UNITED STATESSECURITIES AND EXCHANGE COMMISSION
FORM 10-Q
OR
For the transition period from ____________ to ____________
Commission file number 0-22664
PATTERSON-UTI ENERGY, INC.
P. O. BOX 1416, 4510 LAMESA HIGHWAY, SNYDER, TEXAS, 79550(Address of principal executive offices) (Zip Code)
(325) 574-6300(Registrant’s telephone number, including area code)
N/A(Former name, former address and former fiscal year,if changed since last report)
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.
Yes [x] No [ ]
Indicate by check mark whether the registrant is an accelerated filer (as defined in Rule 12b-2 of the Exchange Act).
Indicate the number of shares outstanding of each of the issuer’s classes of common stock, as of the latest practicable date.
167,381,556 shares of common stock, $0.01 par value, as of October 29, 2004
PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIES
TABLE OF CONTENTS
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PART I — FINANCIAL INFORMATION
ITEM 1. Financial Statements
The accompanying notes are an integral part of these unaudited condensed consolidated financial statements.
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Non-Cash investing and financing activities:
In February 2004, the Company completed its merger with TMBR/Sharp Drilling, Inc. (“TMBR”) in which one of its wholly-owned subsidiaries acquired 100% of the remaining outstanding shares of TMBR for a net cash payment of approximately $32.5 million ($40.4 million paid to TMBR shareholders less $7.9 million in cash acquired in the transaction) and the issuance of 2.78 million shares of the Company’s common stock valued at $17.82 per share (adjusted to reflect the two-for-one stock split in the form of a stock dividend on June 30, 2004). The assets of TMBR included 18 land-based drilling rigs and related equipment, shop facilities, equipment yards and their oil and natural gas properties. The transaction was accounted for as a business combination and the purchase price was allocated among the assets acquired and liabilities assumed based on their estimated fair market values (See Note 2).
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1. Basis of Consolidation and Presentation
The interim condensed consolidated financial statements include the accounts of Patterson-UTI Energy, Inc. (the “Company”) and its wholly-owned subsidiaries. All significant intercompany accounts and transactions have been eliminated.
The interim condensed consolidated financial statements have been prepared by management of the Company, without audit, pursuant to the rules and regulations of the Securities and Exchange Commission. Certain information and footnote disclosures normally included in financial statements prepared in accordance with accounting principles generally accepted in the United States of America have been omitted pursuant to such rules and regulations, although the Company believes the disclosures included herein are adequate to make the information presented not misleading. In the opinion of management, all adjustments, which are of a normal recurring nature considered necessary for presentation of the information have been included. The unaudited condensed consolidated balance sheet as of December 31, 2003, as presented herein, was derived from the audited balance sheet of the Company as of December 31, 2003. These unaudited condensed consolidated financial statements should be read in conjunction with the consolidated financial statements and related notes included in the Company’s Annual Report on Form 10-K for the year ended December 31, 2003, as amended.
The U.S. dollar is the functional currency for all of the Company’s operations except for its Canadian operations, which use the Canadian dollar as their functional currency. The effects of exchange rate changes are reflected in accumulated other comprehensive income, which is a separate component of stockholders’ equity (see Note 4 of these Notes to Unaudited Condensed Consolidated Financial Statements).
On April 28, 2004, the Company’s Board of Directors authorized a two-for-one stock split in the form of a stock dividend which was distributed on June 30, 2004 to holders of record on June 14, 2004. At June 30, 2004, an adjustment was made to reclassify an amount from retained earnings to common stock to account for the par value of the common stock issued as a stock dividend. This adjustment had no overall effect on equity. The September 30, 2003 balance sheet was not restated as a result of this transaction; however, historical earnings per share amounts included in the statements of income and elsewhere in this report have been restated as if the two-for-one stock split had occurred on January 1, 2003.
The Company provides a dual presentation of its earnings per share in its Condensed Consolidated Statements of Income: Basic Earnings per Share (“Basic EPS”) and Diluted Earnings per Share (“Diluted EPS”). Basic EPS is computed using the weighted average number of shares outstanding during the periods presented. Diluted EPS includes common stock equivalents, generally stock options and warrants which are dilutive to earnings per share. For the three months ended September 30, 2004 and 2003, dilutive securities included in the calculation of Diluted EPS were 2.7 million shares and 2.6 million shares, respectively. For the nine months ended September 30, 2004 and 2003, dilutive securities included in the calculation of Diluted EPS were 3.1 million shares and 3.5 million shares, respectively. For the three and nine months ended September 30, 2004, there were 540,000 potentially dilutive options and warrants which were excluded from the calculation of Diluted EPS as their exercise price was greater than the average market price for the period. For the three and nine months ended September 30, 2003, there were 2.3 million and 1.8 million, respectively, potentially dilutive options and warrants which were excluded from the calculation of Diluted EPS as their exercise price was greater than the average market price for the period.
