Item 1. Business
Our Company
We provide contract land drilling services to oil and natural gas exploration and production companies. We currently own a fleet of 64 land drilling rigs, of which 41 are currently operating, four are in the process of being refurbished and 19 are held in inventory. We expect to put all four of the rigs currently being refurbished into service by the end of the second quarter of 2006. We plan on refurbishing seven additional rigs from our current inventory during 2006 at estimated costs (including drill pipe) ranging from $1.8 million to $6.5 million per rig. We continue to focus our refurbishment program on our more powerful rigs, with 1,000 to 2,000 horsepower, which are capable of drilling to depths between 15,000 and 25,000 feet. We also own a fleet of 60 trucks used to transport our rigs.
We commenced operations in 2001 with the purchase of one stacked 650-horsepower rig that we refurbished and deployed. We subsequently made selective acquisitions of both operational and inventoried rigs, as well as ancillary equipment. Our most recent acquisition was completed in January 2006 when we purchased six land drilling rigs and certain other assets, including heavy haul trucks and excess equipment, from Big A Drilling Company, L.C. for $16.3 million in cash and 72,571 shares of our common stock. See “- Our Acquisitions” below for additional information regarding this acquisition. In October 2005, we purchased 12 land drilling rigs from Eagle Drilling, L.L.C. for approximately $50.0 million, and 13 land drilling rigs from Thomas Drilling Co. for approximately $68.0 million. These transactions not only increased the size of our rig fleet, but
Index to Financial Statements
also expanded our operations to the Barnett Shale trend in North Texas and Palo Duro Basin in West Texas. In July 2005, we completed a transaction with Strata Drilling, L.L.C. and Strata Property, L.L.C. in which we acquired, among other assets, three land drilling rigs and a 16 acre storage and refurbishment yard for $20.0 million.
Our management team has significant experience not only with acquiring rigs, but also with refurbishing and deploying inventoried rigs. We have successfully refurbished and brought into operation 12 inventoried drilling rigs since November 2003. Upon completion of refurbishment, the rigs either met or exceeded our operating expectations. In addition, we have a 41,000 square foot machine shop in Oklahoma City, which allows us to refurbish and repair our rigs and equipment in-house. This facility, which complements our four rig refurbishment yards, significantly reduces our reliance on outside machine shops and the attendant risk of third-party delays in our rig refurbishment program.
We currently operate in Oklahoma, Kansas, the Barnett Shale and Cotton Valley trends and Palo Duro Basin in Texas, the Williston Basin in North Dakota and the Piceance Basin in Colorado. A majority of the wells we have drilled for our customers have been drilled in search of natural gas reserves. Natural gas is often found in deep and complex geologic formations that generally require higher horsepower, premium rigs and experienced crews to reach targeted depths. Our current fleet of 64 rigs includes 31 rigs ranging from 950 to 2,500 horsepower. Accordingly, such rigs can, or in the case of inventoried rigs upon refurbishment will be able to, reach the depths required to explore for deep natural gas reserves. Our higher horsepower rigs can also drill horizontal wells, which are increasing as a percentage of total wells drilled in North America. We believe our premium rig fleet, rig inventory and experienced crews position us to benefit from the strong natural gas drilling activity in our core operating areas.
Our Acquisitions
On January 18, 2006, we completed the acquisition of six land drilling rigs and certain other assets, including heavy haul trucks and excess rig equipment and inventory, from Big A Drilling. The purchase price for the assets consisted of $16.3 million in cash and 72,571 shares of our common stock. At closing, we also entered into a lease agreement with an affiliate of Big A Drilling under which we leased a rig refurbishment yard located in Woodward, Oklahoma. The lease has an initial term of six months, and we have the option to extend the term of the lease for a period of three years following the expiration of the initial term. We also have the option to purchase the leased premises at any time during the term of the lease for $200,000. For additional information regarding this transaction, see “Management’s Discussion and Analysis of Financial Condition and Results of Operations-Liquidity and Capital Resources” and “Item 2. Properties.”
The following table summarizes completed acquisitions in which we acquired rigs and rig related equipment since June 2001:
In May 2002, we purchased seven drilling rigs ranging in size from 400 to 950 horsepower, associated spare parts and equipment, drill pipe, haul trucks and vehicles from Bison Drilling L.L.C. and Four Aces Drilling L.L.C. After accepting delivery of the rigs, we spent approximately $97,000 upgrading the rigs before placing six
Index to Financial Statements
of them into service. In August 2003, we purchased all of the outstanding stock of Elk Hill Drilling, Inc. and certain drilling rig structures and components from U.S. Rig & Equipment, Inc., an affiliate of Elk Hill. In these transactions, we acquired drilling rigs and inventoried structures and components which, with refurbishment and upgrades, could be used to assemble 22 drilling rigs. At the date of its acquisition, Elk Hill was an inactive corporation with no customers, employees, operations or operational drilling rigs. We began refurbishing the acquired rigs and have deployed an average of approximately one rig per quarter since November 2003. In July 2005, we acquired all of the membership interests of Strata Drilling, L.L.C. and Strata Property, L.L.C. Included in the Strata acquisitions were two operating rigs, one rig that was refurbished, related structures, equipment and components and a 16 acre yard in Oklahoma City, Oklahoma used for equipment storage and refurbishment of inventoried rigs. In September 2005, we acquired 18 trucks and related equipment through our acquisition of Hays Trucking, Inc. for a purchase price consisting of $3.0 million in cash, which included the repayment of $1.9 million of debt owed by Hays Trucking, and 65,368 shares of our common stock. In October 2005, we purchased 12 land drilling rigs from Eagle Drilling, L.L.C. for approximately $50.0 million plus approximately $500,000 of related transaction costs, and 13 land drilling rigs from Thomas Drilling Co. for approximately $68.0 million plus approximately $2.6 million of related transaction costs. In connection with the Thomas acquisition, we leased an additional rig refurbishment yard for a six month term, with the right to extend the term for an additional three years. We also obtained an option to purchase the yard at any time during the term for $175,000. In January 2006, we completed the Big A Drilling acquisition as described above.
Our Industry
The United States contract land drilling services industry is highly cyclical. Volatility in oil and natural 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 natural gas prices and the outlook for future oil and natural gas prices strongly influence the number of wells oil and natural gas exploration and production companies decide to drill. Nevertheless, we believe that the following trends in our industry should benefit our operations:
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Need for increased natural gas drilling activity as U.S. demand growth outpaces U.S. supply growth. From 1994 to 2003, demand for natural gas in the United States grew at an annual rate of 0.6% while the U.S. domestic supply grew at an annual rate of 0.2%. The Energy Information Administration, or EIA, recently estimated that U.S. domestic consumption of natural gas exceeded domestic production by 17% in 2004, a gap that the EIA forecasts will expand to 24% in 2010.
Index to Financial Statements U.S. Natural Gas Wells Drilled & Production
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Increased decline rates in natural gas basins in the U.S. As the chart above shows, even though the number of U.S. natural gas wells drilled has increased significantly, a corresponding increase in production has not been realized. We believe that a significant reason for the limited supply response, even as drilling activities have increased, is the accelerating decline rates of production from new natural gas wells drilled. A study published by the National Petroleum Council in September 2003 concluded, from analysis of production data over the preceding ten years, that as a result of domestic natural gas decline rates of 25% to 30% per year, 80% of natural gas production in ten years will be from wells that have not yet been drilled. We believe that this tends to support a sustained higher natural gas price environment, which should create incentives for oil and natural gas exploration and production companies to increase drilling activities in the U.S.
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Trend towards drilling and developing unconventional natural gas resources. As a result of improvements in extraction technologies along with general increases in natural gas prices, oil and natural gas companies increasingly are exploring for and developing “unconventional” natural gas resources, such as natural gas from tight sands, shales and coalbed methane. This type of drilling activity is frequently done on tighter acreage spacing, and requires that more wells be drilled. It also requires higher horsepower rigs for techniques such as horizontal drilling. The chart below shows the U.S. land rig count is significantly higher than it has been in recent years.
Index to Financial Statements
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High natural gas prices. While U.S. natural gas prices are volatile, 2005 marked the third consecutive year of increases in the yearly average NYMEX near month natural gas contract prices, as shown on the chart below. We believe that high natural gas prices in the U.S., if sustained, should result in more exploration and development drilling activity, and thus higher utilization and dayrates for drilling companies like us.
Index to Financial Statements
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Increases in dayrates and operating margins for land drilling. The increase in the price of natural gas, coupled with accelerating decline rates and an increase in the number of natural gas wells being drilled, have resulted in increases in rig utilization, and consequently improved dayrates and gross margins.
Our Strengths
Our competitive strengths include:
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Premium rig fleet. We currently operate a fleet of 41 rigs, 20 of which have been refurbished since November 2003 by us or the parties from which the rigs were purchased. Natural gas reserves are often found in deep and complex geological formations that require higher horsepower or premium rigs to drill. In addition, the recovery of unconventional natural gas resources often involves horizontal drilling techniques that also require premium rigs with approximately 1,000 or more horsepower. We believe that our operating history and high-quality rig fleet position us to benefit from this type of drilling activity.
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Inventory of drilling rigs and ancillary equipment. In addition to our four rigs currently being refurbished, our 19 drilling rigs held in inventory for refurbishment will allow us to add capacity in response to the currently strong land drilling market. We also have an inventory of excess drawworks, hooks, blow-out preventors and other rig-related equipment. Our inventoried rigs as well as many of the parts we have in inventory would have long delivery lead times if ordered new.
Index to Financial Statements
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Ability to refurbish inventoried rigs. Our management team has demonstrated the ability to refurbish rigs from our inventory. Since November 2003, we have successfully refurbished and placed into service 12 inventoried drilling rigs at costs ranging from $2.2 million to $6.6 million per rig. We are currently refurbishing four additional rigs, all of which range from 450 to 1,400 horsepower. We expect to put all four of the rigs currently being refurbished into service by the end of the second quarter of 2006. In connection with each of the Thomas and Big A Drilling acquisitions, we leased an additional refurbishment yard for a six month term, with the right to extend the term of the lease for an additional three years. We also obtained options to purchase both of these yards at any time during the term for $175,000 and $200,000, respectively.
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Ability to attract and retain qualified rig crews. We believe that our premium rig fleet and experienced management team allow us to successfully attract and retain qualified rig crews relative to some larger, more diversified land drilling companies. As a result, we believe we have been able to refurbish rigs from our inventory and put them into operation without sacrificing our operating quality.
Our Strategy
Our strategy is to continue to expand our contract land drilling services. Specifically, we intend to:
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Refurbish and deploy rigs from our inventory. We intend to continue the refurbishment and deployment of our inventoried rigs. We expect to put all four of the rigs currently being refurbished into service by the end of the second quarter of 2006. We plan on refurbishing seven additional rigs from our current inventory during 2006, at estimated costs (including drill pipe) ranging from $1.8 million to $6.5 million per rig. We continue to focus our refurbishment program on our higher horsepower rigs. As a result of the Thomas and Big A Drilling acquisitions, we added the use of two additional rig refurbishment yards, bringing the total number of yards in use for refurbishment to four, and also added experienced refurbishing crews that complemented the experienced crews we had in place. Our five rig-up supervisors have an average of 31 years of experience in the drilling industry. Following our Big A Drilling acquisition, the management and crews from Big A Drilling joined our team.
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Expand our rig fleet and geographic focus. We intend to continue to expand our rig fleet and geographic areas of operation by making selected acquisitions and mobilizing rigs to other regions. We are currently operating in Oklahoma, Kansas, the Barnett Shale and Cotton Valley trends and Palo Duro Basin in Texas, the Williston Basin in North Dakota and the Piceance Basin in Colorado. We began operations in the Barnett Shale with seven rigs through our Eagle and Thomas acquisitions. We regularly evaluate potential acquisitions of rigs and ancillary operations in both our existing and new regions.
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Maintain a balanced portfolio of spot and term contracts. We manage our rig fleet as a portfolio, committing some of our rigs to longer-term contracts that meet our targeted returns on invested capital, and leveraging spot market rates with other rigs. As we expand our geographic focus, we initially plan on favoring longer-term contracts in our new markets until we gain operating maturity in those markets.
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Maintain a conservative capital structure and disciplined approach to capital spending. We believe that our conservative balance sheet will allow us to pursue opportunities to grow our business. We will continue to evaluate investment opportunities, including potential acquisitions and additional rig refurbishments, that meet our targeted returns on invested capital.
Drilling Equipment
General
A drilling rig consists of engines, a hoisting system, a rotating system, pumps and related equipment to circulate drilling fluid, blowout preventors 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 drilling rigs employ two or more engines to generate between 500 and
Index to Financial Statements
2,000 horsepower, depending on well depth and rig design. Most drilling rigs capable of drilling in deep formations, involving depths greater than 15,000 feet, use diesel-electric power units to generate and deliver electric current through cables to electrical switch gears, then to direct-current electric motors attached to the equipment in the hoisting, rotating and circulating systems.
Drilling rigs use long strings of drill pipe and drill collars to drill wells. Drilling rigs are also used to set heavy strings of large-diameter pipe, or casing, inside the borehole. Because the total weight of the drill string and the casing can exceed 500,000 pounds, drilling rigs require significant hoisting and braking capacities. Generally, a drilling rig’s hoisting system is made up of a mast, or derrick, a drilling line, a traveling block and hook assembly and ancillary equipment that attaches to the rotating system, a mechanism known as the drawworks. 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 hydromatic or electric auxiliary brake assists the main brake to absorb the great amount of energy developed by the mass of the traveling block, hook assembly, drill pipe, drill collars and drill bit or casing being lowered into the well.
The rotating equipment from top to bottom consists of a swivel, the kelly bushing, the kelly, the rotary table, drill pipe, drill collars and the drill bit. We refer to the equipment between the swivel and the drill bit as the drill stem. The swivel assembly sustains the weight of the drill stem, permits its rotation and affords a rotating pressure seal and passageway for circulating drilling fluid into the top of the drill string. The swivel also has a large handle that fits inside the hook assembly at the bottom of the traveling block. Drilling fluid enters the drill stem through a hose, called the rotary hose, attached to the side of the swivel. The kelly is a triangular, square or hexagonal piece of pipe, usually 40 feet long, that transmits torque from the rotary table to the drill stem and permits its vertical movement as it is lowered into the hole. The bottom end of the kelly fits inside a corresponding triangular, square or hexagonal opening in a device called the kelly bushing. The kelly bushing, in turn, fits into a part of the rotary table called the master bushing. As the master bushing rotates, the kelly bushing also rotates, turning the kelly, which rotates the drill pipe and thus the drill bit. Drilling fluid is pumped through the kelly on its way to the bottom. The rotary table, equipped with its master bushing and kelly bushing, supplies the necessary torque to turn the drill stem. The drill pipe and drill collars are both steel tubes through which drilling fluid can be pumped. Drill pipe, sometimes called drill string, comes in 30-foot sections, or joints, with threaded sections on each end. Drill collars are heavier than drill pipe and are also threaded on the ends. Collars are used on the bottom of the drill stem to apply weight to the drilling bit. At the end of the drill stem is the bit, which chews up the formation rock and dislodges it so that drilling fluid can circulate the fragmented material back up to the surface where the circulating system filters it out of the fluid.
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. Bulk storage of drilling fluid materials, the pumps and the mud-mixing equipment are placed at the start of the circulating system. Working mud pits and reserve storage are at the other end of the system. Between these two points the circulating system includes auxiliary equipment for drilling fluid maintenance and equipment for well pressure control. Within the system, the drilling mud is typically routed from the mud pits to the mud pump and from the mud pump through a standpipe and the rotary hose to the drill stem. The drilling mud travels down the drill stem to the bit, up the annular space between the drill stem and the borehole and through the blowout preventer stack to the return flow line. It then travels to a shale shaker for removal of rock cuttings, and then back to the mud pits, which are usually steel tanks. The reserve pits, usually one or two fairly shallow excavations, are used for waste material and excess water around the location.
There are numerous factors that differentiate 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.
Index to Financial Statements Our Fleet of Drilling Rigs
Our rig fleet consists of 64 drilling rigs, of which 41 are currently operating, four are in the process of being refurbished and 19 are held in inventory. We expect to put the four rigs that are currently being refurbished into service by the end of the second quarter of 2006. We plan on refurbishing seven additional rigs from our current inventory during 2006. We own all the rigs in our fleet. The following table sets forth information regarding utilization for our fleet of operating drilling rigs:
The following table sets forth information regarding our drilling fleet as of March 3, 2006:
Index to Financial Statements Working Rigs
We currently have 41 operating rigs. Eighteen of the rigs are currently operating on term contracts ranging from one to two years and twenty-three of the rigs are operating on a well-to-well basis. Twenty of the 41 rigs we currently operate have undergone significant refurbishment since November 2003 by us or the parties from which the rigs were purchased.
Rig 19. This Mid-Continent U-1220 EB rig was acquired as part of the Elk Hill acquisition. We refurbished this rig from inventory at a cost of approximately $6.6 million and deployed it in July 2005. It is currently working in Caddo County, Oklahoma under a two-year term contract that expires in August 2007.
Index to Financial Statements Rig 18. This Gardner Denver 1500E rig was acquired in the Elk Hill acquisition. We refurbished this rig from inventory at a cost of approximately $4.8 million and deployed it in December 2004. It has been working for the same operator since it was refurbished. It is currently working in Latimer County, Oklahoma on a well-to-well basis.
Rig 17. This Skytop Brewster NE-95 was acquired as part of the Elk Hill acquisition. We completed the refurbishment of this rig from inventory at a cost of $6.5 million and deployed it in January 2006. It is currently working in Roger Mills County, Oklahoma under a two-year term contract that expires January 2008.
Rig 12. This Gardner Denver 1100E rig was acquired in the Elk Hill acquisition. We completed the refurbishment of this rig from inventory at a cost of approximately $2.3 million and deployed it in March 2004. It is currently working in Caddo County, Oklahoma under a two-year term contract that expires in April 2007.
Rig 16. This Oilwell 840E rig was acquired in the Elk Hill acquisition. We completed the refurbishment of this rig from inventory at a cost of approximately $2.2 million and deployed it in October 2003. It is currently working in Grady County, Oklahoma on a well-to-well basis.
Rig 15. This Mid-Continent U-712-EA was acquired as part of the Elk Hill acquisition. We completed the refurbishment of this rig from inventory at a cost of $6.1 million and deployed it in January 2006. It is currently working in Smith County, Texas under a two-year term contract that expires January 2008.
Rig 14. This Mid-Continent U-712-EA rig was acquired in the Elk Hill acquisition. We completed the refurbishment of this rig from inventory at a cost of approximately $4.8 million and deployed it in March 2005. It is currently working on a one-year term contract in Eastern Oklahoma that expires in July 2006.
Rig 77. This Ideco 711 rig was acquired as part of the Eagle acquisition. It is currently working in Pittsburg County, Oklahoma under a one-year term contract that expires in November 2006.
Rig 78. This Seaco 1200 rig was acquired as part of the Eagle acquisition. It is currently working in Johnson County, Texas on a one-year term contract that expires in August 2006.
Rig 56. This BDW 800 MI was acquired as part of the Thomas acquisition. It is currently operating in Parker County, Texas on a well-to-well basis.
Rig 60. This Skytop Brewster N46 was acquired as part of the Thomas acquisition. It is currently operating in Tarrant County, Texas under a one-year contract that expires in February 2007.
Rig 57. This Continental Emsco GB800 was acquired as part of the Thomas acquisition. We completed the refurbishment of this rig from inventory at a cost of approximately $2.3 million and deployed it in March 2006. It is currently drilling its first well in Grady County, Oklahoma. Subsequent to completion of this well it will begin working in Eastern Oklahoma under a two-year term contract that expires in March 2008.
Rig 11. This Gardner Denver 800E rig was acquired in the Elk Hill acquisition. We completed the refurbishment of this rig from inventory at a cost of approximately $2.7 million and deployed it in May 2004. It is currently working in Garvin County, Oklahoma on a well-to-well basis.
Rig 10. This Gardner Denver 800E rig was acquired in the Elk Hill acquisition. We completed the refurbishment of this rig from inventory at a cost of approximately $3.2 million and deployed it in August 2004. It is currently working in Caddo County, Oklahoma on a well-to-well basis.
Rig 43. This National 80B was acquired as part of the Strata acquisition. The refurbishment of this rig was completed pursuant to a $7.0 million seller’s note and deployed in January 2006. It is currently working in Harrison County, Texas under a two-year term contract that expires in January 2008.
Index to Financial Statements Rig 8. This National 80-UE was acquired as part of the Elk Hill acquisition. We completed the refurbishment of this rig from inventory at a cost of $6.0 million and deployed it in November 2005. It is currently working in Billings County, North Dakota under a two-year term contract that expires November 2007.
Rig 3. This Cabot 900 was acquired in the Bison Drilling acquisition. This rig is currently working in Pottawatomie County, Oklahoma under a two-year contract that expires in January 2008.
Rig 4. This Skytop Brewster N46 rig was acquired as part of the Bison acquisition. We completed refurbishment of this rig in August 2005. It is currently working in the Piceance Basin in Colorado under a seventeen-month term contract that expires in September 2006.
Rig 51. This Skytop Brewster N42 was acquired as part of the Thomas acquisition. It is currently operating in Caddo County, Oklahoma on a well-to-well basis.
Rig 52. This Continental Emsco G-500 was acquired as part of the Thomas acquisition. It is currently operating in Dewey County, Oklahoma on a well-to-well basis.
Rig 53. This Skytop Brewster N42 was acquired as part of the Thomas acquisition. It is currently operating in McClain County, Oklahoma on a well-to-well basis.
Rig 54. This Skytop Brewster N46 was acquired as part of the Thomas acquisition. It is currently operating in Murray County, Oklahoma on a well-to-well basis.
Rig 55. This National 50-A was acquired as part of the Thomas acquisition. It is currently operating in Denton County, Texas on a well-to-well basis.
Rig 59. This Skytop Brewster N46 was acquired as part of the Thomas acquisition. It is currently operating in Coal County, Oklahoma under a one-year contract that expires in January 2007.
Rig 61. This National 50-A was acquired as part of the Thomas acquisition. It is currently operating in Parker County, Texas on a well-to-well basis.
Rig 41. This Skytop Brewster N-46 rig was acquired as part of the Strata acquisitions. It has been working for the same operator for the last three years in Central and Western Oklahoma. This rig is currently working in McClain County, Oklahoma on a well-to-well basis.
Rig 72. This Skytop Brewster N45 rig was acquired as part of the Eagle acquisition. It is currently working in Johnson County, Texas on a well-to-well basis.
Rig 75. This Ideco 750 rig was acquired as part of the Eagle acquisition. It is currently working in Murray County, Oklahoma on a well-to-well basis.
Rig 76. This National N55 rig was acquired as part of the Eagle acquisition. It is currently working in Johnson County, Texas under a one-year term contract that expires in November 2006.
