10-K 1 file001.htm FORM 10-K

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, 2005

[_] 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 (I.R.S. Employer
of incorporation or organization) 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: NONE

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

Common Stock, $0.01 par value

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 an accelerated filer (as
defined in Rule 12b-2 of the Securities Exchange Act of 1934). Yes [_] No [X]

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

The aggregate market value of the registrant's voting and nonvoting common
equity held by non-affiliates of the registrant as of the last business day of
the registrant's most recently completed fourth fiscal quarter (December 31,
2005) was $191,951,674 based on the last sales price of the registrant's common
stock reported on the NASDAQ Exchange on that date. The determination of
affiliate status for the purposes of this calculation is not necessarily a
conclusive determination for other purposes. The calculation excludes
approximately 7,955,395 shares held by directors, officers and stockholders
whose ownership exceeded 5% of the Registrant's outstanding Common Stock as of
December 31, 2005. 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 27, 2006, there were 21,166,109 shares of common stock, par value
$0.01 per share, of the registrant issued and outstanding.

DOCUMENTS INCORPORATED BY REFERENCE

Portions of the definitive proxy statement related to the registrant's 2006
Annual Meeting of Stockholders to be held on June 8, 2006, 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..................................................................... 1

Item 1. Business..................................................... 1
Item 1A. Risk Factors................................................. 13
Item 2. Properties................................................... 20
Item 3. Legal Proceedings............................................ 21
Item 4. Submission of Matters to a Vote of Security Holders.......... 21

PART II.................................................................... 21

Item 5. Market for Registrant's Common Equity, Related Stockholder
Matters and Issuer Purchases of Equity Securities............ 21
Item 6. Selected Financial Data...................................... 23
Item 7. Management's Discussion and Analysis of Financial Condition
and Results of Operations.................................... 24
Item 7A. Quantitative and Qualitative Disclosures About Market Risk... 34
Item 8. Financial Statements and Supplementary Data.................. 34
Item 9. Changes in and Disagreements With Accountants on
Accounting and Financial Disclosure.......................... 53
Item 9.A Controls and Procedures...................................... 53

PART III................................................................... 53

Item 10. Directors and Executive Officers of the Registrant........... 54
Item 11. Executive Compensation....................................... 54
Item 12. Security Ownership of Certain Beneficial Owners and
Management and Related Stockholder Matters................... 54
Item 13. Certain Relationships and Related Transactions............... 54
Item 14. Principal Accountant Fees and Services....................... 54

PART IV.................................................................... 55

Item 15. Exhibits, Financial Statement Schedules and Reports
on Form 8-K.................................................. 55

PART I

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

ITEM 1. BUSINESS

GENERAL

We provide contract land drilling services and equipment, primarily to natural
gas producers in the U.S. We commenced operations in 1997 with 12 drilling rigs
and related equipment acquired from a predecessor that was providing contract
drilling services under the name "Union Drilling." Through a combination of
acquisitions and new rig construction, we have increased the size of our fleet
to 70 land drilling rigs, of which 63 are marketed and seven are stacked.

Our principal operations are in the Appalachian Basin, extending from New York
to Tennessee, the Arkoma Basin in eastern Oklahoma and western Arkansas, the
Fort Worth Basin in northern Texas, the Piceance Basin in western Colorado, and
the Uinta Basin in eastern Utah. These geological basins are generally
characterized by unconventional natural gas formations with very low
permeability rock, such as tight sands and shales, and coal seams with coal bed
methane, or CBM, deposits.

Substantially all of our rigs operate in unconventional natural gas producing
areas, where specialized drilling techniques are required to develop
unconventional natural gas resources efficiently. Horizontal drilling is a
specialized drilling technique intended to increase the exposure of the wellbore
to the natural gas producing formation and increase drainage rates and
production volumes. We have equipped 39 of our 70 rigs for drilling horizontal
wells. As many of these areas are also characterized by hard rock formations
entailing more difficult drilling penetration conditions, we have equipped 41 of
our 70 rigs with air compression systems to provide underbalanced drilling,
which results in higher penetration rates through hard rock formations when
compared to traditional fluid-based circulation systems. In response to rising
demand from our customers for equipment that is capable of drilling wells
horizontally into unconventional natural gas formations and providing
underbalanced drilling services, we have increased our fleet of drilling rigs
capable of efficiently serving these markets through acquisitions and new rig
construction.

In response to rising demand from our customers for equipment that is capable of
efficiently drilling wells in unconventional natural gas formations, we have
completed several transactions in 2005 aimed at enhancing our ability to serve
these markets. In April 2005, we acquired Thornton Drilling Company, which owned
a fleet of 12 rigs and leased a thirteenth rig operating in the Arkoma Basin,
and eight rigs from SPA Drilling L.P., five of which are targeting the Barnett
Shale formation in the Fort Worth Basin. In June 2005 and August 2005, we
acquired six more rigs, five of which targeted the Barnett Shale formation in
the Fort Worth Basin. These transactions substantially expanded our
unconventional natural gas contract drilling operations beyond our traditional
markets in the Appalachian Basin and the Rocky Mountains. In addition to these
acquisitions, over the past three years we have purchased seven newly
constructed rigs and have devoted significant capital expenditures to upgrade
other rigs in our fleet for underbalanced and horizontal drilling. These
investments have positioned our fleet to capitalize on our customers' rapidly
growing unconventional resource exploration and development activity.

On November 28, 2005, we consummated an initial public offering of our common
stock (the "IPO"). In the IPO, we sold 4,411,765 shares of our common stock to
the public at a price of $14.00 per share and

certain selling stockholders sold 4,411,765 shares of our common stock to the
public at the same price. We received net proceeds of approximately $55.4
million from the IPO. In connection with the IPO, on November 22, 2005, our
common stock began trading on the NASDAQ National Market. See "Use of Proceeds"
under Item 5 of this Report.

OUR MARKETS

Appalachian Basin

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

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

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

We market 31 drilling rigs and store four stacked rigs in the Appalachian Basin.
The following table sets forth certain information with respect to each of these
marketed rigs as of March 27, 2006.

DRILLING CAPABILITY CURRENT ACTIVITY
-------------------------- --------------------------------------------------------------
RIG NO. HORIZONTAL UNDERBALANCED TYPE CONTRACT PLAY
------- ---------- ------------- ---------- ---------------------------------- ------------

15 [X] Vertical Daywork Devonian (3)
53 [X] [X] Horizontal Daywork CBM (1)
55 [X] [X] Vertical Daywork Devonian
56 [X] [X] Horizontal Daywork CBM
57 [X] [X] Vertical Daywork Devonian
24 [X] Vertical Footage Clinton (2)
25 [X] Vertical Footage Clinton
34 [X] Vertical Footage Clinton
35 [X] Vertical Footage Clinton
36 [X] Vertical Footage Clinton

37 [X] Vertical Footage Clinton
39 [X] [X] Vertical Daywork Devonian
46 [X] [X] Vertical Daywork Devonian
51 [X] [X] Horizontal Daywork Oriskany (4)
21 [X] [X] Horizontal Daywork TBR (5)
43 [X] [X] Horizontal Daywork TBR
48 [X] [X] Horizontal Daywork TBR
52 [X] [X] Horizontal Daywork TBR
54 [X] [X] Horizontal Daywork TBR
1 Coal (6) Daywork N/A
2 Coal Daywork N/A
8 Coal Daywork N/A
10 Coal Daywork N/A
18 Coal Daywork N/A
20 Coal Daywork N/A
31 Coal Daywork N/A
41 Coal Daywork N/A
42 Coal Daywork N/A
4 [X] Vertical Daywork Devonian
3 [X] [X] Available for service but inactive
5 [X] Available for service but inactive

(1) Coalbed methane development.

(2) Clinton/Medina development.

(3) Devonian development.

(4) Oriskany development.

(5) Trenton/Black River exploration and development.

(6) Re-drilling and plugging operations in advance of long wall coal mining.

Our principal competitors in the Appalachian Basin are primarily smaller,
family-owned companies that serve fragmented markets within the Basin.

In the last two years, we have witnessed a significant increase in acquisitions
and divestitures of oil and gas properties in the Appalachian Basin, which we
believe to be directly attributable to the appreciation of natural gas prices
over the same period of time and the corresponding improvement in the economics
of producing natural gas. Acquisition activity has been driven by a broad
universe of buyers, comprised of both publicly traded independent oil and
natural gas companies who have actively sought to expand their operations in the
region, and a number of financial investors who have shown an active interest in
the region. We believe that the recent buyers of oil and natural gas properties
in the region intend to increase the level of drilling activity on the
properties which they have acquired in an effort to enhance the return on the
capital invested in the acquisition of the property. We believe the increased
level of acquisition activity should produce an acceleration of drilling
activity in the Appalachian Basin that will inure to our benefit.

Arkoma Basin

The Arkoma Basin includes portions of western Arkansas and eastern Oklahoma
covering an area of about 33,800 square miles. The area is characterized by
organically rich rock layers that produce natural gas at depths averaging 7,000
feet. Most natural gas directed drilling in the Arkoma Basin is conducted by
rigs equipped with air compression equipment for underbalanced drilling
operations.

More recently, operators have been leasing acreage to develop shallower natural
gas-bearing formations, known as the Fayetteville Shale on the Arkansas side and
the Caney Shale on the Oklahoma side of the Arkoma Basin. These Mississippian
age formations, existing at depths of 1,500 to 6,500 feet, are geologically
similar to the Barnett Shale formation in northern Texas. Within the
Fayetteville Shale, one producer has amassed a substantial acreage position and
has recently commenced a horizontal drilling pilot

program, which in its early stages has yielded results comparable to what has
been achieved in some of the more prolific unconventional resource plays in
North America.

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

We market 15 drilling rigs in the Arkoma Basin. The following table sets forth
certain information with respect to each of these rigs as of March 27, 2006.

DRILLING CAPABILITY CURRENT ACTIVITY
-------------------------- ----------------------------------------
RIG NO. HORIZONTAL UNDERBALANCED TYPE CONTRACT PLAY
------- ---------- ------------- ---------- -------- ----------------
38 [X] [X] Horizontal Daywork Caney (1)
40 [X] [X] Vertical Daywork Conventional (3)
104 [X] [X] Horizontal Daywork CBM (2)
105 [X] [X] Horizontal Daywork CBM
108 [X] [X] Horizontal Daywork CBM
109 [X] [X] Vertical Daywork CBM
114 [X] [X] Horizontal Daywork CBM
115 [X] [X] Vertical Daywork CBM
117 [X] [X] Vertical Footage CBM
119 [X] [X] Horizontal Daywork CBM
110 [X] [X] Vertical Daywork Conventional
112 [X] Vertical Daywork Conventional
116 [X] Vertical Daywork Conventional
118(4) [X] [X] Vertical Daywork Conventional
123 [X] Horizontal Daywork Fayetteville (5)

(1) Caney Shale exploration and development.

(2) Coalbed methane development.

(3) Conventional Arkoma Basin development.

(4) Leased from Stephens Production Co. Inc.

(5) Fayetteville Shale exploration and development

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

Northern Texas

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

We market 12 drilling rigs and store three stacked rigs in northern Texas. The
following table sets forth certain information with respect to each of these
marketed rigs as of March 27, 2006.

DRILLING CAPABILITY CURRENT ACTIVITY
-------------------------- -----------------------------------
RIG NO. HORIZONTAL UNDERBALANCED TYPE CONTRACT PLAY
------- ---------- ------------- ---------- -------- -----------
205 [X] Horizontal Daywork Barnett (1)
206 [X] Vertical Footage Barnett
207 [X] Horizontal Daywork Barnett
209 [X] Horizontal Daywork Barnett
211 [X] Horizontal Daywork Barnett
212 [X] Horizontal Daywork Barnett
214 [X] Horizontal Daywork Barnett
33 Vertical Footage Permian (2)
201 Vertical Footage Permian
203 Vertical Footage Permian
210 Vertical Daywork Permian
215 [X] Horizontal Daywork Barnett

(1) Northern Texas Barnett Shale development.

(2) Eastern Permian Basin oil development.

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

The Rocky Mountains

According to U.S. Geological Survey (USGS) estimates, the Rocky Mountain region
has the largest quantity of natural gas resources in the U.S., most of which are
considered to be unconventional.

Our operations are focused in the Uintah Basin in eastern Utah and the Piceance
Basin in western Colorado. Nearly all of the recoverable natural gas reserves in
these basins are contained in unconventional formations. Natural gas in the
Uintah Basin is produced from three tight sand formations. The Piceance basin is
characterized by thick natural gas accumulations primarily in the Williams Fork
formation.

The Uintah Basin also has deposits of black wax oil at depths of 5,500 to 6,500
feet. This oil has a high paraffin content that makes it viscous and
non-pourable at room temperature, and it must be extracted, transported and
refined with equipment specifically designed to handle it. Two of our rigs that
were previously drilling for natural gas in this market are currently drilling
black wax oil wells.

We market five drilling rigs in the Rocky Mountains. The following table sets
forth certain information with respect to each of these marketed rigs as of
March 27, 2006.

DRILLING CAPABILITY CURRENT ACTIVITY
-------------------------- --------------------------------------
RIG NO. HORIZONTAL UNDERBALANCED TYPE CONTRACT PLAY
------- ---------- ------------- ---------- -------- --------------
32 [X] [X] Horizontal Daywork Uintah Gas (3)
47 [X] [X] Horizontal Daywork Piceance (1)
7 [X] [X] Vertical Daywork Uintah Gas
14 [X] [X] Vertical Daywork Uintah Oil (2)
45 [X] [X] Horizontal Daywork Uintah Gas

(1) Piceance Basin development.

(2) Uintah Basin Lower Green River heavy wax oil drilling.

(3) Uintah Basin Gas development below the Green River formation

Our principal competitors in the Rocky Mountains are Nabors and Patterson-UTI.

CUSTOMERS AND MARKETING

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

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

We market our rigs to a number of customers. In 2005, we drilled wells for 144
different customers, compared to 55 customers in 2004 and 55 customers in 2003.
The increase in number of customers in 2005 versus prior periods reflects the
additional customers we added when we entered the Arkoma and North Texas
markets. The following table shows our three largest customers as a percentage
of our total contract drilling revenue for each of our last three years.

Total Contract Drilling
Year Customer Revenue Percentage
---- -------------------------- -----------------------
2005 Consol 9.3%
Fortuna 6.6%
Great Lakes Energy 5.9%
----
Total 21.8%
====
2004 Fortuna 16.3%
Consol 14.3%
Columbia Natural Resources 12.6%
----
Total 43.2%
====
2003 Equitable Resources 10.8%
Consol 10.4%
Fortuna 9.5%
----
Total 30.7%
====

DRILLING CONTRACTS

Our contracts for drilling natural gas wells are obtained either through
competitive bidding or through direct negotiations with customers. Our oil and
natural gas drilling contracts provide for compensation on a "daywork" or
"footage" basis. In 2005, approximately 77% of our revenues were derived from
daywork contracts. Most of the wells we drilled pursuant to footage contracts
were drilled in our Northern Appalachian region. Contract terms we offer
generally depend on the complexity and risk of operations, the on site drilling
conditions, the type of equipment used and the anticipated duration of the work
to be performed. Our contracts generally provide for the drilling of a single
well or a series of wells and typically permit the customer to terminate on
short notice.

