ITEM 1. BUSINESS
GENERAL
We provide contract land drilling services and equipment, primarily to natural gas producers in the U.S. We commenced operations in 1997 with 12 drilling rigs and related equipment acquired from a predecessor that was providing contract drilling services under the name "Union Drilling." Through a combination of acquisitions and new rig construction, we have increased the size of our fleet to 70 land drilling rigs, of which 63 are marketed and seven are stacked.
Our principal operations are in the Appalachian Basin, extending from New York to Tennessee, the Arkoma Basin in eastern Oklahoma and western Arkansas, the Fort Worth Basin in northern Texas, the Piceance Basin in western Colorado, and the Uinta Basin in eastern Utah. These geological basins are generally characterized by unconventional natural gas formations with very low permeability rock, such as tight sands and shales, and coal seams with coal bed methane, or CBM, deposits.
Substantially all of our rigs operate in unconventional natural gas producing areas, where specialized drilling techniques are required to develop unconventional natural gas resources efficiently. Horizontal drilling is a specialized drilling technique intended to increase the exposure of the wellbore to the natural gas producing formation and increase drainage rates and production volumes. We have equipped 39 of our 70 rigs for drilling horizontal wells. As many of these areas are also characterized by hard rock formations entailing more difficult drilling penetration conditions, we have equipped 41 of our 70 rigs with air compression systems to provide underbalanced drilling, which results in higher penetration rates through hard rock formations when compared to traditional fluid-based circulation systems. In response to rising demand from our customers for equipment that is capable of drilling wells horizontally into unconventional natural gas formations and providing underbalanced drilling services, we have increased our fleet of drilling rigs capable of efficiently serving these markets through acquisitions and new rig construction.
In response to rising demand from our customers for equipment that is capable of efficiently drilling wells in unconventional natural gas formations, we have completed several transactions in 2005 aimed at enhancing our ability to serve these markets. In April 2005, we acquired Thornton Drilling Company, which owned a fleet of 12 rigs and leased a thirteenth rig operating in the Arkoma Basin, and eight rigs from SPA Drilling L.P., five of which are targeting the Barnett Shale formation in the Fort Worth Basin. In June 2005 and August 2005, we acquired six more rigs, five of which targeted the Barnett Shale formation in the Fort Worth Basin. These transactions substantially expanded our unconventional natural gas contract drilling operations beyond our traditional markets in the Appalachian Basin and the Rocky Mountains. In addition to these acquisitions, over the past three years we have purchased seven newly constructed rigs and have devoted significant capital expenditures to upgrade other rigs in our fleet for underbalanced and horizontal drilling. These investments have positioned our fleet to capitalize on our customers' rapidly growing unconventional resource exploration and development activity.
On November 28, 2005, we consummated an initial public offering of our common stock (the "IPO"). In the IPO, we sold 4,411,765 shares of our common stock to the public at a price of $14.00 per share and
certain selling stockholders sold 4,411,765 shares of our common stock to the public at the same price. We received net proceeds of approximately $55.4 million from the IPO. In connection with the IPO, on November 22, 2005, our common stock began trading on the NASDAQ National Market. See "Use of Proceeds" under Item 5 of this Report.
OUR MARKETS
Appalachian Basin
We provide drilling services to customers engaged in developing unconventional natural gas formations throughout the Appalachian Basin. The Appalachian Basin is one of the largest hydrocarbon producing regions in North America, covering approximately 72,000 square miles in the states of Kentucky, New York, Ohio, Pennsylvania, Tennessee, Virginia and West Virginia.
The Basin is characterized by highly porous sandstones alternating with less porous shales, at depths of 3,000 to 6,000 feet. Since the mid 1970's, significant resources have been committed to developing the natural gas bearing Clinton/Medina sands in northwestern Pennsylvania, western New York and eastern Ohio. The Clinton/Medina sands, which are 4,000 to 6,000 feet in depth, generally have very low porosities and permeabilities. To recover natural gas from this formation, fracturing techniques are used to increase permeability, allowing the natural gas to flow to the surface. More recently, producers have been increasing capital spending focused on the development of the deeper Trenton/Black River formations, which are at depths approaching 10,000 feet. Deeper Trenton/Black River wells are vertically drilled on air in an underbalanced state prior to drilling a several thousand foot horizontal section in the formation on fluid. These wells are typically significantly more prolific than more conventional Clinton/Medina wells, with initial production rates ranging from 10 to 20 Mmcf/day and gross reserves per well ranging from 8 to 10 Bcf. We have most of the equipment in the Appalachian Basin capable of drilling Trenton/Black River wells.
Natural gas also is found in shallow coal seams throughout the Appalachian Basin, which is commonly referred to as CBM. In recent years, natural gas producers have begun to exploit these CBM formations, due to advances in extraction technology and higher energy prices. In addition to exploration and development activity on behalf of more traditional natural gas producers, coal companies have engaged in the development of CBM formations in order reduce the concentration of these deposits in advance of mining operations, reducing the risk of underground fires or explosions. We support each of these activities with rigs that drill horizontally into the coal seams, providing faster drainage than vertical drilling. We also have rigs that work for coal companies in advance of coal mining operations to extract metal casing and other materials from existing wells, to reduce the possibility of underground fires or explosions during mining.
We market 31 drilling rigs and store four stacked rigs in the Appalachian Basin. The following table sets forth certain information with respect to each of these marketed rigs as of March 27, 2006.
DRILLING CAPABILITY CURRENT ACTIVITY -------------------------- -------------------------------------------------------------- RIG NO. HORIZONTAL UNDERBALANCED TYPE CONTRACT PLAY ------- ---------- ------------- ---------- ---------------------------------- ------------
15 [X] Vertical Daywork Devonian (3) 53 [X] [X] Horizontal Daywork CBM (1) 55 [X] [X] Vertical Daywork Devonian 56 [X] [X] Horizontal Daywork CBM 57 [X] [X] Vertical Daywork Devonian 24 [X] Vertical Footage Clinton (2) 25 [X] Vertical Footage Clinton 34 [X] Vertical Footage Clinton 35 [X] Vertical Footage Clinton 36 [X] Vertical Footage Clinton
DRILLING CAPABILITY CURRENT ACTIVITY -------------------------- -------------------------------------------------------------- RIG NO. HORIZONTAL UNDERBALANCED TYPE CONTRACT PLAY ------- ---------- ------------- ---------- ---------------------------------- ------------
37 [X] Vertical Footage Clinton 39 [X] [X] Vertical Daywork Devonian 46 [X] [X] Vertical Daywork Devonian 51 [X] [X] Horizontal Daywork Oriskany (4) 21 [X] [X] Horizontal Daywork TBR (5) 43 [X] [X] Horizontal Daywork TBR 48 [X] [X] Horizontal Daywork TBR 52 [X] [X] Horizontal Daywork TBR 54 [X] [X] Horizontal Daywork TBR 1 Coal (6) Daywork N/A 2 Coal Daywork N/A 8 Coal Daywork N/A 10 Coal Daywork N/A 18 Coal Daywork N/A 20 Coal Daywork N/A 31 Coal Daywork N/A 41 Coal Daywork N/A 42 Coal Daywork N/A 4 [X] Vertical Daywork Devonian 3 [X] [X] Available for service but inactive 5 [X] Available for service but inactive
(1) Coalbed methane development.
(2) Clinton/Medina development.
(3) Devonian development.
(4) Oriskany development.
(5) Trenton/Black River exploration and development.
(6) Re-drilling and plugging operations in advance of long wall coal mining.
Our principal competitors in the Appalachian Basin are primarily smaller, family-owned companies that serve fragmented markets within the Basin.
In the last two years, we have witnessed a significant increase in acquisitions and divestitures of oil and gas properties in the Appalachian Basin, which we believe to be directly attributable to the appreciation of natural gas prices over the same period of time and the corresponding improvement in the economics of producing natural gas. Acquisition activity has been driven by a broad universe of buyers, comprised of both publicly traded independent oil and natural gas companies who have actively sought to expand their operations in the region, and a number of financial investors who have shown an active interest in the region. We believe that the recent buyers of oil and natural gas properties in the region intend to increase the level of drilling activity on the properties which they have acquired in an effort to enhance the return on the capital invested in the acquisition of the property. We believe the increased level of acquisition activity should produce an acceleration of drilling activity in the Appalachian Basin that will inure to our benefit.
Arkoma Basin
The Arkoma Basin includes portions of western Arkansas and eastern Oklahoma covering an area of about 33,800 square miles. The area is characterized by organically rich rock layers that produce natural gas at depths averaging 7,000 feet. Most natural gas directed drilling in the Arkoma Basin is conducted by rigs equipped with air compression equipment for underbalanced drilling operations.
More recently, operators have been leasing acreage to develop shallower natural gas-bearing formations, known as the Fayetteville Shale on the Arkansas side and the Caney Shale on the Oklahoma side of the Arkoma Basin. These Mississippian age formations, existing at depths of 1,500 to 6,500 feet, are geologically similar to the Barnett Shale formation in northern Texas. Within the Fayetteville Shale, one producer has amassed a substantial acreage position and has recently commenced a horizontal drilling pilot
program, which in its early stages has yielded results comparable to what has been achieved in some of the more prolific unconventional resource plays in North America.
Currently, the majority of our rigs in the Arkoma Basin are drilling horizontally into the Hartshorne coal seam, which is found at depths of 300 to 4,000 feet throughout the Arkoma Basin. Unlike CBM plays in other parts of the U.S., the Hartshorne coal seams produce very little water and allow for rapid production of CBM after a well is completed. The typical CBM well we drill in this market is 2,500 to 3,000 feet deep with a horizontal section of similar length. While this play began with vertical drilling, it is now almost exclusively drilled horizontally.
We market 15 drilling rigs in the Arkoma Basin. The following table sets forth certain information with respect to each of these rigs as of March 27, 2006.
DRILLING CAPABILITY CURRENT ACTIVITY -------------------------- ---------------------------------------- RIG NO. HORIZONTAL UNDERBALANCED TYPE CONTRACT PLAY ------- ---------- ------------- ---------- -------- ---------------- 38 [X] [X] Horizontal Daywork Caney (1) 40 [X] [X] Vertical Daywork Conventional (3) 104 [X] [X] Horizontal Daywork CBM (2) 105 [X] [X] Horizontal Daywork CBM 108 [X] [X] Horizontal Daywork CBM 109 [X] [X] Vertical Daywork CBM 114 [X] [X] Horizontal Daywork CBM 115 [X] [X] Vertical Daywork CBM 117 [X] [X] Vertical Footage CBM 119 [X] [X] Horizontal Daywork CBM 110 [X] [X] Vertical Daywork Conventional 112 [X] Vertical Daywork Conventional 116 [X] Vertical Daywork Conventional 118(4) [X] [X] Vertical Daywork Conventional 123 [X] Horizontal Daywork Fayetteville (5)
(1) Caney Shale exploration and development.
(2) Coalbed methane development.
(3) Conventional Arkoma Basin development.
(4) Leased from Stephens Production Co. Inc.
(5) Fayetteville Shale exploration and development
Our principal competitor in the Arkoma Basin is Nabors Industries Inc.
Northern Texas
The Barnett Shale formation, found near Fort Worth, Texas, at average depths of 6,500 to 8,500 feet, is the largest natural gas field in Texas. Although natural gas deposits were discovered in the Barnett Shale several decades ago, the technology necessary to economically exploit lower permeability reservoir rock was not available. The use of horizontal drilling to develop the formation, combined with the application of multi-stage fracturing techniques, has opened this formation to extensive drilling.
We market 12 drilling rigs and store three stacked rigs in northern Texas. The following table sets forth certain information with respect to each of these marketed rigs as of March 27, 2006.
DRILLING CAPABILITY CURRENT ACTIVITY -------------------------- ----------------------------------- RIG NO. HORIZONTAL UNDERBALANCED TYPE CONTRACT PLAY ------- ---------- ------------- ---------- -------- ----------- 205 [X] Horizontal Daywork Barnett (1) 206 [X] Vertical Footage Barnett 207 [X] Horizontal Daywork Barnett 209 [X] Horizontal Daywork Barnett 211 [X] Horizontal Daywork Barnett 212 [X] Horizontal Daywork Barnett 214 [X] Horizontal Daywork Barnett 33 Vertical Footage Permian (2) 201 Vertical Footage Permian 203 Vertical Footage Permian 210 Vertical Daywork Permian 215 [X] Horizontal Daywork Barnett
(1) Northern Texas Barnett Shale development.
(2) Eastern Permian Basin oil development.
Our principal competitors in northern Texas are Patterson-UTI and Nabors.
The Rocky Mountains
According to U.S. Geological Survey (USGS) estimates, the Rocky Mountain region has the largest quantity of natural gas resources in the U.S., most of which are considered to be unconventional.
Our operations are focused in the Uintah Basin in eastern Utah and the Piceance Basin in western Colorado. Nearly all of the recoverable natural gas reserves in these basins are contained in unconventional formations. Natural gas in the Uintah Basin is produced from three tight sand formations. The Piceance basin is characterized by thick natural gas accumulations primarily in the Williams Fork formation.
The Uintah Basin also has deposits of black wax oil at depths of 5,500 to 6,500 feet. This oil has a high paraffin content that makes it viscous and non-pourable at room temperature, and it must be extracted, transported and refined with equipment specifically designed to handle it. Two of our rigs that were previously drilling for natural gas in this market are currently drilling black wax oil wells.
We market five drilling rigs in the Rocky Mountains. The following table sets forth certain information with respect to each of these marketed rigs as of March 27, 2006.
DRILLING CAPABILITY CURRENT ACTIVITY -------------------------- -------------------------------------- RIG NO. HORIZONTAL UNDERBALANCED TYPE CONTRACT PLAY ------- ---------- ------------- ---------- -------- -------------- 32 [X] [X] Horizontal Daywork Uintah Gas (3) 47 [X] [X] Horizontal Daywork Piceance (1) 7 [X] [X] Vertical Daywork Uintah Gas 14 [X] [X] Vertical Daywork Uintah Oil (2) 45 [X] [X] Horizontal Daywork Uintah Gas
(1) Piceance Basin development.
(2) Uintah Basin Lower Green River heavy wax oil drilling.
(3) Uintah Basin Gas development below the Green River formation
Our principal competitors in the Rocky Mountains are Nabors and Patterson-UTI.
CUSTOMERS AND MARKETING
Our customers are principally independent natural gas producers. We market our drilling rigs primarily on a regional basis, through employee marketing representatives. Repeat business from previous customers accounts for a substantial portion of our business. Traditionally, our rigs have been contracted on a well by well basis. With the recent strengthening of market conditions, however, we are witnessing a shift in contract terms towards longer duration contracts.
Our drilling rigs are also used to a lesser extent by coal and regulated natural gas storage companies to plug old wells. We also have occasionally drilled for potash, salt and other chemicals as well as provided underground sequestration of carbon dioxide produced by coal fired power plants.
We market our rigs to a number of customers. In 2005, we drilled wells for 144 different customers, compared to 55 customers in 2004 and 55 customers in 2003. The increase in number of customers in 2005 versus prior periods reflects the additional customers we added when we entered the Arkoma and North Texas markets. The following table shows our three largest customers as a percentage of our total contract drilling revenue for each of our last three years.
Total Contract Drilling Year Customer Revenue Percentage ---- -------------------------- ----------------------- 2005 Consol 9.3% Fortuna 6.6% Great Lakes Energy 5.9% ---- Total 21.8% ==== 2004 Fortuna 16.3% Consol 14.3% Columbia Natural Resources 12.6% ---- Total 43.2% ==== 2003 Equitable Resources 10.8% Consol 10.4% Fortuna 9.5% ---- Total 30.7% ====
DRILLING CONTRACTS
Our contracts for drilling natural gas wells are obtained either through competitive bidding or through direct negotiations with customers. Our oil and natural gas drilling contracts provide for compensation on a "daywork" or "footage" basis. In 2005, approximately 77% of our revenues were derived from daywork contracts. Most of the wells we drilled pursuant to footage contracts were drilled in our Northern Appalachian region. 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. Our contracts generally provide for the drilling of a single well or a series of wells and typically permit the customer to terminate on short notice.
Daywork contracts. Under daywork contracts, we provide a drilling rig with required personnel to the operator, who supervises the drilling of the well. We are paid based on a negotiated fixed rate per day while the rig is utilized. The rates for our services depend on market and competitive conditions, the nature of the operations to be performed, the duration of the work, the equipment and services to be provided, the geographic area involved and other variables. Lower rates may be paid when the rig is in transit, or when drilling operations are interrupted or restricted by conditions beyond our control. In addition, daywork contracts typically provide for a separate amount to cover the cost of mobilization and demobilization of the drilling rig. Daywork drilling contracts generally specify the type of equipment to be used, the size of the hole and the depth of the well. Under a daywork drilling contract, the customer bears a large portion of
out-of-pocket costs of drilling and we generally do not bear any part of the usual capital risks associated with oil and natural gas exploration.
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 pay more of the out-of-pocket costs associated with footage contracts compared to daywork contracts. We provide technical expertise and engineering services, as well as most of the equipment required for the well, and are compensated when the contract terms have been satisfied. Many of our footage contracts now provide for conversion to daywork rates under certain specified unexpected conditions.
The risks under footage contracts are greater than under daywork contracts because we assume more of the risks associated with drilling operations generally assumed by the operator in a daywork contract, including risk of blowout, loss of hole, lost or damaged drill pipe, machinery breakdowns, abnormal drilling conditions and risks associated with subcontractors' services, supplies, cost escalation and personnel. Historically, the percentage of revenues derived from footage contracts has decreased from over 50% in the early 2000's to approximately 23% currently. We expect this percentage to decline further in the future. Currently only ten of our 70 rigs are working on a footage basis. Many of our footage contracts now have provisions whereby some or all of the risks associated with geological issues and down hole mechanical matters have been shifted to our customers. The transfer of this risk is done by contractually transferring the drilling services from a footage drilled basis to an hourly based daywork type contract when unforeseen or uncontrollable events are encountered during the drilling process. When this occurs, the contract also provides for the transfer of third party costs and tangible items such as drill bits from us to our customers during these unforeseen problematic periods.
OUR RIG FLEET
General
A land drilling rig consists of engines, a hoisting system, a rotating system, pumps and related equipment to circulate drilling fluid, blowout preventers and related equipment. Diesel or gas engines are typically the main power sources for a drilling rig. Power requirements for drilling jobs may vary considerably, but most land drilling rigs employ two or more engines to generate between 500 and 2,000 horsepower, depending on well depth and rig design. Most drilling rigs capable of drilling in deep formations, involving depths greater than 15,000 feet, use diesel electric power units to generate and deliver electric current through cables to electrical switch gears, then to direct current electric motors attached to the equipment in the hoisting, rotating and circulating systems.
