UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

 

FORM 10-Q

 

 

PIONEER DRILLING COMPANY

(Exact name of registrant as specified in its charter)

 

 

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.

 

 

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

 

As of August 7, 2003, there were 22,197,792 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)
		June 30, 2003			March 31, 2003
ASSETS
Current assets:
Cash and cash equivalents		$	15,213,499		$	21,002,913
Receivables, net		7,582,521			4,499,378
Contract drilling in progress		4,038,041			4,429,545
Federal income tax receivable		—			444,900
Current deferred income taxes		129,821			180,991
Prepaid expenses		754,051			914,187
Total current assets		27,717,933			31,471,914
Property and equipment, at cost		116,052,239			110,223,230
Less accumulated depreciation and depletion		25,303,413			22,367,327
Net property and equipment		90,748,826			87,855,903
Other assets		358,743			366,500
Total assets		$	118,825,502		$	119,694,317
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities:
Notes payable		$	235,704		$	587,177
Current installments of long-term debt and capital lease obligations		3,329,181			2,811,986
Accounts payable		13,935,675			14,206,586
Accrued payroll		1,285,954			847,163
Prepaid drilling contracts		127,500			—
Accrued expenses		2,433,745			1,874,693
Total current liabilities		21,347,759			20,327,605
Long-term debt and capital lease obligations, less current installments		44,892,176			45,854,542
Deferred income taxes		5,924,606			5,839,908
Total liabilities		72,164,541			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; 21,720,792 and 21,700,792 shares issued at June 30, 2003 and March 31, 2003, respectively		2,172,079			2,170,079
Additional paid-in capital		57,773,188			57,730,188
Accumulated deficit		(13,284,306		)	(12,228,005		)
Total shareholders’ equity		46,660,961			47,672,262
Total liabilities and shareholders’ equity		$	118,825,502		$	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 June 30,
		2003			2002
Revenues:
Contract drilling		$	23,850,083		$	18,451,855
Other		8,947			11,940
Total operating revenues		23,859,030			18,463,795
Costs and expenses:
Contract drilling		20,366,406			15,102,980
Depreciation and amortization		3,624,181			2,688,281
General and administrative		648,248			507,885
Total operating costs and expenses		24,638,835			18,299,146
Earnings (loss) from operations		(779,805		)	164,649
Other income (expense):
Interest expense		(733,655		)	(559,790		)
Interest income		47,690			23,551
Gain on sale of marketable securities		—			203,887
Total other income (expense)		(685,965		)	(332,352		)
Loss before income taxes		(1,465,770		)	(167,703		)
Income tax benefit (expense)		409,469			(3,898		)
Net Loss		$	(1,056,301	)	$	(171,601	)
Loss per common share - Basic		$	(0.05	)	$	(0.01	)
Loss per common share - Diluted		$	(0.05	)	$	(0.01	)
Weighted average number of shares outstanding - Basic		21,707,935			15,953,997
Weighted average number of shares outstanding - Diluted		21,707,935			15,953,997

 

See accompanying notes to condensed consolidated financial statements.

 

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PIONEER DRILLING COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

 

(Unaudited)

 