Daywork contracts. Under daywork contracts, we provide a drilling rig with
required personnel to the operator, who supervises the drilling of the well. We
are paid based on a negotiated fixed rate per day while the rig is utilized. The
rates for our services depend on market and competitive conditions, the nature
of the operations to be performed, the duration of the work, the equipment and
services to be provided, the geographic area involved and other variables. Lower
rates may be paid when the rig is in transit, or when drilling operations are
interrupted or restricted by conditions beyond our control. In addition, daywork
contracts typically provide for a separate amount to cover the cost of
mobilization and demobilization of the drilling rig. Daywork drilling contracts
generally specify the type of equipment to be used, the size of the hole and the
depth of the well. Under a daywork drilling contract, the customer bears a large
portion of

out-of-pocket costs of drilling and we generally do not bear any part of the
usual capital risks associated with oil and natural gas exploration.

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

The risks under footage contracts are greater than under daywork contracts
because we assume more of the risks associated with drilling operations
generally assumed by the operator in a daywork contract, including risk of
blowout, loss of hole, lost or damaged drill pipe, machinery breakdowns,
abnormal drilling conditions and risks associated with subcontractors' services,
supplies, cost escalation and personnel. Historically, the percentage of
revenues derived from footage contracts has decreased from over 50% in the early
2000's to approximately 23% currently. We expect this percentage to decline
further in the future. Currently only ten of our 70 rigs are working on a
footage basis. Many of our footage contracts now have provisions whereby some or
all of the risks associated with geological issues and down hole mechanical
matters have been shifted to our customers. The transfer of this risk is done by
contractually transferring the drilling services from a footage drilled basis to
an hourly based daywork type contract when unforeseen or uncontrollable events
are encountered during the drilling process. When this occurs, the contract also
provides for the transfer of third party costs and tangible items such as drill
bits from us to our customers during these unforeseen problematic periods.

OUR RIG FLEET

General

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

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

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

We own 70 drilling rigs, of which 63 are actively marketed. A land drilling rig
of the general type we operate consists of engines, drawworks, mast, pumps,
blowout preventers, drill pipe, air drilling and percussion packages consisting
of compressors and boosters, and related equipment.

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

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

This equipment consists of bulldozers, trucks and other support equipment.

We believe that our drilling rigs and other related equipment are in good
operating condition.

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

COMPETITION

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

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

o the mobility and efficiency of the rigs;

o the safety records of the rigs;

o crew experience and skill;

o customer relationships;

o the offering of ancillary services; and

o the ability to provide drilling equipment adaptable to, and personnel
familiar with, new technologies and drilling techniques.

While we must be competitive in our pricing, our competitive strategy generally
emphasizes the quality of our equipment, the safety record of our rigs and the
experience of our rig crews to differentiate us from our competitors.

Contract drilling companies compete primarily on a regional basis, and the
intensity of competition may vary significantly from region to region at any
particular time. If demand for drilling services improves in a region where we
operate, our competitors might respond by moving in suitable rigs from other
regions.

Many of our competitors have greater financial, technical and other resources
than we do. Their greater capabilities in these areas may enable them to:

o better withstand industry downturns;

o compete more effectively on the basis of price and technology;

o better retain skilled rig personnel; and

o build new rigs or acquire and refurbish existing rigs so as to be able
to place rigs into service more quickly than us in periods of high
drilling demand.

RAW MATERIALS

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

SEASONALITY

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

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

EMPLOYEES

We currently have approximately 1,300 employees. Approximately 160 of these
employees are salaried administrative or supervisory employees. The rest of our
employees are hourly employees who operate or maintain our drilling rigs and
rig-hauling trucks. The number of hourly employees fluctuates depending on the
number of drilling projects we are engaged in at any particular time. None of
our employment arrangements is subject to collective bargaining arrangements.

OPERATING HAZARDS AND INSURANCE

Our operations are subject to many hazards inherent in the land drilling
business, including, for example, blowouts, craterings, fires, explosions, loss
of well control, poisonous gas emissions, loss of hole, damaged or lost drill
strings, and damage or loss from inclement weather. These hazards could cause
personal injury or death, serious damage to or destruction of property and
equipment, suspension of drilling operations, or

substantial damage to the environment, including damage to producing formations
and surrounding areas. Generally, we seek to obtain indemnification from our
customers by contract for some of these risks. To the extent not transferred to
customers by contract, we seek protection against some of these risks through
insurance, including property casualty insurance on our rigs and drilling
equipment, commercial general liability, which has coverage extension for
underground resources and equipment coverage, commercial contract indemnity,
commercial umbrella and workers' compensation insurance.

Our insurance coverage for property damage to our rigs and drilling equipment is
based on our estimate of the cost of comparable used equipment to replace the
insured property. There is a deductible of $100,000 per occurrence on rigs and
$25,000 per occurrence on equipment. Our third party liability insurance
coverage under the general liability policy is $1 million per occurrence, with a
self-insured retention of $10,000 per occurrence. The commercial umbrella policy
coverage is $20 million per occurrence, with a self-insured retention of $10,000
per occurrence. We believe that we are adequately insured for liability and
property damage to others with respect to our operations. However, such
insurance may not be sufficient to protect us against liability for all
consequences of well disasters, extensive fire damage or damage to the
environment.

We maintain worker's compensation insurance in all states in which we operate.
The states of West Virginia and Ohio are exclusive with regard to this coverage.
We pay premiums to those states directly based upon the payroll related to our
employees working in those states. In all other states, with the exception of
Texas, which has a $1,000 deductible, we maintain a $100,000 deductible for each
accident.

GOVERNMENT REGULATION AND ENVIRONMENTAL MATTERS

General

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

Environmental regulation

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

Except for the handling of solid wastes directly generated from the operation
and maintenance of our drilling rigs, such as waste oils and wash water, it is
our practice to require our customers to contractually assume responsibility for
compliance with environmental regulations. Laws and regulations protecting the
environment have become more stringent in recent years, and may, in some
circumstances, impose strict liability, rendering a person liable for
environmental damage without regard to negligence or fault on the part of that
person. These laws and regulations may expose us to liability for the conduct of
or conditions

caused by others, or for our own acts that were in compliance with all
applicable laws at the time the acts were performed. The application of these
requirements or adoption of new requirements could have a material adverse
effect on us.

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

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

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

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

Superfund

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

Hazardous waste disposal

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

Health and safety matters

Our facilities and operations are also governed by laws and regulations,
including the federal Occupational Safety and Health Act, or OSHA, relating to
worker health and workplace safety. As an example, the Occupational Safety and
Health Administration has issued the Hazard Communication Standard, or HCS,
requiring employers to identify the chemical hazards at their facilities and to
educate employees about these

hazards. HCS applies to all private-sector employers, including the oil and
natural gas exploration and producing industry. HCS requires that employers
assess their chemical hazards, obtain and maintain written descriptions of these
hazards, develop a hazard communication program and train employees to work
safely with the chemicals on site. Failure to comply with the requirements of
the standard may result in administrative, civil and criminal penalties. We
believe that appropriate precautions are taken to protect employees and others
from harmful exposure to materials handled and managed at our facilities and
that we operate in substantial compliance with all OSHA regulations.

AVAILABLE INFORMATION

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

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

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

CAUTIONARY STATEMENT CONCERNING
FORWARD-LOOKING STATEMENTS AND RISK FACTORS

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

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

In addition, various statements that this Annual Report on Form 10-K contains,
including those that express a belief, expectation or intention, as well as
those that are not statements of historical fact, are forward-looking
statements. Those forward-looking statements appear in Item 1- "Business", Item
2 - "Properties" and Item 3 - "Legal Proceedings" in Part I of this report and
in Item 5 - "Market for Registrant's Common Equity, Related Stockholder Matters
and Issuer Purchases of Equity Securities," and in Item 7 - "Management's
Discussion and Analysis of Financial Condition and Results of Operations," Item
7A - "Quantitative and Qualitative Disclosures About Market Risk" and in the
Notes to Consolidated Financial Statements we have included in Item 8 of Part II
of this report and elsewhere in this report. These forward-looking statements
speak only as of the date of this report. We disclaim any obligation to update
these statements, and we caution you not to rely on them unduly. We have based
these forward-looking

statements on our current expectations and assumptions about future events.
While our management considers these expectations and assumptions to be
reasonable, they are inherently subject to significant business, economic,
competitive, regulatory and other risks, contingencies and uncertainties, most
of which are difficult to predict and many of which are beyond our control.
These risks, contingencies and uncertainties relate to, among other matters, the
following:

o general economic and business conditions and industry trends;

o the continued strength of the contract land drilling industry in the
geographic areas where we operate;

o levels and volatility of oil and gas prices;

o decisions about onshore exploration and development projects to be
made by oil and gas companies;

o the highly competitive nature of our business;

o the success or failure of our acquisition strategy, including our
ability to finance acquisitions and manage growth;

o our future financial performance, including availability, terms and
deployment of capital;

o the continued availability of qualified personnel; and

o changes in, or our failure or inability to comply with, governmental
regulations, including those relating to the environment.

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

ITEM 1A. RISK FACTORS

RISKS RELATING TO OUR BUSINESS

OUR BUSINESS AND OPERATIONS ARE SUBSTANTIALLY DEPENDENT UPON, AND AFFECTED BY,
THE LEVEL OF U.S. ONSHORE NATURAL GAS EXPLORATION AND DEVELOPMENT ACTIVITY,
WHICH HAS EXPERIENCED SIGNIFICANT VOLATILITY. IF THE LEVEL OF THAT ACTIVITY
DECREASES, OUR BUSINESS AND RESULTS OF OPERATIONS COULD BE ADVERSELY AFFECTED.

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

o the market prices of natural gas;

o market expectations about future prices of natural gas or oil (which
is closely correlated with natural gas prices);

o the cost of producing and delivering natural gas;

o the capacity of the natural gas pipeline network;

o government regulations and trade restrictions;

o the presence or absence of tax incentives;

o national and international political and economic conditions;

o levels of production by, and other activities of, the Organization of
Petroleum Exporting Countries and other oil and natural gas producers;

o the levels of imports of natural gas, whether by pipelines from Canada
or Mexico or by tankers in the form of LNG; and

o the development of alternate energy sources and the long-term effects
of worldwide energy conservation measures.

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

ALMOST 90% OF OUR DRILLING RIGS ARE MORE THAN 20 YEARS OLD, AND MAY REQUIRE
INCREASING AMOUNTS OF CAPITAL TO UPGRADE AND REFURBISH. ANY FAILURE TO CONTINUE
TO INVEST CAPITAL TO UPGRADE AND REFURBISH RIGS COULD RESULT IN OUR HAVING FEWER
RIGS AVAILABLE FOR SERVICE.

Most of our drilling rigs were built during the years 1976 to 1982, the period
of the industry's most recent building cycle. Our rig upgrade and refurbishment
projects on marketed rigs typically require 60 to 90 days to complete at a cost
of $175,000 to $250,000. This process includes derrick recertification, engine
rebuilding or replacement and upgraded or replaced braking systems. Returning
our stacked rigs to service would cost $1.5 to $2.5 million per rig for
refurbishment and the purchase of drillpipe, pumps, generators and other
required equipment. Depending upon the availability of equipment, this process
could take from 90 to 180 days. To the extent we are unable to commence or
continue such projects, we will have fewer rigs available for service, which
could adversely affect our financial condition and results of operations.

IN THE YEAR ENDED DECEMBER 31, 2005, WE DERIVED APPROXIMATELY 21.8% OF OUR TOTAL
REVENUES FROM THREE CUSTOMERS. THE LOSS OF ANY OF THOSE CUSTOMERS OR THE FAILURE
TO REMARKET THE RIGS EMPLOYED BY THOSE CUSTOMERS COULD HAVE A MATERIAL ADVERSE
EFFECT ON OUR FINANCIAL CONDITION AND RESULTS OF OPERATIONS.

In the year ended December 31, 2005, our three largest customers accounted for
approximately 9.3%, 6.6% and 5.9%, respectively, of our total revenues. Our
principal customers may not continue to employ our services and we may not be
able to successfully remarket the rigs that they may choose not to employ. The
loss of any of our principal customers or the failure to remarket the rigs
employed by those customers could have a material adverse effect on our
financial condition and results of operations.

OUR HISTORICAL STRATEGY HAS BEEN PREDICATED ON GROWING THROUGH A COMBINATION OF
ACQUISITIONS OF RIGS FROM THIRD PARTIES AND THE CONSTRUCTION OF NEW RIGS. DUE TO
INCREASED COMPETITION AMONG DRILLING CONTRACTORS FOR ADDITIONAL RIGS, WE MAY NOT
BE ABLE TO CONTINUE TO ADD RIGS TO OUR FLEET, WHICH COULD HAVE AN ADVERSE EFFECT
ON OUR ABILITY TO GROW REVENUE AND PROFITS.

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

INCREASED DEMAND AMONG DRILLING CONTRACTORS FOR CONSUMABLE SUPPLIES, INCLUDING
FUEL, AND ANCILLARY RIG EQUIPMENT, SUCH AS PUMPS, VALVES, DRILLPIPE AND ENGINES,
MAY LEAD TO DELAYS IN OBTAINING THESE MATERIALS AND OUR INABILITY TO OPERATE OUR
RIGS IN AN EFFICIENT MANNER.

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

TO THE EXTENT WE ACQUIRE ADDITIONAL RIGS IN THE FUTURE, WE MAY EXPERIENCE
DIFFICULTY INTEGRATING THOSE ACQUISITIONS. ADDITIONALLY, WE MAY INCUR LEVERAGE
TO EFFECT THOSE ACQUISITIONS, WHICH ADDS ADDITIONAL FINANCIAL RISK TO OUR
BUSINESS. TO THE EXTENT WE INCUR TOO MUCH LEVERAGE IN UNDERTAKING ACQUISITIONS,
WE MAY ADVERSELY AFFECT OUR FINANCIAL POSITION.

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

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

WE INTEND TO PURCHASE ADDITIONAL DRILLING RIGS, UPGRADE SOME OF OUR MARKETED
DRILLING RIGS AND REFURBISH SOME OF OUR STACKED DRILLING RIGS. ANY DELAY COULD
RESULT IN A LOSS OF REVENUE.

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

o shortages of equipment, materials or skilled labor;

o long lead times or delays in the delivery of ordered materials and
equipment;

o engineering problems;

o work stoppages;

o weather interference;

o unavailability of specialized services; and

o unanticipated cost increases.

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

WE HAVE INCURRED LOSSES IN THE PAST AND MAY CONTINUE TO INCUR LOSSES. IF WE
INCUR LOSSES IN THE FUTURE, THE VALUE OF OUR COMMON STOCK COULD DECLINE.

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

WE MAY NOT BE ABLE TO RAISE ADDITIONAL FUNDS THROUGH PUBLIC OR PRIVATE
FINANCINGS OR ADDITIONAL BORROWINGS, WHICH COULD HAVE A MATERIAL ADVERSE EFFECT
ON OUR FINANCIAL CONDITION.

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

WE COULD BE ADVERSELY AFFECTED IF WE LOST THE SERVICES OF CERTAIN OF OUR
OFFICERS AND KEY EMPLOYEES.

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

IF WE CANNOT KEEP OUR RIGS UTILIZED AT PROFITABLE RATES, OUR OPERATING RESULTS
COULD BE ADVERSELY AFFECTED.

Our business has high fixed costs, and if we cannot keep our rigs utilized at
profitable rates, our operating results could be adversely affected.

OUR OPERATIONS COULD BE ADVERSELY AFFECTED BY ABNORMALLY POOR WEATHER
CONDITIONS.

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

INCREASED COMPETITION IN OUR DRILLING MARKETS COULD ADVERSELY AFFECT RATES AND
UTILIZATION OF OUR RIGS, WHICH COULD ADVERSELY AFFECT OUR FINANCIAL CONDITION
AND RESULTS OF OPERATIONS.

