10-Q 1 form10q3qtr.txt THIRD QUARTER FORM 10-Q 2003 SECURITIES AND EXCHANGE COMMISSION Washington, D.C. 20549 Form 10-Q [x] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the quarterly period ended September 30, 2003 OR [ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the transition period from _________ to _________ [Commission File Number 1-9260] U N I T C O R P O R A T I O N (Exact name of registrant as specified in its charter) Delaware 73-1283193 ---------- ------------ (State or other jurisdiction of (I.R.S. Employer incorporation or organization) Identification No.) 1000 Kensington Tower I, 7130 South Lewis, Tulsa, Oklahoma 74136 ----------------- ------- (Address of principal executive offices) (Zip Code) (918) 493-7700 ---------------- (Registrant's telephone number, including area code) None ------ (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). Yes X No --- --- Indicate the number of shares outstanding of each of the issuer's classes of common stock, as of the latest practicable date. Common Stock, $.20 par value 43,575,245 ------------------------------ ------------ Class Outstanding at November 4, 2003 FORM 10-Q UNIT CORPORATION TABLE OF CONTENTS Page Number PART I. Financial Information Item 1. Financial Statements (Unaudited) Consolidated Condensed Balance Sheets December 31, 2002 and September 30, 2003 . . . . . . . 2 Consolidated Condensed Statements of Income Three and Nine Months Ended September 30, 2002 and 2003. . . . . . . . . . . . . . . . . . . . . 4 Consolidated Condensed Statements of Cash Flows Nine Months Ended September 30, 2002 and 2003. . . . . 6 Consolidated Condensed Statements of Comprehensive Income Three and Nine Months Ended September 30, 2002 and 2003. . . . . . . . . . . . . . 7 Notes to Consolidated Condensed Financial Statements. . 8 Report of Independent Accountants . . . . . . . . . . . 22 Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations . . . . . . . . . . 23 Item 3. Quantitative and Qualitative Disclosure about Market Risk . . . . . . . . . . . . . . . . . . . . . . 39 Item 4. Controls and Procedures . . . . . . . . . . . . . . . . 39 PART II. Other Information Item 1. Legal Proceedings . . . . . . . . . . . . . . . . . . . 40 Item 2. Changes in Securities and Use of Proceeds . . . . . . . 40 Item 3. Defaults Upon Senior Securities. . . . . . . . . . . . 40 Item 4. Submission of Matters to a Vote of Security Holders . . 40 Item 5. Other Information . . . . . . . . . . . . . . . . . . . 40 Item 6. Exhibits and Reports on Form 8-K. . . . . . . . . . . . 41 Signatures. . . . . . . . . . . . . . . . . . . . . . . . . . . 42 1 PART I. FINANCIAL INFORMATION Item 1. Financial Statements ------------------------------ UNIT CORPORATION AND SUBSIDIARIES CONSOLIDATED CONDENSED BALANCE SHEETS (UNAUDITED) December 31, September 30, 2002 2003 ----------- ----------- (In thousands) ASSETS ------ Current Assets: Cash and cash equivalents $ 497 $ 1,765 Accounts receivable 33,912 52,734 Materials and supplies 8,794 8,510 Income tax receivable 3,602 107 Other 4,594 4,840 ----------- ----------- Total current assets 51,399 67,956 ----------- ----------- Property and Equipment: Drilling equipment 369,777 383,732 Oil and natural gas properties, on the full cost method: Proved properties 449,226 503,510 Undeveloped leasehold not being amortized 16,024 19,845 Transportation equipment 6,856 7,532 Other 9,906 12,653 ----------- ----------- 851,789 927,272 Less accumulated depreciation, depletion, amortization and impairment 341,031 370,709 ----------- ----------- Net property and equipment 510,758 556,563 ----------- ----------- Goodwill 12,794 12,794 Other Assets 3,212 6,955 ----------- ----------- Total Assets $ 578,163 $ 644,268 =========== =========== The accompanying notes are an integral part of the consolidated condensed financial statements. 2 UNIT CORPORATION AND SUBSIDIARIES CONSOLIDATED CONDENSED BALANCE SHEETS - CONTINUED (UNAUDITED) December 31, September 30, 2002 2003 ----------- ----------- (In thousands) LIABILITIES AND SHAREHOLDERS' EQUITY ------------------------------------ Current Liabilities: Current portion of long-term liabilities and debt $ 1,465 $ 741 Accounts payable 21,119 25,346 Accrued liabilities 11,948 14,795 ----------- ----------- Total current liabilities 34,532 40,882 ----------- ----------- Long-Term Debt 30,500 15,000 ----------- ----------- Other Long-Term Liabilities 5,439 17,609 ----------- ----------- Deferred Income Taxes 86,320 109,436 ----------- ----------- Shareholders' Equity: Preferred stock, $1.00 par value, 5,000,000 shares authorized, none issued - - Common stock, $.20 par value, 75,000,000 shares authorized, 43,339,400 and 43,569,227 shares issued, respectively 8,668 8,714 Capital in excess of par value 264,180 265,666 Retained earnings 148,524 186,961 ----------- ----------- Total shareholders' equity 421,372 461,341 ----------- ----------- Total Liabilities and Shareholders' Equity $ 578,163 $ 644,268 =========== =========== The accompanying notes are an integral part of the consolidated condensed financial statements. 3 UNIT CORPORATION AND SUBSIDIARIES CONSOLIDATED CONDENSED STATEMENTS OF INCOME (UNAUDITED) Three Months Ended Nine Months Ended September 30, September 30, -------------------- -------------------- 2002 2003 2002 2003 --------- --------- --------- --------- (In thousands) Revenues: Contract drilling $ 31,589 $ 50,052 $ 84,144 $129,839 Oil and natural gas 16,357 27,402 46,986 87,521 Other 326 747 625 2,267 --------- --------- --------- --------- Total revenues 48,272 78,201 131,755 219,627 --------- --------- --------- --------- Expenses: Contract drilling: Operating costs 24,350 35,653 63,619 97,105 Depreciation and amortization 4,178 6,318 9,917 17,111 Oil and natural gas: Operating costs 5,169 6,260 15,278 18,768 Depreciation, depletion and amortization 6,142 6,972 17,399 19,464 General and administrative 2,180 2,246 6,222 6,766 Interest 231 154 747 540 --------- --------- --------- --------- Total expenses 42,250 57,603 113,182 159,754 --------- --------- --------- --------- Income Before Income Taxes and Change in Accounting Principle 6,022 20,598 18,573 59,873 --------- --------- --------- --------- Income Tax Expense: Current (285) 157 75 456 Deferred 2,599 7,678 7,040 22,304 --------- --------- --------- --------- Total income taxes 2,314 7,835 7,115 22,760 --------- --------- --------- --------- Income Before Change in Accounting Principle 3,708 12,763 11,458 37,113 Cumulative Effect of Change in Accounting Principle (Net of Income Tax of $811) - - - 1,325 --------- --------- --------- --------- Net Income $ 3,708 $ 12,763 $ 11,458 $ 38,438 ========= ========= ========= ========= The accompanying notes are an integral part of the consolidated condensed financial statements. 4 UNIT CORPORATION AND SUBSIDIARIES CONSOLIDATED CONDENSED STATEMENTS OF INCOME - CONTINUED (UNAUDITED) Three Months Ended Nine Months Ended September 30, September 30, -------------------- -------------------- 2002 2003 2002 2003 --------- --------- --------- --------- (In thousands except per share amounts) Basic Earnings Per Common Share: Income before change in accounting principle $ 0.09 $ 0.29 $ 0.31 $ 0.85 Cumulative effect of change in accounting principle net of income tax - - - 0.03 --------- --------- --------- --------- Net Income $ 0.09 $ 0.29 $ 0.31 $ 0.88 ========= ========= ========= ========= Diluted Earnings Per Common Share: Income before change in accounting principle $ 0.09 $ 0.29 $ 0.30 $ 0.85 Cumulative effect of change in accounting principle net of income tax - - - 0.03 --------- --------- --------- --------- Net Income $ 0.09 $ 0.29 $ 0.30 $ 0.88 ========= ========= ========= ========= Pro Forma Amounts Assuming Retroactive Application of Change in Accounting Principle: Net income $ 3,678 $ 11,371 ========= ========= Basic earnings per share $ 0.09 $ 0.30 ========= ========= Diluted earnings per share $ 0.09 $ 0.30 ========= ========= The accompanying notes are an integral part of the consolidated condensed financial statements. 5 UNIT CORPORATION AND SUBSIDIARIES CONSOLIDATED CONDENSED STATEMENTS OF CASH FLOWS (UNAUDITED) Nine Months Ended September 30, ------------------------- 2002 2003 ---------- ---------- (In thousands) Cash Flows From Operating Activities: Net income $ 11,458 $ 38,438 Adjustments to reconcile net income to net cash provided (used) by operating activities: Depreciation, depletion, and amortization 27,789 37,135 Deferred tax expense 7,040 22,304 Other 373 237 Changes in operating assets and liabilities increasing (decreasing) cash: Accounts receivable 1,347 (19,417) Accounts payable 6,548 3,098 Material and supplies inventory (4,259) 284 Prepaid expenses 1,470 3,056 Contract advances (163) 1,228 Other - net 2,671 2,049 ---------- ---------- Net cash provided by operating activities 54,274 88,412 ---------- ---------- Cash Flows From (Used In) Investing Activities: Capital expenditures (48,825) (65,780) Proceeds from disposition of assets 1,630 960 Other-net 523 (2,555) ---------- ---------- Net cash used in investing activities (46,672) (67,375) ---------- ---------- Cash Flows From (Used In) Financing Activities: Net borrowings (payments) under line of credit (6,500) (15,500) Net payments of notes payable and other long-term debt (22) (1,074) Proceeds from exercise of stock options 213 452 Book overdrafts (1,104) (3,647) ---------- ---------- Net cash used in financing activities (7,413) (19,769) ---------- ---------- Net Increase in Cash and Cash Equivalents 189 1,268 Cash and Cash Equivalents, Beginning of Year 391 497 ---------- ---------- Cash and Cash Equivalents, End of Period $ 580 $ 1,765 ========== ========== The accompanying notes are an integral part of the consolidated condensed financial statements. 6 UNIT CORPORATION AND SUBSIDIARIES CONSOLIDATED CONDENSED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED) Three Months Ended Nine Months Ended September 30, September 30, ---------------------- ---------------------- 2002 2003 2002 2003 ---------- ---------- ---------- ---------- (In thousands) Net Income $ 3,708 $ 12,763 $ 11,458 $ 38,438 Other Comprehensive Income, Net of Taxes: Change in value of cash flow derivative instruments used as cash flow hedges - 74 - (4) Reclassification of derivative settlements - - - 4 ---------- ---------- ---------- ---------- Comprehensive Income $ 3,708 $ 12,837 $ 11,458 $ 38,438 ========== ========== ========== ========== The accompanying notes are an integral part of the consolidated condensed financial statements. 