UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 

FORM 10-Q

 

 

For the transition period from                                     to

 

Commission File Number 001-08182

 

PIONEER DRILLING COMPANY

(Exact name of registrant as specified in its charter)

 

 

 

(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). Yeso  Noý

 

As of February 5, 2004, there were 22,211,792 shares of common stock, par value $0.10 per share, of the registrant issued and outstanding.

 

 

PART 1. FINANCIAL INFORMATION

ITEM 1.     FINANCIAL STATEMENTS

 

PIONEER DRILLING COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

 

		(Unaudited) December 31, 2003			March 31, 2003
ASSETS
Current assets:
Cash and cash equivalents		$	2,829,960		$	21,002,913
Receivables, net		11,207,898			4,499,378
Contract drilling in progress		3,678,962			4,429,545
Federal income tax receivable		—			444,900
Current deferred income taxes		132,031			180,991
Prepaid expenses		1,620,711			914,187
Total current assets		19,469,562			31,471,914
Property and equipment, at cost		133,156,735			110,223,230
Less accumulated depreciation		32,763,264			22,367,327
Net property and equipment		100,393,471			87,855,903
Other assets		345,958			366,500
Total assets		$	120,208,991		$	119,694,317
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities:
Notes payable		$	889,970		$	587,177
Current installments of long-term debt and capital lease obligations		3,609,884			2,811,986
Accounts payable		14,071,461			14,206,586
Accrued payroll		1,810,723			847,163
Accrued expenses		2,507,596			1,874,693
Total current liabilities		22,889,634			20,327,605
Long-term debt and capital lease obligations, less current installments		44,023,163			45,854,542
Deferred income taxes		5,614,993			5,839,908
Total liabilities		72,527,790			72,022,055
Shareholders’ equity:
Preferred stock, 10,000,000 shares authorized; none issued and outstanding		—			—
Common stock, $.10 par value,  100,000,000 shares authorized; 22,211,792 and 21,700,792 shares issued at December 31, 2003 and March 31, 2003, respectively		2,221,179			2,170,079
Additional paid-in capital		59,887,077			57,730,188
Accumulated deficit		(14,427,055		)	(12,228,005		)
Total shareholders’ equity		47,681,201			47,672,262
Total liabilities and shareholders’ equity		$	120,208,991		$	119,694,317

 

See accompanying notes to condensed consolidated financial statements.

 

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PIONEER DRILLING COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

 

(Unaudited)

 

		Three Months Ended December 31,						Nine Months Ended December 31,
		2003			2002			2003			2002
Revenues:
Contract drilling		$	26,414,362		$	19,795,727		$	74,508,827		$	55,289,179
Other		25,184			12,310			65,056			34,743
Total operating revenues		26,439,546			19,808,037			74,573,883			55,323,922
Costs and expenses:
Contract drilling		21,599,719			18,076,564			61,757,266			47,918,096
Depreciation and amortization		4,118,811			3,006,185			11,670,538			8,521,830
General and administrative		687,286			552,714			2,027,132			1,677,622
Bad debt expense		—			—			—			110,000
Total operating costs and expenses		26,405,816			21,635,463			75,454,936			58,227,548
Earnings (loss) from operations		33,730			(1,827,426		)	(881,053		)	(2,903,626		)
Other income (expense):
Interest expense		(683,496		)	(673,194		)	(2,117,226		)	(1,900,116		)
Interest income		10,358			19,516			86,776			72,912
Gain on sale of marketable securities		—			—			—			203,887
Total other income (expense)		(673,138		)	(653,678		)	(2,030,450		)	(1,623,317		)
Loss before income taxes		(639,408		)	(2,481,104		)	(2,911,503		)	(4,526,943		)
Income tax benefit		117,862			777,009			712,453			1,349,348
Net Loss		$	(521,546	)	$	(1,704,095	)	$	(2,199,050	)	$	(3,177,595	)
Loss per common share - Basic		$	(0.02	)	$	(0.11	)	$	(0.10	)	$	(0.20	)
Loss per common share - Diluted		$	(0.02	)	$	(0.11	)	$	(0.10	)	$	(0.20	)
Weighted average number of shares outstanding - Basic		22,203,194			16,142,024			21,983,730			16,078,277
Weighted average number of shares outstanding - Diluted		22,203,194			16,142,024			21,983,730			16,078,277

 

See accompanying notes to condensed consolidated financial statements.