There are numerous factors that differentiate land drilling rigs, including their power generation systems and their drilling depth capabilities. The actual drilling depth capability of a rig may be less than or more than its rated depth capability due to numerous factors, including the size, weight and amount of the drill pipe on the rig. The intended well depth and the drill site conditions determine the amount of drill pipe and other equipment needed to drill a well. Generally, land rigs operate with crews of five to six persons.
Derrick hookload capacity and rig horsepower are the main drivers of depth rating on a vertical rig. They determine a rig's ability to lower, hoist and suspend casing and drilling pipe weight in the wellbore. Relative to total measured depth, horizontal wells have lower requirements on hookload and horsepower because casing, which is used to isolate the natural gas bearing formation from other geological features, is not run into the horizontal section of the well and once drill pipe is laying horizontally, its suspended weight and the power required to raise it decreases compared to a vertical wellbore of the same length. Circulating systems, which can be based on either fluid or compressed air, are used while drilling to evacuate cuttings and prevent the pipe from becoming stuck in the wellbore. Relative to vertical wells of the same measured depth, horizontal wells require greater circulating capability to move the cuttings from the horizontal section through a 90 degree curve to the initial vertical section of the wellbore.
We own 70 drilling rigs, of which 63 are actively marketed. A land drilling rig of the general type we operate consists of engines, drawworks, mast, pumps, blowout preventers, drill pipe, air drilling and percussion packages consisting of compressors and boosters, and related equipment.
The size and type of rig utilized depends, among other factors, upon well depth and site conditions. An active maintenance and replacement program during the life of a drilling rig permits upgrading of components on an individual basis. Over the life of a typical rig, due to the normal wear and tear of operating up to 24 hours a day, several of the major components, such as engines, air compressors, boosters and drill pipe, are replaced or rebuilt on a periodic basis as required. Other components, such as the substructure, mast and drawworks, can be utilized for extended periods of time with proper maintenance.
Our rigs are mechanical, truck-mounted or portable, equipped for fluid and air drilling and are capable of year-round operations. These configurations give us the ability to drill virtually all types of wells drilled in our markets. Due to the geologic characteristics in our markets, most of the wells drilled in these areas utilize air drilling. We believe that air drilling provides advantages over traditional drilling techniques when drilling through hard rock formations. These advantages include improved drilling penetration rates, limited amount of fluids lost into the formation and minimized formation damage. We believe that we have drilled more wells using air drilling techniques than any other U.S. contractor. We also own various vehicles and other ancillary equipment used in the operation of our rigs.
This equipment consists of bulldozers, trucks and other support equipment.
We believe that our drilling rigs and other related equipment are in good operating condition.
Our employees perform periodic maintenance and minor repair work on our drilling rigs. We rely on various oilfield service companies for major repair work and overhaul of our drilling equipment when needed. We also engage in periodic improvement of our drilling equipment. In the event of major breakdowns or mechanical problems, our rigs could be subject to significant idle time and a resulting loss of revenue if the necessary repair services are not immediately available.
COMPETITION
We encounter substantial competition from other drilling contractors. Our primary market areas are highly fragmented and competitive. The fact that drilling rigs are mobile and can be moved from one market to another in response to market conditions heightens the competition in the industry. Our principal competitors vary by region. See "--Our markets."
We believe rig capability, 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:
o the mobility and efficiency of the rigs;
o the safety records of the rigs;
o crew experience and skill;
o customer relationships;
o the offering of ancillary services; and
o the ability to provide drilling equipment adaptable to, and personnel familiar with, new technologies and drilling techniques.
While we must be competitive in our pricing, our competitive strategy generally emphasizes the quality of our equipment, the safety record of our rigs and the experience of our rig crews to differentiate us from our competitors.
Contract drilling companies compete primarily on a regional basis, and the intensity of competition may vary significantly from region to region at any particular time. If demand for drilling services improves in a region where we operate, our competitors might respond by moving in suitable rigs from other regions.
Many of our competitors have greater financial, technical and other resources than we do. Their greater capabilities in these areas may enable them to:
o better withstand industry downturns;
o compete more effectively on the basis of price and technology;
o better retain skilled rig personnel; and
o 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, drill pipe and drill collars. We do not rely on a single source of supply for any of these items. From time to time during periods of high demand we have experienced shortages. Shortages result in increased prices for drilling supplies that we are not always able to pass on to customers. In addition, during periods of shortages, the delivery times for drilling supplies can be substantially longer. Any significant delays in our obtaining drilling supplies could limit drilling operations and jeopardize our relationships 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 an adverse effect on our financial condition and results of operations.
SEASONALITY
Certain of our operations in the Appalachian Basin are conducted in areas subject to extreme weather conditions, and often in difficult terrain. During certain parts of the year, primarily in the winter and the spring, our operations are often hindered because of cold, snow or muddy conditions. Certain state and local governments impose restrictions on the movement of our equipment during parts of the year when the roads are susceptible to damage from the movement of heavy equipment. These restrictions are known as "frost laws". Our operations are also limited from time to time by the practical difficulty of operating in certain weather conditions.
In the southern Appalachian Basin, our operations are limited primarily by winter weather in the fourth quarter and the first quarter. In the northern Appalachian Basin, our operations are limited primarily by the frost laws, in the first quarter and the second quarter.
EMPLOYEES
We currently have approximately 1,300 employees. Approximately 160 of these employees are salaried administrative or supervisory employees. The rest of our employees are hourly employees who operate or maintain our drilling rigs and rig-hauling trucks. The number of hourly employees fluctuates depending on the number of drilling projects we are engaged in at any particular time. None of our employment arrangements is subject to collective bargaining arrangements.
OPERATING HAZARDS AND INSURANCE
Our operations are subject to many hazards inherent in the land drilling business, including, for example, blowouts, craterings, fires, explosions, loss of well control, poisonous gas emissions, loss of hole, damaged or lost drill strings, and damage or loss from inclement weather. These hazards could cause personal injury or death, serious damage to or destruction of property and equipment, suspension of drilling operations, or
substantial damage to the environment, including damage to producing formations and surrounding areas. Generally, we seek to obtain indemnification from our customers by contract for some of these risks. To the extent not transferred to customers by contract, we seek protection against some of these risks through insurance, including property casualty insurance on our rigs and drilling equipment, commercial general liability, which has coverage extension for underground resources and equipment coverage, commercial contract indemnity, commercial umbrella and workers' compensation insurance.
Our insurance coverage for property damage to our rigs and drilling equipment is based on our estimate of the cost of comparable used equipment to replace the insured property. There is a deductible of $100,000 per occurrence on rigs and $25,000 per occurrence on equipment. Our third party liability insurance coverage under the general liability policy is $1 million per occurrence, with a self-insured retention of $10,000 per occurrence. The commercial umbrella policy coverage is $20 million per occurrence, with a self-insured retention of $10,000 per occurrence. We believe that we are adequately insured for 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.
We maintain worker's compensation insurance in all states in which we operate. The states of West Virginia and Ohio are exclusive with regard to this coverage. We pay premiums to those states directly based upon the payroll related to our employees working in those states. In all other states, with the exception of Texas, which has a $1,000 deductible, we maintain a $100,000 deductible for each accident.
GOVERNMENT REGULATION AND ENVIRONMENTAL MATTERS
General
Our operations are affected from time to time and in varying degrees by political developments and federal, state and local environmental, health and safety laws and regulations. In particular, oil and natural gas production, operations and economics are or have been affected by price controls, taxes and other laws relating to the oil and natural gas industry, by changes in such laws and by changes in administrative regulations. Although significant capital expenditures may be required to comply with such laws and regulations, to date, such compliance costs have not had a material adverse effect on our earnings or competitive position. In addition, our operations are vulnerable to risks arising from the numerous laws and regulations governing the discharge of materials into the environment or otherwise relating to environmental protection.
Environmental regulation
Our activities are subject to existing federal, state and local laws and regulations governing environmental quality, pollution control and the preservation of natural resources. These laws and regulations concern, among other things, air emissions, the containment, disposal and recycling of waste materials, and reporting of the storage, use or release of certain chemicals or hazardous substances. Numerous federal and state environmental laws regulate drilling activities and impose liability for discharges of waste or spills, including those in coastal areas. We have conducted drilling activities in or near ecologically sensitive areas, such as wetlands and coastal environments, which are subject to additional regulatory requirements. State and federal legislation also provide special protections to animal and aquatic life that could be affected by our activities. In general, under various applicable environmental programs, we may potentially be subject to regulatory enforcement action in the form of injunctions, cease and desist orders and administrative, civil and criminal penalties for violations of environmental laws. We may also be subject to liability for natural resource damages and other civil claims arising out of a pollution event.
Except for the handling of solid wastes directly generated from the operation and maintenance of our drilling rigs, such as waste oils and wash water, it is our practice to require our customers to contractually assume responsibility for compliance with environmental regulations. Laws and regulations protecting the environment have become more stringent in recent years, and may, in some circumstances, impose strict liability, rendering a person liable for environmental damage without regard to negligence or fault on the part of that person. These laws and regulations may expose us to liability for the conduct of or conditions
caused by others, or for our own acts that were in compliance with all applicable laws at the time the acts were performed. The application of these requirements or adoption of new requirements could have a material adverse effect on us.
Environmental regulations that affect our customers also have an indirect impact on us.
Increasingly stringent environmental regulation of the oil and natural gas industry has led to higher drilling costs and a more difficult and lengthy well permitting process. The primary environmental statutory and regulatory programs that affect our operations include the following:
Oil Pollution Act and Clean Water Act. The Oil Pollution Act of 1990, or OPA, amends several provisions of the federal Water Pollution Control Act of 1972, which is commonly referred to as the Clean Water Act, or CWA, and other statutes as they pertain to the prevention of and response to spills or discharges of hazardous substances or oil into navigable waters. Under the OPA, a person owning or operating a facility or equipment (including land drilling equipment) from which there is a discharge or threat of a discharge of oil into or upon navigable waters and adjoining shorelines is liable, regardless of fault, as a "responsible party" for removal costs and damages. Federal law imposes strict, joint and several liability on facility owners for containment and clean-up costs and some other damages, including natural resource damages, arising from a spill. The U.S. Environmental Protection Agency, or EPA, is also authorized to seek preliminary and permanent injunctive relief, civil or administrative fines or penalties and, in some cases, criminal penalties and fines. State laws governing the control of water pollution also provide varying civil and criminal penalties and liabilities in the case of releases of petroleum or its derivatives into surface waters or into the ground. In the event that a discharge occurs at a well site at which we are conducting drilling operations, we may be exposed to claims under the CWA or similar state laws.
Some of our operations are also subject to EPA regulations that require the preparation and implementation of spill prevention control and countermeasure, or SPCC, plans to address the possible discharge of oil into navigable waters. Where so required, we have SPCC plans in place.
Superfund
The Comprehensive Environmental Response, Compensation, and Liability Act, as amended, also known as CERCLA or the "Superfund" law, imposes liability, without regard to fault or the legality of the original conduct, on certain classes of persons with respect to the release of a "hazardous substance" into the environment. These persons include (i) the current owner and operator of a facility from which hazardous substances are released, (ii) owners and operators of a facility at the time any hazardous substances were disposed, (iii) generators of hazardous substances who arranged for the disposal or treatment at or transportation to such facility of hazardous substances and (iv) transporters of hazardous substances to disposal or treatment facilities selected by them. We may be responsible under CERCLA for all or part of the costs to clean up sites at which hazardous substances have been released. To date, however, we have not been named a potentially responsible party under CERCLA or any similar state Superfund laws.
Hazardous waste disposal
Our operations involve the generation or handling of materials that may be classified as hazardous waste and subject to the federal Resource Conservation and Recovery Act and comparable state statutes. The EPA and various state agencies have limited the disposal options for some hazardous and nonhazardous wastes and is considering the adoption of stricter handling and disposal standards for nonhazardous wastes. We believe that our operations are in material compliance with applicable environmental laws and regulations.
Health and safety matters
Our facilities and operations are also governed by laws and regulations, including the federal Occupational Safety and Health Act, or OSHA, relating to worker health and workplace safety. As an example, the Occupational Safety and Health Administration has issued the Hazard Communication Standard, or HCS, requiring employers to identify the chemical hazards at their facilities and to educate employees about these
hazards. HCS applies to all private-sector employers, including the oil and natural gas exploration and producing industry. HCS requires that employers assess their chemical hazards, obtain and maintain written descriptions of these hazards, develop a hazard communication program and train employees to work safely with the chemicals on site. Failure to comply with the requirements of the standard may result in administrative, civil and criminal penalties. We believe that appropriate precautions are taken to protect employees and others from harmful exposure to materials handled and managed at our facilities and that we operate in substantial compliance with all OSHA regulations.
AVAILABLE INFORMATION
We were incorporated in the State of Delaware in December, 1997. Our principal executive offices are located at 4055 International Plaza, Suite 610, Fort Worth, Texas 76109. Our telephone number is 817-735-8793.
We file annual, quarterly and current reports, proxy statements and other information with the Securities and Exchange Commission, or SEC. You may read and copy our reports, proxy statements and other information at the SEC's public reference room at Room 1024, 450 Fifth Street N.W., Washington, D.C. 20549. You can request copies of these documents by writing to the SEC and paying a fee for the copying cost. Please call the SEC at 1 800-SEC-0330 for more information about the operation of the public reference room. Our SEC filings are also available at the SEC's web site at www.sec.gov. In addition, you can read and copy our SEC filings at the office of the National Association of Securities Dealers, Inc. at 1735 K Street N.W., Washington, D.C. 20006.
You may obtain a free copy of our annual reports on Form 10-K, quarterly reports on Form 10-Q and current reports on Form 8-K and amendments to those reports as soon as reasonably practicable after such reports have been filed with or furnished to the SEC on our website on the World Wide Web at www.uniondrilling.com or by contacting the Investor Relations Department at our corporate offices by calling 817-735-8793 or by sending an e-mail message to brektorik@uniondrilling.com. In addition, our Standards of Integrity, which includes our code of ethics for our senior officers, is available on our website.
CAUTIONARY STATEMENT CONCERNING FORWARD-LOOKING STATEMENTS AND RISK FACTORS
We are including the following discussion to inform our existing and potential security holders generally of some of the risks and uncertainties that can affect our company and to take advantage of the "safe harbor" protection for forward-looking statements that applicable federal securities law affords.
From time to time, our management or persons acting on our behalf make forward-looking statements to inform existing and potential security holders about our company. These statements may include projections and estimates concerning the timing and success of specific projects and our future backlog, revenues, income and capital spending. Forward-looking statements are generally accompanied by words such as "estimate," "project," "predict," "believe," "expect," "anticipate," "plan," "intend," "seek," "will," "should," "goal" or other words that convey the uncertainty of future events or outcomes. These forward-looking statements speak only as of the date on which they are first made, which in the case of forward-looking statements made in this report is the date of this report. Sometimes we will specifically describe a statement as being a forward-looking statement and refer to this cautionary statement.
In addition, various statements that this Annual Report on Form 10-K contains, including those that express a belief, expectation or intention, as well as those that are not statements of historical fact, are forward-looking statements. Those forward-looking statements appear in Item 1 - "Business", Item 2 - "Properties" and Item 3 - "Legal Proceedings" in Part I of this report and in Item 5 - "Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities," and in Item 7 - "Management's Discussion and Analysis of Financial Condition and Results of Operations," Item 7A - "Quantitative and Qualitative Disclosures About Market Risk" and in the Notes to Consolidated Financial Statements we have included in Item 8 of Part II of this report and elsewhere in this report. These forward-looking statements speak only as of the date of this report. We disclaim any obligation to update these statements, and we caution you not to rely on them unduly. We have based these forward-looking
statements on our current expectations and assumptions about future events. While our management considers these expectations and assumptions to be reasonable, they are inherently subject to significant business, economic, competitive, regulatory and other risks, contingencies and uncertainties, most of which are difficult to predict and many of which are beyond our control. These risks, contingencies and uncertainties relate to, among other matters, the following:
o general economic and business conditions and industry trends;
o the continued strength of the contract land drilling industry in the geographic areas where we operate;
o levels and volatility of oil and gas prices;
o decisions about onshore exploration and development projects to be made by oil and gas companies;
o the highly competitive nature of our business;
o the success or failure of our acquisition strategy, including our ability to finance acquisitions and manage growth;
o our future financial performance, including availability, terms and deployment of capital;
o the continued availability of qualified personnel; and
o changes in, or our failure or inability to comply with, governmental regulations, including those relating to the environment.
We believe the items we have outlined above are important factors that could cause our actual results to differ materially from those expressed in a forward-looking statement contained in this report or elsewhere. We have discussed many of these factors in more detail elsewhere in this report. These factors are not necessarily all the important factors that could affect us. Unpredictable or unknown factors we have not discussed in this report could also have material adverse effects on actual results of matters that are the subject of our forward-looking statements. We do not intend to update our description of important factors each time a potential important factor arises. We advise our security holders that they should (1) be aware that important factors not referred to above could affect the accuracy of our forward-looking statements and (2) use caution and common sense when considering our forward-looking statements. Also, please read the risk factors set forth below.
ITEM 1A.
ITEM 1A. RISK FACTORS
RISKS RELATING TO OUR BUSINESS
OUR BUSINESS AND OPERATIONS ARE SUBSTANTIALLY DEPENDENT UPON, AND AFFECTED BY, THE LEVEL OF U.S. ONSHORE NATURAL GAS EXPLORATION AND DEVELOPMENT ACTIVITY, WHICH HAS EXPERIENCED SIGNIFICANT VOLATILITY. IF THE LEVEL OF THAT ACTIVITY DECREASES, OUR BUSINESS AND RESULTS OF OPERATIONS COULD BE ADVERSELY AFFECTED.
Our business and operations are substantially dependent upon, and affected by, the level of U.S. onshore natural gas exploration and development activity. Exploration and development activity determines the demand for contract land drilling and related services. We have no control over the factors driving the level of U.S. natural gas exploration and development activity. Those factors include, among others, the following:
o the market prices of natural gas;
o market expectations about future prices of natural gas or oil (which is closely correlated with natural gas prices);
o the cost of producing and delivering natural gas;
o the capacity of the natural gas pipeline network;
o government regulations and trade restrictions;
o the presence or absence of tax incentives;
o national and international political and economic conditions;
o levels of production by, and other activities of, the Organization of Petroleum Exporting Countries and other oil and natural gas producers;
o the levels of imports of natural gas, whether by pipelines from Canada or Mexico or by tankers in the form of LNG; and
o the development of alternate energy sources and the long-term effects of worldwide energy conservation measures.
