This management's discussion and analysis of financial condition and results of operations ("MD&A") section of our Quarterly Report on Form 10-Q discusses our results of operations, liquidity and capital resources, and certain factors that may affect our future results, including economic and industry-wide factors. You should read this MD&A in conjunction with our condensed financial statements and accompanying notes included under Part I, Item 1, of this Quarterly Report, as well as with our Annual Report on Form 10-K for the fiscal year ended December 31, 2008.

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

Company Overview

Union Drilling, Inc. ("Union Drilling," "Company" or "we") provides contract land drilling services and equipment, primarily to natural gas producers. We presently focus our operations in selected natural gas production regions in the United States, primarily the Appalachian and Arkoma Basins, as well as the Fort Worth Basin's Barnett Shale formation. In addition to our drilling rigs, we provide the drilling crews and most of the ancillary equipment needed to operate our drilling rigs. We do not invest in oil and natural gas properties.

We commenced operations in 1997 with 12 drilling rigs and related equipment acquired from an entity providing contract drilling services under the name "Union Drilling." Through a combination of acquisitions and new rig construction, we have increased the size of our fleet to 71 marketed land drilling rigs. In addition, to enhance our ability to serve our markets, we have invested significant capital to upgrade most of the rigs in our fleet for underbalanced and horizontal drilling. These investments have positioned our fleet to capitalize on our customers' unconventional formation exploration and development activity.

Key Indicators of Financial Performance for Management

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

The following table summarizes management's key indicators of financial performance for the three and nine months ended September 30, 2009 and 2008.

                                         Three Months Ended           Nine Months Ended
                                            September 30,               September 30,
                                         2009           2008          2009          2008
  Revenue days                             2,000         4,823         7,282        13,004
  Average number of marketed rigs           71.0          71.0          71.0          71.0
  Marketed rig utilization rates            30.6 %        73.8 %        37.6 %        66.8 %
  Revenue per revenue day              $  17,592      $ 17,093      $ 17,626      $ 17,064
  Operating expenses per revenue day   $  11,167      $ 10,879      $ 11,351      $ 11,138

As a result of the decline in natural gas prices commencing in the second half of 2008, overall demand for drilling services correspondingly decreased. Consequently, we experienced a drop in our marketed rig utilization during the three and nine months ended September 30, 2009 compared to the same periods in 2008. This decline in demand primarily affected certain of our smaller rigs and caused our revenue days to decrease in 2009. The increase in revenue per revenue day in 2009 was partially attributable to the decreased utilization of our smaller rigs, which earn a lower dayrate than our larger rigs. In addition, revenue per revenue day for the three and nine months ended September 30, 2009 was favorably impacted by tolling agreements that we entered into in late March 2009 related to two rigs for which the operator elected to pay a stand-by or tolling rate rather than to operate them. Tolling rigs provide revenue without contributing any revenue days, and therefore, increase the calculated revenue per revenue day amount. For the three and nine months ended September 30, 2009, these tolling rigs increased revenue per revenue day by $428 and $232, respectively and operating expense per revenue day by $48 and $32, respectively.

Critical Accounting Policies and Estimates

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

Accounts receivable- We evaluate the creditworthiness of our customers based on their financial information, if available, information obtained from major industry suppliers, and our past experiences, if any, with the customer. In some instances, we require new customers to make prepayments. We typically invoice our customers semimonthly during the performance of daywork contracts and upon completion of the daywork contract. Footage contracts are invoiced upon completion of the contract. Our contracts generally provide for payment of invoices in 30 days. We established an allowance for doubtful accounts of $1.4 million and $1.5 million at September 30, 2009 and December 31, 2008, respectively. Any allowance established is subject to judgment and estimates made by management. We determine our allowance by considering a number of factors, including the length of time trade accounts receivable are past due, our previous loss history, our assessment of our customers' current abilities to pay obligations to us and the condition of the general economy and the oil and gas industry as a whole. We write off specific accounts receivable when we determine they are uncollectible.

At September 30, 2009 and December 31, 2008, our unbilled receivables, excluding the reserve for sales credits, totaled $402,000 and $4.4 million, respectively, all of which relates to the revenue recognized, but not yet billed, on daywork and footage contracts in progress at September 30, 2009 and December 31, 2008, respectively. The $4.0 million decrease at September 30, 2009 compared to December 31, 2008 is due to lower production, increased progress billings and a $1 million contract settlement payment we received in January 2009. As of September 30, 2009 and December 31, 2008, the reserve for sales credits was $124,000 and $213,000, respectively.

