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Union Drilling 10-K 2008 Documents found in this filing:Table of Contents
UNITED STATES SECURITIES AND EXCHANGE COMMISSION Washington, D. C. 20549
FORM 10-K (Mark one)
For the fiscal year ended December 31, 2007
Commission File Number: 000-51630 UNION DRILLING, INC. (Exact name of registrant as specified in its charter)
Registrant’s telephone number, including area code: 817-735-8793 Securities registered pursuant to Section 12(b) of the Act:
Securities registered pursuant to Section 12(g) of the Act: None Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes ¨ No x Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Exchange Act. Yes ¨ No x Indicate by check mark whether the registrant: (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes x No ¨ Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. x Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one): Large accelerated filer ¨ Accelerated filer x Non-accelerated filer ¨ Smaller reporting company ¨ (Do not check if a smaller reporting company) Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Securities Exchange Act of 1934). Yes ¨ No x The aggregate market value of the registrant’s voting and nonvoting common equity held by non-affiliates of the registrant as of June 29, 2007, the last business day of the registrant’s most recently completed second fiscal quarter, was $230,200,009 based on the last sales price of the registrant’s common stock on June 29, 2007 as reported on the NASDAQ Global Market. The determination of affiliate status for the purposes of this calculation is not necessarily a conclusive determination for other purposes. The calculation excludes shares held by directors, officers and stockholders whose ownership exceeded 10% of the Registrant’s outstanding Common Stock. Exclusion of these shares should not be construed to indicate that any such person controls, is controlled by or is under common control with the Registrant. As of February 28, 2008, there were 21,974,884 shares of common stock, par value $0.01 per share, of the registrant issued and outstanding. DOCUMENTS INCORPORATED BY REFERENCE Portions of the definitive proxy statement related to the registrant’s 2008 Annual Meeting of Stockholders to be held on June 12, 2008 to be filed subsequently with the Securities and Exchange Commission, are incorporated by reference into Part III of this Annual Report on Form 10-K.
Table of ContentsTABLE OF CONTENTS
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Table of ContentsPART I Statements we make in this Annual Report on Form 10-K, such as “Union” or the “company,” “we,” “us” and “our” refer to Union Drilling, Inc. for 2007, and includes our wholly-owned subsidiaries for 2006 and 2005. Statements we make in this Annual Report on Form 10-K that express a belief, expectation or intention, as well as those that are not historical fact, are forward-looking statements under the Private Securities Litigation Reform Act of 1995. These forward-looking statements are subject to various risks, uncertainties and assumptions, including those to which we refer under the heading “Cautionary Statement Concerning Forward-Looking Statements and Risk Factors” following Item 1 of Part I of this Annual Report. Our actual results may differ significantly from the results discussed in the forward-looking statements. Factors that might cause such a difference include, but are not limited to, those discussed in “Risk Factors,” “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and “Business” as well as those discussed elsewhere in this Annual Report. Actual events or results may differ materially from those discussed in this Annual Report.
General We provide contract land drilling services and equipment, primarily to natural gas producers in the United States. 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 an entity 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 71 marketed land drilling rigs. We presently focus 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 many factors, including the market price of oil and natural gas, available capital, available drilling resources, support services and market availability. These factors should not be considered an exhaustive list. See Item 1A. “Risk Factors.” Substantially all of our rigs operate in unconventional natural gas producing areas, which are characterized by formations with very low permeability rock, such as shales, tight sands and coal bed methane or CBM that require specialized drilling techniques to efficiently develop the natural gas resources. Horizontal drilling is often used in these formations to increase the exposure of the wellbore to the natural gas producing formation and increase drainage rates and production volumes. We have equipped 50 of our 71 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 44 of our 71 rigs with compressed air circulation systems to provide underbalanced drilling, which provide 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 for underbalanced drilling services, we have increased our fleet of drilling rigs with these capabilities through acquisitions and new rig construction. Our principal operations are in the Appalachian Basin, extending from New York to Tennessee, the Arkoma Basin in eastern Oklahoma and Arkansas, including the Fayetteville Shale, and the Fort Worth Basin in northern Texas, including the Barnett Shale. We have completed several transactions in order to enhance our ability to serve these markets. In April 2005, we acquired Thornton Drilling Company, which owned a fleet of 12 rigs and leased an additional rig operating in the Arkoma Basin and we acquired eight rigs from SPA Drilling L.P., five of which were targeting the Barnett Shale formation. In June 2005 and August 2005, we acquired a total of six more rigs, five of which target the Barnett Shale formation. During the second half of 2006 and the first quarter of 2007, we added six newly-constructed rigs to our fleet to capitalize on our customers’ rapidly growing unconventional resource exploration and development activity in the Barnett Shale formation. These transactions substantially expanded our unconventional natural gas contract drilling operations beyond our traditional markets in the Appalachian Basin and the Rocky Mountains. During the fourth quarter of 2006 and the first quarter of 2007, all five of our rigs operating in the Rocky Mountains were moved to eastern Arkansas to target the Fayetteville Shale formation. In the first quarter of 2008, we entered into a contract to build one additional rig to be delivered by June 2008. The Company intends to deploy the rig for an existing customer’s drilling program targeting the Marcellus Shale formation in the Appalachian Basin.
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Table of ContentsOur 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 Appalachian Basin is characterized by highly porous sandstones alternating with less porous shales, at depths of 3,000 to 8,000 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 (“TBR”) and Marcellus Shale formations, which are at depths of up to 10,000 feet. Deeper TBR 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 tend to be 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. Most of the equipment in the Appalachian Basin capable of drilling TBR wells is owned and operated by Union. Natural gas also is found in shallow coal seams throughout the Appalachian Basin. This natural gas 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 to reduce the concentration of these deposits in advance of mining operations, reducing the risk of underground fires or explosions. We support 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. With increased demand for natural gas drilling rigs in the Appalachian Basin, we have upgraded several of these rigs for that purpose and, as a result, well plugging and abandonment work for the coal companies is becoming a smaller portion of our business. In the last three 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, given our market position, will inure to our benefit. However, one of these recent buyers of oil and natural gas properties in the Appalachian Basin has elected to add its own in-house drilling capability. Some of that capability was achieved by acquiring a previously independent drilling contractor in the Appalachian Basin, which was our competitor. We market 32 drilling rigs in the Appalachian Basin. Our principal competitors in the Appalachian Basin are primarily smaller, family-owned companies that serve fragmented markets within the Appalachian Basin. Arkoma Basin The Arkoma Basin includes 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 6,000 feet. Most natural gas directed drilling in the Arkoma Basin is conducted by rigs equipped with air compression equipment for underbalanced drilling operations. Following the acquisition of Thornton Drilling in April 2005, the majority of our rigs in the Arkoma Basin were drilling horizontally into the Hartshorne coal seam, which is found at depths of 300 to 4,000 feet throughout the
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Table of ContentsArkoma 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. Drilling activity and equipment requirements in this area have changed as operators have been leasing acreage to develop natural gas-bearing formations known as the Fayetteville Shale on the Arkansas side and the Caney and Woodford Shales on the Oklahoma side of the Arkoma Basin. These formations, existing at depths of 1,500 to 10,500 feet, are geologically similar to the Barnett Shale formation in northern Texas. Within the Fayetteville Shale, two producers have amassed substantial acreage positions and have horizontal drilling programs that are yielding results comparable to what has been achieved in some of the more prolific unconventional resource plays in North America. We market 19 drilling rigs in the Arkoma Basin. 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 20 drilling rigs in northern Texas. Our principal competitors in northern Texas are Grey Wolf Inc., Pioneer Drilling Company and Nabors Industries Inc. 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. During 2007 and 2006, a greater proportion of our fleet was under term contracts of a year or more to fulfill our customers’ more expansive drilling programs. In Appalachia, 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, and we have drilled wells to provide for the underground sequestration of carbon dioxide produced by coal fired power plants. In Texas, we have drilled for oil in the eastern Permian Basin and we have drilled wells that are used for the disposal of salt water that is a byproduct of natural gas production in the Barnett Shale. We market our rigs to a number of customers. In 2007, we drilled wells for 114 different customers. In 2006, we drilled wells for 148 different customers, compared to 112 customers in 2005. The decrease in the number of customers in 2007 compared to 2006 is due to a higher concentration of our drilling activity with fewer customers, primarily large independent oil and natural gas companies. In 2007, our top 20 customers provided 76% of our total revenue. In 2006, our top 20 customers provided 64% of our total revenue. The increase in number of customers in 2006 versus prior periods reflects the additional customers acquired 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.
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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 2007 and 2006, approximately 84% and 81% respectively, of our revenues were derived from daywork contracts. Most of the wells we drilled pursuant to footage contracts were drilled in the 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 do not bear a significant 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 including fuel, drill bits, mobilization and demobilization. We provide technical expertise and engineering services, as well as most of the equipment required to drill 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 economic risk under footage contracts is greater than under daywork contracts because we assume more of the costs 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 16% at present. Currently, only 13 of our 71 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
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Table of Contentsencountered 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 A land drilling rig consists of a derrick, a substructure, a hoisting system, a rotating system, pumps to circulate drilling fluid, blowout preventers and other related equipment. Diesel engines are typically the main power sources for a drilling rig. 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 four 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. 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 drilling rigs have engines that power the hoisting and rotating systems rated from 400 to 1,500 horsepower and derricks with weight suspension capacities from 110,000 to 750,000 pounds. Most of our rigs that are equipped for horizontal drilling have a pair of circulating pumps, each powered by engines that vary from 500 to 1,600 horsepower and our rigs that are capable of underbalanced drilling have two to four air compressors and one to two compression boosters, each with engines of 450 to 750 horsepower. Some of our rigs also have top drive units that separate the power and control of the hoisting and rotating functions, which often provides better performance in horizontal drilling. Many larger drilling rigs capable of drilling in deep formations generate electricity from diesel engines and power electric motors attached to the equipment in the hoisting, rotating and circulating systems. We have six rigs of this design with a seventh currently on order. Due to the geologic characteristics in our Appalachian and Arkoma Basin markets, many of the wells drilled in these areas utilize underbalanced or air drilling. We believe that air drilling provides advantages over traditional fluid drilling techniques when drilling through hard rock formations. These advantages include improved drilling penetration rates, no fluid loss 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 believe that our drilling rigs and other related equipment are in good operating condition. Our employees perform periodic maintenance and 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. We also own a fleet of trucks that are used to move our rigs as well as bulldozers, forklifts, various vehicles and other support equipment that is used to support the operation of our rigs.
