UNITED STATES 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, 2004 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.) 7130 South Lewis, Suite 1000 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 45,737,599 ---------------------------- ---------- Class Outstanding at November 8, 2004FORM 10-Q UNIT CORPORATION TABLE OF CONTENTS Page Number PART I. Financial Information Item 1. Financial Statements (Unaudited) Consolidated Condensed Balance Sheets December 31, 2003 and September 30, 2004 . . . . . . . . . 2 Consolidated Condensed Statements of Income Three and Nine Months Ended September 30, 2003 and 2004. . 4 Consolidated Condensed Statements of Cash Flows Nine Months Ended September 30, 2003 and 2004. . . . . . . 6 Consolidated Condensed Statements of Comprehensive Income Three and Nine Months Ended September 30, 2003 and 2004. . . . . . . . . . . . . . . . 7 Notes to Consolidated Condensed Financial Statements . . . 8 Report of Independent Registered Public Accounting Firm . . . . . . . . . . . . . . . . . . . . . . . . . . . 26 Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations. . . . . . . . . . . . 27 Item 3. Quantitative and Qualitative Disclosures about Market Risk. . . . . . . . . . . . . . . . . . . . . . . . 52 Item 4. Controls and Procedures. . . . . . . . . . . . . . . . . . 52 PART II. Other Information Item 1. Legal Proceedings. . . . . . . . . . . . . . . . . . . . . 54 Item 2. Unregistered Sales of Equity Securities and Use of Proceeds. . . . . . . . . . . . . . . . . . . . . . 54 Item 3. Defaults Upon Senior Securities. . . . . . . . . . . . . . 54 Item 4. Submission of Matters to a Vote of Security Holders. . . . 54 Item 5. Other Information. . . . . . . . . . . . . . . . . . . . . 54 Item 6. Exhibits . . . . . . . . . . . . . . . . . . . . . . . . . 54 Signatures. . . . . . . . . . . . . . . . . . . . . . . . . . . . . 55 1 PART I. FINANCIAL INFORMATION Item 1. Financial Statements - ------------------------------ UNIT CORPORATION AND SUBSIDIARIES CONSOLIDATED CONDENSED BALANCE SHEETS September 30, December 31, 2004 2003 (Unaudited) ----------- ----------- (In thousands) ASSETS - ------ Current Assets: Cash and cash equivalents $ 598 $ 1,540 Restricted cash -- 5,259 Accounts receivable 58,807 83,632 Materials and supplies 8,023 11,499 Other 5,314 7,243 ----------- ----------- Total current assets 72,742 109,173 ----------- ----------- Property and Equipment: Drilling equipment 424,321 496,037 Oil and natural gas properties, on the full cost method: Proved properties 528,110 705,343 Undeveloped leasehold not being amortized 17,486 28,584 Gas gathering & processing equipment 6,686 35,236 Transportation equipment 9,828 12,562 Other 7,849 10,207 ----------- ----------- 994,280 1,287,969 Less accumulated depreciation, depletion, amortization and impairment 385,219 444,663 ----------- ----------- Net property and equipment 609,061 843,306 ----------- ----------- Goodwill 23,722 28,420 Other Assets 7,400 2,531 ----------- ----------- Total Assets $ 712,925 $ 983,430 =========== =========== The accompanying notes are an integral part of the consolidated condensed financial statements. 2 UNIT CORPORATION AND SUBSIDIARIES CONSOLIDATED CONDENSED BALANCE SHEETS - CONTINUED September 30, December 31, 2004 2003 (Unaudited) ----------- ----------- (In thousands) LIABILITIES AND SHAREHOLDERS' EQUITY - ------------------------------------ Current Liabilities: Current portion of long-term liabilities and debt $ 1,015 $ 941 Accounts payable 32,871 41,906 Accrued liabilities 17,925 44,752 ----------- ----------- Total current liabilities 51,811 87,599 ----------- ----------- Long-Term Debt 400 107,500 ----------- ----------- Other Long-Term Liabilities 17,893 24,727 ----------- ----------- Deferred Income Taxes 127,053 186,742 ----------- ----------- 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, 45,592,012 and 45,734,099 shares issued, respectively 9,117 9,146 Capital in excess of par value 307,938 309,739 Accumulated other comprehensive income -- (1,077) Retained earnings 198,713 259,054 ----------- ----------- Total shareholders' equity 515,768 576,862 ----------- ----------- Total Liabilities and Shareholders' Equity $ 712,925 $ 983,430 ========== ========== 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, ---------------------- ---------------------- 2003 2004 2003 2004 ---------- ---------- ---------- ---------- (In thousands except per share amounts) Revenues: Contract drilling $ 50,052 $ 80,887 $ 129,839 $ 211,211 Oil and natural gas 27,402 46,394 87,521 130,718 Gas gathering & processing 148 11,474 566 11,562 Other 198 4,595 832 5,497 ---------- ---------- ---------- ---------- Total revenues 77,800 143,350 218,758 358,988 ---------- ---------- ---------- ---------- Expenses: Contract drilling: Operating costs 35,653 57,816 97,105 152,736 Depreciation 6,318 8,903 17,111 24,121 Oil and natural gas: Operating costs 6,207 9,746 18,655 29,871 Depreciation depletion and amortization 6,972 12,316 19,464 34,028 Gas gathering & processing: Operating costs 50 10,480 307 10,515 Depreciation 58 451 125 489 General and administrative 2,246 3,081 6,766 8,955 Interest 154 820 540 1,751 ---------- ---------- ---------- ---------- Total expenses 57,658 103,613 160,073 262,466 ---------- ---------- ---------- ---------- Income Before Income Taxes 20,142 39,737 58,685 96,522 ---------- ---------- ---------- ---------- Income Tax Expense: Current 157 1,470 456 3,597 Deferred 7,506 13,673 21,856 33,187 ---------- ---------- ---------- ---------- Total income taxes 7,663 15,143 22,312 36,784 ---------- ---------- ---------- ---------- Equity in Earnings of Unconsolidated Investments, Net of Income Tax 284 53 740 603 ---------- ---------- ---------- ---------- Income Before Change in Accounting Principle 12,763 24,647 37,113 60,341 Cumulative Effect of Change in Accounting Principle (Net of Income Tax of $811) -- -- 1,325 -- ---------- ---------- ---------- ---------- Net Income $ 12,763 $ 24,647 $ 38,438 $ 60,341 ========== ========== ========== ========== 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, ---------------------- ---------------------- 2003 2004 2003 2004 ---------- ---------- ---------- ---------- (In thousands except per share amounts) Basic Earnings per Common Share: Income before change in accounting principle $ 0.29 $ 0.54 $ 0.85 $ 1.32 Cumulative effect of change in accounting principle, net of income tax -- -- 0.03 -- ---------- ---------- ---------- ---------- Net income $ 0.29 $ 0.54 $ 0.88 $ 1.32 ========== ========== ========== ========== Diluted Earnings per Common Share: Income before change in accounting principle $ 0.29 $ 0.54 $ 0.85 $ 1.31 Cumulative effect of change in accounting principle, net of income tax -- -- 0.03 -- ---------- ---------- ---------- ---------- Net income $ 0.29 $ 0.54 $ 0.88 $ 1.31 ========== ========== ========== ========== 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, ------------------------ 2003 2004 ---------- ---------- (In thousands) Cash Flows From Operating Activities: Net income $ 38,438 $ 60,341 Adjustments to reconcile net income to net cash provided (used) by operating activities: Depreciation, depletion, and amortization 37,135 59,327 Deferred tax expense 22,304 33,559 Gain on sale of investment -- (3,783) Other 237 319 Changes in operating assets and liabilities increasing (decreasing) cash: Accounts receivable (19,417) (4,968) Accounts payable 3,098 (2,627) Material and supplies 284 (3,476) Accrued liabilities 1,886 15,241 Prepaid expenses 3,056 (1,874) Contract advances 1,228 (305) Other - net 163 17 ---------- ---------- Net cash provided by operating activities 88,412 151,771 ---------- ---------- Cash Flows From (Used In) Investing Activities: Capital expenditures (including producing property acquisitions and other acquisitions net of acquired assets and liabilities) (65,780) (269,103) Proceeds from disposition of assets and investments 960 8,395 Other-net (2,555) 2,132 ---------- ---------- Net cash used in investing activities (67,375) (258,576) ---------- ---------- Cash Flows From (Used In) Financing Activities: Net borrowings (payments) under line of credit (15,500) 107,100 Net payments of notes payable and other long-term debt (1,074) (1,833) Proceeds from exercise of stock options 452 424 Book overdrafts (3,647) 2,056 ---------- ---------- Net cash from (used in) financing activities (19,769) 107,747 ---------- ---------- Net Increase in Cash and Cash Equivalents 1,268 942 Cash and Cash Equivalents, Beginning of Year 497 598 ---------- ---------- Cash and Cash Equivalents, End of Period $ 1,765 $ 1,540 ========== ========== 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, -------------------- -------------------- 2003 2004 2003 2004 --------- --------- --------- --------- (In thousands) Net Income $ 12,763 $ 24,647 $ 38,438 $ 60,341 Other Comprehensive Income, Net of Taxes: Change in value of cash flow derivative instruments used as cash flow hedges 74 (1,663) (4) (2,219) Adjustment reclassification - derivative settlements -- 717 4 1,142 --------- --------- --------- --------- Comprehensive Income $ 12,837 $ 23,701 $ 38,438 $ 59,264 ========= ========= ========= ========= 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. Certain reclassifications have been made to prior year financial information to conform to the current period presentation. Results for the three and nine months ended September 30, 2004 are not necessarily indicative of the results to be realized during the full year. The consolidated condensed financial statements should be read with the company's Annual Report on Form 10-K for the year ended December 31, 2003. The company's independent auditors performed a review of these interim financial statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Under Rule 436(c) under 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 auditor's liability under Section 11 does not extend to it. 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 value recognition provisions of Financial Accounting Standards Board Statement No. 123, "Accounting for Stock-Based Compensation," to stock-based employee compensation. 8 Three Months Ended Nine Months Ended September 30, September 30, --------------------- --------------------- 2003 2004 2003 2004 --------- --------- --------- --------- (In thousands except per share amounts) Net Income, as Reported $ 12,763 $ 24,647 $ 38,438 $ 60,341 Add Stock-Based Employee Compensation Expense Included in Reported Net Income, Net of Tax 238 318 573 756 Less Total Stock-Based Employee Compensation Expense Determined Under Fair Value Based Method For All Awards (578) (784) (1,453) (1,924) --------- --------- --------- --------- Pro Forma Net Income $ 12,423 $ 24,181 $ 37,558 $ 59,173 ========= ========= ========= ========= Basic Earnings per Share: As reported $ 0.29 $ 0.54 $ 0.88 $ 1.32 ========= ========= ========= ========= Pro forma $ 0.29 $ 0.53 $ 0.86 $ 1.29 ========= ========= ========= ========= Diluted Earnings per Share: As reported $ 0.29 $ 0.54 $ 0.88 $ 1.31 ========= ========= ========= ========= Pro forma $ 0.28 $ 0.53 $ 0.86 $ 1.29 ========= ========= ========= ========= The fair value of each option granted is estimated using the Black-Scholes model. There were no options granted in the first and third quarters of 2003 and 2004. In the second quarter of 2003 and 2004 options were granted of 21,000 and 31,500 shares, respectively with an estimated fair value of approximately $262,000 and $538,000, respectively. For options granted in the second quarter of 2003 and 2004, the company's estimate of stock volatility was 0.53 and 0.52, respectively, based on previous stock performance. Dividend yield was estimated to remain at zero with a risk free interest rate of 3.6% in the second quarter of 2003 and 4.7% in the second quarter of 2004. Expected life ranged from 1 to 9 10 years based on prior experience depending on the vesting periods involved and the make up of participating employees. NOTE 2 - EARNINGS PER SHARE - --------------------------- The following data shows the amounts used in computing earnings per share for the company. Weighted Net Average Income Shares Per-Share (Numerator) (Denominator) Amount ------------- ------------- ---------- (In thousands except per share amounts) 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 ============= ============= ========== For the Three Months Ended September 30, 2004: Basic earnings per common share $ 24,647 45,733 $ 0.54 ========== Effect of dilutive stock options -- 239 ------------- ------------- Diluted earnings per common share $ 24,647 45,972 $ 0.54 ============= ============= ========== 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, 2003 and September 30, 2004 because the option exercise prices were greater than the average market price of common shares: 2003 2004 ---------- ---------- Options 5,000 -- ========== ========== Average exercise price $ 21.50 $ -- ========== ========== 10 Weighted Net Average Income Shares Per-Share (Numerator) (Denominator) Amount ------------- ------------- ---------- (In thousands except per share amounts) 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 ============= ========== 11 Weighted Net Average Income Shares Per-Share (Numerator) (Denominator) Amount ------------- ------------- ---------- (In thousands except per share amounts) For the Nine Months Ended September 30, 2004: Basic earnings per common share: Income before change in accounting principle $ 60,341 45,709 $ 1.32 ============= ========== Net Income $ 60,341 45,709 $ 1.32 ============= ========== Diluted earnings per common share: Weighted average number of common shares used in basic earnings per common share 45,709 Effect of dilutive stock options 206 ------------- Weighted average number of common shares and dilutive potential common shares used in diluted earnings per share 45,915 ============= Income before change in accounting principle $ 60,341 45,915 $ 1.31 ============= ========== Net Income $ 60,341 45,915 $ 1.31 ============= ========== 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, 2003 and September 30, 2004 because the option exercise prices were greater than the average market price of common shares: 2003 2004 ---------- ---------- Options 26,000 -- ========== ========== Average exercise price $ 20.37 $ -- ========== ========== 12 NOTE 3 - ACQUISITIONS - --------------------- On July 30, 2004, the company's wholly-owned subsidiary, Unit Drilling Company, completed its acquisition of Sauer Drilling Company, a Casper-based drilling company, for $34.7 million in cash paid at closing. In addition, the agreement provides that there will be a post closing settlement adjustment for the working capital of Sauer Drilling Company. Currently the seller has estimated this cost to be $6.2 million and the company has estimated this cost to be $5.3 million. In the event the parties can not resolve this discrepancy, the issue will be settled by arbitration. This acquisition includes 9 drilling rigs, a fleet of trucks, and an equipment and repair yard with associated inventory, located in Casper, Wyoming. The rigs range from 500 horsepower to 1,000 horsepower with depth capacities rated from 5,000 feet to 16,000 feet. The fleet of trucks consists of 4 vacuum trucks and 11 rig-up trucks used to move the rigs to new drilling locations. The trucks also have the capacity to move third-party rigs. This acquisition increased the company's market share in the Rocky Mountains in the medium to smaller drilling rig depth ranges. The equipment yard, located in Casper, Wyoming, will continue to provide service space for the nine newly acquired rigs and trucks as well as for the company's existing Rocky Mountain rig fleet. The results of operations for this acquired company are included in the statement of income for the period after July 31, 2004. The $34.7 million paid for Sauer was allocated as follows (in thousands): Drilling Rigs Including Tubulars $ 26,428 Spare Drilling Equipment 1,498 Trucking Fleet 1,433 Land and Buildings 510 Other Vehicles 182 Goodwill Recognized 4,698 ---------- Total consideration $ 34,749 ========== The amount paid was determined through arms-length negotiations between the parties. On July 29, 2004, the company completed its acquisition of the 60% of Superior Pipeline Company LLC ("Superior") it did not already own for $19.8 million, resulting in the company's 100% ownership of Superior. Prior to this acquisition, the company's 40% interest in the operations of Superior was shown as equity in earnings of unconsolidated investments, net of income tax. Superior is a mid-stream company engaged primarily in the gathering, processing and 13 treating of natural gas and owns one natural gas treatment plant, two processing plants, 12 active gathering systems and 400 miles of pipeline. Superior operates in western Oklahoma and the Texas Panhandle and has been in business since 1996. This acquisition will increase the company's ability to gather and market its natural gas (as well as third party natural gas) and construct or acquire existing natural gas gathering and processing facilities. The results of operations for this acquired company are included in the statement of income for the period after July 31, 2004 and intercompany revenue from services and purchases of production between the company's subsidiaries has been eliminated. The $19.8 million paid for Superior was allocated as follows (in thousands): Gas Gathering and Processing Facilities $ 20,886 Other Long-Term Liabilities (1,080) Working Capital (6) ---------- Total consideration $ 19,800 ========== The amount paid was determined through arms-length negotiations between the parties. On May 4, 2004, the company acquired two drilling rigs and related equipment for $5.5 million. The rigs are rated at 850 and 1,000 horsepower, respectively, with depth capacities from 12,000 to 15,000 feet. The company refurbished the rigs for approximately $4.0 million. One rig was placed into service at the beginning of August 2004 and the other rig was placed into service in the middle of September 2004. Both rigs are working in the area covered by the Rocky Mountain division. On January 30, 2004, the company acquired the outstanding common stock of PetroCorp Incorporated for $182.1 million in cash ($92.2 million net of cash acquired). PetroCorp Incorporated explores and develops oil and natural gas properties primarily in Texas and Oklahoma. Approximately 84% of the oil and natural gas properties acquired in the acquisition are located in the Mid-Continent and Permian basins, while 6% are located in the Rocky Mountains and 10% are located in the Gulf Coast basin. The acquired properties increased the company's oil and natural gas reserve base by approximately 56.7 billion equivalent cubic feet of natural gas and provide additional locations for future development drilling. The results of operations for this acquired company are included in the statement of income for the period after January 30, 2004. 