7 UNIT CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED CONDENSED FINANCIAL STATEMENTS NOTE 1 - BASIS OF PREPARATION AND PRESENTATION ---------------------------------------------- The accompanying unaudited consolidated condensed financial statements include the accounts of Unit Corporation and its wholly owned subsidiaries (company) and have been prepared under the rules and regulations of the Securities and Exchange Commission. As applicable under these regulations, certain information and footnote disclosures have been condensed or omitted and the consolidated condensed financial statements do not include all disclosures required by generally accepted accounting principles. In the opinion of the company, the unaudited consolidated condensed financial statements contain all adjustments necessary (all adjustments are of a normal recurring nature) to present fairly the interim financial information. Results for the three and nine months ended September 30, 2003 are not necessarily indicative of the results to be realized during the full year. The condensed financial statements should be read in conjunction with the company's Annual Report on Form 10-K for the year ended December 31, 2002. Our independent accountants have performed a review of these interim financial statements in accordance with standards established by the American Institute of Certified Public Accountants. Under Rule 436(c) of the Securities Act of 1933, their report of that review should not be considered as part of any registration statements prepared or certified by them within the meaning of Section 7 and 11 of that Act and the independent accountants' liability under Section 11 does not extend to them. Because the company does not bear the risk of completion of wells drilled under daywork drilling contracts, it recognizes revenues and expenses from those contracts as the services are performed (i.e. daily). Under "footage" and "turnkey" contracts, revenues and expenses are recognized when the company has satisfied certain requirements detailed in the contracts. If it is determined that a well is going to incur a loss, the entire amount of the estimated loss is recorded when the loss can be determined, however, any profit is recorded only at the time the terms of the contract are completed. The costs of uncompleted drilling contracts include expenses incurred to date on "footage" or "turnkey" contracts, which are still in process at the end of the period, and are included in other current assets. The company's stock-based compensation plans are accounted for under the recognition and measurement principles of APB 25, "Accounting for Stock Issued to Employees," and related Interpretations. No stock-based employee compensation cost related to stock options is reflected in net income, as all options granted under the plan had an exercise price equal to the market value of the underlying common stock on the date of grant. Compensation expense included in reported net income is the company's matching 401(k) contribution. The following table illustrates the effect on net income and earnings per share if the company had applied the fair 8 value recognition provisions of Financial Accounting Standards Board Statement No. 123, "Accounting for Stock-Based Compensation," to stock-based employee compensation. Three Months Ended Nine Months Ended -------------------- -------------------- 2002 2003 2002 2003 --------- --------- --------- --------- (In thousands except per share amounts) Net Income, as Reported $ 3,708 $ 12,763 $ 11,458 $ 38,438 Add Stock-Based Employee Compensation Expense Included in Reported Net Income - Net of Tax 160 238 480 573 Less Total Stock-Based Employee Compensation Expense Determined Under Fair Value Based Method For All Awards (370) (578) (969) (1,453) --------- --------- --------- --------- Pro Forma Net Income $ 3,498 $ 12,423 $ 10,969 $ 37,558 ========= ========= ========= ========= Basic Earnings per Share: As reported $ 0.09 $ 0.29 $ 0.31 $ 0.88 ========= ========= ========= ========= Pro forma $ 0.09 $ 0.29 $ 0.29 $ 0.86 ========= ========= ========= ========= Diluted Earnings per Share: As reported $ 0.09 $ 0.29 $ 0.30 $ 0.88 ========= ========= ========= ========= Pro forma $ 0.09 $ 0.28 $ 0.29 $ 0.86 ========= ========= ========= ========= The fair value of each option is estimated using the Black-Scholes model. In the third quarter of 2003, options were granted for 5,000 shares and for each of the nine month periods ended September 30, 2002 and 2003 options were granted for 26,000 shares. No options were granted in the third quarter of 2002. The options granted in the third quarter of 2003 have a fair value of approximately $67,000. The total options granted during the nine month periods ended September 30, 2002 and 2003 have fair values of approximately $320,000 and $329,000, respectively. For options granted in fiscal 2002 and 2003, the company's estimate of stock volatility was 0.53, based on previous stock performance. Dividend yield 9 was estimated to remain at zero with a risk free interest rate of 4.24 percent in 2002 and interest rates ranging from 3.60 to 4.72 percent in 2003. Expected life ranged from 1 to 10 years based on prior experience depending on the vesting periods involved and the make up of participating employees. The company manages its exposure to environmental liabilities on properties to be acquired by identifying existing problems and assessing the potential liability. The company also conducts periodic reviews, on a company-wide basis, to identify changes in its environmental risk profile. These reviews evaluate whether there is a probable liability, its amount, and the likelihood that the liability will be incurred. The amount of any potential liability is determined by considering, among other matters, incremental direct costs of any likely remediation and the proportionate cost of employees who are expected to devote a significant amount of time directly to any possible remediation effort. As it relates to evaluations of purchased properties, depending on the extent of an identified environmental problem, the company may exclude a property from the acquisition, require the seller to remediate the property to Unit's satisfaction, or agree to assume liability for the remediation of the property. To date, the company has not experienced any substantial environmental liability. All liabilities incurred to date have been small and have been resolved in a timely manner. 10 NOTE 2 - EARNINGS PER SHARE --------------------------- The following data shows the amounts used in computing earnings per share for the company. WEIGHTED INCOME SHARES PER-SHARE (NUMERATOR) (DENOMINATOR) AMOUNT ----------- ------------- ---------- (In thousands except) per share amounts) For the Three Months Ended September 30, 2002: Basic earnings per common share $ 3,708 39,804 $ 0.09 ========== Effect of dilutive stock options - 267 ----------- ------------- Diluted earnings per common share $ 3,708 40,071 $ 0.09 =========== ============= ========== For the Three Months Ended September 30, 2003: Basic earnings per common share $ 12,763 43,556 $ 0.29 ========== Effect of dilutive stock options - 180 ----------- ------------- Diluted earnings per common share $ 12,763 43,736 $ 0.29 =========== ============= ========== The following options and their average exercise prices were not included in the computation of diluted earnings per share for the three months ended September 30, 2002 and September 30, 2003 because the option exercise prices were greater than the average market price of common shares: 2002 2003 ---------- ---------- Options 179,000 5,000 ========== ========== Average exercise price $ 17.23 $ 21.50 ========== ========== 11 WEIGHTED INCOME SHARES PER-SHARE (NUMERATOR) (DENOMINATOR) AMOUNT ----------- ------------- ---------- (In thousands except) per share amounts) For the Nine Months Ended September 30, 2002: Basic earnings per common share $ 11,458 37,330 $ 0.31 ========== Effect of dilutive stock options - 264 ----------- ------------- Diluted earnings per common share $ 11,458 37,594 $ 0.30 =========== ============= ========== For the Nine Months Ended September 30, 2003: Basic earnings per common share: Income before change in accounting principle $ 37,113 43,503 $ 0.85 Cumulative effect of change in accounting principle net of income tax 1,325 43,503 0.03 ----------- ---------- Net Income $ 38,438 43,503 $ 0.88 =========== ========== Diluted earnings per common share: Weighted average number of common shares used in basic earnings per common share 43,503 Effect of dilutive stock options 174 ------------- Weighted average number of common shares and dilutive potential common shares used in diluted earnings per share 43,677 ============= Income before change in accounting principle $ 37,113 43,677 $ 0.85 Cumulative effect of change in accounting principle net of income tax 1,325 43,677 0.03 ----------- ---------- Net Income $ 38,438 43,677 $ 0.88 =========== ========== 12 The following options and their average exercise prices were not included in the computation of diluted earnings per share for the nine months ended September 30, 2002 and 2003 because the option exercise prices were greater than the average market price of common shares: 2002 2003 ---------- ---------- Options 179,000 26,000 ========== ========== Average exercise price $ 17.23 $ 20.37 ========== ========== NOTE 3 - NEW ACCOUNTING PRONOUNCEMENTS -------------------------------------- Goodwill represents the excess of the cost of the acquisition of Hickman Drilling Company, CREC Rig Equipment Company and CDC Drilling Company over the fair value of the net assets acquired. Prior to January 1, 2002 goodwill was amortized on the straight-line method using a 25 year life. The company expensed $243,000 annually for the amortization of goodwill. On July 20, 2001, the Financial Accounting Standards Board (FASB) issued Statement of Financial Accounting Standards No. 142, "Goodwill and Other Intangible Assets" (FAS 142). For goodwill and intangible assets recorded in the financial statements, FAS 142 ended the amortization of goodwill and certain intangible assets and subsequently requires, at least annually, that an impairment test be performed on such assets to determine whether the fair value has declined to a level below the carrying value. FAS 142 became effective for the fiscal years starting after December 15, 2001 (January 1, 2002 for the company). Goodwill is all related to the drilling segment. In 2002 the carrying amount of Goodwill increased by $7,706,000 from the goodwill acquired in the acquisition of CREC Rig Equipment Company and CDC Drilling Company. Goodwill of $7,009,000 is expected to be deductible for tax purposes. 