FORM 10Q (QE 12-31-2005)

10-Q 1 d10q.htm FORM 10Q (QE 12-31-2005) FORM 10Q (QE 12-31-2005)

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

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

For the quarterly period ended December 31, 2005

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

For the transition period from to

Commission File Number 1-8182

PIONEER DRILLING COMPANY

(Exact name of registrant as specified in its charter)


TEXAS		74-2088619
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification Number)

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

210-828-7689

(Registrant’s telephone number, including area code)

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.

Yes þ 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 þ 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 þ

As of February 1, 2006, there were 46,566,978 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


	December 31, 2005		March 31, 2005
	(unaudited)
ASSETS
Current assets:
Cash and cash equivalents	$	32,579,272	$	69,673,279
Marketable securities		—		1,000,000
Receivables:
Trade, net		34,898,698		26,108,291
Contract drilling in progress		9,477,796		5,364,529
Current deferred income taxes		985,110		569,548
Prepaid expenses		2,529,181		1,876,843

Total current assets		80,470,057		104,592,490

Property and equipment, at cost		307,928,034		225,447,939
Less accumulated depreciation and amortization		73,460,616		54,881,488

Net property and equipment		234,467,418		170,566,451
Intangible and other assets		364,847		850,381

Total assets	$	315,302,322	$	276,009,322

LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities:
Notes payable	$	—	$	681,975
Current installments of long-term debt and capital lease obligations		46,016		4,733,026
Accounts payable		17,516,339		15,621,647
Income tax payable		5,022,391		195,949
Prepaid drilling contracts		—		172,750
Accrued expenses:
Payroll and payroll taxes		2,881,617		2,706,623
Other		6,475,489		4,153,851

Total current liabilities		31,941,852		28,265,821
Long-term debt and capital lease obligations, less current installments		989		13,445,017
Non-current liabilities		351,096		400,000
Deferred income taxes		22,352,943		12,283,070

Total liabilities		54,646,880		54,393,908

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; 46,551,978 shares and 45,893,311 shares issued and outstanding at December 31, 2005 and March 31, 2005, respectively		4,655,197		4,589,331
Additional paid-in capital		226,608,210		220,232,520
Retained earnings (accumulated deficit)		29,392,035		(3,206,437	)

Total shareholders’ equity		260,655,442		221,615,414

Total liabilities and shareholders’ equity	$	315,302,322	$	276,009,322

See accompanying notes to condensed consolidated financial statements.

PIONEER DRILLING COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(Unaudited)


	Three Months Ended December 31,						Nine Months Ended December 31,
	2005			2004			2005			2004
Contract drilling revenues	$	74,458,788		$	46,387,624		$	201,308,054		$	129,889,335

Costs and expenses:
Contract drilling		43,028,535			32,356,744			122,466,020			100,802,088
Depreciation and amortization		8,598,306			5,769,959			23,868,669			16,124,317
General and administrative		1,544,808			1,215,189			4,612,454			2,910,879
Bad debt expense		25,110			342,000			25,110			342,000

Total operating costs and expenses		53,196,759			39,683,892			150,972,253			120,179,284

Income from operations		21,262,029			6,703,732			50,335,801			9,710,051

Other income (expense):
Interest expense		(688	)		(158,871	)		(204,296	)		(1,275,111	)
Loss from early extinguishment of debt		—			—			—			(100,833	)
Interest income		398,349			54,988			1,348,872			118,757
Other		8,364			7,192			39,672			22,311

Total other income (expense)		406,025			(96,691	)		1,184,248			(1,234,876	)

Income before income taxes		21,668,054			6,607,041			51,520,049			8,475,175
Income tax expense		(7,875,792	)		(2,428,430	)		(18,921,577	)		(3,157,003	)

Net earnings	$	13,792,262		$	4,178,611		$	32,598,472		$	5,318,172

Earnings per common share - Basic	$	0.30		$	0.11		$	0.70		$	0.16

Earnings per common share - Diluted	$	0.29		$	0.11		$	0.69		$	0.16

Weighted average number of shares outstanding - Basic		46,542,413			38,428,112			46,307,995			33,000,547

Weighted average number of shares outstanding - Diluted		47,325,807			39,534,723			47,010,265			37,167,050

See accompanying notes to condensed consolidated financial statements.

PIONEER DRILLING COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)


	Nine Months Ended December 31,
	2005			2004
Cash flows from operating activities:
Net earnings	$	32,598,472		$	5,318,172
Adjustments to reconcile net earnings to net cash provided by operating activities:
Depreciation and amortization		23,868,669			16,124,317
Allowance for doubtful accounts		25,110			342,000
Loss on disposal of properties and equipment		2,478,988			520,855
Deferred income taxes		9,654,311			3,117,435
Change in other assets		32,478			(444,793	)
Change in non-current liabilities		(100,000	)		—
Deferred operating lease liability		51,096			—
Changes in current assets and liabilities:
Receivables		(8,815,517	)		(9,364,131	)
Contract drilling in progress		(4,113,267	)		1,780,109
Prepaid expenses		(470,291	)		(724,637	)
Accounts payable		1,894,692			(2,064,086	)
Prepaid drilling contracts		(172,750	)		—
Federal income taxes		4,826,442			69,568
Accrued expenses		2,496,631			1,920,432

Net cash provided by operating activities		64,255,064			16,595,241

Cash flows from financing activities:
Payments of debt		(18,813,013	)		(21,452,186	)
Proceeds from notes payable		—			36,554,367
Proceeds from exercise of options		6,441,556			496,783
Proceeds from sale of common stock, net of offering costs of $1,998,180		—			29,741,820

Net cash provided by (used in) financing activities		(12,371,457	)		45,340,784

Cash flows from investing activities:
Business acquisitions		—			(35,200,000	)
Purchase of property and equipment		(91,643,709	)		(27,266,701	)
Proceeds from sale of property and equipment		1,666,095			877,862
Purchase of marketable securities		(130,325,000	)		16,525,000
Proceeds from sale of marketable securities		131,325,000			(17,075,000	)

Net cash used in investing activities		(88,977,614	)		(62,138,839	)

Net decrease in cash and cash equivalents		(37,094,007	)		(202,814	)
Beginning cash and cash equivalents		69,673,279			1,815,759

Ending cash and cash equivalents	$	32,579,272		$	1,612,945

Supplementary Disclosure:
Common stock issued for debenture conversion	$	—		$	28,000,000
Interest paid	$	401,138		$	1,653,973
Income taxes paid (refunded)	$	514,024		$	(30,000	)
Tax benefit from exercise of nonqualified options	$	3,926,798		$	153,283

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 select oil and natural gas exploration and production regions in the United States. We conduct our operations through our principal operating subsidiary, Pioneer Drilling Services, Ltd. The accompanying unaudited condensed consolidated financial statements include our accounts and the accounts of our wholly owned subsidiaries. All intercompany balances and transactions have been eliminated in consolidation.

