Edgar Filing: PIONEER DRILLING CO

As of and
for the
Three Months
Ended
September 30, 2008

As of and
for the
Nine Months
Ended
September 30, 2008

Identifiable assets

Form 10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

x	QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15 (d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended September 30, 2008

¨	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from to

Commission File Number 1-8182

PIONEER DRILLING COMPANY

(Exact name of registrant as specified in its charter)

TEXAS

74-2088619

(State or other jurisdiction of

incorporation or organization)

(I.R.S. Employer

Identification Number)


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

210-828-7689

(Registrant’s telephone number, including area code)

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. Yes x No ¨

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.

Large accelerated filer ¨ Accelerated filer x Non-accelerated filer ¨ Smaller reporting company ¨

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 October 31, 2008, there were 49,988,328 shares of common stock, par value $0.10 per share, of the registrant issued and outstanding.

PART I. FINANCIAL INFORMATION

ITEM 1.

FINANCIAL STATEMENTS

PIONEER DRILLING COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS


	September 30, 2008			December 31, 2007
	(unaudited)			(audited)
	(In thousands, except share data)
ASSETS
Current assets:
Cash and cash equivalents	$	17,342		$	76,703
Receivables, net of allowance for doubtful accounts		87,436			47,370
Unbilled receivables		18,676			7,861
Deferred income taxes		7,013			3,670
Inventory		4,448			1,180
Prepaid expenses and other current assets		8,775			5,073

Total current assets		143,690			141,857

Property and equipment, at cost		813,983			578,697
Less accumulated depreciation and amortization		210,876			161,675

Net property and equipment		603,107			417,022
Deferred income taxes		—			573
Goodwill		106,264			—
Intangibles and other long term assets, net of amortization		107,015			760

Total assets	$	960,076		$	560,212

LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities:
Accounts payable	$	30,906		$	21,424
Current portion of long-term debt		4,452			—
Income taxes payable		4,698			—
Prepaid drilling contracts		3,447			1,933
Accrued expenses:
Payroll and related employee costs		14,934			5,172
Insurance premiums and deductibles		17,484			9,548
Other		7,359			3,973

Total current liabilities		83,280			42,050
Long-term debt, less current portion		278,199			—
Other long term liabilities		5,418			254
Deferred income taxes		62,898			46,836

Total liabilities		429,795			89,140

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; 49,971,328 shares and 49,650,978 shares issued and outstanding at September 30, 2008 and December 31, 2007, respectively		4,997			4,965
Additional paid-in capital		300,147			294,922
Accumulated other comprehensive loss		(1,206	)		—
Accumulated earnings		226,343			171,185

Total shareholders’ equity		530,281			471,072

Total liabilities and shareholders’ equity	$	960,076		$	560,212

See accompanying notes to condensed consolidated financial statements.

PIONEER DRILLING COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(Unaudited)


	Three Months Ended September 30,						Nine Months Ended September 30,
	2008			2007			2008			2007
	(In thousands, except per share data)
Revenues	$	174,245		$	106,516		$	440,189		$	312,642

Costs and expenses:
Operating costs		95,367			65,237			251,986			186,822
Depreciation and amortization		24,225			16,093			61,924			46,927
Selling, general and administrative		12,840			5,252			32,712			13,792
Bad debt expense (recovery)		(260	)		2,627			(216	)		2,627

Total operating costs and expenses		132,172			89,209			346,406			250,168

Income from operations		42,073			17,307			93,783			62,474

Other income (expense):
Interest expense		(3,773	)		(14	)		(9,612	)		(15	)
Interest income		205			731			995			2,474
Other		(1,551	)		11			(1,389	)		39

Total other income (expense)		(5,119	)		728			(10,006	)		2,498

Income before income taxes		36,954			18,035			83,777			64,972
Income tax expense		(12,760	)		(6,255	)		(28,619	)		(22,886	)

Net earnings	$	24,194		$	11,780		$	55,158		$	42,086

Earnings per common share - Basic	$	0.49		$	0.24		$	1.11		$	0.85

Earnings per common share - Diluted	$	0.48		$	0.23		$	1.09		$	0.84

Weighted average number of shares outstanding - Basic		49,791			49,651			49,780			49,635

Weighted average number of shares outstanding - Diluted		50,449			50,205			50,426			50,193

See accompanying notes to condensed consolidated financial statements.

PIONEER DRILLING COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)


	Nine Months Ended September 30,
	2008			2007
	(In thousands)
Cash flows from operating activities:
Net earnings	$	55,158		$	42,086
Adjustments to reconcile net earnings to net cash provided by operating activities:
Depreciation and amortization		61,924			46,927
Allowance for doubtful accounts		270			2,627
Loss (gain) on dispositions of property and equipment		(512	)		2,501
Stock-based compensation expense		2,924			2,714
Deferred income taxes		10,700			10,454
Change in other assets		355			5
Change in non-current liabilities		(329	)		(74	)
Changes in current assets and liabilities:
Receivables		(29,447	)		2,281
Inventory		(1,501	)		444
Prepaid expenses & other current assets		(1,687	)		(1,082	)
Accounts payable		4,194			(140	)
Income tax payable		5,107			(3,791	)
Prepaid drilling contracts		1,514			5,194
Accrued expenses		17,085			5,137

Net cash provided by operating activities		125,755			115,283

Cash flows from investing activities:
Acquisition of production services business of WEDGE		(313,606	)		—
Acquisition of production services business of Competition		(26,770	)		—
Acquisition of production services business of Paltec		(6,520	)		—
Purchases of property and equipment		(99,794	)		(126,994	)
Purchase of auction rate preferred securities		(16,475	)		—
Proceeds from sale of property and equipment		2,712			2,970
Proceeds from insurance recoveries		2,638			—

Net cash used in investing activities		(457,815	)		(124,024	)

Cash flows from financing activities:
Payments of debt		(44,404	)		—
Proceeds from issuance of debt		319,500			—
Debt issuance costs		(3,319	)		—
Proceeds from exercise of options		672			217
Excess tax benefit of stock option exercises		250			73

Net cash provided by financing activities		272,699			290

Net increase (decrease) in cash and cash equivalents		(59,361	)		(8,451	)
Beginning cash and cash equivalents		76,703			74,754

Ending cash and cash equivalents	$	17,342		$	66,303

Supplementary disclosure:
Interest paid	$	8,668		$	15
Income tax paid	$	11,436		$	16,494

See accompanying notes to condensed consolidated financial statements.

PIONEER DRILLING COMPANY AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

1. Nature of Operations and Summary of Significant Accounting Policies

Business and Basis of Presentation

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 69 drilling rigs, 17 of which are operating in South Texas, 22 of which are operating in East Texas, eight of which are operating in North Texas, six of which are operating in Western Oklahoma, 11 of which are operating in the Rocky Mountain region and four of which are operating internationally in Colombia. In addition, we exported a 1500 horsepower rig to Colombia that we expect to begin operating in November 2008. Currently, we are constructing two 1500 horsepower drilling rigs that we expect to be completed and available for operation in the United States in December 2008 and March 2009. Our Production Services Division provides well services, wireline services and fishing and rental services with its fleet of 70 workover rigs, 55 wireline units and approximately $15 million of fishing and rental tools equipment through our facilities in Texas, Kansas, North Dakota, Colorado, Montana, Utah and Oklahoma.

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. In December 2007, our Board of Directors approved a change in our fiscal year end from March 31^st to December 31^st. The fiscal year end change was effective December 31, 2007 and resulted in a nine month reporting period from April 1, 2007 to December 31, 2007. We implemented the fiscal year end change to align our United States reporting period with the required Colombian statutory reporting period as well as the reporting periods of peer companies in the industry.

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 insurance, 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, 2007 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 transition report on Form 10-KT for the fiscal year ended December 31, 2007.

Drilling Contracts

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 generally construct new drilling rigs, once we have entered into longer-term drilling contracts for such rigs. As of October 31, 2008, we had 34 contracts with terms of six months to three years in duration, of which 19 will expire by April 30, 2009, nine have a remaining term of six to 12 months, four have a remaining term of 12 to 18 months and two have a remaining term in excess of 18 months.

Foreign Currencies

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.

Revenue and Cost Recognition

Drilling Services – We earn 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. 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.

Production Services – We earn revenues for well services, wireline services and fishing and rental services based on purchase orders, contracts or other persuasive evidence of an arrangement with the customer, such as master service agreements, that include fixed or determinable prices. These production services revenues are recognized when the services have been rendered and collectability is reasonably assured.

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.