13 The following table shows the adjusted net income and earnings per share resulting from the removal of the amortization expense (net of income tax) recognized in the prior year ended periods: 2000 2001 2002 ------------ ------------ ------------ (In thousands except per share amounts) Adjusted Net Income: Reported net income $ 34,344 $ 62,766 $ 18,244 Add back: Goodwill amortized - net of income tax 92 88 - ------------ ------------ ------------ Adjusted net income $ 34,436 $ 62,854 $ 18,244 ============ ============ ============ Basic Earnings per Share: Reported net income $ 0.96 $ 1.75 $ 0.47 Add back: Goodwill amortized - net of income tax - - - ------------ ------------ ------------ Adjusted basic earnings per share $ 0.96 $ 1.75 $ 0.47 ============ ============ ============ Diluted Earnings per Share: Reported net income $ 0.95 $ 1.73 $ 0.47 Add back: Goodwill amortized - net of income tax - - - ------------ ------------ ------------ Adjusted diluted earnings per share $ 0.95 $ 1.73 $ 0.47 ============ ============ ============ On January 1, 2003 the company adopted Financial Accounting Standards No. 143, "Accounting for Asset Retirement Obligations" (FAS 143). FAS 143 establishes an accounting standard requiring the recording of the fair value of liabilities associated with the retirement of long-lived assets. The company owns oil and natural gas properties which require expenditures to plug and abandon the wells when the oil and natural gas reserves in the wells are depleted. These expenditures under FAS 143 are recorded in the period in which the liability is incurred (at the time the wells are drilled or acquired). The company does not have any assets restricted for the purpose of settling the plugging liabilities. 14 The following table shows the activity for the nine months ending September 30, 2003 relating to the company's retirement obligation for plugging liability: Short-Term Long-Term Plugging Plugging Liability Liability ------------- ------------- (In Thousands) Plugging Liability 1/1/03 $ 203 $ 10,632 Accretion of Discount 8 369 Liability Incurred in the Period - 529 Liability Settled in the Period - (106) Reclassification of Liability From Long- to Short-Term 181 (181) ------------- ------------- Plugging Liability 9/30/03 $ 392 $ 11,243 ============= ============= The effect of this change increased net property, plant and equipment by $13.0 million and liabilities, including deferred tax liabilities, by $11.7 million at January 1, 2003 and decreased net income for the three and nine month periods ended September 30, 2003 by $36,000 ($0.00 per share) and $111,000 ($0.00 per share), respectively. The financial statements for the three and nine months ended September 30, 2002 have not been restated and the cumulative effect of the change of $1.3 million net of tax ($0.03 per share) is shown as a one-time addition to income in the first quarter of 2003. 15 The following table shows the adjusted net income and earnings per share resulting from the accretion of the discount and change in the depreciation, depletion and amortization (both net of income tax) as if the plugging liability had been recognized in the prior year ended periods: 2000 2001 2002 ----------- ----------- ----------- (In thousands except per share amounts) Adjusted Net Income: Reported net income $ 34,344 $ 62,766 $ 18,244 Add back: Decrease in depreciation, depletion and amortiza- tion - net of income tax 80 156 167 Deduct: Accretion of discount - net of income tax (231) (260) (296) ----------- ----------- ----------- Adjusted net income $ 34,193 $ 62,662 $ 18,115 =========== =========== =========== Basic Earnings per Share: Reported net income $ 0.96 $ 1.75 $ 0.47 Net adjustment to income from change in accounting principle - (0.01) - ----------- ----------- ----------- Adjusted basic earnings per share $ 0.96 $ 1.74 $ 0.47 =========== =========== =========== Diluted Earnings per Share: Reported net income $ 0.95 $ 1.73 $ 0.47 Net adjustment to income from change in accounting principle - - (0.01) ----------- ----------- ----------- Adjusted diluted earnings per share $ 0.95 $ 1.73 $ 0.46 =========== =========== =========== If FAS 143 had been applied at January 1, 2000 and December 31, 2000, 2001 and 2002, the plugging liability would have been $8.0, $8.7, $9.7 and $10.8 million, respectively, assuming the liability was measured using the information, assumptions and interest rates used as of the adoption date of January 1, 2003. 16 On January 1, 2003, the company adopted Financial Accounting Standards No. 145, "Rescission of FASB Statements No. 4, 44 and 64, Amendment of FASB Statement 13, and Technical Corrections" (FAS 145). This statement eliminates an inconsistency between the required accounting for sale-leaseback transactions and the required accounting for certain lease modifications that have economic effects that are similar to sale-leaseback transactions. This statement also amends other existing authoritative pronouncements to make various technical corrections, clarify meanings, or describe their applicability under changed conditions. The adoption of FAS 145 did not have a material effect on the company's financial position, results of operations or cash flows. In July 2002, the FASB issued Statement of Financial Accounting Standards No. 146, "Accounting for Cost Associated with Exit or Disposal Activities" (FAS 146). FAS 146 is effective for exit or disposal activities initiated after December 31, 2002. The Statement addresses financial accounting and reporting for costs associated with exit or disposal activities and requires companies to recognize costs associated with exit or disposal activities when they are incurred rather than at the date of a commitment to an exit or disposal plan. FAS 146 nullifies Emerging Issues Task Force Issue No. 94-3, "Liability Recognition for Certain Employee Termination Benefits and Other Costs to Exit an Activity (including Certain Costs Incurred in a Restructuring)." During the first nine months of 2003, the company did not have any exit or disposal activities. In April 2003, the FASB issued Statement of Financial Accounting Standards No. 149, "Amendment of Statement 133 on Derivative Instruments and Hedging Activities" (FAS 149). The Statement is effective for contracts entered into or modified after June 30, 2003 for hedging contracts like the company's. FAS 149 amends and clarifies financial accounting and reporting for derivative instruments, including certain derivative instruments embedded in other contracts (collectively referred to as derivatives) and for hedging activities under FAS No. 133, "Accounting for Derivative Instruments and Hedging Activities". The company does not expect the application of SFAS 149 to have a material effect on its financial position, results of operations or cash flows. During May 2003, the FASB issued Statement on Financial Accounting Standards No. 150, "Accounting for Certain Financial Instruments with Characteristics of both Liabilities and Equity" (FAS 150). FAS 150 establishes standards regarding the classification and measurement of certain financial instruments with characteristics of both liabilities and equity. It requires that an issuer classify a financial instrument that is within its scope as a liability (or an asset in some circumstances). Many of those instruments were previously classified as equity. FAS 150 became effective for the company starting in the quarter ended September 30, 2003. The company's financial position, results of operations or cash flows were not materially effected by the application of SFAS 150. On January 17, 2003, the FASB issued FASB Interpretation No. 46, "Consolidation of Variable Interest Entities, an interpretation of ARB 51" (FIN 46). The primary objectives of FIN 46 are to provide guidance on the 17 identification of entities for which control is achieved through means other than through voting rights ("variable interest entities" or "VIEs") and how to determine when and which business enterprise should consolidate the VIE. This new model for consolidation applies to an entity which either (1) the equity investors (if any) do not have a controlling financial interest or (2) the equity investment at risk is insufficient to finance that entity's activities without receiving additional subordinated financial support from other parties. FIN 46 is effective for periods ending after December 15, 2003 (December 31, 2003 for the company). The company is currently evaluating the impact of FIN 46 on its financial position and results of operations. NOTE 4 - INTANGIBLE UNDEVELOPED LEASEHOLD AND INTANGIBLE DEVELOPED LEASEHOLD ---------------------------------------------------------------------------- Statement of Financial Accounting Standards No. 141, "Business Combinations" (FAS 141) and Statement of Financial Accounting Standards, No. 142, "Goodwill and Intangible Assets" (FAS 142) were issued by the the FASB in June 2001 and became effective for the company on July 1, 2001 and January 1, 2002, respectively. FAS 141 requires all business combinations initiated after June 30, 2001 to be accounted for using the purchase method. Additionally, FAS 141 requires companies to disaggregate and report separately from goodwill certain intangible assets. FAS 142 establishes new guidelines for accounting for goodwill and other intangible assets. Under FAS 142, goodwill and certain other intangible assets are not amortized, but rather are reviewed annually for impairment. Depending on how the accounting and disclosure literature is applied, oil and gas mineral rights held under lease and other contractual arrangements representing the right to extract oil and natural gas reserves for both undeveloped and developed leaseholds may be classified separately from oil and gas properties, as intangible assets on our balance sheets. In addition, the notes to the company's financial statements would include the disclosures required by FAS 141 and 142 regarding intangibles. To date, the company, like many other oil and gas companies, has included oil and gas extraction rights as part of the oil and gas properties, even after FAS 141 and 142 became effective. The company's results of operations and cash flows would not be affected, since these oil and gas mineral extraction rights would continue to be amortized in accordance with full cost accounting rules. At September 30, 2003, the company had undeveloped leaseholds of approximately $16.6 million that would be classified on our balance sheet as "intangible undeveloped leasehold" and developed leaseholds of an estimated $21.3 million that would be classified as "intangible developed leasehold" if the interpretations were applied. This classification would require the company to make the disclosures set forth under FAS 142 related to these interests. The company intends to continue to classify our oil and gas mineral extraction rights as tangible oil and gas properties until further guidance is provided. 