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, 2008

¨ 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	16-1537048
(State or other jurisdiction of incorporation or organization)	(I.R.S. Employer Identification Number)

4055 International Plaza Suite 610 Fort Worth, Texas	76109
(Address of principal executive offices)	(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, a non-accelerated filer or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):

Large accelerated filer	¨	Accelerated filer	x
Non-accelerated filer	¨  (Do not check if a smaller reporting company)	Smaller reporting company	¨

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Securities Exchange Act of 1934).    Yes  ¨    No  x

The aggregate market value of the registrant’s voting and nonvoting common equity held by non-affiliates of the registrant as of June 30, 2008, the last business day of the registrant’s most recently completed second fiscal quarter, was $304,673,181 based on the last sales price of the registrant’s common stock on June 30, 2008 as reported on the NASDAQ Global Market. The determination of affiliate status for the purposes of this calculation is not necessarily a conclusive determination for other purposes. The calculation excludes shares held by directors, officers and stockholders whose ownership exceeded 10% of the Registrant’s outstanding Common Stock. Exclusion of these shares should not be construed to indicate that any such person controls, is controlled by or is under common control with the Registrant.

As of March 10, 2009, there were 22,024,381 shares of common stock, par value $0.01 per share, of the registrant issued and 20,024,381 shares outstanding.

DOCUMENTS INCORPORATED BY REFERENCE

Portions of the definitive proxy statement related to the registrant’s 2009 Annual Meeting of Stockholders to be held on June 11, 2009 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

PART I			3
	Item 1.	Business	3
	Item 1A.	Risk Factors	12
	Item 1B.	Unresolved Staff Comments	18
	Item 2.	Properties	18
	Item 3.	Legal Proceedings	18
	Item 4.	Submission of Matters to a Vote of Security Holders	19
PART II			19
	Item 5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	19
	Item 6.	Selected Financial Data	22
	Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	23
	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			59
	Item 10.	Directors, Executive Officers and Corporate Governance	59
	Item 11.	Executive Compensation	59
	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
	SIGNATURES		62

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PART I

Statements we make in this Annual Report on Form 10-K, such as “Union Drilling” or the “company,” “we,” “us” and “our” refer to Union Drilling, Inc. for 2008 and 2007, and includes our wholly-owned subsidiaries for 2006. Statements we make in this Annual Report on Form 10-K that express a belief, expectation or intention, as well as those that are not historical fact, are forward-looking statements under the Private Securities Litigation Reform Act of 1995. These forward-looking statements are subject to various risks, uncertainties and assumptions, including those to which we refer under the heading “Cautionary Statement Concerning Forward-Looking Statements and Risk Factors” following Item 1 of Part I of this Annual Report. Our actual results may differ significantly from the results discussed in the forward-looking statements. Factors that might cause such a difference include, but are not limited to, those discussed in “Risk Factors,” “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and “Business” as well as those discussed elsewhere in this Annual Report. Actual events or results may differ materially from those discussed in this Annual Report.

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 an entity providing contract drilling services under the name “Union Drilling.” Through a combination of acquisitions and new rig construction, we currently operate a fleet of 71 marketed land drilling rigs. We presently focus our operations in selected natural gas production regions in the United States. We do not invest in oil and natural gas properties. The drilling activity of our customers is highly dependent on many factors, including the market price of oil and natural gas, available capital, available drilling resources, support services and market availability. These factors should not be considered an exhaustive list. See Item 1A. “Risk Factors.”

Substantially all of our rigs operate in unconventional natural gas producing areas, which are characterized by formations with very low permeability rock, such as shales, tight sands and coal bed methane, or CBM, that require specialized drilling techniques to efficiently develop the natural gas resources. Horizontal drilling is often used in these formations to increase the exposure of the wellbore to the natural gas producing formation and increase drainage rates and production volumes. We have equipped 50 of our 71 rigs for drilling horizontal wells. As many of these areas are also characterized by hard rock formations entailing more difficult drilling penetration conditions, we have equipped 46 of our 71 rigs with compressed air circulation systems, also known as underbalanced drilling, which provides higher penetration rates through hard rock formations when compared to traditional fluid-based circulation systems. In response to rising demand from our customers for equipment that is capable of drilling wells horizontally into unconventional natural gas formations and for underbalanced drilling services, we have increased our fleet of drilling rigs with these capabilities through acquisitions and new rig construction.

Our market

We provide drilling services to customers engaged in developing unconventional natural gas formations throughout the United States. We focus our efforts in the Appalachian and Arkoma Basins, as well as the Barnett Shale formation.

The Appalachian Basin is characterized by highly porous sandstones alternating with less porous shales, at depths of 3,000 to 8,000 feet. Since the mid 1970’s, significant resources have been committed to developing the natural gas bearing Clinton/Medina sands in northwestern Pennsylvania, western New York and eastern Ohio. The Clinton/Medina sands, which are 4,000 to 6,000 feet in depth, generally have very low porosities and permeabilities. To recover natural gas from this formation, fracturing techniques are used to increase permeability, allowing the natural gas to flow to the surface. More recently, producers have been increasing capital spending focused on the development of the deeper Marcellus Shale formation at depths of 6,000 to 8,000 feet.

The Marcellus Shale, also referred to as the Marcellus Formation, is a Middle Devonian-age black, low density, carbonaceous (organic rich) shale that occurs in the subsurface beneath much of Ohio, West Virginia, Pennsylvania and New York. Small areas of Maryland, Kentucky, Tennessee and Virginia are also underlain by the Marcellus Shale. Like other shale plays, initial development of the Marcellus Shale has employed a mix of smaller rigs to drill vertically into the formation and larger rigs that are capable of drilling several thousand feet horizontally through the formation. Smaller vertical rigs are often employed during the exploratory phase of a new shale formation to assess its extent and productivity at lower cost than drilling horizontal wells with larger rigs. As the economics

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and geology of a new shale play become better understood and the work becomes more developmental in nature, the proportion of horizontal rigs to vertical rigs increases. Initial production rates from completed horizontal wells in the Marcellus Shale compare favorably with other shale plays such as the Barnett and Fayetteville.

Natural gas also is found in shallow coal seams throughout the Appalachian Basin. This natural gas is commonly referred to as CBM. In recent years, natural gas producers have begun to exploit these CBM formations due to advances in extraction technology. In addition to exploration and development activity on behalf of more traditional natural gas producers, coal companies have engaged in the development of CBM formations in order to reduce the concentration of these deposits in advance of mining operations, reducing the risk of underground fires or explosions. We support these activities with rigs that drill horizontally into the coal seams, providing faster drainage than vertical drilling. We also have rigs that work for coal companies in advance of coal mining operations to extract metal casing and other materials from existing wells to reduce the possibility of underground fires or explosions during mining. With increased demand for natural gas drilling rigs in the Appalachian Basin, we have upgraded several of these rigs for that purpose and, as a result, well plugging and abandonment work for the coal companies is becoming a smaller portion of our business.

The Arkoma Basin includes Arkansas and eastern Oklahoma and covers 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.

Until recently, the primary natural gas bearing formation being developed by our customers in the Arkoma Basin was the Hartshorne coal seam, which is found at depths of 300 to 4,000 feet throughout much of 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.

Drilling activity and equipment requirements in the Arkoma Basin have changed over the past few years as operators have leased acreage to develop natural gas-bearing formations known as the Fayetteville Shale on the Arkansas side and the Caney and Woodford Shales on the Oklahoma side of the Arkoma Basin. These formations, existing at depths of 1,500 to 10,500 feet, are geologically similar to the Barnett Shale formation in northern Texas. Within the Fayetteville Shale, several operators have amassed substantial acreage positions and have horizontal drilling programs that are yielding results comparable to what has been achieved in some of the more prolific unconventional resource plays in North America. Much of the work that we perform is in eastern Arkansas in the Fayetteville Shale formation at depths considerably greater than the Hartshorne coal seam. In order to effectively compete in this play, we mobilized rigs from other locations, purchased existing rigs, ordered new ones and leased an office, maintenance facility and yard closer to the center of activity.

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.

Customers and marketing

Our customers are principally independent natural gas producers. We market our drilling rigs in various manners, primarily through employee marketing representatives. Repeat business from previous customers accounts for a substantial portion of our business. We enter into written contracts with our customers for all rig deployments. The length of contracts has ranged from very short term, for example, a one-well project, to much longer term for major exploration programs. The longest term contract we have entered into was for three years. Contractual commitments were obtained from our customers in recent years to substantiate the purchase of new rigs and significant rig upgrades.

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

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In Texas, we have drilled for oil in the eastern Permian Basin and we have drilled wells used for the disposal of salt water, a byproduct of natural gas production in most shale formations.

We market our rigs to a number of customers. In 2008, we performed services for 121 customers, up 6% from the 114 customers in 2007. In 2006, we drilled wells for 148 customers. The decrease in the number of customers in 2007 compared to 2006 is due to a higher concentration of our drilling activity with fewer customers, primarily large independent oil and natural gas companies. In 2008, 2007 and 2006, our top 20 customers provided 71%, 76% and 64%, respectively, of our total revenue. 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
2008	XTO Energy Inc.	17.7	%
	Quicksilver Resources Inc.	12.4	%
	Chief Oil & Gas LLC	4.9	%
	Total	35.0	%
2007	XTO Energy Inc.	14.5	%
	Quicksilver Resources Inc.	12.9	%
	Hallwood Energy, L.P.	6.5	%
	Total	33.9	%
2006	XTO Energy Inc.	11.5	%
	CONSOL Energy Inc.	6.2	%
	Fortuna Energy Inc.	5.4	%
	Total	23.1	%

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 2008 and 2007, approximately 90% and 84% respectively, of our revenues were derived from daywork contracts. Most of the wells we drilled pursuant to footage contracts were drilled in the northern Appalachian region. Contract terms we offer generally depend on the complexity and risk of operations, the on-site drilling conditions, the type of equipment used and the anticipated duration of the work to be performed. Our contracts generally provide for the drilling of a single well or a series of wells and typically permit the customer to terminate on short notice.

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

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

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The economic return under a footage contract can be greater than a daywork contract, depending on the productivity of the equipment and crew. The economic risk under footage contracts is greater than under daywork contracts because we assume more of the costs associated with drilling operations generally assumed by the operator in a daywork contract, including risk of blowout, loss of hole, lost or damaged drill pipe, machinery breakdowns, abnormal drilling conditions and risks associated with subcontractors’ services, supplies, cost escalation and personnel. Historically, the percentage of revenues derived from footage contracts has decreased from over 50% in the early 2000’s to approximately 10% at present. At December 31, 2008, only 12 of our 71 rigs were working on a footage basis. Many of our footage contracts now have provisions whereby some or all of the risks associated with geological issues and down hole mechanical matters have been shifted to our customers. The transfer of this risk is done by contractually transferring the drilling services from a footage drilled basis to an hourly based daywork type contract when unforeseen or uncontrollable events are encountered during the drilling process. When this occurs, the contract also provides for the transfer of third party costs and tangible items such as drill bits from us to our customers during these unforeseen problematic periods.

Our rig fleet

A land drilling rig consists of a derrick, a substructure, a hoisting system, a rotating system, pumps and holding tanks to circulate and clean drilling fluid, blowout preventers and other related equipment. Diesel engines are typically the main power sources for a drilling rig. There are numerous factors that differentiate land drilling rigs, including their power generation systems and their drilling depth capabilities. The actual drilling depth capability of a rig may be more or less than its rated depth capability due to numerous factors, including the size, weight and amount of the drill pipe on the rig. The intended well depth and the drill site conditions determine the amount of drill pipe and other equipment needed to drill a well. Generally, land rigs operate with crews of four to six persons.

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

The size and type of rig utilized depends, among other factors, upon well depth and site conditions. An active maintenance and replacement program during the life of a drilling rig permits upgrading of components on an individual basis. Over the life of a typical rig, due to the normal wear and tear of operating up to 24 hours a day, several of the major components, such as engines, air compressors, boosters and drill pipe, are replaced or rebuilt on a periodic basis as required. Other components, such as the substructure, mast and drawworks, can be utilized for extended periods of time with proper maintenance.

Our drilling rigs have engines that power the hoisting and rotating systems rated from 400 to 1,600 horsepower and derricks with weight suspension capacities from 110,000 to 750,000 pounds. Most of our rigs that are equipped for horizontal drilling have a pair of circulating pumps, each powered by engines that vary from 500 to 1,600 horsepower and our rigs that are capable of underbalanced drilling have two to four air compressors and one to two compression boosters, each with engines of 450 to 750 horsepower. Eighteen of our rigs, including two rigs under construction, also have top drive units that separate the power and control of the hoisting and rotating functions, which often provides better performance in horizontal drilling. Many larger drilling rigs capable of drilling in deep formations generate electricity from diesel engines and power electric motors attached to the equipment in the hoisting, rotating and circulating systems. We have seven rigs of this design.

Due to the geologic characteristics in the Appalachian and Arkoma Basins, many of the wells drilled in these areas utilize underbalanced or air drilling. We believe that air drilling provides advantages over traditional fluid drilling techniques when drilling through hard rock formations. These advantages include improved drilling penetration rates, no fluid loss into the formation and minimized formation damage. We believe that we have drilled more wells using air drilling techniques than any other U.S. contractor.

We believe that our drilling rigs and other related equipment are in good operating condition. Our employees perform periodic maintenance and repair work on our drilling rigs. We rely on various oilfield service companies for major repair work and overhaul of

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our drilling equipment when needed. We also engage in periodic improvement of our drilling equipment. In the event of major breakdowns or mechanical problems, our rigs could be subject to significant idle time and a resulting loss of revenue if the necessary repair services are not immediately available.

We also own a fleet of trucks that are used to move our rigs as well as bulldozers, forklifts, various vehicles and other equipment that is used to support the operation of our rigs.

The following table sets forth certain information regarding each of our marketed rigs or rigs being manufactured as of March 5, 2009:

Rig No.	Drawworks (HP)	Capacity (LBS)	Pumps (HP)	Horizontal	Under- balanced	Top Drive	Built / Rebuilt
58	1,600	750,000	1,600	ü	ü	ü	2008
219	1,500	750,000	1,600	ü			2006
220	1,500	750,000	1,600	ü		ü	2006
221	1,500	750,000	1,600	ü			2006
222	1,500	750,000	1,600	ü		ü	2007
223	1,500	750,000	1,600	ü		ü	2007
224	1,500	750,000	1,600	ü			2007
212	1,400	460,000	1,300	ü			2005
216	1,200	520,000	1,300	ü			2005
227*	1,000	550,000	1,600	ü		ü	2009
209	1,000	550,000	1,300	ü			1975 / 2007
217	1,000	550,000	1,300	ü			1978 / 2008
225	1,000	550,000	1,300	ü			1976 / 2007
207	1,000	550,000	920	ü			1975 / 2008
122	1,000	500,000	1,600	ü	ü		2007 / 2008
121	1,000	500,000	1,000	ü	ü		2006 / 2008
54	1,000	441,000	1,000	ü	ü	ü	2004
59	1,000	400,000	1,000	ü	ü	ü	2007
215	920	420,000	1,000	ü			2005
214	920	390,000	1,000	ü	ü		1970
125*	900	500,000	1,600	ü	ü		2009
126*	900	500,000	1,600	ü	ü		2009
48	900	410,000	1,000	ü	ü	ü	1982
124*	900	400,000	1,300	ü	ü	ü	1982 / 2009
47	900	369,000	1,000	ü	ü		1981 / 2007
52	900	365,000	1,000	ü	ü	ü	1975 / 2002
21	900	365,000	900	ü	ü		1982 / 2007
38	900	358,000	900	ü	ü		1981 / 2005
43	900	358,000	1,000	ü	ü	ü	1979 / 2001
51	850	300,000	800	ü	ü		1979 / 2007
110	800	500,000	1,000	ü	ü		1964 / 2005
226	800	420,000	900	ü			1972 / 2008
211	800	390,000	1,000	ü	ü		1968
123	800	390,000	800	ü	ü		1957 / 2008
112	800	375,000	800	ü	ü		1967
40	800	358,000	800	ü	ü		1976 / 2008
104	800	300,000	900	ü	ü		1978
114	800	250,000	800	ü	ü		1976

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Rig No.	Drawworks (HP)	Capacity (LBS)	Pumps (HP)	Horizontal	Under- balanced	Top Drive	Built / Rebuilt
116	800	250,000	800	ü	ü		1976 / 2008
205	750	350,000	800	ü			1975
206	750	325,000	920	ü			1980 / 2008
210	750	280,000	650				1968
115	700	250,000	900	ü	ü		1976 / 2007
109	600	110,000	n/a		ü	ü	2000 / 2007
201	550	250,000	400				1950
55	515	185,000	n/a	ü	ü	ü	2005
56	515	185,000	n/a	ü	ü	ü	2005
57	515	185,000	550	ü	ü	ü	2005
53	515	185,000	350	ü	ü	ü	2004
32	500	310,000	900	ü	ü		1982
45	500	300,000	1,000	ü	ü		1984 / 2007
37	500	300,000	600		ü		1982 / 2006
46	500	300,000	600	ü	ü		1982
44	500	275,000	600		ü		1985 / 2008
119	500	120,000	500	ü	ü	ü	2004
117	500	110,000	n/a		ü	ü	2003
8	475	195,000	600				1963
24	450	300,000	600		ü		1981
25	450	300,000	600		ü		1978 / 2007
34	450	300,000	600		ü		1979 / 2007
35	450	300,000	600		ü		1979
36	450	300,000	600		ü		1980
105	450	260,000	800	ü	ü		1968
5	450	240,000	n/a		ü		1981
42	450	231,000	400				1981
20	450	224,000	800	ü	ü		1982
18	450	224,000	400				1981
3	450	224,000	n/a		ü		1968
15	450	212,000	800		ü		1982
41	450	212,000	400				1978
10	450	212,000	n/a		ü		1979
1	450	212,000	250				1975
108	450	200,000	800	ü	ü		1979
31	400	212,000	n/a				1981
203	400	180,000	400				1955

* Rig is under construction, with delivery scheduled for the first half of 2009.