The onshore contract drilling industry has experienced significant volatility in profitability and asset values. The industry's most recent significant downturn occurred in 2001 and 2002, and significantly and adversely affected our operating results. Currently, the onshore contract drilling business is experiencing increased demand for drilling services, principally due to improved oil and natural gas drilling and production economics. The increased activity in the exploration and production sector may not continue. In addition, ongoing movement or reactivation of land drilling rigs (including the movement of rigs from outside the U.S. into U.S. markets) or new construction of drilling rigs could increase rig supply and reduce contract drilling dayrates and utilization levels. We cannot predict the future level of demand for our contract drilling services, future conditions in the onshore contract drilling industry or future onshore contract drilling dayrates.
ALMOST 90% OF OUR DRILLING RIGS ARE MORE THAN 20 YEARS OLD, AND MAY REQUIRE INCREASING AMOUNTS OF CAPITAL TO UPGRADE AND REFURBISH. ANY FAILURE TO CONTINUE TO INVEST CAPITAL TO UPGRADE AND REFURBISH RIGS COULD RESULT IN OUR HAVING FEWER RIGS AVAILABLE FOR SERVICE.
Most of our drilling rigs were built during the years 1976 to 1982, the period of the industry's most recent building cycle. Our rig upgrade and refurbishment projects on marketed rigs typically require 60 to 90 days to complete at a cost of $175,000 to $250,000. This process includes derrick recertification, engine rebuilding or replacement and upgraded or replaced braking systems. Returning our stacked rigs to service would cost $1.5 to $2.5 million per rig for refurbishment and the purchase of drillpipe, pumps, generators and other required equipment. Depending upon the availability of equipment, this process could take from 90 to 180 days. To the extent we are unable to commence or continue such projects, we will have fewer rigs available for service, which could adversely affect our financial condition and results of operations.
IN THE YEAR ENDED DECEMBER 31, 2005, WE DERIVED APPROXIMATELY 21.8% OF OUR TOTAL REVENUES FROM THREE CUSTOMERS. THE LOSS OF ANY OF THOSE CUSTOMERS OR THE FAILURE TO REMARKET THE RIGS EMPLOYED BY THOSE CUSTOMERS COULD HAVE A MATERIAL ADVERSE EFFECT ON OUR FINANCIAL CONDITION AND RESULTS OF OPERATIONS.
In the year ended December 31, 2005, our three largest customers accounted for approximately 9.3%, 6.6% and 5.9%, respectively, of our total revenues. Our principal customers may not continue to employ our services and we may not be able to successfully remarket the rigs that they may choose not to employ. The loss of any of our principal customers or the failure to remarket the rigs employed by those customers could have a material adverse effect on our financial condition and results of operations.
OUR HISTORICAL STRATEGY HAS BEEN PREDICATED ON GROWING THROUGH A COMBINATION OF ACQUISITIONS OF RIGS FROM THIRD PARTIES AND THE CONSTRUCTION OF NEW RIGS. DUE TO INCREASED COMPETITION AMONG DRILLING CONTRACTORS FOR ADDITIONAL RIGS, WE MAY NOT BE ABLE TO CONTINUE TO ADD RIGS TO OUR FLEET, WHICH COULD HAVE AN ADVERSE EFFECT ON OUR ABILITY TO GROW REVENUE AND PROFITS.
Increased levels of U.S. oil and natural gas exploration and development activity has led to increased demand for drilling services by oil and natural gas producers. This has given drilling contractors an economic incentive to build new rigs and acquire additional rigs from third parties, leading to an increase in the backlog for newly built rigs and enhanced competition for the acquisition of existing rigs. Our business and strategy could be adversely affected if we are unable to acquire newly built rigs or purchase additional drilling rigs on acceptable terms or in a timely manner.
INCREASED DEMAND AMONG DRILLING CONTRACTORS FOR CONSUMABLE SUPPLIES, INCLUDING FUEL, AND ANCILLARY RIG EQUIPMENT, SUCH AS PUMPS, VALVES, DRILLPIPE AND ENGINES, MAY LEAD TO DELAYS IN OBTAINING THESE MATERIALS AND OUR INABILITY TO OPERATE OUR RIGS IN AN EFFICIENT MANNER.
All of our contracts provide that our customers bear the financial impact of increased fuel prices. However, prolonged shortages in the availability of fuel to run our drilling rigs resulting from action of the elements, warlike actions or other 'Force Majeure' events could result in the suspension of our contracts and have a material adverse effect on our financial condition and results of operations. In recent months, we have experienced increased lead times in purchasing ancillary equipment for our drilling rigs. To the extent there are continued delays in being able to purchase important components for our rigs, certain of our rigs may not be available for operation or may not be able to operate as efficiently as expected, which could adversely affect our financial condition, results of operations and cash flows.
TO THE EXTENT WE ACQUIRE ADDITIONAL RIGS IN THE FUTURE, WE MAY EXPERIENCE DIFFICULTY INTEGRATING THOSE ACQUISITIONS. ADDITIONALLY, WE MAY INCUR LEVERAGE TO EFFECT THOSE ACQUISITIONS, WHICH ADDS ADDITIONAL FINANCIAL RISK TO OUR BUSINESS. TO THE EXTENT WE INCUR TOO MUCH LEVERAGE IN UNDERTAKING ACQUISITIONS, WE MAY ADVERSELY AFFECT OUR FINANCIAL POSITION.
The process of integrating acquired rigs or newly constructed rigs may involve unforeseen difficulties and may require a disproportionate amount of management's attention and significant financial and other resources. We may not be able to successfully manage and integrate new rigs into our existing operations or successfully maintain the market share attributable to drilling rigs that we purchase. We may also encounter cost overruns related to newly constructed rigs or unexpected costs related to the acquired rigs, including costs associated with major overhauls. To the extent we experience some or all of these difficulties, our financial condition would be adversely affected.
Expanding our fleet by building new rigs or acquiring rigs from third parties may cause the company to incur additional financial leverage, increasing our debt service requirements, which could adversely affect our operating results and financial position.
WE INTEND TO PURCHASE ADDITIONAL DRILLING RIGS, UPGRADE SOME OF OUR MARKETED DRILLING RIGS AND REFURBISH SOME OF OUR STACKED DRILLING RIGS. ANY DELAY COULD RESULT IN A LOSS OF REVENUE.
We intend to purchase additional drilling rigs, upgrade some of our marketed drilling rigs and refurbish some of our stacked drilling rigs. All of these projects are subject to risks of delay or cost overruns inherent in large construction projects. Among those risks are:
o shortages of equipment, materials or skilled labor;
o long lead times or delays in the delivery of ordered materials and equipment;
o engineering problems;
o work stoppages;
o weather interference;
o unavailability of specialized services; and
o unanticipated cost increases.
These factors may contribute to delays in the delivery of the drilling rigs, which could result in a loss of revenue. Additionally, we may incur higher costs than expected, which would adversely affect the economics of the investment in such rigs.
WE HAVE INCURRED LOSSES IN THE PAST AND MAY CONTINUE TO INCUR LOSSES. IF WE INCUR LOSSES IN THE FUTURE, THE VALUE OF OUR COMMON STOCK COULD DECLINE.
We have a history of losses. We reported net losses for the years ended December 31, 2003 and 2002 and for the three years prior to 2001. We earned net income in the year ended December 31, 2004, and for the year ended December 31, 2005, but we may not be able to continue to realize profits. A lack of profitability could adversely affect the price of our common stock. In addition, if we do not remain profitable, our ability to complete future financings could be impaired, which could have an adverse effect on our business.
WE MAY NOT BE ABLE TO RAISE ADDITIONAL FUNDS THROUGH PUBLIC OR PRIVATE FINANCINGS OR ADDITIONAL BORROWINGS, WHICH COULD HAVE A MATERIAL ADVERSE EFFECT ON OUR FINANCIAL CONDITION.
The contract drilling industry is capital intensive. Our cash flow from operations and the continued availability of credit are subject to a number of variables, including our rig utilization rates, operating margins and ability to control costs and obtain contracts in a competitive industry. Our cash flow from operations, proceeds from this offering and present borrowing capacity may not be sufficient to fund our anticipated acquisition program, capital expenditures and working capital requirements. We may from time to time seek additional financing, either in the form of bank borrowings, sales of debt or equity securities or otherwise. To the extent our capital resources and cash flow from operations are at any time insufficient to fund our activities or repay our indebtedness as it becomes due, we will need to raise additional funds through public or private financings or additional borrowings. We may not be able to obtain any such capital resources. If we are at any time not able to obtain the necessary capital resources, our financial condition and results of operations could be materially adversely affected.
WE COULD BE ADVERSELY AFFECTED IF WE LOST THE SERVICES OF CERTAIN OF OUR OFFICERS AND KEY EMPLOYEES.
The success of our business is highly dependent upon the services, efforts and abilities of Christopher D. Strong, our President and Chief Executive Officer, and certain other officers and key employees, particularly Dan Steigerwald, our Chief Financial Officer, and J. Michael Poole, our Executive Vice President of Operations. Our business could be materially and adversely affected by the loss of any of these individuals. We do not have employment agreements with or maintain key man life insurance on the lives of any of our executive officers or key employees.
IF WE CANNOT KEEP OUR RIGS UTILIZED AT PROFITABLE RATES, OUR OPERATING RESULTS COULD BE ADVERSELY AFFECTED.
Our business has high fixed costs, and if we cannot keep our rigs utilized at profitable rates, our operating results could be adversely affected.
OUR OPERATIONS COULD BE ADVERSELY AFFECTED BY ABNORMALLY POOR WEATHER CONDITIONS.
Our operations are conducted in areas subject to extreme weather conditions, and often in difficult terrain. Primarily in the winter and spring, our operations are often curtailed because of cold, snow or muddy conditions. Unusually severe weather conditions could further curtail our operations and could have a material adverse effect on our financial condition and results of operations.
INCREASED COMPETITION IN OUR DRILLING MARKETS COULD ADVERSELY AFFECT RATES AND UTILIZATION OF OUR RIGS, WHICH COULD ADVERSELY AFFECT OUR FINANCIAL CONDITION AND RESULTS OF OPERATIONS.
We face competition from significantly larger drilling contractors with greater resources. Their greater resources may enable them to build new rigs or move existing rigs into any of our regional markets. The addition of rigs into our markets, either by existing competitors or new entrants, including possibly non-U.S. competitors, would increase the supply of available rigs in those markets, which could adversely affect the rates we can charge and utilization levels we can achieve.
OUR OPERATIONS ARE SUBJECT TO HAZARDS INHERENT IN THE LAND DRILLING BUSINESS THAT ARE BEYOND OUR CONTROL. IF THOSE RISKS ARE NOT ADEQUATELY INSURED OR INDEMNIFIED AGAINST, OUR RESULTS OF OPERATIONS COULD BE ADVERSELY AFFECTED.
Our operations are subject to many hazards inherent in the land drilling business, including, but not limited to:
o blowouts;
o craterings;
o fires;
o explosions;
o equipment failures;
o poisonous gas emissions;
o loss of well control;
o loss of hole;
o damaged or lost drill strings; and
o damage or loss from inclement weather or natural disasters.
These hazards are to some extent beyond our control and could cause, among other things:
o personal injury or death;
o serious damage to or destruction of property and equipment;
o suspension of drilling operations; and
o substantial damage to the environment, including damage to producing formations and surrounding areas.
Our insurance policies for public liability and property damage to others and injury or death to persons are in some cases subject to large deductibles and may not be sufficient to protect us against liability for all consequences of well disasters, personal injury, extensive fire damage or damage to the environment. We may not be able to maintain adequate insurance in the future at rates we consider reasonable, or particular types of coverage may not be available. The occurrence of events, including any of the above-mentioned risks and hazards, that are not fully insured against or the failure of a customer that has agreed to indemnify us against certain liabilities to meet its indemnification obligations could subject us to significant liability and could have a material adverse effect on our financial condition and results of operations.
OUR OPERATIONS ARE SUBJECT TO ENVIRONMENTAL, HEALTH AND SAFETY LAWS AND REGULATIONS THAT MAY EXPOSE US TO LIABILITIES FOR NONCOMPLIANCE, WHICH COULD ADVERSELY AFFECT US.
The U.S. oil and natural gas industry is affected from time to time in varying degrees by political developments and federal, state and local environmental, health and safety laws and regulations applicable to our business. Our operations are vulnerable to certain risks arising from the numerous environmental health and safety laws and regulations. These laws and regulations may restrict the types, quantities and concentration of various substances that can be released into the environment in connection with drilling activities, require reporting of the storage, use or release of certain chemicals and hazardous substances, require removal or cleanup of contamination under certain circumstances, and impose substantial civil liabilities or criminal penalties for violations. Environmental laws and regulations may impose strict liability, rendering a company liable for environmental damage without regard to negligence or fault, and could expose us to liability for the conduct of, or conditions caused by, others, or for our acts that were in compliance with all applicable laws at the time such acts were performed. Moreover, there has been a trend in recent years toward stricter standards in environmental, health and safety legislation and regulation, which may continue.
We may incur material liability related to our operations under governmental regulations, including environmental, health and safety requirements. We cannot predict how existing laws and regulations may be interpreted by enforcement agencies or court rulings, whether additional laws and regulations will be adopted, or the effect such changes may have on our business, financial condition or results of operations. Because the requirements imposed by such laws and regulations are subject to change, we are unable to forecast the ultimate cost of compliance with such requirements. The modification of existing laws and regulations or the adoption of new laws or regulations curtailing exploratory or development drilling for oil and natural gas for economic, political, environmental or other reasons could have a material adverse effect on us by limiting drilling opportunities.
WE MAY NOT BE ABLE TO ATTRACT AND RETAIN THE SERVICES OF QUALIFIED OPERATING PERSONNEL, WHICH COULD RESTRICT OUR ABILITY TO MARKET AND OPERATE OUR DRILLING RIGS OR RESULT IN ACCIDENTS AND OTHER OPERATIONAL DIFFICULTIES.
Increases in both onshore and offshore U.S. oil and natural gas exploration and production and resultant increases in contract drilling activity have created a shortage of qualified drilling rig personnel in the industry. If we are unable to attract and retain sufficient qualified operating personnel, our ability to market and operate our drilling rigs will be restricted. In addition, labor shortages could result in wage increases, which could reduce our operating margins and have an adverse effect on our financial condition and results of operations. To the extent that we are required to hire less experienced personnel, we may experience accidents or other operational difficulties and incur related costs.
WE WILL BE SUBJECT TO THE REQUIREMENTS OF SECTION 404 OF THE SARBANES-OXLEY ACT. IF WE ARE UNABLE TO COMPLY WITH SECTION 404 IN A TIMELY MANNER 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 results of operations could be adversely 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 materially adversely 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, all of which could have a material adverse effect on our business, results of operations and financial condition.
OUR DEBT AGREEMENTS CONTAIN RESTRICTIONS THAT LIMIT OUR FLEXIBILITY IN OPERATING OUR BUSINESS.
Our revolving credit facility contains various covenants that limit our ability to engage in specified types of transactions. These covenants limit our ability to, among other things:
o incur additional indebtedness or issue certain preferred shares;
o pay dividends on or make distributions in respect of our capital stock or make other restricted payments;
o make certain investments, including capital expenditures;
o sell certain assets;
o create liens; and
o consolidate, merge, sell or otherwise dispose of all or substantially all of our assets.
RISKS RELATED TO OUR COMMON STOCK
WE ARE CONTROLLED BY OUR PRINCIPAL STOCKHOLDER.
Union Drilling Company LLC, our principal stockholder, owns approximately 38% of our outstanding common stock. Union Drilling Company LLC is controlled by Metalmark Capital LLC. As a result, Union Drilling Company LLC and its affiliates may substantially influence the outcome of stockholder votes, including votes concerning the election of directors, the adoption or amendment of provisions in our certificate of incorporation or bylaws and the approval of mergers and other significant corporate transactions. The existence of these levels of ownership concentration makes it less likely that any small holder of our common stock will be able to affect the management or direction of Union. These factors may also have the effect of delaying or preventing a change in the management or voting control of Union.
WE HAVE RENOUNCED ANY INTEREST IN SPECIFIED BUSINESS OPPORTUNITIES, AND OUR DIRECTORS AND THEIR AFFILIATES GENERALLY HAVE NO OBLIGATION TO OFFER US THOSE OPPORTUNITIES.
Several of our directors and affiliates of Union Drilling Company LLC, our principal stockholder, have investments in other oilfield service companies that may compete with us, and they may invest in other similar companies in the future. Our certificate of incorporation provides that we have renounced any interest in related business opportunities and that neither our directors nor their affiliates have any obligation to offer us those opportunities. These provisions of our certificate of incorporation may be amended only by an affirmative vote of holders of at least two-thirds of our outstanding common stock. As a result of these charter provisions, our future competitive position and growth potential could be adversely affected.
OUR EXISTING DIVIDEND POLICY AND CONTRACTUAL RESTRICTIONS LIMIT OUR ABILITY TO PAY DIVIDENDS.
We have never declared a cash dividend on our common stock and do not expect to pay cash dividends for the foreseeable future. We expect that all cash flow generated from our operations in the foreseeable future will be retained and used to develop or expand our business. In addition, our loan agreement prohibits the payment of dividends without the prior consent of the lenders.
PROVISIONS IN OUR CERTIFICATE OF INCORPORATION AND BYLAWS AND OF DELAWARE CORPORATE LAW MAY MAKE A TAKEOVER DIFFICULT.
Provisions in our certificate of incorporation and bylaws and of Delaware corporate law may make it difficult and expensive for a third party to pursue a tender offer, change in control or takeover attempt that is opposed by our management and board of directors. These anti-takeover provisions could substantially impede the ability of public stockholders to benefit from a change of control or change our management and board of directors.
LIMITED TRADING VOLUME OF OUR COMMON STOCK MAY CONTRIBUTE TO ITS PRICE VOLATILITY.
Our common stock is traded on the NASDAQ National Market. During the period from November 22, 2005 through March 27, 2006, the average daily trading volume of our common stock as reported by the NASDAQ National Market was 256,993 shares. There can be no assurance that a more active trading market in our common stock will develop. As a result, relatively small trades may have a significant impact on the price of our common stock and, therefore, may contribute to the price volatility of our common stock. As a result, our common stock may be subject to greater price volatility than the stock market as a whole and comparable securities of other contract drilling service providers.