18 NOTE 5 - HEDGING ACTIVITY ------------------------- Periodically the company hedges the price it will receive for a portion of its future natural gas and oil production. The hedge is made in an attempt to reduce the impact and uncertainty that price variations have on Unit's cash flow. During the first quarter of 2003, the company entered into two natural gas collar contracts for approximately 37 percent of its April through September 2003 production. One contract had a floor price of $4.00 and a ceiling price of $5.75. The other contract had a floor price of $4.50 and a ceiling price of $6.02. During the first quarter of 2003, the company also entered into two oil collar contracts for approximately 26 percent of its May through December 2003 oil production. One contract has a floor price of $25.00 and a ceiling price of $32.20. The other contract has a floor price of $26.00 and a ceiling price of $31.40. The company had a $6,000 reduction in natural gas revenues because of the natural gas hedges settled in the second quarter of 2003 and a $1,000 reduction in oil revenues because of the oil hedges settled in the third quarter of 2003. Since the amount was immaterial, no fair value was recognized on the September 2003 balance sheet or in accumulated other comprehensive income for the oil collar contracts which remained outstanding at the end of the period. These hedges were fully effective. The company did not have any hedging contracts in place in the first nine months of 2002. NOTE 6 - INDUSTRY SEGMENT INFORMATION ------------------------------------- The company has two business segments: Contract Drilling (Unit Drilling Company), and Oil and Natural Gas (Unit Petroleum Company), representing its two strategic business units offering different products and services. The Contract Drilling segment provides land contract drilling of oil and natural gas wells and the Oil and Natural Gas segment is engaged in the development, acquisition and production of oil and natural gas properties. The company evaluates the performance of its operating segments based on operating income, which is defined as operating revenues less operating expenses and depreciation, depletion and amortization. The company has natural gas production in Canada, which is not significant. Information regarding the company's operations by industry segment for the three and nine month periods ended September 30, 2002 and 2003 is as follows: 19 Three Months Ended Nine Months Ended September 30, September 30, ---------------------- ---------------------- 2002 2003 2002 2003 ---------- ---------- ---------- ---------- (In thousands) Revenues: Contract drilling $ 31,589 $ 50,052 $ 84,144 $ 129,839 Oil and natural gas 16,357 27,402 46,986 87,521 Other 326 747 625 2,267 ---------- ---------- ---------- ---------- $ 48,272 $ 78,201 $ 131,755 $ 219,627 ========== ========== ========== ========== Operating Income (1): Contract drilling $ 3,061 $ 8,081 $ 10,608 $ 15,623 Oil and natural gas 5,046 14,170 14,309 49,289 ---------- ---------- ---------- ---------- Total operating income 8,107 22,251 24,917 64,912 General and administrative expense (2,180) (2,246) (6,222) (6,766) Interest expense (231) (154) (747) (540) Other income - net 326 747 625 2,267 ---------- ---------- ---------- ---------- Income before income taxes and change in accounting principle $ 6,022 $ 20,598 $ 18,573 $ 59,873 ========== ========== ========== ========== (1) Operating income is total operating revenues less operating expenses, depreciation, depletion and amortization and does not include non-operating revenues, general corporate expenses, interest expense or income taxes. The cumulative effect of change in accounting principle recorded in the first quarter of 2003 of $1.3 million, net of $811,000 in income tax, is all related to the oil and natural gas segment. 20 NOTE 7 - ACQUISITIONS --------------------- On August 14, 2003 the company signed a definitive agreement with PetroCorp Incorporated (AMEX - PEX) to acquire all the outstanding shares of PetroCorp. The purchase price under the agreement is approximately $182.1 million and will be paid in cash. The purchase price is subject to certain adjustments including up to $6.5 million which may be placed in escrow to settle or satisfy certain contingent tax and litigation liabilities if not resolved prior to closing. Consummation of the transaction is subject to several conditions typical of transactions of this nature including regulatory review and the approval by two-thirds of PetroCorp's shareholders. PetroCorp shareholders representing approximately 50% of the outstanding shares of PetroCorp have agreed to support the merger. PetroCorp is a Tulsa-based company that explores and develops oil and natural gas properties primarily in Texas and Oklahoma. On August 15, 2002, the company completed the acquisition of CREC Rig Equipment Company and CDC Drilling Company. Both of these acquisitions were stock purchase transactions. The company issued 6,819,748 shares of common stock and paid $3,813,053 for all the outstanding shares of CREC Rig Equipment Company and issued 400,252 shares of common stock and paid $686,947 for all the outstanding shares of CDC Drilling Company. The assets of the acquired companies included twenty drilling rigs, spare drilling equipment and vehicles. The purchase price for both transactions was determined through arms-length negotiations between the parties and only the cash portion of the transaction appears in the investing and financing activities of Unit's Consolidated Condensed Statement of Cash Flows. The results of operations for the acquired entities are included in the statement of operations for the periods beginning after August 15, 2002. 21 REPORT OF INDEPENDENT ACCOUNTANTS To the Board of Directors and Shareholders Unit Corporation We have reviewed the accompanying consolidated condensed balance sheet of Unit Corporation and subsidiaries as of September 30, 2003, and the related consolidated condensed statements of income and comprehensive income for each of the three and nine month periods ended September 30, 2003 and 2002 and the statement of cash flows for the nine month periods ended September 30, 2003 and 2002. These financial statements are the responsibility of the Company's management. We conducted our review in accordance with standards established by the American Institute of Certified Public Accountants. A review of interim financial information consists principally of applying analytical procedures and making inquiries of persons responsible for financial and accounting matters. It is substantially less in scope than an audit conducted in accordance with generally accepted auditing standards, the objective of which is the expression of an opinion regarding the financial statements taken as a whole. Accordingly, we do not express such an opinion. Based on our review, we are not aware of any material modifications that should be made to the accompanying condensed consolidated interim financial statements for them to be in conformity with accounting principles generally accepted in the United States of America. We previously audited, in accordance with auditing standards generally accepted in the United States of America, the consolidated balance sheet as of December 31, 2002, and the related consolidated statements of operations, shareholder's equity and of cash flows for the year then ended (not presented herein), and in our report, dated February 19, 2003, we expressed an unqualified opinion on those consolidated financial statements. In our opinion, the information set forth in the accompanying consolidated balance sheet information as of December 31, 2002, is fairly stated in all material respects in relation to the consolidated balance sheet from which it has been derived. PricewaterhouseCoopers L L P Tulsa, Oklahoma October 22, 2003 22 Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations --------------------------------------------------------------------------- FINANCIAL CONDITION ------------------- Summary. Our financial condition and liquidity depends on the cash flow from our two principal subsidiaries (Unit Drilling Company and Unit Petroleum Company) and borrowings under our bank loan agreement. At September 30, 2003, we had cash totaling $1.8 million and we had borrowed $15.0 million of the $40.0 million we have elected to have available under our loan agreement. The following is a summary of certain financial information on September 30, 2002 and 2003 and for the nine months ended September 30, 2002 and 2003: September 30, September 30, Percent 2002 2003 Change -------------- -------------- ------- (In thousands except percent amounts) Income Before Change in Accounting Principle $ 11,458 $ 37,113 224% Net Income $ 11,458 $ 38,438 235% Net Cash Provided by Operating Activities $ 54,274 $ 88,412 63% Net Cash Used in Investing Activities $ 46,672 $ 67,375 44% Net Cash Used in Financing Activities $ 7,413 $ 19,769 167% Working Capital $ 16,093 $ 27,074 68% Long-Term Debt $ 24,500 $ 15,000 (39%) Shareholders' Equity $ 414,386 $ 461,341 11% Ratio of Long-Term debt to Total Capitalization 6% 3% The following table summarizes certain operating information for the first nine months of 2002 and 2003: Percent 2002 2003 Change ---------- ---------- -------- Oil Production (MBbls) 347 372 7% Natural Gas Production (MMcf) 14,360 15,043 5% Average Oil Price Received $ 20.92 $ 27.02 29% Average Natural Gas Price Received $ 2.59 $ 5.05 95% Average Number of Our Drilling Rigs in Use During the Period 36.2 60.6 67% Total Number of Our Drilling Rigs Available at the End of the Period 75 75 - 23 Our Bank Loan Agreement. On July 24, 2001, we signed a $100 million bank loan agreement. At our election, the amount currently available for us to borrow is $40 million. Although the current value of our assets would allow us to have access to the full $100 million, we elected to set the loan commitment at $40 million. We did this to reduce our financing costs since we are charged a facility fee of .375 of 1 percent on the amount available but not borrowed. Each year, on April 1 and October 1, our banks redetermine the loan value of our assets. At the October 1, 2003 redetermination date, the banks confirmed that the value of our assets would allow us to have access to the full $100 million. This value is mainly based on an amount equal to a percentage of the discounted future value of our oil and natural gas reserves, as determined by the banks. In addition, an amount representing a part of the value of our drilling rig fleet, limited to $20 million, is added to the loan value. Our loan agreement provides for a revolving credit facility, which ends on May 1, 2005 followed by a three-year term loan. Borrowing under our loan agreement totaled $15.0 million at September 30, 2003 and on October 22, 2003 our third quarter earnings release date. Borrowings under the revolving credit facility bear interest at the JP Morgan Chase prime rate ("Prime Rate") or the London Interbank Offered Rates ("Libor Rate") plus 1.00 to 1.50 percent depending on the level of debt as a percentage of the total loan value. After May 1, 2005, borrowings under the loan agreement bear interest at the Prime Rate or the Libor Rate plus 1.25 to 1.75 percent depending on the level of debt as a percentage of the total loan value. In addition, the loan agreement allows us to select, between the date of the agreement and 3 days before the start of the term loan, a fixed rate for the amount outstanding under the credit facility. Our ability to select the fixed