10-K 1 file1.htm

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D. C. 20549

FORM 10-K

(Mark one) [X]  ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 2006
[ ]  TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

Commission File Number: 000-51630

UNION DRILLING, INC.

(Exact name of registrant as specified in its charter)


DELAWARE
(State or other jurisdiction
of incorporation or organization)		 16-1537048
(I.R.S. Employer
Identification Number)
4055 International Plaza
Suite 610
Fort Worth, Texas
(Address of principal executive offices)		 76109
(Zip Code)

Registrant’s telephone number, including area code: 817-735-8793

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


Common Stock, $0.01 Par Value NASDAQ Global Market
(Title of each class) (Name of each exchange on which registered)

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 or a non-accelerated filer. See definition of ‘‘accelerated filer and large accelerated filer’’ in Rule 12b-2 of the Exchange Act. (Check one):


Large accelerated filer [ ] Accelerated filer [X] Non-accelerated filer [ ]

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 the last business day of June 30, 2006, the registrant’s most recently completed second fiscal quarter, was $198,511,723 based on the last sales price of the registrant’s common stock reported on the NASDAQ Global Market on that date. 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 March 8, 2007, there were 21,534,372 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 2007 Annual Meeting of Stockholders to be held on June 12, 2007, 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 Contents

TABLE OF CONTENTS


PART I 1
Item 1. Business 1
Item 1A. Risk Factors 14
Item 2. Properties 20
Item 3. Legal Proceedings 20
Item 4. Submission of Matters to a Vote of Security Holders 20
PART II 21
Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities 21
Item 6. Selected Financial Data 23
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations 24
Item 7A. Quantitative and Qualitative Disclosures About Market Risk 34
Item 8. Financial Statements and Supplementary Data 35
Item 9. Changes in and Disagreements With Accountants on Accounting and Financial Disclosure 59
Item 9A. Controls and Procedures 59
Item 9B. Other Information 59
PART III 60
Item 10. Directors, Executive Officers and Corporate Governance 60
Item 11. Executive Compensation 60
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters 60
Item 13. Certain Relationships and Related Transactions, and Director Independence 60
Item 14. Principal Accountant Fees and Services 60
PART IV 61
Item 15. Exhibits and Financial Statement Schedules 61

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PART I

In this Annual Report, ‘‘Union’’ or the ‘‘company,’’ ‘‘we,’’ ‘‘us’’ and ‘‘our’’ refer to Union Drilling Inc., and our wholly owned subsidiaries. Statements we make in this Annual Report 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.

Item 1.    Business

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 a predecessor that was providing contract drilling services under the name ‘‘Union Drilling.’’ Through a combination of acquisitions and new rig construction, we have increased the size of our fleet to 76 land drilling rigs, of which 70 are marketed and six are stacked. We have focused our operations in selected natural gas production regions in the U.S. We do not invest in oil and natural gas properties. The drilling activity of our customers is highly dependent on the current price of oil and natural gas.

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. These geological basins are generally characterized by unconventional natural gas formations with very low permeability rock, such as tight sands and shales, and coal seams with coal bed methane, or CBM, deposits.

Substantially all of our rigs operate in unconventional natural gas producing areas, where specialized drilling techniques are required to develop unconventional natural gas resources efficiently. Horizontal drilling is a specialized drilling technique intended to increase the exposure of the wellbore to the natural gas producing formation and increase drainage rates and production volumes. We have equipped 48 of our 76 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 43 of our 76 rigs with air compression systems to provide underbalanced drilling, which results in higher penetration rates through hard rock formations when compared to traditional fluid-based circulation systems. In response to rising demand from our customers for equipment that is capable of drilling wells horizontally into unconventional natural gas formations and providing underbalanced drilling services, we have increased our fleet of drilling rigs capable of efficiently serving these markets through acquisitions and new rig construction.

We completed several transactions in 2006 and 2005 that enhanced 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 are targeting the Barnett Shale formation in the Fort Worth Basin. In June 2005 and August 2005, we acquired six more rigs, five of which target the Barnett Shale formation in the Fort Worth Basin. During 2006, we continued to add newly constructed rigs to our fleet to capitalize on our customers’ rapidly growing unconventional resource exploration and development activity. These transactions substantially expanded our unconventional natural gas contract drilling operations beyond our traditional markets in the Appalachian Basin and the Rocky Mountains.

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Our markets

Appalachian Basin

We provide drilling services to customers engaged in developing unconventional natural gas formations throughout the Appalachian Basin. The Appalachian Basin is one of the largest hydrocarbon producing regions in North America, covering approximately 72,000 square miles in the states of Kentucky, New York, Ohio, Pennsylvania, Tennessee, Virginia and West Virginia.

The Appalachian Basin is characterized by highly porous sandstones alternating with less porous shales, at depths of 3,000 to 6,000 feet. Since the mid 1970’s, significant resources have been committed to developing the natural gas bearing Clinton/Medina sands in northwestern Pennsylvania, western New York and eastern Ohio. The Clinton/Medina sands, which are 4,000 to 6,000 feet in depth, generally have very low porosities and permeabilities. To recover natural gas from this formation, fracturing techniques are used to increase permeability, allowing the natural gas to flow to the surface. More recently, producers have been increasing capital spending focused on the development of the deeper Trenton/Black River formations, which are at depths approaching 10,000 feet. Deeper Trenton/Black River wells are vertically drilled on air in an underbalanced state prior to drilling a several thousand foot horizontal section in the formation on fluid. These wells are typically significantly more prolific than more conventional Clinton/Medina wells, with initial production rates ranging from 10 to 20 Mmcf/day and gross reserves per well ranging from 8 to 10 Bcf. Most of the equipment in the Appalachian Basin capable of drilling Trenton/Black River wells is owned and operated by Union.

Natural gas also is found in shallow coal seams throughout the Appalachian Basin, which is commonly referred to as CBM. In recent years, natural gas producers have begun to exploit these CBM formations due to advances in extraction technology and higher energy prices. In addition to exploration and development activity on behalf of more traditional natural gas producers, coal companies have engaged in the development of CBM formations in order to reduce the concentration of these deposits in advance of mining operations, reducing the risk of underground fires or explosions. We support each of these activities with rigs that drill horizontally into the coal seams, providing faster drainage than vertical drilling. We also have rigs that work for coal companies in advance of coal mining operations to extract metal casing and other materials from existing wells to reduce the possibility of underground fires or explosions during mining.

We market 31 drilling rigs and store five stacked rigs in the Appalachian Basin. The following table sets forth certain information with respect to each of these marketed rigs as of March 1, 2007.


Rig No. Drilling Capability Current Activity
Horizontal Underbalanced Type Contract Play
15   X Vertical Daywork Devonian(3)
53 X X Horizontal Daywork CBM(1)
55 X X Horizontal Daywork CBM
56 X X Vertical Daywork CBM
57 X X Horizontal Daywork CBM
5   X Vertical Footage Clinton(2)
24   X Vertical Footage Clinton
25   X Vertical Footage Clinton
34   X Vertical Footage Clinton
35   X Vertical Footage Clinton
36   X Vertical Footage Clinton
37   X Vertical Footage Clinton
39 X X Vertical Daywork CBM
46 X X Vertical Daywork Devonian
51 X X Horizontal Daywork Oriskany(4)

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Rig No. Drilling Capability Current Activity
Horizontal Underbalanced Type Contract Play
21 X X Horizontal Daywork TBR(5)
43 X X Horizontal Daywork TBR
48 X X Horizontal Daywork TBR
52 X X Horizontal Daywork TBR
54 X X Horizontal Daywork TBR
1     Coal(6) Daywork N/A
2     Coal Daywork N/A
8     Coal Daywork N/A
10     Coal Daywork N/A
18     Coal Daywork N/A
20 X X Coal Daywork N/A
31     Coal Daywork N/A
41     Coal Daywork N/A
42     Coal Daywork N/A
3 X X Available for service but inactive
14   X Available for service but inactive
(1) Coalbed methane development.
(2) Clinton/Medina development.
(3) Devonian development.
(4) Oriskany development.
(5) Trenton/Black River exploration and development.
(6) Re-drilling and plugging operations in advance of long wall coal mining.

Our principal competitors in the Appalachian Basin are primarily smaller, family-owned companies that serve fragmented markets within the Appalachian Basin. In the last two years, we have witnessed a significant increase in acquisitions and divestitures of oil and gas properties in the Appalachian Basin, which we believe to be directly attributable to the appreciation of natural gas prices over the same period of time and the corresponding improvement in the economics of producing natural gas. Acquisition activity has been driven by a broad universe of buyers, comprised of both publicly-traded independent oil and natural gas companies who have actively sought to expand their operations in the region, and a number of financial investors who have shown an active interest in the region. We believe that the recent buyers of oil and natural gas properties in the region intend to increase the level of drilling activity on the properties which they have acquired in an effort to enhance the return on the capital invested in the acquisition of the property. We believe the increased level of acquisition activity should produce an acceleration of drilling activity in the Appalachian Basin that will inure to our benefit. However, some of these recent buyers of oil and natural gas properties in the Appalachian Basin have elected to add their own in-house drilling capability. Much of that capability was achieved by acquiring previously independent drilling contractors in the Appalachian Basin, some of which were our competitors.

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.

Recently, operators have been leasing acreage to develop shallower natural gas-bearing formations known as the Fayetteville Shale on the Arkansas side and the Caney and Woodford Shales on the Oklahoma side of the Arkoma Basin. These Mississippian age formations, existing at depths of 1,500 to 6,500 feet, are geologically similar to the Barnett Shale formation in northern Texas. Within the Fayetteville Shale, two producers have amassed substantial acreage positions and have recently

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commenced 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.

Currently, the majority of our rigs in the Arkoma Basin are drilling horizontally into the Hartshorne coal seam, which is found at depths of 300 to 4,000 feet throughout the Arkoma Basin. Unlike CBM plays in other parts of the U.S., the Hartshorne coal seams produce very little water and allow for rapid production of CBM after a well is completed. The typical CBM well we drill in this market is 2,500 to 3,000 feet deep with a horizontal section of similar length. While this play began with vertical drilling, it is now almost exclusively drilled horizontally.

We market 19 drilling rigs in the Arkoma Basin. The following table sets forth certain information with respect to each of these rigs as of March 1, 2007.


  Drilling Capability Current Activity
Rig No. Horizontal Underbalanced Type Contract Play
38 X X Horizontal Daywork CBM(2)
40 X X Horizontal Daywork CBM
104 X X Horizontal Daywork Caney(1)
105 X X Horizontal Daywork CBM
108 X X Horizontal Daywork CBM
109 X X Vertical Daywork CBM
114 X X Horizontal Daywork CBM
115 X X Horizontal Daywork CBM
117   X Vertical Footage CBM
119 X X Vertical Daywork CBM
110 X X Vertical Daywork Conventional(3)
112 X X Vertical Daywork Conventional
116 X X Vertical Daywork Conventional
121 X X Horizontal Daywork Fayetteville(4)
122 X X Horizontal Daywork Fayetteville
123 X X Horizontal Daywork Fayetteville
7 X X Vertical Daywork Fayetteville
45 X X Vertical Daywork Fayetteville
47 X X Vertical Daywork Fayetteville
(1) Caney Shale exploration and development.
(2) Coalbed methane development.
(3) Conventional Arkoma Basin development.
(4) Fayetteville Shale exploration and development.

Our principal competitor in the Arkoma Basin is Nabors Industries Inc.

Northern Texas

The Barnett Shale formation, found near Fort Worth, Texas, at average depths of 6,500 to 8,500 feet, is the largest natural gas field in Texas. Although natural gas deposits were discovered in the Barnett Shale several decades ago, the technology necessary to economically exploit lower permeability reservoir rock was not available. The use of horizontal drilling to develop the formation, combined with the application of multi-stage fracturing techniques, has opened this formation to extensive drilling.

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We market 19 drilling rigs and store one stacked rig in northern Texas. The following table sets forth certain information with respect to each of these marketed rigs as of March 1, 2007.


  Drilling Capability Current Activity
Rig No. Horizontal Underbalanced Type Contract Play
205 X   Horizontal Daywork Barnett
(1)
206 X   Vertical Footage Barnett
207 X   Horizontal Daywork Barnett
209 X   Horizontal Daywork Barnett
211 X   Horizontal Daywork Barnett
212 X   Horizontal Daywork Barnett
214 X   Horizontal Daywork Barnett
33     Vertical Footage Permian
(2)
201     Vertical Footage Permian
203     Vertical Footage Permian
210     Vertical Daywork Permian
215 X   Horizontal Daywork Barnett
216 X   Horizontal Daywork Barnett
217 X   Horizontal Daywork Barnett
219 X   Horizontal Daywork Barnett
220 X   Horizontal Daywork Barnett
221 X   Horizontal Daywork Barnett
222 X   Horizontal Daywork Barnett
223 X   Horizontal Daywork Barnett
(1) Northern Texas Barnett Shale development.
(2) Eastern Permian Basin oil development.

Our principal competitors in northern Texas are Patterson-UTI and Nabors Industries Inc.

The Rocky Mountains

Four of our five drilling rigs previously deployed in the Rocky Mountains have been relocated to other basins in the U.S., primarily eastern Arkansas. Several of these rigs are currently being refurbished.

Our remaining rig in the Rocky Mountains is currently operating in Idaho on a geothermal project. Once this project is completed, this rig will most likely be relocated to eastern Arkansas.

The following table sets forth certain information with respect to the remaining rig in this basin as of March 1, 2007.


  Drilling Capability Current Activity
Rig No. Horizontal Underbalanced Type Contract Play
32 X X Horizontal Daywork Idaho(1)
(1) Geothermal project in Idaho.

Customers and marketing

Our customers are principally independent natural gas producers. We market our drilling rigs primarily on a regional basis, through employee marketing representatives. Repeat business from previous customers accounts for a substantial portion of our business. Traditionally, our rigs have been contracted on a well by well basis. With the recent strengthening of market conditions, however, we are witnessing a shift in contract terms towards longer duration contracts.

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Our drilling rigs are also used to a lesser extent by coal and regulated natural gas storage companies to plug old wells. We also have occasionally drilled for potash, salt and other chemicals as well as provided underground sequestration of carbon dioxide produced by coal fired power plants.

We market our rigs to a number of customers. In 2006, we drilled wells for 148 different customers, compared to 112 customers in 2005 and 55 customers in 2004. 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.


Year Customer Total Contract Drilling
Revenue Percentage
2006 XTO Energy 11.5
%
  CNX/Consol 6.2
%
  Fortuna 5.4
%
  Total 23.1
%
2005 Consol 9.3
%
  Fortuna 6.6
%
  Great Lakes Energy 5.9
%
  Total 21.8
%
2004 Fortuna 16.3
%
  Consol 14.3
%
  Columbia Natural Resources 12.6
%
  Total 43.2
%

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 2006, approximately 81% of our revenues were derived from daywork contracts. Most of the wells we drilled pursuant to footage contracts were drilled in our Northern Appalachian region. Contract terms we offer generally depend on the complexity and risk of operations, the on-site drilling conditions, the type of equipment used and the anticipated duration of the work to be performed. Our contracts generally provide for the drilling of a single well or a series of wells and typically permit the customer to terminate on short notice.

Daywork contracts.    Under daywork contracts, we provide a drilling rig with required personnel to the operator, who supervises the drilling of the well. We are paid based on a negotiated fixed rate per day while the rig is utilized. The rates for our services depend on market and competitive conditions, the nature of the operations to be performed, the duration of the work, the equipment and services to be provided, the geographic area involved and other variables. Lower rates may be paid when the rig is in transit or when drilling operations are interrupted or restricted by conditions beyond our control. In addition, daywork contracts typically provide for a separate amount to cover the cost of mobilization and demobilization of the drilling rig. Daywork drilling contracts generally specify the type of equipment to be used, the size of the hole and the depth of the well. Under a daywork drilling contract, the customer bears a large portion of out-of-pocket costs of drilling and we generally do not bear any part of the usual capital risks associated with oil and natural gas exploration.

Footage contracts.    Under footage contracts, we are paid a fixed amount for each foot drilled, regardless of the time required or the problems encountered in drilling the well. We pay more of the out-of-pocket costs associated with footage contracts compared to daywork contracts. We provide technical expertise and engineering services, as well as most of the equipment required for the well, and are compensated when the contract terms have been satisfied. Many of our footage contracts now provide for conversion to daywork rates under certain specified unexpected conditions.