Restricted Cash

As of September 30, 2008, we had restricted cash in the amount of $3.3 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 a five year term from the escrow account. Restricted cash of $0.7 million and $2.6 million is recorded in other current assets and other long term assets, respectively. The associated obligation of $0.7 million and $2.6 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. The trust account balance of $0.9 million plus net earning will be distributed to the former Chief Financial Officer on March 2, 2009. As of September 30, 2008, this restricted account had a balance of $0.9 million and is recorded in other current assets with the associated obligation recorded in accrued expenses.

Trade Accounts Receivable

We record trade accounts receivable at the amount we invoice our customers. These accounts do not bear interest. The allowance for doubtful accounts is our best estimate of the amount of probable credit losses in our accounts receivable as of the balance sheet date. We determine the allowance based on the credit worthiness of our customers and general economic conditions. Consequently, any change in those factors could affect our estimate of our allowance for doubtful accounts. We review our allowance for doubtful accounts monthly. Balances more than 90 days past due are reviewed individually for collectability. We charge off account balances against the allowance after we have exhausted all reasonable means of collection and determined that the potential for recovery is remote. We do not have any off-balance sheet credit exposure related to our customers. We had an allowance for doubtful accounts of $0.3 million at September 30, 2008 and no allowance for doubtful accounts at December 31, 2007.

Investments

Intangibles and other long-term assets and prepaid expenses and other current assets include our investments in tax exempt, auction rate preferred securities (“ARPSs”). We sold $0.6 million of our ARPSs at par on October 1, 2008, accordingly, these ARPSs are classified in other current assets at September 30, 2008 on our condensed consolidated balance sheet. The remaining fair value of our ARPSs of $14.0 million is classified with other long-term assets because of our inability to determine the recovery period of our investment.

At September 30, 2008, we held $16.5 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, backed by assets that are equal to or greater than 200% of the liquidation preference and guaranteed by monoline bond insurance companies. 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, which might include the company’s own data. 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 September 30, 2008 was $14.6 million compared with a par value of $16.5 million. The $1.9 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, net of tax, in accumulated other comprehensive income (loss). 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.

Inventories

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.

Property and Equipment

Property and equipment are carried at cost less accumulated depreciation. Depreciation is provided for our assets over the estimated useful lives of the assets using the straight-line method. We record the same depreciation expense whether a rig is idle or working. We charge our expenses for maintenance and repairs to operating costs. We charge our expenses for renewals and betterments to the appropriate property and equipment accounts.

We review our long-lived assets and intangible assets for impairment whenever events or circumstances provide evidence that suggests that we may not recover the carrying amounts of any of these assets. In performing the review for recoverability, we estimate the future net cash flows we expect to obtain from the use of each asset and its eventual disposition. If the sum of these estimated future undiscounted net cash flows is less than the carrying amount of the asset, we recognize an impairment loss.

Effective January 1, 2008, management reassessed the estimated useful lives assigned to a group of 19 drilling rigs that were recently constructed. These drilling rigs were constructed with new components that have longer estimated useful lives when compared to other drilling rigs that are equipped with older components. As a result, we increased the estimated useful lives for this group of recently constructed drilling rigs from an average useful life of 9 years to 12 years. The following table provides the impact of this change in depreciation and amortization expense for the three and nine months ended September 30, 2008 (amounts in thousands):


	Three Months Ended September 30, 2008			Nine Months Ended September 30, 2008
Depreciation and amortization expense using prior useful lives	$	25,169		$	64,756
Impact of change in estimated useful lives		(944	)		(2,832	)

Depreciation and amortization expense, as reported	$	24,225		$	61,924

Diluted earnings per common share using prior useful lives	$	0.47		$	1.06
Impact of change in estimated useful lives		0.01			0.03

Diluted earnings per common share, as reported	$	0.48		$	1.09

As of September 30, 2008, the estimated useful lives of our asset classes are as follows:


		Lives
Drilling rigs and equipment		3 - 25
Workover rigs and equipment		5 - 20
Wireline units and equipment		5 - 10
Fishing and rental tools equipment		7
Vehicles		5 - 10
Office equipment		3 - 5
Buildings and improvements		3 - 40

Goodwill and Other Intangible Assets

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 and other intangible assets not subject to amortization are tested for impairment annually or more frequently if events or changes in circumstances indicate that the asset might be impaired. 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. 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. The amount of impairment for goodwill is measured as the excess of its carrying value over its fair value.

Intangible assets subject to amortization under SFAS No. 142 consist of customers relationships, non-compete agreements and trade names. As of September 30, 2008, the gross carrying value of customer relationships, non-compete agreements and trade names was $86.2 million, $2.3 million and $1.6 million, respectively. Amortization expense for our customer relationships are calculated using the straight-line method over their respective estimated economic useful lives which range from four to nine years. Amortization expense for our non-compete agreements are calculated using the straight-line method over the period of the agreements which range from one to five years. Trade names are being amortized over a period less than a year. Accumulated amortization related to these intangibles totaled $3.3 million, $0.6 million and $0.8 million for the customer relationships, non-compete agreements and trade names, respectively. Amortization expense was $4.6 million for the nine months ended September 30, 2008 and is estimated to be approximately $3.7 million for the quarter ending December 31, 2008. Amortization expense is estimated to be approximately $11.7 million, $11.6 million, $11.1 million, $10.6 million and $10.3 million for the years ending December 31, 2009, 2010, 2011, 2012 and 2013, respectively.

Income Taxes

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

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 and nine months ended September 30, 2008. We had no other comprehensive income (loss) for the three and nine months ended September 30, 2007. The following table sets forth the components of comprehensive income:


	Three Months Ended September 30,					Nine Months Ended September 30,
	2008			2007		2008			2007
	(amounts in thousands)
Net income	$	24,194		$	11,780	$	55,158		$	42,086
Other comprehensive loss - unrealized loss on securities		(256	)		—		(1,206	)		—

Comprehensive income	$	23,938		$	11,780	$	53,952		$	42,086

Stock-based Compensation

Effective April 1, 2006, we adopted SFAS No. 123 (Revised), Share-Based Payment, utilizing the modified prospective approach. Prior to the adoption of SFAS 123R, we accounted for stock option grants in accordance with the intrinsic-value-based method prescribed by Accounting Principles Board Opinion No. 25, Accounting for Stock Issued to Employees, and related interpretations, as permitted by SFAS No. 123, Accounting for Stock-Based Compensation. Accordingly, we recognized no compensation expense for stock options granted, as all stock options were granted at an exercise price equal to the closing market value of the underlying common stock on the date of grant. Under the modified prospective approach, compensation cost for the nine months ended September 30, 2008 includes compensation cost for all stock options granted prior to, but not yet vested as of, April 1, 2006, based on the grant-date fair value estimated in accordance with SFAS 123, and compensation cost for all stock options granted subsequent to April 1, 2006, based on the grant-date fair value estimated in accordance with SFAS 123R. We use the graded vesting method for recognizing compensation costs for stock options. Compensation costs of approximately $2.1 million and $0.6 million for stock options were recognized in selling, general and administrative expense and operating costs, respectively, for the nine months ended September 30, 2008.

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 143,054 stock options exercised during the nine months ended September 30, 2008.

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 and nine months ended September 30, 2008 and 2007.


	Three Months Ended September 30,						Nine Months Ended September 30,
	2008			2007			2008			2007
Weighted average expected volatility		44	%		46	%		44	%		46	%
Weighted-average risk-free interest rates		2.8	%		5.0	%		2.6	%		4.8	%
Weighted-average expected life in years		3.74			4.46			3.74			3.97
Options granted		1,057,098			130,000			1,402,098			899,500
Weighted-average grant-date fair value	$	6.11		$	6.23		$	5.77		$	5.89

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 nine months ended September 30, 2008, 178,261 restricted stock awards were granted with a weighted-average grant date price of $17.07. Compensation costs of approximately $0.2 million and $30,000 for restricted stock awards were recognized in selling, general and administrative expense and operating costs, respectively, for the nine months ended September 30, 2008.

Related-Party Transactions

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 the nine months ended September 30, 2008. These individuals acquired a minority working interest in three wells that we drilled for this customer during the nine months ended September 30, 2007. We recognized contract drilling revenues of $1.7 million on these wells during the nine months ended September 30, 2007.

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 nine months ended September 30, 2008 was approximately $323,000 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 $1.6 million as of September 30, 2008. See note 2 for further information regarding the acquisitions.

We purchased goods and services during the nine months ended September 30, 2008 from six vendors that are owned by employees of our company. We purchased $243,000 of well servicing equipment from one of these related party vendors for the nine months ended September 30, 2008. Purchases from the remaining five related party vendors were $196,000 for the nine months ended September 30, 2008.