rate option is subject to several conditions, all of which are set out in the loan agreement. The interest rate on our bank debt was 2.16 percent at September 30, 2003 and October 22, 2003. At our election, any portion of our outstanding bank debt may be fixed at the Libor Rate, as adjusted depending on the level of our debt as a percentage of the amount available for us to borrow. The Libor Rate may be fixed for periods of up to 30, 60, 90 or 180 days with the balance of our bank debt being subject to the Prime Rate. During any Libor Rate funding period, we may not pay any part of the outstanding principal balance which is subject to the Libor Rate. Borrowings subject to the Libor Rate were $15.0 million at September 30, 2003 and October 22, 2003. The loan agreement also requires us to maintain: . consolidated net worth of at least $125 million; . a current ratio of not less than 1 to 1; . a ratio of long-term debt, as defined in the loan agreement, to consolidated tangible net worth not greater than 1.2 to 1; . a ratio of total liabilities, as defined in the loan agreement, to consolidated tangible net worth not greater than 1.65 to 1; and 24 . working capital provided by operations, as defined in the loan agreement, cannot be less than $40 million in any year. We are restricted from paying dividends (other than stock dividends) during any fiscal year in excess of 25 percent of our consolidated net income from the preceding fiscal year and we can pay dividends only if our working capital provided from our operations during the preceding year is equal to or greater than 175 percent of current maturities of long-term debt at the end of the preceding year. We also cannot incur additional debt except in certain limited exceptions and the creation or existence of mortgages or liens, other than those in the ordinary course of business, on any of our property is prohibited unless it is in favor of our banks. We are negotiating with our lead bank under our current loan agreement to establish a new loan agreement. The new agreement would replace our current agreement and we anticipate the new agreement would provide for a maximum loan commitment of $150,000,000. Currently, we anticipate that the effective date for the new loan agreement would be contingent on the closing of our pending acquisition of PetroCorp which is discussed above. Contractual Commitments. We have the following contractual obligations at September 30, 2003: Payments Due by Period -------------------------------------------------- Less Contractual Than 1 2-3 4-5 After 5 Obligations Total Year Years Years Years ------------- --------- -------- -------- --------- -------- (In thousands) Bank Debt(1) $ 15,000 $ - $ 6,667 $ 8,333 $ - Retirement Agreement(2) 1,392 300 600 492 - Operating Leases(3) 3,811 728 1,441 1,062 580 --------- -------- -------- --------- -------- Total Contractual Obligations $ 20,203 $ 1,028 $ 8,708 $ 9,887 $ 580 ========= ======== ======== ========= ======== ------------------- (1) See previous discussion in Management Discussion and Analysis regarding bank debt. (2) In the second quarter of 2001, we recorded $1.3 million in additional employee benefit expenses for the present value of a separation agreement made in connection with the retirement of King Kirchner from his position as Chief Executive Officer. The liability associated with this expense, including accrued interest, will be paid in monthly payments of $25,000 starting in July 2003 and continuing through June 2009. 25 (3) We lease office space in Tulsa and Woodward Oklahoma and Houston and Booker Texas under the terms of operating leases expiring through January 31, 2010 along with leasing space on short term commitments to stack excess rig equipment and production inventory. In the first quarter of 2003, we renegotiated our rental agreement for the Tulsa office reducing the price per square foot while adding additional space and lengthening the term of the agreement to January 31, 2010. At September 30, 2003, we also have the following commitments and contingencies that could create, increase or accelerate our liabilities: Amount of Commitment Expiration Per Period -------------------------------------- Total Amount Committed Less Other Or Than 1 2-3 4-5 After 5 Commitments Accrued Year Years Years Years --------------- --------- -------- -------- -------- -------- (In thousands) Deferred Compensation Agreement(1) $ 1,685 Unknown Unknown Unknown Unknown Separation Benefit Agreement(2) $ 2,617 $ 49 Unknown Unknown Unknown Plugging Liability(3) $ 11,635 $ 392 $ 2,049 $ 644 $ 8,550 Gas Balancing Liability(4) $ 1,020 Unknown Unknown Unknown Unknown Repurchase Obliga- tions(5) Unknown Unknown Unknown Unknown Unknown (1) We provide a salary deferral plan which allows participants to defer the recognition of salary for income tax purposes until actual distribution of benefits, which occurs at either termination of employment, death or certain defined unforeseeable emergency hardships. We recognize payroll expense and record a liability, included in other long-term liabilities in our Consolidated Balance Sheet, at the time of deferral. (2) Effective January 1, 1997, we adopted a separation benefit plan ("Separation Plan"). The Separation Plan allows eligible employees whose employment with us is involuntarily terminated or, in the case of an employee who has completed 20 years of service, voluntarily or involuntarily terminated, to receive benefits equivalent to 4 weeks salary for every whole year of service completed with Unit up to a maximum of 104 weeks. To receive payments the recipient must waive any claims against us 26 in exchange for receiving the separation benefits. On October 28, 1997, we adopted a Separation Benefit Plan for Senior Management ("Senior Plan"). The Senior Plan provides certain officers and key executives of Unit with benefits generally equivalent to the Separation Plan. The Compensation Committee of the Board of Directors has absolute discretion in the selection of the individuals covered by this plan. The accrued liability for the separation benefit plans is determined by an actuary consultant hired by us. (3) On January 1, 2003 we adopted Financial Accounting Standards No. 143, "Accounting for Asset Retirement Obligations" (FAS 143). FAS 143 establishes an accounting standard requiring the recording of the fair value of liabilities associated with the retirement of long-lived assets (mainly plugging and abandonment costs for our depleted wells) in the period in which the liability is incurred (at the time the wells are drilled or acquired). (4) We have recorded a liability on certain properties where we believe there are insufficient reserves available to allow the under-produced owners to recover their under-production from future production volumes. (5) We formed The Unit 1984 Oil and Gas Limited Partnership and the 1986 Energy Income Limited Partnership along with private limited partnerships (the "Partnerships") with certain qualified employees, officers and directors from 1984 through 2003, with a subsidiary of ours serving as General Partner. The Partnerships were formed for the purpose of conducting oil and natural gas acquisition, drilling and development operations and serving as co-general partner with us in any additional limited partnerships formed during that year. The Partnerships participated on a proportionate basis with us in most drilling operations and most producing property acquisitions commenced by us for our own account during the period from the formation of the Partnership through December 31 of each year. These partnership agreements require, upon the election of a limited partner, that we repurchase the limited partner's interest at amounts to be determined by appraisal in the future. Such repurchases in any one year are limited to 20 percent of the units outstanding. We made repurchases of $1,000 in 2002 for such limited partners' interests. We made total repurchases of $18,000 during the second and third quarters of 2003. Hedging. Periodically we hedge the prices we will receive for a portion of our future natural gas and oil production. We do so in an attempt to reduce the impact and uncertainty that price variations have on our cash flow. During the first quarter of 2003, we entered into two natural gas collar contracts for approximately 37 percent of our April through September 2003 production. One contract had a floor price of $4.00 and a ceiling price of $5.75. The other contract had a floor price of $4.50 and a ceiling price of $6.02. During the first quarter of 2003, we also entered into two oil collar contracts for approximately 26 percent of our May through December 2003 oil production. One contract has a floor price of $25.00 and a ceiling price of $32.20. The other contract has a floor price 27 of $26.00 and a ceiling price of $31.40. We had a $6,000 reduction in natural gas revenues because of the natural gas hedges settled in the second quarter of 2003 and a $1,000 reduction in oil revenues because of the oil hedges settled in the third quarter of 2003. Since the amount was immaterial, no fair value was recognized on the September 2003 balance sheet or in accumulated other comprehensive income for the oil collar contracts which remained outstanding at the end of the period. These hedges were fully effective. We did not have any hedging contracts in place in the first nine months of 2002. Self-Insurance. We are self-insured for certain losses relating to workers' compensation, general liability, property damage and employee medical benefits. Due to increases in premium prices in the insurance market, by our election, our self-insurance levels have significantly increased. Effective August 1, 2002, our exposure (i.e. our deductible or retention), per occurrence, ranges from $200,000 for general liability to $1 million for rig physical damage. We have purchased stop-loss coverage in order to limit, to the extent feasible, our per occurrence and aggregate exposure to certain claims. There is no assurance that such coverage will adequately protect us against liability from all potential consequences. Our Oil and Natural Gas Operations. Natural gas comprises 91 percent of our total oil and natural gas reserves. Any significant change in natural gas prices has a material effect on our revenues, cash flow and the value of our oil and natural gas reserves. Based on our 2003 first nine month production, a $.10 per Mcf change in the price we are paid for our natural gas production would result in a corresponding $156,000 per month ($1.9 million annualized) change in our pre-tax cash flow. Our first nine month 2003 average natural gas price was $5.05 compared to an average natural gas price of $2.59 received in the first nine months of 2002. We sell most of our natural gas production to third parties under month-to-month contracts. A $1.00 per barrel change in our oil price would have a $38,000 per month ($456,000 annualized) change in