-----BEGIN PRIVACY-ENHANCED MESSAGE----- Proc-Type: 2001,MIC-CLEAR Originator-Name: webmaster@www.sec.gov Originator-Key-Asymmetric: MFgwCgYEVQgBAQICAf8DSgAwRwJAW2sNKK9AVtBzYZmr6aGjlWyK3XmZv3dTINen TWSM7vrzLADbmYQaionwg5sDW3P6oaM5D3tdezXMm7z1T+B+twIDAQAB MIC-Info: RSA-MD5,RSA, GXXhPQFQyMQ5N74K4F4BdCGegWag3ID8ia/dGTNR87xWACGcLol6qgzHjPpSy9Ad s+luAkXKlJEefoNve0MY1w== 0000798949-96-000002.txt : 19960320 0000798949-96-000002.hdr.sgml : 19960320 ACCESSION NUMBER: 0000798949-96-000002 CONFORMED SUBMISSION TYPE: 10-K PUBLIC DOCUMENT COUNT: 5 CONFORMED PERIOD OF REPORT: 19951231 FILED AS OF DATE: 19960319 SROS: NASD SROS: NYSE FILER: COMPANY DATA: COMPANY CONFORMED NAME: UNIT CORP CENTRAL INDEX KEY: 0000798949 STANDARD INDUSTRIAL CLASSIFICATION: DRILLING OIL & GAS WELLS [1381] IRS NUMBER: 731283193 STATE OF INCORPORATION: DE FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 10-K SEC ACT: 1934 Act SEC FILE NUMBER: 001-09260 FILM NUMBER: 96536161 BUSINESS ADDRESS: STREET 1: 1000 KENSINGTON CENTRE STREET 2: 7130 SOUTH LEWIS CITY: TULSA STATE: OK ZIP: 74136 BUSINESS PHONE: 9184937700 10-K 1 F O R M 1 0 - K SECURITIES AND EXCHANGE COMMISSION Washington, D.C. 20549 (Mark One) [X] ANNUAL REPORT PURSUANT TO SECTION 13 or 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 [FEE REQUIRED] For the fiscal year ended December 31, 1995 OR [ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 [NO FEE REQUIRED] For the transition period from ________ to _________ [Commission File Number 1-9260] U N I T C O R P O R A T I O N (Exact Name of Registrant as Specified in its Charter) Delaware 73-1283193 (State of Incorporation) (I.R.S. Employer Identification No.) 1000 Kensington Tower 7130 South Lewis Tulsa, Oklahoma 74136 (Address of Principal Executive Offices) (Zip Code) Registrant's Telephone Number, Including Area Code (918) 493-7700 ++++++++++++++++++++++++++++++++ SECURITIES REGISTERED PURSUANT TO SECTION 12(b) OF THE ACT: Name of each exchange Title of each class on which registered Common Stock, par value New York Stock Exchange $.20 per share SECURITIES REGISTERED PURSUANT TO SECTION 12(g) OF THE ACT: Warrants to Purchase Shares of Common Stock (Title of Class) Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes X No Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (Section 229.405 of this chapter) is not contained herein, and will not be contained, to the best of registrant's knowledge, in definitive proxy or in formation statements incorporated by reference in PART III of this Form 10-K or any amendment to this Form 10-K. Aggregate Market Value of the Voting Stock Held By Non-affiliates on March 13, 1996 - $69,030,808 Number of Shares of Common Stock Outstanding on March 13, 1996 - 21,009,635 DOCUMENTS INCORPORATED BY REFERENCE 1. Portions of Registrant's Proxy Statement with respect to the Annual Meeting of Stockholders to be held May 1, 1996 are incorporated by reference in Part III. Exhibit Index - See Page 72 FORM 10-K UNIT CORPORATION TABLE OF CONTENTS PART I Item 1. Business............................................. 1 Item 2. Properties........................................... 1 Item 3. Legal Proceedings.................................... 17 Item 4. Submission of Matters to a Vote of Security Holders.. 17 PART II Item 5. Market for the Registrant's Common Equity and Related Stockholder Matters................................ 18 Item 6. Selected Financial Data.............................. 19 Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations................ 20 Item 8. Financial Statements and Supplementary Data.......... 28 Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure................ 61 PART III Item 10. Directors and Executive Officers of the Registrant... 61 Item 11. Executive Compensation............................... 62 Item 12. Security Ownership of Certain Beneficial Owners and Management..................................... 63 Item 13. Certain Relationships and Related Transactions....... 63 PART IV Item 14. Exhibits, Financial Statement Schedules and Reports on Form 8-K........................................ 64 Signatures ..................................................... 71 UNIT CORPORATION Annual Report For The Year Ended December 31, 1995 PART I Item 1. Business and Item 2. Properties - ----------------------------------------- GENERAL The Company, through its wholly owned subsidiaries, is engaged in the land contract drilling of oil and natural gas wells and the development, acquisition and production of oil and natural gas properties. The Company operates primarily in the Anadarko and Arkoma Basins, which cover portions of Oklahoma, Texas, Kansas and Arkansas and has additional producing properties located in Canada and other states, including but not limited to, New Mexico, Louisiana, North Dakota, Colorado, Wyoming, Montana, Alabama and Mississippi. The Company was originally incorporated in Oklahoma in 1963 as Unit Drilling Company. In 1979 it became a publicly held Delaware corporation and changed its name to Unit Drilling and Exploration Company ("UDE") to more accurately reflect the importance of its oil and natural gas business. In September 1986, pursuant to a merger and exchange offer, the Company acquired all of the assets and assumed all of the liabilities of UDE and six oil and gas limited partnerships for which UDE was the general partner, in exchange for shares of the Company's common stock (the "Exchange Offer"). The Company's principal executive offices are maintained at 1000 Kensington Tower, 7130 South Lewis, Tulsa, Oklahoma 74136; telephone number (918) 493-7700. The Company also has a regional office in Houston, Texas. As used herein, the term " Company" refers to Unit Corporation and at times Unit Corporation and/or one or more of its subsidiaries with respect to periods from and after the Exchange Offer and to UDE with respect to periods prior thereto. OIL AND NATURAL GAS OPERATIONS In 1979, the Company began to acquire oil and natural gas properties to diversify its source of revenues which had previously been derived from contract drilling. The development, production and sale of oil and natural gas together with the acquisition of producing properties now constitutes the largest part of the Company's operations as conducted through its wholly owned subsidiary, Unit Petroleum Company. As of December 31, 1995, the Company had 5,428 Mbbls and 108,728 MMcf of estimated proved oil and natural gas reserves, respectively. The Company's producing oil and natural gas interests, undeveloped leaseholds and related assets are locate d primarily in Oklahoma, Texas, Louisiana and New Mexico and to a lesser extent in Arkansas, North Dakota, Colorado, Wyoming, Montana, Alabama, Mississippi and Canada. As of December 31, 1995, the Company had an 1 interest in a total of 2,570 wells in the United States and served as the operator of 482 wells. The Company also had an interest in 65 wells located in Canada. The majority of the Company's development and exploration prospects are generated by its technical staff. When the Company is the operator of a property, it generally employs its own drilling rigs and the Company's own engineering staff supervises the drilling operation. The Company intends to continue the growth in its oil and natural gas operations utilizing funds generated from operations and its bank revolving line of credit. Well and Leasehold Data. The Company's oil and natural gas exploration and development drilling activities and the number of wells in which the Company had an interest, which were producing or capable of producing, were as follows for the periods indicated: Year Ended December 31, Wells drilled: 1995 1994 1993 -------------- Gross Net Gross Net Gross Net Exploratory: ------ ------ ------ ------ ------ ------ Oil.............. - - - - - - Natural gas...... - - 1 .98 1 1.00 Dry.............. - - 2 .80 1 0.10 ------ ------ ------ ------ ------ ------ Total - - 3 1.78 2 1.10 ====== ====== ====== ====== ====== ====== Development: Oil.............. 15 4.70 5 5.00 12 11.98 Natural gas...... 26 7.02 40 13.46 25 11.12 Dry.............. 6 2.27 12 7.26 8 4.29 ------ ------ ------ ------ ------ ------ Total 47 13.99 57 25.72 45 27.39 ====== ====== ====== ====== ====== ====== Oil and natural gas wells producing or capable of producing: ------------------------------------------------------------ Oil - USA........ 750 207.80 675 177.68 337 162.09 Oil - Canada..... - - - - - - Gas -USA........ 1,820 232.03 1,089 179.99 709 141.76 Gas - Canada..... 65 1.63 61 1.53 61 1.53 ------ ------ ------ ------ ------ ------ Total 2,635 441.46 1,825 359.20 1,107 305.38 ====== ====== ====== ====== ====== ====== 2 The following table summarizes the Company's acreage as of the end of each of the years indicated: Developed Acreage Undeveloped Acreage Gross Net Gross Net ------- ------- ------- ------- 1995 ---- USA 548,674 117,403 24,810 12,866 Canada 31,360 784 - - ------- ------- ------- ------- Total 580,034 118,187 24,810 12,866 ======= ======= ======= ======= 1994 ---- USA 340,241 100,732 21,514 11,540 Canada 31,360 784 - - ------- ------- ------- ------- Total 371,601 101,516 21,514 11,540 ======= ======= ======= ======= 1993 ---- USA 246,115 86,013 28,738 18,021 Canada 31,360 784 - - ------- ------- ------- ------- Total 277,475 86,797 28,738 18,021 ======= ======= ======= ======= 3 Price and Production Data. The average sales price, oil and natural gas production volumes and average production cost per equivalent Mcf (1 barrel (Bbl) of oil = 6 thousand cubic feet (Mcf) of natural gas) of production, experienced by the Company, for the periods indicated were as follows: Year Ended December 31, 1995 1994 1993 Average sales price per barrel -------- -------- -------- of oil produced: USA $ 16.65 $ 15.13 $ 16.73 Canada $ - $ - $ - Average sales price per Mcf of natural gas produced: USA $ 1.61 $ 1.86 $ 2.07 Canada $ 0.98 $ 1.27 $ 0.96 Oil production (Mbbls): USA 577 406 397 Canada - - - -------- -------- -------- Total 577 406 397 ======== ======== ======== Natural gas production (MMcf): USA 12,005 9,606 7,435 Canada 54 53 70 -------- -------- -------- Total 12,059 9,659 7,505 ======== ======== ======== Average production expense per equivalent Mcf: USA $ 0.64 $ 0.58 $ 0.66 Canada $ 0.30 $ 0.37 $ 0.21 Reserves. The following table sets forth the estimated proved developed and undeveloped oil and natural gas reserves of the Company at the end of each of the years indicated: Year Ended December 31, 1995 1994 1993 ------- ------- ------- Oil (Mbbls): USA 5,428 4,308 3,304 Canada - - - ------- ------- ------- Total 5,428 4,308 3,304 ======= ======= ======= Natural gas (MMcf): USA 107,950 92,566 71,379 Canada 778 794 861 ------- ------- ------- Total 108,728 93,360 72,240 ======= ======= ======= Further information relating to oil and natural gas operations is presented in Notes 1, 4, 10 and 12 of Notes to Consolidated Financial Statements set forth in Item 8 hereof. 