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Table of ContentsThe following table sets forth certain information regarding each of our marketed rigs as of December 31, 2007:
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Competition We encounter substantial competition from other land 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 important:
While we must be competitive in our pricing, our 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:
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Table of ContentsRaw 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 can be limited from time to time by the 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 1,450 employees. Approximately 200 of these employees are administrative or supervisory employees. The rest of our employees 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. Some of our employees are considered to be “shared employees.” These employees are primarily engaged in our Texas field operations and consisted of 437 employees at December 31, 2007. Under this arrangement, certain human resource functions, including the worker’s compensation and payroll liabilities, are assumed by the third-party professional employer organization (“PEO”.) The PEO we utilize is fully licensed and bonded under Texas law. None of our employment arrangements are subject to collective bargaining arrangements. Operating hazards and insurance Our operations are subject to many hazards inherent in the land drilling business, including, blowout, cratering, fire, explosion, loss of well control, poisonous gas emission, 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 contractual indemnification from our customers 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. There are risks that are outside of our control. Nonetheless, 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 or to insurance companies representing those states based upon the payroll related to our employees working in those states. In all other states we obtain such coverage from third-party providers.
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Table of ContentsGovernment regulation and environmental matters General Our operations are affected from time to time and in varying degrees by political developments. This includes, but is not limited to 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 expenditures may be required to comply with such laws and regulations, currently 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 waste directly generated from the operation and maintenance of our drilling rigs, such as waste oils and wash water, it is our practice, to the greatest extent practicable, 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.
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Table of ContentsSuperfund 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 are 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 subject to the requirements of the federal Occupational Safety and Health Act, or OSHA, as well as comparable state and local laws that regulate the protection of worker health and safety. In addition, the OSHA hazard communication standard requires that we maintain certain information about any hazardous materials used or produced in our operations and that this information be provided to employees, state and local government authorities and citizens. We believe that our operations are in substantial compliance with OSHA requirements, including general industry standards, record keeping requirements and monitoring of occupational exposure to regulated substances. Trucking regulations We operate a fleet of trucks to transport our drilling rigs and related equipment. We operate as a private motor carrier, not as a common carrier for hire. We are licensed to perform both intrastate and interstate trucking operations. As a private motor carrier we are subject to certain safety regulations issued by the Department of Transportation, or DOT. These trucking regulations cover, among other things, driver operations, maintaining log books, truck manifest preparations, the placement of safety placards on our regulated trucks and trailers, driver drug and alcohol testing, safety of operation and equipment, and several other aspects of truck operations. Our trucking operations are also subject to certain OSHA requirements when our employees are loading or unloading equipment at a drilling site. 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 100 F Street, N.E., Room 1580, Washington, D.C. 20549-0213. You can request copies of these documents at prescribed rates by writing to the SEC at Public Reference Section, SEC, 100 F Street, N.E., Washington, D.C. 20549-0213. 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 website 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.
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Table of ContentsYou 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 at www.uniondrilling.com or by contacting our Investor Relations Department at 817-735-8793. In addition, our Code of Ethics is available on our website.
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. If the level of that activity decreases, our business and results of operations could be adversely affected. Other factors include, among others, the following:
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. That downturn adversely affected our operating results. Currently, the onshore contract drilling business is experiencing strong demand for drilling services, principally due to improved oil and natural gas drilling and production economics. Some of the improvement, in economics is due to increased prices, and drilling technology. 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. Approximately 50% 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. Some of our drilling rigs were built during the years 1976 to 1982, which until recently was the last period of significant rig building. Our rig upgrade and refurbishment projects on marketed rigs typically require 60 to 90 days to complete at a cost in excess of $200,000. This process includes derrick recertification, engine rebuilding or replacement and upgraded or replaced braking systems. Returning an idled rig to service could 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
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Table of Contentsunable 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, 2007, we derived approximately 34% 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, 2007, our three largest customers accounted for approximately 14%, 13% and 7%, 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 utilize. The loss of any of our principal customers or the failure to remarket the rigs utilized 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. Most 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. We have periodically experienced increased lead times in purchasing ancillary equipment for our drilling rigs. To the extent there are significant 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, it 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 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 financial risk, and debt service requirements, which could adversely affect our operating results and financial position. We may decide to purchase or internally build additional drilling rigs and upgrade or refurbish some of our marketed drilling rigs. Any delay could result in a loss of revenue. We may purchase or internally build additional drilling rigs and upgrade or refurbish some of our current drilling rigs. All of these projects are subject to risks of delay or cost overruns inherent in large construction projects. Among those risks are:
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These factors may contribute to delays in the delivery, upgrade or completion of the refurbishment 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 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 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 certain key employees, such as our Division Managers and of Christopher D. Strong, our President and Chief Executive Officer, A.J. Verdecchia, our Chief Financial Officer and David S. Goldberg, our General Counsel. Our business could be materially and adversely affected by the loss of any of these individuals. We have limited employment agreements with some key employees. We do not maintain key man life insurance on the lives of any of our executive officers. 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 domestic and international drilling contractors, many with greater resources. Their greater resources may enable them to allocate those resources into any of our regional markets. The additional competition in our markets, either by existing competitors or new entrants would increase the supply 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 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:
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These hazards are to some extent beyond our control and could cause, among other things:
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 resulting 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
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Table of Contentsbe 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. 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:
Risks Related to Our Common Stock Our principal stockholder has significant ownership. Union Drilling Company LLC, our principal stockholder, owns approximately 36% 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 this level 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. Three of our directors are affiliates of Union Drilling Company LLC, our principal stockholder, and 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. Provisions in our certificate of incorporation and bylaws as well as Delaware corporate law may make a takeover difficult. Provisions in our certificate of incorporation and bylaws, as well as 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, or our 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 Global Market. During the period from January 1, 2007 through February 28, 2008, the average daily trading volume of our common stock as reported by the NASDAQ Global Market was 125,407 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 disproportionate 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
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Table of Contentssubject to greater price volatility than the stock market when taken as a whole, or comparable securities of other contract drilling service providers, who may or may not have greater volumes. The market price of our common stock has been, and may continue to be, volatile. For example, during the period from January 1, 2007 through February 28, 2008, the trading price of our common stock ranged from $10.67 to $22.09 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 fully sell shares of our common stock when you desire or at a price you desire.
None.
Facilities We lease approximately 12,600 square feet of office space for our principal executive offices in Fort Worth, Texas. In 2006, we entered into a 90-month lease with monthly payments of approximately $17,000. This lease is cancelable after a period of 48 months from the first month we made lease payments. Our contract drilling operations are conducted from six field offices. From our 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, plus 25,000 square feet of office space and yard space. From our office in Buckhannon, West Virginia, we provide contract drilling services to the entire state of West Virginia, southwestern Virginia, Tennessee, 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 office in Abilene, Texas, we primarily provide contract drilling services in the Permian Basin. We lease a facility in Abilene, Texas, that includes approximately 3,500 square feet of office space, 3,000 square feet of shop space, 9,000 square feet of warehouse space and approximately three acres of yard space. From our office in Cresson, Texas, we provide drilling services to customers in the Fort Worth Basin, primarily targeting the Barnett Shale formation. We own approximately 17 acres of land in Cresson, with two buildings consisting of 3,200 square feet of office space and 9,350 square feet of warehouse space. From our 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. In 2007, we entered into a contract to sell the property in Bartlesville, Oklahoma for $72,500. The Bartlesville property has not been used for operations. We expect to close on the transaction in the first half of 2008. In 2006, we entered into a five year lease for 4,325 square feet of office space and yard space in Searcy, Arkansas, which has become the site of our Fayetteville Shale operations. The monthly lease payments are $12,000.
The Company is currently a party to a lawsuit, brought originally in the United States District Court for the Western District of Arkansas, to determine certain contractual indemnification rights and the insurance coverage applicable as a result of a job-related accident in which a rig worker was fatally injured. On August 13, 2007, the District
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Table of ContentsCourt issued a judgment in this case. This judgment was partially against the Company and partially in its favor. The District Court held that the Company had a contractual obligation to indemnify the lease operator in the amount of $500,000. In turn, the District Court also held that the Company take judgment against the insurer in the amount of $500,000. This judgment was appealed by the insurer and, consequently, the Company determined to join the appeal. Management believes the Company has meritorious arguments in support of its position and the Company intends to vigorously defend this matter. The Company has various other pending claims, lawsuits, disputes with third parties, investigations and actions incidental to its business operations. Although occasional adverse settlements or resolutions may occur and negatively impact its earnings in the period or year of settlement, it is management’s belief that their ultimate resolution will not have a material adverse effect on the Company’s financial condition or liquidity.
We did not submit any matter to a vote of our security holders during the fourth quarter of fiscal 2007. PAR T II
As of February 28, 2008, 21,974,884 shares of our common stock were outstanding. As of February 28, 2008, the number of holders of record of our common stock was eight. Our common stock trades on the NASDAQ Global Market under the symbol “UDRL.” The following table sets forth, for each of the periods indicated, the high and low trading price per share for our common stock on the NASDAQ Global Market:
The last reported sales price for our common stock on the NASDAQ Global Market on February 28, 2008 was $21.02 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.
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Table of ContentsEquity Compensation Plan Information The following table provides information as of December 31, 2007 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:
PERFORMANCE GRAPH The following graph shows a comparison of the total cumulative returns of an investment of $100 in cash on November 22, 2005, the first trading day following our initial public offering, in (i) our common stock, (ii) the Nasdaq Composite Index, U.S. Companies, and (iii) a peer group index that the Company selected that includes 5 public companies within our industry. The companies that comprise the peer group index are Bronco Drilling Company, Inc., Grey Wolf, Inc., Helmerich & Payne, Inc., Patterson-UTI Energy, Inc. and Pioneer Drilling Company. The historical comparisons in the graph are required by the SEC and are not intended to forecast or be indicative of the possible future performance of our common stock. The graph assumes that all dividends have been reinvested (since November 2005, the Company has not declared any dividends).