The market price of our common stock has been, and may continue to be, volatile. For example, during the period from November 22, 2005 through March 27, 2006, the trading price of our common stock ranged from $12.31 to $18.15 per share.
Because of the limited trading market of our common stock and the price volatility of our common stock, you may be unable to sell shares of common stock when you desire or at a price you desire. The inability to sell your shares in a declining market because of such illiquidity or at a price you desire may substantially increase your risk of loss.
ITEM 2.
ITEM 2. PROPERTIES
FACILITIES
We lease approximately 6,000 square feet of office space for our principal executive offices in Bridgeville, Pennsylvania. In May 2006, we will be moving our corporate headquarters to new office space in Fort Worth, Texas. We have entered into a 90-month lease with monthly payment of approximately $15,000. This lease is cancelable after a period of 48 months from the first month we make lease payments.
Our contract drilling operations are conducted from seven field offices.
From our Northern Appalachian office in Punxsutawney, Pennsylvania, we provide oil and natural gas contract drilling services to the northern region of the Appalachian Basin. The northern region of the Appalachian Basin includes the states of Ohio, New York and the northern half of Pennsylvania. The office is located in a leased facility that includes approximately 39,600 square feet of warehouse space, 25,000 square feet of office space and yard space.
From our Central Appalachian office in Buckhannon, West Virginia, we provide contract drilling services to the entire state of West Virginia, as well as southern Pennsylvania, Maryland and New York. This office also serves federally regulated natural gas storage customers and the coal mining industry, with a group of rigs specifically equipped for these two specialty markets. We own approximately 36 acres of land in Buckhannon, on which we have 4,900 square feet of office space and 32,400 square feet of warehouse space.
From our Southern Appalachian office in Norton, Virginia, we provide contract drilling services to the natural gas industry in the southern region of the Appalachian Basin. This office's primary areas of operation include southwestern Virginia, eastern Kentucky, southern West Virginia and the entire state of Tennessee. We lease a facility in Norton that includes approximately 36,000 square feet of warehouse space, 4,940 square feet of office space and yard space.
From our northern Texas office in Abilene, Texas, we provide contract drilling services in the Abilene area. We lease a facility in Abilene, Texas, that includes approximately 9,000 square feet of warehouse space, 2,500 square feet of office space and yard space. In addition, we recently established an office in Cresson, Texas, which has become the site of our Fort Worth Basin operations.
From our Oklahoma office in Pocola, Oklahoma, we provide contract drilling services in the Arkoma Basin. We own approximately 48 acres of land in Pocola, on which we have 4,800 square feet of office space and 8,000 square feet of warehouse space. In addition, we own five acres of land in Dewey, Oklahoma with 534 square feet of office space and two buildings with 7,200 square feet of warehouse space. We also own 2.5 acres of land in McCurtain, Oklahoma, and 1,420 square feet of office space in Bartlesville, Oklahoma.
From our Rocky Mountain office in Vernal, Utah, we provide oil and natural gas contract drilling services primarily in the state of Utah, but also occasionally conduct operations in Colorado. We lease a facility in Vernal that includes approximately 2,500 square feet of warehouse space. We also own or lease other properties in our market areas for storage and similar uses. We consider all of our facilities to be in good operating condition and adequate for their present uses.
ITEM 3.
ITEM 3. LEGAL PROCEEDINGS
Due to the nature of our business, we are, from time to time, involved in routine litigation or subject to disputes or claims related to our business activities, including workers' compensation claims and employment-related disputes. In the opinion of our management, none of the pending litigation, disputes or claims against us will have a material adverse effect on our financial condition or results of operations.
ITEM 4.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
We did not submit any matter to a vote of our security holders during the fourth quarter of fiscal 2005.
PART II
ITEM 5.
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES
As of March 27, 2006, 21,166,109 shares of our common stock were outstanding. As of March 27, 2006, the number of holders of record of our common stock was 7. The number of record holders does not necessarily bear any relationship to the number of beneficial owners of our common stock.
Our common stock began trading on the NASDAQ National Market under the symbol "UDRL" on November 22, 2005. Prior to that time, there was no trading market for our common stock. The following table sets forth, for each of the periods indicated, the high and low sales prices per share on the NASDAQ National Market:
Low High ------ ------ Fiscal Year Ended December 31, 2005: Fourth Quarter (beginning November 22, 2005) $13.60 $15.50
The last reported sales price for our common stock on the NASDAQ National Market on March 27, 2006 was $14.32 per share.
We have not paid or declared any dividends on our common stock and currently intend to retain earnings to fund our working capital needs and growth opportunities. Any future dividends will be at the discretion of
our board of directors after taking into account various factors it deems relevant, including our financial condition and performance, cash needs, income tax consequences and the restrictions Delaware and other applicable laws and our credit facilities then impose. Our debt arrangements include provisions that generally prohibit us from paying dividends, other than dividends on our preferred stock. We currently have no preferred stock outstanding.
EQUITY COMPENSATION PLAN INFORMATION
The following table provides information as of December 31, 2005 about Union's common stock that may be issued upon the exercise of options, warrants and rights granted to employees, consultants or members or the board of directors under all of our existing equity compensation plans:
NUMBER OF SHARES OF COMMON STOCK NUMBER OF SHARES REMAINING AVAILABLE FOR OF COMMON STOCK TO BE WEIGHTED-AVERAGE FUTURE ISSUANCE UNDER EQUITY ISSUED UPON EXERCISE OF EXERCISE PRICE PER SHARE COMPENSATION PLANS OUTSTANDING OPTIONS, OF OUTSTANDING OPTIONS, (EXCLUDING SHARES PLAN CATEGORY WARRANTS AND RIGHTS WARRANTS AND RIGHTS REFLECTED IN COLUMN (A)) ------------------------------- ----------------------- ------------------------ ----------------------------- (A) (B) (C)
Equity compensation plans approved by security holders 1,541,380(1) $7.21 1,222,928(2)
(1) Includes 876,647 shares of common stock issuable upon the exercise of options that were outstanding under our Amended and Restated 2000 Stock Option Plan, 132,958 shares of common stock issuable upon the exercise of options that were outstanding under a separate Union stock option plan and agreement, the terms of which are substantially similar to those of our Amended and Restated 2000 Stock Option Plan and 531,775 shares of common stock issuable upon the exercise of options that were outstanding under our 2005 Stock Option Plan, in each case, as of December 31, 2005.
(2) Represents the difference between the number of shares of our common stock issuable under the Amended and Restated 2000 Stock Option Plan, the separate stock option plan referred to above and the 2005 Stock Option Plan, of 3,292,062 shares, and the number of shares of our common stock issued under such plans as of December 31, 2005, which consist of options to acquire 1,541,380 shares of common stock (net of exercises of 527,754).
RECENT SALES OF UNREGISTERED SECURITIES
The following information relates to securities of Union issued or sold during the year ended December 31, 2005 that were not registered under the Securities Act.
On April 1, 2005, Union sold an aggregate of 2,771,145 shares of its common stock to Steven A. Webster, Wolf Marine S.A. and William R. Ziegler, each of whom was already an indirect investor in Union, for an aggregate purchase price of $20,000,008 in a private placement meeting the requirements of Rule 506 under the Securities Act. Also on April 1, 2005, Union sold 292,509 shares of its common stock to Richard Thornton, the sole stockholder of Thornton Drilling Company, for a purchase price of $1,999,999 in a separate private placement meeting the requirements of Rule 506 under the Securities Act. Mr. Thornton used a portion of the purchase price paid by Union for Thornton Drilling Company, which acquisition also closed on April 1, 2005, to fund his purchase of Union common stock. These share numbers reflect a subsequent stock dividend of 1.6325872 shares for each outstanding share of common stock of Union.
On November 28, 2005, Union issued 527,754 shares of its common stock to W. Henry Harmon, the Vice Chairman of Union at the time of such issuance, pursuant to the exercise of stock options held by Mr. Harmon. The aggregate exercise price received by Union in connection with the exercise of these options was $3,810,384.
Each of the above-described offerings of securities of Union was exempt from the registration requirements of the Securities Act by virtue of Section 4(2) thereof as transactions not involving a public offering.
USE OF PROCEEDS FROM SALES OF REGISTERED SECURITIES
On November 21, 2005, we closed an initial public offering of our common stock consisting of 8,823,530 shares of common stock. Of these shares, 4,411,765 were newly issued shares sold by us and 4,411,765 were existing shares sold by the selling stockholders. On December 9, 2005 an additional 1,323,530 shares of existing common stock were sold by certain selling stockholders pursuant to an exercise by the underwriters of their over allotment option. The offering was effected pursuant to a Registration Statement on Form S-1 (File No. 333-127525), which the SEC declared effective on November 21, 2005, and a final prospectus filed with the SEC pursuant to Rule 424(b) under the Securities Act that was filed on November 23, 2005 (Reg. No. 333-127525). J.P. Morgan Securities Inc. acted as sole book-running lead manager, Jeffries & Company, Inc. acted as joint lead manager and Bear Stearns & Co. Inc. and RBC Capital Markets Corporation acted as co-managers for the offering. As of the date of the filing of this Report, the offering has terminated.
The public offering price was price was $14.00 per share and $123,529,420 in the aggregate. The underwriting discounts and commissions were $0.945 per share and $8,338,236 in the aggregate. Proceeds before expenses to us were $13.055 per share and $57,595,592 in the aggregate. Proceeds, before expenses, to the selling stockholders were $13.055 per share and $57,595,592 in the aggregate.
We did not receive any of the proceeds from the sale of shares by selling stockholders or upon any exercise of the underwriters' over-allotment option. The net proceeds received by us in the offering were $55,379,482, as follows:
Aggregate offering proceeds to the Company $61,764,710 Underwriting discounts and commissions 4,169,118 Finders fees --- Underwriters' fees --- Other fees and expenses 2,216,110 ----------- Total expenses 6,385,228 ----------- Net proceeds to the Company $55,379,482 ===========
We have used the net proceeds to us from our initial public offering as follows:
o $51,332,441 to repay all indebtedness outstanding under our revolving credit facility from PNC Bank and other lenders; and
o $4,047,041 to upgrade our drilling rig fleet and purchase related equipment.
All of the foregoing expenses and uses of proceeds were direct or indirect payments to persons other than (i) our directors, officers or their associates; (ii) persons owning ten percent (10%) or more of our common stock; or (iii) our affiliates.
There has been no material change in the planned use of proceeds from our initial public offering as described in our final prospectus filed with the SEC pursuant to Rule 424(b).
ITEM 6.
ITEM 6. SELECTED FINANCIAL DATA
The following information derives from our audited financial statements. You should review this information in conjunction with "Management's Discussion and Analysis of Financial Condition and Results of Operations" in Item 7
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Statements we make in the following discussion that express a belief, expectation or intention, as well as those which are not historical fact, are forward-looking statements that are subject to risks, uncertainties and assumptions. Our actual results, performance or achievements, or industry results, could differ materially from those we express in the following discussion as a result of a variety of factors, including general economic and business conditions and industry trends, the continued strength or weakness of the contract land drilling industry in the geographic areas in which we operate, decisions about onshore exploration and development projects to be made by oil and gas companies, the highly competitive nature of our business, our future financial performance, including availability, terms and deployment of capital, the continued availability of qualified personnel, and changes in, or our failure or inability to comply with, government regulations, including those relating to the environment.
COMPANY OVERVIEW
Union Drilling Inc. provides contract land drilling services and equipment, primarily to natural gas producers in the U.S. In addition to our drilling rigs, we provide the drilling crews and most of the ancillary equipment needed to operate our drilling rigs. We commenced operations in 1997 with 12 drilling rigs and related equipment acquired from a predecessor that was providing contract drilling services under the name "Union Drilling." Through a combination of acquisitions and new rig construction, we have increased the size of our fleet to 70 land drilling rigs, of which 63 are marketed and seven are stacked. We have focused our operations in selected natural gas production regions in the United States. We do not invest in oil and natural gas properties. The drilling activity of our customers is highly dependent on the current price of oil and natural gas.
In response to rising demand from our customers for equipment that is capable of efficiently drilling wells in unconventional natural gas formations, we have completed several transactions in 2005 aimed at enhancing our ability to serve these markets. In April 2005, we acquired Thornton Drilling Company,
which owned a fleet of 12 rigs and leased a thirteenth rig operating in the Arkoma Basin, and eight rigs from SPA Drilling L.P., five of which are targeting the Barnett Shale formation in the Fort Worth Basin. In June 2005 and August 2005, we acquired six more rigs, five of which target the Barnett Shale formation in the Fort Worth Basin. These transactions substantially expanded our unconventional natural gas contract drilling operations beyond our traditional markets in the Appalachian Basin and the Rocky Mountains. In addition to these acquisitions, over the past three years we have purchased seven newly constructed rigs and have devoted significant capital expenditures to upgrade other rigs in our fleet for underbalanced and horizontal drilling. These investments have positioned our fleet to capitalize on our customers' rapidly growing unconventional resource exploration and development activity.
We earn our revenues by drilling natural gas wells for our customers. We obtain our contracts for drilling 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. Contract terms generally depend on the complexity and risk of operations, the on-site drilling conditions, the type of equipment used and the anticipated duration of the work to be performed. Generally, our contracts provide for the drilling of a single well or series of wells and typically permit the customer to terminate on short notice.
A significant performance measurement in our industry is rig utilization. We compute rig utilization rates by dividing revenue days by total available days during a period. Total available days are the number of calendar days during the period that we have owned the rig. Revenue days for each rig are days when the rig is earning revenues under a contract, which is usually a period from the date the rig begins moving to the drilling location until the rig is released from the contract.
For the three years ended December 31, 2005, our marketed rig utilization, revenue days and average total number of rigs were as follows:
YEARS ENDED DECEMBER 31, ------------------------ 2005 2004 2003 ------ ----- ----- Marketed rig utilization rates 61.9% 50.2% 44.4% Revenue days 12,254 6,390 5,930 Average total number of rigs 60.5 41.8 44.3
The reasons for the increase in the number of revenue days in 2005 over 2004 and 2003 are the increase in size of our rig fleet and the improvement in our overall rig utilization rate due to improved market conditions. A significant factor contributing to the growth in the number of rigs and revenue days was the aforementioned 2005 acquisitions.
We devote substantial resources to maintaining and upgrading our rig fleet. During 2005, we removed certain rigs from service to perform upgrades. In the short term, these actions resulted in fewer revenue days and slightly lower utilization; however, in the long term, we believe the upgrades will help the marketability of the rigs and improve their operating performance. We are currently performing or have recently performed, between contracts or as necessary, safety and equipment upgrades to various rigs in our fleet.
MARKET CONDITIONS IN OUR INDUSTRY
The United States contract land drilling services industry is highly cyclical. Volatility in oil and gas prices can produce wide swings in the levels of overall drilling activity in the markets we serve and affect the demand for our drilling services and the dayrates we can charge for our rigs. The availability of financing sources, past trends in oil and gas prices and the outlook for future oil and gas prices strongly influence the number of wells natural gas exploration and production companies decide to drill.
During fiscal 2005, 2004 and 2003, substantially all the wells we drilled for our customers were drilled in search of natural gas because of the depth capacity of our rigs and the natural gas rich areas in which we operate. Our customers are primarily focused on drilling for natural gas. Natural gas reserves are typically found in deeper geological formations and generally require premium equipment and quality crews to drill the wells.
CRITICAL ACCOUNTING POLICIES AND ESTIMATES
REVENUE AND COST RECOGNITION - We generate revenue principally by drilling wells for natural gas producers on a contracted basis under daywork or footage contracts, which provide for the drilling of single or multiple well projects. Revenues on daywork contracts are recognized based on the days worked at the dayrate each contract specifies. Mobilization fees are recognized in all material respects as the related drilling services are provided. We recognize revenues on footage contracts based on the footage drilled for the applicable accounting period. Expenses are recognized based on the costs incurred during that same accounting period.
At December 31, 2005, our contract drilling work in progress totaled approximately $7.1 million, and approximately $3.8 million at December 31, 2004, all of which relates to the revenue recognized but not yet billed on daywork and footage contracts in progress at December 31, 2005 and 2004, respectively. The increase is due to the increase in the number of rigs working, primarily as a result of the acquisitions of Thornton Drilling Company and the assets of SPA Drilling L.P.
ACCOUNTS RECEIVABLE- We evaluate the creditworthiness of our customers based on their financial information, if available, information obtained from major industry suppliers, and past experiences with customers. 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 contracts provide for payment of invoices in 30 days. We established an allowance for doubtful accounts of $313,000 at December 31, 2005 and $269,000 at December 31, 2004. 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 assessment of our customers' current abilities to pay obligations 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.
ASSET IMPAIRMENTS - We assess the impairment of property and equipment whenever events or circumstances indicate that the carrying value may not be recoverable. Factors that we consider important and which could trigger an impairment review would be our customers' financial condition and any significant negative trends in the industry or the general economy. 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 capital and the trends in the price of used drilling equipment observed by our management. If a review of our drilling rigs indicates that our carrying value exceeds the estimated undiscounted future cash flows, we are required under applicable accounting standards to write down the drilling equipment to its fair market value. 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 ten years after the rig was placed into service. Unlike depreciation based on units-of-production, our approach to depreciation does not change when equipment becomes idle or when utilization changes; we continue to depreciate idled equipment on a straight-line basis, despite the fact that our revenues and operating costs may vary with changes in utilization levels. 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.
DEFERRED TAXES - We record deferred taxes for net operating loss carryforwards and for the basis difference in our property and equipment between financial reporting and tax reporting purposes. For property and
equipment, basis differences arise from differences in depreciation periods and methods and the value of assets acquired in a business acquisition where we acquire the stock of an entity rather than its assets. For financial reporting purposes, we depreciate the various components of our drilling rigs and refurbishments over three to ten years, while federal income tax rules require that we depreciate drilling rigs and refurbishments over five years. Therefore, in the earlier years of our ownership of a drilling rig, our tax depreciation exceeds our financial reporting depreciation, resulting in our recording deferred tax liabilities on this depreciation difference. In later years, financial reporting depreciation exceeds tax depreciation, and the deferred tax liability begins to reverse. A significant portion of our deferred taxes are deferred tax assets that arose as the result of our prior year tax losses. These losses can be carried forward for federal and state tax purposes for as many as twenty years, depending upon the jurisdiction, to reduce future taxes that we would otherwise be required to pay. The utilization of these net operating losses is dependent upon our ability to generate taxable income in the future.