The accompanying unaudited condensed consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America for interim financial information and with the instructions to Form 10-Q and Rule 10-01 of Regulation S-X. Accordingly, they do not include all of the information and footnotes required by generally accepted accounting principles for complete financial statements. In the opinion of our management, all adjustments (consisting of normal, recurring accruals) necessary for a fair presentation have been included. The condensed balance sheet as of March 31, 2005 has been derived from audited financial statements. We suggest that you read these condensed financial statements together with the financial statements and the related notes included in our annual report on Form 10-K for the fiscal year ended March 31, 2005.

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. As demand for drilling rigs has improved during the past year, we have entered into more longer-term drilling contracts. As of February 1, 2005, we had 29 contracts with terms of six months to two years in duration, of which 18 have a remaining term in excess of six months. We also have term contracts of one to two years for 10 rigs currently under construction.

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.

We believe our federal income tax rate for the year ending March 31, 2006 will increase to 35%, as compared to 34% for the year ended March 31, 2005. The effect of this expected increase in our federal income tax rate is reflected in our estimated annual income tax rate utilized for the three and nine months ended December 31, 2005.

Stock-based Compensation

We have adopted SFAS No. 123, Accounting for Stock-Based Compensation. SFAS No. 123 allows a company to adopt a fair-value-based method of accounting for a stock-based employee compensation plan or to continue to use the intrinsic-value-based method of accounting prescribed by Accounting Principles Board (“APB”) Opinion No. 25, Accounting for Stock Issued to Employees. We have elected to continue accounting for stock-based compensation under the intrinsic-value-based method. Under this method, we record no compensation expense for stock option grants when the exercise price of the options granted is equal to the fair market value of our common stock on the date of grant. If we had elected to recognize compensation cost based on the fair value of the options we granted at their respective grant dates as SFAS No. 123 prescribes, our net earnings and net earnings per share would have been reduced to the pro forma amounts the table below indicates:


	Three Months Ended December 31,						Nine Months Ended December 31,
	2005			2004			2005			2004
Net earnings - as reported	$	13,792,262		$	4,178,611		$	32,598,472		$	5,318,172
Deduct: Total stock-based employee compensation expense determined under fair-value-based method for all awards, net of related tax effect		(537,981	)		(217,710	)		(1,506,730	)		(795,755	)

Net earnings - pro forma	$	13,254,281		$	3,960,901		$	31,091,742		$	4,522,417

Net earnings per share - as reported - basic	$	0.30		$	0.11		$	0.70		$	0.16
Net earnings per share - as reported - diluted	$	0.29		$	0.11		$	0.69		$	0.16
Net earnings per share - pro forma - basic	$	0.28		$	0.10		$	0.67		$	0.14
Net earnings per share - pro forma - diluted	$	0.28		$	0.10		$	0.66		$	0.13
Weighted-average fair value of options granted during the period	$	—		$	6.44		$	6.47		$	5.94

We estimate the fair value of each option grant on the date of grant using a Black-Scholes options-pricing model. The model assumed, for the three and nine months ended December 31, 2005 and 2004:


	Three Months Ended December 31,				Nine Months Ended December 31,
	2005		2004		2005		2004
Expected volatility	48	%	85	%	53	%	86	%
Weighted-average risk-free interest rates	4.3	%	3.6	%	4.0	%	3.7	%
Expected life in years	4		5		4.1		5
Options granted	—		155,000		336,500		190,000

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 that the value an optionee actually realizes will be at or near the value we have estimated using the Black-Scholes model.

Related-Party Transactions

As of December 31, 2005, Chesapeake Energy Corporation (“Chesapeake”) owned 16.54% of our outstanding common stock. During the nine months ended December 31, 2005 and 2004, we recognized revenues of approximately $22,162,000 and $1,349,000, respectively, and recorded contract drilling costs, excluding depreciation, of approximately $14,514,000 and $837,000, respectively, on drilling contracts with Chesapeake. Our accounts receivable at December 31, 2005 include approximately $5,758,000 due from Chesapeake.

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

We purchased services from R&B Answering Service and Frontier Services, Inc. during 2005 and 2004. These companies are more than 5% owned by our Chief Operating Officer and an immediate family member of our Vice President and Operations Manager, respectively. The following summarizes the transactions with these companies in each period:


	Three Months Ended December 31,				Nine Months Ended December 31,				Amount Owed December 31,
	2005		2004		2005		2004		2005		2004
R&B Answering Service
Purchases	$	2,996	$	4,761	$	12,391	$	12,055	$	1,403	$	3,334
Payments	$	4,514	$	4,690	$	14,038	$	10,665
Frontier Services, Inc.
Purchases	$	1,521	$	10,704	$	5,953	$	93,709	$	—	$	—
Payments	$	1,521	$	35,975	$	9,302	$	93,709

Recently Issued Accounting Standards

In December 2004, the Financial Accounting Standards Board (the “FASB”) issued SFAS No. 123R (revised 2004), Share-Based Payment. SFAS No. 123R is a revision of FASB SFAS No. 123, Accounting for Stock-Based Compensation, and supersedes APB Opinion No. 25, Accounting for Stock Issued to Employees, and its related implementation guidance. SFAS No. 123R established standards for the accounting for transactions in which an entity exchanges its equity instruments for goods or services. It also addresses transactions in which an entity incurs liabilities in exchange for goods or services that are based on the fair value of the entity’s equity instruments or that may be settled by the issuance of those equity instruments. SFAS No. 123R focuses primarily on accounting for transactions in which an entity obtains employee services in share-based payment transactions. SFAS No. 123R requires a public entity to measure the cost of employee services received in exchange for an award of equity instruments based on the grant-date fair value of the award (with limited exceptions). That cost will be recognized over the period during which an employee is required to provide service in exchange for the award. The provisions of SFAS No. 123R are effective for public entities that do not file as small business issuers as of the beginning of the first annual reporting period that begins after June 15, 2005. We are currently evaluating the negative impact SFAS No. 123R will have on our financial position and results of operations in fiscal year 2007 and in subsequent periods. The negative impact will be created due to the fact that we previously issued employee stock options for which no expense has been recognized, as those options will not be fully vested as of the effective date of SFAS No. 123R. In addition, the cost of employee stock option awards issued in future periods will be recognized over the vesting period of the award.