4 LAND CONTRACT DRILLING OPERATIONS Unit Drilling Company, a wholly owned subsidiary of the Company, engages in the land drilling of oil and natural gas wells for a wide range of customers. A land drilling rig consists, in part, of engines, drawworks or hoists, derrick or mast , pumps to circulate the drilling fluid, blowout preventers and drill pipe. An active maintenance and replacement program during the life of a drilling rig permits upgrading of components on an individual basis. Over the life of a typical rig, due to the normal wear and tear of operating up to 24 hours a day, several of the major components, such as engines, mud pumps and drill pipe, are replaced or rebuilt on a periodic basis as required, while other components, such as the substructure, mast and drawworks, can be utilized for extended periods of time with proper maintenance. The Company also owns additional equipment used in the operation of its rigs, including large air compressors, trucks and other support equipment. As of December 31, 1995, the Company owns 22 operational drilling rigs with rated depth capacities ranging from 8,000 to 25,000 feet. A majority of the Company's rigs are located in the Anadarko and Arkoma Basins of Oklahoma and Texas. In July 1994, the Company began moving rigs to the South Texas basin region thereby expanding the Company's market area for its contract drilling services and in December 1995, the contract drilling operations opened a regional office in Houston, Texas. In the Anadarko and Arkoma Basins the Company's primary focus is on the utilization of its medium depth rigs which have a depth range of 8,000 to 14,000 feet. These medium depth rigs are suited to the contract drilling currently undertaken by operators in these two basins. At present, the Company does not have a shortage of rig equipment. However, certain grades of drill pipe are reaching the end of their useful life and the Company is increasing its drill pipe acquisitions to maintain current utilization levels. At December 31, 1995, the Company had orders for 75,000 feet of drill pipe of various grades scheduled for delivery through the first half of 1996. There is no assurance that sufficient supplies of such equipment will be readily available in the future and, given the general decline experienced in the land contract drilling industry over the past decade, the Company's ability to utilize its full complement of drilling rigs, should economic conditions improve rapidly, will be restricted due to a lack of equipment, drill pipe and qualified labor not only within the Company but in the industry as a whole. 5 The following table sets forth, for each of the periods indicated, certain data concerning the Company's contract drilling operations: Year Ended December 31, 1995 1994 1993 1992 1991 ---- ---- ---- ---- ---- Number of operational rigs owned at end of period 22 25 25 26 26 Average number of rigs utilized(1) 10.9 9.5 8.0 5.5 9.1 Number of wells drilled 111 95 84 56 92 Total footage drilled (feet in 1000's) 1,196 1,027 788 527 736 - ------------------- (1) Utilization rates are based on a 365-day year. A rig is considered utilized when it is operating or being moved, assembled or dismantled under contract. As of March 13, 1996, 14 of the Company's 22 drilling rigs were operating under contract. The following table sets forth, as of March 13, 1996, the type and approximate depth capability of each of the Company's drilling rigs: Depth Capability Type (feet) ---- ---------- U-15 Unit Rig.................................. 11,000 U-15 Unit Rig.................................. 11,000 U-15 Unit Rig.................................. 11,000 U-15 Unit Rig.................................. 11,000 Gardner Denver 800............................. 15,000 Gardner Denver 700............................. 15,000 BDW 800-M1..................................... 15,000 Gardner Denver 700............................. 15,000 Mid-Continent 914-C............................ 20,000 U-15 Unit Rig.................................. 11,000 Brewster N-75.................................. 15,000 Gardner Denver 500............................. 12,000 Gardner Denver 700............................. 15,000 Gardner Denver 700............................. 15,000 Gardner Denver 700............................. 15,000 Brewster N-75.................................. 15,000 BDW 1350-M..................................... 20,000 SU-15 North Texas Machine...................... 12,000 SU-15 North Texas Machine...................... 