		Three Months Ended June 30,
		2003			2002
Cash flows from operating activities:
Net loss		$	(1,056,301	)	$	(171,601	)
Adjustments to reconcile net loss to net cash provided by (used in) operating activities:
Depreciation and amortization		3,624,181			2,688,281
Gain on sales of marketable securities		—			(203,887		)
Loss (gain) on sale of properties and equipment		199,269			(7,633		)
Change in deferred income taxes		135,868			789,792
Changes in current assets and liabilities:
Receivables		(3,083,143		)	152,529
Contract drilling in progress		391,504			514,991
Prepaid expenses		160,136			121,537
Accounts payable		(270,911		)	1,073,280
Prepaid drilling contracts		127,500			—
Federal income taxes		444,900			350,733
Accrued expenses		997,843			79,317
Net cash provided by operating activities		1,670,846			5,387,339
Cash flows from financing activities:
Proceeds from notes payable		—			7,072,080
Payments of debt		(796,644		)	(765,029		)
Decrease in other assets		(2,716		)	(34,642		)
Proceeds from exercise of options		45,000			94,490
Net cash provided by (used in) financing activities		(754,360		)	6,366,899
Cash flows from investing activities:
Purchase of property and equipment		(6,929,550		)	(10,027,526		)
Marketable securities sold		—			375,414
Proceeds from sale of property and equipment		223,650			116,563
Net cash used in investing activities		(6,705,900		)	(9,535,549		)
Net increase (decrease) in cash		(5,789,414		)	2,218,689
Beginning cash and cash equivalents		21,002,913			5,383,045
Ending cash and cash equivalents		$	15,213,499		$	7,601,734
Supplementary Disclosure:
Interest paid		$	265,139		$	873,880
Income taxes refunded		(990,237		)	(1,139,517		)

 

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

 

		Three Months Ended June 30,
		2003			2002
Net loss-as reported		$	(1,056,301	)	$	(171,601	)
Deduct: Total stock-based employee compensation expense determined under fair value based method for all awards net of related tax effect		(96,522		)	(125,187		)
Net loss-pro forma		$	(1,152,823	)	$	(296,788	)
Net loss per share-as reported-basic		$	(0.05	)	$	(0.01	)
Net loss per share-as reported-diluted		(0.05		)	(0.01		)
Net loss per share-pro forma-basic		(0.05		)	(0.02		)
Net loss per share-pro forma-diluted		(0.05		)	(0.02		)
Weighted-average fair value of options granted during the year		$	3.85		$	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 68% and 69% and weighted average risk-free interest rates of  2.9% and 3.2% for grants in 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.

 

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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.

 

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

 

On October 9, 2001, we issued a 6.75% five year $18,000,000 convertible subordinated debenture, Series A, to WEDGE Energy Services, L.L.C. (“WEDGE”). The debenture was convertible into 4,500,000 shares of common stock at $4.00 per share.  We used approximately $9,000,000 of the proceeds to complete the construction of two drilling rigs.  Approximately $6,000,000 was used to reduce a $12,000,000 credit facility.  The balance of the proceeds was used for drilling equipment and working capital.  On July 3, 2002, we issued an additional $10,000,000 of 6.75% convertible subordinated debt to WEDGE with an effective conversion rate of $5.00 per share.  The transaction was completed by an agreement between Pioneer and WEDGE under which WEDGE agreed to provide the additional $10,000,000 in financing and to cancel the previously issued debenture in the principal amount of $18,000,000 in exchange for $28,000,000 in new 6.75% convertible subordinated debentures.  The new debentures are convertible into 6.5 million shares of common stock at $4.31 per share, which is a pro rata blending of the $5.00 conversion rate of the new $10,000,000 financing and the $4.00 conversion rate of the $18,000,000 debenture being cancelled.  WEDGE funded $7,000,000 of the $10,000,000 on July 3, 2002 and $2,000,000 on July 29, 2002.  William H. White, one of our Directors and President of WEDGE, purchased the remaining $1,000,000 on July 29, 2002.  Unlike the cancelled debenture, which was not redeemable by Pioneer, the new debentures are redeemable at a scheduled premium.  We used $7,000,000 of the proceeds to pay down bank debt and used $3,000,000 for the purchase of drilling equipment.  If WEDGE were to convert the new debentures, it would own approximately 48.3% of our outstanding common stock.

 

We have a $1,000,000 line of credit available from a 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 June 30, 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 $1,000,000 plus any outstanding letters of credit issued by the bank on our behalf, our ability to draw under this line would be reduced.  At June 30, 2003, we had no outstanding advances under this line of credit, letters of credit were $1,450,000 and eligible accounts receivable were approximately $5,805,000.  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.

 

At June 30, 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.

 

Current notes payable at June 30, 2003 consists of a $235,704 insurance premium note due August 26, 2003, which bears interest at the rate of 2.8% per year.

