Form 10-Q

Large accelerated filer

Accelerated filer

Non-accelerated filer

Smaller reporting company

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 Exchange 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.

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer,” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.

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

As of April 24, 2009, there were 50,247,728 shares of common stock, par value $0.10 per share, of the registrant issued and outstanding.

Pioneer Drilling Company and subsidiaries provide drilling and production services to our customers in select oil and natural gas exploration and production regions in the United States and Colombia. Our Drilling Services Division provides contract land drilling services with its fleet of 70 drilling rigs in the following locations:

As of April 24, 2009, 27 drilling rigs are operating under drilling contracts, seven of which are earning revenues through early termination fees on contracts with terms expiring in May 2009 through December 2009. We have 37 drilling rigs that are idle and six drilling rigs have been placed in storage or “cold stacked” in our Oklahoma drilling division due to low demand for drilling rigs in that region. We are actively marketing all our idle drilling rigs. We have completed construction of a 1500 horsepower drilling rig that will begin operating in May 2009 in our North Dakota drilling division under a contract with a three year term.

Our Production Services Division provides a broad range of well services to oil and gas drilling and producing companies, including workover services, wireline services, and fishing and rental services. Our production services operations are managed regionally and are concentrated in the major United States onshore oil and gas producing regions in the Gulf Coast, Mid-Continent, and Rocky Mountain states. We have a premium fleet of 74 workover rigs consisting of sixty-nine 550 horsepower rigs, four 600 horsepower rigs, and one 400 horsepower rig. As of April 24, 2009, 58 workover rigs have crews assigned and are either operating or are being actively marketed. The remaining 16 workover rigs in our fleet are idle with no crews assigned. We provide wireline services with a fleet of 61 wireline units and rental services with approximately $15 million of fishing and rental tools.

The accompanying unaudited condensed consolidated financial statements include the accounts of Pioneer Drilling Company and its wholly owned subsidiaries. All intercompany balances and transactions have been eliminated in consolidation. The accompanying unaudited condensed consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America for interim financial information and with the instructions to Form 10-Q and Rule 10-01 of Regulation S-X. Accordingly, they do not include all of the information and footnotes required by generally accepted accounting principles for complete financial statements. In the opinion of our management, all adjustments (consisting of normal, recurring accruals) necessary for a fair presentation have been included. In preparing the accompanying unaudited condensed consolidated financial statements, we make various estimates and assumptions that affect the amounts of assets and liabilities we report as of the dates of the balance sheets and income and expenses we report for the periods shown in the income statements and statements of cash flows. Our actual results could differ significantly from those estimates. Material estimates that are particularly susceptible to significant changes in the near term relate to our recognition of revenues and costs for turnkey contracts, our estimate of the allowance for doubtful accounts, our estimate of the self-insurance portion of our health and workers’ compensation liability, our estimate of asset impairments, our estimate of deferred taxes and our determination of depreciation and amortization expense. The condensed consolidated balance sheet as of December 31, 2008 has been derived from our audited financial statements. We suggest that you read these condensed consolidated financial statements together with the consolidated financial statements and the related notes included in our annual report on Form 10-K for the fiscal year ended December 31, 2008.

Our drilling contracts generally provide for compensation on either a daywork, turnkey 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 and typically permit the customer to terminate on short notice. However, we have entered into more longer-term drilling contracts during periods of high rig demand. In addition, we have entered into longer-term drilling contracts for our newly constructed rigs. As of April 24, 2009, we had 16 contracts with terms of six months to three years in duration, of which 12 will expire by October 24, 2009, one has a remaining term of six to 12 months, one has a remaining term of 12 to 18 months and two have a remaining term in excess of 18 months. We had six drilling rigs earning revenue through early termination fees under six of these longer-term contracts.

Our functional currency for our foreign subsidiary in Colombia is the U.S. dollar. Nonmonetary assets and liabilities are translated at historical rates and monetary assets and liabilities are translated at exchange rates in effect at the end of the period. Income statement accounts are translated at average rates for the period. Gains and losses from remeasurement of foreign currency financial statements into U.S. dollars and from foreign currency transactions are included in other income or expense.

As of March 31, 2009, we had restricted cash in the amount of $2.6 million held in an escrow account to be used for future payments in connection with the acquisition of Prairie Investors d/b/a Competition Wireline (“Competition”). The former owner of Competition will receive annual installments of $0.7 million payable over the remaining four years from the escrow account. Restricted cash of $0.7 million and $1.9 million is recorded in other current assets and other long term assets, respectively. The associated obligation of $0.7 million and $1.9 million is recorded in accrued expenses and other long-term liabilities, respectively.

On August 28, 2008, we deposited $0.9 million into a trust account in accordance with the terms of the severance agreement in connection with the resignation of our former Chief Financial Officer. This balance was distributed to the former Chief Financial Officer on March 3, 2009.

Inventories primarily consist of drilling rig replacement parts and supplies held for use by our Drilling Services Division’s operations and supplies held for use by our Production Services Division’s operations. Inventories are valued at the lower of cost (first in, first out or actual) or market value.

Other long-term assets include investments in tax exempt, auction rate preferred securities (“ARPS”). Our ARPSs are classified with other long-term assets on our condensed consolidated balance sheet as of March 31, 2009 because of our inability to determine the recovery period of our investments.

At March 31, 2009, we held $15.9 million (par value) of ARPSs, which are variable-rate preferred securities and have a long-term maturity with the interest rate being reset through “Dutch auctions” that are held every 7 days. The ARPSs have historically traded at par because of the frequent interest rate resets and because they are callable at par at the option of the issuer. Interest is paid at the end of each auction period. Our ARPSs are AAA/Aaa rated securities, collateralized by municipal bonds and backed by assets that are equal to or greater than 200% of the liquidation preference. Until February 2008, the auction rate securities market was highly liquid. Beginning mid-February 2008, we experienced several “failed” auctions, meaning that there was not enough demand to sell all of the securities that holders desired to sell at auction. The immediate effect of a failed auction is that such holders cannot sell the securities at auction and the interest rate on the security resets to a maximum auction rate. We have continued to receive interest payments on our ARPSs in accordance with their terms. We may not be able to access the funds we invested in our ARPSs without a loss of principal, unless a future auction is successful or the issuer calls the security pursuant to redemption prior to maturity. We have no reason to believe that any of the underlying municipal securities that collateralize our ARPSs are presently at risk of default. We believe we will ultimately be able to liquidate our investments without material loss primarily due to the collateral securing the ARPSs. We do not currently intend to attempt to sell our ARPSs since our liquidity needs are expected to be met with cash flows from operating activities and our senior secured revolving credit facility.

Our ARPSs are reported at amounts that reflect our estimate of fair value. Statement of Financial Accounting Standards (“SFAS”) No. 157, Fair Value Measurement, provides a hierarchal framework associated with the level of subjectivity used in measuring assets and liabilities at fair value. To estimate the fair values of our ARPSs, we used inputs defined by SFAS 157 as level 3 inputs which are unobservable for the asset or liability and are developed based on the best information available in the circumstances. We estimate the fair value of our ARPSs based on discounted cash flow models and secondary market comparisons of similar securities.

Our ARPSs are designated as available-for-sale and are reported at fair market value with the related unrealized gains or losses, included in accumulated other comprehensive income (loss), net of tax, a component of shareholders’ equity. The estimated fair value of our ARPSs at March 31, 2009 was $11.0 million compared with a par value of $15.9 million. The $4.9 million difference represents a fair value discount due to the current lack of liquidity which is considered temporary and has been recorded as an unrealized loss, net of tax, in accumulated other comprehensive income (loss). We recorded $2.0 million of this fair value discount during the year ended December 31, 2008 and the remaining $2.9 million was recorded during the quarter ended March 31, 2009. We would recognize an impairment charge in our statement of operations if the fair value of our investments falls below the cost basis and is judged to be other-than-temporary.

Pursuant to SFAS No. 109, “Accounting for Income Taxes,” we follow the asset and liability method of accounting for income taxes, under which we recognize deferred tax assets and liabilities for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax basis. We measure our deferred tax assets and liabilities by using the enacted tax rates we expect to apply to taxable income in the years in which we expect to recover or settle those temporary differences. Under SFAS No. 109, we reflect in income the effect of a change in tax rates on deferred tax assets and liabilities in the period during which the change occurs.

Comprehensive income is comprised of net income and other comprehensive loss. Other comprehensive loss includes the change in the fair value of our ARPSs, net of tax, for the three months ended March 31, 2009 and 2008. The following table sets forth the components of comprehensive income:

We recognize compensation cost for stock-based compensation based on the grant-date fair value estimated in accordance with SFAS No. 123 (Revised) Share-Based Payment and utilizing the graded vesting method. Compensation costs of approximately $1.0 million and $0.3 million for stock options were recognized in selling, general and administrative expense and operating costs, respectively, for the three months ended March 31, 2009. We receive a tax deduction for certain stock option exercises during the period the options are exercised, generally for the excess of the fair market value of our stock on the date of exercise over the exercise price of the options. In accordance with SFAS 123R, we reported all excess tax benefits resulting from the exercise of stock options as financing cash flows in our consolidated statement of cash flows. There were no stock options exercised during the three months ended March 31, 2009.

We estimate the fair value of each option grant on the date of grant using a Black-Scholes options-pricing model. The following table summarizes the assumptions used in the Black-Scholes option-pricing model for the three months ended March 31, 2009 and 2008.

The assumptions above are based on multiple factors, including historical exercise patterns of homogeneous groups with respect to exercise and post-vesting employment termination behaviors, expected future exercising patterns for these same homogeneous groups and volatility of our stock price. As we have not declared dividends since we became a public company, we did not use a dividend yield. In each case, the actual value that will be realized, if any, will depend on the future performance of our common stock and overall stock market conditions. There is no assurance the value an optionee actually realizes will be at or near the value we have estimated using the Black-Scholes options-pricing model.

Restricted stock awards consist of our common stock that vest over a 3 year period. The fair value of restricted stock is based on the closing price of our common stock on the date of the grant. We amortize the fair value of the restricted stock awards to compensation expense using the graded vesting method. For the three months ended March 31, 2009, 255,700 restricted stock awards were granted with a weighted-average grant date price of $3.84. Compensation costs of approximately $0.4 million and $0.1 for restricted stock awards were recognized in selling, general and administrative expense and operating costs, respectively, for the three months ended March 31, 2009.