Rig 42. This Gardner Denver 500 rig was acquired as a part of the Strata acquisitions. It has been working for the same operator for the last three years in Central and Western Oklahoma. This rig is currently working in Major County, Oklahoma on a well-to-well basis.
Rig 94. This Skytop Brewster N45 rig was acquired as part of the Big A Drilling acquisition. It is currently working in Texas County, Oklahoma on a well-to-well basis.
Index to Financial Statements Rig 95. This Unit U-15 rig was acquired as part of the Big A Drilling acquisition. It is currently working in Roberts County, Texas on a well-to-well basis.
Rig 9. This Gardner Denver 500 was acquired in the Ram acquisition. This rig is currently working in Oklahoma County, Oklahoma under a two-year contract that expires in January 2008.
Rig 7. This Mid-Continent U36A was acquired in the Bison Drilling acquisition. It is drilling a well in Coal County, Oklahoma under a one-year term contract that expires November 2006.
Rig 6. This Mid-Continent U36A was acquired in the Bison Drilling acquisition. This rig is currently working in Major County, Oklahoma under a one-year contract that expires in February 2007.
Rig 5. This Mid-Continent U36A was acquired in the Bison Drilling acquisition. It is drilling in Grady County, Oklahoma on a well-to-well basis.
Rig 92. This Weiss 45 rig was acquired as part of the Big A Drilling acquisition. It is currently working in Texas County, Oklahoma on a well-to-well basis.
Rig 2. This Cardwell L-350 was acquired in the Bison Drilling acquisition. It works primarily in the Arkoma Basin in Eastern Oklahoma. This rig is currently working in Hughes County, Oklahoma on a well-to-well basis.
Rig 91. This Ideco H-35 rig was acquired as part of the Big A Drilling acquisition. It is currently working in Beaver County, Oklahoma on a well-to-well basis.
Rig 96. This Ideco H-35 rig was acquired as part of the Big A Drilling acquisition. It is currently working in Clark County, Kansas on a well-to-well basis.
Rig 93. This Ideco H-30 rig was acquired as part of the Big A Drilling acquisition. It is currently working in Cimarron County, Oklahoma on a well-to-well basis.
Rigs Being Refurbished
We are currently in the process of refurbishing four rigs, all of which we anticipate will be completed by the end of the second quarter of 2006.
Rig 20. This Mid-Continent U-914-EC rig was acquired as part of the Elk Hill acquisition. We started its refurbishment in October 2005 and believe it can be delivered in the first quarter of 2006.
Rig 23. This Continental Emsco D-3 rig was acquired as part of the Elk Hill acquisition. We intend to start its refurbishment in March 2006 and believe it can be delivered in the second quarter of 2006. We have ordered drill pipe, derrick and substructure power packages and SCR house which are scheduled for delivery beginning in the first quarter of 2006.
Rig 58. This Unit U-15 was acquired as part of the Thomas acquisition. We started its refurbishment in October 2005 and anticipate that it will be complete and drill ready by the end of the first quarter 2006.
Rig 70. This National T32 was acquired as part of the Eagle acquisition. We started its refurbishment in February 2006 and believe it can be delivered by the end of the second quarter of 2006.
Rigs in Inventory
We currently have 19 rigs held in inventory in our rig yards in Oklahoma. We define an inventoried rig as a rig that is included in our refurbishment plan and has been assigned a start and delivery date. The seven
Index to Financial Statements
additional rigs that we intend to refurbish during 2006 are described below. We intend to refurbish and deploy our remaining rigs held in inventory on a periodic basis, with such refurbishment currently scheduled for completion by the end of the second quarter of 2008.
Rig 24. This Skytop Brewster NE-12 rig was acquired as part of the Elk Hill acquisition. We intend to start its refurbishment in April 2006 and believe it can be delivered in the third quarter of 2006. We have ordered drill pipe, power packages and SCR house which are scheduled for delivery beginning in the first quarter of 2006.
Rig 25. This National 1320-UE rig was acquired as part of the Elk Hill acquisition. We intend to start its refurbishment in May 2006 and believe it can be delivered by the end of 2006. We have ordered drill pipe, power packages and SCR house which are scheduled for delivery beginning in the first quarter of 2006.
Rig 73. This Skytop Brewster N95 was acquired as part of the Eagle acquisition. We intend to start its refurbishment in April 2006 and believe it can be delivered in the third quarter of 2006.
Rig 74. This Mid-Continent 914 was acquired as part of the Eagle acquisition. We intend to start its refurbishment in July 2006 and believe it can be delivered in the fourth quarter of 2006.
Rig 21. This Mid-Continent U-914-EC rig was acquired as part of the Elk Hill acquisition. We started its refurbishment in October 2005 and believe it can be delivered in the third quarter of 2006.
Rig 22. This Continental Emsco D-3 rig was acquired as part of the Elk Hill acquisition. We started its refurbishment in October 2005 and believe it can be delivered in the fourth quarter of 2006.
Rig 81. This National T32 was acquired as part of the Eagle acquisition. We intend to start its refurbishment in May 2006 and believe it can be delivered in the fourth quarter of 2006.
Excess Rig Inventory
We currently have four rigs that we believe can be refurbished, but are not currently part of our refurbishment plan. We periodically review the market, our financial condition and our refurbishment yard capacity to determine if we will add additional rigs to our refurbishment plan.
Excess Equipment
As of February 28, 2006, we had an inventory of excess rig equipment that includes 42 drawworks (30 of which are 1,000 horsepower or higher), 84 blocks, 69 blow out preventors, 14 electric brakes, 52 hydromatic brakes, 59 rotary tables and 33 swivels. This inventoried equipment could be used with newly ordered or purchased parts to build additional rigs.
As of February 28, 2006, we owned a fleet of 60 trucks and related transportation equipment that we use to transport our drilling rigs to and from drilling sites. By owning our own trucks, we reduce the cost of rig moves and reduce downtime between rig moves.
We believe that our operating drilling rigs and other related equipment are in good operating condition. Our employees perform periodic maintenance and minor repair work on our drilling rigs. Historically, we have relied on various oilfield service companies for major repair work and overhaul of our drilling equipment. In April 2005, we opened a 41,000 square foot machine shop in Oklahoma City, which allows us to refurbish and repair our rigs and equipment in-house. In the event of major breakdowns or mechanical problems, our rigs could be subject to significant idle time and a resulting loss of revenue if the necessary repair services are not immediately available.
Index to Financial Statements 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 natural gas exploration and production companies operating in the geographic markets where we operate. Our business has generally not been affected by seasonal fluctuations. The oil and natural gas exploration and production industry is a historically cyclical industry characterized by significant changes in the levels of exploration and development activities. During periods of lower levels of drilling activity, price competition tends to increase and results in decreases in the profitability of daywork contracts. In this lower level drilling activity and competitive price environment, we may be more inclined to enter into 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 natural gas wells either through competitive bidding or through direct negotiations with customers. Our drilling contracts generally provide for compensation on either a daywork or footage basis. The contract terms we offer generally depend on the complexity and risk of operations, the on-site drilling conditions, the type of equipment used and the anticipated duration of the work to be performed. Generally, our contracts provide for the drilling of a single well and typically permit the customer to terminate on short notice, usually on payment of an agreed fee.
The following table presents, by type of contract, information about the total number of wells we completed for our customers during the years ended December 31, 2005, 2004, and 2003.
Daywork Contracts. Under daywork drilling contracts, we provide a drilling rig with required personnel to our customer who supervises the drilling of the well. We are paid based on a negotiated fixed rate per day while the rig is used. Daywork drilling contracts specify the equipment to be used, the size of the hole and the depth of the well. Under a daywork drilling contract, the customer bears a large portion of the out-of-pocket drilling costs and we generally bear no part of the usual risks associated with drilling, such as time delays and unanticipated costs.
Footage Contracts. Under footage contracts, we are paid a fixed amount for each foot drilled, regardless of the time required or the problems encountered in drilling the well. We typically pay more of the out-of-pocket costs associated with footage contracts as compared to daywork contracts. The risks to us on a footage contract are greater because we assume most of the risks associated with drilling operations generally assumed by the operator in a daywork contract, including the risk of blowout, loss of hole, stuck drill pipe, machinery breakdowns, abnormal drilling conditions and risks associated with subcontractors’ services, supplies, cost escalation and personnel. 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 negative impact on our profitability.
Turnkey Contracts. Turnkey contracts typically provide for a drilling company to drill a well for a 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. The drilling company would provide technical expertise and engineering services, as well as most of the equipment and drilling supplies required to drill the well. The drilling
Index to Financial Statements
company may subcontract for related services, such as the provision of casing crews, cementing and well logging. Under typical turnkey drilling arrangements, a drilling company would not receive progress payments and would be paid by its customer only after it had performed the terms of the drilling contract in full.
Although we have not historically entered into any turnkey contracts, we may decide to enter into such arrangements in the future. The risks to a drilling company under a turnkey contract are substantially greater than on a well drilled on a daywork basis. This is primarily because under a turnkey contract the drilling company assumes most of the risks associated with drilling operations generally assumed by the operator in a daywork contract, including the risk of blowout, loss of hole, stuck drill pipe, machinery breakdowns, abnormal drilling conditions and risks associated with subcontractors’ services, supplies, cost escalations and personnel.
Customers and Marketing
We market our rigs to a number of customers. In 2005, we drilled wells for 52 different customers, compared to 29 customers in 2004 and 34 customers in 2003. The following table shows our customers that accounted for more than 5% of our total contract drilling revenue for each of our last three years.
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 natural gas wells in the near future in our market areas. Once we have been placed on the “bid list” for an operator, we will typically be given the opportunity to bid on most future wells for that operator in the areas in which we operate. Our rigs are typically contracted on a well-by-well basis.
From time to time we also enter into informal, nonbinding commitments with our customers to provide drilling rigs for future periods at specified rates plus fuel and mobilization charges, if applicable, and escalation provisions. This practice is customary in the contract land drilling services business during times of tightening rig supply.
Index to Financial Statements Competition
We encounter substantial competition from other drilling contractors. Our primary market area is 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 Nabors Industries, Inc., Patterson-UTI Energy, Inc., Unit Corp. and Helmerich & Payne, Inc. We believe pricing and rig availability are the primary factors our potential customers consider in determining which drilling contractor to select. In addition, we believe the following factors are also important:
•
the type and condition of each of the competing drilling rigs;
•
the mobility and efficiency of the rigs;
•
the quality of service and experience of the rig crews;
•
the offering of ancillary services; and
•
the ability to provide drilling equipment adaptable to, and personnel familiar with, new technologies and drilling techniques.
While we must be competitive in our pricing, our competitive strategy generally emphasizes the quality of our equipment and the experience of our rig crews to differentiate us from our competitors. This strategy is less effective as lower demand for drilling services or an oversupply of rigs usually results in increased 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 oversupply 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.
Many of our competitors have greater financial, technical and other resources than we do. Their greater capabilities in these areas may enable them to:
•
better withstand industry downturns;
•
compete more effectively on the basis of price and technology;
•
better retain skilled rig personnel; and
•
build new rigs or acquire and refurbish existing rigs so as to be able to place rigs into service more quickly than us in periods of high drilling demand.
Raw Materials
The materials and supplies we use in our drilling operations include fuels to operate our drilling equipment, drilling mud, drill pipe, drill collars, drill bits and cement. We do not rely on a single source of supply for any of these items. While we are not currently experiencing any shortages, from time to time there have been shortages of drilling equipment and supplies during periods of high demand.
Shortages could result in increased prices for drilling equipment or supplies that we may be unable to pass on to customers. In addition, during periods of shortages, the delivery times for equipment and supplies can be substantially longer. Any significant delays in our obtaining drilling equipment or supplies could limit drilling operations and jeopardize our relations with customers. In addition, shortages of drilling equipment or supplies could delay and adversely affect our ability to obtain new contracts for our rigs, which could have a material adverse effect on our financial condition and results of operations.
Index to Financial Statements Operating Risks and Insurance
Our operations are subject to the many hazards inherent in the contract land drilling business, including the risks of:
•
blowouts;
•
fires and explosions;
•
loss of well control;
•
collapse of the borehole;
•
lost or stuck drill strings; and
•
damage or loss from natural disasters.
Any of these hazards can result in substantial liabilities or losses to us from, among other things:
•
suspension of drilling operations;
•
damage to, or destruction of, our property and equipment and that of others;
•
personal injury and loss of life;
•
damage to producing or potentially productive oil and natural 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 have sufficient financial resources or 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 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 a third party estimate of the appraised value of the rigs and drilling equipment. The policy provides for a deductible on rigs of $1.0 million per occurrence and a $40.0 million aggregate stop loss. Our umbrella liability insurance coverage is $25.0 million per occurrence and in the aggregate, with a deductible of $10,000 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.
Employees
As of February 28, 2006, we had approximately 1,400 employees. Approximately 145 of these employees are salaried administrative or supervisory employees. The rest of our employees are hourly employees who operate or maintain our drilling rigs and rig-hauling trucks. The number of hourly employees fluctuates depending on the number of drilling projects we are engaged in at any particular time. None of our employees are subject to collective bargaining arrangements.
Index to Financial Statements 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.
Governmental Regulation
Our operations are subject to stringent federal, state and local laws and regulations governing the protection of the environment and human health and safety. Several such laws and regulations relate to the disposal of hazardous oilfield waste and restrict the types, quantities and concentrations of such regulated substances that can be released into the environment. Several such laws also require removal and remedial action and other cleanup under certain circumstances, commonly regardless of fault. Planning, implementation and maintenance of protective measures are required to prevent accidental discharges. Spills of oil, natural gas liquids, drilling fluids and other substances may subject us to penalties and cleanup requirements. Handling, storage and disposal of both hazardous and non-hazardous wastes are also subject to these regulatory requirements. In addition, our operations are often conducted in or near ecologically sensitive areas, 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, contaminated water or other substances or for noncompliance with other aspects of applicable laws and regulations. Historically, we have not been required to obtain environmental or other permits prior to drilling a well. Instead, the operator of the oil and gas property has been obligated to obtain the necessary permits at its own expense.
The federal Clean Water Act, as amended by the Oil Pollution Act, the federal Clean Air Act, the federal Resource Conservation and Recovery Act, CERCLA, the Safe Drinking Water Act, OSHA and their state counterparts and similar statutes are the primary vehicles for imposition of such requirements and for civil, criminal and administrative penalties and other sanctions for violation of their requirements. 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. In addition, CERCLA, also known as the “Superfund” law, and similar state statutes impose strict liability, without regard to fault or the legality of the original conduct, on certain classes of persons who are considered responsible for the release or threatened release of hazardous substances into the environment. These persons include the current owner or operator of a facility where a release has occurred, the owner or operator of a facility at the time a release occurred and companies that disposed of or arranged for the disposal of hazardous substances found at a particular site. This liability may be joint and several. Such liability, which may be imposed for the conduct of others and for conditions others have caused, includes the cost of removal and remedial action as well as damages to natural resources. Few defenses exist to the liability imposed by environmental laws and regulations. It is also not uncommon for third parties to file claims for personal injury and property damage caused by substances released into the environment.
Environmental laws and regulations are complex and subject to frequent changes. Failure to comply with governmental requirements or inadequate cooperation with governmental authorities could subject a responsible party to administrative, civil or criminal action. We may also be exposed to environmental or other liabilities originating from businesses and assets that we acquired from others. We are in substantial compliance with applicable environmental laws and regulations and, to date, such compliance has not materially affected our
Index to Financial Statements
capital expenditures, earnings or competitive position. We do not expect to incur material capital expenditures in our next fiscal year in order to comply with current or reasonably anticipated environment control requirements. However, our compliance with amended, new or more stringent requirements, stricter interpretations of existing requirements or the future discovery of regulatory noncompliance or 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 natural gas industry and, therefore, is affected by tax, environmental and other laws relating to the oil and natural 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.
Item 1A.
Item 1A. Risk Factors
Risks Relating to the Oil and Natural Gas Industry
We derive all our revenues from companies in the oil and natural 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 natural gas prices.
We derive all our revenues from companies in the oil and natural 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 natural gas prices. Any prolonged reduction in the overall level of exploration and development activities, whether resulting from changes in oil and natural gas prices or otherwise, can adversely impact us in many ways by negatively affecting:
•
our revenues, cash flows and profitability;
•
our ability to maintain or increase our borrowing capacity;
•
our ability to obtain additional capital to finance our business and make acquisitions, and the cost of that capital;
•
our ability to retain skilled rig personnel whom we would need in the event of an upturn in the demand for our services; and
•
the fair market value of our rig fleet.
Worldwide political, economic and military events have contributed to oil and natural gas price volatility and are likely to continue to do so in the future. Depending on the market prices of oil and natural gas, oil and natural gas exploration and production companies may cancel or curtail their drilling programs, thereby reducing demand for our services. Oil and natural 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 natural gas prices, including:
•
the cost of exploring for, producing and delivering oil and natural gas;
•
the discovery rate of new oil and natural gas reserves;
•
the rate of decline of existing and new oil and natural gas reserves;
•
available pipeline and other oil and natural gas transportation capacity;
•
the ability of oil and natural gas companies to raise capital;
•
actions by OPEC, the Organization of Petroleum Exporting Countries;
•
political instability in the Middle East and other major oil and natural gas producing regions;
•
economic conditions in the United States and elsewhere;
Index to Financial Statements
•
governmental regulations, both domestic and foreign;
•
domestic and foreign tax policy;
•
weather conditions in the United States and elsewhere;
•
the pace adopted by foreign governments for the exploration, development and production of their national reserves;
•
the price of foreign imports of oil and natural gas; and
•
the overall supply and demand for oil and natural gas.
Risks Relating to Our Business
Our acquisition strategy exposes us to various risks, including those relating to difficulties in identifying suitable acquisition opportunities and integrating businesses, assets and personnel, as well as difficulties in obtaining financing for targeted acquisitions and the potential for increased leverage or debt service requirements.
As a component of our business strategy, we have pursued and intend to continue to pursue selected acquisitions of complementary assets and businesses. In May 2002, we purchased seven drilling rigs, associated spare parts and equipment, drill pipe, haul trucks and vehicles. In August 2003, we acquired drilling rigs and inventoried structures and components which, with refurbishment and upgrades, could be used to assemble 22 drilling rigs. In July 2005, we acquired three additional rigs and related inventory, equipment, components and rig yard. On October 3, 2005, we acquired five operating rigs, seven inventoried rigs and rig equipment and parts. On October 14, 2005, we acquired nine operating rigs, two rigs undergoing refurbishment, two inventoried rigs and rig equipment and parts. On January 18, 2006, we acquired six operating land drilling rigs and certain other assets, including heavy haul trucks and excess rig equipment. Acquisitions, including those described above, involve numerous risks, including:
•
unanticipated costs and assumption of liabilities and exposure to unforeseen liabilities of acquired companies, including but not limited to environmental liabilities;
•
difficulty in integrating the operations and assets of the acquired business and the acquired personnel and distinct cultures;
•
our ability to properly access and maintain an effective internal control environment over an acquired company, in order to comply with the recently adopted public reporting requirements;
•
potential loss of key employees and customers of the acquired companies;
•
risk of entering markets in which we have limited prior experience; and
•
an increase in our expenses and working capital requirements.
The process of integrating an acquired business may involve unforeseen costs and delays or other operational, technical and financial difficulties and may require a disproportionate amount of management attention and financial and other resources. Our failure to achieve consolidation savings, to incorporate the acquired businesses and assets into our existing operations successfully or to minimize any unforeseen operational difficulties could have a material adverse effect on our financial condition and results of operations.
In addition, we may not have sufficient capital resources to complete additional acquisitions. Historically, we have funded the acquisition of rigs and the refurbishment of our rig fleet through a combination of debt and equity financing. We may incur substantial additional indebtedness to finance future acquisitions and also may issue equity, debt or convertible securities in connection with such acquisitions. Debt service requirements could represent a significant burden on our results of operations and financial condition and the issuance of additional equity or convertible securities could be dilutive to our existing stockholders. Furthermore, we may not be able to
Index to Financial Statements
obtain additional financing on satisfactory terms. Even if we have access to the necessary capital, we may be unable to continue to identify additional suitable acquisition opportunities, negotiate acceptable terms or successfully acquire identified targets.
Increases in the supply of rigs could decrease dayrates and utilization rates.
An increase in the supply of land rigs, whether through new construction or refurbishment, could decrease dayrates and utilization rates, which would adversely affect our revenues and profitability. In addition, such adverse affect on our revenue and profitability caused by such increased competition and lower dayrates and utilization rates could be further aggravated by any downturn in oil and natural gas prices.
A material reduction in the levels of exploration and development activities in Oklahoma or Texas or an increase in the number of rigs mobilized to Oklahoma or Texas could negatively impact our dayrates and utilization rates.
We currently conduct a substantial portion of our operations in Oklahoma and Texas. A material reduction in the levels of exploration and development activities in Oklahoma or Texas due to a variety of oil and natural gas industry risks described above or an increase in the number of rigs mobilized to Oklahoma or Texas could negatively impact our dayrates and utilization rates, which could adversely affect our revenues and profitability.
Our revenues and profitability could be negatively impacted if we are unable to successfully complete the refurbishment of our inventoried rigs on schedule and within budget and use those and the other rigs in our fleet at profitable levels.
We expect to put all four of the rigs currently being refurbished into service by the end of the second quarter of 2006. We plan on refurbishing seven additional rigs from our current inventory during 2006, at estimated costs (including drill pipe) ranging from $1.8 million to $6.5 million per rig. Our revenues and profitability could be negatively impacted if we are unable to successfully complete the refurbishment of our inventoried rigs on schedule and within budget and operate those and the other rigs in our fleet at profitable levels. Our refurbishment projects are subject to the risks of delay and cost overruns inherent in any large construction project, including shortages of equipment, unforeseen engineering problems, work stoppages, weather interference, unanticipated cost increases, inability to obtain necessary certifications and approvals and shortages of materials or skilled labor. Significant delays could negatively impact our anticipated contract commitments with respect to rigs being refurbished, while significant cost overruns or delays in general could adversely affect our financial condition and results of operations. Moreover, customer demand for rigs currently being refurbished may not be as strong as we presently anticipate, and our inability to obtain contracts on anticipated terms or at all may negatively impact our revenues and profitability.
We have a history of losses and may experience losses in the future.
Although we reported net income of $5.1 million for the year ended December 31, 2005, we have a history of losses. We incurred net losses of $2.8 million, $1.6 million and $1.9 million for the years ended December 31, 2004, 2003 and 2002, 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.
We operate in a highly competitive, fragmented industry in which price competition could reduce our profitability.
We operate in a highly competitive, fragmented industry in which price competition could reduce our profitability. 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.