 

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PIONEER DRILLING COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

 

(Unaudited)

 

		Nine Months Ended December 31,
		2003			2002
Cash flows from operating activities:
Net loss		$	(2,199,050	)	$	(3,177,595	)
Adjustments to reconcile net loss to net cash provided by (used in) operating activities:
Depreciation and amortization		11,670,538			8,521,830
Allowance for doubtful accounts		—			110,000
Gain on sales of marketable securities		—			(203,887		)
Loss on sale of property and equipment		516,306			288,544
Change in deferred income taxes		(175,955		)	(456,998		)
Changes in current assets and liabilities:
Receivables		(6,708,520		)	182,507
Contract drilling in progress		750,583			(1,642,000		)
Prepaid expenses		(706,524		)	(814,964		)
Accounts payable		(135,125		)	5,259,361
Federal income taxes		444,900			250,850
Accrued expenses		1,596,464			1,067,545
Net cash provided by operating activities		5,053,617			9,385,193
Cash flows from financing activities:
Proceeds from notes payable		2,110,019			33,484,147
Payments of debt		(2,840,708		)	(11,396,049		)
Increase in other assets		(3,787		)	(234,449		)
Proceeds from exercise of options		85,339			106,790
Net cash provided by (used in) financing activities		(649,137		)	21,960,439
Cash flows from investing activities:
Purchase of property and equipment		(22,936,033		)	(29,042,533		)
Marketable securities sold		—			375,414
Proceeds from sale of property and equipment		358,600			254,130
Net cash used in investing activities		(22,577,433		)	(28,412,989		)
Net increase (decrease) in cash		(18,172,953		)	2,932,643
Beginning cash and cash equivalents		21,002,913			5,383,045
Ending cash and cash equivalents		$	2,829,960		$	8,315,688
Supplementary disclosure:
Interest paid		$	1,655,047		$	1,555,093
Income taxes refunded		(990,237		)	(1,143,200		)
Common stock issued for purchase of rigs		2,122,650			—

 

See accompanying notes to condensed consolidated financial statements.

 

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 PIONEER DRILLING COMPANY AND SUBSIDARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

 

1.  Organization and Basis of Presentation

 

The condensed consolidated financial statements include the accounts of Pioneer Drilling Company and its wholly owned subsidiaries.  All significant 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.

 

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.

 

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 loss and net loss 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,
		2003			2002			2003			2002
Net loss-as reported		$	(521,546	)	$	(1,704,095	)	$	(2,199,050	)	$	(3,177,595	)
Deduct: Total stock-based employee compensation expense determined under fair value based method for all awards  net of related tax effect		(171,870		)	(90,031		)	(380,217		)	(319,230		)
Net loss-pro forma		$	(693,416	)	$	(1,794,126	)	$	(2,579,267	)	$	(3,496,825	)
Net loss per share-as reported-basic		$	(0.02	)	$	(0.11	)	$	(0.10	)	$	(0.20	)
Net loss per share-as reported-diluted		(0.02		)	(0.11		)	(0.10		)	(0.20		)
Net loss per share-pro forma-basic		(0.03		)	(0.11		)	(0.12		)	(0.22		)
Net loss per share-pro forma-diluted		(0.03		)	(0.11		)	(0.12		)	(0.22		)
Weighted-average fair value of options granted during the period		$	3.67		$	—		$	4.23		$	4.50

 

We estimate the fair value of each option grant on the date of grant using a Black-Scholes options-pricing model.  This model assumed expected volatility of 61% and weighted-average risk-free interest rate of 3.36% for grants in the three-month period ended December 31, 2003 and an expected life of five years.  There were no grants in the three-month period ended December 31, 2002.  The model assumed expected volatility of 65% and 69% and

 

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weighted-average risk-free interest rates of 3.3% and 4.2% for grants in the nine-month periods ended December 31, 2003 and 2002, respectively, and an expected life of five years.  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.