The results of operations for the three and nine months ended September 30, 2004 are not necessarily indicative of the results to be expected for the full year.
Certain reclassifications have been made to the 2003 consolidated financial statements in order for them to conform with the 2004 presentation.
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PATTERSON-UTI ENERGY, INC. AND SUBSIDIARIESNOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS-CONTINUED
2. Recent Acquisitions
On February 11, 2004, the Company completed its merger with TMBR/Sharp Drilling, Inc. (“TMBR”), a Texas corporation, in which one of its wholly-owned subsidiaries acquired 100% of the remaining outstanding shares of TMBR. Operations of TMBR subsequent to February 11, 2004, are included in the Company’s consolidated financial statements. The transaction was accounted for as a business combination and the purchase price was allocated among the assets acquired and liabilities assumed based on their estimated fair market values. The assets of TMBR included 18 land-based drilling rigs and related equipment, shop facilities, equipment yards and their oil and natural gas properties.
The purchase price was calculated as follows (in thousands, except per share data and exchange ratio):
The purchase price was allocated among assets acquired and liabilities assumed based on their estimated fair market values as follows (in thousands):
The purchase price allocation is based on preliminary estimates, including estimates of federal tax contingencies, which are subject to change once additional information becomes available. Changes to these estimates could result in changes to the purchase price allocation.
The Company acquired TMBR to increase its productive asset base in the Permian Basin, which is one of the most active land drilling regions in the U.S. TMBR was well established in the contract drilling industry and maintained favorable customer relationships. Goodwill was recognized in the transaction as a result of these factors.
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2. Recent Acquisitions — (continued)
The following represents pro-forma unaudited financial information as if the merger had been completed on January 1, 2003 (in thousands, except per share amounts):
Since the merger was completed on February 11, 2004, and the results of TMBR have been included subsequent to that date, no pro-forma information for the three months ended September 30, 2004 is necessary.
3. Stock-based Compensation
At September 30, 2004, the Company had seven stock-based employee compensation plans, of which three were active. The Company accounts for those plans under the recognition and measurement principles of APB Opinion No. 25, “Accounting for Stock Issued to Employees,” and related interpretations. During the second quarter of 2004, the Company granted restricted shares of the Company’s common stock (the “Restricted Shares”) to certain key employees under the Patterson-UTI Energy, Inc. 1997 Long-Term Incentive Plan, as amended. As required by APB Opinion No. 25, the Restricted Shares were valued based upon the market price of the Company’s common stock on the date of the grant. The resulting value is being amortized over the vesting period of the stock. Compensation expense of $306,000 and $471,000, net of tax, was included in net income for the three and nine months ended September 30, 2004, respectively. Other than the Restricted Shares discussed above, no additional stock-based employee compensation expense is reflected in net income, as all options granted under the plans discussed above had an exercise price equal to the market value of the underlying common stock on the date of grant. The following table illustrates the effect on net income and net income per share if the Company had applied the fair value recognition provisions of Financial Accounting Standards Board Statement No. 123, “Accounting for Stock-Based Compensation,” (“SFAS No. 123”) to stock-based employee compensation (in thousands, except per share amounts):
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4. Comprehensive Income
The following table illustrates the Company’s comprehensive income including the effects of foreign currency translation adjustments for the three and nine months ended September 30, 2004 and 2003 (in thousands):
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5. Business Segments
Our revenues, operating profits and identifiable assets are primarily attributable to four business segments: (i) contract drilling of oil and natural gas wells, (ii) pressure pumping services and (iii) drilling and completion fluid services to operators in the oil and natural gas industry, and (iv) the exploration, development, acquisition and production of oil and natural gas. Each of these segments represents a distinct type of business based upon the type and nature of services and products offered. These segments have separate management teams which report to the Company’s chief executive officer and have distinct and identifiable revenues and expenses. Separate financial data for each of our four business segments is provided below (in thousands).
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6. Recently Issued Accounting Standards
The Financial Accounting Standards Board (“FASB”) issued Interpretation No. 46R, “Consolidation of Variable Interest Entities” (“FIN 46R”) which addresses the consolidation of variable interest entities (“VIEs”) by business enterprises that are the primary beneficiaries. A VIE is an entity that does not have sufficient equity investment at risk to permit it to finance its activities without additional subordinated financial support, or whose equity investors lack the characteristics of a controlling financial interest. The primary beneficiary of a VIE is the enterprise that has the majority of the risks or rewards associated with the VIE. The Company believes it has no material interests in VIEs that require disclosure or consolidation under FIN 46R.
