A significant performance measurement in our industry is operating rig utilization. We compute operating 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 operating rig. Revenue days for each operating rig are days when the rig is earning revenues under a contract, i.e. when the rig begins moving to the drilling location until the rig is released from the contract. On daywork contracts, during the mobilization period we typically earn a fixed amount of revenue based on the mobilization rate stated in the contract. We begin earning our contracted daywork rate when we begin drilling the well. Occasionally, in periods of increased demand, we will receive a percentage of the contracted dayrate during the mobilization period. We account for these revenues as mobilization fees.
For the three months ended March 31, 2007 and 2006 and years ended December 31, 2006, 2005 and 2004, our rig utilization rates, revenue days and average number of operating rigs were as follows:
| | | Three Months Ended | | | | | | | |
| | | March 31, | | Years Ended December 31, | |
| | | 2007 | | 2006 | | 2006 | | 2005 | | 2004 | |
| Average number of operating rigs | | | 51 | | | 39 | | | 45 | | | 17 | | | 9 | |
| Revenue days | | | 3,631 | | | 3,354 | | | 15,202 | | | 5,781 | | | 2,733 | |
| Utilization Rates | | | 79 | % | | 96 | % | | 93 | % | | 95 | % | | 81 | % |
The increase in the number of revenue days in the three month-period ended March 31, 2007 as compared to the same period in 2006 is attributable to the increase in the size of our operating rig fleet partially offset by a decrease in our rig utilization rate.
We devote substantial resources to maintaining, upgrading and expanding our rig fleet. We substantially completed the refurbishment of one rig in the first quarter of 2007, 12 rigs in 2006, and six rigs in 2005, and plan on refurbishing two additional inventoried rigs during the remainder of 2007.
Market Conditions in Our Industry
The United States contract land drilling services industry is highly cyclical. Volatility in oil and natural 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 natural gas prices and the outlook for future oil and natural gas prices strongly influence the number of wells oil and natural gas exploration and production companies decide to drill.
The following table depicts the prices for near month delivery contracts for crude oil and natural gas as traded on the NYMEX, as well as the most recent Baker Hughes domestic land rig count, on the dates indicated:
| | | At March 31, | | At December 31, | |
| | | 2007 | | 2006 | | 2005 | | 2004 | |
| | | | | | | | | | |
| Crude oil (Bbl) | | $ | 65.87 | | $ | 61.05 | | $ | 61.04 | | $ | 43.45 | |
| Natural gas (Mmbtu) | | $ | 7.73 | | $ | 6.30 | | $ | 11.23 | | $ | 6.15 | |
| U.S. Land Rig Count | | | 1,676 | | | 1,626 | | | 1,391 | | | 1,138 | |
We believe capital spent on incremental natural gas production will be driven by an increase in hydrocarbon demand as well as changes in the supply of natural gas. The Energy Information Administration (EIA) has estimated that U.S. consumption of natural gas exceeded domestic production by 13% in 2006 and forecasts that U.S. consumption of natural gas will exceed U.S. domestic production by 24% in 2010. In addition, a study published by the National Petroleum Council in September 2003 concluded from drilling and production data over the preceding ten years that average “initial production rates from new wells have been sustained through the use of advanced technology; however, production declines from these initial rates have increased significantly; and recoverable volumes from new wells drilled in mature producing basins have declined over time.” This point was validated in 2006, as there were 3.4 times the number of wells drilled as compared to ten years earlier with no increase in production. We believe all of these factors tend to support a higher natural gas price environment, which should create strong incentives for oil and natural gas exploration and production companies to increase drilling activity in the U.S.
Critical Accounting Policies and Estimates
Our discussion and analysis of our financial condition and results of operations is based upon our consolidated financial statements, which have been prepared in accordance with accounting policies that are described in the notes to our consolidated financial statements. The preparation of the consolidated financial statements requires our management to make estimates and judgments that affect the reported amounts of our assets, liabilities, revenues and expenses, and related disclosure of contingent assets and liabilities. We continually evaluate our judgments and estimates in determining our financial condition and operating results. Estimates are based upon information available as of the date of the financial statements and, accordingly, actual results could differ from these estimates, sometimes materially. Critical accounting policies and estimates are defined as those that are both most important to the portrayal of our financial condition and operating results and require management’s most subjective judgments. The most critical accounting policies and estimates are described below.
