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 December 31, 2006

OR

¨ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15 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, or a non-accelerated filer. See definition of “accelerated filer and large accelerated filer” in Rule 12b-2 of the Exchange Act.

Large accelerated filer  ¨        Accelerated filer  x        Non-accelerated filer  ¨

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 February 1, 2007, there were 49,616,478 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

	December 31, 2006		March 31, 2006
	(unaudited)
ASSETS
Current assets:
Cash and cash equivalents	$	74,754,205	$	91,173,764
Receivables:
Trade, net		55,676,516		35,544,543
Contract drilling in progress		14,006,151		9,620,179
Current deferred income taxes		1,754,376		989,895
Prepaid expenses		4,026,694		2,207,853
Total current assets		150,217,942		139,536,234
Property and equipment, at cost:		441,122,190		341,768,282
Less accumulated depreciation and amortization		111,472,891		80,984,991
Net property and equipment		329,649,299		260,783,291
Intangible and other assets		306,098		358,180
Total assets	$	480,173,339	$	400,677,705
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities:
Accounts payable	$	19,638,605	$	16,040,568
Income tax payable		3,791,238		6,834,877
Prepaid drilling contracts		—		139,769
Accrued expenses:
Payroll and payroll taxes		3,916,126		3,383,435
Other		10,000,146		6,233,479
Total current liabilities		37,346,115		32,632,128
Non-current liabilities		431,528		387,524
Deferred income taxes		32,221,194		26,982,526
Total liabilities		69,998,837		60,002,178
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; 49,604,478 and 49,591,978 shares issued and outstanding at December 31, 2006 and March 31, 2006, respectively		4,960,447		4,959,197
Additional paid-in capital		290,892,981		288,356,164
Accumulated earnings		114,321,074		47,360,166
Total shareholders’ equity		410,174,502		340,675,527
Total liabilities and shareholders’ equity	$	480,173,339	$	400,677,705

See accompanying notes to condensed consolidated financial statements.

2

PIONEER DRILLING COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(Unaudited)

	Three Months Ended December 31,						Nine Months Ended December 31,
	2006			2005			2006			2005
Contract drilling revenues	$	112,421,347		$	74,458,788		$	312,831,476		$	201,308,054
Costs and expenses:
Contract drilling		58,659,083			42,936,075			164,017,319			122,238,771
Depreciation and amortization		13,969,385			8,598,306			38,120,293			23,868,669
General and administrative		2,743,208			1,637,268			8,515,519			4,839,703
Bad debt expense		800,000			25,110			800,000			25,110
Total operating costs and expenses		76,171,676			53,196,759			211,453,131			150,972,253
Income from operations		36,249,671			21,262,029			101,378,345			50,335,801
Other income (expense):
Interest expense		(8,739	)		(688	)		(73,145	)		(204,296	)
Interest income		835,871			398,349			2,946,499			1,348,872
Other		12,858			8,364			49,821			39,672
Total other income		839,990			406,025			2,923,175			1,184,248
Income before income taxes		37,089,661			21,668,054			104,301,520			51,520,049
Income tax expense		(13,101,642	)		(7,875,792	)		(37,340,611	)		(18,921,577	)
Net earnings	$	23,988,019		$	13,792,262		$	66,960,909		$	32,598,472
Earnings per common share - Basic	$	0.48		$	0.30		$	1.35		$	0.70
Earnings per common share - Diluted	$	0.48		$	0.29		$	1.34		$	0.69
Weighted average number of shares outstanding - Basic		49,603,473			46,542,413			49,597,678			46,307,995
Weighted average number of shares outstanding - Diluted		50,145,605			47,325,807			50,147,531			47,010,265

See accompanying notes to condensed consolidated financial statements.

3

PIONEER DRILLING COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

	Nine Months Ended December 31,
	2006			2005
Cash flows from operating activities:
Net earnings	$	66,960,909		$	32,598,472
Adjustments to reconcile net earnings to net cash provided by operating activities:
Depreciation and amortization		38,120,293			23,868,669
Allowance for doubtful accounts		800,000			25,110
Loss on disposal of properties and equipment		5,183,494			2,478,988
Change in deferred income taxes		4,474,187			9,654,311
Stock-based compensation expense		2,473,738			—
Change in other assets		15,000			32,478
Change in non-current liabilities		—			(100,000	)
Deferred operating lease liability		44,006			51,096
Changes in current assets and liabilities:
Receivables		(20,931,973	)		(8,815,517	)
Contract drilling in progress		(4,385,972	)		(4,113,267	)
Prepaid expenses		(1,818,841	)		(470,291	)
Accounts payable		3,032,721			(2,134,213	)
Prepaid drilling contracts		(139,769	)		(172,750	)
Federal income taxes payable		(3,051,269	)		4,826,442
Accrued expenses		4,299,358			2,496,631
Net cash provided by operating activities		95,075,882			60,226,159
Cash flows from financing activities:
Payments of debt		—			(18,813,013	)
Proceeds from exercise of stock options		64,329			6,441,556
Excess tax benefit of stock option exercises		7,630			—
Net cash provided by (used in) financing activities		71,959			(12,371,457	)
Cash flows from investing activities:
Purchase of property and equipment		(116,637,358	)		(87,614,804	)
Proceeds from sale (purchase) of marketable securities, net		—			1,000,000
Proceeds from sale of property and equipment		5,069,958			1,666,095
Net cash used in investing activities		(111,567,400	)		(84,948,709	)
Net decrease in cash and cash equivalents		(16,419,559	)		(37,094,007	)
Beginning cash and cash equivalents		91,173,764			69,673,279
Ending cash and cash equivalents	$	74,754,205		$	32,579,272
Supplementary Disclosure:
Interest and commitment fees paid	$	104,395		$	401,138
Income taxes paid	$	35,904,735		$	514,024
Tax benefit from exercise of nonqualified options	$	—		$	3,926,798
Change in accounts payable for property and equipment purchases	$	565,316		$	4,028,905

See accompanying notes to condensed consolidated financial statements.

4

PIONEER DRILLING COMPANY AND SUBSIDARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

1. Organization and Basis of Presentation

Business and Principles of Consolidation

Pioneer Drilling Company provides contract land drilling services to its customers in select oil and natural gas exploration and production regions in the United States. As of December 31, 2006, our rig fleet consisted of 63 operating drilling rigs, 17 of which were operating in our South Texas division, 18 of which were operating in our East Texas division, nine of which were operating in our North Texas division, seven of which were operating in our Western Oklahoma division and 12 of which were operating in our Rocky Mountain divisions in Utah and North Dakota. We placed one additional rig in operation in January 2007. We conduct our operations through our principal operating subsidiary, Pioneer Drilling Services, Ltd. The accompanying unaudited condensed consolidated financial statements include our accounts and the accounts of our wholly owned subsidiaries. All intercompany balances and transactions have been eliminated in consolidation.

The accompanying unaudited condensed consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America for interim financial information and with the instructions to Form 10-Q and Rule 10-01 of Regulation S-X. Accordingly, they do not include all of the information and footnotes required by generally accepted accounting principles for complete financial statements. In the opinion of our management, all adjustments (consisting of normal, recurring accruals) necessary for a fair presentation have been included. In preparing the accompanying unaudited condensed consolidated financial statements, we make various estimates and assumptions that affect the amounts of assets and liabilities we report as of the dates of the balance sheets and income and expenses we report for the periods shown in the income statements and statements of cash flows. Our actual results could differ significantly from those estimates. Material estimates that are particularly susceptible to significant changes in the near term relate to our recognition of revenues and costs for turnkey contracts, our estimate of the allowance for doubtful accounts, our estimate of the self-insurance portion of our health and workers’ compensation insurance, our estimate of asset impairments, our estimate of deferred taxes and our determination of depreciation and amortization expense. The condensed balance sheet as of March 31, 2006 has been derived from our audited financial statements. We suggest that you read these condensed financial statements together with the financial statements and the related notes included in our annual report on Form 10-K for the fiscal year ended March 31, 2006.