In March 2004, the FASB issued an exposure draft, “Share-Based Payment, an Amendment of FASB Statements No. 123 and 95”. This proposed statement would prohibit companies from using the intrinsic method of accounting for stock-based compensation currently permitted by APB No. 25, and would generally require the use of the fair-value method of accounting as prescribed in SFAS No. 123. If this exposure draft is approved, we would expect to record a charge to compensation expense associated with our employee stock options outstanding, and may incur additional compensation costs in future periods as outstanding employee stock options vest. On October 13, 2004, the FASB announced that it plans to issue a final standard related to this issue by December 31, 2004, and deferred the effective date of this proposed standard until interim and annual periods beginning after June 15, 2005.
7. Goodwill
In accordance with Statement of Financial Accounting Standards No. 142, “Goodwill and Other Intangible Assets,” goodwill is evaluated to determine if fair value of the asset has decreased below its carrying value. At December 31, 2003, we performed the annual goodwill evaluation and determined no adjustment to impair goodwill was necessary. With respect to our drilling and completion fluids business, the determination that no impairment existed as of December 31, 2003, was based on our expectations of improvement in the results of operations for that business segment. If the expected improvement in results does not continue to occur, all or part of the goodwill of approximately $10 million associated with that business segment may be determined to be impaired. Goodwill as of September 30, 2004 and December 31, 2003 are as follows (in thousands):
8. Restricted Cash
During the second quarter of 2004, the Company entered into an agreement with its workers’ compensation insurance carrier to place restrictions on approximately $11.3 million in cash which is to be used as collateral for losses which may become payable under the terms of the underlying insurance contracts. The agreement restricts the Company from using the cash in operations for an indefinite period; however, the agreement does allow the Company to replace the cash with another form of collateral (such as a letter of credit) acceptable to the insurance carrier. The restricted cash is included in other long-term assets at September 30, 2004.
9. Investment in Equity Securities
During 2002, the Company acquired approximately 19.5% of the outstanding shares of TMBR. Accordingly, the Company accounted for its investment using a method other than the equity method. On February 11, 2004, the Company acquired 100% of the remaining outstanding shares of TMBR. Accordingly, the Company was required to retroactively account for its investment using the equity method of accounting. Therefore, the Company has restated its prior period financial statements to reflect the equity method of accounting for its investment in TMBR for all prior periods.
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9. Investment in Equity Securities — (continued)
The following table presents the restated balances as of December 31, 2003 and for the three and nine months ended September 30, 2003 using the equity method of accounting for its investment in TMBR (in thousands, except per share amounts):
10. Accrued Expenses
Accrued expenses consisted of the following at September 30, 2004 and December 31, 2003 (in thousands):
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11. Asset Retirement Obligation
The FASB issued Statement of Financial Accounting Standards No. 143, “Accounting for Asset Retirement Obligations” (“SFAS No. 143”), in June 2001. SFAS No. 143 requires that, beginning in 2003, we record a liability for the estimated costs to be incurred in connection with the abandonment of oil and natural gas properties in the future. We recorded a liability of approximately $1.1 million in the first quarter of 2003 upon initial adoption of SFAS No. 143. The following table describes the changes to our asset retirement obligations during the first nine months of 2004 (in thousands):
* Includes $1,091 related to TMBR acquisition.
A charge of $469,000 (net of tax) was recorded as a cumulative effect of a change in accounting principle for the quarter ended March 31, 2003. The change relates to the cost associated with the future abandonment of oil and natural gas properties. There was no effect on diluted earnings per share as a result of the change in accounting principle for the three and nine months ended September 30, 2003.
12. Commitments, Contingencies and Other Matters
During the second quarter of 2004, the Company entered into an agreement with its workers’ compensation insurance carrier to place restrictions on approximately $11.3 million in cash which is to be used as collateral for losses which may become payable under the terms of the underlying insurance contracts. The agreement restricts the Company from using the cash in operations for an indefinite period, however, the agreement does allow the Company to replace the cash with another form of collateral (such as a letter of credit) acceptable to the insurance carrier. The restricted cash is included in other long-term assets at September 30, 2004.
The Company maintains letters of credit in the aggregate amount of $38.0 million for the benefit of various insurance companies as collateral for retrospective premiums and retained losses which could become payable under the terms of the underlying insurance contracts. These letters of credit expire at various times during each calendar year. No amounts have been drawn under the letters of credit.
We are party to various legal proceedings arising in the normal course of our business. We do not believe that the outcome of these proceedings, either individually or in the aggregate, will have a material adverse effect on our financial condition.
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13. Stockholders’ Equity
On April 28, 2004, the Company’s Board of Directors authorized a two-for-one stock split in the form of a stock dividend which was distributed on June 30, 2004 to holders of record on June 14, 2004. In connection with the two-for-one stock split, an adjustment was made to reclassify an amount from retained earnings to common stock to account for the par value of the common stock issued as a stock dividend. This adjustment had no overall effect on equity. The prior year balance sheet was not restated as a result of this transaction; however, historical earnings per share amounts included in the statements of income and elsewhere in this report have been restated as if the two-for-one stock split had occurred on January 1, 2003.
