrease in current debt resulted from our repayment$20,000,000 of a $6,000,000 bank loanequity on March 31, 2003, partially offset by increasesof which $14,000,000 was in current installments of other debt obligations.the March 31, 2003 cash balance. The $14,000,000 was used during fiscal 2004 to purchase drilling rigs and equipment.
In March 2003, we completed or had
The increase in progress 20 turnkey contracts. Approximately 68% of our receivables at March 31, 2004 from March 31, 2003 result fromwas due to our operating eleven additional rigs in the quarter ended March 31, 2004, including an approximately $3,693,000 increase in contract drilling in progress related to turnkey contracts, and footage contracts compared to approximately 26% of receivablesan improvement in revenue rates in fiscal 2004 over fiscal 2003.
21
Substantially all our prepaid expenses at March 31, 2002.
2004 consisted of prepaid insurance. The increase in accounts payable at March 31, 2003 over March 31, 2002prepaid insurance is primarily attributable to the increase in our turnkey contract work. Under turnkey contracts, we are responsible for many of the costs which are the responsibility of our customer under daywork contracts. Some of the increase in accounts payable is also due to the increase in the size of our drilling rig fleet.fleet from 24 rigs at March 31, 2003 to 35 rigs at March 31, 2004.
The increase in accrued expenses results from anpayroll is due to the approximately 50% increase in accrued payrollour number of $54,000 resulting from anemployees and the increase in the number of employees;payroll days included in the accrual from seven at March 31, 2003 to nine at March 31, 2004.
The total increase in accrued expenses at March 31, 2004 from March 31, 2003 was due to an increase of approximately $422,000$477,000 in the accrual for our insurance deductibles and additional insurance premiums, expense accruals of approximately $250,000 related to our healththe sale of common stock in February and workers' compensation insurance primarily as a resultaccrued property taxes of approximately $205,000 due to increases in rig valuations and the size of our switching to the deductible health insurance plan in June 2002; and an increase of approximately $247,000 in accrued well control insurance, due to the increase in turnkey contracts.rig fleet.
Long-term Debt
Our cash flows from operating activities for the year ended March 31, 2003 were $14,389,277, compared to $11,044,889 for the year ended March 31, 2002. Our cash flows from operating activities are affected by a number of factors, including rig utilization rates, the types of contracts we are performing, revenue rates we are able to obtain for our services, collection of receivables and the timing of expenditures. The primary reason for the increase in cash flows from operating activities in fiscal 2003 is the increase in payableslong-term debt at March 31, 2003 over March 31, 2002.
Since March 31, 2002, the additions to our property and equipment were $33,588,972. Additions2004 consisted 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 |
|
Drilling rigs(1) | $ | 24,667,710 | |
Other drilling equipment | 8,504,588 | ||
Transportation equipment | 383,650 | ||
Other | 33,024 | ||
$ | 33,588,972 | ||
(1)
On May 28, 2002, we purchased from United Drilling Companythe convertible subordinated debentures and U-D Holdings, L.P. two land drilling rigs, associated spare parts and vehicles for $7,000,000 in cash. We financedWilliam H. White, a former director of our company, holds $1,000,000. WEDGE owns 26.5% of our common stock (40.2% if the acquisition of those assets with a $7,000,000 loan from Frost National Bank. Interest on the loan was payable monthly at prime. The loan was collateralized by the assets that we purchased and a $7,000,000 letter of credit that WEDGE provided. We repaid this loan ondebentures were converted). Beginning July 3, 2002 with $7,000,0002004, we have the option to redeem all or part of the proceeds fromdebentures 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 issuancepurchase of the subordinated debt as described below.
In November and December of 2002, we added two refurbished 18,000-foot SCR land drilling rigs at a cost of approximately $7,000,000 each. As of March 31, 2003,rig we were constructing an additional refurbished 18,000-foot SCR land drilling rig. previously leasing.
22
Contractual Obligations
We estimate the total cost of this rig will be approximately $7,000,000, of which approximately $2,415,000 had been incurreddo not have any routine purchase obligations. However, as of March 31, 2003. We accepted delivery2004, we were in the process of this rig on May 2, 2003. On September 30, 2002, we signed an agreement to purchase another 14,000-foot mechanicalconstructing a drilling rig, located in Trinidad, for $3,150,000, which we expect to be delivered to the Portas described above. The following table excludes interest payments on long-term debt and capital lease obligations. The following table includes all of Houston in July or August 2003. On October 7, 2002, we made a $315,000 deposit toward the purchase of this rig. In March 2003, we signed an amended asset purchase agreement reducing the purchase price for this rig to $2,850,000 and made an additional $300,000 deposit.
Our debtour contractual obligations in the form of notes payable, capital leases and convertible subordinated debentures increased by a net of $14,859,191 fromat March 31, 2002 to March 31, 2003. This increase resulted2004.
|
| Payments Due by Period |
| |||||||||||||
Contractual |
| Total |
| Less than 1 |
| 1-3 |
| 4-5 |
| More than |
| |||||
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 |
| $ | — |
|
Debt Requirements
Borrowings from a $10,000,000 increase in our subordinated debt, $14,500,000 of new debt fromFrost National Bank and Merrill Lynch Capital, a division of Merrill Lynch Business Financial Services, Inc. ("MLC"(“MLC”), $1,239,535 to finance the premiums on insurance policies, $448,475 from our line of credit and $385,492 in capital leases for crew quarters and vehicles. In addition, on May 28, 2002, we obtained a $7,000,000 short-term loan from Frost National Bank, which we repaid on July 3, 2002 with $7,000,000 of proceeds from the issuance of new convertible subordinated debt as described below. We made payments of $18,714,311 on our debt, including the $6,000,000, $7,000,000 and $2,130,503 loan repayments. Borrowings from Frost National Bank, on an installment loan due August 2004, and MLC are secured by drilling equipment. Our bank loan and MLC Loan contain various covenants pertaining to leverage, cash flow coverage, fixed charge coverage and net worth ratios and restrict us from paying dividends. Under these credit arrangements, we determine compliance with the ratios on a quarterly basis, based on the previous four quarters. As of March 31, 2003,2004, we were in compliance with all covenants applicable to our outstanding debt.
On December 23, 2002, we borrowed $14,500,000 from MLC. Under the terms
Events of the MLCdefault in our loan weagreements, which could trigger an early repayment requirement, include, among others:
• our failure to make monthly interest payments until August 1, 2003, when we begin making equal monthly installment payments of principal of $172,619, plus interest. The unpaid balance of the MLC loan will be due at maturity on December 22, 2007. Interest accrues at a floating rate equalrequired payments;
• our failure to comply with financial covenants related to the three month LIBOR rate plus 385 basis points untilmaintenance of a ratio of debt to tangible net worth, a leverage ratio, a cash flow coverage ratio and a senior cash flow coverage ratio;
• our election to convertincurrence of additional indebtedness in excess of $2,000,000 not already allowed by the interest rate to a fixed rate, at which time interest will accrue at the greater of (1) 6.975%, or (2) the sum of the swap rate published on the Bloomberg Screen "USSW" on the conversion date plus 367 basis points. The MLC loan is secured byagreements without each lender’s approval; and
a first priority security interest in certain of our drilling rigs. We may prepay the MLC loan at
• any time in whole, but not in part, subject to certain exceptions and payment of specified prepayment premium requirements. We used $2,130,503 of the proceeds of the Loan to retire all ofcash dividends on our outstanding debt to one of our bank lenders, $5,106,321 to make a final payment on the new/refurbished, 18,000 foot rig added in December, $7,190,676 to replenish our working capital and $72,500 to pay associated loan fees.
On October 9, 2001, we issued a 6.75% five-year $18,000,000 convertible subordinated debenture, Series A, to WEDGE Energy Services, L.L.C. ("WEDGE"). The debenture was convertible into 4,500,000 shares of common stock at $4.00 per share. We used approximately $9,000,000 of the proceeds to complete the construction of two drilling rigs. Approximately $6,000,000 was used to reduce a $12,000,000 credit facility. The balance of the proceeds was used for drilling equipment and working capital. On July 3, 2002, we issued an additional $10,000,000 of 6.75% convertible subordinated debt to WEDGE with an effective conversion rate of $5.00 per share. The transaction was effected by an agreement between Pioneer and WEDGE under which WEDGE agreed to provide the additional $10,000,000 in financing and to cancel the previously issued debenture in the principal amount of $18,000,000 in exchange for $28,000,000 in new 6.75% convertible subordinated debentures. The new debentures are convertible into 6,500,000 shares of common stock at $4.31 per share, which resulted from a pro rata blending of the $5.00 conversion rate of the new $10,000,000 financing and the $4.00 conversion rate of the $18,000,000 debenture being cancelled. WEDGE funded $7,000,000 of the $10,000,000 on July 3, 2002 and $2,000,000 on July 29, 2002. William H. White, one of our Directors and the President of WEDGE, purchased the remaining $1,000,000 on July 29, 2002. Unlike the cancelled debenture, which was not redeemable by Pioneer, the new debentures are redeemable at a scheduled premium. We used $7,000,000 of the proceeds to pay down bank debt and $3,000,000 for the purchase of drilling equipment. If WEDGE were to convert the new debentures, it would own approximately 48.3 percent of our outstanding common stock.
