UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

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

For the quarterly period ended September 30, 2004

OR

o		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)

9310 Broadway, Bldg. 1, San Antonio, Texas		78217
(Address of principal executive offices)		(Zip Code)

210-828-7689
(Registrant’s telephone number, including area code)

(Former name, address and former fiscal year, if changed since last report)

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 ý No o

Indicate by check mark whether the registrant is an accelerated filer (as defined in Rule 12b-2 of the Exchange Act). Yes ý No o

As of October 4, 2004, there were 38,406,645 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

	(Unaudited) September 30, 2004				March 31, 2004
ASSETS
Current assets:
Cash and cash equivalents	$		11,072,872		$	6,365,759
Receivables, net	20,047,155				10,901,991
Contract drilling in progress	5,499,121				9,130,794
Current deferred income taxes	403,394				285,384
Prepaid expenses	475,666				1,336,337
Total current assets	37,498,208				28,020,265

Property and equipment, at cost	166,059,836				151,186,550
Less accumulated depreciation and amortization	44,130,814				35,844,938
Net property and equipment	121,929,022				115,341,612
Intangible and other assets, net of amortization	262,778				369,278
Total assets	$	159,690,008			$		143,731,155

LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities:
Notes payable	$	—			$		558,070
Current installments of long-term debt and capital lease obligations	110,215				3,865,236
Accounts payable	17,822,388				13,270,989
Accrued payroll	2,006,645				1,499,151
Accrued expenses	3,073,428				2,798,801
Total current liabilities	23,012,676				21,992,247

Long-term debt and capital lease obligations, less current installments	59,635				44,891,674
Deferred income taxes	6,887,499				6,010,916
Total liabilities	29,959,810				72,894,837

Shareholders’ equity:
Preferred stock, 10,000,000 shares authorized; none issued and outstanding	—				—
Common stock, $.10 par value, 100,000,000 shares authorized; 38,401,645 shares issued and outstanding at September 30, 2004 and 27,300,126 issued and outstanding at March 31, 2004	3,840,164				2,730,012
Additional paid-in capital	138,768,537				82,124,368
Accumulated deficit	(12,878,503			)	(14,018,062			)
Total shareholders’ equity	129,730,198				70,836,318
Total liabilities and shareholders’ equity	$	159,690,008			$		143,731,155

See accompanying notes to condensed consolidated financial statements.

PIONEER DRILLING COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(Unaudited)

	Three Months Ended September 30,								Six Months Ended September 30,
	2004				2003				2004				2003

Contract drilling revenues	$	42,782,900			$		24,244,382		$		83,501,710		$	48,094,465

Costs and expenses:
Contract drilling	34,590,974				19,791,141				68,445,343				40,157,547
Depreciation and amortization	5,306,041				3,927,546				10,354,358				7,551,727
General and administrative	925,549				691,598				1,695,691				1,339,846
Total operating costs and expenses	40,822,564				24,410,285				80,495,392				49,049,120

Income (loss) from operations	1,960,336				(165,903			)	3,006,318				(954,655			)

Other income (expense):
Interest expense	(398,008			)	(700,075			)	(1,116,240			)	(1,433,730			)
Loss from early extinguishment of debt	(100,833			)	—				(100,833			)	—
Interest income	39,932				28,728				63,769				76,418
Other	11,730				30,925				15,120				39,872
Total other income (expense)	(447,179			)	(640,422			)	(1,138,184			)	(1,317,440			)

Income (loss) before income taxes	1,513,157				(806,325			)	1,868,134				(2,272,095			)
Income tax benefit (expense)	(590,124			)	185,122				(728,573			)	594,591
Net earnings (loss)	$	923,033			$	(621,203		)	$	1,139,561			$		(1,677,504	)

Earnings (loss) per common share - Basic	$		0.03		$		(0.03	)	$	0.04			$		(0.08	)

Earnings (loss) per common share - Diluted	$		0.03		$		(0.03	)	$	0.04			$		(0.08	)

Weighted average number of shares outstanding - Basic	33,211,441				22,037,064				30,271,934				21,873,399

Weighted average number of shares outstanding - Diluted	34,271,180				22,037,064				31,289,416				21,873,399

See accompanying notes to condensed consolidated financial statements.