In May 2005, the FASB issued SFAS No. 154, Accounting Changes and Error Corrections, which supersedes APB Opinion No. 20, Accounting Changes, and SFAS No. 3, Reporting Accounting Changes in Interim Financial Statements. SFAS No. 154 changes the requirements for the accounting for and reporting of changes in accounting principle. The statement requires the retroactive application to prior periods’ financial statements of changes in accounting principles, unless it is impracticable to determine either the period-specific effects or the cumulative effect of the change. SFAS No. 154 does not change the guidance for reporting the correction of an error in previously issued financial statements or the change in an accounting estimate. SFAS No.154 is effective for accounting changes and corrections of errors made in fiscal years beginning after December 15, 2005. We do not expect the adoption of SFAS No. 154 to have a material impact on our financial position and results of operations and financial condition.

Reclassifications

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

2. Long-term Debt and Notes Payable

Notes payable at March 31, 2005 consist of a $681,975 insurance premium note due on August 26, 2005, plus interest at the rate of 3.15% per year.

On October 29, 2004, we entered into a $47,000,000 credit facility with a group of lenders consisting of a $7,000,000 revolving line and letter of credit facility and a $40,000,000 acquisition facility for the acquisition of drilling rigs, drilling rig transportation equipment and associated equipment. Frost National Bank is the administrative agent and lead arranger under the credit facility, and the lenders include Frost National Bank, the Bank of Scotland and Zions First National Bank. Borrowings under the credit facility bear interest at a rate equal to Frost National Bank’s prime rate (7.25% at December 31, 2005) or, at our option, at LIBOR plus a percentage ranging from 1.75% to 2.5%, based on our operating leverage ratio. Borrowings are secured by most of our assets, including all our drilling rigs and associated equipment and receivables. We borrowed the entire $40,000,000 available under the acquisition facility, and we used approximately $3,050,000 of availability under the revolving line and letter of credit facility through the issuance of letters of credit in the ordinary course of business. On March 29, 2005, we repaid $20,000,000 of the borrowings under the acquisition facility. In August 2005, we repaid the then remaining outstanding balance of approximately $16,500,000 under the acquisition facility. In December 2005, the acquisition facility was amended to provide us the ability to draw $50,000,000 for future acquisitions or new rig construction. At December 31, 2005, we had no borrowings under the acquisition facility and the revolving line and letter of credit facility had availability of $3,950,000. Both the revolving line and letter of credit facility and acquisition facility are scheduled to mature in October 2006.

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 are limited to 75% of our eligible accounts receivable, not to exceed $7,000,000. Therefore, if 75% of our eligible accounts receivable was less than $7,000,000, our ability to draw under this line would be reduced. At December 31, 2005, we had no outstanding advances under this line of credit, we had outstanding letters of credit of approximately $3,050,000 and 75% of our eligible accounts receivable was approximately $24,393,000. The letters of credit have been issued to three workers’ compensation insurance companies to secure possible future claims under the deductibles on these policies. It is our practice to pay any amounts due under these deductibles as they are incurred. Therefore, we do not anticipate that the lenders will be required to fund any draws under these letters of credit.

At December 31, 2005, we were in compliance with all covenants applicable to our outstanding debt. Those covenants include, among others, requirements that we maintain a debt to total capitalization ratio of not greater than 0.3 to 1, a fixed charged coverage ratio of not less than 1.5 to 1 and an operating leverage ratio of not more than 3 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

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

On February 28, 2005, we entered into an agreement to lease office space in San Antonio, Texas for our corporate office facilities. Monthly lease payments escalate from $10,880 per month to $18,805 per month over a lease term of 102 months, which began on July 8, 2005. We recognize rent expense on a straight-line basis over the lease term, at $15,769 per month, with the difference between our rent expense and lease payment recognized as a deferred lease liability which has been classified with other non-current liabilities on our balance sheet. The deferred lease liability was $51,096 at December 31, 2005.

At December 31, 2005, we were in the process of constructing 11 drilling rigs and had incurred approximately $16,244,000 of the approximately $79,000,000 of construction costs. One of these rigs was placed in service in January 2006.

4. Equity Transactions

Directors and employees exercised stock options for the purchase of 658,667 shares of common stock during the nine months ended December 31, 2005, at prices ranging from $3.00 to $8.81 per share. Stock options for the purchase of 118,333 shares of common stock were exercised during the nine months ended December 31, 2004, at prices ranging from $2.25 to $6.44 per share.

5. Earnings Per Common Share

The following table presents a reconciliation of the numerators and denominators of the basic earnings per share and diluted earnings per share computations as required by SFAS No. 128:


	Three Months Ended December 31,				Nine Months Ended December 31,
	2005		2004		2005		2004
Basic
Net earnings	$	13,792,262	$	4,178,611	$	32,598,472	$	5,318,172

Weighted average shares		46,542,413		38,428,112		46,307,995		33,000,547

Earnings per share	$	0.30	$	0.11	$	0.70	$	0.16


	Three Months Ended December 31,				Nine Months Ended December 31,
	2005		2004		2005		2004
Diluted
Net earnings	$	13,792,262	$	4,178,611	$	32,598,472	$	5,318,172
Effect of dilutive securities:
Convertible debentures (1)		—		—		—		459,483

Net earnings and assumed conversion	$	13,792,262	$	4,178,611	$	32,598,472	$	5,777,655

Weighted average shares:
Outstanding		46,542,413		38,428,112		46,307,995		33,000,547
Options		783,394		1,106,611		702,270		1,024,550
Convertible debentures (1)		—		—		—		3,141,953

		47,325,807		39,534,723		47,010,265		37,167,050

Earnings per share	$	0.29	$	0.11	$	0.69	$	0.16

(1)	Convertible debentures that were converted into 6,496,519 shares on August 11, 2004 were not included in the computation of diluted earnings per share for the nine months ended December 31, 2004, because they were antidilutive.

ITEM 2.

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

Statements we make in the following discussion which express a belief, expectation or intention, as well as those that are not historical fact, are forward-looking statements that are subject to risks, uncertainties and assumptions. Our actual results, performance or achievements, or industry results, could differ materially from those we express in the following discussion as a result of a variety of factors, including general economic and business conditions and industry trends, the continued strength or weakness of the contract land drilling industry in the geographic areas in which we operate, decisions about onshore exploration and development projects to be made by oil and gas companies, the highly competitive nature of our business, our future financial performance, including availability, terms and deployment of capital, the continued availability of qualified personnel, and changes in, or our failure or inability to comply with, government regulations, including those relating to the environment. We have discussed many of these factors in more detail elsewhere in this report and in our annual report on Form 10-K for the year ended March 31, 2005. 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. We do not intend to update our description of important factors each time a potential important factor arises, except as required by applicable securities laws and regulations. We advise our shareholders that they should (1) be aware that important factors not referred to above could affect the accuracy of our forward-looking statements and (2) use caution and common sense when considering our forward-looking statements.