Asset impairments - We assess the impairment of property and equipment whenever events or circumstances indicate that the asset's carrying value may not be recoverable. In connection with this review, assets are grouped at

the lowest level at which identifiable cash flows are largely independent of other asset groupings. The cyclical nature of our industry has resulted in fluctuations in rig utilization over periods of time. Management believes that the contract drilling business will continue to be highly cyclical and rig utilization will accordingly fluctuate. Based on expectations of future trends, we estimate future cash flows over the life of the respective assets in our assessment of impairment. These estimates of cash flows are based on historical cyclical trends in the oil and gas industry as well as management's expectations regarding the continuation of these trends in the future. Factors that we consider important and which could trigger an impairment review would be any significant negative trends in the industry or the general economy, our contract revenue rates, our rig utilization rates, cash flows generated from operating our drilling rigs, existence of term drilling contracts, current and future oil and natural gas prices, industry analysts' outlook for the oil and gas 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 value.

Consistent with recent prior quarters, there is continued uncertainty of when a sustained recovery for our industry will occur. While there have been some encouraging signs, such as an increase in the overall U.S. land rig count and recent increases in spot prices for natural gas, business conditions remain challenging. As such, we performed an updated impairment analysis as of September 30, 2009 to determine if additional impairment charges were necessary related to our long-lived assets, including certain of our property and equipment. We estimated future cash flows over the estimated life of the identified long-lived assets and determined whether, on an undiscounted basis, estimated cash flows exceeded the carrying value of the long-lived assets. Based on our assessment, no impairment was recognized for the three months ended September 30, 2009. Additionally, the independent appraisal of our drilling equipment (as required under our credit facility) was substantially completed during the quarter which supported our conclusion that no additional impairment was necessary.

For the nine months ended September 30, 2009, $2.9 million of impairment was recognized related to certain long-lived assets. Estimated fair value was determined using unobservable inputs based on both an income approach and a market approach. The income approach was calculated as the estimated discounted future net cash flows assumed to be received from the operation of the asset over its useful life and a terminal value. The Company's primary assumptions impacting the estimated future cash flows were (a) the utilization rate trends over the useful life of the asset, (b) revenues and operating costs per drilling day, and (c) terminal or salvage value for the asset. The market approach was calculated based on recent sales and purchases of similar assets by the Company. The Company's assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of nonfinancial assets and liabilities and their placement within the fair value hierarchy levels. In the event that current market conditions do not improve, the Company may be required to record additional impairment of its property and equipment in the future, and such an impairment expense, even though non-cash, could be material and negatively impact our earnings.

Accrued workers' compensation - The Company accrues for costs under its workers' compensation insurance program in accrued expenses and other liabilities. We have a deductible of $100,000 per covered accident under our workers' compensation insurance. Our insurance policies require us to maintain letters of credit to cover our deductible payments. As of September 30, 2009 and December 31, 2008, we satisfied this requirement with letters of credit totaling $4.8 million and $3.5 million, respectively. Our borrowing capacity under our revolving credit agreement with our banks has been reduced by the same amount. 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 estimates for incurred but not reported claims, claims paid directly by us, administrative costs associated with these claims and our historical experience with these types of claims. In addition, if needed, we accrue on a monthly basis the estimated workers' compensation premium payable to Ohio, a monopolistic state.

Some of our employees engaged in our Texas field operations were previously considered to be "shared employees." Under this arrangement, we paid a fee for certain human resource functions, including the workers' compensation and payroll liabilities, to be assumed by the third-party professional employer organization ("PEO"). This PEO arrangement in Texas was terminated effective August 2, 2009, and such employees are now covered under our workers' compensation insurance program.

Stock-based compensation - Compensation cost resulting from share-based payment awards are measured at fair value and recognized in general and administrative expense on a straight line basis over the requisite service period for the entire award. The amount of compensation cost recognized at any date is at least equal to the portion of the grant-date value of the award that is vested at that date. For the three and nine months ended September 30, 2009, the Company recorded stock-based compensation expense of $173,000 ($33,000, net of tax) and $1.1 million ($700,000, net of tax), respectively. For the three and nine months ended September 30, 2008, the Company recorded stock-based compensation of $792,000 ($532,000, net of tax) and $1.3 million ($927,000, net of tax), respectively. Total unamortized stock-based compensation was $3.9 million at September 30, 2009 and will be recognized over a weighted average service period of 3.3 years.

The fair value of stock options granted is estimated using the Black-Scholes option valuation model based on assumptions for the risk-free interest rate, expected life of the option, dividend yield and volatility of our stock price. Volatility is based upon price performance of the Company and a peer company, as the Company does not have a sufficient historical price base to determine potential volatility over the term of the issued options. During the nine months ended September 30, 2009, 25,000 options were granted. No stock options were granted during the nine months ended September 30, 2008. The fair value of restricted stock or restricted stock units is the closing market price of the Company's stock on the award grant date. No restricted stock or restricted stock units were granted during the nine months ended September 30, 2009. During the nine months ended September 30, 2008, 200,000 restricted stock units were granted.

New shares of common stock are issued to satisfy options exercised. Cash received from the exercise of options during the nine months ended September 30, 2009 and 2008 was $248,000 and $416,000, respectively. Any tax benefit realized from stock option exercises is included as a cash inflow from financing activities on the condensed statements of cash flows.

Results of Operations

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