Index to Financial Statements The drilling contracts we compete for are usually awarded on the basis of competitive bids or direct negotiations with customers. 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 offering of ancillary services; and
•
the ability to provide drilling equipment adaptable to, and personnel familiar with, new technologies and drilling techniques.
While we must be competitive in our pricing, our competitive strategy generally emphasizes the quality of our equipment and experience of our rig crews to differentiate us from our competitors. This strategy is less effective as lower demand for drilling services or an oversupply of rigs usually results in increased 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 oversupply of rigs can cause greater price competition which can, in turn, reduce our profitability.
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.
We face competition from competitors with greater resources that may make it more difficult for us to compete, which can reduce our dayrates and utilization rates.
Some of our competitors have greater financial, technical and other resources than we do that may make it more difficult for us to compete, which can reduce our dayrates and utilization rates. 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.
We are subject to unexpected cost overruns on our footage contracts and, to the extent we enter into such arrangements, turnkey contracts, which could negatively impact our profitability.
For the years ended December 31, 2005 and 2004, 1% and 13%, respectively, of our total revenues was derived from footage contracts. Under footage contracts, we are paid a fixed amount for each foot drilled, regardless of the time required or the problems encountered in drilling the well. We typically pay more of the out-of-pocket costs associated with footage contracts as compared to daywork contracts. The risks to us on a footage contract are greater because we assume most of the risks associated with drilling operations generally assumed by the operator in a daywork contract, including the risk of blowout, loss of hole, stuck drill pipe, machinery breakdowns, abnormal drilling conditions and risks associated with subcontractors’ services, supplies, cost escalation and personnel. The occurrence of uninsured or under-insured losses or operating cost overruns on our footage jobs could have a negative impact on our profitability. Similar to our footage contracts, under
Index to Financial Statements
turnkey contacts drilling companies assume most of the risks associated with drilling operations that the operator generally assumes under a daywork contract. Although we historically have not entered into turnkey contracts, if we were to enter into a turnkey contract or acquire such a contract in connection with future acquisitions, the occurrence of uninsured or under-insured losses or operating cost overruns on such a job could negatively impact our profitability.
Our operations involve operating hazards, which if not insured or indemnified against, could adversely affect our results of operations and financial condition.
Our operations are subject to the many hazards inherent in the contract land drilling business, including the risks of:
•
blowouts;
•
fires and explosions;
•
loss of well control;
•
collapse of the borehole;
•
lost or stuck drill strings; and
•
damage or loss from natural disasters.
Any of these hazards can result in substantial liabilities or losses to us from, among other things:
•
suspension of drilling operations;
•
damage to, or destruction of, our property and equipment and that of others;
•
personal injury and loss of life;
•
damage to producing or potentially productive oil and natural gas formations through which we drill; and
•
environmental damage.
We seek to protect ourselves from some but not all operating hazards through insurance coverage. However, some risks are either not insurable or insurance is available only at rates that we consider uneconomical. Those risks include pollution liability in excess of relatively low limits. Depending on competitive conditions and other factors, we attempt to obtain contractual protection against uninsured operating risks from our customers. However, customers who provide contractual indemnification protection may not in all cases maintain adequate insurance to support their indemnification obligations. Our insurance or indemnification arrangements may not adequately protect us against liability or loss from all the hazards of our operations. The occurrence of a significant event that we have not fully insured or indemnified against or the failure of a customer to meet its indemnification obligations to us could materially and adversely affect our results of operations and financial condition. Furthermore, we may be unable to maintain adequate insurance in the future at rates we consider reasonable.
We face increased exposure to operating difficulties because we primarily focus on drilling for natural gas.
A majority of our drilling contracts are with exploration and production companies in search of natural gas. Drilling on land for natural gas generally occurs at deeper drilling depths than drilling for oil. Although deep-depth drilling exposes us to risks similar to risks encountered in shallow-depth drilling, the magnitude of the risk for deep-depth drilling is greater because of the higher costs and greater complexities involved in drilling deep wells. We generally enter into International Association of Drilling Contractors contracts that contain “day work” indemnification language that transfers responsibility for down hole exposures such as blowout and fire to the
Index to Financial Statements
operator, leaving us responsible only for damage to our rig and our personnel. If we do not adequately insure the risk from blowouts or if our contractual indemnification rights are insufficient or unfulfilled, our profitability and other results of operation and our financial condition could be adversely affected in the event we encounter blowouts or other significant operating difficulties while drilling at deeper depths. If our primary focus shifts from drilling for customers in search of natural gas to drilling for customers in search of oil, the majority of our rig fleet would be disadvantaged in competing for new oil drilling projects as compared to competitors that primarily use shallower drilling depth rigs when drilling in search of oil.
Our operations are subject to various laws and governmental regulations that could restrict our future operations and increase our operating costs.
Many aspects of our operations are subject to various federal, state and local laws and governmental regulations, including laws and regulations governing:
•
environmental quality;
•
pollution control;
•
remediation of contamination;
•
preservation of natural resources; and
•
worker safety.
Our operations are subject to stringent federal, state and local laws and regulations governing the protection of the environment and human health and safety. Several such laws and regulations relate to the disposal of hazardous oilfield waste and restrict the types, quantities and concentrations of such regulated substances that can be released into the environment. Several such laws also require removal and remedial action and other cleanup under certain circumstances, commonly regardless of fault. Planning, implementation and maintenance of protective measures are required to prevent accidental discharges. Spills of oil, natural gas liquids, drilling fluids and other substances may subject us to penalties and cleanup requirements. Handling, storage and disposal of both hazardous and non-hazardous wastes are also subject to these regulatory requirements. In addition, our operations are often conducted in or near ecologically sensitive areas, which are subject to special protective measures and that may expose us to additional operating costs and liabilities for accidental discharges of oil, natural gas, drilling fluids, contaminated water or other substances or for noncompliance with other aspects of applicable laws and regulations. Historically, we have not been required to obtain environmental or other permits prior to drilling a well. Instead, the operator of the oil and gas property has been obligated to obtain the necessary permits at its own expense.
The federal Clean Water Act, as amended by the Oil Pollution Act, the federal Clean Air Act, the federal Resource Conservation and Recovery Act, the federal Comprehensive Environmental Response, Compensation, and Liability Act, or CERCLA, the Safe Drinking Water Act, the Occupational Safety and Health Act, or OSHA, and their state counterparts and similar statutes are the primary vehicles for imposition of such requirements and for civil, criminal and administrative penalties and other sanctions for violation of their requirements. 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. In addition, CERCLA, also known as the “Superfund” law, and similar state statutes impose strict liability, without regard to fault or the legality of the original conduct, on certain classes of persons who are considered responsible for the release or threatened release of hazardous substances into the environment. These persons include the current owner or operator of a facility where a release has occurred, the owner or operator of a facility at the time a release occurred, and companies that disposed of or arranged for the disposal of hazardous substances found at a particular site. This liability may be joint and several. Such liability, which may be imposed for the conduct of others and for conditions others have caused, includes the cost of removal and remedial action as well as damages to natural
Index to Financial Statements
resources. Few defenses exist to the liability imposed by environmental laws and regulations. It is also not uncommon for third parties to file claims for personal injury and property damage caused by substances released into the environment.
Environmental laws and regulations are complex and subject to frequent changes. Failure to comply with governmental requirements or inadequate cooperation with governmental authorities could subject a responsible party to administrative, civil or criminal action. We may also be exposed to environmental or other liabilities originating from businesses and assets that we acquired from others. We are in substantial compliance with applicable environmental laws and regulations and, to date, such compliance has not materially affected our capital expenditures, earnings or competitive position. We do not expect to incur material capital expenditures in our next fiscal year in order to comply with current or reasonably anticipated environment control requirements. However, our compliance with amended, new or more stringent requirements, stricter interpretations of existing requirements or the future discovery of regulatory noncompliance or 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 natural gas industry and, therefore, is affected by tax, environmental and other laws relating to the oil and natural 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.
We rely on a few key employees whose absence or loss could disrupt our operations resulting in a loss of revenues.
Many key responsibilities within our business have been assigned to a small number of employees. The loss of their services, particularly the loss of Frank Harrison, our Chief Executive Officer and President, Zachary Graves, our Chief Financial Officer, or Karl Benzer, our Chief Operating Officer, could disrupt our operations resulting in a loss of revenues. We do not have an employment contract with any of our executives, with the exception of Mr. Benzer, and our executives, with the exception of Mr. Benzer, are not restricted from competing with us if they cease to be employed by us. Additionally, as a practical matter, any employment agreement we may enter into will not assure the retention of our employees. In addition, we do not maintain “key person” life insurance policies on any of our employees. As a result, we are not insured against any losses resulting from the death of our key employees.
We may be unable to attract and retain qualified, skilled employees necessary to operate our business.
Our success depends in large part on our ability to attract and retain skilled and qualified personnel. Our inability to hire, train and retain a sufficient number of qualified employees could impair our ability to manage and maintain our business. We require skilled employees who can perform physically demanding work. Shortages of qualified personnel are occurring in our industry. As a result of the volatility of the oil and natural gas industry and the demanding nature of the work, potential employees may choose to pursue employment in fields that offer a more desirable work environment at wage rates that are competitive with ours. 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. With a reduced pool of workers, it is possible that we will have to raise wage rates to attract workers from other fields and to retain our current employees. If we are not able to increase our service rates to our customers to compensate for wage-rate increases, our profitability and other results of operations may be adversely affected.
Index to Financial Statements Shortages in equipment and supplies could limit our drilling operations and jeopardize our relations with customers.
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. Shortages in equipment supplies could limit our drilling operations and jeopardize our relations with customers. We do not rely on a single source of supply for any of these items. From time to time there have been shortages of drilling equipment and supplies during periods of high demand which we believe could reoccur. Shortages could result in increased prices for drilling equipment or supplies that we may be unable to pass on to customers. In addition, during periods of shortages, the delivery times for equipment and supplies can be substantially longer. Any significant delays in our obtaining drilling equipment or supplies could limit drilling operations and jeopardize our relations with customers. In addition, shortages of drilling equipment or supplies could delay and adversely affect our ability to obtain new contracts for our rigs, which could negatively impact our revenues and profitability.
We will be subject to the requirements of Section 404 of the Sarbanes-Oxley Act. If we are unable to timely comply with Section 404 or if the costs related to compliance are significant, our profitability, stock price and results of operations and financial condition could be materially adversely affected.
We will be required to comply with the provisions of Section 404 of the Sarbanes-Oxley Act of 2002 as of December 31, 2006. Section 404 requires that we document and test our internal control over financial reporting and issue management’s assessment of our internal control over financial reporting. This section also requires that our independent registered public accounting firm opine on those internal controls and management’s assessment of those controls. We are currently evaluating our existing controls against the standards adopted by the Committee of Sponsoring Organizations of the Treadway Commission, or COSO. During the course of our ongoing evaluation and integration of the internal control over financial reporting, we may identify areas requiring improvement, and we may have to design enhanced processes and controls to address issues identified through this review.
We believe that the out-of-pocket costs, the diversion of management’s attention from running the day-to-day operations and operational changes caused by the need to comply with the requirements of Section 404 of the Sarbanes-Oxley Act could be significant. If the time and costs associated with such compliance exceed our current expectations, our profitability could be affected.
We cannot be certain at this time that we will be able to successfully complete the procedures, certification and attestation requirements of Section 404 or that we or our auditors will not identify material weaknesses in internal control over financial reporting. If we fail to comply with the requirements of Section 404 or if we or our auditors identify and report such material weakness, the accuracy and timeliness of the filing of our annual and quarterly reports may be negatively affected and could cause investors to lose confidence in our reported financial information, which could have a negative effect on the trading price of our common stock. In addition, a material weakness in the effectiveness of our internal control over financial reporting could result in an increased chance of fraud and the loss of customers, reduce our ability to obtain financing and require additional expenditures to comply with these requirements, each of which could negatively impact our business, profitability and financial condition.
Risks Related to Our Common Stock
Our largest stockholder controls a significant percentage of our common stock, and its interests may conflict with those of our other stockholders.
Wexford Capital, LLC, through its affiliate Bronco Drilling Holdings, L.L.C., beneficially owns approximately 56% of our common stock. As a result, Wexford exercises significant influence over matters requiring stockholder approval, including the election of directors, changes to our charter documents and significant corporate transactions. This concentration of ownership makes it unlikely that any other holder or
Index to Financial Statements
group of holders of our common stock will be able to affect the way we are managed or the direction of our business. The interests of Wexford 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 stockholders. Wexford’s continued concentrated ownership may have the effect of delaying or preventing a change of control of us, including transactions in which stockholders might otherwise receive a premium for their shares over then current market prices.
Since we are a “controlled company” for purposes of The Nasdaq National Market’s corporate governance requirements, our stockholders will not have, and may never have, the protections that these corporate governance requirements are intended to provide.
Since we are a “controlled company” for purposes of The Nasdaq National Market’s corporate governance requirements, we are not required to comply with the provisions requiring that a majority of our directors be independent, the compensation of our executives be determined by independent directors or nominees for election to our board of directors be selected by independent directors. As a result, our stockholders will not have, and may never have, the protections that these rules are intended to provide. The board of directors has determined that David L. Houston, William R. Snipes and Phillip Lancaster are independent under The Nasdaq National Market listing standards.
We have incurred and will continue to incur increased costs as a result of being a public company.
As a result of becoming a public company in August 2005, we have incurred and will continue to incur significant legal, accounting and other expenses that we did not incur as a private company. We have incurred and will continue to incur costs associated with our public company reporting requirements and costs associated with recently adopted corporate governance requirements, including requirements under the Sarbanes-Oxley Act of 2002, as well as new rules implemented by the SEC and the NASD. We are considered to be controlled by Wexford under The Nasdaq National Market rules, and as a result are eligible for exemptions from provisions of these rules requiring that our board have a majority of independent directors, nominating and corporate governance and compensation committees composed entirely of independent directors and written charters addressing specified matters. On January 31, 2006, we filed a registration statement on Form S-1, File No. 333-131420, with the Securities and Exchange Commission for a proposed public offering of 3,000,000 shares of our common stock, 1,700,000 shares of which would be sold by us and 1,300,000 shares of which would be sold by Bronco Drilling Holdings, L.L.C. If we consummate this public offering, we would be required to comply with these provisions after the specified transition periods. These rules and regulations would increase our legal and financial compliance costs and would make some activities more time-consuming and costly. These new rules and regulations could make it more difficult and more expensive for us to obtain director and officer liability insurance and we may be required to accept reduced policy limits and coverage or incur substantially higher costs to obtain the same or similar coverage. As a result, it would be more difficult for us to attract and retain qualified individuals to serve on our board of directors or as executive officers.
If the price of our common stock fluctuates significantly, your investment could lose value.
Prior to our initial public offering in August 2005, there had been no public market for our common stock. Although our common stock is now quoted on The Nasdaq National Market, we cannot assure you that an active public market will continue to exist for our common stock or that our common stock will continue to trade in the public market at or above the public offering price. In addition, the stock market is subject to significant price and volume fluctuations, and the price of our common stock could fluctuate widely in response to several factors, including:
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our quarterly operating results;
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changes in our earnings estimates;
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additions or departures of key personnel;
Index to Financial Statements
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changes in the business, earnings estimates or market perceptions of our competitors;
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changes in general market or economic conditions; and
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announcements of legislative or regulatory change.
The stock market has experienced extreme price and volume fluctuations in recent years that have significantly affected the quoted prices of the securities of many companies, including companies in our industry. The changes often appear to occur without regard to specific operating performance. The price of our common stock could fluctuate based upon factors that have little or nothing to do with our company and these fluctuations could materially reduce our stock price.
The market price of our common stock could decline following sales of substantial amounts of our common stock in the public markets.
If a large number of shares of our common stock are sold in the open market, the trading price of our common stock could decrease. As of December 31, 2005, we had an aggregate of 75,762,061 shares of our common stock authorized but unissued and not reserved for specific purposes. In general, we may issue all of these shares without any approval by our stockholders. We may pursue acquisitions and may issue shares of our common stock in connection with these acquisitions.
Bronco Drilling Holdings, L.L.C., an entity controlled by Wexford, owned approximately 56% of our common stock as of February 28, 2006. We have entered into a registration rights agreement with Bronco Drilling Holdings under which Bronco Drilling Holdings has three demand registration rights, as well as “piggyback” registration rights. Such sales by Bronco Drilling Holdings, sales by other securityholders or the perception that such sales might occur could have a material adverse effect on the price of our common stock or could impair our ability to obtain capital through an offering of equity securities.
We may issue preferred stock whose terms could adversely affect the voting power or value of our common stock.
Our certificate of incorporation authorizes us to issue, without the approval of our stockholders, one or more classes or series of preferred stock having such designations, preferences, limitations and relative rights, including preferences over our common stock respecting dividends and distributions, as our board of directors may determine. The terms of one or more classes or series of preferred stock could adversely impact the voting power or value of our common stock. For example, we might grant holders of preferred stock the right to elect some number of our directors in all events or on the happening of specified events or the right to veto specified transactions. Similarly, the repurchase or redemption rights or liquidation preferences we might assign to holders of preferred stock could affect the residual value of the common stock.
Provisions in our organizational documents could delay or prevent a change in control of our company, even if that change would be beneficial to our stockholders.
The existence of some provisions in our organizational documents could delay or prevent a change in control of our company, even if that change would be beneficial to our stockholders. Our certificate of incorporation and bylaws contain provisions that may make acquiring control of our company difficult, including:
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provisions regulating the ability of our stockholders to nominate directors for election or to bring matters for action at annual meetings of our stockholders;
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limitations on the ability of our stockholders to call a special meeting and act by written consent;
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the authorization given to our board of directors to issue and set the terms of preferred stock; and
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limitations on the ability of our stockholders from removing our directors without cause.
Index to Financial Statements We do not intend to pay cash dividends on our common stock in the foreseeable future, and therefore only appreciation of the price of our common stock will provide a return to our stockholders.
We currently anticipate that we will retain all future earnings, if any, to finance the growth and development of our business. We do not intend to pay cash dividends in the foreseeable future. Any payment of cash dividends will depend upon our financial condition, capital requirements, earnings and other factors deemed relevant by our board of directors. In addition, the terms of our credit facilities prohibit us from paying dividends and making other distributions. As a result, only appreciation of the price of our common stock, which may not occur, will provide a return to our stockholders.
Item 1B.
Item 1B. Unresolved Staff Comments
None.
Item 2.
Item 2. Property
Our corporate headquarters is located at 14313 North May Avenue, Oklahoma City, Oklahoma in an office building owned by our affiliate, Gulfport. We lease approximately 2,500 square feet of space in the office building for which we pay Gulfport approximately $3,700 per month. This lease of office space is included in our administrative services agreement with Gulfport. The administrative services agreement has a three-year term, and upon expiration, it will continue on a month-to-month basis until cancelled by either party with at least 30 days prior written notice. The administrative services agreement is terminable (1) by us at any time with at least 30 days prior written notice to Gulfport and (2) by either party if the other party is in material breach and such breach has not been cured within 30 days of receipt of written notice of such default.
We own or lease from unaffiliated third parties the following properties:
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a 13 acre yard used for equipment storage and the refurbishment of our inventoried rigs in Duncan, Oklahoma;
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a 15 acre yard, which includes an operations office, rig and equipment storage and a repair facility in Oklahoma City, Oklahoma;
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a 16 acre yard used for equipment storage and the refurbishment of our inventoried rigs in Oklahoma City, Oklahoma;
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a 10 acre yard used as our trucking fleet headquarters in Noble, Oklahoma;
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a 10 acre yard used to dispatch trucks in Seminole, Oklahoma;
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a 5 acre yard used to dispatch trucks in Woodward, Oklahoma;
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a 13 acre yard which includes our machine shop used for drilling rig refurbishment, repair and maintenance in Oklahoma City, Oklahoma; and
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an 8 acre yard used for equipment storage and the refurbishment of our inventoried rigs in Woodward, Oklahoma
In connection with the Thomas acquisition, we leased the Duncan, Oklahoma yard for a six month term, with the right to extend the term for an additional three years. We also obtained an option to purchase the yard at any time during the term for $175,000.
In connection with the Big A Drilling acquisition, we leased an eight acre rig refurbishment yard located in Woodward, Oklahoma. The lease has an initial term of six months, and we have the option to extend the initial term for a period of three years following the expiration of the initial term. We have the option to purchase the leased premises at any time during the term of the lease for $200,000.
Index to Financial Statements
Item 3.
Item 3. Legal Proceedings
We are plaintiffs in a lawsuit involving Atoka Operating, Inc., the defendant, originally filed by us on September 7, 2004 in the 15th Judicial District Court, Grayson County, Texas. This is a breach of contract suit or, alternatively, a suit on a sworn account wherein we sued the defendant for $942,000 as a result of the defendant’s refusal to make payment pursuant to the terms of a drilling contract. The defendant filed a counterclaim on October 11, 2004 for damages in excess of $2.8 million, alleging breach of contract, negligence, gross negligence and breach of warranties. Discovery is ongoing and a trial date of August 14, 2006 has been set. We are vigorously prosecuting our claims and defending against the counterclaims in this matter and will continue to file appropriate responses, motions and documents as necessary. It is not possible to predict the outcome of this matter.
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, with the exception of the matter discussed in the prior paragraph, none of the pending litigation, disputes or claims against us, if decided adversely, will have a material adverse effect on our financial condition or results of operations.
Item 4.
Item 4. Submission of Matters to a Vote of Security Holders
On November 16, 2005, a majority of our stockholders of record as of November 16, 2005 approved Amendment No. 1 to our 2005 Stock Incentive Plan by written consent. The written consent of common stockholders was executed by stockholders holding over 57% of the shares of common stock eligible to vote. Pursuant to the Amendment, the maximum aggregate number of shares of our common stock that may be issued upon exercise of all awards under the 2005 Stock Incentive Plan, including incentive stock options, was increased from a maximum of 500,000 shares to a maximum of 1,000,000 shares.
Index to Financial Statements
PART II
Item 5.
Item 5. Market For Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities.
Our common stock has been quoted on The Nasdaq National Market under the symbol “BRNC” since August 16, 2005. The following table sets forth for the indicated periods the high and low sale prices of our common stock as quoted on The Nasdaq National Market.
On March 6, 2006, the last reported sale price of our common stock on The Nasdaq National Market was $24.06 and we had approximately 6,900 beneficial holders of our common stock.
Dividend Policy
We currently anticipate that we will retain all future earnings, if any, to finance the growth and development of our business. We do not intend to pay cash dividends in the foreseeable future. Any payment of cash dividends will depend upon our financial condition, capital requirements, earnings and other factors deemed relevant by our board of directors. In addition, the terms of our credit facility prohibit us from paying dividends and making other distributions.
Equity Compensation Plan Information
The following table provides information on our equity compensation plan as of December 31, 2005:
Index to Financial Statements
Item 6.
Item 6. Selected Financial Data.