The limitation on additional indebtedness has not affected our operations or liquidity and we do not expect it to affect us in the future as we expect to continue to generate adequate cash flow from operations.
We also have a $1,000,000$2,500,000 line of credit available from Frost National Bank.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 (4.25%(4.00% at March 31, 2003)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 $1,000,000$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, 2003,2004, we had no outstanding advances under this line of credit, letters of credit were $1,450,000$1,664,000 and 75% of eligible accounts receivable were $4,299,179.was approximately $8,030,000. The letters of credit are issued to two workers'workers’ compensation insurance companies to secure possible future claims underthat do not exceed the deductibles on these policies. It is our practice to pay any amounts due underthat 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.
We do not have any routine purchase obligations. However, we are obligated under two asset purchase agreements for the purchase and construction of two drilling rigs as previously described. The following table excludes interest payments on long-term debt and capital lease obligations. The following table includes all of our contractual obligations at March 31, 2003.
| Payments due by period | ||||||||||||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
Contractual obligations | Total | 2004 | 2005 | 2006 | 2007 | 2008 | More than 5 years | ||||||||||||||
Long Term Debt Obligations | $ | 48,265,786 | $ | 2,671,269 | $ | 6,468,524 | $ | 2,076,690 | $ | 2,077,054 | $ | 34,910,777 | $ | 61,472 | |||||||
Capital Lease Obligations | 400,742 | 140,717 | 148,283 | 78,172 | 33,570 | — | — | ||||||||||||||
Operating Lease Obligations | 474,738 | 358,008 | 58,008 | 56,010 | 2,712 | — | — | ||||||||||||||
Total | $ | 49,141,266 | $ | 3,169,994 | $ | 6,674,815 | $ | 2,210,872 | $ | 2,113,336 | $ | 34,910,777 | $ | 61,472 | |||||||
Events of default in our loan agreements, which could trigger an early repayment requirement, include among others:23
The limitation on additional indebtedness has not affected our operations or liquidity and we do not expect it to affect us in the future as we expect to continue to generate adequate cash flow from operations. We also have a $1,000,000 line of credit to supplement our short-term cash needs.
Results of Operations
We earn our revenues by drilling oil and gas wells. We obtain our contracts for
Our operations consist of drilling oil and gas wells either through competitive bidding or through direct negotiations with customers. Our drilling contracts generally provide for compensation on either aour customers under daywork, turnkey, or footage contracts usually on a well-to-well basis. Contract terms we offer generally depend onDaywork contracts are the complexityeasiest for us to perform and involve the least risk. Turnkey contracts are the most difficult to perform and involve much greater risk of operations,but provide the on-site drilling conditions, the type of equipment used and the anticipated duration of the work to be performed. Generally, our contracts provideopportunity for the drilling of a single well.higher operating margins.
Daywork Contracts.Contracts. Under daywork drilling contracts, we provide a drilling rig with required personnel to our customer, who supervises the drilling of the well. We are paid based on a negotiated fixed rate per day while the rig is used. Daywork drilling contracts specify the equipment to be used, the size of the hole and the depth of the well. Under a daywork drilling contract, the customer bears a large portion of out-of-pocket costs of drilling and we generally bear no part of the usual risks associated with drilling, such as time delays and unanticipated costs.
Turnkey Contracts.Under a turnkey contract, we agree to drill a well for our customer to a specified depth and under specified conditions for a fixed price, regardless of the time required or the problems encountered in drilling the well. We provide technical expertise and engineering services, as well as most of the equipment and drilling supplies required to drill the well. We often subcontract for related services, such as the provision of casing crews, cementing and well logging. Under typical turnkey drilling arrangements, we do not receive progress payments and are paid by our customer only after we have performed the terms of the drilling contract in full.
The risks to us under a turnkey contract are substantially greater than on a well drilled onthose under a daywork basis,contract. This is primarily because under a turnkey contract we assume most of the risks associated with drilling operations generally assumed bythat the operator ingenerally assumes under a daywork contract, including the risks of blowout, loss of hole, stuck drill pipe, machinery breakdowns and abnormal drilling conditions, as well as risks associated with subcontractors' services, supplies, cost escalations and personnel. We employ or contract for engineering expertise to analyze seismic, geologic and drilling data to identify and reduce some of the drilling risks assumed by us. We use the results of this analysis to evaluate the risks of a proposed contract and seek to account for such risks in our bid preparation. We believe that our operating experience, qualified drilling personnel, risk management program, internal engineering expertise and access to proficient third-party engineering contractors have allowed us to reduce some of the risks inherent in turnkey drilling operations. We also maintain insurance coverage against some but not all drilling hazards. However, the occurrence of uninsured or under-insured losses or operating cost overruns on our turnkey jobs could have a material adverse effect on our financial position and results of operations.contract.
Footage Contracts.Contracts. Under footage contracts, we are paid a fixed amount for each foot drilled, regardless of the time required or the problems encountered in drilling the well. We typically pay more of the out-of-pocket costs associated with footage contracts as compared withto daywork contracts. Similar to a turnkey contract, the risks to us oncontracts, under a footage contract are greater because we assume most of the risks associated with drilling operations generally assumed bythat the operator ingenerally assumes under a daywork contract. As with turnkey contracts, we manage these additional risks through the use of engineering expertise and bid the footage contracts accordingly, and we maintain insurance coverage against some but not all drilling hazards. However, the occurrence of uninsured or under- insured losses or operating cost overruns on our footage jobs could
We have a material adverse effect on our financial positionhistory of losses. We incurred net losses of approximately $1,800,000, $5,100,000 and results of operations.
For each of$400,000 in the threefiscal years ended March 31, 2004, 2003 our rig utilization and revenue days were as follows:
| 2003 | 2002 | 2001 | ||||
---|---|---|---|---|---|---|---|
Utilization Rates | 79 | % | 82 | % | 91 | % | |
Revenue Days | 6,419 | 5,384 | 3,466 |
The primary reason for the increase2000, respectively. Our profitability in the numberfuture will depend on many factors, but largely on utilization rates and dayrates for our drilling rigs.
The current demand for drilling rigs greatly influences the types of revenue days in 2003 over 2002contracts we are able to obtain. As the demand for rigs increases, daywork rates move up and 2002 over 2001 is the increase in size of our rig fleet from 16 at March 31, 2001we are able to 20 at March 31, 2002switch primarily to 24 at March 31, 2003.daywork contracts.
For each of the three years ended March 31, 2004, 2003 and 2002, the percentages of our drilling revenues by type of contract were as follows:
| 2003 | 2002 | 2001 | ||||
---|---|---|---|---|---|---|---|
Turnkey Contracts | 58 | % | 7 | % | 57 | % | |
Footage Contracts | 1 | % | 2 | % | 1 | % | |
Daywork Contracts | 41 | % | 91 | % | 42 | % |
Due to the
|
| Year Ended March 31, |
| ||||
|
| 2004 |
| 2003 |
| 2002 |
|
Turnkey Contracts |
| 50 | % | 58 | % | 7 | % |
Footage Contracts |
| 3 | % | 1 | % | 2 | % |
Daywork Contracts |
| 47 | % | 41 | % | 91 | % |
While current reduced demand for drilling rigs has increased, we have returnedcontinue to biddingbid on turnkey contracts in an effort to improve margins and maintain rig utilization. In spite of improvements inAlthough oil and natural gas prices have improved, we anticipate only a moderate change in the mix of our typetypes of contracts in the near future.fiscal 2005.
In accordance with Emerging Issues Task Force issue No. 01-14 "Income Statement Characterizationour quarter ended March 31, 2004, we recognized revenues of Reimbursements Received for Out-of-Pocket Expenses Incurred," we have revised the presentation of reimbursements received for certain expenses in the periods presented. These reimbursements are now included inapproximately $924,000 and recorded contract drilling revenues incosts of approximately $745,000, excluding depreciation, on one daywork contract with Chesapeake Energy Corporation, who owns approximately 19.5% of our outstanding common stock.