Effective January 1, 2009, we adopted FASB Staff Position No. EITF 03-6-1 (FSP No. EITF 03-6-1), Determining Whether Instruments Granted in Share-Based Payment Transactions Are Participating Securities, which requires restricted stock granted under our stock-based compensation plans to be treated as participating securities under the two-class method of determining basic earnings per common share. Basic earnings per common share for prior periods are to be adjusted to conform to this FASB Staff Position. The adoption of FSP No. EITF 03-6-1 did not have any effect on the calculation of basic earnings per common share for the three months ended March 31, 2009 and 2008.

Our Chief Executive Officer, President of Drilling Services Division, Senior Vice President of Drilling Services Division—Marketing, and a Vice President of Drilling Services Division—Operations occasionally acquire a 1% to 5% minority working interest in oil and gas wells that we drill for one of our customers. These individuals did not acquire a minority working interest in any wells that we drilled for this customer during either the three months ended March 31, 2009 or the three months ended March 31, 2008.

In connection with the acquisitions of the production services businesses from WEDGE Group Incorporated (“WEDGE”) and Competition on March 1, 2008, we have leases for various operating and office facilities with entities that are owned by former WEDGE employees and Competition employees that are now employees of our company. Rent expense for the three months ended March 31, 2009 was approximately $0.2 million for these related party leases. In addition, we have non-compete agreements with several former WEDGE employees that are now employees of our company. These non-compete agreements are recorded as intangible assets with a cost, net of accumulated amortization, of $1.2 million as of March 31, 2009. See note 2 for further information regarding the acquisitions.

We purchased $0.1 million of goods and services during the three months ended March 31, 2009 from six vendors that are owned by employees of our company.

In December 2007, the FASB issued SFAS No. 160, Noncontrolling Interests in Consolidated Financial Statements – an Amendment of ARB No. 51. This statement establishes accounting and reporting standards for the non-controlling interest in a subsidiary and for the deconsolidation of a subsidiary. SFAS No. 160 clarifies that a non-controlling interest in a subsidiary, which is sometimes referred to as minority interest, is an ownership interest in the consolidated entity that should be reported as a component of equity in the consolidated financial statements. Among other requirements, SFAS No. 160 requires consolidated net income to be reported at amounts that include the amounts attributable to both the parent and the non-controlling interest. It also requires disclosure, on the face of the consolidated income statement, of the amounts of consolidated net income attributable to the parent and to the non-controlling interest. SFAS No.160 is effective for fiscal years beginning on or after December 15, 2008. The adoption of SFAS No. 160 on January 1, 2009 did not have a material impact on our financial position or results of operations and financial condition.

In December 2007, the FASB issued SFAS No. 141R (revised 2007) which replaces SFAS No. 141, Business Combinations (“SFAS No. 141R”). SFAS No. 141R applies to all transactions and other events in which one entity obtains control over one or more other businesses. SFAS No. 141R requires an acquirer, upon initially obtaining control of another entity, to recognize the assets, liabilities and any non-controlling interest in the acquiree at fair value as of the acquisition date. Contingent consideration is required to be recognized and measured at fair value on the date of acquisition rather than at a later date when the amount of that consideration may be determinable beyond a reasonable doubt. This fair value approach replaces the cost-allocation process required under SFAS No. 141 whereby the cost of an acquisition was allocated to the individual assets acquired and liabilities assumed based on their estimated fair value. SFAS No. 141R requires acquirers to expense acquisition-related costs as incurred rather than allocating such costs to the assets acquired and liabilities assumed, as was previously the case under SFAS No. 141. Under SFAS No.141R, the requirements of SFAS No. 146, Accounting for Costs Associated with Exit or Disposal Activities, would have to be met in order to

accrue for a restructuring plan in purchase accounting. SFAS No. 141R had no impact on our financial position or results of operations and financial condition, since we have not had any business combinations closing on or after the January 1, 2009 effective date.

In April 2009 the FASB issued FASB Staff Position 141(R)-1, Accounting for Assets Acquired and Liabilities Assumed in a Business Combination That Arise from Contingencies (“FSP 141(R)-1”). FSP 141(R)-1 amends the provisions in Statement 141(R) for the initial recognition and measurement, subsequent measurement and accounting, and disclosures for assets and liabilities arising from contingencies in business combinations. This FASB Staff Position eliminates the distinction between contractual and non-contractual contingencies, including the initial recognition and measurement criteria in Statement 141(R) and instead carries forward most of the provisions in SFAS 141 for acquired contingencies. FSP 141(R)-1 is effective for contingent assets and contingent liabilities acquired in business combinations for which the acquisition date is on or after the beginning of the first annual reporting period beginning on or after December 15, 2008. FSP 141(R)-1 had no impact on our financial position or results of operations and financial condition, since we have not had any business combinations closing on or after the January 1, 2009 effective date.

In March 2008, the FASB issued SFAS No. 161, Disclosures about Derivative Instruments and Hedging Activities—an amendment of FASB Statement No. 133 (“SFAS No. 161”). SFAS No. 161 changes the disclosure requirements for derivative instruments and hedging activities. Entities are required to provide enhanced disclosures about (a) how and why an entity uses derivative instruments, (b) how derivative instruments and related hedged items are accounted for under Statement 133 and its related interpretations, and (c) how derivative instruments and related hedged items affect an entity’s financial position, financial performance, and cash flows. The guidance in SFAS No. 161 is effective for financial statements issued for fiscal years and interim periods beginning after November 15, 2008, with early application encouraged. This Statement encourages, but does not require, comparative disclosures for earlier periods at initial adoption. We do not have any derivative instruments and the January 1, 2009 adoption of SFAS No. 161 had no impact on our financial statement disclosures.

In April 2009, the FASB issued Staff Position FAS 157-4, Determining Fair Value When the Volume and Level of Activity for the Asset or Liability Have Significantly Decreased and Identifying Transactions That Are Not Orderly (“FSP FAS 157-4”). This FSP provides additional guidance for estimating fair value in accordance with Statement No. 157, Fair Value Measurements, when the volume and level of activity for the asset or liability have significantly decreased and provides additional guidance on the Statement No. 157 disclosure requirements. This FSP also includes guidance on identifying circumstances that indicate a transaction is not orderly. FSP FAS 157-4 is effective for interim and annual reporting periods ending after June 15, 2009, and should be applied prospectively. Early adoption is permitted for periods ending after March 15, 2009. We will adopt FSP FAS 157-4 for our quarter ending June 30, 2009. FSP FAS 157-4 is not expected to have a material impact on our financial position or results of operations.

In April 2009, the FASB issued Staff Position FAS 115-2 and FAS 124-2 Recognition and Presentation of Other-than-temporary Impairments (FSP FAS 115-2 and 124-2). FSP FAS 115-2 and 124-2 amends Statements No. 115, Accounting for Certain Investments in Debt and Equity Securities, and Statement No. 124, Accounting for Certain Investments Held by Not-for-Profit Organizations, to modify the indicator of other-than-temporary impairment for debt securities. Additionally, this FSP changes the amount of an other-than-temporary impairment that is recognized in earnings when there are credit losses on a debt security that management does not intend to sell and it is more-likely-than-not that the entity will not have to sell prior to recovery of the noncredit impairment. In those situations, the portion of the total impairment that is attributable to the credit loss would be recognized in earnings, and the remaining difference between the debt security’s amortized cost basis and its fair value would be included in other comprehensive income. FSP FAS 115-2 and 124-2 is effective for interim and annual reporting periods ending after June 15, 2009, with early adoption permitted for periods ending after March 15, 2009. We are currently assessing the impact of adoption of FSP FAS 115-2 and FAS 124-2 on our financial position and results of operations as of, and for the period ending, June 30, 2009.

On March 1, 2008, we acquired the production services business from WEDGE which provided well services, wireline services and fishing and rental services with a fleet of 62 workover rigs, 45 wireline units and approximately $13 million of fishing and rental equipment through its facilities in Texas, Kansas, North Dakota, Colorado, Utah and Oklahoma. The aggregate purchase price for the acquisition was approximately $314.7 million, which consisted of assets acquired of $340.8 million and liabilities assumed of $26.1 million. The aggregate purchase price includes $3.4 million of costs incurred to acquire the production services business from WEDGE. We financed the acquisition with approximately $3.2 million of cash on hand and $311.5 million of debt incurred under our senior secured revolving credit facility described in Note 3.

The following table summarizes the allocation of the purchase price and related acquisition costs to the estimated fair value of the assets acquired and liabilities assumed as of the date of acquisition (amounts in thousands):

The following unaudited pro forma consolidated summary financial information gives effect of the acquisition of the production services business from WEDGE as though it was effective as of the beginning of the three month periods ended March 31, 2008. Pro forma adjustments primarily relate to additional depreciation, amortization and interest costs. The pro forma information reflects our company’s historical data and historical data from the acquired production services business from WEDGE for the periods indicated. The pro forma data may not be indicative of the results we would have achieved had we completed the acquisition on January 1, 2008, or what we may achieve in the future and should be read in conjunction with the accompanying historical financial statements.

On March 1, 2008, immediately following the acquisition of the production services business from WEDGE, we acquired the production services business from Competition which provided wireline services with a fleet of 6 wireline units through its facilities in Montana. The aggregate purchase price for the Competition acquisition was approximately $30.0 million, which consisted of assets acquired of $30.1 million and liabilities assumed of $0.1 million. The aggregate purchase price includes $0.4 million of costs incurred to acquire the production services business from Competition. We financed the acquisition with $26.7 million cash on hand and a note payable due to the prior owner for $3.3 million. Goodwill of $5.3 million and intangible assets and other assets of $18.0 million were recorded in connection with the acquisition.

On August 29, 2008, we acquired the wireline services business from Paltec, Inc. The aggregate purchase price was $7.8 million which we financed with $6.5 million in cash and a sellers note of $1.3 million. Intangible and other assets of $4.3 million and goodwill of $0.1 million were recorded in connection with the acquisition.