12,000 National 110-E................................. 20,000 Continental Emsco C-1-E........................ 20,000 Gardner Denver 1500-E.......................... 25,000 6 For the past several years, the Company's contract drilling services have encountered significant competition due to depressed levels of activity in contract drilling. While the Company's drilling operations showed improvement in 1995, this competition will, for the foreseeable future, continue to adversely affect the Company. Drilling Contracts. Most of the Company's drilling contracts are obtained through competitive bidding. Generally, the contracts are for a single well with the terms and rates varying depending upon the nature and duration of the work, the equipment and services supplied and other matters. The contracts obligate the Company to pay certain operating expenses, including wages of drilling personnel, maintenance expenses and incidental rig supplies and equipment. Usually, the contracts are subject to termination by the customer on short notice upon payment of a fee. The Company generally indemnifies its customers against certain types of claims by the Company's employees and claims arising from surface pollution caused by spills of fuel, lubricants and other solvents within the control of the Company. Such customers generally indemnify the Company against claims arising from other surface and subsurface pollution other than claims resulting from the Company's gross negligence. The contracts may provide for compensation to the Company on a day rate, footage or turnkey basis with additional compensation for special risks and unusual conditions. Under daywork contracts, the Company provides the drilling rig with the required personnel to the operator who supervises the drilling of the contracted well. Compensation to the Company is based on a negotiated rate per day as the rig is utilized. Footage contracts usually require the Company to bear some of the drilling costs in addition to providing the rig. The Company is compensated on a rate per foot drilled basis upon completion of the well. Under turnkey contracts, the Company contracts to drill a well to a specified depth and provides most of the equipment and services required. The Company bears the risk of drilling the well to the contract depth and is compensated when the contract provisions have been satisfied. Turnkey drilling operations, in particular, might result in losses if the Company underestimates the costs of drilling a well or if unforeseen events occur. Because the proportion of turnkey drilling is currently dictated by market condition s and the desires of customers using the Company's services, the Company is unable to predict whether the portion of drilling conducted on a turnkey basis will increase or decrease in the future. For 1995 turnkey revenue represented approximately 17 percent of the Company's contract drilling revenues. To date, the Company has not experienced significant losses in performing turnkey contracts. Customers. During the fiscal year ended December 31, 1995, 10 contract drilling customers accounted for approximately 19 percent of the Company's total revenues and approximately 1 percent of the Company's total revenues were generated by drilling on oil and natural gas properties of which the Company was the operator (including properties owned by limited partnerships for which the Company acted as general partner). Such drilling was pursuant to contracts containing terms and conditions comparable to those contained in the Company's customary drilling contracts with non-affiliated operators. 7 Further information relating to contract drilling operations is presented in Notes 1 and 10 of Notes to Consolidated Financial Statements set forth in Item 8 hereof. NATURAL GAS MARKETING Prior to April 1995, the Company marketed natural gas from wells located primarily in Oklahoma and Texas and to a lesser extent in Arkansas, Kansas, Louisiana, Mississippi and New Mexico. Effective April 1, 1995 the Company completed a business combination between the Company's natural gas marketing operations and a third party also involved in natural gas marketing activities forming a new company called GED Gas Services, L.L.C. ("GED"). The Company owns a 34 percent interest in GED. Effective November 1, 1995, GED sold its natural gas marketing operations to a third party. This sale removed the Company from the third party natural gas marketing business. The creation of GED and the subsequent sale of the marketing operations did not adversely affect the Company's drilling and oil and natural gas exploration operations or the profitability of the Company as a whole. The disposition of the Company's natural gas marketing segment has been accounted for as a discontinued operation and accordingly, the 1995 and prior year financial information has been restated to reflect this treatment. MARKETING OF OIL AND NATURAL GAS PRODUCTION The Company's revenue and profitability are substantially dependent upon prevailing prices for natural gas and crude oil. These prices vary based on factors beyond the control of the Company, including the extent of domestic production and importation of crude oil and natural gas, the proximity and capacity of oil and natural gas pipelines, the marketing of competitive fuels, general fluctuations in the supply and demand for oil and natural gas, the effect of federal and state regulation of production, refining, transportation and sales, the use and allocation of oil and natural gas and their substitute fuels and general national and worldwide economic conditions. In addition, natural gas spot prices received by the Company are influenced by weather conditions impacting the continental United States. The Company's oil and condensate production is sold at or near the Company's wells under purchase contracts at prevailing prices in accordance with arrangements which are customary in the oil industry. The Company's natural gas production is sold at the wellhead to intrastate and interstate pipelines as well as to independent marketing firms under contracts with original terms ranging from one month to 20 years. Most of these contracts contain provisions for readjustment