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, during periods of high rig demand, we enter into more longer-term drilling contracts. In addition, we have entered into longer-term drilling contracts for our newly constructed rigs. As of February 1, 2007, we had 37 contracts with terms of six months to two years in duration, of which 18 will expire by August 31, 2007, 11 have a remaining term of six to 12 months, three have a remaining term of 12 to 18 months and five have a remaining term in excess of 18 months. We also have term contracts of two and three years for two rigs under construction at February 1, 2007.

Income Taxes

Pursuant to Statement of Financial Accounting Standards (“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.

5

Stock-based Compensation

We have stock option plans that are administered by the compensation committee of our Board of Directors, which selects persons eligible to receive awards and determines the number of stock options subject to each award and the terms, conditions and other provisions of the awards. Employee stock options generally become exercisable over three- to five-year periods, and generally expire 10 years after the date of grant. Stock options granted to outside directors vest immediately and expire five years after the date of grant. Our plans provide that all options must have an exercise price not less than the fair market value of our common stock on the date of grant.

Effective April 1, 2006, we adopted SFAS No. 123 (Revised), Share-Based Payment (“SFAS 123R”), utilizing the modified prospective approach. Prior to the adoption of SFAS 123R, we accounted for stock option grants in accordance with Accounting Principles Board Opinion No. 25, Accounting for Stock Issued to Employees (“APB 25”), and related interpretations, as permitted by SFAS No. 123, Accounting for Stock-Based Compensation (“SFAS 123”). 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 December 31, 2006 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. Prior periods were not restated to reflect the impact of adopting this new standard.

As a result of adopting SFAS 123R on April 1, 2006, our income before income taxes, net earnings and basic and diluted earnings per common share for the nine months ended December 31, 2006, were $2,474,000, $1,608,000 and $.03 per share lower, respectively, than if we had continued to account for stock-based compensation under APB 25 for our stock option grants. Compensation costs of approximately $2,071,000 and $403,000 for stock options were recognized in general and administrative expense and contract drilling costs, respectively, for the nine months ended December 31, 2006. Approximately $260,000 of the compensation costs included in general and administrative expense relate to stock options granted to outside directors that vested immediately upon grant pursuant to our stock option plans. The entire compensation cost must be recognized for stock options that are fully vested at the grant date. We expect compensation costs relating to nonvested stock options to be approximately $590,000 for the remainder of fiscal year 2007.

We receive a tax deduction for certain stock option exercises during the period the options are exercised, generally for the excess of the price at which the options are sold over the exercise price of the options. Prior to adoption of SFAS 123R, we reported all tax benefits resulting from the exercise of stock options as operating cash flows in our condensed consolidated statement of cash flows. There were 12,500 stock options exercised during the nine months ended December 31, 2006.

The following table illustrates the pro forma effect on operating results and per share information had we accounted for stock-based compensation in accordance with SFAS 123R for the three and nine months ended December 31, 2005:

	Three Months Ended December 31, 2005			Nine Months Ended December 31, 2005
Net earnings - as reported	$	13,792,262		$	32,598,472
Deduct: Total stock-based employee compensation expense determined under fair-value-based method for all awards, net of related tax effect		(537,981	)		(1,506,730	)
Net earnings - pro forma	$	13,254,281		$	31,091,742
Net earnings per share - as reported - basic	$	0.30		$	0.70
Net earnings per share - as reported - diluted	$	0.29		$	0.69
Net earnings per share - pro forma - basic	$	0.28		$	0.67
Net earnings per share - pro forma - diluted	$	0.28		$	0.66

6

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 nine months ended December 31, 2006 and 2005. We did not grant any stock options during the three-month periods ended December 31, 2006 or 2005.

	Nine Months Ended December 31,
	2006			2005
Expected volatility		49	%		53	%
Weighted-average risk-free interest rates		5.0	%		4.0	%
Weighted-average expected life in years		2.86			4.10
Options granted		482,000			336,500
Weighted-average grant-date fair value	$	5.36		$	6.47

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.

At December 31, 2006, there was approximately $2,619,000 of unrecognized compensation cost relating to stock options which are expected to be recognized over a weighted-average period of 1.92 years.

The following table represents stock option activity for the nine months ended December 31, 2006:

	Number of Shares		Weighted-average Exercise Price		Weighted-average Remaining Contract Life
Outstanding options at beginning of period	1,592,833		$	7.71
Granted	482,000			14.53
Exercised	(12,500	)		4.72
Canceled	—			—
Forfeited	(21,333	)		9.97
Outstanding options at end of period	2,041,000		$	9.31	7.55
Options exercisable at end of period	901,000		$	6.90	6.46

Shares available for future stock option grants to employees and directors under existing plans were 1,157,833 at December 31, 2006. At December 31, 2006, the aggregate intrinsic value of stock options outstanding was approximately $9,106,000 and the aggregate intrinsic value of stock options exercisable was approximately $5,971,000. Intrinsic value is the difference between the exercise price of a stock option and the closing market price of our common stock, which was $13.28 on December 31, 2006.

The following table summarizes our nonvested stock option activity for the nine months ended December 31, 2006:

	Number of Shares		Weighted-Average Grant-Date Fair Value
Nonvested options at beginning of period	1,046,167		$	4.90
Granted	422,000			5.51
Vested	(306,834	)		4.46
Forfeited	(21,333	)		9.97
Nonvested options at end of period	1,140,000		$	5.45

7

Related-Party Transactions

We purchased services from R&B Answering Service and Frontier Services, Inc. during the three and nine months ended December 31, 2006 and 2005. R&B Answering Service was more than 5% owned by our Chief Operating Officer until August 2006, when he sold his interest in that company. Frontier Services, Inc. is more than 5% owned by an immediate family member of our Vice President and Operations Manager. The following summarizes the transactions with these companies in each period.

	Three Months Ended December 31,				Nine Months Ended December 31,				Amount Owed December 31,
	2006		2005		2006		2005		2006		2005
R&B Answering Service
Purchases	$	—	$	2,996	$	7,542	$	12,391	$	—	$	1,403
Payments	$	—	$	4,514	$	7,542	$	14,038
Frontier Services, Inc.
Purchases	$	—	$	1,521	$	606	$	5,953	$	—	$	—
Payments	$	—	$	1,521	$	606	$	9,302

In July 2005, we began leasing a portion of our corporate office space on a month-to-month basis to Wedge Oil and Gas Services Incorporated for $370 per month for one of its employees located in San Antonio. Wedge Oil and Gas Services Incorporated is an affiliate of WEDGE Group Incorporated. An officer of WEDGE Group Incorporated is a member of our Board of Directors.

Our Chief Executive Officer, Chief Operating Officer, Senior Vice President of Marketing, and Vice President and Operations Manager occasionally acquire a 1% to 5% minority working interest in oil and gas wells that we drill for one of our customers. These individuals acquired a minority working interest on two wells that we drilled for this customer during the nine months ended December 31, 2006. We recognized contract drilling revenues of approximately $1,072,000 on these wells during the nine months ended December 31, 2006. These individuals did not acquire minority working interests in any wells that we drilled for this customer during the nine months ended December 31, 2005.