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

OUR OPERATIONS ARE SUBJECT TO HAZARDS INHERENT IN THE LAND DRILLING BUSINESS
THAT ARE BEYOND OUR CONTROL. IF THOSE RISKS ARE NOT ADEQUATELY INSURED OR
INDEMNIFIED AGAINST, OUR RESULTS OF OPERATIONS COULD BE ADVERSELY AFFECTED.

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

o blowouts;

o craterings;

o fires;

o explosions;

o equipment failures;

o poisonous gas emissions;

o loss of well control;

o loss of hole;

o damaged or lost drill strings; and

o damage or loss from inclement weather or natural disasters.

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

o personal injury or death;

o serious damage to or destruction of property and equipment;

o suspension of drilling operations; and

o substantial damage to the environment, including damage to producing
formations and surrounding areas.

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

OUR OPERATIONS ARE SUBJECT TO ENVIRONMENTAL, HEALTH AND SAFETY LAWS AND
REGULATIONS THAT MAY EXPOSE US TO LIABILITIES FOR NONCOMPLIANCE, WHICH COULD
ADVERSELY AFFECT US.

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

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

WE MAY NOT BE ABLE TO ATTRACT AND RETAIN THE SERVICES OF QUALIFIED OPERATING
PERSONNEL, WHICH COULD RESTRICT OUR ABILITY TO MARKET AND OPERATE OUR DRILLING
RIGS OR RESULT IN ACCIDENTS AND OTHER OPERATIONAL DIFFICULTIES.

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

WE WILL BE SUBJECT TO THE REQUIREMENTS OF SECTION 404 OF THE SARBANES-OXLEY ACT.
IF WE ARE UNABLE TO COMPLY WITH SECTION 404 IN A TIMELY MANNER OR IF THE COSTS
RELATED TO COMPLIANCE ARE SIGNIFICANT, OUR PROFITABILITY, STOCK PRICE AND
RESULTS OF OPERATIONS AND FINANCIAL CONDITION COULD BE MATERIALLY ADVERSELY
AFFECTED.

We will be required to comply with the provisions of Section 404 of the
Sarbanes-Oxley Act of 2002 as of December 31, 2006. Section 404 requires that we
document and test our internal control over financial reporting and issue
management's assessment of our internal control over financial reporting. This
section also requires that our independent registered public accounting firm
opine on those internal controls and management's assessment of those controls.
We are currently evaluating our existing controls against the standards adopted
by the Committee of Sponsoring Organizations of the Treadway Commission, or
COSO. During the course of our ongoing evaluation and integration of the
internal control over financial reporting, we may identify areas requiring
improvement, and we may have to design enhanced processes and controls to
address issues identified through this review. We believe that the out-of-pocket
costs, the diversion of management's attention from running the day-to-day
operations and operational changes caused by the need to comply with the
requirements of Section 404 of the Sarbanes-Oxley Act could be significant. If
the time and costs associated with such compliance exceed our current
expectations, our results of operations could be adversely affected.

We cannot be certain at this time that we will be able to successfully complete
the procedures, certification and attestation requirements of Section 404 or
that we or our auditors will not identify material weaknesses in internal
control over financial reporting. If we fail to comply with the requirements of
Section 404 or if we or our auditors identify and report such material weakness,
the accuracy and timeliness of the filing of our annual and quarterly reports
may be materially adversely affected and could cause investors to lose
confidence in our reported financial information, which could have a negative
effect on the trading price of our common stock. In addition, a material
weakness in the effectiveness of our internal control over financial reporting
could result in an increased chance of fraud and the loss of customers, reduce
our ability to obtain financing and require additional expenditures to comply
with these requirements, all of which could have a material adverse effect on
our business, results of operations and financial condition.

OUR DEBT AGREEMENTS CONTAIN RESTRICTIONS THAT LIMIT OUR FLEXIBILITY IN OPERATING
OUR BUSINESS.

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

o incur additional indebtedness or issue certain preferred shares;

o pay dividends on or make distributions in respect of our capital stock
or make other restricted payments;

o make certain investments, including capital expenditures;

o sell certain assets;

o create liens; and

o consolidate, merge, sell or otherwise dispose of all or substantially
all of our assets.

RISKS RELATED TO OUR COMMON STOCK

WE ARE CONTROLLED BY OUR PRINCIPAL STOCKHOLDER.

Union Drilling Company LLC, our principal stockholder, owns approximately 38% of
our outstanding common stock. Union Drilling Company LLC is controlled by
Metalmark Capital LLC. As a result, Union Drilling Company LLC and its
affiliates may substantially influence the outcome of stockholder votes,
including votes concerning the election of directors, the adoption or amendment
of provisions in our certificate of incorporation or bylaws and the approval of
mergers and other significant corporate transactions. The existence of these
levels of ownership concentration makes it less likely that any small holder of
our common stock will be able to affect the management or direction of Union.
These factors may also have the effect of delaying or preventing a change in the
management or voting control of Union.

WE HAVE RENOUNCED ANY INTEREST IN SPECIFIED BUSINESS OPPORTUNITIES, AND OUR
DIRECTORS AND THEIR AFFILIATES GENERALLY HAVE NO OBLIGATION TO OFFER US THOSE
OPPORTUNITIES.

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

OUR EXISTING DIVIDEND POLICY AND CONTRACTUAL RESTRICTIONS LIMIT OUR ABILITY TO
PAY DIVIDENDS.

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

PROVISIONS IN OUR CERTIFICATE OF INCORPORATION AND BYLAWS AND OF DELAWARE
CORPORATE LAW MAY MAKE A TAKEOVER DIFFICULT.

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

LIMITED TRADING VOLUME OF OUR COMMON STOCK MAY CONTRIBUTE TO ITS PRICE
VOLATILITY.

Our common stock is traded on the NASDAQ National Market. During the period from
November 22, 2005 through March 27, 2006, the average daily trading volume of
our common stock as reported by the NASDAQ National Market was 256,993 shares.
There can be no assurance that a more active trading market in our common stock
will develop. As a result, relatively small trades may have a significant impact
on the price of our common stock and, therefore, may contribute to the price
volatility of our common stock. As a result, our common stock may be subject to
greater price volatility than the stock market as a whole and comparable
securities of other contract drilling service providers.

The market price of our common stock has been, and may continue to be, volatile.
For example, during the period from November 22, 2005 through March 27, 2006,
the trading price of our common stock ranged from $12.31 to $18.15 per share.

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

ITEM 2. PROPERTIES

FACILITIES

We lease approximately 6,000 square feet of office space for our principal
executive offices in Bridgeville, Pennsylvania. In May 2006, we will be moving
our corporate headquarters to new office space in Fort Worth, Texas. We have
entered into a 90-month lease with monthly payment of approximately $15,000.
This lease is cancelable after a period of 48 months from the first month we
make lease payments.

Our contract drilling operations are conducted from seven field offices.

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

From our Central Appalachian office in Buckhannon, West Virginia, we provide
contract drilling services to the entire state of West Virginia, as well as
southern Pennsylvania, Maryland and New York. This office also serves federally
regulated natural gas storage customers and the coal mining industry, with a
group of rigs specifically equipped for these two specialty markets. We own
approximately 36 acres of land in Buckhannon, on which we have 4,900 square feet
of office space and 32,400 square feet of warehouse space.

From our Southern Appalachian office in Norton, Virginia, we provide contract
drilling services to the natural gas industry in the southern region of the
Appalachian Basin. This office's primary areas of operation include southwestern
Virginia, eastern Kentucky, southern West Virginia and the entire state of
Tennessee. We lease a facility in Norton that includes approximately 36,000
square feet of warehouse space, 4,940 square feet of office space and yard
space.

From our northern Texas office in Abilene, Texas, we provide contract drilling
services in the Abilene area. We lease a facility in Abilene, Texas, that
includes approximately 9,000 square feet of warehouse space, 2,500 square feet
of office space and yard space. In addition, we recently established an office
in Cresson, Texas, which has become the site of our Fort Worth Basin operations.

From our Oklahoma office in Pocola, Oklahoma, we provide contract drilling
services in the Arkoma Basin. We own approximately 48 acres of land in Pocola,
on which we have 4,800 square feet of office space and 8,000 square feet of
warehouse space. In addition, we own five acres of land in Dewey, Oklahoma with
534 square feet of office space and two buildings with 7,200 square feet of
warehouse space. We also own 2.5 acres of land in McCurtain, Oklahoma, and 1,420
square feet of office space in Bartlesville, Oklahoma.

From our Rocky Mountain office in Vernal, Utah, we provide oil and natural gas
contract drilling services primarily in the state of Utah, but also occasionally
conduct operations in Colorado. We lease a facility in Vernal that includes
approximately 2,500 square feet of warehouse space. We also own or lease other
properties in our market areas for storage and similar uses. We consider all of
our facilities to be in good operating condition and adequate for their present
uses.

ITEM 3. LEGAL PROCEEDINGS

Due to the nature of our business, we are, from time to time, involved in
routine litigation or subject to disputes or claims related to our business
activities, including workers' compensation claims and employment-related
disputes. In the opinion of our management, none of the pending litigation,
disputes or claims against us will have a material adverse effect on our
financial condition or results of operations.

ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

We did not submit any matter to a vote of our security holders during the fourth
quarter of fiscal 2005.

PART II

ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND
ISSUER PURCHASES OF EQUITY SECURITIES

As of March 27, 2006, 21,166,109 shares of our common stock were outstanding. As
of March 27, 2006, the number of holders of record of our common stock was 7.
The number of record holders does not necessarily bear any relationship to the
number of beneficial owners of our common stock.

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

Low High
------ ------
Fiscal Year Ended December 31, 2005:
Fourth Quarter (beginning November 22, 2005) $13.60 $15.50

The last reported sales price for our common stock on the NASDAQ National Market
on March 27, 2006 was $14.32 per share.

We have not paid or declared any dividends on our common stock and currently
intend to retain earnings to fund our working capital needs and growth
opportunities. Any future dividends will be at the discretion of

our board of directors after taking into account various factors it deems
relevant, including our financial condition and performance, cash needs, income
tax consequences and the restrictions Delaware and other applicable laws and our
credit facilities then impose. Our debt arrangements include provisions that
generally prohibit us from paying dividends, other than dividends on our
preferred stock. We currently have no preferred stock outstanding.

EQUITY COMPENSATION PLAN INFORMATION

The following table provides information as of December 31, 2005 about Union's
common stock that may be issued upon the exercise of options, warrants and
rights granted to employees, consultants or members or the board of directors
under all of our existing equity compensation plans:

NUMBER OF
SHARES OF COMMON STOCK
NUMBER OF SHARES REMAINING AVAILABLE FOR
OF COMMON STOCK TO BE WEIGHTED-AVERAGE FUTURE ISSUANCE UNDER EQUITY
ISSUED UPON EXERCISE OF EXERCISE PRICE PER SHARE COMPENSATION PLANS
OUTSTANDING OPTIONS, OF OUTSTANDING OPTIONS, (EXCLUDING SHARES
PLAN CATEGORY WARRANTS AND RIGHTS WARRANTS AND RIGHTS REFLECTED IN COLUMN (A))
------------------------------- ----------------------- ------------------------ -----------------------------
(A) (B) (C)

Equity compensation plans
approved by security holders 1,541,380(1) $7.21 1,222,928(2)

(1) Includes 876,647 shares of common stock issuable upon the exercise of
options that were outstanding under our Amended and Restated 2000 Stock
Option Plan, 132,958 shares of common stock issuable upon the exercise of
options that were outstanding under a separate Union stock option plan and
agreement, the terms of which are substantially similar to those of our
Amended and Restated 2000 Stock Option Plan and 531,775 shares of common
stock issuable upon the exercise of options that were outstanding under our
2005 Stock Option Plan, in each case, as of December 31, 2005.

(2) Represents the difference between the number of shares of our common stock
issuable under the Amended and Restated 2000 Stock Option Plan, the
separate stock option plan referred to above and the 2005 Stock Option
Plan, of 3,292,062 shares, and the number of shares of our common stock
issued under such plans as of December 31, 2005, which consist of options
to acquire 1,541,380 shares of common stock (net of exercises of 527,754).

RECENT SALES OF UNREGISTERED SECURITIES

The following information relates to securities of Union issued or sold during
the year ended December 31, 2005 that were not registered under the Securities
Act.

On April 1, 2005, Union sold an aggregate of 2,771,145 shares of its common
stock to Steven A. Webster, Wolf Marine S.A. and William R. Ziegler, each of
whom was already an indirect investor in Union, for an aggregate purchase price
of $20,000,008 in a private placement meeting the requirements of Rule 506 under
the Securities Act. Also on April 1, 2005, Union sold 292,509 shares of its
common stock to Richard Thornton, the sole stockholder of Thornton Drilling
Company, for a purchase price of $1,999,999 in a separate private placement
meeting the requirements of Rule 506 under the Securities Act. Mr. Thornton used
a portion of the purchase price paid by Union for Thornton Drilling Company,
which acquisition also closed on April 1, 2005, to fund his purchase of Union
common stock. These share numbers reflect a subsequent stock dividend of
1.6325872 shares for each outstanding share of common stock of Union.

On November 28, 2005, Union issued 527,754 shares of its common stock to W.
Henry Harmon, the Vice Chairman of Union at the time of such issuance, pursuant
to the exercise of stock options held by Mr. Harmon. The aggregate exercise
price received by Union in connection with the exercise of these options was
$3,810,384.

Each of the above-described offerings of securities of Union was exempt from the
registration requirements of the Securities Act by virtue of Section 4(2)
thereof as transactions not involving a public offering.

USE OF PROCEEDS FROM SALES OF REGISTERED SECURITIES

On November 21, 2005, we closed an initial public offering of our common stock
consisting of 8,823,530 shares of common stock. Of these shares, 4,411,765 were
newly issued shares sold by us and 4,411,765 were existing shares sold by the
selling stockholders. On December 9, 2005 an additional 1,323,530 shares of
existing common stock were sold by certain selling stockholders pursuant to an
exercise by the underwriters of their over allotment option. The offering was
effected pursuant to a Registration Statement on Form S-1 (File No. 333-127525),
which the SEC declared effective on November 21, 2005, and a final prospectus
filed with the SEC pursuant to Rule 424(b) under the Securities Act that was
filed on November 23, 2005 (Reg. No. 333-127525). J.P. Morgan Securities Inc.
acted as sole book-running lead manager, Jeffries & Company, Inc. acted as joint
lead manager and Bear Stearns & Co. Inc. and RBC Capital Markets Corporation
acted as co-managers for the offering. As of the date of the filing of this
Report, the offering has terminated.

The public offering price was price was $14.00 per share and $123,529,420 in the
aggregate. The underwriting discounts and commissions were $0.945 per share and
$8,338,236 in the aggregate. Proceeds before expenses to us were $13.055 per
share and $57,595,592 in the aggregate. Proceeds, before expenses, to the
selling stockholders were $13.055 per share and $57,595,592 in the aggregate.

We did not receive any of the proceeds from the sale of shares by selling
stockholders or upon any exercise of the underwriters' over-allotment option.
The net proceeds received by us in the offering were $55,379,482, as follows:

Aggregate offering proceeds to the Company $61,764,710
Underwriting discounts and commissions 4,169,118
Finders fees ---
Underwriters' fees ---
Other fees and expenses 2,216,110
-----------
Total expenses 6,385,228
-----------
Net proceeds to the Company $55,379,482
===========

We have used the net proceeds to us from our initial public offering as follows:

o $51,332,441 to repay all indebtedness outstanding under our revolving
credit facility from PNC Bank and other lenders; and

o $4,047,041 to upgrade our drilling rig fleet and purchase related
equipment.

