Annual Report (Form 10-K), fiscal year 1994

Item 1. Business . . . . . . . . . . . . . . . . . . . . . . . . . . . . .1 Item 2.



Item 2. Properties . . . . . . . . . . . . . . . . . . . . . . . . . . . .1 Item 3.

Item 3. Legal Proceeding - -------------------------
The Company is a party to a settlement agreement dated January 31, 1991 with a natural gas purchaser which superseded a settlement agreement entered into during March of 1988. Under the agreements the purchaser made certain prepayments to the Company for natural gas to be delivered to the purchaser in the future. As of December 31, 1994, this prepayment balance for natural gas yet to be delivered was $3.7 million. The Company has learned that the Oklahoma Tax Commission (the "Commission"), based on four assessments, one in 1988, one in 1992 and two in 1994, is seeking to hold the purchaser liable for certain taxes, interests and penalties that the Commission contends are due and owing with respect to the prepayment amounts made by the purchaser under the agreements on the grounds that the prepayments are solely attributable to the settlement of past claims for take-or-pay obligations. To date, the Company is not a party to the Commission's proceedings, but may in the future, seek to intervene in these proceedings. The purchaser has denied the claims made by the Commission and is contesting the assessments. The purchaser and the Commission have settled the 1988 assessment for approximately $51,000 and the remaining three assessments have been consolidated and set for a hearing before an administrative law judge on or before May 10, 1995. The purchaser has notified the Company of the proceedings and has indicated its intention to assert claims against the Company to recover the amount it paid in settlement of the 1988 assessment (including its attorney fees) as well as any amounts it might have to pay by virtue of the remaining assessments. The Company is aware that the purchaser has made such claims against other companies which also received prepayments from the purchaser, although the type of agreements and the facts involved in those cases are not known by the Company. At this time, the Company is unable to determine what the outcome of the remaining Commission's proceedings will be, the amount of taxes, if any, plus interest and penalties that may ultimately be assessed against the purchaser and the claims, if any, that the purchaser might seek to assert against the Company in the event an unfavorable result is incurred by the purchaser. The Company has advised the purchaser that it believes the responsibility for the payment of the taxes, interest and
penalty sought by the Commission, should it be ultimately determined that any such amounts are in fact owed, is the responsibility of the purchaser and not the Company.
The Company is a party to various legal proceedings arising in the ordinary course of its business none of which, in the Company's opinion, should result in judgments which would have a material adverse effect on the Company.
Item 4.

Item 4. Submission of Matters to a Vote of Security Holders - ------------------------------------------------------------
No matters were submitted to the security holders during the fourth quarter of the Company's calendar year ended December 31, 1994.
PART II
Item 5.

Item 5. Market for the Registrant's Common Equity and Related Stockholder - -------------------------------------------------------------------------- Matters - -------
As of February 21, 1995, the Company had 3,512 holders of record of its common stock. The Company has not paid any cash dividends on shares of its common stock since its organization and currently intends to continue its policy of retaining earnings, if any, from the Company's operations. The Company is prohibited, by certain loan agreement provisions, from declaring and paying dividends (other than stock dividends) during any fiscal year in excess of 25 percent of its consolidated net income of the preceding fiscal year. The table below reflects the high and low sales prices per share of the Company's common stock as reported by the New York Stock Exchange, Inc. for the period indicated:
1994 1993 QUARTER High Low High Low ------- ------ ------ ------ ------ First $3 1/2 $2 5/8 $3 1/4 $1 5/8 Second $3 1/4 $2 3/4 $4 3/8 $2 3/4 Third $3 1/2 $2 5/8 $4 3/4 $3 1/4 Fourth $3 7/8 $2 5/8 $4 3/4 $2 5/8
Item 6.

Item 6. Selected Financial Data - -------------------------------- Year Ended December 31, 1994 1993 1992 1991 1990 ------- ------- ------- ------- ------- (In thousands except per share amounts)
Revenues $87,958 $70,941 $55,827 $69,652 $61,904 ======= ======= ======= ======= ======= Income Before Income Taxes $ 4,814 $ 3,892 $ 1,102(1)$ 4,436 $ 830 ======= ======= ======= ======= ======= Net Income $ 4,794 $ 3,871 $ 1,087(1)$ 4,341 $ 830 ======= ======= ======= ======= ======= Net Income Per Common Share $.23 $.19 $.05(1) $.21 $.04 ==== ==== ==== ==== ==== Total Assets $112,421 $95,762 $88,710 $92,086 $86,286 ======== ======= ======= ======= ======= Long-Term Debt $ 37,824 $25,919 $22,298 $23,153 $19,929 ======== ======= ======= ======= ======= Long-Term Portion of Natural Gas Purchaser Prepayments $ 2,149 $ 4,417 $ 5,924 $ 7,626 $ 9,481 ======== ======= ======= ======= ======= Cash Dividends Per Common Share $ - $ - $ - $ - $ - ======== ======= ======= ======= ======= ___________
(1) Includes a $1.5 million provision for litigation
See Management's Discussion of Financial Condition and Results of Operations for a review of 1994, 1993 and 1992 activity.
Item 7.

Item 7. Management's Discussion and Analysis of Financial Condition and - ------------------------------------------------------------------------ Results of Operations - ---------------------
Financial Condition and Liquidity
On December 12, 1994, the Company amended its credit agreement (as amended the "Agreement"), in part to provide funds for the December 15, 1994 closing of a producing oil and natural gas property acquisition from two subsidiaries of Patrick Petroleum Company (collectively "Patrick"). The acquisition consisted of producing properties, located in Alabama, Louisiana, Mississippi, New Mexico, Oklahoma and Texas and related accounts receivable and certain related assumed liabilities for a net cost of $13.2 million. The Agreement provides for a total commitment of $50 million, consisting of a revolving credit facility through January 1, 1997 and a term loan thereafter, maturing on January 1, 2001. Borrowings under the
revolving credit facility are limited to a borrowing base which is subject to a semi-annual redetermination. The latest borrowing base determination indicated $42 million of the commitment is available to the Company. Certain covenants of the Agreement were also amended. The Company must maintain consolidated net worth of at least $45 million, a modified current ratio of not less than 1 to 1, a ratio of long-term debt, as defined in the Agreement, to consolidated tangible net worth not greater than 1 to 1 and a ratio of total liabilities, as defined in the Agreement, to consolidated tangible net worth not greater than 1.25 to 1. In addition, working capital provided by operations, as defined in the Agreement, cannot be less than $13 million in any year. At December 31, 1994, borrowings under the Agreement totalled $37.3 million. At February 21, 1995, borrowings under the Agreement totalled $37.0 million with $2.7 million available for future borrowings. The interest rate on the bank debt was 8.5 and 9 percent at December 31, 1994 and February 21, 1995, respectively. A commitment fee of 1/2 of 1 percent is charged for any unused portion of the borrowing base.
Shareholders' equity at December 31, 1994 was $52.6 million, making the Company's ratio of long-term debt-to-equity .72 to 1. The Company's primary source of liquidity and capital resources in the near- and long-term will consist of cash flow from operating activities and available borrowings under the Company's Agreement. Net cash provided by operating activities in 1994 was $13.2 million as compared to $9.9 million in 1993.
The Company's capital expenditures during 1994 were $27 million. The majority of the capital expenditures, $25.1 million, were made in the Company's oil and natural gas operations with $11.5 million and $13.1 million used for exploration and development drilling and producing property acquisitions, respectively. Capital expenditures made by the Company's contract drilling operations were approximately $1.1 million in 1994 and principally consisted of improvements to large rig components which benefit current and future years. The Company's rigs are composed of large components some of which, on a rotational basis, are required to be overhauled to assure proper performance. Such capital expenditures will continue in future years. Additional expenditures may be required in 1995 for drill pipe as certain grades of the Company's drill pipe are reaching the end of their useful life.
Late in December 1994, Unit agreed to acquire producing oil and natural gas properties for a purchase price of $2,125,000. This acquisition has an effective date of January 1, 1995 and includes ten natural gas wells located in Lipscomb County, Texas.
During the first half of 1995, the Company plans to pay down a portion of its long-term debt while continuing its developmental drilling on a limited basis. The Company's capital expenditures are discretionary and directed toward increasing reserves and future growth. Current operations should not be adversely affected by any inability to obtain funds outside of the Company's current loan agreement. The decision to acquire or drill on oil and natural gas properties at any given time depends on market conditions, potential return on investment, future drilling potential and the availability of opportunities to obtain financing given the circumstances involved, thus providing the Company with a large degree of
flexibility in incurring such costs. Depending, in part, on commodity pricing, the Company plans to spend approximately $16 million on its capital expenditure program in 1995.
The Company has 2.873 million warrants outstanding. The warrants entitle the holders to purchase one share of common stock at a price of $4.375 per share. The warrants, subject to certain restrictions, are callable by the Company, in whole or in part, at $.50 per warrant. A Second Amendment to the Warrant Agreement between the Company and the Warrant Agent, dated May 9, 1994, extended the term of the warrants to August 30, 1996.
The Company continued to receive monthly payments on behalf of itself and other parties (collectively the "Committed Interest") from a natural gas purchaser pursuant to a settlement agreement (the "Settlement Agreement"). As a result of the Settlement Agreement, the December 31, 1994 prepayment balance of $3.7 million paid by the purchaser for natural gas not taken (the "Prepayment Balance") is subject to recoupment in volumes of natural gas through a period ending on the earlier of recoupment or December 31, 1997 (the "Recoupment Period"). Additionally, the purchaser is obligated to make monthly payments on behalf of the Committed Interest based on their share of the natural gas deliverability of the wells subject to the Settlement Agreement, up to a maximum of $211,000 or a minimum of $110,000 per month for the year 1995. Both the maximum and minimum monthly payments decline annually through the Recoupment Period. If natural gas is taken during a month, the value of such natural gas is credited toward the monthly amount the purchaser is required to pay. In the event the purchaser takes volumes of natural gas valued in excess of its monthly payment obligations, the value taken in excess is applied to reduce any then outstanding Prepayment Balance. The Company currently believes that sufficient natural gas deliverability is available to enable the Committed Interest to receive substantially all of the maximum monthly payments during 1995. At the end of the Recoupment Period, the Settlement Agreement and the natural gas purchase contracts which are subject to the Settlement Agreement will terminate. If the Prepayment Balance is not fully recouped in natural gas by December 31, 1997 then the unrecouped portion is subject to cash repayment, limited to a maximum of $3 million, payable in equal annual installments over a five year period. Under the Settlement Agreement, the purchaser is entitled to make a monthly determination of the volumes to be purchased from the wells subject to the Settlement Agreement. During 1993, the Company, in accordance with the terms of the Settlement Agreement, elected to deliver natural gas at approximately 80 percent of the deliverability of the wells subject to the Settlement Agreement. During 1994 natural gas delivered was again reduced to approximately 75 percent of the deliverability of the wells subject to the Settlement Agreement. However, because these month-to-month determinations, up to certain maximum levels, are made by the purchaser, the Company is unable to predict with certainty future natural gas sales from these wells. In addition, future revenues to be received by the Company would be impacted by the failure of the purchaser to meet its obligations, financially or otherwise, under the terms of the Settlement Agreement or by the ability of the wells to maintain certain projected deliverability requirements. In the event the wells are unable to maintain such deliverability, the monthly
payments to be received by the Company under the Settlement Agreement would be decreased. The price per Mcf under the Settlement Agreement is substantially higher than current spot market prices. The impact of the higher price received under the Settlement Agreement increased pre-tax income by approximately $1.8, $1.9 and $2.8 million in 1994, 1993 and 1992, respectively.