ACCOUNTING ESTIMATES - Another critical estimate is our determination of the useful lives of our depreciable assets, which directly affects our determination of depreciation expense and deferred taxes. A decrease in the useful life of our drilling equipment would increase depreciation expense and reduce deferred taxes. We provide for depreciation of our drilling, transportation and other equipment on a straight-line method over useful lives that we have estimated and that range from three to ten years. We record the same depreciation expense whether a rig is idle or working.
Our other accrued expenses as of December 31, 2005, 2004 and 2003 included accruals of approximately $1,312,000, $928,000 and $584,000 respectively, for costs under our workers' compensation insurance. We have a deductible of $100,000 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 satisfied this requirement with a $2.7 million letter of credit with our bank and our borrowing capacity under our revolving credit agreement with our bank has been reduced by the same amount collateralizing such 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. In addition, we accrue on a monthly basis the estimated workers compensation premium payable to the two states (West Virginia and Ohio) that are considered monopolistic.
RESULTS OF OPERATIONS
Our operations consist of drilling natural gas wells for our customers under either daywork or footage contracts. 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. Our contracts generally provide for the drilling of a single well or series of wells and typically permit the customer to terminate on short notice.
The current demand for drilling rigs greatly influences the types of contracts we are able to obtain. As the demand for rigs increases, daywork rates move up and we are able to switch primarily to daywork contracts.
STATEMENTS OF OPERATIONS ANALYSIS
The following table provides selected information about our operations for the years ended December 31, 2005, 2004, and 2003 (in thousands).
YEARS ENDED DECEMBER 31, ---------------------------- 2005 2004 2003 -------- ------- -------
Drilling revenues $141,621 $67,832 $58,144 -------- ------- ------- Drilling operations expenses $102,266 $50,084 $45,305 -------- ------- -------
Depreciation and amortization $ 15,121 $ 8,103 $ 7,987 General and administrative expense 13,020 7,447 6,696 Interest expense 2,367 629 850 Other income and gain (loss) on sale of fixed assets 851 2,374 152 Revenue days during period 12,254 6,390 5,930 -------- ------- -------
Drilling revenue per revenue day $ 11,557 $10,616 $ 9,805 Drilling cost per revenue day 8,346 7,839 7,640 Rig utilization rates 61.9% 50.2% 44.4% Average number of rigs during the period 60.5 41.8 44.3
DRILLING REVENUES. Our contract drilling revenues grew by approximately $73.8 million, or 109%, in fiscal year 2005 from fiscal year 2004. This increase was primarily a result of the acquisitions of Thornton Drilling Company and the assets of SPA Drilling, L.P. on April 1, 2005. The revenues from these acquisitions accounted for $56.4 million of the revenue increase. The balance of the increase of $17.4 million was due to an increase in revenue days in our historical markets, where revenue days increased by 1,083 days. In addition, the average revenue per revenue day in the Appalachian basin, Rocky Mountain region and our Canadian market increased by $783 per day. The improvement in average revenue per revenue day was a result of increases in our contract rates due to stronger demand for our drilling services.
Our contract drilling revenues grew by approximately $9.7 million, or 16.7%, in fiscal year 2004 from fiscal year 2003, due to a 7.8% increase in revenue days coupled with an 8.3% increase in revenue per day, and a 4.7% increase in rig utilization.
DRILLING OPERATIONS EXPENSES. Our contract drilling costs in fiscal year 2005 grew by approximately $52.2 million. This increase, as with the increase in revenues discussed above, is largely due to the drilling operations expenses related to Thornton Drilling Company and SPA Drilling, L.P. acquisitions, which accounted for $44.7 million of the increase. The remaining increase in drilling operations expense of $7.5 million was related to the increase in revenues associated with our historical markets, and is less than the change in revenue levels due to improvement in overall drilling margins.
Our contract drilling costs grew by approximately $4.8 million, or 10.5%, in fiscal year 2004 from fiscal year 2003 due to the increase in revenue days and rig utilization.
DEPRECIATION AND AMORTIZATION. Our depreciation and amortization expense in 2005 increased by approximately $7.0 million, or 86.6%, from 2004. Depreciation and amortization expense in 2004 increased approximately $116,000, or 1.5%, from 2003. The increase in 2005 over 2004 resulted from the purchase of SPA Drilling assets and the Thornton Drilling Company acquisition on April 1, 2005, as well as other rig purchases and capital equipment upgrades. The increase in 2004 over 2003 resulted from rig purchases and capitalized equipment upgrades throughout the year, partially offset by the sale of our two Canadian-based rigs.
GENERAL AND ADMINISTRATIVE EXPENSES. Our general and administrative expenses increased by approximately $5.6 million, or 74.8%, in fiscal year 2005 from fiscal year 2004. Approximately $2.4 million of the increase relates to the general and administrative costs associated with operations established to support the purchase of SPA Drilling assets and the Thornton Drilling Company acquisition. The remaining $3.2 million increase is due primarily to higher personnel expense (including $788,000 of non-
cash compensation), and higher spending on professional and consulting costs of $306,000, and insurance costs of $453,000 related to the new acquisitions.
Our general and administrative expenses increased by approximately $752,000, or 11.2%, in fiscal year 2004 from fiscal year 2003. This increase was due to higher personnel, insurance and other costs to support expanding operations.
INTEREST EXPENSE. Our interest expense increased by approximately $1.7 million for the year ended December 31, 2005 from the fiscal year 2004. This increase was due primarily to the borrowings required to support our acquisition activity and increased working capital to support revenue growth in excess of 100%.
Our interest expense decreased by approximately $220,000, or 25.9% in fiscal year 2004 from fiscal 2003 due to lower debt levels during 2004.
OTHER INCOME AND GAIN (LOSS) ON SALE OF FIXED ASSETS. Other income and gain (loss) on sale of fixed assets declined by approximately $1.5 million from $2.4 million for the fiscal year 2004 to approximately $851,000 in fiscal year 2005. This was due to the gain associated with the sale of our two Canadian-based rigs being recorded in fiscal year 2004.
TAXES. Our effective income tax rates of 42.3% and 10.6% for 2005 and 2004, respectively, differ from the federal statutory rate of 34% due to related state income taxes and permanent differences associated with meals and entertainment (primarily for our direct service personnel) and non-cash compensation. In prior years, due to net operating loss carryforwards, there were no significant federal income tax provisions required. See Note 7 to our Financial Statements for further information on our income taxes. Permanent differences are costs included in results of operations in the accompanying financial statements, which are not fully deductible for federal income tax purposes.
At December 31, 2005, we had domestic net operating loss carryforwards for income tax purposes of approximately $24.8 million. These losses may be carried forward for 20 years and will begin to expire in 2019. The state losses vary as to carryforward period and will begin to expire in 2008, depending upon the jurisdiction where applied. Based upon 2005 results and forecasted future operations, we feel it is more likely than not that the amounts will be realized. Foreign net operating losses were fully utilized in 2004.
LIQUIDITY AND CAPITAL RESOURCES
SOURCES OF CAPITAL RESOURCES
Our rig fleet has grown from 12 rigs in 1997 to 69 rigs as of December 31, 2005. We have financed this growth with a combination of debt and equity financing. We plan to continue to grow our rig fleet. At December 31, 2005, our total debt to total capital was approximately 8.5%. Due to the volatility in our industry, we are reluctant to take on substantial additional debt in excess of the $57,300,000 of remaining availability under our revolving credit facility. However, our ability to continue funding our growth through the issuance of shares of our common stock is uncertain, as our common stock is not heavily traded and the market price for our common stock has been volatile in recent periods.
On April 1, 2005, we raised $19.9 million, after expenses, through a sale of shares of our common stock. These proceeds plus additional borrowing under our revolving credit facility were used to fund the acquisitions of an Oklahoma-based drilling company which owned 12 drilling rigs and substantially all of the drilling assets (eight rigs) of a Texas-based drilling company.
On November 22, 2005, we also sold 4,411,765 shares of our common stock at approximately $13.05 per share, net of underwriters' commissions, pursuant to a public offering we registered with the Securities and Exchange Commission. The net proceeds to Union, after expenses, of this sale were $55,379,482, and were used primarily to repay indebtedness under our revolving credit facility. See "Use of Proceeds From Sales of Registered Securities" in Item 5 above.
We entered into a Revolving Credit and Security Agreement with PNC Bank, as agent for a group of lenders, dated March 31, 2005, and subsequently amended on April 19, August 15, and October 5, 2005, which provides for a borrowing base equal to the lesser of $60,000,000 and the sum of 85% of eligible receivables and 75% of the liquidation value of eligible rig fleet equipment. The agent may, in the exercise of its reasonable business judgment, increase or decrease those percentage advance rates against eligible receivables and liquidation value. The liquidation value of eligible rig fleet equipment is determined annually (or semi-annually in certain circumstances) by an independent appraisal, with adjustments for acquisitions and dispositions between appraisals. There is a $7,500,000 sublimit for letters of credit. Amounts outstanding under the revolving credit facility bear interest at either (i) the higher of the Federal Funds Open Rate plus 1/2 of 1% or PNC Bank's base commercial lending rate (7.25% at December 31, 2005) or (ii) LIBOR plus 2.00% (6.39% at December 31, 2005). Those rates may increase by up to 0.50% for LIBOR loans or up to 0.25% for domestic rate loans if our fixed charge coverage ratio falls below certain targets.
Interest on outstanding loans is due monthly for domestic rate loans and at the end of the relevant interest period for LIBOR loans. All outstanding principal and interest is due at maturity on March 30, 2009. As of December 31, 2005, we had no outstanding loans under the Revolving Credit and Security Agreement, but $2.7 million of the total capacity has been utilized to support our letter of credit requirement. To date, the revolving credit facility has been used to pay for rig acquisitions and for working capital requirements. If we repay and terminate the obligations under the Revolving Credit and Security Agreement, we would be liable for a substantial prepayment penalty.
The Revolving Credit and Security Agreement is secured by substantially all of our assets, with certain exceptions, and contains affirmative and negative covenants and provides for events of default that are typical for an agreement of this type. Among the affirmative covenants are requirements to maintain a specified tangible net worth (initially $43 million) and a fixed charge coverage ratio of 1.10 to 1.00. Among the negative covenants are restrictions on major corporate transactions, capital expenditures, payment of dividends, incurrence of indebtedness, and amendments to our organizational documents. Net capital expenditures were limited to $45 million in 2005 and $10 million in subsequent years, but those amounts are increased by permitted equity issuance proceeds. Among the events of default are a change in control and any change in our operations or condition, which has a material adverse effect. Effective August 15, 2005, the revolving credit agreement was amended to increase the maximum revolving amount from $50 million to $60 million, and to increase the Net Capital Expenditures limitation for the fiscal year ended December 31, 2005 to $45 million from $15 million.
USES OF CAPITAL RESOURCES
Effective March 31, 2005, the Company acquired all of the capital stock of an Oklahoma-based drilling company, which owned 12 drilling rigs. Also, effective the same date, the Company acquired substantially all of the drilling assets (eight rigs) of a Texas-based drilling company. The total purchase price for these businesses is $49,517,419. These acquisitions were financed by a new $50,000,000 revolving line of credit with a bank (subsequently amended - see above), and collateralized by substantially all of the assets of the Company. The previous debt facilities were both retired at that time. In addition, the Company also received an equity infusion of approximately $20,000,000 from private investors. Also, the seller of the Oklahoma-based company received approximately $2,000,000 in stock of Union Drilling Inc. as part of the transaction. The funding of these transactions occurred on April 1, 2005.
In June 2005 and August 2005, the Company entered into agreements to purchase six additional rigs for a total of $16,650,000.
In the fourth quarter of 2005, the Company acquired two new top head drive rigs for approximately $1,700,000.
In December 2005, the Company entered into a contract with National Oilwell Varco to acquire three rigs and related equipment for an aggregate purchase price of $24 million. In November 2005, Union had paid National Oilwell Varco $250,000 toward the purchase price of such equipment. In December 2005, the Company made a further downpayment of $6,936,500 on the first three rigs. Also in December 2005, the
Company paid $1 million to National Oilwell Varco for an option to acquire an additional three rigs and related equipment for an aggregate purchase price of $25.2 million. If that option is exercised by April 30, 2006, the $1 million option price will be applied to the purchase price for the three rigs. All six rigs, which are capable of horizontal and underbalanced drilling, would be scheduled for delivery during 2006.
For the years ended December 31, 2005 and 2004, the additions to our property and equipment consisted of the following:
YEARS ENDED DECEMBER 31, ------------------------- 2005 2004 ----------- ----------- Land $ 779,790 $ -- Buildings 891,243 1,859 Drilling and well service equipment 81,881,072 13,195,852 Deposits on drilling equipment 8,186,500 -- Vehicles 3,259,258 157,675 Furniture and fixtures 6,486 -- Computer equipment 75,119 14,144 ----------- ----------- $95,079,468 $13,369,530 =========== ===========
---------- WORKING CAPITAL
Our working capital increased to $25,600,921 at December 31, 2005 from $8,070,637 at December 31, 2004. Our current ratio, which we calculate by dividing our current assets by our current liabilities, was 2.21 at December 31, 2005 compared to 1.53 at December 31, 2004. The principal reasons for the increase in our working capital at December 31, 2005 are related to the aforementioned equity infusions and the additional accounts receivable, net of associated liabilities due to the acquisitions made in April 2005 and the year over year increase in general business activity.
Our operations have historically generated sufficient cash flow to meet our requirements for debt service and equipment expenditures (excluding major business acquisitions). The significant increase in working capital for the year ended December 31, 2005 over December 31, 2004 is due primarily to the approximately $15,000,000 overall increase in accounts receivable partially offset by related liabilities associated with the significant acquisitions made in 2005 and a general improvement in drilling activities. This use of cash was partially offset by an increase of approximately $7,018,000 in non-cash depreciation and amortization expense. We believe our cash generated by operations and our ability to borrow the currently unused portion of our line of credit and letter of credit facility of approximately $57,300,000, which takes into account reductions for approximately $2,700,000 of outstanding letters of credit as of December 31, 2005, should allow us to meet our routine financial obligations for the foreseeable future.
The changes in the components of our working capital were as follows:
DECEMBER 31, --------------------------------------- 2005 2004 CHANGE ----------- ----------- -----------
Cash and cash equivalents $ 2,388,276 $ 3,871,271 ($1,482,995) Receivables 28,060,911 13,251,577 14,809,334 Inventories 860,208 779,713 80,495 Prepaid expenses 4,930,431 2,976,788 1,953,643 Deferred taxes 10,542,730 2,404,023 8,138,707 ----------- ----------- ----------- CURRENT ASSETS 46,782,556 23,283,372 23,499,184 ----------- ----------- -----------
Current debt 5,322,634 5,888,577 (565,943) Accounts payable 9,240,626 6,109,983 3,130,643 Current portion of advances from customers 1,265,067 -- 1,265,067 Accrued expenses 5,353,308 3,214,175 2,139,133 ----------- ----------- ----------- CURRENT LIABILITIES 21,181,635 15,212,735 5,968,900 ----------- ----------- -----------
----------- ----------- ----------- WORKING CAPITAL $25,600,921 $ 8,070,637 $17,530,284 =========== =========== ===========
The increase in our receivables at December 31, 2005 from December 31, 2004 was due primarily to increased revenues from the additional rigs acquired in April 2005, June 2005, and August 2005, as well as an improvement in utilization and revenue rates in the second half of fiscal year 2005 over fiscal year 2004.
Substantially all our prepaid expenses at December 31, 2005 consisted of prepaid insurance. The increase in prepaid insurance was due to the increase in size of the Company in 2005, both in terms of assets and employees, due to the acquisitions made and a general improvement in the market.
The increase in the deferred tax asset is due to the addition of deferred tax assets associated with the prior years' net operating loss carryforwards. This was caused by the purchase price allocation related to our Thornton acquisition that resulted in significant deferred tax liabilities and the related reduction in the valuation allowance and intangibles. We believe that our recent and forecast profitability supports this position.
The increase in payables at December 31, 2005 from December 31, 2004 was primarily due to the increase in the size of our drilling rig fleet.
The total increase in accrued expenses at December 31, 2005 from December 31, 2004 was due to an increase in the size of our company. The growth in accrued payroll, accrued workers compensation and other accrued expenses can be attributed to the growth in our employee headcount and the additional expenses associated with being a public company.
Although we have not been required to make income tax payments for the last several years, it is also likely we will be in a current taxable position during fiscal year 2006, due to improving market conditions.
LONG-TERM DEBT
Our long-term debt at December 31, 2005 and 2004 consisted of the following:
2005 2004 ----------- ------------
Indebtness for equipment financed through capital leases $ -- $ 348,172 Notes payable for equipment financed 7,825,984 5,503,179 Term loan with Transamerica - repaid on April 1, 2005 -- 2,053,038 ----------- ----------- 7,825,984 7,904,389 Less current installments (2,013,956) (3,769,723) ----------- ----------- $ 5,812,028 $ 4,134,666 =========== ===========
CONTRACTUAL OBLIGATIONS
The following table includes all of our contractual obligations of the type specified below at December 31, 2005:
CONTRACTUAL LESS THAN 1 4 - 5 MORE THAN 5 OBLIGATIONS TOTAL YEAR 1-3 YEARS YEARS YEARS --------------------------- ----------- ----------- ---------- -------- -----------
Long-Term Debt(1) $ 7,825,984 $2,013,956 $5,453,786 $358,242 $-- Operating Lease Obligations 2,116,918 996,520 1,120,398 -- -- Interest 931,907 406,091 512,663 13,153 -- ----------- ---------- ---------- -------- --- Total $10,874,809 $3,416,567 $7,086,847 $371,395 $-- =========== ========== ========== ======== ===
(1) Does not include our Revolving Credit and Security Agreement with PNC Bank, which we entered into on April 1, 2005.
INFLATION
As a result of the relatively low levels of inflation during the past two years, inflation did not significantly affect our results of operations in any of the periods reported.
OFF BALANCE SHEET ARRANGEMENTS
We do not currently have any off balance sheet arrangements.
RECENTLY ISSUED ACCOUNTING STANDARDS
In December 2004, the Financial Accounting Standards Board ("FASB") issued FASB No. 123 (R), Share-based Payment. FASB No. 123 (R) requires employers to value share-based payments using the fair value method, eliminating the option to use the intrinsic method to value such payments. We will adopt the provisions of SFAS 123 (R) prospectively beginning in the first quarter of 2006. We are currently evaluating the effect of the provisions of this statement on our Consolidated Financial Statements. The impact of option grants measured on an estimated fair value basis on the Company's historic operations is included on a pro forma basis in the notes to the financial statements.