PIONEER DRILLING COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

	Six Months Ended Sept. 30,
	2004				2003
Cash flows from operating activities:
Net earnings (loss)	$	1,139,561			$	(1,677,504	)
Adjustments to reconcile net earnings (loss) to net cash provided by (used in) operating activities:
Depreciation and amortization	10,354,358				7,551,727
Loss on sale of properties and equipment	367,510				403,107
Change in deferred income taxes	758,573				(49,254		)
Changes in current assets and liabilities:
Receivables	(9,145,164			)	(3,615,159		)
Contract drilling in progress	3,631,673				208,634
Prepaid expenses	860,671				649,734
Accounts payable	4,551,399				(3,644,325		)
Prepaid drilling contracts	—				216,000
Federal income taxes	—				444,900
Accrued expenses	782,121				254,307
Net cash provided by operating activities	13,300,702				742,167

Cash flows from financing activities:
Payments of debt	(21,145,131			)	(1,735,556		)
Decrease in other assets	—				(3,787		)
Proceeds from exercise of options/warrants	12,500				45,000
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	8,609,189				(1,694,343		)

Cash flows from investing activities:
Purchase of property and equipment	(17,339,813			)	(15,421,677		)
Proceeds from sale of property and equipment	137,035				348,600
Net cash used in investing activities	(17,202,778			)	(15,073,077		)

Net increase (decrease) in cash and cash equivalents	4,707,113				(16,025,253		)

Beginning cash and cash equivalents	6,365,759				21,002,913
Ending cash and cash equivalents	$		11,072,872		$	4,977,660

Supplementary Disclosure:
Common stock issued for debenture conversion	$		28,000,000		$	—
Common stock issued for acquisition	—				2,122,650
Interest paid	1,644,486				1,444,235
Income taxes refunded	30,000				990,237

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

The accompanying unaudited condensed consolidated financial statements include the accounts of Pioneer Drilling Company and its wholly owned subsidiaries. All intercompany balances and transactions have been eliminated in consolidation.

The accompanying unaudited condensed consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America for interim financial information and with the instructions to Form 10-Q and Rule 10-01 of Regulation S-X. Accordingly, they do not include all of the information and footnotes required by generally accepted accounting principles for complete financial statements. In the opinion of our management, all adjustments (consisting of normal recurring accruals) necessary for a fair presentation have been included.

Income Taxes

We use the asset and liability method of Statement of Financial Accounting Standards (“SFAS”) No. 109 for accounting for income taxes. Under this method, 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 bases. We measure deferred tax assets and liabilities using 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, the effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period that includes the enactment date. At the end of each interim period, we make our best estimate of the effective tax rate we expect to be applicable for the full year and use that rate to determine our income tax expense or benefit on a year-to-date basis.

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 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 (loss) and net earnings (loss) per share would have been reduced to the pro forma amounts the table below indicates:

	Three Months Ended September 30,								Six Months Ended September 30,
	2004			2003					2004				2003
Net earnings (loss) - as reported	$	923,033		$	(621,203			)	$	1,139,561			$	(1,677,504			)
Deduct: Total stock-based employee compensation expense determined under fair value based method for all awards net of related tax effect	(231,954		)	(111,825				)	(579,045			)	(208,347				)
Net earnings (loss) - pro forma	$	691,079		$		(733,028		)	$		560,516		$			(1,885,851	)
Net earnings (loss) per share, as reported - basic	$	0.03		(0.03				)	$		0.04		(0.08				)
Net earnings (loss) per share, as reported-diluted	0.03			(0.03				)	0.04				(0.08				)
Net earnings (loss) per share, pro forma-basic	0.02			(0.03				)	0.02				(0.09				)
Net earnings (loss) per share, pro forma-diluted	0.02			(0.03				)	0.02				(0.09				)
Weighted-average fair value of options granted during the period	$	—		$			4.63		$	6.16			$		4.35

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 each of the three-month and six-month periods ended September 30, 2004 and 2003:

	Three Months				Six Months
	2004		2003		2004		2003
Expected volatility	72	%	66	%	87	%	67	%
Weighted-average risk-free interest rates	3.3	%	3.5	%	4.0	%	3.2	%
Expected life in years	5		5		5		5
Options granted	—		295,000		35,000		465,000

We did not issue any stock options in the quarter ending September 30, 2004.

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 model.

Related Party Transactions

On August 11, 2004 and August 31, 2004, Chesapeake Energy Corporation (“Chesapeake”) purchased 631,133 shares and 94,670 shares of our common stock, respectively, at $6.90 per share pursuant to the preemptive rights we granted to Chesapeake in the stock purchase agreement we entered into in March 2003 when we sold shares of common stock to Chesapeake. As of September 30, 2004, Chesapeake owned 17.02% of our outstanding common stock. During the six months ended September 30, 2004, we recognized revenues of approximately $9,000 on a daywork contract with Chesapeake.