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The risks under footage contracts are greater than under daywork contracts because we assume more of the risks associated with drilling operations generally assumed by the operator in a daywork contract, including risk of blowout, loss of hole, lost or damaged drill pipe, machinery breakdowns, abnormal drilling conditions and risks associated with subcontractors’ services, supplies, cost escalation and personnel. Historically, the percentage of revenues derived from footage contracts has decreased from over 50% in the early 2000’s to approximately 19% currently. We expect this percentage to decline further in the future. During 2006, only fourteen of our 76 rigs worked on a footage basis. Many of our footage contracts now have provisions whereby some or all of the risks associated with geological issues and down hole mechanical matters have been shifted to our customers. The transfer of this risk is done by contractually transferring the drilling services from a footage drilled basis to an hourly based daywork type contract when unforeseen or uncontrollable events are encountered during the drilling process. When this occurs, the contract also provides for the transfer of third party costs and tangible items such as drill bits from us to our customers during these unforeseen problematic periods.

Our rig fleet

General

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

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

Derrick hookload capacity and rig horsepower are the main drivers of depth rating on a vertical rig. They determine a rig’s ability to lower, hoist and suspend casing and drilling pipe weight in the wellbore. Relative to total measured depth, horizontal wells have lower requirements on hookload and horsepower because casing, which is used to isolate the natural gas bearing formation from other geological features, is not run into the horizontal section of the well and once drill pipe is laying horizontally, its suspended weight and the power required to raise it decreases compared to a vertical wellbore of the same length. Circulating systems, which can be based on either fluid or compressed air, are used while drilling to evacuate cuttings and prevent the pipe from becoming stuck in the wellbore. Relative to vertical wells of the same measured depth, horizontal wells require greater circulating capability to move the cuttings from the horizontal section through a 90 degree curve to the initial vertical section of the wellbore.

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.

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Our rigs are mechanical, truck-mounted or portable, equipped for fluid and air drilling and capable of year-round operations. These configurations give us the ability to drill virtually all types of wells drilled in our markets. Due to the geologic characteristics in our markets, most of the wells drilled in these areas utilize air drilling. We believe that air drilling provides advantages over traditional drilling techniques when drilling through hard rock formations. These advantages include improved drilling penetration rates, limited amount of fluids lost into the formation and minimized formation damage. We believe that we have drilled more wells using air drilling techniques than any other U.S. contractor. We also own various vehicles and other ancillary equipment used in the operation of our rigs. This equipment consists of bulldozers, trucks and other support equipment.

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

Competition

We encounter substantial competition from other drilling contractors. Our primary market areas are highly fragmented and competitive. The fact that drilling rigs are mobile and can be moved from one market to another in response to market conditions heightens the competition in the industry. Our principal competitors vary by region. See ‘‘— Our markets.’’

We believe rig capability, pricing and rig availability are the primary factors our potential customers consider in determining which drilling contractor to select. In addition, we believe the following factors are also important:

•  the mobility and efficiency of the rigs;
•  the safety records of the rigs;
•  crew experience and skill;
•  customer relationships;
•  the offering of ancillary services; and
•  the ability to provide drilling equipment adaptable to, and personnel familiar with, new technologies and drilling techniques.

While we must be competitive in our pricing, our 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:

•  better withstand industry downturns;
•  compete more effectively on the basis of price and technology;
•  better retain skilled rig personnel; and
•  build new rigs or acquire and refurbish existing rigs so as to be able to place rigs into service more quickly than us in periods of high drilling demand.

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Raw materials

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

Seasonality

Certain of our operations in the Appalachian Basin are conducted in areas subject to extreme weather conditions and often in difficult terrain. During certain parts of the year, primarily in the winter and the spring, our operations are often hindered because of cold, snow or muddy conditions. Certain state and local governments impose restrictions on the movement of our equipment during parts of the year when the roads are susceptible to damage from the movement of heavy equipment. These restrictions are known as ‘‘frost laws’’. Our operations are also limited from time to time by the practical difficulty of operating in certain weather conditions.

In the southern Appalachian Basin, our operations are limited primarily by winter weather in the fourth quarter and the first quarter. In the northern Appalachian Basin, our operations are limited primarily by the frost laws, in the first quarter and the second quarter.

Employees

We currently have approximately 1,515 employees. Approximately 195 of these employees are salaried administrative or supervisory employees. The rest of our employees are hourly employees who operate or maintain our drilling rigs and rig-hauling trucks. The number of hourly employees fluctuates depending on the number of drilling projects we are engaged in at any particular time. None of our employment arrangements are subject to collective bargaining arrangements.

Operating hazards and insurance

Our operations are subject to many hazards inherent in the land drilling business, including, for example, blowouts, craterings, fires, explosions, loss of well control, poisonous gas emissions, loss of hole, damaged or lost drill strings, and damage or loss from inclement weather. These hazards could cause personal injury or death, serious damage to or destruction of property and equipment, suspension of drilling operations, or substantial damage to the environment, including damage to producing formations and surrounding areas. Generally, we seek to obtain indemnification from our customers by contract for some of these risks. To the extent not transferred to customers by contract, we seek protection against some of these risks through insurance, including property casualty insurance on our rigs and drilling equipment, commercial general liability, which has coverage extension for underground resources and equipment coverage, commercial contract indemnity, commercial umbrella and workers’ compensation insurance.

Our insurance coverage for property damage to our rigs and drilling equipment is based on our estimate of the cost of comparable used equipment to replace the insured property. There is a deductible of $100,000 per occurrence on rigs and equipment. Our third party liability insurance coverage under the general liability policy is $1 million per occurrence, with a self-insured retention of $10,000 per occurrence. The commercial umbrella policy coverage is $20 million per occurrence, with a self-insured retention of $10,000 per occurrence. We also carry Contractor Pollution Liability insurance with $2,000,000 limitation per claim and a self-insured retention of $50,000. 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.

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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 maintain a $100,000 deductible for each accident.

Government regulation and environmental matters

General

Our operations are affected from time to time and in varying degrees by political developments and federal, state and local environmental, health and safety laws and regulations. In particular, oil and natural gas production, operations and economics are or have been affected by price controls, taxes and other laws relating to the oil and natural gas industry, by changes in such laws and by changes in administrative regulations. Although significant capital expenditures may be required to comply with such laws and regulations, to date, such compliance costs have not had a material adverse effect on our earnings or competitive position. In addition, our operations are vulnerable to risks arising from the numerous laws and regulations governing the discharge of materials into the environment or otherwise relating to environmental protection.

Environmental regulation

Our activities are subject to existing federal, state and local laws and regulations governing environmental quality, pollution control and the preservation of natural resources. These laws and regulations concern, among other things, air emissions, the containment, disposal and recycling of waste materials, and reporting of the storage, use or release of certain chemicals or hazardous substances. Numerous federal and state environmental laws regulate drilling activities and impose liability for discharges of waste or spills, including those in coastal areas. We have conducted drilling activities in or near ecologically sensitive areas, such as wetlands and coastal environments, which are subject to additional regulatory requirements. State and federal legislation also provide special protections to animal and aquatic life that could be affected by our activities. In general, under various applicable environmental programs, we may potentially be subject to regulatory enforcement action in the form of injunctions, cease and desist orders and administrative, civil and criminal penalties for violations of environmental laws. We may also be subject to liability for natural resource damages and other civil claims arising out of a pollution event.

Except for the handling of solid wastes directly generated from the operation and maintenance of our drilling rigs, such as waste oils and wash water, it is our practice to require our customers to contractually assume responsibility for compliance with environmental regulations. Laws and regulations protecting the environment have become more stringent in recent years, and may, in some circumstances, impose strict liability, rendering a person liable for environmental damage without regard to negligence or fault on the part of that person. These laws and regulations may expose us to liability for the conduct of or conditions caused by others, or for our own acts that were in compliance with all applicable laws at the time the acts were performed. The application of these requirements or adoption of new requirements could have a material adverse effect on us.

Environmental regulations that affect our customers also have an indirect impact on us.

Increasingly stringent environmental regulation of the oil and natural gas industry has led to higher drilling costs and a more difficult and lengthy well permitting process. The primary environmental statutory and regulatory programs that affect our operations include the following:

Oil Pollution Act and Clean Water Act.    The Oil Pollution Act of 1990, or OPA, amends several provisions of the federal Water Pollution Control Act of 1972, which is commonly referred to as the Clean Water Act, or CWA, and other statutes as they pertain to the prevention of and response to spills or discharges of hazardous substances or oil into navigable waters. Under the OPA, a person owning or operating a facility or equipment (including land drilling equipment) from which there is a discharge or threat of a discharge of oil into or upon navigable waters and adjoining shorelines is

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liable, regardless of fault, as a ‘‘responsible party’’ for removal costs and damages. Federal law imposes strict, joint and several liability on facility owners for containment and clean-up costs and some other damages, including natural resource damages, arising from a spill. The U.S. Environmental Protection Agency, or EPA, is also authorized to seek preliminary and permanent injunctive relief, civil or administrative fines or penalties and, in some cases, criminal penalties and fines. State laws governing the control of water pollution also provide varying civil and criminal penalties and liabilities in the case of releases of petroleum or its derivatives into surface waters or into the ground. In the event that a discharge occurs at a well site at which we are conducting drilling operations, we may be exposed to claims under the CWA or similar state laws.

Some of our operations are also subject to EPA regulations that require the preparation and implementation of spill prevention control and countermeasure, or SPCC, plans to address the possible discharge of oil into navigable waters. Where so required, we have SPCC plans in place.

Superfund

The Comprehensive Environmental Response, Compensation, and Liability Act, as amended, also known as CERCLA or the ‘‘Superfund’’ law, imposes liability, without regard to fault or the legality of the original conduct, on certain classes of persons with respect to the release of a ‘‘hazardous substance’’ into the environment. These persons include (i) the current owner and operator of a facility from which hazardous substances are released, (ii) owners and operators of a facility at the time any hazardous substances were disposed, (iii) generators of hazardous substances who arranged for the disposal or treatment at or transportation to such facility of hazardous substances and (iv) transporters of hazardous substances to disposal or treatment facilities selected by them. We may be responsible under CERCLA for all or part of the costs to clean up sites at which hazardous substances have been released. To date, however, we have not been named a potentially responsible party under CERCLA or any similar state Superfund laws.

Hazardous waste disposal

Our operations involve the generation or handling of materials that may be classified as hazardous waste and subject to the federal Resource Conservation and Recovery Act and comparable state statutes. The EPA and various state agencies have limited the disposal options for some hazardous and nonhazardous wastes and is considering the adoption of stricter handling and disposal standards for nonhazardous wastes. We believe that our operations are in material compliance with applicable environmental laws and regulations.

Health and safety matters

Our facilities and operations are also governed by laws and regulations, including the federal Occupational Safety and Health Act, or OSHA, relating to worker health and workplace safety. As an example, the Occupational Safety and Health Administration has issued the Hazard Communication Standard, or HCS, requiring employers to identify the chemical hazards at their facilities and to educate employees about these hazards. HCS applies to all private-sector employers, including the oil and natural gas exploration and producing industry. HCS requires that employers assess their chemical hazards, obtain and maintain written descriptions of these hazards, develop a hazard communication program and train employees to work safely with the chemicals on site. Failure to comply with the requirements of the standard may result in administrative, civil and criminal penalties. We believe that appropriate precautions are taken to protect employees and others from harmful exposure to materials handled and managed at our facilities and that we operate in substantial compliance with all OSHA regulations.

Available Information

We were incorporated in the State of Delaware in December, 1997. Our principal executive offices are located at 4055 International Plaza, Suite 610, Fort Worth, Texas 76109. Our telephone number is 817-735-8793.

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We file annual, quarterly and current reports, proxy statements and other information with the Securities and Exchange Commission, or SEC. You may read and copy our reports, proxy statements and other information at the SEC’s public reference room at Room 1024, 450 Fifth Street N.W., Washington, D.C. 20549. You can request copies of these documents by writing to the SEC and paying a fee for the copying cost. Please call the SEC at 1 800-SEC-0330 for more information about the operation of the public reference room. Our SEC filings are also available at the SEC’s web site at www.sec.gov. In addition, you can read and copy our SEC filings at the office of the National Association of Securities Dealers, Inc. at 1735 K Street N.W., Washington, D.C. 20006.

You may obtain a free copy of our annual reports on Form 10-K, quarterly reports on Form 10-Q and current reports on Form 8-K and amendments to those reports as soon as reasonably practicable after such reports have been filed with or furnished to the SEC on our website on the World Wide Web at www.uniondrilling.com or by contacting the Investor Relations Department at our corporate offices by calling 817-735-8793 or by sending an e-mail message to brektorik@uniondrilling.com. In addition, our Standards of Integrity, which includes our code of ethics for our senior officers, is available on our website.

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CAUTIONARY STATEMENT CONCERNING
FORWARD-LOOKING STATEMENTS AND RISK FACTORS

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

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

In addition, various statements that this Annual Report on Form 10-K contains, including those that express a belief, expectation or intention, as well as those that are not statements of historical fact, are forward-looking statements. Those forward-looking statements appear in Item 1 — ‘‘Business’’, Item 2 — ‘‘Properties’’ and Item 3 — ‘‘Legal Proceedings’’ in Part I of this report and in Item 5 — ‘‘Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities,’’ and in Item 7 — ‘‘Management’s Discussion and Analysis of Financial Condition and Results of Operations,’’ Item 7A — ‘‘Quantitative and Qualitative Disclosures About Market Risk’’ and in the Notes to Consolidated Financial Statements we have included in Item 8 of Part II of this report and elsewhere in this report. These forward-looking statements speak only as of the date of this report. We disclaim any obligation to update these statements, and we caution you not to rely on them unduly. We have based these forward-looking statements on our current expectations and assumptions about future events. While our management considers these expectations and assumptions to be reasonable, they are inherently subject to significant business, economic, competitive, regulatory and other risks, contingencies and uncertainties, most of which are difficult to predict and many of which are beyond our control. These risks, contingencies and uncertainties relate to, among other matters, the following:

•  general economic and business conditions and industry trends;
•  the continued strength of the contract land drilling industry in the geographic areas where we operate;
•  levels and volatility of oil and gas prices;
•  decisions about onshore exploration and development projects to be made by oil and gas companies;
•  the highly competitive nature of our business;
•  the success or failure of our acquisition strategy, including our ability to finance acquisitions and manage growth;
•  our future financial performance, including availability, terms and deployment of capital;
•  the continued availability of qualified personnel; and
•  changes in, or our failure or inability to comply with, governmental regulations, including those relating to the environment.

We believe the items we have outlined above are important factors that could cause our actual results to differ materially from those expressed in a forward-looking statement contained in this report or elsewhere. We have discussed many of these factors in more detail elsewhere in this report. These

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factors are not necessarily all the important factors that could affect us. Unpredictable or unknown factors we have not discussed in this report could also have material adverse effects on actual results of matters that are the subject of our forward-looking statements. We do not intend to update our description of important factors each time a potential important factor arises. We advise our security holders that they should (1) be aware that important factors not referred to above could affect the accuracy of our forward-looking statements and (2) use caution and common sense when considering our forward-looking statements. Also, please read the risk factors set forth below.

Item 1A.    Risk Factors

Risks Relating to Our Business

Our business and operations are substantially dependent upon, and affected by, the level of U.S. onshore natural gas exploration and development activity, which has experienced significant volatility. If the level of that activity decreases, our business and results of operations could be adversely affected.

Our business and operations are substantially dependent upon, and affected by, the level of U.S. onshore natural gas exploration and development activity. Exploration and development activity determines the demand for contract land drilling and related services. We have no control over the factors driving the level of U.S. natural gas exploration and development activity. Those factors include, among others, the following:

•  the market prices of natural gas;
•  market expectations about future prices of natural gas or oil (which is closely correlated with natural gas prices);
•  the cost of producing and delivering natural gas;
•  the capacity of the natural gas pipeline network;
•  government regulations and trade restrictions;
•  the presence or absence of tax incentives;
•  national and international political and economic conditions;
•  levels of production by, and other activities of, the Organization of Petroleum Exporting Countries and other oil and natural gas producers;
•  the levels of imports of natural gas, whether by pipelines from Canada or Mexico or by tankers in the form of LNG; and
•  the development of alternate energy sources and the long-term effects of worldwide energy conservation measures.