The following table sets forth our selected historical financial data as of and for each of the years indicated. We derived the selected historical financial data as of and for each of the years ended 2005, 2004, 2003 and 2002 from our historical audited consolidated financial statements. We derived the selected historical financial data as of and for the year ended 2001 from our historical unaudited consolidated financial statements. The unaudited information was prepared on a basis consistent with that used in preparing our audited consolidated financial statements and includes all adjustments, consisting of normal and recurring items, that we consider necessary for a fair presentation of the financial position and results of operations for the unaudited period. You should review this information together with “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and consolidated historical financial statements and related notes included elsewhere in this Form 10-K.
Index to Financial Statements
(1) Prior to the completion of our initial public offering in August 2005, we merged with Bronco Drilling Company, L.L.C., our predecessor company. Bronco Drilling Company, L.L.C. was a limited liability company treated as a partnership for federal income tax purposes. As a result, essentially all of its taxable earnings and losses were passed through to its members, and it did not pay federal income taxes at the entity level. Historical income taxes consist mainly of deferred income taxes on a taxable subsidiary, Elk Hill Drilling, Inc. Since we are a C corporation, for comparative purposes we have included a pro forma provision (benefit) for income taxes assuming we had been taxed as a C corporation in all periods prior to the merger.
(2) EBITDA is a non-GAAP financial measure equal to net income (loss), the most directly comparable GAAP financial measure, plus interest expense, income tax expense, depreciation and amortization. We have presented EBITDA because we use EBITDA as an integral part of our internal reporting to measure our performance and to evaluate the performance of our senior management. We consider EBITDA to be an important indicator of the operational strength of our business. EBITDA eliminates the uneven effect of considerable amounts of non-cash depreciation and amortization. A limitation of this measure, however, is that it does not reflect the periodic costs of certain capitalized tangible and intangible assets used in generating revenues in our business. Management evaluates the costs of such tangible and intangible assets and the impact of related impairments through other financial measures, such as capital expenditures, investment spending and return on capital. Therefore, we believe that EBITDA provides useful information to our investors regarding our performance and overall results of operations. EBITDA is not intended to be a performance measure that should be regarded as an alternative to, or more meaningful than, either net income as an indicator of operating performance or to cash flows from operating activities as a measure of liquidity. In addition, EBITDA is not intended to represent funds available for dividends, reinvestment or other discretionary uses, and should not be considered in isolation or as a substitute for measures of performance prepared in accordance with GAAP. The EBITDA measure presented in this Form 10-K may not be comparable to similarly titled measures presented by other companies, and may not be identical to corresponding measures used in our various agreements.
(3) In August 2003, we acquired 22 drilling rigs and drilling rig structures and components for an aggregate of $49.0 million. These transactions were funded directly by our equity holders. Accordingly, they have been accounted for as acquisitions by our equity holders followed by their contribution to us of the acquired assets. As a result, net cash used in investing activities for 2003 does not include the $33.5 million cash portion of the acquisition cost. See Note 2 to our consolidated financial statements appearing elsewhere in this Form 10-K.
Index to Financial Statements
Item 7.
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operation.
The following discussion and analysis should be read in conjunction with the “Selected Historical Financial Data” and the consolidated financial statements and related notes included elsewhere in this Form 10-K. This discussion contains forward-looking statements reflecting our current expectations and estimates and assumptions concerning events and financial trends that may affect our future operating results or financial position. Actual results and the timing of events may differ materially from those contained in these forward-looking statements due to a number of factors, including those discussed in the sections entitled “Risk Factors” and “Cautionary Note Regarding Forward-Looking Statements” appearing elsewhere in this Form 10-K.
Overview
We earn our contract drilling revenues by drilling oil and natural gas wells for our customers. A majority of our wells have been drilled in search of natural gas, which is the primary focus of our customers. We obtain our contracts for drilling oil and natural gas wells either through competitive bidding or through direct negotiations with customers. Our drilling contracts generally provide for compensation on either a daywork or footage basis. We have not historically entered into turnkey contracts and do not intend to enter into them, subject to changes in market conditions, although it is possible that we may acquire such contracts in connection with future acquisitions. 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. Although, we currently have eighteen of our rigs operating under agreements with terms ranging from one to two years, our contracts generally provide for the drilling of a single well and typically permit the customer to terminate on short notice.
A significant performance measurement in our industry is operating rig utilization. We compute operating 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 operating rig. Revenue days for each operating rig are days when the rig is earning revenues under a contract, i.e. when the rig begins moving to the drilling location until the rig was released from the contract. On daywork contracts, during the mobilization period we typically earn a fixed amount of revenue based on the mobilization rate stated in the contract. We begin earning our contracted daywork rate when we begin drilling the well. Occasionally, in periods of increased demand, we will receive a percentage of the contracted dayrate during the mobilization period. Such revenues are accounted for as mobilization fees.
For the years ended December 31, 2005, 2004 and 2003, our rig utilization rates, revenue days and average number of operating rigs were as follows:
The annual increases in the number of revenue days in each of 2005, 2004 and 2003 are attributable to the increases in the size of our operating rig fleet and improvements in our rig utilization rate due to improved market conditions. Based on our plans to refurbish and deploy our inventoried rigs and current market conditions, we anticipate continued growth in revenue days and stable utilization rates for the balance of 2006.
We devote substantial resources to maintaining, upgrading and expanding our rig fleet. We substantially completed the refurbishment of seven rigs in 2005 and plan on refurbishing twelve inventoried rigs during 2006.
Index to Financial Statements Market Conditions in Our Industry
The United States contract land drilling services industry is highly cyclical. Volatility in oil and natural 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 natural gas prices and the outlook for future oil and natural gas prices strongly influence the number of wells oil and natural gas exploration and production companies decide to drill.
The following table depicts the prices for near month delivery contracts for crude oil and natural gas as traded on the NYMEX, as well as the most recent Baker Hughes domestic land rig count, on the dates indicated:
On February 28, 2006, the closing prices for near month delivery contracts for crude oil and natural gas as traded on the NYMEX were $61.41 per barrel and $6.71 per MMbtu, respectively. The Baker Hughes domestic land rig count as of February 24, 2006 was 1,436. Baker Hughes is a large oil field services firm that has issued the rotary rig counts as a service to the petroleum industry since 1944.
We believe capital spent on incremental natural gas production will be driven by an increase in hydrocarbon demand as well as shortages in supply of natural gas. The Energy Information Administration recently estimated that U.S. consumption of natural gas exceeded domestic production by 17% in 2004 and forecasts that U.S. consumption of natural gas will exceed U.S. domestic production by 24% in 2010. In addition, a study published by the National Petroleum Council in September 2003 concluded from drilling and production data over the preceding ten years that average “initial production rates from new wells have been sustained through the use of advanced technology; however, production declines from these initial rates have increased significantly; and recoverable volumes from new wells drilled in mature producing basins have declined over time.” The report went on to state that “without the benefit of new drilling, indigenous supplies have reached a point at which U.S. production declines by 25% to 30% each year” and predicted that in ten years eighty percent of gas production “will be from wells yet to be drilled.” We believe all of these factors tend to support a higher natural gas price environment, which should create strong incentives for oil and natural gas exploration and production companies to increase drilling activity in the U.S. Consequently, these factors may result in higher rig dayrates and rig utilization.
Critical Accounting Policies and Estimates
Our discussion and analysis of our financial condition and results of operations is based upon our consolidated financial statements, which have been prepared in accordance with accounting policies that are described in the notes to our consolidated financial statements. The preparation of the consolidated financial statements requires management to make estimates and judgments that affect the reported amounts of assets, liabilities, revenues and expenses, and related disclosure of contingent assets and liabilities. We continually evaluate our judgments and estimates in determining our financial condition and operating results. Estimates are based upon information available as of the date of the financial statements and, accordingly, actual results could differ from these estimates, sometimes materially. Critical accounting policies and estimates are defined as those that are both most important to the portrayal of our financial condition and operating results and require management’s most subjective judgments. The most critical accounting policies and estimates are described below.
Revenue and Cost Recognition-We earn our revenues by drilling oil and natural gas wells for our customers under daywork or footage contracts, which usually provide for the drilling of a single well. We recognize revenues on daywork contracts for the days completed based on the dayrate each contract specifies.
Index to Financial Statements
Mobilization revenues and costs are deferred and recognized over the drilling days of the related drilling contract. Individual contracts are usually completed in less than 120 days. We follow the percentage-of- completion method of accounting for footage contract drilling arrangements. Under this method, drilling revenues and costs related to a well in progress are recognized proportionately over the time it takes to drill the well. Percentage of completion is determined based upon the amount of expenses incurred through the measurement date as compared to total estimated expenses to be incurred drilling the well. Mobilization costs are not included in costs incurred for percentage-of-completion calculations. Mobilization costs on footage contracts and daywork contracts are deferred and recognized over the days of actual drilling. Under the percentage-of- completion method, management estimates are relied upon in the determination of the total estimated expenses to be incurred drilling the well. When estimates of revenues and expenses indicate a loss on a contract, the total estimated loss is accrued.
Our management has determined that it is appropriate to use the percentage-of-completion method to recognize revenue on our footage contracts, which is the predominant practice in the industry. Although our 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 upon 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 we 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 upon depth in breach of the applicable contract. However, ultimate recovery of that value, in the event we were unable to drill to the agreed upon depth in breach of the contract, would be subject to negotiations with the customer and the possibility of litigation.
We are entitled to receive payment under 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 inception, we have completed all our footage contracts. Although our initial cost estimates for 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 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 adjust our cost estimate for the additional costs to complete the 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. During 2005, we experienced no losses on the five footage contracts we completed. We are more likely to encounter losses on footage contracts in years in which revenue rates are lower for all types of contracts.
Revenues and costs during a reporting period could be affected by contracts in progress at the end of a reporting period that have not been completed before our financial statements for that period are released. We had no footage contracts in progress at December 31, 2004 or December 31, 2005. At December 31, 2005, our contract drilling in progress totaled $1.2 million, all of which relates to the revenue recognized but not yet billed or costs deferred on daywork contracts in progress at December 31, 2005.
We accrue estimated contract costs on footage contracts for each day of work completed based on our estimate of the total costs to complete the contract divided by our estimate of the number of days to complete the contract. Contract costs include labor, materials, supplies, repairs and maintenance and operating overhead allocations. In addition, the occurrence of uninsured or under-insured losses or operating cost overruns on our footage contracts could have a material adverse effect on our financial position and results of operations. Therefore, our actual results could differ significantly if our cost estimates are later revised from our original estimates for contracts in progress at the end of a reporting period that were not completed prior to the release of our financial statements.
Index to Financial Statements Accounts Receivable-We evaluate the creditworthiness of our customers based on their financial information, if available, information obtained from major industry suppliers, current prices of oil and natural gas and any past experience we have with the customer. Consequently, an adverse change in those factors could affect our estimate of our allowance for doubtful accounts. In some instances, we require new customers to establish escrow accounts or make prepayments. We typically invoice our customers at 30-day intervals during the performance of daywork contracts and upon completion of the daywork contract. Footage contracts are invoiced upon completion of the contract. Our typical contract provides for payment of invoices in 10 to 30 days. We generally do not extend payment terms beyond 30 days and have not extended payment terms beyond 60 days for any of our contracts in the last three years. Our allowance for doubtful accounts was $330,000 and $146,000 at December 31, 2005 and December 31, 2004, respectively. Any allowance established is subject to judgment and estimates made by management. We determine our allowance by considering a number of factors, including the length of time trade accounts receivable are past due, our previous loss history, our customer’s current ability to pay its obligation to us and the condition of the general economy and the industry as a whole. We write off specific accounts receivable when they become uncollectible and payments subsequently received on such receivables are credited to the allowance for doubtful accounts.
If a customer defaults on its payment obligation to us under a footage contract, we would need to rely on applicable law to enforce our lien rights, because our 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 might also 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 footage contract.
Asset Impairment and Depreciation-We assess the impairment of property and equipment, intangible assets and goodwill whenever events or circumstances indicate that the carrying value may not be recoverable. Factors that we consider important and could trigger an impairment review would be our customers’ financial condition and any significant negative industry or economic trends. More specifically, among other things, we consider our contract revenue rates, our rig utilization rates, cash flows from our drilling rigs, current oil and natural gas prices, industry analysts’ outlook for the industry and their view of our customers’ access to debt or equity and the trends in the price of used drilling equipment observed by our management. If a review of our drilling rigs, intangible assets and goodwill indicate that our carrying value exceeds the estimated undiscounted future cash flows, we are required under applicable accounting standards to write down the drilling equipment, intangible assets and goodwill to its fair market value. A one percent write-down in the cost of our drilling equipment, intangible assets and goodwill, at December 31, 2005, would have resulted in a corresponding decrease in our net income of approximately $1.7 million for the year ended December 31, 2005.
Our determination of the estimated useful lives of our depreciable assets, 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 rigs, transportation and other equipment on a straight-line method over useful lives that we have estimated and that range from three to fifteen years after the rig was placed into service. We record the same depreciation expense whether an operating rig is idle or working. Depreciation is not recorded on an inventoried rig until placed in service. Our estimates of the useful lives of our drilling, transportation and other equipment are based on our experience in the drilling industry with similar equipment.
We capitalize interest cost as a component of drilling rigs refurbished for our own use. During the years ended December 31, 2005 and 2004, we capitalized approximately $1.2 million and $470,000 of interest incurred, respectively.
Deferred Taxes-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
Index to Financial Statements
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 the stock in an entity rather than just its assets. For financial reporting purposes, we depreciate the various components of our drilling rigs and refurbishments over fifteen 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.
Other Accounting Estimates-Our other accrued expenses as of December 31, 2005 and December 31, 2004 included accruals of approximately $16,000 and $94,000, respectively, for costs under our workers’ compensation insurance. We have a deductible of $250,000 per covered accident under our workers’ compensation insurance. Our insurance policy requires us to maintain a letter of credit to cover payments by us of that deductible. As of December 31, 2005, we had a $2.2 million letter of credit for which we have a deposit account in the amount of $2.2 million collateralizing the letter of credit. 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 paid directly by us, our estimate of the administrative costs associated with these claims and our historical experience with these types of claims.
Year in Review Highlights
The following are recent highlights that have impacted our results of operations for the year ended December 31, 2005:
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On August 19, 2005, we closed our initial public offering of a total of 5,865,000 shares of common stock at a price of $17.00 per share. A total of 5,715,000 shares were sold by us and 150,000 shares were sold by our principal stockholder. We received net proceeds of approximately $89.0 million.
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On November 2, 2005, we completed a follow-on public offering of 4,025,000 shares of our common stock at a price of $23.00 per share. We received net proceeds of approximately $87.0 million.
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During 2005, we acquired 28 rigs and related structures, equipment and components. We also completed the acquisition of 18 trucks and related equipment.
Recent Developments
Since December 31, 2005, we have completed the following:
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On January 13, 2006, we entered into a $150.0 million revolving credit facility with Fortis Capital Corp., as administrative agent, lead arranger and sole bookrunner, and a syndicate of lenders, which include The Royal Bank of Scotland plc, The CIT Group/Business Credit, Inc., Calyon Corporate and Investment Bank, Merrill Lynch Capital, Comerica Bank and Caterpillar Financial Services Corporation. The revolving credit facility matures on January 13, 2009.
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On January 18, 2006, we completed the acquisition of six land drilling rigs and certain other assets, including heavy haul trucks and excess rig equipment and inventory, from Big A Drilling.
Index to Financial Statements Results of Operations
Year Ended December 31, 2005 Compared to Year Ended December 31, 2004
Contract Drilling Revenue. For the year ended December 31, 2005, we reported contract drilling revenues of approximately $77.9 million, a 256% increase from revenues of $21.9 million for 2004. The increase is primarily due to increases in dayrates, revenue days, utilization and average number of rigs working for the year ended December 31, 2005 as compared to 2004. Average dayrates for our drilling services increased $5,534, or 70%, to $13,453 for the year ended December 31, 2005 from $7,919 in 2004. Revenue days increased 112% to 5,781 days for the year ended December 31, 2005 from 2,733 days during 2004. Our utilization increased to 95% from 81%, and our average number of operating rigs increased to 17 from nine, or 89%, for the year ended December 31, 2005 as compared to 2004. The increase in the number of revenue days for the year ended December 31, 2005 as compared to 2004 is attributable to the increase in the size of our operating rig fleet and improvements in our rig utilization rate due to improved market conditions. Based on our plan to refurbish and deploy our inventoried rigs and current market conditions, we anticipate continued growth in revenue days and stable utilization rates for the balance of 2006.
Contract Drilling Expense. Direct rig cost increased $26.0 million to $44.7 million for the year ended December 31, 2005 from $18.7 million in 2004. This 143% increase is primarily due to the increases in revenue days, average number of operating rigs in our fleet and in rig utilization for the year ended December 31, 2005 as compared to 2004. As a percentage of contract drilling revenue, drilling expense decreased to 57% for the year ended December 31, 2005 from 85% in 2004 for the reasons discussed above.
Depreciation and Amortization Expense. Depreciation and amortization expense increased $5.4 million to $9.1 million for year ended December 31, 2005 from $3.7 million in 2004. The increase is primarily due to the 203% increase in fixed assets, including the refurbishment of seven additional rigs from our inventory, the Strata and Hays acquisitions, incremental increases in ancillary equipment as compared to 2004 and, to a lesser extent, amortization of intangible assets from our acquisitions.
General and Administrative Expense. General and administrative expense increased $7.7 million, or 453%, to $9.4 million for the year ended December 31, 2005 from $1.7 million in 2004. This primarily resulted from a $5.1 million increase in payroll costs, a $184,000 increase in administrative reimbursement, an increase of $52,000 in bad debt expense, an increase of $589,000 in stock compensation expense, and lease expense and professional fee increases of $271,000 and $540,000, respectively. The increase in payroll costs to $5.8 million for the year ended December 31, 2005 from $672,000 in 2004 is primarily due to payments made by Bronco Drilling Holdings, L.L.C. to our former President and Chief Operating Officer, Steve Hale, following successful completion of our initial public offering. Although we did not make the payment, we are required to account for these payments as a capital contribution to us in the amount of $4.0 million and compensation expense of $4.0 million. The remaining increase in payroll costs is due to our increased employee count and related wage increases during 2005. The increase in administrative reimbursement to $299,000 for the year ended December 31, 2005 from $115,000 in 2004 is due to the new administrative services agreement entered into with Gulfport and the increased level of services provided thereunder. The increase in lease expense to $358,000 for the year ended December 31, 2005 from $87,000 in 2004 is primarily due to the lease of additional yards that were part of the Elk Hill acquisition. The increase in professional fees to $620,000 for the year ended December 31, 2005 from $80,000 in 2004 is due to an increase in audit and legal expense. The remaining increase in compensation expense is due to our increased employee count resulting from both organic growth and the Strata, Hays, Eagle and Thomas acquisitions, as well as selected wage increases.
Interest Expense. Interest expense increased $1.1 million to $1.4 million for the year ended December 31, 2005 from $285,000 in 2004. The increase is due to an increase in average debt outstanding. We capitalized $1.2 million of interest for the year ended December 31, 2005 as compared to $470,000 in 2004 as part of our rig refurbishment program. We also incurred $2.1 million in expense related to the early extinguishment of debt associated with the payoff of our credit facility with General Electric Capital Corporation, or GECC, and our loan with Theta Investors, L.L.C.
Index to Financial Statements Income Tax Expense. We recorded an income tax expense of $6.5 million for the year ended December 31, 2005. This compares to an income tax expense of $285,000 in 2004. This increase is due mainly to our conversion from a limited liability company to a taxable entity in August 2005 in connection with our initial public offering, which resulted in a liability and expense of approximately $4.4 million at the time of the initial public offering. This is partially offset by the net operating loss that we recognized in the third quarter related to several non-recurring items which include the $4.0 million payment made to our former President and Chief Operating Officer and the $2.1 million loss on the early extinguishment of debt.
Year Ended December 31, 2004 Compared to Year Ended December 31, 2003
Contract Drilling Revenue. For the year ended December 31, 2004, we reported contract drilling revenues of $21.9 million, a 75% increase from revenues of $12.5 million during 2003. The increase is primarily due to increases in dayrates, revenue days, utilization and average number of rigs working for the year ended December 31, 2004 as compared to 2003. Average dayrates for our drilling services increased $1,370, or 21%, to $7,919 for contracts completed in the year ended December 31, 2004 from $6,549 in 2003. Revenue days increased 44% to 2,733 days for the year ended December 31, 2004 from 1,898 days during 2003. Our average number of operating rigs increased to nine from seven, or 29%, for the year ended December 31, 2004 as compared to 2003. The increase in the number of revenue days in 2004 as compared to 2003 is attributable to the increase in the size of our operating rig fleet and improvements in our rig utilization rate due to improved market conditions.
Contract Drilling Expense. Direct rig cost increased $8.1 million to $18.7 million for the year ended December 31, 2004 from $10.5 million in 2003. The 77% increase is primarily due to the increases in revenue days, average number of rigs in our fleet and rig utilization in 2004 as compared to 2003. As a percentage of contract drilling revenue, drilling expense increased to 85% in 2004 from 84% in 2003.
Depreciation Expense. Depreciation expense increased $1.7 million to $3.7 million for the year ended December 31, 2004 from $2.0 million in 2003. The increase is primarily due to the 28% increase in fixed assets, including the deployment of four additional rigs during 2004, as well as incremental increases in ancillary equipment as compared to 2003.
General and Administrative Expense. General and administrative expense increased $488,000, or 40%, to $1.7 million for the year ended December 31, 2004 from $1.2 million in 2003. This primarily resulted from a $303,000 increase in payroll costs and lease expense and professional fee increases of $75,000 and $77,000, respectively. The increase in payroll costs to $672,000 for the year ended December 31, 2004 from $369,000 in 2003 is due to our increased employee count and related wage increases during 2004. The increase in lease expense to $177,000 for the year ended December 31, 2004 from $102,000 in 2003 is due to the lease of additional yards that were part of the Elk Hill acquisition. The increase in professional fees to $80,000 for the year ended December 31, 2004 from $3,000 in 2003 is due to an increase in audit and legal expense.
Interest Expense. Interest expense increased $263,000 to $285,000 for the year ended December 31, 2004 from $21,000 in 2003. The increase is due to an increase in average debt outstanding during 2004 under our credit facility with GECC that we entered into on December 26, 2003. We capitalized $470,000 of interest during 2004 as part of our rig refurbishment program.
Deferred Tax Expense. Deferred tax expense decreased by $32,000, or 10%, to $285,000 for the year ended December 31, 2004 from $317,000 in 2003. The decrease in deferred tax expense is due to a reduction in income by our taxable subsidiary Elk Hill for the year ended December 31, 2004 as compared to 2003.
