Edgar Filing: PIONEER DRILLING CO

Form 10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

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

For the quarterly period ended September 30, 2007

¨	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		(I.R.S. Employer
incorporation or organization)		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 October 31, 2007, there were 49,650,978 shares of common stock, par value $0.10 per share, of the registrant issued and outstanding.

PART I. FINANCIAL INFORMATION

ITEM 1.

FINANCIAL STATEMENTS

PIONEER DRILLING COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS


	September 30,
	2007		March 31,
	(Unaudited)		2007
ASSETS
Current assets:
Cash and cash equivalents	$	66,303,485	$	84,945,210
Receivables:
Trade, net		50,646,039		54,205,696
Contract drilling in progress		13,807,679		9,837,323
Income tax receivable		320,733		3,491,846
Deferred income taxes		2,681,463		2,174,947
Inventory		1,081,715		—
Prepaid expenses and other current assets		3,582,903		3,653,096

Total current assets		138,424,017		158,308,118

Property and equipment, at cost:		557,206,869		462,748,886
Less accumulated depreciation and amortization		147,521,577		119,847,687

Net property and equipment		409,685,292		342,901,199
Intangible and other assets		256,723		286,307

Total assets	$	548,366,032	$	501,495,624


LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities:
Accounts payable	$	24,895,641	$	18,625,737
Prepaid drilling contracts		5,193,956		—
Accrued expenses:
Payroll and related employee costs		6,572,757		7,086,450
Insurance premiums and deductibles		8,187,534		6,754,331
Other		4,291,921		1,752,751

Total current liabilities		49,141,809		34,219,269
Non-current liabilities		357,178		346,196
Deferred income taxes		43,602,310		38,820,868

Total liabilities		93,101,297		73,386,333

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; 49,650,978 shares and 49,628,478 shares issued and outstanding at September 30, 2007 and March 31, 2007, respectively		4,965,097		4,962,847
Additional paid-in capital		293,892,037		291,607,071
Accumulated earnings		156,407,601		131,539,373

Total shareholders’ equity		455,264,735		428,109,291

Total liabilities and shareholders’ equity	$	548,366,032	$	501,495,624

See accompanying notes to condensed consolidated financial statements.

PIONEER DRILLING COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(Unaudited)


	Three Months Ended						Six Months Ended
	September 30,						September 30,
	2007			2006			2007			2006
Contract drilling revenues	$	106,515,937		$	106,916,822		$	209,295,387		$	200,410,129


Costs and expenses:
Contract drilling		66,644,901			55,815,449			130,437,196			105,358,235
Depreciation and amortization		16,093,189			12,580,901			32,190,898			24,150,907
General and administrative		3,844,393			2,846,813			7,164,526			5,772,313
Bad debt expense		2,626,768			—			2,626,768			—

Total operating costs and expenses		89,209,251			71,243,163			172,419,388			135,281,455

Income from operations		17,306,686			35,673,659			36,875,999			65,128,674


Other income (expense):
Interest expense		(14,125	)		(1,255	)		(14,981	)		(64,407	)
Interest income		730,834			1,012,903			1,592,772			2,110,629
Other		11,583			13,636			30,985			36,964

Total other income		728,292			1,025,284			1,608,776			2,083,186


Income before income taxes		18,034,978			36,698,943			38,484,775			67,211,860
Income tax expense		(6,255,022	)		(13,212,550	)		(13,616,546	)		(24,238,970	)

Net earnings	$	11,779,956		$	23,486,393		$	24,868,229		$	42,972,890

Earnings per common share—Basic	$	0.24		$	0.47		$	0.50		$	0.87

Earnings per common share—Diluted	$	0.23		$	0.47		$	0.50		$	0.86

Weighted average number of shares outstanding—Basic		49,650,978			49,597,521			49,642,631			49,594,765

Weighted average number of shares outstanding—Diluted		50,204,735			50,140,476			50,209,819			50,153,336

See accompanying notes to condensed consolidated financial statements.

PIONEER DRILLING COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)


	Six Months Ended September 30,
	2007			2006
Cash flows from operating activities:
Net earnings	$	24,868,229		$	42,972,890
Adjustments to reconcile net earnings to net cash provided by operating activities:
Depreciation and amortization		32,190,898			24,150,907
Loss on disposal of properties and equipment		1,925,024			3,600,520
Allowance for doubtful accounts		2,626,768			—
Change in deferred income taxes		4,274,926			2,983,759
Stock-based compensation expense		2,126,681			1,752,567
Deferred operating lease liability		10,982			29,337
Changes in current assets and liabilities:
Receivables		932,889			(6,694,744	)
Contract drilling in progress		(3,970,356	)		(3,285,161	)
Income taxes receivable		3,171,113			—
Inventory		(1,081,715	)
Prepaid expenses		70,193			1,516,754
Accounts payable		3,029,996			2,158,544
Prepaid drilling contracts		5,193,956			(65,402	)
Income taxes payable		—			(3,995,924	)
Accrued expenses		3,458,680			2,214,882

Net cash provided by operating activities		78,828,264			67,338,929


Cash flows from financing activities:
Proceeds from exercise of stock options		106,700			47,700
Excess tax benefit of stock option exercise		53,834			—

Net cash provided by financing activities		160,534			47,700


Cash flows from investing activities:
Purchase of property and equipment		(99,123,977	)		(80,483,090	)
Proceeds from sale of property and equipment		1,493,454			3,622,898

Net cash used in investing activities		(97,630,523	)		(76,860,192	)


Net decrease in cash and cash equivalents		(18,641,725	)		(9,473,563	)

Beginning cash and cash equivalents		84,945,210			91,173,764

Ending cash and cash equivalents	$	66,303,485		$	81,700,201


Supplementary Disclosure:
Interest and commitment fees paid	$	14,982		$	62,847
Income taxes paid	$	6,140,000		$	25,251,135
Change in accounts payable for property and equipment purchases	$	3,239,909		$	5,200,764

See accompanying notes to condensed consolidated financial statements.

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 and Colombia. As of September 30, 2007, our rig fleet consisted of 68 operating drilling rigs, 17 of which were operating in our South Texas division, 20 of which were operating in our East Texas division, ten of which were operating in our North Texas division, six of which were operating in our Western Oklahoma division, 13 of which were operating in our Rocky Mountain division consisting of locations in Utah and North Dakota and two of which were operating internationally in Colombia. We did not include one 1500 horsepower rig in our 68 rig count as it was being upgraded at September 30, 2007. This rig will be deployed for further expansion into international markets once it is completed.