Revenue and Cost Recognition—We earn our revenues by drilling oil and natural gas wells for our customers under daywork 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. Mobilization revenues and costs are deferred and recognized over the drilling days of the related drilling contract. Individual contracts are usually completed in less than 120 days. We follow the percentage-of- completion method of accounting for footage contract drilling arrangements. Under this method, drilling revenues and costs related to a well in progress are recognized proportionately over the time it takes to drill the well.
Percentage of completion is determined based upon the amount of expenses incurred through the measurement date as compared to total estimated expenses to be incurred drilling the well. Mobilization costs are not included in costs incurred for percentage-of-completion calculations. Mobilization costs on footage contracts and daywork contracts are deferred and recognized over the days of actual drilling. Under the percentage-of-completion method, management estimates are relied upon in the determination of the total estimated expenses to be incurred drilling the well. When estimates of revenues and expenses indicate a loss on a contract, the total estimated loss is accrued.
Our management has determined that it is appropriate to use the percentage-of-completion method to recognize revenue on our footage contracts, which we believe is the predominant practice in the industry. Although our 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 upon depth, we use this method because, as provided in applicable accounting literature, we believe we achieve a continuous sale for our work-in-progress and we believe, under applicable state law, we ultimately could recover the fair value of our work-in-progress even in the event we were unable to drill to the agreed upon depth in breach of the applicable contract. However, ultimate recovery of that value, in the event we were unable to drill to the agreed upon depth in breach of the contract, would be subject to negotiations with the customer and the possibility of litigation.
We are entitled to receive payment under 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 inception, we have completed all our footage contracts. Although our initial cost estimates for 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 operation, 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 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 adjust our cost estimate for the additional costs to complete the contracts. If we anticipate a loss on a contract in progress at the end of a reporting period due to a change in our cost estimate, we immediately accrue the entire amount of the estimated loss, including all costs that are included in our revised estimated cost to complete that contract, in our consolidated statement of operations for that reporting period. During 2006, we did not experience a loss on the one footage contract we completed. We did not drill any wells pursuant to footage contracts during the three months ended March 31, 2007. We are more likely to encounter losses on footage contracts in years in which revenue rates are lower for all types of contracts.
Revenues and costs during a reporting period could be affected by contracts in progress at the end of a reporting period that have not been completed before our financial statements for that period are released. We had no footage contracts in progress at March 31, 2007 or December 31, 2006. At March 31, 2007 and December 31, 2006, our contract drilling in progress totaled $2.1 million and $2.0 million, respectively, all of which relates to the revenue recognized but not yet billed or costs deferred on daywork contracts in progress.
We accrue estimated contract costs on footage contracts for each day of work completed based on our estimate of the total costs to complete the contract divided by our estimate of the number of days to complete the contract. Contract costs include labor, materials, supplies, repairs and maintenance and operating overhead allocations. In addition, the occurrence of uninsured or under-insured losses or operating cost overruns on our 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 that were not completed prior to the release of our financial statements.
Accounts Receivable—We evaluate the creditworthiness of our customers based on their financial information, if available, information obtained from major industry suppliers, current prices of oil and natural 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 30-day intervals during the performance of daywork contracts and upon completion of the daywork contract. 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 years. Our allowance for doubtful accounts was $494,000 and $400,000 at March 31, 2007 and December 31, 2006, respectively. Any allowance established is subject to judgment and estimates made by management. We determine our allowance by considering a number of factors, including the length of time trade accounts receivable are past due, our previous loss history, our customer’s current ability to pay its obligation to us and the condition of the general economy and the industry as a whole. We write off specific accounts receivable when they become uncollectible and payments subsequently received on such receivables reduce the allowance for doubtful accounts.
If a customer defaults on its payment obligation to us under a footage contract, we would need to rely on applicable law to enforce our lien rights, because our 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 might also 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 footage contract.
Asset Impairment and Depreciation—We review long-lived assets to be held and used for impairment whenever events or changes in circumstances indicate that the carrying amount of the assets may not be recoverable. We also evaluate the carrying value of goodwill during the fourth quarter of each year and between annual evaluations if events occur or circumstances change that would more likely than not reduce the fair value below its carrying amount. Factors that we consider important and 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 utilization rates, cash flows from our drilling rigs, current oil and natural gas prices, industry analysts’ outlook for the industry and their view of our customers’ access to debt or equity and the trends in the price of used drilling equipment observed by our management. If a review of our drilling rigs, intangible assets and goodwill indicate that our carrying value exceeds the estimated undiscounted future cash flows, we are required under applicable accounting standards to write down the drilling equipment, intangible assets and goodwill to its fair market value. A one percent write-down in the cost of our drilling equipment, intangible assets and goodwill, at March 31, 2007, would have resulted in a corresponding decrease in our net income of approximately $2.8 million.