24
Statement of Operations Analysis
The following table provides information about our operations for the consolidated statements of operations versus previously being recorded net of the incurred expense in contract drilling costs. These reclassifications had no effect on net income or cash flows for any of the three years ended March 31, 2003.2004, March 31, 2003, and March 31, 2002.
|
| Year Ended March 31, |
| |||||||
|
| 2004 |
| 2003 |
| 2002 |
| |||
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: |
|
|
|
|
|
|
| |||
Turnkey contracts |
| 2,827 |
| 2,619 |
| 289 |
| |||
Footage contracts |
| 311 |
| 119 |
| 136 |
| |||
Daywork contracts |
| 5,626 |
| 3,681 |
| 4,959 |
| |||
Total revenue days |
| 8,764 |
| 6,419 |
| 5,384 |
| |||
|
|
|
|
|
|
|
| |||
Contract drilling revenue per revenue day |
| $ | 12,309 |
| $ | 12,492 |
| $ | 12,747 |
|
Contract drilling cost per revenue day |
| $ | 10,099 |
| $ | 11,033 |
| $ | 8,571 |
|
Rig utilization rates |
| 88 | % | 79 | % | 82 | % |
Our contract drilling revenues forgrew by approximately 35% in fiscal 2004 from fiscal 2003, due to an improvement in rig revenue rates, a 37% 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 year ended March 31, 2003 increasedgrew by $11,556,000, or 17%, from fiscal 2002 due to $80,183,486 from $68,627,486 for the fiscal year ended March 31, 2002. This increase primarily resulted from an approximatelya 19% increase in revenue days, an increase in the number of rigs in our fleet and a higher percentage of turnkey contracts, partially offset by a decrease in rig revenue rates. contracts.
Our contract drilling revenues increased to $68,627,486 forcosts grew by approximately $17,681,000, or 25%, in fiscal 20022004 from $50,344,909 for fiscal 2001 principally2003 due to an increase in revenue rates and a 55%the increase in revenue days, due to more rigs.rig utilization and the number of rigs in our fleet. The increase in daywork revenue days resulted in a $934 decrease in contract drilling costs per revenue day because costs associated with the drilling of daywork contracts is less than costs associated with turnkey and footage contracts. Under daywork contracts, our customer provides supplies and materials such as fuel, drill bits, casing, drilling fluids, etc.
Our contract drilling costs forin fiscal 2003 grew by approximately $24,678,000, or 53%, due primarily to the fiscal year ended March 31, 2003 increased to $70,823,310 from $46,145,364 for the 2002 fiscal year. The percentage increase in revenue days, increase in number of rigs and the additional costs associated with turnkey contracts account for the substantial increase in our drilling coststurnkey contracts. The increase in 2003. Our contract drilling costs increasedper day of $2,462 in 2003 from 2002 is due to $46,145,364 for fiscal 2002 from $41,687,893 for fiscal 2001. Contract
drilling costs for the year ended March 31, 2002 include a $275,000 charge related to severance costs for a corporate officer. In addition, as previously reported, one of our former employees, Jesse J. Sanchez, filed a petition against usincrease in the District Court for the 341st District in Webb County, Texas. The petition asserted a claim for injuries resulting from an accident involving one of our drilling rigs. On December 19, 2001, we settled this claim for $500,000. The cost of this settlement is also included in our contract drilling costs for the fiscal year ended March 31, 2002.turnkey contracts.
Our depreciation and amortization expense in 2004 increased by approximately $4,200,000, or 35%, from 2003. Depreciation and amortization expense in 2003 increased to approximately $11,960,000$3,534,000, or 42%, from approximately $8,426,0002002. The increase in 20022004 over 2003 resulted from our addition of eleven drilling rigs and approximately $3,738,000related equipment in 2001.2004. The increasesincrease in 2003 over 2002 and 2002 over 2001 resulted from our addition of four drilling rigs and related equipment in each of the years ended March 31, 2003 and 2002.during 2003.
Our general and administrative expenses decreased toincreased by approximately $2,232,000$541,000, or 24%, in 2003the year ended March 31, 2004 from approximately $2,855,000 in 2002.the corresponding period of 2003. The decrease resulted from reduced payroll costs, legal and professional fees and investor relation costs. The increase in 2002 from approximately $1,117,000 in 2001 resulted from increased payroll costs, employment fees, loan fees, insurance costs and director fees. In 2004, payroll cost increased by approximately $310,000 due to pay raises and the increase from 12 to 17 employees in our corporate office. Employment and loan fees increased by $61,000 due to the employee additions and fees associated with the Merrill Lynch Capital loan. In addition, our directors’ and officers’ liability and employment practices insurance increased by approximately $60,000 and directors’ fees increased by approximately $93,000.
The approximately $623,000 decrease in general and administrative expenses in 2003 from 2002 is due to reduced payroll costs of approximately $269,000 and lower legal and professional fees and investor relations costs.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
Our contract land drilling operations are subject to various federal and state laws and regulations designed to protect the environment. Maintaining compliance with these regulations is part of our day-to-day operating procedures. We monitor each of our yard facilities and each of our rig locations on a dailyday-to-day basis for potential environmental spill risks. In addition, we maintain a spill prevention control and countermeasures plan for each yard facility and each rig location. The costcosts of these procedures represent only a small portion of our routine employee training, equipment maintenance and job site maintenance costs. We estimate ourthe annual compliance costs for this program is approximately $116,000.$143,000. We are not aware of any potential clean-up obligations that would have a material adverse effect on our financial condition or results of operations.
Our effective income tax expense rates of 30.4%19.2%, 30.4% and 35.1% for 2004, 2003 and 29.6% for 2003, 2002, and 2001respectively, differ from the federal statutory rate of 34% due to permanent differences. Permanent differences are costs included in results of operations in the accompanying financial statements which are not fully deductible for federal income tax purposes.
Accounting MattersInflation
In June 2001, the Financial Accounting Standards Board issued Statement of Financial Accounting Standards ("SFAS") No. 143, "Accounting for Asset Retirement Obligations," which addresses financial accounting and reporting for obligations associated with the retirement of tangible long-lived assets and the associated asset retirement costs. The standard applies to legal obligations associated with the retirement of long-lived assets that result from the acquisition, construction, development and/or normal use of the asset. We are required to adopt the provisions of SFAS No. 143 beginning April 1, 2003. In that connection, we must identify all our legal obligations relating to asset retirements and determine the fair value of these obligations on the date of adoption. We do not expect the adoption of SFAS No. 143 to have a material effect on our financial position or results of operations.
In December 2002, the FASB issued SFAS No. 148, "Accounting for Stock-Based Compensation—Transition and Disclosure, an amendment of FASB Statement No. 123." This Statement amends FASB Statement No. 123, "Accounting for Stock-Based Compensation," to provide alternative methods of transition for a voluntary change to the fair value method of accounting for stock-based employee compensation. In addition, this Statement amends the disclosure requirements of Statement No. 123 to require prominent disclosures in both annual and interim financial statements. Certain of the disclosure modifications are required for fiscal years ending after December 15, 2002 and are included in the notes to the consolidated financial statements included in this report.
Inflation
As a result of the relatively low levels of inflation during the past threetwo years, inflation did not significantly affect our results of operations in any of our last three fiscal years.the periods reported.
Off Balance Sheet Arrangements
We do not currently have any off balance sheet arrangements.
We are subject to market risk exposure related to changes in interest rates on most of our outstanding debt. At March 31, 2003,2004, we had outstanding debt of approximately $20,178,000$20,511,000 that was subject to variable interest rates, in each case based on an agreed percentage-point spread from the lender'slender’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 $133,000$135,000 annually. We did not enter into any of these debt arrangements for trading purposes.
26
Item 8.Financial Statements and Supplementary Data
PIONEER DRILLING COMPANY
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
27
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, 20032004 and 20022003 and the related consolidated statements of operations, shareholders'shareholders’ equity and comprehensive income and cash flows for each of the years in the three-year period ended March 31, 2003.2004. These consolidated financial statements are the responsibility of the Company'sCompany’s management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatements. 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, 20032004 and 2002,2003, and the results of their operations and their cash flows for each of the years in the three-year period ended March 31, 2003,2004, in conformity with U.S.U. S. generally accepted accounting principles.