Liquidity and Capital Resources
Operating Activities. Net cash provided by operating activities was $3.3 million in 2005 as compared to $2.4 million in 2004, and $1.9 million used in 2003. The increase of $900,000 from 2005 to 2004 was primarily
Index to Financial Statements
due to increased cash receipts from customers, partially offset by higher cash payments to employees and suppliers. The change from 2003 to 2004 was primarily attributable to placing refurbished drilling rigs acquired in 2003 in service.
Investing Activities. We use a significant portion of our cash flows from operations and financing activities for acquisitions and for the refurbishment of our rigs. We used cash for investing activities of $190.3 million for 2005 as compared to approximately $19.5 million for 2004, and $4.8 million for 2003. Of this $190.3 million, approximately $135.2 million was used for acquisitions made during 2005 and related transaction costs, $43.8 million was used to refurbish drilling rigs and $1.5 million was placed in a restricted account as security for a letter of credit issued to our workers’ compensation insurance carrier. In August 2003, we acquired 22 drilling rigs and drilling rig structures and components for $33.5 million in cash plus the assumption of $15.5 million of deferred tax liabilities. The cash portion of the purchase price was funded directly by our equity holders. Accordingly, the transaction has been accounted for as an acquisition by our equity holders followed by their contribution to us of the acquired assets. As a result, net cash used in investing activities for 2003 does not include this $33.5 million. See Note 2 to our financial statements appearing elsewhere in this Form 10-K. Also in 2003, we refurbished one of our rigs at a cost of approximately $2.2 million. In 2004, we refurbished four drilling rigs at an aggregate cost of approximately $13.0 million.
Financing Activities. Our cash flows provided by financing activities were $202.9 million for 2005 as compared to $16.6 million for 2004, and $7.8 million for 2003. Our net cash provided by financing activities for 2005 related to net proceeds of approximately $176.0 million from our initial and follow-on public offerings, borrowings of $43.0 million under our credit agreement with Merrill Lynch, borrowings of $68.0 million from Solitair LLC, Theta Investors LLC, and Alpha Investors LLC, entities controlled by Wexford, borrowings of $7.5 million from GECC, and borrowings of $1.2 million from International Bank of Commerce, partially offset by principal payments on borrowings of $23.8 million to GECC, $68.0 million to Solitair LLC and Alpha Investors LLC, and capital contributions of $1.5 million from entities controlled by Wexford. For 2004, our net cash provided by financing activities related to $15.0 million borrowed under our credit facility with GECC, borrowings of $500,000 from International Bank of Commerce, principal payments of $1.2 million to GECC, and capital contributions of $2.9 million from entities controlled by Wexford. For 2003, our net cash provided by financing activities related to capital contributions of $3.7 million from entities controlled by Wexford, borrowings of $3.0 million under our credit facility with GECC and proceeds of $1.3 million from a note payable to International Bank of Commerce.
Sources of Liquidity. Our primary sources of liquidity are cash from operations and debt and equity financing.
Debt Financing. On December 26, 2003, we entered into a credit facility with GECC which provided for term loan advances of up to $12.0 million. At September 24, 2004 and April 22, 2005, we amended our credit facility with GECC to increase the maximum amount of the terms loans to $18.0 million and then to $25.5 million, respectively. Borrowings under this facility bore interest at a rate equal to LIBOR plus 5.0% and were secured by substantially all of our property and assets, including our drilling rigs and associated equipment, and ownership interests in our subsidiaries, but excluding cash and accounts receivable. Draws on the facility were required to be in $2.5 million increments each with a five-year term. Payments of principal and accrued but unpaid interest were due on the first day of each month. This credit facility, which was to mature on October 1, 2010, was repaid in full on August 29, 2005 with a portion of the proceeds from our initial public offering and the credit facility was terminated.
On July 1, 2004, we entered into a revolving line of credit with International Bank of Commerce with a borrowing base of the lesser of $2.0 million or 80% of current receivables. Borrowings under this line bore interest at a rate equal to the greater of 4.0% or JPMorgan Chase prime (effective rate of 7.25% at December 31, 2005). Accrued but unpaid interest was payable monthly. On January 1, 2005, we amended our line of credit with International Bank of Commerce to increase the borrowing base to the lesser of $3.0 million or 80% of current
Index to Financial Statements
receivables. The line of credit had a maturity date of November 1, 2006. It was repaid in full in January 2006 with a portion of the proceeds from our new revolving credit facility and then terminated.
On February 15, 2005, we entered into a $5.0 million revolving credit facility with Solitair LLC, an entity controlled by Wexford. Borrowings under this facility bore interest at a rate equal to LIBOR plus 5.0%. Payment of principal and accrued but unpaid interest were due on the maturity date of the credit facility which was the later of (1) six months after the actual maturity date of our credit facility with GECC and (2) December 1, 2010. We repaid this facility in full on August 22, 2005 with a portion of the proceeds from our initial public offering and the facility was terminated.
In July 2005, we acquired all of the membership interests in Strata Drilling, L.L.C. and Strata Property, L.L.C. and a related rig yard for an aggregate of $20.0 million, of which $13.0 million was paid in cash and $7.0 million paid in the form of promissory notes issued to the sellers. We funded the cash portion of the purchase price with a $13.0 million loan from Alpha Investors LLC, an entity controlled by Wexford. The outstanding principal balance of the loan plus accrued but unpaid interest was due in full upon the earlier to occur of the completion of our initial public offering and the maturity of the loan on July 1, 2006. We repaid this loan in full on August 22, 2005 with a portion of the proceeds from our initial public offering. Borrowings under our loan with Alpha bore interest at a rate equal to LIBOR plus 5% until September 30, 2005, and thereafter were to bear interest at a rate equal to LIBOR plus 7.5%. The $7.0 million original aggregate principal balance of the promissory notes issued to the sellers was automatically reduced by the amount of any costs and expenses we paid in connection with the refurbishment of one of the rigs we acquired from the sellers. The amount due on these notes, net of costs and expenses paid by us, was $4.5 million at December 31, 2005. The outstanding balance of the loan was paid in full on January 5, 2006 upon completion of the refurbishment of this rig.
On September 19, 2005, we entered into a term loan and security agreement with Merrill Lynch Capital, a division of Merrill Lynch Business Financial Services, Inc. The term loan provided for a term installment loan in an aggregate amount not to exceed $50.0 million and provided for a commitment by Merrill Lynch to advance funds from time to time until December 31, 2005. The outstanding balance under the term loan could not exceed 60% of the net orderly liquidation value of our operating land drilling rigs. On September 19, 2005, we borrowed $43.0 million under the term loan. A portion of these borrowings, together with proceeds from our initial public offering, were used to fund the Eagle acquisition. The term loan bore interest on the outstanding principal balance at a variable per annum rate equal to LIBOR plus 271 basis points (7.1% at December 31, 2005). For the period from September 19, 2005 to January 1, 2006, interest only was payable monthly on the outstanding principal balance. Commencing February 1, 2006, the outstanding principal and interest on the term loan were payable in sixty consecutive monthly installments, each in an amount equal to one sixtieth of the outstanding principal balance on January 1, 2006 plus accrued interest on the outstanding principal balance. The maturity date was January 1, 2011. Our obligations under the term loan were secured by a first lien and security interest on substantially all of our assets and were guaranteed by each of our principal subsidiaries. The term loan included usual and customary negative covenants and events of default for loan agreements of this type. The term loan also required us to meet certain financial covenants, including maintaining a minimum Fixed Charge Coverage Ratio and a maximum Total Debt to EBITDA Ratio. This term loan was repaid in full in January 2006 with a portion of the proceeds from our new revolving credit facility and the term loan was terminated.
On October 14, 2005, we entered into a loan agreement with Theta Investors, LLC, an entity controlled by Wexford, for purposes of funding a portion of the purchase price for the Thomas acquisition. The Theta loan provided maximum aggregate borrowings of up to $60.0 million, which borrowings bore interest at a rate equal to LIBOR plus 400 basis points until December 15, 2005 and, thereafter, at a rate equal to LIBOR plus 600 basis points. Payment of principal and accrued but unpaid interest was due on October 15, 2006. Our obligations under the Theta loan were guaranteed by each of our principal subsidiaries. We borrowed $50.0 million under this loan on October 14, 2005. We repaid this facility in full on November 3, 2005 with a portion of the proceeds from our follow-on public offering, which closed November 2, 2005.
Index to Financial Statements On January 13, 2006, we entered into a $150.0 million revolving credit facility with Fortis Capital Corp., as administrative agent, lead arranger and sole bookrunner, and a syndicate of lenders, which include The Royal Bank of Scotland plc, The CIT Group/Business Credit, Inc., Calyon Corporate and Investment Bank, Merrill Lynch Capital, Comerica Bank and Caterpillar Financial Services Corporation. The revolving credit facility matures on January 13, 2009. Loans under the revolving credit facility bear interest at LIBOR plus a margin that can range from 2.0% to 3.0% or, at our option, the prime rate plus a margin that can range from 1.0% to 2.0%, depending on the ratio of our outstanding senior debt to “Adjusted EBITDA” as defined in the credit agreement. Our borrowings under this revolving credit facility were use to fund a portion of the Big A Drilling acquisition and to repay in full all outstanding borrowings under our term loan with Merrill Lynch Capital and our revolving line of credit with International Bank of Commerce.
The revolving credit facility also provides for a quarterly commitment fee of 0.5% per annum of the unused portion of the revolving credit facility, and fees for each letter of credit issued under the facility. Our subsidiaries have guaranteed the loans and other obligations under the revolving credit facility. The obligations under the revolving credit facility and the related guarantees are secured by a first priority security interest in substantially all of our assets, as well as the shares of capital stock of our direct and indirect subsidiaries.
The revolving credit facility contains customary covenants for facilities of such type, including among other things covenants that restrict our ability to make capital expenditures, incur indebtedness, incur liens, dispose of property, repay debt, pay dividends, repurchase shares and make certain acquisitions. The financial covenants are a minimum fixed charge coverage ratio of 1.75 to 1.00 and a maximum total leverage ratio of 2.00 to 1.00. The revolving credit facility provides for mandatory prepayments under certain circumstances as more fully discussed in the revolving credit facility. The revolving credit facility contains various events of default, including failure to pay principal and interest when due, breach of covenants, materially incorrect representations, default under certain other agreements, bankruptcy or insolvency, the occurrence of specified ERISA events, entry of enforceable judgments against us in excess of $3.0 million not stayed, and the occurrence of a change of control. If an event of default occurs, all commitments under the revolving credit facility may be terminated and all of our obligations under the revolving credit facility could be accelerated by the lenders, causing all loans outstanding (including accrued interest and fees payable thereunder) to be declared immediately due and payable.
Issuances of Equity. Our equity holders contributed capital in the amounts of $1.5 million during 2005, and $2.7 million during 2004.
In August 2005, we completed our initial public offering of a total of 5,865,000 shares of common stock at a price of $17.00 per share. In the offering, a total of 5,715,000 shares were sold by us and 150,000 shares were sold by Wexford. We received net proceeds of approximately $89.0 million. We used a portion of these proceeds to repay in full our loans from Alpha and Solitair and all borrowings under our credit facility with GECC.
Under the terms of an agreement between Bronco Drilling Holdings, L.L.C. and Steven C. Hale, our former President and Chief Operating Officer, following successful completion of our initial public offering Mr. Hale was entitled to receive the sum of $2.0 million and shares of our common stock having a market value of $2.0 million based on the initial public offering price. These payments were made by Bronco Drilling Holdings and not by us. We accounted for these payments as a capital contribution to us in the amount of $4.0 million and compensation expense in the amount of $4.0 million during the third quarter of 2005, the period in which such obligations were incurred.
On November 2, 2005, we received net proceeds of $87.5 million from a follow-on public offering of 4,025,000 shares of our common stock at a price of $23.00 per share. We repaid the Theta facility in full on November 3, 2005 with a portion of the proceeds from that offering.
In connection with our acquisitions of Hays Trucking, Inc. and Big A Drilling, we issued 65,368 and 72,571 shares of our common stock, respectively. See “-Capital Expenditures” below.
Index to Financial Statements On January 31, 2006, we filed a registration statement with the Securities and Exchange Commission for a proposed public offering of 3,000,000 shares of our common stock, 1,700,000 shares of which are to be sold by us and 1,300,000 shares of which are to be sold by Bronco Drilling Holdings, L.L.C. We intend to use the net proceeds from our sale of shares in the offering to repay outstanding borrowings under our new revolving credit facility.
Capital Expenditures. In August 2003, our founders purchased all of the outstanding stock of Elk Hill Drilling, Inc. and certain drilling rig structures and components from an affiliate of Elk Hill, U.S. Rig & Equipment, for $33.5 million in cash plus the assumption of $15.5 million of deferred tax liabilities and contributed the assets and liabilities to us. In these transactions, we acquired drilling rigs and inventoried structures and components which, with refurbishment and upgrades, could be used to assemble 22 drilling rigs. At the date of its acquisition, Elk Hill had no customers, employees, operations or operational drilling rigs. For accounting purposes, the Elk Hill and U.S. Rig and Equipment acquisitions were treated as acquisitions by our members and then contributions to us. In November 2003, we completed the refurbishment of a 1,400-horsepower electric drilling rig, which we designated as Rig No. 16. We incurred approximately $2.2 million in refurbishment costs for this rig before it was mobilized to Southern Oklahoma in November 2003. Acquisitions and refurbishment expenditures in 2003 were funded through capital contributions from our equity holders.
In March 2004, we completed the refurbishment of a 1,500-horsepower electric drilling rig, which we designated as Rig No. 12. We incurred approximately $2.3 million in refurbishment costs for this rig which we financed with borrowings under our GECC credit facility. We mobilized Rig No. 12 to Grayson County, Texas in March 2004.
In May 2004, we completed the refurbishment of a 1,000-horsepower electric drilling rig, which we designated as Rig No. 11. We incurred approximately $2.7 million in refurbishment costs for this rig. We mobilized Rig No. 11 to Southern Oklahoma in May 2004. In August 2004, we completed the refurbishment of a 1,000-horsepower electric drilling rig, which we designated as Rig No. 10. We incurred approximately $3.2 million in refurbishment costs for this rig. We mobilized Rig No. 10 to Western Oklahoma in August 2004. In December 2004, we completed the refurbishment of a 2,000-horsepower electric drilling rig, which we designated as Rig No. 18. We incurred approximately $4.8 million in refurbishment costs for this rig. We mobilized Rig No. 18 to Eastern Oklahoma in December 2004. Our refurbishment costs for these rigs were financed with borrowings under our GECC credit facility.
In March 2005, we completed the refurbishment of a 1,200-horsepower electric drilling rig, which we designated as Rig No. 14. We incurred approximately $4.8 million in refurbishment costs for this rig which we financed with borrowings under our GECC credit facility. We mobilized Rig No. 14 to Southern Oklahoma in March 2005.
In July 2005, we completed the refurbishment of a 2,500-horsepower electric drilling rig, which we designated as Rig No. 19. We incurred approximately $6.6 million in refurbishment costs for this rig which we financed with borrowings under our GECC credit facility. We mobilized Rig No. 19 to Southern Oklahoma in July 2005.
In July 2005, we acquired three drilling rigs of 650, 800 and 1,000 horsepower, and related inventory, equipment and components, through our acquisitions of Strata Drilling, L.L.C. and Strata Property, L.L.C., together with a related rig yard, for an aggregate of $20.0 million. The acquisitions were funded with borrowings of $13.0 million from Alpha Investors LLC, an entity controlled by Wexford, and our delivery of promissory notes for an aggregate of $7.0 million. The outstanding balance of this note was paid in full in January 2006.
In August 2005, we completed the refurbishment of a 950-horsepower mechanical drilling rig, which we designated as Rig No. 4. We incurred approximately $4.5 million in refurbishment costs for this rig which we financed with borrowings under our GECC credit facility. We mobilized Rig No. 4 to the Piceance Basin in Colorado in September 2005.
Index to Financial Statements In September 2005, we acquired all the outstanding common stock of Hays Trucking, Inc. for $3.0 million in cash and 65,368 shares of our common stock. In this acquisition, we acquired 18 trucks used to mobilize our rigs to contracted drilling locations.
On October 3, 2005, we purchased 12 rigs from Eagle Drilling, L.L.C. and two of its affiliates. The acquisition involved five operating rigs, seven inventoried rigs and equipment and parts for a purchase price of approximately $50.0 million plus approximately $500,000 of related transaction costs. We funded this acquisition with borrowings under our Merrill Lynch term loan and a portion of the proceeds from our initial public offering.
On October 14, 2005, we purchased 13 rigs from Thomas Drilling Co. The acquisition involved nine operating rigs, two rigs currently under construction, two inventoried rigs, and excess rig equipment and parts for a purchase price of $68.0 million plus approximately $2.6 million of related net transaction costs. In connection with the Thomas acquisition, we leased an additional rig refurbishment yard for a six month term, with the right to extend the term for an additional three years. We also obtained an option to purchase the yard at any time during the term for $175,000. We funded $50.0 million of the purchase price with borrowings under our Theta loan and the remainder with a portion of the proceeds from our initial public offering.
In October 2005, we completed the refurbishment of a 1,000-horsepower electric drilling rig, which we designated as Rig No. 8. We incurred approximately $6.0 million in refurbishment costs for this rig which we financed with proceeds from our initial public offering. We mobilized Rig No. 8 to the Williston Basin in North Dakota in November 2005.
In January 2006, we completed the refurbishment of a 1,700-horsepower electric drilling rig, which we designated Rig No. 17. We incurred approximately $6.0 million in refurbishment costs for this rig which we financed with proceeds from our November 2005 follow-on offering. We mobilized Rig No. 17 to West Oklahoma in January 2006.
In January 2006, we completed the refurbishment of a 1,200-horsepower electric drilling rig, which we designated Rig No. 15. We incurred approximately $6.4 million in refurbishment costs for this rig which we financed with proceeds from our November 2005 follow-on offering. We mobilized Rig No. 15 to East Texas in January 2006.
In January 2006, the refurbishment of a 1,000-horsepower mechanical rig was completed pursuant to a $7.0 million seller’s note incurred in the Strata acquisition. We designated this Rig No. 43 and financed the payment of the note with proceeds from our November 2005 follow-on offering. We mobilized Rig No. 43 to East Texas in January 2006.
On January 18, 2006, we purchased six operating rigs and certain other assets, including heavy haul trucks and excess rig equipment and inventory, from Big A Drilling, L.C. The purchase price for the assets consisted of $16.3 million paid in cash and 72,571 shares of our common stock.
In March 2006, we completed the refurbishment of a 1,100 horsepower mechanical drilling rig, which we designated Rig No. 57. We incurred approximately $2.3 million in refurbishment costs for this rig which we financed with proceeds from our November 2005 follow-on offering. We mobilized Rig No. 57 to Eastern Oklahoma in March 2006.
We intend to refurbish twelve inventoried rigs during 2006 at estimated costs (including drill pipe) ranging from $900,000 to $6.5 million per rig. We continue to focus our refurbishment program on our more powerful rigs, generally with 1,000 to 2,000 horsepower, which are capable of drilling to depths between 15,000 and 25,000 feet. We plan on refurbishing additional rigs in 2007 and thereafter. The timing of these refurbishments will depend upon market and other factors, including our estimation of existing and anticipated demand and dayrates, our success in bidding for domestic contracts, including term contracts, and the expected time needed to
Index to Financial Statements
complete the refurbishments. The actual cost of refurbishing our rigs will depend upon such factors as the availability of equipment, unforeseen engineering problems, work stoppages, weather interference, unanticipated cost increases, inability to obtain necessary certifications and approvals, shortages of skilled labor and the specific customer requirements.
We believe that cash flow from our operations and borrowings under our new revolving credit facility will be sufficient to fund our operations for at least the next twelve months. However, additional capital will likely be required for future rig acquisitions and refurbishments. While we would expect to fund such acquisitions with additional borrowings and the issuance of debt and equity securities, we cannot assure you that such funding will be available or, if available, that it will be on terms acceptable to us.
Contractual and Commercial Commitments
The following table summarizes our contractual obligations and commercial commitments at December 31, 2005 (in thousands):
Off Balance Sheet Arrangements
We do not have any off balance sheet arrangements.
Recent Accounting Pronouncements
SFAS No. 154
In May 2005, the FASB issued SFAS No. 154, “Accounting Changes and Error Corrections.” This is a replacement of APB Opinion No. 20, “Accounting Changes” and SFAS No. 3, “Reporting Accounting Changes in Interim Financial Statements.” Under SFAS 154, all voluntary changes in accounting principles as well as changes pursuant to accounting pronouncements that do not include specific transition requirements, must be applied retrospectively to prior periods’ financial statements. Retrospective application requires the cumulative effect of each change to be reflected in the carrying value of assets and liabilities as of the first period presented and the offsetting adjustments to be recorded in retained earnings for the first period presented. Also, under the new statement, a change in an accounting estimate continues to be accounted for in the period of the change and in future periods if necessary. Under SFAS 154, corrections of errors should continue to be reported by restating prior period financial statements as of the beginning of the first period presented, if material. The statement is effective for accounting changes and corrections of errors made in fiscal years beginning after December 15, 2005. We adopted SFAS 154 effective January 1, 2006. It is anticipated that adoption will not have a material impact on our financial position and results of operations.
Item 7A.
Item 7A. Quantitative and Qualitative Disclosures About Market Risk.
We are subject to market risk exposure related to changes in interest rates on our outstanding floating rate debt. Borrowings under our new revolving credit facility bear interest at a floating rate equal to LIBOR plus a margin that can range from 2.0% to 3.0% or, at our option, the prime rate plus a margin that can range from 1.0% to 2.0%, depending on the ratio of our outstanding senior debt to adjusted EBITDA. An increase or decrease of
Index to Financial Statements
1% in the interest rate would have a corresponding decrease or increase in our net income (loss) of approximately $353,000 annually, based on the $57.0 million outstanding in the aggregate under our credit facility as of February 28, 2006.
Item 8.
Item 8. Financial Statements and Supplementary Data.
Our Financial Statements begin on page of this Form 10-K, Index to Consolidated Financial Statements, and are incorporated herein by this reference.
Item 9.
Item 9. Changes in and Disagreements With Accountants on Accounting and Financial Disclosure.
None.
Item 9A.
Item 9A. Controls and Procedures.
Evaluation of Disclosure Control and Procedures. Under the direction of the Chief Executive Officer and the Chief Financial Officer, we have established disclosure controls and procedures that are designed to ensure that information required to be disclosed in the reports that we file or submit under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms. The disclosure controls and procedures are also intended to ensure that such information is accumulated and communicated to our management, including our Chief Executive Officer and the Vice President and Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosures.
As of December 31, 2005, an evaluation was performed under the supervision and with the participation of our management, including the Chairman and Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of our disclosure controls and procedures pursuant to Rule 13a-15 under the Securities Exchange Act of 1934. Based upon their evaluation, the Chairman and Chief Executive Officer and Chief Financial Officer have concluded that as of December 31, 2005, our disclosure controls and procedures are effective.