All of the foregoing expenses and uses of proceeds were direct or indirect
payments to persons other than (i) our directors, officers or their associates;
(ii) persons owning ten percent (10%) or more of our common stock; or (iii) our
affiliates.

There has been no material change in the planned use of proceeds from our
initial public offering as described in our final prospectus filed with the SEC
pursuant to Rule 424(b).

ITEM 6. 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,
--------------------------------------------------
2005 2004 2003 2002 2001
-------- ------- -------- -------- -------
(IN THOUSANDS, EXCEPT PER SHARE DATA)

Contract drilling revenues $141,621 $67,832 $ 58,144 $ 47,045 $77,945
Income (loss) from operations 11,214 2,198 (1,844) (2,875) 8,065
Income (loss) before income taxes 9,699 3,943 (2,542) (3,596) 7,417
Net income (loss) 5,599 3,527 (2,558) (3,402) 7,213
Earnings (loss) per common share-
basic 0.35 0.27 (0.19) (0.26) 0.55
Earnings (loss) per common share-
diluted 0.34 0.26 (0.19) (0.26) 0.54
Long-term debt and capital lease
obligations, including current portion
and line of credit 7,826 7,904 8,169 10,897 8,626
Stockholders' equity 132,439 43,547 40,875 42,412 45,750
Total assets 177,488 65,598 55,660 57,974 62,740

Calculation of EBITDA:
Net income (loss) $ 5,599 $ 3,527 ($2,558) ($3,402) $ 7,213
Interest expense 2,367 629 850 792 742
Income tax (benefit) expense 4,100 416 16 (194) 204
Depreciation and amortization 15,121 8,103 7,987 7,687 6,021
-------- ------- -------- -------- -------
EBITDA $ 27,187 $12,675 $ 6,295 $ 4,883 $14,180
======== ======= ======== ======== =======

ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS

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

COMPANY OVERVIEW

Union Drilling Inc. provides contract land drilling services and equipment,
primarily to natural gas producers in the U.S. In addition to our drilling rigs,
we provide the drilling crews and most of the ancillary equipment needed to
operate our drilling rigs. We commenced operations in 1997 with 12 drilling rigs
and related equipment acquired from a predecessor that was providing contract
drilling services under the name "Union Drilling." Through a combination of
acquisitions and new rig construction, we have increased the size of our fleet
to 70 land drilling rigs, of which 63 are marketed and seven are stacked. We
have focused our operations in selected natural gas production regions in the
United States. We do not invest in oil and natural gas properties. The drilling
activity of our customers is highly dependent on the current price of oil and
natural gas.

which owned a fleet of 12 rigs and leased a thirteenth rig operating in the
Arkoma Basin, and eight rigs from SPA Drilling L.P., five of which are targeting
the Barnett Shale formation in the Fort Worth Basin. In June 2005 and August
2005, we acquired six more rigs, five of which target the Barnett Shale
formation in the Fort Worth Basin. These transactions substantially expanded our
unconventional natural gas contract drilling operations beyond our traditional
markets in the Appalachian Basin and the Rocky Mountains. In addition to these
acquisitions, over the past three years we have purchased seven newly
constructed rigs and have devoted significant capital expenditures to upgrade
other rigs in our fleet for underbalanced and horizontal drilling. These
investments have positioned our fleet to capitalize on our customers' rapidly
growing unconventional resource exploration and development activity.

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

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

For the three years ended December 31, 2005, our marketed rig utilization,
revenue days and average total number of rigs were as follows:

YEARS ENDED DECEMBER 31,
------------------------
2005 2004 2003
------ ----- -----
Marketed rig utilization rates 61.9% 50.2% 44.4%
Revenue days 12,254 6,390 5,930
Average total number of rigs 60.5 41.8 44.3

The reasons for the increase in the number of revenue days in 2005 over 2004 and
2003 are the increase in size of our rig fleet and the improvement in our
overall rig utilization rate due to improved market conditions. A significant
factor contributing to the growth in the number of rigs and revenue days was the
aforementioned 2005 acquisitions.

We devote substantial resources to maintaining and upgrading our rig fleet.
During 2005, we removed certain rigs from service to perform upgrades. In the
short term, these actions resulted in fewer revenue days and slightly lower
utilization; however, in the long term, we believe the upgrades will help the
marketability of the rigs and improve their operating performance. We are
currently performing or have recently performed, between contracts or as
necessary, safety and equipment upgrades to various rigs in our fleet.

MARKET CONDITIONS IN OUR INDUSTRY

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

During fiscal 2005, 2004 and 2003, substantially all the wells we drilled for
our customers were drilled in search of natural gas because of the depth
capacity of our rigs and the natural gas rich areas in which we operate. Our
customers are primarily focused on drilling for natural gas. Natural gas
reserves are typically found in deeper geological formations and generally
require premium equipment and quality crews to drill the wells.

CRITICAL ACCOUNTING POLICIES AND ESTIMATES

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

At December 31, 2005, our contract drilling work in progress totaled
approximately $7.1 million, and approximately $3.8 million at December 31, 2004,
all of which relates to the revenue recognized but not yet billed on daywork and
footage contracts in progress at December 31, 2005 and 2004, respectively. The
increase is due to the increase in the number of rigs working, primarily as a
result of the acquisitions of Thornton Drilling Company and the assets of SPA
Drilling L.P.

ACCOUNTS RECEIVABLE- We evaluate the creditworthiness of our customers based on
their financial information, if available, information obtained from major
industry suppliers, and past experiences with customers. In some instances, we
require new customers to establish escrow accounts or make prepayments. We
typically invoice our customers at 30 day intervals during the performance of
daywork contracts and upon completion of the daywork contract. Footage contracts
are invoiced upon completion of the contract. Our contracts provide for payment
of invoices in 30 days. We established an allowance for doubtful accounts of
$313,000 at December 31, 2005 and $269,000 at December 31, 2004. Any allowance
established is subject to judgment and estimates made by management. We
determine our allowance by considering a number of factors, including the length
of time trade accounts receivable are past due, our previous loss history, our
assessment of our customers' current abilities to pay obligations to us and the
condition of the general economy and the industry as a whole. We write off
specific accounts receivable when they become uncollectible.

ASSET IMPAIRMENTS - We assess the impairment of property and equipment whenever
events or circumstances indicate that the carrying value may not be recoverable.
Factors that we consider important and which could trigger an impairment review
would be our customers' financial condition and any significant negative trends
in the industry or the general economy. More specifically, among other things,
we consider our contract revenue rates, our rig utilization rates, cash flows
from our drilling rigs, current oil and natural gas prices, industry analysts'
outlook for the industry and their view of our customers' access to capital and
the trends in the price of used drilling equipment observed by our management.
If a review of our drilling rigs indicates that our carrying value exceeds the
estimated undiscounted future cash flows, we are required under applicable
accounting standards to write down the drilling equipment to its fair market
value. We provide for depreciation of our drilling rigs, transportation and
other equipment on a straight line method over useful lives that we have
estimated and that range from three to ten years after the rig was placed into
service. Unlike depreciation based on units-of-production, our approach to
depreciation does not change when equipment becomes idle or when utilization
changes; we continue to depreciate idled equipment on a straight-line basis,
despite the fact that our revenues and operating costs may vary with changes in
utilization levels. Our estimates of the useful lives of our drilling,
transportation and other equipment are based on our experience in the drilling
industry with similar equipment.

DEFERRED TAXES - We record deferred taxes for net operating loss carryforwards
and for the basis difference in our property and equipment between financial
reporting and tax reporting purposes. For property and

equipment, basis differences arise from differences in depreciation periods and
methods and the value of assets acquired in a business acquisition where we
acquire the stock of an entity rather than its assets. For financial reporting
purposes, we depreciate the various components of our drilling rigs and
refurbishments over three to ten years, while federal income tax rules require
that we depreciate drilling rigs and refurbishments over five years. Therefore,
in the earlier years of our ownership of a drilling rig, our tax depreciation
exceeds our financial reporting depreciation, resulting in our recording
deferred tax liabilities on this depreciation difference. In later years,
financial reporting depreciation exceeds tax depreciation, and the deferred tax
liability begins to reverse. A significant portion of our deferred taxes are
deferred tax assets that arose as the result of our prior year tax losses. These
losses can be carried forward for federal and state tax purposes for as many as
twenty years, depending upon the jurisdiction, to reduce future taxes that we
would otherwise be required to pay. The utilization of these net operating
losses is dependent upon our ability to generate taxable income in the future.

ACCOUNTING ESTIMATES - Another critical estimate is our determination of the
useful lives of our depreciable assets, which directly affects our determination
of depreciation expense and deferred taxes. A decrease in the useful life of our
drilling equipment would increase depreciation expense and reduce deferred
taxes. We provide for depreciation of our drilling, transportation and other
equipment on a straight-line method over useful lives that we have estimated and
that range from three to ten years. We record the same depreciation expense
whether a rig is idle or working.

Our other accrued expenses as of December 31, 2005, 2004 and 2003 included
accruals of approximately $1,312,000, $928,000 and $584,000 respectively, for
costs under our workers' compensation insurance. We have a deductible of
$100,000 per covered accident under our workers' compensation insurance. Our
insurance policy requires us to maintain a letter of credit to cover payments by
us of that deductible. As of December 31, 2005, we satisfied this requirement
with a $2.7 million letter of credit with our bank and our borrowing capacity
under our revolving credit agreement with our bank has been reduced by the same
amount collateralizing such letter of credit. We accrue for these costs as
claims are incurred based on cost estimates established for each claim by the
insurance companies providing the administrative services for processing the
claims, including an estimate for incurred but not reported claims, estimates
for claims paid directly by us, our estimate of the administrative costs
associated with these claims and our historical experience with these types of
claims. In addition, we accrue on a monthly basis the estimated workers
compensation premium payable to the two states (West Virginia and Ohio) that are
considered monopolistic.

RESULTS OF OPERATIONS

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

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

STATEMENTS OF OPERATIONS ANALYSIS

The following table provides selected information about our operations for the
years ended December 31, 2005, 2004, and 2003 (in thousands).

YEARS ENDED DECEMBER 31,
----------------------------
2005 2004 2003
-------- ------- -------

Drilling revenues $141,621 $67,832 $58,144
-------- ------- -------
Drilling operations expenses $102,266 $50,084 $45,305
-------- ------- -------

Depreciation and amortization $ 15,121 $ 8,103 $ 7,987
General and administrative expense 13,020 7,447 6,696
Interest expense 2,367 629 850
Other income and gain (loss) on sale of fixed assets 851 2,374 152
Revenue days during period 12,254 6,390 5,930
-------- ------- -------

Drilling revenue per revenue day $ 11,557 $10,616 $ 9,805
Drilling cost per revenue day 8,346 7,839 7,640
Rig utilization rates 61.9% 50.2% 44.4%
Average number of rigs during the period 60.5 41.8 44.3

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

Our contract drilling revenues grew by approximately $9.7 million, or 16.7%, in
fiscal year 2004 from fiscal year 2003, due to a 7.8% increase in revenue days
coupled with an 8.3% increase in revenue per day, and a 4.7% increase in rig
utilization.

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

Our contract drilling costs grew by approximately $4.8 million, or 10.5%, in
fiscal year 2004 from fiscal year 2003 due to the increase in revenue days and
rig utilization.

DEPRECIATION AND AMORTIZATION. Our depreciation and amortization expense in 2005
increased by approximately $7.0 million, or 86.6%, from 2004. Depreciation and
amortization expense in 2004 increased approximately $116,000, or 1.5%, from
2003. The increase in 2005 over 2004 resulted from the purchase of SPA Drilling
assets and the Thornton Drilling Company acquisition on April 1, 2005, as well
as other rig purchases and capital equipment upgrades. The increase in 2004 over
2003 resulted from rig purchases and capitalized equipment upgrades throughout
the year, partially offset by the sale of our two Canadian-based rigs.

GENERAL AND ADMINISTRATIVE EXPENSES. Our general and administrative expenses
increased by approximately $5.6 million, or 74.8%, in fiscal year 2005 from
fiscal year 2004. Approximately $2.4 million of the increase relates to the
general and administrative costs associated with operations established to
support the purchase of SPA Drilling assets and the Thornton Drilling Company
acquisition. The remaining $3.2 million increase is due primarily to higher
personnel expense (including $788,000 of non-

cash compensation), and higher spending on professional and consulting costs of
$306,000, and insurance costs of $453,000 related to the new acquisitions.

Our general and administrative expenses increased by approximately $752,000, or
11.2%, in fiscal year 2004 from fiscal year 2003. This increase was due to
higher personnel, insurance and other costs to support expanding operations.

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

Our interest expense decreased by approximately $220,000, or 25.9% in fiscal
year 2004 from fiscal 2003 due to lower debt levels during 2004.

OTHER INCOME AND GAIN (LOSS) ON SALE OF FIXED ASSETS. Other income and gain
(loss) on sale of fixed assets declined by approximately $1.5 million from $2.4
million for the fiscal year 2004 to approximately $851,000 in fiscal year 2005.
This was due to the gain associated with the sale of our two Canadian-based rigs
being recorded in fiscal year 2004.

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

At December 31, 2005, we had domestic net operating loss carryforwards for
income tax purposes of approximately $24.8 million. These losses may be carried
forward for 20 years and will begin to expire in 2019. The state losses vary as
to carryforward period and will begin to expire in 2008, depending upon the
jurisdiction where applied. Based upon 2005 results and forecasted future
operations, we feel it is more likely than not that the amounts will be
realized. Foreign net operating losses were fully utilized in 2004.

LIQUIDITY AND CAPITAL RESOURCES

SOURCES OF CAPITAL RESOURCES

Our rig fleet has grown from 12 rigs in 1997 to 69 rigs as of December 31, 2005.
We have financed this growth with a combination of debt and equity financing. We
plan to continue to grow our rig fleet. At December 31, 2005, our total debt to
total capital was approximately 8.5%. Due to the volatility in our industry, we
are reluctant to take on substantial additional debt in excess of the
$57,300,000 of remaining availability under our revolving credit facility.
However, our ability to continue funding our growth through the issuance of
shares of our common stock is uncertain, as our common stock is not heavily
traded and the market price for our common stock has been volatile in recent
periods.

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

On November 22, 2005, we also sold 4,411,765 shares of our common stock at
approximately $13.05 per share, net of underwriters' commissions, pursuant to a
public offering we registered with the Securities and Exchange Commission. The
net proceeds to Union, after expenses, of this sale were $55,379,482, and were
used primarily to repay indebtedness under our revolving credit facility. See
"Use of Proceeds From Sales of Registered Securities" in Item 5 above.

We entered into a Revolving Credit and Security Agreement with PNC Bank, as
agent for a group of lenders, dated March 31, 2005, and subsequently amended on
April 19, August 15, and October 5, 2005, which provides for a borrowing base
equal to the lesser of $60,000,000 and the sum of 85% of eligible receivables
and 75% of the liquidation value of eligible rig fleet equipment. The agent may,
in the exercise of its reasonable business judgment, increase or decrease those
percentage advance rates against eligible receivables and liquidation value. The
liquidation value of eligible rig fleet equipment is determined annually (or
semi-annually in certain circumstances) by an independent appraisal, with
adjustments for acquisitions and dispositions between appraisals. There is a
$7,500,000 sublimit for letters of credit. Amounts outstanding under the
revolving credit facility bear interest at either (i) the higher of the Federal
Funds Open Rate plus 1/2 of 1% or PNC Bank's base commercial lending rate (7.25%
at December 31, 2005) or (ii) LIBOR plus 2.00% (6.39% at December 31, 2005).
Those rates may increase by up to 0.50% for LIBOR loans or up to 0.25% for
domestic rate loans if our fixed charge coverage ratio falls below certain
targets.