 

3.  Commitments and Contingencies

 

On September 30, 2002, we signed an agreement to purchase a 14,000-foot mechanical drilling rig, located in Trinidad, for $3,150,000.  On October 7, 2002, we made a $315,000 deposit toward the purchase of this rig.  In March 2003, we signed an amended asset purchase agreement reducing the purchase price to $2,850,000 and made an additional $300,000 deposit.  We expect the rig to be delivered to the Port of Houston in August 2003.

 

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.

 

In addition, due to the nature of our business, we are, from time to time, involved in routine litigation or subject to disputes or claims related to our business activities, including workers’ compensation claims and

 

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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 March 31, 2003, we sold 5,333,333 shares of our common stock to Chesapeake Energy Corporation for $20,000,000 ($3.75 per share), before related offering expenses.  In connection with that sale, we granted Chesapeake Energy a preemptive right to acquire equity securities we may issue in the future, under specified circumstances, in order to permit Chesapeake Energy to maintain its proportionate ownership of our outstanding shares of common stock.  We also granted Chesapeake Energy a right, under certain circumstances, to request registration of the acquired shares under the Securities Act of 1933.

 

Directors and employees exercised stock options for the purchase of 20,000 and 215,000 shares of common stock at prices ranging from $.375 to $2.50 per share during the three months ended June 30, 2003 and June 30, 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 June 30,
		2003			2002
Basic
Net loss		$	(1,056,301	)	$	(171,601	)
Weighted average shares		21,707,935			15,953,997
Loss per share		$	(0.05	)	$	(0.01	)

 

		Three Months Ended June 30,
		2003			2002
Diluted
Net loss		$	(1,056,301	)	$	(171,601	)
Effect of dilutive securities:
Convertible debentures (1)		—			—
Net loss and assumed conversion		$	(1,056,301	)	$	(171,601	)
Weighted average shares:
Outstanding		21,707,935			15,953,997
Options (1)		—			—
Convertible debentures (1)		—			—
		21,707,935			15,953,997
Loss per share		$	(0.05	)	$	(0.01	)

 

(1) Employee stock options to purchase 1,941,000 shares and 6,500,000 shares from convertible debentures were not included in the computation of diluted loss per share for the three months ended June 30, 2003, because we reported a loss.  Options to purchase 2,120,000 shares and 4, 500,000 shares from convertible debentures were not included in the computation of diluted earnings per share for the three months ended June 30, 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.

 

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.

 

Beginning in 1998 and extending into 1999, the domestic contract land drilling industry was adversely affected by an extended period of low oil and gas prices and a domestic natural gas surplus. The price of West Texas Intermediate crude dropped to a low of $10.83 per barrel in December 1998 and the price of natural gas dropped to a low of $1.03 per mmbtu in December 1998. These conditions led to significant reductions in the overall level of domestic land drilling activity, resulting in a historically low domestic land rig count of 380 rigs on April 23, 1999. Prior to this industry downturn, during 1997, the contract land drilling industry experienced a significant level of drilling activity, with a domestic land rig count of 881 rigs on September 5, 1997.

 

Oil and natural gas prices rose sharply in calendar year 2000 and through mid-2001.  Natural gas prices began falling in mid-2001 to a low of approximately $2.00 per mmbtu before returning to current levels of between $4.50 and $5.50 per mmbtu.  Oil prices are currently in the $28.00 to $32.00 per barrel range.  The average weekly spot prices of natural gas and crude oil and the average weekly domestic land rig count for each of the previous six  years ended June 30, 2003 were:

 

		2003			2002			2001			2000			1999			1998
Oil (West Texas Intermediate)		$	29.96		$	23.88		$	30.08		$	26.08		$	14.45		$	17.60
Gas (Henry Hub)		$	4.81		$	2.73		$	5.40		$	2.83		$	1.97		$	2.41
U.S. Land Rig Count		778			821			930			621			517			802

 

Primarily as a result of the increase in oil and natural gas prices, exploration and production companies increased their capital spending budgets in 2000 and early 2001.  These increased spending budgets increased the demand for contract drilling services.  The domestic land rig count climbed to 1,095 on June 22, 2001, representing an increase in the domestic land rig count of 188% from the low of 380 in April 1999.  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 improve our revenue rates and drilling margins. The Baker Hughes domestic land rig count was 967 on July 25, 2003, a 38% increase from 702 on July 26, 2002.