Recently Issued Accounting Standards

In July 2006, the Financial Accounting Standards Board (the “FASB”) issued FASB Interpretation No. 48, Accounting for Uncertainty in Income Taxes - An Interpretation of FASB Statement No. 109 (“FIN 48”). FIN 48 clarifies the accounting for uncertainty in income taxes recognized in a company’s financial statements in accordance with SFAS No. 109. FIN 48 also prescribes a recognition threshold and measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. The new FASB standard also provides guidance on derecognition, classification, interest and penalties, accounting in interim periods, disclosure and transition. FIN 48 is effective for fiscal years beginning after December 15, 2006. We do not expect the adoption of FIN 48 to have a material impact on our financial position or results of operations and financial condition.

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 is effective for financial statements issued for fiscal years beginning after November 15, 2007. We do not expect the adoption of SFAS No. 157 to have a material impact on our financial position or results of operations and financial condition.

In September 2006, the FASB issued Staff Position AUG AIR-1, Accounting for Planned Major Maintenance Activities, which eliminates the acceptability of the accrue-in-advance method of accounting for planned major maintenance activities. This FASB Staff Position is effective for fiscal years beginning after December 15, 2006. We do not use the accrue-in-advance method of accounting for rig refurbishments. We use a “built-in overhaul” method of accounting for rig refurbishments, whereby these expenditures are recognized as capital asset additions when incurred. The application of this FASB Staff Position will not have a material impact on our financial position or results of operations and financial condition.

In September 2006, the U.S. Securities and Exchange Commission (the “SEC”) released Staff Accounting Bulletin No. 108, Considering the Effects of Prior Year Misstatements When Quantifying Misstatements in Current Year Financial Statements, (“SAB 108”), which provides interpretive guidance on the SEC’s views regarding the process of

8

quantifying materiality of financial statement misstatements. SAB 108 is effective for fiscal years ending after November 15, 2006, with early application for the first interim period ending after November 15, 2006. We do not expect the application of SAB 108 will have a material effect on our financial position or results of operations and financial condition.

Reclassifications

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

2. Long-term Debt and Notes Payable

We have a $20,000,000 credit facility with Frost National Bank, consisting of a $10,000,000 revolving line and letter of credit facility and a $10,000,000 acquisition facility for the acquisition of drilling rigs, drilling rig transportation equipment and associated equipment. Borrowings under the credit facility bear interest at a rate equal to Frost National Bank’s prime rate (8.25% at December 31, 2006) or, at our option, at LIBOR plus a percentage ranging from 1.5% to 2.25%, based on our operating leverage ratio. Borrowings are secured by most of our assets, including all our drilling rigs and associated equipment and receivables. At December 31, 2006, we had no borrowings under the acquisition facility and we had used approximately $4,267,000 of availability under the revolving line and letter of credit facility through the issuance of letters of credit in the ordinary course of business. The remaining availability under the revolving line and letter of credit facility is $5,733,000. Both the revolving line and letter of credit facility and acquisition facility are scheduled to mature in October 2008.

The sum of (1) the draws and (2) the amount of all outstanding letters of credit issued for our account under the revolving line and letter of credit facility portion of our credit facility is limited to 75% of our eligible accounts receivable, not to exceed $10,000,000. Therefore, if 75% of our eligible accounts receivable was less than $10,000,000, our ability to draw under this line would be reduced. At December 31, 2006, we had no outstanding advances under this line of credit, we had outstanding letters of credit of approximately $4,267,000 and 75% of our eligible accounts receivable was approximately $36,706,000. The letters of credit have been issued to three workers’ compensation insurance companies to secure possible future claims under the deductibles on these policies. It is our practice to pay any amounts due under these deductibles as they are incurred. Therefore, we do not anticipate that the lenders will be required to fund any draws under these letters of credit.

At December 31, 2006, we were in compliance with all covenants contained in the credit agreement related to our credit facility. Those covenants include, among others, requirements that we maintain a debt to total capitalization ratio of not greater than 0.2 to 1, a fixed charged coverage ratio of not less than 1.5 to 1 and an operating leverage ratio of not more than 2.5 to 1. The covenants also restrict us from paying dividends, restrict us from the sale of assets not permitted by the credit facility and restrict us from the incurrence of additional indebtedness in excess of $3,000,000, to the extent not otherwise allowed by the credit facility.

3. Commitments and Contingencies

As of December 31, 2006, we were constructing, from new and used components, two 1000-horsepower diesel electric rigs and one 1000-horsepower mechanical rig at estimated costs ranging from $8,300,000 to $9,600,000 each. We placed one of those rigs in operation in January 2007 and expect the remaining two rigs to be completed and become available for operation in February and March 2007. As of December 31, 2006, we had incurred approximately $16,593,000 of the approximately $26,295,000 of estimated construction costs on the three rigs under construction. During the quarter ended September 30, 2006, we canceled the construction of one new rig we had previously planned to build.

We have purchase obligations for rig equipment consisting of 70 iron roughnecks and power slips to improve the efficiency and safety of our rig fleet and three topdrives. The iron roughnecks and power slips will be delivered over the 24-month period beginning January 2007, at a total cost of approximately $18,300,000, plus installation costs of approximately $3,000,000. Two topdrives at a total cost of approximately $3,300,000 are due for delivery in February 2007. A third topdrive at a cost of approximately $1,650,000 is due for delivery in July 2007.

Due to the nature of our business, we are, from time to time, involved in routine litigation or subject to disputes or claims related to our business activities, including workers’ compensation claims and employment-related disputes. In the opinion of our management, none of such 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.

9

4. 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 as required by SFAS No. 128:

	Three Months Ended December 31,				Nine Months Ended December 31,
	2006		2005		2006		2005
Basic
Net earnings	$	23,988,019	$	13,792,262	$	66,960,909	$	32,598,472
Weighted average shares		49,603,473		46,542,413		49,597,678		46,307,995
Earnings per share	$	0.48	$	0.30	$	1.35	$	0.70
	Three Months Ended December 31,				Nine Months Ended December 31,
	2006		2005		2006		2005
Diluted
Net earnings	$	23,988,019	$	13,792,262	$	66,960,909	$	32,598,472
Effect of dilutive securities:
None		—		—		—		—
Net earnings and assumed conversion	$	23,988,019	$	13,792,262	$	66,960,909	$	32,598,472
Weighted average shares:
Outstanding		49,603,473		46,542,413		49,597,678		46,307,995
Options		542,132		783,394		549,853		702,270
		50,145,605		47,325,807		50,147,531		47,010,265
Earnings per share	$	0.48	$	0.29	$	1.34	$	0.69

5. Equity Transactions

On February 10, 2006, we sold 3,000,000 shares of our common stock, at approximately $20.63 per share, net of underwriters’ commissions, in a public offering we registered with the SEC.

Employees exercised stock options for the purchase of 12,500 shares of common stock during the nine months ended December 31, 2006 at prices ranging from $4.52 to $4.77 per share. Directors and employees exercised stock options for the purchase of 658,667 shares of common stock during the nine months ended December 31, 2005, at prices ranging from $3.00 to $8.81 per share.