Company Overview

Pioneer Drilling Company provides contract land drilling services to independent and major oil and gas exploration and production companies. In addition to our drilling rigs, we provide the drilling crews and most of the ancillary equipment needed to operate our drilling rigs. We have focused our operations in selected oil and natural gas production regions in the United States. Our company was incorporated in 1979 as the successor to a business that had been operating since 1968. We conduct our operations through our principal operating subsidiary, Pioneer Drilling Services, Ltd. We are an oil and gas services company. We do not invest in oil and natural gas properties. The drilling activity of our customers is highly dependent on the current price of oil and natural gas.

Our business strategy is to own and operate a high-quality fleet of land drilling rigs in active drilling markets, and 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.

Since September 1999, we have significantly expanded our fleet of drilling rigs through acquisitions, construction of new rigs and the refurbishment of older rigs. As of February 1, 2006, our rig fleet consisted of 55 land drilling rigs that drill in depth ranges between 6,000 and 18,000 feet. Fifteen of our rigs are operating in South Texas, 18 in East Texas, five in North Texas, five in western Oklahoma and 12 in the Rocky Mountains. We actively market all of these rigs. We anticipate continued growth of our rig fleet in fiscal year 2006 and 2007. As of February 1, 2006, we were constructing one 1000-horsepower mechanical rig and nine 1000-horsepower diesel electric rigs from new and used components. We expect these rigs to be completed and become available for operation during the period from March 1, 2006 to December 31, 2006.

We earn our revenues by drilling oil and gas wells for our customers. 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. Generally, 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 has improved during the past year, we have entered into more longer-term drilling contracts. As of February 1, 2006, we had 29 contracts with terms of six months to two years in duration, of which 18 have a remaining term in excess of six months. We also have term contracts of one to two years for 10 rigs currently under construction.

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 for a rig are the number of calendar days during the period that we have owned the rig. Revenue days for each rig are days when the rig is earning revenues under a contract, which is usually a period from the date the rig begins moving to the drilling location until the rig is released from the contract.

For the three and nine months ended December 31, 2005 and 2004, our rig utilization and revenue days were as follows:


	Three Months Ended December 31,				Nine Months Ended December 31,
	2005		2004		2005		2004
Utilization Rates	96	%	98	%	95	%	96	%
Revenue Days	4,714		3,524		13,463		9,687

The primary reason for the increase in the number of revenue days in each of the 2005 periods over the corresponding periods in 2004 is the increase in size of our rig fleet from 49 rigs at December 31, 2004 (of which, 12 were acquired in the last month of the quarter) to 54 rigs at December 31, 2005. For the remainder of fiscal year 2006, we anticipate continued growth in revenue days as more rigs are constructed and put into operation. We expect utilization rates for the remainder of fiscal year 2006 to remain at or near current levels.

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

We devote substantial resources to maintaining and upgrading our rig fleet. In the short term, these actions result in fewer revenue days and slightly lower utilization; however, in the long term, we believe the upgrades will help the marketability of our rigs and improve their operating performance. We expended approximately $16,350,000 on rig upgrades during the nine months ended December 31, 2005. We are currently performing, between contracts or as necessary, safety and equipment upgrades to the eight rigs we acquired in March 2004 and the 12 rigs we acquired in November and December 2004.

Market Conditions in Our Industry

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

On January 20, 2006, the spot price for West Texas Intermediate crude oil was $68.35, the spot price for Henry Hub natural gas was $8.78 and the Baker Hughes land rig count was 1,376, a 22% increase from 1,130 on January 28, 2005.

The average weekly spot prices of West Texas Intermediate crude oil and Henry Hub natural gas and the average weekly domestic land rig count, per the Baker Hughes land rig count, for the three months ended December 31, 2005 and each of the previous five years ended December 31, were:


	Three Months Ended December 31, 2005		Years Ended December 31,
	Three Months Ended December 31, 2005		2005		2004		2003		2002		2001
Oil (West Texas Intermediate)	$	59.67	$	56.63	$	42.31	$	31.22	$	26.20	$	26.08
Natural Gas (Henry Hub)	$	11.87	$	8.83	$	5.90	$	5.43	$	3.33	$	3.90
U.S. Land Rig Count		1,375		1,266		1,095		906		700		981

During fiscal years 2005, 2004 and 2003, substantially all the wells we drilled for our customers were drilled in search of natural gas because of the depth capacity of our rigs and the natural gas-rich areas in which we operate. Although we diversified our operations somewhat in November 2004, with the acquisition of six drilling rigs employed in search of oil in the Williston Basin of the Rocky Mountains, our customers remain primarily focused on drilling for natural gas. Natural gas reserves are typically found in deeper geological formations and generally require premium, deeper capacity equipment to drill the wells.

Critical Accounting Policies and Estimates

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

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

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

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

Asset impairments – We assess the impairment of property and equipment whenever events or circumstances indicate that the carrying value may not be recoverable. Factors that we consider important and which could trigger an impairment review would be our customers’ financial condition and any significant negative industry or economic trends. More specifically, among other things, we consider our contract revenue rates, our rig utilizations rates, cash flows from our drilling rigs, current oil and gas prices, industry analysts’ outlook for the industry and their view of our customers’ access to debt or equity, discussions with major industry suppliers, discussions with officers of our primary lender regarding their experiences and expectations for oil and gas operators in our areas of operations and the trends in the price of used drilling equipment observed by our management. If a review of our drilling rigs indicates that our carrying value exceeds the estimated undiscounted future net cash flows, we are required under applicable accounting standards to write down the drilling equipment to its fair market value. A one percent write-down in the cost of our drilling equipment, at December 31, 2005, would have resulted in a corresponding decrease in our net earnings of approximately $1,870,000 for the nine months ended December 31, 2005.

