The following discussion and analysis should be read in conjunction with the "Management's Discussion and Analysis of Financial Condition and Results of Operations" section and audited consolidated financial statements and related notes thereto included in our Annual Report on Form 10-K, filed with the Securities and Exchange Commission, or SEC, on March 17, 2008 and with the unaudited consolidated financial statements and related notes thereto presented in this Quarterly Report on Form 10-Q.

Disclosure Regarding Forward-Looking Statements

Our disclosure and analysis in this Form 10-Q may include forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, or the Securities Act, Section 21E of the Securities Exchange Act of 1934, as amended, or the Exchange Act, and the Private Securities Litigation Reform Act of 1995, that are subject to risks and uncertainties. Forward-looking statements give our current expectations and projections relating to our financial condition, results of operations, plans, objectives, future performance and business. You can identify these statements by the fact that they do not relate strictly to historical or current facts. These statements may include words such as "anticipate," "estimate," "expect," "project," "intend," "plan," "believe" and other words and terms of similar meaning in connection with any discussion of the timing or nature of future operating or financial performance or other events. All statements other than statements of historical facts included in this Form 10-Q that address activities, events or developments that we expect, believe or anticipate will or may occur in the future are forward-looking statements.

These forward-looking statements are largely based on our expectations and beliefs concerning future events, which reflect estimates and assumptions made by our management. These estimates and assumptions reflect our best judgment based on currently known market conditions and other factors relating to our operations and business environment, all of which are difficult to predict and many of which are beyond our control.

Although we believe our estimates and assumptions to be reasonable, they are inherently uncertain and involve a number of risks and uncertainties that are beyond our control. In addition, management's assumptions about future events may prove to be inaccurate. Management cautions all readers that the forward-looking statements contained in this Form 10-Q are not guarantees of future performance, and we cannot assure any reader that those statements will be realized or the forward-looking events and circumstances will occur. Actual results may differ materially from those anticipated or implied in the forward-looking statements due to the factors listed in the "Management's Discussion and Analysis of Financial Condition and Results of Operations" and "Risk Factors" sections of this Quarterly Report on Form 10-Q and our most recent Annual Report on Form 10-K. All forward-looking statements speak only as of the date of this Form 10-Q. We do not intend to publicly update or revise any forward-looking statements as a result of new information, future events or otherwise, except as required by law. These cautionary statements qualify all forward-looking statements attributable to us or persons acting on our behalf.

Overview

We provide contract land drilling and workover services to oil and natural gas exploration and production companies. As of October 31, 2008, we owned a fleet of 56 land drilling rigs, of which 45 were marketed and 11 were held in inventory. We also owned a fleet of 61 workover rigs, of which 56 were operating and five were in the process of being refurbished. As of October 31, 2008, we also owned a fleet of 66 trucks used to transport our rigs.

We commenced operations in 2001 with the purchase of one stacked 650-horsepower drilling rig that we refurbished and deployed. We subsequently made selective acquisitions of both operational and inventoried drilling rigs, as well as ancillary equipment. Our management team has significant experience not only with acquiring rigs, but also with refurbishing and deploying inventoried rigs. We have successfully refurbished and brought into operation 25 inventoried drilling rigs during the period from November 2003 through December 2007. In addition, we have a 41,000 square foot machine shop in Oklahoma City, which allows us to refurbish and repair our rigs and equipment in-house. This facility, which complements our three drilling rig refurbishment yards, significantly reduces our reliance on outside machine shops and the attendant risk of third-party delays in our rig refurbishment program.

We currently operate our drilling rigs in Oklahoma, Texas, Colorado, North Dakota, Louisiana and Mexico. Our workover rigs are currently operating in Oklahoma, Texas, Kansas, Colorado, Arkansas, and New Mexico. A majority of the wells we drill for our customers are drilled in unconventional basins also known as resource plays. These plays are generally characterized by complex geologic formations that often require higher horsepower, premium rigs and experienced crews to reach targeted depths. Our current fleet of 56 rigs includes 36 rigs ranging from 950 to 2,500 horsepower. Accordingly, such rigs can, or in the case of inventoried rigs upon refurbishment, will be able to, reach the depths required and have the capability of drilling horizontal and directional wells, which are increasing as a percentage of total wells drilled in North America. We believe our premium rig fleet, inventory and experienced crews position us to benefit from the drilling activity in our core operating areas.

We earn our contract drilling revenues by drilling oil and natural gas wells for our customers. We obtain our contracts for drilling oil and 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. We have not historically entered into turnkey contracts and do not intend to enter into turnkey contracts, subject to changes in market conditions, although it is possible that we may acquire such contracts in connection with future acquisitions. 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. Although we currently have 28 of our rigs operating under agreements with durations of up to two years, our contracts generally provide for the drilling of a single well and typically permit the customer to terminate on short notice.