14 The amount paid for PetroCorp was allocated as follows (in thousands): Working Capital $ 97,051 Undeveloped Oil and Natural Gas Properties 6,321 Proved Oil and Natural Gas Properties 108,984 Property and Equipment - Other 382 Other Assets 1,445 Other Long-Term Liabilities (5,271) Deferred Income Taxes (net) (26,792) ---------- Total consideration $ 182,120 ========== The amount paid was determined through arms-length negotiations between the parties and only the cash portion of the transaction appears in the investing and financing activities sections of the company's consolidated condensed financial statements of cash flows. At the closing of this acquisition, $5.5 million, otherwise payable to the shareholders of PetroCorp Incorporated, was transferred to an escrow account to reserve for certain liabilities and related costs that may be incurred by PetroCorp Incorporated after the closing of the acquisition. As of September 30, 2004, $5.3 million is in escrow and is reflected as restricted cash. 15 Unaudited summary pro forma results of operations for the company, reflecting the PetroCorp acquisition as if it occurred at January 1, 2003 are as follow: Three Months Ended Nine Months Ended September 30, September 30, ---------------------- ---------------------- 2003 2004 2003 2004 ---------- ---------- ---------- ---------- (In thousands except per share amounts) Revenues $ 86,913 $ 143,350 $ 251,004 $ 362,873 ========== ========== ========== ========== Income Before Change In Accounting Principle $ 14,056 $ 24,647 $ 44,545 $ 60,900 ========== ========== ========== ========== Net Income $ 14,056 $ 24,647 $ 42,901 $ 60,900 ========== ========== ========== ========== Basic Earnings per Share: Income before change in accounting principle $ 0.32 $ 0.54 $ 1.02 $ 1.33 ========== ========== ========== ========== Net income $ 0.32 $ 0.54 $ 0.99 $ 1.33 ========== ========== ========== ========== Diluted Earnings per Share: Income before change in accounting principle $ 0.32 $ 0.54 $ 1.02 $ 1.33 ========== ========== ========== ========== Net income $ 0.32 $ 0.54 $ 0.98 $ 1.33 ========== ========== ========== ========== 16 The pro forma results of operations are not necessarily indicative of the actual results of operations that would have occurred for the respective periods or of the results which may occur in the future. On December 8, 2003, the company acquired SerDrilco Incorporated and its subsidiary, Service Drilling Southwest LLC, for $35.0 million in cash. The terms of the acquisition include an earn-out provision allowing the sellers to obtain one-half of the cash flow in excess of $10 million for each of the three years following the acquisition. The assets of SerDrilco Incorporated included 12 drilling rigs, spare drilling equipment, a fleet of 12 larger trucks and trailers, various other vehicles and a district office and equipment yard in and near Borger, Texas. The results of operations for the acquired entity are included in the statement of income for the periods after December 7, 2003. The amount paid in this acquisition was determined based on a number of factors including the depth capacity of the rigs, the working condition of the rigs, the active nature of the acquired company's operations and the ability of the rigs to enhance the company's ability to provide services and equipment required by its customers on a timely basis within the Anadarko Basin of Western Oklahoma and the Texas Panhandle. The company acquired SerDrilco Incorporated's tax basis in the assets acquired resulting in the recording of a deferred tax liability and goodwill of $10.9 million. The allocation of the amount paid and goodwill recognized for the acquisition is as follows (in thousands): Allocation of Total Consideration Paid and Goodwill Recognized: Drilling rigs including tubulars $ 31,012 Spare drilling equipment 904 Office, yard & yard equipment 1,200 Trucking fleet 1,486 Other vehicles 398 ---------- Total cash consideration 35,000 Goodwill recognized 10,928 ---------- Total consideration paid and recognized $ 45,928 ========== For the first nine months ending September 30, 2004, the rigs included in the Service acquisition have achieved cash flow of approximately $10.0 million. Based on the cash flow of these rigs in the second and third quarter of 2004 the company is estimated to owe the sellers of Service an earn-out payment of approximately $1.8 million for the year ended December 31, 2004. 17 NOTE 4 - Goodwill - ----------------- Goodwill represents the excess of the cost of the acquisition of Hickman Drilling Company, CREC Rig Equipment Company, CDC Drilling Company, SerDrilco Incorporated and Sauer Drilling Company over the fair value of the net assets acquired. Financial Accounting Standards No. 142, "Goodwill and Other Intangible Assets" ("FAS 142") requires, at least annually, that an impairment test be performed on such assets to determine whether the fair value has decreased. Goodwill is all related to the drilling segment. The increase in the carrying amount of goodwill of $4,698,000 during the third quarter of 2004 came from the goodwill acquired in the acquisition of Sauer Drilling Company. The acquisition is more fully discussed in Note 3. Note 5 - SALE OF ASSETS - ----------------------- On August 2, 2004, the company completed the sale of its investment in Eagle Energy Partners I, L.P. for $6.2 million. In the third quarter of 2004, a gain before income taxes of $3.8 million was recognized in other revenues from this sale. NOTE 6 - CREDIT AGREEMENT - ----------------------- On January 30, 2004, in conjunction with the company's acquisition of PetroCorp Incorporated, the company replaced its credit agreement with a revolving $150 million credit facility having a four year term ending January 30, 2008. Borrowings under the new credit facility are limited to a commitment amount. On July 15, 2004, the company increased its loan commitment from $100 million to $150 million. The company pays a commitment fee of .375 of 1% for any unused portion of the commitment amount. The company incurred origination, agency and syndication fees of $515,000 at the inception of the new agreement, $40,000 of which will be paid annually and the remainder of the fees will be amortized over the 4 year life of the loan. At September 30, 2004, the company had $107.5 million borrowed with $103.0 million subject to the Eurodollar Rate. The average interest rate for the first nine months of 2004 was 2.54%. The borrowing base under the current credit facility is re-determined twice each year on May 10 and November 10. This determination is based primarily on the sum of a percentage of the discounted future value of the company's oil and natural gas reserves, as determined by the banks. In addition, an amount representing a part of the value of the company's drilling rig fleet, limited to $20 million, is added to the borrowing base. The agreement also allows for one requested special re-determination of the borrowing base (by either the lender or the company) between each scheduled re-determination date if conditions warrant such a request. At the company's election, any part of the outstanding debt may be fixed at a Eurodollar Rate for a 30, 60, 90 or 180 day term. During any 18 Eurodollar Rate funding period the outstanding principal balance of the note to which such Eurodollar Rate option applies may be repaid on three days prior notice to the administrative agent and subject to the payment of any applicable funding indemnification amounts. Interest on the Eurodollar Rate is computed at the Eurodollar Base Rate applicable for the interest period plus 1.00% to 1.50% depending on the level of debt as a percentage of the total loan value and payable at the end of each term or every 90 days whichever is less. Borrowings not under the Eurodollar Rate bear interest at the JPMorgan Chase Prime Rate payable at the end of each month and the principal borrowed may be paid anytime in part or in whole without premium or penalty. The credit agreement includes prohibitions against: . the payment of dividends (other than stock dividends) during any fiscal year in excess of 25% of our consolidated net income for the preceding fiscal year, . the incurrence of additional debt with 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, except in favor of the company's banks. The credit agreement also requires that the company have at the end of each quarter: . consolidated net worth of at least $350 million, . a current ratio (as defined in the credit agreement) of not less than 1 to 1, and . a leverage ratio of long-term debt to consolidated EBITDA (as defined in the credit agreement) for the most recently ended rolling four fiscal quarters of no greater than 3.25 to 1.0. On September 30, 2004, the company was in compliance with the covenants of its credit agreement. NOTE 7 - NEW ACCOUNTING PRONOUNCEMENTS - -------------------------------------- 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. 19 The following table shows the activity for the nine months ending September 30, 2003 and 2004 relating to the company's retirement obligation for plugging liability: Nine Months Ended ----------------------------- 2003 2004 ------------- ------------- (In Thousands) Short-Term Plugging Liability: Liability at beginning of period $ 203 $ 303 Accretion of discount 8 6 Liability settled in the period -- (62) Sold -- (21) Reclassification of liability from long- to short-term 181 -- ------------- ------------- Plugging liability at end of period $ 392 $ 226 ============= ============= Long-Term Plugging Liability: Liability at beginning of period $ 10,632 $ 11,691 Accretion of discount 369 619 Liability incurred in the period 529 6,048 Liability settled in the period (106) (16) Sold -- (63) Reclassification of liability from long- to short-term (181) -- ------------- ------------- Plugging liability at end of Period $ 11,243 $ 18,279 ============= ============= On September 28, 2004 the Security and Exchange Commission issued Staff Accounting Bulletin No. 106 (SAB No. 106). The interpretations in SAB No. 106 express the staff's views regarding the application of FASB Statement No. 143, "Accounting for Asset Retirement Obligations", by oil and gas producing companies following the full cost accounting method. Under Statement 143, the company must recognize a liability for an asset retirement obligation at fair value in the period in which the obligation is incurred, if a reasonable estimate of fair value can be made. The company also 20 must initially capitalize the associated asset retirement costs by increasing its full cost pool by the same amount as the liability. Under the full cost method of accounting, the company calculates quarterly a limitation on capitalized costs, i.e., the full cost ceiling of our oil and natural gas properties and any asset retirement costs capitalized pursuant to Statement 143 are subject to the full cost ceiling limitation. SAB No. 106 provides that after adoption of Statement 143, the future cash outflows associated with settling AROs that have been accrued on the balance sheet should be excluded from the computation of the present value of estimated future net revenues for purposes of the full cost ceiling calculation. The effect of this interpretation will increase the ceiling the company has currently calculated on its full cost pool. Subsequent to the adoption of Statement 143, the estimated dismantlement and abandonment costs for the company's oil and natural gas properties that have been capitalized have been included in the costs used when calculating the depreciation, depletion and amortization (DD&A) rate used to amortize the properties. Future development activities on proved reserves may result in additional asset retirement obligations when such activities are performed and the associated asset retirement costs will be capitalized at that time. Under the interpretations in SAB No. 106 to the extent that estimated dismantlement and abandonment costs, net of estimated salvage values, have not been capitalized for future development activity, the company will be required to estimate the amount of dismantlement and abandonment costs that will be incurred and include those amounts in the costs to be amortized. The company has not yet determined the full impact this will have on the DD&A rate used by it in the fourth quarter of 2004, but it is not expected to be material. The company will be required to apply the accounting and disclosures described in SAB No. 106 prospectively as of the beginning of the fourth quarter of 2004. The company has not yet determined the full impact this will have on the DD&A rate used by it in the fourth quarter of 2004. On January 17, 2003, the Financial Accounting Standards Board (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 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, as amended, was effective for the company in the fourth quarter of 2003 as it applies to entities created after February 1, 2003. The adoption of FIN 46 with respect to these entities, primarily Eagle Energy Partnership I, L.P. (which we sold in August 2004, See Note 5), did not have an impact on the company's financial position or results of operations or cash flows. For entities created prior to February 1, 2003, which are not special purpose entities, as defined in FIN 46, FIN 46 and the amendment of FIN 46 were effective for the company, as amended, in the quarter ending March 31, 2004. The 21 company evaluated FIN 46 and FIN 46(R) with regard to these types of entities in which it has an ownership interest and there was no material impact to the financial position, results of operations or cash flows from the adoption of FIN 46 and FIN 46(R). NOTE 8 - 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 Financial Accounting Standards Board (FASB) in June 2001 and became effective for the company on July 1, 2001 and January 1, 2002, respectively. The company previously reported that an interpretation of FAS 141 and 142 was being considered as to whether mineral interest use rights in oil and natural gas properties are intangible assets and would be classified as such, separate from oil and natural gas properties. On September 2, 2004, the FASB issued FASB Staff Position 142-2 "Application of FASB Statement No. 142, Goodwill and Other Intangible Assets, to Oil- and Gas-Producing Entities" (FSP 142-2) to address the application of FAS 142 to the oil and natural gas industry. In FSP 142-2 the FASB staff acknowledges that the accounting framework in Statement 19 for oil- and gas-producing entities is based on the level of established reserves - not whether an asset is tangible or intangible. Accordingly, the FASB staff believes that the scope exception in paragraph 8(b) of FAS 142 extends to its disclosure for drilling and mineral rights of oil- and gas-producing entities. FSP 142-2 confirms the company's historical treatment of these costs. NOTE 9 - HEDGING ACTIVITY - ------------------------- Periodically the company hedges the prices 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 cash flow. During the first quarter of 2003, the company entered into two natural gas collar contracts. Each contract was for 10,000 MMBtu's of production per day and covered the period of April through September 2003. One contract had a floor price of $4.00 and a ceiling price of $5.75 and the other contract has 