our pre-tax cash flow. Our first nine months 2003 average oil price was $27.02 compared with an average oil price of $20.92 received in the first nine months of 2002. Because natural gas prices have such a significant effect on the value of our oil and natural gas reserves, declines in those prices can result in a decline in the carrying value of our oil and natural gas properties. Also, price declines can adversely effect the semi-annual determination of the amount available for us to borrow under our bank loan agreement since that determination is based mainly on the value of our oil and natural gas reserves. Such a reduction could limit our ability to carry out our planned capital projects. Our decision to increase our oil and natural gas reserves through acquisitions or through drilling depends on the prevailing or expected market conditions, potential return on investment, future drilling potential and opportunities to obtain acceptable financing under the circumstances involved, all of which give us a large degree of flexibility in deciding when to incur these costs. We drilled 98 wells in the first 28 nine months of 2003 compared to 62 wells in the first nine months of 2002. Through the first nine months of 2003 we incurred $51.1 million of the $70 to $75 million in capital expenditures we expect to make for exploration and development drilling of oil and natural gas properties in 2003. Based on current oil and natural gas prices, we plan to drill and/or participate in an estimated 140 to 150 wells in 2003. Contract Drilling. There are many things that influence the number of rigs we are able to work, as well as, the costs and revenues associated with that work. These things include competition from other drilling contractors, the prevailing prices for natural gas and oil, availability and cost of labor to run our rigs and our ability to supply the needed equipment. We have not encountered major difficulty in hiring and keeping rig crews, but shortages have occurred periodically in the past. If demand for drilling rigs continues to increase, we would incur shortages of experienced personnel which would limit our ability to increase our operating rigs. Through the first nine months of 2003 we incurred $16.8 million in capital expenditures for our drilling operation. For the year 2003, we anticipate spending approximately $25 million on our drilling operations. Low oil and natural gas prices during most of the 1980's and 1990's reduced demand for domestic land contract drilling rigs. However, in the last half of 1999 and throughout 2000, as oil and natural gas prices increased, we experienced a big increase in demand for our rigs. Demand continued to increase until the end of the third quarter of 2001 and reached a high when 52 of our rigs were working in July 2001. Because of declining natural gas prices throughout 2001, demand for our rigs dropped significantly in the fourth quarter of 2001 and carried over into the first quarter of 2002. Average use of our rigs in the first nine months of 2002 was 36.2 rigs compared with 60.6 rigs for the first nine months of 2003. Natural gas prices began increasing in the fourth quarter of 2002 and they increased substantially in the first quarter of 2003. The increase in commodity prices along with our acquisition of 20 rigs in the third quarter of 2002, caused the rise in 2003 utilization. As demand for our rigs increased during 2001 so did the dayrates we received. Our average dayrate reached $11,142 by September of 2001. However, as demand began to decrease, so did our rates. Our average dayrate in the first nine months of 2002 was $7,847 and our average dayrate for the first nine months of 2003 was $7,684. Increases in dayrates typically lag behind increases in utilization. We saw dayrates start to improve in the second quarter of 2003 and they continued a gradual increase in the third quarter of 2003. We anticipate dayrates to remain fairly constant in the fourth quarter of 2003. Based on the average utilization of our rigs in the first nine months of 2003, a $100 per day change in dayrates has a $6,100 per day ($2.2 million annualized) change in our pre-tax operating cash flow. Our contract drilling segment provides drilling services for our exploration and production segment. The contracts for these services are issued under the same conditions and rates as the contracts we have entered into with unrelated third parties. The profit received by our contract 29 drilling segment of $677,000 and $1,411,000 in the first nine months of 2002 and 2003, respectively, was used to reduce the carrying value of our oil and natural gas properties rather than being included in our profits in current operations. Oil and Natural Gas Limited Partnerships and Other Entity Relationships. We are the general partner of nine privately and publicly held oil and natural gas partnerships. The partnership's revenues and costs are shared under formulas prescribed in each limited partnership agreement. The partnerships repay us for contract drilling, well supervision and general and administrative expense. Related party transactions for contract drilling and well supervision fees are the related party's share of such costs. These costs are billed on the same basis as billings to unrelated third parties for similar services. General and administrative reimbursements consist of direct general and administrative expense incurred on the related party's behalf as well as indirect expenses assigned to the related parties. Allocations are based on the related party's level of activity and are considered by management to be reasonable. During 2002, the total paid to us for all of these fees was approximately $232,000 per quarter and during the first nine months of 2003 the amount paid has been 4 percent below last year's quarterly average. Our proportionate share of assets, liabilities and net income relating to the oil and natural gas partnerships is included in our consolidated financial statements. Interests in the employee partnerships were offered to certain employees whose annual base compensation meet a specified amount ($22,680 for 2002 and 2003) and to our directors. The general partner of each partnership is Unit Petroleum Company. Each employee partnership is named the Unit (year) Employee Oil and Gas Limited Partnership. The interests issued in these programs to our directors and executive officers are disclosed in our proxy statements for each year's annual meeting of shareholders. At September 30, 2003, we owned a 40 percent equity interest in Superior Pipeline Company, a natural gas gathering and processing company. Our investment including our share of the equity in the earnings of this company totaled $2.7 million at September 30, 2003. From time to time we may guarantee a portion of the debt of this company. However, as of September 30, 2003 and October 22, 2003, we were not guaranteeing any of the debt of this company. On June 25, 2003, we acquired a 26.04 percent interest in Eagle Energy Partners I, L.P., ("Eagle") a Texas limited partnership for $2.5 million. In the third quarter an additional partner was added to the partnership reducing our interest in Eagle to 16.668 percent. This newly formed partnership is engaged in the purchase and sale of natural gas, electricity (or similar electricity based products), or any future commodities, and the performance of scheduling and nomination services for energy related commodities and similar energy management functions. In addition to our investment in this partnership, the partnership has the right, subject to being the successful bidder, to buy, each month, a certain percentage of our natural gas at competitive prices during the six month period starting 30 August 1, 2003. For October 2003, Eagle will buy approximately 45% of the natural gas we sell on a monthly basis for ourselves and other working interest owners. Outlook. Both of our operating segments are extremely dependent on natural gas prices. These prices affect not only our production revenues, but also the demand and rates for our contract drilling services. Over the first nine months of 2003 our average natural gas price received for each month excluding hedging ranged from $4.18 in January to a high of $8.38 in March and the average Nymex Henry Hub daily price for the same time period ranged from $4.39 to $6.70. On our third quarter earnings release date of October 22, 2003, the Nymex Henry Hub average contract settle price for the next twelve months was $4.93 and, we anticipate that if natural gas prices continue at that level, there will be increased demand for our rigs and upward movement on the rates we receive for our contract drilling services. Critical Accounting Policies. We account for our oil and natural gas exploration and development activities using the full cost method of accounting. Under this method, all costs incurred in the acquisition, exploration and development of oil and natural gas properties are capitalized. At the end of each quarter, the net capitalized costs of our oil and natural gas properties is limited to the lower of unamortized cost or a ceiling. The ceiling is defined as the sum of the present value (10 percent discount rate) of estimated future net revenues from proved reserves, based on period-end oil and natural gas prices, plus the lower of cost or estimated fair value of unproved properties included in the costs being amortized less related income taxes. If the net capitalized costs of our oil and natural gas properties exceed the ceiling, we are subject to a write-down to the extent of such excess. A ceiling test write-down is a non-cash charge to earnings. If required, it reduces earnings and impacts shareholders' equity in the period of occurrence and results in lower depreciation, depletion and amortization expense in future periods. Once incurred, a write-down cannot be reversed even if prices subsequently recover. The risk that we will be required to write-down the carrying value of our oil and natural gas properties increases when oil and natural gas prices are depressed or if we have large downward revisions in our estimated proved reserves. Application of these rules during periods of relatively low oil or natural gas prices, even if temporary, increases the chance of a ceiling test write-down. Based on oil and natural gas prices in effect on September 30, 2003 ($4.44 per Mcf for natural gas and $28.17 per barrel for oil), the unamortized cost of our domestic oil and natural gas properties did not exceed the ceiling of our proved oil and natural gas reserves. Natural gas prices remain erratic and any significant declines below quarter-end prices used in the reserve evaluation could result in a ceiling test write-down in following quarterly reporting periods. Oil and natural gas reserves cannot be measured exactly. Estimates of oil and natural gas reserves require extensive judgments of reservoir engineering data and are less precise than