 

On April 1, 2003, we adopted SFAS No. 143, Accounting for Asset Retirement Obligations, which addresses financial accounting and reporting for obligations associated with the retirement of tangible long-lived assets and the associated asset retirement costs.  The standard applies to legal obligations associated with the retirement of long-lived assets that result from the acquisition, construction, development and/or normal use of the asset.  In that connection, we were required to identify all our legal obligations relating to asset retirements and determine the fair value of these obligations as of April 1, 2003.  Our adoption of SFAS No. 143 did not have a material effect on our financial position or results of operations.

 

On July 1, 2003, we adopted SFAS No. 149, Amendment of Statement 133 on Derivative Instruments and Hedging Activities. This statement amends and clarifies financial accounting and reporting for derivative instruments, including certain derivative instruments in other contracts (collectively referred to as derivatives) and for hedging activities under SFAS No. 133, Accounting for Derivative Instrument and Hedging Activities. The provisions of this statement are effective for contracts entered into or modified after June 30, 2003 and hedging relationships designated after June 30, 2003.  Except for the provisions related to SFAS No. 133, all provisions of this statement will be applied prospectively.  In addition, paragraphs 7(a) and 23(a) of this statement, which relate to forward purchases or sales of when-issued securities or other securities that do not yet exist, should be applied to both existing contracts and new contracts entered into after June 30, 2003.  Our adoption of SFAS No. 149 did not have a material effect on our financial position or results of operations.

 

On July 1, 2003, we adopted SFAS No. 150, Accounting for Certain Financial Instruments with Characteristics of Both Liabilities and Equity.  This statement requires issuers to classify as liabilities (or assets in some circumstance) three classes of freestanding financial instruments that embody obligations of the issuer. The provisions of this statement are effective for financial instruments entered into or modified after May 31, 2003, and otherwise are effective at the beginning of the first interim period beginning after June 15, 2003.  Our adoption of SFAS No. 150 did not have a material effect on our financial position or results of operations.

 

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

 

On December 15, 2003, we obtained a $3,000,000 loan from Frost National Bank and drew $1,000,000 in December.  The loan, secured by a drilling rig, bears interest at prime plus 1% with interest only until April 15, 2004, when we will begin making monthly payments of $42,401.

 

We have a $2,500,000 line of credit available from Frost National Bank.  Any borrowings under this line of credit are secured by our trade receivables and bear interest at a rate of prime (4.00% at December 31, 2003) 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 are limited to 75% of eligible accounts receivable.  Therefore, if 75% of our eligible accounts receivable is 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 December 31, 2003, we had no outstanding advances under this line of credit, letters of credit were $1,684,000 and 75% of our eligible accounts receivable was approximately $8,153,000.  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 the lender will be required to fund any draws under these letters of credit.

 

On September 29, 2003, the monthly installments of our loan from Frost National Bank, maturing in August 2004, were extended through August 2007.

 

At December 31, 2003, we were in compliance with all covenants applicable to our outstanding debt.  Those covenants include, among others, the maintenance of ratios of debt to net worth, leverage, cash flow and fixed cost coverage.  The covenants also restrict the payment of dividends on our common stock.

 

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3.  Commitments and Contingencies

 

We have signed an asset purchase agreement to acquire a seven-rig drilling fleet and related equipment for $12,000,000.  The transaction is subject to our obtaining satisfactory financing and is expected to close in early March 2004.  We also plan to acquire 23 used rig hauling trucks for $1,200,000.  In December 2003, we purchased for approximately $3,750,000 a rig which we had previously leased. We are financing this rig purchase primarily with a $3,000,000 bank loan.  We drew $1,000,000 of the $3,000,000 bank loan in December to make a down payment on the rig.

 

We are in the process of constructing a 1000 hp electric drilling rig from primarily used components.  As of December 31, 2003, we have incurred approximately $1,900,000 of construction costs.  We anticipate additional construction costs of $2,100,000 to $2,600,000; however, we do not have a scheduled completion date at this time.

 

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 or results of operations.

 

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.

 

Directors and employees exercised stock options for the purchase of 34,000 and 245,000 shares of common stock at prices ranging from $.375 to $2.50 per share during the nine months ended December 31, 2003 and December 31, 2002, respectively.