Competition

We encounter substantial competition from other land drilling contractors. 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. We have the largest number of rigs in the Appalachian Basin and our principal competitors are primarily smaller, family-owned companies that serve fragmented markets within the Appalachian Basin. Our principal competitor in the Arkoma Basin is Nabors Industries Inc. Our competitors in northern Texas include many publicly traded drilling companies as well as several privately held drilling companies and no single competitor dominates this market.

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

• 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 quicker than us in periods of high rig demand.

Raw materials

The materials and supplies we use in our drilling operations include fuels to operate our drilling equipment, drill pipe and drill collars. We do not rely on a single source of supply for any of these items. During 2008 and 2007, the industry experienced dramatic increased costs due to higher levels of demand. Currently, the costs for materials and supplies have stabilized.

Seasonality

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

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

Employees

As of February 27, 2009, we had approximately 1,140 full-time employees actively working and 390 employees on temporary lay-off. Approximately 84 of these active employees are administrative or supervisory employees. The rest of our employees operate or maintain our drilling rigs, rig-hauling trucks and other related equipment. The number of hourly employees fluctuates depending on the number of drilling projects we are engaged in at any particular time. Some of our employees are considered to be “shared employees.” These employees are primarily engaged in our Texas field operations and consisted of approximately 360 active employees and 130 employees on temporary lay-off at February 27, 2009. Under this arrangement, we pay a fee for certain human

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resource functions, including the worker’s compensation and payroll liabilities to be assumed by the third-party professional employer organization (“PEO”.) The PEO we utilize is fully licensed and bonded under Texas law. None of our employment arrangements is subject to collective bargaining arrangements.

Operating hazards and insurance

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

• blowouts,

• craterings,

• fires,

• explosions,

• equipment failures,

• loss of well control,

• poisonous gas emissions,

• loss of hole,

• damaged or lost equipment, and

• damage or loss from inclement weather or natural disasters.

These hazards could cause personal injury or death, serious damage to or destruction of property and equipment, suspension of drilling operations, or damage to the environment, including damage to producing formations and surrounding areas. Generally, we seek to obtain contractual indemnification from our customers for some of these risks. To the extent not transferred to customers by contract, we seek protection against some of these risks through insurance, including property casualty insurance on our rigs and drilling equipment, commercial general liability, which has coverage extension for underground resources and equipment coverage, commercial contract indemnity, commercial umbrella and workers’ compensation insurance.

There are risks that are outside of our control. Nonetheless, we believe that we are adequately insured for liability and property damage to others with respect to our operations. However, such insurance may not be sufficient to protect us against liability for all consequences of well disasters, extensive fire damage or damage to the environment.

We maintain workers’ compensation insurance in all states in which we operate. The state of Ohio is monopolistic with regard to this coverage. We pay premiums to Ohio directly based upon the payroll related to our employees working in the state. In all other states, we obtain such coverage from third-party providers.

Government regulation and environmental matters

General

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

Environmental regulation

Our activities are subject to existing federal, state and local laws and regulations governing environmental quality, pollution control and the preservation of natural resources. These laws and regulations concern, among other things, air emissions, water use and disposal, 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

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legislation also provide special protections to animal and aquatic life that could be affected by our activities. In general, under various applicable environmental programs, we may potentially be subject to regulatory enforcement action in the form of injunctions, cease and desist orders and administrative, civil and criminal penalties for violations of environmental laws. We may also be subject to liability for natural resource damages and other civil claims arising out of a pollution event.

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

Environmental regulations that affect our customers also have an indirect impact on us. Increasingly stringent environmental regulation of the oil and natural gas industry has led to higher drilling costs and a more difficult and lengthy well permitting process. The primary environmental statutory and regulatory programs that affect our operations include the following:

Oil Pollution Act and Clean Water Act. The Oil Pollution Act of 1990, or OPA, amends several provisions of the federal Water Pollution Control Act of 1972, which is commonly referred to as the Clean Water Act, or CWA, and other statutes as they pertain to the prevention of and response to spills or discharges of hazardous substances or oil into navigable waters. Under the OPA, a person owning or operating a facility or equipment (including land drilling equipment) from which there is a discharge or threat of a discharge of oil into or upon navigable waters and adjoining shorelines is liable, regardless of fault, as a “responsible party” for removal costs and damages. Federal law imposes strict, joint and several liability on facility owners for containment and clean-up costs and some other damages, including natural resource damages, arising from a spill. The U.S. Environmental Protection Agency, or EPA, is also authorized to seek preliminary and permanent injunctive relief, civil or administrative fines or penalties and, in some cases, criminal penalties and fines. State laws governing the control of water pollution also provide varying civil and criminal penalties and liabilities in the case of releases of petroleum or its derivatives into surface waters or into the ground. In the event that a discharge occurs at a well site at which we are conducting drilling operations, we may be exposed to claims under the CWA or similar state laws.

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

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:

• the current owner and operator of a facility from which hazardous substances are released,

• owners and operators of a facility at the time any hazardous substances were disposed,

• generators of hazardous substances who arranged for the disposal or treatment at or transportation to such facility of hazardous substances, and

• 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.

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Hazardous waste disposal

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

Health and safety matters

Our facilities and operations are also subject to the requirements of the federal Occupational Safety and Health Act, or OSHA, as well as comparable state and local laws that regulate the protection of worker health and safety. In addition, the OSHA hazard communication standard requires that we maintain certain information about any hazardous materials used or produced in our operations and that this information be provided to employees, state and local government authorities and citizens. We believe that our operations are in material compliance with OSHA requirements, including general industry standards, record keeping requirements and monitoring of occupational exposure to regulated substances.

Trucking regulations

We operate a fleet of trucks to transport our drilling rigs and related equipment. We operate as a private motor carrier, not as a common carrier for hire. We are licensed to perform both intrastate and interstate trucking operations. As a private motor carrier we are subject to certain safety regulations issued by the U.S. Department of Transportation, or DOT, and comparable state regulatory agencies. These trucking regulations cover, among other things, driver operations, maintaining log books, truck manifest preparations, the placement of safety placards on our regulated trucks and trailers, driver drug and alcohol testing, safety of operation and equipment, and several other aspects of truck operations. Our trucking operations are also subject to certain OSHA requirements when our employees are loading or unloading equipment at a drilling site. We believe our trucking operations are in material compliance with applicable regulations.

Available Information

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

We file annual, quarterly and current reports, proxy statements and other information with the Securities and Exchange Commission, or SEC. You may read and copy our reports, proxy statements and other information at the SEC’s public reference room at 100 F Street, N.E., Room 1580, Washington, D.C. 20549-0213. You can request copies of these documents at prescribed rates by writing to the SEC at Public Reference Section, SEC, 100 F Street, N.E., Washington, D.C. 20549-0213. Please call the SEC at 1 800-SEC-0330 for more information about the operation of the public reference room. Our SEC filings are also available at the SEC’s website at www.sec.gov. In addition, you can read and copy our SEC filings at the office of the National Association of Securities Dealers, Inc. at 1735 K Street N.W., Washington, D.C. 20006.

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 at www.uniondrilling.com or by contacting our Investor Relations Department at 817-735-8793. In addition, our Code of Ethics is available on our website.

Item 1A. Risk Factors

Risks Relating to Our Business

A deteriorating global economy may affect the Company’s business.

As a result of recent volatility in oil and natural gas prices and substantial uncertainty in the capital and credit markets due to the deteriorating global economic environment, the Company is unable to accurately predict the extent to which its customers will reduce spending on exploration and development drilling or whether customers and /or vendors and suppliers will be able to access financing necessary to sustain their current level of operations, fulfill their commitments and/or fund future operations and obligations. Furthermore, the Company is unable to predict the extent its existing customers will have continuing viability and capability to pay

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amounts owed to the Company. The deteriorating global economic environment may impact industry fundamentals, and the potential resulting decrease in demand for drilling rigs would cause the drilling industry to contract. These conditions could have a material adverse effect on the Company’s business, including reductions in our revenues and impairments of our rig fleet.

Our business and operations are substantially dependent upon, and affected by, the level of U.S. land-based 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. land-based natural gas exploration and development activity. Exploration and development activity determines the demand for contract land drilling and related services. We have no control over the factors driving the level of U.S. natural gas exploration and development activity. If the level of that activity decreases, our business and results of operations could be adversely affected. Other factors include, among others, the following:

• the 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 land-based contract drilling industry has experienced significant volatility in profitability and asset values. The industry’s most recent significant downturn began in the second half of 2008 and declined rapidly in 2009. Management is unable to predict at the present time the extent or longevity of this market decline. The major causes of the industry downturn were generated by a significant widespread global economic downturn and credit restrictions. This economic downturn, driven by decreasing demand, has generated lower natural gas prices and, in turn, has reduced many of our customers’ capital expenditures as well as their ability to finance their commitments. We cannot predict the future level of demand for, or pricing of, natural gas, for our contract drilling services or overall future conditions in the land-based contract drilling industry. We have seen a down turn in our rig utilization, and an increase in requests from customers for pricing considerations. We continue to monitor, evaluate, and implement changes to meet these changing conditions. We have laid off workers, deferred capital expenditure to future periods, and continue to reduce costs.

Term contracts may in certain instances be terminated without an early termination payment.

Term drilling contracts customarily provide for termination at the election of the customer, with an “early termination payment” to be paid to the Company if a contract is terminated prior to the expiration of the term. However, under certain limited circumstances, such as destruction of a drilling rig, limited capital resources of the customer or bankruptcy of the customer, no early termination payment may be paid to the Company or, if paid, not paid in a timely manner. Even if an early termination payment is owed to the Company, the recent deteriorating global economy may affect the customer’s ability to timely pay (or pay at all) the early termination payment.

In the year ended December 31, 2008, we derived approximately 35% 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, 2008, our three largest customers accounted for approximately 18%, 12% 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

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the rigs that they may choose not to utilize. The loss of any of our principal customers or the failure to remarket the rigs utilized by those customers could have a material adverse effect on our financial condition and results of operations.

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

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

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

Reduced demand can drive suppliers from the market. With reduced suppliers, consumables for our operations may not be readily available. Additionally, suppliers may experience shortfalls in obtaining their materials and/or labor. Suppliers who have been regular providers to us may experience shortfalls and that may lead to delays as we secure other sources.

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 additional leverage in financing acquisitions, it may adversely affect our financial position.

The process of integrating acquired rigs or newly constructed rigs may involve unforeseen difficulties and may require a disproportionate amount of management’s attention and other resources. We may not be able to successfully manage and integrate new rigs into our existing operations or successfully maintain the market share attributable to drilling rigs that we purchase. We also may encounter cost overruns related to newly constructed rigs or unexpected costs related to acquired rigs, including costs associated with major overhauls. To the extent we experience some or all of these difficulties, our financial condition would be adversely affected.

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

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

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

• 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;

• availability of specialized services; and

• cost increases.

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

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

The contract drilling industry is capital intensive. Our cash flow from operations and the continued availability of credit are subject to a number of variables, including general economic conditions, and more specifically, 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.

Sources of additional funds through additional borrowings may not be available in future periods.

We may not be able to secure additional future borrowings in the amount or at the time when needed. If we are at any time not able to obtain the necessary capital resources, our financial condition and results of operations could be materially adversely affected.

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

The success of our business is highly dependent upon the services, efforts and abilities of certain key employees, such as our regional managers and of Christopher D. Strong, our President and Chief Executive Officer, A.J. Verdecchia, our Chief Financial Officer and David S. Goldberg, our General Counsel. Our business could be materially and adversely affected by the loss of any of these individuals. We have limited employment agreements with some key employees. We do not maintain key man life insurance on the lives of any of our executive officers.

If we cannot keep our rigs utilized at profitable rates, our operating results could be adversely affected.

Our business has high fixed costs, and if we cannot keep our rigs utilized at profitable rates, our operating results could be adversely affected through reductions in our revenues and impairments of our rig fleet.

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.

We have no control over the timing of payment of our deferred tax liabilities.

We currently have deferred tax liabilities and have no control over the timing of the payment of these deferrals. These deferred liabilities could come due at a time when our revenues are reduced. This could cause tax payments to be due at a time when our cash flow from operations is reduced. Such a situation could have a material adverse effect on our financial condition.

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

We face competition from significantly larger domestic and international drilling contractors, many with greater resources. Their greater resources may enable them to allocate those resources into any of our regional markets. The additional competition in our markets, either by existing competitors or new entrants would increase the supply in those markets, which could adversely affect the rates we can charge and utilization levels we can achieve.

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

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

• blowouts;

• craterings;

• fires;

• explosions;

• equipment failures;

• poisonous gas emissions;

• loss of well control;

• loss of hole;

• damaged or lost equipment; 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. There is no guarantee that our insurance carriers will be able to perform at the time their performance is due.

Oil and natural gas prices are volatile, and low prices could negatively affect our financial results in the future.

Our operations can be materially affected by low oil and natural gas prices. Significant reductions in oil and natural gas prices depress the level of exploration and production activity and result in a corresponding decline in demand for the Company’s services. Worldwide military, political and economic events, including initiatives by the Organization of Petroleum Exporting Countries, may affect both the demand for, and the supply of, oil and natural gas. Fluctuations in the demand and supply of oil and natural gas have contributed in the past to, and are likely to continue to contribute in the future to, price volatility. A prolonged reduction in demand for the Company’s services could have a material adverse effect on the Company’s business, financial condition and results of operations.

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

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

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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.

Our debt agreements contain restrictions that limit our flexibility in operating our business.

Our revolving credit facility contains various provisions that limit our ability to engage in specified types of transactions. These provisions limit our ability to, among other things:

• incur additional indebtedness

• issue certain preferred shares;

• unless certain conditions are satisfied, 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.

As of February 27, 2009, Union Drilling Company LLC, our principal stockholder, owned approximately 40% of our outstanding common stock. As a result, Union Drilling Company LLC and its affiliates may substantially influence the outcome of stockholder votes, including votes concerning the election of directors, the adoption or amendment of provisions in our certificate of incorporation or bylaws and the approval of mergers and other significant corporate transactions. The existence of this level of ownership concentration makes it less likely that any small holder of our common stock will be able to affect the management or direction of Union Drilling. These factors may also have the effect of delaying or preventing a change in the management or voting control of Union Drilling.

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

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

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, 2008 through February 27, 2009, the average daily trading volume of our common stock as reported by the NASDAQ Global Market was 208,313 shares. There can be no assurance that a more or less active trading market in our common stock will develop. As a result, relatively small or large trades may have a disproportionate impact on the price of our common stock and, therefore, may contribute to the price volatility of our common stock. As a result, our common stock may be subject to greater price volatility than the stock market when taken as a whole, or comparable securities of other contract drilling service providers, who may or may not have greater volumes.