10

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, the continued strength or weakness of the contract land drilling industry in the geographic areas in which we operate, decisions about onshore exploration and development projects to be made by oil and gas companies, the highly competitive nature of our business, our future financial performance, including availability, terms and deployment of capital, the continued availability of qualified personnel, and changes in, or our failure or inability to comply with, government regulations, including those relating to the environment. We have discussed many of these factors in more detail elsewhere in this report, and in our annual report on Form 10-K for the fiscal year ended March 31, 2006. These factors are not necessarily all the important factors that could affect us. Unpredictable or unknown factors we have not discussed in this report or in our annual report could also have material adverse effects on actual results of matters that are the subject of our forward-looking statements. We do not intend to update our description of important factors each time a potential important factor arises, except as required by applicable securities laws and regulations. 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 provides contract land drilling services to independent and major oil and gas exploration and production companies. In addition to our drilling rigs, we provide the drilling crews and most of the ancillary equipment needed to operate our drilling rigs. We have focused our operations in selected oil and natural gas production regions in the United States. Our company was incorporated in 1979 as the successor to a business that had been operating since 1968. We conduct our operations through our principal operating subsidiary, Pioneer Drilling Services, Ltd. We are an oil and gas services company. We do not invest in oil and natural gas properties. The drilling activity of our customers is highly dependent on the current and forecasted future price of oil and natural gas. During the quarter ended December 31, 2006, we began experiencing a decline in the demand for drilling rigs and in revenue rates on some contract renewals. If the recent weakness in oil and natural gas prices continues through the winter months, we could see a continued slowdown in drilling activity by oil and gas exploration companies. Any continued slowdown in drilling activity would likely result in lower revenue rates for our rigs as current contracts expire.

Our business strategy is to own and operate a high-quality fleet of land drilling rigs in active drilling markets, and to position ourselves to maximize rig utilization and dayrates and to enhance shareholder value. We intend to continue making additions to our drilling fleet, either through acquisitions of businesses or selected assets or through the construction of new or refurbished drilling rigs as opportunities arise.

Since September 1999, we have significantly expanded our fleet of drilling rigs through acquisitions and the construction of new and refurbished rigs. As of February 1, 2007, our rig fleet consisted of 64 land drilling rigs, of which 24 are premium electric rigs that drill in depth ranges between 6,000 and 18,000 feet. Seventeen of our rigs are operating in our South Texas division, 18 in our East Texas division, ten in our North Texas division, seven in our western Oklahoma division and 12 in our Rocky Mountains divisions in Utah and North Dakota. We actively market all of these rigs. As of February 1, 2007, we were constructing one 1000-horsepower diesel electric rig and one 1000-horsepower mechanical rig. We expect these rigs to be completed and to become available for operation in February and March 2007.

We earn our revenues by drilling oil and gas wells for our customers, as our rigs can be used by our customers to drill for either oil or natural gas. We obtain our contracts for drilling oil and 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. Historically, our contracts provide for the drilling of a single well and typically permit the customer to terminate on short notice. However, during periods of high rig demand, we enter into more longer-term drilling contracts. In addition, we have entered into longer-term drilling contracts for our newly constructed rigs. As of February 1, 2007, we had 37 contracts with terms of six months to two years in duration, of which 18 will expire by August 31, 2007, 11 have a remaining term of six to 12 months, three have a remaining term of 12 to 18 months and five have a remaining term in excess of 18 months. We also have term contracts of two and three years for two rigs under construction at February 1, 2007.

11

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

For the three and nine months ended December 31, 2006 and 2005, our rig utilization and revenue days were as follows:

	Three Months Ended December 31,				Nine Months Ended December 31,
	2006		2005		2006		2005
Utilization Rates	98	%	96	%	97	%	95	%
Revenue Days	5,572		4,714		15,727		13,463

The primary reason for the increase in the number of revenue days in 2006 over 2005 was the increase in size of our rig fleet from 54 rigs at December 31, 2005 to 63 rigs at December 31, 2006. For the remainder of fiscal year 2007, we anticipate continued growth in revenue days as we continue to construct more rigs and put them into operation. We expect utilization rates for the remainder of fiscal year 2007 and fiscal year 2008 to decline modestly due to new rigs entering the market and weakness in oil and gas prices.

In addition to high commodity prices, we attribute our relatively high utilization rates to a strong sales effort, quality equipment, good field and operations personnel, a disciplined safety approach, and our generally successful performance of turnkey operations during periods of reduced demand for drilling rigs.

We devote substantial resources to maintaining and upgrading our rig fleet. In the short term, these actions result in fewer revenue days and slightly lower utilization; however, in the long term, we believe the upgrades will help the marketability of our rigs and improve their operating performance. We are currently performing, between contracts or as necessary, safety and equipment upgrades to the eight rigs we acquired in March 2004 and the 12 rigs we acquired in November and December 2004. During the nine months ended December 31, 2006, we expended approximately $14,608,000 upgrading 15 rigs, using over 391 potential revenue days in the upgrade process.

Market Conditions in Our Industry

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

On January 19, 2007, the spot price for West Texas Intermediate crude oil was $51.99, the spot price for Henry Hub natural gas was $6.40 and the Baker Hughes land rig count was 1,638, a 19% increase from 1,376 on January 20, 2006. Since September 1, 2006 the Baker Hughes land rig count has been between 1,586 and 1,641.

The average weekly spot prices of West Texas Intermediate crude oil and Henry Hub natural gas and the average weekly domestic land rig count, per the Baker Hughes land rig count, for the three months ended December 31, 2006 and each of the previous five years ended December 31, were:

	Three Months Ended December 31,		Years Ended December 31,
	2006		2006		2005		2004		2003		2002
Oil (West Texas Intermediate)	$	60.05	$	66.28	$	56.63	$	42.31	$	31.22	$	26.20
Natural Gas (Henry Hub)	$	6.65	$	6.66	$	8.83	$	5.90	$	5.43	$	3.33
U.S. Land Rig Count		1,609		1,537		1,266		1,095		906		700

12

Most of our customers drill in search of natural gas; however, we currently operate four rigs in the Williston Basin of the Rocky Mountains, where our customers drill in search of oil.

Critical Accounting Policies and Estimates

Revenue and cost recognition – We earn our 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. Contract drilling in progress represents revenues we have recognized in excess of amounts billed on contracts in progress. 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.

Asset impairments – We assess the impairment of property and equipment whenever events or circumstances indicate that the carrying value may not be recoverable. Factors that we consider important and which could trigger an impairment review would be our customers’ financial condition and any significant negative industry or economic trends. More specifically, among other things, we consider our contract revenue rates, our rig utilization rates, cash flows from our drilling rigs, current oil and gas prices and trends in the price of used drilling equipment observed by our management. If a review of our drilling rigs indicates that our carrying value exceeds the estimated undiscounted future net cash flows, we are required under applicable accounting standards to write down the drilling equipment to its fair market value. A one percent write-down in the cost of our drilling equipment, at December 31, 2006, would have resulted in a corresponding decrease in our net earnings of approximately $2,762,000 for the nine months ended December 31, 2006.

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, 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 over five to 15 years and refurbishments over three years, while federal income tax rules

13

require that we depreciate drilling rigs and refurbishments over five years. Therefore, in the first five years of our ownership of a drilling rig, our tax depreciation exceeds our financial reporting depreciation, resulting in our providing deferred taxes on this depreciation difference. After five years, financial reporting depreciation exceeds tax depreciation, and the deferred tax liability begins to reverse.