We purchased services from R&B Answering Service and Frontier Services, Inc. during 2004 and 2003. These companies are more than 5% owned by our Chief Operating Officer and an immediate family member of our Vice President, South Texas Division, respectively. The following summarizes the transactions with these companies in each period.

	Three Months			Six Months			September 30, 2004
	2004		2003	2004		2003	Amount Owed
R&B Answering Service
Purchases	$	4,578	1,993	$	8,436	5,237	$	3,264
Payments	2,563		4,362	7,116		6,199
Frontier Services, Inc.
Purchases	$	35,618	16,205	$	67,201	60,487	$	25,270
Payments	23,268		39,700	57,735		87,356

Reclassifications

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

2. Long-term Debt, Subordinated Debt and Notes Payable

On August 12, 2004, we made a $2,000,000 principal payment on our Collateral Installment Note between Pioneer Drilling Services, Ltd. and Merrill Lynch Capital due in December 2007. In accordance with the terms of the note, we also gave Merrill Lynch Capital the required 30-days notice of our intent to repay the balance outstanding under the note. On September 10, 2004, we repaid the approximately $10,083,000 balance of the note and paid a prepayment fee of approximately $101,000.

On August 12, 2004, we retired our note payable to Frost National Bank in the principal amount of approximately $2,852,000, which was due in March 2007.

On August 16, 2004, we retired our note payable to Frost National Bank in the principal amount of approximately $3,856,000, which was due in August 2007.

At September 30, 2004, we had a $2,500,000 line of credit available from Frost National Bank. Any borrowings under this line of credit were secured by our trade receivables and bear interest at a rate of prime (4.75% at September 30, 2004) plus 1.0%. The sum of draws under this line and the amount of all outstanding letters of credit issued by the bank for our account were limited to 75% of eligible accounts receivable. Therefore, if 75% of our eligible accounts receivable was less than $2,500,000, plus any outstanding letters of credit issued by the bank on our behalf, our ability to draw under this line would be reduced. At September 30, 2004, we had no outstanding advances under this line of credit, letters of credit were $1,664,000 and 75% of our eligible accounts receivable was approximately $14,853,000. The letters of credit are issued to two 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 lender will be required to fund any draws under these letters of credit.

At September 30, 2004, we were in compliance with all covenants applicable to our line of credit. Those covenants include, among others, the maintenance of ratios of debt to net worth, leverage and cash flow coverage. The covenants also restrict the payment of dividends on our common stock.

On October 29, 2004, we entered into a $47,000,000 credit facility with Frost National Bank, 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.

3. Commitments and Contingencies

We are currently constructing, from new and used components, a 1000-horse power electric drilling rig. As of September 30, 2004, we had incurred approximately $919,000 of the estimated $5,500,000 rig construction costs. We expect to complete construction of the rig in December 2004.

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.

4. Equity Transactions

On August 1, 2003, we issued 477,000 shares of our common stock at $4.45 per share to Texas Interstate Drilling Company, L.P. as part of the purchase price of two land drilling rigs.

On February 20, 2004, we sold 4,400,000 shares of our common stock at $5.40 per share in a private placement for $23,760,000 in proceeds, before related offering expenses. Although we issued those shares without registration under the Securities Act of 1933 in reliance on the exemption that Section 4(2) of that Act provides for transactions not involving any public offering, we filed a registration statement on Form S-3 to register the resale of those shares. The registration statement became effective on June 22, 2004.

On August 11, 2004, we sold 4,000,000 shares of our common stock at approximately $6.61 per share, net of underwriters’ commissions, pursuant to a public offering we registered with the SEC under a registration statement filed on Form S-1.

On August 11, 2004, the entire $28,000,000 in aggregate principal amount of our 6.75% convertible subordinated debentures held by WEDGE Energy Services, L.L.C. and William H. White was converted in accordance with the terms of those debentures into 6,496,519 shares of our common stock.

On August 31, 2004, we sold 600,000 additional shares of our common stock at approximately $6.61 per share, net of underwriters’ commissions, pursuant to the underwriters’ exercise of an over-allotment option granted in connection with the public offering we referred to above.

Employees exercised stock options for the purchase of 20,000 shares of common stock at $2.25 per share during the six months ended September 30, 2003.