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Table of ContentsCOMPARISON OF 2 YEAR CUMULATIVE TOTAL RETURN* Among Union Drilling, Inc, The NASDAQ Composite Index And A Peer Group
* $100 invested on 11/22/05 in stock or 10/31/05 in index-including reinvestment of dividends. Fiscal year ending December 31. The foregoing graph shall not be deemed to be “soliciting material” or to be “filed” with the Securities and Exchange Commission or subject to Regulation 14A or 14C under the Securities Exchange Act of 1934 and shall not be deemed incorporated by reference into any filing made by the Company under the Securities Act of 1933 or the Securities Exchange Act of 1934, notwithstanding any general statement contained in any such filing incorporating this Annual Report by reference, except to the extent the Company incorporates such graph by specific reference.
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The following information derives from our audited financial statements. You should review this information in conjunction with “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in Item 7 of this report and the historical financial statements and related notes this report contains.
EBITDA is earnings before net interest, income taxes, depreciation and amortization and non-cash impairment. The Company believes EBITDA is a useful measure of evaluating its financial performance because it is used by external users, such as investors, commercial banks, research analysts and others, to assess: (1) the financial performance of Union’s assets without regard to financing methods, capital structure or historical cost basis, (2) the ability of Union’s assets to generate cash sufficient to pay interest costs and support its indebtedness, and (3) Union’s operating performance and return on capital as compared to those of other entities in our industry, without regard to financing or capital structure. EBITDA is not a measure of financial performance under generally accepted accounting principles. However, EBITDA is a common alternative measure of operating performance used by investors, financial analysts and rating agencies. A reconciliation of EBITDA to net income is included above. EBITDA as presented may not be comparable to other similarly titled measures reported by other companies.
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This MD&A section of our Annual Report on Form 10-K discusses our results of operations, liquidity and capital resources, and certain factors that may affect our future results, including economic and industry-wide factors. You should read this MD&A in conjuction with our financial statements and accompanying notes included under Part II, Item 8, of this Annual Report. Statements we make in the following MD&A discussion and in other parts of this report that express a belief, expectation or intention, as well as those which are not historical fact, are forward-looking statements within the meaning of the federal securities laws and are subject to risks, uncertainties and assumptions. These forward-looking statements may be identified by the use of words such as “expect,” “anticipate,” “believe,” “estimate,” “potential” or similar words. These matters include statements concerning management’s plans and objectives relating to our operations or economic performance and related assumptions, including general economic and business conditions and industry trends, the continued strength or weakness of the contract land drilling industry in the geographic areas in which we operate, decisions about onshore exploration and development projects to be made by oil and gas companies, the highly competitive nature of our business, our future financial performance, including availability, terms and deployment of capital, the continued availability of qualified personnel, and changes in, or our failure or inability to comply with, government regulations, including those relating to the environment. We specifically disclaim any duty to update any of the information set forth in this report, including any forward-looking statements. Forward-looking statements are made based on management’s current expectations and beliefs concerning future events and, therefore, involve a number of assumptions, risks and uncertainties, including the risk factors described in Item 1A, “Risk Factors,” above. Management cautions that forward-looking statements are not guarantees, and our actual results could differ materially from those expressed or implied in the forward-looking statements. Company Overview Union Drilling, Inc. provides contract land drilling services and equipment, primarily to natural gas producers in the United States. 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 an entity 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 71 marketed land drilling rigs. We presently focus our operations in selected natural gas production regions in the United States, primarily the Fort Worth Basin in North Texas, the Arkoma Basin in Oklahoma and Arkansas and throughout the Appalachian Basin. We do not invest in oil and natural gas properties. We completed several transactions in 2007, 2006 and 2005 that enhanced our ability to serve our markets. These transactions provided us with unconventional natural gas contract drilling operations in North Texas and the Arkoma Basin. In April 2005, we acquired Thornton Drilling Company, which owned a fleet of 12 rigs and leased an additional rig operating in the Arkoma Basin, and we acquired 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 a total of six more rigs, five of which target the Barnett Shale formation in the Fort Worth Basin. During 2006 and 2007, we purchased new and 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 formation exploration and development activity. Key Indicators of Financial Performance for Management Significant performance measurements in our industry are rig utilization, revenue per revenue day and operating expenses per revenue day. 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. 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.
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Table of ContentsThe following table summarizes management’s key indicators of financial performance for the three years ended December 31, 2007.
Utilization and revenue days during 2007 were negatively impacted by a significant decline in the demand for smaller rigs in our fleet, the transition of our Rocky Mountain rigs to the Fayetteville Shale, which was completed at the end of the second quarter of 2007, and an increase in the number of rigs available in the market. The reasons for the increase in the number of revenue days in 2006 over 2005 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 2006 and 2005 acquisitions. We devote substantial resources to maintaining and upgrading our rig fleet. On a regular basis, we remove certain rigs from service to perform upgrades. In the short term, these actions result 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. The increase in revenue per revenue day and operating expenses per revenue day in 2007 compared to 2006 was primarily related to the six new rigs placed into service in late 2006 and early 2007. Due to their greater capacity, these new rigs earn a higher dayrate and incur more operating expenses than older rigs in our fleet. Market Conditions in Our Industry The U.S. contract land drilling services industry is highly volatile. 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 rates 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 exploration and production companies decide to drill. See Item 1. “Business” and Item 1A. “Risk Factors.” During fiscal 2007, 2006 and 2005, 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 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. Accounts receivable. We evaluate the creditworthiness of our customers based on their financial information, if available, information obtained from major industry suppliers, and our past experiences with the customer. In some instances, we require new customers to establish escrow accounts or make prepayments. We typically invoice our customers periodically during the performance of daywork contracts and upon completion of the daywork contract. Footage contracts are invoiced upon completion of the contract. Our contracts generally provide for payment of invoices in 30 days. We established an allowance for doubtful accounts of approximately $311,000 at December 31, 2007 and $839,000 at December 31, 2006, respectively. Any allowance established is subject to judgment and estimates made by management. We determine our allowance by considering a number of factors, including the
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Table of Contentslength 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. During 2007, we wrote off $1.4 million of accounts receivable, of which $1.3 million was for one customer. During 2006, we wrote off $155,000 of accounts receivable. At December 31, 2007 and 2006, our contract drilling work in progress totaled approximately $4.1 million and $4.4 million, respectively, all of which relates to the revenue recognized, but not yet billed, on daywork and footage contracts in progress at December 31, 2007 and 2006, respectively. The decrease was due primarily to an increase in progress billings. In addition, unbilled receivables as of December 31, 2007 and 2006 include a reserve for sales credits of approximately $186,000 and $230,000, respectively. Asset impairments and depreciation. 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 any significant negative trends in the industry or the general economy, 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 two to 12 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. Goodwill and intangible assets. Goodwill represents the excess of the purchase price over the estimated fair value of the net assets acquired in the purchase of Thornton Drilling Company in April 2005. See Note 3 of Notes to Financial Statements included in “Item 8. Financial Statements and Supplementary Data” for additional information regarding this acquisition. We allocate the purchase price paid for the acquisition of a business to the assets and liabilities acquired based on the estimated fair values of those assets and liabilities. These estimates are often highly subjective and may have a material impact on the amounts recorded for acquired assets and liabilities. 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. Refer to “Taxes” under “Results of Operations” for information regarding corrections made in 2006 to the purchase price allocation for Thornton Drilling Company which impacted the carrying value of goodwill. Also, in 2006, a $1 million trade name impairment charge was recognized as the Company decided to cease using the Thornton Drilling Company name in its operations. Deferred taxes. We record deferred taxes for the basis difference in our property and equipment between financial reporting and tax reporting purposes and other costs such as compensation, employee benefits and other accrued liabilities which are deductible in different periods for financial reporting and tax reporting purposes. For property and equipment, basis differences arise from differences in depreciation periods and methods and the value of assets acquired in a business acquisition where we acquire 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 two to 12 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. Refer to “Taxes” under “Results of Operations” for information regarding corrections made in 2006 to the income tax provision and deferred tax balances for underreporting of meals and incidental expenses that are only 50% deductible for income tax purposes and to recognize the deferred tax liability attributable to non-deductible intangibles acquired from Thornton Drilling Company. Accrued workers’ compensation. The Company accrues for costs under our workers’ compensation insurance program in accrued expenses and other liabilities. We have a deductible of $100,000 per covered accident under our
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Table of Contentsworkers’ 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, 2007 and 2006, we satisfied this requirement with a $5.0 million and $3.2 million, respectively, 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, administrative costs associated with these claims and our historical experience with these types of claims. Some of our employees are considered to be “shared employees.” These employees are primarily engaged in our Texas field operations and consisted of 437 employees at December 31, 2007. Under this arrangement, certain human resource functions, including the worker’s compensation and payroll liabilities, are assumed by the third-party professional employer organization. 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. Stock-based compensation. Effective January 1, 2006, the Company adopted Statement of Financial Accounting Standards (“SFAS”) No. 123(R), “Share-Based Payment, revised 2004” (“SFAS No. 123R”). The Company adopted the standard by using the modified prospective method. SFAS No. 123R, which revised SFAS No. 123, “Accounting for Stock-Based Compensation” (“SFAS No. 123”), requires that the cost resulting from all share-based payment transactions be measured at fair value and recognized in the financial statements. Compensation cost is recognized on a straight line basis over the requisite service period for the entire award and included in general and administrative expense. The amount of compensation cost recognized at any date is at least equal to the portion of the grant-date value of the award that is vested at that date. For the years ended December 31, 2007 and 2006, the Company recorded total stock-based compensation expense of approximately $968,000 ($741,000 net of tax) and $1.0 million ($751,000 net of tax), respectively, which approximates the amount by which our results of operations were lower than they would have been under APB Opinion No. 25. Basic and diluted earnings per common share were each $0.03 lower for the year ended December 31, 2007 and $0.04 and $0.03 lower, respectively, for the year ended December 31, 2006 than they would have been had we continued to account for stock-based compensation expense under APB Opinion No. 25. Total unamortized stock-based compensation was approximately $2.2 million at December 31, 2007, and will be recognized over a weighted average service period of 2.5 years. The tax benefit realized from stock options exercised during the twelve months ended December 31, 2007 and 2006 is included as a cash inflow from financing activities on the statement of cash flows. The statements of income for the twelve months ended December 31, 2005, have not been restated to reflect stock-based compensation expense, in accordance with SFAS No. 123R. Estimating the fair value of options granted requires us to utilize valuation models and to establish several underlying assumptions. The fair value of option grants was estimated using the Black-Scholes option valuation model based on the following weighted average assumptions:
The risk-free interest rate is the implied yield available for zero-coupon U.S. government issues with a remaining term equal to the expected life of the options. The expected lives of the options are determined based on the Company’s expectations of individual option holders’ anticipated behavior and the term of the option. The Company has not paid out dividends historically; thus, the dividend yield is estimated at zero percent. Volatility is based upon price performance of the Company and a peer company, as the Company does not have a sufficient historical price base to determine potential volatility over the term of the issued options. During 2008, our stock price has increased to over $20.00 per share as compared to $15.77 at December 31, 2007. Such changes can affect the expected volatility and forfeiture rate.