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. Each contract was for 5,000 barrels of production per month and covered the period of May through December 2003. One contract had a floor price of $25.00 and a ceiling price of $32.20 and the other contact had 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 22 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 cash flow hedges and there was no material amount of ineffectiveness. During the first quarter of 2004, the company entered into a natural gas collar covering 10,000 MMBtu's per day of its natural gas production. The transaction covers the periods of April through October of 2004 and has a floor of $4.50 and a ceiling of $6.76. In the first quarter of 2004, the company also entered into an oil hedge covering 1,000 barrels per day of its oil production. The transaction covers the periods of February through December of 2004 and has an average price of $31.40. In April 2004, the company entered into a natural gas collar covering an additional 10,000 MMBtu's per day of its natural gas production. The transaction covers the periods of May through October of 2004 and has a floor of $5.00 and a ceiling of $7.00. The fair value of the oil hedge was recognized on the September 30, 2004 balance sheet as a derivative liability of $1,739,000 and at a loss of $1,077,000, net of tax, in accumulated other comprehensive income. These hedges were cash flow hedges and there was no material amount of ineffectiveness. The natural gas collar contracts increased natural gas revenues by $48,000 during the first nine months of 2004. Oil revenues were reduced by $1,207,000 in the third quarter of 2004 due to the settlement of the oil hedge and oil revenues have been reduced by $1,894,000 for the nine months ended September 30, 2004. NOTE 10 - COMMITMENTS AND CONTINGENCIES - -------------------------------------- Because of increasing cost of steel and the potential for limited availability of new drill pipe, in the first quarter of 2004 the company committed to purchase by the end of 2004 approximately 275,000 feet of drill pipe for $9.3 million. At September 30, 2004, 50,000 feet (or approximately $1.6 million) of this commitment remained outstanding. NOTE 11 - INDUSTRY SEGMENT INFORMATION - ------------------------------------- With the acquisition of Superior Pipeline Company (See Note 3), the company has three primary business segments: Contract Drilling; Oil and Natural Gas; and Gas Gathering and Processing, each offering different products and services. The Contract Drilling segment provides land contract drilling of oil and natural gas wells, the Oil and Natural Gas segment is engaged in the development, acquisition and production of oil and natural gas properties and the Gas Gathering and Processing segment is engaged in the gathering, processing and treating of natural gas. Management 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, 2003 and 2004 is as follows: 23 Three Months Ended Nine Months Ended September 30, September 30, ----------------------- ----------------------- 2003 2004 2003 2004 ---------- ---------- ---------- ---------- (In thousands) Revenues: Contract drilling $ 53,191 $ 83,486 $ 136,232 $ 219,647 Elimination of inter-segment revenue 3,139 2,599 6,393 8,436 ---------- ---------- ---------- ---------- Contract drilling net of inter- segment revenue 50,052 80,887 129,839 211,211 ---------- ---------- ---------- ---------- Oil and natural gas 27,402 46,394 87,521 130,718 ---------- ---------- ---------- ---------- Gas gathering and processing 379 12,658 970 13,495 Elimination of inter-segment revenue 231 1,184 404 1,933 ---------- ---------- ---------- ---------- Gas gathering and processing net of inter-segment revenue 148 11,474 566 11,562 ---------- ---------- ---------- ---------- Other(1) 198 4,595 832 5,497 ---------- ---------- ---------- ---------- Total revenues $ 77,800 $ 143,350 $ 218,758 $ 358,988 ========== ========== ========== ========== 24 Three Months Ended Nine Months Ended September 30, September 30, ----------------------- ----------------------- 2003 2004 2003 2004 ---------- ---------- ---------- ---------- (In thousands) Operating Income (2): Contract drilling $ 8,081 $ 14,168 $ 15,623 $ 34,354 Oil and natural gas 14,223 24,332 49,402 66,819 Gas gathering and processing 40 543 134 558 ---------- ---------- ---------- ---------- Total operating Income 22,344 39,043 65,159 101,731 General and admini- strative expense (2,246) (3,081) (6,766) (8,955) Interest expense (154) (820) (540) (1,751) Other income - net 198 4,595 832 5,497 ---------- ---------- ---------- ---------- Income before income taxes $ 20,142 $ 39,737 $ 58,685 $ 96,522 ========== ========== ========== ========== - ----------------- (1) Other in 2004 includes a $3.8 million gain on the sale of the investment in Eagle Energy Partners I, L.P. (2) 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 $1,325,000, net of $811,000 in income tax, is all related to the oil and natural gas segment. 25 REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM To the Board of Directors and Shareholders Unit Corporation: We have reviewed the accompanying consolidated condensed balance sheet of Unit Corporation and its subsidiaries as of September 30, 2004, and the related consolidated condensed statements of income and comprehensive income for each of the three-month and nine-month periods ended September 30, 2004 and 2003 and the consolidated condensed statements of cash flows for the nine-month periods ended September 30, 2004 and 2003. These interim financial statements are the responsibility of the Company's management. We conducted our review in accordance with the standards of the Public Company Accounting Oversight Board (United States). 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 the standards of the Public Company Accounting Oversight Board, 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 consolidated condensed 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 the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheet as of December 31, 2003, and the related consolidated statements of income, shareholders' equity and cash flows for the year then ended (not presented herein), and in our report dated February 18, 2004 we expressed an unqualified opinion on those consolidated financial statements in a report that also included an explanatory paragraph referring to a change in accounting principle discussed in Note 1 to the financial statements. In our opinion, the information set forth in the accompanying consolidated condensed balance sheet as of December 31, 2003, is fairly stated in all material respects in relation to the consolidated balance sheet from which it has been derived. PricewaterhouseCoopers LLP Tulsa, Oklahoma November 5, 2004 26 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 generated from our three principal business segments (and our subsidiaries that carry out those operations) and borrowings under our bank credit agreement. Our cash flow is influenced mainly by the prices we receive for our natural gas production, the quantity of natural gas produced, the demand for and the dayrates we receive for our drilling rigs and, to a lesser extent, the prices we receive for our oil production and the prices received from gas gathering and processing fees. At September 30, 2004, we had cash totaling $1.5 million and we had borrowed $107.5 million of the $150.0 million we had elected to have available under our credit agreement. Our three principal business segments are (i) contract drilling carried out by our subsidiaries Unit Drilling Company, Service Drilling Southwest, L.L.C. and Sauer Drilling Company, (ii) oil and natural gas exploration, carried out by our subsidiaries Unit Petroleum Company and PetroCorp Incorporated and (iii) gas gathering and processing carried out by our subsidiary Superior Pipeline Company. The following is a summary of certain financial information on September 30, 2003 and September 30, 2004 and for the nine months ended September 30, 2003 and September 30, 2004: September 30, September 30, Percent 2003 2004 Change -------------- -------------- ------- (In thousands except percent amounts) Working Capital $ 27,074 $ 21,574 (20%) Long-Term Bank Debt $ 15,000 $ 107,500 617% Shareholders' Equity $ 461,341 $ 576,862 25% Ratio of Long-Term Debt to Total Capitalization 3% 16% Income Before Change in Accounting Principle $ 37,113 $ 60,341 63% Net Income $ 38,438 $ 60,341 57% Net Cash Provided by Operating Activities $ 88,412 $ 151,771 72% Net Cash Used in Investing Activities $ (67,375) $ (258,576) 284% Net Cash Provided by (Used in) Financing Activities $ (19,769) $ 107,747 -- 27 The following table summarizes certain operating information for the first nine months of 2003 and 2004: Percent 2003 2004 Change ------------ ------------ -------- Oil Production (MBbls) 372 767 106% Natural Gas Production (MMcf) 15,043 19,855 32% Average Oil Price Received $ 27.02 $ 32.17 19% Average Oil Price Received Excluding Hedge $ 27.02 $ 34.64 28% Average Natural Gas Price Received $ 5.05 $ 5.23 4% Average Number of Our Drilling Rigs in Use During the Period 60.6 85.8 42% Total Number of Our Drilling Rigs Available at the End of the Period 75 100 33% Gas Gathered - MMBtu/day 11,200 26,090 133% Gas Processed - MMBtu/day -- 26,669 -- Our Bank Credit Agreement. On January 30, 2004, in conjunction with our acquisition of PetroCorp Incorporated, we replaced our credit agreement with a revolving credit facility totaling $150 million having a four year term ending January 30, 2008. Borrowings under the new credit facility are limited to a commitment amount. On July 15, 2004, the company increased its loan commitment from $100 million to $150 million. We are charged a commitment fee of .375 of 1% on the amount available but not borrowed. We incurred origination, agency and syndication fees of $515,000 at the inception of the new agreement, $40,000 of which will be paid annually and the remainder of the fees amortized over the four year life of the loan. The average interest rate for the first nine months of 2004 was 2.54%. At September 30, 2004 and October 27, 2004 our borrowings were $107.5 million and $103.0 million, respectively. The borrowing base under our current credit facility is subject to a semi-annual re-determination on May 10 and November 10 of each year. This determination is based primarily on the sum of 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. The agreement allows for one requested special re-determination of the borrowing base by either the lender or us between each scheduled re-determination date if conditions warrant such a request. At our election, any part of the outstanding debt may be fixed at a Eurodollar Rate for a 30, 60, 90 or 180 day term. During any Eurodollar Rate funding period the outstanding principal balance of the note to which such Eurodollar Rate option applies may be repaid on three days prior notice to the administrative agent subject to the payment of any applicable funding indemnification amounts. Interest on the Eurodollar Rate is computed at the Eurodollar Base Rate applicable for the interest period plus 1.00% to 1.50% depending on the level of debt as a percentage of the total loan value and is 28 payable at the end of each term or every 90 days whichever is less. Borrowings not under the Eurodollar Rate bear interest at the JPMorgan Chase Prime Rate payable at the end of each month and the principal borrowed may be paid anytime in part or in whole without premium or penalty. At September 30, 2004, $103.0 million of our $107.5 million debt was subject to the Eurodollar Rate. The credit agreement includes prohibitions against: . the payment of dividends (other than stock dividends) during any fiscal year in excess of 25% of our consolidated net income for the preceding fiscal year, . the incurrence of additional debt with 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, except in favor of our banks. The credit agreement also requires that we have at the end of each quarter: . consolidated net worth of at least $350 million, . a current ratio (as defined in the credit agreement) of not less than 1 to 1, and . a leverage ratio of long-term debt to consolidated EBITDA (as defined in the credit agreement) for the most recently ended rolling four fiscal quarters of no greater than 3.25 to 1.0. On September 30, 2004, we were in compliance with the covenants of the credit agreement. 29 Contractual Commitments. We have the following contractual obligations at September 30, 2004: 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) $107,500 $ -- $ -- $107,500 $ -- Retirement Agreement(2) 1,158 300 600 258 -- Operating Leases(3) 4,467 1,168 2,031 1,094 174 Drill Pipe Acquisi- tions(4) 1,600 1,600 -- -- -- Hedging Liability(5) 1,739 1,739 -- -- -- --------- -------- -------- --------- -------- Total Contractual Obligations $116,464 $ 4,807 $ 2,631 $108,852 $ 174 ========= ======== ======== ========= ======== ------------------- (1) See Previous Discussion in Management Discussion and Analysis regarding bank debt. (2) The retirement agreement represents a contractual obligation made in the second quarter of 2001 for a separation agreement made in connection with the retirement of King Kirchner from his position as Chief Executive Officer. The liability, including accrued interest, is being paid monthly in $25,000 installments continuing through June 2009. The discounted liability is on our consolidated condensed balance sheet as part of other long-term liabilities and is presented above undiscounted. (3) We lease office space in Tulsa and Woodward, Oklahoma and Houston and Midland, Texas under the terms of operating leases expiring through January 31, 2010 along with a few office machines and space on short-term commitments to stack excess rig equipment and production inventory. (4) Because of the increasing cost of steel and the potential for limited availability of new drill pipe, in the first quarter of 2004 we made a commitment to purchase approximately 275,000 feet of drill pipe by the end of 2004. At September 30, 2004 approximately 50,000 feet of that commitment remained outstanding. (5) The fair value of our oil hedge is recognized as a derivative liability at September 30, 2004. See subsequent discussion in Management Discussion and Analysis regarding hedging. 30 On December 8, 2003, the company acquired SerDrilco Incorporated and its subsidiary, Service Drilling Southwest LLC, for $35.0 million in cash. The terms of the acquisition include an earn-out provision allowing the sellers to obtain one-half of the cash flow in excess of $10 million for each of the three years following the acquisition. For the first nine months ending September 30, 2004, the rigs included in the Service acquisition have achieved cash flow of approximately $10.0 million. Based on the cash flow of these rigs in the second and third quarter of 2004 the company is estimated to owe the sellers of Service an earn-out payment of approximately $1.8 million for the year ended December 31, 2004. On October 19, 2004, Mr. John Nikkel, the Company's Chairman of the Board of Directors and Chief Executive Officer, announced that he plans to retire as an employee and as the Company's Chief Executive Officer effective April 1, 2005. Mr. Nikkel intends to continue as a director of the Company. In connection with the retirement, the Board of Directors of Unit Corporation and Mr. Nikkel have reached an agreement providing for the following: a. Mr. Nikkel would serve as a consultant to the Company, on an annual basis, for $70,000 per year; and b. The Company would provide office space and secretarial service for Mr. Nikkel for the time he serves as a consultant to the Company. At September 30, 2004, we 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) $ 2,079 Unknown Unknown Unknown Unknown Separation Benefit Agreement(2) $ 2,735 $ 415 Unknown Unknown Unknown Plugging Liability(3) $ 18,505 $ 226 $ 602 $ 841 $ 16,836 Gas Balancing Liability(4) $ 1,191 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 31 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 us up to a maximum of 104 weeks. To receive payments the recipient must waive any claims against us 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 in this plan. (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 a liability recorded for certain properties where we believe there are insufficient natural gas 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 2004, 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 that year. These partnership agreements require, on 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% of the units outstanding. We made repurchases of $106,000 in 2003 for limited partners' interests. Repurchases of $14,000 were made in the first nine months of 2004. 