 

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 December 31,						Nine Months Ended December 31,
		2003			2002			2003			2002
Basic
Net loss		$	(521,546	)	$	(1,704,095	)	$	(2,199,050	)	$	(3,177,595	)
Weighted average shares		22,203,194			16,142,024			21,983,730			16,078,277
Loss per share		$	(0.02	)	$	(0.11	)	$	(0.10	)	$	(0.20	)

 

			Three Months Ended December 31,						Nine Months Ended December 31,
			2003			2002			2003			2002
Diluted
Net loss			$	(521,546	)	$	(1,704,095	)	$	(2,199,050	)	$	(3,177,595	)
Effect of dilutive securities:
Convertible debentures	(1)		—			—			—			—
Net loss and assumed conversion			$	(521,546	)	$	(1,704,095	)	$	(2,199,050	)	$	(3,177,595	)
Weighted average shares:
Outstanding			22,203,194			16,142,024			21,983,730			16,078,277
Options	(1)		—			—			—			—
Convertible debentures	(1)		—			—			—			—
			22,203,194			16,142,024			21,983,730			16,078,277
Loss per share			$	(0.02	)	$	(0.11	)	$	(0.10	)	$	(0.20	)

 

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(1)          Employee stock options to purchase 2,310,000 shares and 6,500,000 shares from convertible debentures were not included in the computation of diluted loss per share for the three and nine months ended December 31, 2003, because we reported a loss.  Options to purchase 1,975,000 shares and 6,500,000 shares from convertible debentures were not included in the computation of diluted earnings per share for the three and nine months ended December 31, 2002, because we reported a loss.

 

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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

 

We provide land contract drilling services to independent and major oil and gas operators drilling wells primarily in South, East and North Texas.  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.

 

Over the past four fiscal years, we have significantly expanded our fleet of drilling rigs through acquisitions and the construction of new and refurbished rigs.  As of December 31, 2003, our rig fleet consisted of 28 land drilling rigs that drill in depth ranges between 8,000 and 18,000 feet.  We actively market 27 of these rigs, while one is idled or “cold stacked.”

 

We are continuing to pursue opportunities to expand our rig fleet.  We have agreed to acquire a seven-rig drilling fleet in a transaction which we expect to close in early March 2004, subject to obtaining satisfactory financing.  Closing this transaction would increase our fleet to 35 rigs, of which 34 would be actively marketed.

 

We earn our revenues by drilling oil and gas wells and use the percentage-of-completion method to record revenues and costs.  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 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 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 nine-month periods ended December 31, 2003 and 2002, our rig utilization and revenue days were as follows:

 

		Three Months Ended December 31,				Nine Months Ended December 31,
		2003		2002		2003		2002
Utilization Rates		88	%	76	%	87	%	78	%
Revenue Days		2,246		1,579		6,268		4,609

 

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The reasons for the increase in the number of revenue days in 2003 over 2002 are the increase in size of our rig fleet from 24 at December 31, 2002 to 28 at December 31, 2003 and the improvement in our overall rig utilization rate.

 

In recent periods, we have maintained rig utilization rates above many of our competitors.  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.  Turnkey contracts account for approximately one-fourth of our contracts; therefore, a higher percentage of our revenues are derived from turnkey contracts than many of our competitors.  Turnkey contracts provide us with the opportunity to improve our drilling margin, but at an increased risk.  Over the long term, turnkey margins per revenue day are greater than daywork margins; however, occasionally, a turnkey will not be profitable if the contract cannot be completed successfully without unanticipated complications.  In December 2003, we encountered problems with a turnkey well on which we lost approximately $250,000 rather than realizing a projected profit of approximately $118,000, which affected our daily margin for the quarter and year to date.

 

We devote substantial resources to maintaining and upgrading our rig fleet.  In December 2003, we removed two rigs from service for approximately three weeks each, in order to perform upgrades.  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.

 

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.

 

Oil prices are currently in the $32.00 to $35.00 per barrel range, and natural gas prices are currently in the $5.00 to $7.00 per mmbtu range.  The average weekly spot prices of crude oil and natural gas and the average weekly domestic land rig count for each of the previous six years ended December 31, 2003 were:

 

		2003			2002			2001			2000			1999			1998
Oil (West Texas Intermediate)		$	31.22		$	26.20		$	26.08		$	29.83		$	19.71		$	14.43
Gas (Henry Hub)		$	5.43		$	3.33		$	3.90		$	4.28		$	2.29		$	2.06
U.S. Land Rig Count		906			700			981			747			512			685

 

The decline in oil and natural gas prices from mid-2001 to mid-2002 resulted in a reduction in the demand for contract land drilling services, which resulted in a substantial reduction in the rates land drilling companies have been able to obtain for their services.  While oil and natural gas prices have recovered in recent months, drilling activity has not yet recovered to a level at which we are able to significantly improve our revenue rates and drilling margins. The Baker Hughes domestic land rig count of rigs under contract was 1,003 on January 16, 2004, a 41% increase from 713 on January 17, 2003.