5. Earnings (Loss) Per Common Share

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

		Three Months Ended September 30,					Six Months Ended September 30,
		2004		2003			2004			2003
Basic
Net earnings (loss)		$	923,033	$	(621,203	)	$		1,139,561	$	(1,677,504	)
Weighted average shares		33,211,441		22,037,064			30,271,934			21,873,399
Earnings (loss) per share		$	0.03	$	(0.03	)	$		0.04	$	(0.08	)

		Three Months Ended September 30,					Six Months Ended September 30,
		2004		2003			2004			2003
Diluted
Net earnings (loss)		$	923,033	$	(621,203	)	$	1,139,561		$	(1,677,504	)
Effect of dilutive securities:
Convertible debentures	(1)	—		—			—			—

Net earnings (loss) and assumed conversion		$	923,033	$	(621,203	)	$	1,139,561		$	(1,677,504	)
Weighted average shares:
Outstanding		33,211,441		22,037,064			30,271,934			21,873,399
Options	(1)	1,059,739		—			1,017,482			—
Convertible debentures	(1)	—		—			—			—
		34,271,180		22,037,064			31,289,416			21,873,399
Earnings (loss) per share		$	0.03	$	(0.03	)	$	0.04		$	(0.08	)

(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 three and six months ended September 30, 2004, because they were antidilutive. Employee stock options to purchase 2,224,000 shares and 6,496,519 shares from convertible debentures were not included in the computation of diluted loss per share for the three months and six months ended September 30, 2003, 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.

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 the natural gas production regions of South, East and North Texas. 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 customer base is diversified. During the six months ended September 30, 2004, no customer accounted for over 7% of our revenues.

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 refurbished drilling rigs.

Over the past four years, we have expanded our fleet of drilling rigs from eight to 36, through acquisitions and the construction of refurbished rigs. Our rigs drill in depth ranges between 8,000 and 18,000 feet. Currently, we have 15 rigs operating in South Texas, 17 in East Texas and four in North Texas. We actively market all of these rigs. Subject to obtaining satisfactory financing, we anticipate continued growth of our rig fleet in fiscal 2005. We are currently constructing a 1000-horse power electric rig.

We earn our revenues by drilling oil and gas wells and obtain our contracts 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 we offer 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.

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. On daywork contracts, 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.

For the three-month and six-month periods ended September 30, 2004 and 2003, our rig utilization and revenue days were as follows:

	Three Months				Six Months
	2004		2003		2004		2003
Utilization Rates	96	%	85	%	94	%	86	%
Revenue Days	3,166		2,064		6,163		4,022

The reasons for the increase in the number of revenue days in 2004 over 2003 are the increase in size of our rig fleet from 27 rigs at September 30, 2003 to 36 rigs at September 30, 2004 and the improvement in our overall rig utilization rate.

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. For the six months ended September 30, 2004, turnkey contracts accounted for approximately 40 percent of our contracts. Turnkey contracts provide us with the opportunity to keep our rigs working in periods of lower demand and improve our profitability, but at an increased risk.

We devote substantial resources to maintaining and upgrading our rig fleet. In the short term, these actions resulted in fewer revenue days and slightly lower utilization; however, in the long term, we believe the upgrades will help the marketability of the rigs and improve their operating performance. We are currently performing, between contracts or as necessary, safety and equipment upgrades to the eight rigs we acquired in March 2004.

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.

For the three months ended September 30, 2004, the average weekly spot price for West Texas Intermediate crude oil was $43.69, the average weekly spot price for Henry Hub natural gas was $5.44 and the average weekly Baker Hughes land rig count was 1,114. On October 22, 2004, the spot price for West Texas Intermediate crude oil was $56.17, the spot price for Henry Hub natural gas was $7.17 and the Baker Hughes land rig count was 1,135, a 17% increase from 970 on October 24, 2003.

The average weekly spot prices of West Texas Intermediate crude oil, Henry Hub natural gas and the average weekly domestic land rig count, per the Baker Hughes land rig count, for each of the previous six years ended September 30, 2004 were:

	2004			2003		2002		2001		2000		1999

Oil (West Texas Intermediate)	$	37.10		$	30.45	$	24.23	$	28.93	$	28.52	$	16.33

Gas (Henry Hub)	$		5.55	$	5.22	$	2.86	$	4.95	$	3.31	$	2.10

U.S. Land Rig Count	1,038			839		734		994		693		482

During the first six months of fiscal 2005, 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 gas-rich areas in which we operate. Natural gas reserves are typically found in deeper geological formations and generally require premium equipment and quality crews 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 for the days completed, based on the contract amount divided by 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. This is primarily because, under a turnkey contract, we assume most of the risks associated with drilling operations 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 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 we 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, ultimate recovery of that value, in the event we were unable to drill to the agreed-on depth in breach of the contract, 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 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 could differ significantly if our cost estimates are later revised from our original estimates for contracts in progress at the end of a reporting period which were 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 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, 2004, would have resulted in a corresponding decrease in our net earnings of approximately $1,013,000 for the three-months and six-months ended September 30, 2004.

