Item 3. 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 the pending litigation, disputes or claims against us will have a material adverse effect on our financial condition or results of operations.
Item 4.
Item 4. Submission of Matters to a Vote of Security Holders
We did not submit any matter to a vote of our security holders during the fourth quarter of fiscal 2005.
PART II
Item 5.
Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
As of May 20, 2005, 45,931,646 shares of our common stock were outstanding, held by approximately 561 shareholders of record. The number of record holders does not necessarily bear any relationship to the number of beneficial owners of our common stock.
Our common stock trades on the American Stock Exchange under the symbol “PDC.” The following table sets forth, for each of the periods indicated, the high and low sales prices per share on the American Stock Exchange:
The last reported sales price for our common stock on the American Stock Exchange on May 27, 2005 was $14.00 per share.
We have not paid or declared any dividends on our common stock and currently intend to retain earnings to fund our working capital needs and growth opportunities. Any future dividends will be at the discretion of our board of directors after taking into account various factors it deems relevant, including our financial condition and performance, cash needs, income tax consequences and the restrictions Texas and other applicable laws and our credit facilities then impose. Our debt arrangements include provisions that generally prohibit us from paying dividends, other than dividends on our preferred stock. We currently have no preferred stock outstanding.
Equity Compensation Plan Information
The following table provides information on our equity compensation plans as of March 31, 2005:
Recent Sales of Unregistered Securities
On August 11, 2004, the entire $28,000,000 in aggregate principal amount of our 6.75% convertible subordinated debentures held by WEDGE Energy Services, L.L.C. and William H. White was converted in accordance with the terms of those debentures into 6,496,519 shares of our common stock. We issued those shares without registration under the Securities Act of 1933 in reliance on the exemption that Section 4(2) of that Act provides for transactions not involving any public offering.
Item 6.
Item 6. Selected Financial Data
The following information derives from our audited financial statements. You should review this information in conjunction with “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in Item 7
Item 7 of this report and the historical financial statements and related notes this report contains.
Refer to Note 2 of the consolidated financial statements for information on acquisitions.
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations
Statements we make in the following discussion that express a belief, expectation or intention, as well as those which are not historical fact, are forward-looking statements that are subject to risks, uncertainties and assumptions. Our actual results, performance or achievements, or industry results, could differ materially from those we express in the following discussion as a result of a variety of factors, including general economic and business conditions and industry trends, the continued strength or weakness of the contract land drilling industry in the geographic areas in which we operate, decisions about onshore exploration and development projects to be made by oil and gas companies, the highly competitive nature of our business, our future financial performance, including availability, terms and deployment of capital, the continued availability of qualified personnel, and changes in, or our failure or inability to comply with, government regulations, including those relating to the environment.
Company Overview
Pioneer Drilling Company provides contract land drilling services to independent and major oil and gas exploration and production companies. In addition to our drilling rigs, we provide the drilling crews and most of the ancillary equipment needed to operate our drilling rigs. We have focused our operations in selected oil and natural gas production regions in the United States. Our company was incorporated in 1979 as the successor to a business that had been operating since 1968. We conduct our operations through our principal operating subsidiary, Pioneer Drilling Services, Ltd. We are an oil and gas services company. We do not invest in oil and natural gas properties. The drilling activity of our customers is highly dependent on the current price of oil and natural gas.
Our business strategy is to own and operate a high-quality fleet of land drilling rigs in active drilling markets, and position ourselves to maximize rig utilization and dayrates and to enhance shareholder value. We intend to continue making additions to our drilling fleet, either through acquisitions of businesses or selected assets or through the construction of new or refurbished drilling rigs.
Since September 1999, we have significantly expanded our fleet of drilling rigs through acquisitions and the construction of new and refurbished rigs. As of March 31, 2005 our rig fleet consisted of 50 land drilling rigs that drill in depth ranges between 6,000 and 18,000 feet. Fifteen of our rigs are operating in South Texas, 17 in East Texas, four in North Texas, five in western Oklahoma and nine in the Rocky Mountains. We actively market all of these rigs. We completed construction of our 50th rig in late March 2005 and began moving it to its first drilling location. We anticipate continued growth of our rig fleet in fiscal year 2006. We are currently constructing two 1000 horsepower electric rigs from new and used components.
We earn our revenues by drilling oil and gas wells for our customers. We obtain our contracts for drilling oil and gas wells either through competitive bidding or through direct negotiations with customers. Our drilling contracts generally provide for compensation on either a daywork, turnkey or footage basis. Contract terms generally depend on the complexity and risk of operations, the on-site drilling conditions, the type of equipment used and the anticipated duration of the work to be performed. Generally, our contracts provide for the drilling of a single well and typically permit the customer to terminate on short notice. However, we currently have thirteen contracts with terms of six months to two years in duration, including the contracts for the two rigs currently under construction.
A significant performance measurement in our industry is rig utilization. We compute rig utilization rates by dividing revenue days by total available days during a period. Total available days are the number of calendar days during the period that we have owned the rig. Revenue days for each rig are days when the rig is earning revenues under a contract, which is usually a period from the date the rig begins moving to the drilling location until the rig is released from the contract.
For the three years ended March 31, 2005, our rig utilization, revenue days and number of rigs were as follows:
The reasons for the increase in the number of revenue days in 2005 over 2004 and 2003 are the increase in size of our rig fleet and the improvement in our overall rig utilization rate due to improved market conditions. For 2006, we anticipate continued growth in revenue days and utilization rates comparable to 2005.
In addition to high commodity prices, we attribute our relatively high utilization rates to a strong sales effort, quality equipment, good field and operations personnel, a disciplined safety approach, and our generally successful performance of turnkey operations. Turnkey contracts currently account for approximately 12% of our contracts. Turnkey contracts provide us with the opportunity to keep our rigs working in periods of lower demand and improve our profitability, but at an increased risk. During periods of reduced demand for drilling
rigs, turnkey operating profit per revenue day has been greater than daywork operating profit; however, occasionally, a turnkey contract will be unprofitable if the contract cannot be completed successfully without unanticipated complications.
We devote substantial resources to maintaining and upgrading our rig fleet. During fiscal 2004, we removed three rigs from service for approximately three weeks each, 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. We are currently performing or have recently performed, between contracts or as necessary, safety and equipment upgrades to the eight rigs we acquired in March 2004 and the 12 rigs we acquired in November and December 2004.
Market Conditions in Our Industry
The United States contract land drilling services industry is highly cyclical. Volatility in oil and gas prices can produce wide swings in the levels of overall drilling activity in the markets we serve and affect the demand for our drilling services and the dayrates we can charge for our rigs. The availability of financing sources, past trends in oil and gas prices and the outlook for future oil and gas prices strongly influence the number of wells oil and gas exploration and production companies decide to drill.
For the three months ended March 31, 2005, the average weekly spot price for West Texas Intermediate crude oil was $49.87, the average weekly spot price for Henry Hub natural gas was $6.39 and the average weekly Baker Hughes land rig count was 1,153. On May 20, 2005, the spot price for West Texas Intermediate crude oil was $46.80, the spot price for Henry Hub natural gas was $6.36 and the Baker Hughes land rig count was 1,202, a 14% increase from 1,056 on May 21, 2004.
The average weekly spot prices of West Texas Intermediate crude oil and Henry Hub natural gas and the average weekly domestic land rig count, per the Baker Hughes land rig count, for each of the previous six years ended March 31, 2005 were:
During fiscal 2005, 2004 and 2003, substantially all the wells we drilled for our customers were drilled in search of natural gas because of the depth capacity of our rigs and the natural gas rich areas in which we operate. Although we have recently diversified our operations somewhat with the November 2004 acquisition of seven drilling rigs from Wolverine Drilling, with six of those rigs employed in search of oil in the Williston Basin of the Rocky Mountains, our customers remain primarily focused on drilling for natural gas. Natural gas reserves are typically found in deeper geological formations and generally require premium equipment and quality crews to drill the wells.
Critical Accounting Policies and Estimates
Revenue and cost recognition - We earn our revenues by drilling oil and gas wells for our customers under daywork, turnkey or footage contracts, which usually provide for the drilling of a single well. We recognize revenues on daywork contracts for the days completed based on the dayrate each contract specifies. We recognize revenues from our turnkey and footage contracts on the percentage-of-completion method based on our estimate of the number of days to complete each contract. Contract drilling in progress represents revenues we have recognized in excess of amounts billed on contracts in progress. Individual contracts are usually completed in less than 60 days. The risks to us under a turnkey contract, and to a lesser extent under footage contracts, are substantially greater than on a contract drilled on a daywork basis. Under a turnkey contract, we assume most of the risks associated with drilling operations that are generally assumed by the operator in a daywork contract, including the risks of blowout, loss of hole, stuck drill pipe, machinery breakdowns and abnormal drilling conditions, as well as risks associated with subcontractors’ services, supplies, cost escalations and personnel operations.
Our management has determined that it is appropriate to use the percentage-of-completion method as defined in SOP 81-1 to recognize revenue on our turnkey and footage contracts. Although our turnkey and footage contracts do not have express terms that provide us with rights to receive payment for the work that we perform prior to drilling wells to the agreed-on depth, we use this method because, as provided in applicable accounting literature, we believe we achieve a continuous sale for our work-in-progress and believe, under applicable state law, we ultimately could recover the fair value of our work-in-progress even in the event we were unable to drill to the agreed-on depth in breach of the applicable contract. However, in the event we were unable to drill to the agreed on depth in breach of the contract, ultimate recovery of that value would be subject to negotiations with the customer and the possibility of litigation.
If a customer defaults on its payment obligation to us under a turnkey or footage contract, we would need to rely on applicable law to enforce our lien rights, because our turnkey and footage contracts do not expressly grant to us a security interest in the work we have completed under the contract and we have no ownership rights in the work-in-progress or completed drilling work, except any rights arising
under the applicable lien statute on foreclosure. If we were unable to drill to the agreed on depth in breach of the contract, we also would need to rely on equitable remedies outside of the contract, including quantum meruit, available in applicable courts to recover the fair value of our work-in-progress under a turnkey or footage contract.