The onshore contract drilling industry has experienced significant volatility in profitability and asset values. The industry’s most recent significant downturn occurred in 2001 and 2002, and significantly and adversely affected our operating results. Currently, the onshore contract drilling business is experiencing increased demand for drilling services, principally due to improved oil and natural gas drilling and production economics. The increased activity in the exploration and production sector may not continue. In addition, ongoing movement or reactivation of land drilling rigs (including the movement of rigs from outside the U.S. into U.S. markets) or new construction of drilling rigs could increase rig supply and reduce contract drilling dayrates and utilization levels. We cannot predict the future level of demand for our contract drilling services, future conditions in the onshore contract drilling industry or future onshore contract drilling dayrates.

Almost 85% of our drilling rigs are more than 20 years old, and may require increasing amounts of capital to upgrade and refurbish. Any failure to continue to invest capital to upgrade and refurbish rigs could result in our having fewer rigs available for service.

Most of our drilling rigs were built during the years 1976 to 1982, which until recently was the last period of significant rig building. Our rig upgrade and refurbishment projects on marketed rigs

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typically require 60 to 90 days to complete at a cost of $175,000 to $250,000. This process includes derrick recertification, engine rebuilding or replacement and upgraded or replaced braking systems. Returning our stacked rigs to service would cost $1.5 to $2.5 million per rig for refurbishment and the purchase of drillpipe, pumps, generators and other required equipment. Depending upon the availability of equipment, this process could take from 90 to 180 days. To the extent we are unable to commence or continue such projects, we will have fewer rigs available for service, which could adversely affect our financial condition and results of operations.

In the year ended December 31, 2006, we derived approximately 23% 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, 2006, our three largest customers accounted for approximately 12%, 6% and 5%, respectively, of our total revenues. Our principal customers may not continue to employ our services and we may not be able to successfully remarket the rigs that they may choose not to employ. The loss of any of our principal customers or the failure to remarket the rigs employed by those customers could have a material adverse effect on our financial condition and results of operations.

Our historical strategy has been predicated on growing through a combination of acquisitions of rigs from third parties and the construction of new rigs. Due to increased competition among drilling contractors for additional rigs, we may not be able to continue to add rigs to our fleet, which could have an adverse effect on our ability to grow revenue and profits.

Increased levels of U.S. oil and natural gas exploration and development activity has led to increased demand for drilling services by oil and natural gas producers. This has given drilling contractors an economic incentive to build new rigs and acquire additional rigs from third parties, leading to an increase in the backlog for newly built rigs and enhanced competition for the acquisition of existing rigs. Our business and strategy could be adversely affected if we are unable to acquire newly built rigs or purchase additional drilling rigs on acceptable terms or in a timely manner.

Increased demand among drilling contractors for consumable supplies, including fuel, and ancillary rig equipment, such as pumps, valves, drillpipe and engines, may lead to delays in obtaining these materials and our inability to operate our rigs in an efficient manner.

All of our contracts provide that our customers bear the financial impact of increased fuel prices. However, prolonged shortages in the availability of fuel to run our drilling rigs resulting from action of the elements, warlike actions or other ’Force Majeure’ events could result in the suspension of our contracts and have a material adverse effect on our financial condition and results of operations. In recent months, we have experienced increased lead times in purchasing ancillary equipment for our drilling rigs. To the extent there are continued delays in being able to purchase important components for our rigs, certain of our rigs may not be available for operation or may not be able to operate as efficiently as expected, which could adversely affect our financial condition, results of operations and cash flows.

To the extent we acquire additional rigs in the future, we may experience difficulty integrating those acquisitions. Additionally, we may incur leverage to effect those acquisitions, which adds additional financial risk to our business. To the extent we incur too much leverage in undertaking acquisitions, 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 significant financial and other resources. We may not be able to successfully manage and integrate new rigs into our existing operations or successfully maintain the market share attributable to drilling rigs that we purchase. We may also encounter cost overruns related to newly constructed rigs or unexpected costs related to the acquired rigs, including costs associated with major overhauls. To the extent we experience some or all of these difficulties, our financial condition would be adversely affected.

Expanding our fleet by building new rigs or acquiring rigs from third parties may cause the company to incur additional financial leverage, increasing our debt service requirements, which could adversely affect our operating results and financial position.

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We may decide to purchase additional drilling rigs, upgrade some of our marketed drilling rigs and refurbish some of our stacked drilling rigs. Any delay could result in a loss of revenue.

We may purchase additional drilling rigs, upgrade some of our marketed drilling rigs and refurbish some of our stacked drilling rigs. All of these projects are subject to risks of delay or cost overruns inherent in large construction projects. Among those risks are:

•  shortages of equipment, materials or skilled labor;
•  long lead times or delays in the delivery of ordered materials and equipment;
•  engineering problems;
•  work stoppages;
•  weather interference;
•  unavailability of specialized services; and
•  unanticipated cost increases.

These factors may contribute to delays in the delivery of the drilling rigs, which could result in a loss of revenue. Additionally, we may incur higher costs than expected, which would adversely affect the economics of the investment in such rigs.

We have incurred losses in the past and may incur losses in the future. If we incur losses in the future, the value of our common stock could decline.

We reported net losses for the years ended December 31, 2003 and 2002 and for the three years prior to 2001. We earned net income in the years ended December 31, 2006, 2005 and 2004, but we may not be able to continue to realize profits. A lack of profitability could adversely affect the price of our common stock. In addition, if we do not remain profitable, our ability to complete future financings could be impaired, which could have an adverse effect on our business.

We may not be able to raise additional funds through public or private financings or additional borrowings, which could have a material adverse effect on our financial condition.

The contract drilling industry is capital intensive. Our cash flow from operations and the continued availability of credit are subject to a number of variables, including our rig utilization rates, operating margins and ability to control costs and obtain contracts in a competitive industry. Our cash flow from operations and present borrowing capacity may not be sufficient to fund our anticipated acquisition program, capital expenditures and working capital requirements. We may from time to time seek additional financing, either in the form of bank borrowings, sales of debt or equity securities or otherwise. To the extent our capital resources and cash flow from operations are at any time insufficient to fund our activities or repay our indebtedness as it becomes due, we will need to raise additional funds through public or private financings or additional borrowings. We may not be able to obtain any such capital resources. If we are at any time not able to obtain the necessary capital resources, our financial condition and results of operations could be materially adversely affected.

We could be adversely affected if we lost the services of certain of our officers and key employees.

The success of our business is highly dependent upon the services, efforts and abilities of Christopher D. Strong, our President and Chief Executive Officer, and certain other officers and key employees, particularly Dan Steigerwald, our Chief Financial Officer, our Division Managers and A.J. Verdecchia, our Corporate Controller. Our business could be materially and adversely affected by the loss of any of these individuals. We do not have employment agreements with or maintain key man life insurance on the lives of any of our executive officers.

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.

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Our operations could be adversely affected by abnormally poor weather conditions.

Our operations are conducted in areas subject to extreme weather conditions, and often in difficult terrain. Primarily in the winter and spring, our operations are often curtailed because of cold, snow or muddy conditions. Unusually severe weather conditions could further curtail our operations and could have a material adverse effect on our financial condition and results of operations.

Increased competition in our drilling markets could adversely affect rates and utilization of our rigs, which could adversely affect our financial condition and results of operations.

We face competition from significantly larger drilling contractors with greater resources. Their greater resources may enable them to build new rigs or move existing rigs into any of our regional markets. The addition of rigs into our markets, either by existing competitors or new entrants, including possibly non-U.S. competitors, would increase the supply of available rigs in those markets, which could adversely affect the rates we can charge and utilization levels we can achieve.

Our operations are subject to hazards inherent in the land drilling business that are beyond our control. If those risks are not adequately insured or indemnified against, our results of operations could be adversely affected.

Our operations are subject to many hazards inherent in the land drilling business, including, but not limited to:

•  blowouts;
•  craterings;
•  fires;
•  explosions;
•  equipment failures;
•  poisonous gas emissions;
•  loss of well control;
•  loss of hole;
•  damaged or lost drill strings; and
•  damage or loss from inclement weather or natural disasters.

These hazards are to some extent beyond our control and could cause, among other things:

•  personal injury or death;
•  serious damage to or destruction of property and equipment;
•  suspension of drilling operations; and
•  substantial damage to the environment, including damage to producing formations and surrounding areas.

Our insurance policies for public liability and property damage to others and injury or death to persons are in some cases subject to large deductibles and may not be sufficient to protect us against liability for all consequences of well disasters, personal injury, extensive fire damage or damage to the environment. We may not be able to maintain adequate insurance in the future at rates we consider reasonable, or particular types of coverage may not be available. The occurrence of events, including any of the above-mentioned risks and hazards, that are not fully insured against or the failure of a customer that has agreed to indemnify us against certain liabilities to meet its indemnification obligations could subject us to significant liability and could have a material adverse effect on our financial condition and results of operations.

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Our operations are subject to environmental, health and safety laws and regulations that may expose us to liabilities for noncompliance, which could adversely affect us.

The U.S. oil and natural gas industry is affected from time to time in varying degrees by political developments and federal, state and local environmental, health and safety laws and regulations applicable to our business. Our operations are vulnerable to certain risks arising from the numerous environmental health and safety laws and regulations. These laws and regulations may restrict the types, quantities and concentration of various substances that can be released into the environment in connection with drilling activities, require reporting of the storage, use or release of certain chemicals and hazardous substances, require removal or cleanup of contamination under certain circumstances, and impose substantial civil liabilities or criminal penalties for violations. Environmental laws and regulations may impose strict liability, rendering a company liable for environmental damage without regard to negligence or fault, and could expose us to liability for the conduct of, or conditions caused by, others, or for our acts that were in compliance with all applicable laws at the time such acts were performed. Moreover, there has been a trend in recent years toward stricter standards in environmental, health and safety legislation and regulation, which may continue.

We may incur material liability related to our operations under governmental regulations, including environmental, health and safety requirements. We cannot predict how existing laws and regulations may be interpreted by enforcement agencies or court rulings, whether additional laws and regulations will be adopted, or the effect such changes may have on our business, financial condition or results of operations. Because the requirements imposed by such laws and regulations are subject to change, we are unable to forecast the ultimate cost of compliance with such requirements. The modification of existing laws and regulations or the adoption of new laws or regulations curtailing exploratory or development drilling for oil and natural gas for economic, political, environmental or other reasons could have a material adverse effect on us by limiting drilling opportunities.

We may not be able to attract and retain the services of qualified operating personnel, which could restrict our ability to market and operate our drilling rigs or result in accidents and other operational difficulties.

Increases in both onshore and offshore U.S. oil and natural gas exploration and production and resultant increases in contract drilling activity have created a shortage of qualified drilling rig personnel in the industry. If we are unable to attract and retain sufficient qualified operating personnel, our ability to market and operate our drilling rigs will be restricted. In addition, labor shortages could result in wage increases, which could reduce our operating margins and have an adverse effect on our financial condition and results of operations. To the extent that we are required to hire less experienced personnel, we may experience accidents or other operational difficulties and incur related costs.

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:

•  incur additional indebtedness or issue certain preferred shares;
•  pay dividends on or make distributions in respect of our capital stock or make other restricted payments;
•  make certain investments, including capital expenditures;
•  sell certain assets;
•  create liens; and
•  consolidate, merge, sell or otherwise dispose of all or substantially all of our assets.

Risks Related to Our Common Stock

Our principal stockholder has significant ownership.

Union Drilling Company LLC, our principal stockholder, owns approximately 37% of our outstanding common stock. Union Drilling Company LLC is controlled by Metalmark Capital LLC. As a result,

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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.

Several of our directors and affiliates of Union Drilling Company LLC, our principal stockholder, have investments in other oilfield service companies that may compete with us, and they may invest in other similar companies in the future. Our certificate of incorporation provides that we have renounced any interest in related business opportunities and that neither our directors nor their affiliates have any obligation to offer us those opportunities. These provisions of our certificate of incorporation may be amended only by an affirmative vote of holders of at least two-thirds of our outstanding common stock. As a result of these charter provisions, our future competitive position and growth potential could be adversely affected.

Our existing dividend policy and contractual restrictions limit our ability to pay dividends.

We have never declared a cash dividend on our common stock and do not expect to pay cash dividends for the foreseeable future. We expect that all cash flow generated from our operations in the foreseeable future will be retained and used to develop or expand our business. In addition, our loan agreement prohibits the payment of dividends without the prior consent of the lenders.

Provisions in our certificate of incorporation and bylaws and of Delaware corporate law may make a takeover difficult.

Provisions in our certificate of incorporation and bylaws and of Delaware corporate law may make it difficult and expensive for a third party to pursue a tender offer, change in control or takeover attempt that is opposed by our management and board of directors. These anti-takeover provisions could substantially impede the ability of public stockholders to benefit from a change of control or change our management and board of directors.

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

Our common stock is traded on the NASDAQ Global Market. During the period from January 1, 2006 through March 8, 2007, the average daily trading volume of our common stock as reported by the NASDAQ Global Market was 150,436 shares. There can be no assurance that a more active trading market in our common stock will develop. As a result, relatively small trades may have a significant impact on the price of our common stock and, therefore, may contribute to the price volatility of our common stock. As a result, our common stock may be subject to greater price volatility than the stock market as a whole and comparable securities of other contract drilling service providers.

The market price of our common stock has been, and may continue to be, volatile. For example, during the period from January 1, 2006 through March 8, 2007, the trading price of our common stock ranged from $10.29 to $18.63 per share.

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

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Item 2.    Properties

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 Northern Appalachian office in Punxsutawney, Pennsylvania, we provide oil and natural gas contract drilling services to the northern region of the Appalachian Basin. The northern region of the Appalachian Basin includes the states of Ohio, New York and the northern half of Pennsylvania. The office is located in a leased facility that includes approximately 39,600 square feet of warehouse space, 25,000 square feet of office space and yard space.

From our Central and Southern Appalachian 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 northern Texas office in Abilene, Texas, we provide contract drilling services in the Abilene area. We lease a facility in Abilene, Texas, that includes approximately 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. In addition, we established an office in Cresson, Texas, which has become the site of our Fort Worth Basin operations. 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 Oklahoma office in Pocola, Oklahoma, we provide contract drilling services in the Arkoma Basin. We own approximately 48 acres of land in Pocola, on which we have 4,800 square feet of office space and 8,000 square feet of warehouse space. In addition, we own five acres of land in Dewey, Oklahoma with 534 square feet of office space and two buildings with 7,200 square feet of warehouse space. We also own 2.5 acres of land in McCurtain, Oklahoma, and 1,420 square feet of office space in Bartlesville, Oklahoma.

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 approximately $12,000.

Item 3.    Legal Proceedings

Due to the nature of our business, we are, from time to time, involved in routine litigation or subject to disputes or claims related to our business activities, including workers’ compensation claims and employment-related disputes. The Company is a defendant in a lawsuit brought in U.S. District Court to determine insurance coverage for the death of a well worker. The Company intends to vigorously defend the claim; however, an unfavorable outcome is reasonably possible. The Company could experience a potential loss of approximately $500,000 to $700,000. The Company has not reserved any amounts for this legal matter. In the opinion of our management, no other such pending litigation, disputes or claims against us will have a material adverse effect on our financial condition, results of operations or cash flow from operations, and there is only a remote possibility that any such other matter will require any additional loss accrual.

Item 4.    Submission of Matters to a Vote of Security Holders

We did not submit any matter to a vote of our security holders during the fourth quarter of fiscal 2006.

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PART II

Item 5.  Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities

As of March 8, 2007, 21,534,372 shares of our common stock were outstanding. As of March 8, 2007, the number of holders of record of our common stock was nine.

Our common stock began trading on the NASDAQ Global Market under the symbol ‘‘UDRL’’ on November 22, 2005. Prior to that time, there was no trading market for our common stock. The following table sets forth, for each of the periods indicated, the high and low sales prices per share on the NASDAQ Global Market:


  Low High
Fiscal Year 2006  
 
Fourth quarter $ 10.29
$ 15.69
Third quarter $ 10.51
$ 16.01
Second quarter $ 11.85
$ 18.63
First quarter $ 12.31
$ 18.15
Fiscal Year 2005  
 
Fourth quarter (beginning November 22, 2005) $ 13.60
$ 15.50

The last reported sales price for our common stock on the NASDAQ Global Market on March 8, 2007 was $12.87 per share.