other estimates made in connection with financial disclosures. Assigning monetary values to our estimates does not reduce the subjectivity and changing nature of our 31 reserve estimates. Indeed, the uncertainties inherent in the disclosure are compounded by applying additional estimates of the rates and timing of production and the costs that will be incurred in developing and producing the reserves. Reserve estimates effect many areas of accounting for oil and natural gas operations including the carrying value and depreciation, depletion and amortization of our oil and gas properties. We use the sales method for recording natural gas sales. This method allows for recognition of revenue, which may be more or less than our share of pro-rata production from certain wells. Our policy is to expense our pro-rata share of lease operating costs from all wells as incurred. Such expenses relating to the natural gas balancing position on wells in which we have an imbalance are not material. Drilling equipment, transportation equipment and other property and equipment are carried at cost. Renewals and improvements are capitalized while repairs and maintenance are expensed. Realization of the carrying value of property and equipment is reviewed for possible impairment whenever events or changes in circumstances suggest the carrying amount may not be recoverable. Assets are determined to be impaired if a forecast of undiscounted estimated future net operating cash flows directly related to the asset including disposal value if any, is less than the carrying amount of the asset. If any asset is determined to be impaired, the loss is measured as the amount by which the carrying amount of the asset exceeds its fair value. An estimate of fair value is based on the best information available, including prices for similar assets. Changes in such estimates could cause us to reduce the carrying value of our property and equipment. Because the Company does not bear the risk of completion of wells drilled under "daywork" drilling contracts, it recognizes revenues and expenses for these contracts as the services are performed (i.e. daily). Under "footage" and "turnkey" contracts, revenues and expenses are recognized when we have satisfied certain contractual requirements. If it is determined that a well is going to incur a loss, the entire amount of the estimated loss is recorded when the loss is determined, however, any profit is recorded only at the time the terms of the contract are satisfied. The costs of uncompleted drilling contracts include expenses incurred to date on "footage" or "turnkey" contracts, which are still in process at the end of the period, and are included in other current assets. Statement of Financial Accounting Standards No. 141, "Business Combinations" (FAS 141) and Statement of Financial Accounting Standards, No. 142, "Goodwill and Intangible Assets" (FAS 142) were issued by the Financial Accounting Standards Board (FASB) in June 2001 and became effective for us on July 1, 2001 and January 1, 2002, respectively. FAS 141 requires all business combinations initiated after June 30, 2001 to be accounted for using the purchase method. Additionally, FAS 141 requires companies to disaggregate and report separately from goodwill certain intangible assets. FAS 142 establishes new guidelines for accounting for goodwill and other intangible assets. Under FAS 142, goodwill and certain other intangible assets are not amortized, but rather are reviewed annually for impairment. Depending on how the accounting and disclosure literature is applied, these oil and gas mineral rights held under lease and other contractual arrangements representing the right to extract such reserves 32 for both undeveloped and developed leaseholds may be classified separately from oil and gas properties, as intangible assets on our balance sheets. In addition, the disclosures required by FAS 141 and 142 relative to intangibles would be included in the notes to financial statements. Historically, we, like many other oil and gas companies, have included these oil and gas mineral rights held under lease and other contractual arrangements representing the right to extract such reserves as part of the oil and gas properties, even after FAS 141 and 142 became effective. Our results of operations and cash flows would not be affected, since these oil and gas mineral rights held under lease and other contractual arrangements representing the right to extract such reserves would continue to be amortized in accordance with full cost accounting rules. At September 30, 2003, we had undeveloped leaseholds of approximately $16.6 million that would be classified on our balance sheet as "intangible undeveloped leasehold" and developed leaseholds of an estimated $21.3 million that would be classified as "intangible developed leasehold" if we applied the interpretations. This classification would require us to make disclosures set forth under FAS 142 related to these interests. We will continue to classify our oil and gas mineral rights held under lease and other contractual rights representing the right to extract such reserves as tangible oil and gas properties until further guidance is provided. Acquisitions. On August 14, 2003 we signed a definitive agreement with PetroCorp Incorporated (AMEX - PEX) to acquire all the outstanding shares of PetroCorp. The purchase price under the agreement is approximately $182.1 million and will be paid in cash. The purchase price is subject to certain adjustments including up to $6.5 million which will be placed in escrow to settle or satisfy certain contingent tax and litigation liabilities if not resolved prior to closing. Consummation of the transaction is subject to several conditions typical of transactions of this nature including regulatory review and the approval by two-thirds of PetroCorp's shareholders. PetroCorp shareholders representing approximately 50% of the outstanding shares of PetroCorp have agreed to support the merger. PetroCorp is a Tulsa-based company that explores and develops oil and natural gas properties primarily in Texas and Oklahoma. Change in Board of Directors. We announced on October 27, 2003 that our Board of Directors elected Mr. Mark E. Monroe to the Company's Board of Directors. Mr. Monroe recently served as the President, Chief Executive Officer and a director of Louis Dreyfus Natural Gas Corp until that company was sold in 2001. He currently serves as a member of the Board of Directors for Continental Resources, Inc. He has served as President of the Oklahoma Independent Petroleum Association, on the Board of the Independent Petroleum Association of America, and as a member of the Domestic Petroleum Council and the National Petroleum Council. Mr. Monroe holds a Bachelor's degree in Business Administration from the University of Texas and is a Certified Public Accountant. 33 SAFE HARBOR STATEMENT --------------------- Statements in this document as well as information contained in written material, press releases and oral statements issued by or for us contain, or may contain, certain "forward-looking statements" within the meaning of federal securities laws. All statements, other than statements of historical facts, included in this document which address activities, events or developments which we expect or expect will or may occur in the future are forward-looking statements. The words "believes," "intends," "expects," "anticipates," "projects," "estimates," "predicts" and similar expressions are also intended to identify forward-looking statements. These forward-looking statements include, among others, such things as: . the amount and nature of future capital expenses; . wells to be drilled or reworked; . oil and natural gas prices to be received and demand for oil and natural gas; . exploitation and exploration prospects; . estimates of proved oil and natural gas reserves; . reserve potential; . development and infill drilling potential; . drilling prospects; . expansion and other development trends of the oil and natural gas industry; . our business strategy; . production of our oil and natural gas reserves; . expansion and growth of our business and operations; . availability of drilling rigs and rig related equipment; . drilling rig use, revenues and costs; and . availability of qualified labor. These statements are based on certain assumptions and analyses made by us in light of our experience and our view of historical trends, current conditions and expected future developments as well as other factors we believe are proper in the circumstances. However, whether actual results and developments will conform to our expectations and predictions is subject to many risks and uncertainties which could cause actual results to differ materially from our expectations, including: . the risk factors discussed in this document; . general economic, market or business conditions; . the nature or lack of business opportunities that may be presented to and pursued by us; . demand for land drilling services; . changes in laws or regulations; and . other reasons, most of which are beyond our control. A more thorough discussion of forward-looking statements with the possible impact of some of these risks and uncertainties is provided in our Annual Report on Form 10-K filed with the Securities and Exchange Commission. We encourage you to get and read that document. 