We accrue estimated contract costs on turnkey and footage contracts for each day of work completed based on our estimate of the total costs to complete the contract divided by our estimate of the number of days to complete the contract. Contract costs include labor, materials, supplies, repairs and maintenance, operating overhead allocations and allocations of depreciation and amortization expense. In addition, the occurrence of uninsured or under-insured losses or operating cost overruns on our turnkey and footage contracts could have a material adverse effect on our financial position and results of operations. Therefore, our actual results could differ significantly if our cost estimates are later revised from our original estimates for contracts in progress at the end of a reporting period which were not completed prior to the release of our financial statements.
Asset impairments - We assess the impairment of property and equipment whenever events or circumstances indicate that the carrying value may not be recoverable. Factors that we consider important and which could trigger an impairment review would be our customers’ financial condition and any significant negative industry or economic trends. More specifically, among other things, we consider our contract revenue rates, our rig utilizations rates, cash flows from our drilling rigs, current oil and gas prices, industry analysts’ outlook for the industry and their view of our customers’ access to debt or equity, discussions with major industry suppliers, discussions with officers of our primary lender regarding their experiences and expectations for oil and gas operators in our areas of operations and the trends in the price of used drilling equipment observed by our management. If a review of our drilling rigs indicates that our carrying value exceeds the estimated undiscounted future net cash flows, we are required under applicable accounting standards to write down the drilling equipment to its fair market value. A one percent write-down in the cost of our drilling equipment, at March 31, 2005, would have resulted in a corresponding decrease in our net earnings of approximately $1,427,000 for our fiscal year ended March 31, 2005.
Deferred taxes - We provide deferred taxes for net operating loss carryforwards and for the basis difference in our property and equipment between financial reporting and tax reporting purposes. For property and equipment, basis differences arise from differences in depreciation periods and methods and the value of assets acquired in a business acquisition where we acquire an entity rather than just its assets. For financial reporting purposes, we depreciate the various components of our drilling rigs over eight to 15 years and refurbishments over three years, while federal income tax rules require that we depreciate drilling rigs and refurbishments over five years. Therefore, in the first five years of our ownership of a drilling rig, our tax depreciation exceeds our financial reporting depreciation, resulting in our providing deferred taxes on this depreciation difference. After five years, financial reporting depreciation exceeds tax depreciation, and the deferred tax liability begins to reverse.
Accounting estimates - We consider the recognition of revenues and costs on turnkey and footage contracts critical accounting estimates. On these types of contracts, we are required to estimate the number of days it will require for us to complete the contract and our total cost to complete the contract. Our actual costs could substantially exceed our estimated costs if we encounter problems such as lost circulation, stuck drill pipe or an underground blowout on contracts still in progress subsequent to the release of the financial statements.
We receive payment under turnkey and footage contracts when we deliver to our customer a well completed to the depth specified in the contract, unless the customer authorizes us to drill to a shallower depth. Since 1995, when current management joined our company, we have completed all our turnkey or footage contracts. Although our initial cost estimates for turnkey and footage contracts do not include cost estimates for risks such as stuck drill pipe or loss of circulation, we believe that our experienced management team, our knowledge of geologic formations in our areas of operations, the condition of our drilling equipment and our experienced crews enable us to make reasonably dependable cost estimates and complete contracts according to our drilling plan. While we do bear the risk of loss for cost overruns and other events that are not specifically provided for in our initial cost estimates, our pricing of turnkey and footage contracts takes such risks into consideration. When we encounter, during the course of our drilling operations, conditions unforeseen in the preparation of our original cost estimate, we immediately increase our cost estimate to complete the contracts. If we anticipate a loss on a contract in progress at the end of a reporting period due to a change in our cost estimate, we immediately accrue the entire amount of the estimated loss including all costs that are included in our revised estimated cost to complete that contract in our consolidated statement of operations for that reporting period. During fiscal year 2005, we experienced losses on 17 of the 182 turnkey and footage contracts completed, with losses exceeding $25,000 on ten contracts and losses exceeding $100,000 on four contracts. We are more likely to encounter losses on turnkey and footage contracts in years in which revenue rates are lower for all types of contracts. During periods of reduced demand for drilling rigs, our overall profitability on turnkey and footage contracts has historically exceeded our profitability on daywork contracts.
Revenues and costs during a reporting period could be affected for contracts in progress at the end of a reporting period which have not been completed before our financial statements for that period are released. All of our turnkey contracts in progress at March 31, 2005 were completed prior to the release of the financial statements included in this report. At March 31, 2005 our contract drilling in progress totaled approximately $5,365,000. Of that amount accrued, turnkey and footage contract revenues were approximately $2,344,000. The remaining balance of approximately $3,021,000 relates to the revenue recognized but not yet billed on daywork contracts in progress at March 31, 2005. At March 31, 2004, drilling in progress totaled $9,131,000 of which $7,683,000 related to turnkey contracts and $1,488,000 related to daywork contracts.
We estimate an allowance for doubtful accounts based on the creditworthiness of our customers as well as general economic conditions. We evaluate the creditworthiness of our customers based on information obtained from major industry suppliers, current prices of oil and gas and any past experience we have with the customer. Consequently, an adverse change in those factors could affect our estimate of our allowance for doubtful accounts. In some instances, we require new customers to establish escrow accounts or make prepayments. We typically invoice our customers at 15-day intervals during the performance of daywork contracts and upon completion of the daywork contract. Turnkey and footage contracts are invoiced upon completion of the contract. Our typical contract provides for payment of invoices in 10 to 30 days. We generally do not extend payment terms beyond 30 days and have not extended payment terms beyond 60 days for any of our contracts in the last three fiscal years. We established an allowance for doubtful accounts of $352,000 at March 31, 2005, an increase of $242,000 from $110,000 at March 31, 2004.
Another critical estimate is our determination of the useful lives of our depreciable assets, which directly affects our determination of depreciation expense and deferred taxes. A decrease in the useful life of our drilling equipment would increase depreciation expense and reduce deferred taxes. We provide for depreciation of our drilling, transportation and other equipment on a straight-line method over useful lives that we have estimated and that range from three to 15 years. We record the same depreciation expense whether a rig is idle or working. Our estimates of the useful lives of our drilling, transportation and other equipment are based on our more than 35 years of experience in the drilling industry with similar equipment.
Our other accrued expenses as of March 31, 2005 include an accrual of approximately $1,334,000 for costs incurred under the self-insurance portion of our health insurance and under our workers’ compensation insurance. We have a deductible of (1) $100,000 per covered individual per year under the health insurance and (2) $250,000 per occurrence under our workers’ compensation insurance, except in North Dakota where the deductible is $100,000. We accrue for these costs as claims are incurred based on cost estimates established for each claim by the insurance companies providing the administrative services for processing the claims, including an estimate for incurred but not reported claims, estimates for claims paid directly by us, our estimate of the administrative costs associated with these claims and our historical experience with these types of claims. Management evaluates these cost estimates by the insurance companies based on historical claim information and adjusts the accrued claim costs if deemed necessary.
Liquidity and Capital Resources
Sources of Capital Resources
Our rig fleet has grown from eight rigs in August 2000 to 50 rigs as of March 31, 2005. We have financed this growth with a combination of debt and equity financing. We have raised additional equity or used equity for growth eight times since January 2000 and have increased our long-term debt from approximately $3,909,000 at June 30, 2000 to approximately $18,200,000 at March 31, 2005. We plan to continue to grow our rig fleet. At March 31, 2005, our total debt to total capital was approximately 7.6%. Due to the volatility in our industry, we are reluctant to take on substantial additional debt in excess of the $20,000,000 of remaining availability under our acquisition credit facility. However, our ability to continue funding our growth through the issuance of shares of our common stock is uncertain, as our common stock is not heavily traded and the market price for our common stock has been volatile in recent periods.
On February 20, 2004, we sold 4,400,000 shares of our common stock at $5.40 per share in a private placement to accredited investors for $23,760,000 in proceeds, before related offering expenses.
On August 11, 2004, the entire $28,000,000 in aggregate principal amount of our 6.75% convertible subordinated debentures held by WEDGE Energy Services, L.L.C. and William H. White was converted in accordance with the terms of those debentures into 6,496,519 shares of our common stock.
On August 11, 2004, we also sold 4,000,000 shares of our common stock at approximately $6.61 per share, net of underwriters’ commissions, pursuant to a public offering we registered with the SEC. On August 31, 2004, we sold 600,000 additional shares of our common stock at approximately $6.61 per share, net of underwriters’ commissions, pursuant to the underwriters’ exercise of an over-allotment option granted in connection with that public offering.
On March 22, 2005, we sold 6,945,000 shares of our common stock, including shares we sold pursuant to the underwriters’ exercise of an over-allotment option, at approximately $11.78 per share, net of underwriters’ commissions, pursuant to a public offering we registered with the SEC.
On October 29, 2004, we entered into a $47,000,000 credit facility with a group of lenders consisting of a $7,000,000 revolving line and letter of credit facility and a $40,000,000 acquisition facility for the acquisition of drilling rigs, rig transportation equipment and associated equipment. Frost National Bank is the administrative agent and lead arranger under the new credit facility, and the lenders include Frost National Bank, the Bank of Scotland and Zions First National Bank. Borrowings under the new credit facility bear interest at a rate equal to Frost National Bank’s prime rate (5.75% at March 31, 2005) and are secured by most of our assets, including all our drilling rigs, associated equipment and receivables. As described below, we borrowed the entire $40,000,000 available under the acquisition facility and we have used approximately $2,825,000 of availability under the revolving line and letter of credit facility through the issuance of letters of credit in the ordinary course of
business. On March 29, 2005, we repaid $20,000,000 of the borrowings under the acquisition facility. On May 11, 2005, the lenders agreed to an amendment to the acquisition facility to provide us with the ability to draw an additional $20,000,000 for future acquisitions. The remaining approximately $20,0000,000 and $4,175,000 of availability under the acquisition facility and the revolving line and letter of credit facility, respectively, should remain available to us until those facilities mature in October 2006 and October 2005, respectively.