On April 28, 2004, the Company’s Board of Directors approved the initiation of a quarterly cash dividend on each share of the Company’s common stock. The first quarterly dividend in the amount of $0.02 per share, or approximately $3.3 million was paid on June 2, 2004 to holders of record as of May 17, 2004. The second quarterly dividend in the amount of $0.02 per share, or approximately $3.3 million was paid on September 1, 2004 to holders of record as of August 16, 2004. On October 27, 2004, our Board of Directors approved a cash dividend of $0.02 per share on each share of our common stock to be paid on December 1, 2004 to holders of record on November 15, 2004. The amount and timing of all future dividend payments is subject to the discretion of the Board of Directors and will depend upon business conditions, results of operations, financial conditions and other factors.
On June 7, 2004, the Company’s Board of Directors authorized a stock buyback program for the purchase of up to $30 million of outstanding shares of the Company’s common stock. During the second quarter of 2004, the Company purchased 100,000 shares of its common stock in the open market for approximately $1.5 million. These shares are included in treasury stock at September 30, 2004.
During the second quarter of 2004, the Company granted the Restricted Shares to certain key employees under the Patterson-UTI Energy, Inc. 1997 Long-Term Incentive Plan, as amended. As required by APB Opinion No. 25, the Restricted Shares were valued based upon the market price of the Company’s common stock on the date of the grant. The resulting value is being amortized over the vesting period of the stock. Compensation expense of $306,000 and $471,000, net of tax, was included in net income for the three and nine months ended September 30, 2004, respectively.
14. Subsequent Event
On October 27, 2004, the Company’s Board of Directors approved a cash dividend on each share of its common stock in the amount of $0.02 per share. The dividend is to be paid to holders of record on November 15, 2004 and paid on December 1, 2004.
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ITEM 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations
Management Overview — We are a leading provider of contract services to the North American oil and natural gas industry. Our services primarily involve the drilling, on a contract basis, of land-based oil and natural gas wells and to a lesser extent, we provide pressure pumping services and drilling and completion fluid services. In addition to the aforementioned contract services, we also engage in the development, exploration, acquisition and production of oil and natural gas. For the three and nine months ended September 30, 2004 and 2003, our operating revenues consisted of the following (dollars in thousands):
We provide our contract services to oil and natural gas operators in North America. Our contract drilling operations are focused in various regions of Texas, New Mexico, Oklahoma, Louisiana, Mississippi, Colorado, Utah, Wyoming and Western Canada, while our pressure pumping services are focused primarily in the Appalachian Basin. Our drilling and completion fluids services are provided to operators in Texas, New Mexico, Oklahoma, the Gulf Coast regions of Texas and Louisiana and the Gulf of Mexico. Our oil and natural gas operations are primarily focused in Texas, New Mexico and Mississippi.
We have been a leading consolidator of the domestic land-based contract drilling industry over the past several years by increasing our drilling fleet to 361 rigs, which we believe is the second largest drilling fleet in North America. Growth by acquisition has been a corporate strategy intended to expand both revenues and market share.
The profitability of our business is most readily assessed by two primary indicators: our average number of rigs operating and our average revenue per operating day. During the third quarter of 2004, our average number of rigs operating increased to 216 from 203 in the second quarter of 2004 and 192 in the third quarter of 2003. Our average revenue per operating day increased to $10,400 in the third quarter of 2004 from $10,200 in the second quarter of 2004 and $9,580 in the third quarter of 2003.
Our revenues, profitability and cash flows are highly dependent upon the market prices of oil and natural gas. During periods of improved commodity prices, the capital spending budgets of oil and natural gas operators tend to expand, which results in increased demand for our contract services. Conversely, in periods of time when these commodity prices deteriorate, the demand for our contract services generally weakens and we experience downward pressure on pricing for our services. Our operations are also impacted by competition, the availability of excess equipment, labor shortages and various other factors which are more fully described as risk factors in our “Forward Looking Statements and Cautionary Statements for Purposes of the ‘Safe Harbor’ Provisions of the Private Securities Litigation Reform Act of 1995” included in our Annual Report on Form 10-K for the year ended December 31, 2003, as amended, beginning on page 15.
Management believes that the liquidity of our balance sheet as of September 30, 2004, which includes approximately $196 million in working capital (including $70 million in cash), no long term debt and $62 million available under our existing $100 million line of credit (availability of $38 million is reserved for outstanding letters of credit), provides us with the ability to pursue acquisition opportunities, expand into new regions, make improvements to our assets and survive downturns in our industry.