Deferred taxes – We provide deferred taxes for the basis differences in our property and equipment between financial reporting and tax reporting purposes and other costs such as compensation, employee benefit and other accrued liabilities which are deducted in different periods for financial reporting and tax reporting purposes. For property and equipment, basis differences arise from differences in depreciation periods and methods and the value of assets acquired in a business acquisition where we acquire an entity rather than just its assets. For financial reporting purposes, we depreciate the various components of our drilling rigs over five to 15 years and refurbishments over three years, while federal income tax rules 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 critical accounting estimates. On these types of contracts, we are required to estimate the number of days needed for us to complete the contract and our total cost to complete the contract. Our actual costs could substantially exceed our estimated costs if we encounter problems such as lost circulation, stuck drill pipe or an underground blowout on contracts still in progress subsequent to the release of the financial statements.

We receive payment under turnkey and footage contracts when we deliver to our customer a well completed to the depth specified in the contract, unless the customer authorizes us to drill to a shallower depth. Since 1995, when current management joined our company, we have completed all our turnkey or footage contracts. Although our initial cost estimates for turnkey and footage contracts do not include cost estimates for risks such as stuck drill pipe or loss of circulation, we believe that our experienced management team, our knowledge of geologic formations in our areas of operations, the condition of our drilling equipment and our experienced crews enable us to make reasonably dependable cost estimates and complete contracts according to our drilling plan. While we do bear the risk of loss for cost overruns and other events that are not specifically provided for in our initial cost estimates, our pricing of turnkey and footage contracts takes such risks into consideration. When we encounter, during the course of our drilling operations, conditions unforeseen in the preparation of our original cost estimate, we increase our cost estimate to complete the contract. If we anticipate a loss on a contract in progress at the end of a reporting period due to a change in our cost estimate, we accrue the entire amount of the estimated loss, including all costs that are included in our revised estimated cost to complete that contract, in our consolidated statement of operations for that reporting period. During the nine months ended December 31, 2005, we experienced losses on 17 of the 111 turnkey and footage contracts completed, with losses of less than $25,000 each on 14 contracts, losses exceeding $25,000 but less than $100,000 on two contracts, and losses exceeding $100,000 on one contract. During the nine months ended December 31, 2004, we experienced losses on 14 of the 128 turnkey and footage contracts completed, with losses exceeding $25,000 on nine contracts and losses exceeding $100,000 on four contracts. We are more likely to encounter losses on turnkey and footage contracts in periods in which revenue rates are lower for all types of contracts. During periods of reduced demand for drilling rigs, our overall profitability on turnkey and footage contracts has historically exceeded our profitability on daywork contracts.

Revenues and costs during a reporting period could be affected for contracts in progress at the end of a reporting period which have not been completed before our financial statements for that period are released. We had no turnkey contracts and three footage contracts in progress at December 31, 2005, each of which we completed prior to the release of this report. Our contract drilling in progress totaled approximately $9,478,000 at December 31, 2005. Of that amount accrued, turnkey and footage contract revenues were approximately $663,000. The remaining balance of approximately $8,815,000 related to the revenue recognized but not yet billed on daywork contracts in progress at December 31, 2005. At March 31, 2005, drilling in progress totaled $5,365,000, of which $2,344,000 related to turnkey and footage contracts and $3,021,000 related to daywork contracts.

We estimate an allowance for doubtful accounts based on the creditworthiness of our customers as well as general economic conditions. We evaluate the creditworthiness of our customers based on information obtained from major industry suppliers, current prices of oil and gas and any past experience we have with the customer. Consequently, an adverse change in those factors could affect our estimate of our allowance for doubtful accounts. In some instances, we require new customers to establish escrow accounts or make prepayments. We typically invoice our customers at 15-day intervals during the performance of daywork contracts and upon completion of the daywork contract. Turnkey and footage contracts are invoiced upon completion of the contract. Our typical contract provides for payment of invoices in 10 to 30 days. We generally do not extend payment terms beyond 30 days and have not extended payment terms beyond 60 days for any of our contracts in the last three fiscal years. We had an allowance for doubtful accounts of $377,000 and $352,000 at December 31, 2005 and March 31, 2005, respectively.

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

Our other accrued expenses as of December 31, 2005 include accruals of approximately $738,000 and $1,502,000 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) $100,000 per covered individual per year under the health insurance (increasing to $125,000 on March 1, 2006) and (2) $250,000 per occurrence under our workers’ compensation insurance, except in North Dakota, where the deductible is $100,000. 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 July 2000 to 55 rigs as of February 1, 2006. We have financed this growth with a combination of debt and equity financing. We have raised additional equity or used equity for growth eight times since January 2000. We plan to continue to grow our rig fleet. Over the next 12 months, we expect to finance the construction of 10 additional rigs from existing cash and cash flows from operations. However, we are also likely to finance growth with debt and the issuance of additional shares of our common stock.

Uses of Capital Resources

For the three and nine months ended December 31, 2005, the additions to our property and equipment consisted of the following:


	Three Months		Nine Months
Drilling rigs (1)	$	22,594,584	$	45,572,320
Other drilling equipment		16,710,264		41,717,839
Transportation equipment		805,567		2,934,733
Other		489,745		1,418,817

	$	40,600,160	$	91,643,709

(1)	Includes capitalized interest costs of $0 and $194,500 for the three months and nine months ended December 31, 2005, respectively.

As of December 31, 2005, we were constructing, from new and used components, one 1500-horsepower diesel electric rig, nine 1000-horsepower diesel electric rigs and one 1000-horsepower mechanical rig. We placed the 1500-horsepower rig into service in January 2006. We expect to place the 1000-horsepower mechanical rig into service in February 2006 and the nine 1000-horsepower diesel electric rigs into service during the period from March 2006 to December 2006. As of December 31, 2005, we had incurred approximately $16,244,000 of the approximately $79,000,000 of construction costs on these rigs.

For the remainder of fiscal year 2006, we anticipate routine rig capital expenditures (excluding new rig construction costs) to be approximately $5,300,000, rig upgrade expenditures to be approximately $2,000,000, transportation equipment capital expenditures of approximately $750,000 and other capital expenditures of approximately $250,000. These capital expenditures are expected to be funded primarily from operating cash flow in excess of cash flow necessary to meet routine contractual obligations.

Working Capital

Our working capital was $48,528,205 at December 31, 2005, compared to $76,326,669 at March 31, 2005. Our current ratio, which we calculate by dividing our current assets by our current liabilities, was 2.52 at December 31, 2005, compared to 3.70 at March 31, 2005.