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Table of ContentsResults of Operations Our operations primarily consist of drilling natural gas wells for our customers under daywork contracts and, to a lesser extent, 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 multiple wells or a specific period of time for which the rig will be under contract. Statements of Operations Analysis The following table provides selected information about our operations for the years ended December 31, 2007, 2006 and 2005 (in thousands).
Revenues. Our revenues grew by approximately $32.1 million, or 12%, in fiscal year 2007 from fiscal year 2006. The increase in revenue was primarily due to the addition of new rigs in our Texas operations. This was partially offset by a lower demand for certain smaller rigs in our fleet. These new rigs earned a day rate higher than the average rate earned in 2006, thus increasing the average rate per day. This was the major contribution to the increase in the day rate of approximately $2,300. Our revenues grew by approximately $115.3 million, or 81%, in fiscal year 2006 from fiscal year 2005. This increase was primarily due to the additional assets acquired through Thornton Drilling Company and SPA Drilling, L.P. The increase during the first quarter of 2006 represented $29.2 million of the increase. The remaining $86.1 million increase was due to additional utilization during 2006. Due to the greater demand for our drilling services, the average revenue per revenue day increased by approximately $2,700 per day. Operating expenses. The $16.8 million, or 11% increase in operating expenses during 2007 compared to 2006 was primarily due to the new rigs placed into service in late 2006 and early 2007. Our operating expenses in fiscal year 2006 grew by approximately $52.9 million. Approximately $17.4 million of the increase related to expenses of Thornton Drilling Company and SPA Drilling, L.P. during the first quarter of 2006. An additional $35.5 million of the increase was due to increased utilization of our marketed rigs. Depreciation and amortization. Depreciation and amortization expense increased $14.3 million, or 57%, primarily due to the increase in depreciable assets. Capital expenditures were $68.1 million in 2007 and $94.0 million in 2006. Our depreciation and amortization expense in 2006 increased by approximately $9.7 million, or 64%, from 2005. Approximately $2.6 million of the increase was attributable to depreciation expense during the first quarter of 2006 related to the assets acquired in April 2005. The remaining increase was the result of 2006 capital spending for rig purchases and capital equipment upgrades. Trade name impairment charge. Effective December 31, 2006, Thornton Drilling Company, a then 100% owned subsidiary, was merged with and into the Company. Concurrently, the Company decided to cease using the
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Table of ContentsThornton Drilling Company name in its operations. As a result, the Company recognized a $1 million impairment charge to write off the intangible asset associated with the trade name in December 2006. General and administrative expenses. General and administrative expenses increased $3.3 million, or 15% in 2007 compared to 2006. Payroll expenses increased $2.4 million primarily due to additional wages to professional and administrative employees and a $541,000 increase in other noncash compensation expense. In addition, $1.3 million of the increase in general and administrative expenses was due to increases in property taxes, property insurance and safety program costs primarily related to the new rigs placed into service in late 2006 and early 2007. These increases were partially offset by the decrease in nonrecurring expenses in 2006, including $587,000 for consulting fees and $466,000 for certain relocation costs. Our general and administrative expenses increased by approximately $8.5 million, or 65%, in fiscal year 2006 from fiscal year 2005. Approximately $1.0 million was attributable to stock-based compensation cost related to the implementation of SFAS No. 123R in 2006. The remainder of the increase was primarily due to the increase in employment costs of $1.5 million and insurance costs of $1.3 million to support the Company’s growth, additional professional and consulting fees of $1.3 million as a result of becoming a public company, $690,000 for additional property and franchise taxes, a $500,000 increase to the provision for doubtful accounts and relocation costs of approximately $460,000, primarily for the corporate office move to Texas. In addition, approximately $917,000 of the increase was attributable to first quarter 2006 general and administrative costs related to operations established to support the purchase of SPA Drilling, L.P. assets and the Thornton Drilling Company acquisition on April 1, 2005. Interest expense. Interest expense increased $1.3 million in 2007 compared to 2006 due to the higher average balance on our revolving credit facility during 2007 and less interest capitalized related to construction in progress during the last nine months of 2007. Our interest expense decreased by approximately $1.8 million for fiscal year 2006 from fiscal year 2005. This decrease resulted primarily from interest expense being capitalized in 2006 related to construction in progress and increased interest expense in 2005 related to the financing of the 2005 rig acquisitions. Much of these financing costs were repaid in the fourth quarter of 2005 with the proceeds from the Company’s initial public offering. Other income and gain on sale or disposal of fixed assets. The $1.1 million increase in other income and gain on sale or disposal of fixed assets in 2007 compared to 2006 was primarily due to the sale of various utility vehicles at auction during the second quarter of 2007. Other income and gain on sale or disposal of fixed assets decreased approximately $541,000 in 2006 compared to 2005 primarily due to $676,000 gain recognized in 2005 related to the sale of two rigs. Partially offsetting this decrease was an insurance settlement received in 2006 related to a 2004 rig accident, resulting in a gain of approximately $274,000. Taxes. Our effective income tax rates of 41.7%, 41.3% and 42.3% for 2007, 2006 and 2005, respectively, differ from the federal statutory rate of 35% in 2007 and 2006 and 34% in 2005, primarily due to state income taxes and permanent book/tax differences associated with 50% limitation on meals and entertainment expense, the domestic manufacturing deduction and non-cash compensation. See Note 7 to our Financial Statements for further information on our income taxes. During 2006, the Company corrected its income tax provisions and deferred tax balances for underreporting of meals and incidental expenses that are only 50% deductible for income tax purposes and to recognize the deferred tax liability attributable to non-deductible intangibles acquired from Thornton Drilling Company. This correction resulted in a $462,000 additional charge to the Company’s income tax provision attributable to the year ended December 31, 2005. This correction also resulted in a $1.2 million increase to deferred tax liabilities, a $1.3 million reduction in deferred tax assets, a $2.5 million increase to recorded goodwill and a $462,000 increase to income taxes payable. Management concluded that the effect of the corrections was not material to any period impacted. At December 31, 2007 and 2006, we had federal net operating loss carryforwards for income tax purposes of approximately $98,000 and $7.7 million, respectively. These losses may be carried forward for 20 years and will begin to expire in 2023. State net operating loss carryforwards at December 31, 2007 and 2006 were $3.4 million and $15.9 million, respectively. State net operating loss carryforwards vary as to carryforward period and will begin to expire in 2013, depending upon the jurisdiction where applied. Based upon 2007 results and forecasted future operations, we believe it is more likely than not that the amounts will be realized.
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Table of ContentsLiquidity and Capital Resources Our operations have historically generated sufficient cash flow to meet our requirements for debt service and equipment expenditures (excluding major business and asset acquisitions). Cash flow provided by operating activities during fiscal year 2007 was $82.6 million compared to $57.1 million during fiscal year 2006. This $25.5 million improvement in cash flow from operating activities for 2007 over 2006 was primarily due to our reduced investment in working capital in 2007 and an increase in net income after adjusting for the non-cash cost of depreciation and amortization and non-cash impairment. During 2006, as revenues expanded rapidly, our account receivable balance increased by $20.0 million, whereas in 2007, due to a reduction in the average number of days to collect receivables, rather than a decline in revenue, our accounts receivable balance declined by $7.7 million. For 2007, net income plus depreciation and amortization was $69.9 million. For 2006, net income plus depreciation and amortization and non-cash impairment was $57.7 million. Our cash flow from operations was primarily used to invest in new machinery and equipment as well as for capitalized maintenance and repairs to our fleet. For example, between November 2005 and March 2007, construction was completed and we took delivery of six new drilling rigs costing approximately $67 million. These new rigs were utilized under long-term customer contracts upon delivery. During 2007 and 2006, cash used in investing activities totaled $65.8 million and $92.9 million, respectively. For the year ended December 31, 2007, our net borrowings declined by $18.2 million compared to a net increase of $27.8 million during the same period in 2006. The net borrowings are the primary component of the $16.8 million used in financing activities in 2007 compared to the $33.4 million provided in the same period of 2006. Compared to 2006, our pace of acquisitions slowed in the second half of 2007. With a more balanced market for contract drilling services and fewer opportunities to invest in drilling rigs secured by term contracts, we have used cash flow from operating activities to reduce the Company’s outstanding debt. This resulted in an $18.2 million reduction of the loan balance under our Revolving Credit and Security Agreement from $27.8 million on December 31, 2006 to $9.6 million on December 31, 2007. We believe cash generated by our operations and our ability to borrow the currently unused portion of our Revolving Credit and Security Agreement of approximately $85.4 million, after reductions for approximately $5.0 million outstanding letters of credit as of December 31, 2007 should allow us to meet our routine financial obligations for the foreseeable future. The $39.4 million increase in cash flow provided by operating activities in 2006 compared to 2005 was primarily due to the $26.3 million improvement in net income, plus the approximate $9.7 million increase in non-cash depreciation and amortization expense, $1 million trade name impairment charge and the utilization of our deferred tax asset of $5.2 million. In 2006, our cash flow used in investing activities was $92.9 million compared to $99.2 million in 2005. While the $47.5 million used in 2005 for the purchase of businesses was not repeated in 2006, we did, however, have significant expenditures in 2006 for the purchase of machinery and equipment, including several new rigs. Cash flow provided by financing activities in 2006 was $33.5 million compared to $80.1 million in 2005. The 2005 amount reflects the proceeds from certain sales of our common stock, including $55.4 million from our initial public offering in November 2005. Sources of Capital Resources Our rig fleet has grown from 12 rigs in 1997 to 71 marketed rigs at December 31, 2007. We have financed this growth with a combination of debt and equity financing. At December 31, 2007, our total debt to total capital was approximately 7.8%. Due to the volatility in our industry, we are reluctant to take on additional debt in excess of the $85.4 million 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. In April 2005, we raised $19.9 million, after expenses, through a private placement of shares of our common stock. These proceeds plus additional borrowing under our revolving credit facility were used to fund the acquisitions of Thornton Drilling Company and SPA Drilling, L.P. In November 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. The net proceeds to Union, after expenses, of this sale were approximately $55.4 million, and were used primarily to repay indebtedness under our revolving credit facility.