Oil prices received by the Company in 1994 ranged from an average of $12.53 in February to $17.78 in July and averaged $15.73 in December. The Company's average price for oil received in 1994 was $15.13. Average natural gas prices received by the Company have gradually declined since the first quarter of 1994, and December's average price of $1.52 per Mcf was 32 percent less than the average natural gas price of $2.24 received by the Company in March 1994. Oil prices received early in the first quarter of 1995 were 3 percent higher than average prices received by the Company at December 31, 1994 while spot prices for natural gas dropped 17 percent from the December 31, 1994 price. Oil prices within the industry remain largely dependent upon world market developments for crude oil. Prices for natural gas are influenced by weather conditions and supply imbalances, particularly in the domestic market, and by world wide oil price levels. The large drop in spot market natural gas prices had a significant adverse effect on the value of the Company's reserves at year end 1994 and could cause the Company to reduce the carrying value of its oil and natural gas properties in 1995 (see Note 12 of Notes to Consolidated Financial Statements). Likewise, declines in natural gas or oil prices could adversely effect the semi-annual borrowing base determination under the Company's current credit agreement since this determination is, for the most part, calculated on the value of the Company's oil and natural gas reserves.
The Company's ability to utilize its full complement of drilling rigs, should economic conditions improve in the future, will be restricted due to the lack of qualified labor and certain supporting equipment not only within the Company but in the industry as a whole. The Company's ability to utilize its drilling rigs at any given time is dependent on a number of factors, including but not limited to, the price of both oil and natural gas, the availability of labor and the Company's ability to supply the type of equipment required. The Company's management expects that these factors will continue to influence the Company's rig utilization during 1995.
In the third quarter of 1994, the Company's Board of Directors authorized the Company to purchase up to 1,000,000 shares of the Company's outstanding common stock on the open market. At December 31, 1994 25,100 shares had been repurchased at prices ranging from $2 5/8 to $3 3/8 per share.
The Company's wholly owned natural gas marketing subsidiary, Mountain Front Pipeline Company, while achieving substantial growth in revenues in recent years, has not achieved the size necessary to reach desired levels of profitability. Consequently, the Company is currently negotiating to effect a business combination between Mountain Front Pipeline Company's marketing operations and a third party. The combination, if completed, would leave the Company with a minority interest in the resulting larger
entity. Such a combination would not adversely affect the operations of the Company's drilling and oil and natural gas exploration segments or the profitability of the Company as a whole, although it would result in a significant reduction in the Company's total revenues and associated costs.
Effects of Inflation
The effects of inflation on the Company's current operations have been minimal due to low inflation rates. However, the impact of inflation on the Company in the future will depend on the relative increase, if any, the Company may realize in its rig rates and the selling price of its oil and natural gas. If industry activity increases substantially, shortages in support equipment such as drill pipe, third party services and qualified labor would occur resulting in corresponding increases in material and labor costs. These market conditions may limit the Company's ability to realize improvements in operating profits.
Results of Operations
1994 versus 1993 - ----------------
Net income for 1994 was $4,794,000, compared with $3,871,000 in 1993. The increase in net income was achieved through improved operating results in the Company's contract drilling and natural gas marketing operations and also from a net gain of $742,000 recognized in conjunction with the sale of one of the Company's gas gathering systems. Total revenues were $87,958,000 in 1994 and $70,941,000 in 1993.
Oil and natural gas revenues increased 8 percent due to a 29 percent increase in natural gas production and a 2 percent increase in oil production between 1994 and 1993. Average natural gas and oil prices received by the Company both decreased 10 percent and partially offset the increases in production. Average natural gas prices received by the Company declined due to a 14 percent reduction in average spot market prices received by the Company coupled with a 14 percent reduction in volumes produced from certain wells included under a settlement agreement which contains provisions for prices which are higher than current spot market prices. Approximately 92 percent of the Company's natural gas production was sold under spot market prices in 1994 as compared with 88 percent in 1993.
In 1994, revenues from contract drilling operations increased by 16 percent as average rig utilization increased from 8 rigs in 1993 to 9.5 rigs in 1994. Daywork revenues represented 58 percent of total drilling revenues in 1994 as opposed to 47 percent in 1993. Turnkey and footage contracts typically provide for higher revenues since a greater portion of the expense of drilling the well is born by the drilling contractor.
In July 1994, the Company moved one of its rigs under a multi-well contract to the South Texas Basin creating a new operating region for the Company to market its drilling services. In November, the Company moved a
second rig under contract into the region and a third rig was moved under contract in February 1995.
The Company's marketing and natural gas processing revenues increased 38 percent as the marketing operation moved 53 percent higher volumes in 1994 while experiencing a 15 percent decrease in prices.
Operating margins (revenues less operating costs) were either slightly improved or unchanged for all segments on the Company's operations when comparing 1994 with 1993. Operating margins for the Company's oil and natural gas operations were unchanged due primarily to increased production offset by the decrease in average prices received for natural gas. Total operating costs from oil and natural gas operations increased 9 percent as the Company increased production from reserves added primarily through development drilling in 1993 and 1994.
Operating margins for contract drilling improved from 10 percent in 1993 to 12 percent in 1994. Increased rig utilization helped provide greater revenue in relation to fixed costs. Total operating costs for contract drilling were up 12 percent in 1994 versus 1993 due to the increased utilization.
Natural gas marketing and processing operating margins improved from a negative 1 percent in 1993 to a positive 1 percent in 1994. Increased volumes marketed in 1994 helped to improve the Company's ability to cover its fixed overhead. Total natural gas marketing and processing expense increased 36 percent due to increased volumes marketed between the comparative periods.
Contract drilling depreciation increased 19 percent in response to increased rig utilization. Depreciation, depletion and amortization ("DD&A") of oil and natural gas properties increased 18 percent as the Company increased its equivalent barrels of production by 22 percent. The Company's average DD&A rate per equivalent barrel dropped from $4.13 in 1993 to $4.08 in 1994.
General and administrative expense increased 8 percent as certain employee and reporting costs increased between the comparative years. This increase is expected to continue in 1995 as the Company continues to expand its area of operation. Interest expense increased 25 percent as the average interest rate on the Company's outstanding bank debt increased from 6 percent in 1993 to 7.15 percent in 1994. Outstanding bank debt was $12.4 million higher at December 31, 1994 when compared with December 31, 1993 due to the financing of the December 15, 1994 Patrick acquisition previously discussed.
1993 versus 1992 - ----------------
Net income for 1993 was $3,871,000, compared with $1,087,000 in 1992. The increase in 1993 resulted primarily from improved operating results associated with the contract drilling segment. Additionally net income for
1992 was negatively impacted by a $1.5 million provision for certain litigation.
Total revenues were $70,941,000 in 1993 and $55,827,000 in 1992. Oil and natural gas revenues increased 3 percent due to a 10 percent increase in natural gas production and a 6 percent increase in oil production between 1993 and 1992. Average natural gas and oil prices received by the Company decreased 4 and 14 percent, respectively, and partially offset the increases in production. Although spot market natural gas prices increased, the Company's natural gas price was negatively impacted by a 26 percent reduction in volumes produced from certain wells included under a settlement agreement which contains provisions for prices which are higher than current spot market prices. Approximately 88 percent of the Company's natural gas production was sold under spot market prices in 1993 as compared with 83 percent in 1992.
Higher spot market natural gas prices had a positive effect on the Company's contract drilling operations. Revenues from contract drilling operations increased 51 percent as utilization went from 21 percent in 1992 to 31 percent in 1993. Rising spot market natural gas prices encouraged domestic operators to increase their focus on drilling new wells as opposed to acquiring producing properties as in previous years. To a lesser extent, the increase in drilling revenues resulted from higher rates per day for daywork drilling and a greater portion of the Company's contract drilling being performed under turnkey and footage contracts. Turnkey and footage contracts typically provide for higher revenues since a greater portion of the expense of drilling the well is born by the drilling contractor. Daywork revenues represented 47 percent of total drilling revenues in 1993 as opposed to 51 percent in 1992.
The Company's marketing and natural gas processing revenues increased 46 percent as the marketing operations began moving higher volumes in 1993 after experiencing reduced volumes in 1992 which were associated with the change in focus of its marketing activity toward an end user market. The Company had previously marketed its natural gas primarily to broker and commodity markets.
Increased revenues were complemented by improved operating margins (revenues less operating costs) in 1993 versus 1992 from both contract drilling and natural gas marketing and processing. Operating margins for the Company's oil and natural gas operations declined from 68 percent to 66 percent due primarily to the decrease in average prices received for oil and natural gas. Total operating costs from oil and natural gas operations increased 7 percent as the Company increased production from reserves added primarily through developmental drilling in 1993 and from producing property acquisitions in 1992.
Operating margins for contract drilling showed significant improvement as they moved from a negative 2 percent in 1992 to a positive 10 percent in 1993. This increase was a result of a reduction in fixed overhead expense made by the Company during the last six months of 1992, reduced worker's compensation expense and increased rig utilization and dayrates which provided greater revenue to cover fixed costs. Total operating costs for
contract drilling were up 34 percent in 1993 versus 1992 due to the increased utilization.
Natural gas marketing and processing operating margins improved from a negative 3 percent in 1992 to a negative 1 percent in 1993. Increased volumes marketed in 1993 helped to improve the Company's ability to cover its fixed overhead. Total natural gas marketing and processing expense increased 43 percent due to the increased volumes marketed between the comparative periods.
Contract drilling depreciation increased 33 percent in response to increased rig utilization and a $160,000 write down in value of components previously utilized on one of the Company's rigs which was retired at December 31, 1993. Depreciation, depletion and amortization ("DD&A") of oil and natural gas properties decreased 2 percent as the Company's average DD&A rate per equivalent barrel dropped from $4.67 per equivalent barrel in 1992 to $4.13 per equivalent barrel in 1993. The effect of the decreased rate was partially offset by increased production volumes between the comparative periods.
General and administrative expense increased 6 percent, primarily due to increased payroll, employee benefits and office related expenses. Interest expense decreased 19 percent as interest rates remained stable and the Company's average debt outstanding for the year of 1993 remained below the average debt outstanding in 1992.
Item 8.