On October 1, 2008, we acquired the well services business from Pettus Well Service. The aggregated purchase price was $3.0 million which we financed with $2.8 million in cash and a sellers note of $0.2 million. Intangible and other assets of $1.2 million and goodwill of $0.1 million were recorded in connection with acquisition.

The acquisitions of the production services businesses from WEDGE, Competition, Paltec and Pettus were accounted for as acquisitions of businesses. The purchase price allocations for these production services businesses have been finalized as of December 31, 2008. Goodwill was recognized as part of the WEDGE, Competition, Paltec and Pettus acquisitions since the purchase price exceeded the estimated fair value of the assets acquired and liabilities assumed. The goodwill was related to the acquired workforces, expected synergies between our Drilling Services Division and our Production Services Division and the ability to expand our service offerings. These acquisitions occurred between March 1, 2008 and October 1, 2008, when production service revenues, margins and cash flows and our market capitalization were at historically high levels. Our goodwill impairment analysis performed at December 31, 2008 led us to conclude that there would be no remaining implied value attributable to our goodwill and accordingly, we recorded a non-cash charge of $118.6 million for a full impairment of goodwill relating to these acquisitions. We also performed an impairment analysis at December 31, 2008 which resulted in an impairment charge of $52.8 million and reduction

in the intangible asset carrying value of customer relationships relating to these acquisitions. These impairment charges were primarily related to significant adverse changes in the economic and business climate that began during the fourth quarter of the year ended December 31, 2008.

Long-term debt as of March 31, 2009 consists of the following (amounts in thousands):

On February 29, 2008, we entered into a credit agreement with Wells Fargo Bank, N.A. and a syndicate of lenders (collectively the “Lenders”). The credit agreement provides for a senior secured revolving credit facility, with sub-limits for letters of credit and a swing-line facility of up to an aggregate principal amount of $400 million, all of which mature on February 28, 2013. The senior secured revolving credit facility and the obligations thereunder are secured by substantially all our domestic assets and are guaranteed by certain of our domestic subsidiaries. Borrowings under the senior secured revolving credit facility bear interest, at our option, at the bank prime rate or at the LIBOR rate, plus an applicable per annum margin in each case. The applicable per annum margin is determined based upon our leverage ratio in accordance with a pricing grid in the credit agreement. The per annum margin for LIBOR rate borrowings ranges from 1.50% to 2.50% and for bank prime rate borrowings ranges from 0.50% to 1.50%. Based on the terms in the credit agreement, the LIBOR margin and bank prime rate margin in effect until delivery of our financial statements and the compliance certificate for March 31, 2009 are 1.75% and 0.75%, respectively. A commitment fee is due quarterly based on the average daily unused amount of the commitments of the Lenders under the senior secured revolving credit facility. In addition, a fronting fee is due for each letter of credit issued and a quarterly letter of credit fee is due based on the average undrawn amount of letters of credit outstanding during such period. We may repay the senior secured revolving credit facility balance outstanding in whole or in part at any time without premium or penalty. Borrowings under the senior secured revolving credit facility were used to fund the WEDGE acquisition and are available for future acquisitions, working capital and other general corporate purposes.

At April 24, 2009, we had $257.5 million outstanding under the revolving portion of the senior secured revolving credit facility and $10.4 million in committed letters of credit. Under the terms of the credit agreement, committed letters of credit are applied against our borrowing capacity under the senior secured revolving credit facility. The borrowing availability under the senior secured revolving credit facility was $132.1 million at April 24, 2009. There are no limitations on our ability to access the full borrowing availability under the senior secured revolving credit facility other than maintaining compliance with the covenants in the credit agreement. The outstanding balance under our senior secured credit facility is not due until maturity on February 28, 2013. However, when cash and working capital is sufficient, we may make principal payments to reduce the outstanding debt balance prior to maturity.

At March 31, 2009, we were in compliance with the restrictive covenants contained in the credit agreement which include the following:

At March 31, 2009, our consolidated leverage ratio was 1.34 to 1.00 and our interest coverage ratio was 15.13 to 1.00. The credit agreement has additional restrictive covenants that, among other things, limit the incurrence of additional debt to a maximum of $15 million (other than debt under the senior secured revolving credit facility), investments, liens, dividends, acquisitions, redemptions of capital stock, prepayments of indebtedness, asset dispositions, mergers and consolidations, transactions with affiliates, capital expenditures, hedging contracts, sale leasebacks and other matters customarily restricted in such agreements. In addition, the credit agreement contains customary events of default, including without limitation, payment defaults, breaches of representations and

warranties, covenant defaults, cross-defaults to certain other material indebtedness in excess of specified amounts, certain events of bankruptcy and insolvency, judgment defaults in excess of specified amounts, failure of any guaranty or security document supporting the credit agreement and change of control. While we are currently in compliance with the covenants in the credit agreement, if utilization rates and revenue rates remain at depressed levels throughout 2009, we could potentially experience difficulty remaining in compliance with such covenants beginning in the fourth quarter of 2009. We are monitoring our compliance with such covenants and, based on preliminary discussions with our lenders, we currently believe that we will be able to negotiate some relief with respect to such covenants. However, such relief would likely result in additional costs in the form of increased interest rates, additional fees or modification of other terms. In addition, there can be no assurance that we will be able to maintain compliance with the covenants in the credit agreement, negotiate any relief from such covenants, or that the costs associated with such relief will be commercially reasonable. Non-compliance with restrictive covenants or other events of default under the credit agreement could trigger an early repayment requirement and terminate the senior secured revolving credit facility.

In addition to amounts outstanding under the senior secured revolving credit facility, long-term debt includes subordinated notes payable to certain employees that are former shareholders of the production services businesses that were acquired by WEDGE prior to our acquisition of WEDGE on March 1, 2008, a subordinated note payable to an employee that is a former shareholder of Competition, two subordinated notes payable to certain employees that are former shareholders of Paltec, Inc. and Pettus Well Service. These subordinated notes payable have interest rates ranging from 5.4% to 14%, require quarterly or annual payments of principal and interest and have final maturity dates ranging from April 2009 to March 2013. The aggregate outstanding balance of these subordinated notes payable was $5.5 million as of March 31, 2009.

Other debt represents financing arrangements for computer software with an outstanding balance of $0.3 million at March 31, 2009.

In connection with our expansion into international markets, our foreign subsidiaries have obtained bonds for bidding on drilling contracts, performing under drilling contracts, and remitting customs and importation duties. We have guaranteed payments of $34.9 million relating to our performance under these bonds.

In addition, 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. Legal costs relating to these matters are expensed as incurred. 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, results of operations or cash flow from operations.

The following table presents a reconciliation of the numerators and denominators of the basic earnings per share and diluted earnings per share computations (amounts in thousands, except per share data):

Employees and former employees exercised stock options for the purchase of 138,000 shares of common stock during the three months ended March 31, 2008 at prices ranging from $3.70 to $10.31 per share. Employees and former employees did not exercise any stock options during the three months ended March 31, 2009.

Employees were awarded 255,700 shares of restricted stock with a weighted-average grant date price of $3.84 during the three months ended March 31, 2009.

At March 31, 2009, we had two operating segments referred to as the Drilling Services Division and the Production Services Division which is the basis management uses for making operating decisions and assessing performance. Prior to our acquisitions of the production services businesses from WEDGE and Competition on March 1, 2008, all our operations related to the Drilling Services Division and we reported these operations in a single operating segment. The acquisitions of the production services businesses from WEDGE and Competition resulted in the formation of our Production Services Division. See Note 2.

Drilling Services Division – Our Drilling Services Division provides contract land drilling services with its fleet of 70 drilling rigs in the following locations:

Production Services Division – Our Production Services Division provides a broad range of well services to oil and gas drilling and producing companies, including workover services, wireline services, and fishing and rental services. Our production services operations are managed regionally and are concentrated in the major United States onshore oil and gas producing regions in the Gulf Coast, Mid-Continent, and Rocky Mountain states. We have a premium fleet of 74 workover rigs consisting of sixty-nine 550 horsepower rigs, four 600 horsepower rigs, and one 400 horsepower rig. We provide wireline services with a fleet of 61 wireline units and rental services with approximately $15 million of fishing and rental tools.

The following tables set forth certain financial information for our two operating segments and corporate (amounts in thousands):

The following table reconciles the segment profits reported above to income from operations as reported on the condensed consolidated statements of operations (amounts in thousands):

The following table sets forth certain financial information for our international operations in Colombia which is included in our Drilling Services Division (amounts in thousands):

Statements we make in the following discussion that express a belief, expectation or intention, as well as those that 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, the availability, terms and deployment of capital, future compliance with covenants under our senior secured revolving credit facility, the availability of qualified personnel, and changes in, or our failure or inability to comply with, government regulations, including those relating to the environment. We have discussed many of these factors in more detail elsewhere in this report and in our Annual Report on Form 10-K for the year ended December 31, 2008. These factors are not necessarily all the important factors that could affect us. Unpredictable or unknown factors we have not discussed in this report or in our Annual Report on Form 10-K for the year ended December 31, 2008 could also have material adverse effect on actual results of matters that are the subject of our forward-looking statements. All forward-looking statements speak only as the date on which they are made and we undertake no duty to update or revise any forward-looking statements. We advise our shareholders 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.

Pioneer Drilling Company provides drilling services and production services to independent and major oil and gas exploration and production companies throughout the United States and internationally in Colombia. Our company was incorporated in 1979 as the successor to a business that had been operating since 1968. Our business has grown through acquisitions and through organic growth. Over the last 10 years, we have significantly expanded our drilling rig fleet by adding 38 rigs through acquisitions and by adding 27 rigs through the construction of rigs from new and used components. On March 1, 2008, we significantly expanded our service offerings when we acquired the production services businesses of WEDGE Group Incorporated (“WEDGE”) for $314.7 million and Prairie Investors d/b/a Competition Wireline (“Competition”) for $30.0 million which provide well services, wireline services and fishing and rental services. We funded the WEDGE acquisition primarily with $311.5 million of borrowings under our $400 million senior secured revolving credit facility. As of April 24, 2009, the senior secured revolving credit facility had an outstanding balance of $257.5 million, all of which matures in February 2013. Drilling services and production services are fundamental to establishing and maintaining the flow of oil and natural gas throughout the productive life at a well site and enable us to meet multiple needs of our customers.