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Table of ContentsWe entered into a Revolving Credit and Security Agreement with PNC Bank, as agent for a group of lenders, in March 2005, and subsequently amended in April, August, and October, 2005, and in September and December, 2006. This credit facility matures on March 30, 2009 and provides for a borrowing base equal to the lesser of $100 million or 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 has been determined annually by an independent appraisal, with adjustments for acquisitions and dispositions between appraisals. There is a $7.5 million 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 50 basis points or PNC Bank’s base commercial lending rate (7.25% at December 31, 2007) or (ii) LIBOR plus 200 basis points (6.9% at December 31, 2007). Those rates may increase by up to 50 basis points for LIBOR loans or up to 25 basis points for domestic rate loans if our fixed charge coverage ratio falls below certain targets. A fee of 25 basis points is applied to the available borrowing capacity. The available borrowing capacity was $85.4 million as of December 31, 2007. 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, 2007, we had a loan balance of $9.6 million under the Revolving Credit and Security Agreement, and an additional $5.0 million of the total capacity had 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 completely and terminate the obligations under the Revolving Credit and Security Agreement, we would be liable for a prepayment penalty. As of December 31, 2006, approximately $27.8 million was outstanding under this revolving credit facility and $3.2 million of the total capacity had 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 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. Events of default would include a change in control and any change in our operations or condition, which has a material adverse effect. As of December 31, 2007, the Company was in compliance with all debt covenants. In September 2006, the Agreement was amended to increase the 2006 net capital expenditure limitation to $125 million and $40 million in subsequent years, but those amounts are increased by permitted equity issuance proceeds and the unused amounts can be carried over to the next fiscal year. For 2007, the net capital expenditure limitation was approximately $71 million. Capital expenditures for 2007 were approximately $68.1 million, of which $63.3 million was for drilling equipment. For 2008, the net capital expenditure limitation is approximately $43 million. Current portion of other obligations at December 31, 2006 consisted of financed annual insurance premiums, which was repaid over 11 months in 2007. The interest rate on these borrowings was 6.3%. In December 2007, we used excess borrowing capacity on our revolving credit facility to finance the insurance premiums. In addition, the Company has entered into various equipment-specific financing agreements with several third-party financing institutions. The terms of these agreements range from 36 to 60 months. As of December 31, 2007, the total outstanding balance under these arrangements, including principal and interest, was approximately $8.3 million. The interest rate on these borrowings ranges from 3.5% to 7.6%.
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Table of ContentsUses of Capital Resources For the years ended December 31, 2007 and 2006, the additions to our property and equipment consisted of the following (in thousands):
In March 2007, we placed into service in the Arkoma Basin, a rig which we built internally for approximately $6 million. The Company previously entered into agreements with National Oilwell Varco to purchase six rigs and related equipment for an aggregate price of approximately $67 million, including internal costs, additional equipment and sales tax. The first three rigs were delivered in late 2006 and the remaining three were delivered in the first quarter of 2007. All six rigs are capable of horizontal and underbalanced drilling, and were placed into service in the Fort Worth Basin. In the first six months of 2006, the Company acquired two rigs for deployment in the Fayetteville Shale play in eastern Arkansas for a total purchase price of approximately $9 million. Working Capital Our working capital decreased $6.2 million to $20.8 million at December 31, 2007 from $27.0 million at December 31, 2006. Our current ratio, which we calculate by dividing our current assets by our current liabilities, was 1.7 at December 31, 2007 compared to 1.8 at December 31, 2006.
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Table of ContentsThe changes in the components of our working capital were as follows (in thousands):
The decrease in our receivables at December 31, 2007 from December 31, 2006 was due primarily to increased collection efforts. During 2007, the Company improved procedures to monitor and investigate past due receivables on a more timely basis. Enhanced procedures and improved communication with operations personnel has enabled the Company to achieve a more manageable receivables balance. We also wrote off $1.4 million of specific receivable accounts which became uncollectible in 2007. The $3.0 million increase in prepaid expenses, deposits and other receivables at December 31, 2007 compared to December 31, 2006 was primarily due to $2.8 million prepaid income tax and $771,000 insurance claims receivable as of December 31, 2007, and partially offset by lower prepaid insurance premiums. Assets held for sale at December 31, 2006 represented one of the Company’s stacked rigs. Management decided during the fourth quarter of 2006 to dispose of this rig. In January 2007, some components of the rig were sold for $415,000. In August 2007, management determined the remaining assets held for sale would be better utilized as part of our rig fleet. Therefore, the assets have been reclassified to fixed assets. The $2.9 million decrease in the deferred tax asset was due to utilization of federal and state net operating losses from prior years as a reduction to current taxes payable during 2007. The $1.7 million decrease in current debt at December 31, 2007 was primarily due to $2.3 million financed insurance liability as of December 31, 2006 which was paid over 11 months in 2007. This decrease was partially offset by the $631,000 increase in the current portion of notes payable for equipment as a result of $2.8 million of equipment financed in 2007, of which $2.2 million was classified as long-term. The $3.5 million decrease in our accounts payable at December 31, 2007 from December 31, 2006 was primarily due to shorter payment terms with vendors. The $2.9 million increase in the current portion of advances from customers at December 31, 2007 compared to December 31, 2006 was due to $6.9 million of customer advances received in 2007, net of $4.6 million application to revenue, of which a net decrease of $621,000 was classified as long term. Accrued expenses and other liabilities at December 31, 2007 decreased $1.1 million from December 31, 2006 primarily due to a decrease in the number of days of accrued payroll expenses as of December 31, 2007 compared to December 31, 2006, the payment in 2007 of insurance premiums accrued at December 31, 2006 and the current income tax payable as of December 31, 2006 compared to a prepaid income tax position at December 31, 2007.
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Table of ContentsLong-term Debt Our long-term debt at December 31, 2007 and 2006 consisted of the following (in thousands):
Contractual Obligations The following table includes all of our contractual obligations of the type specified below at December 31, 2007 (in thousands):
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 September 2006, the Financial Accounting Standards Board (“ FASB”) issued Staff Position AUG AIR-1, Accounting for Planned Major Maintenance Activities, which eliminates the acceptability of the accrue-in-advance method of accounting for planned major maintenance activities. This FASB Staff Position was effective for fiscal years beginning after December 15, 2006. We do not use the accrue-in-advance method of accounting for rig refurbishments. The application of this FASB Staff Position had no material impact on our financial position or results of operations and financial condition. In September 2006, the FASB issued Statement of Financial Accounting Standards No. 157 “Fair Value Measurements” (“SFAS No. 157”). This Statement defines fair value, establishes a framework for measuring fair value in GAAP, and expands disclosures about fair value measurements. SFAS No. 157 is effective for financial statements issued for fiscal years beginning after November 15, 2007, and interim periods within those fiscal years. We do not expect the adoption of SFAS No. 157 to have a material impact on our financial position or results of operations. In February 2007, the FASB issued SFAS No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities” (“SFAS No. 159”). SFAS No. 159 permits entities to measure many financial instruments and certain other items at fair value that are not currently required to be measured at fair value. SFAS No. 159 is effective for financial statements issued for fiscal years beginning after November 15, 2007, and interim periods within those fiscal years. The implementation of SFAS No. 159 is not expected to have a material effect on the financial condition or results of operations of the Company.
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Table of Contents
We are subject to market risk exposure related to changes in interest rates on our revolving credit facility, which provides for interest on borrowings under the facility at a floating rate. At December 31, 2007, we had approximately $9.6 million outstanding debt on our revolving credit facility. An increase or decrease of 1% in the interest rate would have a corresponding decrease or increase in our net income of approximately $96,000 annually.
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UNION DRILLING, INC. INDEX TO FINANCIAL STATEMENTS
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Table of ContentsMANAGEMENT’S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING To the Board of Directors and Stockholders of Union Drilling, Inc.: Management is responsible for establishing and maintaining adequate internal control over financial reporting (as defined in Rule 13a-15(f) under the Securities Exchange Act of 1934). Our internal control over financial reporting is designed to provide reasonable assurance to management and the Board of Directors regarding the preparation and fair presentation of published financial statements. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Therefore, even those systems determined to be effective can provide only reasonable assurance with respect to financial statement preparation and presentation. Management assessed the effectiveness of our internal control over financial reporting as of December 31, 2007. In making this assessment, management used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control – Integrated Framework. Based on our assessment, we believe that, as of December 31, 2007, our internal control over financial reporting is effective based on those criteria. Ernst & Young, LLP, an independent registered public accounting firm which also audited our financial statements has issued an attestation report on the effectiveness of our internal control over financial reporting as of December 31, 2007. This report, which expresses an unqualified opinion on the effectiveness of our internal control over financial reporting as of December 31, 2007 is included under the heading “Report of Independent Registered Public Accounting Firm on Internal Control Over Financial Reporting.”