Our determination of the estimated useful lives of our depreciable assets, 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 rigs, transportation and other equipment on a straight-line method over useful lives that we have estimated and that range from three to fifteen years after the rig was placed into service. We record the same depreciation expense whether an operating rig is idle or working. Depreciation is not recorded on an inventoried rig until placed in service. Our estimates of the useful lives of our drilling, transportation and other equipment are based on our experience in the drilling industry with similar equipment.
We capitalize interest cost as a component of drilling rigs refurbished for our own use. During the three months ended March 31, 2007 and year ended December 31, 2006, we capitalized approximately $454,000 and $3.6 million, respectively.
Stock Based Compensation—We have adopted SFAS No. 123(R), “Share-Based Payment” upon granting our first stock options on August 16, 2005. SFAS No. 123(R) requires a public entity to measure the costs of employee services received in exchange for an award of equity or liability instruments based on the grant-date fair value of the award. That cost will be recognized over the periods during which an employee is required to provide service in exchange for the award. Stock compensation expense was $693 and $530 for the three months ended March 31, 2007 and 2006, respectively.
The fair value of each option award is estimated on the date of grant using a Black-Scholes valuation model that uses various assumptions related to volatility, expected life, forfeitures, exercise patterns, risk free rates and expected dividends. Expected volatilities are based on the historical volatility of a selected peer and other factors. The majority of our options are held by employees that make up one group with similar expected exercise behavior for valuation purposes. The expected term of options granted is estimated based on an average of the vesting period and the contractual period. The risk-free rate for periods within the contractual life of the option is based on the U.S. Treasury yield curve in effect at the time of the grant.
We have not declared dividends since we became a public company and do not intend to do so in the foreseeable future, and thus did not use a dividend yield. Expected life has been determined using the permitted short cut method. In each case, the actual value that will be realized, if any, will depend on the future performance of the common stock and overall stock market conditions. There is no assurance that the value an optionee actually realizes will be at or near the value estimated using the Black-Scholes model.
Under our stock incentive plans, employee stock options become exercisable in equal monthly installments over a three-year period, and all options generally expire ten years after the date of grant. The 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 the grant.
Deferred Income Taxes—We provide deferred income taxes for the basis difference in our property and equipment, stock compensation expense, and other items 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 the stock in an entity rather than just its assets. For financial reporting purposes, we depreciate the various components of our drilling rigs and refurbishments over fifteen 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.
Other Accounting Estimates—Our other accrued expenses as of March 31, 2007 and December 31, 2006 included accruals of approximately $2.4 million and $1.9 million, respectively, for costs under our workers’ compensation insurance. We have a deductible of $1.0 million per covered accident under our workers’ compensation insurance. Our insurance policy requires us to maintain a letter of credit to cover payments by us of that deductible. As of both March 31, 2007 and December 31, 2006, we had a $2.6 million letter of credit. 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. We also have a self-insurance program for major medical hospitalization and dental coverage for employees and their dependents. The Company recognizes both reported and incurred but not reported costs related to the self-insurance portion of our health insurance. Since the accrual is based on estimates of expenses for claims, the ultimate amounts paid may differ from accrued amounts.