We have not paid or declared any dividends on our common stock and currently intend to retain earnings to fund our working capital needs and growth opportunities. Any future dividends will be at the discretion of our board of directors after taking into account various factors it deems relevant, including our financial condition and performance, cash needs, income tax consequences and the restrictions Delaware and other applicable laws and our credit facilities then impose. Our debt arrangements include provisions that generally prohibit us from paying dividends, other than dividends on our preferred stock. We currently have no preferred stock outstanding.

Equity Compensation Plan Information

The following table provides information as of December 31, 2006 about Union’s common stock that may be issued upon the exercise of options, warrants and rights granted to employees, consultants or members or the board of directors under all of our existing equity compensation plans:


  Number of shares of
common stock to be
issued upon exercise of
outstanding options,
warrants and rights		 Weighted average
exercise price per share
of outstanding options
warrants and rights		 Number of
shares of common stock
remaining available for
future issuance under equity
compensation plans
(excluding shares
reflected in column (a))
  (a) (b) (c)
Equity compensation plans
approved by security holders		 1,092,169
(1)
$ 8.33
1,314,671
(2)
(1) Includes 473,818 shares of common stock issuable upon the exercise of options that were outstanding under our Amended and Restated 2000 Stock Option Plan, 132,958 shares of common stock issuable upon the exercise of options that were outstanding under a separate Union stock option plan and agreement, the terms of which are substantially similar to those of our Amended and Restated 2000 Stock Option Plan and 485,393 shares of common stock issuable upon the exercise of options that were outstanding under our 2005 Stock Option Plan, in each case, as of December 31, 2006.
(2) Represents the difference between the number of shares of our common stock issuable under the Amended and Restated 2000 Stock Option Plan, the separate stock option plan referred to above and the 2005 Stock

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Option Plan, of 3,292,062 shares, and the number of shares of our common stock issued under such plans as of December 31, 2006, which consist of options to acquire 1,092,169 shares of common stock and 885,222 shares of common stock issued upon exercises of options.

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 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 (to date, the Company has not declared any dividends).


Year End November 22,
2005		 December 31,
2005		 December 31,
2006
UDI 100
100.83
97.71
Peer Index 100
103.82
118.59
NASDAQ 100
101.52
77.24

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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Item 6.  Selected Financial Data

The following information derives from our audited financial statements. You should review this information in conjunction with ‘‘Management’s Discussion and Analysis of Financial Condition and Results of Operations’’ in Item 7 of this report and the historical financial statements and related notes this report contains.


  Year Ended December 31,
  2006 2005 2004 2003 2002
  (In thousands, except per share data)
Revenues $ 256,944
$ 141,621
$ 67,832
$ 58,144
$ 47,045
Income (loss) from operations 54,487
11,214
2,198
(1,844
)
 (2,875
)
Income (loss) before income taxes 54,270
9,699
3,943
(2,542
)
 (3,596
)
Net income (loss) 31,852
5,599
3,527
(2,558
)
 (3,402
)
Earnings (loss) per common share-basic 1.50
0.35
0.27
(0.19
)
 (0.26
)
Earnings (loss) per common share-diluted 1.47
0.34
0.26
(0.19
)
 (0.26
)
Long-term debt and capital lease obligations, including current portion and line of credit 35,574
7,826
7,904
8,169
10,897
Stockholders’ equity 167,599
132,439
43,547
40,875
42,412
Total assets 257,418
174,038
65,598
55,660
57,974
Calculation of EBITDA:  
 
 
 
 
Net income (loss) $ 31,852
$ 5,599
$ 3,527
$ (2,558
)
 $ (3,402
)
Interest expense 527
2,367
629
850
792
Income tax expense (benefit) 22,418
4,100
416
16
(194
)
Depreciation and amortization 24,820
15,121
8,103
7,987
7,687
Trade name impairment charge 1,000
—
—
—
—
EBITDA $ 80,617
$ 27,187
$ 12,675
$ 6,295
$ 4,883

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 of its focus on the Company’s results from operations before net interest, income taxes, depreciation and amortization. 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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Item 7.  Management’s Discussion and Analysis of Financial Condition and Results of Operations

Statements we make in the following discussion that express a belief, expectation or intention, as well as those which are not historical fact, are forward-looking statements that are subject to risks, uncertainties and assumptions. Our actual results, performance or achievements, or industry results, could differ materially from those we express in the following discussion as a result of a variety of factors, including general economic and business conditions and industry trends, the continued strength or weakness of the contract land drilling industry in the geographic areas in which we operate, decisions about onshore exploration and development projects to be made by oil and gas companies, the highly competitive nature of our business, our future financial performance, including availability, terms and deployment of capital, the continued availability of qualified personnel, and changes in, or our failure or inability to comply with, government regulations, including those relating to the environment.

Company Overview

Union Drilling Inc. provides contract land drilling services and equipment, primarily to natural gas producers in the 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 a predecessor that was providing contract drilling services under the name ‘‘Union Drilling.’’    Through a combination of acquisitions and new rig construction, we have increased the size of our fleet to 76 land drilling rigs, of which 70 are marketed and six are stacked. We have focused our operations in selected natural gas production regions in the U.S.  We do not invest in oil and natural gas properties. The drilling activity of our customers is highly dependent on the current price of oil and natural gas.

In response to rising demand from our customers for equipment that is capable of efficiently drilling wells in unconventional natural gas formations, we have completed several transactions in 2006 and 2005 aimed at enhancing our ability to serve these markets. In April 2005, we acquired Thornton Drilling Company, which owned a fleet of 12 rigs and leased 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 rigs, five of which target the Barnett Shale formation in the Fort Worth Basin. During 2006, we have continued to add new and newly constructed rigs to our fleet to capitalize on our customers’ rapidly growing unconventional resource exploration and development activity. These transactions substantially expanded our unconventional natural gas contract drilling operations beyond our traditional markets in the Appalachian Basin and the Rocky Mountains.

We earn our revenues by drilling natural gas wells for our customers. We obtain our contracts for drilling natural gas wells either through competitive bidding or through direct negotiations with customers. Our drilling contracts generally provide for compensation on either a daywork or footage basis. Contract terms generally depend on the complexity and risk of operations, the on-site drilling conditions, the type of equipment used and the anticipated duration of the work to be performed. Generally, our contracts provide for the drilling of a single well or series of wells and typically permit the customer to terminate on short notice.

A significant performance measurement in our industry is rig utilization. We compute rig utilization rates by dividing revenue days by total available days during a period. Total available days are the number of calendar days during the period that we have owned the rig. Revenue days for each rig are days when the rig is earning revenues under a contract, which is usually a period from the date the rig begins moving to the drilling location until the rig is released from the contract.

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For the three years ended December 31, 2006, our marketed rig utilization, revenue days and average total number of rigs were as follows:


  Years Ended December 31,  
  2006 2005 2004  
Marketed rig utilization rates 76.4
%
 61.9
%
 50.2
%
  
Revenue days 18,028
12,254
6,390
 
Average total number of rigs 71.5
60.5
41.8
 

The reasons for the increase in the number of revenue days in 2006 over 2005 and 2004 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.

Market Conditions in Our Industry

The U.S. contract land drilling services industry is highly cyclical. Volatility in oil and gas prices can produce wide swings in the levels of overall drilling activity in the markets we serve and affect the demand for our drilling services and the dayrates we can charge for our rigs. The availability of financing sources, past trends in oil and gas prices and the outlook for future oil and gas prices strongly influence the number of wells natural gas exploration and production companies decide to drill.

During fiscal 2006, 2005 and 2004, 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.

At December 31, 2006 and 2005, our contract drilling work in progress totaled approximately $4.4 million and $7.1 million, respectively, all of which relates to the revenue recognized, but not yet billed, on daywork and footage contracts in progress at December 31, 2006 and 2005, respectively. The decrease is due primarily to an increase in progress billings and more efficient processing of customer invoices. In addition, the December 31, 2006 balance includes a reserve for sales credits of approximately $230,000.

Accounts receivable   —   We evaluate the creditworthiness of our customers based on their financial information, if available, information obtained from major industry suppliers, and past experiences with customers. In some instances, we require new customers to establish escrow accounts or make prepayments. We typically invoice our customers at 15 or 30 day intervals during the performance of daywork contracts and upon completion of the daywork contract. Footage contracts are invoiced upon

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completion of the contract. Our contracts provide for payment of invoices in 30 days. We established an allowance for doubtful accounts of approximately $839,000 at December 31, 2006 and $313,000 at December 31, 2005. Any allowance established is subject to judgment and estimates made by management. We determine our allowance by considering a number of factors, including the length of time trade accounts receivable are past due, our previous loss history, our assessment of our customers’ current abilities to pay obligations to us and the condition of the general economy and the industry as a whole. We write off specific accounts receivable when they become uncollectible.

Asset impairments 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 three 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 Consolidated 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 net operating loss carryforwards and for the basis difference in our property and equipment between financial reporting and tax reporting purposes. For property and equipment, basis differences arise from differences in depreciation periods and methods and the value of assets acquired in a business acquisition where we acquire the stock of an entity rather than its assets. For financial reporting purposes, we depreciate the various components of our drilling rigs and refurbishments over three to 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. A significant portion of our deferred taxes are deferred tax assets that arose as the result of our prior year tax losses. These losses can be carried forward for federal and state tax purposes for as many as 20 years, depending upon the jurisdiction, to reduce future taxes that we would otherwise be required to pay. The utilization of these net operating losses is dependent upon our ability to generate taxable income in the future. 

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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, 2006 and 2005, we satisfied this requirement with a $3.2 million and $2.7 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, our estimate of the administrative costs associated with these claims and our historical experience with these types of claims. In addition, we accrue on a monthly basis the estimated workers compensation premium payable to the two states (West Virginia and Ohio) that are considered monopolistic.

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 provided for under SFAS No. 123R. 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 year ended December 31, 2006, the Company recorded total stock-based compensation expense of $999,644 ($751,204 net of tax). The remaining estimated pretax amortization on outstanding options of approximately $2.3 million will be recognized through April 2011.

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:


  2006 2005 2004
Risk-free interest rate 4.4% – 5.0% 4.1% – 4.2% 2.9%
Expected life 5 – 6 years 1.5 – 5 years 4 years
Dividend yield 0% 0% 0%
Expected volatility 46% – 60% 44% – 61% 94%

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 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.

Results of Operations

Our operations consist of drilling natural gas wells for our customers under either daywork or footage contracts. Contract terms we offer generally depend on the complexity and risk of operations, the on site drilling conditions, the type of equipment used and the anticipated duration of the work to be performed. Our contracts generally provide for the drilling of a single well or series of wells and typically permit the customer to terminate on short notice.

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

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Statements of Operations Analysis

The following table provides selected information about our operations for the years ended December 31, 2006, 2005, and 2004 (in thousands).


  Years Ended December 31,
  2006 2005 2004
Revenues $ 256,944
$ 141,621
$ 67,832
Operating expenses $ 155,123
$ 102,266
$ 50,084
Depreciation and amortization $ 24,820
$ 15,121
$ 8,103
Trade name impairment charge $ 1,000
$ —
$ —
General and administrative expense $ 21,514
$ 13,020
$ 7,447
Interest expense $ 527
$ 2,367
$ 629
Other income and gain on sale of fixed assets $ 310
$ 851
$ 2,374
Effective income tax rate 41.3
%
 42.3
%
 10.6
%
Revenue days during period 18,028
12,254
6,390
Revenue per revenue day $ 14,252
$ 11,557
$ 10,616
Operating expenses per revenue day $ 8,605
$ 8,346
$ 7,839
Rig utilization rates 76.4
%
 61.9
%
 50.2
%
Average total number of rigs 71.5
60.5
41.8

Revenues.    Our revenues grew by approximately $115.3 million, or 81%, in fiscal year 2006 from fiscal year 2005. This increase was partly a result of the acquisitions of Thornton Drilling Company and the assets of SPA Drilling, L.P. on April 1, 2005. The revenues from these acquisitions during the first quarter of 2006 accounted for $29.2 million of the revenue increase. The balance of the increase of $86.2 million was due to 3,719 additional revenue days in 2006 resulting from the additional acquired rigs and increased rig utilization. In addition, the average revenue per revenue day increased by $2,703 per day. The improvement in average revenue per revenue day was a result of increases in our contract rates due to stronger demand for our drilling services.

Our revenues grew by approximately $73.8 million, or 109%, in fiscal year 2005 from fiscal year 2004, primarily due to the acquisitions of Thornton Drilling Company and the assets of SPA Drilling, L.P. on April 1, 2005. The 2005 revenues from these acquisitions accounted for $56.4 million of the revenue increase. The remaining $17.4 million increase was due to 1,083 additional revenue days in our historical markets. In addition, the average revenue per revenue day in the Appalachian basin, Rocky Mountain region and our Canadian market increased by $783 per day as a result of increases in our contract rates due to stronger demand for our drilling services. 

Operating expenses.    Our operating expenses in fiscal year 2006 grew by approximately $52.9 million. This increase, as with the increase in revenues discussed above, is partly due to the operating expenses related to Thornton Drilling Company and SPA Drilling, L.P. acquisitions, which accounted for $17.4 million of the increase during the first quarter of 2006. The remaining $35.5 million increase in operating expenses is primarily due to the increase in number of revenue days during which drilling services were being provided, however, these expenses did not increase at the same rate as revenue due to improvement in overall operating margins associated with higher contract rates.

Our operating expenses in fiscal year 2005 grew by approximately $52.2 million. This increase, as with the increase in revenues discussed above, is largely due to the operating expenses related to Thornton Drilling Company and SPA Drilling, L.P. acquisitions, which accounted for $44.7 million of the increase. The remaining increase in operating expenses of $7.5 million was related to the increase in revenues associated with our historical markets, and is less than the change in revenue levels due to improvement in overall operating margins.

Depreciation and amortization.    Our depreciation and amortization expense in 2006 increased by approximately $9.7 million, or 64%, from 2005. $2.6 million of the increase is attributable to depreciation expense during the first quarter of 2006 related to the assets acquired on April 1, 2005. The remaining increase is the result of 2006 capital spending for rig purchases and capital equipment upgrades.

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Depreciation and amortization expense in 2005 increased approximately $7.0 million, or 87%, from 2004. The increase in 2005 over 2004 resulted from the purchase of SPA Drilling, L.P. assets and the Thornton Drilling Company acquisition on April 1, 2005, as well as other rig purchases and capital equipment upgrades. 

Trade name impairment charge.    Effective December 31, 2006, Thornton Drilling Company, a 100% owned subsidiary, was merged with the parent company. Concurrently, the Company decided to cease using the Thornton 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.

General and administrative expenses.    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 is attributable to stock-based compensation cost related to the implementation of SFAS No. 123R in 2006. The remainder of the increase is 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 is 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.

Our general and administrative expenses increased by approximately $5.6 million, or 74.8%, in fiscal year 2005 from fiscal year 2004. Approximately $2.4 million of the increase relates to the general and administrative costs associated with operations established to support the purchase of SPA Drilling, L.P. assets and the Thornton Drilling Company acquisition. The remaining $3.2 million increase is due primarily to higher personnel expense (including $788,000 of non-cash compensation), and higher spending on professional and consulting costs of $306,000, and insurance costs of $453,000 related to the new acquisitions.

Interest expense.    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 acquisitions. Much of these financing costs were repaid in the fourth quarter of 2005 with the proceeds from the Company’s initial public offering.

Interest expense increased by approximately $1.7 million for the year ended December 31, 2005 from the fiscal year 2004. This increase was due primarily to the borrowings required to support our acquisition activity and increased working capital to support revenue growth in excess of 100%.

Other income and gain on sale of fixed assets.    Other income and gain on sale of fixed assets decreased approximately $542,000 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. For the year ended December 31, 2005, other income and gain on sale of fixed assets declined by approximately $1.5 million from fiscal year 2004, primarily as a result of $2.2 million of gains associated with the sale of our two Canadian-based rigs recorded in fiscal year 2004.

Taxes.    Our effective income tax rates of 41.3%, 42.3% and 10.6% for 2006, 2005 and 2004, respectively, differ from the federal statutory rate of 35% in 2006 and 34% in 2005 and 2004 due to related state income taxes and permanent differences associated with meals and entertainment (primarily for our direct service personnel) and non-cash compensation. In prior years, due to net operating loss carryforwards, there were no significant federal income tax payments required. See Note 7 to our Financial Statements for further information on our income taxes. Permanent differences are costs included in results of operations in the accompanying financial statements, which are not fully deductible for federal income tax purposes. 

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

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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 $1,164,000 increase to deferred tax liabilities, a $1,312,000 reduction in deferred tax assets, a $2,476,000 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 prior periods, expected 2006 results or the trend of earnings.