We currently conduct our operations through two operating segments: our Drilling Services Division and our Production Services Division. The following is a description of these two operating segments. Financial information about our operating segments is included in Note 7, Segment Information, of the Notes to Condensed Consolidated Financial Statements, included in Part I, Item I, Financial Statements, of this Quarterly Report on Form 10-Q.

through competitive bidding or through direct negotiations with customers. Our drilling contracts generally provide for compensation on either a daywork, turnkey 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.

Pioneer Drilling Company’s corporate office is located at 1250 N.E. Loop 410, Suite 1000, San Antonio, Texas 78209. Our phone number is (210) 828-7689 and our website address is www.pioneerdrlg.com. We make available free of charge though our website our Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K, and all amendments to those reports as soon as reasonably practicable after such material is electronically filed with the Securities and Exchange Commission (the “SEC”). Information on our website is not incorporated into this report or otherwise made part of this report.

Since late 2008, there has been substantial volatility and a decline in oil and natural gas prices due to the deteriorating global economic environment. In addition, there has been substantial uncertainty in the capital markets and access to financing is uncertain. These conditions have adversely affected our business environment. Our customers have curtailed their drilling programs and reduced their production activities, which has resulted in a decrease in demand for drilling and production services and a reduction in day rates and utilization. In addition, certain of our customers could experience an inability to pay suppliers in the event they are unable to access the capital markets to fund their business operations.

Demand for oilfield services offered by our industry is a function of our customers’ willingness to make operating and capital expenditures to explore for, develop and produce hydrocarbons, which in turn is affected by current and expected levels of oil and natural gas prices. Since 2004, domestic exploration and production spending increased as oil and natural gas prices increased. Oil and natural gas prices have declined significantly since late 2008 in a deteriorating global economic environment and exploration and production companies have announced cuts in their exploration budgets for 2009. These reductions in oil and gas exploration budgets resulted in a reduction in our rig utilization and revenue rates on new contracts during the three months ended March 31, 2009. Rig utilization and revenue rates are expected to remain at depressed levels for the remainder of 2009. In addition, we may experience a shift to more turnkey and footage drilling contracts from daywork drilling contracts. For additional information concerning the effects of the volatility in oil and gas prices and uncertainty in capital markets, see Item 1A—“Risk Factors” in Part I of our Annual Report on Form 10-K for the year ended December 31, 2008.

On April 24, 2009 the spot price for West Texas Intermediate crude oil was $50.80, the spot price for Henry Hub natural gas was $3.29 and the Baker Hughes land rig count was 899, a 49% decrease from 1,750 on April 25, 2008. The average weekly spot prices of West Texas Intermediate crude oil and Henry Hub natural gas, the average weekly domestic land rig count per the Baker Hughes land rig count, and the average monthly domestic workover rig count for the three months ended March 31, 2009, and each of the previous five years ended March 31, 2009:

Increased expenditures for exploration and production activities generally lead to increased demand for our drilling services and production services. Over the past several years until late 2008, rising oil and natural gas prices and the corresponding increase in onshore oil and natural gas exploration and production spending led to expanded drilling and well service activity as reflected by the increases in the U.S. land rig counts and U.S. workover rig counts as noted in the table above.

Exploration and production spending is generally categorized as either a capital expenditure or an operating expenditure. Activities designed to add hydrocarbon reserves are classified as capital expenditures, while those associated with maintaining or accelerating production are categorized as operating expenditures. Our business is influenced substantially by both operating and capital expenditures by exploration and production companies.

Capital expenditures by oil and gas companies tend to be relatively sensitive to volatility in oil or natural gas prices because project decisions are tied to a return on investment spanning a number of years. As such, capital expenditure economics often require the use of commodity price forecasts which may prove inaccurate in the amount of time required to plan and execute a capital expenditure project (such as the drilling of a deep well). When commodity prices are depressed for even a short period of time, capital expenditure projects are routinely deferred until prices return to an acceptable level.

In contrast, both mandatory and discretionary operating expenditures are more stable than capital expenditures for exploration. Mandatory operating expenditure projects involve activities that cannot be avoided in the short term, such as regulatory compliance, safety, contractual obligations and certain projects to maintain the well and related infrastructure in operating condition. Discretionary operating expenditure projects may not be critical to the short-term viability of a lease or field, but these projects are less sensitive to commodity price volatility as compared to capital expenditures for exploration. Discretionary operating expenditure work is evaluated according to a simple short-term payout criterion which is far less dependent on commodity price forecasts.

In past years, our strategy was to become a premier land drilling company through steady and disciplined growth. We executed this strategy by acquiring and building a high quality drilling rig fleet that operates in active drilling markets in the United States. Our long-term strategy is to maintain and leverage our position as a leading land drilling company and evolve into a premier multi-service, international oilfield services provider. The key elements of this long-term strategy include:

With the declines in oil and natural gas prices due to the deteriorating global economic environment since late 2008 and the reductions in our rig utilization and revenue rates on new contracts in 2009, our near-term strategy is focused on maintaining adequate liquidity. Management has initiated certain cost reduction measures including workforce and wage rate reductions that will reduce operating expenses during the downturn in the industry cycle. Budgeted capital expenditures for 2009 represent routine capital expenditures necessary to keep our equipment in safe and efficient working order and limited discretionary capital expenditures of new equipment or upgrades of existing equipment. In addition, our marketing initiatives are focused on identifying regional opportunities and evaluating more turnkey drilling contract opportunities. We believe this near-term strategy will position us to take advantage of business opportunities and continue our long-term growth strategy.

Our principal sources of liquidity consist of: (i) cash and cash equivalents (which equaled $30.0 million as of March 31, 2009); (ii) cash generated from operations; and (iii) the unused portion of our senior secured revolving credit facility which has borrowing availability of $132.1 million as of April 24, 2009. There are no limitations on our ability to access the full borrowing availability under the senior secured revolving credit facility other than maintaining compliance with the covenants in the credit agreement. Additional information regarding these covenants is provided in the Debt Requirements section below. Our principal liquidity requirements have been for working capital needs, capital expenditures and acquisitions.

their terms. Unless a future auction is successful or the issuer calls the security pursuant to redemption prior to maturity, we may not be able to access the funds we invested in our ARPSs without a loss of principal. We have no reason to believe that any of the underlying municipal securities that collateralize our ARPSs are presently at risk of default. We believe we will ultimately be able to liquidate our investments without material loss primarily due to the collateral securing the ARPSs. We do not currently intend to attempt to sell our ARPSs at a discount since our liquidity needs are expected to be met with cash flows from operating activities and our senior secured revolving credit facility. Our ARPSs are designated as available-for-sale and are reported at fair market value with the related unrealized gains or losses, included in accumulated other comprehensive income (loss), net of tax, a component of shareholders’ equity. The estimated fair value of our ARPSs at March 31, 2009 was $11.0 million compared with a par value of $15.9 million. The $4.9 million difference represents a fair value discount due to the current lack of liquidity which is considered temporary and is recorded as an unrealized loss. We would recognize an impairment charge if the fair value of our investments falls below the cost basis and is judged to be other-than-temporary. Our ARPSs are classified with other long-term assets on our condensed consolidated balance sheet as of March 31, 2009 because of our inability to determine the recovery period of our investments.

For the three months ended March 31, 2009, we had $26.7 million of additions to our property and equipment. For the remainder of fiscal year 2009, we project capital expenditures to be approximately $57.8 million, comprised of new rig and equipment expenditures of approximately $5.8 million, routine capital expenditures of approximately $18.5 million, and non-routine capital expenditures of approximately $33.5 million. We expect to fund these capital expenditures primarily from operating cash flow in excess of our working capital and other normal cash flow requirements and availability under our senior secured revolving credit facility. Based on our near-term strategy to maintain adequate liquidity, budgeted capital expenditures for 2009 represent routine capital expenditures necessary to keep our equipment in safe and efficient working order and limited discretionary capital expenditures of new equipment or upgrades of existing equipment.

Our working capital was $67.3 million at March 31, 2009, compared to $64.4 million at December 31, 2008. Our current ratio, which we calculate by dividing our current assets by our current liabilities, was 2.3 at March 31, 2009 compared to 1.8 at December 31, 2008.

Our operations have historically generated cash flows sufficient to at least meet our requirements for debt service and normal capital expenditures. However, during periods when higher percentages of our drilling contracts are turnkey and footage contracts, our short-term working capital needs could increase.

The increase in cash and cash equivalents was due to cash provided by operations of $43.9 million offset by $24.8 million of property and equipment expenditures and $16.1 million of debt payments.

The decreases in our receivables and unbilled revenues as of March 31, 2009 as compared to December 31, 2008 were primarily due to the decrease in revenues of $69.9 million, or 41%, for the quarter ended March 31, 2009 as compared to the quarter ended December 31, 2008.

The increase in inventory at March 31, 2009 as compared to December 31, 2008 was primarily due to additional inventory needed for our fourth and fifth drilling rigs that began operating in Colombia in August 2008 and November 2008. We maintain inventories of replacement parts and supplies for our drilling rigs operating in Colombia to ensure efficient operations in geographically remote areas.

The decrease in prepaid expenses and other current assets at March 31, 2009 as compared to December 31, 2008 is primarily due to a decrease in prepaid insurance. We renew and prepay most of our insurance premiums in late October of each year and some in April of each year. As of March 31, 2009, we had amortization of five months of these October insurance premiums, as compared to two months of amortization as of December 31, 2008. In addition, prepaid expenses and other current assets decreased by $0.9 million relating to funds held in a trust account that were distributed to our former Chief Financial Officer on March 2, 2009 in accordance with the terms of the severance agreement and $0.7 million relating to funds held in escrow that were paid to the former owner of Competition.

The decrease in accounts payable at March 31, 2009 as compared to December 31, 2008 is due to the decline in demand for drilling, workover, wireline and fishing and rental services during the quarter ended March 31, 2009 as compared to the quarter ended December 31, 2008, which resulted in decreased purchases from vendors.