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Table of ContentsREPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM ON INTERNAL CONTROL OVER FINANCIAL REPORTING To the Board of Directors and Stockholders of Union Drilling, Inc: We have audited Union Drilling, Inc.’s internal control over financial reporting as of December 31, 2007, based on criteria established in Internal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (the COSO criteria). Union Drilling, Inc.’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting included in the accompanying Management’s Report on Internal Control Over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit. We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion. A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. In our opinion, Union Drilling, Inc. maintained, in all material respects, effective internal control over financial reporting as of December 31, 2007, based on the COSO criteria. We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the balance sheets of Union Drilling, Inc. as of December 31, 2007 and 2006 and the related statements of income, stockholders’ equity and cash flows for each of the three years in the period ended December 31, 2007 and our report dated March 7, 2008 expressed an unqualified opinion thereon.
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Table of ContentsReport of Independent Registered Public Accounting Firm The Board of Directors and Stockholders of Union Drilling, Inc. We have audited the accompanying balance sheets of Union Drilling, Inc. (the “Company”) as of December 31, 2007 and 2006, and the related statements of income, stockholders’ equity, and cash flows for each of the three years in the period ended December 31, 2007. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Union Drilling, Inc. at December 31, 2007 and 2006, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2007, in conformity with U.S. generally accepted accounting principles. As discussed in Note 2 to the financial statements, effective January 1, 2007, the Company adopted FASB Interpretation No. 48, “Accounting for Uncertainty in Income Taxes – an Interpretation of FASB No. 109,” and effective January 1, 2006, the Company adopted Statement of Financial Accounting Standards No. 123(R), “Share Based Payment.” We also have audited, in accordance with the Standards of the Public Company Accounting Oversight Board (United States), the Company’s internal control over financial reporting as of December 31, 2007, based on criteria established in Internal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission, and our report dated March 7, 2008 expressed an unqualified opinion thereon.
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Table of ContentsBalance Sheets (in thousands, except share data)
See accompanying notes to financial statements.
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Table of ContentsStatements of Income (in thousands, except share and per share data)
See accompanying notes to financial statements.
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Table of ContentsStatements of Stockholders’ Equity (in thousands, except share data)
See accompanying notes to financial statements.
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Table of ContentsStatements of Cash Flows (in thousands)
See accompanying notes to financial statements.
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Table of ContentsNOTES TO FINANCIAL STATEMENTS
Union Drilling, Inc. (“Union”, “Company” or “we”) was incorporated in Delaware in September 1997. In October 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.
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, New York, Ohio, Oklahoma, Pennsylvania, Texas and West Virginia. As the Company substantially completed the liquidation of its Canadian operations in 2004, all subsequent foreign currency translation adjustments were recorded through other income/expense in the statements of operations. In December 2006, the Canadian subsidiary was dissolved. 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, 2007 represented approximately 60% of total revenues with two customers’ revenue totaling 14% and 13%, respectively. Revenues from the top ten customers for the year ended December 31, 2006 represented approximately 46% of total revenues with one customer’s revenue totaling 12%. Revenues from the top ten customers for the year ended December 31, 2005 represented approximately 46% of total revenues with no single customer accounting for over 10% of our revenue. Basis of Presentation For fiscal years 2006 and 2005, the financial statements are consolidated and include the accounts of Union and its wholly-owned subsidiaries after the elimination of all significant intercompany balances and transactions. Effective January 1, 2007, all wholly-owned subsidiaries had been dissolved or merged into Union. 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 evaluate the creditworthiness of our customers based on their financial information, if available, information obtained from major industry suppliers, and our past experiences with the customer. In some instances, we require new customers to establish escrow accounts or make prepayments. We typically invoice our customers periodically during the performance of daywork contracts and upon completion of the daywork contract. Footage contracts are invoiced upon completion of the contract. Our contracts generally provide for payment of invoices in 30 days. We established an allowance for doubtful accounts of approximately $311,000 at December 31, 2007 and $839,000 at December 31, 2006, respectively. Any allowance established is subject to judgment and estimates made by management. We determine our allowance by considering a number of factors, including the length of time trade accounts receivable are past due, our previous loss history, our assessment of our customers’ current abilities to pay
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Table of Contentsobligations 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. During 2007, we wrote off $1.4 million of accounts receivable, of which $1.3 million was for one customer. During 2006, we wrote off $155,000 of accounts receivable. At December 31, 2007 and 2006, our contract drilling work in progress totaled approximately $4.1 million and $4.4 million, respectively, all of which relates to the revenue recognized, but not yet billed, on daywork and footage contracts in progress at December 31, 2007 and 2006, respectively. The decrease was due primarily to an increase in progress billings. In addition, unbilled receivables as of December 31, 2007 and 2006 include a reserve for sales credits of approximately $186,000 and $230,000, respectively. Inventories Inventories maintained by the Company are primarily consumable replacement parts and drill bits. Inventories are maintained on the lower of first-in, first-out cost, or market. Prepaid Expenses, Deposits and Other Receivables Prepaid expenses, deposits and other receivables include items such as insurance, taxes, utility deposits, fees and insurance claim receivables. We routinely expense these items in the normal course of business over the periods these expenses benefit. Included in prepaid expenses, deposits and other receivables is prepaid insurance of approximately $2.6 million and $3.1 million at December 31, 2007 and 2006, respectively. Also included in the December 31, 2007 balance is $2.8 million prepaid income tax and approximately $771,000 insurance claim receivables. Assets Held for Sale During the fourth quarter of 2006, management made the decision to dispose of one of its stacked rigs. Subsequent to December 31, 2006, some components of the rig were sold. In August 2007, management determined the remaining assets held for sale would be better utilized as part of our rig fleet, thus these assets were appropriately reclassified. Goodwill and Intangible Assets Goodwill represents the excess of the purchase price over the estimated fair value of the net assets acquired in the purchase of Thornton Drilling Company in April 2005. See Note 3 of Notes to Financial Statements for additional information regarding this acquisition. We allocate the purchase price paid for the acquisition of a business to the assets and liabilities acquired based on the estimated fair values of those assets and liabilities. These estimates are often highly subjective and may have a material impact on the amounts recorded for acquired assets and liabilities. 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. Refer to Note 7 “Income Taxes” of Notes to Financial Statements for information regarding corrections made in 2006 to the purchase price allocation for Thornton Drilling Company which impacted the carrying value of goodwill. Also, in 2006, a $1 million trade name impairment charge was recognized as the Company decided to cease using the Thornton Drilling Company name in its operations.
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Table of ContentsProperty, Buildings and Equipment Property and equipment is stated on the basis of cost. The Company capitalizes costs of replacements or renewals that improve or extend the lives of existing property, buildings and equipment. Maintenance and repairs are expensed as incurred. Depreciation is calculated on the straight-line method over the estimated remaining useful lives of the assets. Depreciation on acquired or constructed rigs and other components does not commence until the assets are placed in service. Once placed in service, depreciation continues when assets are being repaired, refurbished or between periods of deployment. As a result, our depreciation charges will not vary with changes in utilization levels, unlike our revenue. For the year ended December 31, 2007, depreciation expense was approximately $38.7 million. Capital spare parts are classified as property and equipment. The estimated lives of the assets are as follows:
Impairment of Long-Lived Assets 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 any significant negative trends in the industry or the general economy, 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 two to 12 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. Accrued Workers’ Compensation The Company accrues for costs under our workers’ compensation insurance program in accrued expenses and other liabilities. 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, 2007 and 2006, we satisfied this requirement with a $5.0 million and $3.2 million, respectively, 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, administrative costs associated with these claims and our historical experience with these types of claims. Some of our employees are considered to be “shared employees.” These employees are primarily engaged in our Texas field operations and consisted of 437 employees at December 31, 2007. Under this arrangement, certain human resource functions, including the worker’s compensation and payroll liabilities, are assumed by the third-party professional employer organization. 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. Stock-Based Compensation Effective January 1, 2006, the Company adopted Statement of Financial Accounting Standards (“SFAS”) No. 123(R), “Share-Based Payment, revised 2004” (“SFAS No. 123R”). The Company adopted the standard by using the modified prospective method. SFAS No. 123R, which revised SFAS No. 123, “Accounting for Stock-Based Compensation” (“SFAS No. 123”), requires that the cost resulting from all share-based payment transactions be measured at fair value and recognized in the financial statements. Compensation cost is recognized on a straight line basis over the requisite service period for the entire award and included in general and administrative expense. The
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Table of Contentsamount of compensation cost recognized at any date is at least equal to the portion of the grant-date value of the award that is vested at that date. For the years ended December 31, 2007 and 2006, the Company recorded total stock-based compensation expense of approximately $968,000 ($741,000 net of tax) and $1.0 million ($751,000 net of tax), respectively, which approximates the amount by which our results of operations were lower than they would have been under APB Opinion No. 25. Basic and diluted earnings per common share were each $0.03 lower for the year ended December 31, 2007 and $0.04 and $0.03 lower, respectively, for the year ended December 31, 2006 than they would have been had we continued to account for stock-based compensation expense under APB Opinion No. 25. Total unamortized stock-based compensation was approximately $2.2 million at December 31, 2007, and will be recognized over a weighted average service period of 2.5 years. The tax benefit realized from stock options exercised during the twelve months ended December 31, 2007 and 2006 is included as a cash inflow from financing activities on the statement of cash flows. The statements of income for the twelve months ended December 31, 2005, have not been restated to reflect stock-based compensation expense, in accordance with SFAS No. 123R. Estimating the fair value of options granted requires us to utilize valuation models and to establish several underlying assumptions. The fair value of option grants was estimated using the Black-Scholes option valuation model based on the following weighted average assumptions:
The risk-free interest rate is the implied yield available for zero-coupon U.S. government issues with a remaining term equal to the expected life of the options. The expected lives of the options are determined based on the Company’s expectations of individual option holders’ anticipated behavior and the term of the option. The Company has not paid out dividends historically; thus, the dividend yield is estimated at zero percent. Volatility is based upon price performance of the Company and a peer company, as the Company does not have a sufficient historical price base to determine potential volatility over the term of the issued options. Changes in our stock price can affect the expected volatility and forfeiture rate. Prior to the implementation of SFAS No. 123R, the Company accounted for stock-based compensation under APB Opinion No. 25, “Accounting for Stock Issued to Employees”, and the disclosure-only provisions of SFAS No. 123. SFAS No. 123 permitted the Company to continue accounting for stock-based compensation as set forth in APB Opinion No. 25, provided the Company disclosed the pro forma effect on net income and earnings per share of adopting the full provisions of SFAS No. 123. Accordingly, the Company continued to account for stock-based compensation under APB Opinion No. 25 and provided the required pro forma disclosures.