In May 2005, the FASB issued Statement No. 154, Accounting Changes and Error Corrections - a replacement of APB Opinion No. 20 and FASB Statement No. 3 ("SFAS 154"). This statement changes the requirements for the accounting for and reporting of a change in accounting principle. SFAS 154 requires retrospective application to prior periods' financial statements of changes in accounting principle and is limited to direct effects of the change. This statement is effective, and will be adopted, for accounting changes made in fiscal years beginning after December 31, 2005. Adoption is not expected to have a material effect on the our financial position or 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 Revolving Credit Facility. At December 31, 2005, we had no outstanding debt on our Revolving Credit Facility.
ITEM 8.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
UNION DRILLING INC.
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
Page ---- Report of Independent Registered Public Accounting Firm 35
Consolidated Balance Sheets as of December 31, 2005 and 2004 36
Consolidated Statements of Operations for the Years Ended December 31, 2005, 2004 and 2003 37
Consolidated Statements of Stockholders' Equity for the Years Ended December 31, 2005, 2004 and 2003 38
Consolidated Statements of Cash Flows for the Years Ended December 31, 2005, 2004 and 2003 39
Notes to Consolidated Financial Statements 40
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
The Board of Directors and Stockholders of Union Drilling, Inc.
We have audited the accompanying consolidated balance sheets of Union Drilling, Inc. as of December 31, 2005 and 2004, and the related consolidated statements of operations, 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 an audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. We were not engaged to perform an audit of the Company's 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, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of Union Drilling, Inc. at December 31, 2005 and 2004, and the consolidated results of its operations and its cash flows for each of the three years in the period ended December 31, 2005, in conformity with U.S. generally accepted accounting principles.
/s/ Ernst & Young LLP
Pittsburgh, Pennsylvania March 8, 2006
UNION DRILLING, INC. CONSOLIDATED BALANCE SHEETS
DECEMBER 31, -------------------------- 2005 2004 ------------ -----------
ASSETS: CURRENT ASSETS: Cash and cash equivalents $ 2,388,276 $ 3,871,271 Accounts receivable (net of allowance for doubtful accounts of $313,436 and $269,192 at December 31, 2005 and 2004, respectively) 27,579,254 11,286,696 Accounts receivable - related party 481,657 1,964,881 Inventories 860,208 779,713 Prepaid expenses and other assets 4,930,431 2,976,788 Deferred taxes 10,542,730 2,404,023 ------------ ----------- Total current assets 46,782,556 23,283,372 Goodwill 5,424,793 -- Intangible assets (net of accumulated amortization of $202,500 at December 31, 2005) 3,797,500 -- Property, buildings and equipment (net of accumulated depreciation of $46,250,906 and $32,760,108 at December 31, 2005 and 2004, respectively) 120,783,092 42,314,897 Other assets 700,409 -- ------------ ----------- Total assets $177,488,350 $65,598,269 ============ =========== LIABILITIES AND STOCKHOLDERS' EQUITY: CURRENT LIABILITIES: Accounts payable $ 9,240,626 $ 6,109,983 Current portion of long-term obligations 2,013,956 3,421,551 Current portion of capital lease obligations -- 348,173 Current portion of other obligations 3,308,678 2,118,853 Current portion of advances from customers 1,265,067 -- Accrued expenses and other liabilities 5,353,308 3,214,175 ------------ ----------- Total current liabilities 21,181,635 15,212,735 Revolving credit facility -- -- Long-term obligations 5,812,028 4,134,666 Deferred taxes 17,916,781 2,534,670 Advances from customers 138,605 169,071 ------------ ----------- Total liabilities 45,047,049 22,051,142 STOCKHOLDERS' EQUITY: Common stock, par value $.01 per share; 75,000,000 shares authorized; 21,166,109 and 13,162,936 shares issued and outstanding at December 31, 2005 and December 31, 2004, respectively 211,661 131,629 Additional paid-in capital 133,381,395 50,168,371 Retained earnings (deficit) (1,153,755) (6,752,873) ------------ ----------- Total shareholders' equity 132,439,301 43,547,127 ------------ ----------- Total liabilities and stockholders' equity $177,488,350 $65,598,269 ============ ===========
See accompanying notes.
UNION DRILLING, INC. CONSOLIDATED STATEMENTS OF OPERATIONS
YEARS ENDED DECEMBER 31 ----------------------------------------- 2005 2004 2003 ------------ ------------ -----------
REVENUES Nonaffiliates $136,388,802 $ 59,097,454 $54,631,018 Related party 5,232,314 8,734,944 3,512,810 ------------ ------------ ----------- Total revenues 141,621,116 67,832,398 58,143,828 ------------ ------------ -----------
COST AND EXPENSES Drilling operations 102,265,841 50,083,525 45,305,104 Depreciation and amortization 15,120,947 8,103,387 7,987,398 General and administrative expenses 13,020,180 7,447,137 6,695,063 ------------ ------------ ----------- Total cost and expenses 130,406,968 65,634,049 59,987,565 ------------ ------------ -----------
Operating income (loss) 11,214,148 2,198,349 (1,843,737)
Interest expense (2,366,769) (629,322) (849,570) Gain (loss) on sale of assets 649,229 1,679,053 (161,891) Other income 202,033 695,043 313,071 ------------ ------------ ----------- Income (loss) before income taxes 9,698,641 3,943,123 (2,542,127) Income tax expense 4,099,523 416,387 15,927 ------------ ------------ ----------- Net income (loss) $ 5,599,118 $ 3,526,736 $(2,558,054) ============ ============ ===========
Earnings (loss) per common share: Basic $ 0.35 $ 0.27 $ (0.19) ============ ============ =========== Diluted $ 0.34 $ 0.26 $ (0.19) ============ ============ ===========
Weighted-average common shares outstanding: Basic 16,012,486 13,162,936 13,162,936 ============ ============ =========== Diluted 16,553,894 13,311,203 13,162,936 ============ ============ ===========
SEE ACCOMPANYING NOTES.
UNION DRILLING, INC. CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY
Accumulated Additional Other Retained Paid-In Comprehensive Earnings Common Stock Capital Income (Loss) (Deficit) Total ----------------------- ------------ ------------- ------------- ------------ Shares $ ---------- ----------
Balance at December 31, 2002 13,162,936 131,629 $ 50,168,371 ($166,212) ($ 7,721,555) $ 42,412,233 Foreign translation adjustment -- -- -- 1,021,143 1,021,143 Net loss -- -- -- -- (2,558,054) (2,558,054) ------------ Total comprehensive loss -- -- -- -- -- (1,536,911) ---------- ---------- ------------ ---------- ------------- ------------ Balance at December 31, 2003 13,162,936 131,629 50,168,371 854,931 (10,279,609) 40,875,322 Foreign translation adjustments: Current period translation -- -- -- (679,678) (679,678) Reclassification to earnings -- -- -- (175,253) (175,253) Net income -- -- -- -- 3,526,736 3,526,736 ------------ Total comprehensive income -- -- -- -- -- 2,671,805 ---------- ---------- ------------ ---------- ------------- ------------ Balance at December 31, 2004 13,162,936 131,629 50,168,371 -- (6,752,873) 43,547,127 Issuance of common shares, net of $80,001 issuance costs 2,771,145 27,711 19,892,296 -- -- 19,920,007 Issuance of common shares in association with initial public offering, net of $2,216,110 issuance costs 4,411,765 44,118 55,335,364 55,379,482 Non-cash compensation -- -- 787,697 -- -- 787,697 Exercise of stock options and related tax benefit of $1,395,487 527,754 5,278 5,200,593 -- -- 5,205,871 Issuance of common shares 292,509 2,925 1,997,074 -- -- 1,999,999 Net income -- -- -- -- 5,599,118 5,599,118 ---------- ---------- ------------ ---------- ------------- ------------ Balance at December 31, 2005 21,166,109 $ 211,661 $133,381,395 $ -- ($ 1,153,755) $132,439,301 ========== ========== ============ ========== ============= ============
SEE ACCOMPANYING NOTES.
UNION DRILLING, INC. CONSOLIDATED STATEMENTS OF CASH FLOWS
YEAR ENDED DECEMBER 31, ------------------------------------------- 2005 2004 2003 ------------- ------------ ------------
OPERATING ACTIVITIES: Net income (loss ) $ 5,599,118 $ 3,526,736 $ (2,558,054) Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities: Depreciation and amortization 15,120,947 8,103,387 7,987,398 Non-cash compensation expense 787,697 -- -- Provision for doubtful accounts 155,000 152,015 120,000 (Gain) loss on sale or disposal of fixed assets (649,229) (1,679,053) 161,891 Provision for deferred taxes 3,937,732 130,647 -- Changes in operating assets and liabilities: Accounts receivable (12,837,923) (1,856,326) (4,076,808) Accounts receivable - related party 1,483,224 (1,776,792) (101,735) Inventories (80,494) 20,245 (1,928) Prepaid and other assets (791,032) (2,461,005) 439,843 Accounts payable 3,130,643 1,636,195 2,155,770 Accrued expenses and other liabilities 1,828,017 1,436,462 (70,533) ------------- ------------ ------------ Cash flow provided by operating activities 17,683,700 7,232,511 4,055,844
INVESTING ACTIVITIES: Purchase of businesses (47,517,419) -- -- Purchases of machinery and equipment (53,994,141) (13,369,530) (4,923,059) Proceeds from sale of machinery and equipment 2,346,579 7,080,032 598,626 ------------- ------------ ------------ Cash flow (used in) investing activities (99,164,981) (6,289,498) (4,324,433) FINANCING ACTIVITIES: Borrowings on line of credit 175,689,103 22,956,618 20,970,271 Repayments on line of credit (175,689,103) (22,956,618) (20,970,271) Borrowings to finance equipment purchases 5,464,051 6,858,726 1,383,479 Repayments on capital leases and other debt (2,393,337) (1,864,838) (1,282,460) Repayments on term loan (2,053,038) (3,139,821) (2,828,571) Issuance of common shares in initial public offering 55,379,482 -- -- Issuance of common shares 19,920,007 -- -- Exercise of stock options 3,810,384 -- -- ------------- ------------ ------------ Cash flow provided by (used in) financing activities 80,127,549 1,854,067 (2,727,552) Foreign currency translation adjustment (129,263) (558,985) (173,708) ------------- ------------ ------------ Net increase (decrease) in cash (1,482,995) 2,238,095 (3,169,849) Cash and cash equivalents at beginning of period 3,871,271 1,633,176 4,803,025 ------------- ------------ ------------ Cash and cash equivalents at end of period $ 2,388,276 $ 3,871,271 $ 1,633,176 ============= ============ ============ SUPPLEMENTAL DISCLOSURE OF NON CASH INVESTING AND FINANCING ACTIVITIES: Common stock issued for business acquisition $ 2,000,000 $ -- $ -- ============= ============ ============
SEE ACCOMPANYING NOTES.
UNION DRILLING INC. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. ORGANIZATION
Union Drilling, Inc. (Union or the Company) was incorporated in Delaware on September 23, 1997. On October 21, 1997, the Company acquired substantially all of the drilling equipment assets of a division of Equitable Resources Energy Company. Since that time the Company has increased its productive capacity by purchasing additional rigs and related equipment as described in Note 11.
2. DESCRIPTION OF BUSINESS AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
DESCRIPTION OF BUSINESS
The Company is engaged in the business of onshore contract drilling and related services. The primary market for the Company's services is the onshore oil and natural gas industry. The Company operates primarily in Arkansas, Colorado, Kentucky, New York, Ohio, Oklahoma, Pennsylvania, Texas, Virginia, and West Virginia. In fiscal year 2004, the Company operated in the provinces of New Brunswick, Nova Scotia, Ontario and Quebec, Canada.
During 2004, in response to the low productivity in Canada, the Company sold two rigs and associated equipment located in Canada. The net book value of these assets was approximately $4.0 million and the Company recorded a net gain on the sale of approximately $1.5 million. These assets constituted all of the productive capacity of the Company's Canadian operation. In response to the disposition of these assets, the Company has recorded (and will prospectively) all foreign currency translation adjustments through other income/expense in the consolidated statements of operations.
The Company intends to service the drilling needs of the Canadian market by using available drilling capacity located in the United States.
United States Canada Total -------- ------ -------- (In Thousands) 2005: Revenue $141,598 $ 23 $141,621 Net income (loss) before taxes 9,999 (300) 9,699 Total assets 177,327 161 177,488
2004: Revenue $ 65,606 $2,226 $ 67,832 Net income before taxes 1,662 2,281 3,943 Total assets 63,879 1,719 65,598
2003: Revenue $ 57,104 $1,040 $ 58,144 Net loss before taxes (1,895) (647) (2,542) Total assets 50,179 5,481 55,660 -------- ------ --------
The Company's primary customers are involved in the oil and gas industry. Revenues from the top ten customers for the year ended December 31, 2005 represented approximately 46% of total revenues with no one customer's revenue over 10%. Revenues from the top ten customers for the year ended December 31, 2004 represented approximately 67% of total revenues with revenues from three customers over 10%. Revenues from the top ten customers for the year ended December 31, 2003 represented approximately 64% of total revenues with revenues from two customers over 10%.
Revenues from the top ten customers for the year ended December 31,2003 represented approximately 64% of total revenues with revenues from two customers over 10%.
BASIS OF PRESENTATION
The consolidated financial statements include the accounts of the Company and its wholly owned subsidiaries after the elimination of all significant intercompany balances and transactions.
USE OF ESTIMATES
The preparation of financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the amounts reported in the financial statements and accompanying notes. Actual results may differ from those estimates.
CASH AND CASH EQUIVALENTS
The Company considers all highly liquid investments with an original maturity date of three months or less when purchased to be cash equivalents.
ACCOUNTS RECEIVABLE
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 contracts provide for payment of invoices in 30 days. We evaluate the creditworthiness of our customers based on their financial information, if available, information obtained from major industry suppliers, and our past experience with these customers. In some instances, we require customers to establish escrow accounts or make prepayments.
The Company provides an allowance for bad debts in recognition of uncollectible accounts. 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 assessment of our customers' current abilities to pay obligations 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. All known losses have been provided for in the accompanying financial statements.
INVENTORIES
Inventories maintained by the Company are primarily replacement parts and drill bits. Inventories are maintained on the lower of first-in, first-out cost, or market.
PREPAID EXPENSES
Prepaid expenses and other assets include items such as insurance, taxes, utility deposits and fees. We routinely expense these items in the normal course of business over the periods these expenses benefit. Included in prepaid expenses and other assets is prepaid insurance of $3,343,904 and $2,419,015 at December 31, 2005 and 2004, respectively.
GOODWILL AND INTANGIBLE ASSETS
In accordance with SFAS No 142, "Goodwill and Other Intangibles," the Company assesses the impairment of its goodwill annually or on an interim basis if events or circumstances indicate that the fair value of the asset has decreased below its carrying value. Other intangibles are tested for impairment if indicators of impairment are present.
PROPERTY, BUILDINGS AND EQUIPMENT
Property and equipment is stated on the basis of cost. Depreciation on buildings and equipment is calculated on the straight-line method over the estimated remaining useful lives of the assets. Depreciation does not commence until acquired rigs are placed in service. Once placed in service, depreciation continues when rigs are being repaired, refurbished or between periods of deployment. Unlike depreciation based on units-of-production, our method of depreciation does not change when equipment becomes idle or when utilization changes; we continue to depreciate idled equipment on a straight-line basis, despite the fact that our revenues and operating costs may vary with changes in utilization levels. The cost of maintenance and repairs is charged to operations as incurred; renewals and betterments are capitalized. The estimated lives of the assets are as follows:
Buildings 31.5 years Drilling and well service equipment 3-10 years Vehicles 3-5 years
IMPAIRMENT OF LONG-LIVED ASSETS
In accordance with SFAS No. 144, whenever events or changes in circumstances indicate that the carrying amount of long-lived assets may not be recoverable, the Company reviews its long-lived assets for impairment by first comparing the carrying value of the assets to the sum of the undiscounted cash flows expected to result from the use and eventual disposition of the assets. If the carrying value exceeds the sum of the assets' undiscounted cash flows, the Company estimates an impairment loss by taking the difference between the carrying value and fair value of the assets. No impairment charge has been recognized in any of the periods presented.
STOCK-BASED COMPENSATION
The Company has adopted SFAS No. 148, Accounting for Stock-Based Compensation-Transition and Disclosure (SFAS No. 148), and the disclosure-only provisions of SFAS No. 123, Accounting for Stock-Based Compensation (SFAS No. 123). SFAS No. 123 permits the Company to continue accounting for stock-based compensation as set forth in APB Opinion No. 25, Accounting for Stock Issued to Employees, provided the Company discloses the pro forma effect on net income and earnings per share of adopting the full provisions of SFAS No. 123. Accordingly, the Company continues to account for stock-based compensation under APB Opinion No. 25 and has provided the required pro forma disclosures.
The following table illustrates the effect on net income/(loss) and income/(loss) per share if the Company had applied the fair value recognition provisions of SFAS No. 123 to employee stock-based awards. The assumptions employed to develop these estimates and the detail related to the Plans, option activity and a Contingent Management Compensation Plan is set forth in Note 13.
December 31, ------------------------------------- 2005 2004 2003 ---------- ---------- ----------- Reported net income (loss) $5,599,118 $3,526,736 $(2,558,054) Apply: Total stock-based compensation expense determined under fair value method for all awards 810,962 198,202 125,089 ---------- ---------- ----------- Pro forma net income/(loss) $4,788,156 $3,328,534 $(2,683,143) ========== ========== =========== Basic and diluted income/(loss) per share: Basic, as reported $ 0.35 $ 0.27 $ (0.19) Diluted, as reported $ 0.34 $ 0.26 $ (0.19) Basic, pro forma $ 0.30 $ 0.25 $ (0.20) Diluted, pro forma $ 0.29 $ 0.25 $ (0.20)
Includes contingent management equity compensation of $787,697 in 2005 as described in Note 13.
REVENUE RECOGNITION
Substantially all revenue is derived from gas drilling operations. Gas drilling contract terms are based on either daywork or footage. Revenue is recognized and recorded based on contracted rates applied to either the number of days drilling has taken place (daywork) or the depth drilled (footage). Losses, if any, are recognized on drilling contracts when such amounts are determinable. Mobilization fees are recognized in all material respects as the related drilling services are provided.
CONCENTRATION OF CREDIT RISK
Substantially all of the Company's drilling services are performed for independent oil and natural gas producers in North America. Although the Company has provided drilling services in several states and provinces, these operations are aggregated into one segment for reporting purposes based on the similarity of economic characteristics among all markets including the nature of the services provided and the type of customers for such services.