Deferred taxes – We provide deferred taxes for net operating loss carryforwards and for the basis difference in our property and equipment between 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 eight 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 it will require 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 immediately increase our cost estimate for the additional costs to complete the contracts. 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 immediately 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, 2004, we experienced losses on 13 of the 90 turnkey and footage contracts completed, with losses exceeding $25,000 on eight contracts and losses exceeding $100,000 on four contracts. We are more likely to encounter losses on turnkey and footage contracts in years 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. All of our turnkey and footage contracts in progress at September 30, 2004 were completed prior to the release of the financial statements included in this report. At September 30, 2004, our contract drilling in progress totaled approximately $5,499,000, of which turnkey and footage contract revenues were approximately $3,633,000 and daywork contract revenues were approximately $1,866,000.

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.

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.

Other accrued expenses in our September 30, 2004 financial statements include an accrual of approximately $721,000 for costs incurred under the self-insurance portion of our health insurance and under our workers’ compensation insurance. We have a deductible of (1) $100,000 per covered individual per year under the health insurance and (2) $250,000 per occurrence under our workers’ compensation insurance. We accrue for these costs as claims are incurred, based on cost estimates established for each claim by the insurance companies providing the administrative services for processing the claims, including an estimate for incurred but not reported claims, estimates for claims paid directly by us, our estimate of the administrative costs associated with these claims and our historical experience with these types of claims.

Liquidity and Capital Resources

Sources of Capital Resources

Our rig fleet has grown from eight rigs in August 2000 to 36 rigs as of September 30, 2004. We have financed this growth with a combination of debt and equity financing. We have raised additional equity or used equity for growth six times since January 2000. We plan to continue to grow our rig fleet. We have arranged a new credit facility to finance near-term growth and anticipate the use of equity financing for additional long-term growth. However, our ability to continue funding our growth through the issuance of shares of our common stock is uncertain, as our common stock is not heavily traded and the market price for our common stock has been volatile in recent periods.

On August 11, 2004, the entire $28,000,000 in aggregate principal amount of our 6.75% convertible subordinated debentures held by WEDGE Energy Services, L.L.C. and William H. White was converted in accordance with the terms of those debentures into 6,496,519 shares of our common stock. We issued those shares without registration under the Securities Act of 1933 in reliance on the exemption that Section 4(2) of that Act provides for transactions not involving any public offering.

On August 11, 2004, we also sold 4,000,000 shares of our common stock at approximately $6.61per share, net of underwriters’ commissions, pursuant to a public offering we registered with the SEC under a registration statement filed on Form S-1. On August 31, 2004, we sold 600,000 additional shares of our common stock at approximately $6.61 per share, net of underwriters’ commissions, pursuant to the underwriters’ exercise of an over-allotment option granted in connection with that public offering.

On October 29, 2004, we entered into a $47,000,000 credit facility with Frost National Bank 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.

Our new credit facility from Frost National Bank, contains various covenants pertaining to a debt to capitalization ratio, operating leverage ratio and fixed charge coverage ratio and restricts us from paying dividends. We will 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 not permitted by the agreement;

• our failure to comply with financial covenants related to a capitalization ratio of 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 not already allowed by the credit agreement;

• 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.

Uses of Capital Resources

For the three and six months ended September 30, 2004, the additions to our property and equipment consisted of the following:

	Three Months			Six Months
Drilling rigs (1)	$		1,628,229	$	4,242,280
Other drilling equipment	6,150,295			10,592,511
Transportation equipment	518,364			1,654,381
Other	627,402			850,640
	$	8,924,290		$		17,339,812

(1) Includes capitalized interest costs of $0 for the three months and $28,740 for the six months ended September 30, 2004.

Working Capital

Our working capital increased to $14,485,532 at September 30, 2004 from $6,028,018 at March 31, 2004. Our current ratio, which we calculate by dividing our current assets by our current liabilities, was 1.63 at September 30, 2004, compared to 1.27 at March 31, 2004. The principal reason for the increase in our working capital at September 30, 2004 was our August 2004 public offering of common stock in which we raised proceeds of approximately $29,700,000. Approximately $18,800,00 of those proceeds was used to retire substantially all our long-term debt. Our operations generated cash flows in excess of our requirements for debt service and normal capital expenditures. If necessary, we can defer rig upgrades to improve our cash position. Therefore, we believe our cash generated by operations and our ability to borrow on our currently unused line of

credit and letter of credit facility of approximately $4,500,000, after reductions for letters of credit, should allow us to meet our routine financial obligations.