The market price of our common stock has been, and may continue to be, volatile. During the period from January 1, 2008 through February 27, 2009, the trading price of our common stock ranged from $2.94 to $22.73 per share. Because of the limited trading market of our common stock and the price volatility of our common stock, you may be unable to fully sell shares of our common stock when you desire or at a price you desire.

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Item 1B. Unresolved Staff Comments

None.

Item 2. Properties

Facilities

Our principal executive offices are located in Fort Worth, Texas, while our contract drilling operations are conducted from eight field offices, described as follows:

Location	Service Area	Property Description	Leased/Own
Fort Worth, TX	Corporate	12,600 sq ft office space	Leased
Punxsutawney, PA	Appalachian Basin (Northern)	39,600 sq ft warehouse space and 25,000 sq ft office and yard space	Leased
Buckhannon, WV	Appalachian Basin (Southern)	36 acres land, 4,900 sq ft office space and 32,400 sq ft warehouse space	Own
Williamsport, PA	Marcellus Shale	4 acres land and 1,200 sq ft office space	Leased
Abilene, TX	Permian Basin	3 acres yard space, 3,500 sq ft office space, 3,000 sq ft shop space, 9,000 sq ft warehouse space	Leased
Cresson, TX	Fort Worth Basin – Barnett Shale	17 acres land, 3,200 sq ft office space and 9,350 sq ft warehouse space	Own
Midland, TX	Permian Basin	4 acres land 1,200 sq ft temporary office space	Leased Own
Pocola, OK	Arkoma Basin	48 acres land, 4,800 sq ft office space and 8,000 sq ft warehouse space	Own
		2.5 acres land in McCurtain, OK	Own
		1,420 sq ft office space in Bartlesville, OK	Own
Searcy, AR	Fayetteville Shale	10 acres land, 11,800 sq ft shop and 4,325 sq ft office space	Leased

Item 3. Legal Proceedings

From time to time, we are a party to claims, litigation or other legal or administrative proceedings that we consider to arise in the ordinary course of our business. While no assurances can be given regarding the outcome of these or any other pending proceedings, or the ultimate effect such outcomes may have, we do not believe we are a party to any legal or administrative proceedings which, if determined adversely to us, individually or in the aggregate, would have a material effect on our financial position, results of operations or cash flows. Management believes that the Company maintains adequate levels of insurance necessary to cover its business risk.

On October 31, 2008, the Company was named in a lawsuit filed in the United States District Court for the Eastern District of Arkansas (Western Division). The lawsuit was filed by Stephen Rose, individually, and Elizabeth Rose, both individually and on behalf of the deceased children of Stephen and Elizabeth Rose. The lawsuit alleges negligence on behalf of the Company relating to a

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traffic accident involving a mobile drilling rig owned by the Company. The Roses’ children were fatally injured in this accident. The lawsuit seeks unspecified compensatory and punitive damages. The Company intends to vigorously defend itself in this litigation.

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 2008.

PART II

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

As of February 27, 2009, 20,024,381 shares of our common stock were outstanding. As of February 27, 2009, the number of holders of record of our common stock was seven.

Our common stock trades on the NASDAQ Global Market under the symbol “UDRL.” The following table sets forth, for each of the periods indicated, the high and low trading price per share for our common stock on the NASDAQ Global Market:

	Low		High
Fiscal Year 2008
Fourth quarter	$	3.54	$	10.53
Third quarter	$	10.09	$	22.07
Second quarter	$	15.00	$	22.73
First quarter	$	13.06	$	22.09
Fiscal Year 2007
Fourth quarter	$	10.67	$	16.14
Third quarter	$	12.24	$	17.38
Second quarter	$	14.20	$	16.86
First quarter	$	11.45	$	14.67

The last reported sales price for our common stock on the NASDAQ Global Market on February 27, 2009 was $3.43 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 place certain limits on payment of dividends and share repurchases.

Purchases of Equity Securities

In August 2008, the Company’s Board approved the 2008 Union Drilling, Inc. Share Repurchase Program (the “Program”). Under the Program, the Board authorized the Company to repurchase up to two million shares of the Company’s outstanding common stock. The authorization under the Program did not have a stated expiration date and the pace of repurchase activity was dependant on factors such as levels of cash generation from operations, cash requirements for asset acquisitions or other capital expenditures, debt repayment and the Company’s current stock price, among other factors. The table below sets forth share repurchase information for the time periods indicated.

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	Total Number of Shares Purchased	Average Price Paid Per Share		Total Number of Shares Purchased As Part of Publicly Announced Plans or Programs	Maximum Number of Shares that May Yet be Purchased Under the Plans or Programs
November 1 - 30, 2008	509,603	$	5.44	509,603	1,490,397
December 1 - 31, 2008	1,205,215	$	5.09	1,205,215	285,182
Total	1,714,818	$	5.19	1,714,818

During January 2009, the remaining 285,182 authorized common shares under the Program were repurchased.

Equity Compensation Plan Information

The following table provides information as of December 31, 2008 about our 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	1,045,942	(1)	$	10.40	761,372	(2)
Equity compensation plans not approved by security holders	98,722	(3)	$	2.51	0

(1) Includes 252,326 shares of common stock issuable upon the exercise of options that were outstanding under our Amended and Restated 2000 Stock Option Plan and 793,616 shares of common stock issuable upon the exercise of options that were outstanding under our Amended and Restated 2005 Stock Incentive Plan, in each case, as of December 31, 2008.

(2) Includes 80,789 shares and 680,583 shares of common stock available for future issuance under our Amended and Restated 2000 Stock Option Plan and our Amended and Restated 2005 Stock Incentive Plan, respectively, as of December 31, 2008.

(3) Includes 98,722 shares of common stock issuable upon the exercise of options that were outstanding under a separate Union Drilling stock option plan and agreement, the terms of which are substantially similar to those of our Amended and Restated 2000 Stock Option Plan.

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PERFORMANCE GRAPH

The following graph shows a comparison of the total cumulative returns of an investment of $100 in cash on November 22, 2005, the first trading day following our initial public offering, in (i) our common stock, (ii) the Nasdaq Composite Index, U.S. Companies, and (iii) a peer group index that the Company selected that includes 5 public companies within our industry. The companies that comprise the peer group index are Bronco Drilling Company, Inc., Grey Wolf, Inc., Helmerich & Payne, Inc., Patterson-UTI Energy, Inc. and Pioneer Drilling Company. The historical comparisons in the graph are required by the SEC and are not intended to forecast or be indicative of the possible future performance of our common stock. The graph assumes that all dividends have been reinvested (since November 2005, the Company has not declared any dividends).

		December 31,
	November 22, 2005	2005	2006	2007	2008
Union Drilling, Inc	100	100.83	97.71	109.44	36.02
NASDAQ Composite	100	104.55	117.18	127.94	74.54
Peer Group	100	101.68	77.68	86.05	54.84

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,
	2008		2007		2006		2005		2004
	(In thousands, except per share data)
Revenues	$	302,780	$	289,035	$	256,944	$	141,621	$	67,832
Income from operations		22,389		53,291		54,487		11,214		2,198
Income before income taxes		20,361		52,852		54,270		9,699		3,943
Net income		7,750		30,832		31,852		5,599		3,527
Earnings per common share-basic		0.35		1.41		1.50		0.35		0.27
Earnings per common share-diluted		0.35		1.41		1.47		0.34		0.26
Long-term debt and capital lease obligations, including current portion and line of credit		47,745		17,309		35,574		7,826		7,904
Stockholders’ equity		204,713		203,409		167,599		132,439		43,547
Total assets		336,605		277,308		257,418		174,038		65,598
Calculation of EBITDA:
Net income	$	7,750	$	30,832	$	31,852	$	5,599	$	3,527
Interest expense		845		1,824		527		2,367		629
Income tax expense		12,611		22,020		22,418		4,100		416
Depreciation and amortization		44,298		39,072		24,820		15,121		8,103
Impairment charge		7,909		—		1,000		—		—
EBITDA	$	73,413	$	93,748	$	80,617	$	27,187	$	12,675

EBITDA is earnings before net interest, income taxes, depreciation and amortization and non-cash impairment. The Company believes EBITDA is a useful measure of evaluating its financial performance because it is used by external users, such as investors, commercial banks, research analysts and others, to assess: (1) the financial performance of Union Drilling’s assets without regard to financing methods, capital structure or historical cost basis, (2) the ability of Union Drilling’s assets to generate cash sufficient to pay interest costs and support its indebtedness, and (3) Union Drilling’s operating performance and return on capital as compared to those of other entities in our industry, without regard to financing or capital structure. EBITDA is not a measure of financial performance under generally accepted accounting principles. However, EBITDA is a common alternative measure of operating performance used by investors, financial analysts and rating agencies. A reconciliation of EBITDA to net income is included above. EBITDA as presented may not be comparable to other similarly titled measures reported by other companies.

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Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations

This MD&A section of our Annual Report on Form 10-K discusses our results of operations, liquidity and capital resources, and certain factors that may affect our future results, including economic and industry-wide factors. You should read this MD&A in conjunction with our financial statements and accompanying notes included under Part II, Item 8, of this Annual Report.

Statements we make in the following MD&A discussion and in other parts of this report that express a belief, expectation or intention, as well as those which are not historical fact, are forward-looking statements within the meaning of the federal securities laws and are subject to risks, uncertainties and assumptions. These forward-looking statements may be identified by the use of words such as “expect,” “anticipate,” “believe,” “estimate,” “potential” or similar words. These matters include statements concerning management’s plans and objectives relating to our operations or economic performance and related assumptions, including general economic and business conditions and industry trends, the continued strength or weakness of the contract land drilling industry in the geographic areas in which we operate, decisions about onshore exploration and development projects to be made by oil and gas companies, the highly competitive nature of our business, our future financial performance, including availability, terms and deployment of capital, the continued availability of qualified personnel, and changes in, or our failure or inability to comply with, government regulations, including those relating to the environment. We specifically disclaim any duty to update any of the information set forth in this report, including any forward-looking statements. Forward-looking statements are made based on management’s current expectations and beliefs concerning future events and, therefore, involve a number of assumptions, risks and uncertainties, including the risk factors described in Item 1A, “Risk Factors,” above. Management cautions that forward-looking statements are not guarantees, and our actual results could differ materially from those expressed or implied in the forward-looking statements.

Company Overview

Union Drilling, Inc. provides contract land drilling services and equipment, primarily to natural gas producers in the United States. In addition to our drilling rigs, we provide the drilling crews and most of the ancillary equipment needed to operate our drilling rigs. We commenced operations in 1997 with 12 drilling rigs and related equipment acquired from an entity providing contract drilling services under the name “Union Drilling.” Through a combination of acquisitions and new rig construction, we have increased the size of our fleet to 71 marketed land drilling rigs. We presently focus our operations in selected natural gas production regions in the United States, primarily the Fort Worth Basin in North Texas, the Arkoma Basin in Oklahoma and Arkansas and throughout the Appalachian Basin. We do not invest in oil and natural gas properties.

We completed several transactions from 2005 through 2008 which increased the size of our rig fleet, thus enhancing our ability to serve our customers. Two acquisitions in 2005 provided us with unconventional natural gas contract drilling operations in North Texas and the Arkoma Basin. We subsequently purchased additional rigs, including newly-constructed rigs, and have devoted significant capital expenditures to upgrade other rigs in our fleet for underbalanced and horizontal drilling. At various times, we remove rigs from our marketed fleet, and the components are made available for use on other rigs. These investments positioned our fleet to capitalize on our customers’ unconventional formation exploration and development activity.

Key Indicators of Financial Performance for Management

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

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The following table summarizes management’s key indicators of financial performance for the three years ended December 31, 2008.

	Years Ended December 31,
	2008			2007			2006
Revenue days		17,538			17,421			18,028
Average number of marketed rigs		71.0			70.5			64.7
Marketed rig utilization rates		67.5	%		68.0	%		76.4	%
Revenue per revenue day	$	17,264		$	16,591		$	14,252
Operating expenses per revenue day	$	11,181		$	9,867		$	8,605

Revenue days increased slightly in 2008 compared to 2007 primarily due to four new large rigs deployed in the latter part of the third quarter of 2008. This increase in revenue days was partially offset by the continued decline in demand for smaller rigs in our fleet, resulting in the slight decrease in the marketed rig utilization rates. Utilization and revenue days during 2007 were negatively impacted by a significant decline in the demand for smaller rigs in our fleet, the transition of our Rocky Mountain rigs to the Fayetteville Shale, which was completed at the end of the second quarter of 2007, and an increase in the number of rigs available in the market

We devote substantial resources to maintaining and upgrading our rig fleet. On a regular basis, we remove certain rigs from service to perform upgrades. In the short term, these actions result in fewer revenue days and slightly lower utilization; however, in the long term, we believe the upgrades will help the marketability of the rigs and improve their operating performance. We are currently performing or have recently performed, between contracts or as necessary, safety and equipment upgrades to various rigs in our fleet.

The increase in revenue per revenue day and operating expenses per revenue day in 2008 compared to 2007 was primarily related to the new rigs placed into service during the latter part of the third quarter of 2008. In addition, operating expenses per revenue day in 2008 grew more rapidly than revenue per revenue day due to higher employment costs, repairs and maintenance, fuel and supplies which we were not able to fully pass through to our customers. The increase in 2007 compared to 2006 was primarily due to the new rigs placed into service in late 2006 through early 2007. Due to their greater capacity, these new rigs earned a higher dayrate and incurred more operating expenses than older rigs in our fleet.

Market Conditions in Our Industry

The U.S. contract land drilling services industry is highly volatile. Volatility in oil and natural gas prices can produce wide swings in the levels of overall drilling activity in the markets we serve and affect the demand for our drilling services and the rates we can charge for our rigs. The availability of financing sources, past trends in oil and natural gas prices and the outlook for future oil and natural gas prices strongly influence the number of wells exploration and production companies decide to drill. See Item 1. “Business” and Item 1A. “Risk Factors.”

During fiscal 2008, 2007 and 2006, substantially all the wells we drilled for our customers were drilled in search of natural gas because of the depth capacity of our rigs and the natural gas rich areas in which we operate. Our customers are primarily focused on drilling for natural gas. Natural gas reserves are typically found in deeper geological formations and generally require premium equipment and quality crews to drill the wells.

Critical Accounting Policies and Estimates

Revenue and cost recognition. We generate revenue principally by drilling wells for natural gas producers on a contracted basis under daywork or footage contracts, which provide for the drilling of single or multiple well projects. Revenues on daywork contracts are recognized based on the days worked at the dayrate each contract specifies. Mobilization fees are recognized as the related drilling services are provided. We recognize revenues on footage contracts based on the footage drilled for the applicable accounting period. Expenses are recognized based on the costs incurred during that same accounting period.

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

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the contract. Our contracts generally provide for payment of invoices in 30 days. We established an allowance for doubtful accounts of approximately $1.5 million and $311,000 at December 31, 2008 and 2007, respectively. Any allowance established is subject to judgment and estimates made by management. We determine our allowance by considering a number of factors, including the length of time trade accounts receivable are past due, our previous loss history, our assessment of our customers’ current abilities to pay obligations to us and the condition of the general economy and the industry as a whole. We write off specific accounts receivable when they become uncollectible. During 2008, we wrote off $5.1 million of accounts receivable, primarily for four customers, three of which subsequently declared bankruptcy. We are pursuing our claims in the bankruptcy proceedings. During 2007, we wrote off $1.4 million of accounts receivable, of which $1.3 million was for one customer. In addition, the reserve for sales credits was approximately $213,000 and $186,000 as of December 31, 2008 and 2007, respectively.

At December 31, 2008 and 2007, our contract drilling work in progress totaled approximately $4.4 million and $4.3 million, respectively, all of which relates to the revenue recognized, but not yet billed, on daywork and footage contracts in progress at December 31, 2008 and 2007, respectively. The balance at December 31, 2008 includes $1 million of revenue we recognized as a result of our settlement with a customer under a drilling contract. Excluding this $1 million settlement accrual, the decrease in our contract drilling work in progress was due primarily to an increase in progress billings.