INCOME TAXES
The Company follows the liability method of accounting for income taxes pursuant to SFAS No. 109, Accounting for Income Taxes. Under SFAS No. 109, deferred tax assets and liabilities are determined based on differences between financial reporting and tax bases of assets and liabilities and are measured using the enacted tax laws and rates applicable to the periods in which the differences are expected to reverse. The Company provides a valuation allowance to reduce deferred tax assets to their estimated realizable value.
FOREIGN CURRENCY TRANSLATION
The functional currency of the Company's foreign subsidiary was the Canadian dollar. The Company translated all assets and liabilities to U.S. dollars at the current exchange rates as of the applicable balance sheet date with the exception of long-term notes payable to the parent company. This liability was translated at the historical rate and was paid in full during fiscal year 2004. Revenue and expenses were translated at the average monthly exchange rate prevailing during each period. Gains and losses resulting from the translation of the foreign subsidiary's financial statements were reported as a separate component of total other comprehensive income (loss) in stockholders' equity. As indicated in Note 2, the Company made the strategic decision to service the Canadian market utilizing available domestic drilling capacity. This resulted in the sale of substantially all of the Company's drilling equipment in Canada. As such, the foreign currency translation gain of approximately $175,000 was reclassified from other comprehensive
income and increased the gain realized on the disposition of these non-domestic assets. Net gains resulting from foreign exchange transactions, which are recorded in the consolidated statements of operations in other income, approximated $12,000 in 2005, $532,000 in 2004 and $259,000 in 2003.
EARNINGS (LOSS) PER SHARE
Basic earnings (loss) per common share is computed by dividing net income or loss by the weighted-average number of common shares outstanding during the period. Diluted earnings per common share is computed by dividing net income by the weighted-average number of common shares outstanding during the period and the effect of all dilutive common stock equivalents, such as stock options.
FAIR VALUE OF FINANCIAL INSTRUMENTS
For certain financial instruments, including cash and cash equivalents, accounts receivable, accounts payable, and accrued liabilities, recorded amounts approximate fair value due to the relative short maturity period. The pricing mechanisms in the Company's debt agreements combined with the short-term nature of the equipment financing arrangements result in the carrying values of these obligations approximating their respective fair values.
RECENT ACCOUNTING PRONOUNCEMENTS
In December 2004, the Financial Accounting Standards Board ("FASB") issued FASB No. 123 (R), Share-based Payment. FASB No. 123 (R) requires employers to value share-based payments using the fair value method, eliminating the option to use the intrinsic method to value such payments. We will adopt the provisions of SFAS 123 (R) prospectively beginning in the first quarter of 2006. We are currently evaluating the effect of the provisions of this statement on our Consolidated Financial Statements. The impact of option grants measured on an estimated fair value basis on the Company's historic operations is included on a pro forma basis in the notes to the financial statements.
In May 2005, the FASB issued Statement No. 154, Accounting Changes and Error Corrections - a replacement of APB Opinion No. 20 and FASB Statement No. 3 ("SFAS 154"). This statement changes the requirements for the accounting for and reporting of a change in accounting principle. SFAS 154 requires retrospective application to prior periods' financial statements of changes in accounting principle and is limited to direct effects of the change. This statement is effective, and will be adopted, for accounting changes made in fiscal years beginning after December 31, 2005. Adoption is not expected to have a material effect on the Company's financial position or results of operations.
RECLASSIFICATIONS
Certain amounts in the financial statements for the prior year have been reclassified to conform to the current year's presentation.
INITIAL PUBLIC OFFERING
In November 2005, the Company issued 4,411,765 common shares at a price of $14.00 per share in its initial public offering. The Company received approximately $55,379,000 in proceeds, net of underwriting discounts, commissions, and offering expenses. In connection with the offering, the Company repaid approximately $51,332,000 of outstanding debt and approximately $4,047,000 to upgrade their drilling rig fleet and purchase of related equipment.
3. ACQUISITIONS
Effective April 1, 2005, the Company acquired substantially all of the drilling assets (the drilling business) of SPA Drilling L.P. The aggregate cash purchase price for the drilling assets was $20,320,000. This
acquisition provided the Company with a foothold in the North Texas market. Since the acquisition of these assets, the Company has purchased an additional six rigs for a total of $16,650,000, which are to be utilized in the same market.
Effective April 1, 2005, the Company acquired all the outstanding stock of Thornton Drilling Company. The aggregate purchase price of approximately $29,197,000 (including transaction costs of approximately $269,000) consisted of 292,509 common shares valued at approximately $2,000,000 and $26,928,000 in cash. The transaction has been accounted for as a purchase. The purchase price has been allocated to the assets acquired and liabilities assumed based upon their respective fair market values. The fair market value of the property and equipment was determined by an independent appraisal. The fair market values of the identified intangible assets were determined by an independent valuation and will be amortized to expense over the estimated useful lives. The excess of the purchase price over the fair value of assets acquired and liabilities assumed in the acquisition of approximately $5,425,000 is classified as goodwill. The allocation of the assets acquired and liabilities assumed of Thornton Drilling Company are as follows (in thousands):
Amount ------- Current assets $ 5,402 Property and equipment 20,765 Identified intangible assets 4,000 Goodwill 5,425 Deferred tax asset 2,129 Other long-term assets 113 Current liabilities (1,744) Deferred tax liabilities (6,893) ------- $29,197 =======
The following pro forma information gives effect to the Thornton Drilling Company acquisition and the purchase of the drilling business of SPA Drilling, L.P. as though they were effective as of the beginning of the fiscal year for each period presented. Pro forma adjustments primarily relate to additional depreciation, amortization and interest costs. The information reflects our historical data and historical data from these acquired businesses for the periods indicated. The pro forma data may not be indicative of the results we would have achieved had we completed these acquisitions on January 1, 2004 or 2005, or that we may achieve in the future. The pro forma financial information should be read in conjunction with the accompanying historical financial statements.
Pro Forma Years Ended December 31, (In thousands, except per share data) ------------------------------------- 2005 2004 -------- --------
Total revenues $155,942 $112,922 Net income $ 5,578 $ 2,072 Earnings per common share Basic $ 0.33 $ 0.13 Diluted $ 0.32 $ 0.13
The fair market values of identified intangible assets were determined by an independent valuation and certain intangible assets will be amortized to expense over the estimated useful lives. Customer relations are amortized over their estimated benefit period of 20 years. Intangibles related to the non-compete agreement are amortized over the period of the non-compete agreement of five years. Depreciation and amortization includes amortization of intangibles of $202,500 for the year ended December 31, 2005. Amortization of intangibles is not expected to exceed $270,000 per year over the next five years.
The total cost and accumulated amortization of intangible assets related to our 2005 acquisition are as follows:
December 31, ------------ Customer relations $2,200,000 Non compete agreement 800,000 Trade name 1,000,000 ---------- Intangible assets 4,000,000 ---------- Customer relations (82,500) Non compete agreement (120,000) ---------- Accumulated amortization (202,500) ---------- Intangible assets (net) $3,797,500 ==========
4. RELATED-PARTY TRANSACTIONS
During 2005 and 2004, the Company entered into contract arrangements with Triana Energy, Inc. and Columbia Natural Resources, which was purchased by Triana in August 2003, and sold by Triana Energy, Inc. in December 2005. The Company's former Vice Chairman of the Board of Directors is the Chief Executive Officer of Triana Energy, Inc. For the periods ended December 31, 2005, 2004, and 2003 the Company had revenues related to transactions with Columbia Natural Resources and Triana Energy, Inc. of $5,232,314, $8,734,944 and $3,512,810, respectively. At December 31, 2005 and 2004, the Company had accounts receivable from Columbia Natural Resources and Triana Energy, Inc. of $481,657 and $1,964,881, respectively. Effective December 31, 2005, the Chief Executive Officer of Triana Energy, Inc. resigned as the Vice Chairman of the Board of Directors and as a Director.
Both Triana Energy, Inc. and the Company share an ultimate common venture fund owner that provided capital investment funds employed in the initial formation of the business.
5. ACCOUNTS RECEIVABLE
Accounts receivable consist of the following:
December 31 ------------------------- Description 2005 2004 ------------------------------- ----------- ----------- Billed receivables $20,829,400 $ 7,752,449 Unbilled receivables 7,063,290 3,803,439 ----------- ----------- Total receivables 27,892,690 11,555,888 Allowance for doubtful accounts (313,436) (269,192) ----------- ----------- Net receivables $27,579,254 $11,286,696 =========== ===========
Unbilled receivables represent recorded revenue that is billable by the Company at future dates based on contractual payment terms, and is anticipated to be billed and collected within the quarter following the balance sheet date.
Activity in the allowance for doubtful accounts is as follows:
Balance, December 31, 2002 $128,201 Net charge to expense 120,000 Amounts written off 25,855 -------- Balance, December 31, 2003 222,346 Net charge to expense 152,015 Amounts written off 105,169 -------- Balance, December 31, 2004 269,192 Net charge to expense 155,000 Amounts written off 110,756 -------- Balance, December 31, 2005 $313,436 ========
6. PROPERTY, BUILDINGS AND EQUIPMENT
Major classes of property, buildings and equipment are as follows:
DECEMBER 31, -------------------------- 2005 2004 ------------ ----------- Land $ 967,432 $ 187,642 Buildings 978,489 382,428 Drilling and well service equipment 135,617,519 68,493,832 Vehicles 5,949,101 2,987,883 Furniture and fixtures 37,977 31,491 Computer equipment 595,702 520,583 Leasehold improvements 78,175 78,175 Construction in progress 22,809,603 2,392,971 ------------ ----------- 167,033,998 75,075,005 Less accumulated depreciation 46,250,906 32,760,108 ------------ ----------- $120,783,092 $42,314,897 ============ ===========
Property, buildings and equipment include certain capitalized leases. The Company had no recorded value of capital lease assets at December 31, 2005, and $977,914 at December 31, 2004. Amortization of these assets was $977,914 and $987,845 for the years ended December 31, 2005 and 2004, respectively, and is included in depreciation expense in the financial statements. As of December 31, 2005, there were no future minimum payments under these leases. Included in construction in progress is $307,254 of capitalized interest for the year ended December 31, 2005.
7. INCOME TAXES
The current and deferred components of income tax expense are as follows:
Years Ended December 31 ------------------------------- 2005 2004 2003 ---------- -------- ------- Current tax expense: Federal $ 56,629 $ 73,055 $ -- State 73,681 -- -- Foreign 31,481 212,685 15,927 ---------- -------- ------- 161,791 285,740 15,927
Deferred tax expense (benefit): Federal 3,506,596 48,755 -- State 515,676 -- -- Foreign (84,540) 81,892 -- ---------- -------- ------- 3,937,732 130,647 -- ---------- -------- ------- $4,099,523 $416,387 $15,927 ========== ======== =======
The components of the net deferred income tax assets and liabilities are as follows:
December 31 ------------------------- 2005 2004 ----------- ----------- Deferred tax assets: Bad debt expense $ 122,240 $ 104,985 Workers compensation and deferred revenue accrual 541,014 427,972 Net operating loss carry forwards 9,770,774 11,514,881 Federal AMT tax credit 87,923 -- Other 20,779 398 ----------- ----------- Subtotal net deferred tax assets 10,542,730 12,048,236 Valuation allowance -- (2,129,809) ----------- ----------- Total net deferred tax assets 10,542,730 9,918,427
Deferred tax liabilities: Foreign subsidiary earnings 13,278 429,044 Property building and equipment, principally due to differnces in depreciation 17,903,503 9,620,030 ----------- ----------- Total deferred tax liabilities 17,916,781 10,049,074 ----------- ----------- Net deferred taxes $ 7,374,051 $ 130,647 =========== ===========
The Company has domestic net operating loss carryforwards of approximately $24.8 million at December 31, 2005. These losses may be carried forward for 20 years and will begin to expire in 2019. The state losses vary as to carryforward period and will begin to expire in 2008, depending upon the jurisdiction where applied. Foreign net operating losses were fully utilized in 2004. The company also has federal alternative minimum tax (AMT) credits of approximately $88,000, which may be carried forward indefinitely.
The elimination of the deferred tax valuation allowance occurred with the allocation of purchase price associated with the Thornton Drilling Company acquisition described in Note 3. The elimination of the valuation allowance was treated as a reduction in goodwill associated with this acquisition.
Total income tax expense (benefit) differed from the amounts computed by applying the U.S. federal income tax rate to income before income taxes as a result of the following:
2005 2004 2003 ---------- ----------- --------- Income tax (expense) benefit at the 34% statutory federal tax rate $3,297,539 $ 1,340,661 $(869,738) State, local and provincial income taxes, net of federal tax benefit 509,207 189,277 (4,760) Change in valuation reserve -- (1,922,942) 948,551 Meals and entertainment 239,516 8,326 -- Non-cash compensation 255,957 -- -- Permanent and other 30,707 42,165 (58,126) Deferred tax adjustment (233,403) 395,188 -- Deferred taxes on unremitted earnings -- 363,712 -- ---------- ----------- --------- $4,099,523 $ 416,387 $ 15,927 ========== =========== =========
During 2005, 2004 and 2003, the Company made tax payments of approximately $252,000, $4,000 and $34,000, respectively.
8. ACCRUED EXPENSES AND OTHER LIABILITIES
A detail of accrued expenses and other liabilities is as follows:
December 31, ----------------------- 2005 2004 ---------- ---------- Accrued payroll and bonus $2,709,219 $1,350,426 Accrued workers compensation 1,312,214 928,309 Other 1,331,875 935,440 ---------- ---------- $5,353,308 $3,214,175 ========== ==========
9. LONG-TERM OBLIGATIONS
On May 3, 2002, the Company entered into an agreement with a bank to provide a line of credit facility totaling $10,000,000. The amount available under the line of credit is limited by a percentage of eligible accounts receivable (approximately $4.1 million at December 31, 2004). The line of credit bears interest at either (i) a fluctuating rate per annum equal to the higher of the Prime Rate or the sum of the Federal Funds Effective Rate plus 50 basis points or (ii) a fluctuating rate per annum equal to the LIBOR rate plus 187.5 basis points. These rates increase when borrowings under the facility exceed certain percentages of the total $10 million commitment. The highest rate is paid once the Company's borrowings exceed 67% of the total commitment. The maximum interest rate at that level of borrowing is the Prime Rate plus 62.5 basis points or the LIBOR rate plus 250 basis points.
On June 30, 2004, the credit agreement was amended and restated to extend the revolving credit facility termination date to December 31, 2005.
On April 1, 2005, the Company paid off the outstanding balance and retired the line of credit.
The Company entered into a Revolving Credit and Security Agreement dated March 31, 2005, and subsequently amended on April 19, August 15, and October 5, 2005, which provides for a borrowing base equal to the lesser of $60,000,000 and the sum of 85% of eligible receivables and 75% of the liquidation value of eligible rig fleet equipment. There is a $7,500,000 sublimit for letters of credit. Amounts outstanding under the revolving credit facility bear interest at either (i) the higher of the Federal Funds Open Rate plus one half of 1.00% or the base commercial lending rate of the agent for the lenders (7.25% at December 31, 2005) or (ii) LIBOR plus 2.00% (6.39% at December 31, 2005). As of December 31, 2005, the Company had no outstanding loans under the Revolving Credit and Security Agreement, but $2.7 million of the total capacity has been utilized to support the Company's letter of credit requirement.
The Revolving Credit and Security Agreement is secured by substantially all of our assets, with certain exceptions, and contains affirmative and negative covenants and provides for events of default that are typical for an agreement of this type. Among the affirmative covenants are requirements to maintain a specified tangible net worth (initially $43 million) and a fixed charge coverage ratio of 1.10 to 1.00. Among the negative covenants are restrictions on major corporate transactions, capital expenditures, payment of dividends, incurrence of indebtedness, and amendments to our organizational documents. Net capital expenditures were limited to $45 million in 2005 and $10 million in subsequent years, but those amounts are increased by permitted equity issuance proceeds. Among the events of default are a change in control and any change in our operations or condition, which has a material adverse effect. Effective August 15, 2005, the revolving credit agreement was amended to increase the maximum revolving amount from $50 million to $60 million, and to increase the Net Capital Expenditures limitation for the fiscal year ended December 31, 2005 to $45 million from $15 million.
On March 29, 2002, the Company entered into a Loan and Security Agreement with a financial institution to provide term loans in the amount of $9.9 million. These term loans bear interest at the greater of LIBOR plus 450 basis points or 7.6% and are secured by liens on specific rigs and equipment. These term loans had an outstanding balance of $2,053,038 as of December 31, 2004.
On April 1, 2005, the Company paid off the outstanding balance and retired the term loan.
In addition, the Company has entered into various equipment-specific financing agreements with several third-party financing institutions. The terms of these agreements vary but the majority of them are for 48 months, while three have a term of 36 months and eight have a term of 60 months. As of December 31, 2005, the total outstanding balance under these arrangements, including principal and interest, was $8,757,891. The interest rate on these borrowings ranges from 1.7% to 7.5%. The following is a schedule, by year, of the future debt payments under these agreements, together with the present value of the net payments as of December 31, 2005:
Year ending December 31:
2006 $2,420,048 2007 2,263,908 2008 2,091,993 2009 1,610,547 2010 371,395 ---------- Total minimum debt payments 8,757,891 Less amount representing interest 931,907 ---------- Total present value of minimum payments 7,825,984 Less current portion of such obligations 2,013,956 ---------- Long-term portion of obligations $5,812,028 ----------
The Company paid approximately $2,367,000, $629,300 and $849,600 in interest, net of capitalized interest, on all debt during 2005, 2004 and 2003, respectively.
10. OTHER INCOME
Included in other income in 2004 is approximately $707,000 of foreign currency gains associated with the sale of assets and the reclassification of currency translation gains.
11. PRODUCTIVE CAPACITY
The Company has increased its productive capacity through the purchase of rotary drilling rigs, equipment (primarily dozers and trucks), and drilling supplies from other drilling companies and suppliers. The following table illustrates the number of rigs purchased and the total purchase price of the rigs and related drilling equipment since the inception of the Company:
Rotary Rigs and Related Drilling Equipment Purchase Price (in Purchases by Year Purchased millions) ----------------- ----------------------- ------------------ 1997 12 $ 7.2 1998 19 11.0 1999 7 8.3 2000 7 4.7 2001 4 7.5 2002 2 4.2 2004 2 5.5 2005 29 57.7 --- ------ Total 82 $106.1 === ======
In December 2005, the Company entered into a contract with National Oilwell Varco to acquire three rigs and related equipment for an aggregate purchase price of $24 million. In November 2005, Union had paid National Oilwell Varco $250,000 toward the purchase price of such equipment. In December 2005, the Company made a further downpayment of $6,936,500 on the first three rigs. Also in December 2005, the Company paid $1 million to National Oilwell Varco for an option to acquire an additional three rigs and related equipment for an aggregate purchase price of $25.2 million. If that option is exercised by April 30, 2006, the $1 million option price will be applied to the purchase price for the three rigs. All six rigs, which are capable of horizontal and underbalanced drilling, would be scheduled for delivery during 2006.