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

	September 30, 2004			March 31, 2004			Change

Cash and cash equivalents	$		11,072,872	$	6,365,759		$		4,707,113
Receivables	20,047,155			10,901,991			9,145,164
Contract drilling in progress	5,499,121			9,130,794			(3,631,673			)
Deferred income taxes	403,394			285,384			118,010
Prepaid expenses	475,666			1,336,337			(860,671			)
Current assets	37,498,208			28,020,265			9,477,943

Current debt	110,215			4,423,306			(4,313,091			)
Accounts payable	17,822,388			13,270,989			4,551,399
Accrued payroll	2,006,645			1,499,151			507,494
Accrued expenses	3,073,428			2,798,801			274,627
	23,012,676			21,992,247			1,020,429

Working capital	$	14,485,532		$		6,028,018	$	8,457,514

The increase in our receivables at September 30, 2004 from March 31, 2004 was due to our operating one additional rig, the improvement in rig utilization and revenue rates, and the timing of the completion of contracts as reflected in the decrease in contract drilling in progress. We invoiced approximately $18,700,000 of completed work in September 2004.

The change in contract drilling in progress was primarily due to the number and stage of completion of turnkey contracts in progress at September 30, 2004 compared to March 31, 2004.

Substantially all our prepaid expenses at September 30, 2004 consisted of prepaid insurance. We renew and pay our insurance premium in late October of each year. At September 30, 2004, we had amortized eleven months of the premiums, compared to five months of amortization as of March 31, 2004.

The increase in accounts payable was due to the increase in turnkey contracts completed during September and in progress at September 30, 2004 and rig upgrades.

The increase in accrued payroll was due to the 10 days of payroll accrual at September 30, 2004 compared to nine days at March 31, 2004, the addition of a rig, the addition of our East Texas trucking department and the timing of a payroll tax deposit of approximately $430,000.

The increase in accrued expenses at September 30, 2004 compared to March 31, 2004 is principally due to the increase in the accrual for property taxes and insurance costs offset by the decrease in accrued interest expense.

Long-term Debt

Our long-term debt at September 30, 2004 consisted of capital lease obligations of $169,850.

Contractual Obligations

We do not have any routine purchase obligations. The following table excludes interest payments on long-term debt and capital lease obligations. The following table includes all of our contractual obligations at September 30, 2004.

	Payments Due by Period
Contractual Obligations	Total		Less than 1 year		1-3 years			4-5 years		More than 5 years
Capital Lease Obligations	$	169,850	$	110,215	$		59,635	—		—
Operating Lease Obligations	140,466		77,664		62,802			—		—
Total	$	310,316	$	187,879	$	122,437		$	—	$	—

Debt Requirements

At September 30, 2004, we had a $2,500,000 line of credit available from Frost National Bank. Any borrowings under this line of credit were secured by our trade receivables and bear interest at a rate of prime (4.75% at September 30, 2004) plus 1.0%. The sum of draws under this line and the amount of all outstanding letters of credit issued by the bank for our account were limited to 75% of eligible accounts receivable. Therefore, if 75% of our eligible accounts receivable was less than $2,500,000 plus any outstanding letters of credit issued by the bank on our behalf, our ability to draw under this line would be reduced. At September 30, 2004, we had no outstanding advances under this line of credit, letters of credit were $1,664,000 and 75% of eligible accounts receivable was approximately $14,853,000. The letters of credit are issued to two workers’ compensation insurance companies to secure possible future claims that do not exceed the deductibles on these policies. It is our practice to pay any amounts due that do not exceed these deductibles as they are incurred. Therefore, we do not anticipate the lender will be required to fund any draws under these letters of credit.

At September 30, 2004, our line of credit loan agreement from Frost National Bank contained various covenants pertaining to debt to net worth, leverage and cash flow coverage ratios and restricted us from paying dividends. We determined compliance with the ratios on a quarterly basis, based on the previous four quarters. As of September 30, 2004, we were in compliance with all covenants applicable to our outstanding debt.