A significant performance measurement in our industry is operating rig utilization. We compute operating 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 operating rig. Revenue days for each operating rig are days when the rig is earning revenues under a contract, i.e. when the rig begins moving to the drilling location until the rig is released from the contract. On daywork contracts, during the mobilization period we typically earn a fixed amount of revenue based on the mobilization rate stated in the contract. We begin earning our contracted daywork rate when we begin drilling the well. Occasionally, in periods of increased demand, we will receive a percentage of the contracted dayrate during the mobilization period. We account for these revenues as mobilization fees.

For the three and nine months ended September 30, 2008 and 2007 and for the years ended December 31, 2007, 2006 and 2005, our rig utilization rates, revenue days and average number of operating rigs were as follows:

                     Three Months Ended          Nine Months Ended
                        September 30,              September 30,              Years Ended December 31,
                      2008          2007         2008          2007         2007         2006        2005
Average number
of operating
rigs                       42           53            44           52           51           45          17
Revenue days            3,208        3,739         9,412       10,995       14,245       15,202       5,781
Utilization
Rates                      84 %         76 %          78 %         77 %         76 %         93 %        95 %

The decrease in the number of revenue days in the three and nine month-periods ended September 30, 2008 as compared to the same period in 2007 is attributable to a decrease in our average number of operating rigs due primarily to the rigs sold and contributed to Challenger. See "-Recent Highlights" below.

Market Conditions in Our Industry

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

The following table depicts the prices for near month delivery contracts for crude oil and natural gas as traded on the NYMEX, as well as the most recent Baker Hughes domestic land rig count, on the dates indicated:

                                At September 30,              At December 31,
                                      2008             2007        2006        2005

         Crude oil (Bbl)       $           100.64     $ 95.98     $ 61.05     $ 61.04
         Natural gas (Mmbtu)   $             7.44     $  7.48     $  6.30     $ 11.23
         U.S. Land Rig Count                1,926       1,719       1,626       1,391

As of October 31, 2008, the price for near month delivery contracts for crude oil and natural gas as traded on the NYMEX were 67.81 and 6.78, respectively. As of October 31, 2008 the U.S. Land Rig Count according to Baker Hughes was 1,906.

Critical Accounting Policies and Estimates

Our discussion and analysis of our financial condition and results of operations is based upon our consolidated financial statements, which have been prepared in accordance with accounting policies that are described in the notes to our consolidated financial statements. The preparation of the consolidated financial statements requires management to make estimates and judgments that affect the reported amounts of assets, liabilities, revenues and expenses, and related disclosure of contingent assets and liabilities. We continually evaluate our judgments and estimates in determining our financial condition and operating results. Estimates are based upon information available as of the date of the financial statements and, accordingly, actual results could differ from these estimates, sometimes materially. Critical accounting policies and estimates are defined as those that are both most important to the portrayal of our financial condition and operating results and require management's most subjective judgments. The most critical accounting policies and estimates are described below.

Revenue and Cost Recognition-We earn our revenues by drilling oil and natural gas wells for our customers under daywork or footage contracts. We recognize revenues on daywork contracts for the days completed based on the dayrate each contract specifies. Mobilization revenues and costs are deferred and recognized over the drilling days of the related well. Individual wells are usually completed in less than 120 days. We follow the percentage-of-completion method of accounting for footage contract drilling arrangements. Under this method, drilling revenues and costs related to a well in progress are recognized proportionately over the time it takes to drill the well. Percentage of completion is determined based upon the amount of expenses incurred through the measurement date as compared to total estimated expenses to be incurred drilling the well. Mobilization costs are not included in costs incurred for percentage-of-completion calculations. Mobilization costs on footage contracts and daywork contracts are deferred and recognized over the days of actual drilling. Under the percentage-of-completion method, management estimates are relied upon in the determination of the total estimated expenses to be incurred drilling the well. When estimates of revenues and expenses indicate a loss on a contract, the total estimated loss is accrued.

Our management has determined that it is appropriate to use the percentage-of-completion method to recognize revenue on our footage contracts, which is the predominant practice in the industry. Although our footage contracts do not have express terms that provide us with rights to receive payment for the work that we perform prior to drilling wells to the agreed upon depth, we use this method because, as provided in applicable accounting literature, we believe we achieve a continuous sale for our work-in-progress and we believe, under applicable state law, we ultimately could recover the fair value of our work-in-progress even in the event we were unable to drill to the agreed upon depth in breach of the applicable contract. However, ultimate recovery of that value, in the event we were unable to drill to the agreed upon depth in breach of the contract, would be subject to negotiations with the customer and the possibility of litigation.