Changes in Internal Control over Financial Reporting. There have not been any changes in our internal control over financial reporting that occurred during the last fiscal quarter that have materially affected, or are reasonably likely to materially affect, internal control over financial reporting.
Item 9B.
Item 9B. Other Information.
None.
Index to Financial Statements
PART III
Item 10.
Item 10. Directors and Executive Officers of the Registrant.
Set forth below is the name, age, position and a brief account of the business experience of each of our executive officers and directors.
Name
Age
Position
D. Frank Harrison
Chief Executive Officer, President and Director
Zachary M. Graves
Chief Financial Officer, Secretary and Treasurer
Karl W. Benzer
Chief Operating Officer
Mike Liddell
Chairman of the Board and Director
David L. Houston
Director
Phillip Lancaster
Director
William R. Snipes
Director
D. Frank Harrison has served as served as Chief Executive Officer and a director of our company since May 2005 and as President since August 2005. Mr. Harrison served as President of Harding & Shelton, Inc., a privately held oil and natural gas exploration, drilling and development firm, from 1999 to 2002. From 2002 to 2005, Mr. Harrison served as an agent for the purchase and sale of oil and gas properties for entities controlled by Wexford. He graduated from Oklahoma State University with a Bachelor of Science degree in Sociology.
Zachary M. Graves has served as Chief Financial Officer, Secretary and Treasurer of our company since April 2005. He previously served as our Controller and the Controller of Gulfport from April 2003 to March 2005. Prior to joining our company, Mr. Graves served as an accountant with KPMG LLP from August 2000 to April 2003. He received a Bachelor of Business Administration degree in Accounting from the University of Oklahoma and is a licensed Certified Public Accountant.
Karl W. Benzer has served as our Chief Operating Officer since August 2005. From 2002 to August 2005, Mr. Benzer served as a Vice President and Division Manager of Unit Drilling Co., a privately held oil and natural gas land drilling company. From 1994 to 2001, Mr. Benzer served as the Senior Vice President of UTI Drilling L.P. and manager of Southland Drilling Company, Ltd and UTI Central Purchasing. UTI Energy Corp. was a publicly held oil and natural gas land drilling company that subsequently merged with Patterson Energy, Inc., a publicly held oil and natural gas land drilling company. Mr. Benzer graduated from the University of Rhode Island with a Bachelor of Science degree in Mechanical Engineering and a Master of Business Administration.
Mike Liddell has served as the Chairman of the Board and a director of our company since May 2005. Mr. Liddell has served as a director of Gulfport Energy Corporation since July 11, 1997, as its Chief Executive Officer since April 28, 1998, as its Chairman of the Board since July 28, 1998 and as its President since July 15, 2000. He received a Bachelor of Science degree in Education from Oklahoma State University.
David L. Houston has served as a director of our company since May 2005. Since 1991, Mr. Houston has been the principal financial advisor of Houston Financial, a firm that offers life and disability insurance, compensation and benefits plans and estate planning. He currently serves on the board of directors of Gulfport Energy Corporation and the board of directors and executive committee of Deaconess Hospital, located in Oklahoma City, Oklahoma. Mr. Houston is the former chair of the Oklahoma State Ethics Commission and the Oklahoma League of Savings Institutions. He received a Bachelor of Science degree in Business from Oklahoma State University and a graduate degree in Banking from Louisiana State University.
Phillip Lancaster has served as a director of our company since July 2005. Since April 2000, Mr. Lancaster’s has served as a managing director for a sports facility in Dallas, Texas which is affiliated with ClubCorp. Mr. Lancaster is a founder and has served as a director of three Australian companies, Ozpride Pty LTD., Texoz Pty LTD and Magipark Pty LTD since 1996, 1994 and 1990, respectively. The principal business of
Index to Financial Statements
these companies is real-estate investment and property management in Australia. Mr. Lancaster was the managing partner of Lankin Drilling Fund, Inc. from 1985 through 1999. Mr. Lancaster received a Bachelor of Science degree in Sociology from David Lipscomb College in 1978.
William R. Snipes has served as a director of our company since February 2006. Mr. Snipes has served as the owner and President of Snipes Insurance Agency, Inc., an independent insurance agency concentrating in property and liability insurance, since 1991. From 1981 to 1991, Mr. Snipes was the owner and President of William R. Snipes, CPA, Inc., a public accounting firm concentrating in financial accounting and tax services. He received a Bachelor of Science degree and a Masters degree in Accounting from Oklahoma State University and is a licensed Certified Public Accountant.
Our Board of Directors and Committees
Our board of directors currently consists of five directors. Our directors generally serve one-year terms from the time of their election until the next annual meeting of stockholders or until their successors are duly elected and qualified.
Our board of directors has established an audit committee whose functions include the following:
•
assist the board of directors in its oversight responsibilities regarding (1) the integrity of our financial statements, (2) our risk management compliance with legal and regulatory requirements, (3) our system of internal controls regarding finance and accounting and (4) our accounting, auditing and financial reporting processes generally, including the qualifications, independence and performance of the independent auditor;
•
prepare the report required by the SEC for inclusion in our annual proxy or information statement;
•
appoint, retain, compensate, evaluate and terminate our independent accountants;
•
approve audit and non-audit services to be performed by the independent accountants; and
•
perform such other functions as the board of directors may from time to time assign to the audit committee.
The specific functions and responsibilities of the audit committee are set forth in the audit committee charter.
Michael O. Thompson resigned from the audit committee on February 7, 2006 and as a member of our board of directors effective February 28, 2006. Effective February 28, 2006, our board of directors acted by unanimous written consent to appoint William R. Snipes to serve on our board of directors and appointed Mr. Snipes to serve on the audit committee. There are no agreements or understandings pursuant to which Mr. Snipes was appointed as a member of our board of directors. Our audit committee currently includes three independent directors, Mr. Houston, Mr. Snipes and Mr. Lancaster.
Pursuant to our bylaws, our board of directors may, from time to time, establish other committees to facilitate the management of our business and operations. Because we are considered to be controlled by Wexford under The Nasdaq National Market rules, we are eligible for exemptions from provisions of these rules requiring that a majority of the board be independent directors, nominating and corporate governance and compensation committees composed entirely of independent directors and written charters addressing specified matters. We have elected to take advantage of these exemptions.
Certain other information relating to this Item 10 is incorporated by reference to the Proxy Statement for our 2006 Annual Meeting of Stockholders, which will be filed with the Securities and Exchange Commission no later than 120 days after December 31, 2005.
Index to Financial Statements
Item 11.
Item 11. Executive Compensation.
The following table sets forth the compensation information earned during 2005 by our Chief Executive Officer and by the two most highly compensated executive officers and one additional executive officer who would have been one of our most highly compensated executive officer if he had continued to be employed with us as of December 31, 2005. We refer to these officers as our named executive officers.
(1) Amounts shown include cash and non-cash compensation earned and received by the named executives as well as amounts earned but deferred at their election. We provide various perquisites to certain employees, including the named executives. In each case, the aggregate value of the perquisite provided to the named executives did not exceed $50,000 or 10% of such named executive’s total annual salary and bonus.
(2) Amounts represent our matching contributions to our 401(k) Plan.
(3) Mr. Harrison joined us in May 2005 with a salary of $200,000. His current salary is $300,000.
(4) Mr. Benzer joined us in August 2005 with a salary of $180,000. His current salary is $200,000.
(5) Mr. Graves joined us in April 2005 with a salary of $135,000. His current salary is $190,000.
(6) Mr. Hale served as our President beginning in June 2001 and as our Chief Operating Officer beginning in April 2005 and resigned in August 2005. Under the terms of an agreement between Bronco Drilling Holdings, L.L.C., an entity controlled by Wexford, and Mr. Hale, following successful completion of our initial public offering, Mr. Hale was entitled to receive the sum of $2.0 million and shares of our common stock having a market value of $2.0 million based on the initial public offering price. These payments were made by Bronco Drilling Holdings and not by us. We accounted for these payments as a capital contribution to us in the amount of $4.0 million and compensation expense in the amount of $4.0 million during the third quarter of 2005, the period in which such obligations were incurred.
Index to Financial Statements Option Grants in Last Fiscal Year
The following table sets forth certain information concerning option grants made to the named executive officers during 2005 pursuant to our 2005 Stock Incentive Plan.
(1) In 2005, we granted options to purchase a total of 574,500 shares of common stock at exercise prices ranging from $17.00 to $25.51 per share.
(2) In accordance with SEC rules, the amounts shown on this table represent hypothetical gains that could be achieved for the options if exercised at the end of the option term. These gains are based on the assumed rates of stock appreciation of 5% and 10% compounded annually from the date the options were granted to their expiration date and do not reflect our estimates or projections of the future price of our common stock. The gains shown are net of the option exercise price, but do not include deductions for taxes or other expenses associated with the exercise. Actual gains, if any, on stock option exercises will depend on the future performance of our common stock, the option holder’s continued employment through the option period, and the date on which the options are exercised.
Option Exercises in Last Fiscal Year
The following table sets forth certain information concerning all unexercised options held by the named executive officers as of December 31, 2005. None of the named executive officers exercised any options during 2005.
(1) Value for “in-the-money” options represents the positive spread between the respective exercise prices of outstanding options and the closing price of the shares of common stock on The Nasdaq National Market of $23.01 per share on December 30, 2005.
2005 Stock Incentive Plan
We have implemented our 2005 Stock Incentive Plan. The purpose of the plan is to enable our company, and any of its affiliates, to attract and retain the services of the types of employees, consultants and directors who will contribute to our long range success and to provide incentives which are linked directly to increases in share value which will inure to the benefit of our stockholders. The plan provides a means by which eligible recipients of awards may be given an opportunity to benefit from increases in value of our common stock through the granting of incentive stock options and nonstatutory stock options.
Index to Financial Statements Eligible award recipients are employees, consultants and directors of our company and its affiliates. Incentive stock options may be granted only to our employees. Awards other than incentive stock options may be granted to employees, consultants and directors. The shares that may be issued pursuant to awards consist of our authorized but unissued common stock, and the maximum aggregate amount of such common stock which may be issued upon exercise of all awards under the plan, including incentive stock options, may not exceed 1,000,000 shares, subject to adjustment to reflect certain corporate transactions or changes in our capital structure.
We have granted options to employees and certain non-employee directors to purchase a total of 654,500 shares of our common stock under the plan, including option grants covering a total of 200,000 shares to D. Frank Harrison, 60,000 shares to Zachary M. Graves and 70,000 shares to Karl M. Benzer. These options have a weighted average exercise price of $19.55 per share, have a term of ten years and vest in 36 equal monthly installments beginning on the date of grant. In addition, we have granted options to eligible non-employee directors as described in “-Director Compensation” below.
Employment Agreements
On August 25, 2005, we entered into an employment agreement with Karl W. Benzer, our Chief Operating Officer. The agreement has a five year term and provided for an initial base salary of $180,000 per year which was increased to $200,000 per year effective January 1, 2006. Under the agreement, Mr. Benzer will be eligible to receive, but is not guaranteed, salary increases, based upon merit (as determined by our Chief Executive Officer), our financial performance (as determined by our monthly profit and loss statements), market conditions and other industry factors. The agreement provides for a one-time year-end bonus of $50,000 which was paid on December 31, 2005, and a one-time, first-quarter bonus of $40,000 which was paid on January 16, 2006, subject to certain forfeiture conditions. Beginning in 2006, Mr. Benzer will also be eligible for bonuses based upon merit, financial performance, market conditions and other industry factors. The agreement also grants Mr. Benzer an option to purchase 70,000 shares of our common stock at a price of $18.70 per share. If we terminate Mr. Benzer’s employment without cause, Mr. Benzer is entitled to severance pay equal to the base salary earned under the agreement through the date of such termination without cause, and base salary for the remainder of the term of the agreement. Mr. Benzer will also be permitted to exercise stock options then vested within ten days of such termination without cause by us. The agreement provides that during the five-year term of Mr. Benzer’s employment with us and for a period of two years thereafter or, if longer, a period of two years following the termination of Mr. Benzer’s employment with us, Mr. Benzer will not recruit, solicit, encourage or induce any employees of ours or our affiliates to terminate their employment or otherwise disrupt any employees relationship with us or our affiliates or hire, employ or offer employment to any person who is or was employed by us or any of our affiliates. Mr. Benzer is also prohibited, during the five-year term of his employment with us and for a period of two years thereafter, or, if longer, a period of two years following the termination of Mr. Benzer’s employment with us, from soliciting any past or current customer, supplier or any other person with a business relationship with us to cease doing business with us.
In connection with our initial public offering, we entered into an employment agreement with Steven C. Hale, our former President and Chief Operating Officer. Mr. Hale resigned from his positions with us in August 2005. His employment agreement provided for an annual base salary of $175,000 during its one-year term. The employment agreement also provided that in the event that Mr. Hale was terminated by us without cause, Mr. Hale would have been entitled to severance pay in an aggregate amount equal to three months of his then current base salary. No severance payments were due, payable or made to Mr. Hale by us under the employment agreement or otherwise. Under the employment agreement, Mr. Hale is prohibited, for a period of five years following the termination of Mr. Hale’s employment, from directly or indirectly disclosing any confidential information Mr. Hale obtained as a result of his employment. Mr. Hale is also prohibited, for a period of 12 months following his termination of employment with us, from soliciting the business of any established customer of ours in the United States or soliciting, enticing, persuading or inducing any employee, agent or representative of ours to terminate such person’s relationship with us or to become employed by any business or person other than us or hire or retain any such person.
Index to Financial Statements Under the terms of an agreement between Bronco Drilling Holdings, L.L.C. and Mr. Hale, following successful completion of our initial public offering, Mr. Hale was entitled to receive the sum of $2.0 million and shares of our common stock having a market value of $2.0 million based on the initial public offering price. These payments were made by Bronco Drilling Holdings and not by us. We accounted for these payments as a capital contribution to us in the amount of $4.0 million and compensation expense in the amount of $4.0 million during the third quarter of 2005, the period in which such obligations were incurred.
Director Compensation
Prior to our initial public offering in August 2005, none of our directors received compensation for services rendered as a board member. Following completion of our initial public offering, our non-employee directors are paid a monthly retainer of $1,000 and a per meeting attendance fee of $500 and are reimbursed for all ordinary and necessary expenses incurred in the conduct of our business. Members of our board of directors who are also officers or employees of our company do not receive compensation for their services as directors.
In connection with our initial public offering, we implemented our 2005 Stock Incentive Plan. Under the plan, certain non-employee directors were granted a nonqualified stock option to purchase 20,000 shares of our common stock at an exercise price of $17.00 per share, an amount equal to the initial public offering price. Options granted to eligible non-employee directors under the plan vest in 36 equal monthly installments beginning on the date of grant and are exercisable for a period of ten years beginning on the date of its grant.
Compensation Committee Interlocks and Insider Participation
We do not currently have a compensation committee. None of our executive officers serves, or has served during the past year, as a member of the board of directors or compensation committee of any other company that has one or more executive officers serving as a member of our board of directors or compensation committee.
Limitations of Liability and Indemnification of Directors and Officers
Certificate of Incorporation and Bylaws
Our certificate of incorporation provides that no director shall be personally liable to us or any of our stockholders for monetary damages resulting from breaches of their fiduciary duty as directors, except to the extent such limitation on or exemption from liability is not permitted under the Delaware General Corporation Law, or DGCL. The effect of this provision of our certificate of incorporation is to eliminate our rights and those of our stockholders (through stockholders’ derivative suits on our behalf) to recover monetary damages against a director for breach of the fiduciary duty of care as a director, including breaches resulting from negligent or grossly negligent behavior, except, as restricted by the DGCL:
•
for any breach of the director’s duty of loyalty to the company or its stockholders;
•
for acts or omissions not in good faith or that involve intentional misconduct or a knowing violation of law;
•
in respect of certain unlawful dividend payments or stock redemptions or repurchases; and
•
for any transaction from which the director derives an improper personal benefit.
This provision does not limit or eliminate our rights or the rights of any stockholder to seek non-monetary relief, such as an injunction or rescission, in the event of a breach of a director’s duty of care.
Our certificate of incorporation also provides that we will, to the fullest extent permitted by Delaware law, indemnify our directors and officers against losses that they may incur in investigations and legal proceedings resulting from their service.
Index to Financial Statements Our bylaws include provisions relating to advancement of expenses and indemnification rights consistent with those provided in our certificate of incorporation. In addition, our bylaws provide:
•
for a right of indemnitee to bring a suit in the event a claim for indemnification or advancement of expenses is not paid in full by us within a specified period of time; and
•
permit us to purchase and maintain insurance, at our expense, to protect us and any of our directors, officers and employees against any loss, whether or not we would have the power to indemnify that person against that loss under Delaware law.
Liability Insurance and Indemnification Agreements
We have obtained liability insurance for our current directors and officers. We have also entered into contractual indemnification arrangements with our directors and executive officers under which we have agreed, in certain circumstances, to compensate them for costs and liabilities incurred in actions brought against them while acting as directors or executive officers of our company.
At present, there is no pending litigation or proceeding involving any of our directors, officers or employees for which indemnification from us is sought. We are not aware of any threatened litigation that may result in claims for indemnification from us.
Certain other information relating to this Item 11 is incorporated by reference to the Proxy Statement for our 2006 Annual Meeting of Stockholders, which will be filed with the Securities and Exchange Commission no later than 120 days after December 31, 2005.
Index to Financial Statements
Item 12.
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters.
The following table sets forth certain information regarding the beneficial ownership of our common stock as of February 28, 2006 by:
•
each of our directors;
•
each of our named executive officers;
•
all of our directors and executive officers as a group; and
•
each person, or group of affiliated persons, known to us to beneficially own 5% or more of our outstanding common stock.
Except as otherwise indicated, the beneficial owners named in the table below have sole voting and investment power with respect to all shares of capital stock held by them.
* Less than 1%
(1) Percentage of beneficial ownership is based upon 23,237,939 shares of common stock outstanding as of February 28, 2006. For purposes of this table, a person or group of persons is deemed to have “beneficial ownership” of any shares which such person owns or has the right to acquire within 60 days. For purposes of computing the percentage of outstanding shares held by each person or group of persons named above, any security which such person or group of persons has the right to acquire within 60 days is deemed to be outstanding for the purpose of computing the percentage ownership for such person or persons, but is not deemed to be outstanding for the purpose of computing the percentage ownership of any other person. As a result, the denominator used in calculating the beneficial ownership among our stockholders may differ.
(2) Wexford Capital LLC is the sole manager of Bronco Drilling Holdings, L.L.C., or Holdings, and controls three limited liability companies that own membership interests in Holdings. We refer to these three companies as the Wexford members. The remaining membership interests are owned by Mike Liddell. The Wexford members have the exclusive authority to appoint the manager to manage and act on behalf of Holdings. Mr. Liddell has no power or authority to act for or on behalf of Holdings or make decisions with respect to the shares of our company owned by Holdings. All distributions made by Holdings are first paid to the Wexford members pro rata until they have received amounts equal to their capital contributions in Holdings, which currently aggregate approximately $60.9 million. Thereafter, distributions are to be made 90% to the Wexford members and 10% to Mr. Liddell. Wexford Capital may, by reason of its status as manager of Holdings, be deemed to own beneficially the interest in the shares of our common stock of which Holdings possesses beneficial ownership. Each of Charles E. Davidson and Joseph M. Jacobs may, by reason of his status as a controlling person of Wexford, be deemed to beneficially own the interests in the
Index to Financial Statements
shares of our common stock of which Holdings possesses beneficial ownership. Each of Charles E. Davidson, Joseph M. Jacobs and Wexford shares the power to vote and to dispose of the interests in the shares of our common stock beneficially owned by Holdings. Each of Messrs. Davidson and Jacobs disclaims beneficial ownership of the shares of our common stock owned by Holdings and Wexford. Wexford’s address is Wexford Plaza, 411 West Putnam Avenue, Greenwich, Connecticut 06830.
(3) Based solely upon information obtained from Schedule 13G filed with the SEC on February 14, 2006 on behalf of Wellington Management Company, LLP, or Wellington, Wellington, in its capacity as investment advisor, has shared power to vote or to direct the vote with respect to 650,612 shares of our common stock and has shared power to dispose or to direct the disposition of 1,224,027 shares of our common stock. These shares are owned of record by clients of Wellington which have the right to receive, or the power to direct the receipt of, dividends from, or the proceeds from the sale of, these shares. Wellington’s address is 75 State Street, Boston, Massachusetts 02109.
(4) Includes 50,000 shares beneficially owned under options that are currently exercisable or will become exercisable within 60 days after February 28, 2006.
(5) Includes 5,000 shares beneficially owned under options that are currently exercisable or will become exercisable within 60 days after February 28, 2006.
(6) Includes 17,500 shares beneficially owned under options that are currently exercisable or will become exercisable within 60 days after February 28, 2006.
(7) Includes 15,000 shares beneficially owned under options that are currently exercisable or will become exercisable within 60 days after February 28, 2006.
(8) Includes 92,500 shares beneficially owned by the directors and executive officers under options that are currently exercisable or will become exercisable within 60 days after February 28, 2006.
Certain other information relating to this Item 12 is incorporated by reference to the Proxy Statement for our 2006 Annual Meeting of Stockholders, which will be filed with the Securities and Exchange Commission no later than 120 days after December 31, 2005.
Item 13.
Item 13. Certain Relationships and Related Transactions.
Administrative Services Agreement and Lease of Space
Effective April 1, 2005, we entered into an administrative services agreement with Gulfport Energy Corporation. Under this agreement, Gulfport agreed to provide certain services to us, including accounting, human resources, legal and technical support services. In return for these services, we agreed to pay Gulfport an annual fee of approximately $414,000 payable in equal monthly installments during the term of this agreement. In addition, we leased approximately 1,200 square feet of office space from Gulfport for our headquarters located in Oklahoma City, Oklahoma for which we paid Gulfport annual rent of $20,880 in equal monthly installments. The services we receive under the administrative services agreement and the fees for such services can be amended by mutual agreement of the parties. In January 2006, we reduced the level of administrative services being provided by Gulfport and increased our office space to approximately 2,500 square feet. As a result, our annual fee for administrative services was reduced to approximately $150,000 and our annual rental was increased to approximately $44,000. The administrative services agreement has a three-year term, and upon expiration of that term the agreement will continue on a month-to-month basis until cancelled by either party with at least 30 days prior written notice. The administrative services agreement is terminable (1) by us at any time with at least 30 days prior written notice to Gulfport and (2) by either party if the other party is in material breach and such breach has not been cured within 30 days of receipt of written notice of such breach. Prior to entry into this administrative services agreement, we reimbursed Gulfport for its dedicated employee time, office space and general and administrative costs based upon the pro rata share of time its employees spend performing services for us. In 2005, 2004 and 2003, we made payments to Gulfport for such services and overhead totaling approximately $353,000, $115,000, and $33,000, respectively. Three of our directors, Mike Liddell, David L. Houston and Phil Lancaster, are also directors of Gulfport and Mr. Liddell is Gulfport’s Chairman. Wexford and its affiliates together own a majority of the outstanding common stock of Gulfport.