Item 8. Financial Statements and Supplementary Data - -----------------------------------------------------
UNIT CORPORATION AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS
As of December 31, ASSETS 1994 1993 ---------- ---------- (In thousands) Current Assets: Cash and cash equivalents $ 2,749 $ 3,756 Short-term investments - 41 Accounts receivable (less allowance for doubtful accounts of $289 and $411) 16,369 14,099 Materials and supplies 1,498 1,424 Prepaid expenses and other 1,222 736 --------- --------- Total current assets 21,838 20,056 --------- --------- Property and Equipment: Drilling equipment 75,746 75,528 Oil and natural gas properties, on the full cost method 157,393 132,704 Transportation equipment 3,341 2,851 Other 7,925 8,541 --------- --------- 244,405 219,624 Less accumulated depreciation, depletion, amortization and impairment 153,862 144,099 --------- --------- Net property and equipment 90,543 75,525 --------- --------- Other Assets 40 181 --------- --------- Total Assets $112,421 $ 95,762 ========= =========
The accompanying notes are an integral part of the consolidated financial statements
UNIT CORPORATION AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS - CONTINUED
As of December 31, LIABILITIES AND SHAREHOLDERS' EQUITY 1994 1993 ---------- ---------- (In thousands) Current Liabilities: Current portion of long-term debt $ 496 $ 481 Current portion of natural gas purchaser prepayments (Note 4) 1,580 1,170 Accounts payable 14,593 14,008 Accrued liabilities 3,014 1,983 Contract advances 158 10 ---------- ---------- Total current liabilities 19,841 17,652 ---------- ---------- Natural Gas Purchaser Prepayments (Note 4) 2,149 4,417 ---------- ---------- Long-Term Debt 37,824 25,919 ---------- ---------- Commitments and Contingencies (Note 9) Shareholders' Equity: Preferred stock, $1.00 par value, 5,000,000 shares authorized, none issued - - Common stock, $.20 par value, 40,000,000 shares authorized, 20,910,190 and 20,861,505 shares issued, respectively 4,182 4,172 Capital in excess of par value 50,086 49,977 Accumulated deficit (1,581) (6,375) Treasury stock, at cost (25,100 shares) (80) - ---------- ---------- Total shareholders' equity 52,607 47,774 ---------- ---------- Total Liabilities and Shareholders' Equity $ 112,421 $ 95,762 ========== ==========
The accompanying notes are an integral part of the consolidated financial statements
UNIT CORPORATION AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF OPERATIONS
Year Ended December 31, 1994 1993 1992 -------- -------- -------- (In thousands except per share amounts) Revenues: Contract drilling $16,952 $14,676 $ 9,732 Oil and natural gas 26,001 24,073 23,464 Natural gas marketing and processing 44,171 32,104 21,970 Other 834 88 661 -------- -------- -------- Total revenues 87,958 70,941 55,827 -------- -------- -------- Expenses: Contract drilling: Operating costs 14,909 13,269 9,901 Depreciation and impairment 2,030 1,713 1,284 Oil and natural gas: Operating costs 8,799 8,098 7,538 Depreciation, depletion and amortization 8,281 7,018 7,128 Natural gas marketing and processing 43,897 32,325 22,627 General and administrative 3,574 3,302 3,114 Interest 1,654 1,324 1,633 Provision for litigation - - 1,500 -------- -------- -------- Total expenses 83,144 67,049 54,725 -------- -------- -------- Income Before Income Taxes 4,814 3,892 1,102
Income Tax Expense 20 21 15 -------- -------- -------- Net Income $ 4,794 $ 3,871 $ 1,087 ======== ======== ======== Net Income Per Common Share $ .23 $ .19 $ .05 ======== ======== ======== Weighted Average Shares Outstanding 20,900 20,860 20,781 (Both Primary and Fully Diluted) ======== ======== ========
The accompanying notes are an integral part of the consolidated financial statements
UNIT CORPORATION AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDERS' EQUITY Year Ended December 31, 1992, 1993 and 1994
Capital In Excess Treasury Common Of Par Accumulated Stock Value Deficit Stock Total -------- -------- --------- -------- -------- (In thousands) Balances, January 1, 1992 $ 4,143 $49,733 $(11,333) $ - $42,543
Net income - - 1,087 - 1,087 Activity in employee compensation plans (67,755 shares) 14 108 - - 122 -------- -------- --------- -------- --------
Balances, December 31, 1992 4,157 49,841 (10,246) - 43,752
Net income - - 3,871 - 3,871 Activity in employee compensation plans (78,706 shares) 15 136 - - 151 -------- -------- --------- -------- --------
Balances, December 31, 1993 4,172 49,977 (6,375) - 47,774
Net income - - 4,794 - 4,794 Activity in employee compensation plans (48,685 shares) 10 109 - - 119 Purchase of treasury stock (25,100 shares) - - - (80) (80) -------- -------- --------- -------- -------- Balances, December 31, 1994 $ 4,182 $50,086 $ (1,581) $ (80) $52,607 ======== ======== ========= ======== ========
The accompanying notes are an integral part of the consolidated financial statements
UNIT CORPORATION AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF CASH FLOWS
Year Ended December 31, 1994 1993 1992 -------- -------- -------- (In thousands) Cash Flows From Operating Activities: Net income $ 4,794 $ 3,871 $ 1,087 Adjustments to reconcile net income to net cash provided by operating activities: Depreciation, depletion, amortization and impairment 10,774 9,256 8,772 Gain on disposition of assets (813) (49) (463) Employee stock compensation plans 119 151 122 Bad debt expense - - 200 Provision for litigation - - 1,500 Changes in operating assets and liabilities increasing (decreasing) cash: Accounts receivable (939) (1,257) 2,493 Materials and supplies (74) (99) 121 Prepaid expenses and other (486) 83 191 Accounts payable 735 634 (747) Accrued liabilities 760 (947) (151) Contract advances 148 8 (876) Natural gas purchaser prepayments (1,858) (1,743) (2,319) -------- -------- -------- Net cash provided by operating activities 13,160 9,908 9,930 -------- -------- --------
The accompanying notes are an integral part of the consolidated financial statements
UNIT CORPORATION AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF CASH FLOWS - CONTINUED
Year Ended December 31, 1994 1993 1992 --------- --------- --------- (In thousands) Cash Flows From Investing Activities: Capital expenditures (including producing property acquisitions) $(28,227) $(11,946) $(10,768) Proceeds from disposition of assets 2,038 709 1,146 Decrease in short-term investments 41 664 170 (Acquisition) disposition of other assets 141 (45) 60 --------- --------- --------- Net cash used in investing activities (26,007) (10,618) (9,392)
Cash Flows From Financing Activities: Borrowings under line of credit 63,700 43,400 23,900 Payments under line of credit (51,300) (40,600) (24,700) Proceeds from notes payable and other long-term debt - 911 710 Payments on notes payable and other long-term debt (480) (367) (80) Acquisition of treasury stock (80) - - --------- --------- --------- Net cash provided by (used in) financing activities 11,840 3,344 (170) --------- --------- --------- Net Increase (Decrease) in Cash and Cash Equivalents (1,007) 2,634 368
Cash and Cash Equivalents, Beginning of Year 3,756 1,122 754 --------- --------- --------- Cash and Cash Equivalents, End of Year $ 2,749 $ 3,756 $ 1,122 ========= ========= =========
Supplemental Disclosure of Cash Flow Information: Cash paid during the year for: Interest $ 1,548 $ 1,326 $ 1,673 Income taxes $ 2 $ 2 $ 63
The accompanying notes are an integral part of the consolidated financial statements
UNIT CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NOTE 1 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - ---------------------------------------------------
Principles of Consolidation
The consolidated financial statements include the accounts of Unit Corporation and its directly and indirectly wholly owned subsidiaries (the "Company"). The Company's investment in limited partnerships is accounted for on the proportionate consolidation method, whereby its share of the partnerships' assets, liabilities, revenues and expenses is included in the appropriate classification in the accompanying consolidated financial statements.
Drilling Contracts
The Company accounts for "footage" and "turnkey" drilling contracts, in which the Company assumes the risks associated with drilling the well, under the completed-contract method and for "daywork" drilling contracts under the percentage-of-completion method. The entire amount of the loss, if any, is recorded when the loss is determinable.
The costs of uncompleted drilling contracts include expenses incurred to date on "footage" or "turnkey" drilling contracts which are still in process.
Cash Equivalents and Short-Term Investments
The Company includes as cash equivalents, certificates of deposits and all investments with original maturities at date of purchase of three months or less which are readily convertible into known amounts of cash.
Property and Equipment
Drilling equipment, transportation equipment and other property and equipment are carried at cost. The Company provides for depreciation of drilling equipment on the units-of-production method based on estimated useful lives, including a minimum provision of 20 percent of the active rate when the equipment is idle. At December 31, 1993, one of the Company's rigs was retired and certain components of the rig were written down by $160,000 to their estimated market value. The Company uses the composite method of depreciation for drill pipe and collars and calculates the depreciation by footage actually drilled compared to total estimated remaining footage. Depreciation of other property and equipment is comput- ed using the straight-line method over the estimated useful lives of the assets ranging from 3 to 15 years.
When property and equipment components are disposed of, the cost and the related accumulated depreciation are removed from the accounts and any resulting gain or loss is generally reflected in operations. For dispo-
sitions of drill pipe and drill collars, an average cost for the appropriate feet of drill pipe and drill collars is removed from the asset account and charged to accumulated depreciation and proceeds, if any, are credited to accumulated depreciation.
Oil and Natural Gas Operations
The Company accounts for its oil and natural gas exploration and development activities on the full cost method of accounting prescribed by the Securities and Exchange Commission ("SEC"). Accordingly, all produc- tive and non-productive costs incurred in connection with the acquisition, exploration and development of oil and natural gas reserves are capitalized and amortized on a composite units-of-production method based on proved oil and natural gas reserves. The Company's determination of its oil and natural gas reserves are reviewed annually by independent petroleum engineers. The average composite rates used for depreciation, depletion and amortization ("DD&A") were $4.08, $4.13 and $4.67 per equivalent barrel in 1994, 1993 and 1992, respectively. The Company's calculation of DD&A includes estimated future expenditures to be incurred in developing proved reserves and estimated dismantlement and abandonment costs, net of estimated salvage values. In the event the unamortized cost of oil and natural gas properties being amortized exceeds the full cost ceiling, as defined by the SEC, the excess is charged to expense in the period during which such excess occurs.
No gains or losses are recognized upon the sale, conveyance or other disposition of oil and natural gas properties unless a significant reserve amount is involved.
The SEC's full cost accounting rules prohibit recognition of income in current operations for services performed on oil and natural gas properties in which the Company has an interest or on properties in which a part- nership, of which the Company is a general partner, has an interest. Accordingly, in 1994 the Company recorded $14,000 of contract drilling profits as a reduction of the carrying value of its oil and natural gas properties rather than including these profits in current operations. No contract drilling profits were realized on such interests in 1993 and 1992.
Limited Partnerships
The Company, through its wholly owned subsidiary, Unit Petroleum Company, is a general partner in eleven oil and natural gas limited part- nerships sold privately and publicly. Certain of the Company's officers and directors own interests in some of these partnerships. Their interests were acquired generally on the same basis as other outside investors. Prior to December 31, 1993, the Company also was general partner of seven additional employee limited partnerships. However, pursuant to the terms of an agreement and plan of merger, these seven limited partnerships were consolidated into one new employee limited partnership effective December 31, 1993.
The Company shares in partnership revenues and costs in accordance with formulas prescribed in each limited partnership agreement. The
partnerships also reimburse the Company for certain administrative costs incurred on behalf of the partnerships.