Uses of Capital Resources
In late May 2004 and late December 2004, we completed constructing, primarily from used components, two 1000 horsepower electric drilling rigs, at a cost of approximately $5,000,000 and $6,500,000, respectively. In late March 2005, we completed the construction, primarily from used components, of a 1000 horsepower mechanical rig, at a cost of approximately $5,700,000.
In November 2004, we acquired a fleet of seven drilling rigs and related equipment from Wolverine Drilling, obtained noncompetition agreements from the two stockholders of Wolverine Drilling and purchased a 4.7-acre rig storage and maintenance yard in Kenmare, North Dakota for total consideration of $28,000,000 in cash. In December 2004, we acquired a fleet of five drilling rigs and related equipment and a 17-acre rig storage and maintenance yard located in Woodward, Oklahoma from Allen Drilling for total consideration of $7,200,000 in cash. We also obtained a noncompetition agreement from the President of Allen Drilling for additional consideration to be paid over the next five years. We funded the purchase price for each of these acquisitions with borrowings under our new credit facility aggregating $35,200,000.
We have also begun constructing, from new and used components, two 1000 horsepower electric rigs at an estimated cost of $6,500,000 each. We expect to place one of these rigs in service in June 2005 and the second in August 2005. As of March 31, 2005, we have incurred approximately $3,300,000 of construction costs on these rigs.
For fiscal year 2006, we project regular rig capital expenditures to be approximately $20,200,000, rig upgrade expenditures to be approximately $9,000,000, transportation equipment capital expenditures of approximately $2,900,000 and other capital expenditures of approximately $1,400,000. These capital expenditures are expected to be funded primarily from operating cash flow in excess of cash flow necessary to meet routine contractual obligations.
For the years ended March 31, 2005 and 2004, the additions to our property and equipment consisted of the following:
(1) Includes capitalized interest costs of $86,819 in 2005 and $106,395 in 2004.
Working Capital
Our working capital increased to $76,326,669 at March 31, 2005 from $6,028,018 at March 31, 2004. Our current ratio, which we calculate by dividing our current assets by our current liabilities, was 3.70 at March 31, 2005 compared to 1.27 at March 31, 2004. The principal reason for the increase in our working capital at March 31, 2005 was the approximately $61,300,000 in proceeds, after the payment of $20,000,000 of long-term debt, from the shares of common stock we sold in a public offering on March 22, 2005. Approximately $13,000,000 of the proceeds from that offering will be used for the construction of the two rigs described above. We anticipate that the remaining proceeds will be used for future rig and equipment acquisitions.
Our operations have historically generated sufficient cash flow to meet our requirements for debt service and equipment expenditures (excluding rig and other major equipment acquisitions). However, during periods when a higher percentage of our contracts are turnkey and footage contracts, our short-term working capital needs could increase. The significant improvement in operating cash flow for the year ended March 31, 2005 over March 31, 2004 is due primarily to the approximately $12,600,000 overall improvement in net earnings, components of which are discussed in “Results of Operations.” That improvement was net of approximately $6,900,000 in noncash depreciation and amortization expense. If necessary, we can defer rig upgrades to improve our cash position. We believe our cash generated by operations and our ability to borrow the currently unused portion of our line of credit and letter of credit facility of approximately $4,175,000, which takes into account reductions for approximately $2,825,000 of outstanding letters of credit as of March 31, 2005, should allow us to meet our routine financial obligations for the foreseeable future.
The changes in the components of our working capital were as follows:
The large cash balance at March 31, 2005 was due to our sale of shares of common stock on March 22, 2005 for net proceeds of approximately $81,300,000, of which $20,000,000 was used to reduce long-term debt and $61,300,000 was in the March 31, 2005 cash balance.
The increase in our receivables at March 31, 2005 from March 31, 2004 was due to our operating 15 additional rigs in the quarter ended March 31, 2005, and an improvement in utilization and revenue rates in the fourth quarter of fiscal year 2005 over fiscal year 2004.
Substantially all our prepaid expenses at March 31, 2005 consisted of prepaid insurance. The increase in prepaid insurance was primarily due to the increase in the size of our drilling rig fleet from 35 rigs at March 31, 2004 to 50 rigs at March 31, 2005.
The increase in payables at March 31, 2005 from March 31, 2004 was primarily due to the increase in the size of our drilling rig fleet.
The increase in accrued payroll was primarily due to the approximately 49% increase in our number of employees and the increase in the number of payroll days included in the accrual from nine days at March 31, 2004 to ten days at March 31, 2005.
The total increase in accrued expenses at March 31, 2005 from March 31, 2004 was due to an increase of approximately $685,000 in the accrual for our insurance deductibles and additional insurance premiums, an increase in bonus accruals of approximately $525,000, an increase in vacation pay accruals of approximately $101,000 and an increase in accrued property taxes of approximately $171,000 due to increases in rig valuations and the size of our rig fleet. These increases were offset by a decrease of approximately $127,000 in other accrued expense items.
Although, we have not been required to make income tax payments for the last three years, it is likely we will be in a current taxable position during fiscal year 2006 due to improving market conditions and the reversal of deferred tax liabilities.
Long-term Debt
Our long-term debt at March 31, 2005 and 2004 consisted of the following:
(1) Wedge Energy Services, LLC (“WEDGE”) held $27,000,000 of the convertible subordinated debentures and William H. White, a former director of our company, held $1,000,000 of the convertible subordinated debentures. The convertible subordinate debentures were converted into 6,496,519 shares of our common stock on August 11, 2004.
(2) These notes were repaid in August and September 2004 with proceeds from our August 2004 common stock offering.
Contractual Obligations
We do not have any routine purchase obligations. However, as of March 31, 2005, we were in the process of constructing two drilling rigs, as described above. The following table excludes interest payments on long-term debt and capital lease obligations. The following table includes all of our contractual obligations of the type specified below at March 31, 2005:
Debt Requirements
The $18,077,778 amount of indebtedness outstanding under the acquisition facility portion of our new credit facility is due in monthly installments of $388,889 plus interest, based on a 72-month amortization schedule, with all remaining unpaid principal being due on December 1, 2007. All the indebtedness under the acquisition facility bears interest at Frost National Bank’s prime rate (5.75% as of March 31, 2005).
The sum of (1) the draws under and (2) the amount of all outstanding letters of credit issued for our account under the revolving line and letter of credit facility portion of our new credit facility are limited to 75% of our eligible accounts receivable, not to exceed $7,000,000. Therefore, if 75% of our eligible accounts receivable was less than $7,000,000, our ability to draw under this line would be reduced. At March 31, 2005, we had no outstanding advances under this line of credit, outstanding letters of credit were $2,825,000 and 75% of our eligible accounts receivable was approximately $19,084,000. The letters of credit are issued to three workers’ compensation insurance companies to secure possible future claims under the deductibles on these policies. It is our practice to pay any amounts due under these deductibles as they are incurred. Therefore, we do not anticipate that the lenders will be required to fund any draws under these letters of credit. The termination date of the revolving line and letter of credit facility portion of our new credit facility is October 28, 2005.
Our new credit facility contains various covenants pertaining to a debt to total capitalization ratio, operating leverage ratio and fixed charge coverage ratio and restricts us from paying dividends. We determine compliance with the ratios on a quarterly basis, based on the previous four quarters. Events of default, which could trigger an early repayment requirement, include, among others:
• our failure to make required payments;
• any sale of assets by us not permitted by the credit facility;
• our failure to comply with financial covenants related to a debt to total capitalization ratio not to exceed 0.3 to 1, an operating leverage ratio not to exceed 3 to 1, and a fixed charge coverage ratio of not less than 1.5 to 1;
• our incurrence of additional indebtedness in excess of $3,000,000 not already allowed by the credit facility;
• any event which results in a change in the ownership of at least 40% of all classes of our outstanding capital stock; and
• any payment of cash dividends on our common stock.
The limitation on additional indebtedness described above has not affected our operations or liquidity and we do not expect it to affect our future operations or liquidity, as we expect to continue to generate adequate cash flow from operations to fund our anticipated working capital and other normal cash flow requirements.
Results of Operations
Our operations consist of drilling oil and gas wells for our customers under daywork, turnkey, or footage contracts usually on a well-to-well basis. Daywork contracts are the least complex for us to perform and involve the least risk. Turnkey contracts are the most difficult to perform and involve much greater risk but provide the opportunity for higher operating profits.
Daywork Contracts. Under daywork drilling contracts, we provide a drilling rig with required personnel to our customer, who supervises the drilling of the well. We are paid based on a negotiated fixed rate per day while the rig is used. During the mobilization period we typically earn a fixed amount of revenue based on the mobilization rate stated in the contract. We attempt to set the mobilization rate at an amount equal to our external costs for the move plus our internal costs during the mobilization period. We begin earning our contracted daywork rate when we begin drilling the well. Occasionally, in periods of increased demand, some of our contracts will provide for the trucking costs to be paid by the customer and we will receive a reduced dayrate during the mobilization period.
Turnkey Contracts. Under a turnkey contract, we agree to drill a well for our customer to a specified depth and under specified conditions for a fixed price, regardless of the time required or the problems encountered in drilling the well. We provide technical expertise and engineering services, as well as most of the equipment and drilling supplies required to drill the well. We often subcontract for related services, such as the provision of casing crews, cementing and well logging. Under typical turnkey drilling arrangements, we do not receive progress payments and are entitled to be paid by our customer only after we have performed the terms of the drilling contract in full. The risks under a turnkey contract are greater than those under a daywork contract, because under a turnkey contract we assume most of the risks associated with drilling operations that the operator generally assumes under a daywork contract.
Footage Contracts. Under footage contracts, we are paid a fixed amount for each foot drilled, regardless of the time required or the problems encountered in drilling the well. We typically pay more of the out-of-pocket costs associated with footage contracts as compared to daywork contracts. Similar to turnkey contracts, under a footage contract we assume most of the risks associated with drilling operations that the operator generally assumes under a daywork contract.