Recently Issued Accounting Standards

In September 2006, the FASB issued SFAS No. 157, Fair Value Measurements. SFAS No. 157 defines fair value, establishes a framework for measuring fair value and expands disclosure of fair value measurements. SFAS No. 157 applies under other accounting pronouncements that require or permit fair value measurements and, accordingly, does not require any new fair value measurements. SFAS No. 157, as issued, was effective for financial statement issued for fiscal years beginning after November 15, 2007, and interim periods within those fiscal years. However, on February 12, 2008, the FASB issued FSP FAS No. 157-2, Effective Dates of FASB Statement No. 157, which delays the effective date of SFAS No. 157 for fiscal years beginning after November 15, 2008 for all nonfinancial assets and nonfinancial liabilities, except those that are recognized or disclosed at fair value in the financial statements on a recurring basis. The adoption of SFAS No. 157 did not have a material impact on our financial position or results of operations and financial condition.

In February 2007, the FASB issued SFAS No. 159, The Fair Value Option for Financial Assets and Financial Liabilities — Including an amendment of FASB Statement No. 115. This statement permits entities to choose to measure many financial instruments and certain other items at fair value that are not currently required to be measured at fair value and establishes presentation and disclosure requirements designed to facilitate comparisons between entities that choose different measurement attributes for similar types of assets and liabilities. SFAS No. 159 is effective for fiscal years beginning after November 15, 2007. The adoption of SFAS No. 159 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. 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. We do not expect the adoption to 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. Pre-acquisition contingencies are to be recognized at fair value, unless it is a non-contractual contingency that is not likely to materialize, in which case, nothing should be recognized in purchase accounting and, instead, that contingency would be subject to the recognition criteria of SFAS No. 5, Accounting for Contingencies. SFAS No. 141R is expected to have a significant impact on our accounting for business combinations closing on or after January 1, 2009.

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 expect the adoption of SFAS No. 161 to have no impact on our financial position or results of operations and financial condition.

In May 2008, the FASB issued SFAS No. 162, The Hierarchy of Generally Accepted Accounting Principles (“SFAS No. 162”). SFAS No. 162 identifies the sources of accounting principles and the framework for selecting the principles used in the preparation of financial statements that are presented in conformity with generally accepted accounting principles. SFAS No. 162 is effective 60 days following approval by the Securities and Exchange Commission of the Public Company Accounting Oversight Board’s amendments to AU Section 411, The Meaning of Present Fairly in Conformity with Generally Accepted Accounting Principles. The adoption of SFAS No. 162 will not affect our financial position or results of operations.

Reclassification

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

2. Acquisitions

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 $329.0 million and liabilities assumed of $14.3 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 preliminary estimated fair value of the assets acquired and liabilities assumed as of the date of acquisition (amounts in thousands):


Cash acquired	$	1,168
Other current assets		22,102
Property and equipment		138,906
Intangible asset and other assets		66,118
Goodwill		100,689

Total assets acquired	$	328,983

Current liabilities	$	10,655
Long-term debt		1,462
Other long term liabilities		2,182

Total liabilities assumed	$	14,299

Net assets acquired	$	314,684

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 each of the nine month periods ended September 30, 2008 and 2007. 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, 2007 or 2008, or what we may achieve in the future and should be read in conjunction with the accompanying historical financial statements.


	Pro Forma Nine Months Ended September 30,
	2008		2007
	(in thousands)
Total revenues	$	463,840	$	390,866
Net earnings	$	55,539	$	41,534
Earnings per common share
Basic	$	1.12	$	0.84
Diluted	$	1.10	$	0.83

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 $4.4 million were recorded in connection with the acquisition.

The acquisitions of the production services businesses from WEDGE, Competition and Paltec were accounted for as acquisitions of businesses. The purchase price allocations for the production services businesses are preliminary at this time and may change by a material amount once we receive finalized information regarding the fair value estimates of the assets acquired and liabilities assumed in the acquisition. Our purchase price allocation for the WEDGE acquisition changed due to an increase in our preliminary fair value estimate of intangible assets and other assets from $0.4 million at June 30, 2008 to $66.1 million at September 30, 2008 with an offsetting decrease to goodwill. Goodwill was recognized as part of the WEDGE and Competition acquisitions since the purchase price exceeded the estimated fair value of the assets acquired and liabilities assumed. We believe that the goodwill is related to the acquired workforces, future synergies between our existing Drilling Services Division and our new Production Services Division and the ability to expand our service offerings.

3. Long-term Debt

Long-term debt as of September 30, 2008 consists of the following (amounts in thousands):


Senior secured credit facility	$	275,500
Subordinated notes payable		6,455
Other		696

		282,651
Less current portion		(4,452	)

	$	278,199

Senior Secured Revolving Credit Facility

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 December 31, 2008 are 2.25% and 1.25%, 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 letter 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. The senior secured revolving credit facility replaced the $20.0 million credit facility we previously had with Frost National Bank. 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 October 31, 2008, we had $273.5 million outstanding under the revolving portion of the senior secured revolving credit facility and $8.3 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 $118.2 million at October 31, 2008. Principal payments of $2.0 million made after September 30, 2008 are classified in the current portion of long-term debt as of September 30, 2008. 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.

agreement could not exceed $350 million at any time (provided, however, that the commitment fee would continue to be calculated based on the total commitment of $400 million), and the per annum margin applicable to all amounts outstanding under the credit agreement would increase from the current rate of 2.25% for LIBOR rate borrowings and 1.25% for bank prime rate borrowings to 2.50% for LIBOR rate borrowings and 1.50% for bank prime rate borrowings. The required financial statements and our compliance certificate were delivered concurrently with the filing of the Quarterly Report on Form 10-Q for the quarterly period ended March 31, 2008 which occurred on August 5, 2008.

We were in compliance at September 30, 2008 with the covenants contained in the credit agreement which include 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. The credit agreement requires that we meet a maximum consolidated leverage ratio, a minimum interest coverage ratio and, if the leverage ratio is greater than 2.25 to 1.00, a minimum asset coverage ratio. 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.

Subordinated Notes Payable and Other

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 and a subordinated note payable to an employee that is a former shareholder of Paltec. These subordinated notes payable have interest rates ranging from 6% to 14%, require quarterly payments of principal and interest and have final maturity dates ranging from January 2009 to March 2013. The aggregate outstanding balance of these subordinated notes payable was $6.5 million as of September 30, 2008.

Other debt represents financing arrangements for computer software and hardware with an outstanding balance of $0.7 million at September 30, 2008.

4. Commitments and Contingencies

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 $41.5 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 and there is only a remote possibility that any such matter will require any additional loss accrual.

5. Earnings Per Common Share

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


	Three Months Ended September 30,				Nine Months Ended September 30,
	2008		2007		2008		2007
Basic
Net earnings	$	24,194	$	11,780	$	55,158	$	42,086

Weighted average shares		49,791		49,651		49,780		49,635

Earnings per share	$	0.49	$	0.24	$	1.11	$	0.85


	Three Months Ended September 30,				Nine Months Ended September 30,
	2008		2007		2008		2007
Diluted
Net earnings	$	24,194	$	11,780	$	55,158	$	42,086

Weighted average shares:
Outstanding		49,791		49,651		49,780		49,635
Diluted effect of stock options		658		554		646		558

		50,449		50,205		50,426		50,193

Earnings per share	$	0.48	$	0.23	$	1.09	$	0.84

6. Equity Transactions

Employees and former employees exercised stock options for the purchase of 143,054 shares of common stock during the nine months ended September 30, 2008 at prices ranging from $3.70 to $10.31 per share. Employees and former employees exercised stock options for the purchase of 56,500 shares of common stock during the nine months ended September 30, 2007 at prices ranging from $3.20 to $4.77 per share.

Employees and directors were awarded 178,261 shares of restricted stock with a weighted-average grant date price of $17.07 for the nine months ended September 30, 2008.

7. Segment Information

At September 30, 2008, 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 69 drilling rigs, 17 of which were operating in South Texas, 22 of which were operating in East Texas, eight of which were operating in North Texas, six of which were operating in Western Oklahoma, 11 of which were operating in the Rocky Mountain region and four of which were operating internationally in Colombia. In addition, we have exported a 1500 horsepower rig to Colombia that we expect to begin operating in November 2008. Currently, we are constructing two 1500 horsepower drilling rigs that we expect to be completed and available for operation in the United States in December 2008 and March 2009.

Production Services Division – Our Production Services Division provides well services, wireline services and fishing and rental services:

•

Well services are provided with a fleet of 70 rigs (sixty-five 550 horsepower rigs, four 600 horsepower rigs and one 400 horsepower rig) and pump packages capable of working at depths of 20,000 feet to complete, maintain, and workover oil and natural gas producing wells.