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Table of ContentsThe following table illustrates the effect on net income and income per share if the Company had applied the fair value recognition provisions of SFAS No. 123 to employee stock-based awards prior to January 1, 2006 (in thousands).
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. Revenue 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 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. 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, 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 We record deferred taxes for the basis difference in our property and equipment between financial reporting and tax reporting purposes and other costs such as compensation, employee benefit and other accrued liabilities which are deductible in different periods for financial reporting and tax reporting purposes. For property and equipment, basis differences arise from differences in depreciation periods and methods and the value of assets acquired in a business acquisition where we acquire 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 two to 12 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. Refer to Note 7 “Income Taxes” for information regarding corrections made in 2006 to the income tax provision and deferred tax balances for underreporting of meals and incidental expenses that are only 50% deductible for income tax purposes and to recognize the deferred tax liability attributable to non-deductible intangibles acquired from Thornton Drilling Company.
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Table of ContentsIn June 2006, the FASB issued FASB Interpretation No. 48, “Accounting for Uncertainty in Income Taxes – an interpretation of FASB Statement No. 109” (“FIN 48”). FIN 48 clarifies the accounting for uncertainty in income taxes recognized in an enterprise’s financial statements in accordance with SFAS No. 109. This interpretation prescribes a recognition threshold and measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. FIN 48 also provides guidance on derecognition, classification, interest and penalties, accounting in interim periods, disclosure and transition. We adopted the provisions of FIN 48 on January 1, 2007. Implementation of FIN 48 did not result in a cumulative effect adjustment to retained earnings. See Note 7 regarding further disclosures required under FIN 48. Foreign Currency Translation In December 2006, the Canadian subsidiary was dissolved. The functional currency of the Company’s foreign subsidiary was the Canadian dollar. Net (loss) gains resulting from foreign exchange transactions, which are recorded in the statements of operations in other income, approximated ($1,600) in 2006 and $12,000 in 2005. Earnings Per Share Basic earnings per common share is computed by dividing net income 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. The treasury stock method is used to compute the assumed incremental shares related to our outstanding stock options. The average common stock market prices for the periods are used to determine the number of incremental shares. 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. Other Comprehensive Income For fiscal years 2007, 2006 and 2005, other comprehensive income equals net income. Recent Accounting Pronouncements In September 2006, the Financial Accounting Standards Board (“ FASB”) issued Staff Position AUG AIR-1, Accounting for Planned Major Maintenance Activities, which eliminates the acceptability of the accrue-in-advance method of accounting for planned major maintenance activities. This FASB Staff Position was effective for fiscal years beginning after December 15, 2006. We do not use the accrue-in-advance method of accounting for rig refurbishments. The application of this FASB Staff Position had no material impact on our financial position or results of operations and financial condition. In September 2006, the Financial Accounting Standards Board (“FASB”) issued SFAS No. 157 “Fair Value Measurements” (“SFAS No. 157”). This Statement defines fair value, establishes a framework for measuring fair value in GAAP, and expands disclosures about fair value measurements. SFAS No. 157 is effective for financial statements issued for fiscal years beginning after November 15, 2007, and interim periods within those fiscal years. We do not expect the adoption of SFAS No. 157 to have a material impact on our financial position or results of operations. In February 2007, the FASB issued SFAS No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities” (“SFAS No. 159”). SFAS No. 159 permits entities to measure many financial instruments and certain other items at fair value that are not currently required to be measured at fair value. SFAS No. 159 is effective for
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Table of Contentsfinancial statements issued for fiscal years beginning after November 15, 2007, and interim periods within those fiscal years. The implementation of SFAS No. 159 is not expected to have a material effect on the financial condition or results of operations of the Company.
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 $20.3 million. This acquisition provided the Company with a presence in the North Texas market. Also, effective April 1, 2005, the Company acquired all the outstanding stock of Thornton Drilling Company. The aggregate purchase price of approximately $29.2 million (including transaction costs of approximately $269,000) consisted of common shares valued at approximately $2.0 million and $26.9 million in cash. The transaction was 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 certain assets 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 $7.9 million was classified as goodwill. Management believes the goodwill will be recovered through the expected strategic benefits and operating synergies of the acquisition that are expected to be realized on a reporting unit basis. The allocation of the assets acquired and liabilities assumed of Thornton Drilling Company are as follows (in thousands):
Refer to “Income Taxes” in Note 2 for further information regarding corrections made to the purchase price allocation in 2006. 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 2005. 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, 2005, or that we may achieve in the future. The pro forma financial information (in thousands, except per share data) should be read in conjunction with the accompanying historical financial statements.
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Table of ContentsThe 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 two years. Depreciation and amortization includes amortization of intangibles of $403,000, $326,000 and $202,000 for the years ended December 31, 2007, 2006 and 2005, respectively. Amortization of intangibles is not expected to exceed $281,000 per year over the next five years. The total cost and accumulated amortization of intangible assets related to our 2005 acquisition are as follows (in thousands):
Effective December 31, 2006, the Thornton Drilling Company subsidiary was merged with and into the Company. Concurrently, the Company decided to cease using the Thornton Drilling Company name in its operations. As a result, a $1 million impairment charge was recognized to write off the trade name intangible asset.
William R. Ziegler, a member of our board of directors through March 31, 2006, is Of Counsel to Satterlee Stephens Burke & Burke LLP, a law firm which periodically provides legal counsel to the Company. During the three months ended March 31, 2006, legal fees related to transactions with Satterlee Stephens Burke & Burke LLP were $49,985. During the twelve months ended December 31, 2005, legal fees were $642,105. During 2005, 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 period ended December 31, 2005, the Company had revenues related to transactions with Columbia Natural Resources and Triana Energy, Inc. of $5,232,314. 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.
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Accounts receivable consist of the following (in thousands):
Unbilled receivables represent recorded revenue for contract drilling services performed 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. At December 31, 2007 and 2006, unbilled receivables were net of an estimated reserve for sales credits of $186,000 and $230,000, respectively. Activity in the allowance for doubtful accounts was as follows (in thousands):
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Major classes of property, buildings and equipment are as follows (in thousands):
During 2007, 2006 and 2005, we capitalized $909,000, $1.8 million and $307,000, respectively, of interest costs incurred during the construction periods of certain drilling equipment.
The current and deferred components of income tax expense are as follows (in thousands):
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Table of ContentsThe components of the net deferred income tax assets and liabilities are as follows (in thousands):
Deferred tax assets and liabilities are presented net in the balance sheet according to their current or long-term classification. The Company had federal net operating loss carryforwards of approximately $98,000 and $7.7 million at December 31, 2007 and 2006, respectively. These losses may be carried forward for 20 years and will begin to expire in 2023. State net operating losses at December 31, 2007 and 2006, were $3.4 million and $15.9 million, respectively. State losses vary as to carryforward period and will begin to expire in 2013, depending upon the jurisdiction where applied. Total income tax expense differed from the amounts computed by applying the U.S. statutory federal income tax rate to income before income taxes as a result of the following (in thousands):
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Table of ContentsDuring 2007, 2006, and 2005, the Company made tax payments of approximately $14 million, $11 million and $252,000, respectively. At January 1, 2007 and December 31, 2007 we had approximately $120,000 and $561,000, respectively, of unrecognized tax benefits, as defined by FIN 48, all of which would affect our effective tax rate if recognized. Such amounts are carried as other long-term liabilities. A reconciliation of the beginning and ending amount of unrecognized tax benefits is as follows (in thousands):
Interest and penalties related to uncertain tax positions are classified as interest expense and general and administrative costs, respectively. During fiscal year 2007, the Company recognized approximately $21,000 in interest related to unrecognized tax benefits in interest expense. As of December 31, 2007 the Company has approximately $21,000 of interest accrued in relation to uncertain tax positions. The Company files income tax returns in the U.S. federal and in various state jurisdictions, and, prior to 2007, in Canada. The tax years 2004 to 2006 remain open to examination by the major taxing jurisdictions to which we are subject. During 2006, the Company corrected its income tax provisions and deferred tax balances for underreporting of meals and incidental expenses that are only 50% deductible for income tax purposes and to recognize the deferred tax liability attributable to non-deductible intangibles acquired from Thornton Drilling Company. This correction resulted in a $462,000 additional charge to the Company’s income tax provision attributable to the year ended December 31, 2005. This correction also resulted in a $1.2 million increase to deferred tax liabilities, a $1.3 million reduction in deferred tax assets, a $2.5 million increase to recorded goodwill and a $462,000 increase to income taxes payable. Management concluded that the effect of the corrections was not material to any period impacted.