KPMG LLP |
San Antonio, Texas |
28
PIONEER DRILLING COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
|
| March 31, |
| ||||
|
| 2004 |
| 2003 |
| ||
ASSETS |
|
|
|
|
| ||
Current assets: |
|
|
|
|
| ||
Cash and cash equivalents |
| $ | 6,365,759 |
| $ | 21,002,913 |
|
Receivables: |
|
|
|
|
| ||
Trade, net |
| 10,901,991 |
| 4,499,378 |
| ||
Contract drilling in progress |
| 9,130,794 |
| 4,429,545 |
| ||
Federal income tax receivable |
| — |
| 444,900 |
| ||
Current deferred income taxes |
| 285,384 |
| 180,991 |
| ||
Prepaid expenses |
| 1,336,337 |
| 914,187 |
| ||
Total current assets |
| 28,020,265 |
| 31,471,914 |
| ||
Property and equipment, at cost: |
|
|
|
|
| ||
Drilling rigs and equipment |
| 145,758,913 |
| 106,728,573 |
| ||
Transportation, office, land and other |
| 5,427,637 |
| 3,494,657 |
| ||
|
| 151,186,550 |
| 110,223,230 |
| ||
Less accumulated depreciation and amortization |
| 35,844,938 |
| 22,367,327 |
| ||
Net property and equipment |
| 115,341,612 |
| 87,855,903 |
| ||
Other assets |
| 369,278 |
| 366,500 |
| ||
Total assets |
| $ | 143,731,155 |
| $ | 119,694,317 |
|
|
|
|
|
|
| ||
LIABILITIES AND SHAREHOLDERS’ EQUITY |
|
|
|
|
| ||
Current liabilities: |
|
|
|
|
| ||
Notes payable |
| $ | 558,070 |
| $ | 587,177 |
|
Current installments of long-term debt |
| 3,724,302 |
| 2,671,269 |
| ||
Current installments of capital lease obligations |
| 140,934 |
| 140,717 |
| ||
Accounts payable |
| 13,270,989 |
| 14,206,586 |
| ||
Accrued expenses: |
|
|
|
|
| ||
Payroll and payroll taxes |
| 1,499,151 |
| 847,163 |
| ||
Other |
| 2,798,801 |
| 1,874,693 |
| ||
Total current liabilities |
| 21,992,247 |
| 20,327,605 |
| ||
Long-term debt, less current installments |
| 44,786,920 |
| 45,594,517 |
| ||
Capital lease obligations, less current installments |
| 104,754 |
| 260,025 |
| ||
Deferred income taxes |
| 6,010,916 |
| 5,839,908 |
| ||
Total liabilities |
| 72,894,837 |
| 72,022,055 |
| ||
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 |
| ||
Additional paid-in capital |
| 82,124,368 |
| 57,730,188 |
| ||
Accumulated deficit |
| (14,018,062 | ) | (12,228,005 | ) | ||
Total shareholders’ equity |
| 70,836,318 |
| 47,672,262 |
| ||
Total liabilities and shareholders’ equity |
| $ | 143,731,155 |
| $ | 119,694,317 |
|
See accompanying notes to consolidated financial statements.PIONEER DRILLING COMPANY AND SUBSIDIARIESCONSOLIDATED BALANCE SHEETS
| March 31, | ||||||||
---|---|---|---|---|---|---|---|---|---|
| 2003 | 2002 | |||||||
ASSETS | |||||||||
Current assets: | |||||||||
Cash and cash equivalents | $ | 21,002,913 | $ | 5,383,045 | |||||
Securities available for sale | — | 337,309 | |||||||
Receivables: | |||||||||
Trade, net of allowance for doubtful accounts of $110,000 in 2003 | 4,499,378 | 6,160,797 | |||||||
Contract drilling in progress | 4,429,545 | 3,120,252 | |||||||
Federal income tax receivable | 444,900 | 880,068 | |||||||
Current deferred income taxes | 180,991 | — | |||||||
Prepaid expenses | 914,187 | 634,747 | |||||||
Total current assets | 31,471,914 | 16,516,218 | |||||||
Property and equipment, at cost: | |||||||||
Drilling rigs and equipment | 106,728,573 | 77,149,043 | |||||||
Transportation, office, land and other | 3,494,657 | 3,203,979 | |||||||
110,223,230 | 80,353,022 | ||||||||
Less accumulated depreciation and amortization | 22,367,327 | 13,621,396 | |||||||
Net property and equipment | 87,855,903 | 66,731,626 | |||||||
Other assets | 366,500 | 201,914 | |||||||
Total assets | $ | 119,694,317 | $ | 83,449,758 | |||||
LIABILITIES AND SHAREHOLDERS' EQUITY | |||||||||
Current liabilities: | |||||||||
Notes payable | $ | 587,177 | $ | 6,329,925 | |||||
Current installments of long-term debt | 2,671,269 | 1,836,860 | |||||||
Current installments of capital lease obligations | 140,717 | 109,129 | |||||||
Accounts payable | 14,206,586 | 6,507,169 | |||||||
Current deferred income taxes | — | 23,571 | |||||||
Accrued expenses: | |||||||||
Payroll and payroll taxes | 847,163 | 792,805 | |||||||
Other | 1,874,693 | 1,185,237 | |||||||
Total current liabilities | 20,327,605 | 16,784,696 | |||||||
Long-term debt, less current installments | 45,594,517 | 25,829,610 | |||||||
Capital lease obligations, less current installments | 260,025 | 288,991 | |||||||
Deferred income taxes | 5,839,908 | 7,203,456 | |||||||
Total liabilities | 72,022,055 | 50,106,753 | |||||||
Shareholders' equity: | |||||||||
Preferred stock, 10,000,000 shares authorized; none issued and outstanding | |||||||||
Common stock $.10 par value; 100,000,000 shares authorized; 21,700,792 shares and 15,922,459 shares issued and outstanding at March 31, 2003 and March 31,2002, respectively | 2,170,079 | 1,592,245 | |||||||
Additional paid-in capital | 57,730,188 | 38,783,731 | |||||||
Accumulated deficit | (12,228,005 | ) | (7,142,387 | ) | |||||
Accumulated other comprehensive income-unrealized gain on securities available for sale | — | 109,416 | |||||||
Total shareholders' equity | 47,672,262 | 33,343,005 | |||||||
Total liabilities and shareholders' equity | $ | 119,694,317 | $ | 83,449,758 | |||||
See accompanying notes to consolidated financial statements.
PIONEER DRILLING COMPANY AND SUBSIDIARIESCONSOLIDATED STATEMENTS OF OPERATIONS
| Years Ended March 31, | ||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|
| 2003 | 2002 | 2001 | ||||||||
Contract drilling Revenues | $ | 80,183,486 | $ | 68,627,486 | $ | 50,344,909 | |||||
Costs and expenses: | |||||||||||
Contract drilling | 70,823,310 | 46,145,364 | 41,687,893 | ||||||||
Depreciation and amortization | 11,960,387 | 8,426,082 | 3,737,533 | ||||||||
General and administrative | 2,232,390 | 2,855,274 | 1,116,727 | ||||||||
Bad debt expense | 110,000 | — | — | ||||||||
Total operating costs and expenses | 85,126,087 | 57,426,720 | 46,542,153 | ||||||||
Earnings (loss) from operations | (4,942,601 | ) | 11,200,766 | 3,802,756 | |||||||
Other income (expense): | |||||||||||
Interest expense | (2,698,529 | ) | (1,616,984 | ) | (888,863 | ) | |||||
Interest income | 94,235 | 80,932 | 316,025 | ||||||||
Other | 37,614 | 72,096 | 71,559 | ||||||||
Gain on sale of securities | 203,887 | — | 536,486 | ||||||||
Total other income (expense) | (2,362,793 | ) | (1,463,956 | ) | 35,207 | ||||||
Earnings (loss) before income taxes | (7,305,394 | ) | 9,736,810 | 3,837,963 | |||||||
Income tax (expense) benefit | 2,219,776 | (3,418,525 | ) | (1,135,174 | ) | ||||||
Net earnings (loss) | (5,085,618 | ) | 6,318,285 | 2,702,789 | |||||||
Preferred stock dividend requirement | — | 92,814 | 274,630 | ||||||||
Net earnings (loss) applicable to common shareholders | $ | (5,085,618 | ) | $ | 6,225,471 | $ | 2,428,159 | ||||
Earnings (loss) per common share—Basic | $ | (0.31 | ) | $ | 0.41 | $ | 0.22 | ||||
Earnings (loss) per common share—Diluted | $ | (0.31 | ) | $ | 0.35 | $ | 0.19 | ||||
Weighted average number of shares outstanding—Basic | 16,163,098 | 15,112,272 | 11,137,171 | ||||||||
Weighted average number of shares outstanding—Diluted | 16,163,098 | 19,221,256 | 13,901,101 | ||||||||
See accompanying notes to consolidated financial statements.