of price, termination and other terms which are customary in the industry. The worldwide supply of oil has been largely dependent upon rates of production of foreign reserves. Although the demand for oil has increased slightly in the United States, imports of foreign oil continue to increase. Future domestic oil prices will depend largely upon the actions of foreign producers with respect to rates of production and it is virtually impossible to predict what actions those producers will take in the future. Prices may also be affected by political, social and other factors relating to the Middle East. 8 In view of the many uncertainties affecting the supply and demand for oil and natural gas, the Company is unable to predict future oil and natural gas prices or the overall effect, if any, that a decline in demand or oversupply of such products would have on the Company. COMPETITION All lines of business in which the Company engages are highly competitive. Competition in land contract drilling traditionally involves such factors as price, efficiency, condition of equipment, availability of labor and equipment, reputation and customer relations. Some of the Company's competitors in the land contract drilling business are substantially larger than the Company and have appreciably greater financial and other resources. As a result of the decrease in demand for land contract drilling services over the past decade, a surplus of certain types of drilling rigs currently exists while inventories of certain components such as drill pipe have been depleted from continued use. Accordingly, the competitive environment within which the Company's drilling operations presently operates is uncertain and extremely price oriented. The Company's oil and natural gas operations likewise encounter strong competition from major oil companies, independent operators, and others. Many of these competitors have appreciably greater financial, technical and other resources and a re more experienced in the exploration for and production of oil and natural gas than the Company. OIL AND NATURAL GAS PROGRAMS The Company currently serves as a general partner to 4 oil and gas limited partnerships and 7 employee oil and gas limited partnerships. The employee partnerships acquire an interest fixed annually ranging from 5% to 15% of the Company's interest in most oil and natural gas drilling activities and purchases of producing oil and natural gas properties participated in by the Company. The limited partners in the employee partnerships are either employees or directors of the Company or its subsidiaries. Under the terms of the partnership agreements of each limited partnership, the general partner, which in each case is Unit Petroleum Company, has broad discretionary authority to manage the business and operations of the partnership, including the authority to make decisions on such matters as the partnership's participation in a drilling location or a property acquisition, the partnership's expenditure of funds and the distribution of funds to partners. Because the business activities of the limited partners on the one hand, and the general partner on the other hand, are not the same, conflicts of interest will exist and it is not possible to eliminate entirely such conflicts. Additionally, conflicts of interest may arise where t he Company is the operator of an oil and natural gas well and also provides contract drilling services. Although the Company has no formal procedures for resolving such conflicts, the Company believes it fulfills its responsibility to each contracting party and complies fully with the terms of the agreements which regulate such conflicts. 9 Depending upon a number of factors, including the performance of the drilling programs and general economic and capital market conditions, the Company may form additional drilling and/or producing property acquisition programs in the future. EMPLOYEES As of March 13, 1996, the Company had approximately 225 employees in its land contract drilling operations, 64 employees in its oil and natural gas operations and 23 in its general corporate area. None of the Company's employees are represented by a union or labor organization nor have the Company's operations ever been interrupted by a strike or work stoppage. The Company considers relations with its employees to be satisfactory. OPERATING AND OTHER RISKS The Company's land contract drilling and oil and natural gas operations are subject to a variety of oil field hazards such as fire, explosion, blowouts, cratering and oil spills or certain other types of possible surface and subsurface pollution, any of which can cause personal injury and loss of life and severely damage or destroy equipment, suspend drilling operations and cause substantial damage to surrounding areas or property of others. As protection against some, but not all, of these operating hazards, the Company maintains broad insurance coverage, including all-risk physical damage, employer's liability and comprehensive general liability. In all states in which the Company operates except Oklahoma, the Company maintains worker's compensation insurance for losses exceeding $50,000. In Oklahoma, starting in August 1991, the Company elected to become self insured. In consideration therewith, the Company purchased an excess liability reinsurance policy. The Company believes that to the extent reasonably practicable such