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 shallower depth. Since 1995, when current management joined our company, 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 enable us to make reasonably dependable cost estimates and complete contracts according to our drilling plan. While we do bear the risk of loss for cost overruns and other events that are not specifically provided for in our initial cost estimates, our pricing of 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 December 31, 2006, we experienced losses of less than $25,000 each on six of the 44 turnkey and footage contracts completed. During the nine months ended December 31, 2005, we experienced losses on 17 of the 111 turnkey and footage contracts completed, with losses of less than $25,000 each on 14 contracts, losses exceeding $25,000 but less than $100,000 on two contracts, and a loss exceeding $100,000 on one contract. We are more likely to encounter losses on turnkey and footage contracts in periods in which revenue rates are lower for all types of contracts. During periods of reduced demand for drilling rigs, our overall profitability on turnkey and footage contracts has historically exceeded our profitability on daywork contracts.

Revenues and costs during a reporting period could be affected for contracts in progress at the end of a reporting period which have not been completed before our financial statements for that period are released. We had no turnkey contracts and two footage contracts in progress at December 31, 2006, which were completed prior to the release of the financial statements included in this report. Our contract drilling in progress totaled approximately $14,006,000 at December 31, 2006. Of that amount accrued, footage contract revenues were approximately $584,000. The remaining balance of approximately $13,422,000 related to the revenue recognized but not yet billed on daywork contracts in progress at December 31, 2006. At March 31, 2006, drilling in progress totaled $9,620,000, of which $599,000 related to footage contracts and $9,021,000 related to daywork contracts.

We estimate an allowance for doubtful accounts based on the creditworthiness of our customers as well as general economic conditions. We evaluate the creditworthiness of our customers based on information obtained from major industry suppliers, current prices of oil and gas and any past experience we have with the customer. Consequently, an adverse change in those factors could affect our estimate of our allowance for doubtful accounts. In some instances, we require new customers to establish escrow accounts or make prepayments. We typically invoice our customers at 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 60 days for any of our contracts in the last three fiscal years. We had an allowance for doubtful accounts of $1,000,000 and $200,000 at December 31, 2006 and March 31, 2006, respectively.

Another critical estimate is our determination of the useful lives of our depreciable assets, which directly affects our determination of depreciation expense and deferred taxes. A decrease in the useful life of our drilling equipment would increase depreciation expense and reduce deferred taxes. We provide for depreciation of our drilling, transportation and other equipment on a straight-line method over useful lives that we have estimated and that range from three to 15 years. We record the same depreciation expense whether a rig is idle or working. Our estimates of the useful lives of our drilling, transportation and other equipment are based on our more than 35 years of experience in the drilling industry with similar equipment.

14

Our other accrued expenses as of December 31, 2006 include accruals of approximately $608,000 and $2,947,000 for costs incurred under the self-insurance portion of our health insurance and under our workers’ compensation insurance, respectively. We have a deductible of (1) $125,000 per covered individual per year under the health insurance and (2) $250,000 per occurrence under our workers’ compensation insurance, except in North Dakota, where we do not have a deductible. 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 claim cost estimates based on estimates provided by the insurance companies that provide claims processing services.

Liquidity and Capital Resources

Sources of Capital Resources

Our rig fleet has grown from eight rigs in August 2000 to 64 rigs as of February 1, 2007. We have financed this growth with a combination of debt and equity financing. We have raised additional equity or used equity for growth nine times since January 2000. We plan to continue to grow our rig fleet. Over the remainder of fiscal year 2007, we expect to finance the construction of two additional rigs from existing cash and cash flows from operations. However, we may finance other growth opportunities through the issuance of debt and the issuance of additional shares of our common stock.

On February 10, 2006, we sold 3,000,000 shares of our common stock, at approximately $20.63 per share, net of underwriters’ commissions, in a public offering we registered with the U.S. Securities and Exchange Commission (the “SEC”).

We have a $20,000,000 credit facility with Frost National Bank consisting of a $10,000,000 revolving line and letter of credit facility and a $10,000,000 acquisition facility for the acquisition of drilling rigs, drilling rig transportation equipment and associated equipment. Borrowings under the credit facility bear interest at a rate equal to Frost National Bank’s prime rate (8.25% at December 31, 2006) or, at our option, at LIBOR plus a percentage ranging from 1.5% to 2.25%, based on our operating leverage ratio. Borrowings are secured by most of our assets, including all our drilling rigs and associated equipment and receivables. At December 31, 2006, we had no borrowings under the acquisition facility and we had used approximately $4,267,000 of availability under the revolving line and letter of credit facility through the issuance of letters of credit in the ordinary course of business. The remaining availability under the revolving line and letter of credit facility is $5,733,000. Both the revolving line and letter of credit facility and acquisition facility are scheduled to mature in October 2008.

Uses of Capital Resources

For the three and nine months ended December 31, 2006, the additions to our property and equipment consisted of the following:

	Three Months		Nine Months
Drilling rigs	$	19,980,725	$	64,969,782
Other drilling equipment		8,271,855		46,826,206
Transportation equipment		2,426,052		4,320,744
Other		840,191		1,085,942
	$	31,518,823	$	117,202,674

As of December 31, 2006, we were constructing, from new and used components, two 1000-horsepower diesel electric rigs and one 1000-horsepower mechanical rig at estimated costs ranging from $8,300,000 to $9,600,000 each. We placed one rig in operation in January 2007 and expect the remaining two rigs to be completed and become available for operation in February and March 2007. As of December 31, 2006, we had incurred approximately $16,593,000 of the approximately $26,295,000 of estimated construction costs on the three rigs under construction. During the quarter ended September 30, 2006, we canceled the construction of one new rig we had previously planned to build.

For the remainder of fiscal year 2007, we project regular rig capital expenditures (excluding construction costs to complete the construction of the rigs referred to above) to be approximately $14,300,000, rig upgrade expenditures to be approximately $9,600,000, transportation equipment capital expenditures to be approximately $5,400,000 and other capital expenditures to be approximately $200,000. These capital expenditures are expected to be funded primarily from operating cash flow in excess of cash flow necessary to meet routine financial obligations.

15

Working Capital

Our working capital was $112,871,827 at December 31, 2006, compared to $106,904,106 at March 31, 2006. Our current ratio, which we calculate by dividing our current assets by our current liabilities, was 4.0 at December 31, 2006, compared to 4.3 at March 31, 2006.

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 contracts are turnkey and footage contracts, our short-term working capital needs could increase. If necessary, we can defer rig upgrades to improve our cash position. The significant improvement in operating cash flow for the nine months ended December 31, 2006 over December 31, 2005 is due primarily to the approximately $34,362,000 improvement in net earnings, plus the increase of approximately $14,252,000 in depreciation and amortization expense. We believe our cash generated by operations and our ability to borrow under the currently unused portion of our line of credit and letter of credit facility should allow us to meet our routine financial obligations for the foreseeable future. The changes in the components of our working capital were as follows:

	December 31, 2006		March 31, 2006		Change
Cash and cash equivalents	$	74,754,205	$	91,173,764	$	(16,419,559	)
Receivables		55,676,516		35,544,543		20,131,973
Contract drilling in progress		14,006,151		9,620,179		4,385,972
Deferred income taxes		1,754,376		989,895		764,481
Prepaid expenses		4,026,694		2,207,853		1,818,841
Current assets		150,217,942		139,536,234		10,681,708
Accounts payable		19,638,605		16,040,568		3,598,037
Income tax payable		3,791,238		6,834,877		(3,043,639	)
Prepaid drilling contracts		—		139,769		(139,769	)
Accrued payroll		3,916,126		3,383,435		532,691
Accrued expenses		10,000,146		6,233,479		3,766,667
		37,346,115		32,632,128		4,713,987
Working capital	$	112,871,827	$	106,904,106	$	5,967,721

The increase in our receivables and contract drilling in progress at December 31, 2006 from March 31, 2006 was due to our operating seven additional rigs and the increase of approximately $2,554 per day in average revenue rates.