 

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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.  See “Results of Operations” below for a general description of these contracts.  We recognize revenues on daywork contracts for the days completed based on the dayrate each contract specifies.  We recognize revenues from our turnkey and footage contracts on the percentage-of-completion method based on our estimate of the number of days to complete each contract.  Contract drilling in progress represents revenues we have recognized in excess of amounts billed on contracts in progress.  Individual contracts are usually completed in less than 60 days.  The risks to us under a turnkey contract, and to a lesser extent under footage contracts, are substantially greater than on a contract drilled on a daywork basis, 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 cost 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.  Changes in job performance, job conditions and estimated profitability on uncompleted contracts may result in revisions to costs and income, including losses, which we recognize 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 bases difference in our property and equipment between financial reporting and tax reporting purposes.  For property and equipment, bases 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 drilling rigs over 10 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 June 30, 2003 were approximately $3,215,000.  All of our turnkey contracts in progress at June 30, 2003 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.

 

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Our financial statements include accruals for costs incurred under the $100,000 self-insurance portion of our health insurance and the $250,000 deductible under our workers’ compensation insurance.  These accruals of approximately $696,000 at June 30, 2003 are based on information provided by the insurance companies and our historical experience with these types of insurance costs.

 

Liquidity and Capital Resources

 

On March 31, 2003, we sold 5,333,333 shares of our common stock to Chesapeake Energy Corporation for $20,000,000 ($3.75 per share), before related offering expenses.  In connection with that sale, we granted Chesapeake Energy a preemptive right to acquire equity securities we may issue in the future, under specified circumstances, in order to permit Chesapeake Energy to maintain its proportionate ownership of our outstanding shares of common stock.  We also granted Chesapeake Energy a right, under certain circumstances, to request registration of the acquired shares under the Securities Act of 1933.  Chesapeake Energy owns approximately 24.6% of our outstanding common stock, or approximately 17.7% assuming the conversion of all outstanding options and convertible subordinated debentures.

 

Our working capital decreased to $6,370,174 at June 30, 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 1.30 at June 30, 2003 compared to 1.55 at March 31, 2003.  The principal reason for the decrease in our working capital at June 30, 2003 was our use of approximately $4,900,000 of cash toward the purchase of a drilling rig in May 2003.

 

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

 

		June 30, 2003			March 31, 2003			Change
Cash and cash equivalents		$	15,213,499		$	21,002,913		$	(5,789,414	)
Receivables		11,620,562			8,928,923			2,691,639
Income tax receivable		—			444,900			(444,900		)
Deferred tax receivable		129,821			180,991			(51,170		)
Prepaid expenses		754,051			914,187			(160,136		)
Current assets		27,717,933			31,471,914			(3,753,981		)
Current debt		3,564,885			3,399,163			165,722
Accounts payable		13,935,675			14,206,586			(270,911		)
Accrued expenses		3,847,199			2,721,856			1,125,343
		21,347,759			20,327,605			1,020,154
Working capital		$	6,370,174		$	11,144,309		$	(4,774,135	)

 

Our cash flows from operating activities for the three months ended June 30, 2003 were $1,670,846, compared to $5,387,339 for the three months ended June 30, 2002.  Our cash flows from operating activities are affected by a number of factors, including rig utilization rates, the types of contracts we are performing, revenue rates we are able to obtain for our services, collection of receivables and the timing of expenditures.

 

Since March 31, 2003, the additions to our property and equipment were $6,929,550.  Additions consisted of the following:

 

Drilling rigs (1)		$	5,358,282
Other drilling equipment		1,417,538
Transportation equipment		145,451
Other		8,279
		$	6,929,550

 

(1) Includes capitalized interest costs of $10,855.