insurance coverages are adequate. The Company's insurance policies do not, however, provide protection against revenue losses incurred by reason of business interruptions caused by the destruction or damage of major items of equipment nor certain types of hazards such as specific types of environmental pollution claims. In view of the difficulties which may be encountered in renewing such insurance at reasonable rates, no assurance can be given that the Company will be able to maintain the amount of insurance coverage which it considers adequate at reasonable rates. Moreover, loss of or serious damage to any of the Company's equipment, although adequately covered by insurance, could have an adverse effect upon the Company's earning capacity. The Company's oil and natural gas operations are also subject to all of the risks and hazards typically associated with the search for and production of oil and natural gas. These include the necessity of expending large sums of money for the location and acquisition of properties and for drilling exploratory wells. In such exploratory work, many failures and losses may occur before any accumulation of oil or natural gas is found. If oil or natural gas is encountered, there is no assurance that it will be capable of being produced or will be in quantities sufficient to warrant development or that it can be satisfactorily marketed. The Company's future natural gas and crude oil revenues and production, and therefore cash flow and income, are highly 10 dependent upon the Company's level of success in acquiring or finding additional reserves. Without continuing reserve additions through exploration or acquisitions, the Company's reserves and production will decline over the long - -term. GOVERNMENTAL REGULATIONS The production and sale of oil and natural gas is highly affected by various state and federal regulations. All states in which the Company conducts activities impose restrictions on the drilling, production and sale of oil and natural gas, which often include requirements relating to well spacing, waste prevention, production limitations, pollution prevention and clean-up, obtaining drilling permits and similar matters. The following discussion summarizes, in part, the regulations of the United States oil and natural gas industry and is not intended to constitute a complete discussion of the many statutes, rules, regulations and governmental orders to which the Company's operations may be subject. The Company's activities are subject to existing federal and state laws and regulations governing environmental quality and pollution control. Various states and governmental agencies are considering, and some have adopted, laws and regulations regarding environmental control which could adversely affect the business of the Company. Such laws and regulations may substantially increase the costs of doing business and may prevent or delay the commencement or continuation of given operations. Compliance with such legislation and regulations, together with any penalties resulting from noncompliance therewith, will increase the cost of oil and natural gas drilling, development, production and processing. In the opinion of the Company 's management, its operations to date comply in all material respects with applicable environmental legislation and regulations; however, in view of the many uncertainties with respect to the current controls, including their duration, interpretation and possible modification, the Company can not predict the overall effect of such controls on its operations. On July 26, 1989, the Natural Gas Wellhead Decontrol Act of 1989 (the "Wellhead Decontrol Act") became effective. Under the Wellhead Decontrol Act, all remaining price and non-price controls of first sales under the NGA and NGPA were removed effective January 1, 1993. Prices for deregulated categories of natural gas fluctuate in response to market pressures which currently favor purchasers and disfavor producers. As a result of the deregulation of a greater proportion of the domestic United States natural gas market and an increase in the availability of natural gas transportation, a competitive trading market for natural gas has developed. During the past several years, the Federal Energy Regulatory Commission ("FERC") has adopted several regulations designed to accomplish a more competitive, less regulated market for natural gas. These regulations have materially affected the market for natural gas. The major elements of several of these initiatives remain subject to appellate review. 11 One of the initiatives FERC adopted was order 636. In brief, the primary requirements of Order 636 are as follows: pipelines must separate their sales and transportation services; pipelines must provide open access transportation services t hat are equal in quality for all natural gas suppliers and must provide access to storage on an open access contract basis; pipelines that provide firm sales service on May 18, 1992 must offer a "no-notice" firm transportation service under which fir m shippers may receive delivery of natural gas on demand up to their firm entitlement without incurring daily balancing and scheduling penalties; pipelines must provide all shippers with equal and timely access to information relevant to the availability of their open access transportation services; open access pipelines must allow firm transportation customers to downstream