Substantially all our prepaid expenses at December 31, 2006 and March 31, 2006 consisted of prepaid insurance. We renew and pay most of our insurance premiums in late October of each year and some in April of each year. At March 31, 2006, we had amortized five months of the October premiums, compared to two months of amortization as of December 31, 2006. In addition, insurance premiums have increased in the current year as a result of our growth.

The increase in accounts payable was primarily due to our operating seven additional rigs and the increase of approximately $1,164 per day in average drilling costs.

The increase in accrued expenses at December 31, 2006, compared to March 31, 2006, was primarily due to increases in the accruals for property taxes and self-insurance costs.

The decrease in income tax payable at December 31, 2006 primarily related to the timing of quarterly income tax payments which was partially offset by the increase in current taxable income as a percentage of income before taxes. Also, income taxes payable for the year ended March 31, 2006 were decreased when we fully utilized net operating loss carryforwards.

16

Long-term Debt

We had no long-term debt outstanding at December 31, 2006. See “- Sources of Capital Resources” for a description of our credit facility.

Contractual Obligations

We have purchase obligations for rig equipment consisting of 70 iron roughnecks and power slips and three topdrives at a cost of approximately $21,300,000 and $4,950,000, respectively. We do not have other routine purchase obligations. However, as of December 31, 2006, we were in the process of constructing three drilling rigs, as described above. The following table includes all our contractual obligations of the types specified below at December 31, 2006.

	Payments Due by Period
Contractual Obligations	Total		Less than 1 year		1-3 years		4-5 years		More than 5 years
Purchase Obligations	$	26,250,000	$	17,730,012	$	8,519,988	$	—	$	—
Operating Lease Obligations		1,728,363		306,288		541,266		436,722		444,087
Total	$	27,978,363	$	18,036,300	$	9,061,254	$	436,722	$	444,087

Debt Requirements

The sum of (1) the draws and (2) the amount of all outstanding letters of credit issued for our account under the revolving line and letter of credit facility portion of our credit facility is limited to 75% of our eligible accounts receivable, not to exceed $10,000,000. Therefore, if 75% of our eligible accounts receivable was less than $10,000,000, our ability to draw under this line would be reduced. At December 31, 2006, we had no outstanding advances under this line of credit, we had outstanding letters of credit of approximately $4,267,000 and 75% of our eligible accounts receivable was approximately $36,706,000. The letters of credit have been issued to three workers’ compensation insurance companies to secure possible future claims under the deductibles on these policies. It is our practice to pay any amounts due under these deductibles as they are incurred. Therefore, we do not anticipate that the lenders will be required to fund any draws under these letters of credit.

Our new credit facility contains various covenants pertaining to a debt to total capitalization ratio, operating leverage ratio and fixed charge coverage ratio and restricts us from paying dividends. We determine compliance with the ratios on a quarterly basis, based on the previous four quarters. Events of default, which could trigger an early repayment requirement, include, among others:

• our failure to make required payments;

• any sale of assets by us not permitted by the credit facility;

• our failure to comply with financial covenants related to a debt to total capitalization ratio not to exceed 0.2 to 1, an operating leverage ratio of not more than 2.5 to 1, and a fixed charge coverage ratio of not less than 1.5 to 1;

• our incurrence of additional indebtedness in excess of $3,000,000, to the extent not otherwise allowed by the credit facility;

• any event which results in a change in the ownership of at least 40% of all classes of our outstanding capital stock; and

• any payment of cash dividends on our common stock.

The limitation on additional indebtedness described above has not affected our operations or liquidity, and we do not expect it to affect our future operations or liquidity, as we expect to continue to generate adequate cash flow from operations to fund our anticipated working capital and other normal cash flow requirements.

17

Results of Operations

Our operations consist of drilling oil and gas wells for our customers under daywork, turnkey or footage contracts usually on a well-to-well basis. Daywork contracts are the least complex for us to perform and involve the least risk. Turnkey contracts are the most difficult to perform and involve much greater risk but provide the opportunity for higher operating profits.

Daywork Contracts. Under daywork drilling contracts, we provide a drilling rig with required personnel to our customer, who supervises the drilling of the well. We are paid based on a negotiated fixed rate per day while the rig is used. During the mobilization period, we typically earn a fixed amount of revenue based on the mobilization rate stated in the contract. We attempt to set the mobilization rate at an amount equal to our external costs for the move plus our internal costs during the mobilization period. We begin earning our contracted daywork rate when we begin drilling the well. Occasionally, in periods of increased demand, our contracts will provide for the trucking costs to be paid by the customer, and we will receive a reduced dayrate during the mobilization period.

Turnkey Contracts. Under a turnkey contract, we agree to drill a well for our customer to a specified depth and under specified conditions for a fixed price, regardless of the time required or the problems encountered in drilling the well. We provide technical expertise and engineering services, as well as most of the equipment and drilling supplies required to drill the well. We often subcontract for related services, such as the provision of casing crews, cementing and well logging. Under typical turnkey drilling arrangements, we do not receive progress payments and are entitled to be paid by our customer only after we have performed the terms of the drilling contract in full. The risks under a turnkey contract are greater than those under a daywork contract, because under a turnkey contract we assume most of the risks associated with drilling operations that the operator generally assumes under a daywork contract.

Footage Contracts. Under footage contracts, we are paid a fixed amount for each foot drilled, regardless of the time required or the problems encountered in drilling the well. We typically pay more of the out-of-pocket costs associated with footage contracts as compared to daywork contracts. Similar to turnkey contracts, under a footage contract we assume most of the risks associated with drilling operations that the operator generally assumes under a daywork contract.

During periods of reduced demand for drilling rigs, revenue rates may be significantly lower than current revenue rates and we may incur net losses primarily due to significant depreciation costs associated with our drilling equipment. Our profitability in the future will depend on many factors, but largely on utilization rates and revenue rates for our drilling rigs. We incurred net losses of approximately $1,800,000, $5,100,000 and $400,000 in the fiscal years ended March 31, 2004, 2003 and 2000, respectively.

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

For the three and nine months ended December 31, 2006 and 2005, the percentages of our drilling revenues by type of contract were as follows:

	Three Months Ended December 31,				Nine Months Ended December 31,
	2006		2005		2006		2005
Daywork contracts	97	%	91	%	97	%	86	%
Turnkey contracts	—		—		—		5	%
Footage contracts	3	%	9	%	3	%	9	%

We had no turnkey contracts in progress at December 31, 2006 or December 31, 2005. We had two footage contracts in progress at December 31, 2006 and three footage contracts in progress at December 31, 2005.

18

Statement of Operations Analysis

The following table provides information for our operations for the three and nine months ended December 31, 2006 and 2005.