Income Taxes
Income taxes are accounted for in accordance with Statement of Financial Accounting Standards (SFAS) No. 109, "Accounting for Income Taxes". SFAS No. 109 requires the measurement of deferred tax assets for deductible temporary differences and operating loss carryforwards, and of deferred tax liabilities for taxable temporary differences. Measurement of current and deferred tax liabilities and assets is based on provisions of enacted tax law; the effects of future changes in tax laws or rates are not included in the measurement. Deferred tax assets primarily result from net operating loss carryforwards, and deferred tax liabilities result from the recognition of depreciation, depletion and amortization in different periods for financial reporting and tax purposes. Valuation allowances are established where necessary to reduce deferred tax assets to the amount expected to be realized. Income tax expense is the tax payable for the year and the change during that year in deferred tax assets and liabilities.
Natural Gas Balancing
The Company uses the sales method for recording natural gas sales. This method allows for recognition of revenue which may be more or less than the Company's share of pro-rata production from certain wells. Based upon the Company's 1994 average spot market natural gas price of $1.65 per Mcf, the Company estimates its balancing position to be approximately $5.5 million on under-produced properties and approximately $3.1 million on over-produced properties.
The Company's policy is to expense its pro-rata share of lease oper- ating costs from all wells as incurred. Such expenses relating to the Company's balancing position on wells on which the Company has imbalances are not material.
Financial Instruments and Concentrations of Credit Risk
At December 31, 1994, the Company had natural gas price swaps, related to its marketing of natural gas, which qualify as hedges of the Company's future purchase and sales commitments. Gains or losses on these swaps are recognized in the consolidated statement of operations and included in operating cash flows in the same period as the associated sale of natural gas occurs. At December 31, 1994, the Company had price swap agreements for 380,000 Mcf totaling $525,000 related to purchase commitments and 358,000 Mcf totaling $694,000 related to sales commitments for the period of January through March of 1995.
Financial instruments which potentially subject the Company to concentrations of credit risk consist primarily of trade receivables with a variety of national and international oil and natural gas companies. The Company does not generally require collateral related to receivables. Such credit risk is considered by management to be limited due to the large
number of customers comprising the Company's customer base. The Company had one customer in its natural gas marketing operation at December 31, 1993, with an accounts receivable balance of $4.1 million which was subsequently paid in January 1994. In addition, at December 31, 1994 and 1993, the Company had a concentration of cash of $2.3 and $3.4 million, respectively, with one bank.
RECLASSIFICATIONS
Certain reclassifications have been made in the 1992 and 1993 consolidated financial statements to conform them to classifications used in 1994.
NOTE 2 - PRODUCING PROPERTY ACQUISITION - ---------------------------------------
On December 15, 1994, Unit Petroleum Company, a wholly owned subsidiary of Unit Corporation, acquired interests in approximately 700 oil and natural gas wells located primarily in Oklahoma, Texas, New Mexico and Louisiana. Financing for the transaction was provided under the Company's bank credit agreement. The acquisition is summarized as follows:
Current assets net of current liabilities $ 976,000 Producing oil and natural gas properties 12,261,000 ----------- Net assets acquired $13,237,000 =========== Unaudited summary pro forma results of operations for the Company, reflecting the above described acquisition as if it had occurred at the beginning of the years ended December 31, 1994 and December 31, 1993, are as follows, respectively; revenues, $94,373,000 and $79,807,000; net income, $5,068,000 and $7,259,000; and net income per common share, $.24 and $.35. The pro forma results of operations are not necessarily indicative of the actual results of operations that would have occurred had the purchase actually been made at the beginning of the respective periods nor of the results which may occur in the future.
NOTE 3 - WARRANTS - -----------------
In 1987, the Company issued 2.873 million units, consisting of three shares of the Company's common stock and one warrant, at a price of $10.375 per unit. Each warrant entitles the holder to purchase one share of the Company's common stock at a price of $4.375 anytime prior to the warrant's expiration on August 30, 1996. The warrants, subject to certain restrictions, are callable by the Company, in whole or in part, at $.50 per warrant. As of December 31, 1994 no warrants have been exercised.
NOTE 4 - NATURAL GAS PURCHASER PREPAYMENTS - -------------------------------------------
In March 1988, the Company entered into a settlement agreement with a natural gas purchaser. During early 1991, the Company and the natural gas purchaser superseded the original agreement with a new settlement agreement effective retroactively to January 1, 1991. Under these settlement agreements, the Company has a prepayment balance of $3.7 million at December 31, 1994 representing proceeds received from the purchaser as prepayment for natural gas. This amount is net of natural gas recouped and net of certain amounts disbursed to other owners (such owners, collectively with the Company are referred to as the "Committed Interest") for their proportionate share of the prepayments. The December 31, 1994 prepayment balance is subject to recoupment in volumes of natural gas for a period ending the earlier of recoupment or December 31, 1997 (the "Recoupment Period"). Additionally, the purchaser is obligated to make monthly payments on behalf of the Committed Interest in an amount calculated as a percentage of the Committed Interest's share of the deliverability of the wells subject to the settlement agreement, up to a maximum of $211,000 or a minimum of $110,000 per month for the year 1995. Both the maximum and minimum monthly payments decline annually through the Recoupment Period. At December 31, 1997, the Committed Interest's prepayment balance, if any, that has not been fully recouped in natural gas is subject to a cash repayment limited to a maximum of $3 million to be made in equal payments over a five year period. The prepayment amounts subject to recoupment from future production by the purchaser are being recorded as liabilities and are reflected in revenues as recoupment occurs. The portion of the prepay- ments that are estimated to be recouped in the next twelve months has been included in current liabilities. At the end of the Recoupment Period, the terms of the settlement agreement and the natural gas purchase contracts which are subject to the settlement agreement will terminate.
NOTE 5 - LONG-TERM DEBT - ------------------------
Long-term debt consisted of the following as of December 31, 1994 and 1993:
1994 1993 --------- --------- Revolving credit and term loan, (In thousands) with interest at December 31, 1994 and 1993 of 8.5% and 6%, respectively $ 37,300 $ 24,900 Other 1,020 1,500 --------- --------- 38,320 26,400 Less current portion 496 481 --------- --------- Total long-term debt $ 37,824 $ 25,919 ========= =========
At December 31, 1994, the Company's credit agreement ("Agreement") provided for a total loan commitment of $50 million consisting of a revolv- ing credit facility through January 1, 1997 and a term loan thereafter, maturing on January 1, 2001. Borrowings under the Agreement are limited to a semi-annual borrowing base computation which as of December 31, 1994 is $42 million.
The principal of the revolving credit facility is due in 48 equal monthly payments commencing February 1, 1997 and continuing on the first day of each month thereafter through maturity. The outstanding principal amount of the revolving credit facility which is less than or equal to the loan value of the mineral interest then in effect shall bear interest at the Chase Manhattan Bank, N.A. prime rate ("Prime Rate") and that portion of the outstanding balance exceeding such loan value shall bear interest at the Prime Rate plus 1 and 1/2 percent through January 1, 1997. Subsequent to January 1, 1997 and continuing through January 1, 2001, the portion of the outstanding amount under the Agreement which is less than or equal to the loan value of the mineral interests then in effect shall bear interest at the Prime Rate plus 1/4 of 1 percent and any portion of the outstanding principal balance exceeding such loan value shall bear interest equal to the Prime Rate plus 1 and 1/2 percent. The Agreement also provides for a commitment fee of 1/2 of 1 percent of the unused portion of the borrowing base. Virtually all of the Company's drilling rigs are collateral for such indebtedness and the balance of the Company's assets are subject to a negative pledge.
The Agreement includes prohibitions against (i) the payment of divi- dends (other than stock dividends) during any fiscal year in excess of 25 percent of the consolidated net income of the Company during the preceding fiscal year, (ii) the incurrence by the Company or any of its subsidiaries of additional debt with certain very limited exceptions and (iii) the creation or existence of mortgages or liens, other than those in the ordinary course of business, on any property of the Company or any of its subsidiaries, except in favor of its banks. The Agreement also requires that the Company maintain consolidated net worth of at least $45 million, a modified current ratio of not less than 1 to 1, a ratio of long-term debt, as defined in the Agreement, to consolidated tangible net worth not greater than 1 to 1 and a ratio of total liabilities, as defined in the Agreement, to consolidated tangible net worth not greater than 1.25 to 1. In addition, working capital provided by operations, as defined in the Agreement, cannot be less than $13 million in any year.
Estimated annual principal payments under the terms of all long-term debt from 1995 through 1999 are $496,000, $200,000, $200,000, $8,671,000 and $9,325,000.
NOTE 6 - INCOME TAXES - ---------------------
A reconciliation of the income tax expense, computed by applying the federal statutory rate to pre-tax income, to the Company's effective income tax expense is as follows: 1994 1993 1992 -------- -------- -------- (In thousands) Income tax expense computed by applying the statutory rate $ 1,637 $ 1,323 $ 375 Tax benefit of net operating loss carryforward (1,652) (1,308) (396) Alternative minimum tax - - 2 State income tax 6 1 7 Other 29 5 27 -------- -------- -------- Income tax expense $ 20 $ 21 $ 15 ======== ======== ========
Deferred tax assets and liabilities are comprised of the following at December 31, 1994 and 1993:
1994 1993 -------- -------- Deferred tax assets: (In thousands) Allowance for losses $ 521 $ 580 Gas purchaser prepayments - 149 Net operating loss carryforwards 18,190 18,118 Statutory depletion carryforward 2,500 2,500 Investment tax credit carryforward 3,530 3,530 -------- -------- Gross deferred tax assets 24,741 24,877 -------- -------- Deferred tax liabilities: Depreciation, depletion and amortization 18,318 16,659 -------- -------- Gross deferred tax liabilities 18,318 16,659 -------- -------- Net deferred tax asset 6,423 8,218 Valuation allowance 6,423 8,218 -------- -------- $ - $ - ======== ========
The net deferred tax asset valuation allowance reflects that the tax carryforwards above may not be utilized before the expiration dates as itemized below due in part to the effects of anticipated future exploratory and development drilling costs.
At December 31, 1994, the Company has net operating loss carryforwards for regular tax purposes of approximately $47,868,000 and net operating loss carryforwards for alternative minimum tax purposes of approximately
$38,260,000 which expire in various amounts from 1999 to 2007. The Company has investment tax credit carryforwards of approximately $3,530,000 which expire from 1995 to 2000. In addition, a statutory depletion carryforward of approximately $6,579,000 is available to reduce future taxable income, subject to statutory limitations. Statutory depletion may be carried forward indefinitely.
In 1987, the Company completed an equity offering which constituted an ownership change as that term is used in the Internal Revenue Code. As a result of the ownership change, the amount of taxable income in future years which may be offset by the Company's net operating loss carryovers prior to the ownership change is limited. Tax losses of $45,950,000 at December 31, 1994 are not subject to these limitations. The remaining tax net operating loss carryforward will become available for utilization by the Company at a rate of $3,500,000 per year. Similar limitations apply to investment tax credits.