 

During fiscal 2003 and the first nine months of fiscal 2004, 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

 

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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, because 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.

 

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 and operating overhead allocations.   We record provisions for estimated losses on uncompleted contracts in the period in which such losses are determined.  Changes in job performance, job conditions and estimated profitability may result in revisions to costs and income and are recognized in the period in which we determine the revisions.  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.

 

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  that could trigger an impairment review would be our customers’ financial condition and any significant negative industry or economic trends.  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.

 

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 8 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 subsequent to the release of the financial statements.  Revenues and costs during a reporting period could be affected for contracts in progress at the end of that reporting period which have not been completed before our financial statements for that period are released.  Turnkey contract revenues we had accrued in “Contract Drilling in Progress” at December 31, 2003 were approximately $2,293,000.  We had six turnkey contracts in progress at December 31, 2003 and all were completed prior to the release of these financial statements.

 

We estimate an allowance for doubtful accounts based on the creditworthiness of our customers as well as general economic conditions.  Consequently, an adverse change in those factors could affect our estimate of our allowance for doubtful accounts.

 

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.

 

Our financial statements include accruals for costs incurred under the $100,000 self-insurance portion of our health insurance, the $250,000 deductible under our workers’ compensation insurance and the $100,000 deductible under our general liability insurance.  These accruals of approximately $713,000 at December 31, 2003

 

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are based on information provided by the insurance companies and our historical experience with these types of insurance costs.

 

Liquidity and Capital Resources

 

Our rig fleet has grown from 8 rigs in August 2000 to 28 as of December 31, 2003.  We have financed this growth with a combination of debt and equity financing.  We have raised additional equity or used equity for growth five times since January 2000 and have increased our long-term debt from approximately $3,909,000 at June 30, 2000 to approximately $47,600,000 at December 31, 2003.  We plan to continue to grow our rig fleet.  We believe that near-term growth will require the use of equity financing rather than additional debt.  At December 31, 2003, our debt to capital ratio was approximately 1:1.  Due to the volatility in our industry, we are reluctant to take on substantial additional debt at this time.  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.

 

We have agreed to acquire a seven-rig drilling fleet for $12,000,000 in a transaction which we expect to close in early March 2004, subject to our obtaining satisfactory financing.  We also plan to acquire 23 used rig hauling trucks and associated trailers and equipment for $1,200,000.  In December 2003, we purchased for approximately $3,750,000 a rig we had previously leased.  We paid $1,000,000 of the purchase price in December, and the balance of the purchase price is included in accounts payable at December 31, 2003.  We are financing this rig purchase primarily with a $3,000,000 bank loan.  We borrowed the first $1,000,000 of the $3,000,000 bank loan in December to make the down payment on this rig.

 

We are also in the process of accumulating primarily used components for the construction of a 1000-hp electric drilling rig.  As of December 31, 2003, we have incurred approximately $1,900,000 of construction costs.  We anticipate additional construction costs of $2,100,000 to $2,600,000; however, we do not have a scheduled completion date at this time.  When funds are available, we plan to reactivate and upgrade our cold stacked rig at a cost of approximately $2,500,000.

 

Since March 31, 2003, the additions to our property and equipment were $25,058,683.  Additions consisted of the following:

 

Drilling rigs (1)		$	19,170,016
Other drilling equipment		5,283,469
Transportation equipment		542,596
Other		62,602
		$	25,058,683

 

(1) Includes capitalized interest costs of $78,163.

 

In May 2003, we added one refurbished 18,000-foot SCR land drilling rig at a cost of approximately $7,000,000.  On August 1, 2003, we purchased two land drilling rigs, associated spare parts and equipment and vehicles from Texas Interstate Drilling Company, L. P. for $2,500,000 in cash and the issuance of 477,000 shares of our common stock at $4.45 per share.  On August 26, 2003, we purchased a 14,000-foot mechanical rig for $2,925,661 in cash.  Since accepting delivery of the rig, we have spent approximately $2,400,000 preparing the rig for utilization.