Asset impairments. We assess the impairment of property and equipment whenever events or circumstances indicate that the carrying value may not be recoverable. In connection with this review, assets are grouped at the lowest level at which identifiable cash flows are largely independent of other asset groupings. The cyclical nature of our industry has resulted in fluctuations in rig utilization over periods of time. Management believes that the contract drilling industry will continue to be cyclical and rig utilization will fluctuate. Based on management’s expectations of future trends, we estimate future cash flows over the life of the respective assets in our assessment of impairment. These estimates of cash flows are based on historical cyclical trends in the industry as well as management’s expectations regarding the continuation of these trends in the future. 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, existence of term drilling contracts, 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.

In the fourth quarter of 2008, oil and natural gas prices and the market capitalization of the Company declined significantly. However, our rig utilization rates and revenue trends were relatively consistent with or slightly improved over prior 2008 quarters and were improved over 2007 levels. Based on these factors, we considered whether there were indicators of impairment for certain of our property and equipment. We estimated future cash flows over the expected life of the identified long-lived assets and determined that, on an undiscounted basis, expected cash flows exceeded the carrying value of the long-lived assets. Based on this assessment, no impairment was recognized. In the event that market conditions continue to deteriorate, the Company may be required to record impairment of its property and equipment in the future, and such impairment could be material.

Depreciation. We provide for depreciation of our drilling rigs, transportation and other equipment on a straight line method over useful lives that we have estimated and that range from two to 12 years after the rig was placed into service. Unlike depreciation based on units-of-production, our approach to depreciation does not change when equipment becomes idle or when utilization changes. We continue to depreciate idled equipment on a straight-line basis despite the fact that our revenues and operating costs may vary with changes in utilization levels. Our estimates of the useful lives of our drilling, transportation and other equipment are based on our experience in the drilling industry with similar equipment.

Goodwill and intangible assets. Goodwill as of December 31, 2007 represented the excess of the purchase price over the estimated fair value of the net assets acquired in the purchase of Thornton Drilling Company in 2005. 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. 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.

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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. Goodwill impairment testing is performed at the level of our reporting units. In connection with the assessment of potential impairment of goodwill, we compare the fair value of the reporting unit with the carrying value. If the fair value exceeds the carrying value, no impairment is indicated. If the carrying value exceeds the fair value, we measure any impairment of goodwill in the reporting unit by allocating the fair value to the identifiable assets and liabilities of the reporting unit based on their respective fair values. Any excess unallocated fair value would equal the implied fair value of goodwill, and if that amount is below the carrying value of goodwill, an impairment charge is recognized.

In light of the adverse market conditions affecting our common stock price beginning in the fourth quarter of 2008, we utilized multiple market approaches to estimate the fair value of the reporting unit holding goodwill. In developing these fair value estimates, there is considerable judgment involved, particularly in determining the valuation methodologies to utilize and the weighting of different valuation methodologies applied. Certain key assumptions included the trading day period over which to assess market capitalization, implied control premium, multiples of earnings before interest, income taxes, depreciation and amortization, and forecasted 2009 operating results. Based on the results of the first step of the impairment test, an impairment of our goodwill was indicated. The allocation of the fair value of the reporting unit to the identifiable assets and liabilities of the reporting unit indicated no residual value for goodwill, and accordingly, we recorded an impairment charge of $7.9 million.

The fair market values of identified intangible assets acquired in the purchase of Thornton Drilling Company 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 were amortized over the period of the non-compete agreement of two years. Other intangibles are tested for impairment if indicators of impairment are present. In 2006, a $1 million trade name impairment charge was recognized when the Company decided to cease using the Thornton Drilling Company name in its operations.

Deferred taxes. We record deferred taxes for the basis difference in our property and equipment between financial reporting and tax reporting purposes and other costs such as compensation, employee benefits and other accrued liabilities which are deductible in different periods for financial reporting and tax reporting purposes. For property and equipment, basis differences arise from differences in depreciation periods and methods and the value of assets acquired in a business acquisition where we acquire the stock of an entity rather than its assets. For financial reporting purposes, we depreciate the various components of our drilling rigs and refurbishments over two to 12 years, while federal income tax rules require that we depreciate drilling rigs and refurbishments over five years. In 2008, tax depreciation also included bonus depreciation allowed as a result of the Economic Stimulus Act of 2008. Therefore, in the earlier years of our ownership of a drilling rig, our tax depreciation exceeds our financial reporting depreciation, resulting in our recording deferred tax liabilities on this depreciation difference. In later years, financial reporting depreciation exceeds tax depreciation, and the deferred tax liability begins to reverse. Refer to “Taxes” under “Results of Operations” for information regarding corrections made in 2006 to the income tax provision and deferred tax balances for underreporting of meals and incidental expenses that are only 50% deductible for income tax purposes and to recognize the deferred tax liability attributable to non-deductible intangibles acquired from Thornton Drilling Company.

Accrued workers’ compensation. The Company accrues for costs under our workers’ compensation insurance program in accrued expenses and other liabilities. We have a deductible of $100,000 per covered accident under our 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, 2008 and 2007, we satisfied this requirement with a $3.5 million and $5.0 million, respectively, letter of credit with our bank and our borrowing capacity under our revolving credit agreement with our bank has been reduced by the same amount collateralizing such letter of credit. We accrue for these costs as claims are incurred based on cost estimates established for each claim by the insurance companies providing the administrative services for processing the claims, including an estimate for incurred but not reported claims, estimates for claims paid directly by us, administrative costs associated with these claims and our historical experience with these types of claims. Some of our employees are considered to be “shared employees.” These employees are primarily engaged in our Texas field operations and consisted of approximately 500 employees at December 31, 2008. Under this arrangement, we pay a fee for certain human resource functions, including the worker’s compensation and payroll liabilities, to be assumed by the third-party professional employer organization. In addition, we accrue on a monthly basis the estimated workers compensation premium payable to Ohio, a monopolistic state.

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Stock-based compensation. The Company accounts for stock-based compensation under Statement of Financial Accounting Standards (“SFAS”) No. 123(R), “Share-Based Payment, revised 2004” (“SFAS No. 123R”) which requires that the cost resulting from all share-based payment transactions be measured at fair value and recognized in the financial statements. Compensation cost is recognized on a straight line basis over the requisite service period for the entire award and included in general and administrative expense. The amount of compensation cost recognized at any date is at least equal to the portion of the grant-date value of the award that is vested at that date. For the years ended December 31, 2008, 2007 and 2006, the Company recorded total stock-based compensation expense of approximately $2.1 million ($1.5 million net of tax), $968,000 ($741,000 net of tax) and $1.0 million ($751,000 net of tax), respectively. Total unamortized stock-based compensation was approximately $4.9 million at December 31, 2008, and will be recognized over a weighted average service period of 3.7 years.

The tax benefit realized from stock options exercised during the twelve months ended December 31, 2008 and 2007 is included as a cash inflow from financing activities on the statement of cash flows.

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:

	2008	2007	2006
Risk-free interest rate	1.6% - 2.5%	3.1% - 4.6%	4.4% - 5.0%
Expected life	5 years	2 - 5 years	5 - 6 years
Dividend yield	0%	0%	0%
Expected volatility	52% - 61%	44% - 47%	46% - 60%

The risk-free interest rate is the implied yield available for zero-coupon U.S. government issues with a remaining term equal to the expected life of the options.

The expected lives of the options are determined based on the Company’s expectations of individual option holders’ anticipated behavior and the term of the option.

The Company has not paid out dividends historically; thus, the dividend yield is estimated at zero percent.

Volatility is based upon price performance of the Company and a peer company, as the Company does not have a sufficient historical price base to determine potential volatility over the term of the issued options.

Results of Operations

Our operations primarily consist of drilling natural gas wells for our customers under daywork contracts and, to a lesser extent, footage contracts. Contract terms we offer generally depend on the complexity and risk of operations, the on-site drilling conditions, the type of equipment used and the anticipated duration of the work to be performed. Our contracts generally provide for the drilling of multiple wells or a specific period of time for which the rig will be under contract.

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Statements of Operations Analysis

The following table provides selected information about our operations for the years ended December 31, 2008, 2007 and 2006 (in thousands).

	Years Ended December 31,
	2008			2007			2006
Revenues	$	302,780		$	289,035		$	256,944
Operating expenses		196,100			171,897			155,123
Depreciation and amortization		44,298			39,072			24,820
Impairment charge		7,909			—			1,000
General and administrative expense		34,084			24,775			21,514
Interest expense		845			1,824			527
Other income and gain on sale or disposal of fixed assets		817			1,385			310
Effective income tax rate		61.9	%		41.7	%		41.3	%

Revenues. Our revenues grew by $13.7 million, or 5%, in 2008 compared to 2007, primarily due to $12.1 million of revenue related to four new large rigs being deployed in the latter part of the third quarter of 2008. Due to their greater capacity, these new rigs earn a higher day rate than our smaller rigs.

The $32.1 million, or 12%, increase in revenues in 2007 compared to 2006 was primarily due to the addition of six new rigs in late 2006 and early 2007. This was partially offset by a lower demand for smaller rigs in our fleet. These new rigs earned a day rate higher than the average rate earned in 2006, thus increasing the average rate per day by $2,300.

Operating expenses. Operating expenses increased $24.2 million, or 14%, in 2008 compared to 2007. The operating costs related to the four new rigs discussed above were $6.7 million. The remaining increase was due to increases in wages, vehicle and fuel expense, supplies and repairs and maintenance costs.

The $16.8 million, or 11% increase in operating expenses during 2007 compared to 2006 was primarily due to the new rigs placed into service in late 2006 and early 2007.

Depreciation and amortization. Depreciation and amortization expense increased $5.2 million, or 13%, primarily due to the increase in depreciable assets. Capital expenditures for rig purchases and capital equipment upgrades were $103.6 million in 2008, of which $36.3 million represents construction in progress at December 31, 2008.

Our depreciation and amortization expense in 2007 increased by $14.3 million, or 57%, from 2006 due to the increase in depreciable assets. Capital expenditures in 2007 were $68.1 million.

Impairment charge. The $7.9 million impairment charge in 2008 is related to goodwill impairment recognized in the fourth quarter of 2008.

In December 2006, the Company recognized a $1 million impairment charge to write off the trade name intangible asset. Effective December 31, 2006, Thornton Drilling Company, a then 100% owned subsidiary, was merged with and into the Company. Concurrently, the Company decided to cease using the Thornton Drilling Company name in its operations.

General and administrative expenses. Our general and administrative expenses increase by $9.3 million, or 38%, in 2008 compared to 2007. As a result of the deteriorating economy and its impact on specific customers, our provision for doubtful accounts increased $5.5 million in 2008. Payroll expense increased $2.1 million primarily due to additional wages to professional and administrative employees and other stock-based compensation expense increased approximately $900,000. An additional $900,000 increase related to safety expenses, other consulting fees and property taxes.

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General and administrative expenses increased $3.3 million, or 15% in 2007 compared to 2006. Payroll expenses increased $2.4 million primarily due to additional wages to professional and administrative employees and a $541,000 increase in other stock-based compensation expense. In addition, $1.3 million of the increase in general and administrative expenses was due to increases in property taxes, property insurance and safety program costs primarily related to the new rigs placed into service in late 2006 and early 2007. These increases were partially offset by the decrease in nonrecurring expenses in 2006, including $587,000 for consulting fees and $466,000 for certain relocation costs.

Interest expense. Interest expense decreased approximately $979,000 in 2008 compared to 2007, primarily due to the decrease in interest rates and higher capitalization of interest related to construction in progress during 2008.

Interest expense increased $1.3 million in 2007 compared to 2006 due to the higher average balance on our revolving credit facility during 2007 and less interest capitalized related to construction in progress during the last nine months of 2007.

Other income and gain on sale or disposal of fixed assets. Other income and gain on sale or disposal of fixed assets decreased $568,000 in 2008 compared to 2007 and increased $1.1 million in 2007 compared to 2006 primarily due to the sale of various utility vehicles at auction during the second quarter of 2007. The decrease in 2008 was partially offset by a $400,000 gain on involuntary conversions related to rig damages.

Taxes. Our effective income tax rates of 61.9%, 41.7% and 41.3% for 2008, 2007 and 2006, respectively, differ from the federal statutory rate of 35%, primarily due to the non-deductible goodwill impairment charge in 2008, state income taxes and permanent book/tax differences associated with 50% limitation on meals and entertainment expense, the domestic manufacturing deduction in 2007 and 2006 and stock-based compensation. See Note 6 to our Financial Statements for further information on our income taxes.

During 2006, the Company corrected its income tax provisions and deferred tax balances for underreporting of meals and incidental expenses that are only 50% deductible for income tax purposes and to recognize the deferred tax liability attributable to non-deductible intangibles acquired from Thornton Drilling Company. This correction resulted in a $462,000 additional charge to the Company’s income tax provision attributable to the year ended December 31, 2005. This correction also resulted in a $1.2 million increase to deferred tax liabilities, a $1.3 million reduction in deferred tax assets, a $2.5 million increase to recorded goodwill and a $462,000 increase to income taxes payable. Management concluded that the effect of the corrections was not material to any period impacted.

At both December 31, 2008 and 2007, we had federal net operating loss carryforwards for income tax purposes of approximately $98,000. These losses may be carried forward for 20 years and will begin to expire in 2023. State net operating loss carryforwards at December 31, 2008 and 2007 were $1.3 million and $3.4 million, respectively. State net operating loss carryforwards vary as to carryforward period and will begin to expire in 2013, depending upon the jurisdiction where applied. Based upon 2008 results and forecasted future operations, we believe it is more likely than not that the amounts will be realized.

Liquidity and Capital Resources

Our operations have historically generated sufficient cash flow to meet our requirements for debt service and equipment expenditures (excluding major business and asset acquisitions). Cash flow provided by operating activities was $73.0 million and $82.6 million during 2008 and 2007, respectively. During 2008, cash flow provided by operating activities was driven by net income plus non-cash depreciation and amortization, goodwill impairment and provision for deferred income taxes which totaled $80.1 million. The $25.5 million improvement in cash flow from operating activities for 2007 over 2006 was primarily due to our reduced investment in working capital in 2007 and an increase in net income after adjusting for the non-cash cost of depreciation and amortization and non-cash impairment. During 2007, due to a reduction in the average number of days to collect receivables, rather than a decline in revenue, our accounts receivable balance declined by $7.7 million. For 2007, net income plus depreciation and amortization was $69.9 million.

Our cash flow from operations primarily was used to invest in new machinery and equipment as well as for capitalized upgrades to our fleet. During 2008 and 2007, cash used in investing activities totaled $91.1 million and $65.8 million, respectively.

For the year ended December 31, 2008, our cash flow from financing activities was $18.4 million, consisting primarily of the $26.8 million increase in our net borrowings on our Revolving Credit and Security Agreement and other debt, and partially offset by $8.9

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million used for treasury stock purchases during the fourth quarter of 2008. The increase in our loan balance on our credit facility from $9.6 million at December 31, 2007 to $42.6 million at December 31, 2008 was primarily the result of the excess of our cash paid for 2008 capital expenditures of $94.1 million over our $73.0 million cash flow from operations. During 2007, our cash flow used in financing activities was $16.8 million, primarily due to the $20.8 million net debt repayments and partially offset by $4.0 million in stock option exercise proceeds and related tax benefit. Compared to 2006, our pace of acquisitions slowed in the second half of 2007. With a more balanced market for contract drilling services and fewer opportunities to invest in drilling rigs secured by term contracts, we used cash flow from operating activities to reduce the Company’s outstanding debt. This resulted in an $18.2 million reduction of the loan balance under our Revolving Credit and Security Agreement from $27.8 million on December 31, 2006 to $9.6 million on December 31, 2007.

We believe cash generated by our operations and our ability to borrow the currently unused portion of our Revolving Credit and Security Agreement of approximately $51.3 million, after reductions for approximately $3.5 million outstanding letters of credit as of December 31, 2008, should allow us to meet our routine financial obligations for the foreseeable future. Given the current economic environment, management intends to continue its active monitoring of all internal and external factors which could have a negative impact on the Company’s liquidity and, to the extent reasonably practicable, take appropriate mitigating actions as management may then deem to be warranted.

Sources of Capital Resources

Our rig fleet has grown from 12 rigs in 1997 to 71 marketed rigs at December 31, 2008. We have financed this growth with a combination of debt and equity financing. At December 31, 2008, our total debt to total capital was approximately 18.9%. Due to the volatility of rig demand in our industry, we are reluctant to take on additional debt in excess of the $51.3 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.