We conduct our operations through our principal operating subsidiary, Pioneer Drilling Services, Ltd. The accompanying consolidated financial statements include our accounts and the accounts of our wholly owned subsidiaries. In accordance with the Financial Accounting Standards Board (the “FASB”) Interpretation No. 46(R), consolidation of Variable Interest Entities, we also consolidate any variable interest entity of which we are the primary beneficiary, as defined. 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 consolidated balance sheet as of March 31, 2007 has been derived from our audited financial statements. We suggest that you read these condensed consolidated financial statements together with the consolidated financial statements and the related notes included in our annual report on Form 10-K for the fiscal year ended March 31, 2007.

Foreign Currencies

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

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 undertake more longer-term drilling contracts. In addition, we have entered into longer-term drilling contracts for our newly constructed rigs. As of October 31, 2007, we had 19 contracts with terms of six months to two years in duration, of which seven will expire by May 1, 2008, eight have a remaining term of seven to 12 months, three have a remaining term of 13 to 18 months and one has a remaining term in excess of 18 months.

Trade Accounts Receivable

We record trade accounts receivable at the amount we invoice our customers. These accounts do not bear interest. The allowance for doubtful accounts is our best estimate of the amount of probable credit losses in our accounts receivable as of the balance sheet date. We determine the allowance based on the credit worthiness of our customers and general economic conditions. Consequently, an adverse change in those factors could affect our estimate of our allowance for doubtful accounts. We review our allowance for doubtful accounts monthly. Balances more than 90 days past due are reviewed individually for collectibility. We charge off account balances against the allowance after we have exhausted all reasonable means of collection and determined that the potential for recovery is remote. We do not have any off-balance sheet credit exposure related to our customers.

We recorded bad debt expense of approximately $2,627,000 during the quarter ended September 30, 2007 due to a decrease in our estimated recovery from a customer in bankruptcy. As a result, our allowance for doubtful accounts increased from $1,000,000 to approximately $3,627,000 at September 30, 2007.

Inventories

Inventories are primarily replacement parts and supplies held for use in our drilling operations. Inventories are valued at the lower of cost (first in, first out or actual) or market value.

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.

Stock-based Compensation

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 the intrinsic-value-based method prescribed by 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 six months ended September 30, 2007 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.

Compensation costs of approximately $1,682,000 and $445,000 for stock options were recognized in general and administrative expense and contract drilling costs, respectively, for the six months ended September 30, 2007. Approximately $261,000 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. In accordance with SFAS 123R, the entire compensation cost has been recognized for stock options that are fully vested at the grant date.

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. In accordance with SFAS 123R, we reported all excess tax benefits resulting from the exercise of stock options as financing cash flows in our consolidated statement of cash flows. There were 22,500 stock options exercised during the six months ended September 30, 2007.

We estimate the fair value of each option grant on the date of grant using a Black-Scholes options-pricing model. The following table summarizes the assumptions used in the Black-Scholes option-pricing model for the three months ended September 30, 2007 and the six months ended September 30, 2007 and 2006. There were no options granted during the three months ended September 30, 2006:


	Three Months Ended
	September 30,			Six Months Ended September 30,
	2007			2007			2006
Weighted average expected volatility		46	%		47	%		49	%
Weighted-average risk-free interest rates		5.0	%		4.8	%		5.0	%
Weighted-average expected life in years		4.46			3.97			2.86
Options granted		130,000			899,500			482,000
Weighted-average grant-date fair value	$	6.23		$	5.89		$	5.36

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.

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

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

Related-Party Transactions

We purchased services from Frontier Services, Inc. during the three and six months ended September 30, 2007 and 2006. Frontier Services, Inc. is more than 5% owned by an immediate family member of a Vice President of Operations of our company. The following summarizes the transactions with this company in each period.


	Three Months Ended September 30,				Six Months Ended September 30,				Amount Owed September 30,
	2007		2006		2007		2006		2007		2006
Frontier Services, Inc.
Purchases	$	4,588	$	—	$	12,561	$	606	$	1,870	$	—
Payments	$	5,660	$	—	$	15,259	$	606

Our Chief Executive Officer, Chief Operating Officer, Senior Vice President of Marketing, and a Vice President of Operations occasionally acquire a 1% to 5% minority working interest in oil and gas wells that we drill for one of our customers. These individuals acquired a minority working interest in three wells that we drilled for this customer during the six months ended September 30, 2007. We recognized contract drilling revenues of approximately $1,431,000 on these wells during the six months ended September 30, 2007. These individuals did not acquire a minority working interest in any wells that we drilled during the six months ended September 30, 2006.

Recently Issued Accounting Standards

In July 2006, the Financial Accounting Standards Board 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. We adopted the provisions of FIN 48 effective April 1, 2007. The adoption of FIN 48 had no 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 had no material impact on our financial position or results of operations and financial condition.

In February 2007, the FASB issued SFAS No. 159, The Fair Value Option for Financial Assets and Financial Liabilities — Including an amendment of FASB Statement No. 115. This statement permits entities to choose to measure many financial instruments and certain other items at fair value that are not currently required to be measured at fair value and establishes presentation and disclosure requirements designed to facilitate comparisons between entities that choose different measurement attributes for similar types of assets and liabilities. SFAS No. 159 is effective for fiscal years beginning after November 15, 2007. We do not expect the adoption of SFAS No. 159 to have a material impact on our financial position or results of operations and financial condition.

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 other equipment. Borrowings under the credit facility bear interest at a rate equal to Frost National Bank’s prime rate (7.75% at September 30, 2007) 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 United States drilling rigs and associated equipment and receivables. At September 30, 2007, 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 September 30, 2007, 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 $34,533,000. 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 September 30, 2007, 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

In connection with our expansion into international markets, we have obtained bonds for bidding on drilling contracts, performing under drilling contracts, and remitting customs and importation duties. We have guaranteed payments of approximately $14,975,000 relating to our performance relating to these bonds.

In addition, due to the nature of our business, we are, from time to time, involved in routine litigation or subject to disputes or claims related to our business activities, including workers’ compensation claims and employment-related disputes. Legal costs relating to these matters are expensed as incurred. In the opinion of our management, none of the pending litigation, disputes or claims against us will have a material adverse effect on our financial condition, results of operations or cash flow from operations and there is only a remote possibility that any such matter will require any additional loss accrual.