At December 31, 2006 and 2005, we had federal net operating loss carryforwards for income tax purposes of approximately $7.7 million and $24.8 million, respectively. These losses may be carried forward for 20 years and will begin to expire in 2019. State net operating losses at December 31, 2006 and 2005 were $15.9 million and $27.9 million, respectively. State losses vary as to carryforward period and will begin to expire in 2013, depending upon the jurisdiction where applied. Based upon 2006 results and forecasted future operations, we feel it is more likely than not that the amounts will be realized. Foreign net operating losses were fully utilized in 2004.

Liquidity and Capital Resources

Sources of Capital Resources

Our rig fleet has grown from 12 rigs in 1997 to 73 rigs as of December 31, 2006. We have financed this growth with a combination of debt and equity financing. At December 31, 2006, our total debt to total capital was approximately 18.8%. Due to the volatility in our industry, we are reluctant to take on additional debt in excess of the $69.0 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.

On April 1, 2005, we raised $19.9 million, after expenses, through a sale of shares of our common stock. These proceeds plus additional borrowing under our revolving credit facility were used to fund the acquisitions of Thornton Drilling Company which owned 12 drilling rigs and substantially all of the drilling assets (eight rigs) of SPA Drilling, L.P.

On November 22, 2005, we also sold 4,411,765 shares of our common stock at approximately $13.05 per share, net of underwriters’ commissions, pursuant to a public offering we registered with the Securities and Exchange Commission. The net proceeds to Union, after expenses, of this sale were approximately $55.4 million, and were used primarily to repay indebtedness under our revolving credit facility.

We entered into a Revolving Credit and Security Agreement with PNC Bank, as agent for a group of lenders, dated March 31, 2005, and subsequently amended on April 19, August 15, and October 5, 2005, and on September 27 and December 5, 2006, which provides for a borrowing base equal to the lesser of $100 million and the sum of 85% of eligible receivables and 75% of the liquidation value of eligible rig fleet equipment. The agent may, in the exercise of its reasonable business judgment, increase or decrease those percentage advance rates against eligible receivables and liquidation value. The liquidation value of eligible rig fleet equipment is determined annually (or semi-annually in certain circumstances) by an independent appraisal, with adjustments for acquisitions and dispositions between appraisals. There is a $7,500,000 sublimit for letters of credit. Amounts outstanding under the revolving credit facility bear interest at either (i) the higher of the Federal Funds Open Rate plus 1⁄2 of 1% or PNC Bank’s base commercial lending rate (8.25% at December 31, 2006) or (ii) LIBOR plus 2.00% (7.3601% at December 31, 2006). Those rates may increase by up to 0.50% for LIBOR loans or up to 0.25% for domestic rate loans if our fixed charge coverage ratio falls below certain targets. A fee of 0.25% is applied to the unused portion of the $100 million capacity of the revolving credit facility.

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

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March 30, 2009. As of December 31, 2006, we had a loan balance of $27.8 million under the Revolving Credit and Security Agreement, and an additional $3.2 million of the total capacity had been utilized to support our letter of credit requirement. At December 31, 2005, we had no outstanding loans under the Revolving Credit and Security Agreement, but $2.7 million of the total capacity was utilized to support our letter of credit requirement. To date, the revolving credit facility has been used to pay for rig acquisitions and for working capital requirements. If we repay and terminate the obligations under the Revolving Credit and Security Agreement, we would be liable for a substantial prepayment penalty.

The Revolving Credit and Security Agreement is secured by substantially all of our assets, with certain exceptions, and contains affirmative and negative covenants and provides for events of default that are typical for an agreement of this type. Among the affirmative covenants are requirements to maintain a specified tangible net worth (initially $43 million) and a fixed charge coverage ratio of 1.10 to 1.00. Among the negative covenants are restrictions on major corporate transactions, capital expenditures, payment of dividends, incurrence of indebtedness, and amendments to our organizational documents. Net capital expenditures were limited to $45 million in 2005 and $10 million in subsequent years, but those amounts are increased by permitted equity issuance proceeds. On September 27, 2006, the agreement was amended to increase the 2006 net capital expenditure limitation to $125 million. Among the events of default are a change in control and any change in our operations or condition, which has a material adverse effect. As of December 31, 2006, the Company was in compliance with all debt covenants.

Current portion of other obligations consists of financed annual insurance costs. The interest rate on these borrowings is 6.258%. This debt will be repaid over 11 months in 2007. The $1.0 million decrease from December 31, 2005 is due to the financing of worker’s compensation premiums in the prior policy year.

Uses of Capital Resources 

For the years ended December 31, 2006 and 2005, the additions to our property and equipment consisted of the following:


  Years Ended December 31,
  2006 2005
Land $ 43,000
$ 779,790
Buildings 103,730
891,243
Drilling and well service equipment 84,437,555
81,881,072
Deposits on drilling equipment 6,545,825
8,186,500
Vehicles 2,519,181
3,259,258
Furniture and fixtures 319,669
6,486
Computer equipment 39,950
75,119
  $ 94,008,910
$ 95,079,468

In December 2005 and April 2006, the Company entered into agreements with National Oilwell Varco (‘‘NOV’’) to purchase six rigs and related equipment for an aggregate purchase price of $52.7 million. All six rigs are capable of horizontal and underbalanced drilling. As of December 31, 2006, three of the six rigs have been delivered and are currently in service in the Fort Worth basin. As of March 1, 2007, five of the six rigs have been delivered. The Company has paid $46.1 million to NOV, including $2.5 million as a downpayment for the remaining rig, which is scheduled for delivery in March 2007.

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 $8.8 million.

Effective April 1, 2005, the Company acquired all of the capital stock of Thornton Drilling Company, which owned 12 drilling rigs. Also, effective the same date, the Company acquired substantially all of the drilling assets (eight rigs) of SPA Drilling, L.P. The total purchase price for these businesses was

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$49.5 million. These acquisitions were financed by a new $50 million revolving line of credit with a bank (subsequently amended — see above), and collateralized by substantially all of the assets of the Company. The previous debt facilities were both retired at that time. In addition, the Company also received an equity infusion of approximately $20 million from private investors. Also, the seller of Thornton Drilling Company received approximately $2 million in stock of Union Drilling, Inc. as part of the transaction. The funding of these transactions occurred on April 1, 2005. 

Also during 2005, the Company purchased a total of 8 rigs for approximately $18.4 million.

Working Capital

Our working capital increased to $27.0 million at December 31, 2006 from $22.2 million at December 31, 2005. The principal reason for the increase in our working capital at December 31, 2006 is the additional accounts receivable, net of associated liabilities, related to the year over year increase in general business activity. Our current ratio, which we calculate by dividing our current assets by our current liabilities, was 1.83 at December 31, 2006 compared to 2.05 at December 31, 2005. 

Our operations have historically generated sufficient cash flow to meet our requirements for debt service and equipment expenditures (excluding major business and asset acquisitions).  The significant improvement in cash flow from operating activities for 2006 over 2005 is primarily due to the $26.3 million improvement in net earnings, 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. We believe our cash generated by operations and our ability to borrow the currently unused portion of our line of credit and letter of credit facility of approximately $69.0 million, which takes into account reductions for approximately $3.2 million of outstanding letters of credit as of December 31, 2006, should allow us to meet our routine financial obligations for the foreseeable future.

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


  December 31,
  2006 2005 Change
Cash and cash equivalents $ 20,350
$ 2,388,276
$ (2,367,926
)
Receivables 47,612,631
28,060,911
19,551,720
Inventories 1,072,814
860,208
212,606
Prepaid expenses 3,920,606
4,930,431
(1,009,825
)
Assets held for sale 2,143,678
—
2,143,678
Deferred taxes 4,685,803
7,091,903
(2,406,100
)
Current assets 59,455,882
43,331,729
16,124,153
Current debt 4,841,465
5,322,634
(481,169
)
Accounts payable 17,018,095
9,240,626
7,777,469
Current portion of advances from customers 1,612,600
1,265,067
347,533
Accrued expenses 8,971,305
5,353,308
3,617,997
Current liabilities 32,443,465
21,181,635
11,261,830
Working capital $ 27,012,417
$ 22,150,094
$ 4,862,323

The increase in our receivables at December 31, 2006 from December 31, 2005 was due primarily to revenue generated by the five additional rigs acquired in 2006, as well as an improvement in utilization and revenue rates in fiscal year 2006 over fiscal year 2005. 

Substantially all our prepaid expenses and other assets at December 31, 2006 consisted of prepaid insurance. At December 31, 2005, prepaid expenses and other assets included various non-trade receivables in addition to prepaid insurance. The decrease in prepaid expenses and other assets from December 31, 2005 was primarily due to the settlement of these non-trade receivables in January 2006.

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Assets held for sale at December 31, 2006 represents one of the Company’s stacked rigs. Management decided during the fourth quarter of 2006 to dispose of this rig. Subsequent to December 31, 2006, some components of the rig were sold. The remaining portions continue to be held for sale.

The decrease in the deferred tax asset is due to the use of some of the net operating loss carryforward during 2006 and adjustments to the carryforwards for underreporting of non-deductible meals and incidental expenses in prior years. Refer to ‘‘Income Taxes’’ in Note 2 to our Financial Statements for further information regarding 2006 activity.

The increase in payables at December 31, 2006 from December 31, 2005 was primarily due to the additional operating costs associated with the increased size of our drilling rig fleet.

The increase in accrued expenses at December 31, 2006 from December 31, 2005 was due to an increase in the size of our company. The growth in accrued payroll, accrued workers compensation and other accrued expenses can be attributed to the growth in our employee headcount and the additional expenses associated with being a public company.

Long-term Debt

Our long-term debt at December 31, 2006 and 2005 consisted of the following:


  December 31,
  2006 2005
Revolving credit facility $ 27,810,247
$ —
Notes payable for equipment financed 7,764,250
7,825,984
  35,574,497
7,825,984
Less current installments (2,508,127
)
 (2,013,956
)
  $ 33,066,370
$ 5,812,028

Contractual Obligations

The following table includes all of our contractual obligations of the type specified below at December 31, 2006:


Contractual Obligations Total Less than 1
year		 1 – 3 years 4 – 5 years More than 5
years
Rig purchase commitments $ 21,423,526
$ 21,423,526
$ —
$ —
$     —
Long-term debt(1) 7,764,250
2,508,127
4,577,887
678,236
—
Operating lease obligations 4,534,468
1,871,206
2,267,696
395,566
—
Interest 644,887
376,710
249,201
18,976
—
Total $ 34,367,131
$ 26,179,569
$ 7,094,784
$ 1,092,778
$ —
(1) Does not include our Revolving Credit and Security Agreement with PNC Bank, which we entered into on April 1, 2005.

Inflation

As a result of the relatively low levels of inflation during the past two years, inflation did not significantly affect our results of operations in any of the periods reported.

Off Balance Sheet Arrangements

We do not currently have any off balance sheet arrangements.

Recently Issued Accounting Standards

In September 2006, the Financial Accounting Standards Board (‘‘FASB’’) issued SFAS No. 157 ‘‘Fair Value Measurements’’. 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

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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 June 2006, the FASB issued FASB Interpretation No. 48 (‘‘FIN 48’’), ‘‘Accounting for Uncertainty in Income Taxes — an interpretation of FASB Statement No. 109.’’ 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. This interpretation is effective for fiscal years beginning after December 15, 2006. We have not fully assessed the impact of the adoption of FIN 48 on our financial position or results of operations.

Item 7A.    Quantitative and Qualitative Disclosures About Market Risk

We are subject to market risk exposure related to changes in interest rates on our revolving credit facility, which provides for interest on borrowings under the facility at a floating rate. At December 31, 2006, we had approximately $27.8 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 $278,000 annually.

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Item 8.    Financial Statements and Supplementary Data

UNION DRILLING, INC.

INDEX TO CONSOLIDATED FINANCIAL STATEMENTS


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MANAGEMENT’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, 2006. 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, 2006, our internal control over financial reporting is effective based on those criteria.

Management’s assessment of the effectiveness of internal control over financial reporting as of December 31, 2006, has been audited by Ernst & Young, LLP, an independent registered public accounting firm which also audited our consolidated financial statements. Ernst & Young’s attestation report on management’s assessment of our internal control over financial reporting as of December 31, 2006 is included under the heading ‘‘Report of Independent Registered Public Accounting Firm on Internal Control Over Financial Reporting.’’


By: /s/ Christopher D. Strong                         By: /s/ Dan E. Steigerwald                        
       Christopher D. Strong        Dan E. Steigerwald
       President and Chief Executive Officer        Vice-President, Chief Financial Officer,
         Treasurer and Secretary

Fort Worth, Texas
March 15, 2007

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REPORT 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 management’s assessment, included in the accompanying Management’s Report on Internal Control Over Financial Reporting, that Union Drilling, Inc. (the ‘‘Company’’) maintained effective internal control over financial reporting as of December 31, 2006, based on criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (the COSO criteria). The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting. Our responsibility is to express an opinion on management’s assessment and an opinion on the effectiveness of the Company’s internal control over financial reporting based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). 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, evaluating management’s assessment, testing and evaluating the design and operating effectiveness of internal control, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

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

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

In our opinion, management’s assessment that Union Drilling, Inc. maintained effective internal control over financial reporting as of December 31, 2006, is fairly stated, in all material respects, based on the COSO criteria. Also, in our opinion, Union Drilling, Inc. maintained, in all material respects, effective internal control over financial reporting as of December 31, 2006, based on the COSO criteria.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of Union Drilling, Inc. as of December 31, 2006 and 2005 and the related consolidated statements of income, stockholders’ equity and cash flows for each of the three years in the period ended December 31, 2006 and our report dated March 15, 2007 expressed an unqualified opinion thereon.

Ernst & Young LLP

Fort Worth, Texas
March 15, 2007

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Report of Independent Registered Public Accounting Firm

The Board of Directors and Stockholders
of Union Drilling, Inc.

We have audited the accompanying consolidated balance sheets of Union Drilling, Inc. (the ‘‘Company’’) as of December 31, 2006 and 2005, and the related consolidated statements of income, stockholders’ equity, and cash flows for each of the three years in the period ended December 31, 2006. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform an audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. 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 consolidated financial position of Union Drilling, Inc. at December 31, 2006 and 2005, and the consolidated results of its operations and its cash flows for each of the three years in the period ended December 31, 2006, in conformity with U.S. generally accepted accounting principles.

As discussed in Note 2 to the consolidated financial statements, 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 effectiveness of the Company’s internal control over financial reporting as of December 31, 2006, based on the criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission, and our report dated March 15, 2007 expressed an unqualified opinion thereon.

Ernst & Young LLP

Fort Worth, Texas
March 15, 2007

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Union Drilling, Inc.
Consolidated Balance Sheets


  December 31,
  2006 2005
Assets:  
 
Current assets:  
 
Cash and cash equivalents $ 20,350
$ 2,388,276
Accounts receivable (net of allowance for doubtful accounts of
$838,585 and $313,436 at December 31, 2006 and 2005, respectively)		 47,612,631
27,579,254
Accounts receivable – related party —
481,657
Inventories 1,072,814
860,208
Prepaid expenses and other assets 3,920,606
4,930,431
Assets held for sale 2,143,678
—
Deferred taxes 4,685,803
7,091,903
Total current assets 59,455,882
43,331,729
Goodwill 7,909,349
5,424,793
Intangible assets (net of accumulated amortization of $528,056
and $202,500 at December 31, 2006 and 2005, respectively)		 2,471,944
3,797,500
Property, buildings and equipment (net of accumulated depreciation of $69,338,007 and $46,250,906 at December 31, 2006 and 2005, respectively) 187,084,437
120,783,092
Other assets 496,259
700,409
Total assets $ 257,417,871
$ 174,037,523
Liabilities and Stockholders’ Equity:  
 
Current liabilities:  
 
Accounts payable $ 17,018,095
$ 9,240,626
Current portion of long-term obligations 2,508,127
2,013,956
Current portion of other obligations 2,333,338
3,308,678
Current portion of advances from customers 1,612,600
1,265,067
Accrued expenses and other liabilities 8,971,305
5,353,308
Total current liabilities 32,443,465
21,181,635
Revolving credit facility 27,810,247
—
Long-term obligations 5,256,123
5,812,028
Deferred taxes 23,480,921
14,465,954
Advances from customers 827,605
138,605
Total liabilities 89,818,361
41,598,222
Stockholders’ equity:  
 
Common stock, par value $.01 per share; 75,000,000 shares authorized; 21,523,577 shares and 21,166,109 shares issued and outstanding at December 31, 2006 and 2005, respectively 215,236
211,661
Additional paid-in capital 136,686,152
133,381,395
Retained earnings (deficit) 30,698,122
(1,153,755
)
Total stockholders’ equity 167,599,510
132,439,301
Total liabilities and stockholders’ equity $ 257,417,871
$ 174,037,523

See accompanying notes to consolidated financial statements.