	Three Months Ended December 31,						Nine Months Ended December 31,
	2006			2005			2006			2005
Contract drilling revenues:
Daywork contracts	$	108,808,207		$	67,895,686		$	302,272,866		$	173,006,043
Turnkey contracts		—			—			—			10,829,977
Footage contracts		3,613,140			6,563,102			10,558,610			17,472,034
Total contract drilling revenues	$	112,421,347		$	74,458,788		$	312,831,476		$	201,308,054
Contract drilling costs:
Daywork contracts	$	55,726,328		$	37,885,263		$	156,479,535		$	101,418,616
Turnkey contracts		—			—			—			7,462,869
Footage contracts		2,932,755			5,050,812			7,537,784			13,357,286
Total contract drilling costs	$	58,659,083		$	42,936,075		$	164,017,319		$	122,238,771
Drilling margin:
Daywork contracts	$	53,081,879		$	30,010,423		$	145,793,331		$	71,587,427
Turnkey contracts		—			—			—			3,367,108
Footage contracts		680,385			1,512,290			3,020,826			4,114,748
Total drilling margin	$	53,762,264		$	31,522,713		$	148,814,157		$	79,069,283
Revenue days by type of contract:
Daywork contracts		5,312			4,269			15,084			11,635
Turnkey contracts		—			—			—			558
Footage contracts		260			445			643			1,270
Total revenue days		5,572			4,714			15,727			13,463
Contract drilling revenue per revenue day	$	20,176		$	15,795		$	19,891		$	14,953
Contract drilling costs per revenue day	$	10,527		$	9,108		$	10,429		$	9,080
Drilling margin per revenue day	$	9,649		$	6,687		$	9,462		$	5,873
Rig utilization rates		98	%		96	%		97	%		95	%
Average number of rigs during the period		62.3			53.3			59.6			51.3

We present drilling margin information, defined as contract drilling revenues less contract drilling costs, because we believe it provides investors and our management additional information to assist them in assessing our business and performance in comparison to other companies in our industry. Since drilling margin is a “non-GAAP” financial measure under the rules and regulations of the SEC, we have included below a reconciliation of drilling margin to net earnings, which is the nearest comparable GAAP financial measure.

	Three Months Ended December 31,						Nine Months Ended December 31,
	2006			2005			2006			2005
Reconciliation of drilling margin to net earnings:
Drilling margin	$	53,762,264		$	31,522,713		$	148,814,157		$	79,069,283
Depreciation and amortization		(13,969,385	)		(8,598,306	)		(38,120,293	)		(23,868,669	)
General and administrative expense		(2,743,208	)		(1,637,268	)		(8,515,519	)		(4,839,703	)
Bad debt expense		(800,000	)		(25,110	)		(800,000	)		(25,110	)
Other income		839,990			406,025			2,923,175			1,184,248
Income tax expense		(13,101,642	)		(7,875,792	)		(37,340,611	)		(18,921,577	)
Net earnings	$	23,988,019		$	13,792,262		$	66,960,909		$	32,598,472

Our contract drilling revenues grew by approximately $37,963,000, or 51%, in the quarter ended December 31, 2006 from the quarter ended December 31, 2005, due to an improvement of $4,381 per day, or 28%, in average rig revenue rates

19

resulting from an increase in demand for drilling rigs, an 18% increase in revenue days due to an increase in the number of rigs in our fleet, and a 2% increase in rig utilization. Our contract drilling revenues grew by approximately $111,523,000, or 55%, for the nine months ended December 31, 2006 from the nine months ended December 31, 2005, due to an improvement of $4,938 per day, or 33%, in average rig revenue rates resulting from an increase in demand for drilling rigs, a 17% increase in revenue days due to an increase in the number of rigs in our fleet, and a 2% increase in rig utilization.

Our contract drilling costs grew by approximately $15,723,000, or 37%, in the quarter ended December 31, 2006 from the corresponding quarter of 2005, primarily due to the increase in the number of revenue days resulting from the increase in the number of rigs in our fleet and the increase in rig utilization. Our contract drilling costs per revenue day increased by $1,419, or 16%, in the quarter ended December 31, 2006 from the corresponding quarter in 2005, primarily due to higher wages and higher repairs and maintenance expenses. The overall increase in contract drilling costs was partially offset by decreases in contract drilling costs due to a shift to more daywork revenue days as a percentage of total revenue days. Daywork days represented 95% of revenue days in the quarter ended December 31, 2006, compared to 91% in the quarter ended December 31, 2005. Under turnkey and footage contracts, we provide supplies and materials such as fuel, drill bits, casing and drilling fluids, which significantly add to drilling costs when compared to daywork contracts. These costs are also included in the revenues we recognize for turnkey and footage contracts, resulting in higher revenue rates per day for turnkey and footage contracts compared to daywork contracts which do not include such costs.

Our contract drilling costs grew by approximately $41,779,000, or 34%, during the nine months ended December 31, 2006 from the corresponding period in 2005, primarily due to the increase in the number of revenue days resulting from the increase in the number of rigs in our fleet. Our contract drilling costs per revenue day increased by $1,349, or 15%, during the nine months ended December 31, 2006 from the corresponding period in 2005, primarily due to higher wages and higher repairs and maintenance expenses. The overall increase in contract drilling costs was partially offset by decreases in contract drilling costs due to a shift to more daywork revenue days as a percentage of total revenue days. Daywork days represented 96% of revenue days during the nine months ended December 31, 2006, compared to 86% during the nine months ended December 31, 2005.

Our depreciation and amortization expenses for the quarter ended December 31, 2006 increased by approximately $5,371,000, or 62%, compared to the corresponding quarter in 2005. Our depreciation and amortization expenses for the nine months ended December 31, 2006 increased by approximately $14,252,000, or 60%, compared to the corresponding period in 2005. These increases in 2006 over 2005 resulted primarily from an increase in the average size of our rig fleet, which increases consisted entirely of newly constructed rigs. The higher costs of our new rigs increased our average depreciation costs per revenue day by $683 to $2,507 from $1,824 in the quarter ended December 31, 2006, compared to the corresponding quarter in 2005, and by $651 to $2,424 from $1,773 during the nine months ended December 31, 2006, compared to the corresponding period in 2005.

Our general and administrative expense for the quarter ended December 31, 2006 increased by approximately $1,106,000, or 68%, compared to the corresponding quarter in 2005. The increase resulted primarily from compensation expense recognized for stock options and increases in payroll costs, bonus accruals, rent expenses, insurance expenses and director fees. Effective April 1, 2006, we adopted SFAS No. 123 (Revised), Share-Based Payment, and recognized approximately $584,000 of compensation expense for stock options in general and administrative expense for the quarter ended December 31, 2006. Also during the quarter ended December 31, 2006, payroll costs and bonus accrual costs increased by approximately $435,000, due to pay raises and an increase in the number of employees in our corporate offices, as compared to the quarter ended December 31, 2005. Insurance expenses, rent expenses and travel expenses increased by approximately $61,000 in the aggregate. We expect compensation costs for stock options to be approximately $590,000 for the remainder of fiscal year 2007, of which approximately $446,000 will be recognized as general and administrative expense.

Our general and administrative expense for the nine months ended December 31, 2006 increased by approximately $3,676,000, or 76%, compared to the corresponding period in 2005. The increase resulted primarily from compensation expense recognized for stock options and increases in payroll costs, bonus accruals, travel expenses, rent expenses, insurance expenses and director fees. We recognized approximately $2,071,000 of compensation expense for stock options in general and administrative expense for the nine months ended December 31, 2006. Also during the nine months ended December 31, 2006, payroll costs and bonus accrual costs increased by approximately $1,161,000, due to pay raises and an increase in the number of employees in our corporate offices, as compared to the nine months ended December 31, 2005. Director fees, insurance expenses, rent expenses and travel expenses increased by approximately $398,000 in the aggregate.

Our other income for the quarter ended December 31, 2006 increased by approximately $434,000, or 107%, compared to the corresponding quarter in 2005. Our other income for the nine months ended December 31, 2006 increased by approximately $1,739,000, or 147%, compared to the corresponding period in 2005. The increase was primarily due to

20

increased interest income that resulted from increased cash and cash equivalents and marketable security balances. Cash and cash equivalents increased from $32,579,272 at December 31, 2005 to $74,754,205 at December 31, 2006.