PIONEER DRILLING COMPANY AND SUBSIDIARIESCONSOLIDATED 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 | ||||||||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
Balance as of March 31, 2000 | 7,274,684 | 584,615 | $ | 727,468 | $ | 3,799,994 | $ | 17,723,569 | $ | (15,796,017 | ) | $ | 328,478 | $ | 6,783,492 | |||||||||
Comprehensive income: | ||||||||||||||||||||||||
Net earnings | — | — | — | — | — | 2,702,789 | — | 2,702,789 | ||||||||||||||||
Net unrealized change in securities available for sale, net of tax of $56,750 | — | — | — | — | — | — | (218,360 | ) | (218,360 | ) | ||||||||||||||
Total comprehensive income | — | — | — | — | — | — | — | 2,484,429 | ||||||||||||||||
Issuance of common stock for: | ||||||||||||||||||||||||
Sale, net of related expenses | 3,678,161 | — | 367,816 | — | 7,632,184 | — | — | 8,000,000 | ||||||||||||||||
Acquisition | 341,576 | — | 34,158 | — | 734,387 | — | — | 768,545 | ||||||||||||||||
Conversion of preferred | 800,000 | (400,000 | ) | 80,000 | (800,000 | ) | 720,000 | — | — | — | ||||||||||||||
Exercise of options | 51,500 | — | 5,150 | — | 59,776 | — | — | 64,926 | ||||||||||||||||
Preferred stock dividend | — | — | — | — | — | (274,630 | ) | — | (274,630 | ) | ||||||||||||||
Balance as of March 31, 2001 | 12,145,921 | 184,615 | 1,214,592 | 2,999,994 | 26,869,916 | (13,367,858 | ) | 110,118 | 17,826,762 | |||||||||||||||
Comprehensive income: | ||||||||||||||||||||||||
Net earnings | — | — | — | — | — | 6,318,285 | — | 6,318,285 | ||||||||||||||||
Net unrealized change in securities available for sale, net of tax of $384 | — | — | — | — | — | — | (702 | ) | (702 | ) | ||||||||||||||
Total comprehensive income | — | — | — | — | — | — | — | 6,317,583 | ||||||||||||||||
Issuance of common stock for: | ||||||||||||||||||||||||
Sale, net of related expenses | 2,400,000 | — | 240,000 | — | 8,808,000 | — | — | 9,048,000 | ||||||||||||||||
Conversion of preferred | 1,199,038 | (184,615 | ) | 119,903 | (2,999,994 | ) | 2,880,091 | — | — | — | ||||||||||||||
Exercise of options | 177,500 | — | 17,750 | — | 225,724 | — | — | 243,474 | ||||||||||||||||
Preferred stock dividend | — | — | — | — | — | (92,814 | ) | — | (92,814 | ) | ||||||||||||||
Balance as of March 31, 2002 | 15,922,459 | — | 1,592,245 | — | 38,783,731 | (7,142,387 | ) | 109,416 | 33,343,005 | |||||||||||||||
Comprehensive income: | ||||||||||||||||||||||||
Net loss | — | — | — | — | — | (5,085,618 | ) | — | (5,085,618 | ) | ||||||||||||||
Net unrealized change in securities available for sale, net of tax of $56,366 | — | — | — | — | — | — | (109,416 | ) | (109,416 | ) | ||||||||||||||
Total comprehensive loss | — | — | — | — | — | — | — | (5,195,034 | ) | |||||||||||||||
Issuance of common stock for: | ||||||||||||||||||||||||
Sale, net of related expenses | 5,333,333 | — | 533,334 | — | 18,809,167 | — | — | 19,342,501 | ||||||||||||||||
Exercise of options and related income tax benefits | 445,000 | — | 44,500 | — | 137,290 | — | — | 181,790 | ||||||||||||||||
Balance as of March 31, 2003 | 21,700,792 | — | $ | 2,170,079 | $ | — | $ | 57,730,188 | $ | (12,228,005 | ) | $ | — | $ | 47,672,262 | |||||||||
See accompanying notes to consolidated financial statements.
PIONEER DRILLING COMPANY AND SUBSIDIARIESCONSOLIDATED STATEMENTS OF CASH FLOWS
| Years Ended March 31, | ||||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| 2003 | 2002 | 2001 | ||||||||||
Cash flows from operating activities: | |||||||||||||
Net earnings (loss) | $ | (5,085,618 | ) | $ | 6,318,285 | $ | 2,702,789 | ||||||
Adjustments to reconcile net earnings (loss) to net cash provided by operating activities: | |||||||||||||
Depreciation and amortization | 11,960,387 | 8,426,082 | 3,737,533 | ||||||||||
Allowance for doubtful accounts | 110,000 | — | — | ||||||||||
Gain on sale of securities | (203,887 | ) | — | (536,486 | ) | ||||||||
Loss (gain) on sale of properties and equipment | 279,054 | (2,237 | ) | — | |||||||||
Change in deferred income taxes | (1,511,744 | ) | 1,991,458 | 965,008 | |||||||||
Changes in current assets and liabilities: | |||||||||||||
Receivables | 242,126 | (4,172,470 | ) | (3,157,961 | ) | ||||||||
Prepaid expenses | (279,440 | ) | (322,471 | ) | 177,676 | ||||||||
Accounts payable | 7,699,417 | (1,099,813 | ) | 3,642,048 | |||||||||
Federal income taxes | 435,168 | (930,266 | ) | 50,198 | |||||||||
Accrued expenses | 743,814 | 836,321 | 853,045 | ||||||||||
Net cash provided by operating activities | 14,389,277 | 11,044,889 | 8,433,850 | ||||||||||
Cash flows from financing activities: | |||||||||||||
Proceeds from notes payable | 23,573,501 | 19,556,286 | 15,547,477 | ||||||||||
Proceeds from subordinated debenture | 10,000,000 | 18,000,000 | 9,000,000 | ||||||||||
Increase in other assets | (253,698 | ) | (195,000 | ) | (46,322 | ) | |||||||
Payment of preferred dividends | — | (859,395 | ) | (160,614 | ) | ||||||||
Proceeds from exercise of options and warrants | 181,790 | 243,474 | 64,926 | ||||||||||
Proceeds from common stock, net | 19,342,501 | 9,048,000 | 8,000,000 | ||||||||||
Payments of debt | (18,714,311 | ) | (27,026,538 | ) | (6,336,803 | ) | |||||||
Net cash provided by financing activities | 34,129,783 | 18,766,827 | 26,068,664 | ||||||||||
Cash flows from investing activities: | |||||||||||||
Purchases of property and equipment: | |||||||||||||
Acquisitions | — | — | (22,806,456 | ) | |||||||||
Other | (33,588,972 | ) | (27,597,265 | ) | (12,165,178 | ) | |||||||
Proceeds from sale of marketable securities | 375,414 | — | 1,039,597 | ||||||||||
Proceeds from sale of property and equipment | 314,366 | 675,660 | — | ||||||||||
Net cash used in investing activities | (32,899,192 | ) | (26,921,605 | ) | (33,932,037 | ) | |||||||
Net increase in cash and cash equivalents | 15,619,868 | 2,890,111 | 570,477 | ||||||||||
Beginning cash and cash equivalents | 5,383,045 | 2,492,934 | 1,922,457 | ||||||||||
Ending cash and cash equivalents | $ | 21,002,913 | $ | 5,383,045 | $ | 2,492,934 | |||||||
Supplementary disclosure: | |||||||||||||
Interest paid | $ | 2,785,177 | $ | 1,046,943 | $ | 760,821 | |||||||
Income taxes paid (refunded) | (1,143,200 | ) | 2,342,006 | 140,655 | |||||||||
Dividends accrued | — | 92,814 | 274,630 | ||||||||||
Conversion of preferred stock | — | 2,999,994 | 800,000 | ||||||||||
Pioneer Drilling Co. acquisition: | |||||||||||||
Common Stock issued | — | — | 768,545 | ||||||||||
Debt assumed | — | — | 1,673,533 | ||||||||||
Deferred taxes assumed | — | — | 4,214,195 |
See accompanying notes to consolidated financial statements.