Commitments and Contingencies — During 2004, the Company entered into an agreement with its workers’ compensation insurance carrier to place restrictions on approximately $11.3 million in cash which is to be used as collateral for losses which may become payable under the terms of the underlying insurance contracts. The agreement restricts the Company from using the cash in operations for an indefinite period, however, the agreement does allow the Company to replace the cash with another form of collateral (such as a letter of credit) acceptable to the insurance carrier. The restricted cash is included in other long-term assets at September 30, 2004.
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We have no other commitments or contingencies which require disclosure in our financial statements other than letters of credit totaling $38.0 million at September 30, 2004, maintained for the benefit of various insurance companies as collateral for retrospective premiums and retained losses which may become payable under the terms of the underlying insurance contracts. No amounts have been drawn under the letters of credit.
Trading and Investing — We have not engaged in trading activities that include high-risk securities, such as derivatives and non-exchange traded contracts. We invest cash primarily in highly liquid, short-term investments such as overnight deposits, money markets, and highly rated municipal and commercial bonds.
Description of Business — As a leading provider of onshore contract drilling services, we currently own 361 land-based drilling rigs. Our pressure pumping services consist primarily of well stimulation and cementing for completion of new wells and remedial work on existing wells. Our drilling and completion fluids services are used to control pressure when drilling oil and natural gas wells. We are also engaged in the development, exploration, acquisition, and production of oil and natural gas.
The contract drilling business experienced many downturns in demand over the last several years. During these periods, there have been substantially more drilling rigs available than necessary to meet demand in most operational and geographic segments of the North American land drilling industry. As a result, drilling contractors have had difficulty sustaining profit margins.
In addition to adverse effects that future declines in demand could have on the Company, ongoing factors which could adversely affect utilization rates and pricing, even in an environment of stronger oil and natural gas prices and increased drilling activity, include:
We cannot predict either the future level of demand for our contract drilling services or future conditions in the oil and natural gas contract drilling business.
Critical Accounting Policies
In addition to established accounting policies, our consolidated financial statements are impacted by certain estimates and assumptions made by management. The following is a discussion of our critical accounting policies pertaining to property and equipment, oil and natural gas properties, intangible assets, revenue recognition, and the use of estimates.
Property and equipment — Property and equipment, including betterments which extend the useful life of the asset, are stated at cost. Maintenance and repairs are charged to expense when incurred. We provide for the depreciation of our property and equipment using the straight-line method over the estimated useful lives. Our method of depreciation does not change when equipment becomes idle; we continue to depreciate idled equipment on a straight-line basis. No provision for salvage value is considered in determining depreciation of our property and equipment. We review our assets for impairment when events or changes in circumstances indicate that the carrying values of certain assets either exceed their respective fair values or may not be recovered over their estimated remaining useful lives. The cyclical nature of our industry has resulted in fluctuations in rig utilization over periods of time. Management believes that the contract drilling industry will continue to be cyclical and rig utilization will fluctuate. Based on management’s expectations of future trends we estimate future cash flows in our assessment of impairment assuming the following four-year industry cycle: one year projected with low utilization, one year projected as a recovery period with improving utilization and the remaining two years projecting higher utilization. Provisions for asset impairment are charged to income when estimated future cash flows, on an undiscounted basis, are less than the asset’s net book value. Impairment charges are recorded based on discounted cash flows. There were no impairment charges to property and equipment during the nine months ended September 30, 2004 or 2003.
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Oil and natural gas properties — Oil and natural gas properties are accounted for using the successful efforts method of accounting. Under the successful efforts method of accounting, exploration costs which result in the discovery of oil and natural gas reserves and all development costs are capitalized to the appropriate well. Exploration costs which do not result in discovering oil and natural gas reserves are charged to expense when such determinations are made. In accordance with Statement of Financial Accounting Standards No. 19, “Financial Accounting and Reporting by Oil and Gas Producing Companies,” (“SFAS No. 19”) costs of exploratory wells are initially capitalized to wells in progress until the outcome of the drilling is known. We review wells in progress quarterly to determine the related reserve classification. If the reserve classification is uncertain after one year following the completion of drilling, we consider the costs of the well to be impaired and recognize the costs as expense. Geological and geophysical costs, including seismic costs and costs to carry and retain undeveloped properties, are charged to expense when incurred. The capitalized costs of both developmental and successful exploratory type wells, consisting of lease and well equipment, lease acquisition costs, and intangible development costs, are depreciated, depleted, and amortized on the units-of-production method, based on petroleum engineer estimates of proved oil and natural gas reserves of each respective field. The Company reviews its proved oil and natural gas properties for impairment when an event occurs such as downward revisions in reserve estimates or decreases in oil and natural gas prices. Proved properties are grouped by field and undiscounted cash flow estimates are provided by our reserve engineer. If the net book value of a field exceeds its undiscounted cash flow estimate, impairment expense is measured and recognized as the difference between its net book value and discounted cash flow. Unproved oil and natural gas properties are reviewed quarterly to determine impairment. The Company’s intent to drill, lease expiration, and abandonment of area are considered. Assessment of impairment is made on a lease-by-lease basis. If an unproved property is determined to be impaired, then costs related to that property are expensed. Impairment expense of approximately $891,000 and $3.0 million for the three and nine months ended September 30, 2004, respectively, is included in depreciation, depletion, amortization and impairment in the accompanying financial statements.