Index to Financial Statements Credit Facilities
On July 1, 2004, we entered into a revolving line of credit with International Bank of Commerce with a borrowing base of the lesser of $2.0 million or 80% of current receivables. Our performance obligations under this credit facility were guaranteed by Wexford Partners VI, L.P., a fund controlled by Wexford, and Taurus Investors, LLC, a member of our predecessor company that is also controlled by Wexford. Borrowings under this line bore interest at a rate equal to the greater of 4.0% or JPMorgan Chase prime. Accrued but unpaid interest was payable monthly. On January 1, 2005, we amended our line of credit with International Bank of Commerce to increase the borrowing base to the lesser of $3.0 million or 80% of current receivables. The line of credit had a maturity date of November 1, 2006. At December 31, 2005, our outstanding borrowings under this line of credit were $3.0 million. We repaid all outstanding borrowings under this line of credit in January 2006 with borrowings under our new revolving facility and the line of credit was terminated.
On February 15, 2005, we entered into a $5.0 million revolving credit facility with Solitair LLC, an entity controlled by Wexford. Borrowings under this facility bore interest at a rate equal to LIBOR plus 5.0%. Payments of principal and accrued but unpaid interest were due on the maturity date of the credit facility. In connection with the amendment of our senior credit facility with GECC on April 22, 2005, Solitair entered into a subordination agreement which, among other thing, effectively amended the maturity date of its loan to the later of (1) six months after the actual maturity date of our credit facility with GECC and (2) December 1, 2010. We repaid all $5.0 million of outstanding borrowings under this credit facility on August 22, 2005 with a portion of the proceeds from our initial public offering and the facility was terminated.
On June 30, 2005, we borrowed $13.0 million from Alpha Investors LLC, an entity controlled by Wexford, to fund a portion of our acquisitions of 100% of the membership interests in Strata Drilling, L.L.C. and Strata Property, L.L.C. and a related rig yard for an aggregate of $20.0 million. The outstanding principal balance of the loan plus accrued but unpaid interest was due in full upon the earlier to occur of the completion of our initial public offering and the maturity of the loan on July 1, 2006. Borrowings under our loan with Alpha bore interest at a rate equal to LIBOR plus 5% until September 30, 2005, and thereafter at a rate equal to LIBOR plus 7.5%. We repaid this loan in full on August 22, 2005 with a portion of the proceeds from our initial public offering.
On October 14, 2005, we borrowed $50.0 million from Theta Investors LLC, an entity controlled by Wexford, to fund a portion of the purchase price for the Thomas acquisition. The loan provided for maximum aggregate borrowings of up to $60.0 million that bore interest at a rate equal to LIBOR plus 400 basis points until December 15, 2005 and, thereafter, at a rate equal to LIBOR plus 600 basis points. Payment of principal and accrued but unpaid interest was due on October 15, 2006. Our obligations under the Theta loan were guaranteed by each of our principal subsidiaries. We borrowed $50.0 million under this loan on October 14, 2005. We repaid this facility in full on November 3, 2005, with a portion of the proceeds from our follow-on public offering which closed on November 2, 2005.
Drilling Services
During 2003, 2004 and 2005, we received $184,000, $0 and $2.5 million, respectively, for drilling services rendered to Windsor Energy Group, LLC, an affiliate of Wexford. On January 26, 2006, we entered into a term contract with Windsor, in which we agreed to provide Windsor a drilling rig for a period of two years. Under the terms of this contract, Windsor agreed to pay us a day work rate of $21,000 for the first twelve months of the contract term and a day work rate of $23,000 for the subsequent twelve months of the contract term.
Consulting Agreement with Michael O. Thompson
Effective February 28, 2006, Michael O. Thompson resigned from his positions as a member of our board of directors. In connection with his resignation, we entered into a consulting agreement with Mr. Thompson under which Mr. Thompson has agreed to provide us with consulting services for a period of approximately 30 months.
Index to Financial Statements
Although Mr. Thompson will not receive any additional compensation for providing these services to us, the stock options granted to him under our 2005 Stock Incentive Plan will continue to vest in accordance with their terms.
Item 14.
Item 14. Principal Accounting Fees and Services
The information relating to this Item 14 is incorporated by reference to the Proxy Statement for our 2006 Annual Meeting of Stockholders, which will be filed with the Securities and Exchange Commission no later than 120 days after December 31, 2005.
Index to Financial Statements
PART IV
Item 15.
Item 15. Exhibits, Financial Statement Schedules.
(a) The following documents are filed as part of this report:
1. Financial Statements
See Index to Consolidated Financial Statements on page of this Form 10-K.
2. Financial Statement Schedules
Schedule II
3. Exhibits:
The following exhibits are filed as part of this report or, where indicated, were previously filed and are hereby incorporate by reference.
Index to Financial Statements
Index to Financial Statements
+ Management contract, compensatory plan or arrangement.
* Filed herewith.
Index to Financial Statements
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
BRONCO DRILLING COMPANY, INC.
Page
Bronco Drilling Company, Inc. and Subsidiaries
Report of Independent Registered Public Accounting Firm
Consolidated Balance Sheets as of December 31, 2005 and 2004
Consolidated Statements of Operations for the years ended December 31, 2005, 2004 and 2003
Consolidated Statements of Members’/Stockholders’ Equity for the years ended December 31, 2003, 2004 and 2005
Consolidated Statements of Cash Flows for the years ended December 31, 2005, 2004 and 2003
Notes to Consolidated Financial Statements
Index to Financial Statements
Report of Independent Registered Public Accounting Firm
Board of Directors
Bronco Drilling Company, Inc. and Subsidiaries
We have audited the accompanying consolidated balance sheets of Bronco Drilling Company, Inc. and Subsidiaries as of December 31, 2005 and 2004, and the related consolidated statements of operations, members’/stockholders’ equity and cash flows for each of the three years in the period ended December 31, 2005. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these 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 audits to obtain reasonable assurance about whether the financial statements are free of material misstatement. The Company is not required to have, nor were we engaged to perform an audit of its internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, 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 Bronco Drilling Company, Inc. and Subsidiaries as of December 31, 2005 and 2004, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2005 in conformity with accounting principles generally accepted in the United States of America.
/S/ GRANT THORNTON LLP
Oklahoma City, Oklahoma
March 6, 2006
Index to Financial Statements
Bronco Drilling Company, Inc. and Subsidiaries
CONSOLIDATED BALANCE SHEETS
(Amounts in thousands except share par value)
The accompanying notes are an integral part of these statements.
Index to Financial Statements
Bronco Drilling Company, Inc. and Subsidiaries
CONSOLIDATED STATEMENTS OF OPERATIONS
(Amounts in thousands except per share amounts)
The accompanying notes are in integral part of these statements.
Index to Financial Statements
Bronco Drilling Company, Inc. and Subsidiaries
CONSOLIDATED STATEMENT OF MEMBERS’/STOCKHOLDERS’ EQUITY
(Amounts in thousands)
The accompanying notes are an integral part of these statements.
Index to Financial Statements
Bronco Drilling Company, Inc. and Subsidiaries
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Amounts in thousands)
The accompanying notes are an integral part of these statements.
Index to Financial Statements
Bronco Drilling Company, Inc. and Subsidiaries
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Amounts in thousands, except per share amounts)
1. Organization and Summary of Significant Accounting Policies
Business and Principles of Consolidation
Bronco Drilling Company, Inc. (the “Company”) provides contract land drilling services to oil and natural gas exploration and production companies, primarily in Oklahoma and Texas. On June 1, 2001, the Company’s predecessor, Bronco Drilling Company, L.L.C., was formed as an Oklahoma limited liability company. Effective August 15, 2005, the Company merged with Bronco Drilling Company, L.L.C. in connection with the Company’s consummation of its initial public offering. The Company was initially capitalized on May 26, 2005 as a Delaware corporation in anticipation of its merger with Bronco Drilling Company, L.L.C. During the year ended December 31, 2005, the Company made several business acquisitions to expand its drilling fleet (See Note 2). The accompanying consolidated financial statements include the Company’s accounts and the accounts of its wholly owned subsidiaries. All intercompany accounts and transactions have been eliminated in consolidation.
The Company has prepared the consolidated financial statements and related notes in accordance with accounting principles generally accepted in the United States of America. In preparing the financial statements, the Company made various estimates and assumptions that affect the amounts of assets and liabilities the Company reports as of the dates of the balance sheets and revenues and expenses the Company reports for the periods shown in the statements of operations. Material estimates that are particularly susceptible to significant changes in the near term relate to the Company’s recognition of revenues and accrued expenses, estimates of the allowance for doubtful accounts, estimates of asset impairments, estimates of deferred taxes and determinations of depreciation and amortization expense.
A summary of the significant accounting policies consistently applied in the preparation of the accompanying consolidated financial statements follows.
Cash and Cash Equivalents
The Company considers all highly liquid debt instruments purchased with a maturity of three months or less when acquired and money market mutual funds to be cash equivalents.
The Company maintains its cash and cash equivalents in accounts and instruments that may not be federally insured. The Company has not experienced any losses in such accounts and believes it is not exposed to any significant credit risks on cash and cash equivalents.
Revenue Recognition
The Company earns contract drilling revenue under daywork and footage contracts.
The Company follows the percentage-of-completion method of accounting for footage contract drilling arrangements. Under this method, drilling revenues and costs related to a well in progress are recognized proportionately over the time it takes to drill the well. Percentage-of-completion is determined based upon the amount of expenses incurred through the measurement date as compared to total estimated expenses to be incurred drilling the well. Mobilization costs are not included in costs incurred for percentage-of-completion calculations. Mobilization costs on footage contracts are deferred and recognized over the days of actual drilling. Under the percentage-of-completion method, management estimates are relied upon in the determination of the total estimated expenses to be incurred drilling the well. When estimates of revenues and expenses indicate a loss on a contract, the total estimated loss is accrued.
Index to Financial Statements Bronco Drilling Company, Inc. and Subsidiaries
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
(Amounts in thousands, except per share amounts)
Revenues on daywork contracts are recognized based on the days completed at the dayrate each contract specifies. Mobilization revenues and costs for daywork contracts are deferred and recognized over the days of actual drilling.
The receivables from contract drilling in progress represents revenues in excess of amounts billed on contracts in progress.
Revenue arising from claims for amounts billed in excess of the contract price or for amounts not included in the original contract are recognized when billed less any allowance for uncollectibility. Revenue from such claims is only recognized if it is probable that the claim will result in additional revenue, the costs for the additional services have been incurred, management believes there is a legal basis for the claim and the amount can be reliably estimated. Historically, such claims have been immaterial as we have not billed any customers for amounts not included in the original contract.
Accounts Receivable
The Company records trade accounts receivable at the amount invoiced to customers. Substantially all of the Company’s accounts receivable are due from companies in the oil and gas industry. Credit is extended based on evaluation of a customer’s financial condition and, generally, collateral is not required. Accounts receivable are due within 30 days and are stated at amounts due from customers, net of an allowance for doubtful accounts when the Company believes collection is doubtful. Accounts outstanding longer than the contractual payment terms are considered past due. The Company determines its allowance by considering a number of factors, including the length of time trade accounts receivable are past due, the Company’s previous loss history, the customer’s current ability to pay its obligation to the Company and the condition of the general economy and the industry as a whole. The Company writes off specific accounts receivable when they become uncollectible and payments subsequently received on such receivables are credited to the allowance for doubtful accounts. At December 31, 2005 and 2004, our allowance for doubtful accounts was $330 and $146, respectively.
Prepaid Expenses
Prepaid expenses include items such as insurance and fees. The Company routinely expenses these items in the normal course of business over the periods these expenses benefit.
Property Equipment
Property and equipment, including renewals and betterments, are capitalized and stated at cost, while maintenance and repairs are expensed currently. Assets are depreciated on a straight-line basis. The depreciable lives of drilling rigs and related equipment are three to 15 years. The depreciable life of other equipment is three years. Depreciation is not commenced until acquired rigs are placed in service. Once placed in service, depreciation continues when rigs are being repaired, refurbished or between periods of deployment. Assets not placed in service and not being depreciated were $47,655 and $34,118 as of December 31, 2005 and 2004, respectively.
The Company capitalizes interest as a component of the cost of drilling rigs constructed for its own use. For the years ended December 31, 2005 and 2004, the Company capitalized $1,207 and $470, respectively, of interest costs incurred during the construction periods of certain drilling rigs.
The Company reviews long-lived assets to be held and used for impairment whenever events or changes in circumstances indicate that the carrying amount of the assets may not be recoverable. If the sum of the undiscounted expected future cash flows is less than the carrying amount of the assets, the Company recognizes an impairment loss based upon fair value of the asset.
Index to Financial Statements Bronco Drilling Company, Inc. and Subsidiaries
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
(Amounts in thousands, except per share amounts)
Goodwill
The Company evaluates the carrying value of goodwill during the fourth quarter of each year and between annual evaluations if events occur or circumstances change that would more likely than not reduce the fair value below its carrying amount. Such circumstances could include, but are not limited to: (1) a significant adverse change in legal factors or in business climate, (2) unanticipated competition, or (3) an adverse action or assessment by a regulator. When evaluating whether goodwill is impaired, the Company compares its fair value to its carrying amount, including goodwill. Fair value is estimated using a combination of income, or discounted cash flows approach and the market approach, which utilizes comparable companies’ data. If the carrying amount exceeds its fair value, then the amount of the impairment loss must be measured. The impairment loss would be calculated by comparing the implied fair value of reporting unit goodwill to its carrying amount. In calculating the implied fair value of goodwill, the fair value of the Company is allocated to all of its other assets and liabilities based on their fair values. The excess of the fair value of the Company over the amount assigned to its other assets and liabilities is the implied fair value of goodwill. An impairment loss would be recognized when the carrying amount of goodwill exceeds its implied fair value. Goodwill recognized during 2005 through acquisitions was $20,774.
Intangibles, Net and Other
Intangibles, restricted cash and other assets consist of intangibles related to acquisitions, net of amortization, cash deposits related to the deductibles on our workers compensation insurance policies and debt issue costs, net of amortization. The Company follows Statement of Financial Accounting Standards (“SFAS”) No. 142, “Goodwill and Other Intangibles” to account for amortizable intangibles. Intangible assets that are acquired either individually or with a group of other assets are recognized based on its fair value and amortized over its useful life. The Company’s amortizable intangibles consist entirely of customer lists and relationships obtained through acquisitions in 2005. Customer lists and relationships are amortized over their estimated benefit period of four years. Depreciation expense includes amortization of intangibles of $87 for the year ended December 31, 2005. Total cost and accumulated amortization of intangibles at December 31, 2005 was $2,106 and $87, respectively.
Estimated amortization expense for each year subsequent to December 31, 2005 is as follows:
Legal fees and other debt issue costs incurred in obtaining financing are amortized over the term of the debt using a method which approximates the effective interest method. Gross debt issue costs were $268 and $259 at December 31, 2005 and 2004, respectively. Amortization expense related to debt issue costs was $53, $43 and $3 for years ended December 31, 2005, 2004 and 2003, respectively, and is included in interest expense in the consolidated statements of operations. Accumulated amortization related to loan fees was $14 and $46 as of December 31, 2005 and 2004, respectively. On August 29, 2005, the Company paid off its term note with General Electric Capital Corporation. The Company incurred a prepayment penalty of $644 and wrote-off debt issue costs of $349, which is included in loss from early extinguishment of debt on the consolidated statement of operations for the year ended December 31, 2005. On November 2, 2005, the Company paid off its term note with Theta Investors, LLC, formerly Alpha Investors LLC, an entity controlled by Wexford Capital, LLC (“Wexford”), the Company’s
Index to Financial Statements Bronco Drilling Company, Inc. and Subsidiaries
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
(Amounts in thousands, except per share amounts)
principal stockholder. The Company wrote-off debt issue costs of $1,075, which is included in loss from early extinguishment of debt on the consolidated statement of operations for the year ended December 31, 2005.
Restricted Cash
At December 31, 2005 and 2004, the Company had restricted cash of $2,184 and $600, respectively, at a bank collateralizing letters of credit with the Company’s workers’ compensation insurers.
Income Taxes
Pursuant to SFAS No. 109, “Accounting for Income Taxes,” the Company follows the asset and liability method of accounting for income taxes, under which the Company recognizes 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. Deferred tax assets and liabilities were measured using enacted tax rates expected to apply to taxable income in the years in which the Company expects to recover or settle those temporary differences. A statutory Federal tax rate of 34% and effective state tax rate of 3.7% (net of Federal income tax effects) were used for the enacted tax rate for all periods.
As changes in tax laws or rates are enacted, deferred income tax assets and liabilities are adjusted through the provision for income taxes. Deferred tax assets are reduced by a valuation allowance if, based on available evidence, it is more likely than not that some portion or all of the deferred tax assets will not be realized. The classification of current and noncurrent deferred tax assets and liabilities is based primarily on the classification of the assets and liabilities generating the difference. As a result of our conversion to a taxable corporation on August 15, 2005, a charge to income tax expense of $4,412 was made to record deferred taxes for the differences between the tax basis and financial reporting basis of our assets and liabilities.
Pro Forma Income Taxes (unaudited)
Our predecessor, a limited liability company, was classified as a partnership for income tax purposes. Accordingly, income taxes on net earnings were payable by the members and are not reflected in historical financial statements except for taxes associated with a taxable subsidiary. Pro forma adjustments are reflected to provide for income taxes in accordance with SFAS No. 109. For unaudited pro forma income tax calculations, deferred tax assets and liabilities were recognized for the future tax consequences attributable to differences between the assets and liabilities and were measured using enacted tax rates expected to apply to taxable income in the years in which the Company expects to recover or settle those temporary differences. A statutory Federal tax rate of 34% and effective state tax rate of 3.7% (net of Federal income tax effects) were used for the pro forma enacted tax rate for all periods. The pro forma tax effects are based upon currently available information and assume the Company had been a taxable entity in the periods presented. Management believes that these assumptions provide a reasonable basis for presenting the pro forma tax effects.
Net income (Loss) Per Common Share
The Company computes and presents net income (loss) per common share in accordance with SFAS No. 128 “Earnings per Share.” This standard requires dual presentation of basic and diluted net income (loss) per share on the face of the Company’s statement of operations. Basic net income (loss) per common share is computed by dividing income or loss attributable to common stock by the weighted average number of common shares outstanding for the period. Diluted net income (loss) per common share reflects the potential dilution that could occur if options or other contracts to issue common stock were exercised or converted into common stock using the treasury stock method. Diluted net loss per common share does not reflect dilution from potential
Index to Financial Statements Bronco Drilling Company, Inc. and Subsidiaries
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
(Amounts in thousands, except per share amounts)
common shares, because to do so would be anti-dilutive. Calculations of basic and diluted net income (loss) per common share are illustrated in Note 10. The Company had no potentially dilutive options or contracts prior to the granting of stock options on August 19, 2005.
Pro Forma Income (Loss) Per Share (unaudited)
Pro forma income (loss) per basic and diluted common share is computed based on weighted average pro forma number of basic and diluted shares assumed to be outstanding during the periods. Pro forma basic and diluted income (loss) per share is presented for the predecessor’s historical years ended December 31, 2004 and 2003 on the basis of 13,360 shares issued to our founder in the merger immediately prior to our initial public offering in August 2005.
Stock-based Compensation
The Company has adopted SFAS No. 123(R), “Share-Based Payment” upon granting its first stock options on August 19, 2005. SFAS No. 123(R) requires a public entity to measure the costs of employee services received in exchange for an award of equity or liability instruments based on the grant-date fair value of the award. That cost will be recognized over the period during which an employee is required to provide service in exchange for the award.
Recent Accounting Pronouncements
In May 2005, the FASB issued SFAS No. 154 (“SFAS 154”). “Accounting Changes and Error Corrections.” This is a replacement of APB Opinion No. 20, “Accounting Changes” and SFAS No. 3, “Reporting Accounting Changes in Interim Financial Statements.” Under SFAS 154, all voluntary changes in accounting principles as well as changes pursuant to accounting pronouncements that do not include specific transition requirements, must be applied retrospectively to prior periods’ financial statements. Retrospective application requires the cumulative effect of each change to be reflected in the carrying value of assets and liabilities as of the first period presented and the offsetting adjustments to be recorded in retained earnings for the first period presented. Also, under the new statement, a change in an accounting estimate continues to be accounted for in the period of the change and in future periods if necessary. Under SFAS 154, corrections of errors should continue to be reported by restating prior period financial statements as of the beginning of the first period presented, if material. The statement is effective for accounting changes and corrections of errors made in fiscal years beginning after December 15, 2005. The Company will adopt SFAS 154 on January 1, 2006. It is anticipated that adoption will not have a material impact on the Company’s financial position and results of operations.
Reclassifications
Certain reclassifications have been made to the 2004 consolidated financial statements to conform to the presentation for the year ended December 31, 2005.
2. Acquisitions
In July 2005, the Company acquired all the membership interests in Strata Drilling, L.L.C. and Strata Property, L.L.C. (collectively “Strata”) and a related rig yard. Included in these acquisitions were two operating rigs, one rig that was being refurbished, related structures, equipment and components and a 16 acre yard in Oklahoma City, Oklahoma used for equipment storage and refurbishment of inventoried rigs. The aggregate
Index to Financial Statements Bronco Drilling Company, Inc. and Subsidiaries
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
(Amounts in thousands, except per share amounts)
purchase price was $20,000, of which $13,000 was paid in cash and $7,000 was paid in the form of promissory notes issued to the sellers. The Company funded the cash portion of the purchase price with a $13,000 loan from Theta Investors, LLC, formerly Alpha Investors LLC, an entity controlled by Wexford. The outstanding principal balance of the Alpha loan was paid in full on August 22, 2005 with proceeds from our initial public offering. This purchase was accounted for as an acquisition of a business, and the results of operations of the acquired business have been included in our statement of operations since the date of acquisition. We allocated the purchase price to property and equipment and related assets based on their relative fair values at the date of acquisition.
The $7,000 original aggregate outstanding principal balance of the promissory notes issued to the sellers is automatically reduced by the amount of any costs and expenses the Company pays in connection with the refurbishment of one of the rigs it acquired from the sellers. The Company granted the sellers a security interest in this rig to secure its obligations under the notes. The outstanding principal balance on these notes does not bear any interest other than default interest in the event of a default. In January 2006, the rig was completed to the satisfaction of the Company and title passed at such point. Upon acceptance of the rig the note was paid in full (see Note 3).