We have a history of losses. We incurred net losses of approximately $1,800,000, $5,100,000 and $400,000 in the fiscal years ended March 31, 2004, 2003 and 2000, respectively. Our profitability in the future will depend on many factors, but largely on utilization rates and dayrates for our drilling rigs.
The current demand for drilling rigs greatly influences the types of contracts we are able to obtain. As the demand for rigs increases, daywork rates move up and we are able to switch primarily to daywork contracts.
For the years ended March 31, 2005, 2004 and 2003, the percentages of our drilling revenues by type of contract were as follows:
While demand for drilling rigs has been increasing, we continue to bid on turnkey contracts in an effort to meet our customer demand and maintain rig utilization. With the improvements in daywork contract rates, we anticipate a gradual decline in the number of turnkey contracts. We had 6 turnkey contracts in progress at March 31, 2005 compared to 16 turnkey contracts in progress at March 31, 2004. We also had 6 footage contracts in progress at March 31, 2005 compared to none in progress at March 31, 2004.
In our years ended March 31, 2005 and 2004, we recognized revenues of approximately $4,885,000 and $924,000, respectively, and recorded contract drilling costs of approximately $3,263,000 and $745,000, respectively, excluding depreciation, on contracts with Chesapeake Energy Corporation. At March 31, 2005, Chesapeake owned 16.78% of our outstanding common stock.
Statements of Operations Analysis
The following table provides information about our operations for the years ended March 31, 2005, March 31, 2004, and March 31, 2003.
Our contract drilling revenues grew by approximately $77,000,000, or 72%, in fiscal year 2005 from fiscal year 2004, primarily due to the 59% increase in revenue days (approximately $63,000,000) and the approximately $1,000 increase in revenue per revenue day (approximately $14,000,000), which was attributable to improving market conditions in our industry.
Our contract drilling revenues grew by approximately $28,000,000, or 35%, in fiscal year 2004 from fiscal year 2003, primarily due to a 37% increase in revenue days, which was mostly attributable to the 22% increase in the average number of rigs in our rig fleet, and a 9% increase in rig utilization. The $183 per day decrease in average contract drilling revenue is due to the decrease in turnkey and footage revenue days as a percentage of total revenue days.
Our contract drilling costs in fiscal year 2005 grew by approximately $50,000,000, or 56%, primarily due to the increases in 2005 in revenue days and rig utilization referred to above. The $132 decrease in average cost per revenue day was primarily due to the greater increase in daywork revenue days (3,059 days) in fiscal 2005 over the increase in turnkey and footage revenue days (2,071). Under daywork contracts, our customer provides supplies and materials, such as fuel, drill bits, casing and drilling fluids, which we are required to provide under turnkey contracts.
Our contract drilling costs grew by approximately $18,000,000, or 25%, in fiscal year 2004 from fiscal year 2003 due to the increase in revenue days and rig utilization. The increase in daywork revenue days by 1,945 revenue days in fiscal year 2004 resulted in a $934 decrease in contract drilling costs per revenue day because costs associated with the drilling of daywork contracts is less than costs associated with turnkey and footage contracts which only increased by 400 revenue days in fiscal year 2004.
Our depreciation and amortization expense in 2005 increased by approximately $7,000,000, or 43%, from 2004. Depreciation and amortization expense in 2004 increased approximately $4,000,000, or 35%, from 2003. The increase in 2005 over 2004 resulted from our addition of 15 drilling rigs and related equipment in 2005. The increase in 2004 over 2003 resulted from our addition of 11 drilling rigs and related equipment during 2004.
Our general and administrative expenses increased by approximately $1,900,000, or 68%, in fiscal year 2005 from fiscal year 2004. The increase resulted from increased payroll costs, professional and consulting costs, insurance costs and director fees. Payroll related costs
increased by approximately $894,000 due to pay increases, staff additions and an approximately $610,000 increase in bonus costs. Professional and consulting costs increased approximately $587,000, with much of this increase due to the implementation of Sarbanes-Oxley compliance procedures. Director fees increased approximately $142,000. Insurance costs increased approximately $89,000, due to an increase in the cost of director and officer liability insurance coverage.
Our general and administrative expenses increased by approximately $541,000, or 24%, in fiscal year 2004 from fiscal year 2003. The increase resulted from increased payroll costs, employment fees, loan fees, insurance costs and director fees. In 2004, payroll costs increased by approximately $310,000 due to pay raises and the increase from 12 to 17 employees in our corporate office. Employment and loan fees increased by $61,000 due to the employee additions and fees associated with the Merrill Lynch Capital loan. In addition, our directors’ and officers’ liability and employment practices insurance increased by approximately $60,000 and directors’ fees increased by approximately $93,000.
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 monitor each of our yard facilities and each of our rig locations on a day-to-day basis for potential environmental spill risks. In addition, we maintain a spill prevention control and countermeasures plan for each yard facility and each rig location. The costs of these procedures represent only a small portion of our routine employee training, equipment maintenance and job site maintenance costs. We estimate the annual compliance costs for this program is approximately $212,000. 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 rates of 37.0%, 19.2% and 30.4% for 2005, 2004 and 2003, 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. At March 31, 2005, we had a net operating loss carryforwards for income tax purposes of approximately $16,500,000, of which approximately $6,600,000 will expire in 2023 and $9,900,000 in 2024. We feel that it is more likely than not that we will realize the benefits of these deductible differences. Therefore, we have established a deferred tax asset applicable to these net operating loss carryforwards of approximately $4,300,000.
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.
Off Balance Sheet Arrangements
We do not currently have any off balance sheet arrangements.
Recently Issued Accounting Standards
In December 2004, the FASB issued SFAS No. 123 (revised 2004), Share-Based Payment. SFAS No. 123R is a revision of FASB SFAS No. 123, Accounting for Stock-Based Compensation and supersedes APB Opinion No. 25, Accounting for Stock Issued to Employees, and its related implementation guidance. SFAS No. 123R established standards for the accounting for transactions in which an entity exchanges its equity instruments for goods or services. It also addresses transactions in which an entity incurs liabilities in exchange for goods or services that are based on the fair value of the entity’s equity instruments or that may be settled by the issuance of those equity instruments. SFAS No. 123R focuses primarily on accounting for transactions in which an entity obtains employee services in share-based payment transactions. SFAS No. 123R requires a public entity to measure the cost of employee services received in exchange for an award of equity instruments based on the grant-date fair value of the award (with limited exceptions). That cost will be recognized over the period during which an employee is required to provide service in exchange for the award. The provisions of SFAS No. 123R are effective for public entities that do not file as small business issuers as of the beginning of the first annual reporting period that begins after June 15, 2005. We are currently evaluating the negative impact SFAS No. 123R will have on our financial position and results of operations in fiscal year 2007. The negative impact will be created due to the fact that we previously issued employee stock options for which no expense has been recognized, as these options will not be fully vested as of the effective date of SFAS No. 123R.
Item 7A.
Item 7A. Quantitative and Qualitative Disclosures About Market Risk
We are subject to market risk exposure related to changes in interest rates on most of our outstanding debt. At March 31, 2005, we had outstanding debt of approximately $18,078,000 that was subject to variable interest rates, based on Frost National Bank’s prime interest rate. An increase or decrease of 1% in that interest rate would have a corresponding decrease or increase in our net income (loss) of approximately $120,000 annually. We did not enter into this debt arrangement for trading purposes.
Item 8.
Item 8. Financial Statements and Supplementary Data
PIONEER DRILLING COMPANY
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
Reports of Independent Registered Public Accounting Firm
Consolidated Balance Sheets as of March 31, 2005 and 2004
Consolidated Statements of Operations for the Years Ended March 31, 2005, 2004 and
Consolidated Statements of Shareholders’ Equity and Comprehensive Income for the Years Ended March 31, 2005, 2004 and 2003
Consolidated Statements of Cash Flows for the Years Ended March 31, 2005, 2004 and
Notes to Consolidated Financial Statements
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Shareholders
Pioneer Drilling Company:
We have audited the accompanying consolidated balance sheets of Pioneer Drilling Company and subsidiaries as of March 31, 2005 and 2004, and the related consolidated statements of operations, stockholders’ equity, and cash flows for each of the years in the three-year period ended March 31, 2005. In connection with our audits of the consolidated financial statements, we also have audited the financial statement schedule II. These consolidated financial statements and financial statement schedule are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated financial statements and financial statement schedule based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Pioneer Drilling Company and subsidiaries as of March 31, 2005 and 2004, and the results of their operations and their cash flows for each of the years in the three-year period ended March 31, 2005, in conformity with U.S. generally accepted accounting principles. Also in our opinion, the related financial statement schedule, when considered in relation to the basic consolidated financial statements taken as a whole, present fairly, in all material respects, the information set forth therein.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the effectiveness of Pioneer Drilling Company’s internal control over financial reporting as of March 31, 2005, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), and our report dated May 27, 2005 expressed an unqualified opinion on management’s assessment of, and the effective operation of, internal control over financial reporting.
KPMG LLP
San Antonio, Texas
May 27, 2005
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
The Board of Directors and Stockholders
Pioneer Drilling Company:
We have audited management’s assessment, included in Management’s Report on Internal Control over Financial Reporting in Item 9A of Pioneer Drilling Company’s Annual Report on Form 10-K for the year ended March 31, 2005, that Pioneer Drilling Company and subsidiaries maintained effective internal control over financial reporting as of March 31, 2005, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Pioneer Drilling Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting. Our responsibility is to express an opinion on management’s assessment and an opinion on the effectiveness of the Company’s internal control over financial reporting based on our audit.
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of the Company’s internal control over financial reporting, evaluating management’s assessment, testing and evaluating the design and operating effectiveness of the Company’s internal control over financial reporting, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
In our opinion, management’s assessment that Pioneer Drilling Company maintained effective internal control over financial reporting as of March 31, 2005, is fairly stated, in all material respects, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Also, in our opinion, Pioneer Drilling Company maintained, in all material respects, effective internal control over financial reporting as of March 31, 2005, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of Pioneer Drilling Company and subsidiaries as of March 31, 2005 and 2004, and the related consolidated statements of operations, stockholders’ equity, and cash flows for each of the years in the three-year period ended March 31, 2005, and our report dated May 27, 2005 expressed an unqualified opinion on those consolidated financial statements.