Goodwill — Goodwill is considered to have an indefinite useful economic life and is not amortized until its life is determined to be finite. As such, we assess impairment of our goodwill annually or on an interim basis if events or circumstances indicate that the fair value of the asset has decreased below its carrying value. With respect to our drilling and completion fluids business, the determination that no impairment existed as of December 31, 2003, was based on our expectations of improvement in the results of operations for that business segment. If the expected improvement in results does not continue to occur, all or part of the goodwill of approximately $10 million associated with that business segment may be determined to be impaired.
Revenue recognition — Revenues are recognized when services are performed, except for revenues earned under turnkey contract drilling arrangements which are recognized using the completed contract method of accounting, as described below. The Company follows the percentage-of-completion method of accounting for footage contract drilling arrangements. 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. Due to the nature of turnkey contract drilling arrangements and risks therein, the Company follows the completed contract method of accounting for such arrangements. Under this method, all drilling advances and costs related to a well in progress are deferred and recognized as revenues and expenses in the period the well is completed. Provisions for losses on incomplete or in-process wells are made when estimated total costs are expected to exceed estimated total revenues.
In accordance with Emerging Issues Task Force Issue No. 00-14, the Company recognizes reimbursements received from third parties for out-of-pocket expenses incurred by the Company as revenues and accounts for out-of-pocket expenses as direct costs.
Use of estimates — The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from such estimates.
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Key estimates used by management include:
Liquidity and Capital Resources
As of September 30, 2004, we had working capital of approximately $196 million, including cash and cash equivalents of $70 million. For the nine months ended September 30, 2004, our significant sources of cash flow were approximately:
We used approximately $33 million to acquire the remaining outstanding shares of TMBR and approximately $137 million:
Additionally, approximately $6.7 million was used to pay dividends on the Company’s common stock and approximately $1.5 million was used to buy back 100,000 shares of the Company’s common stock pursuant to the stock buyback program authorized by the Company’s Board of Directors on June 7, 2004. Furthermore, restrictions on the Company’s use of approximately $11.3 million were put into place during the second quarter of 2004 as the Company pledged this cash as collateral for losses which could become payable under the terms of its workers’ compensation insurance contracts.
In February 2004, the Company completed its merger with TMBR in which one of the Company’s wholly-owned subsidiaries acquired 100% of the remaining outstanding shares of TMBR for a net cash payment of approximately $33 million ($40.4 million paid to TMBR shareholders less $7.9 million in cash acquired in the transaction) and the issuance of 2.78 million shares of the Company’s common stock valued at $17.82 per share. The assets of TMBR included 18 land-based drilling rigs and related equipment, shop facilities, equipment yards and their oil and natural gas properties. The transaction was accounted for as a business combination and the purchase price was allocated among the assets acquired and liabilities assumed based on their estimated fair market values.
We believe that the current level of cash and short-term investments, together with cash generated from operations, should be sufficient to meet our capital needs. From time to time, acquisition opportunities are reviewed. The timing, size or success of any acquisition and the associated capital commitments are unpredictable. Over the longer term, should further opportunities for growth requiring capital arise, we believe we would be able to satisfy these needs through a combination of working capital, cash generated from operations, and either debt or equity financing. However, there can be no assurance that such capital would be available.
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Commitments, Contingencies and Other Matters
During 2004, the Company entered into an agreement with its workers’ compensation insurance carrier to place restrictions on approximately $11.3 million in cash which is to be used as collateral for losses which may become payable under the terms of the underlying insurance contracts. The agreement restricts the Company from using the cash in operations for an indefinite period, however, the agreement does allow the Company to replace the cash with another form of collateral (such as a letter of credit) acceptable to the insurance carrier. The restricted cash is included in other long-term assets at September 30, 2004.
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Results of Operations
The following tables summarize operations by business segment for the three months ended September 30, 2004 and 2003:
Revenues and direct operating costs increased as a result of the increased number of operating days, as well as an increase in the average revenue and average direct operating costs per operating day. Revenue per operating day increased as a result of increased pricing for our drilling services resulting from increased demand for our contract drilling services. Significant capital expenditures were incurred during the third quarter of 2004 to modify and upgrade our existing drilling rigs and to acquire additional related equipment such as drill pipe, drill collars, engines, fluid circulating systems, rig hoisting systems and safety enhancement equipment. Increased depreciation expense was due to significant capital expenditures, including the acquisition of 19 drilling rigs and related equipment during 2003 and 18 drilling rigs and related equipment acquired during the first quarter of 2004.