We entered into a Revolving Credit and Security Agreement with PNC Bank, for itself and as agent for a group of lenders, in March 2005. This credit facility has been amended numerous times, most recently on September 30, 2008. This credit facility matures on March 30, 2012 and provides for a borrowing base equal to $97.5 million. Amounts outstanding under the revolving credit facility bear interest, depending upon facility usage, at either (i) the higher of the Federal Funds Open Rate plus 75 to 125 basis points or PNC Bank’s base commercial lending rate (3.3% at December 31, 2008) or (ii) LIBOR plus 250 to 300 basis points (3.5% at December 31, 2008). Interest on outstanding loans is due monthly for domestic rate loans and at the end of the relevant interest period for LIBOR loans. Depending upon our facility usage, we are assessed an unused line fee of 37.5 to 62.5 basis points on the available borrowing capacity. The available borrowing capacity was $51.3 million as of December 31, 2008. There is a $7.5 million sublimit for letters of credit. If we repay and terminate the obligations under this facility, we would be liable for a substantial prepayment penalty.

In general, the credit facility is secured by substantially all of our assets The liquidation value of our assets serving as collateral is determined annually by an independent appraisal, with adjustments for acquisitions and dispositions between appraisals. The credit facility contains affirmative and negative covenants and also provides for events of default that are typical for such an agreement. Among the affirmative covenants are requirements to maintain a specified tangible net worth and a fixed charge coverage ratio. Among the negative covenants are restrictions on major corporate transactions, incurrence of indebtedness and amendments to our organizational documents. Events of default would include a change in control and any change in our operations or condition, which has a material adverse effect. As of December 31, 2008, we were in compliance with all financial covenants.

To date, the credit facility primarily has been used to pay for rig acquisitions and for our working capital requirements. Cash used for capital expenditures for 2008 was $94.1 million, and was primarily for drilling equipment. The credit facility may also be used by the Company, subject to certain conditions, to repurchase its common stock and/or pay a cash dividend. During the fourth quarter of 2008, treasury stock purchases totaled $8.9 million. As of December 31, 2008, we had a loan balance of $42.6 million under the credit facility, and an additional $3.5 million of the total capacity had been utilized to support our letter of credit requirement. As of December 31, 2007, $9.6 million was outstanding under our credit facility and $5.0 million of the total capacity had been utilized to support our letter of credit requirement. Cash used for capital expenditures for 2007 was $68.1 million, and was also primarily for drilling equipment.

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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 12 to 60 months. As of December 31, 2008 and 2007, the total outstanding balance under these arrangements was approximately $5.1 million and $7.7 million, respectively, and is classified, according to payment date, in current portion of notes payable for equipment and long-term notes payable for equipment in the accompanying balance sheets. The stated interest rate on these borrowings ranges from zero percent to 7.6%.

Uses of Capital Resources

For the years ended December 31, 2008 and 2007, the additions to our property and equipment consisted of the following (in thousands):

	Years Ended December 31,
	2008		2007
Buildings	$	138	$	168
Drilling rigs and related equipment		102,844		63,258
Vehicles		1,777		4,543
Computer equipment		73		151
	$	104,832	$	68,120

Our capital expenditures program in 2008 included the purchase or partial payments associated with eight new rigs for which we had agreements with customers to deploy the rigs under term contracts. In addition, we upgraded and enhanced several of the existing rigs and related equipment in our fleet. In particular, four rigs were upgraded with new 1,000 horsepower drawworks, and two new 550,000 pound derricks were installed and numerous rigs received higher horsepower mud pumps to facilitate longer reach horizontal drilling. Most of this capital spending was tied to improved dayrates and extension of term contracts to provide a return on the incremental capital.

The following table provides a summary of capital expenditures during 2008 for new rigs placed into service in 2008:

Rig No.	Drawworks (HP)	Capacity (LBS)	Power Type	2008 Capital Expenditures (in millions)		Actual Inservice Date
58	1,600	750,000	Electric	$	16.3	Aug 2008
59	1,000	400,000	Mechanical		9.5	Aug 2008
225	1,000	550,000	Mechanical		8.2	Jun 2008
226	800	420,000	Mechanical		1.2	Aug 2008
				$	35.2

During 2008, the Company made the following progress payments related to four rigs scheduled for delivery in 2009:

Rig No.	Drawworks (HP)	Capacity (LBS)	Power Type	2008 Capital Expenditures (in millions)		Projected Inservice Date	Original Commitment (in millions)
124	900	400,000	Mechanical	$	4.6	Apr 2009	$	10.8
125	900	500,000	Electric		4.6	Apr 2009		9.5
126	900	500,000	Electric		4.6	Apr 2009		9.5
227	1,000	550,000	Electric		10.6	Feb 2009		14.0
				$	24.4		$	43.8

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The following table provides a summary of capital expenditures during 2007 related to new rigs place into service:

Rig No.	Drawworks (HP)	Capacity (LBS)	Power Type	2007 Capital Expenditures (in millions)		Actual Inservice Date
122	1,000	500,000	Mechanical	$	1.0	Mar 2007
222	1,500	750,000	Electric		9.2	Jan 2007
223	1,500	750,000	Electric		9.2	Feb 2007
224	1,500	750,000	Electric		7.6	Mar 2007
				$	27.0

Working Capital

Our working capital decreased slightly, from $20.8 million at December 31, 2007 to $20.6 million at December 31, 2008. Our current ratio, which we calculate by dividing our current assets by our current liabilities, was 1.5 and 1.7 at December 31, 2008 and 2007, respectively.

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

	December 31,
	2008		2007		Change
Cash and cash equivalents	$	406	$	20	$	386
Accounts receivable		44,712		39,878		4,834
Inventories		1,536		1,201		335
Prepaid expenses, deposits and other receivables		11,617		6,957		4,660
Deferred taxes		406		1,812		(1,406	)
Current assets		58,677		49,868		8,809
Accounts payable		25,361		13,545		11,816
Current debt		3,126		3,139		(13	)
Current portion of advances from customers		484		4,530		(4,046	)
Accrued expenses and other liabilities		9,127		7,862		1,265
Current liabilities		38,098		29,076		9,022
Working capital	$	20,579	$	20,792	$	(213	)

The $4.8 million increase in our receivables at December 31, 2008 from December 31, 2007 was due primarily to increased revenues in December 2008 compared to December 2007. In addition, the December 31, 2008 balance includes $1 million of revenue we recognized as a result of our settlement with a customer under a drilling contract.

The $4.7 million increase in prepaid expenses, deposits and other receivables at December 31, 2008 compared to December 31, 2007 was primarily due to the $4.8 million increase in income tax recoverables as of December 31, 2008, due to a tax loss carryback resulting from bonus depreciation in 2008.

The $1.4 million decrease in deferred tax asset consists primarily of a $1.1 million decrease related to a change in our tax treatment of prepaid expenses and a $450,000 decrease related to a decrease in our workers’ compensation reserves.

The $11.8 million increase in accounts payable at December 31, 2008 is primarily the result of increased capital spending in December 2008 compared to December 2007.

The $4.0 million decrease in the current portion of advances from customers at December 31, 2008 compared to December 31, 2007 was due to $4.6 million application of prepayments to revenue and partially offset by $600,000 of customer advances received in 2008.

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Accrued expenses and other liabilities at December 31, 2008 increased $1.3 million from December 31, 2007 primarily due to the $2.2 million increase in accrued sales, franchise and property taxes and $500,000 increase in accrued payroll expenses, and partially offset by a $1.6 million decrease in accrued workers compensation expense.

Long-term Debt

Our long-term debt at December 31, 2008 and 2007 consisted of the following (in thousands):

	December 31,
	2008			2007
Revolving credit facility	$	42,645		$	9,578
Notes payable for equipment financed		5,100			7,731
		47,745			17,309
Less current installments		(3,126	)		(3,139	)
	$	44,619		$	14,170

Contractual Obligations

The following table includes all of our contractual obligations of the type specified below at December 31, 2008 (in thousands):

Contractual Obligations	Total		Less than 1 year		1-3 years		4 - 5 years		More than 5 years
Revolving credit facility (a)	$	42,645	$	—	$	—	$	42,645	$	—
Purchase commitments (b)		19,425		19,425
Notes payable for equipment		5,100		3,126		1,974		—		—
Operating lease obligations		2,283		1,274		1,007		2		—
Interest on notes payable		254		186		68		—		—
Total	$	69,707	$	24,011	$	3,049	$	42,647	$	—

(a) The amount included in the table above represents principal maturities only. See “Item 7A. Quantitative and Qualitative Disclosures About Market Risk” for information regarding estimated future interest payment obligations under long-term debt obligations and Note 8 of Notes to Financial Statements included in “Item 8. Financial Statements and Supplementary Data.”

(b) Purchase commitments include remaining payments related to four rigs under construction and scheduled for delivery in 2009.

Inflation

As a result of the relatively low levels of inflation during 2006, 2007 and through early 2008 in the broader U.S. economy, inflation did not significantly affect our results of operations in any of the periods reported. However, the Company did experience some inflationary pressures, primarily in the second half of 2008, related to salaries of field personnel, certain material and equipment costs and fuel expense. Management believes modest inflationary pressure will continue in some areas but, overall, does not believe inflation will have a significant effect on the Company.

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 Statement of Financial Accounting Standards (“SFAS”) No. 157, “Fair Value Measurements” (“SFAS No. 157”). This Statement defines fair value, establishes a framework for measuring fair value in GAAP, and expands disclosures about fair value measurements. SFAS No. 157 was effective for financial

33

statements issued for fiscal years beginning after November 15, 2007, and interim periods within those fiscal years, and as a result, the Company adopted SFAS No. 157 effective January 1, 2008 as it relates to financial assets and liabilities. The Company has no financial assets or liabilities that are recognized or disclosed at fair value in its financial statements so the implementation of SFAS No. 157 as it relates to these assets had no material impact. In February 2008, the FASB issued FASB Staff Position SFAS No. 157-2, which defers the effective date of SFAS No. 157 to fiscal years beginning after November 15, 2008 for non-financial assets and non-financial liabilities that are recognized or disclosed at fair value in an entity’s financial statements on a recurring basis. The implementation of SFAS No. 157 as it relates to the Company’s non-financial assets and non-financial liabilities will not have a material impact on our financial position or results of operations.

In February 2007, the FASB issued SFAS No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities” (“SFAS No. 159”). SFAS No. 159 permits entities to measure many financial instruments and certain other items at fair value that are not currently required to be measured at fair value. SFAS No. 159 was effective for financial statements issued for fiscal years beginning after November 15, 2007, and interim periods within those fiscal years. The implementation of SFAS No. 159 did not have a material effect on the financial condition or results of operations of the Company.

In December 2007, the FASB revised SFAS No. 141(R), “Business Combinations” (“SFAS No. 141(R)”). This Statement establishes principles and requirements for how the acquirer in a business combination: a) recognizes and measures in its financial statements the identifiable assets acquired, the liabilities assumed, and any noncontrolling interest in the acquiree; b) recognizes and measures the goodwill acquired in the business combination or a gain from a bargain purchase; and c) determines what information to disclose to enable users of the financial statements to evaluate the nature and financial effects of the business combination. This Statement applies prospectively to the Company for any business combinations for which the acquisition date is on or after January 1, 2009. We do not expect the adoption of SFAS No. 141(R) to have a material impact on our financial position or results of operations.

In May 2008, the FASB issued SFAS No. 162, “The Hierarchy of Generally Accepted Accounting Principles” (“SFAS No. 162”). This statement identifies the sources of accounting principles and the framework for selecting the principles to be used in the preparation of financial statements in conformity with generally accepted accounting principles (GAAP) in the United States. This statement became effective on November 15, 2008. The adoption of SFAS No. 162 did not have a material effect on the financial condition or results of operations of the Company.

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, 2008, we had $42.6 million outstanding debt on our revolving credit facility. An increase or decrease of 1% in the interest rate would have a corresponding decrease or increase in our net income of approximately $426,000 annually.

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Item 8. Financial Statements and Supplementary Data

UNION DRILLING, INC.

INDEX TO FINANCIAL STATEMENTS

	Page
Management’s Report on Internal Control Over Financial Reporting	36
Report of Independent Registered Public Accounting Firm	37
Report of Independent Registered Public Accounting Firm	38
Balance Sheets as of December 31, 2008 and 2007	39
Statements of Income for the Years Ended December 31, 2008, 2007 and 2006	40
Statements of Stockholders’ Equity for the Years Ended December 31, 2008, 2007 and 2006	41
Statements of Cash Flows for the Years Ended December 31, 2008, 2007 and 2006	42
Notes to Financial Statements	43

35

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, 2008. 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, 2008, our internal control over financial reporting is effective based on those criteria.

Ernst & Young, LLP, an independent registered public accounting firm, which also audited our financial statements, has issued an attestation report on the effectiveness of our internal control over financial reporting as of December 31, 2008. This report, which expresses an unqualified opinion on the effectiveness of our internal control over financial reporting as of December 31, 2008, is included under the heading “Report of Independent Registered Public Accounting Firm” on the following page.

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

The Board of Directors and Stockholders of

Union Drilling, Inc.

We have audited Union Drilling, Inc.’s internal control over financial reporting as of December 31, 2008, based on criteria established in Internal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (the COSO criteria). Union Drilling, Inc.’s management is responsible for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting included in the accompanying Management’s Report on Internal Control Over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

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

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

In our opinion, Union Drilling, Inc. maintained, in all material respects, effective internal control over financial reporting as of December 31, 2008, based on the COSO criteria.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the balance sheets of Union Drilling, Inc. as of December 31, 2008 and 2007 and the related statements of income, stockholders’ equity and cash flows for each of the three years in the period ended December 31, 2008 and our report dated March 11, 2009 expressed an unqualified opinion thereon.

	Ernst & Young LLP
Fort Worth, Texas
March 11, 2009

37

Report of Independent Registered Public Accounting Firm

The Board of Directors and Stockholders

of Union Drilling, Inc.

We have audited the accompanying balance sheets of Union Drilling, Inc. (the “Company”) as of December 31, 2008 and 2007, and the related statements of income, stockholders’ equity, and cash flows for each of the three years in the period ended December 31, 2008. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Union Drilling, Inc. at December 31, 2008 and 2007, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2008, in conformity with U.S. generally accepted accounting principles.

As discussed in Note 2 to the financial statements, effective January 1, 2007, the Company adopted FASB Interpretation No. 48, “Accounting for Uncertainty in Income Taxes – an Interpretation of FASB No. 109.”

We also have audited, in accordance with the Standards of the Public Company Accounting Oversight Board (United States), Union Drilling, Inc.’s internal control over financial reporting as of December 31, 2008, based on criteria established in Internal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission, and our report dated March 11, 2009 expressed an unqualified opinion thereon.

	Ernst & Young LLP
Fort Worth, Texas
March 11, 2009

38

Union Drilling, Inc.

Balance Sheets

(in thousands, except share data)

	December 31,
	2008			2007
Assets:
Current assets:
Cash and cash equivalents	$	406		$	20
Accounts receivable (net of allowance for doubtful accounts of $1,495 and $311 at December 31, 2008 and 2007, respectively)		44,712			39,878
Inventories		1,536			1,201
Prepaid expenses, deposits and other receivables		11,617			6,957
Deferred taxes		406			1,812
Total current assets		58,677			49,868
Goodwill		—			7,909
Intangible assets (net of accumulated amortization of $412 and $931 at December 31, 2008 and 2007, respectively)		1,788			2,069
Property, buildings and equipment (net of accumulated depreciation of $145,315 and $105,675 at December 31, 2008 and 2007, respectively)		275,757			217,359
Other assets		383			103
Total assets	$	336,605		$	277,308
Liabilities and Stockholders’ Equity:
Current liabilities:
Accounts payable	$	25,361		$	13,545
Current portion of notes payable for equipment		3,126			3,139
Current portion of customer advances		484			4,530
Accrued expense and other liabilities		9,127			7,862
Total current liabilities		38,098			29,076
Revolving credit facility		42,645			9,578
Long-term notes payable for equipment		1,974			4,592
Deferred taxes		48,633			30,002
Customer advances and other long-term liabilities		542			651
Total liabilities		131,892			73,899
Stockholders’ equity:
Common stock, par value $.01 per share; 75,000,000 shares authorized; 22,024,381 shares and 21,974,884 shares issued at December 31, 2008 and 2007, respectively		220			220
Additional paid-in capital		144,113			141,659
Retained earnings		69,280			61,530
Treasury stock; 1,714,818 shares and no shares at December 31, 2008 and 2007, respectively		(8,900	)		—
Total stockholders’ equity		204,713			203,409
Total liabilities and stockholders’ equity	$	336,605		$	277,308

See accompanying notes to financial statements.