NOTE 7 - BENEFIT AND COMPENSATION PLANS - ---------------------------------------
In December 1984, the Board of Directors approved the adoption of an Employee Stock Bonus Plan ("the Plan") whereby 330,950 shares of common stock were authorized for issuance under the Plan. Under the terms of the Plan, bonuses may be granted to employees in either cash or stock or a combination thereof, and are payable in a lump sum or in annual in- stallments subject to certain restrictions. The Company issued 38,354 and 50,788 shares under the Plan in 1993 and 1992, respectively. No shares were issued under the Plan in 1994.
The Company has a Stock Option Plan which provides for the granting of options for up to 1,000,000 shares of common stock to officers and employees. The plan permits the issuance of qualified or nonqualified stock options. Stock options granted in 1986 became exercisable at the rate of 20 percent per year through 1990. Options granted subsequent to 1986 become exercisable at the rate of 20 percent per year one year after being granted.
Activity pertaining to the Stock Option Plan is as follows:
NUMBER OF OPTION PRICE SHARES ----------------------------- --------- PER SHARE AGGREGATE Outstanding at ----------------------------- January 1, 1992 752,000 $1.50 to 3.375 $1,476,995 Granted 10,000 1.875 18,750 Cancelled (10,000) 2.37 to 2.875 (26,225) --------- -------------- ---------- Outstanding at December 31, 1992 752,000 1.50 to 3.375 1,469,520 Granted 89,000 2.75 244,750 Exercised (12,000) 1.50 to 2.37 (19,740) --------- -------------- ----------- Outstanding at December 31, 1993 829,000 1.50 to 3.375 1,694,530 Granted 102,500 3.00 307,500 Exercised (16,000) 1.50 to 2.37 (24,870) --------- -------------- ----------- Outstanding at December 31, 1994 915,500 $1.50 to 3.375 $ 1,977,160 ========= ============== ===========
Options for 676,400, 610,500 and 556,400 shares were exercisable at prices ranging from $1.50 to $3.375 at December 31, 1994, 1993 and 1992, respectively.
In February and May 1992, the Board of Directors and shareholders, respectively, approved the Unit Corporation Non-Employee Directors' Stock Option Plan (the "Directors' Plan"). An aggregate of 100,000 shares of the Company's common stock may be issued or delivered upon exercise of the stock options. On the first business day following each annual meeting of stockholders of the Company, each person who is then a member of the Board of Directors of the Company and who is not then an employee of the Company or any of its subsidiaries will be granted an option to purchase 2,500 shares of common stock. The option price for each stock option is the fair market value of the common stock on the date the stock options are granted. No stock options may be exercised during the first six months of its term except in case of death and no stock options are exercisable after ten years from the date of grant.
Activity pertaining to the Directors' Plan is as follows:
NUMBER OF OPTION PRICE SHARES -------------------------- ------- PER SHARE AGGREGATE 1992: -------------- --------- Granted 10,000 $ 1.75 $ 17,500 ------- -------------- --------- Outstanding at December 31, 1992 10,000 1.75 17,500 Granted 10,000 3.75 37,500 ------- -------------- --------- Outstanding at December 31, 1993 20,000 1.75 to 3.75 55,000 Granted 10,000 2.875 28,750 ------- -------------- --------- Outstanding at December 31, 1994 30,000(1) $1.75 to 3.75 $ 83,750 ======= ============== ========= - ------------- (1) All 30,000 options were exercisable at December 31, 1994.
Under the Company's 401(k) Employee Thrift Plan, employees who meet specified service requirements may contribute a percentage of their total compensation, up to a specified maximum, to the plan. Each employee's contribution, up to a specified maximum, may be matched by the Company in full or on a partial basis. The Company made discretionary contributions under the plan of 32,685, 28,352 and 16,967 shares of common stock and recognized expense of $130,000, $162,000 and $33,000 in 1994, 1993 and 1992, respectively.
Effective March 1, 1993, the Company adopted a salary deferral plan ("Deferral Plan"). The Deferral Plan allows participants to defer the recognition of salary for income tax purposes until actual distribution of benefits which occurs at either termination of employment, death or certain defined unforeseeable emergency hardships. Funds set aside in a trust to satisfy the Company's obligation under the Deferral Plan at December 31, 1994 and 1993 totaled $108,000 and $41,000, respectively. The Company recognizes payroll expense and records a deferred liability at the time of deferral.
NOTE 8 - TRANSACTIONS WITH RELATED PARTIES - ------------------------------------------
The Company formed private limited partnerships (the "Partnerships") with certain qualified employees, officers and directors from 1984 through 1994, with a subsidiary of the Company 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 the Company in any additional limited partnerships formed during that year. The Partnerships participated on a proportionate basis with the Company in most drilling operations and most producing property
acquisitions commenced by the Company for its own account during the period from the formation of the Partnership through December 31 of each year. Pursuant to the terms of an agreement and plan of merger, seven limited partnerships, in which the Company was general partner, were consolidated into one new employee limited partnership effective December 31, 1993.
Amounts received in the following years ended December 31 from both public and private Partnerships for which the Company is a general partner are as follows:
1994 1993 1992 -------- -------- -------- (In thousands) Contract drilling $ 53 $ 60 $ 38 Well supervision and other fees $ 226 $ 278 $ 277 General and administrative expense reimbursement $ 209 $ 231 $ 294
A subsidiary of the Company paid the Partnerships, for which the Company or a subsidiary is the general partner, $38,000, $65,000 and $58,000 during the years ended December 31, 1994, 1993 and 1992, respectively, for purchases of natural gas production.
During 1993 and 1992, the Company received legal services from a law firm of which one of the Company's directors was a partner. Total payments to the law firm during 1993 and 1992 were $164,000 and $130,000, respectively. The Company did not receive such services from the law firm in 1994.
During 1994, a bank owned by one of the Company's Directors became a participant in the Company's loan agreement. The bank's total pro rata share of the Company's line of credit is not to exceed $1.5 million.
NOTE 9 - COMMITMENTS AND CONTINGENCIES - --------------------------------------
The Company is currently negotiating a new operating lease agreement to remain in its current office space until February 1, 2000. Future minimum rental payments under the proposed terms of the lease would be approximately $205,000, $224,000, $244,000, $246,000 and $246,000 in 1995, 1996, 1997, 1998 and 1999, respectively. Total rent expense incurred by the Company was $210,000, $208,000 and $205,000 in 1994, 1993 and 1992, respectively.
The Company had letters of credit totaling $835,600 outstanding at December 31, 1994.
The Unit 1984 Oil and Gas Limited Partnership and the 1986 Energy Income Limited Partnership agreements along with the employee oil and gas limited partnerships require, upon the election of a limited partner, that the Company repurchase the limited partner's interest at amounts to be determined by appraisal in the future. Such repurchases in any one year are limited to 20 percent of the units outstanding. The Company made
repurchases of $38,000, $56,000 and $70,000 in 1994, 1993 and 1992, respectively, for such limited partner's interest.
The Company is a party to a settlement agreement dated January 31, 1991 with a natural gas purchaser which superseded a settlement agreement entered into during March of 1988. Under the agreements the purchaser made certain prepayments to the Company for natural gas to be delivered to the purchaser in the future. As of December 31, 1994, this prepayment balance for natural gas yet to be delivered was $3.7 million. The Company has learned that the Oklahoma Tax Commission (the "Commission"), based on four assessments, one in 1988, one in 1992 and two in 1994, is seeking to hold the purchaser liable for certain taxes, interests and penalties that the Commission contends are due and owing with respect to the prepayment amounts made by the purchaser under the agreements on the grounds that the prepayments are solely attributable to the settlement of past claims for take-or-pay obligations. To date, the Company is not a party to the Commission's proceedings, but may in the future, seek to intervene in these proceedings. The purchaser has denied the claims made by the Commission and is contesting the assessments. The purchaser and the Commission have settled the 1988 assessment for approximately $51,000 and the remaining three assessments have been consolidated and set for a hearing before an administrative law judge on or before May 10, 1995. The purchaser has notified the Company of the proceedings and has indicated its intention to assert claims against the Company to recover the amount it paid in settlement of the 1988 assessment (including its attorney fees) as well as any amounts it might have to pay by virtue of the remaining assessments. The Company is aware that the purchaser has made such claims against other companies which also received prepayments from the purchaser, although the type of agreements and the facts involved in those cases are not known by the Company. At this time, the Company is unable to determine what the outcome of the remaining Commission's proceedings will be, the amount of taxes, if any, plus interest and penalties that may ultimately be assessed against the purchaser and the claims, if any, that the purchaser might seek to assert against the Company in the event an unfavorable result is incurred by the purchaser. The Company has advised the purchaser that it believes the responsibility for the payment of the taxes, interest and penalty sought by the Commission, should it be ultimately determined that any such amounts are in fact owed, is the responsibility of the purchaser and not the Company.
The Company is a party to various legal proceedings arising in the ordinary course of its business none of which, in the Company's opinion, should result in judgements which would have a material adverse effect on the Company.
NOTE 10 - INDUSTRY SEGMENT INFORMATION - -------------------------------------- The Company operates in the United States in three industry segments which are contract drilling, oil and natural gas exploration and production and natural gas marketing and processing. The Company also has natural gas production in Canada which is not significant. Selected financial information by industry segment is as follows:
- --------------------- (1) Operating profit is total operating revenues, less operating expenses, depreciation, depletion, amortization and impairment and does not include non-operating revenues, general corporate expenses, interest expense, income taxes or provision for litigation.
(2) Identifiable assets are those used in the Company's operations in each industry segment. Corporate assets are principally cash and cash equivalents, short-term investments, corporate leasehold improvements and furniture and equipment.
NOTE 11 - SELECTED QUARTERLY FINANCIAL INFORMATION (UNAUDITED) - --------------------------------------------------------------
Summarized quarterly financial information for 1994 and 1993 is as follows: Three Months Ended ------------------------------------------------- March 31 June 30 September 30 December 31 --------- --------- ----------- ---------- (In thousands except per share amounts) Year ended December 31, 1994:
Revenues $ 23,005 $ 19,926 $ 21,166 (2) $ 23,861 ========= ========= ========= ========= Gross Profit(1) $ 2,396 $ 2,726 $ 2,090 $ 1,996 ========= ========= ========= ========= Income before income taxes $ 1,215 $ 1,430 $ 1,595 (2) $ 574 ========= ========= ========= ========= Net income $ 1,211 $ 1,425 $ 1,590 (2) $ 568 ========= ========= ========= ========= Net income per common share $ .06 $ .07 $ .07 (2) $ .03 ========= ========= ========= ========= Year ended December 31, 1993:
Revenues $ 15,574 $ 17,881 $ 16,935 $ 20,551 ========= ========= ========= ========= Gross Profit(1) $ 2,357 $ 1,982 $ 1,920 $ 2,171 ========= ========= ========= ========= Income before income taxes $ 1,163 $ 884 $ 890 $ 955 ========= ========= ========= ========= Net income $ 1,156 $ 878 $ 886 $ 951 ========= ========= ========= ========= Net income per common share $ 0.06 $ 0.04 $ 0.04 $ 0.05 ========= ========= ========= ========= - ------------- (1) Gross Profit excludes other revenues, general and administrative expense and interest expense.
(2) Includes $742,000 net gain on sale of natural gas gathering system.