We are entitled to receive payment under footage contracts when we deliver to our customer a well completed to the depth specified in the contract, unless the customer authorizes us to drill to a shallower depth. Since inception, we have completed all our footage contracts. Although our initial cost estimates for footage contracts do not include cost estimates for risks such as stuck drill pipe or loss of circulation, we believe that our experienced management team, our knowledge of geologic formations in our areas of operations, the condition of our drilling equipment and our experienced crews enable us to make reasonably dependable cost estimates and complete contracts according to our drilling plan. While we do bear the risk of loss for cost overruns and other events that are not specifically provided for in our initial cost estimates, our pricing of footage contracts takes such risks into consideration. When we encounter, during the course of our drilling operations, conditions unforeseen in the preparation of our original cost estimate, we immediately adjust our cost estimate for the additional costs to complete the contracts. If we anticipate a loss on a contract in progress at the end of a reporting period due to a change in our cost estimate, we immediately accrue the entire amount of the estimated loss, including all costs that are included in our revised estimated cost to complete that contract, in our consolidated statement of operations for that reporting period. We are more likely to encounter losses on footage contracts in years in which revenue rates are lower for all types of contracts.

Revenues and costs during a reporting period could be affected by contracts in progress at the end of a reporting period that have not been completed before our financial statements for that period are released. We had no footage contracts in progress at September 30, 2008 and December 31, 2007. At September 30, 2008 and December 31, 2007, our contract drilling in progress totaled $3.0 million and $2.1 million, respectively, all of which relates to the revenue recognized but not yet billed or costs deferred on daywork contracts in progress.

We accrue estimated contract costs on footage contracts for each day of work completed based on our estimate of the total costs to complete the contract divided by our estimate of the number of days to complete the contract. Contract costs include labor, materials, supplies, repairs and maintenance and operating overhead allocations. In addition, the occurrence of uninsured or under-insured losses or operating cost overruns on our footage contracts could have a material adverse effect on our financial position and results of operations. Therefore, our actual results could differ significantly if our cost estimates are later revised from our original estimates for contracts in progress at the end of a reporting period that were not completed prior to the release of our financial statements.

Accounts Receivable-We evaluate the creditworthiness of our customers based on their financial information, if available, information obtained from major industry suppliers, current prices of oil and natural gas and any past experience we have with the customer. Consequently, an adverse change in those factors could affect our estimate of our allowance for doubtful accounts. 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 typical contract provides for payment of invoices in 10 to 30 days. We generally do not extend payment terms beyond 30 days. We are currently involved in legal actions to collect various overdue accounts receivable. Our allowance for doubtful accounts was $1.2 million and $1.8 million at September 30, 2008 and December 31, 2007, respectively. Any allowance established is subject to judgment and estimates made by management. We determine our allowance by considering a number of factors, including the length of time trade accounts receivable are past due, our previous loss history, our customer's current ability to pay its obligation 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 and payments subsequently received on such receivables reduce the allowance for doubtful accounts.

If a customer defaults on its payment obligation to us under a footage contract, we would need to rely on applicable law to enforce our lien rights, because our footage contracts do not expressly grant to us a security interest in the work we have completed under the contract and we have no ownership rights in the work-in-progress or completed drilling work, except any rights arising under the applicable lien statute on foreclosure. If we were unable to drill to the agreed on depth in breach of the contract, we might also need to rely on equitable remedies outside of the contract, including quantum meruit, available in applicable courts to recover the fair value of our work-in-progress under a footage contract.

Asset Impairment and Depreciation-We review long-lived assets to be held and used for impairment whenever events or changes in circumstances indicate that the carrying amount of the assets may not be recoverable. We also evaluate the carrying value of goodwill during the fourth quarter of each year and between annual evaluations if events occur or circumstances change that would more likely than not reduce the fair value below its carrying amount. Factors that we consider important and could trigger an impairment review would be our customers' financial condition and any significant negative industry or economic trends. 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 debt or equity and the trends in the price of used drilling equipment observed by our management. If a review of our drilling rigs, intangible assets and goodwill indicate that our carrying value exceeds the estimated undiscounted future cash flows, we are required under applicable accounting standards to write down the drilling equipment, intangible assets and goodwill to its fair market value. A one percent write-down in the cost of our drilling equipment, intangible assets, and goodwill, at September 30, 2008, would have resulted in a corresponding decrease in our net income of approximately $2.8 million.

Our determination of the estimated useful lives of our depreciable assets, 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 rigs, transportation and other equipment on a straight-line method over useful lives that we have estimated and that range from three to fifteen years after the rig was placed into service. We record the same depreciation expense whether an operating rig is idle or working. Depreciation is not recorded on an inventoried rig until placed in service. 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.

We capitalize interest cost as a component of drilling and workover rigs refurbished for our own use. During the three and nine months ended September 30, 2008, we capitalized approximately $205,000 and $663,000, respectively, and during the three and nine months ended September 30, 2007 we capitalized approximately $366,000 and $1.3 million, respectively.