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Table of Contents

Union Drilling, Inc.
Consolidated Statements of Income


  Years Ended December 31,
  2006 2005 2004
Revenues  
 
 
Nonaffiliates $ 256,943,921
$ 136,388,802
$ 59,097,454
Related party —
5,232,314
8,734,944
Total revenues 256,943,921
141,621,116
67,832,398
Cost and expenses  
 
 
Operating expenses 155,123,449
102,265,841
50,083,525
Depreciation and amortization 24,819,567
15,120,947
8,103,387
Trade name impairment charge 1,000,000
—
—
General and administrative 21,514,046
13,020,180
7,447,137
Total cost and expenses 202,457,062
130,406,968
65,634,049
Operating income 54,486,859
11,214,148
2,198,349
Interest expense (527,095
)
 (2,366,769
)
 (629,322
)
Gain on sale or disposal of fixed assets 4,122
649,229
1,679,053
Other income 305,672
202,033
695,043
Income before income taxes 54,269,558
9,698,641
3,943,123
Income tax expense 22,417,681
4,099,523
416,387
Net income $ 31,851,877
$ 5,599,118
$ 3,526,736
Earnings per common share:  
 
 
Basic $ 1.50
$ 0.35
$ 0.27
Diluted $ 1.47
$ 0.34
$ 0.26
Weighted-average common shares outstanding:  
 
 
Basic 21,284,047
16,012,486
13,162,936
Diluted 21,660,792
16,553,894
13,311,203

See accompanying notes to consolidated financial statements.

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Union Drilling, Inc.
Consolidated Statements of Stockholders’ Equity


      
Common Stock		 Additional
Paid-In
Capital		 Accumulated
Other
Comprehensive
Income (Loss)		 Retained
Earnings
(Deficit)		 Total
  Shares $
Balance at December 31, 2003 13,162,936
$ 131,629
$ 50,168,371
$ 854,931
$ (10,279,609
)
 $ 40,875,322
Foreign translation adjustments:  
 
 
 
 
 
Current period translation —
—
—
(679,678
)
 —
(679,678
)
Reclassification to earnings —
—
—
(175,253
)
 —
(175,253
)
Net income —
—
—
—
3,526,736
3,526,736
Total comprehensive income —
—
—
—
—
2,671,805
Balance at December 31, 2004 13,162,936
131,629
50,168,371
—
(6,752,873
)
 43,547,127
Issuance of common shares, net of
$80,001 transaction costs		 2,771,145
27,711
19,892,296
—
—
19,920,007
Issuance of common shares in association with intial public offering, net of $2,216,110 transaction costs 4,411,765
44,118
55,335,364
—
—
55,379,482
Compensation costs included in
net income		 —
—
787,697
—
—
787,697
Exercise of stock options and related
tax benefit of $1,395,487		 527,754
5,278
5,200,593
—
—
5,205,871
Issuance of common shares 292,509
2,925
1,997,074
—
—
1,999,999
Net income —
—
—
—
5,599,118
5,599,118
Balance at December 31, 2005 21,166,109
211,661
133,381,395
—
(1,153,755
)
 132,439,301
Compensation costs included in
net income		 —
—
453,286
—
—
453,286
Stock issuance costs —
—
(35,984
)
 —
—
(35,984
)
Exercise of stock options and related
tax benefit of $1,491,852		 357,468
3,575
2,887,455
—
—
2,891,030
Net income  
 
 
 
31,851,877
31,851,877
Balance at December 31, 2006 21,523,577
$ 215,236
$ 136,686,152
$ —
$ 30,698,122
$ 167,599,510

See accompanying notes to consolidated financial statements.

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Union Drilling, Inc.
Consolidated Statements of Cash Flows


  Year Ended December 31,
  2006 2005 2004
Operating activities:  
 
 
Net income $ 31,851,877
$ 5,599,118
$ 3,526,736
Adjustments to reconcile net income to net cash
provided by (used in) operating activities:		  
 
 
Depreciation and amortization 24,819,567
15,120,947
8,103,387
Trade name impairment charge 1,000,000
—
—
Amortization of stock-based compensation expense 453,286
787,697
—
Provision for doubtful accounts 680,000
155,000
152,015
Gain on sale or disposal of fixed assets (4,122
)
 (649,229
)
 (1,679,053
)
Provision for deferred taxes 8,988,501
3,937,732
130,647
Excess tax benefits from share-based payment arrangements (1,491,852
)
 —
—
Changes in operating assets and liabilities:  
 
 
Accounts receivable (20,711,798
)
 (12,837,923
)
 (1,856,326
)
Accounts receivable – related party 481,657
1,483,224
(1,776,792
)
Inventories (212,606
)
 (80,494
)
 20,245
Prepaid expenses and other assets 1,161,985
(791,032
)
 (2,461,005
)
Accounts payable 3,873,997
3,130,643
1,636,195
Accrued expenses and other liabilities 6,224,396
1,828,017
1,436,462
Cash flow provided by operating activities 57,114,888
17,683,700
7,232,511
Investing activities:  
 
 
Purchase of businesses —
(47,517,419
)
 —
Purchases of machinery and equipment (94,008,910
)
 (53,994,141
)
 (13,369,530
)
Proceeds from sale of machinery and equipment 1,073,998
2,346,579
7,080,032
Cash flow used in investing activities (92,934,912
)
 (99,164,981
)
 (6,289,498
)
Financing activities:  
 
 
Borrowings on line of credit 258,162,950
175,689,103
22,956,618
Repayments on line of credit (230,352,703
)
 (175,689,103
)
 (22,956,618
)
Cash overdrafts 3,899,454
—
—
Borrowings – other debt 5,342,289
5,464,051
6,858,726
Repayments – other debt (6,457,375
)
 (2,393,337
)
 (1,864,838
)
Repayments on term loan —
(2,053,038
)
 (3,139,821
)
Issuance of common shares in initial public offering —
55,379,482
—
Issuance of common shares —
19,920,007
—
Stock issuance costs (35,984
)
 —
—
Exercise of stock options 1,399,178
3,810,384
—
Excess tax benefits from share-based payment arrangements 1,491,852
—
—
Cash flow provided by financing activities 33,449,661
80,127,549
1,854,067
Foreign currency translation adjustment 2,437
(129,263
)
 (558,985
)
Net (decrease) increase in cash (2,367,926
)
 (1,482,995
)
 2,238,095
Cash and cash equivalents at beginning of period 2,388,276
3,871,271
1,633,176
Cash and cash equivalents at end of period $ 20,350
$ 2,388,276
$ 3,871,271
Supplemental disclosure of non cash investing
and financing activities:		  
 
 
Common stock issued for business acquisition $ —
$ 2,000,000
$ —

See accompanying notes to consolidated financial statements.

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UNION DRILLING INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1. Organization

Union Drilling, Inc. (Union or the Company) was incorporated in Delaware on September 23, 1997. On October 21, 1997, the Company acquired substantially all of the drilling equipment assets of a division of Equitable Resources Energy Company. Since that time the Company has increased its productive capacity by purchasing additional rigs and related equipment as described in Note 10.

2. Description of Business and Summary of Significant Accounting Policies

Description of business

The Company is engaged in the business of onshore contract drilling and related services. The primary market for the Company’s services is the onshore oil and natural gas industry. The Company operates primarily in Arkansas, Colorado, Kentucky, New York, Ohio, Oklahoma, Pennsylvania, Texas, Virginia, and West Virginia. In fiscal year 2004, the Company operated in the provinces of New Brunswick, Nova Scotia, Ontario and Quebec, Canada.

During 2004, in response to the low productivity in Canada, the Company sold two rigs and associated equipment located in Canada. The net book value of these assets was approximately $4.0 million and the Company recorded a net gain on the sale of approximately $1.5 million. These assets constituted all of the productive capacity of the Company’s Canadian operation. As the Company substantially completed the liquidation of its investment in Canada in 2004, the Company has recorded all subsequent foreign currency translation adjustments through other income/expense in the consolidated statements of operations. In December 2006, the Canadian subsidiary was dissolved.

The following table provides selected information about the Company’s domestic and foreign operations for the three years ended December 31, 2006:


  United
States		 Canada Total
  (In Thousands)
2006:  
 
 
Revenue $ 256,944
$ —
$ 256,944
Net income (loss) before taxes 54,292
(22
)
 54,270
Total assets 257,418
—
257,418
2005:  
 
 
Revenue $ 141,598
$ 23
$ 141,621
Net income (loss) before taxes 9,999
(300
)
 9,699
Total assets 173,877
161
174,038
2004:  
 
 
Revenue $ 65,606
$ 2,226
$ 67,832
Net income before taxes 1,662
2,281
3,943
Total assets 63,879
1,719
65,598

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, 2006 represented approximately 46% of total revenues with one customer’s revenue totaling 11.5%. Revenues from the top ten customers for the year ended December 31, 2005 represented approximately 46% of total revenues with no one customer’s revenue over 10%. Revenues from the top ten customers for the year ended December 31, 2004 represented approximately 67% of total revenues with revenues from three customers totaling 16.3%, 14.3% and 12.6%, respectively.

Basis of Presentation

The consolidated financial statements include the accounts of the Company and its wholly owned subsidiaries after the elimination of all significant intercompany balances and transactions.

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Use of Estimates

The preparation of financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the amounts reported in the financial statements and accompanying notes. Actual results may differ from those estimates.

Cash and Cash Equivalents

The Company considers all highly liquid investments with an original maturity date of three months or less when purchased to be cash equivalents.

Accounts Receivable

We typically invoice our customers at 15 or 30 day intervals during the performance of daywork contracts and upon completion of the daywork contract. Footage contracts are invoiced upon completion of the contract. Our contracts generally provide for payment of invoices in 30 days. We evaluate the creditworthiness of our customers based on their financial information, if available, information obtained from major industry suppliers, and past experience with customers. In some instances, we require new customers to establish escrow accounts or make prepayments.

The Company provides an allowance for doubtful accounts in recognition of uncollectible accounts. Any allowance established is subject to judgment and estimates made by management. We determine our allowance by considering a number of factors, including the length of time trade accounts receivable are past due, our previous loss history, our assessment of our customers’ current abilities to pay obligations to us and the condition of the general economy and the industry as a whole. We write off specific accounts receivable when they become uncollectible. All known losses have been provided for in the accompanying financial statements.

Inventories

Inventories maintained by the Company are primarily replacement parts and drill bits. Inventories are maintained on the lower of first-in, first-out cost, or market.

Prepaid Expenses

Prepaid expenses and other assets include items such as insurance, taxes, utility deposits and fees. We routinely expense these items in the normal course of business over the periods these expenses benefit. Included in prepaid expenses and other assets is prepaid insurance of approximately $3.1 million and $3.3 million at December 31, 2006 and 2005, respectively.

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. The remaining portions continue to be held for sale.

Goodwill and Intangible Assets

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 ‘‘Income Taxes’’ below 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.

Property, 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.

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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 does not commence until the rigs are placed in service. Once placed in service, depreciation continues when rigs 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, 2006, depreciation expense was approximately $24.5 million. The cost of maintenance and repairs is charged to operations as incurred; renewals and betterments are capitalized. The estimated lives of the assets are as follows:


Buildings 32 – 39 years
Drilling and well service equipment 3 – 12 years
Vehicles 3 – 7 years

Impairment of Long-Lived Assets

Whenever events or changes in circumstances indicate that the carrying amount of long-lived assets may not be recoverable, the Company reviews its long-lived assets for impairment by first comparing the carrying value of the assets to the sum of the undiscounted cash flows expected to result from the use and eventual disposition of the assets. If the carrying value exceeds the sum of the assets’ undiscounted cash flows, the Company estimates an impairment loss by taking the difference between the carrying value and fair value of the assets. No impairment charge, other than the trade name impairment charge discussed above, has been recognized in any of the periods presented.

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, 2006 and 2005, we satisfied this requirement with a $3.2 million and $2.7 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, our estimate of the administrative costs associated with these claims and our historical experience with these types of claims. In addition, we accrue on a monthly basis the estimated workers compensation premium payable to the two states (West Virginia and Ohio) that are considered monopolistic.

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 twelve months ended December 31, 2006, the Company recorded total stock-based compensation expense of $999,644 ($751,204 net of tax), 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 are $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 $2.3 million at December 31, 2006, and will be recognized over a weighted average service period of 2.3 years.

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The tax benefit realized from stock options exercised during the twelve months ended December 31, 2006 is included as a cash inflow from financing activities on the consolidated statement of cash flows.

The consolidated statements of income for the twelve months ended December 31, 2005 and 2004, have not been restated to reflect stock-based compensation expense in accordance with SFAS No. 123R.

The fair value of option grants was determined using the Black-Scholes option valuation model based on the following weighted average assumptions:


  2006 2005 2004
Risk-free interest rate 4.4% – 5.0% 4.1% – 4.2% 2.9%
Expected life 5 – 6 years 1.5 – 5 years 4 years
Dividend yield 0% 0% 0%
Expected volatility 46% – 60% 44% – 61% 94%

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 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.

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.

The 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.


  2005 2004
Reported net income $ 5,599,118
$ 3,526,736
Plus: Recorded stock-based compensation expense included in net income, net of tax 454,501
—
Less: Total stock-based compensation expense determined under fair value method for all awards, net of tax (1,265,463
)
 (198,202
)
Pro forma net income $ 4,788,156
$ 3,328,534
Basic and diluted income per share:  
 
Basic, as reported $ 0.35
$ 0.27
Diluted, as reported $ 0.34
$ 0.26
Basic, pro forma $ 0.30
$ 0.25
Diluted, pro forma $ 0.29
$ 0.25

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.

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Table of Contents

Revenue Recognition

Substantially all revenue is derived from gas drilling operations. Gas drilling contract terms are based on either daywork or footage. Revenue is recognized and recorded based on contracted rates applied to either the number of days drilling has taken place (daywork) or the depth drilled (footage). Losses, if any, are recognized on drilling contracts when such amounts are determinable. Mobilization fees are recognized as the related drilling services are provided.

Concentration of Credit Risk

Substantially all of the Company’s drilling services are performed for independent oil and natural gas producers in North America. Although the Company has provided drilling services in several states and provinces, these operations are aggregated into one segment for reporting purposes based on the similarity of economic characteristics among all markets including the nature of the services provided and the type of customers for such services.

Income Taxes

The Company follows the liability method of accounting for income taxes. Deferred tax assets and liabilities are determined based on differences between financial reporting and tax bases of assets and liabilities and are measured using the enacted tax laws and rates applicable to the periods in which the differences are expected to reverse.

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 $1,164,000 increase to deferred tax liabilities, a $1,312,000 reduction in deferred tax assets, a $2,476,000 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 prior periods, expected 2006 results or the trend of earnings.

Foreign Currency Translation

The functional currency of the Company’s foreign subsidiary was the Canadian dollar. The Company translated all assets and liabilities to U.S. dollars at the current exchange rates as of the applicable balance sheet date with the exception of long-term notes payable to the parent company. This liability was translated at the historical rate and was paid in full during fiscal year 2004. Revenue and expenses were translated at the average monthly exchange rate prevailing during each period. Gains and losses resulting from the translation of the foreign subsidiary’s financial statements were reported as a separate component of total other comprehensive income (loss) in stockholders’ equity. As indicated in Note 2, the Company made the strategic decision to exit the Canadian market. This resulted in the sale of substantially all of the Company’s drilling equipment in Canada in 2004. As such, the foreign currency translation gain of approximately $175,000 was reclassified from other comprehensive income and increased the gain realized on the disposition of these non-domestic assets. Net (loss) gains resulting from foreign exchange transactions, which are recorded in the consolidated statements of operations in other income, approximated ($1,600) in 2006, $12,000 in 2005 and $532,000 in 2004. In December 2006, the Canadian subsidiary was dissolved.

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.

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Table of Contents

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 2006 and 2005, other comprehensive income equals net income.