•

Wireline services provide open and cased-hole wireline services with a fleet of 55 wireline units. Services include radial and standard cement bond logging with gamma-ray-neutron, casing calipers, temperature logging, pipe recovery, bridge plugs and a full range of perforating. In addition, the group operates the latest pulsed-neutron technology in through-casing logs, utilizing a direct, deeper-reading neutron detector.

•

Fishing and rental services are provided though approximately $15 million of fishing and rental tool equipment, air drilling equipment, power swivels and blowout preventers.

The following tables set forth certain financial information for our two operating segments and corporate as of and for the three months and nine months ended September 30, 2008 (amounts in thousands):


	As of and for the Three Months Ended September 30, 2008
	Drilling Services Division		Production Services Division		Corporate		Total
Identifiable assets	$	545,863	$	388,687	$	25,526	$	960,076

Revenues	$	124,297	$	49,948	$	—	$	174,245
Operating costs		70,342		25,025		—		95,367

Segment margin	$	53,955	$	24,923	$	—	$	78,878

Depreciation and amortization	$	16,754	$	7,368	$	103	$	24,225
Capital expenditures	$	29,560	$	16,893	$	918	$	47,371

	As of and for the Nine Months Ended September 30, 2008
	Drilling Services Division		Production Services Division		Corporate		Total
Identifiable assets	$	545,863	$	388,687	$	25,526	$	960,076

Revenues	$	333,587	$	106,602	$	—	$	440,189
Operating costs		198,115		53,871		—		251,986

Segment margin	$	135,472	$	52,731	$	—	$	188,203

Depreciation and amortization	$	48,900	$	12,739	$	285	$	61,924
Capital expenditures	$	72,673	$	26,875	$	1,228	$	100,776

The following table reconciles the segment profits reported above to income from operations as reported on the condensed consolidated statements of operations for the three months and nine months ended September 30, 2008 (amounts in thousands):


	Three Months Ended September 30, 2008			Nine Months Ended September 30, 2008
Segment margin	$	78,878		$	188,203
Depreciation and amortization		(24,225	)		(61,924	)
Selling, general and administrative		(12,840	)		(32,712	)
Bad debt (expense) recovery		260			216

Income from operations	$	42,073		$	93,783

The following table sets forth certain financial information for our international operations in Colombia as of and for the three months and nine months ended September 30, 2008 which is included in our Drilling Services Division (amounts in thousands):

ITEM 2.

MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Statements we make in the following discussion that express a belief, expectation or intention, as well as those 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, risks associated with the current global economic crisis and its impact on capital markets and liquidity, the continued strength or weakness of the oil and gas production industry in the geographic areas in which we operate including price of oil and natural gas in general , and the recent precipitous decline in prices in particular, and the impact of commodity prices and other factors upon future decisions about onshore exploration and development projects to be made by oil and gas companies and their ability to obtain necessary financing, the highly competitive nature of our business, difficulty in integrating the services of acquired companies, including the production services businesses of WEDGE, Competition and Paltec in an efficient and effective manner, the availability, terms and deployment of capital, 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, in our transition report on Form 10-KT for the fiscal year ended December 31, 2007 and in our quarterly report on Form 10-Q for the period ended March 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, in our transitional report on Form 10-KT for the fiscal year ended December 31, 2007, or in our quarterly report on Form 10-Q for the period ended March 31, 2008 could also have material adverse effects 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.

Company Overview

Pioneer Drilling Company is a multi-national oilfield services company that 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. Over the years, our business has grown through acquisitions and through organic growth. Since September 1999, we have significantly expanded our drilling rig fleet by adding 42 rigs through acquisitions and by adding 26 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”) and Prairie Investors d/b/a Competition Wireline (“Competition”) which provide well services, wireline services and fishing and rental services. These 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.

Business Segments

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 1, Financial Statements, of this Quarterly Report on Form 10-Q.

•

Drilling Services Division – Our Drilling Services Division provides contract land drilling services with its fleet of 69 drilling rigs, 17 of which are operating in South Texas, 22 of which are operating in East Texas, eight of which are operating in North Texas, six of which are operating in Western Oklahoma, 11 of which are operating in the Rocky Mountain region and four of which are operating internationally in Colombia. In addition, we have exported a 1500 horsepower rig to Colombia that we expect to begin operating in November 2008. Currently, we are constructing two 1500 horsepower drilling rigs that we expect to be completed and available for operation in the United States in December 2008 and March 2009, respectively. In addition to our drilling rigs, we provide the drilling crews and most of the ancillary equipment needed to operate our drilling rigs. We obtain our contracts for drilling oil and natural gas wells either through competitive bidding or through direct negotiations with customers. Our drilling contracts generally provide for compensation on either a daywork, 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.

•

Production Services Division – Our Production Services Division earns revenues for well services, wireline services and fishing and rental services based on purchase orders, contracts or other persuasive evidence of an arrangement with the customer, such as master service agreements, that include fixed or determinable prices. These production services revenues are recognized when the services have been rendered and collectability is reasonably assured.

•

Well services are provided with a fleet of 70 rigs (sixty-five 550 horsepower rigs, four 600 horsepower rigs and one 400 horsepower rig) with pump packages capable of working at depths of 20,000 feet to complete, maintain, and workover oil and natural gas producing wells.

•

Fishing and rental services are provided though approximately $15 million of fishing and rental tool equipment, air drilling equipment, power swivels and blowout preventers.

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.

Business Strategy

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:

•

Expand our Operations into International Markets – In early 2007, we announced our intention to expand internationally and began negotiating drilling contracts in Colombia. We are currently operating four drilling rigs in Colombia and have exported a 1500 horsepower drilling rig that we expect will begin operating in Colombia in November 2008.

•

Pursue Opportunities into Other Oilfield Services – We strive to mitigate the cyclical risk in oilfield services by complimenting our drilling services with certain production services. 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 with a fleet of 62 workover rigs, 51 wireline units and approximately $13 million of fishing and rental tools equipment through its facilities in Texas, Kansas, North Dakota, Colorado, Utah, Montana and Oklahoma. These acquisitions resulted in the formation of our Production Services Division operating segment. In August 2008, we continued our production services growth with the acquisition of Paltec, Inc. (Paltec) which provides wireline services with four wireline units operating in Texas.

•

Continue Growth with Select Capital Deployment – We intend to continue growing our business by making selective acquisitions, continuing new-build programs and / or upgrading our existing assets. Our capital investment decisions are determined by an analysis of the projected return on capital employed on each of those alternatives. Acquisitions and new-build opportunities that support our long term strategy are also evaluated for “fit” with our current geographic locations and risk assessments are performed. We are currently constructing two 1500 horsepower drilling rigs that we expect to be completed and available for operation in the United States in December 2008 and March 2009, respectively. In addition, we will take delivery of four new workover rigs and four wireline units before year end 2008, and six new workover rigs and six wireline units during 2009.

Market Conditions in Our Industry

During recent months, 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 could have an adverse effect on our business environment. Our customers may curtail their drilling programs and reduce their production activities, which could result in a decrease in demand for drilling and production services and a reduction in day rates and/or 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. As oil and natural gas prices have risen, exploration and production companies have generally increased their drilling and workover activities. Generally, domestic exploration and production spending has increased over the last three years as oil and natural gas prices have increased. Oil and natural gas prices have declined significantly in recent months in a deteriorating global economic environment and several exploration and production companies have announced cuts in their exploration budgets for 2009. These reductions in oil and gas exploration budgets may result in a reduction in our rig utilization and revenue rates in 2009. In addition, during periods of reduced demand for drilling rigs, 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 II of this Quarterly Report on Form 10-Q.

On October 24, 2008 the spot price for West Texas Intermediate crude oil was $63.15, the spot price for Henry Hub natural gas was $6.29 and the Baker Hughes land rig count was 1,867, a 9.2% increase from 1,710 on November 2, 2007. 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 nine months ended September 30, 2008 and each of the previous five years ended September 30, 2008 were:


	Nine Months Ended September 30, 2008		Years Ended September 30,
	Nine Months Ended September 30, 2008		2008		2007		2006		2005		2004
Oil (West Texas Intermediate)	$	113.93	$	108.31	$	64.87	$	66.19	$	53.72	$	37.10
Natural Gas (Henry Hub)	$	9.65	$	8.96	$	6.85	$	7.97	$	7.36	$	5.55
U.S. Land Rig Count		1,783		1,764		1,646		1,479		1,203		1,038
U.S. Workover Rig Count		2,529		2,499		2,383		2,334		2,172		2,049

Increased expenditures for exploration and production activities generally leads to increased demand for our drilling services and production services. Over the past several years, rising oil and natural gas prices and the corresponding increase in onshore oil and natural gas exploration and production spending have 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 over the previous five years 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.