Interest on outstanding loans is due monthly for domestic rate loans and at the
end of the relevant interest period for LIBOR loans. All outstanding principal
and interest is due at maturity on March 30, 2009. As of December 31, 2005, we
had no outstanding loans under the Revolving Credit and Security Agreement, but
$2.7 million of the total capacity has been utilized to support our letter of
credit requirement. To date, the revolving credit facility has been used to pay
for rig acquisitions and for working capital requirements. If we repay and
terminate the obligations under the Revolving Credit and Security Agreement, we
would be liable for a substantial prepayment penalty.

The Revolving Credit and Security Agreement is secured by substantially all of
our assets, with certain exceptions, and contains affirmative and negative
covenants and provides for events of default that are typical for an agreement
of this type. Among the affirmative covenants are requirements to maintain a
specified tangible net worth (initially $43 million) and a fixed charge coverage
ratio of 1.10 to 1.00. Among the negative covenants are restrictions on major
corporate transactions, capital expenditures, payment of dividends, incurrence
of indebtedness, and amendments to our organizational documents. Net capital
expenditures were limited to $45 million in 2005 and $10 million in subsequent
years, but those amounts are increased by permitted equity issuance proceeds.
Among the events of default are a change in control and any change in our
operations or condition, which has a material adverse effect. Effective August
15, 2005, the revolving credit agreement was amended to increase the maximum
revolving amount from $50 million to $60 million, and to increase the Net
Capital Expenditures limitation for the fiscal year ended December 31, 2005 to
$45 million from $15 million.

USES OF CAPITAL RESOURCES

Effective March 31, 2005, the Company acquired all of the capital stock of an
Oklahoma-based drilling company, which owned 12 drilling rigs. Also, effective
the same date, the Company acquired substantially all of the drilling assets
(eight rigs) of a Texas-based drilling company. The total purchase price for
these businesses is $49,517,419. These acquisitions were financed by a new
$50,000,000 revolving line of credit with a bank (subsequently amended - see
above), and collateralized by substantially all of the assets of the Company.
The previous debt facilities were both retired at that time. In addition, the
Company also received an equity infusion of approximately $20,000,000 from
private investors. Also, the seller of the Oklahoma-based company received
approximately $2,000,000 in stock of Union Drilling Inc. as part of the
transaction. The funding of these transactions occurred on April 1, 2005.

In June 2005 and August 2005, the Company entered into agreements to purchase
six additional rigs for a total of $16,650,000.

In the fourth quarter of 2005, the Company acquired two new top head drive rigs
for approximately $1,700,000.

Company paid $1 million to National Oilwell Varco for an option to acquire an
additional three rigs and related equipment for an aggregate purchase price of
$25.2 million. If that option is exercised by April 30, 2006, the $1 million
option price will be applied to the purchase price for the three rigs. All six
rigs, which are capable of horizontal and underbalanced drilling, would be
scheduled for delivery during 2006.

For the years ended December 31, 2005 and 2004, the additions to our property
and equipment consisted of the following:

YEARS ENDED DECEMBER 31,
-------------------------
2005 2004
----------- -----------
Land $ 779,790 $ --
Buildings 891,243 1,859
Drilling and well service equipment 81,881,072 13,195,852
Deposits on drilling equipment 8,186,500 --
Vehicles 3,259,258 157,675
Furniture and fixtures 6,486 --
Computer equipment 75,119 14,144
----------- -----------
$95,079,468 $13,369,530
=========== ===========

----------
WORKING CAPITAL

Our working capital increased to $25,600,921 at December 31, 2005 from
$8,070,637 at December 31, 2004. Our current ratio, which we calculate by
dividing our current assets by our current liabilities, was 2.21 at December 31,
2005 compared to 1.53 at December 31, 2004. The principal reasons for the
increase in our working capital at December 31, 2005 are related to the
aforementioned equity infusions and the additional accounts receivable, net of
associated liabilities due to the acquisitions made in April 2005 and the year
over year increase in general business activity.

Our operations have historically generated sufficient cash flow to meet our
requirements for debt service and equipment expenditures (excluding major
business acquisitions). The significant increase in working capital for the year
ended December 31, 2005 over December 31, 2004 is due primarily to the
approximately $15,000,000 overall increase in accounts receivable partially
offset by related liabilities associated with the significant acquisitions made
in 2005 and a general improvement in drilling activities. This use of cash was
partially offset by an increase of approximately $7,018,000 in non-cash
depreciation and amortization expense. We believe our cash generated by
operations and our ability to borrow the currently unused portion of our line of
credit and letter of credit facility of approximately $57,300,000, which takes
into account reductions for approximately $2,700,000 of outstanding letters of
credit as of December 31, 2005, should allow us to meet our routine financial
obligations for the foreseeable future.

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

DECEMBER 31,
---------------------------------------
2005 2004 CHANGE
----------- ----------- -----------

Cash and cash equivalents $ 2,388,276 $ 3,871,271 ($1,482,995)
Receivables 28,060,911 13,251,577 14,809,334
Inventories 860,208 779,713 80,495
Prepaid expenses 4,930,431 2,976,788 1,953,643
Deferred taxes 10,542,730 2,404,023 8,138,707
----------- ----------- -----------
CURRENT ASSETS 46,782,556 23,283,372 23,499,184
----------- ----------- -----------

Current debt 5,322,634 5,888,577 (565,943)
Accounts payable 9,240,626 6,109,983 3,130,643
Current portion of advances from customers 1,265,067 -- 1,265,067
Accrued expenses 5,353,308 3,214,175 2,139,133
----------- ----------- -----------
CURRENT LIABILITIES 21,181,635 15,212,735 5,968,900
----------- ----------- -----------

----------- ----------- -----------
WORKING CAPITAL $25,600,921 $ 8,070,637 $17,530,284
=========== =========== ===========

The increase in our receivables at December 31, 2005 from December 31, 2004 was
due primarily to increased revenues from the additional rigs acquired in April
2005, June 2005, and August 2005, as well as an improvement in utilization and
revenue rates in the second half of fiscal year 2005 over fiscal year 2004.

Substantially all our prepaid expenses at December 31, 2005 consisted of prepaid
insurance. The increase in prepaid insurance was due to the increase in size of
the Company in 2005, both in terms of assets and employees, due to the
acquisitions made and a general improvement in the market.

The increase in the deferred tax asset is due to the addition of deferred tax
assets associated with the prior years' net operating loss carryforwards. This
was caused by the purchase price allocation related to our Thornton acquisition
that resulted in significant deferred tax liabilities and the related reduction
in the valuation allowance and intangibles. We believe that our recent and
forecast profitability supports this position.

The increase in payables at December 31, 2005 from December 31, 2004 was
primarily due to the increase in the size of our drilling rig fleet.

The total increase in accrued expenses at December 31, 2005 from December 31,
2004 was due to an increase in the size of our company. The growth in accrued
payroll, accrued workers compensation and other accrued expenses can be
attributed to the growth in our employee headcount and the additional expenses
associated with being a public company.

Although we have not been required to make income tax payments for the last
several years, it is also likely we will be in a current taxable position during
fiscal year 2006, due to improving market conditions.

LONG-TERM DEBT

Our long-term debt at December 31, 2005 and 2004 consisted of the following:

2005 2004
----------- ------------

Indebtness for equipment financed through capital leases $ -- $ 348,172
Notes payable for equipment financed 7,825,984 5,503,179
Term loan with Transamerica - repaid on April 1, 2005 -- 2,053,038
----------- -----------
7,825,984 7,904,389
Less current installments (2,013,956) (3,769,723)
----------- -----------
$ 5,812,028 $ 4,134,666
=========== ===========

CONTRACTUAL OBLIGATIONS

The following table includes all of our contractual obligations of the type
specified below at December 31, 2005:

CONTRACTUAL LESS THAN 1 4 - 5 MORE THAN 5
OBLIGATIONS TOTAL YEAR 1-3 YEARS YEARS YEARS
--------------------------- ----------- ----------- ---------- -------- -----------

Long-Term Debt(1) $ 7,825,984 $2,013,956 $5,453,786 $358,242 $--
Operating Lease Obligations 2,116,918 996,520 1,120,398 -- --
Interest 931,907 406,091 512,663 13,153 --
----------- ---------- ---------- -------- ---
Total $10,874,809 $3,416,567 $7,086,847 $371,395 $--
=========== ========== ========== ======== ===

(1) Does not include our Revolving Credit and Security Agreement with PNC Bank,
which we entered into on April 1, 2005.

INFLATION

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

OFF BALANCE SHEET ARRANGEMENTS

We do not currently have any off balance sheet arrangements.

RECENTLY ISSUED ACCOUNTING STANDARDS

In December 2004, the Financial Accounting Standards Board ("FASB") issued FASB
No. 123 (R), Share-based Payment. FASB No. 123 (R) requires employers to value
share-based payments using the fair value method, eliminating the option to use
the intrinsic method to value such payments. We will adopt the provisions of
SFAS 123 (R) prospectively beginning in the first quarter of 2006. We are
currently evaluating the effect of the provisions of this statement on our
Consolidated Financial Statements. The impact of option grants measured on an
estimated fair value basis on the Company's historic operations is included on a
pro forma basis in the notes to the financial statements.

In May 2005, the FASB issued Statement No. 154, Accounting Changes and Error
Corrections - a replacement of APB Opinion No. 20 and FASB Statement No. 3
("SFAS 154"). This statement changes the requirements for the accounting for and
reporting of a change in accounting principle. SFAS 154 requires retrospective
application to prior periods' financial statements of changes in accounting
principle and is limited to direct effects of the change. This statement is
effective, and will be adopted, for accounting changes made in fiscal years
beginning after December 31, 2005. Adoption is not expected to have a material
effect on the our financial position or results of operations.

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

We are subject to market risk exposure related to changes in interest rates on
our Revolving Credit Facility. At December 31, 2005, we had no outstanding debt
on our Revolving Credit Facility.

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

UNION DRILLING INC.

INDEX TO CONSOLIDATED FINANCIAL STATEMENTS

Page
----
Report of Independent Registered Public Accounting Firm 35

Consolidated Balance Sheets as of December 31, 2005 and 2004 36

Consolidated Statements of Operations for the Years Ended December 31,
2005, 2004 and 2003 37

Consolidated Statements of Stockholders' Equity for the Years Ended
December 31, 2005, 2004 and 2003 38

Consolidated Statements of Cash Flows for the Years Ended December 31,
2005, 2004 and 2003 39

Notes to Consolidated Financial Statements 40

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

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

We have audited the accompanying consolidated balance sheets of Union Drilling,
Inc. as of December 31, 2005 and 2004, and the related consolidated statements
of operations, stockholders' equity, and cash flows for each of the three years
in the period ended December 31, 2005. These financial statements are the
responsibility of the Company's management. Our responsibility is to express an
opinion on these financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company
Accounting Oversight Board (United States). Those standards require that we plan
and perform an audit to obtain reasonable assurance about whether the financial
statements are free of material misstatement. We were not engaged to perform an
audit of the Company's internal control over financial reporting. Our audits
included consideration of internal control over financial reporting as a basis
for designing audit procedures that are appropriate in the circumstances, but
not for the purpose of expressing an opinion on the effectiveness of the
Company's internal control over financial reporting. Accordingly, we express no
such opinion. An audit also includes examining, on a test basis, evidence
supporting the amounts and disclosures in the financial statements, assessing
the accounting principles used and significant estimates made by management, and
evaluating the overall financial statement presentation. We believe that our
audits provide a reasonable basis for our opinion.

In our opinion, the financial statements referred to above present fairly, in
all material respects, the consolidated financial position of Union Drilling,
Inc. at December 31, 2005 and 2004, and the consolidated results of its
operations and its cash flows for each of the three years in the period ended
December 31, 2005, in conformity with U.S. generally accepted accounting
principles.

/s/ Ernst & Young LLP

Pittsburgh, Pennsylvania
March 8, 2006

UNION DRILLING, INC.
CONSOLIDATED BALANCE SHEETS

DECEMBER 31,
--------------------------
2005 2004
------------ -----------

ASSETS:
CURRENT ASSETS:
Cash and cash equivalents $ 2,388,276 $ 3,871,271
Accounts receivable (net of allowance for doubtful
accounts of $313,436 and $269,192 at December 31, 2005
and 2004, respectively) 27,579,254 11,286,696
Accounts receivable - related party 481,657 1,964,881
Inventories 860,208 779,713
Prepaid expenses and other assets 4,930,431 2,976,788
Deferred taxes 10,542,730 2,404,023
------------ -----------
Total current assets 46,782,556 23,283,372
Goodwill 5,424,793 --
Intangible assets (net of accumulated amortization of
$202,500 at December 31, 2005) 3,797,500 --
Property, buildings and equipment (net of accumulated
depreciation of $46,250,906 and $32,760,108 at
December 31, 2005 and 2004, respectively) 120,783,092 42,314,897
Other assets 700,409 --
------------ -----------
Total assets $177,488,350 $65,598,269
============ ===========
LIABILITIES AND STOCKHOLDERS' EQUITY:
CURRENT LIABILITIES:
Accounts payable $ 9,240,626 $ 6,109,983
Current portion of long-term obligations 2,013,956 3,421,551
Current portion of capital lease obligations -- 348,173
Current portion of other obligations 3,308,678 2,118,853
Current portion of advances from customers 1,265,067 --
Accrued expenses and other liabilities 5,353,308 3,214,175
------------ -----------
Total current liabilities 21,181,635 15,212,735
Revolving credit facility -- --
Long-term obligations 5,812,028 4,134,666
Deferred taxes 17,916,781 2,534,670
Advances from customers 138,605 169,071
------------ -----------
Total liabilities 45,047,049 22,051,142
STOCKHOLDERS' EQUITY:
Common stock, par value $.01 per share; 75,000,000
shares authorized; 21,166,109 and 13,162,936
shares issued and outstanding at December 31, 2005
and December 31, 2004, respectively 211,661 131,629
Additional paid-in capital 133,381,395 50,168,371
Retained earnings (deficit) (1,153,755) (6,752,873)
------------ -----------
Total shareholders' equity 132,439,301 43,547,127
------------ -----------
Total liabilities and stockholders' equity $177,488,350 $65,598,269
============ ===========

See accompanying notes.

UNION DRILLING, INC.
CONSOLIDATED STATEMENTS OF OPERATIONS

YEARS ENDED DECEMBER 31
-----------------------------------------
2005 2004 2003
------------ ------------ -----------

REVENUES
Nonaffiliates $136,388,802 $ 59,097,454 $54,631,018
Related party 5,232,314 8,734,944 3,512,810
------------ ------------ -----------
Total revenues 141,621,116 67,832,398 58,143,828
------------ ------------ -----------

COST AND EXPENSES
Drilling operations 102,265,841 50,083,525 45,305,104
Depreciation and amortization 15,120,947 8,103,387 7,987,398
General and administrative expenses 13,020,180 7,447,137 6,695,063
------------ ------------ -----------
Total cost and expenses 130,406,968 65,634,049 59,987,565
------------ ------------ -----------

Operating income (loss) 11,214,148 2,198,349 (1,843,737)

Interest expense (2,366,769) (629,322) (849,570)
Gain (loss) on sale of assets 649,229 1,679,053 (161,891)
Other income 202,033 695,043 313,071
------------ ------------ -----------
Income (loss) before income taxes 9,698,641 3,943,123 (2,542,127)
Income tax expense 4,099,523 416,387 15,927
------------ ------------ -----------
Net income (loss) $ 5,599,118 $ 3,526,736 $(2,558,054)
============ ============ ===========

Earnings (loss) per common share:
Basic $ 0.35 $ 0.27 $ (0.19)
============ ============ ===========
Diluted $ 0.34 $ 0.26 $ (0.19)
============ ============ ===========

Weighted-average common shares outstanding:
Basic 16,012,486 13,162,936 13,162,936
============ ============ ===========
Diluted 16,553,894 13,311,203 13,162,936
============ ============ ===========

SEE ACCOMPANYING NOTES.