 

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On May 28, 2002, we purchased from United Drilling Company and U-D Holdings, L.P. two land drilling rigs, associated spare parts and vehicles for $7,000,000 in cash.  We financed the acquisition of those assets with a $7,000,000 loan from Frost National Bank.  Interest on the loan was payable monthly at prime.  The loan was collateralized by the assets that we purchased and a $7,000,000 letter of credit that WEDGE provided.  We repaid this loan on July 3, 2002 with $7,000,000 of the proceeds from the issuance of the subordinated debt as described below.

 

In November and December 2002 and May 2003, we added three refurbished 18,000-foot SCR land drilling rigs at a cost of approximately $7,000,000 each.  On September 30, 2002, we signed an agreement to purchase another 14,000-foot mechanical drilling rig, located in Trinidad, for $3,150,000.  On October 7, 2002, we made a $315,000 deposit toward the purchase of this rig.  In March 2003, we signed an amended asset purchase agreement reducing the purchase price for this rig to $2,850,000 and made an additional $300,000 deposit.  We expect this rig to be delivered to the Port of Houston in August 2003.

 

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.

 

Borrowings from Frost National Bank, on an installment loan due August 2004, and Merrill Lynch Capital, a division of Merrill Lynch Business Financial Services, Inc. (“MLC”), are secured by drilling equipment.  Our bank loan and MLC loan 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 June 30, 2003, we were in compliance with all covenants applicable to our outstanding debt.

 

On December 23, 2002, we borrowed $14,500,000 from MLC.  Under the terms of the MLC loan, we make monthly interest payments until August 1, 2003, when we begin making equal monthly installment payments of principal of $172,619, plus interest.  The unpaid balance of the MLC loan will be due at maturity on December 22, 2007.  Interest accrues at a floating rate, adjusted quarterly, equal to the three-month LIBOR rate plus 385 basis points until our election to convert the interest rate to a fixed rate, at which time interest will accrue at the greater of (1) 6.975%, or (2) the sum of the swap rate published on the Bloomberg Screen “USSW” on the conversion date plus 367 basis points.  The MLC loan is secured by a first priority security interest in certain of our drilling rigs.  We may prepay the MLC loan at any time in whole, but not in part, subject to certain exceptions and payment of specified prepayment premium requirements.  We used $2,130,503 of the proceeds of the Loan to retire all of our outstanding debt to one of our bank lenders, $5,106,321 to make a final payment on the new/refurbished, 18,000 foot rig added in December 2002, $7,190,676 to replenish our working capital and $72,500 to pay associated loan fees.

 

 On October 9, 2001, we issued a 6.75% five-year $18,000,000 convertible subordinated debenture, Series A, to WEDGE Energy Services, L.L.C. (“WEDGE”). The debenture was convertible into 4,500,000 shares of common stock at $4.00 per share.  We used approximately $9,000,000 of the proceeds to complete the construction of two drilling rigs.  Approximately $6,000,000 was used to reduce a $12,000,000 credit facility.  The balance of the proceeds was used for drilling equipment and working capital. On July 3, 2002, we issued an additional $10,000,000 of 6.75% convertible subordinated debt to WEDGE with an effective conversion rate of $5.00 per share.  The transaction was effected by an agreement between Pioneer and WEDGE under which WEDGE agreed to provide the additional $10,000,000 in financing and to cancel the previously issued debenture in the principal amount of $18,000,000 in exchange for $28,000,000 in new 6.75% convertible subordinated debentures.  The new debentures are convertible into 6,500,000 shares of common stock at $4.31 per share, which resulted from a pro rata blending of the $5.00 conversion rate of the new $10,000,000 financing and the $4.00 conversion rate of the $18,000,000 debenture being cancelled.  WEDGE funded $7,000,000 of the $10,000,000 on July 3, 2002 and $2,000,000 on July 29, 2002.  William H. White, one of our Directors and the President of WEDGE, purchased the remaining $1,000,000 on July 29, 2002.  Unlike the cancelled debenture, which was not redeemable by Pioneer, the new debentures are redeemable at a scheduled premium.  We used $7,000,000 of the proceeds to pay down bank debt and $3,000,000 for the purchase of drilling equipment.  If WEDGE were to convert the new debentures, it would own approximately 48.3% of our outstanding common stock.