NOTE 12 - OIL AND NATURAL GAS INFORMATION (UNAUDITED) - -----------------------------------------------------
The capitalized costs at year end and costs incurred during the year were as follows:
USA Canada Total --------- -------- -------- (In thousands) 1994: Capitalized costs: Proved properties $ 154,688 $ 455 $155,143 Unproved properties 2,250 - 2,250 --------- -------- -------- 156,938 455 157,393 Less accumulated depreciation, depletion, amortization and impairment 81,583 368 81,951 --------- -------- -------- Net capitalized costs $ 75,355 $ 87 $ 75,422 ========= ======== ======== Cost incurred: Unproved properties $ 460 $ - $ 460 Producing properties 13,108 - 13,108 Exploration 1,825 - 1,825 Development 9,716 1 9,717 --------- -------- -------- Total costs incurred $ 25,109 $ 1 $ 25,110 ========= ======== ======== 1993: Capitalized costs: Proved properties $ 129,612 $ 454 $130,066 Unproved properties 2,638 - 2,638 --------- -------- -------- 132,250 454 132,704 Less accumulated depreciation, depletion, amortization and impairment 73,419 314 73,733 --------- -------- -------- Net capitalized costs $ 58,831 $ 140 $ 58,971 ========= ======== ======== Cost incurred: Unproved properties $ 732 $ - $ 732 Producing properties 1,241 - 1,241 Exploration 1,359 - 1,359 Development 8,084 6 8,090 --------- -------- -------- Total costs incurred $ 11,416 $ 6 $ 11,422 ========= ======== ========
USA Canada Total --------- -------- -------- 1992: (In thousands) Capitalized costs: Proved properties $ 117,721 $ 448 $ 118,169 Unproved properties 3,680 - 3,680 --------- -------- -------- 121,401 448 121,849 Less accumulated depreciation, depletion, amortization and impairment 66,544 233 66,777 --------- -------- -------- Net capitalized costs $ 54,857 $ 215 $ 55,072 ========= ======== ======== Cost incurred: Unproved properties $ 504 $ - $ 504 Producing properties 3,629 - 3,629 Exploration 900 - 900 Development 2,918 - 2,918 --------- -------- -------- Total costs incurred $ 7,951 $ - $ 7,951 ========= ======== ========
The results of operations before income taxes for producing activities are provided below. Due to the Company's utilization of net operating loss carryforwards, income taxes are not significant and have not been included.
USA Canada Total --------- -------- -------- (In thousands) 1994: Revenues $ 23,964 $ 67 $24,031 Production costs 7,011 19 7,030 Depreciation, depletion and amortization 8,165 53 8,218 --------- -------- -------- Results of operations for producing activities before income taxes (excluding corporate overhead and financing costs) $ 8,788 $ (5) $ 8,783 ======== ======== ========
USA Canada Total --------- -------- -------- (In thousands) 1993: Revenues $ 22,040 $ 67 $22,107 Production costs 6,439 15 6,454 Depreciation, depletion and amortization 6,875 81 6,956 --------- -------- -------- Results of operations for producing activities before income taxes (excluding corporate overhead and financing costs) $ 8,726 $ (29) $ 8,697 ======== ======== ======== 1992: Revenues $21,816 $ 75 $21,891 Production costs 6,159 10 6,169 Depreciation, depletion and amortization 6,961 94 7,055 --------- -------- -------- Results of operations for producing activities before income taxes (excluding corporate overhead and financing costs) $ 8,696 $ (29) $ 8,667 ======== ======== ========
Estimated quantities of proved developed oil and natural gas reserves and changes in net quantities of proved developed and undeveloped oil and natural gas reserves were as follows: USA Canada Total ----------------- ------------- ---------------- Natural Natural Natural Oil Gas Oil Gas Oil Gas Bbls Mcf Bbls Mcf Bbls Mcf ------- -------- ------ ----- ------- -------- 1994: (In thousands) Proved developed and undeveloped reserves: Beginning of year 3,304 71,379 - 861 3,304 72,240 Revision of previous estimates (97) (571) - (14) (97) (585) Extensions, discoveries and other additions 601 17,426 - - 601 17,426 Purchases of minerals in place 910 14,075 - - 910 14,075 Sales of minerals in place (4) (137) - - (4) (137) Production (406) (9,606) - (53) (406) (9,659) ------- -------- ----- ----- ------- -------- End of Year 4,308 92,566 - 794 4,308 93,360 ======= ======== ===== ===== ======= ======== Proved developed reserves: Beginning of year End of year
1993: Proved developed and undeveloped reserves: Beginning of year 3,308 63,761 - 931 3,308 64,692 Revision of previous estimates (132) 4,662 - - (132) 4,662 Extensions, discoveries and other additions 549 9,169 - - 549 9,169 Purchases of minerals in place 18 1,369 - - 18 1,369 Sales of minerals in place (42) (147) - - (42) (147) Production (397) (7,435) - (70) (397) (7,505) ------- -------- ----- ----- ------- -------- End of Year 3,304 71,379 - 861 3,304 72,240 ======= ======== ===== ===== ======= ======== Proved developed reserves: Beginning of year 3,245 58,809 - 468 3,245 59,277 End of year 3,187 65,395 - 426 3,187 65,821
USA Canada Total ----------------- ------------- ---------------- Natural Natural Natural Oil Gas Oil Gas Oil Gas Bbls Mcf Bbls Mcf Bbls Mcf ------- -------- ------ ------ ------- -------- 1992: Proved developed and undeveloped reserves: Beginning of year 2,943 52,853 - 964 2,943 53,817 Revision of previous estimates 235 7,679 - 47 235 7,726 Extensions, discoveries and other additions 190 1,655 - - 190 1,655 Purchases of minerals in place 316 8,327 - - 316 8,327 Sales of minerals in place (1) (23) - - (1) (23) Production (375) (6,730) - (80) (375) (6,810) ------- -------- ----- ----- ------- -------- End of Year 3,308 63,761 - 931 3,308 64,692 ======= ======== ===== ===== ======= ======== Proved developed reserves: Beginning of year 2,778 44,936 - 499 2,278 45,435 End of year 3,245 58,809 - 468 3,245 59,277
Oil and natural gas reserves cannot be measured exactly. Estimates of oil and natural gas reserves require extensive judgments of reservoir engineering data and are generally less precise than other estimates made in connection with financial disclosures. The Company utilizes Ryder Scott Company, independent petroleum consultants, to review the Company's reserves as prepared by the Company's reservoir engineers.
Proved reserves are those quantities which, upon analysis of geolog- ical and engineering data, appear with reasonable certainty to be recov- erable in the future from known oil and natural gas reservoirs under exist- ing economic and operating conditions. Proved developed reserves are those reserves which can be expected to be recovered through existing wells with existing equipment and operating methods. Proved undeveloped reserves are those reserves which are expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expendi- ture is required.
Estimates of oil and natural gas reserves require extensive judgments of reservoir engineering data as explained above. Assigning monetary values to such estimates does not reduce the subjectivity and changing nature of such reserve estimates. Indeed the uncertainties inherent in the disclosure are compounded by applying additional estimates of the rates and timing of production and the costs that will be incurred in developing and producing the reserves. The information set forth herein is therefore subjective and, since judgments are involved, may not be comparable to estimates submitted by other oil and natural gas producers. In addition, since prices and costs do not remain static and no price or cost escala- tions or de-escalations have been considered, the results are not neces- sarily indicative of the estimated fair market value of estimated proved reserves nor of estimated future cash flows.
The standardized measure of discounted future net cash flows ("SMOG") was calculated using year-end prices and costs, and year-end statutory tax rates, adjusted for permanent differences, that relate to existing proved oil and natural gas reserves. SMOG as of December 31 is as follows:
USA Canada Total --------- -------- -------- 1994: (In thousands) Future cash flows $234,171 $ 1,255 $235,426 Future production and development costs 105,876 311 106,187 Future income tax expenses 20,161 524 20,685 --------- -------- -------- Future net cash flows 108,134 420 108,554 10% annual discount for estimated timing of cash flows 30,116 170 30,286 --------- -------- -------- Standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves $ 78,018 $ 250 $ 78,268 ========= ======== ========= 1993: Future cash flows $214,800 $ 861 $215,661 Future production and development costs 90,177 229 90,406 Future income tax expenses 17,097 244 17,341 --------- -------- -------- Future net cash flows 107,526 388 107,914 10% annual discount for estimated timing of cash flows 34,374 157 34,531 --------- -------- -------- Standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves $ 73,152 $ 231 $ 73,383 ======== ======== ======== Future cash flows $208,964 $ 931 $209,895 Future production and development costs 86,417 361 86,778 Future income tax expenses 19,634 194 19,828 --------- -------- -------- Future net cash flows 102,913 376 103,289 10% annual discount for estimated timing of cash flows 32,653 120 32,773 --------- -------- -------- Standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves $ 70,260 $ 256 $ 70,516 ======== ======== ========
The principal sources of changes in the standardized measure of discounted future net cash flows were as follows: USA Canada Total --------- -------- --------- (In thousands) 1994: Sales and transfers of oil and natural gas produced, net of production costs $(16,953) $ (48) $(17,001) Net changes in prices and production costs (14,941) 206 (14,735) Revisions in quantity estimates and changes in production timing (482) (5) (487) Extensions, discoveries and improved recovery, less related costs 17,050 - 17,050 Purchases of minerals in place 13,426 - 13,426 Sales of minerals in place (138) - (138) Accretion of discount 7,915 35 7,950 Net change in income taxes (457) (177) (634) Other - net (554) 8 (546) --------- -------- --------- Net change 4,866 19 4,885 Beginning of year 73,152 231 73,383 --------- -------- --------- End of year $ 78,018 $ 250 $ 78,268 ========= ======== ========= 1993: Sales and transfers of oil and natural gas produced, net of production costs $(15,359) $ (52) $(15,411) Net changes in prices and production costs (4,997) 73 (4,924) Revisions in quantity estimates and changes in production timing 483 (70) 413 Extensions, discoveries and improved recovery, less related costs 12,886 - 12,886 Purchases of minerals in place 1,440 - 1,440 Sales of minerals in place (284) - (284) Accretion of discount 7,619 36 7,655 Net change in income taxes (74) (8) (82) Other - net 1,178 (4) 1,174 --------- -------- -------- Net change 2,892 (25) 2,867 Beginning of year 70,260 256 70,516 --------- -------- -------- End of year $ 73,152 $ 231 $ 73,383 ========= ======== =========
USA Canada Total --------- -------- -------- (In Thousands) 1992: Sales and transfers of oil and natural gas produced, net of production costs $(14,693) $ (65) $(14,758) Net changes in prices and production costs (1,081) (117) (1,198) Revisions in quantity estimates and changes in production timing 4,113 2 4,115 Extensions, discoveries and improved recovery, less related costs 3,677 - 3,677 Purchases of minerals in place 9,488 - 9,488 Sales of minerals in place (47) - (47) Accretion of discount 6,602 49 6,651 Net change in income taxes (2,870) 95 (2,775) Other - net 2,104 5 2,109 --------- -------- --------- Net change 7,293 (31) 7,262 Beginning of year 62,967 287 63,254 --------- -------- --------- End of year $ 70,260 $ 256 $ 70,516 ========= ======== =========
The Company's SMOG and changes therein were determined in accordance with Statement of Financial Accounting Standards No. 69. Certain infor- mation concerning the assumptions used in computing SMOG and their inherent limitations are discussed below. Management believes such information is essential for a proper understanding and assessment of the data presented.