pipelines to acquire capacity on upstream pipelines held by downstream pipelines; pipelines must implement a capacity releasing program so that firm shippers can release unwanted capacity to those desiring capacity (which program replaces previous "capacity brokering" and "buy-sell" programs); existing bundled firm sales entitlement are converted to unbundled firm sales entitlement and to unbundled firm transportation rights on the effective date of a particular pipeline's blanket sales certificate; and pipeline transportation rights must be developed under the Straight Fixed Variable (SFV) method of cost classification, allocation and rate design unless the FERC permits the pipeline to use some other method. The FERC will not permit a pipeline to change the new resulting rates until the FERC accepts the pipeline's formal restructuring plans. In essence, the goal of Order 636 is to make a pipeline's position as natural gas merchant indistinguishable from that of a non-pipeline supplier. It, therefore, pushes the point or sale of natural gas by pipelines upstream, perhaps all the way to the wellhead. Order 636 also requires pipelines to give firm transportation customers flexibility with respect to receipt and delivery points (except that a firm shipper's choice of delivery point cannot be downstream of the existing primary delivery point) and to allow "no-notice" service (which means that natural gas is available not only simultaneously but also without prior nomination, with the only limitation being the customer's daily contract demand) if the pipeline offered no-not ice city-gate sales service on May 18, 1992. Thus, this separation of pipelines' sales and transportation allows non-pipeline sellers to acquire firm downstream transportation rights and thus to offer buyers what is effectively a bundled city-gate s ales service and it permits each customer to assemble a package of services that serves its individual requirements. But it also makes more difficult the coordination of natural gas supply and transportation. A corollary to these changes is that all pipelines will be permitted to sell natural gas at market-based rates. The results of these changes may be the increased availability of firm transportation and the reduction of interruptible transportation, with a corresponding reduction in the rates for off-peak and interruptible transportation. However, due to the still evolutionary nature of Order 636 and its implementation, it is not possible to project the overall potential impact on transportation rates for natural gas or market prices of natural gas. 12 The future interpretation and application by FERC of these rules and its broad authority, or of the state and local regulations by the relevant agencies, could affect the terms and availability of transportation services for transportation of natural gas to customers and the prices at which natural gas can be sold by the Company. Additional proceedings that might affect the natural gas industry are pending before the FERC and the courts. The natural gas industry historically has been very heavily regulated; therefore, there is no assurance that the less stringent regulatory approach recently pursued by the FERC and Congress will continue. Sales of petroleum liquids by the Company are not currently regulated and are made at market prices; however, the FERC is considering a proposal that could increase transportation rates for petroleum liquids. A number of legislative proposals have also been introduced in Congress and the state legislatures of various states, that, if enacted, would significantly affect the petroleum industry. Such proposals involve, among other things, the imposition of land and use controls and certain measures designed to prevent petroleum companies from acquiring assets in other energy areas. In addition, there is always the possibility that if market conditions change dramatic ally in favor of oil and natural gas producers that some new form of "windfall profits" or severance tax may be proposed and imposed upon oil or natural gas. At the present time it is impossible to predict which proposals, if any, will actually be enacted by Congress or the various state legislatures. The Company believes that it is complying with all orders and regulations applicable to its operations. However, in view of the many uncertainties with respect to the current controls, including their duration and possible modification together with any new proposals that may be enacted, the Company cannot predict the overall effect, if any, of such controls on Company operations. Certain states in which the Company operates control production from wells through regulations establishing the spacing of wells, limiting the number of days in a given month during which a well can produce and otherwise limiting the rate of allowable production. As noted above, the Company's operations are subject to numerous federal and state laws and regulations regarding the control of contamination of the environment. These laws and regulations may require the acquisition of a permit before or after drilling commences, prohibit drilling activities on certain lands lying within wilderness areas or where pollution arises and impose substantial liabilities for pollution resulting from drilling operations, particularly operations in offshore waters or on submerged lands. A past, present, or future release or threatened release