 

We have a $1,000,000 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 June 30, 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

 

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account are limited to 75% of eligible accounts receivable.  Therefore, if 75% of our eligible accounts receivable is less than $1,000,000 plus any outstanding letters of credit issued by the bank on our behalf, our ability to draw under this line would be reduced.  At June 30, 2003, we had no outstanding advances under this line of credit, letters of credit were $1,450,000 and eligible accounts receivable were approximately $5,805,000.  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.

 

Our long-term debt, capital lease and operating lease obligations in the years subsequent to June 30, 2003 are as follows:

 

		Long-term Debt			Capital Leases			Operating Leases
2004		$	3,184,524		$	144,657		$	268,008
2005		6,142,175			138,054			58,008
2006		2,071,429			61,226			42,186
2007		30,071,429			20,957			2,034
2008		6,386,906			—			—
		$	47,856,463		$	364,894		$	370,236

 

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 any 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.

 

Results of Operations

 

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.

 

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.  Daywork drilling contracts specify the equipment to be used, the size of the hole and the depth of the well.  Under a daywork drilling contract, the customer bears a large portion of out-of-pocket costs of drilling and we generally bear no part of the usual risks associated with drilling, such as time delays and unanticipated costs.

 

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.  Turnkey contracts generally afford an opportunity to earn a higher return than would normally be available on daywork contracts if the contract can be completed successfully without complications.

 

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The risks to us under a turnkey contract are substantially greater than on a well 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.  We employ or contract for engineering expertise to analyze seismic, geologic and drilling data to identify and reduce some of the drilling risks assumed by us.  We use the results of this analysis to evaluate the risks of a proposed contract and seek to account for such risks in our bid preparation.  We believe that our operating experience, qualified drilling personnel, risk management program, internal engineering expertise and access to proficient third-party engineering contractors have allowed us to reduce some of the risks inherent in turnkey drilling operations. We also maintain insurance coverage against some but not all drilling hazards.  However, the occurrence of uninsured or under-insured losses or operating cost overruns on our turnkey jobs could have a material adverse effect on our financial position and results of operations.

 

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 the risks under a turnkey contract, the risks to us under a footage contract are greater because we assume most of the risks associated with drilling operations generally assumed by the operator in a daywork contract.  As with turnkey contracts, we manage these additional risks through the use of engineering expertise and bid the footage contracts accordingly, and we maintain insurance coverage against some but not all drilling hazards.  However, the occurrence of uninsured or under-insured losses or operating cost overruns on our footage jobs could have a material adverse effect on our financial position and results of operations.

 

For the three months ended June 30, 2003 and 2002, our rig utilization and revenue days were as follows:

 

		2003		2002
Utilization Rates		87	%	77	%
Revenue Days		1,958		1,453

 

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 22 at June 30, 2002 to 25 at June 30, 2003 and the improvement in the rig utilization rate.  The utilization rate is computed by dividing revenue days during a period by total available days during the period.

 

For the three months ended June 30, 2003 and 2002, the percentages of our drilling revenues by type of contract were as follows:

 

		2003		2002
Turnkey Contracts		56	%	45	%
Footage Contracts		3	%	2	%
Daywork Contracts		41	%	53	%

 

Due to the current reduced demand for drilling rigs, we have returned to bidding on turnkey contracts in an effort to improve margins and 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.