 

Our working capital decreased to ($3,420,072) at December 31, 2003 from $11,144,309 at March 31, 2003.  Our current ratio, which we calculate by dividing our current assets by our current liabilities, was 0.85 at December 31, 2003 compared to 1.55 at March 31, 2003.  The principal reason for the decrease in our working capital at December 31, 2003 was our use of approximately $19,200,000 of working capital toward the purchase of five drilling rigs, the partial construction of a sixth rig, and approximately $1,700,000 for the purchase of spare equipment and  upgrades to other rigs.  We used substantially all the $20,000,000 proceeds from the shares of common stock we sold Chesapeake Energy Corporation on March 31, 2003 to expand our rig fleet or reduce debt we incurred to expand our rig fleet.  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 of $2,500,000 should allow us to meet our routine financial obligations.

 

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

 

		December 31, 2003			March 31, 2003			Change
Cash and cash equivalents		$	2,829,960		$	21,002,913		$	(18,172,953	)
Receivables		14,886,860			8,928,923			5,957,937
Income tax receivable		—			444,900			(444,900		)
Deferred tax receivable		132,031			180,991			(48,960		)
Prepaid expenses		1,620,711			914,187			706,524
Current assets		19,469,562			31,471,914			(12,002,352		)
Current debt		4,499,854			3,399,163			1,100,691
Accounts payable		14,071,461			14,206,586			(135,125		)
Accrued expenses		4,318,319			2,721,856			1,596,463
Current liabilities		22,889,634			20,327,605			2,562,029
Working capital (deficit)		$	(3,420,072	)	$	11,144,309		$	(14,564,381	)

 

The increase in our receivables at December 31, 2003 from March 31, 2003 was due to our operating four additional rigs in the quarter ended December 31, 2003 and the holiday period at the end of the period and not a  result of any significant change in our collection of receivables.  By the end of January 2004, we had collected over 85% of the approximately $11,200,000 of receivables outstanding at December 31, 2003.

 

Substantially all our prepaid expenses at December 31, 2003 consisted of prepaid insurance.  We renew and pay our insurance premium in late October of each year.  At December 31, 2003, we had only amortized two months of the premiums, compared to five months of amortization as of March 31, 2003.

 

Of the total increase in accrued expenses at December 31, 2003 from March 31, 2003, accrued payroll cost accounted for approximately $963,000 (16 days compared to 7 days of accrual), accrued interest on our subordinated debt accounted for approximately $472,000 (6 months compared to 3 months of accrual), and accrued property taxes accounted for the balance (12 months compared to 3 months of accrual).

 

Our long-term debt at December 31, 2003 consisted of the following:

 

Convertible subordinated debentures due July 2007 at 6.75% (1)		$	28,000,000
Note payable to Merrill Lynch Capital, secured by drilling equipment, due in monthly payments of $172,619 plus interest at a floating rate equal to the 3-month LIBOR rate plus 385 basis points, due December 2007		13,636,905
Note payable to Frost National Bank, secured by drilling equipment, due in monthly payments of $107,143 plus interest at prime (4.0% at December 31, 2003) plus 1.00%, due August 2007		4,713,603
Note payable to Frost National Bank, secured by drilling equipment, due in monthly payments of $42,401, including interest at prime plus 1%, beginning April 15, 2004, due March 15, 2007 (2)		1,000,000
Capital lease obligations		282,539
		$	47,633,047

 

(1)          Wedge Energy Services, LLC (WEDGE) holds $27,000,000 of the convertible subordinated debentures and Bill White, a director of our company, holds $1,000,000.  WEDGE owns 32.6% of our common stock

 

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(47.4% if the debentures were converted).  Beginning July 3, 2004, we have the option to redeem all or part of the debentures by paying a premium of 5% through July 2, 2005, 4% through July 2, 2006, 3% through July 2, 2007 and 0% thereafter.

 

(2)          This loan is being used to finance the purchase of the rig we were previously leasing.  The loan is for $3,000,000.  We anticipate drawing the remaining $2,000,000 by early March.