34 RESULTS OF OPERATIONS --------------------- Third Quarter 2003 versus Third Quarter 2002 -------------------------------------------- Provided below is a comparison of selected operating and financial data for the third quarter of 2003 versus the third quarter of 2002: Third Third Percent Quarter 2002 Quarter 2003 Change --------------- --------------- --------- Total Revenue $ 48,272,000 $ 78,201,000 62% Net Income $ 3,708,000 $ 12,763,000 244% Oil and Natural Gas: Revenue $ 16,357,000 $ 27,402,000 68% Average natural gas price (Mcf) $ 2.71 $ 4.50 66% Average oil price (Bbl) $ 22.99 $ 25.51 11% Natural gas production (Mcf) 4,707,000 5,233,000 11% Oil production (Bbl) 120,000 134,000 12% Operating profit (revenue less operating costs) $ 11,188,000 21,142,000 89% Operating margin 68% 77% Depreciation, depletion and amortization rate (Mcfe) $ 1.06 $ 1.15 8% Depreciation, depletion and amortization $ 6,142,000 $ 6,972,000 14% Drilling: Revenue $ 31,589,000 $ 50,052,000 58% Percentage of revenue from daywork contracts 92% 99% Average number of rigs in use 42.5 68.2 60% Average dayrate on daywork contracts $ 7,529 $ 8,015 6% Operating profit (revenue less operating costs) $ 7,239,000 $ 14,399,000 99% Operating margin 23% 29% Depreciation $ 4,178,000 $ 6,318,000 51% General and Administrative Expense $ 2,180,000 $ 2,246,000 3% Interest Expense $ 231,000 $ 154,000 (33%) Average Interest Rate 3.1% 2.3% (74%) Average Long-Term Debt Outstanding $ 22,610,000 $ 16,763,000 (26%) 35 Oil and natural gas revenues, operating profits and operating profit margins were all positively affected by higher oil and natural gas prices and increased oil and natural gas production between the third quarter of 2003 and the third quarter of 2002. We continue to focus our drilling program on the development of natural gas reserves. Total operating cost increased in the third quarter of 2003 when compared with the third quarter of 2002 due mainly to higher gross production taxes and, to a lesser extent, from costs associated with adding personnel to support the growth in this segment of our business. Our total depreciation, depletion and amortization ("DD&A) increased due an increase in our DD&A rate per Mcfe and increased production volumes. During 2002 and continuing into the first nine months of 2003, we experienced higher cost per Mcfe for the discovery of new reserves through our development drilling program resulting in an increase in the DD&A rate between the comparative quarters. Reduced natural gas prices in the fourth quarter of 2001 and the first half of 2002, reduced the demand for our contract drilling rigs throughout most of 2002. Along with our acquisition of 20 rigs in the third quarter of 2002, natural gas prices increased once again into the first quarter of 2003. Our second and third quarter 2003 utilization increased and the third quarter rig use was 60 percent higher than the third quarter of 2002. In the second and third quarter of 2003 dayrates for our rigs also increased from our first quarter lows and were six percent higher in the third quarter of 2003 than in the third quarter of 2002. Operating margins increased between the comparative periods, since we had higher rig utilization and dayrates to cover our fixed operating costs. Approximately one percent of our third quarter 2003 drilling revenues came from footage and turnkey contracts, which had profit margins lower than our daywork contracts. Contract drilling depreciation increased due to the acquisition of 20 rigs in August of 2002 and the increase in rigs used between the comparative quarters. General and administrative expense was higher in the third quarter of 2003 because of increases in our insurance expense. Our total interest expense is lower due to lower interest rates and decreased average debt outstanding. Income tax expense increased primarily due to the increase in pre-tax income. 36 Nine Months 2003 versus Nine Months 2002 ---------------------------------------- Provided below is a comparison of selected operating and financial data for the first nine months of 2003 versus the first nine months of 2002: First Nine First Nine Percent Months 2002 Months 2003 Change --------------- --------------- --------- Total Revenue $ 131,755,000 $ 219,627,000 67% Income Before Change in Accounting Principle $ 11,458,000 $ 37,113,000 224% Net Income $ 11,458,000 $ 38,438,000 235% Oil and Natural Gas: Revenue $ 46,986,000 $ 87,521,000 86% Average natural gas price (Mcf) $ 2.59 $ 5.05 95% Average oil price (Bbl) $ 20.92 $ 27.02 29% Natural gas production (Mcf) 14,360,000 15,043,000 5% Oil production (Bbl) 347,000 372,000 7% Operating profit (revenue less operating costs) $ 31,708,000 $ 68,753,000 117% Operating margin 67% 79% Depreciation, depletion and amortization rate (Mcfe) $ 1.03 $ 1.12 9% Depreciation, depletion and amortization $ 17,399,000 $ 19,464,000 12% Drilling: Revenue $ 84,144,000 $ 129,839,000 54% Percentage of revenue from daywork contracts 91% 97% Average number of rigs in use 36.2 60.6 67% Average dayrate on daywork contracts $ 7,847 $ 7,684 (2%) Operating profit (revenue less operating costs) $ 20,525,000 $ 32,734,000 59% Operating margin 24% 25% Depreciation $ 9,917,000 $ 17,111,000 73% General and Administrative Expense $ 6,222,000 $ 6,766,000 9% Interest Expense $ 747,000 $ 540,000 (28%) Average Interest Rate 3.1% 2.2% (71%) Average Long-Term Debt Outstanding $ 24,907,000 $ 23,727,000 (5%) 37 Oil and natural gas revenues, operating profits and operating profit margins were all positively affected by higher prices received for both oil and natural gas between the first nine months of 2003 and the first nine months of 2002. We continue to focus our drilling program on the development of natural gas reserves and we experienced an increase in both our oil and natural gas production volumes between the comparative nine month periods. Total operating cost increased in the first nine months of 2003 when compared with the first nine months of 2002 due mainly to higher gross production taxes and, to a lesser extent, from costs associated with adding personnel to support the growth in this segment of our business. Our total depreciation, depletion and amortization ("DD&A) increased due to the increase in equivalent volumes produced and an increase in our DD&A rate per Mcfe. During 2002 and into the first nine months of 2003, we experienced higher cost per Mcfe for the discovery of new reserves through our development drilling program resulting in an increase in the DD&A rate between the comparative nine month periods. Reduced natural gas prices in the fourth quarter of 2001 and the first half of 2002, reduced the demand for our contract drilling rigs throughout most of 2002. Demand recovered in the nine months of 2003 and the average number of rigs in use was 24 more than during the first nine months of 2002. We also had more rigs available due to the 20 rig acquisition we completed in August of 2002. Since utilization typically increases before dayrates our dayrates did not start to improve until the second quarter of 2003, so the average dayrate for the first nine months of 2003 was lower than the average dayrate received for the same period in 2002. Our operating margins was one percentage point higher than the first nine months of 2002. Approximately 3 percent of our first nine month 2003 drilling revenues came from footage and turnkey contracts, which had profit margins lower than our daywork contracts. Nine percent of our total drilling revenues came from footage and turnkey contracts in the first nine months of 2002. Contract drilling depreciation increased due to the acquisition of 20 rigs in August of 2002 and the increase in rigs used between the comparative nine month periods. General and administrative expense was higher in the first nine months of 2003 because of increases in our insurance expense. Our total interest expense is lower due to lower interest rates and average debt outstanding. Income tax expense increased primarily due to the increase in pre-tax income. 38 Item 3. Quantitative and Qualitative Disclosures about Market Risk ------- ---------------------------------------------------------- Our operations are exposed to market risks due to changes in commodity prices. The price we receive is primarily driven by the prevailing worldwide price for crude oil and the domestic prices established for natural gas. Historically, the prices we have received for our oil and natural gas production have been volatile and such volatility is expected to continue. Over the past several years we have tried to reduce the impact of price fluctuations, by using hedging strategies to hedge the price we will receive for a portion of our future oil and natural gas production. A detailed explanation of those transactions has been included under hedging in the financial condition portion of management's discussion and analysis of financial condition and results of operations included above under Item 2. Item 4. Controls and Procedures -------------------------------- As of the end of the period covered by this report, we carried out an evaluation, under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of our disclosure controls and procedures pursuant to Exchange Act Rule 13a-14. Based on that evaluation, our Chief Executive Officer and Chief Financial Officer concluded that the company's disclosure controls and procedures are effective in timely alerting them to material information required to be included in our periodic SEC filings relating to the company (including its consolidated subsidiaries). There were no significant changes in the company's internal controls or in other factors that could significantly affect these internal controls subsequent to the date of our most recent evaluation. 39 PART II. OTHER INFORMATION Item 1. Legal Proceedings -------------------------- Not applicable Item 2. Changes in Securities and Use of Proceeds -------------------------------------------------- Not applicable Item 3. Defaults Upon Senior Securities ---------------------------------------- Not applicable Item 4. Submission of Matters to a Vote of Security Holders ------------------------------------------------------------ Not applicable Item 5. Other Information -------------------------- In accordance with Section 10A(i)(2) of the Securities Exchange Act of 1934, as added by Section 202 of the Sarbanes-Oxley Act of 2002, we are responsible for disclosing any non-audit services approved by our Audit Committee (the "Committee") to be performed by PricewaterhouseCoopers LLP, who is our external auditor. Non-audit services are defined in the Act as services other than those provided in connection with an audit or a review of the financial statements of Unit. The Committee has approved the engagement of PricewaterhouseCoopers LLP to provide non-audit services assisting in (i) reviewing our internal control procedures, (ii)our pending acquisition of PetroCorp Incorporated and (iii) responding to the SEC's comments in connection with the SEC's review of the recent S-3 Registration Statement we filed on March 31, 2003. 40 Item 6. Exhibits and Reports on Form 8-K ----------------------------------------- (a) Exhibits: 15 Letter re: Unaudited Interim Financial Information. 31.1 SEC Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 by the Principal Executive Officer, John G. Nikkel of Unit Corporation. 31.2 SEC Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 by the Principal Financial Officer, Larry D. Pinkston, of Unit Corporation. 32 Certification Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. (b) On July 1, 2003, we filed a report on Form 8-K under Item 5 and 7. This report announced that we had entered into a letter of intent to acquire PetroCorp Incorporated ("PetroCorp") (AMEX:PEX) and furnished as an exhibit the press release of the announcement. On July 23, 2003, we filed a report on Form 8-K under Item 7 and 9. This report furnished as an exhibit the press release announcing our results of operations and financial condition for the quarter ended June 30, 2003. 41 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. UNIT CORPORATION Date: November 6, 2003 By: /s/ John G. Nikkel --------------------------- ------------------------------ JOHN G. NIKKEL Chairman of the Board, Chief Executive Officer, Chief Operating Officer and Director Date: November 6, 2003 By: /s/ Larry D. Pinkston --------------------------- ------------------------------ LARRY D. PINKSTON President, Chief Financial Officer and Treasurer 42