UNION DRILLING, INC.
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY

Accumulated
Additional Other Retained
Paid-In Comprehensive Earnings
Common Stock Capital Income (Loss) (Deficit) Total
----------------------- ------------ ------------- ------------- ------------
Shares $
---------- ----------

Balance at December 31, 2002 13,162,936 131,629 $ 50,168,371 ($166,212) ($ 7,721,555) $ 42,412,233
Foreign translation adjustment -- -- -- 1,021,143 1,021,143
Net loss -- -- -- -- (2,558,054) (2,558,054)
------------
Total comprehensive loss -- -- -- -- -- (1,536,911)
---------- ---------- ------------ ---------- ------------- ------------
Balance at December 31, 2003 13,162,936 131,629 50,168,371 854,931 (10,279,609) 40,875,322
Foreign translation adjustments:
Current period translation -- -- -- (679,678) (679,678)
Reclassification to earnings -- -- -- (175,253) (175,253)
Net income -- -- -- -- 3,526,736 3,526,736
------------
Total comprehensive income -- -- -- -- -- 2,671,805
---------- ---------- ------------ ---------- ------------- ------------
Balance at December 31, 2004 13,162,936 131,629 50,168,371 -- (6,752,873) 43,547,127
Issuance of common shares, net
of $80,001 issuance costs 2,771,145 27,711 19,892,296 -- -- 19,920,007
Issuance of common shares in
association with initial
public offering, net of
$2,216,110 issuance costs 4,411,765 44,118 55,335,364 55,379,482
Non-cash compensation -- -- 787,697 -- -- 787,697
Exercise of stock options and
related tax benefit of
$1,395,487 527,754 5,278 5,200,593 -- -- 5,205,871
Issuance of common shares 292,509 2,925 1,997,074 -- -- 1,999,999
Net income -- -- -- -- 5,599,118 5,599,118
---------- ---------- ------------ ---------- ------------- ------------
Balance at December 31, 2005 21,166,109 $ 211,661 $133,381,395 $ -- ($ 1,153,755) $132,439,301
========== ========== ============ ========== ============= ============

SEE ACCOMPANYING NOTES.

UNION DRILLING, INC.
CONSOLIDATED STATEMENTS OF CASH FLOWS

YEAR ENDED DECEMBER 31,
-------------------------------------------
2005 2004 2003
------------- ------------ ------------

OPERATING ACTIVITIES:
Net income (loss ) $ 5,599,118 $ 3,526,736 $ (2,558,054)
Adjustments to reconcile net income (loss)
to net cash provided by (used in)
operating activities:
Depreciation and amortization 15,120,947 8,103,387 7,987,398
Non-cash compensation expense 787,697 -- --
Provision for doubtful accounts 155,000 152,015 120,000
(Gain) loss on sale or disposal of
fixed assets (649,229) (1,679,053) 161,891
Provision for deferred taxes 3,937,732 130,647 --
Changes in operating assets and liabilities:
Accounts receivable (12,837,923) (1,856,326) (4,076,808)
Accounts receivable - related party 1,483,224 (1,776,792) (101,735)
Inventories (80,494) 20,245 (1,928)
Prepaid and other assets (791,032) (2,461,005) 439,843
Accounts payable 3,130,643 1,636,195 2,155,770
Accrued expenses and other liabilities 1,828,017 1,436,462 (70,533)
------------- ------------ ------------
Cash flow provided by operating activities 17,683,700 7,232,511 4,055,844

INVESTING ACTIVITIES:
Purchase of businesses (47,517,419) -- --
Purchases of machinery and equipment (53,994,141) (13,369,530) (4,923,059)
Proceeds from sale of machinery and equipment 2,346,579 7,080,032 598,626
------------- ------------ ------------
Cash flow (used in) investing activities (99,164,981) (6,289,498) (4,324,433)
FINANCING ACTIVITIES:
Borrowings on line of credit 175,689,103 22,956,618 20,970,271
Repayments on line of credit (175,689,103) (22,956,618) (20,970,271)
Borrowings to finance equipment purchases 5,464,051 6,858,726 1,383,479
Repayments on capital leases and other debt (2,393,337) (1,864,838) (1,282,460)
Repayments on term loan (2,053,038) (3,139,821) (2,828,571)
Issuance of common shares in initial public
offering 55,379,482 -- --
Issuance of common shares 19,920,007 -- --
Exercise of stock options 3,810,384 -- --
------------- ------------ ------------
Cash flow provided by (used in) financing
activities 80,127,549 1,854,067 (2,727,552)
Foreign currency translation adjustment (129,263) (558,985) (173,708)
------------- ------------ ------------
Net increase (decrease) in cash (1,482,995) 2,238,095 (3,169,849)
Cash and cash equivalents at beginning of period 3,871,271 1,633,176 4,803,025
------------- ------------ ------------
Cash and cash equivalents at end of period $ 2,388,276 $ 3,871,271 $ 1,633,176
============= ============ ============
SUPPLEMENTAL DISCLOSURE OF NON CASH INVESTING
AND FINANCING ACTIVITIES:
Common stock issued for business acquisition $ 2,000,000 $ -- $ --
============= ============ ============

SEE ACCOMPANYING NOTES.

UNION DRILLING INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1. ORGANIZATION

Union Drilling, Inc. (Union or the Company) was incorporated in Delaware on
September 23, 1997. On October 21, 1997, the Company acquired substantially all
of the drilling equipment assets of a division of Equitable Resources Energy
Company. Since that time the Company has increased its productive capacity by
purchasing additional rigs and related equipment as described in Note 11.

2. DESCRIPTION OF BUSINESS AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

DESCRIPTION OF BUSINESS

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

During 2004, in response to the low productivity in Canada, the Company sold two
rigs and associated equipment located in Canada. The net book value of these
assets was approximately $4.0 million and the Company recorded a net gain on the
sale of approximately $1.5 million. These assets constituted all of the
productive capacity of the Company's Canadian operation. In response to the
disposition of these assets, the Company has recorded (and will prospectively)
all foreign currency translation adjustments through other income/expense in the
consolidated statements of operations.

The Company intends to service the drilling needs of the Canadian market by
using available drilling capacity located in the United States.

United
States Canada Total
-------- ------ --------
(In Thousands)
2005:
Revenue $141,598 $ 23 $141,621
Net income (loss) before taxes 9,999 (300) 9,699
Total assets 177,327 161 177,488

2004:
Revenue $ 65,606 $2,226 $ 67,832
Net income before taxes 1,662 2,281 3,943
Total assets 63,879 1,719 65,598

2003:
Revenue $ 57,104 $1,040 $ 58,144
Net loss before taxes (1,895) (647) (2,542)
Total assets 50,179 5,481 55,660
-------- ------ --------

The Company's primary customers are involved in the oil and gas industry.
Revenues from the top ten customers for the year ended December 31, 2005
represented approximately 46% of total revenues with no one customer's revenue
over 10%. Revenues from the top ten customers for the year ended December 31,
2004 represented approximately 67% of total revenues with revenues from three
customers over 10%. Revenues from the top ten customers for the year ended
December 31, 2003 represented approximately 64% of total revenues with revenues
from two customers over 10%.

Revenues from the top ten customers for the year ended December 31,2003
represented approximately 64% of total revenues with revenues from two customers
over 10%.

BASIS OF PRESENTATION

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

USE OF ESTIMATES

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

CASH AND CASH EQUIVALENTS

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

ACCOUNTS RECEIVABLE

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

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

INVENTORIES

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

PREPAID EXPENSES

Prepaid expenses and other assets include items such as insurance, taxes,
utility deposits and fees. We routinely expense these items in the normal course
of business over the periods these expenses benefit. Included in prepaid
expenses and other assets is prepaid insurance of $3,343,904 and $2,419,015 at
December 31, 2005 and 2004, respectively.

GOODWILL AND INTANGIBLE ASSETS

In accordance with SFAS No 142, "Goodwill and Other Intangibles," the Company
assesses the impairment of its goodwill annually or on an interim basis if
events or circumstances indicate that the fair value of the asset has decreased
below its carrying value. Other intangibles are tested for impairment if
indicators of impairment are present.

PROPERTY, BUILDINGS AND EQUIPMENT

Property and equipment is stated on the basis of cost. Depreciation on buildings
and equipment is calculated on the straight-line method over the estimated
remaining useful lives of the assets. Depreciation does not commence until
acquired rigs are placed in service. Once placed in service, depreciation
continues when rigs are being repaired, refurbished or between periods of
deployment. Unlike depreciation based on units-of-production, our method of
depreciation does not change when equipment becomes idle or when utilization
changes; we continue to depreciate idled equipment on a straight-line basis,
despite the fact that our revenues and operating costs may vary with changes in
utilization levels. The cost of maintenance and repairs is charged to operations
as incurred; renewals and betterments are capitalized. The estimated lives of
the assets are as follows:

Buildings 31.5 years
Drilling and well service equipment 3-10 years
Vehicles 3-5 years

IMPAIRMENT OF LONG-LIVED ASSETS

In accordance with SFAS No. 144, whenever events or changes in circumstances
indicate that the carrying amount of long-lived assets may not be recoverable,
the Company reviews its long-lived assets for impairment by first comparing the
carrying value of the assets to the sum of the undiscounted cash flows expected
to result from the use and eventual disposition of the assets. If the carrying
value exceeds the sum of the assets' undiscounted cash flows, the Company
estimates an impairment loss by taking the difference between the carrying value
and fair value of the assets. No impairment charge has been recognized in any of
the periods presented.

STOCK-BASED COMPENSATION

The Company has adopted SFAS No. 148, Accounting for Stock-Based
Compensation-Transition and Disclosure (SFAS No. 148), and the disclosure-only
provisions of SFAS No. 123, Accounting for Stock-Based Compensation (SFAS No.
123). SFAS No. 123 permits the Company to continue accounting for stock-based
compensation as set forth in APB Opinion No. 25, Accounting for Stock Issued to
Employees, provided the Company discloses the pro forma effect on net income and
earnings per share of adopting the full provisions of SFAS No. 123. Accordingly,
the Company continues to account for stock-based compensation under APB Opinion
No. 25 and has provided the required pro forma disclosures.

The following table illustrates the effect on net income/(loss) and
income/(loss) per share if the Company had applied the fair value recognition
provisions of SFAS No. 123 to employee stock-based awards. The assumptions
employed to develop these estimates and the detail related to the Plans, option
activity and a Contingent Management Compensation Plan is set forth in Note 13.

December 31,
-------------------------------------
2005 2004 2003
---------- ---------- -----------
Reported net income (loss) $5,599,118 $3,526,736 $(2,558,054)
Apply: Total stock-based compensation
expense determined under fair value
method for all awards 810,962 198,202 125,089
---------- ---------- -----------
Pro forma net income/(loss) $4,788,156 $3,328,534 $(2,683,143)
========== ========== ===========
Basic and diluted income/(loss)
per share:
Basic, as reported $ 0.35 $ 0.27 $ (0.19)
Diluted, as reported $ 0.34 $ 0.26 $ (0.19)
Basic, pro forma $ 0.30 $ 0.25 $ (0.20)
Diluted, pro forma $ 0.29 $ 0.25 $ (0.20)

Includes contingent management equity compensation of $787,697 in 2005 as
described in Note 13.

REVENUE RECOGNITION

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

CONCENTRATION OF CREDIT RISK

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

INCOME TAXES

The Company follows the liability method of accounting for income taxes pursuant
to SFAS No. 109, Accounting for Income Taxes. Under SFAS No. 109, deferred tax
assets and liabilities are determined based on differences between financial
reporting and tax bases of assets and liabilities and are measured using the
enacted tax laws and rates applicable to the periods in which the differences
are expected to reverse. The Company provides a valuation allowance to reduce
deferred tax assets to their estimated realizable value.

FOREIGN CURRENCY TRANSLATION

The functional currency of the Company's foreign subsidiary was the Canadian
dollar. The Company translated all assets and liabilities to U.S. dollars at the
current exchange rates as of the applicable balance sheet date with the
exception of long-term notes payable to the parent company. This liability was
translated at the historical rate and was paid in full during fiscal year 2004.
Revenue and expenses were translated at the average monthly exchange rate
prevailing during each period. Gains and losses resulting from the translation
of the foreign subsidiary's financial statements were reported as a separate
component of total other comprehensive income (loss) in stockholders' equity. As
indicated in Note 2, the Company made the strategic decision to service the
Canadian market utilizing available domestic drilling capacity. This resulted in
the sale of substantially all of the Company's drilling equipment in Canada. As
such, the foreign currency translation gain of approximately $175,000 was
reclassified from other comprehensive

income and increased the gain realized on the disposition of these non-domestic
assets. Net gains resulting from foreign exchange transactions, which are
recorded in the consolidated statements of operations in other income,
approximated $12,000 in 2005, $532,000 in 2004 and $259,000 in 2003.

EARNINGS (LOSS) PER SHARE

Basic earnings (loss) per common share is computed by dividing net income or
loss by the weighted-average number of common shares outstanding during the
period. Diluted earnings per common share is computed by dividing net income by
the weighted-average number of common shares outstanding during the period and
the effect of all dilutive common stock equivalents, such as stock options.

FAIR VALUE OF FINANCIAL INSTRUMENTS

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

RECENT ACCOUNTING PRONOUNCEMENTS

RECLASSIFICATIONS

Certain amounts in the financial statements for the prior year have been
reclassified to conform to the current year's presentation.

INITIAL PUBLIC OFFERING

In November 2005, the Company issued 4,411,765 common shares at a price of
$14.00 per share in its initial public offering. The Company received
approximately $55,379,000 in proceeds, net of underwriting discounts,
commissions, and offering expenses. In connection with the offering, the Company
repaid approximately $51,332,000 of outstanding debt and approximately
$4,047,000 to upgrade their drilling rig fleet and purchase of related
equipment.

3. ACQUISITIONS

Effective April 1, 2005, the Company acquired substantially all of the drilling
assets (the drilling business) of SPA Drilling L.P. The aggregate cash purchase
price for the drilling assets was $20,320,000. This

acquisition provided the Company with a foothold in the North Texas market.
Since the acquisition of these assets, the Company has purchased an additional
six rigs for a total of $16,650,000, which are to be utilized in the same
market.

Effective April 1, 2005, the Company acquired all the outstanding stock of
Thornton Drilling Company. The aggregate purchase price of approximately
$29,197,000 (including transaction costs of approximately $269,000) consisted of
292,509 common shares valued at approximately $2,000,000 and $26,928,000 in
cash. The transaction has been accounted for as a purchase. The purchase price
has been allocated to the assets acquired and liabilities assumed based upon
their respective fair market values. The fair market value of the property and
equipment was determined by an independent appraisal. The fair market values of
the identified intangible assets were determined by an independent valuation and
will be amortized to expense over the estimated useful lives. The excess of the
purchase price over the fair value of assets acquired and liabilities assumed in
the acquisition of approximately $5,425,000 is classified as goodwill. The
allocation of the assets acquired and liabilities assumed of Thornton Drilling
Company are as follows (in thousands):

Amount
-------
Current assets $ 5,402
Property and equipment 20,765
Identified intangible assets 4,000
Goodwill 5,425
Deferred tax asset 2,129
Other long-term assets 113
Current liabilities (1,744)
Deferred tax liabilities (6,893)
-------
$29,197
=======

The following pro forma information gives effect to the Thornton Drilling
Company acquisition and the purchase of the drilling business of SPA Drilling,
L.P. as though they were effective as of the beginning of the fiscal year for
each period presented. Pro forma adjustments primarily relate to additional
depreciation, amortization and interest costs. The information reflects our
historical data and historical data from these acquired businesses for the
periods indicated. The pro forma data may not be indicative of the results we
would have achieved had we completed these acquisitions on January 1, 2004 or
2005, or that we may achieve in the future. The pro forma financial information
should be read in conjunction with the accompanying historical financial
statements.