39

Union Drilling, Inc.

Statements of Income

(in thousands, except share and per share data)

	Years Ended December 31
	2008			2007			2006
Revenues	$	302,780		$	289,035		$	256,944
Cost and expenses
Operating expenses		196,100			171,897			155,123
Depreciation and amortization		44,298			39,072			24,820
Goodwill and intangibles impairment charge		7,909			—			1,000
General and administrative		34,084			24,775			21,514
Total cost and expenses		282,391			235,744			202,457
Operating income		20,389			53,291			54,487
Interest expense		(845	)		(1,824	)		(527	)
Gain on sale or disposal of fixed assets		606			998			4
Other income		211			387			306
Income before income taxes		20,361			52,852			54,270
Income tax expense		12,611			22,020			22,418
Net income	$	7,750		$	30,832		$	31,852
Earnings per common share:
Basic	$	0.35		$	1.41		$	1.50
Diluted	$	0.35		$	1.41		$	1.47
Weighted-average common shares outstanding:
Basic		21,890,273			21,818,381			21,284,047
Diluted		22,005,118			21,940,210			21,660,792

See accompanying notes to financial statements.

40

Union Drilling, Inc.

Statements of Stockholders’ Equity

(in thousands, except share data)

	Common Stock				Additional Paid-In Capital			Retained Earnings (Deficit)			Treasury Stock			Total
	Shares		$
Balance at December 31, 2005	21,166,109		$	212	$	133,381		$	(1,154	)	$	—		$	132,439
Compensation costs included in net income	—			—		453			—						453
Stock issuance costs	—			—		(36	)		—						(36	)
Exercise of stock options and related tax benefit of $1,492	357,468			3		2,888			—						2,891
Net income	—			—		—			31,852						31,852
Balance at December 31, 2006	21,523,577			215		136,686			30,698			—			167,599
Compensation costs included in net income	—			—		994			—						994
Exercise of stock options and related tax benefit of $1,507	451,307			5		3,979			—						3,984
Net income	—			—		—			30,832						30,832
Balance at December 31, 2007	21,974,884			220		141,659			61,530			—			203,409
Compensation costs included in net income	—			—		1,899			—			—			1,899
Exercise of stock options and related tax benefit of $139	49,497					555			—			—			555
Purchase of treasury stock	(1,714,818	)		—		—			—			(8,900	)		(8,900	)
Net income	—			—		—			7,750			—			7,750
Balance at December 31, 2008	20,309,563		$	220	$	144,113		$	69,280		$	(8,900	)	$	204,713

See accompanying notes to financial statements.

41

Union Drilling, Inc.

Statements of Cash Flows

(in thousands)

	Year Ended December 31,
	2008			2007			2006
Operating activities:
Net income	$	7,750		$	30,832		$	31,852
Adjustments to reconcile net income to net cash provided by (used in) operating activities:
Depreciation and amortization		44,298			39,072			24,820
Impairment charge		7,909			—			1,000
Amortization of stock-based compensation expense		1,899			994			453
Provision for doubtful accounts		6,318			837			680
Gain on sale or disposal of fixed assets		(606	)		(998	)		(4	)
Provision for deferred taxes		20,190			9,395			8,989
Excess tax benefits from share-based payment arrangements		(139	)		(1,507	)		(1,492	)
Changes in operating assets and liabilities:
Accounts receivable		(11,152	)		6,898			(20,712	)
Accounts receivable - related party		—			—			482
Inventories		(335	)		(128	)		(213	)
Prepaid expenses and deposits		(4,940	)		(2,643	)		1,162
Accounts payable		4,760			(3,243	)		3,874
Accrued expenses and other liabilities		(2,904	)		3,137			6,224
Cash flow provided by operating activities		73,048			82,646			57,115
Investing activities:
Purchases of machinery and equipment		(94,107	)		(68,120	)		(94,009	)
Proceeds from sale of machinery and equipment		3,023			2,318			1,074
Cash flow used in investing activities		(91,084	)		(65,802	)		(92,935	)
Financing activities:
Borrowings on line of credit		329,013			288,107			258,163
Repayments on line of credit		(295,946	)		(306,339	)		(230,353	)
Cash overdrafts		(3,669	)		(230	)		3,900
Borrowings - other debt		634			3,161			5,342
Repayments - other debt		(3,265	)		(5,527	)		(6,457	)
Stock issuance costs		—			—			(36	)
Purchases of treasury stock		(8,900	)		—			—
Exercise of stock options		416			2,477			1,399
Excess tax benefits from share-based payment arrangements		139			1,507			1,492
Cash flow provided by (used in) financing activities		18,422			(16,844	)		33,450
Foreign currency translation adjustment		—			—			2
Net increase (decrease) in cash		386			—			(2,368	)
Cash and cash equivalents at beginning of period		20			20			2,388
Cash and cash equivalents at end of period	$	406		$	20		$	20

See accompanying notes to financial statements.

42

UNION DRILLING, INC.

NOTES TO FINANCIAL STATEMENTS

1. Organization

Union Drilling, Inc. (“Union Drilling”, “Company” or “we”) was incorporated in Delaware in September 1997. In October 1997, the Company acquired substantially all of the drilling equipment assets of a division of Equitable Resources Energy Company. Since that time, the Company has increased its productive capacity by purchasing additional rigs and related equipment.

2. Description of Business and Summary of Significant Accounting Policies

Description of business

The Company is engaged in the business of contract land drilling and related services. The primary market for the Company’s services is the onshore oil and natural gas industry. The Company operates primarily in Arkansas, New York, Ohio, Oklahoma, Pennsylvania, Texas and West Virginia.

As the Company substantially completed the liquidation of its Canadian operations in 2004, all subsequent foreign currency translation adjustments were recorded through other income/expense in the statements of operations. In December 2006, the Canadian subsidiary was dissolved.

The Company’s primary customers are involved in the oil and natural gas industry. Revenues from the top ten customers for the year ended December 31, 2008 represented approximately 56% of total revenues with two customers’ revenue totaling 18% and 12%, respectively. Revenues from the top ten customers for the year ended December 31, 2007 represented approximately 60% of total revenues with two customers’ revenue totaling 14% and 13%, respectively. Revenues from the top ten customers for the year ended December 31, 2006 represented approximately 46% of total revenues with one customer’s revenue totaling 12%.

Basis of Presentation

For fiscal year 2006, the financial statements are consolidated and include the accounts of Union Drilling and its wholly-owned subsidiaries after the elimination of all significant intercompany balances and transactions. Effective January 1, 2007, all wholly-owned subsidiaries had been dissolved or merged into Union Drilling.

Use of Estimates

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

Cash and Cash Equivalents

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

Accounts Receivable

We evaluate the creditworthiness of our customers based on their financial information, if available, information obtained from major industry suppliers, and our past experiences with the customer. In some instances, we require new customers to establish escrow accounts or make prepayments. We typically invoice our customers during the performance of daywork contracts and upon completion of the daywork contract. Footage contracts are invoiced upon completion of the contract. Our contracts generally provide for payment of invoices in 30 days. We established an allowance for doubtful accounts of approximately $1.5 million and $311,000 at December 31, 2008 and 2007, respectively. Any allowance established is subject to judgment and estimates made by management. We determine our allowance by considering a number of factors, including the length of time trade accounts receivable are past due, our previous loss history, our assessment of our customers’ current abilities to pay obligations to us and the condition of the general

43

economy and the industry as a whole. We write off specific accounts receivable when they become uncollectible. During 2008, we wrote off $5.1 million of accounts receivable, primarily for four customers, three of which subsequently declared bankruptcy. We are pursuing our claims in the bankruptcy proceedings. During 2007, we wrote off $1.4 million of accounts receivable, of which $1.3 million was for one customer.

At December 31, 2008 and 2007, our contract drilling work in progress totaled approximately $4.4 million and $4.3 million, respectively, all of which relates to the revenue recognized, but not yet billed, on daywork and footage contracts in progress at December 31, 2008 and 2007, respectively. The balance at December 31, 2008 includes $1 million of revenue we recognized as a result of our settlement with a customer under a drilling contract. Excluding this $1 million settlement accrual, the decrease in our contract drilling work in progress was due primarily to an increase in progress billings.

Accounts receivables as of December 31, 2008 and 2007 also include a reserve for sales credits of approximately $213,000 and $186,000, respectively.

Inventories

Inventories maintained by the Company are primarily consumable replacement parts and drill bits. Inventories are maintained on a first-in, first-out basis, and recorded at the lower of cost or net realizable value.

Prepaid Expenses, Deposits and Other Receivables

Prepaid expenses, deposits and other receivables include items such as insurance, taxes, utility deposits, fees and insurance claim receivables. We routinely expense our prepaid expenses in the normal course of business over the periods these expenses benefit. A detail of prepaid expenses, deposits and other receivables is as follows:

	December 31,
	2008		2007
Prepaid insurance	$	2,872	$	2,588
Income tax recoverable		7,607		2,828
Deposits		793		281
Unamortized loan costs		164		410
Insurance claim receivables		56		771
Other		125		79
	$	11,617	$	6,957

The $4.8 million increase in income tax recoverable as of December 31, 2008 is due to a tax loss carryback primarily resulting from bonus depreciation in 2008.

Goodwill and Intangible Assets

Goodwill at December 31, 2007 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. 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. Refer to Note 6 “Income Taxes” of Notes to Financial Statements for information regarding corrections made in 2006 to the purchase price allocation for Thornton Drilling Company which impacted the carrying value of goodwill.

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. Goodwill impairment testing is performed at the level of our reporting units. In connection with the assessment of potential impairment of goodwill, we compare the fair value of the reporting unit with the carrying value. If the fair value exceeds the carrying value, no impairment is indicated. If the carrying value exceeds the fair value, we measure any impairment of goodwill in the reporting unit by allocating the fair value to the identifiable assets and liabilities of the reporting unit based on their respective fair values. Any excess unallocated fair value would equal the implied fair value of goodwill, and if that amount is below the carrying value of goodwill, an impairment charge is recognized.

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In light of the adverse market conditions affecting our common stock price beginning in the fourth quarter of 2008, we utilized multiple market approaches to estimate the fair value of the reporting unit holding goodwill. In developing these fair value estimates, there is considerable judgment involved, particularly in determining the valuation methodologies to utilize and the weighting of different valuation methodologies applied. Certain key assumptions included the trading day period over which to assess market capitalization, implied control premium, multiples of earnings before interest, income taxes, depreciation and amortization and forecasted 2009 operating results. Based on the results of the first step of the impairment test, an impairment of our goodwill was indicated. The allocation of the fair value of the reporting unit to the identifiable assets and liabilities of the reporting unit indicated no residual value for goodwill, and accordingly, we recorded an impairment charge of $7.9 million.

The fair market values of identified intangible assets acquired in the purchase of Thornton Drilling Company 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 were amortized over the period of the non-compete agreement of two years. Depreciation and amortization includes amortization of intangibles of $281,000, $403,000 and $326,000 for the years ended December 31, 2008, 2007 and 2006, respectively. Amortization of intangibles is not expected to exceed $110,000 per year over the next five years. Other intangibles are tested for impairment if indicators of impairment are present. Effective December 31, 2006, the Thornton Drilling Company subsidiary was merged with and into the Company. Concurrently, the Company decided to cease using the Thornton Drilling Company name in its operations. As a result, a $1 million impairment charge was recognized in 2006 to write off the trade name intangible asset.

The total cost and accumulated amortization of intangible assets are as follows (in thousands):

	December 31,
	2008			2007
Customer relations	$	2,200		$	2,200
Non compete agreement		—			800
Intangible assets		2,200			3,000
Customer relations		(412	)		(302	)
Non compete agreement		—			(629	)
Accumulated amortization		(412	)		(931	)
Intangible assets, net	$	1,788		$	2,069

Property, Buildings and Equipment

Property, buildings and equipment is stated on the basis of cost. The Company capitalizes costs of replacements or renewals that improve or extend the lives of existing property, buildings and equipment. Maintenance and repairs are expensed as incurred. Depreciation is calculated on the straight-line method over the estimated remaining useful lives of the assets. Depreciation on acquired or constructed rigs and other components does not commence until the assets are placed in service. Once placed in service, depreciation continues when assets are being repaired, refurbished or between periods of deployment. As a result, our depreciation charges will not vary with changes in utilization levels, unlike our revenue. 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. For the years ended December 31, 2008, 2007 and 2006, depreciation expense was $44.0 million, $38.7 million and $24.5 million.

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The estimated lives of the assets are as follows:

Buildings	30 - 40 years
Drilling rigs and related equipment	2 - 12 years
Vehicles	5 - 7 years

Impairment of Long-Lived Assets

We assess the impairment of property and equipment whenever events or circumstances indicate that the carrying value may not be recoverable. In connection with this review, assets are grouped at the lowest level at which identifiable cash flows are largely independent of other asset groupings. The cyclical nature of our industry has resulted in fluctuations in rig utilization over periods of time. Management believes that the contract drilling industry will continue to be cyclical and rig utilization will fluctuate. Based on management’s expectations of future trends, we estimate future cash flows over the life of the respective assets in our assessment of impairment. These estimates of cash flows are based on historical cyclical trends in the industry as well as management’s expectations regarding the continuation of these trends in the future. 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, existence of term drilling contracts, 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.

In the fourth quarter of 2008, oil and natural gas prices and the market capitalization of the Company declined significantly. However, our rig utilization rates and revenue trends were relatively consistent with or slightly improved over prior 2008 quarters and were improved over 2007 levels. Based on these factors, we considered whether there were indicators of impairment for certain of our property and equipment. We estimated future cash flows over the expected life of the identified long-lived assets and determined that, on an undiscounted basis, expected cash flows exceeded the carrying value of the long-lived assets. Based on this assessment, no impairment was recognized. In the event that market conditions continue to deteriorate, the Company may be required to record impairment of its property and equipment in the future, and such impairment could be material.

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, 2008 and 2007, we satisfied this requirement with a $3.5 million and $5.0 million, respectively, letter of credit with our bank and our borrowing capacity under our revolving credit agreement with our bank has been reduced by the same amount collateralizing such letter of credit. We accrue for these costs as claims are incurred based on cost estimates established for each claim by the insurance companies providing the administrative services for processing the claims, including an estimate for incurred but not reported claims, estimates for claims paid directly by us, administrative costs associated with these claims and our historical experience with these types of claims. Some of our employees are considered to be “shared employees.” These employees are primarily engaged in our Texas field operations and consisted of approximately 500 employees at December 31, 2008. Under this arrangement, certain human resource functions, including the workers’ compensation and payroll liabilities, are assumed by the third-party professional employer organization. In addition, we accrue on a monthly basis the estimated workers’ compensation premium payable to Ohio, a monopolistic state.

Stock-Based Compensation

The Company accounts for stock-based compensation under Statement of Financial Accounting Standards (“SFAS”) No. 123(R), “Share-Based Payment, revised 2004” (“SFAS No. 123R”) which requires that the cost resulting from all share-based payment transactions be measured at fair value and recognized in the financial statements. Compensation cost is recognized on a straight line basis over the requisite service period for the entire award and included in general and administrative expense. The amount of compensation cost recognized at any date is at least equal to the portion of the grant-date value of the award that is vested at that date. For the years ended December 31, 2008, 2007 and 2006, the Company recorded total stock-based compensation expense of approximately $2.1 million ($1.5 million net of tax), $968,000 ($741,000 net of tax) and $1.0 million ($751,000 net of tax), respectively. Total unamortized stock-based compensation was approximately $4.9 million at December 31, 2008, and will be recognized over a weighted average service period of 3.7 years.

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The tax benefit realized from stock options exercised during the twelve months ended December 31, 2008, 2007 and 2006 is included as a cash inflow from financing activities on the statement of cash flows.

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:

	2008	2007	2006
Risk-free interest rate	1.6% - 2.5%	3.1% - 4.6%	4.4% - 5.0%
Expected life	5 years	2 - 5 years	5 - 6 years
Dividend yield	0%	0%	0%
Expected volatility	52% - 61%	44% - 47%	46% - 60%

The risk-free interest rate is the implied yield available for zero-coupon U.S. government issues with a remaining term equal to the expected life of the options.