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 substantially 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 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 relatively insensitive to commodity price volatility. Discretionary operating expenditure work is evaluated according to a simple short-term payout criterion which is far less dependent on commodity price forecasts.

Our business is influenced substantially by both operating and capital expenditures by exploration and production companies. Because existing oil and natural gas wells require ongoing spending to maintain production, expenditures by exploration and production companies for the maintenance of existing wells are relatively stable and predictable. In contrast, capital expenditures by exploration and production companies for exploration and drilling are more directly influenced by current and expected oil and natural gas prices and generally reflect the volatility of commodity prices.

Liquidity and Capital Resources

Sources of Capital Resources

Our principal sources of liquidity consist of: (i) cash and cash equivalents (which equaled $17.3 million as of September 30, 2008); (ii) cash generated from operations; and (iii) the unused portion of our senior secured revolving credit facility which has borrowing availability of $118.2 million as of October 31, 2008. Our principal liquidity requirements have been for working capital needs, capital expenditures and acquisitions.

At September 30, 2008, we held $16.5 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, backed by assets that are equal to or greater than 200% of the liquidation preference and guaranteed by monoline bond insurance companies. 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 September 30, 2008 was $14.6 million compared with a par value of $16.5 million. The $1.9 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. We sold $0.6 million of our ARPSs at par on October 1, 2008, accordingly, these ARPSs are classified in other current assets at September 30, 2008 on our condensed consolidated balance sheet. The remaining fair value of our ARPSs of $14.0 million is classified with other long-term assets because of our inability to determine the recovery period of our investment.

Uses of Capital Resources

On March 1, 2008, we acquired the production services business of 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 tools equipment through facilities in Texas, Kansas, North Dakota, Colorado, Montana, Utah and Oklahoma. The aggregate purchase price for the acquisition was approximately $314.7 million, which consisted of assets acquired of $329.0 million and liabilities assumed of $14.3 million. The aggregate purchase price included $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 new $400 million senior secured revolving credit facility.

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.

On August 29, 2008, we acquired the wireline services business from Paltec. 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 $4.4 million were recorded in connection with the acquisition.

For the nine months ended September 30, 2008, we had $100.8 million of additions to our property and equipment. For the remainder of fiscal year 2008, we project capital expenditures to be approximately $52.5 million, comprised of new rig and equipment expenditures of approximately $30.5 million, routine capital expenditures of approximately $16.3 million, and non-routine capital expenditures of approximately $5.7 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.

Working Capital

Our working capital was $60.4 million at September 30, 2008, compared to $99.8 million at December 31, 2007. Our current ratio, which we calculate by dividing our current assets by our current liabilities, was 1.7 at September 30, 2008 compared to 3.4 at December 31, 2007.

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


	September 30, 2008		December 31, 2007		Change
	(In thousands)
Cash and cash equivalents	$	17,342	$	76,703	$	(59,361	)
Receivables		87,436		47,370		40,066
Unbilled receivables		18,676		7,861		10,815
Deferred income taxes		7,013		3,670		3,343
Inventory		4,448		1,180		3,268
Prepaid expenses and other current assets		8,775		5,073		3,702

Current assets		143,690		141,857		1,833

Accounts payable		30,906		21,424		9,482
Current portion of long-term debt		4,452		—		4,452
Income taxes payable		4,698		—		4,698
Prepaid drilling contracts		3,447		1,933		1,514
Accrued payroll and related employee costs		14,934		5,172		9,762
Accrued insurance premiums deductibles		17,484		9,548		7,936
Other accrued expenses		7,359		3,973		3,386

Current liabilities		83,280		42,050		41,230

Working capital	$	60,410	$	99,807	$	(39,397	)

The decrease in cash and cash equivalents was primarily due to our use of $99.8 million for certain property and equipment expenditures, debt payments of $44.4 million, $36.4 million of cash to fund the WEDGE, Competition and Paltec acquisitions and $16.5 million used to purchase ARPSs in January 2008 that are recorded as other current assets and other long term assets as of September 30, 2008. This overall decrease in cash and cash equivalents was offset by $125.8 million of cash provided by operating activities and borrowings under the credit line of $8.0 million.

The increase in our receivables at September 30, 2008 as compared to December 31, 2007 was due to receivables of $23.5 million at September 30, 2008 that relate to our new Production Services Division that was formed when we acquired the production services businesses of WEDGE and Competition on March 1, 2008 and an increase in receivables of $17.2 million for our Drilling Services Division at September 30, 2008 which includes a $5.7 million increase relating to our Colombian operations. The increase in receivables for our Drilling Services Division is due to a $1,083 per day increase in average revenue rates and a 13% increase in the number of revenue days for the quarter ended September 30, 2008, compared to the quarter ended December 31, 2007.

The increase in unbilled receivables at September 30, 2008 as compared to December 31, 2007 was primarily due to unbilled receivables of $2.0 million at September 30, 2008 that relate to our new Production Services Division and an increase in unbilled receivables of $5.0 million that relate to our drilling contracts in Colombia.

The increase in inventory at September 30, 2008 as compared to December 31, 2007 was primarily due to the addition of inventory of $1.6 million for our new Production Services Division and an increase of $1.6 million of inventory primarily related to our third and fourth drilling rigs that began operating in Colombia in February 2008 and August 2008. We maintain inventories of replacement parts and supplies for our drilling rigs operating in Colombia to ensure efficient operations in geographically remote areas.

Most of our prepaid expenses and other current assets consist of prepaid insurance and deferred mobilization costs. The increase at September 30, 2008 as compared to December 31, 2007 is primarily due to an increase of $4.5 million in prepaid expenses and other current assets of our Colombian operations that related to our third and fourth drilling rigs that began operating in Colombia in February 2008 and August 2008, respectively. In addition, our new Production Services Division contributed $0.8 million to the increase in prepaid expenses and other current assets. The overall increase in prepaid expenses and other current assets was partially offset by a decrease in prepaid insurance. We renew and pay most of our insurance premiums in late October of each year and some in April of each year. As of September 30, 2008, we had amortization of 11 months of these October insurance premiums, as compared to two months of amortization as of December 31, 2007.

The increase in accounts payable at September 30, 2008 as compared to December 31, 2007 was primarily due to accounts payable of $7.8 million for our new Production Services Division and an increase of $1.9 million in accounts payable for our Colombian operations.

The increase in the current portion of long-term debt at September 30, 2008 is primarily due to principal payments that were made after September 30, 2008 to reduce the outstanding balance of our senior secured revolving credit facility and the current portion of our subordinated notes payable. 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 increase in accrued payroll and related employee costs was due to an increase in the number of employees primarily due to our new Production Services Division, an increase in the number of days in the payroll accrual and an additional accrual for the severance payout in connection with the resignation of the former Chief Financial Officer.

The increase in accrued insurance premiums and deductibles was primarily due to increases in costs incurred for the self-insurance portion of our health and workers compensation insurance and other insurance costs during the nine months ended September 30, 2008 as compared to December 31, 2007.

Long Term Debt

Long-term debt as of September 30, 2008 consists of the following (amounts in thousands):


Senior secured credit facility	$	275,500
Subordinated notes payable		6,455
Other		696

		282,651
Less current portion		(4,452	)

	$	278,199

Contractual Obligations

The following table includes all our contractual obligations of the types specified below at September 30, 2008 (amounts in thousands):


	Payments Due by Period
Contractual Obligations	Total		Less than 1 year		1-3 years		4-5 years		More than 5 years
Long-term debt	$	282,651	$	4,452	$	3,399	$	274,800	$	—
Interest on long term debt		73,950		15,404		32,113		26,433		—
Purchase commitments		66,025		66,025		—		—		—
Operating leases		4,482		1,385		1,920		1,089		88
Restricted cash obligation		4,137		1,537		1,300		1,300		—
Other		490		390		100		—		—

Total	$	431,735	$	89,193	$	38,832	$	303,622	$	88

Long-term debt consists of $275.5 million outstanding under our senior secured credit facility, $6.5 million outstanding under subordinated notes payable to certain employees that are former shareholders of previously acquired production services businesses and other debt of $0.7 million. The outstanding balance under our senior secured credit facility is not due until maturity on February 28, 2013, but principal payments of $2.0 million made after September 30, 2008 are classified in the current portion of long-term debt as of September 30, 2008. 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 (1) interest rates that are in effect on October 31, 2008, (2) $2.0 million of principal payments that have been made after September 30, 2008 to reduce the outstanding principal balance, and (3) the remaining principal balance of $273.5 million to be paid at maturity in February 2013. Interest payment obligations on our subordinated notes payable are based on interest rates ranging from 6% to 14%, with quarterly payments of principal and interest and final maturity dates ranging from January 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 September 30, 2008, we had restricted cash in the amount of $3.3 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. In addition, we had restricted cash in the amount of $0.9 million in a trust account that will be distributed to the former Chief Financial Officer on March 2, 2009 in accordance with the terms of the severance agreement.