Our operations have historically generated cash flows in excess of our requirements for debt service and normal capital expenditures. The significant improvement in operating cash flow for the nine months ended December 31, 2005 over December 31, 2004 is primarily due to the approximately $27,280,000 improvement in net earnings, plus the approximately $7,744,000 increase in depreciation and amortization expense. If necessary, we can defer rig upgrades to improve our cash position. However, during periods when a higher percentage of our contracts are turnkey or footage contracts, our short-term working capital needs could increase. We believe our cash generated by operations and our ability to borrow on the currently unused portion of our line of credit and letter of credit facility of approximately $3,950,000, net of reductions for approximately $3,050,000 of outstanding letters of credit as of December 31, 2005, should allow us to meet our routine financial obligations.

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


	December 31, 2005		March 31, 2005		Change
Cash and cash equivalents	$	32,579,272	$	69,673,279	$	(37,094,007	)
Marketable securities		—		1,000,000		(1,000,000	)
Trade receivables		34,898,698		26,108,291		8,790,407
Contract drilling in progress		9,477,796		5,364,529		4,113,267
Current deferred income taxes		985,110		569,548		415,562
Prepaid expenses		2,529,181		1,876,843		652,338

Current assets		80,470,057		104,592,490		(24,122,433	)

Current debt		46,016		5,415,001		(5,368,985	)
Accounts payable		17,516,339		15,621,647		1,894,692
Accrued payroll and payroll taxes		2,881,617		2,706,623		174,994
Income tax payable		5,022,391		195,949		4,826,442
Prepaid drilling contracts		—		172,750		(172,750	)
Other accrued expenses		6,475,489		4,153,851		2,321,638

Current liabilities		31,941,852		28,265,821		3,676,031

Working capital	$	48,528,205	$	76,326,669	$	(27,798,464	)

The increase in our receivables and contract drilling in progress at December 31, 2005 from March 31, 2005 was due to our operating four additional rigs and the improvement of approximately $2,600 per day in average revenue rates.

The increase in current deferred income taxes was due to the classification of benefit from our alternative minimum tax credit carryforwards as current deferred income taxes at December 31, 2005. At March 31, 2004, the benefit from our alternative minimum tax credit carryforwards were classified as long-term deferred income taxes.

Substantially all our prepaid expenses at December 31, 2005 consisted of prepaid insurance. We generally renew and pay our insurance premiums in late October of each year. At March 31, 2005, we had amortized five months of the premiums, compared to two months of amortization as of December 31, 2005.

The increase in accounts payable was due to 11 drilling rigs under construction at December 31, 2005 as compared to two drilling rigs under construction at March 31, 2005. As of December 31, 2005, we have incurred approximately $16,244,000 of construction costs on these rigs. This increase was partially offset by a decrease in accounts payable due to fewer turnkey and footage contracts completed during December and in progress at December 31, 2005. We had no turnkey and three footage contracts in progress at December 31, 2005, compared to six turnkey and six footage contracts in progress at March 31, 2005.

The increase in accrued payroll and payroll taxes was due to the increase in the number of our employees due to the rig addition and the increase in rig employee wage rates, partially offset by the decrease in the number of payroll days included in the accrual from 10 days at March 31, 2005 compared to 5 days at December 31, 2005.

The increase in income tax payable at December 31, 2005 was due to the increase in net earnings, which was $32,598,472 for nine months ended December 31, 2005, as compared to $10,811,625 for the year ended March 31, 2005. This increase was partially offset by use of all of our net operating loss carryforwards during the nine months ended December 31, 2005. Income tax payable at March 31, 2005 only included an accrual for alternative minimum taxes.

The increase in accrued expenses at December 31, 2005, compared to March 31, 2005, was principally due to increases in the accrual for property taxes and self-insurance costs.

Long-term Debt

Our long-term debt at December 31, 2005, including current maturities, consisted of capital lease obligations of $47,005.

Contractual Obligations

We do not have any routine purchase obligations. However, as of December 31, 2005, we were in the process of constructing 11 drilling rigs, as described above. The following table excludes interest payments on long-term debt and capital lease obligations. The following table includes all our contractual obligations of the types specified below at December 31, 2005.


	Payments Due by Period
Contractual Obligations	Total		Less than 1 year		1-3 years		4-5 years		More than 5 years
Capital Lease Obligations		47,005	$	46,016	$	989	$	—	$	—
Operating Lease Obligations		1,775,288		256,230		435,943		422,405		660,710

Total	$	1,822,293	$	302,246	$	436,932	$	422,405	$	660,710

Debt Requirements

In August 2005, we repaid the then remaining outstanding balance of approximately $16,500,000 under our acquisition facility. See “Sources of Capital Resources.”

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 0.3 to 1, an operating leverage ratio of not more than 3 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, as we are now experiencing, 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.

We have a history of losses. We incurred net losses of approximately $1,800,000, $5,100,000 and $400,000 in the fiscal years ended March 31, 2004, 2003 and 2000, respectively. Our profitability in the future will depend on many factors, but largely on utilization rates and dayrates 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 nine months ended December 31, 2005 and 2004, the percentages of our drilling revenues by type of contract were as follows:


	Three Months Ended December 31,				Nine Months Ended December 31,
	2005		2004		2005		2004
Daywork contracts	91	%	58	%	86	%	46	%
Turnkey contracts	—		40	%	5	%	51	%
Footage contracts	9	%	2	%	9	%	3	%

We had no turnkey contracts in progress at December 31, 2005, compared to seven turnkey contracts in progress at December 31, 2004. We also had three footage contracts in progress at December 31, 2005 compared to four footage contracts in progress at December 31, 2004.

Statement of Operations Analysis

The following table provides information for our operations for the three and nine months ended December 31, 2005 and 2004.


	Three Months Ended December 31,						Nine Months Ended December 31,
	2005			2004			2005			2004
Contract drilling revenues:
Daywork contracts	$	67,895,686		$	26,823,504		$	173,006,043		$	59,277,124
Turnkey contracts		—			18,544,370			10,829,977			66,235,119
Footage contracts		6,563,102			1,019,750			17,472,034			4,377,092

Total contract drilling revenues	$	74,458,788		$	46,387,624		$	201,308,054		$	129,889,335

Contract drilling costs:
Daywork contracts	$	37,977,723		$	18,146,355		$	101,645,865		$	44,400,934
Turnkey contracts		—			13,582,177			7,462,869			53,152,744
Footage contracts		5,050,812			628,212			13,357,286			3,248,410

Total contract drilling costs	$	43,028,535		$	32,356,744		$	122,466,020		$	100,802,088

Drilling margin by contract:
Daywork contracts	$	29,917,963		$	8,677,149		$	71,360,178		$	14,876,190
Turnkey contracts		—			4,962,193			3,367,108			13,082,375
Footage contracts		1,512,290			391,538			4,114,748			1,128,682