The outstanding balance under our senior secured credit facility is not due until maturity on February 28, 2013. However, when cash and working capital is sufficient, we may make principal payments to reduce the outstanding debt balance prior to maturity. The current portion of long-term debt at December 31, 2008 included principal payments of $15 million that were made after December 31, 2008 to reduce the outstanding balance of our senior secured revolving credit facility. We have not made any principal payments to reduce the outstanding balance of our senior secured revolving credit facility after March 31, 2009. Therefore, no portion of the outstanding balance of our senior secured revolving credit facility is included in the current portion of long-term debt at March 31, 2009.

Prepaid drilling contracts represent amounts billed for mobilization revenues in excess of revenue recognized for certain drilling contracts in Colombia. Mobilization billings, and costs incurred for the mobilization, are deferred and recognized over the term of the related drilling contracts. As of March 31, 2009, the initial terms of these drilling contracts had concluded and all associated mobilization revenues had been recognized.

The decrease in accrued payroll and related employee costs was primarily due to a decrease of $3.9 million in accrued employee bonuses as of March 31, 2009 as compared to December 31, 2008. Annual employee bonuses for the year ended December 31, 2008 were paid in early March 2009. In addition, accrued payroll and related employee costs decreased due to workforce reductions that occurred during the quarter ended March 31, 2009.

The increase in accrued insurance premiums and deductibles was primarily due to increases in costs incurred for the self-insurance portion of our health insurance and other insurance costs during the quarter ended March 31, 2009 as compared to December 31, 2008.

The decrease in accrued expenses – other at March 31, 2009 as compared to December 31, 2008 is primarily due to property tax accruals. We accrue property taxes throughout the year and make most of our required property tax payments in January.

Long-term debt as of March 31, 2009 consists of the following (amounts in thousands):

The following table includes all our contractual obligations of the types specified below at March 31, 2009 (amounts in thousands):

Long-term debt consists of $257.5 million outstanding under our senior secured credit facility, $5.5 million outstanding under subordinated notes payable to certain employees that are former shareholders of previously acquired production services businesses and other debt of $0.3 million. The outstanding balance under our senior secured credit facility is not due until maturity on February 23, 2013. We may make principal payments to reduce the outstanding debt balance prior to maturity when cash and working capital is sufficient.

Interest payment obligations on our senior secured credit facility are estimated based on interest rates that are in effect on April 24, 2009 and the remaining principal balance of $257.5 million to be paid at maturity in February 2013. Interest payment obligations on our subordinated notes payable are based on interest rates ranging from 5.4% to 14%, with quarterly payments of principal and interest and final maturity dates ranging from April 2009 to March 2013.

Purchase obligations primarily relate to drilling rig and well servicing rig upgrades, acquisitions or new construction.

Operating leases consist of lease agreements with terms in excess of one year for office space, operating facilities, equipment and personal property.

As of March 31, 2009, we had restricted cash in the amount of $2.6 million held in an escrow account to be used for future payments in connection with the acquisition of Competition. The former owner of Competition will receive annual installments of $0.7 million payable over a five year term from the escrow account.

At March 31, 2009, we were in compliance with the restrictive covenants contained in the credit agreement which include the following:

the credit agreement and change of control. While we are currently in compliance with the covenants in the credit agreement, if utilization rates and revenue rates remain at depressed levels throughout 2009, we could potentially experience difficulty remaining in compliance with such covenants beginning in the fourth quarter of 2009. We are monitoring our compliance with such covenants and, based on preliminary discussions with our lenders, we currently believe that we will be able to negotiate some relief with respect to such covenants. However, such relief would likely result in additional costs in the form of increased interest rates, additional fees or modification of other terms. In addition, there can be no assurance that we will be able to maintain compliance with the covenants in the credit agreement, negotiate any relief from such covenants, or that the costs associated with such relief will be commercially reasonable. Non-compliance with restrictive covenants or other events of default under the credit agreement could trigger an early repayment requirement and terminate the senior secured revolving credit facility.

Effective March 1, 2008, we acquired the production services businesses of WEDGE and Competition which provide well services, wireline services and fishing and rental services The acquisitions of the production services businesses of WEDGE and Competition resulted in the formation of our new operating segment, the Production Services Division. We consolidated the results of these acquisitions from the day they were acquired. These acquisitions affect the comparability from period to period of our historical results, and our historical results may not be indicative of our future results.

The following table provides information for our operations for the three months ended March 31, 2009 and 2008 (amounts in thousands, except average number of drilling rigs, utilization rate and revenue days information):

We present Drilling Services Division margin, Production Services Division margin, combined margin and earnings before interest, taxes, depreciation and amortization (EBITDA) information because we believe it provides investors and our management additional information to assist them in assessing our business and performance in comparison to other companies in our industry. Since Drilling Services Division margin, Production Services Division margin, combined margin and EBITDA are “non-GAAP” financial measure under the rules and regulations of the SEC, we are providing the following reconciliation of combined margin and EBITDA to net (loss) earnings, which is the nearest comparable GAAP financial measure.

Our Drilling Services Division’s revenues decreased by $28.7 million, or 29%, for the quarter ended March 31, 2009, as compared to the corresponding quarter in 2008, due to a 34% decrease in revenue days that resulted from decline in our rig utilization rate from 84% to 52%. The decrease in our Drilling Services Divisions revenues was partially offset by an increase in average contract drilling revenues of $1,768 per day, or 9%. The demand for drilling rigs has decreased during 2009 as compared to 2008 resulting in lower revenues per day on new contracts. However, a significant portion of our drilling rigs were operating during the quarter ended March 31, 2009 under longer-term drilling contracts that were entered into when drilling rig demand was high and revenues per day were at historically high levels.

Our Drilling Services Division’s operating costs declined by $19.4 million, or 31%, for the quarter ended March 31, 2009, as compared to the corresponding period in 2008, primarily due to a 34% decrease in revenue days that resulted from a decline in our rig utilization rate from 84% to 52%. The decrease in our Drilling Services Division’s operating costs was partially offset by an increase in average operating costs of $767 per day, or 6%, primarily due to fixed overhead costs associated with division offices, supervisory level employees and insurance. Since we had a significant decrease in revenue days, these fixed overhead costs result in an increase in average operating costs per revenue day.

Our Production Services Division’s revenue increased by $16.1 million and operating costs increased by $11.8 million for the quarter ended March 31, 2009, as compared to the corresponding quarter in 2008. Our Production Services Division was created on March 1, 2008 when we acquired the production services businesses of WEDGE and Competition. Therefore, three months of Production Services Division operating results are reflected in the quarter ended March 31, 2009, as compared to one month of operating results for the quarter ended March 31, 2008. These increases in Production Services Division revenue and operating costs were partially offset by revenue and operating cost decreases resulting from lower demand for well services, wireline services and fishing and rental services during the quarter ended March 31, 2009, as compared to the corresponding period in 2008.

Our selling, general and administrative expense for the quarter ended March 31, 2009 increased by approximately $2.3 million, or 30%, compared to the corresponding quarter in 2008, primarily due to an increase of $2.8 million in selling, general and administrative expenses relating to our Production Services Division. As noted above, three months of Production Services Division operating results are reflected in the quarter ended March 31, 2009, as compared to one month of operating results for the quarter ended March 31, 2008. The overall increase in selling, general and administrative expense was partially offset by a decrease in professional and consulting expenses for the quarter ended March 31, 2009, as compared to the quarter ended March 31, 2008.

Our other income (expense) for the quarter ended March 31, 2009 decreased by $1.6 million compared to the corresponding quarter in 2008, primarily due to foreign currency translation gains and losses relating to our operations in Colombia. We recorded foreign currency translation losses of $0.7 million for the quarter ended March 31, 2009 and foreign currency translation gains of $1.0 million for the quarter ended March 31, 2008.

Our depreciation and amortization expenses increased by $8.3 million, or 49%, for the quarter ended March 31, 2009 when compared to the corresponding period in 2008. The increases resulted primarily from additional depreciation and amortization expense of $4.5 million for our new Production Services Division. As noted above, we have three months of Production Services Division operating results are reflected in the quarter ended March 31, 2009, as compared to one month of operating results for the quarter ended March 31, 2008. The remaining portion of the increase is due to the increases in the average size of our drilling rig fleet, which increases consisted of newly constructed rigs, and other fixed asset additions.

Interest expense for the quarters ended March 31, 2009 and March 31, 2008 are primarily related to interest due on the amounts outstanding under our new senior secured revolving credit facility which was first used to fund the acquisitions of the production services businesses of WEDGE and Competition on March 1, 2008.

Our effective income tax rate for the quarter ended March 31, 2009 differs from the federal statutory rate in the United States of 35% primarily due to pretax income recognized in foreign jurisdictions with a lower effective tax rate, tax benefits recognized for previously unrecognized deferred tax assets and state income taxes.

Due to the increased rig count in each of our market areas over the past several years, availability of personnel to operate our rigs was limited. In April 2005, January 2006, May 2006 and September 2008, we raised wage rates for our drilling rig personnel by an average of 6%, 6%, 14% and 6%, respectively. We were able to pass these wage rate increases on to our customers based on contract terms. In February 2009, we reduced wage rates for drilling rig personnel to offset the wage rate increases from September 2008. We do not expect wage rate increases during the remainder of fiscal year ending December 31, 2009.

During the fiscal years ended December 31, 2007 and 2008, we experienced increases in costs for rig repairs and maintenance and costs of rig upgrades and new rig construction, due to the increased industry-wide demand for equipment, supplies and service. We estimate these costs increased by 10% to 15% during the fiscal years ended December 31, 2007 and 2008. We do not expect similar cost increases during the fiscal year ending December 31, 2009.

Revenue and cost recognition – Our Drilling Services Division earns revenues by drilling oil and gas wells for our customers under daywork, turnkey or footage contracts, which usually provide for the drilling of a single well. We recognize revenues on daywork contracts for the days completed based on the dayrate each contract specifies. We recognize revenues from our turnkey and footage contracts on the percentage-of-completion method based on our estimate of the number of days to complete each contract. Individual contracts are usually completed in less than 60 days. The risks to us under a turnkey contract and, to a lesser extent, under footage contracts, are substantially greater than on a contract drilled on a daywork basis. Under a turnkey contract, we assume most of the risks associated with drilling operations that are generally assumed by the operator in a daywork contract, including the risks of blowout, loss of hole, stuck drill pipe, machinery breakdowns and abnormal drilling conditions, as well as risks associated with subcontractors’ services, supplies, cost escalations and personnel operations.