KPMG LLP
San Antonio, Texas
May 27,
PIONEER DRILLING COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
See accompanying notes to consolidated financial statements.
PIONEER DRILLING COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
See accompanying notes to consolidated financial statements.
PIONEER DRILLING COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF SHAREHOLDERS’ EQUITY AND COMPREHENSIVE INCOME
See accompanying notes to consolidated financial statements.
PIONEER DRILLING COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
See accompanying notes to consolidated financial statements.
PIONEER DRILLING COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. Organization and Summary of Significant Accounting Policies
Business and Principles of Consolidation
Pioneer Drilling Company provides contract land drilling services to select oil and natural gas exploration and production regions in the United States. We conduct our operations through our principal operating subsidiary, Pioneer Drilling Services, Ltd. The accompanying consolidated financial statements include our accounts and the accounts of our wholly owned subsidiaries. We have eliminated all intercompany accounts and transactions in consolidation.
We have prepared the accompanying consolidated financial statements in accordance with accounting principles generally accepted in the United States of America. In preparing the financial statements, we make various estimates and assumptions that affect the amounts of assets and liabilities we report as of the dates of the balance sheets and income and expenses we report for the periods shown in the income statements and statements of cash flows. Our actual results could differ significantly from those estimates. Material estimates that are particularly susceptible to significant changes in the near term relate to our recognition of revenues and costs for turnkey contracts, our estimate of the allowance for doubtful accounts, our estimate of the self-insurance portion of our health and workers’ compensation insurance, our estimate of asset impairments, our estimate of deferred taxes and our determination of depreciation and amortization expense.
Income Taxes
Pursuant to Statement of Financial Accounting Standards (“SFAS”) No. 109, “Accounting for Income Taxes,” we follow the asset and liability method of accounting for income taxes, under which we recognize deferred tax assets and liabilities for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax basis. We measure our deferred tax assets and liabilities by using the enacted tax rates we expect to apply to taxable income in the years in which we expect to recover or settle those temporary differences. Under SFAS No. 109, we reflect in income the effect of a change in tax rates on deferred tax assets and liabilities in the period during which the change occurs.
Earnings (Loss) Per Common Share
We compute and present earnings (loss) per common share in accordance with SFAS No. 128 “Earnings per Share.” This standard requires dual presentation of basic and diluted earnings (loss) per share on the face of our statement of operations. For fiscal years 2004 and 2003, we did not include the effects of convertible subordinated debt and stock options on loss per common share because they were antidilutive.
Stock-based Compensation
We have adopted SFAS No. 123, “Accounting for Stock-Based Compensation.” SFAS No. 123 allows a company to adopt a fair value based method of accounting for a stock-based employee compensation plan or to continue to use the intrinsic value based method of accounting prescribed by Accounting Principles Board (“APB”) Opinion No. 25, “Accounting for Stock Issued to Employees.” We have elected to continue accounting for stock-based compensation under the intrinsic value method. Under this method, we record no compensation expense for stock option grants when the exercise price of the options granted is equal to the fair market value of our common stock on the date of grant. If we had elected to recognize compensation cost based on the fair value of the options we granted at their respective grant dates as SFAS No. 123 prescribes, our net earnings (loss) and net earnings (loss) per share would have been reduced to the pro forma amounts the table below indicates:
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.
Revenue and Cost Recognition
We earn our contract drilling revenues under daywork, turnkey and footage 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 well. Individual wells are usually completed in less than 60 days.
Our management has determined that it is appropriate to use the percentage-of-completion method as defined in SOP 81-1to recognize revenue on our turnkey and footage contracts. Although our turnkey and footage contracts do not have express terms that provide us with rights to receive payment for the work that we perform prior to drilling wells to the agreed on depth, we use this method because, as provided in applicable accounting literature, we believe we achieve a continuous sale for our work-in-progress and believe, under applicable state law, we ultimately could recover the fair value of our work-in-progress even in the event we were unable to drill to the agreed on depth in breach of the applicable contract. However, ultimate recovery of that value, in the event we were unable to drill to the agreed on depth in breach of the contract, would be subject to negotiations with the customer and the possibility of litigation.
If a customer defaults on its payment obligation to us under a turnkey or footage contract, we would need to rely on applicable law to enforce our lien rights, because our turnkey and footage contracts do not expressly grant to us a security interest in the work we have completed under the contract and we have no ownership rights in the work-in-progress or completed drilling work, except any rights arising under the applicable lien statute on foreclosure. If we were unable to drill to the agreed on depth in breach of the contract, we also would need to rely on equitable remedies outside of the contract, including quantum meruit, available in applicable courts to recover the fair value of our work-in-progress under a turnkey or footage contract.
We accrue estimated 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, maintenance, operating overhead allocations and allocations of depreciation and amortization expense. We charge general and administrative expenses to expense as we incur them. Changes in job performance, job conditions and estimated profitability on uncompleted contracts may result in revisions to costs and income. When we encounter, during the course of our drilling operations, conditions unforeseen in the preparation of our original cost estimate, we immediately increase our cost estimate for the additional costs to complete the contract. If we anticipate a loss on a contract in progress at the end of a reporting period due to a change in our cost estimate, we immediately accrue the entire amount of the estimated loss including all costs that are included in our revised estimated cost to complete that contract in our consolidated statement of operations for that reporting period.
The asset “contract drilling in progress” represents revenues we have recognized in excess of amounts billed on contracts in progress. The liability “prepaid drilling contracts” represents amounts collected on contracts in excess of revenues recognized.
Prepaid Expenses
Prepaid expenses include items such as insurance, rent deposits and fees. We routinely expense these items in the normal course of business over the periods these expenses benefit.
Property and Equipment
We provide for depreciation of our drilling, transportation and other equipment using the straight-line method over useful lives that we have estimated and that range from three to 15 years. We record the same depreciation expense whether a rig is idle or working.
We charge our expenses for maintenance and repairs to operations. We charge our expenses for renewals and betterments to the appropriate property and equipment accounts. Our gains and losses on the sale of our property and equipment are recorded in drilling costs. During fiscal 2005 and 2004, we capitalized $86,819 and $106,395, respectively, of interest costs incurred during the construction periods of certain drilling equipment. At March 31, 2005 and 2004, costs incurred on rigs under construction were approximately $3,300,000 and $2,800,000, respectively.
We review our long-lived assets and intangible assets for impairment whenever events or circumstances provide evidence that suggests that we may not recover the carrying amounts of any of these assets. In performing the review for recoverability, we estimate the future net cash flows we expect to obtain from the use of each asset and its eventual disposition. If the sum of these estimated future undiscounted net cash flows is less than the carrying amount of the asset, we recognize an impairment loss.
Cash and Cash Equivalents
We maintain cash accounts at several financial institutions. These account balances are insured by the Federal Deposit Insurance Corporation up to $100,000. At March 31, 2005, we had cash account balances of approximately $1,200,000 exceeding the $100,000 insurance threshold.
For purposes of the statements of cash flows, we consider all highly liquid debt instruments purchased with a maturity of three months or less to be cash equivalents. Cash equivalents consist of investments in corporate and government money market accounts. Cash equivalents at March 31, 2005 and 2004 were $65,046,000 and $1,568,000, respectively.
Marketable Securities
Marketable securities consist of auction rate seven-day preferred securities whose market value is equal to their cost. The objective of investing in these securities is to improve our yield on short-term investments of cash. There were no realized or unrealized gains or losses relating to marketable securities during the years ended March 31, 2005 and 2004.
Trade Accounts Receivable
We record trade accounts receivable at the amount we invoice our customers. These accounts do not bear interest. The allowance for doubtful accounts is our best estimate of the amount of probable credit losses in our accounts receivable as of the balance sheet date. We determine the allowance based on the credit worthiness of our customers and general economic conditions. Consequently, an adverse change in those factors could affect our estimate of our allowance for doubtful accounts. We review our allowance for doubtful accounts monthly. Balances more than 90 days past due are reviewed individually for collectibility. We charge off account balances against the allowance after we have exhausted all reasonable means of collection and determined that the potential for recovery is remote. We do not have any off-balance sheet credit exposure related to our customers. At March 31, 2005 and 2004 our allowance for doubtful accounts was $352,000 and $110,000.
Intangible and Other Assets
Intangible and other assets consist of cash deposits related to the deductibles on our workers compensation insurance policies, loan fees net of amortization and intangibles related to acquisitions, net of amortization. Loan fees are amortized over the three-year term of the related debt. Customer lists are amortized over their estimated benefit periods of up to 18 months. Intangibles related to non-compete agreements are amortized over the period of the non-compete agreements of three to five years. Depreciation and amortization expense includes amortization of intangibles of $142,157, $39,341 and $82,141 during the years ended March 31, 2005, 2004 and 2003 respectively. Amortization of intangibles is not expected to exceed $150,000 per year over the next five years. Total cost and accumulated amortization of intangibles at March 31, 2005 was $480,284 and $59,831, respectively, and $162,500 and $43,222, respectively at March 31, 2004.
Derivative Instruments and Hedging Activities
We do not have any free standing derivative instruments and we do not engage in hedging activities.
Related Party Transactions
On August 11, 2004 and August 31, 2004, Chesapeake Energy Corporation (“Chesapeake”) purchased 631,133 shares and 94,670 shares of our common stock, respectively, at $6.90 per share pursuant to the preemptive rights we granted to Chesapeake in the stock purchase agreement we entered into in March 2003 when we sold shares of common stock to Chesapeake in a private placement transaction. On March 29, 2005, we sold Chesapeake an additional 1,165,769 shares pursuant to the preemptive rights agreement. At March 31, 2005, Chesapeake owned 16.78% of our outstanding common stock, and its preemptive rights have expired. During the years ended March 31, 2005 and 2004, we recognized revenues of approximately $4,885,000 and $924,000, respectively, and recorded contract drilling costs of approximately $3,263,000 and $745,000, respectively, excluding depreciation, on contracts with Chesapeake. Our accounts receivable at March 31, 2005 and 2004 include $2,939,000 and $532,000, respectively, due from Chesapeake.