A detail of accrued expenses and other liabilities is as follows (in thousands):
We entered into a Revolving Credit and Security Agreement with PNC Bank, as agent for a group of lenders, in March 2005, and subsequently amended in April, August, and October, 2005, and in September and December, 2006. This credit facility matures on March 30, 2009 and provides for a borrowing base equal to the lesser of $100 million or 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 has been determined annually by an independent appraisal, with adjustments for acquisitions and dispositions between appraisals. There is a $7.5 million sublimit for letters of credit. Amounts outstanding under the revolving credit
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Table of Contentsfacility bear interest at either (i) the higher of the Federal Funds Open Rate plus 50 basis points or PNC Bank’s base commercial lending rate (7.25% at December 31, 2007) or (ii) LIBOR plus 200 basis points (6.9% at December 31, 2007). Those rates may increase by up to 50 basis points for LIBOR loans or up to 25 basis points for domestic rate loans if our fixed charge coverage ratio falls below certain targets. A fee of 25 basis points is applied to the available borrowing capacity. The available borrowing capacity was $85.4 million as of December 31, 2007. 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, 2007, we had a loan balance of $9.6 million under the Revolving Credit and Security Agreement, and an additional $5.0 million of the total capacity had 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 completely and terminate the obligations under the Revolving Credit and Security Agreement, we would be liable for a prepayment penalty. As of December 31, 2006, approximately $27.8 million was outstanding under this revolving credit facility and $3.2 million of the total capacity had 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 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. Events of default would include a change in control and any change in our operations or condition, which has a material adverse effect. As of December 31, 2007, the Company was in compliance with all debt covenants. In September 2006, the Agreement was amended to increase the 2006 net capital expenditure limitation to $125 million and $40 million in subsequent years, but those amounts are increased by permitted equity issuance proceeds and the unused amounts can be carried over to the next fiscal year. For 2007, the net capital expenditure limitation was approximately $71 million. Capital expenditures for 2007 were approximately $68.1 million, of which $63.3 million was drilling equipment. For 2008, the net capital expenditure limitation is approximately $43 million. Current portion of other obligations at December 31, 2006 consists of financed annual insurance premiums. The interest rate on these borrowings was 6.3%. This debt was repaid over 11 months in 2007. In December 2007, we started using excess borrowing capacity on our revolving credit facility to finance the insurance premiums. In addition, the Company has entered into various equipment-specific financing agreements with several third-party financing institutions. The terms of these agreements range from 36 to 60 months. As of December 31, 2007, the total outstanding balance under these arrangements, including principal and interest, was approximately $8.3 million. The interest rate on these borrowings ranges from 3.5% to 7.6%. 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, 2007 (in thousands):
The Company paid approximately $2.7 million, $2.3 million and $2.7 million in interest on all debt during 2007, 2006 and 2005, respectively.
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At December 31, 2007, the number of authorized shares of common stock was 75,000,000 shares, of which 21,974,884 shares were outstanding, and 1,955,533 shares were reserved for future issuance through the Company’s stock option plans. The number of authorized shares of preferred stock was 100,000 shares at December 31, 2007. No shares of preferred stock were outstanding or reserved for future issuance. 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 $55.4 million in proceeds, net of underwriting discounts, commissions, and offering expenses. In connection with the offering, the Company repaid approximately $51.3 million of outstanding debt and approximately $4.0 million to upgrade their drilling rig fleet and purchase of related equipment. In October 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.
Stock Option Plans The Company has two stock option plans, the Amended 2005 Stock Option Plan and the Amended and Restated 2000 Stock Option Plan. Under each plan, 1,579,552 shares of the Company’s common stock have been authorized for awards of stock options. As of December 31, 2007, 761,775 options have been granted under the Amended 2005 Stock Option Plan and 1,548,124 options have been granted under the Amended and Restated 2000 Stock Option Plan. In addition, 132,958 options were granted outside the plans in 1999. Stock options are granted with an exercise price equal to the fair market value on the grant date, which is determined by the closing trading price of our common stock on the Nasdaq Global Market. Prior to the Company’s IPO in November 2005, the exercise price of stock options were based on the Board of Directors’ assessment of the fair market value of the stock at the time the options were granted. Options typically vest in four equal annual installments from the grant date, depending on the terms of the grant, and expire on the tenth anniversary of the grant date. Stock option activity for all options was as follows:
Cash received from the exercise of options for the years ended December 31, 2007, 2006 and 2005, was $2.5 million, $1.4 million and $3.8 million, respectively. New shares of common stock are issued to satisfy options exercised. The total intrinsic value of options exercised during 2007 and 2006 was $4.6 million and $3.9 million, respectively.
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Table of ContentsA summary of options outstanding as of December 31, 2007, is as follows:
The aggregate intrinsic value of options exercisable as of December 31, 2007 was $2.6 million. The weighted average remaining contractual life of options exercisable as of December 31, 2007 was 4.6 years. A summary of nonvested option activity was as follows:
The total fair value of options vested during the year ended December 31, 2007 was $1.0 million. The following table summarizes additional information as of December 31, 2007 for fully vested options and options expected to vest:
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 $479,000, $321,000 and $210,000 during the years ended December 31, 2007, 2006 and 2005, respectively. Contingent Management Compensation The Company’s Chief Executive Officer (“CEO”) 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”), our principal stockholder. 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 CEO is 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 the CEO at fair market value, which includes consideration of the threshold amount in the determination of that value, upon his termination of employment by the Company. Further, the rights may be repurchased from the CEO for no consideration upon voluntary termination or upon termination of employment by the Company for cause.
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Table of ContentsAt December 31, 2007 and 2006 the threshold amounts were $32.0 million and $29.1 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. In 2007 and 2005, $26,000 and $753,000 of compensation costs was recognized as a result of the fair value of the assets owned by UDC exceeding the threshold. In 2006, the Company recognized $546,000 of compensation cost reversals, primarily due to the voluntary termination of a previous Company participant and the repurchase of such participant’s rights for no consideration. All compensation costs related to these rights are classified as general and administrative expense. As UDC is responsible for the cash settlement of these awards, the offsetting balance is recorded as additional paid in capital. The defined participants in this arrangement would be entitled to up to 22.5% of the value realized in excess of the threshold amount. The CEO is entitled to approximately 1% of the 22.5%. Changes in our stock price can affect the compensation expense. In addition, the Company recognized approximately $35,000 in compensation costs during 2005 related to variable stock options issued.
The following table presents a reconciliation of the numerators and denominators of the basic earnings per share and diluted earnings per share computations as required by SFAS No. 128:
The weighted average number of dilutive shares in 2007 excludes 115,000 options due to their antidilutive effects.
Operating Leases The Company leases certain buildings, automobiles, office equipment and phone services under noncancelable operating agreements. Lease expense was approximately $2.1 million, $1.8 million and $1.1 million for the years ended December 31, 2007, 2006 and 2005, respectively. As of December 31, 2007, future minimum lease payments under noncancelable operating leases consist of the following (in thousands):
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Table of ContentsLitigation The Company is currently a party to a lawsuit, brought originally in the United States District Court for the Western District of Arkansas, to determine certain contractual indemnification rights and the insurance coverage applicable as a result of a job-related accident in which a rig worker was fatally injured. On August 13, 2007, the District Court issued a judgment in this case. This judgment was partially against the Company and partially in its favor. The District Court held that the Company had a contractual obligation to indemnify the lease operator in the amount of $500,000. In turn, the District Court also held that the Company take judgment against the insurer in the amount of $500,000. This judgment was appealed by the insurer and, consequently, the Company determined to join the appeal. Management believes the Company has meritorious arguments in support of its position and the Company intends to vigorously defend this matter. The Company has various other pending claims, lawsuits, disputes with third parties, investigations and actions incidental to its business operations. Although occasional adverse settlements or resolutions may occur and negatively impact its earnings in the period or year of settlement, it is management’s belief that their ultimate resolution will not have a material adverse effect on the Company’s financial condition or liquidity.
The following table sets forth unaudited financial results on a quarterly basis for each of the last two years (in thousands, except per share amounts):
On January 4, 2008, the Company entered into an agreement with IDM Equipment, LLC (“IDM”) to purchase one 1600hp AC Fast Moving Quicksilver Drilling System, together with related equipment (the “Rig”). The aggregate purchase price for the Rig and certain additional related equipment, including, among other things, a top drive, an air circulation system and tubulars, is approximately $17 million. The Rig is scheduled for delivery to the Company on or before May 31, 2008. The Company intends to deploy the Rig for an existing customer’s drilling program in the Appalachian Basin.
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None
Evaluation of Disclosure Controls and Procedures. As of the end of the period covered by this report, we carried out an evaluation, under the supervision and with the participation of management, including our Chief Executive Officer and Chief Financial Officer, of the effectiveness of our disclosure controls and procedures (as defined in 13a-15(e) of the Securities Exchange Act of 1934, or the Exchange Act). Based on that evaluation, our Chief Executive Officer and our Chief Financial Officer concluded that our disclosure controls and procedures are effective. Management’s Report on Internal Control over Financial Reporting. The report of our management regarding internal control over financial reporting is set forth in Item 8 of this Annual Report on Form 10-K under the caption “Management Report on Internal Control over Financial Reporting” and is incorporated herein by reference. Attestation Report of Independent Registered Public Accounting Firm. The attestation report of our independent registered public accounting firm regarding internal control over financial reporting is set forth in Item 8 of this Annual Report on Form 10-K under the caption “Report of Independent Registered Public Accounting Firm Report on Internal Control over Financial Reporting” and is incorporated herein by reference. 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, 2007 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.
None. 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 2008 Annual Meeting of Stockholders. We intend to file our definitive proxy statement with the SEC by April 29, 2008.
We have a Code of Ethics that applies to our directors and all employees including our principal executive officer, principal financial officer, principal accounting officer and persons performing similar functions. Our Code of Ethics is posted in the “Investor Relations” section on our website at http://www.uniondrilling.com. The other information required in response to this Item will be set forth in our definitive proxy statement for our 2008 Annual Meeting of Stockholders and is incorporated herein by reference.
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The information required in response to this Item will be set forth in our definitive proxy statement for our 2008 Annual Meeting of Stockholders and is incorporated herein by reference.
The information required in response to this Item will be set forth in our definitive proxy statement for our 2008 Annual Meeting of Stockholders and is incorporated herein by reference.
The information required in response to this Item will be set forth in our definitive proxy statement for our 2008 Annual Meeting of Stockholders and is incorporated herein by reference.
The information required in response to this Item will be set forth in our definitive proxy statement for our 2008 Annual Meeting of Stockholders and is incorporated herein by reference.
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Table of ContentsPART IV
1. Financial Statements. See Index to Financial Statements on page 33. 2. Financial Statement Schedules: All financial statement schedules have been omitted because they are not applicable or the required information is presented in the financial statements or the notes to the financial statements. (b) Exhibits. A list of exhibits required by Item 601 of Regulation S-K and to be filed as part of this report is set forth in the Index to Exhibits beginning on page 62, which immediately precedes such exhibits.
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Table of ContentsSIGNATURES Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.
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Table of ContentsUNION DRILLING, INC. INDEX TO EXHIBITS
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