PIONEER DRILLING COMPANY AND SUBSIDIARIESNOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. Organization and Summary of Significant Accounting Policies
Business and Principles of Consolidation
29
PIONEER DRILLING COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
|
| Years Ended March 31, |
| |||||||
|
| 2004 |
| 2003 |
| 2002 |
| |||
|
|
|
|
|
|
|
| |||
Contract drilling revenues |
| $ | 107,875,533 |
| $ | 80,183,486 |
| $ | 68,627,486 |
|
|
|
|
|
|
|
|
| |||
Costs and expenses: |
|
|
|
|
|
|
| |||
Contract drilling |
| 88,504,102 |
| 70,823,310 |
| 46,145,364 |
| |||
Depreciation and amortization |
| 16,160,494 |
| 11,960,387 |
| 8,426,082 |
| |||
General and administrative |
| 2,772,730 |
| 2,232,390 |
| 2,855,274 |
| |||
Bad debt expense |
| — |
| 110,000 |
| — |
| |||
|
|
|
|
|
|
|
| |||
Total operating costs and expenses |
| 107,437,326 |
| 85,126,087 |
| 57,426,720 |
| |||
Income (loss) from operations |
| 438,207 |
| (4,942,601 | ) | 11,200,766 |
| |||
|
|
|
|
|
|
|
| |||
Other income (expense): |
|
|
|
|
|
|
| |||
Interest expense |
| (2,807,822 | ) | (2,698,529 | ) | (1,616,984 | ) | |||
Interest income |
| 101,584 |
| 94,235 |
| 80,932 |
| |||
Other |
| 51,675 |
| 37,614 |
| 72,096 |
| |||
Gain on sale of securities |
| — |
| 203,887 |
| — |
| |||
Total other income (expense) |
| (2,654,563 | ) | (2,362,793 | ) | (1,463,956 | ) | |||
|
|
|
|
|
|
|
| |||
Income (loss) before income taxes |
| (2,216,356 | ) | (7,305,394 | ) | 9,736,810 |
| |||
Income tax (expense) benefit |
| 426,299 |
| 2,219,776 |
| (3,418,525 | ) | |||
|
|
|
|
|
|
|
| |||
Net earnings (loss) |
| (1,790,057 | ) | (5,085,618 | ) | 6,318,285 |
| |||
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 |
|
|
|
|
|
|
|
|
| |||
Earnings (loss) per common share - Diluted |
| $ | (0.08 | ) | $ | (0.31 | ) | $ | 0.35 |
|
|
|
|
|
|
|
|
| |||
Weighted average number of shares outstanding - Basic |
| 22,585,612 |
| 16,163,098 |
| 15,112,272 |
| |||
|
|
|
|
|
|
|
| |||
Weighted average number of shares outstanding - Diluted |
| 22,585,612 |
| 16,163,098 |
| 19,221,256 |
|
See accompanying notes to consolidated financial statements.
30
PIONEER DRILLING COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF SHAREHOLDERS’ EQUITY AND COMPREHENSIVE INCOME
|
| Shares |
| Shares |
| Amount |
| Preferred |
| Additional |
| Accumulated |
| Accumulated |
| Total |
| ||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||
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 |
| ||||||
Comprehensive income: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||
Net loss |
| — |
| — |
| — |
| — |
| — |
| (1,790,057 | ) | — |
| (1,790,057 | ) | ||||||
Total comprehensive loss |
| — |
| — |
| — |
| — |
| — |
| — |
| — |
| (1,790,057 | ) | ||||||
Issuance of common stock for: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||
Sale, net of related expenses of $1,654,753 |
| 4,400,000 |
| — |
| 440,000 |
| — |
| 21,665,247 |
| — |
| — |
| 22,105,247 |
| ||||||
Equipment acquisitions |
| 477,000 |
| — |
| 47,700 |
| — |
| 2,074,950 |
| — |
| — |
| 2,122,650 |
| ||||||
Exercise of options and related income tax benefits |
| 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 |
|
See accompanying notes to consolidated financial statements.
31
PIONEER DRILLING COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
|
| Years Ended March 31, |
| |||||||
|
| 2004 |
| 2003 |
| 2002 |
| |||
Cash flows from operating activities: |
|
|
|
|
|
|
| |||
Net earnings (loss) |
| $ | (1,790,057 | ) | $ | (5,085,618 | ) | $ | 6,318,285 |
|
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 |
| |||
Allowance for doubtful accounts |
| — |
| 110,000 |
| — |
| |||
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 |
| |||
Changes in current assets and liabilities: |
|
|
|
|
|
|
| |||
Receivables |
| (11,103,862 | ) | 242,126 |
| (4,172,470 | ) | |||
Prepaid expenses |
| (422,150 | ) | (279,440 | ) | (322,471 | ) | |||
Accounts payable |
| (935,597 | ) | 7,699,417 |
| (1,099,813 | ) | |||
Federal income taxes |
| 444,900 |
| 435,168 |
| (930,266 | ) | |||
Accrued expenses |
| 1,576,096 |
| 743,814 |
| 836,321 |
| |||
Net cash provided by operating activities |
| 4,864,966 |
| 14,389,277 |
| 11,044,889 |
| |||
|
|
|
|
|
|
|
| |||
Cash flows from financing activities: |
|
|
|
|
|
|
| |||
Proceeds from notes payable |
| 4,110,019 |
| 23,573,501 |
| 19,556,286 |
| |||
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 |
| |||
Payments of debt |
| (4,048,744 | ) | (18,714,311 | ) | (27,026,538 | ) | |||
Net cash provided by financing activities |
| 22,800,316 |
| 34,129,783 |
| 18,766,827 |
| |||
Cash flows from investing activities: |
|
|
|
|
|
|
| |||
Purchases of property and equipment |
| (42,722,094 | ) | (33,588,972 | ) | (27,597,265 | ) | |||
Proceeds from sale of marketable securities |
| — |
| 375,414 |
| — |
| |||
Proceeds from sale of property and equipment |
| 419,658 |
| 314,366 |
| 675,660 |
| |||
Net cash used in investing activities |
| (42,302,436 | ) | (32,899,192 | ) | (26,921,605 | ) | |||
Net increase (decrease) in cash and cash equivalents |
| (14,637,154 | ) | 15,619,868 |
| 2,890,111 |
| |||
Beginning cash and cash equivalents |
| 21,002,913 |
| 5,383,045 |
| 2,492,934 |
| |||
Ending cash and cash equivalents |
| $ | 6,365,759 |
| $ | 21,002,913 |
| $ | 5,383,045 |
|
Supplementary disclosure: |
|
|
|
|
|
|
| |||
Interest paid |
| $ | 2,821,041 |
| $ | 2,785,177 |
| $ | 1,046,943 |
|
Income taxes paid (refunded) |
| (990,237 | ) | (1,143,200 | ) | 2,342,006 |
| |||
Dividends accrued |
| — |
| — |
| 92,814 |
| |||
Conversion of preferred stock |
| — |
| — |
| 2,999,994 |
| |||
Acquisition - common stock issued |
| 2,122,650 |
| — |
| — |
| |||
Tax benefit from exercise of nonqualified options |
| 52,423 |
| 2,720 |
| — |
|
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 oil and gas exploration and production companies in the North, South and East Texas markets. 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. 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 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, “Accounting for Stock-Based Compensation.” SFAS No. 123 allows a company to adopt a fair value based method of accounting for a stock-based employee compensation plan or to continue to use the intrinsic value based method of accounting prescribed by Accounting Principles Board (“APB”) Opinion No. 25, “Accounting for Stock Issued to Employees.” We have elected to continue accounting for stock-based compensation under the intrinsic value 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 |
|
We estimate the fair value of each option grant on the date of grant using a Black-Scholes options-pricing model. This model assumed expected volatility of 94%, 69% 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. As we have not declared dividends since we became a public company, we did not use a dividend yield. In each case, the actual value that will be realized, if any, will depend on the future performance of our common stock and overall stock market conditions. There is no assurance the value an optionee actually realizes will be at or near the value we have estimated using the Black-Scholes model.
Revenue and Cost Recognition
We earn our contract drilling revenues under daywork, turnkey and footage contracts. We recognize revenues on daywork contracts for the days completed based on the dayrate each contract specifies. We recognize revenues from our turnkey and footage contracts on the percentage-of-completion method based on our estimate of the number of days to complete each well. Individual wells are usually completed in less than 60 days.
Our management has determined that it is appropriate to use the percentage-of-completion method 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 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, including quantum meruit, available in applicable courts to recover the fair value of our work-in-progress under a turnkey or footage contract.
We accrue estimated costs on turnkey and footage contracts for each day of work completed based on our estimate of the total cost to complete the contract divided by our estimate of the number of days to complete the contract. Contract costs include labor, materials, supplies, repairs, maintenance, operating overhead allocations and allocations of depreciation and amortization
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.