Events of default in our loan agreement, which could trigger an early repayment requirement, include among others:

• our failure to make required payments;

• our failure to comply with financial covenants related to the maintenance of a ratio of debt to tangible net worth, a leverage ratio, a cash flow coverage ratio and a senior cash flow coverage ratio;

• our incurrence of additional indebtedness in excess of $2,000,000 not already allowed by the credit agreements; and

• any payment of cash dividends on our common stock.

The limitation on additional indebtedness has not affected our operations or liquidity and we do not expect it to affect us in the future, as we expect to continue to generate adequate cash flow from operations.

Results of Operations

Contracts

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 easiest 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.

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 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 compared with 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.

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 to primarily daywork contracts.

For the three and six month periods ended September 30, 2004 and 2003, the percentages of our drilling revenues by type of contract were as follows:

	Three Months				Six Months
	2004		2003		2004		2003
Daywork Contracts	40	%	49	%	38	%	45	%
Turnkey Contracts	56	%	46	%	58	%	51	%
Footage Contracts	4	%	5	%	4	%	4	%

While current demand for drilling rigs has increased, we continue to bid on turnkey contracts in an effort to improve profitability and maintain rig utilization. With the improvements in daywork rates, we anticipate a gradual decline in the number of turnkey contracts.

Statement of Operations Analysis

The following table provides information for our operations for the three-month and six-month periods ended September 30, 2004 and September 30, 2003.

	Three Months										Six Months
	2004				2003						2004					2003
Contract drilling revenues:
Daywork contracts	$	17,276,731			$			11,831,824			$	31,417,487				$	21,627,884
Turnkey contracts	23,820,635				11,258,181						48,439,968					24,561,779
Footage contracts	1,685,534				1,154,377						3,644,255					1,904,802
Total contract drilling revenues	$	42,782,900			$				24,244,382		$	83,501,710				$	48,094,465
Contract drilling costs:
Daywork contracts	$	13,743,157			$		10,130,675				$	25,272,395				$	18,848,876
Turnkey contracts	19,475,630				8,872,345						40,336,150					19,868,898
Footage contracts	1,372,186				788,121						2,836,798					1,439,773
Total contract drilling costs	$	34,590,973			$	19,791,141					$		68,445,343			$		40,157,547

Depreciation and amortization	$		5,306,041		$	3,927,546					$			10,354,358		$			7,551,727
General and administrative expense	925,549				691,598						1,695,691					1,339,846
Revenue days by type of contract:
Daywork contracts	1,674				1,362						3,151					2,548
Turnkey contracts	1,347				610						2,723					1,319
Footage contracts	145				92						289					155
Total Revenue days	3,166				2,064						6,163					4,022

Contract drilling revenue per revenue day	$		13,513		$	11,746					$			13,549		$			11,958
Contract drilling cost per revenue day	10,926				9,589						11,106					9,984
Rig utilization rates	96			%	85					%	94				%	86				%
Average number of rigs during the period	36				26.3						35.7					25.4

Our contract drilling revenues grew by approximately $18,539,000, or 76%, in the quarter ended September 30, 2004 from 2003, due to an improvement in rig revenue rates due to an increase in demand for drilling rigs, an increase in the number of rigs in our fleet and an 11% increase in rig utilization. Our contract drilling revenues grew by approximately $35,407,000, or 74%, in the six months ended September 30, 2004 from 2003, due to an improvement in rig revenue rates due to an increase in demand for drilling rigs, an increase in the number of rigs in our fleet and an 8% increase in rig utilization. The improvement in contract drilling revenue per day is due to the improvement in revenue rates and the increase in revenues from turnkey contracts.

Our contract drilling costs grew by approximately $14,800,000, or 75%, in the quarter ended September 30, 2004 from the corresponding quarter of 2003 due to the increases in the number of rigs in our fleet, rig utilization and the 121% increase in turnkey revenue days in 2004 compared to 2003. Under turnkey and footage contracts we provide supplies and materials such as fuel, drill bits, casing, drilling fluids, etc., which significantly adds to drilling costs.

Our contract drilling costs grew by approximately $28,300,000, or 70%, in the six months ended September 30, 2004 from the corresponding period of 2003 due to the increases in the number of rigs in our fleet, rig utilization and the 106% increase in turnkey revenue days in 2004 compared to 2003.

Our depreciation and amortization expense in the quarter ended September 30, 2004 increased by approximately $1,378,000, or 35%, from the corresponding quarter of 2003. Our depreciation and amortization expense for the six months ended September 30, 2004 increased by approximately $2,803,000, or 37%, from the corresponding six months of 2003. The increases in 2004 over 2003 primarily resulted from the 37% increase in the average size of our rig fleet.