Debt Requirements

Effective June 11, 2008, we entered into a Waiver Agreement with the Lenders to waive the requirement to provide certain financial statements in conjunction with our compliance certificate within the time period required by the credit agreement. The Waiver Agreement required us to provide the financial statements and our compliance certificate on or before August 13, 2008. Until we provided these financial statements and our compliance certificate, the aggregate principal amount outstanding under the credit agreement could not exceed $350 million at any time (provided, however, that the commitment fee would continue to be calculated based on the total commitment of $400 million), and the per annum margin applicable to all amounts outstanding under the credit agreement would increase from the current rate of 2.25% for LIBOR rate borrowings and 1.25% for bank prime rate borrowings to 2.50% for LIBOR rate borrowings and 1.50% for bank prime rate borrowings. The required financial statements and our compliance certificate were delivered concurrently with the filing of the Quarterly Report on Form 10-Q for the quarterly period ended March 31, 2008 which occurred on August 5, 2008.

We were in compliance at September 30, 2008 with all covenants contained in the credit agreement for our senior secured revolving credit facility which include 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. The credit agreement requires that we meet a maximum consolidated leverage ratio, a minimum interest coverage ratio and, if the leverage ratio is greater than 2.25 to 1.00, a minimum asset coverage ratio. 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.

Results of Operations

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.

Statement of Operations Analysis

The following table provides information for our operations for the three and nine months ended September 30, 2008 and 2007 (amounts in thousands, except average number of drilling rigs, utilization rate and revenue days information):


	Three Months Ended September 30,						Nine Months Ended September 30,
	2008			2007			2008			2007
Drilling Services Division:
Revenues	$	124,297		$	106,516		$	333,587		$	312,642
Operating costs		70,342			65,237			198,115			186,822

Drilling Services Division margin	$	53,955		$	41,279		$	135,472		$	125,820

Average number of drilling rigs		68.0			67.3			67.0			65.7
Utilization rate		96	%		90	%		90	%		90	%
Revenue days		6,017			5,559			16,528			16,149

Average revenues per day	$	20,658		$	19,161		$	20,183		$	19,360
Average operating costs per day		11,691			11,735			11,987			11,569

Drilling Services Division margin per day	$	8,967		$	7,426		$	8,196		$	7,791

Production Services Division:
Revenues	$	49,948		$	—		$	106,602		$	—
Operating costs		25,025			—			53,871			—

Production Services Division margin	$	24,923		$	—		$	52,731		$	—

EBITDA	$	64,747		$	33,411		$	154,318		$	109,440

We present Drilling Services Division margin, Production Services Division margin and earnings before interest, taxes, depreciation and amortization (“EBITDA”) as measures of our operating performance because we believe that these measures allow management and investors to make a direct comparison between us and our competitors, without regard to differences in capital structure or to differences in the cost basis of our rigs and those of our competitors. Since Drilling Services Division margin, Production Services Division margin and EBITDA information are “non-GAAP” financial measures under the rules and regulations of the SEC, we have included below a reconciliation of Drilling Services Division margin, Production Services Division margin and EBITDA to net earnings, which is the nearest comparable GAAP financial measure.


	Three Months Ended September 30,						Nine Months Ended September 30,
	2008			2007			2008			2007
	(amounts in thousands)
Reconciliation of combined Drilling Services Division margin and Production Services Division margin and EBITDA to net earnings:
Drilling Services Division margin	$	53,955		$	41,279		$	135,472		$	125,820
Production Services Division margin		24,923			—			52,731			—

Combined margin		78,878			41,279			188,203			125,820

Selling, general and administrative		(12,840	)		(5,252	)		(32,712	)		(13,792	)
Bad debt (expense) recovery		260			(2,627	)		216			(2,627	)
Other income (expense)		(1,551	)		11			(1,389	)		39

EBITDA		64,747			33,411			154,318			109,440

Depreciation and amortization		(24,225	)		(16,093	)		(61,924	)		(46,927	)
Interest income (expense), net		(3,568	)		717			(8,617	)		2,459
Income tax expense		(12,760	)		(6,255	)		(28,619	)		(22,886	)

Net earnings	$	24,194		$	11,780		$	55,158		$	42,086

Our Drilling Services Division’s revenues increased by $17.8 million, or 17%, for the quarter ended September 30, 2008, as compared to the corresponding quarter in 2007, due to an 8% increase in revenue days that resulted from a 6% increase in utilization rates. The increase in Drilling Services Divisions revenues is also due to an increase in average contract drilling revenues of $1,497 per day, or 8%, that resulted from an increased demand for drilling rigs and higher revenues per day earned by our expanding Colombian operations.

Our Drilling Services Division’s revenues increased by $20.9 million, or 7%, for the nine months ended September 30, 2008, as compared to the corresponding period in 2007, primarily due to a 2% increase in revenue days that resulted from an increase in the number of drilling rigs in our fleet and an increase in average contract drilling revenues of $823 per day, or 4%, that resulted from an increased demand for drilling rigs and higher revenues per day earned by our expanding Colombian operations.

Our Drilling Services Division’s operating costs grew by $5.1 million, or 8%, for the quarter ended September 30, 2008, as compared to the corresponding period in 2007, primarily due to an 8% increase in revenue days that resulted from a 6% increase in utilization.

Our Drilling Services Division’s operating costs grew by $11.3 million, or 6%, for the nine months ended September 30, 2008, as compared to the corresponding period in 2007, due to a 2% increase in revenue days that resulted from an increase in the number of drilling rigs in our fleet. This increase in our Drilling Services Division’s operating costs is also due to an increase in average contract drilling operating costs of $418 per day, or 4%, that resulted primarily from higher operating costs per day for our Colombian operations which has higher labor and fuel costs when compared to drilling operations in the United States.

Our Production Services Division’s revenue of $49.9 million and operating costs of $25.0 million for the quarter ended September 30, 2008 and $106.6 million revenue and operating costs of $53.9 million for the nine months ended September 30, 2008 are based on the operating results for this new operating segment which was created on March 1, 2008 when we acquired the production services businesses of WEDGE and Competition.

Our selling, general and administrative expense for the quarter ended September 30, 2008 increased by approximately $7.6 million, or 144%, compared to the corresponding quarter in 2007. The increase resulted from $1.3 million in additional compensation-related expenses incurred for existing and new employees in our corporate office which includes $0.9 million paid to the former chief financial officer based on the severance agreement. Professional and consulting expenses increased $2.0 million during the quarter ended September 30, 2008 primarily due to the investigation conducted by the special committee. In addition, we incurred $4.4 million and $0.1 million of additional selling, general and administrative expenses relating to our Production Service Division and our Colombian operations, respectively.

Our selling, general and administrative expense for the nine months ended September 30, 2008 increased by approximately $18.9 million, or 137%, compared to the corresponding period in 2007. The increase resulted from $3.5 million in additional compensation-related expenses incurred for existing and new employees in our corporate office which includes $0.9 million paid to the former Chief Financial Officer. Professional and consulting expenses increased $4.2 million during the nine months ended September 30, 2008 which includes approximately $3.1 million due to the investigation conducted by the special committee. In addition, we incurred $10.3 million and $1.0 million of additional selling, general and administrative expenses relating to our Production Service Division and our Colombian operations, respectively.

Our other income for the quarter ended September 30, 2008 decreased by $1.6 million compared to the corresponding quarter in 2007 and decreased by $1.4 million for the nine months ended September 30, 2008, primarily due to foreign currency translation losses relating to our operations in Colombia.

Our depreciation and amortization expenses increased by $8.1 million, or 50%, for the quarter ended September 30, 2008 and increased by $15.0 million, or 32%, for the nine months ended September 30, 2008, when compared to the corresponding periods in 2007. The increases resulted primarily from additional depreciation and amortization expense of $7.4 million which includes an increase in amortization expense of intangible assets of $3.5 million during the quarter ended September 30, 2008, for our new Production Services Division. Additional depreciation and amortization expense of $12.7 million for the nine month period relates to our new Production Services Division. The increases are also due to the increases in the average size of our drilling rig fleet, which increases consisted of newly constructed rigs. Partially offsetting the increases in depreciation and amortization expense were decreases of approximately $0.9 million and $2.8 million for the quarter and nine month periods, respectively, resulting from the change in the estimated useful lives of a group of 19 drilling rigs from an average useful life of 9 years to 12 years.