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				Six Months Ended
	September 30,				September 30,
	2007		2006		2007		2006
Basic
Net earnings	$	11,779,956	$	23,486,393	$	24,868,229	$	42,972,890

Weighted average shares		49,650,978		49,597,521		49,642,631		49,594,765

Earnings per share	$	0.24	$	0.47	$	0.50	$	0.87


	Three Months Ended				Six Months Ended
	September 30,				September 30,
	2007		2006		2007		2006
Diluted
Net earnings	$	11,779,956	$	23,486,393	$	24,868,229	$	42,972,890
Effect of dilutive securities:
None		—		—		—		—

Net earnings and assumed conversion	$	11,779,956	$	23,486,393	$	24,868,229	$	42,972,890

Weighted average shares:
Outstanding		49,650,978		49,597,521		49,642,631		49,594,765
Options		553,757		542,955		567,188		558,571

		50,204,735		50,140,476		50,209,819		50,153,336

Earnings per share	$	0.23	$	0.47	$	0.50	$	0.86

5. Equity Transactions

Employees exercised stock options for the purchase of 22,500 shares of common stock during the six months ended September 30, 2007 at prices ranging from $4.52 to $4.77 per share. An employee exercised 10,000 shares of stock options during the six months ended September 30, 2006 at a price of $4.77 per share.

6. Variable Interest Entity

A special income tax benefit is available to companies that invest capital assets in Colombia. Our U.S. operating company acquired three drilling rigs for export to Colombia because our operating entity in Colombia was not yet formed and was not able to acquire the drilling rigs directly from the third party vendor. After our operating entity in Colombia was formed, our U.S. operating company sold two drilling rigs to Stayton Asset Group, a newly created variable interest entity. Stayton Asset Group immediately sold these two drilling rigs to our operating entity in Colombia. We completed the sale and repurchase of one drilling rig for approximately $17,800,000 in July 2007 and the sale and repurchase of second rig for approximately $17,200,000 in September 2007. We determined that we are the primary beneficiary of Stayton Asset Group. Accordingly, we consolidated the accounts of Stayton Asset Group in our consolidated financial statements at September 30, 2007 in accordance with the requirements of FIN 46R. At September 30, 2007, Stayton Asset Group’s financial statements reflected a receivable of approximately $35,000,000 due from our operating company in the Colombia and a payable to our operating company in the United States, which were both eliminated upon consolidation in our consolidated financial statements.

The special income tax benefit permitted by the Colombian government will allow us to recover 140% of the cost of certain imported assets. We recognized a tax benefit for this Colombian tax deduction to the extent of taxable income that we expect to earn over the term of the two existing drilling contracts in Colombia with the excess tax benefit offset by a valuation allowance. The terms of the two existing drilling contracts expire in the fourth quarter of fiscal year 2008 and first quarter of fiscal year 2009. We estimated our taxable income over the terms of these existing contracts and recognized a pro rata portion of the tax benefit of approximately $24,000 for the quarter ended September 30, 2007. We recorded a valuation allowance of approximately $3,834,000 to offset the excess tax benefit. We expect to recognize additional tax benefits for this Colombian tax deduction over the remaining term of these existing drilling contracts. Also, we expect to recognize additional tax benefits for this Colombian tax deduction, if we extend the terms of the existing drilling contracts or we enter into new drilling contracts.

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, the availability, terms and deployment of capital, the availability of qualified personnel, and changes in, or our failure or inability to comply with, government regulations, including those relating to the environment. We have discussed many of these factors in more detail elsewhere in this report and in our annual report on Form 10-K for the fiscal year ended March 31, 2007. These factors are not necessarily all the important factors that could affect us. Unpredictable or unknown factors we have not discussed in this report or in our annual report on Form 10-K could also have material adverse effects on actual results of matters that are the subject of our forward-looking statements. All forward-looking statements speak only as the date on which they are made and we undertake no duty to update or revise any forward-looking statements. We advise our shareholders that they should (1) be aware that important factors not referred to above could affect the accuracy of our forward-looking statements and (2) use caution and common sense when considering our forward-looking statements.

Company Overview

Pioneer Drilling Company 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 and Colombia. 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. Since November 2006, we have been experiencing a decline in the demand for drilling rigs and have experienced a decline in revenue rates on contract renewals due to an excess supply of drilling rigs within the industry, which is due to the substantial addition of new and refurbished drilling rigs during the past year. Any continued weakness in the demand for additional drilling rigs will likely result in lower revenue rates for our rigs as existing contracts expire and more drilling rigs are added to the market.

Our business strategy is to own and operate a high-quality fleet of land drilling rigs in active drilling markets, 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 attractive opportunities arise. We may explore acquiring businesses in other sectors within the oilfield services industry. In addition, we are evaluating opportunities for expansion into international markets beginning with Colombia. We commenced operations in Colombia with two contracts for which we exported two drilling rigs to Colombia that began operations in September 2007 and October 2007. Our immediate international business strategy is to continue our expansion in Colombia to include at least three drilling rigs by fiscal year end.

Since September 1999, we have significantly expanded our fleet of drilling rigs through acquisitions and the construction of new and refurbished rigs. As of October 31, 2007, our rig fleet consisted of 68 operating drilling rigs, of which 27 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, 20 are operating in our East Texas division, ten are operating in our North Texas division, six are operating in our Western Oklahoma division, 13 are operating in our Rocky Mountain division consisting of locations in Utah and North Dakota and two are operating internationally in Colombia. Not included in our 68 operating rig count is a 1500 horsepower rig that we were upgrading at September 30, 2007 that we plan to deploy for further expansion into international markets.

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. As demand for drilling rigs improved during calendar year 2005 and 2006, we entered into more longer-term drilling contracts. As of October 31, 2007, we had 19 contracts with terms of six months to two years in duration, of which seven will expire by May 1, 2008, eight have a remaining term of seven to 12 months, three have a remaining term of 13 to 18 months and one has a remaining term in excess of 18 months.

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 each period presented below, all of our operating rigs were capable of working and are included in our rig utilization calculations.

For the three and six months ended September 30, 2007 and 2006 our rig utilization, revenue days and number of operating drilling rigs were as follows:


	Three Months Ended				Six Months Ended
	September 30,				September 30,
	2007		2006		2007		2006
Utilization Rates	90	%	97	%	90	%	96	%
Revenue Days	5,559		5,274		10,946		10,155

The primary reason for the increase in the number of revenue days in 2007 over 2006 is the increase in size of our rig fleet. Due to the current excess supply of drilling rigs available for work, we currently expect a 5% to 10% decrease in utilization rates for the remainder of fiscal year 2008 as compared to fiscal year 2007.

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. Upgrades for the fiscal year ending March 31, 2008 will primarily focus on: replacing older engines with more modern, efficient engines; upgrading to higher horsepower mud pumps; upgrading to modern mud cleaning systems on some of our drilling rigs; and adding iron roughnecks to approximately 30 of our drilling rigs.

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.

In addition, the availability of drilling rigs capable of working affects our revenue rates and utilization rates. For much of calendar year 2005 and 2006, our industry experienced a shortage of drilling rigs leading to revenue rates and utilization rates that were at historically high levels. However, our industry is currently experiencing an excess drilling rig supply due to new construction and refurbishments. This condition may correct itself over time if older drilling rigs are retired and if the outlook for natural gas pricing improves and results in an increase in drilling activity.