12. STOCKHOLDERS' EQUITY
At December 31, 2005, the number of authorized shares of common and preferred stock was 75,000,000 and 100,000 shares, respectively, of which 21,166,109 and zero were outstanding, and 2,764,308 and zero were reserved for future issuance.
On October 6, 2005, the Company effected a stock dividend of 1.6325872 shares for each outstanding share of common stock. All common stock prices and amounts impacted by the dividend have been retroactively adjusted. Certain share calculations resulting in fractional amounts have been truncated.
13. MANAGEMENT COMPENSATION
STOCK OPTION PLANS
The Company established a 2005 Stock Option Plan authorizing up to 1,579,552 shares of the company's common stock. Grants have been made of 531,775 options to purchase common stock at $14.00 per share.
Effective March 16, 2000, the Board of Directors of Union adopted the 2000 Employee Stock Option Plan (the Plan). The Plan, as amended on June 1, 2003, reserves 1,579,552 shares of the Company's common stock. As of December 31, 2005 and 2004, 1,404,401 and 876,647 options, respectively, had been granted under the Plan. The options expire on the tenth anniversary of the grant date. Vesting typically occurs in two, three or four equal annual installments from the grant date, depending on the terms of the grant. The exercise price of stock options under the Plan was based on the Board of Directors assessment of the fair market value of the stock at the time the options were granted. Outside of the Plan, 132,958 options were granted in 1999.
Stock option activity for all options was as follows:
WEIGHTED NUMBER OF OPTION PRICE AVERAGE SHARES RANGE EXERCISE PRICE --------- ------------ --------------
Outstanding at December 31, 2002 918,702 $ 2.51-$3.80 $ 3.30 Granted 618,657 $ 3.80 $ 3.80 Exercised -- $ -- $ -- Canceled (527,754) $ 3.26 $ 3.26 --------- ------------ ------ Outstanding at December 31, 2003 and 2004 1,009,605 $ 2.51-$3.80 $ 3.63 Granted 1,059,529 $7.22-$14.00 $10.62 Exercised (527,754) $ 7.22 $ 7.22 Canceled -- $ -- $ -- --------- ------------ ------ Outstanding at December 31, 2005 1,541,380 $2.51-$14.00 $ 7.21 ========= ============ ======
As of December 31, 2005, the weighted-average remaining contractual life on the options outstanding was 7.8 years. As of December 31, 2005, options to purchase 650,916 shares of common stock were exercisable.
For purposes of determining compensation expense using the provisions of SFAS No. 123 as set forth in Note 2, the fair value of option grants was determined using the Black-Scholes option valuation model. The key input variables used in valuing the options were: risk-free interest rates of approximately 4.2% to 4.4%, 2.9% and 2.3% for the 2005, 2004 and 2003 grants, respectively; dividend yield of zero; stock price volatility of 19%, 94% and 71% for 2005, 2004 and 2003, respectively, prior years were based on a publicly traded peer of the Company; and option lives of approximately two, four and ten years. The effects of applying SFAS No. 123 in this pro forma disclosure may not be representative of the effects on reported net income for future periods.
EMPLOYEE BENEFIT PLAN
The Company has a defined contribution employee benefit plan covering substantially all of its employees. Company contributions to the plan are discretionary. The Company started matching employee contributions effective January 1, 2001, and made contributions of approximately $210,000, $120,000 and $106,000 during the years ended December 31, 2005, 2004 and 2003, respectively.
CONTINGENT MANAGEMENT COMPENSATION
Certain members of the Company management and certain other participants have been awarded rights to participate in the proceeds associated with the appreciation in value ultimately associated with dispositions of the Company's shares by Union Drilling Company LLC (UDC). In order to receive benefits from this arrangement, the fair market value of the Company's shares held by UDC must exceed certain threshold amounts.
The Company participants in this arrangement are to receive benefits as a result of UDC's sale, distribution or disposition of Company shares and the related recognition of a gain in excess of the threshold amount. These rights may be repurchased from these individuals at fair market value, which includes consideration of the threshold amount in the determination of that value, upon termination of their employment by the Company.
At December 31, 2005 and 2004 the threshold amounts were $26.5 million and $86.4 million, respectively. These amounts are determined based upon cash invested in UDC (and invested by UDC in the Company's stock) plus a compounded annual return of 10% less cash returned to investors. Compensation expense was not recognized prior to January 1, 2005, as the threshold amounts were not exceeded. During the year-ended December 31, 2005, $752,816 of compensation costs was recognized as a result of the fair value of the assets owned by UDC exceeding the threshold. This amount is classified as general and administrative expense. This compensation was initially recognized at $1,167,398 (estimated fair market value of Company shares at $17.00 per share). This amount was adjusted to the year-end market value of $14.53 per share, resulting in a reduction in compensation expense of $414,582 during the fourth quarter.
The defined group of participants in this arrangement would be entitled to up to 22.5% of the value realized in excess of the threshold amount. Members of Company management are entitled to approximately 4% of the 22.5%.
In addition, the Company recognized $34,881 in compensation costs during 2005 related to variable stock options issued.
14. OPERATING LEASES
The Company leases certain buildings and automobiles under noncancelable operating agreements. Lease expense was $1,074,704, $787,799 and $674,899 for the years ended December 31, 2005, 2004 and 2003, respectively.
Future minimum lease payments under noncancelable operating leases consist of the following:
2006 $ 996,520 2007 709,351 2008 361,547 2009 49,500 ---------- Total $2,116,918 ==========
ITEM 9.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
None
ITEM 9.A CONTROLS AND PROCEDURES
(A) EVALUATION OF DISCLOSURE CONTROLS AND PROCEDURES.
Our disclosure controls and procedures (as defined in Rule 13a-15(e) under the Securities Exchange Act of 1934 (the "Exchange Act")), which we refer to as disclosure controls, are controls and procedures that are designed with the objective of ensuring that information required to be disclosed in our reports filed under the Exchange Act, such as this annual report, is recorded, processed, summarized and reported within the time periods specified in the Securities and Exchange Commission's rules and forms. Disclosure controls are also designed with the objective of ensuring that such information is accumulated and communicated to our management, including the Chief Executive Officer and the Chief Financial Officer, as appropriate to allow timely decisions regarding required disclosure. There are inherent limitations to the effectiveness of any control system. A control system, no matter how well conceived and operated, can provide only reasonable assurance that its objectives are met. No evaluation of controls can provide absolute assurance that all control issues and instances of fraud, if any, within our company have been detected.
As of December 31, 2005, an evaluation was carried out under the supervision and with the participation of our management, including the Chief Executive Officer and the Chief Financial Officer, of the effectiveness of the design and operation of our disclosure controls. Based upon that evaluation, the Chief Executive Officer and the Chief Financial Officer concluded that, as of such date, the design and operation of these disclosure controls were effective to accomplish their objectives at the reasonable assurance level.
(B) CHANGES IN INTERNAL CONTROL OVER FINANCIAL REPORTING.
No change in our internal control over financial reporting (as defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act) occurred during the fiscal quarter ended December 31, 2005 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.
PART III
In Items 10, 11, 12, 13 and 14 below, we are incorporating by reference the information we refer to in those Items from the definitive proxy statement for our 2006 Annual Meeting of Stockholders. We intend to file that definitive proxy statement with the SEC by April 30, 2006.
ITEM 10.
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
The following information will be included in our Proxy Statement to be filed within 120 days after the fiscal year end of December 31, 2005, and is incorporated herein by reference:
o Information regarding our executive officers and directors required by this Item is set forth under the heading "Management of the Company"
o Information regarding our audit committee and designated "audit committee financial experts" is set forth under the heading "Board Meetings and Committees - Audit Committee"
o Information regarding Section 16(a) beneficial ownership reporting compliance is set forth under the heading "Section 16(a) Beneficial Ownership Reporting Compliance"
CODE OF ETHICS
We have adopted a code of ethics and business conduct, entitled "Standards of Integrity," that applies to our employees including our principal executive officer, principal financial officer, principal accounting officer, and persons performing similar functions. Our Standards of Integrity can be found posted in the investor relations section on our website at http://www.uniondrilling.com.
ITEM 11.
ITEM 11. EXECUTIVE COMPENSATION
The information required by this Item is incorporated by reference to the information provided under the headings "Executive Compensation," "Compensation Committee Report on Executive Compensation," "Director Compensation," "Compensation Committee Interlocks and Insider Participation" and "Performance Graph" in the Proxy Statement.
ITEM 12.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS
The information required by this Item is incorporated by reference to the information provided (1) under the heading "Equity Compensation Plan Information" in Item 5 of this Report and (2) under the heading "Security Ownership of Certain Beneficial Owners" in the Proxy Statement.
ITEM 13.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
The information required by this Item is incorporated by reference to the information provided under the heading "Certain Relationships and Related Transactions" in the Proxy Statement.
ITEM 14.
ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES
The information required by this Item is incorporated by reference to the information provided under the headings "Audit and Non-Audit Fees" and "Audit Committee Approval of Audit and Non-Audit Services" in the Proxy Statement.
PART IV
ITEM 15.
ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K
(1) Financial Statements.
See Index to Consolidated Financial Statements on page 34.
(2) Exhibits. The following exhibits are filed (or incorporated by reference) as part of this report:
EXHIBIT NUMBER DESCRIPTION ------- ------------------------------------------------------------------- 3.1 -- Form of Amended and Restated Certificate of Incorporation of Union (incorporated by reference to Exhibit 3.1 to our Registration Statement on Form S-1 (File No. 333-127525) filed on August 15, 2005).
3.2 -- Form of Amended and Restated Bylaws of Union (incorporated by reference to Exhibit 3.2 to our Registration Statement on Form S-1 (File No. 333-127525) filed on August 15, 2005).
4.1 -- Specimen Stock Certificate for the common stock, par value $0.01 per share, of Union (incorporated by reference to Exhibit 4.1 to our Registration Statement on Form S-1 (File No. 333-127525) filed on August 15, 2005).
10.1* -- Amended and Restated 2000 Stock Option Plan of Union (incorporated by reference to Exhibit 10.1 to our Registration Statement on Form S-1 (File No. 333-127525) filed on August 15, 2005).
10.2* -- Form of stock option agreements under the Amended and Restated 2000 Stock Option Plan (incorporated by reference to Exhibit 10.2 to our Registration Statement on Form S-1 (File No. 333-127525) filed on August 15, 2005).
10.3* -- Stock Option Plan and Agreement, dated May 13, 1999, by and between Union and Christopher Strong (incorporated by reference to Exhibit 10.3 to our Registration Statement on Form S-1 (File No. 333-127525) filed on August 15, 2005).
10.4* -- 2005 Stock Option Plan of Union (incorporated by reference to Exhibit 10.4 to our Registration Statement on Form S-1 (File No. 333-127525) filed on August 15, 2005).
10.5* -- Form of stock option agreements under the 2005 Stock Option Plan (incorporated by reference to Exhibit 10.5 to our Registration Statement on Form S-1 (File No. 333-127525) filed on August 15, 2005).
10.6 -- Form of Stockholders Agreement by and among Union and certain of its direct and indirect stockholders (incorporated by reference to Exhibit 10.6 to Amendment No. 2 to our Registration Statement on Form S-1 (File No. 333-127525) filed on October 18, 2005).
10.7 -- Revolving Credit and Security Agreement, dated March 31, 2005, between Union the lenders signatory thereto and PNC Bank, as agent for the lenders, together with the First Amendment dated April 19, 2005 (incorporated by reference to Exhibit 10.7 to our Registration Statement on Form S-1 (File No. 333-127525) filed on August 15, 2005).
10.8 -- Stock Purchase Agreement, dated as of March 31, 2005, by and between Union and Richard Thornton, the sole stockholder of Thornton Drilling Company (incorporated by reference to Exhibit 10.8 to our Registration Statement on Form S-1 (File No. 333-127525) filed on August 15, 2005).
10.9 -- Registration Rights Agreement, dated as of March 31, 2005, between Union and Richard Thornton (incorporated by reference to Exhibit 10.9 to our Registration Statement on Form S-1 (File No. 333-127525) filed on August 15, 2005).
10.10* -- Employment Agreement, dated as of March 31, 2005, between Union and Richard Thornton (incorporated by reference to Exhibit 10.10 to our Registration Statement on Form S-1 (File No. 333-127525) filed on August 15, 2005).
10.11 -- Stock Purchase Agreement, dated as of March 31, 2005, by and between Union, Steven A. Webster, Wolf Marine S.A. and William R. Ziegler (incorporated by reference to Exhibit 10.11 to our Registration Statement on Form S-1 (File No. 333-127525) filed on August 15, 2005).
10.12 -- Option and Asset Purchase and Sale Agreement dated as of February 28, 2005 between Thornton Drilling Company and SPA Drilling, LP; Amendment No. 1 to Purchase and Sale Agreement between Thornton Drilling Company and SPA Drilling, LP; and Assignment and Assumption Agreement between Thornton Drilling Company and Union Drilling Texas, LP. (incorporated by
reference to Exhibit 10.12 to Amendment No. 4 to our Registration Statement on Form S-1 (File No. 333-127525) filed on November 7, 2005).
10.13 -- Asset Purchase Agreement, dated May 31, 2005, between C and L Services, LP and Union Drilling Texas, LP. (incorporated by reference to Exhibit 10.13 to our Registration Statement on Form S-1 (File No. 333-127525) filed on August 15, 2005).
10.14 -- Forms of Indemnification Agreement with Union directors and certain of its officers (incorporated by reference to Exhibit 10.14 to Amendment No. 2 to our Registration Statement on Form S-1 (File No. 333-127525) filed on October 18, 2005).
10.15 -- Second Amendment, dated August 15, 2005, to the Revolving Credit and Security Agreement between Union, the lenders signatory thereto and PNC Bank, as agent for the lenders (incorporated by reference to Exhibit 10.15 to Amendment No. 1 to our Registration Statement on Form S-1 (File No. 333-127525) filed on September 28, 2005).
10.16 -- Asset Purchase Agreement, dated August 12, 2005, between C and L Services, LP and Union Drilling Texas, LP. (incorporated by reference to Exhibit 10.16 to Amendment No. 1 to our Registration Statement on Form S-1 (File No. 333-127525) filed on September 28, 2005).
10.17 -- Third Amendment, dated October 5, 2005, to the Revolving Credit and Security Agreement between Union, the lenders signatory thereto and PNC Bank, as agent for the lenders (incorporated by reference to Exhibit 10.17 to Amendment No. 2 to our Registration Statement on Form S-1 (File No. 333-127525) filed on October 18, 2005).
10.18 -- Option to purchase drilling rigs from National Oilwell Varco (incorporated by reference to Exhibit 10.18 to Amendment No. 4 to our Registration Statement on Form S-1 (File No. 333-127525) filed on November 7, 2005).
10.19 -- Purchase and Sale Agreement, dated December 8, 2005, between Union and National-Oilwell, L.P., relating to the purchase of three drilling rigs (incorporated by reference to Exhibit 10.1 to our Form 8-K (File No. 000-51630) filed on December 13, 2005).
10.20 -- Option Agreement, dated December 8, 2005, between Union and National-Oilwell, L.P., relating to the purchase of three drilling rigs (incorporated by reference to Exhibit 10.2 to our Form 8-K (File No. 000-51630) filed on December 13, 2005).
10.21 -- Assets Purchase Agreement, dated December 19, 2005, between Permian Drilling Corporation and Maverick Oil and Gas, Inc., (incorporated by reference to Exhibit 10.1 to our Form 8-K (File No. 000-51630) filed on February 3, 2006).
10.22 -- Agreement Regarding Assignment and Assumption of Rights and Obligations under Assets Purchase Agreement, dated January 30, 2006, between Maverick Oil and Gas, Inc. and Thornton Drilling Company; (incorporated by reference to Exhibit 10.1 to our Form 8-K (File No. 000-51630) filed on February 3, 2006).
10.23 -- Addendum to Assets Purchase Agreement and Letter Agreement, dated January 30, 2006, between Permian Drilling Corporation, Maverick Oil and Gas, Inc. and Thornton Drilling Company, (incorporated by reference to Exhibit 10.1 to our Form 8-K (File No. 000-51630) filed on February 3, 2006).
21.1 -- List of Subsidiaries filed herewith.
31.1 -- Certification of Chief Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 filed herewith.**
31.2 -- Certification of Chief Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 filed herewith.**
32.1 -- Certification of Chief Executive Officer Pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 filed herewith.**
32.2 -- Certification of Chief Financial Officer Pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 filed herewith.**
---------- * Management contract or compensatory plan or arrangement.
** This certification is being furnished solely to accompany this Annual Report pursuant to 18 U.S.C.Section 1350, and is not being filed for purposes of Section 18 of the Securities Exchange Act of 1934, as amended, and is not to be incorporated by reference to any filing of the Company, whether made before or after the date hereof, regardless of any general incorporation language in such filing.
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
UNION DRILLING, INC.
March 28, 2006 By: /s/ Christopher D. Strong ----------------------------------------- Christopher D. Strong President and Chief Executive Officer
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.
SIGNATURE TITLE DATE --------------------------- ------------------------------------------------ -------------
/s/ Christopher D. Strong --------------------------- Christopher D. Strong President and Chief Executive Officer (Principal March 28, 2006 Executive Officer)
/s/ Dan E. Steigerwald --------------------------- Dan E. Steigerwald Vice President, Chief Financial Officer, March 28, 2006 Treasurer and Secretary (Principal Financial and Accounting Officer)
/s/ Thomas H. O'Neill, Jr. --------------------------- Thomas H. O'Neill Jr. Chairman of the Board March 28, 2006 (non-executive)
/s/ William R. Ziegler --------------------------- William R. Ziegler Vice Chairman of the Board March 28, 2006 (non-executive)
/s/ Howard I. Hoffen --------------------------- Howard I. Hoffen Director March 28, 2006
/s/ Gregory D. Myers --------------------------- Gregory D. Myers Director March 28, 2006
/s/ John J. Moon --------------------------- John J. Moon Director March 28, 2006
/s/ Thomas M. Mercer, Jr. --------------------------- Thomas M. Mercer, Jr. Director March 28, 2006
/s/ M. Joseph McHugh --------------------------- M. Joseph McHugh Director March 28, 2006