32 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. Each collar contract was for 10,000 MMBtu's of production per day and covered the period of April through September 2003. One contract had a floor price of $4.00 and a ceiling price of $5.75 and the other contract has 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. Each contract was for 5,000 barrels of production per month and covered the period of May through December 2003. One contract had a floor price of $25.00 and a ceiling price of $32.20 and the other contact had a floor price 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 cash flow hedges and there was no material amount of ineffectiveness. During the first and second quarters of 2004, we entered into two natural gas collar contracts. Each collar contract was for 10,000 MMBtu's of production per day. One contract covers the period of April through October of 2004 and has a floor of $4.50 and a ceiling of $6.76. The other contract covers the period of May through October of 2004 and has a floor of $5.00 and a ceiling of $7.00. We also entered into an oil hedge covering 1,000 barrels per day of oil production. The transaction covers the periods of February through December of 2004 and has an average price of $31.40. The fair value of the oil hedge was recognized on the September 30, 2004 balance sheet as a derivative liability of $1,739,000 and at a loss of $1,077,000, net of tax, in accumulated other comprehensive income. These hedges were cash flow hedges and there was no material amount of ineffectiveness. The natural gas collar contracts increased natural gas revenues by $48,000 during the first nine months of 2004. Oil revenues were reduced by $1,207,000 in the third quarter of 2004 due to the settlement of the oil hedge and oil revenues have been reduced by $1,894,000 for the nine months ended September 30, 2004. 33 Self-Insurance or Retentions. We are self-insured (or have a retention) for certain losses relating to workers' compensation, general liability, property damage and employee medical benefits. The exposure (i.e. our deductible or retention) per occurrence is generally $1 million for general liability and $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. Following the acquisition of SerDrilco we have continued to use its ERISA governed occupational injury benefit plan to cover its employees in lieu of covering them under an insured Texas workers' compensation plan. Impact of Prices for Our Oil and Natural Gas. With the acquisition of PetroCorp Incorporated (as previously discussed in Note 3 of the Notes to Consolidated Condensed Financial Statements), natural gas comprises 86% of our total oil and natural gas reserves. Any significant change in natural gas prices has a material affect on our revenues, cash flow and the value of our oil and natural gas reserves. Generally, prices and demand for domestic natural gas are influenced by weather conditions, supply imbalances, the amount and timing of liquid natural gas imports and by world wide oil price levels. Domestic oil prices are primarily influenced by world oil market developments. All of these factors are beyond our control and we can not predict nor measure their future influence on the prices we will receive. Based on our production in 2004, after the acquisition of PetroCorp Incorporated, a $.10 per Mcf change in what we are paid for our natural gas production would result in a corresponding $235,000 per month ($2,820,000 annualized) change in our pre-tax operating cash flow. Our first nine month 2004 average natural gas price was $5.23 compared to an average natural gas price of $5.05 for the first nine months of 2003. A $1.00 per barrel change in our oil price would have a $92,800 per month ($1,114,000 annualized) change in our pre-tax operating cash flow based on our production in 2004 after the acquisition of PetroCorp Incorporated. Our first nine month 2004 average oil price was $32.17 compared with an average oil price of $27.02 received in the first nine months of 2003. Because natural gas prices have such a significant affect on the value of our oil and natural gas reserves, declines in these prices can result in a decline in the carrying value of our oil and natural gas properties. Price declines can also adversely affect the semi-annual determination of the amount available for us to borrow under our bank credit 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. We sell most of our natural gas production to third parties under month-to-month contracts. Presently we believe that our buyers will be able to perform their commitments to us. On August 2, 2004, we completed the sale of our 16.7% limited partner interest in Eagle Energy Partners I, L.P., whose purchases, which are competitively marketed, accounted for 29% of our oil and 34 natural gas revenues in the first nine months of 2004. They marketed approximately 56% of the natural gas volumes we sold for ourselves and third parties during the same period. Oil and Natural Gas Acquisitions and Capital Expenditures. Most of our capital expenditures are discretionary and directed toward future growth. Any 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 financing under the circumstances involved, all of which provide us with a large degree of flexibility in deciding when and if to incur these costs. We drilled 110 wells (47.02 net wells) in the first nine months of 2004 compared to 98 wells (38.04 net wells) in the first nine months of 2003. Our total capital expenditures for oil and natural gas exploration and acquisitions in the first nine months of 2004 totaled $187.8 million with $115.6 million relating to the PetroCorp Incorporated acquisition. Included in the PetroCorp Incorporated acquisition was a plugging liability and deferred tax liability of $32.1 million. Based on current prices, we plan to drill an estimated total of 165 to 175 wells in 2004 and total capital expenditures for oil and natural gas exploration and acquisitions is planned to be approximately $105 million excluding the PetroCorp Incorporated acquisition. Due to the anticipated upward trend in costs resulting from a shortage in steel, we increased our inventory of production casing and tubing from $3.1 million to $7.3 million in the first nine months of 2004. This inventory will be used to meet our continued demand for such items as we complete wells in our development drilling program. Contract Drilling. Our drilling work is subject to many factors that influence the number of rigs we have working as well as the costs and revenues associated with that work. These factors 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 equipment needed. We have not encountered major difficulty in hiring and keeping rig crews, but shortages have occurred periodically in the past. At the end of the first quarter of 2004, we increased wages in some of our drilling areas and implemented longevity pay incentives to help maintain our contract drilling labor base. If demand for drilling rigs increases in the future, shortages of experienced personnel may well limit our ability to increase the number of rigs we could operate. We currently do not have a shortage of drill pipe. Because of increasing steel costs and the potential for future shortages in the availability of new drill pipe, we committed in the first quarter of 2004 to purchase by the end of 2004 approximately 275,000 feet of drill pipe for $9.3 million. At September 30, 2004, 50,000 feet (or approximately $1.6 million) of this commitment remains outstanding. Most of our contract drilling fleet is targeted to the drilling of natural gas wells, so changes in natural gas prices heavily influence the demand for our drilling rigs and the prices we can charge for our contract drilling services. The average rates we received for our drilling rigs during 2003 and 2004 reached a low of $7,275 per day in February of 2003. Natural gas and oil prices began to 35 rise since the second quarter of 2003 and have continued to remain strong through the first nine months of 2004 and both demand for our drilling rigs and dayrates have continued to improve. In the first nine months of 2004, the average dayrate we received was $8,722 per day compared to $7,684 per day in the first nine months of 2003. The average use of our drilling rigs in the first nine months of 2004 was 85.8 rigs (95%) compared with 60.6 rigs (81%) for the first nine months of 2003. Based on the average utilization of our drilling rigs in the first nine months of 2004, a $100 per day change in dayrates has an $8,580 per day ($3,132,000 annualized) change in our pre-tax operating cash flow. Utilization and dayrates for our drilling rigs will depend mainly on the price of natural gas. Our contract drilling subsidiaries provide drilling services for our exploration and production subsidiaries. The contracts for these services are issued under the same conditions and rates as the contracts we have entered into with unrelated third parties for comparable type projects. During the first nine months of 2003 and 2004, we drilled 34 and 30 wells, respectively, for our exploration and production subsidiaries. The profit received by our contract drilling segment of $1,411,000 and $2,760,000 during the first nine months of 2003 and 2004, 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. Drilling Acquisitions and Capital Expenditures. On July 30, 2004, we acquired Sauer Drilling Company, a Casper-based drilling company and a wholly-owned subsidiary of Tom Brown, Inc., for $34.7 million in cash paid at closing. In addition, the agreement provides that there will be a post closing settlement adjustment for the working capital of Sauer Drilling Company. Currently the seller has estimated this cost to be $6.2 million and the company has estimated this cost to be $5.3 million. In the event the parties can not resolve this discrepancy, the issue will be settled by arbitration. This acquisition includes 9 drilling rigs, a fleet of trucks, and an equipment and repair yard with associated inventory, located in Casper, Wyoming. Of the 9 rigs, 8 are currently operating under contract in the Wind River Basin in Wyoming and the Paradox Basin in Colorado. The rigs range from 500 horsepower to 1,000 horsepower with depth capacities rated from 5,000 feet to 16,000 feet. The fleet of trucks consists of 4 vacuum trucks and 11 rig-up trucks used to move the rigs to new drilling locations. The trucks also have the capacity to move third-party rigs. This acquisition increased our market share within medium to shallower drilling depth ranges in our areas of operation in our Rocky Mountain Division. The equipment yard, located in Casper, Wyoming, will not only provide service space for the nine newly acquired rigs and trucks but also for our existing Rocky Mountain rig fleet. On May 4, 2004, we acquired two drilling rigs and related equipment for $5.5 million. The rigs are rated at 850 and 1,000 horsepower, respectively, with depth capacities from 12,000 to 15,000 feet. We refurbished the rigs for 36 approximately $4.0 million. One rig was placed into service at the beginning of August 2004 and the other rig was placed into service in the middle of September 2004. Both rigs are working in the area covered by the Rocky Mountain division. The 2 rigs acquired on May 4, 2004 and the Sauer Drilling Company rigs were added to the area covered by the Rocky Mountain division bringing the total rigs in that area to 19. With these two acquisitions and the completion of construction of another rig in June 2004, our total rig fleet now consists of 100 drilling rigs. We are currently constructing our 101st rig which is contracted and should be ready to enter the market in December 2004. Our contract drilling operations, during the first nine months of 2004, incurred $82.1 million in capital expenditures including the $34.7 million paid for the Sauer Drilling Company acquisition and the $9.5 million paid for the 2 rigs acquired on May 4, 2004 and their subsequent refurbishment. For the year 2004, we have budgeted capital expenditures of approximately $50 million for our contract drilling operations (excluding our acquisition of Sauer Drilling Company and the capital expenditures on the two rigs acquired on May 4, 2004). On December 8, 2003, we acquired SerDrilco Incorporated and its subsidiary, Service Drilling Southwest LLC, for $35.0 million in cash. The terms of the acquisition include an earn-out provision allowing the sellers to obtain one-half of the cash flow in excess of $10 million for each of the three years following the acquisition. The assets of SerDrilco Incorporated included 12 drilling rigs, spare drilling equipment, a fleet of 12 larger trucks and trailers, various other vehicles and a district office and an equipment yard in and near Borger, Texas. For the first nine months ending September 30, 2004, the rigs included in the Service acquisition have achieved cash flow of approximately $10.0 million. Based on the cash flow of these rigs in the second and third quarter of 2004 the company is estimated to owe the sellers of Service an earn-out payment of approximately $1.8 million for the year ended December 31, 2004. Acquisition of Gas Gathering and Processing Company On July 29, 2004, we completed the acquisition of the 60% of Superior Pipeline Company LLC ("Superior") we did not already own for $19.8 million. Superior is a mid-stream company engaged primarily in the gathering, processing and treating of natural gas and owns one natural gas treatment plant, two processing plants, 12 active gathering systems and 400 miles of pipeline. Superior operates in western Oklahoma and the Texas Panhandle and has been in business since 1996. This acquisition will increase our ability to gather and market our (as well as third parties) natural gas and construct or acquire existing natural gas gathering and processing facilities. During the first nine months of 2004, Superior purchased $3.1 million of our natural gas production and paid $30,000 for our natural gas liquids. We paid this company $300,000 for gathering and compression services in the first nine months of 2004. The results of operations for this acquired company are included in the statement of income for the period after July 31, 2004 and intercompany revenue from services and purchases of production between subsidiaries has been eliminated. 37 Oil and Natural Gas Limited Partnerships and Other Entity Relationships. One of our wholly-owned subsidiaries is the general partner for 10 oil and natural gas limited partnerships which were formed either privately or publicly. Each partnership's revenues and costs are shared under formulas prescribed in the applicable 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 2003, the total amount paid to us for all of these fees was $873,000 and during the first nine months of 2004 the amount paid has been 15 percent below last year's nine month comparable amount. Our proportionate share of assets, liabilities and net income relating to the oil and natural gas partnerships is included in our consolidated financial statements. On August 2, 2004, we completed the sale of our investment in Eagle Energy Partners I, L.P. for $6.2 million. In the third quarter of 2004, a gain before income taxes of $3.8 million was recognized in other revenues from this sale. Eagle is engaged in the purchase and sale of natural gas, electricity (or similar electricity based products), future commodities, and the performance of scheduling and nomination services for both energy related commodities and similar energy management functions. Eagle marketed approximately 56% of the natural gas volumes we sold for ourselves and third parties in the first nine months of 2004. Critical Accounting Policies. Summary In this section, we have identified the critical accounting policies we follow in preparing our financial statements and related disclosures. Many of these policies require us to make difficult, subjective and complex judgments in the course of making estimates of matters that are inherently imprecise. We will explain the nature of these estimates, assumptions and judgments, and the likelihood that materially different amounts would be reported in our financial statements under different conditions or using different assumptions. 