Interest expense for the quarter and nine months ended September 30, 2008 is related to interest due on the amounts outstanding under our new senior secured revolving credit facility which was used to fund the acquisitions of the production services businesses of WEDGE and Competition on March 1, 2008.

Our effective income tax rates of 34.5%, for the quarter ended September 30, 2008 and 34.2% for the nine months ended September 30, 2008, differ from the federal statutory rate of 35% primarily due to tax benefits in foreign jurisdictions, tax benefits recognized for previously unrecognized deferred tax assets and state income taxes.

Inflation

Due to the increased rig count in each of our market areas, availability of personnel to operate our rigs is 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.

We are experiencing 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% in fiscal year 2007. We expect similar cost increases during the remainder of the fiscal year ending December 31, 2008.

Off Balance Sheet Arrangements

We do not currently have any off balance sheet arrangements.

Critical Accounting Policies and Estimates

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” 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 collectability is reasonably assured.

Asset impairments – We assess the impairment of property and equipment whenever events or circumstances indicate that the carrying value may not be recoverable. Factors that we consider important and which could trigger an impairment review would be our customers’ financial condition, local conditions in a particular market and any significant negative industry or economic trends. More specifically, among other things, we consider our contract revenue rates; our utilization rates; cash flows from our drilling rigs, workover rigs, wireline units and fishing and rental tools equipment; current oil and gas prices, rig counts and trends in the price of used equipment observed by our management. If a review of our property and equipment indicates that our carrying value exceeds the estimated undiscounted future net cash flows, we are required under applicable accounting standards to write down the property and equipment to its fair market value. A one percent write-down in our net property and equipment, at September 30, 2008, would have resulted in a corresponding decrease in our net earnings of approximately $3.9 million for the three months ended September 30, 2008.

Goodwill Impairments – 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 and other intangible assets not subject to amortization are tested for impairment annually, or more frequently if events or changes in circumstances indicate that the asset might be impaired. 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. 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. The amount of impairment for goodwill is measured as the excess of its carrying value over its fair value.

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 5 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 nine months ended September 30, 2008, we experienced losses on six of the 65 turnkey and footage contracts completed, with a loss of less than $25,000 each on three of these contracts and a loss of less than $125,000 each on the remaining 3 contracts. 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 two footage contracts in progress at September 30, 2008, which were completed prior to the release of the financial statements included in this report. Our unbilled receivables totaled $18.7 million at September 30, 2008. Of that amount accrued, turnkey and footage contract revenues were $0.5 million. The remaining balance of $16.2 million related to the revenue recognized but not yet billed on daywork drilling contracts in progress at September 30, 2008 and $2.0 million related to unbilled receivables for our Production Services Division.

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 $0.3 million at September 30, 2008 and no allowance for doubtful accounts at December 31, 2007.

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 3 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. Effective January 1, 2008, we reassessed the estimated useful lives assigned to a group of 19 drilling rigs that were recently constructed. These drilling rigs were constructed with new components that have longer estimated useful lives when compared to other drilling rigs that are equipped with older components. As a result, we increased the estimated useful lives for this group of recently constructed drilling rigs from an average useful life of 9 years to 12 years. This change in the estimated useful lives of this group of 19 drilling rigs resulted in a $2.8 million decrease in depreciation and amortization expense for the nine months ended September 30, 2008.

As of September 30, 2008, we had foreign net operating losses for tax purposes and other tax benefits available to reduce future taxable income in a foreign jurisdiction. The valuation allowance in the amount of $1.6 million offsets in part our foreign net operating losses and other tax benefits. In assessing the realizability of our foreign deferred tax assets, we recognized a tax benefit to the extent of taxable income we expect to earn over the terms of four existing drilling contracts in the foreign jurisdiction. The term of one contract expires in February 2009, and the remaining three contracts are based on a fixed number of wells anticipated to be

completed in February 2009, March 2009 and June 2009, respectively. If one or more of these contracts are extended or renewed or new contracts are entered into, then we expect to recognize additional tax benefits to the extent projected future taxable income increases. 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. We exported a 1500 horsepower drilling rig to Colombia in October 2008. To obtain this special income tax benefit, our U.S operating company sold this drilling rig in October 2008 to Stayton Asset Group, a variable interest entity established for this transaction for which we are the primary beneficiary. Stayton Asset Group immediately sold this drilling rig to our operating entity in Colombia.

Our accrued insurance premiums and deductibles as of September 30, 2008 include accruals for costs incurred under the self-insurance portion of our health insurance of approximately $0.8 million and our workers’ compensation, general liability and auto liability insurance of approximately $10.4 million. We have a deductible of $125,000 per covered individual per year under the health insurance, except for individuals employed by our Production Services Division where we have no deductible. 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.

Recently Issued Accounting Standards

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. We do not expect the adoption to 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. Pre-acquisition contingencies are to be recognized at fair value, unless it is a non-contractual contingency that is not likely to materialize, in which case, nothing should be recognized in purchase accounting and, instead, that contingency would be subject to the recognition criteria of SFAS No. 5, Accounting for Contingencies. SFAS No.141R is expected to have a significant impact on our accounting for business combinations closing on or after January 1, 2009.

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 expect the adoption of SFAS No. 161 to have no impact on our financial position or results of operations and financial condition.

ITEM 3.

QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Interest Rate Risk

We are subject to interest rate market risk on our variable rate debt. As of September 30, 2008, we had $275.5 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 $0.7 million and a decrease in net income of approximately $0.5 million during a quarterly period.

At September 30, 2008, we held $16.5 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, backed by assets that are equal to or greater than 200% of the liquidation preference and guaranteed by monoline bond insurance companies. 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 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 September 30, 2008 was $14.6 million compared with a par value of $16.5 million. The $1.9 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. We sold $0.6 million of our ARPSs at par on October 1, 2008, accordingly, these ARPSs are classified in other current assets at September 30, 2008 on our condensed consolidated balance sheet. The remaining fair value of our ARPSs of $14.0 million is classified with other long-term assets because of our inability to determine the recovery period of our investment.

Foreign Currency Risk

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.

The impact of currency rate changes on our Colombian Peso denominated transactions and balances resulted in a foreign currency losses of $1.6 million and $1.7 million for the three and nine month periods ended September 30, 2008, respectively.

ITEM 4.

CONTROLS AND PROCEDURES

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 September 30, 2008 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 September 30, 2008 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

On March 1, 2008, we completed the acquisitions of the production services businesses of WEDGE and Competition. We are in the process of transferring accounting processes for the new acquisition to our headquarters and into our existing internal control processes. The integration will lead to changes in these controls in future fiscal periods but we do not expect these changes to materially affect our internal controls over financial reporting. Consistent with published guidance of the SEC, our management excluded the acquired companies from the scope of its assessment of internal control over financial reporting as of September 30, 2008. Total assets and total revenues from the acquisitions represented approximately 41% and 24%, respectively, of the related consolidated financial statement amounts of the Company as of and for the nine months ended September 30, 2008.

Investigation by the Special Subcommittee of the Board of Directors

On May 12, 2008, the Company announced a delay in filing its Form 10-Q for the quarter ended March 31, 2008 (the “Quarterly Report”), as a result of certain questions raised with respect to the effectiveness of the Company’s internal control over financial reporting. On May 15, 2008, the Board of Directors formed a special subcommittee of the Board (the “Special Committee”) to investigate the questions raised regarding the Company’s internal control over financial reporting and to determine whether such weaknesses, if any, have materially affected the Company’s financial statements The Special Committee engaged Bracewell & Giuliani LLP (“Bracewell”), as independent legal counsel, and Deloitte & Touche LLP (“Deloitte”), as independent forensic accountants, to assist in the investigation.

In July 2008, after an extensive document review and interviewing relevant current and former employees and vendors, Bracewell presented their report to the Special Committee. After consideration of the report, the Special Committee then met with the Board of Directors, at which meeting Bracewell also presented its report to the Board of Directors, to discuss the report and present the Special Committee’s recommendations.

After reviewing the report, the Special Committee and the Board of Directors concluded that they were not aware of any facts that caused them to believe that there was any material misstatement of the Company’s historical financial statements or in the financial statements proposed to be included in the Quarterly Report.

Furthermore, based on the Bracewell report, the Special Committee and the Board do not believe that the questions raised constituted a material weakness in the Company’s internal control over financial reporting. The Bracewell report, however, did identify certain control deficiencies and made recommendations, that have been adopted by the Board of Directors, to enhance the Company’s governance and control environment.