Recent Highlights
The following are highlights that impacted our liquidity or results of operations for the three months ended March 31, 2007:
| · | On January 2, 2007, we purchased an approximately 18,100 square foot building located in Edmond, Oklahoma for a total purchase price of $3.0 million, less an amount equal to one-half of the principal reduction on the seller’s loan secured by the property between the effective date of the purchase agreement and the closing. We paid $1.4 million in cash and assumed debt of approximately $1.6 million. Prior to closing, we subleased a total of 9,050 square feet of the building from its tenants until the closing date for a monthly rental of $8,341. |
| · | On January 9, 2007, we completed the acquisition of 31 workover rigs, 24 of which were operating, from Eagle Well Services, Inc. and related subsidiaries for $2.5 million in cash, 1,070,390 shares of our common stock, and the assumption of debt of $6.5 million, liabilities of $819,000 and additional deferred income taxes of $7.7 million. We subsequently deployed three of these rigs and intend to deploy the remaining four rigs periodically over the coming months with the expectation that all 31 will be in service by the end of the second quarter of 2007. |
Results of Operations
Three Months Ended March 31, 2007 Compared to Three Months Ended March 31, 2006
Contract Drilling Revenue. For the three months ended March 31, 2007, we reported contract drilling revenues of $74.5 million, a 32% increase from revenues of $56.4 million for the same period in 2006. The increase is primarily due to an increase in dayrates, revenue days, and average number of rigs working for the three months ended March 31, 2007 as compared to the same period in 2006. Average dayrates for our drilling services increased $3,126, or 20%, to $18,749 for the three months ended March 31, 2007 from $15,623 in the same period in 2006. Revenue days increased 8% to 3,631 days for the three months ended March 31, 2007 from 3,354 days during the same period in 2006. Our average number of operating rigs increased to 52 from 39, or 33%, for the three months ended March 31, 2007 as compared to the same period in 2006. The increase in the number of revenue days for the three months ended March 31, 2007 as compared to the same period in 2006 is attributable to the increase in the size of our operating rig fleet due to refurbishments partially offset by a decrease in our rig utilization rate to 79% for the three months ended March 31, 2007 from 96% for the three months ended March 31, 2006. This 17% decrease was due primarily to a more competitive market resulting from an increase in the supply of drilling rigs and unfavorable weather conditions in the first quarter.
Contract Drilling Expense. Direct rig cost increased $12.8 million to $40.8 million for the three months ended March 31, 2007 from $28.0 million for the same period in 2006. This 46% increase is primarily due to the increase in revenue days and the increase in average number of operating rigs in our fleet for the three months ended March 31, 2007 as compared to the same period in 2006. As a percentage of contract drilling revenue, drilling expense increased to 55% for the three-month period ended March 31, 2007 from 50% for the same period in 2006 due primarily to expenses related to the retention of crews of idle rigs.
Depreciation Expense. Depreciation expense increased $5.3 million to $11.2 million for the three months ended March 31, 2007 from $5.9 million for the same period in 2006. The increase is primarily due to the 45% increase in fixed assets, including the deployment of twelve additional rigs from our inventory and the Eagle Well Services acquisition, as well as incremental increases in ancillary equipment, all of which occurred after the 2006 period.
General and Administrative Expense. General and administrative expense increased $1.5 million to $4.7 million for the three months ended March 31, 2007 from $3.2 million for the same period in 2006. The increase is the result of an increase in yard expense of $717,000, an increase in payroll costs of $316,000, an increase in bad debt expense of $185,000, and an increase in stock compensation expense of $163,000. The increase in yard expense is primarily due to the acquisition of Eagle Well Services during the first quarter and the increase in payroll is primarily due to our increased employee count due both to organic growth and acquisitions as well as selected wage increases.
Interest Expense. Interest expense increased $1.2 million to $1.3 million for the three months ended March 31, 2007 from $85,000 for the same period in 2006. The increase is due to a decrease in the capitalization of interest expense related to our rig refurbishment program. We capitalized $454,000 of interest for the three months ended March 31, 2007 as compared to $1.1 million for the same period in 2006 as part of our rig refurbishment program. The increase is also attributable to an increase in the average debt outstanding during the respective periods.
Tax Expense (Benefit). We recorded a tax expense of $7.1 million for the three months ended March 31, 2007, of which $4.4 million is deferred tax expense. This compares to a deferred tax expense of $6.9 million for the three months ended March 31, 2006. This increase is due to an increase in pre-tax income and an increase in our effective tax rate.
Liquidity and Capital Resources
Operating Activities. Net cash provided by operating activities was $15.2 million for the three months ended March 31, 2007 as compared to $14.8 million in 2006. The increase of $400,000 from 2007 to 2006 was primarily due to increased cash receipts from customers, partially offset by higher cash payments to employees and suppliers.