Pro Forma
Years Ended December 31,
(In thousands, except per share data)
-------------------------------------
2005 2004
-------- --------

Total revenues $155,942 $112,922
Net income $ 5,578 $ 2,072
Earnings per common share
Basic $ 0.33 $ 0.13
Diluted $ 0.32 $ 0.13

The fair market values of identified intangible assets were determined by an
independent valuation and certain intangible assets will be amortized to expense
over the estimated useful lives. Customer relations are amortized over their
estimated benefit period of 20 years. Intangibles related to the non-compete
agreement are amortized over the period of the non-compete agreement of five
years. Depreciation and amortization includes amortization of intangibles of
$202,500 for the year ended December 31, 2005. Amortization of intangibles is
not expected to exceed $270,000 per year over the next five years.

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

December 31,
2005
------------
Customer relations $2,200,000
Non compete agreement 800,000
Trade name 1,000,000
----------
Intangible assets 4,000,000
----------
Customer relations (82,500)
Non compete agreement (120,000)
----------
Accumulated amortization (202,500)
----------
Intangible assets (net) $3,797,500
==========

4. RELATED-PARTY TRANSACTIONS

During 2005 and 2004, the Company entered into contract arrangements with Triana
Energy, Inc. and Columbia Natural Resources, which was purchased by Triana in
August 2003, and sold by Triana Energy, Inc. in December 2005. The Company's
former Vice Chairman of the Board of Directors is the Chief Executive Officer of
Triana Energy, Inc. For the periods ended December 31, 2005, 2004, and 2003 the
Company had revenues related to transactions with Columbia Natural Resources and
Triana Energy, Inc. of $5,232,314, $8,734,944 and $3,512,810, respectively. At
December 31, 2005 and 2004, the Company had accounts receivable from Columbia
Natural Resources and Triana Energy, Inc. of $481,657 and $1,964,881,
respectively. Effective December 31, 2005, the Chief Executive Officer of Triana
Energy, Inc. resigned as the Vice Chairman of the Board of Directors and as a
Director.

Both Triana Energy, Inc. and the Company share an ultimate common venture fund
owner that provided capital investment funds employed in the initial formation
of the business.

5. ACCOUNTS RECEIVABLE

Accounts receivable consist of the following:

December 31
-------------------------
Description 2005 2004
------------------------------- ----------- -----------
Billed receivables $20,829,400 $ 7,752,449
Unbilled receivables 7,063,290 3,803,439
----------- -----------
Total receivables 27,892,690 11,555,888
Allowance for doubtful accounts (313,436) (269,192)
----------- -----------
Net receivables $27,579,254 $11,286,696
=========== ===========

Unbilled receivables represent recorded revenue that is billable by the Company
at future dates based on contractual payment terms, and is anticipated to be
billed and collected within the quarter following the balance sheet date.

Activity in the allowance for doubtful accounts is as follows:

Balance, December 31, 2002 $128,201
Net charge to expense 120,000
Amounts written off 25,855
--------
Balance, December 31, 2003 222,346
Net charge to expense 152,015
Amounts written off 105,169
--------
Balance, December 31, 2004 269,192
Net charge to expense 155,000
Amounts written off 110,756
--------
Balance, December 31, 2005 $313,436
========

6. PROPERTY, BUILDINGS AND EQUIPMENT

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

DECEMBER 31,
--------------------------
2005 2004
------------ -----------
Land $ 967,432 $ 187,642
Buildings 978,489 382,428
Drilling and well service equipment 135,617,519 68,493,832
Vehicles 5,949,101 2,987,883
Furniture and fixtures 37,977 31,491
Computer equipment 595,702 520,583
Leasehold improvements 78,175 78,175
Construction in progress 22,809,603 2,392,971
------------ -----------
167,033,998 75,075,005
Less accumulated depreciation 46,250,906 32,760,108
------------ -----------
$120,783,092 $42,314,897
============ ===========

Property, buildings and equipment include certain capitalized leases. The
Company had no recorded value of capital lease assets at December 31, 2005, and
$977,914 at December 31, 2004. Amortization of these assets was $977,914 and
$987,845 for the years ended December 31, 2005 and 2004, respectively, and is
included in depreciation expense in the financial statements. As of December 31,
2005, there were no future minimum payments under these leases. Included in
construction in progress is $307,254 of capitalized interest for the year ended
December 31, 2005.

7. INCOME TAXES

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

Years Ended December 31
-------------------------------
2005 2004 2003
---------- -------- -------
Current tax expense:
Federal $ 56,629 $ 73,055 $ --
State 73,681 -- --
Foreign 31,481 212,685 15,927
---------- -------- -------
161,791 285,740 15,927

Deferred tax expense (benefit):
Federal 3,506,596 48,755 --
State 515,676 -- --
Foreign (84,540) 81,892 --
---------- -------- -------
3,937,732 130,647 --
---------- -------- -------
$4,099,523 $416,387 $15,927
========== ======== =======

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

December 31
-------------------------
2005 2004
----------- -----------
Deferred tax assets:
Bad debt expense $ 122,240 $ 104,985
Workers compensation and deferred
revenue accrual 541,014 427,972
Net operating loss carry forwards 9,770,774 11,514,881
Federal AMT tax credit 87,923 --
Other 20,779 398
----------- -----------
Subtotal net deferred tax assets 10,542,730 12,048,236
Valuation allowance -- (2,129,809)
----------- -----------
Total net deferred tax assets 10,542,730 9,918,427

Deferred tax liabilities:
Foreign subsidiary earnings 13,278 429,044
Property building and equipment,
principally due to differnces in
depreciation 17,903,503 9,620,030
----------- -----------
Total deferred tax liabilities 17,916,781 10,049,074
----------- -----------
Net deferred taxes $ 7,374,051 $ 130,647
=========== ===========

The Company has domestic net operating loss carryforwards of approximately $24.8
million at December 31, 2005. These losses may be carried forward for 20 years
and will begin to expire in 2019. The state losses vary as to carryforward
period and will begin to expire in 2008, depending upon the jurisdiction where
applied. Foreign net operating losses were fully utilized in 2004. The company
also has federal alternative minimum tax (AMT) credits of approximately $88,000,
which may be carried forward indefinitely.

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

Total income tax expense (benefit) differed from the amounts computed by
applying the U.S. federal income tax rate to income before income taxes as a
result of the following:

2005 2004 2003
---------- ----------- ---------
Income tax (expense) benefit at the 34%
statutory federal tax rate $3,297,539 $ 1,340,661 $(869,738)
State, local and provincial income
taxes, net of federal tax benefit 509,207 189,277 (4,760)
Change in valuation reserve -- (1,922,942) 948,551
Meals and entertainment 239,516 8,326 --
Non-cash compensation 255,957 -- --
Permanent and other 30,707 42,165 (58,126)
Deferred tax adjustment (233,403) 395,188 --
Deferred taxes on unremitted earnings -- 363,712 --
---------- ----------- ---------
$4,099,523 $ 416,387 $ 15,927
========== =========== =========

During 2005, 2004 and 2003, the Company made tax payments of approximately
$252,000, $4,000 and $34,000, respectively.

8. ACCRUED EXPENSES AND OTHER LIABILITIES

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

December 31,
-----------------------
2005 2004
---------- ----------
Accrued payroll and bonus $2,709,219 $1,350,426
Accrued workers compensation 1,312,214 928,309
Other 1,331,875 935,440
---------- ----------
$5,353,308 $3,214,175
========== ==========

9. LONG-TERM OBLIGATIONS

On May 3, 2002, the Company entered into an agreement with a bank to provide a
line of credit facility totaling $10,000,000. The amount available under the
line of credit is limited by a percentage of eligible accounts receivable
(approximately $4.1 million at December 31, 2004). The line of credit bears
interest at either (i) a fluctuating rate per annum equal to the higher of the
Prime Rate or the sum of the Federal Funds Effective Rate plus 50 basis points
or (ii) a fluctuating rate per annum equal to the LIBOR rate plus 187.5 basis
points. These rates increase when borrowings under the facility exceed certain
percentages of the total $10 million commitment. The highest rate is paid once
the Company's borrowings exceed 67% of the total commitment. The maximum
interest rate at that level of borrowing is the Prime Rate plus 62.5 basis
points or the LIBOR rate plus 250 basis points.

On June 30, 2004, the credit agreement was amended and restated to extend the
revolving credit facility termination date to December 31, 2005.

On April 1, 2005, the Company paid off the outstanding balance and retired the
line of credit.

The Company entered into a Revolving Credit and Security Agreement dated March
31, 2005, and subsequently amended on April 19, August 15, and October 5, 2005,
which provides for a borrowing base equal to the lesser of $60,000,000 and the
sum of 85% of eligible receivables and 75% of the liquidation value of eligible
rig fleet equipment. There is a $7,500,000 sublimit for letters of credit.
Amounts outstanding under the revolving credit facility bear interest at either
(i) the higher of the Federal Funds Open Rate plus one half of 1.00% or the base
commercial lending rate of the agent for the lenders (7.25% at December 31,
2005) or (ii) LIBOR plus 2.00% (6.39% at December 31, 2005). As of December 31,
2005, the Company had no outstanding loans under the Revolving Credit and
Security Agreement, but $2.7 million of the total capacity has been utilized to
support the Company's letter of credit requirement.

On March 29, 2002, the Company entered into a Loan and Security Agreement with a
financial institution to provide term loans in the amount of $9.9 million. These
term loans bear interest at the greater of LIBOR plus 450 basis points or 7.6%
and are secured by liens on specific rigs and equipment. These term loans had an
outstanding balance of $2,053,038 as of December 31, 2004.

On April 1, 2005, the Company paid off the outstanding balance and retired the
term loan.

In addition, the Company has entered into various equipment-specific financing
agreements with several third-party financing institutions. The terms of these
agreements vary but the majority of them are for 48 months, while three have a
term of 36 months and eight have a term of 60 months. As of December 31, 2005,
the total outstanding balance under these arrangements, including principal and
interest, was $8,757,891. The interest rate on these borrowings ranges from 1.7%
to 7.5%. The following is a schedule, by year, of the future debt payments under
these agreements, together with the present value of the net payments as of
December 31, 2005:

Year ending December 31:

2006 $2,420,048
2007 2,263,908
2008 2,091,993
2009 1,610,547
2010 371,395
----------
Total minimum debt payments 8,757,891
Less amount representing interest 931,907
----------
Total present value of minimum payments 7,825,984
Less current portion of such obligations 2,013,956
----------
Long-term portion of obligations $5,812,028
----------

The Company paid approximately $2,367,000, $629,300 and $849,600 in interest,
net of capitalized interest, on all debt during 2005, 2004 and 2003,
respectively.

10. OTHER INCOME

Included in other income in 2004 is approximately $707,000 of foreign currency
gains associated with the sale of assets and the reclassification of currency
translation gains.

11. PRODUCTIVE CAPACITY

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

Rotary Rigs and Related
Drilling Equipment Purchase Price (in
Purchases by Year Purchased millions)
----------------- ----------------------- ------------------
1997 12 $ 7.2
1998 19 11.0
1999 7 8.3
2000 7 4.7
2001 4 7.5
2002 2 4.2
2004 2 5.5
2005 29 57.7
--- ------
Total 82 $106.1
=== ======

In December 2005, the Company entered into a contract with National Oilwell
Varco to acquire three rigs and related equipment for an aggregate purchase
price of $24 million. In November 2005, Union had paid National Oilwell Varco
$250,000 toward the purchase price of such equipment. In December 2005, the
Company made a further downpayment of $6,936,500 on the first three rigs. Also
in December 2005, the Company paid $1 million to National Oilwell Varco for an
option to acquire an additional three rigs and related equipment for an
aggregate purchase price of $25.2 million. If that option is exercised by April
30, 2006, the $1 million option price will be applied to the purchase price for
the three rigs. All six rigs, which are capable of horizontal and underbalanced
drilling, would be scheduled for delivery during 2006.

12. STOCKHOLDERS' EQUITY

At December 31, 2005, the number of authorized shares of common and preferred
stock was 75,000,000 and 100,000 shares, respectively, of which 21,166,109 and
zero were outstanding, and 2,764,308 and zero were reserved for future
issuance.

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

13. MANAGEMENT COMPENSATION

STOCK OPTION PLANS

The Company established a 2005 Stock Option Plan authorizing up to 1,579,552
shares of the company's common stock. Grants have been made of 531,775 options
to purchase common stock at $14.00 per share.

Effective March 16, 2000, the Board of Directors of Union adopted the 2000
Employee Stock Option Plan (the Plan). The Plan, as amended on June 1, 2003,
reserves 1,579,552 shares of the Company's common stock. As of December 31, 2005
and 2004, 1,404,401 and 876,647 options, respectively, had been granted under
the Plan. The options expire on the tenth anniversary of the grant date. Vesting
typically occurs in two, three or four equal annual installments from the grant
date, depending on the terms of the grant. The exercise price of stock options
under the Plan was based on the Board of Directors assessment of the fair market
value of the stock at the time the options were granted. Outside of the Plan,
132,958 options were granted in 1999.

Stock option activity for all options was as follows:

WEIGHTED
NUMBER OF OPTION PRICE AVERAGE
SHARES RANGE EXERCISE PRICE
--------- ------------ --------------

Outstanding at December 31, 2002 918,702 $ 2.51-$3.80 $ 3.30
Granted 618,657 $ 3.80 $ 3.80
Exercised -- $ -- $ --
Canceled (527,754) $ 3.26 $ 3.26
--------- ------------ ------
Outstanding at December 31, 2003 and 2004 1,009,605 $ 2.51-$3.80 $ 3.63
Granted 1,059,529 $7.22-$14.00 $10.62
Exercised (527,754) $ 7.22 $ 7.22
Canceled -- $ -- $ --
--------- ------------ ------
Outstanding at December 31, 2005 1,541,380 $2.51-$14.00 $ 7.21
========= ============ ======

As of December 31, 2005, the weighted-average remaining contractual life on the
options outstanding was 7.8 years. As of December 31, 2005, options to purchase
650,916 shares of common stock were exercisable.

For purposes of determining compensation expense using the provisions of SFAS
No. 123 as set forth in Note 2, the fair value of option grants was determined
using the Black-Scholes option valuation model. The key input variables used in
valuing the options were: risk-free interest rates of approximately 4.2% to
4.4%, 2.9% and 2.3% for the 2005, 2004 and 2003 grants, respectively; dividend
yield of zero; stock price volatility of 19%, 94% and 71% for 2005, 2004 and
2003, respectively, prior years were based on a publicly traded peer of the
Company; and option lives of approximately two, four and ten years. The effects
of applying SFAS No. 123 in this pro forma disclosure may not be representative
of the effects on reported net income for future periods.