The expected lives of the options are determined based on the Company’s expectations of individual option holders’ anticipated behavior and the term of the option.

The Company has not paid out dividends historically; thus, the dividend yield is estimated at zero percent.

Volatility is based upon price performance of the Company and a peer company, as the Company does not have a sufficient historical price base to determine potential volatility over the term of the issued options. Changes in our stock price can affect the expected volatility and forfeiture rate.

Revenue Recognition

We generate revenue principally by drilling wells for natural gas producers on a contracted basis under daywork or footage contracts, which provide for the drilling of single or multiple well projects. Revenues on daywork contracts are recognized based on the days worked at the dayrate each contract specifies. Mobilization fees are recognized as the related drilling services are provided. We recognize revenues on footage contracts based on the footage drilled for the applicable accounting period. Expenses are recognized based on the costs incurred during that same accounting period.

Concentration of Credit Risk

Substantially all of the Company’s operations relate to drilling services performed for independent oil and natural gas producers in the United States. The Company utilizes a fleet of land drilling rigs to provide these contract drilling services. These operations are aggregated into one reportable segment based on the similarity of economic characteristics among all markets and the similarity of the nature of the services provided and the type of customers served.

Income Taxes

We record deferred taxes for the basis difference in our property and equipment between financial reporting and tax reporting purposes and other costs such as compensation, employee benefit and other accrued liabilities which are deductible in different periods for financial reporting and tax reporting purposes. For property and equipment, basis differences arise from differences in depreciation periods and methods and the value of assets acquired in a business acquisition where we acquire the stock of an entity rather than its assets. For financial reporting purposes, we depreciate the various components of our drilling rigs and refurbishments over two to 12 years, while federal income tax rules require that we depreciate drilling rigs and refurbishments over five years. Therefore, in the earlier years of our ownership of a drilling rig, our tax depreciation exceeds our financial reporting depreciation, resulting in our recording deferred tax liabilities on this depreciation difference. In later years, financial reporting depreciation exceeds tax depreciation, and the deferred tax liability begins to reverse. In 2008, tax depreciation also included bonus depreciation allowed as a result of the Economic Stimulus Act of 2008.

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Refer to Note 6 “Income Taxes” for information regarding corrections made in 2006 to the income tax provision and deferred tax balances for underreporting of meals and incidental expenses that are only 50% deductible for income tax purposes and to recognize the deferred tax liability attributable to non-deductible intangibles acquired from Thornton Drilling Company.

In June 2006, the FASB issued FASB Interpretation No. 48, “Accounting for Uncertainty in Income Taxes – an interpretation of FASB Statement No. 109” (“FIN 48”). FIN 48 clarifies the accounting for uncertainty in income taxes recognized in an enterprise’s financial statements in accordance with SFAS No. 109. This interpretation prescribes a recognition threshold and measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. FIN 48 also provides guidance on derecognition, classification, interest and penalties, accounting in interim periods, disclosure and transition. We adopted the provisions of FIN 48 on January 1, 2007. Implementation of FIN 48 did not result in a cumulative effect adjustment to retained earnings. See Note 6 regarding further disclosures required under FIN 48.

Foreign Currency Translation

In December 2006, the Canadian subsidiary was dissolved. The functional currency of the Company’s foreign subsidiary was the Canadian dollar. Net loss resulting from foreign exchange transactions, which are recorded in the statements of operations in other income in 2006, approximated $1,600.

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 and restricted stock units. The treasury stock method is used to compute the assumed incremental shares related to our outstanding stock options and restricted stock units. The average common stock market prices for the periods are used to determine the number of incremental shares.

Fair Value of Financial Instruments

For certain financial instruments, including cash and cash equivalents, accounts receivable, accounts payable, and accrued liabilities, recorded amounts approximate fair value due to the relative short maturity period. The pricing mechanisms in the Company’s debt agreements combined with the short-term nature of the equipment financing arrangements result in the carrying values of these obligations approximating their respective fair values.

Other Comprehensive Income

For fiscal years 2008, 2007 and 2006, other comprehensive income equals net income.

Recent Accounting Pronouncements

In September 2006, the Financial Accounting Standards Board (“FASB”) issued Statement of Financial Accounting Standards (“SFAS”) No. 157, “Fair Value Measurements” (“SFAS No. 157”). This Statement defines fair value, establishes a framework for measuring fair value in GAAP, and expands disclosures about fair value measurements. SFAS No. 157 was effective for financial statements issued for fiscal years beginning after November 15, 2007, and interim periods within those fiscal years, and as a result, the Company adopted SFAS No. 157 effective January 1, 2008 as it relates to financial assets and liabilities. The Company has no financial assets or liabilities that are recognized or disclosed at fair value in its financial statements so the implementation of SFAS No. 157 as it relates to these assets had no material impact. In February 2008, the FASB issued FASB Staff Position SFAS No. 157-2, which defers the effective date of SFAS No. 157 to fiscal years beginning after November 15, 2008 for non-financial assets and non-financial liabilities that are recognized or disclosed at fair value in an entity’s financial statements on a recurring basis. The implementation of SFAS No. 157 as it relates to the Company’s non-financial assets and non-financial liabilities will not have a material impact on our financial position or results of operations.

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In February 2007, the FASB issued SFAS No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities” (“SFAS No. 159”). SFAS No. 159 permits entities to measure many financial instruments and certain other items at fair value that are not currently required to be measured at fair value. SFAS No. 159 was effective for financial statements issued for fiscal years beginning after November 15, 2007, and interim periods within those fiscal years. The implementation of SFAS No. 159 did not have a material effect on the financial condition or results of operations of the Company.

In December 2007, the FASB revised SFAS No. 141(R), “Business Combinations” (“SFAS No. 141(R)”). This Statement establishes principles and requirements for how the acquirer in a business combination: a) recognizes and measures in its financial statements the identifiable assets acquired, the liabilities assumed, and any noncontrolling interest in the acquiree; b) recognizes and measures the goodwill acquired in the business combination or a gain from a bargain purchase; and c) determines what information to disclose to enable users of the financial statements to evaluate the nature and financial effects of the business combination. This Statement applies prospectively to the Company for any business combinations for which the acquisition date is on or after January 1, 2009. We do not expect the adoption of SFAS No. 141(R) to have a material impact on our financial position or results of operations.

In May 2008, the FASB issued SFAS No. 162, “The Hierarchy of Generally Accepted Accounting Principles” (“SFAS No. 162”). This statement identifies the sources of accounting principles and the framework for selecting the principles to be used in the preparation of financial statements in conformity with generally accepted accounting principles (GAAP) in the United States. This statement became effective on November 15, 2008. The adoption of SFAS No. 162 did not have a material effect on the financial condition or results of operations of the Company.

3. 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, a law firm which previously provided legal counsel to the Company. During the three months ended March 31, 2006, legal fees related to transactions with Satterlee Stephens Burke & Burke LLP were approximately $50,000.

4. Accounts Receivable

Accounts receivable consist of the following (in thousands):

	December 31,
	2008			2007
Billed receivables	$	42,026		$	36,113
Unbilled receivables		4,394			4,262
Reserve for sales credits		(213	)		(186	)
Total receivables		46,207			40,189
Allowance for doubtful accounts		(1,495	)		(311	)
Net receivables	$	44,712		$	39,878

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.

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Activity in the allowance for doubtful accounts was as follows (in thousands):

Balance, December 31, 2005	$	313
Net charge to expense		680
Amounts written off		(154	)
Balance, December 31, 2006		839
Net charge to expense		837
Amounts written off		(1,365	)
Balance, December 31, 2007		311
Net charge to expense		6,318
Amounts written off		(5,134	)
Balance, December 31, 2008	$	1,495

5. Property, Buildings and Equipment

Major classes of property, buildings and equipment are as follows (in thousands):

	December 31,
	2008			2007
Land	$	988		$	1,010
Buildings		1,489			1,565
Drilling and well service equipment		367,940			302,834
Vehicles		12,192			10,581
Furniture and fixtures		168			168
Computer equipment		661			639
Leasehold improvements		110			93
Construction in progress		37,524			6,144
		421,072			323,034
Accumulated depreciation		(145,315	)		(105,675	)
	$	275,757		$	217,359

During 2008, 2007 and 2006, we capitalized $1.2 million, $909,000 and $1.8 million, respectively, of interest costs incurred during the construction periods of certain drilling equipment.

6. Income Taxes

The current and deferred components of income tax expense are as follows (in thousands):

	Years Ended December 31,
	2008			2007		2006
Current tax expense (benefit):
Federal	$	(7,318	)	$	9,995	$	11,786
State		(261	)		2,630		1,643
		(7,579	)		12,625		13,429
Deferred tax expense:
Federal		18,993			8,817		8,661
State		1,197			578		328
		20,190			9,395		8,989
Income tax expense	$	12,611		$	22,020	$	22,418

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The components of the net deferred income tax assets and liabilities are as follows (in thousands):

	December 31,
	2008		2007
Current deferred tax assets:
Bad debt expense	$	567	$	120
Workers compensation and other insurance reserves		715		1,165
Deferred revenue		26		267
Net operating loss carry forwards		84		188
Sales returns		83		72
Other		27		—
		1,502		1,812
Long-term deferred tax assets:
Stock compensation		883		257
Other		153		—
		1,036		257
Total deferred tax assets		2,538		2,069
Current deferred tax liabilities:
Prepaid expenses		1,096		—
Long-term deferred tax liabilities:
Intangible assets		685		789
Property, building and equipment, principally due to differences in depreciation		48,984		29,470
		49,669		30,259
Total deferred tax liabilities		50,765		30,259
Net deferred tax liability	$	48,227	$	28,190

Deferred tax assets and liabilities are presented net in the balance sheet according to their current or long-term classification.

The Company had federal net operating loss carryforwards of approximately $98,000 at both December 31, 2008 and 2007. These losses may be carried forward for 20 years and will begin to expire in 2023. State net operating losses at December 31, 2008 and 2007, were $1.3 million and $3.4 million, respectively. State losses vary as to carryforward period and will begin to expire in 2013, depending upon the jurisdiction where applied.

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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 (in thousands):

	2008			2007			2006
U.S. statutory federal income tax rate		35	%		35	%		35	%
Income tax expense at the statutory federal tax rate	$	7,126		$	18,498		$	18,994
State, local and provincial income taxes, net of federal tax benefit		755			2,322			2,382
Meal allowances		1,962			1,924			1,559
Non-cash compensation		130			96			235
Goodwill and intangibles impairment charge		3,062			—			350
Domestic production deduction		—			(549	)		(343	)
Decrease in unrecognized tax benefits		(276	)		—			—
Deferred tax adjustment		—			(169	)		(693	)
Other		(148	)		(102	)		(66	)
Income tax expense	$	12,611		$	22,020		$	22,418

During 2008, the Company received tax refunds, net of payments made, of approximately $2.6 million. During 2007 and 2006, the Company made tax payments of approximately $14 million and $11 million, respectively.

At December 31, 2008 and 2007 we had approximately $438,000 and $561,000, respectively, of unrecognized tax benefits, as defined by FIN 48, of which approximately $285,000 would affect our effective tax rate if recognized. Such amounts are carried as other long-term liabilities.

A reconciliation of the beginning and ending amount of unrecognized tax benefits is as follows (in thousands):

Balance at December 31, 2007	$	561
Reductions for tax positions of prior years		(276	)
Additions for tax positions of prior years		153
Balance at December 31, 2008	$	438

Interest and penalties related to uncertain tax positions are classified as interest expense and general and administrative costs, respectively. During 2008 and 2007, the Company recognized approximately $82,500 and $21,000, respectively, in interest and penalties related to unrecognized tax benefits in interest and penalty expense. As of December 31, 2008 and 2007, the Company had approximately $104,000 and $21,000, respectively, of interest and penalties accrued in relation to uncertain tax positions. It is reasonably possible that within the next 12 months, we may resolve some or all of the uncertain tax positions as a result of negotiations with taxing authorities which would result in a decrease in unrecognized tax.

The Company files income tax returns in the U.S. federal and in various state jurisdictions, and, prior to 2007, in Canada. The tax years 2005 to 2007 remain open to examination by the major taxing jurisdictions to which we are subject. In addition, tax years 1999, 2000, 2002 and 2003 remain open due to utilized losses in some jurisdictions in subsequent years. The Company’s 2006 U.S. federal return is currently under examination by the IRS. Although the Company believes it has adequately provided for all tax positions, amounts asserted by taxing authorities could be greater than the Company’s accrued position.

During 2006, the Company corrected its income tax provisions and deferred tax balances for underreporting of meals and incidental expenses that are only 50% deductible for income tax purposes and to recognize the deferred tax liability attributable to non-deductible intangibles acquired from Thornton Drilling Company. This correction resulted in a $462,000 additional charge to the Company’s income tax provision attributable to the year ended December 31, 2005. This correction also resulted in a $1.2 million increase to deferred tax liabilities, a $1.3 million reduction in deferred tax assets, a $2.5 million increase to recorded goodwill and a $462,000 increase to income taxes payable. Management concluded that the effect of the corrections was not material to any period impacted.

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7. Accrued Expenses and Other Liabilities

A detail of accrued expenses and other liabilities is as follows (in thousands):

	December 31,
	2008		2007
Payroll and bonus	$	3,102	$	2,607
Workers compensation		604		2,216
Medical claims		775		749
Other taxes		3,582		1,334
Other		1,064		956
	$	9,127	$	7,862

Other taxes includes sales, franchise and property taxes.

8. Debt Obligations

We entered into a Revolving Credit and Security Agreement with PNC Bank, for itself and as agent for a group of lenders, in March 2005. This credit facility has been amended numerous times, most recently on September 30, 2008. This credit facility matures on March 30, 2012 and provides for a borrowing base equal to $97.5 million. Amounts outstanding under the revolving credit facility bear interest, depending upon facility usage, at either (i) the higher of the Federal Funds Open Rate plus 75 to 125 basis points or PNC Bank’s base commercial lending rate (3.3% at December 31, 2008) or (ii) LIBOR plus 250 to 300 basis points (3.5% at December 31, 2008). Interest on outstanding loans is due monthly for domestic rate loans and at the end of the relevant interest period for LIBOR loans. Depending upon our facility usage, we are assessed an unused line fee of 37.5 to 62.5 basis points on the available borrowing capacity. The available borrowing capacity was $51.3 million as of December 31, 2008. There is a $7.5 million sublimit for letters of credit. If we repay and terminate the obligations under this facility, we would be liable for a substantial prepayment penalty.

In general, the credit facility is secured by substantially all of our assets The liquidation value of our assets serving as collateral is determined annually by an independent appraisal, with adjustments for acquisitions and dispositions between appraisals. The credit facility contains affirmative and negative covenants and also provides for events of default that are typical for such an agreement. Among the affirmative covenants are requirements to maintain a specified tangible net worth and a fixed charge coverage ratio. Among the negative covenants are restrictions on major corporate transactions, incurrence of indebtedness and amendments to our organizational documents. Events of default would include a change in control and any change in our operations or condition, which has a material adverse effect. As of December 31, 2008, we were in compliance with all financial covenants.

To date, the credit facility primarily has been used to pay for rig acquisitions and for our working capital requirements. Cash used for capital expenditures for 2008 was $94.1 million, and was primarily for drilling equipment. The credit facility may also be used by the Company, subject to certain conditions, to repurchase its common stock and/or pay a cash dividend. During the fourth quarter of 2008, treasury stock purchases totaled $8.9 million. As of December 31, 2008, we had a loan balance of $42.6 million under the credit facility, and an additional $3.5 million of the total capacity had been utilized to support our letter of credit requirement. As of December 31, 2007, $9.6 million was outstanding under our credit facility and $5.0 million of the total capacity had been utilized to support our letter of credit requirement. Cash used for capital expenditures for 2007 was $68.1 million, and was also primarily for drilling equipment.

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 12 to 60 months. As of December 31, 2008 and 2007, the total outstanding balance under these arrangements was approximately $5.1 million and $7.7 million, respectively, and is classified, according to payment date, in current portion of notes payable for equipment and long-term notes payable for equipment in the accompanying balance sheets. The stated interest rate on these borrowings ranges from zero percent to 7.6%.

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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, 2008 (in thousands):

Year ending December 31:
2009	$	3,312
2010		1,656
2011		386
2012		—
2013		—
Total minimum debt payments		5,354
Less amount representing interest		(254	)
Total present value of minimum payments		5,100
Less current portion of such obligations		(3,126	)
Long-term portion of obligations	$	1,974

The Company paid approximately $1.9 million, $2.7 million and $2.3 million in interest on all debt during 2008, 2007 and 2006, respectively.