Investing Activities. We use a significant portion of our cash flows from operations and financing activities for acquisitions and the refurbishment of our rigs. Cash used for investing activities was $17.1 million for the three-months ended March 31, 2007 as compared to $41.4 million for the same period in 2006. For the three months ended March 31, 2007, we used 16.2 million to refurbish our drilling rigs and $2.3 million to purchase Eagle Well Service, Inc. These amounts were partially offset by $1.4 million of proceeds received from the sale of assets. During the 2006 period, $16.4 million related to the Big A acquisition and $25.8 million was used to refurbish drilling rigs. These amounts were partially offset by $801,000 received from a restricted account that is used as security for a letter of credit issued to workers’ compensation insurance carrier.
Financing Activities. Our cash flows used in financing activities were $6.8 million for the three months ended March 31, 2007 as compared to $15.2 million provided by financing activities for the same period in 2006. For the three months ended March 31, 2007, our net cash used in financing activities related to principal payments of $14.8 million under our credit agreement with Fortis Capital Corp., partially offset by borrowings of $8.0 million under our credit facility with Fortis Capital Corp. Our net cash provided by financing activities for the three months ended March 31, 2006 related to net proceeds of approximately $36.4 million from our follow-on offering, borrowings of $15.0 million under our credit agreement with Fortis Capital Corp., partially offset by principal payments of $30.0 million under our credit facility with Fortis Capital Corp. and $4.6 million on a promissory note given in connection with our acquisition of all of the membership interests of Strata Drilling, L.L.C. and Strata Property, L.L.C. (together, "Strata") discussed below.
Sources of Liquidity. Our primary sources of liquidity are cash from operations and debt and equity financing.
Debt Financing. On July 1, 2004, we entered into a revolving line of credit with International Bank of Commerce with a borrowing base of the lesser of $2.0 million or 80% of current receivables. Borrowings under this line bore interest at a rate equal to the greater of 4.0% or JPMorgan Chase prime (effective rate of 7.25% at December 31, 2005). Accrued but unpaid interest was payable monthly. On January 1, 2005, we amended our line of credit with International Bank of Commerce to increase the borrowing base to the lesser of $3.0 million or 80% of current receivables. The line of credit had a maturity date of November 1, 2006. It was repaid in full in January 2006 with a portion of the proceeds from our new revolving credit facility and then terminated.
In July 2005, we acquired all of the membership interests in Strata and a related rig yard for an aggregate of $20.0 million, of which $13.0 million was paid in cash and $7.0 million paid in the form of promissory notes issued to the sellers. We funded the cash portion of the purchase price with a $13.0 million loan from Alpha Investors LLC ("Alpha"), an entity controlled by Wexford Capital L.L.C ("Wexford"). The outstanding principal balance of the loan plus accrued but unpaid interest was due in full upon the earlier to occur of the completion of our initial public offering and the maturity of the loan on July 1, 2006. We repaid this loan in full on August 22, 2005 with a portion of the proceeds from our initial public offering. Borrowings under our loan with Alpha bore interest at a rate equal to LIBOR plus 5% until September 30, 2005, and thereafter were to bear interest at a rate equal to LIBOR plus 7.5%. The $7.0 million original aggregate principal balance of the promissory notes issued to the sellers was automatically reduced by the amount of any costs and expenses we paid in connection with the refurbishment of one of the rigs we acquired from the sellers. The amount due on these notes, net of costs and expenses paid by us, was $4.5 million at December 31, 2005. The outstanding balance of the loan was paid in full on January 5, 2006 upon completion of the refurbishment of this rig.
On September 19, 2005, we entered into a term loan and security agreement with Merrill Lynch Capital, a division of Merrill Lynch Business Financial Services, Inc. The term loan provided for a term installment loan in an aggregate amount not to exceed $50.0 million and provided for a commitment by Merrill Lynch Capital to advance funds from time to time until December 31, 2005. The outstanding balance under the term loan could not exceed 60% of the net orderly liquidation value of our operating land drilling rigs. On September 19, 2005, we borrowed $43.0 million under the term loan. A portion of these borrowings, together with proceeds from our initial public offering, were used to fund the Eagle acquisition. The term loan bore interest on the outstanding principal balance at a variable per annum rate equal to LIBOR plus 271 basis points (7.1% at December 31, 2005). For the period from September 19, 2005 to January 1, 2006, interest only was payable monthly on the outstanding principal balance. Commencing February 1, 2006, the outstanding principal and interest on the term loan were payable in 60 consecutive monthly installments, each in an amount equal to one sixtieth of the outstanding principal balance on January 1, 2006 plus accrued interest on the outstanding principal balance. The maturity date was January 1, 2011. Our obligations under the term loan were secured by a first lien and security interest on substantially all of our assets and were guaranteed by each of our principal subsidiaries. The term loan included usual and customary negative covenants and events of default for loan agreements of this type. The term loan also required us to meet certain financial covenants, including maintaining a minimum Fixed Charge Coverage Ratio and a maximum Total Debt to EBITDA Ratio. This term loan was repaid in full in January 2006 with a portion of the proceeds from our new revolving credit facility and the term loan was terminated.