The Bracewell report noted some deficiencies in the Company’s manual process to record purchases and process expenditures, for both expense and capital expenditures. While there were certain compensating controls that mitigated the financial reporting risks associated with these deficiencies, the Bracewell report recommended that the Company implement a more effective systematic purchase order application integrated with the general ledger. Consistent with the recommendation in the Bracewell report, the Company intends to enhance its current process by expanding, upgrading, better systematizing and making prospective its current purchase order system.

The Bracewell report and the Special Committee’s review also noted the desirability to improve communications and more clearly delineate roles and responsibilities within the Company. As recommended in the Bracewell report, the Company intends to hire a general counsel and chief compliance officer, to further define roles and responsibilities, and to undertake a series of training initiatives.

The Bracewell report also reviewed certain matters related to the Company’s Colombian operations. In light of the recent commencement of these operations and cultural and other issues involved in integrating them into the Company and its systems, including documentation procedures, the Bracewell report recommended, and the Board has already begun to focus on, additional oversight of these operations as the Company continues the intended expansion in this market.

Finally, the Board has directed management to consider and report back to the Board with respect to the implementation of additional controls and procedures. These include a disclosure committee comprised of representatives from operations, compliance and finance and accounting and a quarterly subcertification and management representation process with signoff by segment and service line operating executives and controllers, corporate accounting managers and other personnel involved in the financial reporting process. These processes should enhance internal accountability for our financial statements.

PART II. OTHER INFORMATION

ITEM 1.

LEGAL PROCEEDINGS

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.

ITEM 1A.

RISK FACTORS

While we attempt to identify, manage and mitigate risks and uncertainties associated with our business to the extent practical under the circumstances, some level of risk and uncertainty will always be present. Part I, Item 1A of our Transition Report on Form 10-KT for the fiscal year ended December 31, 2007, Part II, Item 1A of our Quarterly Report on Form 10-Q for the quarterly period ended March 31, 2008 and the additional risk factors set forth below in this Part II, Item 1A of this Quarterly Report on Form 10-Q describe some of the risks and uncertainties associated with our business that have the potential to materially affect our business, financial condition or results of operations. Additional risks and uncertainties not presently known to us or that we currently believe are immaterial also may negatively impact our business, financial condition or operating results.

Set forth below are various risks and uncertainties that could adversely impact our business, financial condition, results of operations and cash flows.

As a result of recent volatility in oil and natural gas prices and substantial uncertainty in the capital markets due to the deteriorating global economic environment, we are unable to determine whether customers will reduce spending on exploration and production or whether customers and/or vendors and suppliers will be able to access financing necessary to sustain their current level of operations, fulfill their commitments and/or fund future operations and obligations. The deteriorating global economic environment may impact industry fundamentals, and the potential resulting decrease in demand for drilling and production services could adversely affect our business

The success of our business largely depends on 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.

Oil and natural gas prices, and market expectations of potential changes in these prices, significantly impact the level of worldwide drilling and production services activities. Oil and natural gas prices have declined significantly during recent months in a deteriorating global economic environment. A sustained decline in oil and natural gas prices could cause exploration and production companies to reduce their overall level of drilling and production services activity and spending. When drilling and production activity and spending declines, both day rates and utilization have historically declined. As a result, the recent volatility in oil and natural gas prices and the global economic crisis could materially and adversely affect our business and financial results.

Moreover, the deteriorating global economic environment may impact fundamentals that are critical to our industry, such as the global demand for, and consumption of, oil and natural gas. Reduced demand for oil and natural gas generally results in lower prices for these commodities and may impact the economics of planned drilling projects and ongoing production projects, resulting in the curtailment, reduction, delay or postponement for an indeterminate period of time.

Exploration and production companies also may reduce their drilling and production services activities as a result of the current crisis in the global credit market. Companies that planned to finance exploration, development or production projects through the capital markets may be forced to curtail, reduce, postpone or delay drilling or production services activities, and also may experience inability to pay suppliers. The deteriorating global economic environment could also impact our vendors and suppliers’ ability to meet obligations to provide materials and services in general. If any of the foregoing were to occur, it could have a material adverse effect on our business and financial results.

ITEM 2.

Unregistered Sales of Equity Securities and Use of Proceeds

We did not make any unregistered sales of equity securities during the quarter ended September 30, 2008, nor did we repurchase any shares of our common stock during the quarter ended September 30, 2008.

ITEM 3.

Defaults Upon Senior Securities

Not Applicable.

ITEM 4.

Submission of Matters to a Vote of Security Holders

Not Applicable.

ITEM 5.

Other Information

Not Applicable.

ITEM 6.

EXHIBITS

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


3.1 *	-	Articles of Incorporation of Pioneer Drilling Company, as amended (Form 10-K for the year ended March 31, 2001 (File No. 1-8182, Exhibit 3.1)).

3.2 *	-	Articles of Amendment to the Articles of Incorporation of Pioneer Drilling Company (Form 10-Q for the quarter ended September 30, 2001 (File No. 1-8182, Exhibit 3.1)).

3.3 *	-	Amended and Restated Bylaws of Pioneer Drilling Company (Form 8-K dated December 10, 2007 (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 *	-	Agreement between Joyce M. Schuldt and Pioneer Drilling Company, dated August 20, 2008 (Form 8-K dated August 21, 2008 (File No. 1-8182, Exhibit 10.1)).

10.2 *	-	Pioneer Drilling Company 2007 Incentive Plan Form of Stock Options Agreement (Form 8-K dated September 4, 2008 (File No. 1-8182, Exhibit 10.1)).

10.3 *	-	Pioneer Drilling Company 2007 Incentive Plan Form of Employee Restricted Stock Award Agreement (Form 8-K dated September 4, 2008 (File No. 1-8182, Exhibit 10.2)).

10.4 *	-	Pioneer Drilling Company 2007 Incentive Plan Form of Non-Employee Director Restricted Stock Award Agreement (Form 8-K dated September 4, 2008 (File No. 1-8182, Exhibit 10.3)).

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

31.2 **	-	Certification by William D. Hibbetts, Senior Vice President and Interim Chief Financial Officer, pursuant to Rule 13a-14(a) or 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 (18 U.S.C. 1350).

32.2 #	-	Certification by William D. Hibbetts, Senior Vice President and Interim Chief Financial Officer, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (18 U.S.C. 1350).

*	Incorporated herein by reference to the specified prior filing by Pioneer Drilling Company.

**	Filed herewith

#	Furnished herewith

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/ William D. Hibbetts

William D. Hibbetts

Senior Vice President and Interim Chief Financial Officer

(Principal Financial Officer and Duly Authorized Representative)

Dated: November 6, 2008

Index to Exhibits


3.1 *	-	Articles of Incorporation of Pioneer Drilling Company, as amended (Form 10-K for the year ended March 31, 2001 (File No. 1-8182, Exhibit 3.1)).

3.2 *	-	Articles of Amendment to the Articles of Incorporation of Pioneer Drilling Company (Form 10-Q for the quarter ended September 30, 2001 (File No. 1-8182, Exhibit 3.1)).

3.3 *	-	Amended and Restated Bylaws of Pioneer Drilling Company (Form 8-K dated December 10, 2007 (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 *	-	Agreement between Joyce M. Schuldt and Pioneer Drilling Company, dated August 20, 2008 (Form 8-K dated August 21, 2008 (File No. 1-8182, Exhibit 10.1)).

10.2 *	-	Pioneer Drilling Company 2007 Incentive Plan Form of Stock Options Agreement (Form 8-K dated September 4, 2008 (File No. 1-8182, Exhibit 10.1)).

10.3 *	-	Pioneer Drilling Company 2007 Incentive Plan Form of Employee Restricted Stock Award Agreement (Form 8-K dated September 4, 2008 (File No. 1-8182, Exhibit 10.2)).

10.4 *	-	Pioneer Drilling Company 2007 Incentive Plan Form of Non-Employee Director Restricted Stock Award Agreement (Form 8-K dated September 4, 2008 (File No. 1-8182, Exhibit 10.3)).

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

31.2 **	-	Certification by William D. Hibbetts, Senior Vice President and Interim Chief Financial Officer, pursuant to Rule 13a-14(a) or 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 (18 U.S.C. 1350).

32.2 #	-	Certification by William D. Hibbetts, Senior Vice President and Interim Chief Financial Officer, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (18 U.S.C. 1350).

*	Incorporated herein by reference to the specified prior filing by Pioneer Drilling Company.

**	Filed herewith

#	Furnished herewith