9. Stockholders’ Equity

At December 31, 2008, the number of authorized shares of common stock was 75,000,000 shares, of which 20,309,563 shares were outstanding, and 1,906,036 shares were reserved for future issuance through the Company’s equity based plans. The number of authorized shares of preferred stock was 100,000 shares at December 31, 2008. No shares of preferred stock were outstanding or reserved for future issuance.

In August 2008, the Company’s Board approved the 2008 Union Drilling, Inc. Share Repurchase Program (the “Program”). Under the Program, the Board authorized the Company to repurchase up to two million shares of the Company’s outstanding common stock. The authorization under the Program did not have a stated expiration date and the pace of repurchase activity was dependant on factors such as levels of cash generation from operations, cash requirements for asset acquisitions or other capital expenditures, debt repayment and the Company’s current stock price, among other factors. During 2008, 1,714,818 shares of treasury stock were purchased by the Company.

10. Management Compensation

Equity Based Plans

The Company has two equity based plans, the Amended and Restated 2005 Stock Incentive 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. Under both plans, incentive and non-qualified stock options may be awarded to directors and employees. Restricted stock and restricted stock units may be granted under the Amended and Restated 2005 Stock Incentive Plan. As of December 31, 2008, 852,646 options and 264,774 restricted stock units have been granted under the Amended 2005 Stock Option Plan and 1,548,124 options have been granted under the Amended and Restated 2000 Stock Option Plan. In addition, 132,958 options were granted outside the plans in 1999. Stock options are granted with an exercise price equal to the fair market value on the grant date, which is determined by the closing trading price of our common stock on the Nasdaq Global Market. Prior to the Company’s initial public offering 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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Stock options. Options typically vest in four equal annual installments from the grant date, depending on the terms of the grant, and, unless earlier exercised or forfeited, expire on the tenth anniversary of the grant date. A summary of stock option activity for 2008 was as follows:

	2008				2007				2006
	Shares		Weighted Average Exercise Price		Shares		Weighted Average Exercise Price		Shares		Weighted Average Exercise Price
Outstanding at beginning of year	845,097		$	10.92	1,092,169		$	8.33	1,541,380		$	7.21
Granted	90,871			4.72	243,723			12.95	130,000			15.32
Exercised	(49,497	)		8.41	(451,307	)		5.49	(357,468	)		3.91
Canceled/forfeited	(6,581	)		14.00	(39,488	)		14.00	(221,743	)		11.73
Outstanding at end of year	879,890		$	10.40	845,097		$	10.92	1,092,169		$	8.33
Options exercisable at end of year	506,402		$	9.29	336,407		$	8.03	540,955		$	5.16
Weighted average fair value of options granted during the year			$	2.46			$	5.66			$	6.29

New shares of common stock are issued to satisfy options exercised. Cash received from the exercise of options for the years ended December 31, 2008, 2007 and 2006, was approximately $416,000, $2.5 million and $1.4 million, respectively. The total intrinsic value of options exercised during 2008, 2007 and 2006 was approximately $514,000, $4.6 million and $3.9 million, respectively.

A summary of options outstanding as of December 31, 2008, was 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 $7.02	298,196	4.0	$	3.65	220,659	$	3.28
$12.75 to $15.60	581,694	7.6	$	13.85	285,743	$	13.94
	879,890				506,402

The aggregate intrinsic value of options outstanding and options exercisable as of December 31, 2008 was approximately $462,000 and $422,000, respectively. The weighted average remaining contractual life of options exercisable as of December 31, 2008 was 4.8 years.

The total fair value of options vested during the year ended December 31, 2008 was $1.2 million.

The following table summarizes additional information as of December 31, 2008 for fully vested options and options expected to vest:

Number of shares outstanding		789,843
Weighted average exercise price	$	10.14
Aggregate intrinsic value (in thousands)	$	456
Weighted average remaining contractual term		6.1 years

Restricted stock awards. During 2008, 264,774 restricted stock units were awarded at a weighted average grant date fair value of $15.75 per unit and vesting periods ranging from three to seven years. One of these awards for 200,000 restricted stock units is subject to both performance and service criteria, which as of December 31, 2008, have not been met. As of December 31, 2008, no other restricted stock awards were outstanding.

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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 made contributions of approximately $585,000, $479,000 and $321,000 during the years ended December 31, 2008, 2007 and 2006, respectively.

Contingent Management Compensation

The Company’s Chief Executive Officer (“CEO”) and certain other participants have been awarded rights to participate in the proceeds associated with the appreciation in value ultimately associated with dispositions of the Company’s shares by Union Drilling Company LLC (“UDC”), our principal stockholder. In order to receive benefits from this arrangement, the fair market value of the Company’s shares held by UDC must exceed certain threshold amounts.

The CEO is to receive benefits as a result of UDC’s sale, distribution or disposition of Company shares and the related recognition of a gain in excess of the threshold amount. These rights may be repurchased from the CEO at fair market value, which includes consideration of the threshold amount in the determination of that value, upon his termination of employment by the Company. Further, the rights may be repurchased from the CEO for no consideration upon voluntary termination or upon termination of employment by the Company for cause.

At December 31, 2008 and 2007 the threshold amounts were $35.2 million and $32.0 million, respectively. These amounts are determined based upon cash invested in UDC (and invested by UDC in the Company’s stock) plus a compounded annual return of 10% less cash returned to investors. In 2007, $26,000 of compensation costs were recognized as a result of the fair value of the assets owned by UDC exceeding the threshold. In 2008 and 2006, the Company recognized $218,000 and $546,000 of compensation cost reversals. The cost reversals in 2008 was related to the decrease in the market value of the Company’s common stock price, while the cost reversals in 2006 was primarily due to the voluntary termination of a previous Company participant and the repurchase of such participant’s rights for no consideration. All compensation costs related to these rights are classified as general and administrative expense. As UDC is responsible for the cash settlement of these awards, the offsetting balance is recorded as additional paid in capital.

The defined participants in this arrangement would be entitled to up to 22.5% of the value realized in excess of the threshold amount. The CEO is entitled to approximately 1% of the 22.5%.

Changes in our stock price can affect the compensation expense.

11. 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:

	2008		2007		2006
Net income	$	7,750	$	30,832	$	31,852
Weighted average shares outstanding		21,890,273		21,818,381		21,284,047
Incremental shares from assumed conversion of stock options		114,845		121,829		376,745
Weighted average and assumed incremental shares		22,005,118		21,940,210		21,660,792
Earnings per share:
Basic	$	0.35	$	1.41	$	1.50
Diluted	$	0.35	$	1.41	$	1.47

The weighted average number of dilutive shares in 2008 excludes 122,500 options due to their antidilutive effects.

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12. Commitments and Contingencies

Operating Leases

The Company leases certain buildings, automobiles, office equipment and phone services under noncancelable operating agreements. Lease expense was approximately $2.3 million, $2.1 million and $1.8 million for the years ended December 31, 2008, 2007 and 2006, respectively. As of December 31, 2008, future minimum lease payments under noncancelable operating leases consist of the following (in thousands):

2009	$	1,274
2010		777
2011		230
2012		2
2013		—
Total	$	2,283

Litigation

From time to time, we are a party to claims, litigation or other legal or administrative proceedings that we consider to arise in the ordinary course of our business. While no assurances can be given regarding the outcome of these or any other pending proceedings, or the ultimate effect such outcomes may have, we do not believe we are a party to any legal or administrative proceedings which, if determined adversely to us, individually or in the aggregate, would have a material effect on our financial position, results of operations or cash flows. Management believes that the Company maintains adequate levels of insurance necessary to cover its business risk.

On October 31, 2008, the Company was named in a lawsuit filed in the United States District Court for the Eastern District of Arkansas (Western Division). The lawsuit was filed by Stephen Rose, individually, and Elizabeth Rose, both individually and on behalf of the deceased children of Stephen and Elizabeth Rose. The lawsuit alleges negligence on behalf of the Company relating to a traffic accident involving a mobile drilling rig owned by the Company. The Roses’ children were fatally injured in this accident. The lawsuit seeks unspecified compensatory and punitive damages. The Company intends to vigorously defend itself in this litigation.

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13. Quarterly Financial Data (Unaudited)

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

	First Quarter		Second Quarter		Third Quarter		Fourth Quarter			Total
2008
Revenues	$	64,078	$	75,389	$	82,439	$	80,874		$	302,780
Operating income		3,385		7,295		9,785		(76	)		20,389
Net income		2,146		3,372		5,947		(3,715	)		7,750
Net income per common share:
Basic	$	0.10	$	0.15	$	0.27	$	(0.17	)	$	0.35
Diluted	$	0.10	$	0.15	$	0.27	$	(0.17	)	$	0.35
2007
Revenues	$	70,532	$	74,200	$	76,938	$	67,365		$	289,035
Operating income		14,960		14,785		16,047		7,499			53,291
Net income		8,500		9,199		9,266		3,867			30,832
Net income per common share:
Basic	$	0.39	$	0.42	$	0.42	$	0.18		$	1.41
Diluted	$	0.39	$	0.42	$	0.42	$	0.18		$	1.41

14. Subsequent Event

During January 2009, the remaining 285,182 shares of common stock authorized for repurchase under the Program were repurchased as treasury shares for approximately $1.6 million.

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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 is incorporated herein by reference.

Attestation Report of Independent Registered Public Accounting Firm.

The attestation report of our independent registered public accounting firm regarding internal control over financial reporting is set forth in Item 8 of this Annual Report on Form 10-K under the caption “Report of Independent Registered Public Accounting Firm Report” and is incorporated herein by reference.

Changes in Internal Control over Financial Reporting.

No change in our internal control over financial reporting (as defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act) occurred during the fiscal quarter ended December 31, 2008 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

Item 9B. Other Information

None.

PART III

In Items 10, 11, 12, 13 and 14 below, we are incorporating by reference the information we refer to in those Items from the definitive proxy statement for our 2009 Annual Meeting of Stockholders. We intend to file our definitive proxy statement with the SEC by April 30, 2009.

Item 10. Directors, Executive Officers and Corporate Governance

We have a Code of Ethics that applies to our directors and all employees including our principal executive officer, principal financial officer, principal accounting officer and persons performing similar functions. Our Code of Ethics is posted in the “Investor Relations” section on our website at http://www.uniondrilling.com.

The other information required in response to this Item will be set forth in our definitive proxy statement for our 2009 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 2009 Annual Meeting of Stockholders and is incorporated herein by reference.

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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 2009 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 2009 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 2009 Annual Meeting of Stockholders and is incorporated herein by reference.

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PART VI

Item 15. Exhibits and Financial Statement Schedules

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

1. Financial Statements.

See Index to 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 financial statements.

(b) Exhibits. A list of exhibits required by Item 601 of Regulation S-K and to be filed as part of this report is set forth in the Index to Exhibits beginning on page 63, which immediately precedes such exhibits.

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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 12, 2009	By:	/s/ Christopher D. Strong
		Christopher D. Strong
		President and Chief Executive Officer

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

Signature	Title	Date
/s/ Christopher D. Strong
Christopher D. Strong	President and Chief Executive Officer (Principal Executive Officer) and Director	March 12, 2009
/s/ A.J. Verdecchia
A.J. Verdecchia	Vice President, Chief Financial Officer and Treasurer (Principal Financial and Accounting Officer)	March 12, 2009
/s/ Thomas H. O’Neill, Jr.
Thomas H. O’Neill Jr.	Director	March 12, 2009
/s/ Howard I. Hoffen
Howard I. Hoffen	Director	March 12, 2009
/s/ Gregory D. Myers
Gregory D. Myers	Director	March 12, 2009
/s/ M. Joseph McHugh
M. Joseph McHugh	Director	March 12, 2009
/s/ T.J. Glauthier
T.J. Glauthier	Director	March 12, 2009
/s/ Ronald Harrell
Ronald Harrell	Director	March 12, 2009
/s/ Robert M. Wohleber
Robert M. Wohleber	Director	March 12, 2009

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UNION DRILLING, INC.

INDEX TO EXHIBITS

Exhibit Number		Description
3.1	—	Form of Amended and Restated Certificate of Incorporation of Union Drilling (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 Drilling (incorporated by reference to Exhibit 3.1 to our Form 8-K filed on August 9, 2007).
4.1	—	Specimen Stock Certificate for the common stock, par value $0.01 per share, of Union Drilling (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†	—	First Amendment to Union Drilling’s Amended and Restated 2000 Stock Option Plan and Its Accompanying Form of Stock Option Agreement (incorporated by reference to Exhibit 10.1 to our Form 8-K filed on November 30, 2007).
10.2†	—	Form of Stock Option Agreement under First Amendment to Union Drilling’s Amended and Restated 2000 Stock Option Plan (incorporated by reference to Exhibit 10.1 to our Form 8-K filed on November 30, 2007).
10.3†	—	Stock Option Plan and Agreement, dated May 13, 1999, by and between Union Drilling 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†	—	First Amendment to Union Drilling’s 2005 Stock Option Plan and Its Accompanying Form of Stock Option Agreement (incorporated by reference to Exhibit 10.2 to our Form 8-K filed on November 30, 2007).
10.5†	—	Form of Stock Option Agreement under Union Drilling’s Amended and Restated 2005 Stock Option Plan (incorporated by reference to Exhibit 10.2 to our Form 8-K filed on November 30, 2007).
10.5.1†	—	Amended and Restated 2005 Stock Incentive Plan and the accompanying forms of award agreements (incorporated by reference to Exhibit 10.1 to our Form 8-K filed on June 11, 2008).
10.5.2†	—	Restricted Stock Unit Agreement, dated June 10, 2008, between Union Drilling and Christopher D. Strong (incorporated by reference to Exhibit 10.2 to our Form 8-K filed on June 11, 2008).
10.6	—	Form of Stockholders Agreement by and among Union Drilling 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 Drilling the lenders signatory thereto and PNC Bank, as agent for the lenders, together with the First Amendment dated April 19, 2005 (incorporated by reference to Exhibit 10.7 to our Registration Statement on Form S-1 (File No. 333-127525) filed on August 15, 2005).
10.8	—	Stock Purchase Agreement, dated as of March 31, 2005, by and between Union Drilling 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 Drilling 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 Drilling 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 Drilling, 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).

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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 Drilling 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 Drilling, 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 Drilling, 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 Drilling 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 filed on December 13, 2005).
10.20	—	Option Agreement, dated December 8, 2005, between Union Drilling 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 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 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 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 filed on February 3, 2006).
10.24	—	Purchase and Sale Agreement dated April 21, 2006 between Union Drilling 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 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 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 filed on December 7, 2006).
10.27	—	Purchase and Sale Agreement dated January 4, 2008 between Union Drilling and IDM Equipment, LLC (incorporated by reference to Exhibit 10.1 to our Form 8-K filed on January 8, 2008).
10.28	—	Sixth Amendment to Revolving Credit and Security Agreement dated July 29, 2008 between Union Drilling and PNC Bank, National Association, for itself and for the other lenders (incorporated by reference to Exhibit 10.1 to our Form 8-K filed on July 31, 2008).
10.29	—	Seventh Amendment to Revolving Credit and Security Agreement dated September 30, 2008 between Union Drilling and PNC Bank, National Association, for itself and for the other lenders (incorporated by reference to Exhibit 10.1 to our Form 8-K filed on October 6, 2008).
23.1*	—	Consent of Ernst & Young LLP, Independent Registered Public Accounting Firm
31.1*	—	Rule 13a-14(a)/15d-14(a) Certification of Chief Executive Officer.

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31.2*	—	Rule 13a-14(a)/15d-14(a) Certification of Chief Financial Officer.
32.1*	—	Section 1350 Certification of Chief Executive Officer.**
32.2*	—	Section 1350 Certification of Chief Financial Officer.**

† Management contract or compensatory plan or arrangement.

* Filed with this Report.

** This Certification shall not be deemed “filed” for purposes of Section 18 of the Securities Exchange Act of 1934, as amended, or otherwise subject to the liability of that section. This Certification shall not be deemed to be incorporated by reference into any filing of the Company under the Securities Act of 1933 or the Securities Exchange Act of 1934, each as amended, whether made before or after the date hereof, except to the extent that the Company specifically incorporates it by reference.

65