38 The following table lists our critical accounting policies, the estimates and assumptions that can have a significant impact on the application of these accounting policies, and the financial statement accounts affected by these estimates and assumptions. Accounting Policies Estimates or Accounts Affected Assumptions - --------------------- -------------------- -------------------- Full cost method of . Reserve . Oil and gas accounting for oil estimates and properties and gas properties related present . Accumulated DD&A value of future . Provision for net revenues DD&A . Valuation of . Impairment of unproved proved and properties unproved properties . Long-term debt and interest expense Accounting for . Cost estimates . Oil and gas asset retirement related to the properties obligations for oil plugging and . Accumulated DD&A and gas properties abandonment of . Provision for depleted wells DD&A . Current and non- current liabilities . Operating expense Accounting for . Forecast of . Drilling property impairment of undiscounted and equipment drilling property estimated future . Accumulated and equipment net operating cash depreciation flows . Provision for depreciation . Impairment of drilling property and equipment Turnkey and footage . Estimates of costs . Revenue and drilling contracts to complete turnkey operating expense and footage . Current assets and contracts liabilities 39 Significant Estimates and Assumptions Reserve engineering is a subjective process of estimating underground accumulations of oil and gas that cannot be measured in an exact manner. The accuracy of a reserve estimate depends on the quality of available geological and engineering data, the precision of the interpretations of that data, and judgment based on experience and training. Annually, we engage an independent petroleum engineering firm to evaluate our oil and gas reserves. The techniques used in estimating reserves annually depend on the nature and extent of available data and the accuracy of the estimates accordingly. As a general rule, the degree of accuracy of reserve estimates varies with the reserve classification and the related accumulation of available data, as shown in the following table. Type of Reserves Nature of Available Degree of Accuracy Data ------------------ --------------------- -------------------- Proved undeveloped Data from offsetting Least accurate wells, seismic data Proved developed Logs, core samples, More accurate Non-producing well tests, pressure data Proved developed Production history, Most accurate Producing pressure data over time Assumptions as to future commodity prices and operating and capital costs also play a significant role in estimating oil and gas reserves and the estimated present value of the cash flows to be received from the future production of those reserves. Volumes of recoverable reserves are affected by the assumed prices and costs due to what is known as the economic limit (that point in the future when the projected costs and expenses of producing recoverable reserves exceed the projected revenues from the reserves). But more significantly, the estimated present value of future cash flows from the reserves is extremely sensitive to prices and costs, and may vary materially based on different assumptions. SEC financial accounting and reporting standards require that pricing parameters be tied to the price received for oil and natural gas on the last day of the reporting period. This requirement can result in significant changes from period to period given the volatile nature of oil and natural gas prices. We compute our provision for DD&A on a units-of-production method. Each quarter, we use the following formulas to compute the provision for DD&A for our producing properties: . DD&A Rate = Unamortized Cost / Beginning of Period Reserves . Provision for DD&A = DD&A Rate x Current Period Production 40 Reserve estimates have a significant impact on the DD&A rate. If reserve estimates for a property or group of properties are revised downward in future periods, the DD&A rate will increase as a result of the revision. Alternatively, if reserve estimates are revised upward, the DD&A rate will decrease. 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 are limited to the lower of unamortized cost or a ceiling. The ceiling is defined as the sum of the present value (10% discount rate) of estimated future net revenues from proved reserves, based on period-end oil and natural gas prices adjusted for hedging, plus the lower of cost or estimated fair value of unproved properties not 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 on September 30, 2004 ($5.74 per Mcf for natural gas and $49.64 per barrel for oil), the unamortized cost of our oil and natural gas properties did not exceed the ceiling of our proved oil and natural gas reserves. Natural gas and oil prices remain erratic and any significant declines below prices used in the reserve evaluation could result in a ceiling test write-down in following quarterly reporting periods. 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. 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. 41 Drilling equipment, transportation equipment and other property and equipment are carried at cost. Renewals and enhancements 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 these estimates could cause us to reduce the carrying value of property and equipment. We recognize revenues and expense generated from "daywork" drilling contracts as the services are performed, since we do not bear the risk of completion of the well. Under "footage" and "turnkey" contracts, we bear the risk of completion of the well, so revenues and expenses are recognized when the well is substantially completed. Under this method, substantial completion is determined when the well bore reaches the negotiated depth as stated in the contract. The entire amount of a loss, if any, is recorded when the loss can be reasonably determined, however, any profit is recorded only at the time the well is finished. 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. 42 NEW ACCOUNTING PRONOUNCEMENTS - ----------------------------- On September 28, 2004 the Security and Exchange Commission issued Staff Accounting Bulletin No. 106 (SAB No. 106). The interpretations in SAB No. 106 express the staff's views regarding the application of FASB Statement No. 143, "Accounting for Asset Retirement Obligations", by oil and gas producing companies following the full cost accounting method. Under Statement 143, we must recognize a liability for an asset retirement obligation at fair value in the period in which the obligation is incurred, if a reasonable estimate of fair value can be made. We also must initially capitalize the associated asset retirement costs by increasing our full cost pool by the same amount as the liability. Under the full cost method of accounting, we calculate quarterly a limitation on capitalized costs, i.e., the full cost ceiling of our oil and natural gas properties and any asset retirement costs capitalized pursuant to Statement 143 are subject to the full cost ceiling limitation. SAB No. 106 provides that after adoption of Statement 143, the future cash outflows associated with settling AROs that have been accrued on the balance sheet should be excluded from the computation of the present value of estimated future net revenues for purposes of the full cost ceiling calculation. The effect of this interpretation will increase the ceiling we currently calculated on our full cost pool. Subsequent to the adoption of Statement 143, the estimated dismantlement and abandonment costs for our oil and natural gas properties that have been capitalized have been included in the costs used when calculating the depreciation, depletion and amortization (DD&A) rate used to amortize the properties. Future development activities on proved reserves may result in additional asset retirement obligations when such activities are performed and the associated asset retirement costs will be capitalized at that time. Under the interpretations in SAB No. 106 to the extent that estimated dismantlement and abandonment costs, net of estimated salvage values, have not been capitalized for future development activity, we will be required to estimate the amount of dismantlement and abandonment costs that will be incurred and include those amounts in the costs to be amortized. We have not yet determined the full impact this will have on the DD&A rate used by us in the fourth quarter of 2004, but it is not expected to be material. We are required to apply the accounting and disclosures described in SAB No. 106 prospectively as of the beginning of the fourth quarter of 2004. We have not yet determined the full impact this will have on the DD&A rate used by us in the fourth quarter of 2004. 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 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 43 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, as amended, was effective for us in the fourth quarter of 2003 as it applies to entities created after February 1, 2003. The adoption of FIN 46 with respect to these entities, primarily Eagle Energy Partnership I, L.P., did not have an impact on our financial position or results of operations or cash flows. For entities created prior to February 1, 2003, which are not special purpose entities, as defined in FIN 46, FIN 46 and the amendment of FIN 46 were effective for us, as amended, in the quarter ending March 31, 2004. We evaluated FIN 46 and FIN 46(R) with regard to these types of entities in which we have an ownership interest and there was no material impact to the financial position, results of operations or cash flows from the adoption of FIN 46 and FIN 46(R). 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 FASB in June 2001 and became effective for us on July 1, 2001 and January 1, 2002, respectively. We previously reported that an interpretation of FAS 141 and 142 was being considered as to whether mineral interest use rights in oil and natural gas properties are intangible assets and would be classified as such, separate from oil and natural gas properties. On September 2, 2004, the FASB issued FASB Staff Position 142-2 "Application of FASB Statement No. 142, Goodwill and Other Intangible Assets, to Oil- and Gas-Producing Entities" (FSP 142-2) to address the application of FAS 142 to the oil and natural gas industry. In FSP 142-2 the FASB staff acknowledges that the accounting framework in Statement 19 for oil- and gas-producing entities is based on the level of established reserves - not whether an asset is tangible or intangible. Accordingly, the FASB staff believes that the scope exception in paragraph 8(b) of FAS 142 extends to its disclosure for drilling and mineral rights of oil- and gas-producing entities. FSP 142-2 confirms our historical treatment of these costs. 44 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 and value 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. 45 RESULTS OF OPERATIONS - --------------------- Third Quarter 2004 versus Third Quarter 2003 - -------------------------------------------- Provided below is a comparison of selected operating and financial data for the third quarter of 2004 versus the third quarter of 2003: Third Third Percent Quarter 2003 Quarter 2004 Change --------------- --------------- --------- Total Revenue $ 77,800,000 $ 143,350,000 84% Net Income $ 12,763,000 $ 24,647,000 93% Oil and Natural Gas: Revenue $ 27,402,000 $ 46,394,000 69% Operating costs $ 6,207,000 $ 9,746,000 57% Average natural gas price (Mcf) $ 4.50 $ 5.21 16% Average oil price (Bbl) $ 25.51 $ 34.46 35% Natural gas production (Mcf) 5,233,000 6,947,000 33% Oil production (Bbl) 134,000 274,000 104% Depreciation, depletion and amortization rate (Mcfe) $ 1.14 $ 1.43 25% Depreciation, depletion and amortization $ 6,972,000 $ 12,316,000 77% Drilling: Revenue $ 50,052,000 $ 80,887,000 62% Operating costs $ 35,653,000 $ 57,816,000 62% Percentage of revenue from daywork contracts 99% 100% Average number of rigs in use 68.2 92.0 35% Average dayrate on daywork Contracts $ 8,015 $ 9,103 14% Depreciation $ 6,318,000 $ 8,903,000 41% Gas Gathering and Processing: Revenues $ 148 $ 11,474 7,652% Operating costs $ 50 $ 10,480 20,860% Gas gathered - MMBtu/day 14,758 28,356 92% Gas processed - MMBtu/day -- 26,669 -- Depreciation $ 58 $ 451 678% General and Administrative Expense $ 2,246,000 $ 3,081,000 37% Interest Expense $ 154,000 $ 820,000 432% Average Interest Rate 2.26% 2.99% 32% Average Long-Term Debt Outstanding $ 16,763,000 $ 98,749,000 489% 46 Oil and natural gas revenues increased 69% due to increases in both oil and natural gas production and from increases in oil and natural gas prices between the third quarter of 2004 and the third quarter of 2003. PetroCorp Incorporated was acquired on January 30, 2004 and its production is included in our operating results subsequent to the acquisition date. Oil production was up 104% between the comparative quarters. Oil production from PetroCorp wells contributed 61% of the increase while the remaining wells owned by us contributed 43% of the increase. Natural gas production was up 33% between the comparative quarters. Natural gas production from PetroCorp wells contributed 13% of the increase while the remaining wells owned by us contributed 20% of the increase. The increase in production for both oil and natural gas over that contributed from the PetroCorp acquisition came from wells added through our development drilling program. We will continue to grow production primarily in natural gas through development drilling and acquisition of producing oil and natural gas properties when economical. Increases or decreases in future revenues, however are largely determined by the prices we receive for our natural gas production. Based on the Nymex futures prices for the fourth quarter of 2004 and the first quarter of 2005, we anticipate prices for natural gas to increase from prices received during the third quarter of 2004. Total operating cost increased 57% in the third quarter of 2004 when compared with the third quarter of 2003 due mainly from the acquisition of PetroCorp Incorporated and to a lesser extent from costs associated with the addition of new wells from our drilling program. PetroCorp Incorporated has historically experienced higher operating cost per equivalent barrel due to the types of wells under production and the reserve base being more concentrated toward oil. Operating cost from PetroCorp wells contributed to 35% of the increase while the remaining wells owned by us contributed 22% of the increase. We anticipate that there will continue to be upward pressure on the amount we pay for services associated with operating our wells throughout the coming year. Gross production taxes which are based on a percentage of revenues were also higher, since they are a percentage of total revenues received. Our total depreciation, depletion and amortization ("DD&A) increased 77% due to an increase in both the equivalent volumes produced and our DD&A rate per Mcfe. The increase in volumes produced increased total DD&A by 41% while the increase in the DD&A rate increased total DD&A by 36%. The acquisition of PetroCorp Incorporated was made at a higher cost per equivalent volumes than we have previously experienced through both our drilling program and from previous acquisitions. During 2003 and the first nine months of 2004, we also experienced higher cost per Mcfe for the discovery of new reserves through our development drilling program. Contract drilling revenues increased 62% between the comparative quarters due to increases in demand for our drilling rigs and increases in dayrates. Dayrates increased revenue by 15% with the remainder of the increase coming from increased utilization. Utilization increased by 23.8 rigs with 16.6 of the increase in rigs utilized coming from the 12 Service Drilling Company and 9 Sauer Drilling Company rigs acquired in December 2003 and July 2004, respectively. Natural gas prices remained between $4.00 and $5.50 through most of 2003 and continued at that level into the first nine months of 2004 causing an increase in demand for our rigs. Dayrates, which typically increase after the 47 increase in demand for rigs, also started increasing in the second quarter of 2003 and have continued to steadily increase throughout the first nine months of 2004. With the increase in demand and the rigs added through our acquisitions, total operating cost increased along with our revenues. We did not drill any turnkey or footage wells in the third quarter of 2004. Approximately 1% of our total drilling revenues in the third quarter of 2003 came from footage and turnkey contracts, which had profit margins lower than our daywork contracts. Dayrates for our contract drilling services are anticipated to increase over levels achieved in the third quarter of 2004 and utilization is anticipated to remain high through 2005 as long as commodity prices remain at the levels achieved in 2004. Contract drilling depreciation increased 41% due to the acquisition of 12 rigs in the fourth quarter of 2003 and 9 rigs in the third quarter of 2004 and increased rig utilization from rigs previously owned. On July 29, 2004, we completed the acquisition of the 60% of Superior Pipeline Company LLC ("Superior") we did not already own for $19.8 million. Superior is a mid-stream company engaged primarily in the gathering, processing and treating of natural gas and owns one natural gas treatment plant, two processing plants, 12 active gathering systems and 400 miles of pipeline. Superior operates in western Oklahoma and the Texas Panhandle and has been in business since 1996. This acquisition will increase our ability to gather and market our (as well as third party's) natural gas and construct or acquire existing natural gas gathering and processing facilities. The results of operations for this acquired company are included in the statement of income for the period after July 31, 2004. Gas gathering and processing revenues increased by $11.3 million and gas gathering and processing operating costs increased by $10.4 million between the comparative quarters as a result of the acquisition. General and administrative expense increased 37% in the third quarter of 2004 due primarily to increases in employee cost of $362,000, outside audit related costs and other third party costs primarily associated with compliance of the Sarbanes-Oxley Act of approximately $170,000, and general