On January 13, 2006, we entered into a $150.0 million revolving credit facility with Fortis Capital Corp., as administrative agent, lead arranger and sole bookrunner, and a syndicate of lenders, which include The Royal Bank of Scotland plc, The CIT Group/Business Credit, Inc., Calyon Corporate and Investment Bank, Merrill Lynch Capital, Comerica Bank and Caterpillar Financial Services Corporation. The revolving credit facility matures on January 13, 2009. The initial aggregate revolving commitment of $150.0 million is automatically and permanently reduced by $10.0 million at the end of each fiscal quarter starting September 30, 2006. The aggregate revolving commitment was $120,000 at March 31, 2007. Loans under the revolving credit facility bear interest at LIBOR plus a margin that can range from 2.0% to 3.0% or, at our option, the prime rate plus a margin that can range from 1.0% to 2.0%, depending on the ratio of our outstanding senior debt to “Adjusted EBITDA” as defined in the credit agreement. Our borrowings under this revolving credit facility were used to fund a portion of the Big A acquisition and to repay in full all outstanding borrowings under our term loan with Merrill Lynch Capital and our revolving line of credit with International Bank of Commerce.
The revolving credit facility also provides for a quarterly commitment fee of 0.5% per annum of the unused portion of the revolving credit facility, and fees for each letter of credit issued under the facility. Commitment fees paid for the three months ended March 31, 2007 were $161. Our subsidiaries have guaranteed the loans and other obligations under the revolving credit facility. The obligations under the revolving credit facility and the related guarantees are secured by a first priority security interest in substantially all of our assets, as well as the shares of capital stock of our direct and indirect subsidiaries.
The revolving credit facility contains customary covenants for facilities of this type, including among other things, covenants that restrict our ability to make capital expenditures, incur indebtedness, incur liens, dispose of property, repay debt, pay dividends, repurchase shares and make certain acquisitions. The financial covenants are a minimum fixed charge coverage ratio of 1.75 to 1.00 and a maximum total leverage ratio of 2.00 to 1.00. The Company was in compliance with all covenants at March 31, 2007. The revolving credit facility provides for mandatory prepayments under certain circumstances as more fully discussed in the revolving credit facility. The revolving credit facility contains various events of default, including failure to pay principal and interest when due, breach of covenants, materially incorrect representations, default under certain other agreements, bankruptcy or insolvency, the occurrence of specified ERISA events, entry of enforceable judgments against us in excess of $3.0 million not stayed, and the occurrence of a change of control. If an event of default occurs, all commitments under the revolving credit facility may be terminated and all of our obligations under the revolving credit facility could be accelerated by the lenders, causing all loans outstanding (including accrued interest and fees payable thereunder) to be declared immediately due and payable.
We are party to term installment loans for an aggregate principal amount of approximately $6.0 million. These term loans are payable in 96 monthly installments, mature from 2013 - 2015 and have an weighted average annual interest rate of 6.94%. The proceeds from these term loans were used to purchase cranes.
We are party to a term loan agreement with Holliday American Mortgage for an aggregate principal amount of approximately $1.6 million related to the acquisition of the building. This term loan is payable in 166 monthly installments, matures in 2021 and has a interest rate of 6%.
Issuances of Equity. In March 2006, we closed a public offering of 3,450,000 shares of our common stock at a price of $22.75 per share. In the offering, a total of 1,700,000 shares were sold by us and 1,750,000 shares were sold by the selling stockholder. The offering resulted in net proceeds to us of approximately $36.2 million, excluding offering expenses of $577,000. We did not receive any proceeds from the sale of shares by the selling stockholder.
In connection with our acquisitions of Big A Drilling and Eagle Well Services, Inc. we issued 72,571 and 1,070,390 shares of our common stock, respectively. See “Capital Expenditures” below.
Capital Expenditures.