On October 19, 2007, the spot price for West Texas Intermediate crude oil was $88.60, the spot price for Henry Hub natural gas was $6.91 and the Baker Hughes land rig count was 1,687, a 3.6% increase from 1,629 on October 20, 2006. Since January 1, 2007, the Baker Hughes land rig count has been between 1,588 and 1,730.

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 quarter ended September 30, 2007 and each of the previous five years ended September 30, 2007 were:


	Three Months Ended
	September 30,		Years Ended September 30,
	2007		2007		2006		2005		2004		2003
Oil (West Texas Intermediate)	$	75.73	$	64.87	$	67.46	$	53.72	$	37.10	$	30.45

Natural Gas (Henry Hub)	$	6.12	$	6.85	$	8.24	$	7.36	$	5.55	$	5.22

U.S. Land Rig Count		1,693		1,646		1,479		1,203		1,038		839

Most of our customers drill in search of natural gas; however, we currently operate five 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. Individual contracts are usually completed in less than 60 days. The risks to us under a turnkey contract and, to a lesser extent, under footage contracts, are substantially greater than on a contract drilled on a daywork basis. Under a turnkey contract, we assume most of the risks associated with drilling operations that are generally assumed by the operator in a daywork contract, including the risks of blowout, loss of hole, stuck drill pipe, machinery breakdowns and abnormal drilling conditions, as well as risks associated with subcontractors’ services, supplies, cost escalations and personnel operations.

Our management has determined that it is appropriate to use the percentage-of-completion method, as defined in the American Institute of Certified Public Accountants’ Statement of Position 81-1, to recognize revenue on our turnkey and footage contracts. Although our turnkey and footage contracts do not have express terms that provide us with rights to receive payment for the work that we perform prior to drilling wells to the agreed-on depth, we use this method because, as provided in applicable accounting literature, we believe we achieve a continuous sale for our work-in-progress and believe, under applicable state law, we ultimately could recover the fair value of our work-in-progress even in the event we were unable to drill to the agreed-on depth in breach of the applicable contract. However, in the event we were unable to drill to the agreed-on depth in breach of the contract, ultimate recovery of that value would be subject to negotiations with the customer and the possibility of litigation.

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

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

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

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 September 30, 2007, would have resulted in a corresponding decrease in our net earnings of approximately $3,470,000 for the six months ended September 30, 2007.

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

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

We receive payment under turnkey and footage contracts when we deliver to our customer a well completed to the depth specified in the contract, unless the customer authorizes us to drill to a more shallow depth. Since 1995, we have completed all our turnkey or footage contracts. Although our initial cost estimates for turnkey and footage contracts do not include cost estimates for risks such as stuck drill pipe or loss of circulation, we believe that our experienced management team, our knowledge of geologic formations in our areas of operations, the condition of our drilling equipment and our experienced crews have previously enabled us to make reasonable cost estimates and complete contracts according to our drilling plan. While we do bear the risk of loss for cost overruns and other events that are not specifically provided for in our initial cost estimates, our pricing of turnkey and footage contracts takes such risks into consideration. When we encounter, during the course of our drilling operations, conditions unforeseen in the preparation of our original cost estimate, we increase our cost estimate to complete the contract. If we anticipate a loss on a contract in progress at the end of a reporting period due to a change in our cost estimate, we accrue the entire amount of the estimated loss, including all costs that are included in our revised estimated cost to complete that contract, in our consolidated statement of operations for that reporting period. During the six months ended September 30, 2007, we experienced losses on five of the 43 turnkey and footage contracts completed, with losses exceeding $25,000 each on three contracts. During the six months ended September 30, 2006, we experienced losses on two of 26 footage contracts completed, and those losses were each less than $25,000. 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 four footage contracts in progress at September 30, 2007, which were completed prior to the release of the financial statements included in this report. Our contract drilling in progress totaled approximately $13,808,000 at September 30, 2007. Of that amount accrued, footage contract revenues were approximately $1,040,000. The remaining balance of approximately $12,768,000

related to the revenue recognized but not yet billed on daywork contracts in progress at September 30, 2007. At March 31, 2007, drilling in progress totaled $9,837,000, of which $329,000 related to footage contracts and $9,508,000 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 commercial credit reports, trade references, bank references, financial information, production information 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 90 days for any of our contracts in the last three fiscal years. We had an allowance for doubtful accounts of $3,627,000 at September 30, 2007 and $1,000,000 at March 31, 2007.

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.

Our accrued insurance premiums and deductibles as of September 30, 2007 include accruals of approximately $752,000 and $6,792,000 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. Our deductible under our workers’ compensation insurance increased to $500,000 in October 2007. 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 68 operating rigs as of October 31, 2007. We have financed this growth with a combination of debt and equity financing and internal cash flows. We have raised additional equity or used equity for growth nine times since January 2000. We plan to continue to grow our rig fleet and we may pursue other business opportunities that are complementary to our U.S. contract land drilling business. We may finance these growth opportunities through the issuance of debt and the issuance of additional shares of our common stock.

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 (7.75% at September 30, 2007) 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 United States drilling rigs and associated equipment and receivables. At September 30, 2007, 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 six months ended September 30, 2007, the additions to our property and equipment consisted of the following:


	Three Months		Six Months
Drilling rigs	$	20,940,696	$	56,598,615
Other drilling equipment		28,222,095		43,464,982
Transportation equipment		1,081,609		1,799,374
Other		213,357		500,915

	$	50,457,757	$	102,363,886

Property and equipment additions for the six months ended September 30, 2007 include approximately $3,240,000 of purchases recorded in accounts payable at March 31, 2007.

As of March 31, 2007, we were constructing one 1000-horsepower mechanical rig. We placed this rig into service in April 2007 and incurred approximately $2,173,000 of rig construction costs during the six months ended September 30, 2007. In addition, we incurred approximately $53,609,000 during the six months ended September 30, 2007 to purchase and upgrade the three drilling rigs acquired for expansion into international markets. We expect to incur approximately $3,000,000 on additional acquisition and upgrade costs for these three drilling rigs during the remainder of fiscal year 2008.

For the remainder of fiscal year 2008, we project capital expenditures (excluding the new rig acquisition and upgrade costs for the three drilling rigs noted above) to be approximately $22,700,000, comprised of routine rig capital expenditures of approximately $16,300,000, rig upgrade expenditures of approximately $4,600,000, and other capital expenditures of approximately $1,800,000. We expect to fund these capital expenditures primarily from operating cash flow in excess of our working capital and other normal cash flow requirements.