corporate cost of $160,000. Increases in general and administrative expenses are anticipated in the remainder of 2004 and into 2005. Our total interest expense was higher due to the additional debt incurred from the PetroCorp Incorporated, Superior Pipeline Company and Sauer Drilling Company acquisitions. In the absence of further acquisitions, we intend to pay down this debt in 2005 through cash flow from our operating activity. Income tax expense increased primarily due to the increase in income before income taxes. Current income tax expense increased in the third quarter of 2004 due to an increase in the provision for alternative minimum tax which was based on higher estimates of total taxable income for the year. On August 2, 2004, the company completed the sale of its investment in Eagle Energy Partners I, L.P. for $6.2 million. In the third quarter of 2004, a gain before income taxes of $3.8 million was recognized in other revenues from this sale. 48 First Nine Months 2004 versus First Nine Months 2003 - ---------------------------------------------------- Provided below is a comparison of selected operating and financial data for the first nine months of 2004 versus the first nine months of 2003: First Nine First Nine Percent Months 2003 Months 2004 Change --------------- --------------- --------- Total Revenue $ 218,758,000 $ 358,988,000 64% Income Before Change in Accounting Principle $ 37,113,000 $ 60,341,000 63% Net Income $ 38,438,000 $ 60,341,000 57% Oil and Natural Gas: Revenue $ 87,521,000 $ 130,718,000 49% Operating costs $ 18,655,000 $ 29,871,000 60% Average natural gas price (Mcf) $ 5.05 $ 5.23 4% Average oil price (Bbl) $ 27.02 $ 32.17 19% Natural gas production (Mcf) 15,043,000 19,855,000 32% Oil production (Bbl) 372,000 767,000 106% Depreciation, depletion and amortization rate (Mcfe) $ 1.12 $ 1.38 23% Depreciation, depletion and amortization $ 19,464,000 $ 34,028,000 75% Drilling: Revenue $ 129,839,000 $ 211,211,000 63% Operating costs $ 97,105,000 $ 152,736,000 57% Percentage of revenue from daywork contracts 97% 100% Average number of rigs in use 60.6 85.8 42% Average dayrate on daywork contracts $ 7,684 $ 8,722 14% Depreciation $ 17,111,000 $ 24,121,000 41% Gas Gathering and Processing: Revenue $ 566 $ 11,562 1,943% Operating costs $ 307 $ 10,515 3,325% Gas gathered - MMBtu/day 11,200 26,090 133% Gas processed - MMBtu/day -- 26,669 -- Depreciation $ 125 $ 489 291% General and Administrative Expense $ 6,766,000 $ 8,955,000 32% Interest Expense $ 540,000 $ 1,751,000 224% Average Interest Rate 2.16% 2.54% 18% Average Long-Term Debt Outstanding $ 23,727,000 $ 76,740,000 223% 49 Oil and natural gas revenues increased 49% due to increases in both oil and natural gas production and to a lesser extent from an increase in oil and natural gas prices between the first nine months of 2004 and the first nine months of 2003. PetroCorp Incorporated was acquired on January 30, 2004 and its production is included in our operating results subsequent to the acquisition date. Oil production was up 106% compared to the first nine months of 2003. Oil production from PetroCorp wells contributed 64% of the increase while the remaining wells owned by us contributed 42% of the increase. Natural gas production was up 32% compared to the first nine months of 2003. Natural gas production from PetroCorp wells contributed 18% of the increase while the remaining wells owned by us contributed 14% of the increase. The increase in production for both oil and natural gas over that contributed from the PetroCorp acquisition came from wells added through our development drilling program. We will continue to grow production primarily in natural gas through development drilling and acquisition of producing oil and natural gas properties when economical. Increases or decreases in future revenues, however are largely determined by the prices we receive for our natural gas production. Based on the Nymex futures prices for the fourth quarter of 2004 and the first quarter of 2005, we anticipate prices for natural gas to increase from prices received during the first nine months of 2004. Total operating cost increased 60% in the first nine months of 2004 when compared with the first nine months of 2003 due mainly from the acquisition of PetroCorp Incorporated and to a lesser extent from costs associated with the addition of new wells from our drilling program. PetroCorp Incorporated has historically experienced higher operating cost per equivalent barrel due to the types of wells under production and the reserve base being more concentrated toward oil. Operating cost from PetroCorp wells contributed to 35% of the increase while the remaining wells owned by us contributed 25% of the increase. We anticipate that there will continue to be upward pressure on the amount we pay for services associated with operating our wells throughout the coming year. Gross production taxes which are based on a percentage of revenues were also higher. Our total depreciation, depletion and amortization ("DD&A) increased 75% due to the increase in equivalent volumes produced and an increase in our DD&A rate per Mcfe. The increase in volumes produced increased total DD&A by 42% while the increase in the DD&A rate increased total DD&A by 33%.The acquisition of PetroCorp Incorporated was made at a higher cost per equivalent volumes than we have previously experienced through both our drilling program and from other acquisitions on average. During 2003 and the first nine months of 2004, we also experienced higher cost per Mcfe for the discovery of new reserves through our development drilling. Contract drilling revenues increased 63% due to increases in demand for our drilling rigs and increases in dayrates. Dayrates increased revenue by 16% with the remainder of the increase coming from increased utilization. Utilization increased by 25.2 rigs with 13.2 of the increase in rigs utilized coming from the 12 Service Drilling Company and 9 Sauer Drilling Company rigs acquired in December 2003 and July 2004, respectively. Natural gas prices remained between $4.00 and $5.50 through most of 2003 and continued at that level into the first nine months of 2004 causing an increase in demand for our rigs. Dayrates, which 50 typically increase after the increase in demand for rigs, also started increasing in the second quarter of 2003 and have continued to steadily increase throughout the first nine months of 2004. With the increase in demand and the rigs added through our acquisitions total operating cost increased along with our revenues. We did not drill any turnkey or footage wells in the first nine months of 2004. Approximately 3% of our total drilling revenues in the first nine months of 2003 came from footage and turnkey contracts, which had profit margins lower than our daywork contracts. Dayrates for our contract drilling services are anticipated to increase over the 2004 year-to-date levels and utilization is anticipated to remain high through 2005 as long as commodity prices remain at the levels achieved in 2004. Contract drilling depreciation increased due to the utilization associated with the 12 rigs acquired in the fourth quarter of 2003 and the 9 rigs acquired in the third quarter of 2004 and increases in utilization from the remainder of our rigs. On July 29, 2004, we completed the acquisition of the 60% of Superior Pipeline Company LLC ("Superior") we did not own for $19.8 million. Superior is a mid-stream company engaged primarily in the gathering, processing and treating of natural gas and owns one natural gas treatment plant, two processing plants, 12 active gathering systems and 400 miles of pipeline. Superior operates in western Oklahoma and the Texas Panhandle and has been in business since 1996. This acquisition will increase our ability to gather and market our (as well as third party's) natural gas and construct or acquire existing natural gas gathering and processing facilities. The results of operations for this acquired company are included in the statement of income for the period after to July 31, 2004. Gas gathering and processing revenues increased by $11.0 million and operating costs by $10.2 million in the comparative nine month periods as a result of this acquisition. General and administrative expense increased 32% in the nine months of 2004 primarily due to increases in employee cost of $1.2 million, outside audit related costs and other third party costs primarily associated with compliance of the Sarbanes-Oxley Act of approximately $365,000, insurance cost of $238,000 and general corporate cost of $165,000. Increases in general and administrative expenses are anticipated in the remainder of 2004 and into 2005. Our total interest expense was higher due to the additional debt incurred from the PetroCorp Incorporated, Superior Pipeline and Sauer Drilling Company acquisitions. In the absence of further acquisitions, we intend to pay down this debt in 2005 through cash flow from our operating activity. Income tax expense increased primarily due to the increase in income before income taxes. Current income tax expense increased in the first nine months of 2004 due to an increase in the provision for alternative minimum tax which was based on higher estimates of total taxable income for the year. Net income in the first nine months of 2003 includes $1.3 million of income due to a change in accounting principle for the implementation of Financial Accounting Standards No. 143, "Accounting for Asset Retirement Obligations" (FAS 143). 51 On August 2, 2004, the company completed the sale of its investment in Eagle Energy Partners I, L.P. for $6.2 million. In the third quarter of 2004, a gain before income taxes of $3.8 million was recognized in other revenues from this sale. Item 3. Quantitative and Qualitative Disclosures about Market Risk - ------- ---------------------------------------------------------- Our operations are exposed to market risks primarily as a result of changes in commodity prices and interest rates. We do not use derivative financial instruments for speculative or trading purposes. Commodity Price Risk We produce, purchase, gather, process and sell crude oil, natural gas, condensate and natural gas liquids. As a result, our financial results can be significantly impacted as these commodity prices fluctuate widely in response to changing market forces. Relatively modest changes in gas prices significantly impact our results of operations and cash flows. In an effort to try and reduce the impact of price fluctuations, over the past several years we periodically have used hedging strategies to hedge the prices 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. Interest Rate Risk Our interest rate risk exposure results primarily from short-term rates, mainly LIBOR-based, on borrowings from our banks. At September 30, 2004, our total bank debt was $107.5 million, of which $103.0 million was at LIBOR-based rates. In the past, we have not entered into financial instruments such as interest rate swaps or interest rate lock agreements. Based on our current debt level at September 30, 2004, a one percent change in the interest rate we pay will have a $89,600 per month ($1,075,000 annualized) change in our pre-tax operating cash flow. Item 4. Controls and Procedures - -------------------------------- We maintain a set of disclosure controls and procedures that are designed to provide reasonable assurance that information required to be disclosed in our reports filed under the Securities and Exchange Act of 1934, as amended, is recorded, processed, summarized, and reported within the time periods specified in the U.S. Securities and Exchange Commission's rules and forms. 52 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 under Exchange Act Rule 13a-15. 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 has been no change in our internal control over financial reporting during the quarter ended September 30, 2004 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting. 53 PART II. OTHER INFORMATION Item 1. Legal Proceedings - -------------------------- Not applicable Item 2. Unregistered Sales of Equity 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 - -------------------------- Not applicable Item 6. Exhibits - ----------------- Exhibits: 15 Letter re: Unaudited Interim Financial Information. 31.1 Certification of Chief Executive Officer under Rule 13a - 14(a) of the Exchange Act. 31.2 Certification of Chief Financial Officer under Rule 13a - 14(a) of the Exchange Act. 32 Certification of Chief Executive Officer and Chief Financial Officer under Rule 13a - 14(a) of the Exchange Act and 18 U.S.C. Section 1350, as adopted under Section 906 of the Sarbanes-Oxley Act of 2002. 99.1 Form of Stock Option Agreement used under the Unit Corporation 2000 Non-Employee Directors' Stock Option Agreement. 99.2 Form of ISO Agreement used under the Employee Stock Option Plan. 54 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 9, 2004 By: /s/ John G. Nikkel --------------------------- ------------------------------ JOHN G. NIKKEL Chief Executive Officer, and Director Date: November 9, 2004 By: /s/ David T. Merrill --------------------------- ------------------------------ DAVID T. MERRILL Chief Financial Officer and Treasurer 55
Exhibit 15 ---------- November 8, 2004 Securities and Exchange Commission 450 Fifth Street, N.W. Washington, D.C. 20549 Commissioners: We are aware that our report dated November 5, 2004 on our review of interim financial information of Unit Corporation for the three and nine month periods ended September 30, 2003 and 2004 and included in the Company's quarterly report on Form 10-Q for the quarter ended September 30, 2004 is incorporated by reference in its registration statements on Form S-8 (File No.'s 33-19652, 33-44103, 33-49724, 33-64323, 33-53542, 333-38166 and 333-39584) and Form S-3 (File No.'s 333-83551 and 333-99979). Yours very truly, PricewaterhouseCoopers LLP
Exhibit 31.1 ------------ TRANSITIONAL FORM OF SECTION 302 CERTIFICATIONS FOR ACCELERATED FILER I, John G. Nikkel, certify that: 1. I have reviewed this quarterly report on form 10-Q of Unit Corporation; 2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report; 3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report; 4. The registrant's other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(c) for the registrant and have: (a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared; (b) Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and (c) Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and 5. The registrant's other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions): (a) All significant deficiencies and material weaknesses in the design oroperation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and (b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting. Date: November 9, 2004 ---------------- /s/ John G. Nikkel - ------------------ JOHN G. NIKKEL Chief Executive Officer and Director
Exhibit 31.2 ------------ TRANSITIONAL FORM OF SECTION 302 CERTIFICATIONS FOR ACCELERATED FILER I, David T. Merrill, certify that: 1. I have reviewed this quarterly report on form 10-Q of Unit Corporation; 2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report; 3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report; 4. The registrant's other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(c) for the registrant and have: (a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared; (b) Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and (c) Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and 5. The registrant's other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions): (a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and (b) Any fraud, whether or not material, that involves management or otheremployees who have a significant role in the registrant's internal control over financial reporting. Date: November 9, 2004 ---------------- /s/ David T. Merrill - -------------------- DAVID T. MERRILL Chief Financial Officer and Treasurer
Exhibit 32 ---------- CERTIFICATION PURSUANT TO SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002 (SUBSECTIONS (A) AND (B) OF SECTION 1350, CHAPTER 63 OF TITLE 18, UNITED STATES CODE) Pursuant to section 906 of the Sarbanes-Oxley Act of 2002 (subsections (a) and (b) of section 1350, chapter 63 of title 18, United States Code), each of the undersigned officers of Unit Corporation a Delaware corporation (the "Company"), does hereby certify, to such officer's knowledge, that: The Quarterly Report on Form 10-Q for the quarter ended September 30, 2004 (the "Form 10-Q") of the Company fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934 and information contained in the Form 10-Q fairly presents, in all material respects, the financial condition and results of operations of the Company as of September 30, 2004 and December 31, 2003 and for three and nine month periods ended September 30, 2004 and 2003. Dated: November 9, 2004 By: /s/ John G. Nikkel - ----------------------- John G. Nikkel Chief Executive Officer Dated: November 9, 2004 By: /s/ David T. Merrill - -------------------------- David T. Merrill Chief Financial Officer and Treasurer The foregoing certification is being furnished solely pursuant to section 906 of the Sarbanes-Oxley Act of 2002 (subsections (a) and (b) of section 1350, chapter 63 of title 18, United States Code) and is not being filed as part of the Form 10-Q or as a separate disclosure document. A signed original of this written statement required by Section 906 of the Sarbanes-Oxley Act of 2002 has been provided to Unit Corporation and will be retained by Unit Corporation and furnished to the Securities and Exchange Commission or its staff on request.