During 2006, we substantially completed the refurbishment of 12 rigs, ranging from 450 to 1,500 horsepower. We incurred refurbishment costs of $67.7 million, ranging from $544,000 to $7.9 million per rig, which were funded with borrowings under our various credit facilities, public offerings, and cash flows from operations.
In January 2006, the refurbishment of a 1,000-horsepower mechanical rig was completed pursuant to a $7.0 million seller’s note incurred in the Strata acquisition. We designated this Rig No. 43 and repaid the note with proceeds from our November 2005 follow-on offering.
On January 18, 2006, we purchased six operating rigs and certain other assets, including heavy haul trucks and excess rig equipment and inventory, from Big A Drilling, L.C. The purchase price for the assets consisted of $16.3 million paid in cash and 72,571 shares of our common stock.
In October 2006, we purchased a 1,000-horsepower electric drilling rig, which we designated Rig No. 37. We paid approximately $7.4 million for this rig.
During the first quarter of 2007 we completed the refurbishment of a 1,500 horsepower rig. We incurred refurbishment costs of $7.0 million which were funded with borrowings under our various credit facilities and cash flows from operations.
We intend to complete the refurbishment of two additional inventoried rigs during 2007 at estimated costs (including drill pipe) for $5.9 million per rig. The actual cost of refurbishing our rigs will depend upon such factors as the availability of equipment, unforeseen engineering problems, work stoppages, weather interference, unanticipated cost increases, inability to obtain necessary certifications and approvals, shortages of skilled labor and the specific customer requirements.
On January 2, 2007, we purchased an approximately 18,100 square foot building located in Edmond, Oklahoma for cash of $1.4 million and the assumption of existing debt of approximately $1.6 million, less one-half of the principal reduction on the sellers’ loan secured by the property between the effective date and closing. Prior to closing on the building we subleased a total of 9,050 square feet of the building from its current tenants for a monthly rental of $8,341.
On January 9, 2007, we completed the acquisition of 31 workover rigs, 24 of which were operating, from Eagle Well Services, Inc. and related subsidiaries for $2.5 million in cash, 1,070,390 shares of common stock and the assumption of debt of $6.5 million, liabilities of $819,000 and additional deferred income taxes of $7.7 million. We subsequently deployed three of these rigs and intend to deploy the remaining four rigs periodically over the coming months with the expectation that all 31 will be in service by the end of the second quarter of 2007.
We believe that cash flow from our operations and borrowings under our revolving credit facility will be sufficient to fund our operations for at least the next 12 months. However, additional capital may be required for future rig acquisitions. While we would expect to fund such acquisitions with additional borrowings and the issuance of debt and equity securities, we cannot assure you that such funding will be available or, if available, that it will be on terms acceptable to us.
We are subject to market risk exposure related to changes in interest rates on our outstanding floating rate debt. Borrowings under our new revolving credit facility bear interest at a floating rate equal to LIBOR plus a margin that can range from 2.0% to 3.0% or, at our option, the prime rate plus a margin that can range from 1.0% to 2.0%, depending on the ratio of our outstanding senior debt to adjusted EBITDA. An increase or decrease of 1% in the interest rate would have a corresponding decrease or increase in our net income (loss) of approximately $368,000 annually, based on the $60.0 million outstanding in the aggregate under our credit facility as of March 31, 2007.
Item 4. Controls and Procedures.
Evaluation of Disclosure Control and Procedures.
As of the end of the period covered by this Quarterly Report on Form 10−Q, our management, under the supervision and with the participation of our Chief Executive Officer and Chief Financial Officer, evaluated the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rules 13a−15(e) or 15d−15(e) under the Securities Exchange Act of 1934, as amended). Based on that evaluation, our Chief Executive Officer and Chief Financial Officer concluded that as of March 31, 2007 our disclosure controls and procedures are effective.
Disclosure controls and procedures are controls and procedures designed to ensure that information required to be disclosed in our reports filed or submitted under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported within the time periods specified in the SEC's rules and forms; and include controls and procedures designed to ensure that information is accumulated and communicated to our management, and made known to our Chief Executive Officer and Chief Financial Officer, particularly during the period when this Quarterly Report on Form 10−Q was prepared, as appropriate to allow timely decision regarding the required disclosure.
Changes in Internal Control over Financial Reporting.
There were no changes in our internal control over financial reporting that occurred during the first quarter that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.