 

Our current long-term debt, capital lease and operating lease obligations in the years subsequent to December 31, 2003 are as follows:

 

		Long-term Debt			Capital Leases			Operating Leases
2004		$	3,464,286		$	145,598		$	112,008
2005		3,500,000			90,516			111,009
2006		3,500,000			45,437			51,537
2007		36,886,222			988			678
		$	47,350,508		$	282,539		$	275,232

 

Borrowings from Frost National Bank and Merrill Lynch Capital, a division of Merrill Lynch Business Financial Services, Inc. (“MLC”), contain various covenants pertaining to leverage, cash flow coverage, fixed charge coverage and net worth ratios and restrict us from paying dividends.  Under these credit arrangements, we determine compliance with the ratios on a quarterly basis based on the previous four quarters.  As of December 31, 2003, we were in compliance with all covenants applicable to our outstanding debt.

 

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

 

•                  our failure to make required payments;

 

•                  our failure to comply with financial covenants;

 

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

 

•                  any payment of cash dividends on our common stock.

 

We have a $2,500,000 line of credit available from Frost National Bank.  Any borrowings under this line of credit are secured by our trade receivables and bear interest at a rate of prime (4.00% at December 31, 2003) 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 are limited to 75% of eligible accounts receivable.  Therefore, if 75% of our eligible accounts receivable is 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 December 31, 2003, we had no outstanding advances under this line of credit, letters of credit were $1,684,000 and 75% of eligible accounts receivable was approximately $8,153,000.  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.

 

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 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 margins.

 

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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.

 

We have a history of losses.  We incurred net losses of approximately $5,100,000, $400,000 and $1,600,000 in the fiscal years ended March 31, 2003, 2000 and 1999, respectively, and incurred a net loss of approximately $2,200,000 for the nine months ended December 31, 2003.  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 to primarily daywork contracts.

 

For the three-month and nine-month periods ended December 31, 2003 and 2002, the percentages of our drilling revenues by type of contract were as follows:

 

		Three Months Ended December 31,				Nine Months Ended December 31,
		2003		2002		2003		2002
Daywork Contracts		55	%	38	%	49	%	48	%
Turnkey Contracts		40	%	60	%	47	%	50	%
Footage Contracts		5	%	2	%	4	%	2	%

 

While current demand for drilling rigs has increased, we continue to bid on turnkey contracts in an effort to improve margins and maintain rig utilization.  In spite of improvements in oil and natural gas prices, we anticipate only a moderate change in the mix of our types of contracts in the near future.

 

Our drilling margins, which we compute by subtracting contract drilling costs from contract drilling revenues, margin percentages, which we compute by dividing the drilling margin by contract drilling revenues, and drilling margin per revenue day, which we compute by dividing the drilling margin by revenue days, for the three- month and nine-month periods ended December 31, 2003 and 2002 were:

 

		Three Months Ended December 31,						Nine Months Ended December 31,
		2003			2002			2003			2002
Contract drilling revenues		$	26,414,362		$	19,795,727		$	74,508,827		$	55,289,179
Contract drilling costs		21,599,719			18,076,564			61,757,266			47,918,096
Drilling margin		$	4,814,643		$	1,719,163		$	12,751,561		$	7,371,083
Drilling margin percent		18		%	8		%	17		%	13		%
Drilling margin per revenue day		$	2,144		$	1,089		$	2,034		$	1,599

 

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The drilling margin percentage increase in the three-month period ended December 31, 2003 compared with the same period in 2002 primarily resulted from increases in rig revenue rates we charged under our drilling contracts.  The additional costs associated with turnkey contracts account for the substantial increase in our drilling costs in the three-month and the nine-month periods ended December 31, 2003 and 2002.  These additional costs negatively affect our margin percentage in periods in which turnkey contracts make up a higher percentage of our revenues.

 

Drilling margin per revenue day is a measure of profitability from drilling operations, before taxes, depreciation, general and administrative expenses and other income (expense), for each day a rig is earning revenue.  Rigs earn revenue while moving, drilling, waiting on standby or cleaning up at the end of a contract.  We believe drilling margin per revenue day is a good measure to compare our drilling operations from year to year as well as against competitors in our peer group.  Drilling margin per revenue day rose in the quarter and the nine-month period ended December 31, 2003 compared to the same periods in 2002 due to the increased dayrate environment we experienced in the quarter and the nine-month period ended December 31, 2003.