Our management has determined that it is appropriate to use the percentage-of-completion method, as defined in the American Institute of Certified Public Accountants’ Statement of Position 81-1, to recognize revenue on our turnkey and footage contracts. Although our turnkey and 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-on 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 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-on depth in breach of the applicable contract. However, in the event we were unable to drill to the agreed-on depth in breach of the contract, ultimate recovery of that value would be subject to negotiations with the customer and the possibility of litigation.

If a customer defaults on its payment obligation to us under a turnkey or footage contract, we would need to rely on applicable law to enforce our lien rights, because our turnkey and 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 also would 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 turnkey or footage contract.

We accrue estimated contract costs on turnkey and 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, operating overhead allocations and allocations of depreciation and amortization expense. In addition, the occurrence of uninsured or under-insured losses or operating cost overruns on our turnkey and footage contracts could have a material adverse effect on our financial position and results of operations. Therefore, our actual results for a contract could differ significantly if our cost estimates for that contract are later revised from our original cost estimates for a contract in progress at the end of a reporting period which was not completed prior to the release of our financial statements.

With most drilling contracts, we receive payments contractually designated for the mobilization of rigs and other equipment. Payments received, and costs incurred for the mobilization services are deferred and recognized on a straight line basis over the contract term of certain drilling contracts. Costs incurred to relocate rigs and other drilling equipment to areas in which a contract has not been secured are expensed as incurred. Reimbursements that we receive for out-of-pocket expenses are recorded as revenue and the out-of-pocket expenses for which they relate are recorded as operating costs.

The asset “unbilled receivables” represents revenues we have recognized in excess of amounts billed on drilling contracts and production services in progress. The asset “prepaid expenses and other current assets” includes deferred mobilization costs for certain drilling contracts. The liability “prepaid drilling contracts” represents deferred mobilization revenues for certain drilling contracts and amounts collected on contracts in excess of revenues recognized.

Our Production Services Division earns revenues for well services, wireline services and fishing and rental services pursuant to master services agreements based on purchase orders, contracts or other persuasive evidence of an arrangement with the customer that include fixed or determinable prices. Production service revenue is recognized when the service has been rendered and collectibility is reasonably assured.

Long-lived Assets and Intangible Assets – We evaluate for potential impairment of long-lived assets and intangible assets subject to amortization when indicators of impairment are present, as defined in SFAS No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets. Circumstances that could indicate a potential impairment include significant adverse changes in industry trends, economic climate, legal factors, and an adverse action or assessment by a regulator. More specifically, significant adverse changes in industry trends include significant declines in revenue rates, utilization rates, oil and natural gas market prices and industry rig counts for drilling rigs and workover rigs. In performing the impairment evaluation, we estimate the future undiscounted net cash flows relating to long-lived assets and intangible assets grouped at the lowest level that cash flows can be identified. For our Production Services Division, our long-lived assets and intangible assets are grouped at the reporting unit level which is one level below the operating segment level. For our Drilling Services Division, we perform an impairment evaluation and estimate future undiscounted cash flows for individual drilling rig assets. If the sum of the estimated future undiscounted net cash flows is less than the carrying amount of the long-lived assets and intangible assets for these asset grouping levels, then we would recognize an impairment charge. The amount of an impairment charge would be measured as the difference between the carrying amount and the fair value of these assets. The assumptions used in the impairment evaluation for long-lived assets and intangible assets are inherently uncertain and require management judgment.

We performed an impairment analysis of our long-lived assets and intangible assets at December 31, 2008, due to significant adverse changes in the economic and business climate that resulted in decreases in estimated revenues, margins and cash flows. Essentially all our intangible assets were recorded in connection with the acquisitions of the production services businesses from WEDGE, Competition, Pettus and Paltec when revenues, margins and cash flows were at historically high levels earlier in 2008. We determined that the sum of the estimated future undiscounted net cash flows is less than the carrying amount of the long-lived assets and intangible assets in each reporting unit at December 31, 2008. Our long-lived asset and intangible asset impairment analysis for the reporting units in our Production Services Division resulted in no impairment charge to property and equipment and a non-cash impairment charge of $52.8 million to the carrying value of our intangible assets for customers relationships for the year ended December 31, 2008. For our Drilling Services Division, we did not record an impairment charge on any long-lived assets for the year ended December 31, 2008. The assumptions used in the impairment evaluation for long-lived assets and intangible assets are inherently uncertain and require management judgment. This impairment charge is not expected to have an impact on our liquidity or debt covenants; however, it is a reflection of the overall downturn in our industry and decline in our projected cash flows.

Goodwill – Goodwill results from business acquisitions and represents the excess of acquisition costs over the fair value of the net assets acquired. We account for goodwill and other intangible assets under the provisions of SFAS No. 142, Goodwill and Other Intangible Assets. Goodwill is tested for impairment annually as of December 31 or more frequently if events or changes in circumstances indicate that the asset might be impaired. Circumstances that could indicate a potential impairment include a significant adverse change in the economic or business climate, a significant adverse change in legal factors, an adverse action or assessment by a regulator, unanticipated competition, loss of key personnel and the likelihood that a reporting unit or significant portion of a reporting unit will be sold or otherwise disposed of. These circumstances could lead to our net book value exceeding our market capitalization which is another indicator of a potential impairment in goodwill. SFAS No. 142 requires a two-step process for testing impairment. First, the fair value of each reporting unit is compared to its carrying value to determine whether an indication of impairment exists. Goodwill was initially recorded for our Production Services Division operating segment and was allocated to its three reporting units which are well services, wireline services and fishing and rental services. Second, if impairment is indicated, then the fair value of the reporting unit’s goodwill is determined by allocating the unit’s fair value to its assets and liabilities (including any unrecognized intangible assets) as if the reporting unit had been acquired in a business combination on the impairment test date. The amount of impairment for goodwill is measured as the excess of the carrying value of the reporting unit over its fair value.

When estimating fair values of a reporting unit for our goodwill impairment test, we use a combination of an income approach and a market approach which incorporates both management’s views and those of the market. The income approach provides an estimated fair value based on each reporting unit’s anticipated cash flows that are discounted using a weighted average cost of capital rate. The market approach provides an estimated fair value based on our market capitalization that is computed using the 30-day average market price of our common stock and the number of shares outstanding as of the impairment test date. The estimated fair values computed using the income approach and the market approach are then equally weighted and combined into a single fair value. The primary assumptions used in the income approach are estimated cash flows and weighted average cost of capital. Estimated cash flows are primarily based on projected revenues, operating costs and capital expenditures and are discounted based on comparable industry average rates for weighted average cost of capital. We utilized discount rates based on weighted average cost of capital ranging from 15.8% to 16.7% when we estimated fair values of our reporting units as of December 31, 2008. The primary assumptions used in the market approach is the allocation of total market capitalization to each reporting unit, which is based on projected EBITDA percentages for each reporting unit, and control premiums, which are based on comparable industry averages. We utilized a 30% control premium when we estimated fair values of our reporting units as of December 31, 2008. To ensure the reasonableness of the estimated fair values of our reporting units, we performed a reconciliation of our total market capitalization to the total estimated fair value of all our reporting units. The assumptions used in estimating fair values of reporting units and performing the goodwill impairment test are inherently uncertain and require management judgment.

Our common stock price per share declined in market value from $13.30 at September 30, 2008, to $5.57 at December 31, 2008, which resulted in our net book value exceeding our market capitalization during most of this time period. We believed the decline in the market price of our common stock resulted from a significant adverse change in the economic and business climate as financial markets reacted to the credit crisis facing major lending institutions and worsening conditions in the overall economy during the fourth quarter of the year ended December 31, 2008. During the same time, there were significant declines in oil and natural gas prices which lead to declines in production service revenues, margins and cash flows. We considered the impact of these significant adverse changes in the economic and business climate as we performed our annual impairment assessment of goodwill as of December 31, 2008. The estimated fair values of our reporting units were negatively impacted by significant reductions in estimated cash flows for the income approach component and a significant reduction in our market capitalization for the market approach component of our fair value estimation process. Our goodwill was initially recorded in connection with the acquisitions of the production services businesses from WEDGE, Competition, Pettus and Paltec, all of which occurred between March 1, 2008 and October 1, 2008, when production service revenues, margins and cash flows and our market capitalization were at historically high levels.

Our goodwill impairment analysis as of December 31, 2008 lead us to conclude that there would be no remaining implied value attributable to our goodwill and accordingly, we recorded a non-cash charge of $118.6 million to our operating results for the year ended December 31, 2008, for the full impairment of our goodwill. Therefore, we had no remaining goodwill reflected on our consolidated balance sheet as of December 31, 2008. Our goodwill impairment analysis would have lead to the same full impairment conclusion if we increased or decreased our discount rates or control premiums by 10% when estimating the fair values of our reporting units. This impairment charge is not expected to have an impact on our liquidity or debt covenants; however, it is a reflection of the overall downturn in our industry and decline in our projected cash flows.

Deferred taxes – We provide deferred taxes for the basis differences in our property and equipment between financial reporting and tax reporting purposes and other costs such as compensation, foreign net operating loss carryforwards, employee benefit and other accrued liabilities which are deducted in different periods for financial reporting and tax reporting purposes. For property and equipment, basis differences arise from differences in depreciation periods and methods and the value of assets acquired in a business acquisition where we acquire an entity rather than just its assets. For financial reporting purposes, we depreciate the various components of our drilling rigs, workover rigs and wireline units over 2 to 25 years and refurbishments over 3 to 5 years, while federal income tax rules require that we depreciate drilling rigs, workover rigs, wireline units and refurbishments over 5 years. Therefore, in the first 5 years of our ownership of a drilling rig, workover rig or wireline unit, our tax depreciation exceeds our financial reporting depreciation, resulting in our providing deferred taxes on this depreciation difference. After 5 years, financial reporting depreciation exceeds tax depreciation, and the deferred tax liability begins to reverse.