Prepaid Expenses
Prepaid expenses include items such as insurance and licenses. We routinely expense these items in the normal course of business over the periods these expenses benefit.
Property and Equipment
We provide for depreciation of our drilling, transportation and other equipment using the straight-line method over useful lives that we have estimated and that range from three to 15 years. We record the same depreciation expense whether a rig is idle or working.
We charge our expenses for maintenance and repairs to operations. We charge our expenses for renewals and betterments to the appropriate property and equipment accounts. Our gains and losses on the sale of our property and equipment are recorded in drilling costs. During fiscal 2004 and 2003, we capitalized $106,395 and $96,079, respectively, of interest costs incurred during the construction periods of certain drilling equipment. At March 31, 2004 and 2003, costs incurred on rigs under construction were approximately $2,800,000 and $2,415,000, 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 cash flows we expect to obtain from the use of each asset and its eventual disposition. If the sum of these estimated future cash flows is less than the carrying amount of the asset, we recognize an impairment loss.
Cash Equivalents
For purposes of the statements of cash flows, we consider all highly liquid debt instruments purchased with a maturity of three months or less to be cash equivalents. Cash equivalents consist of investments in corporate and government money market accounts and auction rate seven day taxable preferred securities. Cash equivalents at March 31, 2004 and 2003 were $6,118,000 and $1,060,000, respectively.
Investment Securities
We carry our available-for-sale investment securities at their fair values. Investment securities consist of common stock. Unrealized holding gains and losses, net of 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 of March 31, 2002, these securities had an aggregate cost of $171,527, a gross unrealized gain of $165,782 and an aggregate fair value of $337,309. We sold all of our investment securities in April 2002, realizing a gain of $203,887.
Trade Accounts Receivable
We record trade accounts receivable at the amount we invoice our customers. These accounts do not bear interest. The allowance for doubtful accounts is our best estimate of the amount of probable credit losses in our accounts receivable as of the balance sheet date. We determine the allowance based on the credit worthiness of our customers and general economic conditions. Consequently, an adverse change in those factors could affect our estimate of our allowance for doubtful accounts. We review our allowance for doubtful accounts monthly. Balances more than 90 days past due are reviewed individually for collectibility. We charge off account balances against the allowance after we have exhausted all reasonable means of collection and determined that the potential for recovery is remote. We do not have any off-balance-sheet credit exposure related to our customers. At March 31, 2004 and 2003 our allowance for doubtful accounts was $110,000.
35
Other Assets
Other assets consist of cash deposits related to the deductibles on our workers compensation insurance policies, loan fees net of amortization and intangibles related to acquisitions, net of amortization. Loan fees are amortized over the terms of the related debt. Intangibles related to acquisitions, primarily customer lists, are amortized over their estimated benefit periods of up to 18 months.
Derivative Instruments and Hedging Activities
We do not have any free standing derivative instruments and we do not engage in hedging activities.
Recently Issued Accounting Standards
On April 1, 2003, we adopted SFAS No. 143, Accounting for Asset Retirement Obligations, which addresses financial accounting and reporting for obligations associated with the retirement of tangible long-lived assets and the associated asset retirement costs. The standard applies to legal obligations associated with the retirement of long-lived assets that result from the acquisition, construction, development and/or normal use of the asset. In that connection, we were required to identify all our legal obligations relating to asset retirements and determine the fair value of these obligations as of April 1, 2003. Our adoption of SFAS No. 143 did not have a material effect on our financial position or results of operations.
On July 1, 2003, we adopted SFAS No. 149, Amendment of Statement 133 on Derivative Instruments and Hedging Activities. This statement amends and clarifies financial accounting and reporting for derivative instruments, including certain derivative instruments in other contracts (collectively referred to as derivatives) and for hedging activities under SFAS No. 133, Accounting for Derivative Instrument and Hedging Activities. The provisions of this statement 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 securities that do not yet exist, should be applied to both existing contracts and new contracts entered into after June 30, 2003. Our adoption of SFAS No. 149 did not have a material effect on our financial position or results of operations.
On July 1, 2003, we adopted SFAS No. 150, Accounting for Certain Financial Instruments with Characteristics of Both Liabilities and Equity. This statement requires issuers to classify as liabilities (or assets in some circumstance) three classes of freestanding financial instruments that embody obligations of the issuer. The provisions of this statement are effective for financial instruments entered into or modified after May 31, 2003, and otherwise are effective at the beginning of the first interim period beginning after June 15, 2003. Our adoption of SFAS No. 150 did not have a material effect on our financial position or results of operations.
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, we acquired all the land contract drilling assets of United Drilling Company and U-D Holdings, L.P. The assets included two land drilling rigs, associated spare parts and equipment and vehicles. We paid $7,000,000 in cash for these assets. The purchase was accounted for as an acquisition of assets, and the purchase price was allocated to drilling equipment and related assets based on their relative fair values at the date of acquisition.
On August 1, 2003, we purchased two land drilling rigs, associated spare parts and equipment and vehicles from Texas Interstate Drilling Company, L. P. for $2,500,000 in cash and the issuance of 477,000 shares of our common stock at $4.45 per share. The purchase was accounted for as an acquisition of a business, and we have included the results of operations of these assets in our statement of operations since the date of acquisition. We allocated the purchase price to drilling equipment and related assets, including intangibles, based on their relative fair values at the date of acquisition.
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 of assets, and the purchase price was allocated to the trucks and related assets based on their relative fair values at the date of acquisition.
On March 4, 2004, we acquired a seven-rig drilling fleet from Sawyer Drilling & Services, Inc. for $12,000,000. This purchase was accounted for as an acquisition of a business, and we have included the results of operations of these assets in our statement of operations since the date of acquisition. We allocated the purchase price to drilling equipment and related assets, including intangibles, based on their relative fair values at the date of acquisition.
On March 12, 2004, we acquired one drilling rig from SEDCO Drilling Co., Ltd. for $2,015,000. This purchase was accounted for as an acquisition of assets, and we have included the results of operations of these assets in our statement of operations since the date of acquisition. We allocated the purchase price to drilling equipment and related assets, including intangibles, based on their relative fair values at the date of acquisition.
3.Long-term Debt, Subordinated Debt and Note Payable
Our long-term debt is described below:
|
| March 31, |
| ||||
|
| 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 |
|
(1) Wedge Energy Services, LLC (“WEDGE”) holds $27,000,000 of the 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 |
|
|
| |
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. On July 3, 2002, we issued an additional $10,000,000 of 6.75% convertible subordinated debt to WEDGE with an effective conversion rate of $5.00 per share. The transaction was effected by an agreement between Pioneer and WEDGE under which WEDGE agreed to provide the additional $10,000,000 in financing and to cancel the previously issued debenture in the principal amount of $18,000,000 in exchange for $28,000,000 in new 6.75% convertible subordinated debentures. The new debentures are convertible into 6,500,000 shares of common stock at $4.31 per share, which resulted from a pro rata blending of the $5.00 conversion rate of the new $10,000,000 financing and the $4.00 conversion rate of the $18,000,000 debenture being cancelled. WEDGE funded $7,000,000 of the $10,000,000 on July 3, 2002 and $2,000,000 on July 29, 2002. William H. White, a former Director of our Company and the former President of WEDGE, purchased the remaining $1,000,000 on July 29, 2002. Unlike the cancelled debenture, which was not redeemable by Pioneer, the new debentures are redeemable at a scheduled premium. We used $7,000,000 of the proceeds to pay down bank debt and $3,000,000 for the purchase of drilling equipment.
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% 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.
Notes payable at March 31, 2004 consists of a $558,070 insurance premium note due in monthly installments of $112,355 through August 26, 2004 which bears interest at the rate of 2.65% 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.
Rent expense under these operating leases for the years ended March 31, 2004, 2003 and 2002 was $278,746, $344,752 and $208,150, respectively.