Revenues and direct operating costs increased as a result of the increased number of jobs, as well as an increase in the average revenue and average direct operating costs per job. The increase in jobs in the quarter was largely due to the Company’s expanded operations in the Appalachian regions of Kentucky, Tennessee and West Virginia, as well as increased demand for our services resulting from the sustained high natural gas prices during 2004. Increased pricing for our services resulted in increased average revenue per job. General and administrative expenses increased as a result of the expanding operations of the pressure pumping segment. Increased depreciation expense for the 2004 quarter was largely due to the expansion of the pressure pumping segment during 2003 and 2004 and related expenditures to acquire necessary equipment to facilitate the growth. Capital expenditures increased in 2004 compared to 2003 due to further expansion of services into Tennessee and Wyoming as well as equipment modifications and upgrades.
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Revenues and direct operating costs increased during the third quarter of 2004 compared to the third quarter of 2003 primarily as a result of the increased number of jobs.
Oil and natural gas revenues and direct operating costs increased in the third quarter of 2004 compared to the third quarter of 2003, primarily due to the acquisition of the oil and natural gas properties acquired in the merger with TMBR during February 2004 and increased market prices received for oil and natural gas during the third quarter of 2004. Depreciation, depletion and impairment expense increased in 2004 as a result of approximately $900,000 of expenses incurred to impair certain oil and natural gas properties during the 2004 quarter and significantly increased production of oil and natural gas as a result of the aforementioned merger with TMBR.
Selling, general and administrative expenses increased as a result of increased professional expenses, and additional compensation expense related to the Company’s issuance of restricted shares to certain key employees of the Company.
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The following tables summarize operations by business segment for the nine months ended September 30, 2004 and 2003:
Revenues and direct operating costs increased as a result of the increased number of operating days, as well as an increase in the average revenue and average direct operating costs per operating day. Revenue per operating day increased as a result of increased pricing for our drilling services resulting from increased demand for our contract drilling services. Significant capital expenditures were incurred during the first nine months of 2004 to modify and upgrade our existing drilling rigs and to acquire additional related equipment such as drill pipe, drill collars, engines, fluid circulating systems, rig hoisting systems and safety enhancement equipment. Increased depreciation expense was due to significant capital expenditures, including the acquisition of 19 drilling rigs and related equipment during 2003 and 18 drilling rigs and related equipment acquired during the first quarter of 2004.
Revenues and direct operating costs increased as a result of the increased number of jobs, as well as an increase in the average revenue and average direct operating costs per job. The increase in jobs in 2004 was largely due to the Company’s continued growth in the Appalachian regions of Kentucky, Tennessee and West Virginia, as well as increased demand for our services resulting from the sustained high natural gas prices during 2004. Increased pricing for our services resulted in increased average revenue per job. General and administrative expenses increased as a result of the expanding operations of the pressure pumping segment. Increased depreciation expense during 2004 was largely due to the expansion of the pressure pumping segment during 2003 and 2004 and related expenditures to acquire necessary equipment to facilitate the growth. Capital expenditures increased in 2004 compared to 2003 due to further expansion of services into Tennessee and Wyoming as well as modifications and upgrades to existing equipment and facilities.
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Revenues and direct operating costs increased during the first nine months of 2004 compared to the first nine months of 2003 primarily as a result of the increased number of jobs, as well as an increase in the average revenue and average direct operating costs per job. Average revenue and direct operating costs per job increased as a result of an increase in the number of larger jobs in the Gulf of Mexico.
Oil and natural gas revenues and direct operating costs increased in 2004 compared to 2003, primarily due to the acquisition of the oil and natural gas properties acquired in the merger with TMBR during February 2004 and increased market prices received for oil and natural gas during the first nine months of 2004. Direct operating costs further increased as a result of approximately $600,000 of dry hole costs incurred during the 2004 period. Depreciation, depletion and impairment expense increased in 2004 primarily as a result of approximately $3.0 million of expenses incurred to impair certain oil and natural gas properties.
Selling, general and administrative expenses increased as a result of increased professional expenses, and additional compensation expense related to the Company’s issuance of restricted shares to certain key employees of the Company. In 2003, other income from operations includes a $2.5 million payment received as settlement for contract drilling services previously provided in Mexico by Norton Drilling Company Mexico, Inc., a wholly-owned subsidiary of the Company. The receivable had been reserved as uncollectible at the time of the Company’s acquisition of Norton Drilling Company Mexico, Inc. in 1999. Other income in 2003 includes approximately $1.7 million representing the Company’s pro rata share of the net income of TMBR for that nine month period, using the equity method of accounting.