Recent Accounting Pronouncements

In September 2006, the Financial Accounting Standards Board (‘‘FASB’’) issued SFAS No. 157 ‘‘Fair Value Measurements’’. 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 June 2006, the FASB issued FASB Interpretation No. 48 (‘‘FIN 48’’), ‘‘Accounting for Uncertainty in Income Taxes — an Interpretation of SFAS No. 109.’’ FIN 48 clarifies the accounting for uncertainty in income taxes recognized in an enterprise’s financial statements in accordance with SFAS No. 109, ‘‘Accounting for Income Taxes.’’ FIN 48 prescribes a recognition threshold and measurement of a tax position taken or expected to be taken in an enterprise’s tax return. In addition, FIN 48 provides guidance on derecognition, classification, interest, penalties, accounting in interim periods and disclosure related to uncertain income tax positions. FIN 48 is effective for fiscal years beginning after December 15, 2006. The Company is currently evaluating the impact that the adoption of FIN 48 will have, if any, on its consolidated financial statements. However, we do not expect the adoption of FIN 48 to have a material effect on the Company’s financial position or operating results.

Reclassifications

Certain portions of deferred taxes in the financial statements for the prior year have been reclassified to appropriately present the current and long-term classification of such items on a consistent basis with the current year’s presentation.

3. Acquisitions

Effective April 1, 2005, the Company acquired substantially all of the drilling assets (the drilling business) of SPA Drilling L.P. The aggregate cash purchase price for the drilling assets was $20.3 million. This acquisition provided the Company with a foothold 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 is classified as goodwill. Management believes the goodwill will be recovered through the expected strategic benefits as 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):

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  Amount
Current assets $ 5,465
Property and equipment 20,765
Identified intangible assets 4,000
Goodwill 7,909
Deferred tax asset 814
Other long-term assets 113
Current liabilities (1,744
)
Deferred tax liabilities (8,125
)
  $ 29,197

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 for each period presented. Pro forma adjustments primarily relate to additional depreciation, amortization and interest costs. The information reflects our historical data and historical data from these acquired businesses for the periods indicated. The pro forma data may not be indicative of the results we would have achieved had we completed these acquisitions on January 1, 2004 or 2005, or that we may achieve in the future. The pro forma financial information should be read in conjunction with the accompanying historical financial statements.


  Pro Forma
Years Ended December 31,
  2005 2004
  (In thousands, except per share data)
Total revenues $ 155,942
$ 112,922
Net income $ 5,578
$ 2,072
Earning per common share:  
 
Basic $ 0.33
$ 0.13
Diluted $ 0.32
$ 0.13

The fair market values of identified intangible assets were determined by an independent valuation and certain intangible assets will be amortized to expense over the estimated useful lives. Customer relations are amortized over their estimated benefit period of 20 years. Intangibles related to the non-compete agreement are amortized over the period of the non-compete agreement of two years. Depreciation and amortization includes amortization of intangibles of $325,556 and $202,500 for the years ended December 31, 2006 and 2005, respectively. Amortization of intangibles is not expected to exceed $403,000 per year over the next five years.

The total cost and accumulated amortization of intangible assets related to our 2005 acquisition are as follows:

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Table of Contents
  December 31,
  2006 2005
Customer relations $ 2,200,000
$ 2,200,000
Non compete agreement 800,000
800,000
Trade name —
1,000,000
Intangible assets 3,000,000
4,000,000
Customer relations (192,500
)
 (82,500
)
Non compete agreement (335,556
)
 (120,000
)
Accumulated amortization (528,056
)
 (202,500
)
Intangible assets, net $ 2,471,944
$ 3,797,500

Effective December 31, 2006, the Thornton Drilling Company subsidiary was merged with the parent 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.

4. Related-Party Transactions

William R. Ziegler, a member of our board of directors through March 31, 2006, is of counsel to Satterlee Stephens Burke & Burke LLP, legal counsel for 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. At December 31, 2005, the Company had no outstanding accounts payable to Satterlee Stephens Burke & Burke LLP.

During 2005 and 2004, the Company entered into contract arrangements with Triana Energy, Inc. and Columbia Natural Resources, which was purchased by Triana in August 2003, and sold by Triana Energy, Inc. in December 2005. The Company’s former Vice Chairman of the Board of Directors is the Chief Executive Officer of Triana Energy, Inc. For the periods ended December 31, 2005 and 2004, the Company had revenues related to transactions with Columbia Natural Resources and Triana Energy, Inc. of $5,232,314 and $8,734,944, respectively. At December 31, 2005, the Company had accounts receivable from Columbia Natural Resources and Triana Energy, Inc. of $481,657. Effective December 31, 2005, the Chief Executive Officer of Triana Energy, Inc. resigned as the Vice Chairman of the Board of Directors and as a Director. Both Triana Energy, Inc. and the Company share an ultimate common venture fund owner that provided capital investment funds employed in the initial formation of the business.

5. Accounts Receivable

Accounts receivable consist of the following:


  December 31,
  2006 2005
Billed receivables $ 44,007,225
$ 20,829,400
Unbilled receivables 4,443,991
7,063,290
Total receivables 48,451,216
27,892,690
Allowance for doubtful accounts (838,585
)
 (313,436
)
Net receivables $ 47,612,631
$ 27,579,254

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, 2006, unbilled receivables was net of an estimated reserve for sales credits of $230,292.

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Activity in the allowance for doubtful accounts is as follows:


Balance, December 31, 2003 $ 222,346
Net charge to expense 152,015
Amounts written off (105,169
)
Balance, December 31, 2004 269,192
Net charge to expense 155,000
Amounts written off (110,756
)
Balance, December 31, 2005 313,436
Net charge to expense 680,000
Amounts written off (154,851
)
Balance, December 31, 2006 $ 838,585

6. Property, Buildings and Equipment

Major classes of property, buildings and equipment are as follows:


  December 31,
  2006 2005
Land $ 1,010,432
$ 967,432
Buildings 1,357,621
978,489
Drilling and well service equipment 220,005,680
135,617,519
Vehicles 7,607,236
5,949,101
Furniture and fixtures 161,929
37,977
Computer equipment 534,949
595,702
Leasehold improvements 97,956
78,175
Construction in progress 25,646,641
22,809,603
  256,422,444
167,033,998
Less accumulated depreciation 69,338,007
46,250,906
  $ 187,084,437
$ 120,783,092

During 2006 and 2005, we capitalized $1,781,958 and $307,254, respectively, of interest costs incurred during the construction periods of certain drilling equipment.

7. Income Taxes

The current and deferred components of income tax expense are as follows:


  Years Ended December 31,
  2006 2005 2004
Current tax expense:  
 
 
Federal $ 11,786,167
$ 56,629
$ 73,055
State 1,643,013
73,681
—
Foreign —
31,481
212,685
  13,429,180
161,791
285,740
Deferred tax expense (benefit):  
 
 
Federal 8,660,392
3,506,596
48,755
State 328,109
515,676
—
Foreign —
(84,540
)
 81,892
  8,988,501
3,937,732
130,647
Income tax expense $ 22,417,681
$ 4,099,523
$ 416,387

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The components of the net deferred income tax assets and liabilities are as follows:


  December 31,
  2006 2005
Current deferred tax assets:  
 
Bad debt expense $ 325,841
$ 122,240
Workers compensation and deferred revenue accrual 1,103,803
541,014
Net operating loss carry forwards 3,166,824
6,333,551
Federal AMT tax credit —
87,923
Other 89,335
7,175
  4,685,803
7,091,903
Long-term deferred tax assets:  
 
Net operating loss carry forwards 270,400
3,437,223
Stock compensation 212,843
13,604
  483,243
3,450,827
Total deferred tax assets 5,169,046
10,542,730
Deferred tax liabilities:  
 
Foreign subsidiary earnings —
13,278
Intangible assets 958,917
—
Property, building and equipment, principally due to differences in depreciation 23,005,247
17,903,503
Total deferred tax liabilities 23,964,164
17,916,781
Net deferred taxes $ 18,795,118
$ 7,374,051

The Company had federal net operating loss carryforwards of approximately $7.7 million and $24.8 million at December 31, 2006 and 2005, respectively. These losses may be carried forward for 20 years and will begin to expire in 2019. State net operating losses at December 31, 2006 and 2005, were $15.9 million and $27.9 million, respectively. State losses vary as to carryforward period and will begin to expire in 2013, depending upon the jurisdiction where applied. Foreign net operating losses were fully utilized in 2004. The company also had federal alternative minimum tax (AMT) credits of approximately none and $88,000 at December 31, 2006 and 2005, respectively.

The elimination of the deferred tax valuation allowance occurred with the allocation of purchase price associated with the Thornton Drilling Company acquisition described in Note 3. The elimination of the valuation allowance was treated as a reduction in goodwill associated with this acquisition.

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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:


  2006 2005 2004
U.S. statutory federal income tax rate 35
%
 34
%
 34
%
Income tax expense at the statutory federal tax rate $ 18,994,345
$ 3,297,539
$ 1,340,661
State, local and provincial income taxes, net of  
 
 
federal tax benefit 2,382,203
509,207
189,277
Change in valuation reserve —
—
(1,922,942
)
Meal allowances 1,558,357
239,516
8,326
Non-cash compensation 235,121
255,957
—
Trade name write off 350,000
—
—
Domestic production deduction (342,885
)
 —
—
Permanent and other (66,352
)
 30,707
42,165
Deferred tax adjustment (693,108
)
 (233,403
)
 395,188
Deferred taxes on unremitted earnings —
—
363,712
Income tax expense $ 22,417,681
$ 4,099,523
$ 416,387

During 2006, 2005 and 2004, the Company made tax payments of approximately $11 million, $252,000 and $4,000, respectively.

8. Accrued Expenses and Other Liabilities

A detail of accrued expenses and other liabilities is as follows:


  December 31,
  2006 2005
Accrued payroll and bonus $ 3,668,083
$ 2,709,219
Accrued workers compensation 2,840,777
1,312,214
Other 2,462,445
1,331,875
  $ 8,971,305
$ 5,353,308

9. Debt Obligations

The Company entered into a Revolving Credit and Security Agreement with PNC Bank, as agent for a group of lenders, dated March 31, 2005, which matures on March 30, 2009, that was subsequently amended on April 19, August 15, and October 5, 2005, and on September 27 and December 5, 2006, which 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. There is a $7,500,000 sublimit for letters of credit. Amounts outstanding under the revolving credit facility bear interest at either (i) the higher of the Federal Funds Open Rate plus one half of 1.00% or the base commercial lending rate of the agent for the lenders (8.25% at December 31, 2006) or (ii) LIBOR plus 2.00% (7.3601% at December 31, 2006). A fee of 0.25% is applied to the unused portion of the $100 million capacity of the revolving credit facility. As of December 31, 2006, approximately $27.8 million was outstanding under the Revolving Credit and Security Agreement and $3.2 million of the total capacity had been utilized to support the Company’s letter of credit requirement. As of December 31, 2005, the Company had no outstanding loans under this revolving credit facility, but $2.7 million of the total capacity was utilized to support the Company’s letter of credit requirement.

The Revolving Credit and Security Agreement is secured by substantially all of the Company’s assets, with certain exceptions, and contains affirmative and negative covenants and provides for events of default that are typical for an agreement of this type. Among the affirmative covenants are requirements to maintain a specified tangible net worth (initially $43 million) and a fixed charge

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coverage ratio of 1.10 to 1.00. Among the negative covenants are restrictions on major corporate transactions, capital expenditures, payment of dividends, incurrence of indebtedness, and amendments to our organizational documents. Net capital expenditures (excluding acquisitions) were limited to $45 million in 2005 and $10 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. On September 27, 2006, the Agreement was amended to increase the 2006 net capital expenditure limitation to $125 million. Among the events of default are a change in control and any change in our operations or condition, which has a material adverse effect. As of December 31, 2006, the Company was in compliance with all debt covenants.

Current portion of other obligations consists of financed annual insurance costs. The interest rate on these borrowings is 6.258%. This debt will be repaid over 11 months in 2007. The $1.0 million decrease from December 31, 2005 is due to the financing of worker’s compensation premiums in the prior policy year.

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, 2006, the total outstanding balance under these arrangements, including principal and interest, was approximately $8.5 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, 2006:


Year ending December 31:  
2007 $ 2,884,837
2008 2,712,921
2009 2,205,187
2010 697,211
2011 —
Total minimum debt payments 8,500,156
Less amount representing interest 735,906
Total present value of minimum payments 7,764,250
Less current portion of such obligations 2,508,127
Long-term portion of obligations $ 5,256,123

The Company paid approximately $2.3 million, $2.7 million, and $629,000 in interest on all debt during 2006, 2005 and 2004, respectively.

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10. Productive Capacity

The Company has increased its productive capacity through the purchase of rotary drilling rigs, equipment (primarily dozers and trucks), and drilling supplies from other drilling companies and suppliers. The following table illustrates the number of rigs purchased and the total purchase price of the rigs and related drilling equipment since the inception of the Company:


Purchases by Year Rotary Rigs and Related
Drilling Equipment
Purchased		 Purchase Price
(in millions)
1997 12
$ 7.2
1998 19
11.0
1999 7
8.3
2000 7
4.7
2001 4
7.5
2002 2
4.2
2004 2
5.5
2005 29
57.7
2006 7
42.3
Total 89
$ 148.4

In December 2005 and April 2006, the Company entered into agreements with National Oilwell Varco (‘‘NOV’’) to purchase six rigs and related equipment for an aggregate purchase price of $52.7 million. All six rigs are capable of horizontal and underbalanced drilling. As of December 31, 2006, three of the six rigs have been delivered and are currently in service in the Fort Worth basin. As of March 1, 2007, five of the six rigs have been delivered. The Company has paid $46.1 million to NOV, including $2.5 million as a downpayment for the remaining rig, which is scheduled for delivery in March 2007.

11. Stockholders’ Equity

At December 31, 2006, the number of authorized shares of common and preferred stock was 75,000,000 and 100,000 shares, respectively, of which 21,523,577 and zero were outstanding, and 2,406,840 and zero were 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 $55,379,000 in proceeds, net of underwriting discounts, commissions, and offering expenses. In connection with the offering, the Company repaid approximately $51,332,000 of outstanding debt and approximately $4,047,000 to upgrade their drilling rig fleet and purchase of related equipment.

On October 6, 2005, the Company effected a stock dividend of 1.6325872 shares for each outstanding share of common stock. All common stock prices and amounts impacted by the dividend have been retroactively adjusted. Certain share calculations resulting in fractional amounts have been truncated.

12. Management Compensation

Stock Option Plans

The Company has two stock option plans, the 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, 2006, 661,775 options have been granted under the 2005 Stock Option Plan and 1,404,401 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. 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.

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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:


  2006 2005 2004
  Shares Weighted
Average
Exercise
Price		 Shares Weighted
Average
Exercise
Price		 Shares Weighted
Average
Exercise
Price
Outstanding at beginning of year 1,541,380
$ 7.21
1,009,605
$ 3.63
1,009,605
$ 3.63
Granted 130,000
$ 15.32
1,059,529
$ 10.62
—
$ —
Exercised (357,468
)
 $ 3.91
(527,754
)
 $ 7.22
—
$ —
Canceled/forfeited (221,743
)
 $ 11.73
—
$ —
—
$ —
Outstanding at end of year 1,092,169
$ 8.33
1,541,380
$ 7.21
1,009,605
$ 3.63
Options exercisable at end of year 540,955
$ 5.16
650,916
$ 3.54
496,251
$ 3.45
Weighted average fair value of
options granted during the year		  
$ 6.29
 
$ 4.16
 
$ —

Cash received from the exercise of options for the year ended December 31, 2006, was $1,399,178. New shares of common stock are issued to satisfy options exercised. The total intrinsic value of options exercised during 2006 is $3,889,076.

A summary of options outstanding as of December 31, 2006, is as follows:


  Options Outstanding Options Exercisable
Range of Exercise Prices Number
Outstanding		 Weighted
Average Years
of Remaining
Contractual
Life		 Weighted
Average
Exercise
Price		 Number
Outstanding		 Weighted
Average
Exercise
Price
$2.51 to $3.80 606,776
4.7
$ 3.52
452,111
$ 3.42
$14.00 to $15.60 485,393
8.9
$ 14.35
88,844
$ 14.00
  1,092,169
 
 
540,955
 

The aggregate intrinsic value of options exercisable as of December 31, 2006 is $4,826,324. The weighted average remaining contractual life of options exercisable as of December 31, 2006 is 4.88 years.