PART II: OTHER INFORMATION
Item 1. Legal Proceedings
Due to the nature of our business, we are, from time to time, involved in routine litigation or subject to disputes or claims related to our business activities, including workers’ compensation claims and employment related disputes. In the opinion of our management, with the exception of the matters previously disclosed in our filing with the SEC, none of the pending litigation, disputes or claims against us, if decided adversely, will have a material adverse effect on our financial condition or results of operations.
Item 1A. Risk Factors
There have been no material changes to the Risk Factors previously disclosed in our Annual Report on Form 10-K for the year ended December 31, 2006 filed with the SEC on March 8, 2007.
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds
None, except as previously disclosed.
Item 3. Defaults Upon Senior Securities
Item 4. Submission of Matters to a Vote of Security Holders
None.
Item 5. Other Information
None.
Exhibits:
Exhibit No. | Description |
| 2.1 | Merger Agreement, dated as of August 11, 2005, by and among Bronco Drilling Holdings, L.L.C, Bronco Drilling Company, L.L.C. and Bronco Drilling Company, Inc. (incorporated by reference to Exhibit 2.1 to the Registration Statement on Form S-1, File No. 333-128861, filed by the Company with the SEC on October 6, 2005). |
| | |
| 2.2 | Agreement and Plan of Merger by and among the Company, BDC Acquisition Company, Eagle Well Services Inc. (“Eagle”), and the stockholders of Eagle dated as of January 9, 2007 (incorporated by reference to Exhibit 2.1 to the Company’s Current Report on Form 8-K, File No. 000-51571, filed by the Company with the SEC on January 16, 2007). |
| | |
| 3.1 | Amended and Restated Certificate of Incorporation of the Company, dated August 11, 2005 (incorporated by reference to Exhibit 2.1 to the Registration Statement on Form S-1, File No. 333-128861, filed by the Company with the SEC on October 6, 2005). |
| | |
| 3.2 | Bylaws of the Company (incorporated by reference to Exhibit 3.2 to Amendment No. 1 to the Registration Statement on Form S-1, File No. 333-125405, filed by the Company with the SEC on July 14, 2005). |
| | |
| 4.1 | Form of Common Stock certificate (incorporated by reference to Exhibit 4.1 to Amendment No. 2 to the Registration Statement on Form S-1, File No. 333-125405, filed by the Company with the SEC on August 2, 2005). |
| | |
| 10.1 | Agreement and Plan of Merger, effective as of January 9, 2007, by and between the Company, BDC Acquisition Company, Eagle Well Services, Inc., Kim Snell and the stockholders of Eagle (incorporated by reference to Exhibit 2.1 to the Current Report on Form 8-K, File No. 000-51471, filed by the Company with the SEC on January 17, 2007). |
| | |
| *31.1 | Certification of Chief Executive Officer of Bronco Drilling Company, Inc. pursuant to Rule 13a-14(a) promulgated under the Securities Exchange Act of 1934, as amended. |
| | |
| *31.2 | Certification of Chief Financial Officer of Bronco Drilling Company, Inc. pursuant to Rule 13a-14(a) promulgated under the Securities Exchange Act of 1934, as amended |
| | |
| *32.1 | Certification of Chief Executive Officer of Bronco Drilling Company, Inc. pursuant to Rule 13a-14(b) promulgated under the Securities Exchange Act of 1934, as amended, and Section 1350 of Chapter 63 of Title 18 of the United States Code. |
| | |
| *32.2 | Certification of Chief Financial Officer of Bronco Drilling Company, Inc. pursuant to Rule 13a-14(b) promulgated under the Securities Exchange Act of 1934, as amended, and Section 1350 of Chapter 63 of Title 18 of the United States Code. |
+ Management contract, compensatory plan or arrangement.
* Filed herewith.
SIGNATURE
Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on their behalf by the undersigned, thereunto duly authorized.
| | | | | |
| Dated: May 9, 2007 | | BRONCO DRILLING COMPANY, INC. |
| | | |
| | | By: | | /s/ Zachary M. Graves |
| | | | | Zachary M. Graves |
| | | | | Chief Financial Officer |
| | | | | (Principal Accounting and Financial Officer) |
| | | |
| Dated: May 9, 2007 | | By: | | /s/ D. Frank Harrison |
| | | | | D. Frank Harrison |
| | | | | Chief Executive Officer |
| | | | | (Authorized Officer and Principal Executive Officer) |