Accounting estimates – We consider the recognition of revenues and costs on turnkey and footage contracts to be critical accounting estimates. On these types of contracts, we are required to estimate the number of days needed for us to complete the contract and our total cost to complete the contract. Our actual costs could substantially exceed our estimated costs if we encounter problems such as lost circulation, stuck drill pipe or an underground blowout on contracts still in progress subsequent to the release of the financial statements. We receive payment under turnkey and 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 more shallow depth. Since 1995, we have completed all our turnkey or footage contracts. Although our initial cost estimates for turnkey and 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 have

previously enabled us to make reasonable 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 turnkey and 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 increase our cost estimate to complete the contract. 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 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. During the three months ended March 31, 2009, we did not experience a loss on any turnkey and footage contracts completed. We are more likely to encounter losses on turnkey and footage contracts in periods in which revenue rates are lower for all types of contracts. During periods of reduced demand for drilling rigs, our overall profitability on turnkey and footage contracts has historically exceeded our profitability on daywork contracts.

Revenues and costs during a reporting period could be affected for contracts in progress at the end of a reporting period which have not been completed before our financial statements for that period are released. We had no turnkey or footage contracts in progress at March 31, 2009. Our unbilled receivables at March 31, 2009 did not include any amounts related to turnkey or footage contracts.

We estimate an allowance for doubtful accounts based on the creditworthiness of our customers as well as general economic conditions. We evaluate the creditworthiness of our customers based on commercial credit reports, trade references, bank references, financial information, production information and any past experience we have with the customer. Consequently, any 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 15-day intervals during the performance of daywork contracts and upon completion of the daywork contract. Turnkey and 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 and have not extended payment terms beyond 90 days for any of our contracts in the last three fiscal years. We had an allowance for doubtful accounts of $1.6 million at both March 31, 2009 and December 31, 2008.

Our determination of the useful lives of our depreciable assets, which directly affects our determination of depreciation expense and deferred taxes is also a critical accounting estimate. A decrease in the useful life of our property and equipment would increase depreciation expense and reduce deferred taxes. We provide for depreciation of our drilling, production, transportation and other equipment on a straight-line method over useful lives that we have estimated and that range from 2 to 25 years. We record the same depreciation expense whether a drilling rig, workover rig or wireline unit is idle or working. Our estimates of the useful lives of our drilling, production, transportation and other equipment are based on our more than 35 years of experience in the oilfield services industry with similar equipment.

As of March 31, 2009, we had foreign deferred tax assets consisting of foreign net operating losses and other tax benefits available to reduce future taxable income in a foreign jurisdiction. In assessing the realizability of our foreign deferred tax assets, we only recognize a tax benefit to the extent of taxable income that we expect to earn in the foreign jurisdiction in future periods. Due to declines in oil and natural gas prices and the downturn in our industry since late 2008, we anticipate drilling rig utilization and revenue rates will remain at depressed levels for the remainder of 2009. Consequently, we have a valuation allowance of $3.6 million that fully offsets our foreign deferred tax assets. The foreign net operating loss has an indefinite carryforward period. The foreign net operating loss is primarily due to the special income tax benefits permitted by the Colombian government that allows us to recover 140% of the cost of certain imported assets.

Our accrued insurance premiums and deductibles as of March 31, 2009 include accruals for costs incurred under the self-insurance portion of our health insurance of approximately $1.8 million and our workers’ compensation, general liability and auto liability insurance of approximately $9.8 million. We have a deductible of $125,000 per covered individual per year under the health insurance. We have a deductible of $500,000 per occurrence under our workers’ compensation insurance, except in North Dakota, where we do not have a deductible. We have deductibles of $250,000 and $100,000 per occurrence under our general liability insurance and auto liability insurance, respectively. We accrue for these costs as claims are incurred based on historical claim development data, and we accrue the costs of administrative services associated with claims processing. We also evaluate our workers’ compensation claim cost estimates based on estimates provided by a professional actuary.

We are subject to interest rate market risk on our variable rate debt. As of March 31, 2009, we had $257.5 million outstanding under our senior secured revolving credit facility subject to variable interest rate risk. The impact of a 1% increase in interest rates on this amount of debt would result in increased interest expense of approximately $0.6 million and a decrease in net income of approximately $0.4 million during a quarterly period.

At March 31, 2009, we held $15.9 million (par value) of investments comprised of tax exempt, auction rate preferred securities (“ARPSs”), which are variable-rate preferred securities and have a long-term maturity with the interest rate being reset through “Dutch auctions” that are held every 7 days. The ARPSs have historically traded at par because of the frequent interest rate resets and because they are callable at par at the option of the issuer. Interest is paid at the end of each auction period. Our ARPSs are AAA/Aaa rated securities, collateralized by municipal bonds and backed by assets that are equal to or greater than 200% of the liquidation preference. Until February 2008, the auction rate securities market was highly liquid. Beginning mid-February 2008, we experienced several “failed” auctions, meaning that there was not enough demand to sell all of the securities that holders desired to sell at auction. The immediate effect of a failed auction is that such holders cannot sell the securities at auction and the interest rate on the security resets to a maximum auction rate. We have continued to receive interest payments on our ARPSs in accordance with their terms. Unless a future auction is successful or the issuer calls the security pursuant to redemption prior to maturity, we may not be able to access the funds we invested in our ARPSs without a loss of principal. We have no reason to believe that any of the underlying municipal securities that collateralize our ARPSs are presently at risk of default. We believe we will ultimately be able to liquidate our investments without material loss primarily due to the collateral securing the ARPSs. We do not currently intend to attempt to sell our ARPSs at a discount since our liquidity needs are expected to be met with cash flows from operating activities and our senior secured revolving credit facility. Our ARPSs are designated as available-for-sale and are reported at fair market value with the related unrealized gains or losses, included in accumulated other comprehensive income (loss), net of tax, a component of shareholders’ equity. The estimated fair value of our ARPSs at March 31, 2009 was $11.0 million compared with a par value of $15.9 million. The $4.9 million difference represents a fair value discount due to the current lack of liquidity which is considered temporary and is recorded as an unrealized loss. We would recognize an impairment charge if the fair value of our investments falls below the cost basis and is judged to be other-than-temporary. Our ARPSs are classified with other long-term assets on our condensed consolidated balance sheet as of March 31, 2009 because of our inability to determine the recovery period of our investments.

While the U.S. dollar is the functional currency for reporting purposes for our Colombian operations, we enter into transactions denominated in Colombian pesos. Nonmonetary assets and liabilities are translated at historical rates and monetary assets and liabilities are translated at exchange rates in effect at the end of the period. Income statement accounts are translated at average rates for the period. As a result, Colombian Peso denominated transactions are affected by changes in exchange rates. We generally accept the exposure to exchange rate movements without using derivative financial instruments to manage this risk. Therefore, both positive and negative movements in the Colombian Peso currency exchange rate against the U.S. dollar has and will continue to affect the reported amount of revenues, expenses, profit, and assets and liabilities in the Company’s consolidated financial statements.

In accordance with Exchange Act Rules 13a-15 and 15d-15, we carried out an evaluation, under the supervision and with the participation of management, including our Chief Executive Officer and Chief Financial Officer, of the effectiveness of our disclosure controls and procedures as of the end of the period covered by this Quarterly Report on Form 10-Q. Based on that evaluation, our Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures were effective as of March 31, 2009 to provide reasonable assurance that information required to be disclosed in our reports filed or submitted under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the Securities and Exchange Commission’s rules and forms and that such information is accumulated and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosure.

There has been no change in our internal control over financial reporting that occurred during the three months ended March 31, 2009 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

We are involved in litigation arising in the ordinary course of our business. Although the amount of any liability that could arise with respect to these actions cannot be accurately predicted, in management’s opinion, any such liability will not have a material adverse effect on our business, financial condition or operating results.

We did not make any unregistered sales of equity securities during the quarter ended March 31, 2009, nor did we repurchase any shares of our common stock during the quarter ended March 31, 2009.

The following exhibits are filed as part of this report or incorporated by reference herein:

Pursuant to the requirements 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.

PIONEER DRILLING COMPANY

/s/ Lorne E. Phillips

Lorne E. Phillips

Executive Vice President and Chief Financial Officer

(Principal Financial Officer and Duly Authorized Representative)


1250 N.E. Loop 410, Suite 1000, San Antonio, Texas		78209
(Address of principal executive offices)		(Zip Code)


	March 31, 2009			December 31, 2008
	(unaudited)			(audited)
	(In thousands, except share data)
ASSETS
Current assets:
Cash and cash equivalents	$	30,014		$	26,821
Receivables, net of allowance for doubtful accounts		62,099			87,161
Unbilled receivables		11,302			12,262
Deferred income taxes		5,417			6,270
Inventory		4,672			3,874
Prepaid expenses and other current assets		5,233			8,902

Total current assets		118,737			145,290

Property and equipment, at cost		885,113			858,491
Less accumulated depreciation and amortization		254,689			230,929

Net property and equipment		630,424			627,562
Intangible assets, net of amortization		28,736			29,913
Other long-term assets		17,990			21,714

Total assets	$	795,887		$	824,479


LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities:
Accounts payable	$	16,557		$	21,830
Current portion of long-term debt		2,156			17,298
Prepaid drilling contracts		—			1,171
Accrued expenses:
Payroll and related employee costs		7,582			13,592
Insurance premiums and deductibles		18,620			17,520
Other		6,570			9,507

Total current liabilities		51,485			80,918
Long-term debt, less current portion		261,152			262,115
Other long-term liabilities		6,310			6,413
Deferred income taxes		62,291			60,915

Total liabilities		381,238			410,361

Commitments and contingencies
Shareholders’ equity:
Preferred stock, 10,000,000 shares authorized; none issued and outstanding		—			—
Common stock $.10 par value; 100,000,000 shares authorized; 50,248,178 shares and 49,997,578 shares issued and outstanding at March 31, 2009 and December 31, 2008, respectively		5,025			5,000
Additional paid-in capital		303,667			301,923
Accumulated earnings		109,058			108,440
Accumulated other comprehensive loss		(3,101	)		(1,245	)

Total shareholders’ equity		414,649			414,118

Total liabilities and shareholders’ equity	$	795,887		$	824,479


	Three Months Ended March 31,
	2009			2008
	(In thousands, except per share data)
Revenues:
Drilling services	$	71,366		$	100,041
Production services		29,474			13,356