 

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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 months ended June 30, 2003 and 2002 were:

 

		2003			2002
Contract drilling revenues		$	23,850,083		$	18,451,855
Contract drilling costs		20,366,406			15,102,980
Drilling margin		$	3,483,677		$	3,348,875
Drilling margin percent		15		%	18		%
Drilling margin per revenue day		$	1,779		$	2,305

 

The drilling margin percentage decrease in 2003 from 2002 principally resulted from decreases 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 months ended June 30, 2003.  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.  Drilling margin per revenue day is a good index by which to compare our drilling operations from year to year as well as against competitors in our peer group.  Drilling margin per revenue day was down substantially in the three months ended June 30, 2003 compared to the three months ended June 30, 2002 due to the significantly lower dayrate environment we experienced in the three months ended June 30, 2003.

 

Our depreciation and amortization expense in the three months ended June 30, 2003 increased to approximately $3,624,000 from approximately $2,688,000 in the three months ended June 30, 2002.  The increase resulted from our addition of three drilling rigs and related equipment since June 30, 2002.

 

 Our general and administrative expenses increased to approximately $648,000 in the three months ended June 30, 2003 from approximately $508,000 in the three months ended June 30, 2002.  The increase resulted from increased payroll costs, legal and professional fees and investor relation costs.

 

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 expense rates of 27.9% and 2.3% for the three months ended June 30, 2003 and the three months ended June 30, 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.

 

Recent Accounting Pronouncements

 

In April 2003, the Financial Accounting Standards Board (the “FASB”) issued the Statement of Financial Accounting Standards (“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 Derivate 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), 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.  We do not expect the adoption of SFAS No. 149 to have a material effect on our financial position or results of operations.

 

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In May 2003, the FASB issued 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.  We do not expect the adoption of SFAS No. 150 to have a material effect on our financial position or results of operations.

 

Inflation

 

As a result of the relatively low levels of inflation during the past three years, inflation did not significantly affect our results of operations in any of our last three fiscal years.

 

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 June 30, 2003, we had outstanding debt of approximately $19,856,000 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 $131,000 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 June 30, 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 June 30, 2003 that has materially affected, or is reasonably likely to materially affect, our internal controls over financial reporting.

 

PART II.  OTHER INFORMATION

 

ITEM 1.                        LEGAL PROCEEDINGS

 

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.

 

ITEM 6.                        EXHIBITS AND REPORTS ON FORM 8-K

 

(a)

Exhibits

The following exhibits are filed as part of this report:

 

 

3.1*			Articles of Incorporation of Pioneer Drilling Company, as amended (Form 10-K for the year ended March 31, 2001 (File No. 2-70145, Exhibit 3.1)).
3.2*	-		Bylaws of Pioneer Drilling Company  (Form 10-K for the year ended March 31, 2001 (File No. 2-70145, Exhibit 3.2)).
4.1*	-		Common Stock Purchase Agreement dated March 31, 2003, between Pioneer Drilling Company and Chesapeake Energy Corporation (Form 8-K filed  March 31, 2003 (File No. 2-70145, Exhibit 4.1)).

 

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4.2*	-		Registration Rights Agreement dated March 31, 2003, among Pioneer Drilling Company, WEDGE Energy Services, L.L.C., William H. White, an individual, and Chesapeake Energy Corporation (Form 8-K filed March 31, 2003 (File No. 2-70145, Exhibit 4.2)).
31.1	-		Certification by Pioneer Drilling Company’s Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2	-		Certification by Pioneer Drilling Company’s Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.1	-		Certification by Pioneer Drilling Company’s Chief Executive Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
32.2	-		Certification by Pioneer Drilling Company’s Chief Financial Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

 

*              Incorporated by reference to the filing indicated.

 

(b)           Reports on Form 8-K.          On April 9, 2003, we filed a current report on Form 8-K, dated March 31, 2003, to report our sale of 5,333,333 shares of our common stock to Chesapeake Energy Corporation for $20,000,000.  We did not file any other current reports on Form 8-K during the three months ended June 30, 2003 covered by this report.

 

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/  Wm. Stacy Locke
	Wm. Stacy Locke
	President and Chief Financial Officer
	(Principal Financial Officer and Duly Authorized Representative)
Dated:   August 7, 2003

 

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