The assumptions used to compute SMOG do not necessarily reflect management's expectations of actual revenues to be derived from those reserves nor their present worth. Assigning monetary values to the reserve quantity estimation process does not reduce the subjective and ever-changing nature of such reserve estimates. Additional subjectivity occurs when determining present values because the rate of producing the reserves must be estimated. In addition to errors inherent in predicting the future, variations from the expected production rate could result from factors outside of management's control, such as unintentional delays in development, environmental concerns or changes in prices or regulatory controls. Also, the reserve valuation assumes that all reserves will be disposed of by production. However, other factors such as the sale of reserves in place could affect the amount of cash eventually realized.
Future cash flows are computed by applying year-end prices of oil and natural gas relating to proved reserves to the year-end quantities of those reserves. Future price changes are considered only to the extent provided by contractual arrangements in existence at year-end.
Future production and development costs are computed by estimating the expenditures to be incurred in developing and producing the proved oil and natural gas reserves at the end of the year, based on continuation of existing economic conditions.
Future income tax expenses are computed by applying the appropriate year-end statutory tax rates to the future pretax net cash flows relating to proved oil and natural gas reserves less the tax basis of the Company's properties. The future income tax expenses also give effect to permanent differences and tax credits and allowances relating to the Company's proved oil and natural gas reserves.
Care should be exercised in the use and interpretation of the above data. As production occurs over the next several years, the results shown may be significantly different as changes in production performance, petroleum prices and costs are likely to occur.
As disclosed in Note 4, the Company is receiving payments from a natural gas purchaser which are subject to recoupment from future natural gas production. The amounts received will be reflected in revenues and the reserves and future net cash flows will be reduced as recoupment occurs.
Subsequent to December 31, 1994, the natural gas industry experienced a significant downturn in natural gas prices. The Company's reserves were determined at December 31, 1994 using a natural gas price of approximately $1.70 per Mcf for natural gas not subject to long-term contracts. At February 21, 1995, the natural gas prices received by the Company fell to approximately $1.41 per Mcf for natural gas not subject to long-term contracts. This decrease in natural gas prices would have had a significant effect on the SMOG value of the Company's reserves at December 31, 1994 and would have resulted in a provision to reduce the carrying value of oil and natural gas properties of approximately $3.5 million. REPORT OF INDEPENDENT ACCOUNTANTS
The Shareholders and Board of Directors Unit Corporation
We have audited the accompanying consolidated balance sheets of Unit Corporation and subsidiaries as of December 31, 1994 and 1993 and the related consolidated statements of operations, changes in shareholders' equity and cash flows and the related financial statement schedule for each of the three years in the period ended December 31, 1994. These financial statements and financial statement schedule are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements and financial statement schedule based on our audits.
We conducted our audits in accordance with generally accepted auditing standards. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of Unit Corporation and subsidiaries as of December 31, 1994 and 1993, and the con- solidated results of their operations and their cash flows for each of the three years in the period ended December 31, 1994 in conformity with generally accepted accounting principles. In addition, in our opinion, the financial statement schedule referred to above, when considered in relation to the basic financial statements taken as a whole, presents fairly, in all material respects, the information required to be included therein.
COOPERS & LYBRAND L.L.P.
Tulsa, Oklahoma February 22, 1995
Item 9.

Item 9. Changes in and Disagreements with Accountants on Accounting and - ------------------------------------------------------------------------ Financial Disclosure. - --------------------
None.
PART III
Item 10.



Item 10. Directors and Executive Officers of the Registrant - ------------------------------------------------------------
The table below and accompanying footnotes set forth certain infor- mation concerning each executive officer of the Company. Unless otherwise indicated, each has served in the positions set forth for more than five years. Executive officers are elected for a term of one year. There are no family relationships between any of the persons named.
NAME AGE POSITION - ---------------- --- ----------------------------------------
King P. Kirchner 67 Chairman of the Board, Chief Executive Officer and Director
John G. Nikkel 60 President, Chief Operating Officer and Director
Earle Lamborn 60 Senior Vice President, Drilling and Director
Philip M. Keeley 53 Senior Vice President, Exploration and Production
Larry D. Pinkston 40 Vice President, Treasurer and Chief Financial Officer
Mark E. Schell 37 General Counsel and Secretary ________
Mr. Kirchner, a co-founder of the Company, has been the Chairman of the Board and a director since 1963 and was President until November 1983. Mr. Kirchner is a Registered Professional Engineer within the State of Oklahoma, having received degrees in Mechanical Engineering from Oklahoma State University and in Petroleum Engineering from the University of Oklahoma.
Mr. Nikkel joined the Company in 1983 as its President and a director. From 1976 until January 1982 when he co-founded Nike Exploration Company, Mr. Nikkel was an officer and director of Cotton Petroleum Corporation, serving as the President of that Company from 1979 until his departure. Prior to joining Cotton, Mr. Nikkel was employed by Amoco Production Company for 18 years, last serving as Division Geologist for Amoco's Denver Division. Mr. Nikkel presently serves as President and a director of Nike
Exploration Company. Mr. Nikkel received a Bachelor of Science degree in Geology and Mathematics from Texas Christian University.
Mr. Lamborn has been actively involved in the oil field for over 40 years, joining the Company's predecessor in 1952 prior to it becoming a publicly-held corporation. He was elected Vice President, Drilling in 1973 and to his current position as Senior Vice President and Director in 1979.
Mr. Keeley joined the Company in November 1983 as a Senior Vice President, Exploration and Production. Prior to that time, Mr. Keeley co- founded (with Mr. Nikkel) Nike Exploration Company in January 1982 and serves as Executive Vice President and a director of that company. From 1977 until 1982, Mr. Keeley was employed by Cotton Petroleum Corporation, serving first as Manager of Land and from 1979 as Vice President and a director. Before joining Cotton, Mr. Keeley was employed for four years by Apexco, Inc. as Manager of Land and prior thereto he was employed by Texaco, Inc. for nine years. He received a Bachelor of Arts degree in Petroleum Land Management from the University of Oklahoma.
Mr. Pinkston joined the Company in December 1981. He had served as Corporate Budget Director and Assistant Controller prior to being appointed as Controller in February 1985. He has been Treasurer since December 1986 and was elected to the position of Vice President and Chief Financial Officer in May 1989. He holds a Bachelor of Science Degree in Accounting from East Central University of Oklahoma and is a Certified Public Accountant.
Mr. Schell joined the Company in January of 1987, as its Secretary and General Counsel. From 1979 until joining the Company, Mr. Schell was Counsel, Vice President and a member of the Board of Directors of C & S Exploration, Inc. He received a Bachelor of Science degree in Political Science from Arizona State University and his Juris Doctorate degree from the University of Tulsa Law School.
The balance of the information required in this Item 10 is incorpo- rated by reference to the Company's Proxy Statement to be filed with the Securities and Exchange Commission in connection with the Company's 1995 annual meeting of stockholders.
Item 11.

Item 11. Executive Compensation - ---------------------------------
Information required by this item is incorporated by reference to the Company's Proxy Statement to be filed with the Securities and Exchange Commission in connection with the Company's 1995 annual meeting of stockholders.
Item 12.

Item 12. Security Ownership of Certain Beneficial Owners and Management - ------------------------------------------------------------------------
Information required by this item is incorporated by reference to the Company's Proxy Statement to be filed with the Securities and Exchange Commission in connection with the Company's 1995 annual meeting of stockholders.
Item 13.

Item 13. Certain Relationships and Related Transactions - --------------------------------------------------------
Information required by this item is incorporated by reference to the Company's Proxy Statement to be filed with the Securities and Exchange Commission in connection with the Company's 1995 annual meeting of stockholders.
PART IV
Item 14.

Item 14. Exhibits, Financial Statement Schedules and Reports on Form 8-K - -------------------------------------------------------------------------
(a) Financial Statements, Schedules and Exhibits:
1. Financial Statements: --------------------- Included in Part II of this report: Consolidated Balance Sheets as of December 31, 1994 and 1993 Consolidated Statements of Operations for the years ended December 31, 1994, 1993 and 1992 Consolidated Statements of Changes in Shareholders' Equity for the years ended December 31, 1994, 1993 and 1992 Consolidated Statements of Cash Flows for the years ended December 31, 1994, 1993 and 1992 Notes to Consolidated Financial Statements Report of Independent Accountants
2. Financial Statement Schedules: ------------------------------ Included in Part IV of this report for the years ended December 31, 1994, 1993 and 1992: Schedule VIII - Valuation and Qualifying Accounts and Reserves
Other schedules are omitted because of the absence of conditions under which they are required or because the required information is included in the consolidated financial statements or notes thereto.
The exhibit numbers in the following list correspond to the numbers assigned such exhibits in the Exhibit Table of Item 601 of Regulation S-K.
3. Exhibits: -------- 2 Certificate of Ownership and Merger of the Company and Unit Drilling Co., dated February 22, 1979 (filed as an Exhibit to the Company's Registration Statement No. 2-63702, which is incorporated herein by reference).
3.1.1 Certificate of Incorporation (filed as Exhibit 3.2 to the Company's Registration Statement on Form S-4 as S.E.C. File No. 33-7848, which is incorporated herein by reference).
3.1.2 Certificate of Amendment of Certificate of Incorporation dated July 21, 1988 (filed as an Exhibit to the Company's Annual Report under cover of Form 10-K for the year ended December 31, 1989, which is incorporated herein by reference).
3.1.3 Restated Certificate of Incorporation of Unit Corporation dated February 2, 1994 (filed as an Exhibit to the Company's Annual Report under cover of Form 10-K for the year ended December 31, 1993, which is incorporated herein by reference).
3.2.1 By-Laws (filed as Exhibit 3.5 to the Company's Registration Statement of Form S-4 as S.E.C. File No. 33-7848, which is incorporated herein by reference).
3.2.2 Amended and Restated By-Laws, dated June 29, 1988 (filed as an Exhibit to the Company's Annual Report under cover of Form 10-K for the year ended December 31, 1989, which is incorporated herein by reference).
4.2.1 Form of Warrant Agreement between the Company and the Warrant Agent (filed as Exhibit 4.1 to the Company's Registration statement on Form S-2 as S.E.C. File No. 33-16116, which is incorporated herein by reference).
4.2.2 Form of Warrant (filed as Exhibit 4.3 to the Company's Registration Statement of Form S-2 as S.E.C. File No. 33-16116, which is incorporated herein by reference).
4.2.3 Form of Common Stock Certificate (filed as Exhibit 4.2 on Form S-2 as S.E.C. File No. 33-16116, which is incorporated herein by reference).
4.2.4 First Amendment to Warrant Agreement (filed as an Exhibit to the Company's Quarterly Report under cover of Form 10-Q for the quarter ended March 31, 1992, which is incorporated herein by reference).