We purchased services from R&B Answering Service and Frontier Service, Inc. during 2005, 2004 and 2003. These companies are more than 5% owned by our Chief Operating Officer and an immediate family member of our Vice President, South Texas Division, respectively. The following summarizes the transactions with these companies in each period.
Recently Issued Accounting Standards
In December 2004, the FASB issued SFAS No. 123 (revised 2004), Share-Based Payment. SFAS No. 123R is a revision of FASB SFAS No. 123, Accounting for Stock-Based Compensation and supersedes APB Opinion No. 25, Accounting for Stock Issued to Employees, and its related implementation guidance. SFAS No. 123R established standards for the accounting for transactions in which an entity exchanges its equity instruments for goods or services. It also addresses transactions in which an entity incurs liabilities in exchange for goods or services that are based on the fair value of the entity’s equity instruments or that may be settled by the issuance of those equity instruments. SFAS No. 123R focuses primarily on accounting for transactions in which an entity obtains employee services in share-based payment transactions. SFAS No. 123R requires a public entity to measure the cost of employee services received in exchange for an award of equity instruments based on the grant-date fair value of the award (with limited exceptions). That cost will be recognized over the period during which an employee is required to provide service in exchange for the award. The provisions of SFAS No. 123R are effective for public entities that do not file as small business issuers as of the beginning of the first annual reporting period that begins after June 15, 2005. We are currently evaluating the negative impact SFAS No. 123R will have on our financial position and results of operations in fiscal year 2007. The negative impact will be created due to the fact that we previously issued employee stock options for which no expense has been recognized, as those options will not be fully vested as of the effective date of SFAS No. 123R.
Reclassifications
Certain amounts in the financial statements for the prior years have been reclassified to conform to the current year’s presentation.
2. Acquisitions
On November 30, 2004, we acquired all the contract drilling assets and a 4.7-acre rig storage and maintenance yard of Wolverine Drilling, Inc., a land drilling contractor based in Kenmare, North Dakota. The equipment included seven mechanical land drilling rigs and related assets, including trucks, trailers, vehicles, spare drill pipe and yard equipment. We paid $28,000,000 in cash for these assets and non-competition agreements with the two owners of Wolverine. We funded this acquisition with $28,000,000 of bank debt described in note 3. This purchase was accounted for as an acquisition of a business, and we have included the results of operation of the acquired business in our statement of operations since the date of acquisition. We allocated the purchase price to property and equipment and related assets, including the non-competition agreements and other intangibles, based on their relative fair values at the date of acquisition.
On December 15, 2004, we acquired all the contract drilling assets and a 17-acre rig storage and maintenance yard of Allen Drilling Company, a land drilling contractor based in Woodward, Oklahoma. The equipment included five mechanical drilling rigs and related assets, including trucks, trailers, vehicles, spare drill pipe and yard equipment. We paid $7, 200,000 in cash for these assets. We also entered into a non-competition agreement with the President of Allen Drilling which provides for the payment of $500,000 due in annual installments of $100,000 each beginning December 15, 2005. We funded this acquisition with $7,200,000 of bank debt described in note 3. This purchase was accounted for as an acquisition of a business, and we have included the results of operations of the acquired business in our statement of operations since the date of acquisition. We allocated the purchase price to property and equipment and related assets, including the non-competition agreements and other intangibles, based on their relative fair values at the date of acquisition.
The following table summarizes the allocation of purchase price to property and equipment and other assets acquired in the Wolverine and Allen Drilling acquisitions:
The following pro forma information gives effect to the Wolverine and Allen Drilling acquisitions as though they were effective as of the beginning of the fiscal year for each period presented. Pro forma adjustments primarily relate to additional depreciation, amortization and interest costs. The information reflects our historical data and historical data from these acquired businesses for the periods indicated. The pro forma data may not be indicative of the results we would have achieved had we completed these acquisitions on April 1, 2003 or 2004, or that we may achieve in the future. The pro forma financial information should be read in conjunction with the accompanying historical financial statements.
On May 28, 2002, we acquired all the land contract drilling assets of United Drilling Company and U-D Holdings, L.P. The assets included two land drilling rigs, associated spare parts and equipment and vehicles. We paid $7,000,000 in cash for these assets. The purchase was accounted for as an acquisition of assets, and the purchase price was allocated to drilling equipment and related assets based on their relative fair values at the date of acquisition.
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. The purchase was accounted for as an acquisition of a business, and we have included the results of operations of these assets in our statement of operations since the date of acquisition. We allocated the purchase price to drilling equipment and related assets, including intangibles, based on their relative fair values at the date of acquisition.
On December 15, 2003, we acquired for approximately $3,770,000 a rig we had previously been leasing from International Drilling Services, Inc. This purchase was accounted for as an acquisition of assets.
On March 2, 2004, we acquired 23 used rig hauling trucks and associated trailers and equipment from A & R Trejo Trucking for $1,200,000. This purchase was accounted for as an acquisition of assets, and the purchase price was allocated to the trucks and related assets based on their relative fair values at the date of acquisition.
On March 4, 2004, we acquired a seven-rig drilling fleet from Sawyer Drilling & Services, Inc. for $12,000,000. This purchase was accounted for as an acquisition of a business, and we have included the results of operations of these assets in our statement of operations since the date of acquisition. We allocated the purchase price to drilling equipment and related assets, including intangibles, based on their relative fair values at the date of acquisition.
On March 12, 2004, we acquired one drilling rig from SEDCO Drilling Co., Ltd. for $2,015,000. This purchase was accounted for as an acquisition of assets, and we have included the results of operations of these assets in our statement of operations since the date of acquisition. We allocated the purchase price to drilling equipment and related assets, including intangibles, based on their relative fair values at the date of acquisition.
3. Long-term Debt, Subordinated Debt and Note Payable
Our long-term debt is described below:
(1) WEDGE Energy Services, LLC (“WEDGE”) held $27,000,000 of the convertible subordinated debentures and William H. White, a former director of our company, held $1,000,000 of the convertible subordinated debentures. The convertible subordinate debentures were converted into 6,496,519 shares of our common stock on August 11, 2004.
(2) These notes were repaid in August and September 2004 with proceeds from our August 2004 common stock offering.
Long-term debt maturing each year subsequent to March 31, 2005 is as follows:
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 was convertible into 6,496,519 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, a former Director of our Company and the former 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 were 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. On August 11, 2004, these debentures were converted in accordance with their terms into 6,496,519 shares of our common stock.
On October 29, 2004, we entered into a $47,000,000 credit facility with a group of lenders consisting of a $7,000,000 revolving line and letter of credit facility and a $40,000,000 acquisition facility for the acquisition of drilling rigs, drilling rig transportation equipment and associated equipment. Frost National Bank is the administrative agent and lead arranger under the new credit facility, and the lenders include Frost National Bank, the Bank of Scotland and Zions First National Bank. Borrowings under the new credit facility bear interest at a rate equal to Frost National Bank’s prime rate (5.75% at March 31, 2005) and are secured by most of our assets, including all our drilling rigs and associated equipment and receivables. We borrowed the entire $40,000,000 available under the acquisition facility and we have used approximately $2,825,000 of availability under the revolving line and letter of credit facility through the issuance of letters of credit in the ordinary course of business. On March 29, 2005, we repaid $20,000,000 of the borrowings under the acquisition facility. On May 11, 2005, the lenders amended the acquisition facility to provide us with the ability to again draw the $20,000,000 for future acquisitions. The remaining approximately $20,0000,000 and $4,175,000 of availability under the acquisition facility and the revolving line and letter of credit facility, respectively, should remain available to us until those facilities mature in October 2006 and October 2005, respectively.
The sum of (1) the draws under and (2) the amount of all outstanding letters of credit issued for our account under the revolving line and letter of credit facility portion of our new credit facility are limited to 75% of our eligible accounts receivable, not to exceed $7,000,000. Therefore, if 75% of our eligible accounts receivable was less than $7,000,000, our ability to draw under this line would be reduced. At March 31, 2005, we had no outstanding advances under this line of credit, outstanding letters of credit were $2,825,000 and 75% of our eligible accounts receivable was approximately $19,084,000. The letters of credit are issued to three workers’ compensation insurance companies to secure possible future claims under the deductibles on these policies. It is our practice to pay any amounts due under these deductibles as they are incurred. Therefore, we do not anticipate that the lenders will be required to fund any draws under these letters of credit. The termination date of the revolving line and letter of credit facility portion of our new credit facility is October 28, 2005.
At March 31, 2005, we were in compliance with all covenants applicable to our outstanding debt. Those covenants include, among others, a debt to total capitalization ratio of not greater than .3 to 1, a fixed charged coverage ratio of not less than 1.5 to 1, an operating leverage ratio of less than 3 to 1, restrict us from paying dividends, restrict us from the sale of assets not permitted by the credit facility and restrict us from the incurrence of additional indebtedness in excess of $3,000,000 not already allowed by the credit facility.
Notes payable at March 31, 2005 consists of a $681,975 insurance premium note due in monthly installments of $137,400, including interest, through August 26, 2005, which bears interest at the rate of 3.15% per year.
4. Leases
We are obligated under capital leases covering several trucks that expire at various dates through January 2007. At March 31, 2005 and 2004, the gross amount of transportation equipment and related amortization recorded under capital leases were as follows:
Amortization of assets held under capital leases is included with depreciation expense.