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Volatility of Oil and Natural Gas Prices and its Impact on Operations
Our revenue, profitability, and future rate of growth are substantially dependent upon prevailing prices for oil and natural gas, with respect to all of our operating segments. Historically, oil and natural gas prices and markets have been volatile. Prices are affected by market supply and demand factors as well as actions of state and local agencies, the United States and foreign governments, and international cartels. All of these factors are beyond our control. Natural gas prices fell from an average of $6.23 per Mcf in the first quarter of 2001 to an average of $2.51 per Mcf for the same period in 2002. During this same period, the average number of our rigs operating dropped by approximately 50%. The average market price of natural gas improved to $5.45 in 2003 compared to $3.36 in 2002, resulting in an increase in demand for our drilling services. Our average number of rigs operating increased to 188 in 2003 from 126 in 2002. During the third quarter of 2004, the average market price of natural gas was $5.62 per Mcf and our average number of rigs operating increased to 216. We expect oil and natural gas prices to continue to be volatile and to affect our financial condition and operations and ability to access sources of capital.
Impact of Inflation
We believe that inflation will not have a significant near-term impact on our financial position.
ITEM 3. Quantitative and Qualitative Disclosures About Market Risk
We currently have no significant exposure to interest rate market risk because we have no outstanding balance under our credit facility. Should we incur a balance in the future, we would have exposure associated with the floating rate of the interest charged on that balance. The revolving credit facility calls for periodic interest payments at a floating rate ranging from LIBOR plus 1.75 % to 2.75%. The applicable rate above LIBOR (1.75% at September 30, 2004) is based upon our trailing twelve-month EBITDA (earnings before interest expense, income taxes, and depreciation, depletion, and amortization expense). Our exposure to interest rate risk due to changes in LIBOR is not expected to be material.
We conduct limited business in Canadian dollars through our Canadian land-based drilling operations. The exchange rate between Canadian dollars and U.S. dollars has fluctuated during the last ten years. If the value of the Canadian dollar against the U.S. dollar weakens, revenues and earnings of our Canadian operations will be reduced when they are translated to U.S. dollars. Also, the value of our Canadian net assets in U.S. dollars may decline.
ITEM 4. Controls and Procedures
As of the end of the period covered by this Quarterly Report on Form 10-Q, the effectiveness of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) promulgated under the Securities Exchange Act of 1934) was evaluated by our management, with the participation of our Chief Executive Officer, Cloyce A. Talbott (principal executive officer), and our Vice President, Chief Financial Officer, Secretary and Treasurer, Jonathan D. Nelson (principal financial officer). Messrs. Talbott and Nelson have concluded that our disclosure controls and procedures are effective, as of the end of the period covered by this Quarterly Report on Form 10-Q, to help ensure that information we are required to disclose in reports that we file with the SEC is accumulated and communicated to management and recorded, processed, summarized and reported within the time periods prescribed by the SEC.
There were no changes in our internal control over financial reporting that occurred during our last fiscal quarter that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.
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FORWARD LOOKING STATEMENTS AND CAUTIONARY STATEMENTS FOR PURPOSES OF THE “SAFE HARBOR” PROVISIONS OF THE PRIVATE SECURITIES LITIGATION REFORM ACT OF 1995
“Management’s Discussion and Analysis of Financial Condition and Results of Operations” included in Item 2 of this Report contains forward-looking statements which are made pursuant to the “safe harbor” provisions of the Private Securities Litigation Reform Act of 1995. These statements include, without limitation, statements relating to: liquidity; financing of operations; continued volatility of oil and natural gas prices; source and sufficiency of funds required for immediate capital needs and additional rig acquisitions (if further opportunities arise); and other matters. The words “believes,” “plans,” “intends,” “expected,” “estimates” or “budgeted” and similar expressions identify forward-looking statements. The forward-looking statements are based on certain assumptions and analyses we make in light of our experience and our perception of historical trends, current conditions, expected future developments and other factors we believe are appropriate in the circumstances. We do not undertake to update, revise or correct any of the forward-looking information. Factors that could cause actual results to differ materially from our expectations expressed in the forward-looking statements include, but are not limited to, the following:
For a more complete explanation of these various factors and others, see “Forward Looking Statements and Cautionary Statements for Purposes of the ‘Safe Harbor’ Provisions of the Private Securities Litigation Reform Act of 1995” included in our Annual Report on Form 10-K for the year ended December 31, 2003, as amended, beginning on page 15.
You are cautioned not to place undue reliance on any of our forward-looking statements, which speak only as of the date of the document or in the case of documents incorporated by reference, the date of those documents.
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PART II — OTHER INFORMATION
ITEM 6. Exhibits
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SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
DATED: October 29, 2004
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