 

Our depreciation and amortization expense in the quarter ended December 31, 2003 increased to approximately $4,119,000 from approximately $3,006,000 in the quarter ended December 31, 2002.  Our depreciation and amortization expense in the nine months ended December 31, 2003 increased to approximately $11,671,000 from approximately $8,522,000 in the corresponding period of 2002.  These increases resulted from our purchase of five drilling rigs and related equipment since December 31, 2002.

 

Our general and administrative expenses increased to approximately $687,000 in the quarter ended December 31, 2003 from approximately $553,000 in the quarter ended December 31, 2002.  Our general and administrative expenses increased to approximately $2,027,000 in the nine months ended December 31, 2003 from approximately $1,678,000 in the corresponding period of 2002.  The increases resulted from increased payroll costs, employment fees, loan fees and insurance costs.  In the nine-month period, payroll cost increased by approximately $223,000 due to pay raises and the increase from 12 to 15 employees in our corporate office.  Employment and loan fees increased by $55,000 in the nine-month period due to the employee additions and fees associated with the Merrill Lynch Capital loan.  In addition, our directors and officers liability insurance increased by approximately $45,000 in the nine-month period.

 

Our contract land drilling operations are subject to various federal and state laws and regulations designed to protect the environment.  Maintaining compliance with these regulations is part of our day-to-day operating procedures.  We are not aware of any potential clean-up obligations that would have a material adverse effect on our financial condition or results of operations.

 

Our effective income tax benefit rates of 18% and 31% for the three-month periods ended December 31, 2003 and 2002 and 24% and 30% for the nine-month periods ended December 31, 2003 and 2002, respectively, differ from the federal statutory rate of 34% due to permanent differences.  Permanent differences are costs included in results of operations in the accompanying financial statements which are not fully deductible for federal income tax purposes.

 

Inflation

 

As a result of the relatively low levels of inflation during the past two years, inflation did not significantly affect our results of operations in any of the periods reported.

 

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ITEM 3.                             QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

 

We are subject to market risk exposure related to changes in interest rates on some of our outstanding debt.  At December 31, 2003, we had outstanding debt of approximately $19,351,000 that was subject to variable interest rates, in each case based on an agreed percentage-point spread from the lender’s prime interest rate.  An increase or decrease of 1% in the interest rate would have a corresponding decrease or increase in our net income of approximately $128,000 annually.  We did not enter into these 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 December 31, 2003 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 December 31, 2003 that has materially affected, or is reasonably likely to materially affect, our internal controls over financial reporting.

 

PART II.  OTHER INFORMATION

 

ITEM 6.                             EXHIBITS AND REPORTS ON FORM 8-K

 

(a) 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. 001-08182, 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. 001-08182, Exhibit 3.1)).
3.3		-		Amended and Restated Bylaws of Pioneer Drilling Company.
4.1		-		Amended and Restated Loan Agreement dated December 15, 2003, between Pioneer Drilling Services, Ltd., Pioneer Drilling Company and The Frost National Bank.
4.2		-		First Amendment to Amended and Restated Loan Agreement dated January 29, 2004 between Pioneer Drilling Services, Ltd., Pioneer Drilling Company and The Frost National Bank.
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.

 

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32.2

-

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

 

*                                         Incorporated herein by reference as indicated.

 

(b)                                 Reports on Form 8-K.                              On November 6, 2003, we furnished a current report on Form 8-K relating to the press release we issued on November 6, 2003 with respect to our results of operations for the second quarter (ended September 30, 2003) of our fiscal year ending March 31, 2004.

 

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 5, 2004

 

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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. 001-08182, 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. 001-08182, Exhibit 3.1)).
3.3		-		Amended and Restated Bylaws of Pioneer Drilling Company.
4.1		-		Amended and Restated Loan Agreement dated December 15, 2003, between Pioneer Drilling Services, Ltd., Pioneer Drilling Company and The Frost National Bank.
4.2		-		First Amendment to Amended and Restated Loan Agreement dated January 29, 2004 between Pioneer Drilling Services, Ltd., Pioneer Drilling Company and The Frost National Bank.
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 reference as indicated.

 

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