Our effective income tax rates of 35.3% and 35.8% for the three and nine months ended December 31, 2006, respectively, and 36.3% and 36.7% for the three and nine months ended December 31, 2005, respectively, differ from the federal statutory rate of 35%, due to permanent differences and state income taxes. Permanent differences are costs included in results of operations in the accompanying financial statements which are not fully deductible for federal income tax purposes. During the quarter ended June 30, 2006, we recognized a nonrecurring increase in income tax expense and deferred income taxes of approximately $362,000, due to the effects of changes in Texas franchise taxes on the future reversals of temporary differences. The Texas franchise tax changes became effective June 1, 2006. We estimate our effective tax rate for fiscal year 2007 to be approximately 35.8%.

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 and May 2006, we raised wage rates for our rig personnel by an average of 6%, 6% and 14%, respectively. We were able to pass these wage rate increases on to our customers based on contract terms. Availability of personnel in each of our market areas should improve if we continue experiencing a decline in the demand for drilling rigs. Therefore, it is not likely that we will experience additional wage rate increases until we have increased demand for drilling rigs.

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. We estimate these costs increased between 10% and 15% in fiscal year 2007, and we expect similar cost increases in fiscal year 2008. We may not be able to recover these cost increases through improvements in our daywork revenue rates.

Off Balance Sheet Arrangements

We do not currently have any off balance sheet arrangements.

Recently Issued Accounting Standards

Effective April 1, 2006, we adopted SFAS No. 123 (Revised), Share-Based Payment, utilizing the modified prospective approach. See the “Stock-based Compensation” section of Note 1 to the condensed consolidated financial statements included in this report for additional information.

In July 2006, the Financial Accounting Standards Board (the “FASB”) issued FASB Interpretation No. 48, Accounting for Uncertainty in Income Taxes - An Interpretation of FASB Statement No. 109 (“FIN 48”). FIN 48 clarifies the accounting for uncertainty in income taxes recognized in a company’s financial statements in accordance with SFAS No. 109. FIN 48 also prescribes a recognition threshold and measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. The new FASB standard also provides guidance on derecognition, classification, interest and penalties, accounting in interim periods, disclosure and transition. FIN 48 is effective for fiscal years beginning after December 15, 2006. We do not expect the adoption of FIN 48 to have a material impact on our financial position or results of operations and financial condition.

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 is effective for financial statements issued for fiscal years beginning after November 15, 2007. We do not expect the adoption of SFAS No. 157 to have a material impact on our financial position or results of operations and financial condition.

In September 2006, the FASB issued Staff Position AUG AIR-1, Accounting for Planned Major Maintenance Activities, which eliminates the acceptability of the accrue-in-advance method of accounting for planned major maintenance activities. This FASB Staff Position is effective for fiscal years beginning after December 15, 2006. We do not use the accrue-in-advance method of accounting for rig refurbishments. We use a “built-in overhaul” method of accounting for rig refurbishments, whereby these expenditures are recognized as capital asset additions when incurred. The application of this FASB Staff Position will not have a material impact on our financial position or results of operations and financial condition.

21

In September 2006, the SEC released Staff Accounting Bulletin No. 108, Considering the Effects of Prior Year Misstatements When Quantifying Misstatements in Current Year Financial Statements, (“SAB 108”), which provides interpretive guidance on the SEC’s views regarding the process of quantifying materiality of financial statement misstatements. SAB 108 is effective for fiscal years ending after November 15, 2006, with early application for the first interim period ending after November 15, 2006. We do not expect the application of SAB 108 will have a material effect on our financial position or results of operations and financial condition.

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Our exposure to market risk from changes in interest rates primarily relates to our cash equivalents and marketable securities, which consist of investments in highly liquid debt instruments denominated in U.S. dollars. We are averse to principal loss and ensure the safety and preservation of our invested funds by limiting default risk, market risk and reinvestment risk.

We are subject to market risk exposure related to changes in interest rates on our outstanding floating rate debt. However, at December 31, 2006 we had no outstanding debt subject to variable interest rates.

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 report. Based on that evaluation, our Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures were effective as of December 31, 2006 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.

There has been no change in our internal control over financial reporting that occurred during the nine months ended December 31, 2006 which has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

PART II. OTHER INFORMATION

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 10-Q for the quarter ended December 31, 2003 (File No. 1-8182, Exhibit 3.3)).
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 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 (Subsections (a)

22

		and (b) of Section 1350, Chapter 63 of Title 18, United States Code).
32.2	-	Certification by William D. Hibbetts, Senior Vice President and Chief Financial Officer, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (Subsections (a) and (b) of Section 1350, Chapter 63 of Title 18, United States Code).

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

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 Chief Financial Officer

(Principal Financial Officer and Duly Authorized Representative)

Dated: February 1, 2007

23

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 10-Q for the quarter ended December 31, 2003 (File No. 1-8182, Exhibit 3.3)).
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 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 (Subsections (a) and (b) of Section 1350, Chapter 63 of Title 18, United States Code).
32.2		-	Certification by William D. Hibbetts, Senior Vice President and Chief Financial Officer, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (Subsections (a) and (b) of Section 1350, Chapter 63 of Title 18, United States Code).

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

EX-31.1

EXHIBIT 31.1

I, Wm. Stacy Locke, President and Chief Executive Officer of Pioneer Drilling Company, certify that:

1. I have reviewed this quarterly report on Form 10-Q of Pioneer Drilling Company for the quarterly period ended December 31, 2006;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

February 1, 2007

/s/ Wm. Stacy Locke

Wm. Stacy Locke

President and Chief Executive Officer

EX-31.2

EXHIBIT 31.2

I, William D. Hibbetts, Senior Vice President and Chief Financial Officer of Pioneer Drilling Company, certify that:

1. I have reviewed this quarterly report on Form 10-Q of Pioneer Drilling Company for the quarter ended December 31, 2006;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

February 1, 2007

/s/ William D. Hibbetts

William D. Hibbetts

Senior Vice President and Chief Financial Officer

EX-32.1

EXHIBIT 32.1

Certification Pursuant to

Section 906 of the Sarbanes-Oxley Act of 2002

(Subsections (a) and (b) of Section 1350, Chapter 63 of Title 18, United States Code)

Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (Subsections (a) and (b) of Section 1350, Chapter 63 of Title 18, United States Code), I, Wm. Stacy Locke, President and Chief Executive Officer of Pioneer Drilling Company, a Texas corporation (the “Company”), hereby certify, to my knowledge, that:

(1) the Company’s Quarterly Report on Form 10-Q for the quarter ended December 31, 2006 (the “Report”) fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2) the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

Dated: February 1, 2007	/s/ Wm. Stacy Locke
	Wm. Stacy Locke
	President and Chief Executive Officer

EX-32.2

EXHIBIT 32.2

Certification Pursuant to

Section 906 of the Sarbanes-Oxley Act of 2002

(Subsections (a) and (b) of Section 1350, Chapter 63 of Title 18, United States Code)

Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (Subsections (a) and (b) of Section 1350, Chapter 63 of Title 18, United States Code), I, William D. Hibbetts, Senior Vice President and Chief Financial Officer of Pioneer Drilling Company, a Texas corporation (the “Company”), hereby certify, to my knowledge, that:

(1) the Company’s Quarterly Report on Form 10-Q for the quarter ended December 31, 2006 (the “Report”) fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2) the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

Dated: February 1, 2007	/s/ William D. Hibbetts
	William D. Hibbetts
	Senior Vice President and Chief Financial Officer