Stock Based Compensation--- We have adopted SFAS No. 123(R), "Share-Based Payment" upon granting our first stock options on August 16, 2005. SFAS No. 123(R) requires a public entity to measure the costs of employee services received in exchange for an award of equity or liability instruments based on the grant-date fair value of the award. That cost will be recognized over the periods during which an employee is required to provide service in exchange for the award. Stock compensation expense was $2.0 million and $4.5 million for the three and nine months ended September 30, 2008, respectively, and $1.0 million and $2.7 million for the three and nine months ended September 30, 2007, respectively.

The fair value of each option award is estimated on the date of grant using a Black Scholes valuation model that uses various assumptions related to volatility, expected life, forfeitures, exercise patterns, risk free rates and expected dividends. Expected volatilities are based on the historical volatility of a selected peer and other factors. The majority of our options were granted to employees that made up one group with similar expected exercise behavior for valuation purposes. The expected term of options granted was estimated based on an average of the vesting period and the contractual period. The risk-free rate for periods within the contractual life of the option was based on the U.S. Treasury yield curve in effect at the time of the grant.

We have not declared dividends since we became a public company and do not intend to do so in the foreseeable future, and thus did not use a dividend yield. Expected life has been determined using the permitted short cut method.

Under our 2005 Stock Incentive Plan, employee stock options become exercisable in equal monthly installments over a three-year period, and all options generally expire ten years after the date of grant. The 2005 Plan provides that all options must have an exercise price not less than the fair market value of our common stock on the date of the grant.

The Company's board of directors and a majority of the Company's stockholders approved the Company's 2006 Stock Incentive Plan, effective April 20, 2006. No further awards will be made under the 2005 Plan. The purpose of the 2006 Plan is to provide a means by which eligible recipients of awards may be given an opportunity to benefit from increases in value of the Company's common stock through the granting of one or more of the following awards: (1) incentive stock options, (2) nonstatutory stock options, (3) restricted awards, (4) performance awards and (5) stock appreciation rights. The maximum aggregate amount of the Company's common stock which may be issued upon exercise of all awards under the 2006 Plan, may not exceed 2,500,000 shares, less shares underlying options granted to employees under the 2005 Plan prior to the adoption of the 2006 Plan. There have been no stock options exercised under the 2006 Plan.

On April 20, 2007, we filed a Tender Offer Statement on Schedule TO relating to our offer to twenty-five eligible directors, officers, employees and consultants to exchange certain outstanding options to purchase shares of our common stock for restricted stock awards consisting of the right to receive restricted shares of our common stock, which we refer to as the "restricted stock awards." The offer expired on May 21, 2007. Pursuant to the offer, we accepted for cancellation eligible options to purchase 729,000 shares of our common stock tendered by directors, officers, employees and consultants eligible to participate in the offer. Subject to the terms and conditions of the offer, on May 21, 2007 we granted one restricted stock award in exchange for every two shares of common stock underlying the eligible options tendered. Half of the restricted stock awards vested on January 1, 2008 and the balance vest on January 1, 2009, subject to earlier vesting or forfeiture in certain circumstances. We granted the restricted stock awards under our 2006 Stock Incentive Plan, effective as of April 20, 2006.

An incremental cost was computed in accordance with SFAS No. 123(R) upon the conversion of options to restricted stock. The incremental cost was measured as the excess of the fair value of the modified award over the fair value to the original award immediately preceding conversion, measured based on the share price and other pertinent factors at that date. The incremental cost to be recognized over the vesting period of the modified award is $387,000.

Deferred Income Taxes-We provide deferred income taxes for the basis difference in our property and equipment, stock compensation expense and other items 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 in an entity rather than just its assets. For financial reporting purposes, we depreciate the various components of our drilling rigs and refurbishments over fifteen years, while federal income tax rules require that we depreciate drilling rigs and refurbishments over five years. Therefore, in the first five years of our ownership of a drilling rig, our tax depreciation exceeds our financial reporting depreciation, resulting in our providing deferred taxes on this depreciation difference. After five years, financial reporting depreciation exceeds tax depreciation, and the deferred tax liability begins to reverse.

Other Accounting Estimates-Our other accrued expenses as of September 30, 2008 and December 31, 2007 included accruals of approximately $3.6 million and $3.0 million, respectively, for costs under our workers' compensation insurance. We have a deductible of $1.0 million per covered accident under our workers' compensation insurance. We maintain letters of credit in the aggregate amount of $7.3 million for the benefit of various insurance companies as collateral for retrospective premiums and retained losses which may become payable under the terms of the underlying insurance contracts. The letters of credit are typically renewed annually. No amounts have been drawn under the letters of credit. At September 30, 2008 and December 31, 2007, we had deposits of $2.8 million and $2.7 million, respectively, with an insurance company collateralizing a 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 . . .