Working Capital

Our working capital was $89,282,208 at September 30, 2007, compared to $124,088,849 at March 31, 2007. Our current ratio, which we calculate by dividing our current assets by our current liabilities, was 2.8 at September 30, 2007, compared to 4.6 at March 31, 2007.

Our operations have historically generated cash flows sufficient to at least meet our requirements for debt service and normal capital expenditures. However, during periods when higher percentages of our 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. We believe our cash generated by operations and our ability to borrow under the currently unused portion of our revolving line and letter of credit facility should allow us to meet our routine financial obligations for at least the next twelve months.

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


	September 30,		March 31,
	2007		2007		Change
Cash and cash equivalents	$	66,303,485	$	84,945,210	$	(18,641,725	)
Trade receivables, net		50,646,039		54,205,696		(3,559,657	)
Contract drilling in progress		13,807,679		9,837,323		3,970,356
Income tax receivable		320,733		3,491,846		(3,171,113	)
Deferred income taxes		2,681,463		2,174,947		506,516
Inventory		1,081,715		—		1,081,715
Prepaid expenses		3,582,903		3,653,096		(70,193	)

Current assets		138,424,017		158,308,118		(19,884,101	)

Accounts payable		24,895,641		18,625,737		6,269,904
Prepaid drilling contracts		5,193,956		—		5,193,956
Accrued payroll and related employee costs		6,572,757		7,086,450		(513,693	)
Accrued insurance premiums and deductibles		8,187,534		6,754,331		1,433,203
Other accrued expenses		4,291,921		1,752,751		2,539,170

Current liabilities		49,141,809		34,219,269		14,922,540

Working capital	$	89,282,208	$	124,088,849	$	(34,806,641	)

The decrease in cash and cash equivalents was primarily due to property and equipment expenditures of approximately $99,124,000 during the six months ended September 30, 2007.

The decrease in our receivables at September 30, 2007 from March 31, 2007 was due to a $702 per day decrease in average revenue rates in the second quarter of fiscal year 2008, compared to the fourth quarter of fiscal year 2007, and due to a $2,627,000 increase in our allowance for doubtful accounts. This decrease in receivables was partially offset by an increase in receivables due to our operating three additional rigs during the three months ended September 30, 2007, as compared to March 31, 2007.

The increase in contract drilling in progress at September 30, 2007 from March 31, 2007 was due to four footage contracts that were in progress as of September 30, 2007, compared to two footage contracts in progress as of March 31, 2007. The increase is also due to mobilization in progress at September 30, 2007 for one of our drilling rigs to Colombia.

The decrease in our income tax receivable is due to the collection of an income tax refund that resulted from an excess tax deposit for our fiscal year ended March 31, 2007.

During the three months ended September 30, 2007, we began maintaining inventories of replacement parts and supplies for our drilling rigs operating in Colombia to ensure efficient operations in geographically remote areas.

Most of our prepaid expenses as of September 30, 2007 and March 31, 2007 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. As of September 30, 2007, the decrease in prepaid expenses was primarily due to the amortization of 11 months of these October insurance premiums, as compared to five months of amortization as of March 31, 2007. The decrease in prepaid expense was substantially offset by an increase in prepaid expenses for deferred mobilization costs relating to our drilling contracts in Colombia.

The increase in accounts payable at September 30, 2007, as compared to March 31, 2007, was primarily due to our operating three additional drilling rigs and a $379 per day increase in average drilling costs during the second quarter of fiscal year 2008, as compared to the fourth quarter of fiscal year 2007.

The increase in prepaid drilling contracts as of September 30, 2007, as compared to March 31, 2007, was due to amounts billed for mobilization revenues on our Colombian drilling contracts in excess of revenue recognized. Mobilization billings, and costs incurred for the mobilization, are deferred and recognized over the term of the related drilling contract.

The decrease in accrued payroll and related employee costs was primarily due to a decrease in accrued bonuses at September 30, 2007, as compared to March 31, 2007.

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

The increase in other accrued expenses at September 30, 2007, as compared to March 31, 2007, was primarily due to accruals for property taxes. The majority of property taxes are paid in January of each year, so the accrual increases each quarter until the property taxes are paid.

Long Term Debt

We had no long-term bank debt outstanding at September 30, 2007. See “- Sources of Capital Resources” for a description of our credit facility.

Contractual Obligations

The following table includes all our contractual obligations of the types specified below at September 30, 2007.


	Payments Due by Period
Contractual Obligations	Total		Less than 1 year		1-3 years		4-5 years		More than 5 years
Purchase Obligations	$	2,769,861	$	2,769,861	$	—	$	—	$	—

Operating Lease Obligations		1,692,182		368,536		611,039		433,246		279,361

Total	$	4,462,043	$	3,138,397	$	611,039	$	433,246	$	279,361

Debt Requirements

Our 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.

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 or excess capacity of drilling rigs in the industry, revenue rates and utilization rates may be significantly lower than the rates we are currently experiencing. Our profitability in the future will depend on many factors, but significantly on utilization rates and revenue rates for our drilling rigs.

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 six months ended September 30, 2007 and 2006, the percentages of our drilling revenues by type of contract were as follows:


	Three Months Ended September 30,				Six Months Ended September 30,
	2007		2006		2007		2006
Daywork contracts	93	%	97	%	94	%	97	%
Turnkey contracts	2	%	—		2	%	—
Footage contracts	5	%	3	%	4	%	3	%

We had no turnkey contracts in progress at September 30, 2007 or September 30, 2006. We had four footage contracts in progress at September 30, 2007 and one footage contract in progress at September 30, 2006.

Statement of Operations Analysis

The following table provides information for our operations for the three and six months ended September 30, 2007 and 2006.


	Three Months Ended September 30,						Six Months Ended September 30,
	2007			2006			2007			2006
Contract drilling revenues:
Daywork contracts	$	98,925,195		$	103,403,793		$	197,352,296		$	193,464,659
Turnkey contracts		2,195,312			—			3,048,921			—
Footage contracts		5,395,430			3,513,029			8,894,170			6,945,470

Total contract drilling revenues	$	106,515,937		$	106,916,822		$	209,295,387		$	200,410,129

Contract drilling costs:
Daywork contracts	$	61,128,977		$	53,273,500		$	121,212,568		$	100,753,205
Turnkey contracts		1,426,858			—			2,168,122			—
Footage contracts		4,089,066			2,541,949			7,056,506			4,605,030

Total contract drilling costs	$	66,644,901		$	55,815,449		$	130,437,196		$	105,358,235

Drilling margin:
Daywork contracts	$	37,796,218		$	50,130,293		$	76,139,728		$	92,711,454
Turnkey contracts		768,454			—			880,799			—
Footage contracts		1,306,364			971,080			1,837,664			2,340,440