EMPLOYEE BENEFIT PLAN

The Company has a defined contribution employee benefit plan covering
substantially all of its employees. Company contributions to the plan are
discretionary. The Company started matching employee contributions effective
January 1, 2001, and made contributions of approximately $210,000, $120,000 and
$106,000 during the years ended December 31, 2005, 2004 and 2003, respectively.

CONTINGENT MANAGEMENT COMPENSATION

Certain members of the Company management and certain other participants have
been awarded rights to participate in the proceeds associated with the
appreciation in value ultimately associated with dispositions of the Company's
shares by Union Drilling Company LLC (UDC). In order to receive benefits from
this arrangement, the fair market value of the Company's shares held by UDC must
exceed certain threshold amounts.

The Company participants in this arrangement are to receive benefits as a result
of UDC's sale, distribution or disposition of Company shares and the related
recognition of a gain in excess of the threshold amount. These rights may be
repurchased from these individuals at fair market value, which includes
consideration of the threshold amount in the determination of that value, upon
termination of their employment by the Company.

At December 31, 2005 and 2004 the threshold amounts were $26.5 million and $86.4
million, respectively. These amounts are determined based upon cash invested in
UDC (and invested by UDC in the Company's stock) plus a compounded annual return
of 10% less cash returned to investors. Compensation expense was not recognized
prior to January 1, 2005, as the threshold amounts were not exceeded. During the
year-ended December 31, 2005, $752,816 of compensation costs was recognized as a
result of the fair value of the assets owned by UDC exceeding the threshold.
This amount is classified as general and administrative expense. This
compensation was initially recognized at $1,167,398 (estimated fair market value
of Company shares at $17.00 per share). This amount was adjusted to the year-end
market value of $14.53 per share, resulting in a reduction in compensation
expense of $414,582 during the fourth quarter.

The defined group of participants in this arrangement would be entitled to up to
22.5% of the value realized in excess of the threshold amount. Members of
Company management are entitled to approximately 4% of the 22.5%.

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

14. OPERATING LEASES

The Company leases certain buildings and automobiles under noncancelable
operating agreements. Lease expense was $1,074,704, $787,799 and $674,899 for
the years ended December 31, 2005, 2004 and 2003, respectively.

Future minimum lease payments under noncancelable operating leases consist of
the following:

2006 $ 996,520
2007 709,351
2008 361,547
2009 49,500
----------
Total $2,116,918
==========

ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE

None

ITEM 9.A CONTROLS AND PROCEDURES

(A) EVALUATION OF DISCLOSURE CONTROLS AND PROCEDURES.

Our disclosure controls and procedures (as defined in Rule 13a-15(e) under the
Securities Exchange Act of 1934 (the "Exchange Act")), which we refer to as
disclosure controls, are controls and procedures that are designed with the
objective of ensuring that information required to be disclosed in our reports
filed under the Exchange Act, such as this annual report, is recorded,
processed, summarized and reported within the time periods specified in the
Securities and Exchange Commission's rules and forms. Disclosure controls are
also designed with the objective of ensuring that such information is
accumulated and communicated to our management, including the Chief Executive
Officer and the Chief Financial Officer, as appropriate to allow timely
decisions regarding required disclosure. There are inherent limitations to the
effectiveness of any control system. A control system, no matter how well
conceived and operated, can provide only reasonable assurance that its
objectives are met. No evaluation of controls can provide absolute assurance
that all control issues and instances of fraud, if any, within our company have
been detected.

As of December 31, 2005, an evaluation was carried out under the supervision and
with the participation of our management, including the Chief Executive Officer
and the Chief Financial Officer, of the effectiveness of the design and
operation of our disclosure controls. Based upon that evaluation, the Chief
Executive Officer and the Chief Financial Officer concluded that, as of such
date, the design and operation of these disclosure controls were effective to
accomplish their objectives at the reasonable assurance level.

(B) CHANGES IN INTERNAL CONTROL OVER FINANCIAL REPORTING.

No change in our internal control over financial reporting (as defined in Rules
13a-15(f) and 15d-15(f) under the Exchange Act) occurred during the fiscal
quarter ended December 31, 2005 that has materially affected, or is reasonably
likely to materially affect, our internal control over financial reporting.

PART III

In Items 10, 11, 12, 13 and 14 below, we are incorporating by reference the
information we refer to in those Items from the definitive proxy statement for
our 2006 Annual Meeting of Stockholders. We intend to file that definitive proxy
statement with the SEC by April 30, 2006.

ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT

The following information will be included in our Proxy Statement to be filed
within 120 days after the fiscal year end of December 31, 2005, and is
incorporated herein by reference:

o Information regarding our executive officers and directors required by
this Item is set forth under the heading "Management of the Company"

o Information regarding our audit committee and designated "audit
committee financial experts" is set forth under the heading "Board
Meetings and Committees - Audit Committee"

o Information regarding Section 16(a) beneficial ownership reporting
compliance is set forth under the heading "Section 16(a) Beneficial
Ownership Reporting Compliance"

CODE OF ETHICS

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

ITEM 11. EXECUTIVE COMPENSATION

The information required by this Item is incorporated by reference to the
information provided under the headings "Executive Compensation," "Compensation
Committee Report on Executive Compensation," "Director Compensation,"
"Compensation Committee Interlocks and Insider Participation" and "Performance
Graph" in the Proxy Statement.

ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND
RELATED STOCKHOLDER MATTERS

The information required by this Item is incorporated by reference to the
information provided (1) under the heading "Equity Compensation Plan
Information" in Item 5 of this Report and (2) under the heading "Security
Ownership of Certain Beneficial Owners" in the Proxy Statement.

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS

The information required by this Item is incorporated by reference to the
information provided under the heading "Certain Relationships and Related
Transactions" in the Proxy Statement.

ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES

The information required by this Item is incorporated by reference to the
information provided under the headings "Audit and Non-Audit Fees" and "Audit
Committee Approval of Audit and Non-Audit Services" in the Proxy Statement.

PART IV

ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K

(1) Financial Statements.

See Index to Consolidated Financial Statements on page 34.

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

EXHIBIT
NUMBER DESCRIPTION
------- -------------------------------------------------------------------
3.1 -- Form of Amended and Restated Certificate of Incorporation of Union
(incorporated by reference to Exhibit 3.1 to our Registration
Statement on Form S-1 (File No. 333-127525) filed on August 15,
2005).

3.2 -- Form of Amended and Restated Bylaws of Union (incorporated by
reference to Exhibit 3.2 to our Registration Statement on Form S-1
(File No. 333-127525) filed on August 15, 2005).

4.1 -- Specimen Stock Certificate for the common stock, par value $0.01
per share, of Union (incorporated by reference to Exhibit 4.1 to
our Registration Statement on Form S-1 (File No. 333-127525) filed
on August 15, 2005).

10.1* -- Amended and Restated 2000 Stock Option Plan of Union (incorporated
by reference to Exhibit 10.1 to our Registration Statement on Form
S-1 (File No. 333-127525) filed on August 15, 2005).

10.2* -- Form of stock option agreements under the Amended and Restated 2000
Stock Option Plan (incorporated by reference to Exhibit 10.2 to our
Registration Statement on Form S-1 (File No. 333-127525) filed on
August 15, 2005).

10.3* -- Stock Option Plan and Agreement, dated May 13, 1999, by and between
Union and Christopher Strong (incorporated by reference to Exhibit
10.3 to our Registration Statement on Form S-1 (File No.
333-127525) filed on August 15, 2005).

10.4* -- 2005 Stock Option Plan of Union (incorporated by reference to
Exhibit 10.4 to our Registration Statement on Form S-1 (File No.
333-127525) filed on August 15, 2005).

10.5* -- Form of stock option agreements under the 2005 Stock Option Plan
(incorporated by reference to Exhibit 10.5 to our Registration
Statement on Form S-1 (File No. 333-127525) filed on August 15,
2005).

10.6 -- Form of Stockholders Agreement by and among Union and certain of
its direct and indirect stockholders (incorporated by reference to
Exhibit 10.6 to Amendment No. 2 to our Registration Statement on
Form S-1 (File No. 333-127525) filed on October 18, 2005).

10.7 -- Revolving Credit and Security Agreement, dated March 31, 2005,
between Union the lenders signatory thereto and PNC Bank, as agent
for the lenders, together with the First Amendment dated April 19,
2005 (incorporated by reference to Exhibit 10.7 to our Registration
Statement on Form S-1 (File No. 333-127525) filed on August 15,
2005).

10.8 -- Stock Purchase Agreement, dated as of March 31, 2005, by and
between Union and Richard Thornton, the sole stockholder of
Thornton Drilling Company (incorporated by reference to Exhibit
10.8 to our Registration Statement on Form S-1 (File No.
333-127525) filed on August 15, 2005).

10.9 -- Registration Rights Agreement, dated as of March 31, 2005, between
Union and Richard Thornton (incorporated by reference to Exhibit
10.9 to our Registration Statement on Form S-1 (File No.
333-127525) filed on August 15, 2005).

10.10* -- Employment Agreement, dated as of March 31, 2005, between Union and
Richard Thornton (incorporated by reference to Exhibit 10.10 to our
Registration Statement on Form S-1 (File No. 333-127525) filed on
August 15, 2005).

10.11 -- Stock Purchase Agreement, dated as of March 31, 2005, by and
between Union, Steven A. Webster, Wolf Marine S.A. and William R.
Ziegler (incorporated by reference to Exhibit 10.11 to our
Registration Statement on Form S-1 (File No. 333-127525) filed on
August 15, 2005).

10.12 -- Option and Asset Purchase and Sale Agreement dated as of February
28, 2005 between Thornton Drilling Company and SPA Drilling, LP;
Amendment No. 1 to Purchase and Sale Agreement between Thornton
Drilling Company and SPA Drilling, LP; and Assignment and
Assumption Agreement between Thornton Drilling Company and Union
Drilling Texas, LP. (incorporated by

reference to Exhibit 10.12 to Amendment No. 4 to our Registration
Statement on Form S-1 (File No. 333-127525) filed on November 7,
2005).

10.13 -- Asset Purchase Agreement, dated May 31, 2005, between C and L
Services, LP and Union Drilling Texas, LP. (incorporated by
reference to Exhibit 10.13 to our Registration Statement on Form
S-1 (File No. 333-127525) filed on August 15, 2005).

10.14 -- Forms of Indemnification Agreement with Union directors and certain
of its officers (incorporated by reference to Exhibit 10.14 to
Amendment No. 2 to our Registration Statement on Form S-1 (File No.
333-127525) filed on October 18, 2005).

10.15 -- Second Amendment, dated August 15, 2005, to the Revolving Credit
and Security Agreement between Union, the lenders signatory thereto
and PNC Bank, as agent for the lenders (incorporated by reference
to Exhibit 10.15 to Amendment No. 1 to our Registration Statement
on Form S-1 (File No. 333-127525) filed on September 28, 2005).

10.16 -- Asset Purchase Agreement, dated August 12, 2005, between C and L
Services, LP and Union Drilling Texas, LP. (incorporated by
reference to Exhibit 10.16 to Amendment No. 1 to our Registration
Statement on Form S-1 (File No. 333-127525) filed on September 28,
2005).

10.17 -- Third Amendment, dated October 5, 2005, to the Revolving Credit and
Security Agreement between Union, the lenders signatory thereto and
PNC Bank, as agent for the lenders (incorporated by reference to
Exhibit 10.17 to Amendment No. 2 to our Registration Statement on
Form S-1 (File No. 333-127525) filed on October 18, 2005).

10.18 -- Option to purchase drilling rigs from National Oilwell Varco
(incorporated by reference to Exhibit 10.18 to Amendment No. 4 to
our Registration Statement on Form S-1 (File No. 333-127525) filed
on November 7, 2005).

10.19 -- Purchase and Sale Agreement, dated December 8, 2005, between Union
and National-Oilwell, L.P., relating to the purchase of three
drilling rigs (incorporated by reference to Exhibit 10.1 to our
Form 8-K (File No. 000-51630) filed on December 13, 2005).

10.20 -- Option Agreement, dated December 8, 2005, between Union and
National-Oilwell, L.P., relating to the purchase of three drilling
rigs (incorporated by reference to Exhibit 10.2 to our Form 8-K
(File No. 000-51630) filed on December 13, 2005).

10.21 -- Assets Purchase Agreement, dated December 19, 2005, between Permian
Drilling Corporation and Maverick Oil and Gas, Inc., (incorporated
by reference to Exhibit 10.1 to our Form 8-K (File No. 000-51630)
filed on February 3, 2006).

10.22 -- Agreement Regarding Assignment and Assumption of Rights and
Obligations under Assets Purchase Agreement, dated January 30,
2006, between Maverick Oil and Gas, Inc. and Thornton Drilling
Company; (incorporated by reference to Exhibit 10.1 to our Form 8-K
(File No. 000-51630) filed on February 3, 2006).

10.23 -- Addendum to Assets Purchase Agreement and Letter Agreement, dated
January 30, 2006, between Permian Drilling Corporation, Maverick
Oil and Gas, Inc. and Thornton Drilling Company, (incorporated by
reference to Exhibit 10.1 to our Form 8-K (File No. 000-51630)
filed on February 3, 2006).

21.1 -- List of Subsidiaries filed herewith.

31.1 -- Certification of Chief Executive Officer Pursuant to Section 302 of
the Sarbanes-Oxley Act of 2002 filed herewith.**

31.2 -- Certification of Chief Financial Officer Pursuant to Section 302 of
the Sarbanes-Oxley Act of 2002 filed herewith.**

32.1 -- Certification of Chief Executive Officer Pursuant to 18 U.S.C.
Section 1350, as adopted pursuant to Section 906 of the
Sarbanes-Oxley Act of 2002 filed herewith.**

32.2 -- Certification of Chief Financial Officer Pursuant to 18 U.S.C.
Section 1350, as adopted pursuant to Section 906 of the
Sarbanes-Oxley Act of 2002 filed herewith.**

----------
* Management contract or compensatory plan or arrangement.

** This certification is being furnished solely to accompany this Annual
Report pursuant to 18 U.S.C.Section 1350, and is not being filed for
purposes of Section 18 of the Securities Exchange Act of 1934, as amended,
and is not to be incorporated by reference to any filing of the Company,
whether made before or after the date hereof, regardless of any general
incorporation language in such filing.

SIGNATURES

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

UNION DRILLING, INC.

March 28, 2006 By: /s/ Christopher D. Strong
-----------------------------------------
Christopher D. Strong
President and Chief Executive Officer

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

SIGNATURE TITLE DATE
--------------------------- ------------------------------------------------ -------------

/s/ Christopher D. Strong
---------------------------
Christopher D. Strong President and Chief Executive Officer (Principal March 28, 2006
Executive Officer)

/s/ Dan E. Steigerwald
---------------------------
Dan E. Steigerwald Vice President, Chief Financial Officer, March 28, 2006
Treasurer and Secretary
(Principal Financial and Accounting Officer)

/s/ Thomas H. O'Neill, Jr.
---------------------------
Thomas H. O'Neill Jr. Chairman of the Board March 28, 2006
(non-executive)

/s/ William R. Ziegler
---------------------------
William R. Ziegler Vice Chairman of the Board March 28, 2006
(non-executive)

/s/ Howard I. Hoffen
---------------------------
Howard I. Hoffen Director March 28, 2006

/s/ Gregory D. Myers
---------------------------
Gregory D. Myers Director March 28, 2006

/s/ John J. Moon
---------------------------
John J. Moon Director March 28, 2006

/s/ Thomas M. Mercer, Jr.
---------------------------
Thomas M. Mercer, Jr. Director March 28, 2006

/s/ M. Joseph McHugh
---------------------------
M. Joseph McHugh Director March 28, 2006