The total fair value of options vested during the year ended December 31, 2006 was $1,192,031.

The following table summarizes additional information as of December 31, 2006 for fully vested options and options expected to vest:


Number of shares outstanding 899,244
Weighted average exercise price $7.66
Aggregate intrinsic value 5,769,153
Weighted average remaining contractual term 6.22 years

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 $321,000, $210,000 and $120,000 during the years ended December 31, 2006, 2005 and 2004, respectively.

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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.

At December 31, 2006 and 2005 the threshold amounts were $29.1 million and $26.5 million, respectively. These amounts are determined based upon cash invested in UDC (and invested by UDC in the Company’s stock) plus a compounded annual return of 10% less cash returned to investors. Compensation expense was not recognized prior to January 1, 2005, as the threshold amounts were not exceeded. In 2005, $752,816 of compensation costs was recognized as a result of the fair value of the assets owned by UDC exceeding the threshold. During the year-ended December 31, 2006, the Company recognized $546,358 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%.

In addition, the Company recognized $34,881 in compensation costs during 2005 related to variable stock options issued.

13. Earnings Per Common Share

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:


  2006 2005 2004
Net income $ 31,851,877
$ 5,599,118
$ 3,526,736
Weighted average shares outstanding 21,284,047
16,012,486
13,162,936
Incremental shares from assumed
conversion of stock options		 376,745
541,408
148,267
Weighted average and assumed
incremental shares		 21,660,792
16,553,894
13,311,203
Earnings per share:  
 
 
Basic $ 1.50
$ 0.35
$ 0.27
Diluted $ 1.47
$ 0.34
$ 0.26

The weighted average number of dilutive shares in 2006 excludes 485,393 options due to their antidilutive effects.

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14. Commitments and Contingencies

Operating Leases

The Company leases certain buildings and automobiles under noncancelable operating agreements. Lease expense was approximately $1.8 million, $1.1 million and $788,000 for the years ended December 31, 2006, 2005 and 2004, respectively. As of December 31, 2006, future minimum lease payments under noncancelable operating leases consist of the following:


2007 $ 1,871,206
2008 1,466,431
2009 801,264
2010 299,566
2011 96,000
Total $ 4,534,467

Litigation

Due to the nature of our business, we are, from time to time, involved in routine litigation or subject to disputes or claims related to our business activities, including workers’ compensation claims and employment-related disputes. The Company is a defendant in a lawsuit brought in U.S. District Court to determine insurance coverage for the death of a well worker. The Company intends to vigorously defend the claim; however, an unfavorable outcome is reasonably possible. The Company could experience a potential loss of approximately $500,000 to $700,000. The Company has not reserved any amounts for this legal matter. In the opinion of our management, no other such pending litigation, disputes or claims against us will have a material adverse effect on our financial condition, results of operations or cash flow from operations, and there is only a remote possibility that any such other matter will require any additional loss accrual.

15. Quarterly Financial Information (Unaudited)

The following table sets forth unaudited financial information on a quarterly basis for each of the last two years (in thousands, except per share amounts):


  First
Quarter		 Second
Quarter		 Third
Quarter		 Fourth
Quarter		 Total
2006  
 
 
 
 
Revenues $ 56,579
$ 58,816
$ 69,482
$ 72,067
$ 256,944
Operating income 11,723
10,631
17,112
15,021
54,487
Net income 6,972
6,459
9,794
8,627
31,852
Net income per common share:  
 
 
 
 
Basic $ 0.33
$ 0.30
$ 0.46
$ 0.41
$ 1.50
Diluted $ 0.32
$ 0.30
$ 0.45
$ 0.40
$ 1.47
2005  
 
 
 
 
Revenues $ 17,164
$ 34,771
$ 43,230
$ 46,456
$ 141,621
Operating income 296
1,842
3,016
6,060
11,214
Net income 242
1,015
13
4,329
5,599
Net income per common share:  
 
 
 
 
Basic $ 0.02
$ 0.06
$ —
$ 0.27
$ 0.35
Diluted $ 0.02
$ 0.06
$ —
$ 0.26
$ 0.34

16. Subsequent Events

As part of our annual insurance renewal process effective December 1, 2006, it was decided to change insurance underwriters for our worker’s compensation coverage.  In order to provide collateral to our

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new underwriter we entered into a Letter of Credit Agreement with our bank, effective January 1, 2007.  The Letter of Credit amount increases quarterly from $437,500 as of January 1, 2007 to $1,750,000 at September 1, 2007.  The Letter of Credit outstanding at December 31, 2006 for $3.2 million is to provide collateral to our previous underwriter. This amount is expected to decrease in the future as claims are settled.

On January 18, 2007, we sold various components of a stacked rig which was being held for sale for $415,000.

Item 9.  Changes in and Disagreements With Accountants on Accounting and Financial Disclosure

None

Item 9A.  Controls and Procedures

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 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 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, 2006 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

Item 9B.  Other Information

None.

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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 2007 Annual Meeting of Stockholders. We intend to file that definitive proxy statement with the SEC by April 30, 2007.

Item 10.  Directors, Executive Officers and Corporate Governance

We have adopted a code of ethics and business conduct, entitled ‘‘Standards of Integrity,’’ that applies to our employees including our principal executive officer, principal financial officer, principal accounting officer and persons performing similar functions. Our Standards of Integrity can be found posted in the investor relations section on our website at http://www.uniondrilling.com.

The other information required in response to this Item will be set forth in our definitive proxy statement for our 2007 Annual Meeting of Stockholders and is incorporated herein by reference.

Item 11.  Executive Compensation

The information required in response to this Item will be set forth in our definitive proxy statement for our 2007 Annual Meeting of Stockholders and is incorporated herein by reference.

Item 12.  Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters

The information required in response to this Item will be set forth in our definitive proxy statement for our 2007 Annual Meeting of Stockholders and is incorporated herein by reference.

Item 13.  Certain Relationships and Related Transactions, and Director Independence

The information required in response to this Item will be set forth in our definitive proxy statement for our 2007 Annual Meeting of Stockholders and is incorporated herein by reference.

Item 14.  Principal Accountant Fees and Services

The information required in response to this Item will be set forth in our definitive proxy statement for our 2007 Annual Meeting of Stockholders and is incorporated herein by reference.

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PART IV

Item 15.    Exhibits, Financial Statement Schedules

(a)    The following documents are filed as a part of this Report:

1.    Financial Statements.

See Index to Consolidated Financial Statements on page 35.

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 consolidated financial statements.

(b)    Exhibits.    The following exhibits are filed (or incorporated by reference) as part of this report:


Exhibit Number   Description
3 .1
— Form of Amended and Restated Certificate of Incorporation of Union (incorporated by reference to Exhibit 3.1 to our Registration Statement on Form S-1 (File No. 333-127525) filed on August 15, 2005).
3 .2
— Form of Amended and Restated Bylaws of Union (incorporated by reference to Exhibit 3.2 to our Registration Statement on Form S-1 (File No. 333-127525) filed on August 15, 2005).
4 .1
— Specimen Stock Certificate for the common stock, par value $0.01 per share, of Union (incorporated by reference to Exhibit 4.1 to our Registration Statement on Form S-1 (File No. 333-127525) filed on August 15, 2005).
10 .1*
— Amended and Restated 2000 Stock Option Plan of Union (incorporated by reference to Exhibit 10.1 to our Registration Statement on Form S-1 (File No. 333-127525) filed on August 15, 2005).
10 .2*
— Form of stock option agreements under the Amended and Restated 2000 Stock Option Plan (incorporated by reference to Exhibit 10.2 to our Registration Statement on Form S-1 (File No. 333-127525) filed on August 15, 2005).
10 .3*
— Stock Option Plan and Agreement, dated May 13, 1999, by and between Union and Christopher Strong (incorporated by reference to Exhibit 10.3 to our Registration Statement on Form S-1 (File No. 333-127525) filed on August 15, 2005).
10 .4*
— 2005 Stock Option Plan of Union (incorporated by reference to Exhibit 10.4 to our Registration Statement on Form S-1 (File No. 333-127525) filed on August 15, 2005).
10 .5*
— Form of stock option agreements under the 2005 Stock Option Plan (incorporated by reference to Exhibit 10.5 to our Registration Statement on Form S-1 (File No. 333-127525) filed on August 15, 2005).
10 .6
— Form of Stockholders Agreement by and among Union and certain of its direct and indirect stockholders (incorporated by reference to Exhibit 10.6 to Amendment No. 2 to our Registration Statement on Form S-1 (File No. 333-127525) filed on October 18, 2005).
10 .7
— Revolving Credit and Security Agreement, dated March 31, 2005, between Union the lenders signatory thereto and PNC Bank, as agent for the lenders, together with the First Amendment dated April 19, 2005 (incorporated by reference to Exhibit 10.7 to our Registration Statement on Form S-1 (File No. 333-127525) filed on August 15, 2005).

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Exhibit Number   Description
10 .8
— Stock Purchase Agreement, dated as of March 31, 2005, by and between Union and Richard Thornton, the sole stockholder of Thornton Drilling Company (incorporated by reference to Exhibit 10.8 to our Registration Statement on Form S-1 (File No. 333-127525) filed on August 15, 2005).
10 .9
— Registration Rights Agreement, dated as of March 31, 2005, between Union and Richard Thornton (incorporated by reference to Exhibit 10.9 to our Registration Statement on Form S-1 (File No. 333-127525) filed on August 15, 2005).
10 .10*
— Employment Agreement, dated as of March 31, 2005, between Union and Richard Thornton (incorporated by reference to Exhibit 10.10 to our Registration Statement on Form S-1 (File No. 333-127525) filed on August 15, 2005).
10 .11
— Stock Purchase Agreement, dated as of March 31, 2005, by and between Union, Steven A. Webster, Wolf Marine S.A. and William R. Ziegler (incorporated by reference to Exhibit 10.11 to our Registration Statement on Form S-1 (File No. 333-127525) filed on August 15, 2005).
10 .12
— Option and Asset Purchase and Sale Agreement dated as of February 28, 2005 between Thornton Drilling Company and SPA Drilling, LP; Amendment No. 1 to Purchase and Sale Agreement between Thornton Drilling Company and SPA Drilling, LP; and Assignment and Assumption Agreement between Thornton Drilling Company and Union Drilling Texas, LP. (incorporated by reference to Exhibit 10.12 to Amendment No. 4 to our Registration Statement on Form S-1 (File No. 333-127525) filed on November 7, 2005).
10 .13
— Asset Purchase Agreement, dated May 31, 2005, between C and L Services, LP and Union Drilling Texas, LP. (incorporated by reference to Exhibit 10.13 to our Registration Statement on Form S-1 (File No. 333-127525) filed on August 15, 2005).
10 .14
— Forms of Indemnification Agreement with Union directors and certain of its officers (incorporated by reference to Exhibit 10.14 to Amendment No. 2 to our Registration Statement on Form S-1 (File No. 333-127525) filed on October 18, 2005).
10 .15
— Second Amendment, dated August 15, 2005, to the Revolving Credit and Security Agreement between Union, the lenders signatory thereto and PNC Bank, as agent for the lenders (incorporated by reference to Exhibit 10.15 to Amendment No. 1 to our Registration Statement on Form S-1 (File No. 333-127525) filed on September 28, 2005).
10 .16
— Asset Purchase Agreement, dated August 12, 2005, between C and L Services, LP and Union Drilling Texas, LP. (incorporated by reference to Exhibit 10.16 to Amendment No. 1 to our Registration Statement on Form S-1 (File No. 333-127525) filed on September 28, 2005).
10 .17
— Third Amendment, dated October 5, 2005, to the Revolving Credit and Security Agreement between Union, the lenders signatory thereto and PNC Bank, as agent for the lenders (incorporated by reference to Exhibit 10.17 to Amendment No. 2 to our Registration Statement on Form S-1 (File No. 333-127525) filed on October 18, 2005).
10 .18
— Option to purchase drilling rigs from National Oilwell Varco (incorporated by reference to Exhibit 10.18 to Amendment No. 4 to our Registration Statement on Form S-1 (File No. 333-127525) filed on November 7, 2005).
10 .19
— Purchase and Sale Agreement, dated December 8, 2005, between Union and National-Oilwell, L.P., relating to the purchase of three drilling rigs (incorporated by reference to Exhibit 10.1 to our Form 8-K (File No. 000-51630) filed on December 13, 2005).

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Exhibit Number   Description
10 .20
— Option Agreement, dated December 8, 2005, between Union and National-Oilwell, L.P., relating to the purchase of three drilling rigs (incorporated by reference to Exhibit 10.2 to our Form 8-K (File No. 000-51630) filed on December 13, 2005).
10 .21
— Assets Purchase Agreement, dated December 19, 2005, between Permian Drilling Corporation and Maverick Oil and Gas, Inc., (incorporated by reference to Exhibit 10.1 to our Form 8-K (File No. 000-51630) filed on February 3, 2006).
10 .22
— Agreement Regarding Assignment and Assumption of Rights and Obligations under Assets Purchase Agreement, dated January 30, 2006, between Maverick Oil and Gas, Inc. and Thornton Drilling Company; (incorporated by reference to Exhibit 10.1 to our Form 8-K (File No. 000-51630) filed on February 3, 2006).
10 .23
— Addendum to Assets Purchase Agreement and Letter Agreement, dated January 30, 2006, between Permian Drilling Corporation, Maverick Oil and Gas, Inc. and Thornton Drilling Company, (incorporated by reference to Exhibit 10.1 to our Form 8-K (File No. 000-51630) filed on February 3, 2006).
10 .24
— Purchase and Sale Agreement dated April 21, 2006 between Union and National-Oilwell, L.P., relating to the purchase price of three drilling rigs (incorporated by reference to Exhibit 10.2 to our Form 8-K (File No. 000-51630) filed on May 2, 2006).
10 .25
— Fourth Amendment to Revolving Credit and Security Agreement, dated September 27, 2006, between Union Drilling, Inc., Thorton Drilling Company, Union Drilling Texas L.P., and PNC Bank, National Association, for itself and for other lenders (incorporated by reference to Exhibit 10.1 to our Form 8-K (File No. 000-51630) filed on September 28, 2006).
10 .26
— Fifth Amendment to Revolving Credit and Security Agreement, dated December 5, 2006, between Union Drilling, Inc., Thorton Drilling Company, Union Drilling Texas L.P., and PNC Bank, National Association, for itself and for other lenders (incorporated by reference to Exhibit 10.1 to our Form 8-K/A (File No. 000-51630) filed on December 7, 2006).
23 .1
— Consent of Ernst & Young LLP, Independent Registered Public Accounting Firm, filed herewith.
31 .1
— Certification of Chief Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 filed herewith.**
31 .2
— Certification of Chief Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 filed herewith.**
32 .1
— Certification of Chief Executive Officer Pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 filed herewith.**
32 .2
— Certification of Chief Financial Officer Pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 filed herewith.**
* Management contract or compensatory plan or arrangement.
** This certification is being furnished solely to accompany this Annual Report pursuant to 18 U.S.C. § 1350, and is not being filed for purposes of Section 18 of the Securities Exchange Act of 1934, as amended, and is not to be incorporated by reference to any filing of the Company, whether made before or after the date hereof, regardless of any general incorporation language in such filing.

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SIGNATURES

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


  UNION DRILLING, INC.
March 15, 2007 By:  /s/ Christopher D. Strong                                
  Christopher D. Strong
President and Chief Executive Officer

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

Signature Title Date
/s/ Christopher D. Strong President and Chief Executive
Officer (Principal Executive Officer)		 March 15, 2007
Christopher D. Strong
/s/ Dan E. Steigerwald Vice President, Chief Financial
Officer, Treasurer and Secretary
(Principal Financial and
Accounting Officer)		 March 15, 2007
Dan E. Steigerwald
/s/ Thomas H. O’Neill, Jr. Chairman of the Board
(non-executive)		 March 15, 2007
Thomas H. O’Neill, Jr.
/s/ Howard I. Hoffen Director March 15, 2007
Howard I. Hoffen
/s/ Gregory D. Myers Director March 15, 2007
Gregory D. Myers
/s/ Thomas M. Mercer, Jr. Director March 15, 2007
Thomas M. Mercer, Jr.
/s/ M. Joseph McHugh Director March 15, 2007
M. Joseph McHugh
/s/ T.J. Glauthier Director March 15, 2007
T.J. Glauthier
/s/ Ronald Harrell Director March 15, 2007
Ronald Harrell

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