Total drilling margin	$	39,871,036		$	51,101,373		$	78,858,191		$	95,051,894

Revenue days by type of contract:
Daywork contracts		5,196			5,077			10,326			9,772
Turnkey contracts		42			—			69			—
Footage contracts		321			197			551			383

Total revenue days		5,559			5,274			10,946			10,155

Contract drilling revenue per revenue day	$	19,161		$	20,272		$	19,121		$	19,735
Contract drilling costs per revenue day	$	11,989		$	10,583		$	11,916		$	10,375
Drilling margin per revenue day	$	7,172		$	9,689		$	7,204		$	9,360
Rig utilization rates		90	%		97	%		90	%		96	%
Average number of rigs during the period		67.3			59.7			66.5			58.2

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 September 30,						Six Months Ended September 30,
	2007			2006			2007			2006
Reconciliation of drilling margin to net earnings:
Drilling margin	$	39,871,036		$	51,101,373		$	78,858,191		$	95,051,894
Depreciation and amortization		(16,093,189	)		(12,580,901	)		(32,190,898	)		(24,150,907	)
General and administrative expense		(3,844,393	)		(2,846,813	)		(7,164,526	)		(5,772,313	)
Bad debt expense		(2,626,768	)		—			(2,626,768	)		—
Other income		728,292			1,025,284			1,608,776			2,083,186
Income tax expense		(6,255,022	)		(13,212,550	)		(13,616,546	)		(24,238,970	)

Net earnings	$	11,779,956		$	23,486,393		$	24,868,229		$	42,972,890

Our contract drilling revenues decreased by approximately $401,000, or .4%, for the quarter ended September 30, 2007, as compared to the corresponding quarter in 2006, due to a $1,111 per day decrease in average drilling revenues rates partially offset by a 5% increase in revenue days that resulted from an increase in the number of rigs in our fleet. Our contract drilling revenues increased by approximately $8,885,000, or 4%, for the six month period ended September 30, 2007, as compared to the corresponding period in 2006, due to an 8% increase in revenue days that resulted from an increase in the number of rigs in our fleet partially offset by a $614 per day decrease in average drilling revenues rates.

Our contract drilling costs grew by approximately $10,829,000, or 19%, for the quarter ended September 30, 2007, as compared to the corresponding period in 2006, due to the increase in the number of revenue days and a $1,406 increase in the average drilling costs per revenue day, which was primarily due to higher employee costs, higher repairs and maintenance expenses and more turnkey and footage costs. 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 $25,079,000, or 24%, during the six months ended September 30, 2007, as compared to the corresponding quarter in 2006, due to the increase in the number of revenue days and a $1,541 increase in the average drilling costs per revenue day, which was primarily due to higher wages, higher repairs and maintenance expenses and more turnkey and footage costs.

Our depreciation and amortization expenses for the quarter ended September 30, 2007 increased by approximately $3,512,000, or 28%, compared to the corresponding quarter in 2006. Our depreciation and amortization expenses for the six months ended September 30, 2007 increased by approximately $8,040,000, or 33%, as compared to the corresponding period in 2006. The increases in 2007 over 2006 resulted primarily from an increase in the average size of our rig fleet, which increase consisted of newly constructed rigs. The higher costs of our new rigs increased our average depreciation costs per revenue day by $510 to $2,895 during the quarter ended September 30, 2007, as compared to $2,385 during the quarter ended September 30, 2006, and by $563 to $2,941 during the six months ended September 30, 2007, as compared to $2,378 during the six months ended September 30, 2006.

Our general and administrative expense for the quarter ended September 30, 2007 increased by approximately $998,000, or 35%, compared to the corresponding quarter in 2006, primarily due to approximately $607,000 in additional compensation-related expenses for salaries, bonuses and stock options incurred for existing and new employees in our corporate office. In addition, professional and consulting expenses increased approximately $275,000 for the quarter ended September 30, 2007.

Our general and administrative expense for the six months ended September 30, 2007 increased by approximately $1,392,000, or 24%, compared to the corresponding period in 2006, primarily due to approximately $661,000 in additional compensation-related expenses for salaries, bonuses and stock options incurred for existing and new employees in our corporate office. In addition, professional and consulting expenses increased approximately $508,000 for the six month ended September 30, 2007.

Our allowance for bad debt expense increased by approximately $2,627,000 for both the quarter and six month periods ended September 30, 2007, compared to the corresponding periods in 2006, due to a decrease in our estimated recovery from a customer in bankruptcy.

Our other income for the quarter ended September 30, 2007 decreased by approximately $297,000, or 29%, compared to the corresponding quarter in 2006. Our other income for the six months ended September 30, 2007 decreased by approximately $474,000, or 23%, compared to the corresponding period in 2006. The decrease was primarily due to decreased interest income that resulted from decreased cash and cash equivalents from approximately $81,700,000 at September 30, 2006 to approximately $66,303,000 at September 30, 2007.

Our effective income tax rate of 35.4% for the six months ended September 30, 2007 and 36.1% for the six month ended September 30, 2006 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. For the quarter ended September 30, 2007, permanent differences include a special income tax benefit permitted by the Colombian government that will allow us to recover 140% of the cost of certain imported assets. We recognized a tax benefit for this Colombian tax deduction to the extent of taxable income that we expect to earn over the term of the two existing drilling contracts in Colombia with the excess tax benefit offset by a valuation allowance. The terms of the two existing drilling contracts expire in the fourth quarter of fiscal year 2008 and first quarter of fiscal year

2009. We estimated our taxable income over the terms of these existing contracts and recognized a pro rata portion of the tax benefit of approximately $24,000 for the quarter ended September 30, 2007. We recorded a valuation allowance of approximately $3,834,000 to offset the excess tax benefit. During the quarter ended September 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.

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. We currently do not anticipate additional wage rate increases in fiscal year 2008.

We are experiencing increases in costs for rig repairs and maintenance and costs of rig upgrades and new rig construction, due to the increased industry-wide demand for equipment, supplies and service. We estimate these costs increased by 10% to 15% in fiscal year 2007. We have experienced similar cost increases in fiscal year 2008 as rig counts remain at historically high levels.

Off Balance Sheet Arrangements

We do not currently have any off balance sheet arrangements.

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. We adopted the provisions of FIN 48 effective April 1, 2007. The adoption of FIN 48 had no material impact on our financial position or results of operations and financial condition.

ITEM 3.

QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Interest Rate Risk

Our exposure to market risk from changes in interest rates primarily relates to our cash equivalents, 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 also subject to market risk exposure related to changes in interest rates on floating rate debt we may incur under our credit facility. However, at September 30, 2007, we had no outstanding borrowings under our credit facility.