UNIT CORPORATION 2000 NON-EMPLOYEE DIRECTORS' STOCK OPTION AGREEMENT THIS AGREEMENT, made as of this _____ day of _______________, 20___, by and between UNIT CORPORATION, a Delaware corporation, (the "Company"), having a place of business at 7130 South Lewis, Suite 1000, Tulsa, Oklahoma, 74136, AND ______________________, a non-employee director of the Company the ("Optionee"); WITNESSETH: WHEREAS, Optionee is a director of the Company and the Company desires to provide Optionee with incentives to continue to serve as a member of the Board of Directors of the Company, and to devote his best efforts to the long-term success of the Company. WHEREAS, the Company has adopted the Unit Corporation 2000 Non-Employee Directors' Stock Option Plan (the "Plan") in order to provide its non-employee directors with such incentives by establishing procedures under which each of the Company's non-employee directors is to be granted stock options to purchase shares of the Company's common stock ($0.20 par value per share) (the "Common Stock"); WHEREAS, Optionee is entitled to receive an option to purchase __________ shares of the Company's Common Stock pursuant to the terms of the Plan; and, WHEREAS, the Company and Optionee desire to set forth the terms and conditions of Optionee's Option. NOW, THEREFORE, in consideration of the covenants and agreements herein contained, and intending to be legally bound thereby, the parties hereto agree as follows: 1. Stock Option. Subject to the terms and conditions set forth herein and to the terms of the Plan, the Company hereby grants to Optionee the right and option to purchase from the Company up to, but not exceeding in the aggregate, __________ shares of the Common Stock (the "Option"), at the option price per share described in the succeeding paragraph and at the times described in Section 2 of this Agreement. The option price per share under this Agreement shall be $__________ per share, this being the fair market value of shares of Common Stock on the date of this Agreement. Upon exercise of the Option, in whole or in part, the option price, multiplied by the number of shares with respect to which Options are being exercised, shall be payable in accordance with Section 3.2. Time of Exercise of Options. The Option granted hereunder shall not be exercisable during the first six months hereof except in case of death as provided in Section 4(E) of the Plan. After such time the Option shall become exercisable to the extent set forth in the Plan. If the Option is exercised in part, the unexercised portion of the Option shall continue to be held by the Optionee and may thereafter be exercised as provided herein. The Option granted herein shall, if not previously exercised, terminate on the tenth anniversary of the date hereof, and shall not be exercisable at any time after such date. 3. Manner of Exercise. The Option shall be exercised by Optionee delivering to the Compensation Committee of the Company's Board of Directors a written notification specifying the number of shares of Common Stock which Optionee desires to purchase by exercise of the Option, together with a check payable to the order of the Company equal in value to the option price of the shares to be purchased. At the election of Optionee, the option price, in whole or in part, may be paid by surrendering to the Company stock certificates representing a whole number of Common Stock of the Company, together with a stock power executed in blank, having a fair market value on the date of exercise of the Option, determined as provided in Section 4(G) of the Plan, equal to the option price for the shares being purchased; except that (i) any portion of the option price representing a fraction of a share shall in any event be paid in cash; and, (ii) no shares of Common Stock which have been held for less than six months may be delivered in payment of the option price of the Option. Upon receipt of such payment, and upon the Company's receipt of payment of any taxes pursuant to the notice described in Section 4 below, the Company shall deliver to Optionee (or the person entitled to exercise the Option) a stock certificate or certificates representing the shares of Common Stock purchased by Optionee. 4. Withholding Taxes. The Company shall have the right to require Optionee to remit to the Company an amount sufficient to satisfy any federal, state and local withholding tax requirement prior to the delivery of any shares of Common Stock acquired by the exercise of the Option granted hereunder. In each case of the exercise of the Option, the Company will notify Optionee of the amount of the withholding tax, if any, which must be paid under federal and, where applicable, state and local law. Upon receipt of such notice, Optionee shall promptly remit to the Company the amount specified in such notice. 5. Termination of Option. If Optionee ceases to be a director of the Company, any outstanding stock option held by Optionee hereunder shall be exercisable and/or shall terminate, according to the following provisions: (a) If Optionee ceases to be a director of the Company for any reason other than resignation, removal for cause, or death, any part of the Option then outstanding shall be exercisable by Optionee (but only to the extent exercisable 2 by Optionee immediately prior to ceasing to be a director) at any time prior to the regular expiration date of the Option or within one year after the date Optionee ceases to be a director, whichever is the longer period; (b) If during his or her term of office as a director Optionee resigns from the Board or is removed from office for cause, that part of the Option held by Optionee which is not exercisable immediately prior to Optionee's resignation or removal shall terminate as of the date of such resignation or removal, and that part of the Option held by Optionee which is exercisable by Optionee immediately prior to resignation or removal shall be exercisable by Optionee at any time prior to the regular expiration date of the Option or within 90 days after the date of resignation or removal, whichever is the longer period; (c) Following the death of Optionee during service as a director of the Company, that part of the Option held by Optionee at the time of death (whether or not exercisable by Optionee immediately prior to death) shall be exercisable by the person entitled to do so under the Will of Optionee, or, if Optionee shall fail to make testamentary disposition of the Option or shall die intestate, by the legal representative of Optionee at any time prior to the regular expiration date of such Option or within two years after the date of death, whichever is the longer period; (d) Following the death of Optionee after ceasing to be a director and during a period when the Option is exercisable, that part of the Option then outstanding at the time of death shall be exercisable by such person entitled to do so under the Will of Optionee or by such legal representative at any time prior to the expiration date of such Option or within one year after the date of death, whichever is the shorter period. 6. Nonassignability. This Option shall not be assignable or transferable by Optionee except by the laws of descent and distribution. During the lifetime of Optionee, the Option shall be exercisable only by Optionee, and no other person shall acquire any rights therein. 7. Miscellaneous. (a) If a dividend or other distribution shall be declared upon the Common Stock payable in shares of the Common Stock the number of shares of the Common Stock set forth in Section 1 shall be adjusted by adding thereto the number of shares of the Common Stock which would have been distributable thereon if such shares had been outstanding on the date fixed for determining the stockholders entitled to receive such stock dividend or distribution. If the outstanding shares of the Common Stock shall be changed into or exchangeable for a different number or kind of shares of stock, other securities or other property of the Company or another corporation, whether through reorganization, reclassification, recapitalization, stock split-up, combination of shares, merger or consolidation, then there shall be substituted for each share of the Common Stock set forth in Section 1 the number and kind of shares of stock or other securities into which each outstanding share of the Common Stock shall be so changed or for which each such share shall be exchangeable. 3 In case of any adjustment or substitution as provided for in this Section 7, the aggregate option price for all shares subject to any outstanding Option prior to such adjustments or substitution shall be the aggregate option price for all shares of stock or other securities (including any fraction) to which such shares shall have been adjusted or which shall have been substituted for such shares. Any new option price per share shall be carried to at least three decimal places with the last decimal place rounded upwards to the nearest whole number. No adjustment or substitution provided for in this Section 7 shall require the Company to issue or deliver or sell a fraction of a share or other security. Accordingly, all fractional shares or other securities which result from any such adjustment or substitution shall be eliminated and not carried forward to any subsequent adjustment or substitution. The grant of the Option provided for herein shall not affect in any way the right or power of the Company to make adjustments, reclassifications, reorganizations or changes of its capital or business structure or to merge or to consolidate or to dissolve, liquidate or sell, or transfer all or any part of its business or assets. (b) Neither Optionee nor a transferee of the Option shall have any rights as a stockholder with respect to any shares covered by the Option until the date of the exercise of the Option and the receipt of payment (including any amounts which may be required by the Company pursuant to Section 4) by the Company. No adjustments shall be made in respect of the Option for dividends (ordinary or extraordinary, whether in cash, securities or other property) or distributions or other rights for which the record date is prior to such date, except as provided in Subsection (a) of Section 7 hereof. (c) The Plan shall be administered by the Compensation Committee appointed by the Board of Directors, which shall have the power to construe the Plan, to determine all questions arising thereunder, to adopt and amend such rules and regulations for the administration of the Plan as it may deem desirable, and to otherwise carry out the terms of the Plan. The interpretation and construction by the Committee of any provisions of the Plan or of any option granted under it shall be final. This Agreement is subject to amendment as set forth in the Plan. (d) If the Company shall determine, in its discretion, that the listing, registration or qualification of the shares subject to the Option upon any securities exchange or under any state or federal law, or the consent or approval of any government regulatory body, is necessary or desirable as a condition of, or in connection with, the granting of the Option or the issuance, if any, of the Common Stock or purchase of shares in connection therewith, the Option granted herein may not be exercised unless such listing, registration, qualification, consent or approval shall have been effected or obtained, free of conditions not acceptable to the Company. (e) The Option granted hereunder is not an Incentive Stock Option entitled to favorable tax treatment under Section 422A of the Internal Revenue Code. 4 (f) Nothing in the Plan, this Agreement or the Option shall confer any right to Optionee to continue as a director of the Company or interfere in any way with the rights of the stockholders of the Company or the Board of Directors to elect and/or remove directors. (g) Optionee represents that he/she accepts the Option, and any stock received pursuant to exercise of the Option for his/her own account for investment and not with a view to, or for resale in connection with any distribution by him/her. Optionee further represents that he/she will not resell or otherwise dispose of any shares of the Common Stock received pursuant to exercise of the Option except in accordance with the provisions of the Securities Act of 1933, as amended, and all of the Federal and State laws applicable to such resale or other disposition. (h) Optionee agrees that the Plan (a copy of which is attached hereto) is the controlling instrument and to the extent that there is any conflict between the terms of the Plan and this Agreement, the Plan shall control and be the governing document. WITNESS the due execution hereof. UNIT CORPORATION By:__________________________________ ____________________, President OPTIONEE ______________________________________ ______________________, Optionee 5
UNIT CORPORATION GRANT OF INCENTIVE STOCK OPTION Date of Grant: ____________________, 20___ This Grant, dated as of the date of grant first stated above (the "Date of Grant") is delivered by UNIT CORPORATION, a Delaware corporation (hereinafter called "Corporation") (to the extent necessary the term Corporation shall also be deemed to include all wholly owned subsidiaries of Unit Corporation), to ____________________, who is an employee of Corporation (hereinafter called "Optionee"); W I T N E S S E T H : WHEREAS, Corporation desires to afford the Optionee an option to purchase shares of its Common Stock, par value $00.20 per share, (hereinafter called "Common Stock"), as hereinafter provided, in order to carry out the purposes of the Unit Corporation Amended and Restated Stock Option Plan, adopted by the Board of Directors of the Corporation on December 15, 1983, as last amended and restated effective February 15, 2000, as may subsequently be amended and/or restated (hereinafter called the "Plan"). NOW, THEREFORE, in consideration of the mutual agreements hereinafter set forth, the parties hereby agree as follows: 1. Grant of Option. Subject to the terms and conditions hereinafter set forth, the Corporation hereby grants to the Optionee, as of the Date of Grant, an option to purchase up to __________ shares of Common Stock at a price of $__________ per share, the fair market value. Such option is hereinafter referred to as the "Option" and the shares of Common Stock purchasable upon exercise of the Option are hereinafter sometimes referred to as the "Option Shares." The Option is intended by the parties hereto to be, and shall be treated as, an incentive stock option (as such term is defined under section 422 of the Internal Revenue Code of 1986). 