We lease various office equipment under non-cancelable operating leases expiring through 2008 and real estate as follows:
• a 43-acre division office and storage yard in Decatur, Texas, at a cost of $800 per month, pursuant to a lease extending through September 2006;
• a trucking department office, storage and maintenance yard in Alice, Texas, at a cost of $4,500 per month, pursuant to a lease extending through July 2006;
• a division office in Denver, Colorado, at a cost of $1,210 per month, pursuant to a lease extending through June 2005;
• a yard office in Kenmare, North Dakota, at a cost of $700 per month, pursuant to a lease extending through March 31, 2006; and
• part of a 2.2-acre division office and storage yard in Vernal, Utah at a cost of $2,000 per month pursuant to a lease extending through October 2005.
In August 2004, we purchased the real estate we had previously been leasing in Henderson, Texas.
Rent expense under these operating leases for the years ended March 31, 2005, 2004 and 2003 was $102,077, $278,746 and $344,752, respectively.
In four to six months we will take over the entire division office and storage yard in Vernal, Utah and will enter into a two year lease at a cost of $6,000 per month.
In June 2005, we are moving our corporate headquarters to new office space in San Antonio, Texas. We have entered into a 102 month lease, beginning upon occupancy, with monthly payments of approximately $12,300 for the first two years increasing to an average of approximately $20,000 per month thereafter. The lease grants two options to renew the lease for a renewal term of five years each. We plan to sell our current corporate headquarters building in San Antonio, Texas.
Future lease obligations, including our new corporate headquarters, and minimum capital lease payments as of March 31, 2005 were as follows:
5. Income Taxes
Our provision for income taxes consists of the following:
In fiscal years 2005, 2004 and 2003, our expected tax, which we compute by applying the federal statutory rate of 34% to income (loss) before income taxes, differs from our income tax expense as follows:
Deferred income taxes arise from temporary differences between the tax basis of assets and liabilities and their reported amounts in the consolidated financial statements. The components of our deferred income tax liabilities were as follows:
In assessing our ability to realize deferred tax assets, we consider whether it is more likely than not that some portion or all of the deferred tax assets will not be realized. Our ultimate realization of deferred tax assets depends on the generation of future taxable income during the periods in which those temporary differences become deductible. We consider the scheduled reversal of deferred tax liabilities, projected future taxable income, and tax planning strategies in making this assessment. Based on the level of historical taxable income and projections for future taxable income over the periods during which the deferred tax assets are deductible, we believe it is more likely than not that we will realize the benefits of these deductible differences
At March 31, 2005, we had net operating loss carryforwards for federal income tax purposes of approximately $16,500,000, which will expire if not utilized as of the end of our fiscal years ending as follows:
6. Fair Value of Financial Instruments
Cash and cash equivalents, trade receivables and payables and short-term debt:
The carrying amounts of our cash and cash equivalents, trade receivables, payables and short-term debt approximate their fair values.
Long-term debt:
The carrying amount of our long-term debt approximates its fair value, as supported by the recent issuance of the debt and because the rates and terms currently available to us approximate the rates and terms on the existing debt.
7. Earnings (Loss) Per Common Share
The following table presents a reconciliation of the numerators and denominators of the basic EPS and diluted EPS comparisons as required by SFAS No. 128:
The weighted average number of diluted shares in 2004 and 2003 excludes 7,612,924 and 7,185,995, respectively, of shares for options and convertible debt due to their antidilutive effects.
8. 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. At March 31, 2005, Chesapeake Energy owned 16.78% of our outstanding common stock and its preemptive rights have expired.
On February 20, 2004, we sold 4,400,000 shares of our common stock at $5.40 per share in a private placement for $23,760,000 in proceeds, before related offering expenses. We issued those shares without registration under the Securities Act of 1933 in reliance on the exemption that Section 4(2) of that Act provides for transactions not involving any public offering. We subsequently filed a registration statement on Form S-3 to register the resales of those shares. The registration statement became effective on June 22, 2004.
On August 11, 2004, the entire $28,000,000 in aggregate principal amount of our 6.75% convertible subordinated debentures held by WEDGE Energy Services, L.L.C. and William H. White was converted in accordance with the terms of those debentures into 6,496,519 shares of our common stock.
On August 11, 2004, we sold 4,000,000 shares of our common stock at approximately $6.61 per share, net of underwriters’ commissions, pursuant to a public offering we registered with the SEC under a registration statement filed on Form S-1. On August 31, 2004, we sold 600,000 additional shares of our common stock at approximately $6.61 per share, net of underwriters’ commissions, pursuant to the underwriters’ exercise of an over-allotment option granted in connection with that public offering.
On March 22, 2005, we sold 6,945,000 shares of our common stock, including shares we sold pursuant to the underwriters’ exercise of an over-allotment option, at approximately $11.78 per share, net of underwriters’ commissions, pursuant to a public offering we registered with the SEC.
Directors and employees exercised stock options for the purchase of 551,666 shares of common stock at prices ranging from $.375 to $6.44 per share during the fiscal year ended March 31, 2005, 722,334 shares of common stock at prices ranging from $.625 to $3.20 per share during the fiscal year ended March 31, 2004 and 445,000 shares of common stock at prices ranging from $0.375 to $2.50 per share during the fiscal year ended March 31, 2003.
9. Stock Options, Warrants and Stock Option Plan
Under our stock option plans, employee stock options generally become exercisable over three- to five-year periods, and all options generally expire 10 years after the date of grant. Our plans provide that all options must have an exercise price not less than the fair market value of our common stock on the date of grant. Accordingly, as we discussed in Note 1, we do not recognize any compensation expense relating to these options in our results of operations.
The following table provides information relating to our outstanding stock options at March 31, 2005, 2004 and 2003:
As of March 31, 2005, there were no outstanding warrants.
The following table summarizes information about our employee stock options outstanding and exercisable at March 31, 2005:
10. Employee Benefit Plans and Insurance
We maintain a 401(k) retirement plan for our eligible employees. Under this plan, we may contribute, on a discretionary basis, a percentage of an eligible employee’s annual contribution, which we determine annually. Our contributions for fiscal 2005, 2004 and 2003 were approximately $399,000, $76,000 and $92,000, respectively.
We maintain a self-insurance program, for major medical, hospitalization and dental coverage for employees and their dependents, which is partially funded by payroll deductions. We have provided for both reported and incurred but not reported medical costs in the accompanying consolidated balance sheets. We have a maximum liability of $100,000 per employee/dependent per year. Amounts in excess of the stated maximum are covered under a separate policy provided by an insurance company. Accrued expenses at March 31, 2005 include approximately $489,000 for our estimate of incurred but unpaid costs related to the self-insurance portion of our health insurance.
We are self-insured for up to $250,000 for all workers’ compensation claims submitted by employees for on-the-job injuries, except in North Dakota where the deductible is $100,000. We have provided for both reported and incurred but not reported costs of workers’ compensation coverage in the accompanying consolidated balance sheets. Accrued expenses at March 31, 2005 include approximately $845,000 for our estimate of incurred but unpaid costs related to workers’ compensation claims. Based upon our past experience, management believes that we have adequately provided for potential losses. However, future multiple occurrences of serious injuries to employees could have a material adverse effect on our financial position and results of operations.
11. Business Segments and Concentrations
Substantially all our operations relate to contract drilling of oil and gas wells. Accordingly, we classify all our operations in a single segment.
During the fiscal year ended March 31, 2005, our three largest customers accounted for 6.5%, 5.0% and 4.6%, respectively, of our total contract drilling revenue. All three of these customers were customers of ours in 2004. In fiscal 2004, our three largest customers accounted for 10.5%, 6.4% and 4.9%, of our total contract drilling revenue. Two of these customers were customers of ours in fiscal 2003. In fiscal 2003, our three largest customers accounted for 10.8%, 6.5% and 5.4% of our total contract drilling revenue.
12. Commitments and Contingencies
We are in the process of constructing, primarily from new and used components, two 1000 horsepower electric rigs at an estimated cost of $6,500,000 each. We expect to place one of these rigs in service in June 2005 and the second in August 2005. As of March 31, 2005, we have incurred approximately $3,300,000 of construction cost on these rigs.
In addition, due to the nature of our business, we are, from time to time, involved in routine litigation or subject to disputes or claims related to our business activities, including workers’ compensation claims and employment-related disputes. In the opinion of our management, none of the pending litigation, disputes or claims against us will have a material adverse effect on our financial condition, results of operations or cash flow from operations and there is only a remote possibility that any such matter will require any additional loss accrual.
13. Quarterly Results of Operations (unaudited)
The following table summarizes quarterly financial data for our fiscal years ended March 31, 2005 and 2004 (in thousands, except per share data):
The sum of the quarterly earnings per share amounts do not necessarily agree with the year end amounts due to the dilutive effects of convertible instruments.
Item 9.
Item 9. Changes in and Disagreements With Accountants on Accounting and Financial Disclosure
Not applicable.
Item 9A.
Item 9A. 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 upon that evaluation, our Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures were effective as of March 31, 2005 to provide reasonable assurance that information required to be disclosed in our reports filed or submitted under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the Securities and Exchange Commission’s rules and forms.
There has been no change in our internal controls over financial reporting that occurred during the three months ended March 31, 2005 that has materially affected, or is likely to materially affect, our internal controls over financial reporting.
Management’s Report on Internal Control over Financial Reporting
The management of Pioneer Drilling Company is responsible for establishing and maintaining adequate internal control over financial reporting. Pioneer Drilling Company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. Pioneer Drilling Company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
Pioneer Drilling Company’s management assessed the effectiveness of the Company’s internal control over financial reporting as of March 31, 2005. In making this assessment, it used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control-Integrated Framework. Based on our assessment we have concluded that, as of March 31, 2005, Pioneer Drilling Company’s internal control over financial reporting was effective based on those criteria.
Pioneer Drilling Company’s independent registered public accounting firm has audited management’s assessment of the effectiveness of Pioneer Drilling Company’s internal control over financial reporting as of March 31, 2005, as stated in their report which appears herein. That report appears on page 31.
PART III
In Items 10, 11, 12, 13 and 14 below, we are incorporating by reference the information we refer to in those Items from the definitive proxy statement for our 2005 Annual Meeting of Shareholders. We intend to file that definitive proxy statement with the SEC by July 15, 2005.
Item 10.