In September 2005, the Company acquired all the outstanding common stock of Hays Trucking, Inc. for $3,000 in cash, which includes the repayment of $1,900 of debt owed by Hays Trucking, and the issuance of 65 shares of common stock with a fair value of $1,274 based on the closing stock price at date of acquisition. In this acquisition, the Company acquired 18 trucks used to mobilize rigs to contracted drilling locations as well as other ancillary equipment. Approximately $286 of the purchase price was allocated to customer lists and is included in intangibles on the balance sheet at December 31, 2005.
In October 2005, the Company purchased 12 land drilling rigs from Eagle Drilling, L.L.C., and two of its affiliates (“Eagle”). This acquisition involved five operating rigs, seven inventoried rigs and rig equipment and parts for a purchase price of approximately $50,517. In connection with this acquisition, the Company leased the use of an additional rig refurbishment yard for a two-year term. The purchase price of $50,517, which includes approximately $517 of related transaction costs, was funded with a $7,517 from cash on hand and a $43,000 loan from Merrill Lynch Business Financial Services, Inc., as lender (see Note 4). The purchase price has been allocated to property and equipment totaling $33,838, goodwill of $16,026 and customer lists and relationships of $653.
In October 2005, the Company purchased 13 land drilling rigs from Thomas Drilling Company. (“Thomas”). This acquisition involved nine operating rigs, two rigs being refurbished, two inventoried rigs and rig equipment and parts for a purchase price of approximately $70,622, which includes approximately $2,622 of related transaction costs. In connection with this acquisition, the Company leased the use of an additional rig refurbishment yard for a six-month term, with the right to extend the term for an additional three years, and obtained an option to purchase the yard for $175. The purchase price was partially funded through a $50,000 loan from Theta Investors LLC, an entity controlled by Wexford. This loan was repaid in full on November 3, 2005 with a portion of the proceeds from the Company’s follow-on common stock offering which closed on November 2, 2005. The purchase price has been allocated to property and equipment totaling $64,708, goodwill of $4,748 and customer lists of $1,166.
Index to Financial Statements Bronco Drilling Company, Inc. and Subsidiaries
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
(Amounts in thousands, except per share amounts)
The following table summarizes the allocation of purchase price to the Company’s significant acquisitions:
The following pro forma information gives effect to the Strata, Eagle and Thomas acquisitions as though they were effective at the beginning of each year presented. Pro forma adjustments primarily relate to additional depreciation, amortization and interest costs. The information reflects the Company’s historical data and historical data from the acquired business for the periods indicated. The pro forma data may not be indicative of the results the Company would have achieved had it completed the acquisition at the beginning of each year presented, or that it may achieve in the future. The pro forma financial information should be read in conjunction with the accompanying historical financial statements. Pro forma income per basic and diluted common share is computed based on the weighted average pro forma number of basic and diluted shares assumed to be outstanding during the period. Pro forma per share information is presented for the year ended December 31, 2005 on the basis of 16,259 and 16,306 weighted average shares issued basic and diluted. Pro forma per share information is presented for the year ended December 31, 2004 on the basis of 13,360 shares issued to our founder. Dilutive pro forma effect is given to shares which are issuable under an employee stock option plan.
In August 2003, we purchased all of the outstanding stock of Elk Hill Drilling, Inc. and certain drilling rig structures and components from an affiliate of Elk Hill, U.S. Rig & Equipment, for $33,500 in cash plus the assumption of $15,500 of deferred tax liabilities. In these transactions, we acquired drilling rigs and inventoried structures and components which, with refurbishment and upgrades, could be used to assemble 22 drilling rigs. At the date of its acquisition, Elk Hill had no customers, employees, operations or operational drilling rigs. For accounting purposes, the Elk Hill and U.S. Rig and Equipment acquisitions were treated as acquisitions by our members and then contributions to us.
Index to Financial Statements Bronco Drilling Company, Inc. and Subsidiaries
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
(Amounts in thousands, except per share amounts)
3. Notes Payable
Notes payable consists of advances under a $3,000 revolving line of credit with a bank (“Bank Note Payable”) and $7,000 original aggregate principal amount of notes payable to the sellers in the Strata acquisition. The Bank Note Payable bears interest based on JPMorgan Chase prime (effective rate of 7.25% at December 31, 2005) and is guaranteed by affiliates of Wexford. Interest on the Bank Note Payable is due monthly with outstanding principal due November 1, 2006 and is collateralized by the Company’s accounts receivable. The Bank Note Payable has certain financial covenants which include maintaining a 1 to 1 current ratio and minimum tangible net worth for which the Company was in compliance at December 31, 2005, and among other things, prohibits the payment of dividends. The Bank Note Payable was paid in full in January 2006 (See Note 17).
The $7,000 original aggregate principal balance of the promissory notes issued to the sellers is automatically reduced by the amount of any costs and expenses the Company pays in connection with the refurbishment of one of the rigs it acquired from the sellers. Payment of the outstanding balance of the notes is due and payable upon satisfactory completion of the refurbishment of this rig. The Company granted the sellers a security interest in this rig to secure its obligations under the notes. The outstanding aggregate principal balance on these notes do not bear any interest other than default interest in the event of a default. The amount due on the note, net of costs and expenses of $2,497 paid by the Company, was $4,503 at December 31, 2005. The note was paid in full in January 2006 (See Note 2).
4. Long-term Debt
Long-term debt consists of the following at:
Index to Financial Statements Bronco Drilling Company, Inc. and Subsidiaries
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
(Amounts in thousands, except per share amounts)
Long-term debt maturing each year subsequent to December 31, 2005 is as follows:
(1) At December 31, 2004, the credit facility with General Electric Capital Corporation (“GECC”) provided for monthly advances at the Company’s request of at least $3,000, subject to maximum borrowings of $18,000. In April 2005, the credit facility was amended to increase the maximum amount of term loans to $25,000 and reduce required draws to $2,500 increments. Each advance was payable in 60 equal monthly installments with final maturity at April 1, 2010. Interest was due monthly at LIBOR plus 5%. The term note was collateralized by the Company’s assets, excluding cash and accounts receivable. The term note was repaid in full on August 29, 2005, with proceeds from the Company’s initial public offering.
(2) On September 19, 2005, the Company entered into a Term Loan and Security Agreement with Merrill Lynch Capital, a division of Merrill Lynch Business Financial Services, Inc., as lender (“Merrill Lynch” or the “lender”). The term loan provides for a term installment loan in an aggregate amount not to exceed $50,000 and provides for a commitment by Merrill Lynch to advance funds from time to time until December 31, 2005. The outstanding balance under the term loan may not exceed 60% of the net orderly liquidation value of the Company’s operating land drilling rigs. Proceeds of the term loan may be used to replenish working capital for general business purposes, finance improvements to and the refurbishment of land drilling rigs, and to acquire additional land drilling rigs. On September 19, 2005, the Company borrowed $43,000 under the term loan.
The term loan bears interest on the outstanding principal balance at a variable per annum rate equal to LIBOR plus 271 basis points. For the period from September 19, 2005 to January 1, 2006, interest only is payable monthly on the outstanding principal balance. Commencing February 1, 2006, the outstanding principal and interest on the term loan will be payable in sixty consecutive monthly installments, each in an amount equal to one sixtieth of the outstanding principal balance on January 1, 2006 plus accrued interest on the outstanding principal balance. Any outstanding principal and accrued but unpaid interest will be immediately due and payable in full on January 1, 2011. The Company’s obligations under the term loan are collateralized by a first lien and security interest on substantially all of the Company’s assets and are guaranteed by each of the Company’s principal subsidiaries. The term loan includes usual and certain restrictive negative covenants and requires the Company to meet certain financial covenants, including maintaining (1) a minimum “Fixed Charge Coverage Ratio” and (2) a maximum “Total Debt to EBITDA Ratio” as defined in the agreement. The Company was in compliance with all covenants at December 31, 2005. In January 2006, all borrowings were repaid in full and the term loan and security agreement were terminated at such time (See Note 17).
(3) On December 7, 2005, the Company entered into a Term Loan and Security Agreement with De Lage Landen Financial Services, Inc. The term loan provides for a term installment loan in an aggregate amount not to exceed $1,322. The proceeds of the term loan were used to purchase a crane.
Index to Financial Statements Bronco Drilling Company, Inc. and Subsidiaries
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
(Amounts in thousands, except per share amounts)
5. Income Taxes
Income tax expense consists of the following:
Deferred income tax assets and liabilities are as follows:
Upon the conversion from a limited liability company to a taxable corporation in conjunction with its initial public offering, the Company incurred a one-time charge to operations in the third quarter of 2005 of approximately $4,412 to record deferred taxes upon change in tax status.
In assessing its ability to realize deferred tax assets, the Company considers whether it is more likely than not that some portion or all of the deferred tax assets will not be realized. Its ultimate realization of deferred tax assets depends on the generation of future taxable income during the periods in which those temporary differences become deductible. The Company considers the scheduled reversal of deferred tax liabilities and projected future taxable income in making this assessment. The Company believe it is more likely than not that it will realize the benefits of these deductible differences.
The provision for income taxes on continuing operations differs from the amounts computed by applying the federal income tax rate of 34% to net income. The differences are summarized as follows:
Index to Financial Statements Bronco Drilling Company, Inc. and Subsidiaries
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
(Amounts in thousands, except per share amounts)
6. Workers’ Compensation and Health Insurance
The Company is insured under a large deductible workers’ compensation insurance policy. The policy generally provides for a $250 deductible per covered accident. Due to the high deductible, the policy requires the Company to maintain a letter of credit with a bank. At December 31, 2005 and 2004, the Company had deposits of $2,184 and $600, respectively, with a bank collateralizing the letter of credits. The deposits are reflected in restricted cash.
On November 1, 2005, the Company initiated a self-insurance program for major medical, hospitalization and dental coverage for employees and their dependents, which is partially funded by payroll deductions. The Company provided for both reported and incurred but not reported medical costs in the accompanying consolidated balance sheets. We have a maximum liability of $50 per employee/dependent per year. Amounts in excess of the stated maximum are covered under a separate policy provided by an insurance company. Accrued expenses at December 31, 2005 included approximately $170 for our estimate of incurred but not reported costs related to the self-insurance portion of our health insurance.
7. Transactions with Affiliates
Effective April 1, 2005, the Company entered into an administrative services agreement with its affiliate Gulfport Energy Corporation (“Gulfport”). Under this agreement, Gulfport agreed to provide certain services to the Company, including accounting, human resources, legal and technical support services. In return for the services, the Company has agreed to pay Gulfport an annual fee of approximately $414 payable in equal monthly installments during the term of this agreement. In addition, the Company leased approximately 1,200 square feet of office space from Gulfport for the Company’s headquarters for an annual rent of $21 payable in equal monthly installments. The services we receive under the administrative services agreement and the fees for such services can be amended by mutual agreement of the parties. In January 2006, the Company reduced the level of administrative services being provided by Gulfport and increased its office space to approximately 2,500 square feet. As a result, the Company’s annual fee for administrative services was reduced to approximately $150 and its annual rental was increased to approximately $44 payable in equal monthly installments. The administrative services agreement has a three-year term, and upon expiration of that term the agreement will continue on a month-to-month basis until cancelled by either party with at least 30 days prior written notice. The administrative services agreement is terminable (1) by the Company at any time with at least 30 days prior written notice to Gulfport and (2) by either party if the other party is in material breach of the agreement and such breach has not been cured within 30 days of receipt of written notice of such breach of the agreement. Prior to entry into this administrative services agreement, we reimbursed Gulfport for its dedicated employee time, office space and general and administrative costs based upon the pro rata share of time its employees spend performing services for us. The Company reimbursed Gulfport approximately $353, $115 and $33 in consideration for those services during the years ended December 31, 2005, 2004 and 2003, respectively. At December 31, 2005 and 2004, approximately $47 and $17, respectively, was owed to Gulfport and included in accounts payable.
Additionally, the Company provided contract drilling services totaling $2,527, $0 and $184 to affiliated entities for the years ended December 31, 2005, 2004 and 2003. Certain borrowings for acquisitions (see Note 2) and note payable guarantee (see Note 3) were from affiliates.
8. Commitments and Contingencies
The Company leases six service locations under noncancelable operating leases that have various expirations from 2008 to 2015. Related rent expense was $358, $177 and $98 for the years ended December 31, 2005, 2004 and 2003, respectively.
Index to Financial Statements Bronco Drilling Company, Inc. and Subsidiaries
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
(Amounts in thousands, except per share amounts)
Aggregate future minimum lease payments under the noncancelable operating leases for years subsequent to December 31, 2005 are as follows:
The Company currently has a lawsuit pending in which the Company sued the defendant, an oil and gas operating company, for approximately $942 as a result of the defendant’s refusal to make payment pursuant to the terms of its drilling contract. The defendant has countersued for damages in excess of $2,800, alleging breach of contract, negligence, gross negligence and breach of warranties. The trial date has been set for August 14, 2006. The Company is vigorously prosecuting its claims and defending against the counterclaims in this matter, and will continue to file appropriate responses, motions and documents as necessary. It is not possible to predict the outcome of this matter. An allowance of $146 has been provided for a portion of the amounts receivable under the drilling contract. No amounts have been accrued for damages sought in the counterclaim. Should the amounts ultimately not be collected or if any amounts are due under the counterclaims then additional expenses will be recorded.
Various other claims and lawsuits, incidental to the ordinary course of business, are pending against the Company. In the opinion of management, all matters are adequately covered by insurance or, if not covered, are not expected to have a material effect on the Company’s consolidated financial position, results of operations or cash flows.
9. Business Segments and Concentrations
Substantially all of the Company’s operations relate to contract drilling of oil and gas wells. Accordingly, we classify all our operations in a single segment.
For the year ended 2005, revenue from one customer was approximately 10% of total revenue, for 2004 one customer accounted for 11% of total revenue and for 2003 two customers accounted for 13% and 11% of total revenues. At December 31, 2005, three customers accounted for approximately 8%, 7% and 7% of accounts receivable. At December 31, 2004, three customers accounted for approximately 14%, 13% and 12% of accounts receivable.
Index to Financial Statements Bronco Drilling Company, Inc. and Subsidiaries
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
(Amounts in thousands, except per share amounts)
10. Net Income Per Common Share
The following table presents a reconciliation of the numerators and denominators of the basic earnings per share (“EPS”) and diluted EPS comparisons as required by SFAS No. 128 for the year:
11. Equity Transactions
In January 2005, the Company received a capital contribution of $1,515 from Wexford. This contribution was used to fund the letter of credit required for the Company’s workers’ compensation policy.
In August 2005, the Company completed its initial public offering in which the Company sold 5,715 shares of common stock at an offering price of $17.00 per share, resulting in net proceeds to the Company of approximately $89,000, excluding offering expenses of $1,354. The Company used approximately $40,500 of these proceeds to repay in full its loans from Alpha Investors, LLC and Solitair LLC, entities controlled by Wexford, and all borrowings under the credit facility with GECC.
Under the terms of an agreement between Bronco Drilling Holdings, L.L.C., the Company’s then sole stockholder, and Steven C. Hale, the Company’s former President and Chief Operating Officer, following successful completion of the initial public offering Mr. Hale was entitled to receive the sum of $2,000 and shares of common stock having a market value of $2,000 based on the initial public offering price. These payments were made by Bronco Drilling Holdings and not by the Company. The Company accounted for the payments as a capital contribution in the amount of $4,000 and compensation expense in the amount of $4,000 during the third quarter of 2005, the period in which the obligations were incurred.
Effective September 1, 2005, the Company issued 65 shares of common stock to the shareholders of Hays Trucking, Inc. in connection with our acquisition of Hays Trucking, Inc. (See Note 2).
In November 2005, the Company closed a follow-on public offering of a total of 4,025 shares of common stock at a price of $23.00 per share resulting in net proceeds to the Company of approximately $87,000, excluding offering expenses of $462. The offering included a total of 525 shares purchased pursuant to the underwriters’ overallotment option, which was exercised in full on October 31, 2005.
Index to Financial Statements Bronco Drilling Company, Inc. and Subsidiaries
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
(Amounts in thousands, except per share amounts)
The Company has adopted SFAS No. 123(R), “Share-Based Payment.” SFAS No. 123(R) requires a public entity to measure the costs of employee services received in exchange for an award of equity instruments based on the grant-date fair value of the award. That cost will be recognized over the period during which an employee is required to provide service in exchange for the award. The compensation expense recorded of $589 is also reflected in paid-in-capital at December 31, 2005.
12. Stock Options and Stock Option Plan
On December 31, 2005, the Company had one share-based compensation plan adopted on July 20, 2005 and amended on November 16, 2005 which is described below. The compensation cost that has been charged against income was $589 for the year ended December 31, 2005. The total income tax benefit recognized in the income statement for share-based compensation arrangements was $222 for the year ended December 31, 2005. These options are reported as equity instruments and their fair value is amortized to expense using the straight line method over the vesting period. The shares of stock issued once the options are exercised will be authorized but unissued common stock.
The purpose of the plan is to enable the Company, and any of its affiliates, to attract and retain the services of the types of employees, consultants and directors who will contribute to its long-range success and to provide incentives which are linked directly to increases in share value which will inure to the benefit of the Company’s stockholders. The plan provides a means by which eligible recipients of awards may be given an opportunity to benefit from increases in value of the Company’s common stock through the granting of incentive stock options and nonstatutory stock options. Eligible award recipients are employees, consultants and directors of the Company and its affiliates. Incentive stock options may be granted only to employees. Awards other than incentive stock options may be granted to employees, consultants and directors. The shares that may be issued upon exercise of the options will be from authorized but unissued common stock, and the maximum aggregate amount of such common stock which may be issued upon exercise of all awards under the plan, including incentive stock options, may not exceed 1,000,000 shares, subject to adjustment to reflect certain corporate transactions or changes in the Company’s capital structure.
The fair value of each option award is estimated on the date of grant using a Black Scholes valuation model that uses the assumptions noted in the following table. Expected volatilities are based on the historical volatility of a selected peer group and other factors. The majority of the Company’s options are held by employees that make up one group with similar expected exercise behavior for valuation purposes. The expected term of options granted is estimated based on an average of the vesting period and the contractual period. The risk-free rate for periods within the contractual life of the option is based on the U.S. Treasury yield curve in effect at the time of the grant.
Under the 2005 Stock Incentive Plan, employee stock options become exercisable in equal monthly installments over a three-year period, and all options generally expire ten years after the date of grant. The plan provides that all options must have an exercise price not less than the fair market value of the Company’s common stock on the date of the grant.
The following table provides information relating to outstanding stock options at December 31, 2005:
Index to Financial Statements Bronco Drilling Company, Inc. and Subsidiaries
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
(Amounts in thousands, except per share amounts)
The Company has not declared dividends since it became a public company and does not intend to do so in the foreseeable future, and thus 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 the common stock and overall stock market conditions. There is no assurance that the value an optionee actually realizes will be at or near the value estimated using the Black-Scholes model. The following table provides information relating to activity in the 2005 Stock Incentive Plan during 2005:
As of December 31, 2005, there was $4,998 of total unrecognized compensation cost related to nonvested share-based compensation arrangements granted under the Plan. That cost is expected to be recognized over a weighted-average period of 1.4 years.
13. 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 due to the short-term nature of these instruments.
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 of the existing debt.
14. Employee Benefit Plans
The Company implemented a 401(k) retirement plan for our eligible employees during 2005. Under the plan, the Company matches employees’ contributions up to 2%. Employee contributions vest evenly over a three-year period. Our contributions for year ended December 31, 2005 were $58.
Index to Financial Statements Bronco Drilling Company, Inc. and Subsidiaries
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
(Amounts in thousands, except per share amounts)
15. Quarterly Results of Operations (unaudited)
The following table summarizes quarterly financial data for our years ended December 31, 2005 and 2004 (in thousands, except per share data):
Pro forma earnings (loss) per share are presented for all periods prior to our initial public offering (IPO) based on the number of shares issued to our founders at our IPO.
16. Valuation and Qualifying Accounts
The Company’s valuation and qualifying accounts for the years ended December 31, 2005, 2004 and 2003 are as follows:
Index to Financial Statements Bronco Drilling Company, Inc. and Subsidiaries
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-(Continued)
(Amounts in thousands, except per share amounts)
17. Subsequent Events
On January 18, 2006, the Company completed the acquisition of six land drilling rigs and certain other assets, including heavy haul trucks and excess rig equipment and inventory, from Big A Drilling, L.L.C. The purchase price for the assets consisted of $16,300 in cash and 73 shares of our common stock. At closing, the Company also entered into a lease agreement with an affiliate of Big A Drilling under which it leased a rig refurbishment yard located in Woodward, Oklahoma. The lease has an initial term of six months, and the Company has the option to extend the initial term for a period of three years following the expiration of the initial term. The Company has the option to purchase the leased premises at any time during the term of the lease for $200.
On January 13, 2006, the Company entered into a $150,000 revolving credit facility with Fortis Capital Corp., as administrative agent, lead arranger and sole bookrunner, and a syndicate of lenders, which include The Royal Bank of Scotland plc, The CIT Group/Business Credit, Inc., Calyon Corporate and Investment Bank, Merrill Lynch Capital, Comerica Bank and Caterpillar Financial Services Corporation. The revolving credit facility matures on January 13, 2009. Loans under the revolving credit facility bear interest at LIBOR plus a margin that can range from 2.0% to 3.0% or, at our option, the prime rate plus a margin that can range from 1.0% to 2.0%, depending on the ratio of our outstanding senior debt to “Adjusted EBITDA” as defined in the agreement. Our outstanding borrowings under this revolving credit facility of $57,000 as of January 30, 2006 were used to fund a portion of the Big A Drilling acquisition, and to repay in full borrowings under our term loan with Merrill Lynch Capital and our revolving line of credit with International Bank of Commerce.
Index to Financial Statements SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, Bronco Drilling Company, Inc. has duly caused this Annual Report on Form 10-K to be signed on its behalf by the undersigned, thereunto duly authorized.
Power of Attorney
Each of the persons whose signature appears below hereby constitutes and appoints D. Frank Harrison, Karl W. Benzer, Zachary M. Graves and Mark Dubberstein, and each of them, his true and lawful attorneys-in-fact and agents, with full power of substitution and resubstitution, from such person and in each person’s name, place and stead, in any and all capacities, to sign the Form 10-K filed herewith and any and all amendments to said Form 10-K, with all exhibits thereto and all documents in connection therewith, with the SEC, granting unto said attorneys-in-fact and agents, and each of them, full power and authority to do and perform each and every act and thing requisite and necessary to be done as fully to all said attorneys-in-fact and agents, or any of them, may lawfully do or cause to be done by virtue thereof.
Pursuant to the requirements of the Securities and Exchange Act of 1934, this report has been signed below by the following persons on behalf of Bronco Drilling Company, Inc. and in the capacities and on the dates indicated.