4.2.5 Second Amendment to Warrant Agreement (filed as an Exhibit to the Company's Quarterly Report under cover of Form 10-Q for the quarter ended March 31, 1994, which is incorporated herein by reference).
10.1.14 Amended and Restated Credit Agreement dated as of January 17, 1992 by and between Unit Corporation and Bank of Oklahoma N.A., F&M Bank and Trust Company, Fourth National Bank of Tulsa and Western National Bank of Tulsa (filed as an Exhibit to the Company's Annual Report under cover of Form 10-K for the year ended December 31, 1991, which is incorporated herein by reference).
10.1.16 First Amendment to Amended and Restated Credit Agreement dated as of May 1, 1992, by and between Unit Corporation and Bank of Oklahoma, N.A., F&M Bank and Trust Company, Fourth National Bank of Tulsa, and Western National Bank of Tulsa (filed as an Exhibit to the Company's Quarterly Report under cover of Form 10-Q for the quarter ended June 30, 1992, which is incorporated herein by reference).
10.1.17 Second Amendment to Amended and Restated Credit Agreement, dated March 3, 1993 and effective as of March 1, 1993, by and between Unit Corporation and Bank of Oklahoma, N.A., F&M Bank and Trust Company, Fourth National Bank of Tulsa, and Western National Bank of Tulsa (filed as an Exhibit to the Company's Quarterly Report under cover of Form 10-Q for the quarter ended March 31, 1993, which is incorporated herein by reference).
10.1.18 Third Amendment to Amended and Restated Credit Agreement effective as of March 31, 1994, by and between Unit Corporation and Bank of Oklahoma, N.A., F&M Bank and Trust Company, Bank IV, Oklahoma, N.A. and American National Bank and Trust Company of Shawnee (filed as an Exhibit to the Company's Quarterly Report under cover of Form 10-Q for the quarter ended March 31, 1994, which is incorporated herein by reference).
10.1.19 Fourth Amendment to Amended and Restated Credit Agreement dated as of December 12, 1994, by and between Unit Corporation and Bank of Oklahoma, N.A., F&M Bank and Trust Company, Bank IV, Oklahoma, N.A. and American National Bank and Trust Company of Shawnee (filed as an Exhibit in Form 8-K dated December 15, 1994, which is incorporated herein by reference).
10.2.2 Unit 1979 Oil and Gas Program Agreement of Limited Partnership (filed as Exhibit I to Unit Drilling and Exploration Company's Registration Statement on Form S-1 as S.E.C. File No. 2-66347, which is incorporated herein by reference).
10.2.10 Unit 1984 Oil and Gas Program Agreement of Limited Partnership (filed as an Exhibit 3.1 to Unit 1984 Oil and Gas Program's Registration Statement Form S-1 as S.E.C. File No. 2-92582, which is incorporated herein by reference).
10.2.11 Unit 1984 Employee Oil and Gas Program Agreement of Limited Partnership (filed as an Exhibit 3.1 to Unit 1984 Employee Oil and Gas Program's Registration Statement of Form S-1 as S.E.C. File No. 2-89678, which is incorporated herein by reference).
10.2.12 Unit 1985 Employee Oil and Gas Limited Partnership Agreement of Limited Partnership (filed as an Exhibit 3.1 to Unit 1985 Employee Oil and Gas Limited Partnership's Registration Statement on Form S-1 as S.E.C. File No. 2-95068, which is incorporated herein by reference).
10.2.13 Unit 1986 Employee Oil and Gas Limited Partnership Agreement of Limited Partnership (filed as an Exhibit 10.11 to the Company's Registration Statement on Form S-4 as S.E.C. File No. 33-7848, which is incorporated herein by reference).
10.2.14 Unit 1987 Employee Oil and Gas Limited Partnership Agreement of Limited Partnership (filed as an Exhibit to the Company's Annual Report under cover of Form 10-K for the year ended December 31, 1989, which is incorporated herein by reference).
10.2.15 Unit 1988 Employee Oil and Gas Limited Partnership Agreement of Limited Partnership (filed as an Exhibit to the Company's Annual Report under cover of Form 10-K for the year ended December 31, 1989, which is incorporated herein by reference).
10.2.16 Unit 1989 Employee Oil and Gas Limited Partnership Agreement of Limited Partnership (filed as an Exhibit to the Company's Annual Report under cover of Form 10-K for the year ended December 31, 1989, which is incorporated herein by reference).
10.2.17 Unit 1990 Employee Oil and Gas Limited Partnership Agreement of Limited Partnership (filed as an Exhibit to the Company's Annual Report under cover of Form 10-K for the year ended December 31, 1990, which is incorporated herein by reference).
10.2.18 Unit 1991 Employee Oil and Gas Limited Partnership Agreement of Limited Partnership (filed as an Exhibit to the Company's Annual Report under cover of Form 10-K for the year ended December 31, 1991, which is incorporated herein by reference).
10.2.19 Unit 1992 Employee Oil and Gas Limited Partnership Agreement of Limited Partnership (filed as an Exhibit to the Company's Annual Report under cover of Form 10-K for the year ended December 31, 1992, which is incorporated herein by reference).
10.2.20 Unit 1993 Employee Oil and Gas Limited Partnership Agreement of Limited Partnership (filed as an Exhibit to the Company's Annual Report under cover of Form 10-K for the year ended December 31, 1992, which is incorporated herein by reference).
10.2.21* Unit Drilling and Exploration Employee Bonus Plan (filed as Exhibit 10.16 to the Company's Registration Statement on Form S-4 as S.E.C. File No. 33-7848, which is incorporated herein by reference).
10.2.22* The Company's Stock Option Plan (filed on the Company's Registration Statement of Form S-8 as S.E.C. File No. 33-44103, which is incorporated herein by reference)
10.2.23* Unit Corporation Non-Employee Directors' Stock Option Plan (filed on Form S-8 as S.E.C. File No. 33-49724, which is incorporated herein by reference).
10.2.24* Unit Corporation Employees' Thrift Plan (filed on Form S-8 as S.E.C. File No. 33-53542, which is incorporated herein by reference).
10.2.25 Unit Consolidated Employee Oil and Gas Limited Partnership Agreement. (filed as an Exhibit to the Company's Annual Report under cover of Form 10-K for the year ended December 31, 1993, which is incorporated herein by reference).
10.2.26 Unit 1994 Employee Oil and Gas Limited Partnership Agreement of Limited Partnership (filed as an Exhibit to the Company's Annual Report under cover of Form 10-K for the year ended December 31, 1993, which is incorporated herein by reference).
10.2.27* Unit Corporation Salary Deferral Plan (filed as an Exhibit to the Company's Annual Report under cover of Form 10-K for the year ended December 31, 1993, which is incorporated herein by reference).
10.2.28 Unit 1995 Employee Oil and Gas Limited Partnership Agreement of Limited Partnership (filed herewith).
10.3.4 Director and Officers Insurance and Company Reimbursement Policy (filed as an Exhibit to the Company's Quarterly Report under cover of Form 10-Q for the quarter ended March 31, 1993, which is incorporated herein by reference).
10.5 Acquisition and Development Agreement, dated September 26, 1991, between Registrant and Municipal Energy Agency of Nebraska (filed on Form 8-K dated September 30, 1991, which is incorporated herein by reference).
10.6 Purchase and Sale Agreement, dated May 22, 1992, between Esco Exploration, Inc. and Aleco Production Company (as "Seller") and Unit Petroleum Company (a "Buyer") and Helmerich & Payne, Inc. (a "Buyer") (filed on Form 8-K dated May 21, 1992, which is incorporated herein by reference).
10.7 Asset Purchase Agreement, dated as of November 28, 1994, between the Registrant and Patrick Petroleum Corp of Michigan and American National Petroleum Company (filed as an Exhibit in Form 8-K dated December 15, 1994, which is incorporated herein by reference).
22.1 Subsidiaries of the Registrant (filed herewith).
24.1 Consent of Independent Accountants (filed herewith).
27 Financial Data Schedules (filed herewith).
* Indicates a management contract or compensatory plan identified pursuant to the requirements of Item 14 of Form 10-K.
(b) Reports on Form 8-K:
On December 28, 1994 (as amended by Form 8-K/A filed February 24, 1995), the Company filed a report on Form 8-K under Item 2 and Item 5 reporting the purchase of certain oil and natural gas wells located in Oklahoma, Texas, New Mexico and Louisiana from Patrick Petroleum Corp of Michigan and American National Petroleum Company and the amending of the Company's credit agreement.
Schedule VIII
UNIT CORPORATION AND SUBSIDIARIES
VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
Allowance for Doubtful Accounts:
Additions Balance Balance at charged to Deductions at beginning costs & & net end of Description of period expenses write-offs period ----------- --------- -------- --------- -------- (In thousands) Year ended December 31, 1994 $ 411 $ - $ 122 $ 289 ======== ======== ======== ======== Year ended December 31, 1993 $ 376 $ - $ (35) $ 411 ======== ======== ======== ======== Year ended December 31, 1992 $ 170 $ 200 $ (6) $ 376 ======== ======== ======== ========
Deferred Tax Asset Valuation Allowance:
Balance at Balance at beginning end of Description of period Additions Deductions period ----------- --------- -------- --------- -------- (In thousands) Year ended December 31, 1994 $ 8,218 $ - $ 1,795 $ 6,423 ======== ======== ======== ======== Year ended December 31, 1993 $ 12,245 $ - $ 4,027 $ 8,218 ======== ======== ======== ======== Year ended December 31, 1992 $ 12,905(1) $ - $ 660 $ 12,245 ======== ======== ======== ========
___________
(1) Represents initial valuation allowance recorded at the date of adoption of Statement of Financial Accounting Standard No. 109.
SIGNATURES Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
UNIT CORPORATION DATE: March 21, 1995 By: /s/ John G. Nikkel -------------- --------------------------- JOHN G. NIKKEL President and Chief Operating Officer
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the Registrant and in the capacities indicated on the 21st day of March, 1995. Name Title /s/ King P. Kirchner - ------------------------------- Chairman of the Board and Chief KING P. KIRCHNER Executive Officer, Director
/s/ John G. Nikkel - ------------------------------- President and Chief Operating JOHN G. NIKKEL Officer, Director
/s/ Earle Lamborn - ------------------------------- Senior Vice President, Drilling, EARLE LAMBORN Director
/s/ Larry D. Pinkston - ------------------------------- Vice President, Chief Financial LARRY D. PINKSTON Officer and Treasurer
/s/ Stanley W. Belitz - ------------------------------- Controller STANLEY W. BELITZ
/s/ Don Bodard - ------------------------------- Director DON BODARD
/s/ Don Cook - ------------------------------- Director DON COOK
/s/ William B. Morgan - ------------------------------- Director WILLIAM B. MORGAN
/s/ John S. Zink - ------------------------------- Director JOHN S. ZINK
/s/ John H. Williams - ------------------------------- Director JOHN H. WILLIAMS
EXHIBIT INDEX -----------------------
Exhibit No. Description Page ------- ----------------------------------------------- -----
10.2.28 Unit 1995 Employee Oil and Gas Limited Partnership Agreement of Limited Partnership.
22.1 Subsidiaries of the Registrant.
24.1 Consent of Independent Accountants.
27 Financial Data Schedule