2. Time of Exercise of Option. During the period ending twelve months after the grant of this Option, it may not be exercised as to any of the Option Shares; during the period beginning twelve months after the grant of this Option and ending twenty-four months after the grant of this Option, it may be exercised as to an aggregate number of shares which is not more than 20% of the total number of Option Shares; during the period beginning twenty-four months after the grant of this Option and ending thirty-six months after the grant of this Option, it may be exercised as to an aggregate number of shares which is not more than 40% of the total number of Option Shares; and during the period beginning thirty-six months after the grant of this Option and ending forty-eight months after the grant of this Option, it may be exercised as to an aggregate number of shares which is not more than 60% of the total number of Option Shares; during the period beginning forty-eight months after the grant of this Option and ending sixty months after the grant of this Option, it may be exercised as to an aggregate number of shares which is not more that 80% of the total number of Option Shares; and, during the period beginning sixty months after the grant of this Option and ending with the expiration or termination of this Option, it may be exercised as to an aggregate number of shares which is equal to the total number of Option Shares.3. Method of Exercise and Payment. (a) Subject to all of the provisions hereof the Option may be exercised by the Optionee delivering to the Compensation Committee of the Board of Directors (the "Committee") on any business day a written notice specifying the number of Option Shares the Optionee then desires to purchase. The option price for the Option Shares to be purchased shall be payable (i) in cash upon the exercise of the Option by cash or by check, (ii) by delivery to the Corporation of shares of Common Stock, or (iii) any combination of (i) and (ii). If any portion of the purchase price is paid by delivery to the Corporation of shares of its Common Stock, the aggregate fair market value of such shares shall be credited against the purchase price. (b) As soon as is practicable after the exercise date specified in the Optionee's notice, the Corporation shall cause to be delivered to the Optionee, a certificate or certificates for the Option Shares then being purchased (out of theretofore unissued Common Stock or reacquired Common Stock, as the Corporation may elect) upon full payment for such Option Shares. The obligation of the Corporation to deliver Common Stock shall, however, be subject to the condition that if at any time the Committee shall determine in its discretion that the listing, registration or qualification of the Option or the Option Shares upon any securities exchange or under any state or federal law, or the consent or approval of any governmental regulatory body, is necessary or desirable as a condition of, or in connection with, the Option or the issuance or purchase of Common Stock thereunder, the Option may not be exercised in whole or in part unless such listing, registration, qualification, consent or approval shall have been effected or obtained free of any conditions not acceptable to the Committee. If the Optionee fails to pay for any of the Option Shares specified in such notice or fails to accept delivery thereof, the Optionee's right to purchase such Option Shares may be terminated by the Corporation. The date specified in the Optionee's notice as the date of exercise shall be deemed the date of exercise of the Option, provided that payment in full for the Option Shares to be purchased upon such exercise shall have been received by such date. 5. General Restrictions. Except as limited by Section 6 below and subject to the express restrictions of Section 2 above, the Option may be exercised at any time, and from time to time, in whole or in part, until the termination thereof as set below in Section 13, or until all Option Shares covered by the Option shall have been purchased, whichever first occurs. During the lifetime of the Optionee, the Option shall be exercisable only by him or her and, except as provided in Section 6 hereof, shall not be assignable or transferable by him or her and no other person shall acquire any rights therein. 6. Death and Termination of Employment. In the event of the death of the Optionee while in the employ of the Corporation or any of its Subsidiaries, the Option, to the extent not theretofore exercised, and as hereinafter limited, may be exercised in full or in part by the estate of the Optionee, or by a person who acquired the right to exercise such Option by bequest or inheritance from such Optionee at any time, or from time to time, within (and in no event after) six months after the date of the Optionee's death, but not later than the date on which the Option would otherwise expire; provided, however, that the Option may be exercised as to no more than the aggregate number of Option Shares which could have been purchased by the deceased Optionee by exercise of this Option on the date of his or her death. 2 If the employment of the Optionee is terminated by reason of disability (within the meaning of Section 22 (e)(3) of the Internal Revenue Code of 1986, the Option, to the extent not theretofore exercised, and as hereinafter limited, may be exercised in full or in part at any time or from time to time, within (and in no event after) three months after the effective date of such termination, but not later than the date on which the Option would otherwise expire; provided, however, that the Option may be exercised as to no more than the aggregate number of Option Shares which could have been purchased by the disabled Optionee by exercise of this Option on the effective date of the termination of his or her employment. If the employment of the Optionee is terminated for any reason other than death or disability as above provided, the Option held by such Optionee, to the extent not theretofore exercised and as hereinafter limited, may be exercised in full or in part at any time or from time to time within (and in no event after) 30 days after the effective date of such termination, but not later than the date on which the Option would otherwise expire; provided, however, that the Option may be exercised as to no more than the aggregate number of Option Shares which could have been purchased by the Optionee by exercise of this Option on the effective date of the termination of his or her employment. If the Optionee's employment is terminated by retirement in accordance with any normal retirement policies of the Corporation, if any, as determined by the Committee, or if the Optionee's employment is otherwise terminated and the Committee determines it would be desirable to allow exercise of the Option following termination, the Option, to the extent not theretofore exercised and as hereinafter limited, may be exercised in whole or in part, at any time or from time to time, within and in no event after a period of three months after the effective date of such termination of employment, but not later than the date on which the Option would otherwise expire; provided, however, that the Option may be exercised as to no more than the aggregate number of Option Shares which could have been purchased by the Optionee on the effective date of such termination of employment. The employment of the Optionee shall not be deemed to have terminated if the Optionee is an employee of the Corporation who is absent upon a bona fide leave of absence (including absence for military or governmental service in which the employee's reemployment rights are guaranteed and to the extent such rights are guaranteed) or who is transferred to and becomes an employee of a subsidiary or a parent corporation of the Corporation, or a parent or subsidiary corporation of such corporation issuing or assuming the stock option or a transaction to which Section 424 of the Internal Revenue Code of 1986 applies. Whether a corporation is a "parent or subsidiary corporation" with respect to another corporation shall be determined under Section 424 of the Internal Revenue Code of 1986. 7. Reorganization, Liquidation or Change in Control. If the Corporation is reorganized or consolidated or merged with or acquired by another corporation, the Optionee shall be entitled to receive options covering shares of such reorganized, consolidated, merged or acquired company in the same proportion, at an equivalent price, and subject to the same conditions set forth herein. For purposes of the preceding sentence, the excess of the aggregate fair market value of the shares subject to the Option immediately after the reorganization, consolidation, merger or acquisition over the aggregate option price of such shares shall not be more than the excess of the aggregate fair market value of all shares subject to the Option immediately before such reorganization, consolidation, merger or acquisition over the aggregate option price of such shares, and the new option or assumption of the old option shall not give the Optionee additional benefits which he or she did not have under the old option, or deprive him or her of benefits which he or she had under the old option. 3 In the event of any (i) dissolution or liquidation of the Corporation, (ii) reorganization, merger, consolidation or acquisition involving the Corporation which results in a "change in control" (as hereinafter defined) or (iii) sale or disposition of substantially all of the assets of the Corporation to an entity other than a wholly owned subsidiary of the Corporation, the Corporation shall give the Optionee written notice that such dissolution, liquidation, reorganization, merger, consolidation, acquisition, sale or disposition is to occur at least sixty days prior to the effective date thereof and the Optionee shall have the right to exercise his or her Option in whole or in part at any time after the date of such notice and before the date on which the Option would otherwise expire, to the extent not theretofore exercised, without regard to any restrictions on exercise contained in Section 2 above. In the event of a "change in control" of the Corporation as hereinafter defined, the Optionee shall be permitted to exercise the option in full and without regard to any requirements as to installment exercise contained in Section 2 above at any time thereafter and prior to the expiration of this Option as set forth in Section 13 hereof. A "change in control" shall be deemed to have occurred when any "person" (as such term is used in Sections 3(a)(9) and 13(d) of the Securities Exchange Act of 1934, as amended, (the "Exchange Act") other than the Corporation or an Exempt Person (as hereinafter defined) is or becomes the beneficial owner (as defined in Rule 13d-3 under the Exchange Act), directly or indirectly, of securities of the Corporation representing 50% or more of the combined voting power of the Corporation's then outstanding securities. For these purposes the term "Exempt person" shall mean: (a) Any person who, on the date of this Agreement, owns beneficially securities of the Corporation representing more than 20% of the combined voting power of the Corporation's then outstanding securities, and any spouse, parent, or issue (either natural or adopted) of such person. (b) Any corporation or other business entity all of the outstanding securities or interests of which are beneficially owned (i) by all of the former beneficial shareholders of the Corporation, as the same shall have existed immediately prior to such transaction in the same proportions in which they beneficially owned securities of the Corporation immediately prior to such transaction, or (ii) by any one or more of the persons described in (a) above. (c) The estate of any person described in (a) above. (d) Any trust of which any person described in (a) above is considered to be the owner under the applicable rules of Subchapter J of the Code relating to grantors and others being treated as substantial owners. (e) Any trust with respect to which the aggregate actuarial value of the beneficial interests of persons described in (a) above exceeds 50% of the value of the trust property as determined under the applicable rules of Section 318(a)(3)(B)(i) of the Code. 4 8. Recapitalization. If the shares of Common Stock as a whole are increased, decreased or changed into, or exchanged for, a different number or kind of shares or securities of the Corporation, whether through merger, consolidation, reorganization, recapitalization, reclassification, stock dividend, stock split, combination of shares, exchange of shares, change in corporate structure or the like, an appropriate and proportionate adjustment may be made in the number, kinds, and per share exercise price of shares subject to any unexercised portion of the Option granted prior to any such change. Any such adjustment in the Option, however, shall be made without a change in the total price applicable to the unexercised portion of the Option, but with a corresponding adjustment in the price for each share of Common Stock covered by the Option. To the extent that the foregoing adjustments relate to stock or securities of the Corporation, such adjustments shall be made by the Committee, whose determination in that respect shall be final, binding and conclusive provided that the Option shall not be adjusted in a manner that causes the option to fail to continue to qualify as an incentive stock option within the meaning of Section 422 of the Internal Revenue Code of 1986. 9. Rights as a Stockholder. The Optionee, or a transferee of the Option, shall have no rights as a stockholder with respect to any Option Shares until the date of the issuance of a stock certificate to him or her for such Option Shares. No adjustment shall be made for dividends (ordinary or extraordinary, whether in cash, securities or other property) or distributions of other rights for which the record date is prior to the date such stock certificate is issued, except as provided in Section 8 hereof. 10. Purchase for Investment. Optionee represents that he or she accepts the Option granted herein, and any stock received pursuant to exercise of the Option for his or her own account for investment and not with a view to, or for resale in connection with any distribution by him or her. Optionee further represents that he or she will not resell or otherwise dispose of any Option Shares received pursuant to exercise of the Option except in accordance with the provisions of the Securities Act of 1933, as amended, and all of the Federal and State laws applicable to such resale or other disposition. 11. Plan Controlling Document. The Option is granted pursuant to the terms of the Plan, the terms of which are incorporated herein by reference, and the Option shall in all respects be interpreted in accordance with the Plan. The Committee shall interpret and construe the Plan and this instrument, and its interpretations and determinations shall be conclusive and binding on the parties hereto and any other person claiming an interest hereunder, with respect to any issue arising hereunder or thereunder. 12. Fair Market Value. For the purposes hereof, if the Corporation's Common Stock is traded upon an established stock exchange or exchanges, the fair market value of shares of Common Stock so delivered to the Corporation shall be determined to be the highest closing price of the Corporation's Common Stock on such stock exchange or exchanges on the day the shares are delivered to the Corporation by the Optionee; or if no sale of the Corporation's Common Stock shall have been made on any stock exchange on that day, on the next preceding day on which there was a sale of such stock; provided, however, that during such time as the Corporation's Common Stock is not listed upon an established stock exchange, the fair market value for such shares shall be the mean between dealer "bid" and "ask" prices of the Corporation's Common Stock in the New York 5 over-the-counter market, as reported by the National Association of Securities Dealers, on the day the shares are delivered to the Corporation. 13. Expiration of Option. Anything contained in this instrument to the contrary notwithstanding, the Option, to the extent not theretofore exercised, shall terminate and become null and void after the expiration of ten (10) years from the Date of Grant, or, if earlier, upon the first to occur of: (1) the expiration of the three months period beginning with the Optionee's death, as provided in Section 6; or (2) the expiration of the three months period beginning with the effective date of termination of the Optionee's employment by reason of disability, as provided in Section 6, or (3) the expiration of the 30 days period beginning with the effective date of the Optionee's termination of employment other than by reason of death or disability (as described in Section 6) or by reason of normal retirement, and if the expiration date has not otherwise been extended pursuant to Section 6; or (4) the expiration of the three months period beginning with the effective date of the Optionee's retirement in accordance with the Corporation's normal retirement practices or beginning with the effective date of the Optionee's termination of employment (but only if the Committee has elected to permit post-termination exercise), all as provided in Section 6. 14. Employment Not Affected. The granting of the Option nor its exercise shall not be construed as granting to the Optionee any right with respect to continuance of employment of the Corporation. Except as may otherwise be limited by a written agreement between the Corporation and the Optionee, the right of the Corporation to terminate at will the Optionee's employment with it at any time (whether by dismissal, discharge, retirement or otherwise) is specifically reserved by the Corporation, as the Corporation or on behalf of the Corporation (whichever the case may be), and acknowledged by the Optionee. 15. Amendment of Option. The Option may be amended by the Board of Directors of the Corporation or the Committee at any time (i) if the Board of Directors of the Corporation or the Committee determines, in its sole discretion, that amendment is necessary or advisable in the light of any addition to or change in the Internal Revenue Code of 1986 or in the regulations issued thereunder, or any federal or state securities law or other law or regulation, which change occurs after the Date of Grant and by its terms applies to the Option; or (ii) other than in the circumstances described in clause (i), with the consent of the Optionee. 16. Governing Law. The validity, construction, interpretation and effect of this instrument shall exclusively be governed by and determined in accordance with the law of the State of Oklahoma, except to the extent preempted by federal law, which shall to the extent govern. 6 IN WITNESS WHEREOF, the parties hereto have executed this Incentive Stock Option Agreement as of the day and year first above written. UNIT CORPORATION By: _________________________________ ____________________, President __________________________________ ____________________, Optionee 7 End of Filing