Item 10. Directors and Executive Officers of the Registrant
Please see the information appearing under the headings “Proposal No. 1-Election of Directors” and “Executives and Executive Compensation” in the definitive proxy statement for our 2005 Annual Meeting of Shareholders for the information this Item 10 requires.
Item 11.
Item 11. Executive Compensation
Please see the information appearing under the heading “Executives and Executive Compensation” in the definitive proxy statement for our 2005 Annual Meeting of Shareholders for the information this Item 11 requires.
Item 12.
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
Please see the information appearing (1) under the heading “Equity Compensation Plan Information” in Item 5 of this report and (2) under the heading “Security Ownership of Certain Beneficial Owners and Management” in the definitive proxy statement for our 2005 Annual Meeting of Shareholders for the information this Item 12 requires.
Item 13.
Item 13. Certain Relationships and Related Transactions
Please see the information appearing under the heading “Certain Transactions” in the definitive proxy statement for our 2005 Annual Meeting of Shareholders for the information this Item 13 requires.
Item 14.
Item 14. Principal Accountant Fees and Services
Please see the information appearing under the heading “Ratification of Appointment of Independent Auditors” in the definitive proxy statement for our 2005 Annual Meeting of Shareholders for the information this Item 14 requires.
PART IV
Item 15.
Item 15. Exhibits, Financial Statement Schedules and Reports on Form 8-K
(1) Financial Statements.
See Index to Consolidated Financial Statements on page 29.
(2) Financial Statement Schedules:
Schedule II
(3) Exhibits. The following exhibits are filed as part of this report:
Exhibit
Number
Description
2.1
-
Asset Purchase Agreement dated November 11, 2004 between Wolverine Drilling, Inc. and Robert Mau, Robert S. Blackford and Pioneer Drilling Services, Ltd. (Form 8-K dated November 11, 2004 (File No. 1-8182, Exhibit 2.1)).
2.2
-
Asset Purchase Agreement dated November 29,2004, by and among Allen Drilling Company, the Earl Allen Family Trust dated April 1, 1079, the sole shareholder of Allen Drilling Company, Dixon Allen, Paula K. Hoisington and Lisa D. Johonnesson, all of the beneficiaries of the Trust, and Pioneer Drilling Services, Ltd. (Form 8-K dated November 30, 2004 (File No. 1-8182m Exhibit 2.1)).
3.1*
-
Articles of Incorporation of Pioneer Drilling Company, as amended (Form 10-K for the year ended March 31, 2001 (File No. 1-8182, Exhibit 3.1)).
3.2*
-
Articles of Amendment to the Articles of Incorporation of Pioneer Drilling Company (Form 10-Q for the quarter ended September 30, 2001 (File No. 1-8182, Exhibit 3.1)).
3.3*
-
Amended and Restated Bylaws of Pioneer Drilling Company (Form 10-Q for the quarter ended December, 2003 (File No. 1-8182, Exhibit 3.3)).
4.1*
-
Form of Certificate representing Common Stock of Pioneer Drilling Company (Form s-8 filed November 18, 2003 (Reg. No. 333-110569, Exhibit 4.3)).
4.2*
-
Form of Purchase Agreement dated February 13, 2004 between Pioneer Drilling Company and the several purchasers (Form s-3 filed February 24, 3004 (Reg. No. 333-113036, Exhibit 4.1)).
4.3*
-
Credit Agreement between Pioneer Drilling Services, Ltd. and Frost National Bank, as Administrative Agent, Agent, Lead Arranger and Lender dated October 29, 2004 (Form 8-K dated October 29, 2004 (File No. 1-8182, Exhibit 4.1)).
10.1+*
-
Executive Employment Agreement dated May 1, 1995 between Pioneer Drilling Company and Wm. Stacy Locke (Form 10-K for the year ended March 31, 2001 (File No. 1-8182, Exhibit 10.1+)).
10.2+*
-
Second Amendment to Executive Employment Agreement dated August 21, 2000 between Pioneer Drilling Company and Wm. Stacy Locke (Form 10-K for the year ended March 31, 2001 (File No. 1-8182, Exhibit 10.4+)).
10.3+*
-
Pioneer Drilling Company’s 1995 Stock Plan and form of Stock Option Agreement (Form 10-K for the year ended March 31, 2001 (File No. 1-8182, Exhibit 10.5+)).
10.4+*
-
Pioneer Drilling Company’s 1999 Stock Plan and form of Stock Option Agreement (Form 10-K for the year ended March 31, 2001 (File No. 1-8182, Exhibit 10.7+)).
10.5*
-
Pioneer Drilling Company 2003 Stock Plan (Form S-8 filed November 18, 2003 (File No. 333-110569, Exhibit 4.4)).
10.6
-
Termination Agreement dated May 26, 2005 between Michael E. Little, Wm. Stacy Locke, Pioneer Drilling Company and WEDGE Energy Services, L.L.C.
21.1
-
Subsidiaries of Pioneer Drilling Company.
23.1
-
Consent of KPMG LLP.
31.1
-
Certification by Wm. Stacy Locke, President and Chief Executive Officer, pursuant to Rule 13a-14(a) or Rule 15d-14(a) under the Securities Exchange Act of 1934.
31.2
-
Certification by William D. Hibbetts, Senior Vice President and Chief Financial Officer, pursuant to Rule 13a-14(a) or Rule 15d-14(a) under the Securities Exchange Act of 1934.
32.1
-
Certification by Wm. Stacy Locke, President and Chief Executive Officer, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (Subsections (a) and (b) of Section 1350, Chapter 63 of Title 18, United States Code).
32.2
-
Certification by William D. Hibbetts, Senior Vice President and Chief Financial Officer, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (Subsections (a) and (b) of Section 1350, Chapter 63 of Title 18, United States Code).
* Incorporated by reference to the filing indicated.
+ Management contract or compensatory plan or arrangement.
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) 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.
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.
Index To Exhibits
2.1
-
Asset Purchase Agreement dated November 11, 2004 between Wolverine Drilling, Inc. and Robert Mau, Robert S. Blackford and Pioneer Drilling Services, Ltd. (Form 8-K dated November 11, 2004 (File No. 1-8182, Exhibit 2.1)).
2.2
-
Asset Purchase Agreement dated November 29,2004, by and among Allen Drilling Company, the Earl Allen Family Trust dated April 1, 1079, the sole shareholder of Allen Drilling Company, Dixon Allen, Paula K. Hoisington and Lisa D. Johonnesson, all of the beneficiaries of the Trust, and Pioneer Drilling Services, Ltd. (Form 8-K dated November 30, 2004 (File No. 1-8182m Exhibit 2.1)).
3.1*
-
Articles of Incorporation of Pioneer Drilling Company, as amended (Form 10-K for the year ended March 31, 2001 (File No. 1-8182, Exhibit 3.1)).
3.2*
-
Articles of Amendment to the Articles of Incorporation of Pioneer Drilling Company (Form 10-Q for the quarter ended September 30, 2001 (File No. 1-8182, Exhibit 3.1)).
3.3*
-
Amended and Restated Bylaws of Pioneer Drilling Company (Form 10-Q for the quarter ended December, 2003 (File No. 1-8182, Exhibit 3.3)).
4.1*
Form of Certificate representing Common Stock of Pioneer Drilling Company (Form S-8 filed November 18, 2003 (Reg. No. 333-110569, Exhibit 4.3)).
4.2*
Form of Purchase Agreement dated February 13, 2004 between Pioneer Drilling Company and the several purchasers (Form S-3 filed February 24, 2004 (Reg. No. 333-113036, Exhibit 4.1)).
4.3
-
Credit Agreement between Pioneer Drilling Services, Ltd. and Frost National Bank, as Administrative Agent, Agent, Lead Arranger and Lender dated October 29, 2004 (Form 8-K dated October 29, 2004 (File No. 1-8182, Exhibit 4.1)).
10.1+*
-
Executive Employment Agreement dated May 1, 1995 between Pioneer Drilling Company and Wm. Stacy Locke (Form 10-K for the year ended March 31, 2001 (File No. 1-8182, Exhibit 10.1+)).
10.2+*
-
Second Amendment to Executive Employment Agreement dated August 21, 2000 between Pioneer Drilling Company and Wm. Stacy Locke (Form 10-K for the year ended March 31, 2001 (File No. 1-8182, Exhibit 10.4+)).
10.3+*
-
Pioneer Drilling Company’s 1995 Stock Plan and form of Stock Option Agreement (Form 10-K for the year ended March 31, 2001 (File No. 1-8182, Exhibit 10.5+)).
10.4+*
-
Pioneer Drilling Company’s 1999 Stock Plan and form of Stock Option Agreement (Form 10-K for the year ended March 31, 2001 (File No. 1-8182, Exhibit 10.7+)).
10.5*
-
Pioneer Drilling Company 2003 Stock Plan (Form S-8 filed November 18, 2003 (File No. 333-110569, Exhibit 4.4)).
10.6
-
Termination Agreement date May 26, 2005 between Michael E. Little, Wm. Stacy Locke, Pioneer Drilling Company and WEDGE Energy Services, L.L.C.
21.1
-
Subsidiaries of Pioneer Drilling Company.
23.1
-
Consent of KPMG LLP.
31.1
-
Certification by Wm. Stacy Locke, President and Chief Executive Officer, pursuant to Rule 13a-14(a) or Rule 15d-14(a) under the Securities Exchange Act of 1934.
31.2
-
Certification by William D. Hibbetts, Senior Vice President and Chief Financial Officer, pursuant to Rule 13a-14(a) or Rule 15d-14(a) under the Securities Exchange Act of 1934.
32.1
-
Certification by Wm. Stacy Locke, President and Chief Executive Officer, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (Subsections (a) and (b) of Section 1350, Chapter 63 of Title 18, United States Code).
32.2
-
Certification by William D. Hibbetts, Senior Vice President and Chief Financial Officer, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (Subsections (a) and (b) of Section 1350, Chapter 63 of Title 18, United States Code).
* Incorporated by reference to the filing indicated.
+ Management contract or compensatory plan or arrangement.