Total drilling margin	$	31,430,253		$	14,030,880		$	78,842,034		$	29,087,247

Revenue days by type of contract:
Daywork contracts		4,269			2,421			11,635			5,680
Turnkey contracts		—			1,024			558			3,667
Footage contracts		445			79			1,270			340

Total revenue days		4,714			3,524			13,463			9,687

Contract drilling revenue per revenue day	$	15,795		$	13,163		$	14,953		$	13,409
Contract drilling cost per revenue day	$	9,128		$	9,182		$	9,096		$	10,406
Drilling margin per revenue day	$	6,667		$	3,982		$	5,856		$	3,003
Rig utilization rates		96	%		98	%		95	%		96	%
Average number of rigs during the period		53.3			39.7			51.3			37.1

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


	Three Months Ended December 31,						Nine Months Ended December 31,
	2005			2004			2005			2004
Reconciliation of drilling margin to net earnings:
Drilling margin	$	31,430,253		$	14,030,880		$	78,842,034		$	29,087,247
Depreciation and amortization		(8,598,306	)		(5,769,959	)		(23,868,669	)		(16,124,317	)
General and administrative expense		(1,544,808	)		(1,215,189	)		(4,612,454	)		(2,910,879	)
Bad debt expense		(25,110	)		(342,000	)		(25,110	)		(342,000	)
Other income (expense)		406,025			(96,691	)		1,184,248			(1,234,876	)
Income tax expense		(7,875,792	)		(2,428,430	)		(18,921,577	)		(3,157,003	)

Net earnings	$	13,792,262		$	4,178,611		$	32,598,472		$	5,318,172

Our contract drilling revenues grew by approximately $28,071,000, or 61%, in the quarter ended December 31, 2005 from the quarter ended December 31, 2004, due to an improvement of $2,600 per day in average rig revenue rates resulting from an increase in demand for drilling rigs and the 34% increase in revenue days primarily due to an increase in the number of rigs in our fleet, which was partially offset by a 2% decrease in rig utilization. Our contract drilling revenues grew by approximately $71,419,000, or 55%, in the nine months ended December 31, 2005 from the nine months ended December 31, 2004, due to an improvement in average rig revenue rates of $1,500 per day resulting from an increase in demand for drilling rigs, the 39% increase in revenue days due to an increase in the number of rigs in our fleet, which was partially offset by a 1% decrease in rig utilization.

Our contract drilling costs grew by approximately $10,672,000, or 33%, in the quarter ended December 31, 2005 from the corresponding quarter of 2004 due to the increase in the number of revenue days resulting from the increase in the number of rigs in our fleet, which was partially offset by the 2% decrease in rig utilization. The $54 decline in average contract drilling cost per revenue day was primarily due to the shift to more daywork revenue days as a percentage of total revenue days. Daywork days represented 91% of revenue days in the quarter ended December 31, 2005 compared to 69% in the quarter ended December 31, 2004. Under turnkey and footage contracts, we provide supplies and materials such as fuel, drill bits, casing and drilling fluids, which significantly adds to drilling costs for turnkey and footage 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 $21,664,000, or 21%, in the nine months ended December 31, 2005 from the corresponding period in 2004 due to the increase in the number of revenue days resulting from the increase in the number of rigs in our fleet, which was partially offset by a 1% decrease in rig utilization. The $1,310 decrease in average contract drilling cost per revenue day was primarily due to the 105% increase in daywork contract revenue days.

Our drilling margins increased by approximately $17,399,000, or 124%, in the quarter ended December 31, 2005 from the quarter ended December 31, 2004, due to an improvement of $2,700 per day in average drilling margin resulting from an increase in demand for drilling rigs and the 34% increase in revenue days primarily due to an increase in the number of rigs in our fleet, which was partially offset by a 2% decrease in rig utilization. Our drilling margins grew by approximately $49,755,000, or 171%, in the nine months ended December 31, 2005 from the nine months ended December 31, 2004, due to an improvement in average drilling margins of $2,900 per day resulting from an increase in demand for drilling rigs, and the 39% increase in revenue days was primarily due to an increase in the number of rigs in our fleet, partially offset by a 1% decrease in rig utilization.

Our depreciation and amortization expenses for the quarter ended December 31, 2005 increased by approximately $2,828,000, or 49%, compared to the corresponding quarter in 2004. Our depreciation and amortization expenses for the nine months ended December 31, 2005 increased by approximately $7,744,000, or 48%, compared to the corresponding period in 2004. These increases resulted primarily from the 34% and 38% increases in the average size of our rig fleet for the quarter ended and nine months ended December 31, 2005, respectively, when compared to the corresponding periods in 2004.

Our general and administrative expenses for the quarter ended December 31, 2005 increased by approximately $330,000, or 27%, compared to the corresponding quarter in 2004. The increase resulted primarily from increases in payroll costs, bonus accrual costs, office rent and insurance costs. During the quarter ended December 31, 2005, payroll costs increased by approximately $160,000, due to pay raises and an increase in the number of employees in our corporate office as compared to the quarter ended December 31, 2004. Bonus accrual costs increased by approximately $45,000, office rent increased by approximately $38,000 and insurance costs increased by approximately $22,000.

Our general and administrative expenses for the nine months ended December 31, 2005 increased by approximately $1,702,000, or 58%, compared to the corresponding period in 2004. The increase resulted primarily from increases in payroll costs, bonus accrual costs, professional fees, office rent and insurance costs. During the nine months ended December 31, 2005, payroll costs increased by approximately $514,000, due to pay raises and an increase in the number of employees in our corporate office as compared to the corresponding period in 2004. Bonus accrual costs increased by approximately $276,000, professional fees increased by approximately $511,000, office rent increased by approximately $84,000 and insurance costs increased by approximately $66,000.

Our effective income tax rates of approximately 37% for the nine months ended December 31, 2005 and 2004 differ from the federal statutory rates of 35% and 34% for the nine months ended December 31, 2005 and 2004, respectively, 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.