Our general and administrative expense in the quarter ended September 30, 2004 increased by approximately $234,000, or 34%, from the corresponding quarter of 2003. The increase resulted from increased payroll costs, insurance costs, professional fees and director fees. In the quarter ended September 30, 2004, payroll cost increased by approximately $76,000,

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

We are usually subject to market risk exposure related to changes in interest rates on our outstanding floating rate debt. At September 30, 2004, except for a few capital leases with fixed interest rates, we had no outstanding debt, as all of our long-term debt was paid during the quarter. We did not enter into any debt arrangements for trading purposes.

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, 2004 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 controls over financial reporting that occurred during the three months ended September 30, 2004 that has materially affected, or is reasonably likely to materially affect, our internal controls over financial reporting.

PART II. OTHER INFORMATION

ITEM 2. UNREGISTERED SALES OF EQUITY SECURITES AND USE OF PROCEEDS

On August 11, 2004, the entire $28,000,000 in aggregate principal amount of our 6.75% convertible subordinated debentures held by WEDGE Energy Services, L.L.C. and William H. White was converted in accordance with the terms of those debentures into 6,496,519 shares of our common stock. We issued those shares without registration under the Securities Act of 1933 in reliance on the exemption that Section 4(2) of that Act provides for transactions not involving any public offering.

ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

On August 6, 2004, the annual meeting of the shareholders of the Company was held. At the meeting, Mike E. Little and C. Robert Bunch were elected to the Board of Directors of the Company. The following matters were submitted to the shareholders of the Company for their approval.

(1) Election of Directors:

Michael E. Little. 21,693,815 votes were cast for and 71,390 votes were withheld.

C. Robert Bunch. 21,692,782 votes were cast for and 72,423 votes were withheld.

(2) The shareholders ratified the appointment of KPMG LLP as our independent auditors for the fiscal year ending March 31, 2005. 21,733,235 votes were cast for the matter, and 23,270 were cast against the matter. 0 votes were withheld. 8,700 votes were abstentions and 0 votes were broker non-votes.

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))

10.1 *	-	Irrevocable Conversion Notice and Agreement between Pioneer Drilling Company and William H. White dated July 9, 2004. (Form S-1 (Reg. No. 333-117279), Exhibit 4.19).

10.2 *	-	Irrevocable Conversion Notice and Agreement between Pioneer Drilling Company and WEDGE Energy Services, L.L.C. dated July 9, 2004. (Form S-1 (Reg. No. 333-117279), Exhibit 4.20).
10.3 *	-	Agreement Regarding Preemptive Rights dated July 26, 2004 between Pioneer Drilling Company and Chesapeake Energy Corporation (Form S-1 (Reg. No. 333-117279), Exhibit 4.21).

31.1	-	Rule 13a-14(a)/15d-14(a) Certification by Pioneer Drilling Company’s Chief Executive Officer.

31.2	-	Rule 13a-14(a)/15d-14(a) Certification by Pioneer Drilling Company’s Chief Financial Officer.

32.1	-	Section 1350 Certification by Pioneer Drilling Company’s Chief Executive Officer.

32.2	-	Section 1350 Certification by Pioneer Drilling Company’s Chief Financial Officer.

* 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 initially filed with the Securities and Exchange Commission on November 5, 2004.

		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:	November 5, 2004

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)).

10.1 *	-	Irrevocable Conversion Notice and Agreement between Pioneer Drilling Company and William H. White dated July 9, 2004. (Form S-1 (Reg. No. 333-117279), Exhibit 4.19).

10.2 *	-	Irrevocable Conversion Notice and Agreement between Pioneer Drilling Company and WEDGE Energy Services, L.L.C. dated July 9, 2004. (Form S-1 (Reg. No. 333-117279), Exhibit 4.20).

10.3 *	-	Agreement Regarding Preemptive Rights dated July 26, 2004 between Pioneer Drilling Company and Chesapeake Energy Corporation (Form S-1 (Reg. No. 333-117279), Exhibit 4.21).

31.1	-	Rule 13a-14(a)/15d-14(a) Certification by Pioneer Drilling Company’s Chief Executive Officer.

31.2	-	Rule 13a-14(a)/15d-14(a) Certification by Pioneer Drilling Company’s Chief Financial Officer.

32.1	-	Section 1350 Certification by Pioneer Drilling Company’s Chief Executive Officer.

32.2	-	Section 1350 Certification by Pioneer Drilling Company’s Chief Financial Officer.

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