Foreign Currency Risk

We recently began operations in Colombia and are involved in transactions denominated in currencies other than the U.S. dollar, which exposes us to foreign exchange rate risk. A hypothetical 10% increase or decrease in the value of the Colombian peso relative to the U.S. dollar as of September 30, 2007 would result in a corresponding increase or decrease of approximately $54,000 for the six month periods ending September 30, 2007.

We do not currently use derivative financial instruments to hedge against interest rate risk or foreign currency risk.

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 September 30, 2007 to provide reasonable assurance that information required to be disclosed in our reports filed or submitted under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the Securities and Exchange Commission’s rules and forms and that such information is accumulated and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosure.

There has been no change in our internal control over financial reporting that occurred during the three months ended September 30, 2007 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

PART II. OTHER INFORMATION

ITEM 1.

LEGAL PROCEEDINGS

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

ITEM 1A.

RISK FACTORS

While we attempt to identify, manage and mitigate risks and uncertainties associated with our business to the extent practical under the circumstances, some level of risk and uncertainty will always be present. Part I, Item 1A of our Annual Report on Form 10-K for the fiscal year ended March 31, 2007 describes some of the risks and uncertainties associated with our business that have the potential to materially affect our business, financial condition or results of operations. The risk factors presented below update, and should be considered in addition to, the risk factors previously disclosed by us in such Annual Report on Form 10-K. Additional risks and uncertainties not presently known to us or that we currently believe are immaterial also may negatively impact our business, financial condition or operating results.

As we expand into international markets, our international operations will be subject to political, economic and other uncertainties not encountered in our domestic operations.

As we continue to implement our strategy of expanding into areas outside the United States, our international operations will be subject to political, economic and other uncertainties not generally encountered in our U.S. operations. These will include, among potential others:

•

risks of war, terrorism and civil unrest;

•

expropriation, confiscation or nationalization of our assets;

•

renegotiation or nullification of contracts;

•

foreign taxation;

•

the inability to repatriate earnings or capital, due to laws limiting the right and ability of foreign subsidiaries to pay dividends and remit earnings to affiliated companies;

•

changing political conditions and changing laws and policies affecting trade and investment;

•

regional economic downturns;

•

the overlap of different tax structures; and

•

the risks associated with the assertion of foreign sovereignty over areas in which our operations are conducted.

Our international operations may also face the additional risks of fluctuating currency values, hard currency shortages and controls of foreign currency exchange. Additionally, in some jurisdictions, we may be subject to foreign governmental regulations favoring or requiring the awarding of contracts to local contractors or requiring foreign contractors to employ citizens of, or purchase supplies from, a particular jurisdiction. These regulations could adversely affect our ability to compete.

ITEM 4.

SUBMISSIONS OF MATTERS TO A VOTE OF SECURITY HOLDERS

The following matters were voted upon at our 2007 Annual Meeting of Shareholders held on August 3, 2007, and received the votes set forth below:

A proposal to elect C. Robert Bunch as our single Class III director was approved, with 38,599,489 votes FOR and 5,532,164 votes WITHHELD for C. Robert Bunch. Wm. Stacy Locke, C. John Thompson, Michael F. Harness, and Dean A. Burkhardt continued as directors pursuant to their prior election.

A proposal to approve the Pioneer Drilling Company 2007 Incentive Plan (the “2007 Plan”) was approved, with 27,178,127 votes FOR, 5,788,710 votes AGAINST, 104,169 ABSTENTIONS, and 11,060.647 BROKER NON-VOTES for the 2007 Plan.

A proposal to ratify the appointment of KPMG LLP as our independent auditors for our fiscal year ending March 31, 2008 was approved, with 43,441,224 votes FOR, 609,812 votes AGAINST, 80,617 ABSTENTIONS for KPMG LLP. There were no broker non-votes on this matter.

ITEM 5.

OTHER INFORMATION

On May 14, 2007, the Compensation Committee (the “Compensation Committee”) of the Board of Directors of Pioneer Drilling Company (the “Company”) approved increases, effective as of April 1, 2007, to the annual base salaries of certain of the Company’s executive officers and other key employees (collectively, the “Named Officers”).

On May 14, 2007, the Compensation Committee also approved grants of long-term incentive awards in the form of stock options to the Named Officers for the Company’s fiscal year ending March 31, 2008 (“FY 2008”). These option grants were made pursuant to the Company’s 2003 Stock Plan, have an exercise price equal to the fair market value of the Company’s common stock on May 14, 2007 (the date of grant), generally vest in three equal annual installments beginning on the first anniversary of the grant date, and expire no later than the tenth anniversary of the grant date.

On June 11, 2007, the Compensation Committee approved threshold, target and above expectation annual incentive compensation award opportunities for the Named Officers for FY 2008, pursuant to the Company’s 2007 Plan. The Award Opportunities are expressed as a percentage of the Named Officer’s annual base salary.

The annual base salaries, as adjusted, stock option grants and target award opportunities for the Named Officers are as follows:


Name	Position	Adjusted Base Salary		Stock Options	Target Award Opportunity⁽¹⁾
Wm. Stacy Locke	Director, President and Chief Executive Officer	$	450,000	200,000	80	%
William D. Hibbetts⁽²⁾	Senior Vice President, Chief Financial Officer and Secretary	$	210,000	20,000	40	%
Franklin C. West	Executive Vice President and Chief Operating Officer	$	370,000	—	50	%
Donald G. Lacombe	Senior Vice President of Marketing	$	195,000	50,000	40	%
J. Blaine David ⁽³⁾	Vice President of Operations	$	195,000	40,000	35	%
Willie E. Walker ⁽³⁾	Vice President of Operations	$	195,000	40,000	35	%

(1)

For each of the Named Officers, the threshold award opportunity is equal to approximately 30% of the target award opportunity and the above expectation award opportunity is equal to approximately 200% of the target award opportunity, with the exception of Mr. Locke whose above expectation award opportunity is 175% of his target award opportunity.

(2)

On July 17, 2007, Ms. Joyce M. Schuldt joined the Company as Executive Vice President, Chief Financial Officer and Secretary of the Company. Mr. Hibbetts continues to serve in a senior management position in the Company’s financial organization. Details of Ms. Schuldt’s base salary, target incentive award opportunity and stock option grants are disclosed in the Company’s Current Report on Form 8-K filed with the Securities and Exchange Commission on July 18, 2007.

(3)	Mr. David and Mr. Walker are considered key employees, but not executive officers of the Company.