Future lease obligations and minimum capital lease payments as of March 31, 2004 were as follows:
Year Ended |
| Operating |
| Capital |
| ||
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 |
|
5.Income Taxes
Our provision for income taxes consists of the following:
|
| Years Ended March 31, |
| |||||||
|
| 2004 |
| 2003 |
| 2002 |
| |||
|
|
|
|
|
|
|
| |||
Current tax - federal |
| $ | — |
| $ | (708,032 | ) | $ | 1,427,067 |
|
Deferred tax - federal |
| (426,299 | ) | (1,511,744 | ) | 1,991,458 |
| |||
Income tax expense (benefit) |
| $ | (426,299 | ) | $ | (2,219,776 | ) | $ | 3,418,525 |
|
In fiscal years 2004, 2003 and 2002, our expected tax, which we compute by applying the federal statutory rate of 34% to income (loss) before income taxes, differs from our income tax expense as follows:
|
| Years Ended March 31, |
| |||||||
|
| 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
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 |
|
In assessing our ability to realize deferred tax assets, we consider whether it is more likely than not that some portion or all of the deferred tax assets will not be realized. Our ultimate realization of deferred tax assets depends on the generation of future taxable income during the periods in which those temporary differences become deductible. We consider the scheduled reversal of deferred tax liabilities, projected future taxable income, and tax planning strategies in making this assessment. Based on the level of historical taxable income and projections for future taxable income over the periods during which the deferred tax assets are deductible, we believe it is more likely than not that we will realize the benefits of these deductible differences.
At March 31, 2004, we had net operating loss carryforwards for federal income tax purposes of approximately $25,500,000 which will expire if not utilized as of the end of our fiscal years ending as follows:
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 |
|
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.
8.Equity Transactions
On May 18, 2001, we retired the 4.86% subordinated debenture we issued to WEDGE on March 30, 2001 in connection with the Mustang Drilling, Ltd. acquisition. We funded the repayment of the $9,000,000 face amount of the debenture, together with the payment of $59,535 of accrued interest, with a short-term bank borrowing. We then sold 2,400,000 shares of our common stock to WEDGE in a private placement for $9,048,000, or $3.77 per share. We used the proceeds from this sale to fund the repayment of the short-term bank borrowing.
In accordance with the terms of the Series B Preferred Stock Agreement that we entered into on January 20, 1998, the conversion price for our Series B convertible preferred stock was revised from $3.25 per share to $2.50 per share as of January 20, 2001. This revision was based on the average trading price of our common stock for the 30 trading days preceding that date. In August 2001, the holders converted all of their 184,615 shares of our Series B convertible preferred stock into 1,199,038 shares of our common stock at $2.50 per share.
On May 31, 2001, San Patricio Corporation exercised its option to acquire 150,000 shares of our common stock for $225,000 ($1.50 per share).
On March 31, 2003, we sold 5,333,333 shares of our common stock to Chesapeake Energy Corporation for $20,000,000 ($3.75 per share), before related offering expenses. In connection with that sale, we granted Chesapeake Energy a preemptive right
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 March 31, 2004, we recognized revenues of approximately $924,000 and recorded contract drilling costs of approximately $745,000, excluding depreciation, on one daywork contract with Chesapeake Energy Corporation. Although our normal payment terms are 30 days from date of invoice, Chesapeake Energy Corporation requires 60 day payment terms.
On February 20, 2004, we sold 4,400,000 shares of our common stock at $5.40 per share in a private placement for $23,760,000 in proceeds, before related offering expenses. 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.
Directors and employees exercised stock options for the purchase of 722,334 shares of common stock at prices ranging from $.625 to $3.20 per share during the 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.
9.Stock Options, Warrants and Stock Option Plan
Under our stock option plans, employee stock options generally become exercisable over three to five-year periods, and all options generally expire 10 years after the date of grant. Our plans provide that all options must have an exercise price not less than the fair market value of our common stock on the date of grant. Accordingly, as we discussed in Note 1, we do not recognize any compensation expense relating to these options in our results of operations.
The following table provides information relating to our outstanding stock options at March 31, 2004, 2003 and 2002:
|
| 2004 |
| 2003 |
| 2002 |
| |||||||||
|
| Shares |
| Exercise |
| Shares |
| Exercise |
| Shares |
| Exercise |
| |||
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 |
|
|
|
As of March 31, 2004, there were no outstanding warrants.
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.
10.Employee BenefitPlans and Insurance
We maintain a 401(k) retirement plan for our eligible employees. Under this plan, we may contribute, on a discretionary basis, a percentage of an eligible employee’s annual contribution, which we determine annually. Our contributions for fiscal 2004, 2003 and 2002 were approximately $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 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, 2004 include approximately $280,000 for our estimate of incurred but unpaid costs related to the self-insurance portion of our health insurance.
We are self-insured for up to $250,000 for all workers’ compensation claims submitted by employees for on-the-job injuries. We have provided for both reported and incurred but not reported costs of workers’ compensation coverage in the accompanying consolidated balance sheets. Accrued expenses at March 31, 2004 include approximately $400,000 for our estimate of incurred but unpaid costs related to workers’ compensation claims. Based upon our past experience, management believes that we have adequately provided for potential losses. However, future multiple occurrences of serious injuries to employees could have a material adverse effect on our financial position and results of operations.
11.Business Segments and Supplementary Earnings Information
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, 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, we have incurred approximately $2,800,000 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.
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. In the opinion of our management, none of the pending litigation, disputes or claims against us will have a material adverse effect on our financial condition, results of operations or cash flow from operations and there is only a remote possibility that any such matter will require any additional loss accrual.
13.Quarterly Results of Operations (unaudited)
The following table summarizes quarterly financial data for our fiscal years ended March 31, 2004 and 2003 (in thousands, except per share data):
|
| First |
| Second |
| Third |
| Fourth |
| 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 | ) |
43
Not applicable.
Item 9A.Controls and Procedures
In accordance with Exchange Act Rules 13a-15 and 15d-15, we carried out an evaluation, under the supervision and with the participation of management, including our Chief Executive Officer and Chief Financial Officer, of the effectiveness of our disclosure controls and procedures as of the end of the period covered by this report. Based upon that evaluation, our Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures were effective as of March 31, 2004 to provide reasonable assurance that information required to be disclosed in our reports filed or submitted under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the Securities and Exchange Commission’s rules and forms.
There has been no change in our internal controls over financial reporting that occurred during the three months ended March 31, 2004 that has materially affected, or is likely to materially affect, our internal controls over financial reporting.
In Items 10, 11, 12 and 13 below, we are incorporating by reference the information we refer to in those Items from the definitive proxy statement for our 2004 Annual Meeting of Shareholders. We intend to file that definitive proxy statement with the SEC by July 15, 2004.
Please see the information appearing under the headings “Proposal No. 1—Election of Directors” and “Executives and Executive Compensation” in the definitive proxy statement for our 2004 Annual Meeting of Shareholders for the information this Item 10 requires.
Please see the information appearing under the heading “Executives and Executive Compensation” in the definitive proxy statement for our 2004 Annual Meeting of Shareholders for the information this Item 11 requires.
Please see the information appearing (1) under the heading “Equity Compensation Plan Information” in Item 5 of this report and (2) under the heading “Security Ownership of Certain Beneficial Owners and Management” in the definitive proxy statement for our 2004 Annual Meeting of Shareholders for the information this Item 12 requires.
Please see the information appearing under the heading “Certain Transactions” in the definitive proxy statement for our 2004 Annual Meeting of Shareholders for the information this Item 13 requires.
Please see the information appearing under the heading “Ratification of Appointment of Independent Auditors” in the definitive proxy statement for our 2004 Annual Meeting of Shareholders for the information this Item 14 requires.
44
Item 15. Exhibits, Financial Statement Schedules and Reports on Form 8-K
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 |
4.18* | - | Form of Purchase Agreement dated February 13, 2004 between Pioneer Drilling Company and the |
10.1* | - | Voting Agreement dated June 18, 1997 between Robert R. Marmor, William D. Hibbetts, Wm. Stacy Locke, Alvis L. Dowell, Charles B Tichenor and Richard Phillips (Form 10-K for the year ended March 31, 2001 (File No. 1-8182, Exhibit 9.1)). |
10.2* | - | Voting Agreement dated May 11, 2000 between Wm. Stacy Locke, Michael E. Little, Pioneer Drilling Company and WEDGE Energy Services, L.L.C. (Form 10-K for the year ended March 31, 2001 (File No. 1-8182, Exhibit 9.2)). |
10.3* | - | Voting Agreement dated October 9, 2001 between Pioneer Drilling Company and WEDGE Energy Service, L.L.C. (See Section 1.3 of the |
10.4+* | - | Executive Employment Agreement dated May 1, 1995 between Pioneer Drilling Company and Wm. Stacy Locke (Form 10-K for the year ended March 31, 2001 (File No. 1-8182, Exhibit 10.1+)). |
10.5+* | - | 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+* | - | 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+* | - | 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 |
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.
(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.
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.
49 Index To Exhibits
50
51
52
* Incorporated by reference to the filing indicated. + Management contract or compensatory plan or arrangement. 53 |