Total revenue	$	100,840		$	113,397


Costs and expenses:
Drilling services		44,128			63,497
Production services		18,716			6,929
Depreciation and amortization		25,446			17,119
Selling, general and administrative		10,027			7,722
Bad debt (recovery) expense		(334	)		135

Total operating costs and expenses		97,983			95,402


Income from operations		2,857			17,995


Other (expense) income:
Interest expense		(1,988	)		(1,574	)
Interest income		84			585
Other		(515	)		1,092

Total other (expense) income		(2,419	)		103


Income before income taxes		438			18,098
Income tax benefit (expense)		180			(6,250	)


Net earnings	$	618		$	11,848


Earnings per common share - Basic	$	0.01		$	0.24


Earnings per common share - Diluted	$	0.01		$	0.24


Weighted average number of shares outstanding - Basic		49,824			49,759


Weighted average number of shares outstanding - Diluted		49,929			50,291


	Three months ended March 31,
	2009			2008
	(In thousands)
Cash flows from operating activities:
Net earnings	$	618		$	11,848
Adjustments to reconcile net earnings to net cash provided by operating activities:
Depreciation and amortization		25,446			17,119
Allowance for doubtful accounts		66			135
Loss (gain) on dispositions of property and equipment		149			(23	)
Stock-based compensation expense		1,769			951
Deferred income taxes		3,336			554
Change in other assets		761			74
Change in non-current liabilities		(815	)		(88	)
Changes in current assets and liabilities:
Receivables		25,919			(7,023	)
Inventory		(798	)		(259	)
Prepaid expenses & other current assets		3,669			491
Accounts payable		(7,178	)		132
Income tax payable		—			4,780
Prepaid drilling contracts		(1,171	)		1,150
Accrued expenses		(7,848	)		10,144

Net cash provided by operating activities		43,923			39,985

Cash flows from investing activities:
Acquisition of production services business of WEDGE		—			(313,610	)
Acquisition of production services business of Competition		—			(26,101	)
Purchases of property and equipment		(24,830	)		(32,938	)
Purchase of auction rate preferred securities		—			(16,475	)
Proceeds from sale of property and equipment		169			933
Proceeds from insurance recoveries		36			—

Net cash used in investing activities		(24,625	)		(388,191	)

Cash flows from financing activities:
Payments of debt		(16,105	)		(22,001	)
Proceeds from issuance of debt		—			311,500
Debt issuance costs		—			(3,281	)
Proceeds from exercise of options		—			653
Excess tax benefit of stock option exercises		—			250

Net cash (used in) provided by financing activities		(16,105	)		287,121

Net increase (decrease) in cash and cash equivalents		3,193			(61,085	)
Beginning cash and cash equivalents		26,821			76,703

Ending cash and cash equivalents	$	30,014		$	15,618

Supplementary disclosure:
Interest paid	$	2,080		$	1,489
Income tax paid	$	2		$	1


Drilling Division Locations		Rig Count
South Texas		17
East Texas		22
North Texas		8
Utah		6
North Dakota		6
Oklahoma		6
Colombia		5


Cash acquired	$	1,168
Other current assets		22,102
Property and equipment		138,493
Intangible asset and other assets		66,118
Goodwill		112,869

Total assets acquired	$	340,750


Current liabilities	$	10,655
Long-term debt		1,462
Other long term liabilities		13,949

Total liabilities assumed	$	26,066

Net assets acquired	$	314,684


	Pro Forma
	Three Months Ended March 31, 2008
	(in thousands)
Total revenues	$	137,048
Net earnings	$	12,651
Earnings per common share
Basic	$	0.25
Diluted	$	0.25


Senior secured credit facility	$	257,500
Subordinated notes payable		5,467
Other		341

		263,308
Less current portion		(2,156	)

	$	261,152


	As of and for the Three Months Ended March 31, 2009
	Drilling Services Division		Production Services Division		Corporate		Total
Identifiable assets	$	548,519	$	227,077	$	20,291	$	795,887


Revenues	$	71,366	$	29,474	$	—	$	100,840
Operating costs		44,128		18,716		—		62,844

Segment margin	$	27,238	$	10,758	$	—	$	37,996

Depreciation and amortization	$	19,337	$	5,724	$	385	$	25,446
Capital expenditures	$	19,883	$	6,273	$	582	$	26,738


	Three Months Ended
	March 31, 2009			March 31, 2008
Segment margin	$	37,996		$	42,971
Depreciation and amortization		(25,446	)		(17,119	)
Selling, general and administrative		(10,027	)		(7,722	)
Bad debt recovery (expense)		334			(135	)

Income from operations	$	2,857		$	17,995


	As of and for the Three Months Ended
	March 31, 2009		March 31, 2008

Identifiable assets	$	110,734	$	97,779


Revenues	$	14,617	$	8,541


	Three Months Ended March 31,		Years ended March 31,
	2009		2009		2008		2007		2006		2005
Oil (West Texas Intermediate)	$	43.69	$	86.35	$	82.50	$	64.96	$	59.94	$	45.04

Natural Gas (Henry Hub)	$	4.51	$	7.78	$	7.27	$	6.53	$	9.10	$	5.99

U.S. Land Rig Count		1,280		1,690		1,685		1,589		1,329		1,110

U.S. Workover Rig Count		1,975		2,392		2,412		2,376		2,271		2,087


	March 31, 2009		December 31, 2008		Change
Cash and cash equivalents	$	30,014	$	26,821	$	3,193
Receivables, net		62,099		87,161		(25,062	)
Unbilled receivables		11,302		12,262		(960	)
Deferred income taxes		5,417		6,270		(853	)
Inventory		4,672		3,874		798
Prepaid expenses and other current		5,233		8,902		(3,669	)

Current assets		118,737		145,290		(26,553	)


Accounts payable		16,557		21,830		(5,273	)
Current portion of long-term debt		2,156		17,298		(15,142	)
Prepaid drilling contracts		—		1,171		(1,171	)
Accrued expenses - payroll and related employee costs		7,582		13,592		(6,010	)
Accrued expenses - insurance premiums and deductibles		18,620		17,520		1,100
Accrued expenses - other		6,570		9,507		(2,937	)

Current liabilities		51,485		80,918		(29,433	)


Working capital	$	67,252	$	64,372	$	2,880


	Payments Due by Period
Contractual Obligations	Total		Less than 1 year		2-3 years		4-5 years		More than 5 years
Long-term debt	$	263,308	$	2,156	$	3,001	$	258,151	$	—
Interest on long term debt		23,328		6,189		11,864		5,275		—
Purchase commitments		25,170		25,170		—		—		—
Operating leases		5,702		1,775		2,587		1,340		—
Restricted cash obligation		2,600		650		1,300		650		—
Other		200		200		—		—		—


Total	$	320,308	$	36,140	$	18,752	$	265,416	$	—


	Three Months Ended March 31,
	2009			2008
Drilling Services Division:
Revenues	$	71,366		$	100,041
Operating costs		44,128			63,497

Drilling Services Division margin	$	27,238		$	36,544


Average number of drilling rigs		70.0			67.0
Utilization rate		52	%		84	%
Revenue days		3,299			5,036

Average revenues per day	$	21,633		$	19,865
Average operating costs per day		13,376			12,609


Drilling Services Division margin per day	$	8,257		$	7,256


Production Services Division:
Revenues	$	29,474		$	13,356
Operating costs		18,716			6,929

Production Services Division margin	$	10,758		$	6,427


Combined
Revenues	$	100,840		$	113,397
Operating costs		62,844			70,426

Combined margin	$	37,996		$	42,971


EBITDA	$	27,788		$	36,206


2.1 *	-	Securities Purchase Agreement, dated January 31, 2008, by and among Pioneer Drilling Company, WEDGE Group Incorporated, WEDGE Energy Holdings, L.L.C., WEDGE Oil & Gas Services, L.L.C., Timothy Daley, John Patterson and Patrick Grissom (Form 8-K dated February 1, 2008 (File No. 1-8182, Exhibit 2.1))

2.2 *	-	Letter Agreement, dated February 29, 2008, amending the Securities Purchase Agreement, dated January 31, 2008, by and among Pioneer Drilling Company, WEDGE Group Incorporated, WEDGE Energy Holdings, L.L.C., WEDGE Oil & Gas Services, L.L.C., Timothy Daley, John Patterson and Patrick Grissom (Form 8-K dated March 3, 2008 (File No. 1-8182, Exhibit 2.1))

3.1 *	-	Restated Articles of Incorporation of Pioneer Drilling Company (Form 10-K for the year ended December 31, 2008 (File No. 1-8182, Exhibit 3.1)).

3.2 *	-	Amended and Restated Bylaws of Pioneer Drilling Company (Form 8-K dated December 15, 2008 (File No. 1-8182, Exhibit 3.1)).

4.1 *	-	Form of Certificate representing Common Stock of Pioneer Drilling Company (Form S-8 filed November 18, 2003 (Reg. No. 333-110569, Exhibit 4.3)).

10.1 *	-	Employment Letter Agreement, effective January 7, 2009, from Pioneer Drilling Company to Lorne E. Phillips (Form 8-K dated January 14, 2009 (File No. 1-8182, Exhibit 10.1)).

31.1 **	-	Certification by Wm. Stacy Locke, President and Chief Executive Officer, pursuant to Rule 13a-14(a) or Rule 15d-14(a) under the Securities Exchange Act of 1934.

31.2 **	-	Certification by Lorne E. Phillips, Executive Vice President and Chief Financial Officer, pursuant to Rule 13a-14(a) or Rule 15d-14(a) under the Securities Exchange Act of 1934.

32.1 #	-	Certification by Wm. Stacy Locke, President and Chief Executive Officer, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (Subsections (a) and (b) of Section 1350, Chapter 63 of Title 18, United States Code).

32.2 #	-	Certification by Lorne E. Phillips, Executive Vice President and Chief Financial Officer, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (Subsections (a) and (b) of Section 1350, Chapter 63 of Title 18, United States Code).


Dated: May 7, 2009		/s/ Wm. Stacy Locke
		Wm. Stacy Locke
		President and Chief Executive Officer