The payment of annual incentive compensation awards for FY 2008 will be based on the Company’s achievement of annual performance measures and each Named Officer’s achievement of individual performance objectives. Company achievement of annual performance measures comprises 70% of the annual incentive compensation award and the Named Officer’s achievement of individual performance objectives accounts for the remaining 30% of that Named Officer’s annual incentive compensation award. For the Named Officers, the Company’s FY 2008 annual performance measures and corresponding percentage of the annual incentive compensation award attributable to such measures are indicated in the table below.


Name	EPS⁽¹⁾		EBITDA⁽²⁾		EBITDA Return on Capital Employed⁽³⁾		Safety (Recordable Incident Rate)⁽⁴⁾		Individual Performance Objective(s)
Wm. Stacy Locke	20	%	15	%	15	%	20	%	30	%
William D. Hibbetts	20	%	15	%	15	%	20	%	30	%
Franklin C. West	20	%	15	%	15	%	20	%	30	%
Donald G. Lacombe	20	%	15	%	15	%	20	%	30	%
J. Blaine David	20	%	15	%	15	%	20	%	30	%
Willie E. Walker	20	%	15	%	15	%	20	%	30	%

(1)	Earnings per share.

(2)	Earnings before interest, taxes, depreciation and amortization.

(3)	Calculated by dividing EBITDA by the average shareholder’s equity plus average long-term debt (less current installments) for the FY 2008.

(4)	Calculated based on the number of recordable incidents per 200,000 hours worked for the applicable business unit (i.e. division, corporate); in the event of a fatality accident, the safety component of the incentive award is eliminated for the applicable division and corporate participants.

For each performance measure, a threshold, target and above expectation level of performance was established. Target performance is generally set at the budgeted level for the fiscal year, threshold performance is generally set at 75% of the budgeted level and above expectation performance is generally set at 130% of the budgeted level.

On October 30, 2007, the Company’s Board of Directors appointed Ms. Joyce M. Schuldt as the Principal Accounting Officer of the Company effective November 2, 2007. Ms. Schuldt joined the Company in July 2007 as Executive Vice President, Chief Financial Officer and Secretary. Ms. Schuldt’s biographical information and details of her base salary, target incentive award opportunity and stock option grants, as well as Ms. Schuldt’s letter of employment, dated July 17, 2007 (the “Employment Letter”), are disclosed in the Company’s Current Report on Form 8-K (the “Form 8-K”) filed with the Securities and Exchange Commission on July 18, 2007 (File No. 001-08182). The disclosures in the Form 8-K, including the Employment Letter, are incorporated herein by reference.

Effective as of Ms. Schuldt’s appointment, Kurt Forkheim will no longer serve as the Company’s Principal Accounting Officer, but he will serve as Vice President and Director of Technical Accounting. Mr. Forkheim’s reassignment is not related to any disagreement he had with senior management or with the Company’s accounting or operating policies.

We have included the above information in this Quarterly Report on Form 10-Q in lieu of filing a report on Form 8-K under Items 5.02(e), (b) and (c).

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)).

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

4.2 *		- Credit Agreement between Pioneer Drilling Services, Ltd. and The Frost National Bank, as Administrative Agent, Agent, Lead Arranger and Lender dated October 29, 2004 (Form 8-K filed November 2, 2004 (File No. 001-08182, Exhibit 4.1))

4.6 *		- Fifth Amendment, dated October 30, 2006, to Credit Agreement between Pioneer Drilling Services, Ltd. and The Frost National Bank, as Administrative Agent, Lead Arranger and Lender dated October 29, 2004 (Form 8-K filed October 31, 2006 (File No. 001-08182, Exhibit 4.1))

10.1 +		- Pioneer Drilling Company Form of Indemnification Agreement (Form 8-K filed August 8, 2007(File No. 001-08182, Exhibit 10.1))

10.2 +		Pioneer Drilling Services, Ltd. Key Executive Severance Plan (Form 8-K filed August 8, 2007(File No. 001-08182, Exhibit 10.2))

10.3 +		- Pioneer Drilling Company Employee Relocation Policy for Executive Officers – Package “A” (Form 8-K filed August 8, 2007(File No. 001-08182, Exhibit 10.3))

10.4 +		Joyce M. Schuldt Employment Letter, dated July 17, 2007 (Form 8-K filed July 18, 2007 (File No. 001-08182, Exhibit 10.1))

10.5 +		- William D. Hibbetts Reassignment Letter, dated July 17, 2007 (Form 8-K filed July 18, 2007 (File No. 001-08182, Exhibit 10.2))

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 Joyce M. Schuldt, Executive 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 (18 U.S.C. 1350).

32.2 #		- Certification by Joyce M. Schuldt, Executive Vice President and Chief Financial Officer, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (18 U.S.C. 1350).

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

**	Filed herewith

+	Management contract or compensatory plan or arrangement.

#	Furnished herewith

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

PIONEER DRILLING COMPANY

/s/ Joyce M. Schuldt

Joyce M. Schuldt

Executive Vice President and Chief Financial Officer

(Principal Financial Officer and Duly Authorized Representative)

Dated: November 2, 2007

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)).

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

4.2 *		- Credit Agreement between Pioneer Drilling Services, Ltd. and The Frost National Bank, as Administrative Agent, Agent, Lead Arranger and Lender dated October 29, 2004 (Form 8-K filed November 2, 2004 (File No. 001-08182, Exhibit 4.1))

4.6 *		- Fifth Amendment, dated October 30, 2006, to Credit Agreement between Pioneer Drilling Services, Ltd. and The Frost National Bank, as Administrative Agent, Lead Arranger and Lender dated October 29, 2004 (Form 8-K filed October 31, 2006 (File No. 001-08182, Exhibit 4.1))

10.1 +		- Pioneer Drilling Company Form of Indemnification Agreement (Form 8-K filed August 8, 2007(File No. 001-08182, Exhibit 10.1))

10.2 +		- Pioneer Drilling Services, Ltd. Key Executive Severance Plan (Form 8-K filed August 8, 2007(File No. 001-08182, Exhibit 10.2))

10.3 +		- Pioneer Drilling Company Employee Relocation Policy for Executive Officers – Package “A” (Form 8-K filed August 8, 2007(File No. 001-08182, Exhibit 10.3))

10.4 +		Joyce M. Schuldt Employment Letter, dated July 17, 2007 (Form 8-K filed July 18, 2007 (File No. 001-08182, Exhibit 10.1))

10.5 +		- William D. Hibbetts Reassignment Letter, dated July 17, 2007 (Form 8-K filed July 18, 2007 (File No. 001-08182, Exhibit 10.2))

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 Joyce M. Schuldt, Executive 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 (18 U.S.C. 1350).

32.2 #		- Certification by Joyce M. Schuldt, Executive Vice President and Chief Financial Officer, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (18 U.S.C. 1350).

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

**	Filed herewith

+	Management contract or compensatory plan or arrangement.

#	Furnished herewith