Accounting Matters

In December 2004, the Financial Accounting Standards Board (the “FASB”) issued SFAS No. 123R (revised 2004), Share-Based Payment. SFAS No. 123R is a revision of FASB SFAS No. 123, Accounting for Stock-Based Compensation, and supersedes APB Opinion No. 25, Accounting for Stock Issued to Employees, and its related implementation guidance. SFAS No. 123R established standards for the accounting for transactions in which an entity exchanges its equity instruments for goods or services. It also addresses transactions in which an entity incurs liabilities in exchange for goods or services that are based on the fair value of the entity’s equity instruments or that may be settled by the issuance of those equity instruments. SFAS No. 123R focuses primarily on accounting for transactions in which an entity obtains employee services in share-based payment transactions. SFAS No. 123R requires a public entity to measure the cost of employee services received in exchange for an award of equity instruments based on the grant-date fair value of the award (with limited exceptions). That cost will be recognized over the period during which an employee is required to provide service in exchange for the award. The provisions of SFAS No. 123R are effective for public entities that do not file as small business issuers as of the beginning of the first annual reporting period that begins after June 15, 2005. We are currently evaluating the negative impact SFAS No. 123R will have on our financial position and results of operations in fiscal year 2007 and in subsequent periods. The negative impact will be created due to the fact that we previously issued employee stock options for which no expense has been recognized, as those options will not be fully vested as of the effective date of SFAS No. 123R. In addition, the fair value of employee stock option awards issued in future periods will be recognized over the vesting period of the award.

In May 2005, the FASB issued SFAS No. 154, Accounting Changes and Error Corrections, which supersedes APB Opinion No. 20, Accounting Changes and SFAS No. 3, Reporting Accounting Changes in Interim Financial Statements. SFAS No. 154 changes the requirements for the accounting for and reporting of changes in accounting principles. The statement requires the retroactive application to prior periods’ financial statements of changes in accounting principles, unless it is impracticable to determine either the period-specific effects or the cumulative effect of the change. SFAS No. 154 does not change the guidance for reporting the correction of an error in previously issued financial statements or the change in an accounting estimate. SFAS No. 154 is effective for accounting changes and corrections of errors made in fiscal years beginning after December 15, 2005. We do not expect the adoption of SFAS No. 154 to have a material impact on our financial position and results of operations and financial condition.

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 and January 2006, we raised wage rates for our rig personnel in most of our areas of operation by an average of 6% at both dates. We have been able to pass these wage rate increases on to our customers based on contract terms. Availability of personnel in each of our market areas continues to be very constrained. Therefore, it is likely that we will experience additional wage rate increases. We anticipate that we will be able to pass any such increases for rig personnel on to our customers.

We are experiencing increases in costs for rig repairs and maintenance and costs of rig upgrades and new rig construction due to the increased rig count. We estimate these costs have increased between 10% and 15%. We anticipate that we will be able to recover these cost increases through improvements in our daywork revenue rates.

Off Balance Sheet Arrangements

We do not currently have any off balance sheet arrangements.

ITEM 3.

QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

We are subject to market risk exposure related to changes in interest rates on our outstanding floating rate debt. However, at December 31, 2005, we had no outstanding debt subject to variable interest rates.

ITEM 4.

CONTROLS AND PROCEDURES

In accordance with Exchange Act Rules 13a-15 and 15d-15, we carried out an evaluation, under the supervision and with the participation of management, including our Chief Executive Officer and Chief Financial Officer, of the effectiveness of our disclosure controls and procedures as of the end of the period covered by this report. Based on that evaluation, our Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures were effective as of December 31, 2005 to provide reasonable assurance that information required to be disclosed in our reports filed or submitted under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the Securities and Exchange Commission’s rules and forms.

There has been no change in our internal control over financial reporting that occurred during the three months ended December 31, 2005 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

PART II. OTHER INFORMATION

ITEM 4.

SUBMISSIONS OF MATTERS TO A VOTE OF SECURITY HOLDERS

There were no matters submitted to the shareholders of the Company for their approval during the quarter ended December 31, 2005.

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 *	-	Credit Agreement between Pioneer Drilling Services, Ltd. and Frost National Bank, as Administrative Agent, Agent, Lead Arranger and Lender dated October 29, 2004 (Form 8-K dated October 29, 2004 (File No. 1-8182, Exhibit 4.1)).

4.2 *	-	Second Amendment, dated May 11, 2005, to Credit Agreement between Pioneer Drilling Services, Ltd. and Frost National Bank, as Administrative Agent, Lead Arranger and Lender dated October 29, 2004 (Form 8-K filed May 13, 2005 (File No. 1-8182, Exhibit 4.1)).



4.3*	-	Third Amendment, dated October 25, 2005, to Credit Agreement between Pioneer Drilling Services, Ltd. and Frost National Bank, as Administrative Agent, Lead Arranger and Lender dated October 29, 2004 (Form 8-K filed October 28, 2005 (File No. 1-8182, Exhibit 4.1)).

4.4*	-	Fourth Amendment, dated December 15, 2005, to Credit Agreement between Pioneer Drilling Services, Ltd. and Frost National Bank, as Administrative Agent, Lead Arranger and Lender dated October 29, 2004 (Form 8-K filed December 16, 2005 (File No. 1-8182, Exhibit 4.1)).

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 Act of 1934.

31.2	-	Certification by William D. Hibbetts, Senior Vice President and Chief Financial Officer, pursuant to Rule 13a-14(a) or 15d-14(a) under the Securities Act of 1934.

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

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

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

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

PIONEER DRILLING COMPANY

/s/ WILLIAM D. HIBBETTS

William D. Hibbetts

Senior Vice President and Chief Financial Officer

(Principal Financial Officer and Duly Authorized Representative)

Dated: February 2, 2006

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 *	-	Credit Agreement between Pioneer Drilling Services, Ltd. and Frost National Bank, as Administrative Agent, Agent, Lead Arranger and Lender dated October 29, 2004 (Form 8-K dated October 29, 2004 (File No. 1-8182, Exhibit 4.1)).

4.2 *	-	Second Amendment, dated May 11, 2005, to Credit Agreement between Pioneer Drilling Services, Ltd. and Frost National Bank, as Administrative Agent, Lead Arranger and Lender dated October 29, 2004 (Form 8-K filed May 13, 2005 (File No. 1-8182, Exhibit 4.1)).

4.3*	-	Third Amendment, dated October 25, 2005, to Credit Agreement between Pioneer Drilling Services, Ltd. and Frost National Bank, as Administrative Agent, Lead Arranger and Lender dated October 29, 2004 (Form 8-K filed October 28, 2005 (File No. 1-8182, Exhibit 4.1)).

4.4*	-	Fourth Amendment, dated December 15, 2005, to Credit Agreement between Pioneer Drilling Services, Ltd. and Frost National Bank, as Administrative Agent, Lead Arranger and Lender dated October 29, 2004 (Form 8-K filed December 16, 2005 (File No. 1-8182, Exhibit 4.1)).

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 Act of 1934.

31.2	-	Certification by William D. Hibbetts, Senior Vice President and Chief Financial Officer, pursuant to Rule 13a-14(a) or 15d-14(a) under the Securities Act of 1934.

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

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

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