of a hazardous substance into the air, water, or ground by the Company or as a result of disposal practices may subject the Company to liability under the Comprehensive Environmental Response, Compensation and Liability Act, as amended ("CERCLA"), the Resource Conservation Recovery Act ("RCRA"), the Clean Water Act, and/or similar state laws, and any regulations promulgated pursuant thereto. Under CERCLA and similar laws, the Comp any may be fully liable for the cleanup costs of a release of hazardous substances even though it contributed to only part of the release. While liability under CERCLA and similar laws may be limited under 13 certain circumstances, the limits are so high that the maximum liability would likely have a significant adverse effect on the Company. In certain circumstances, the Company may have liability for releases of hazardous substances by previous owners of Company properties. CERCLA currently excludes petroleum from its definition of "hazardous substances." However, Congress may delete this exclusion for petroleum, in which case the Company would be required to manage its petroleum production and wastes from its exploration and production activities as CERCLA hazardous substances. In addition, RCRA classifies certain oil field wastes as "non-hazardous." Congress may delete this exemption for oilfield waste, in which case the Company would have to manage much of its oilfield waste as hazardous. Additionally, the discharge or substantial threat of a discharge of oil by the Company into United States waters or onto an adjoining shoreline may subject the Company to liability under the Oil Pollution Act of 1990 and similar state laws. While liability under the Oil Pollution Act of 1990 is limited under certain circumstances, the maximum liability under those limits would still likely have a significant adverse effect on the Company. Violation of environmental legislation and regulations may result in the imposition of fines or civil or criminal penalties and, in certain circumstances, the entry of an order for the abatement of the conditions, or suspension of the activities, giving rise to the violation. The Company believes that the Company has complied with all orders and regulations applicable to its operations. However, in view of many uncertainties with respect to the current controls, including their duration and possible modification, the Company cannot predict the overall effect of such controls on such operations. Similarly, the Company cannot predict what future environmental laws may be enacted or regulations may be promulgated and what, if any, impact they would have on operations. FACTORS INFLUENCING PROJECTIONS OF FUTURE ACTIVITY In the normal course of its business, the Company, in an effort to help keep its shareholders and the public informed about the Company's operations, may, from time to time, issue certain statements, either in writing or orally, that contain or may contain forward looking information. Generally, these statements relate to projections involving the anticipated revenues to be received from the Company's oil and natural gas production, the utilization rate of its drilling rigs, growth of its oil and natural gas reserves and well performance, and the Company's anticipated bank debt. As with any forward- looking statement, these statements are subject to a number of factors that may tend to influence the accuracy of the statements and the projections upon which the statements are based. As noted elsewhere in this report, all phases of the Company's operations are subject to a number of influences outside the control of the Company, any one of which, or a combination of which, could materially affect the results of the Company's operations. In order to provide a more thorough understanding of the possible effects of some of these influences on any projections made by the Company, the 14 following discussion outlines certain factors that in the future could affect the Company's consolidated results for 1996 and beyond to differ materially from those that may be set forth in any such forward-looking statement made by or on behalf of the Company. COMMODITY PRICES The prices received by the Company for its oil and natural gas production have a direct impact on the Company's revenues, profitability and cash flow as well as its ability to meet its projected financial and operational goals. The prices for natural gas and crude oil are heavily dependent on a number of factors beyond the control of the Company, including, but not limited to, the demand for oil and/or natural gas; current weather conditions in the continental United States which can greatly influence the demand for natural gas at any given time as well as the price to be received for such gas; and the ability of current distribution systems in the United States to effectively meet the demand for oil and or natural gas at any given time, particularly in times of peak demand which may result due to adverse weather conditions. Oil prices are extremely sensitive to foreign influences that may be based on political, social or economic underpinnings, any one of which could have an immediate and significant effect on the price and supply of oil. In addition, prices of both natural gas and oil are becoming more and more influenced by trading on the commodities markets which, at times, has tended to increase the volatility associated with these prices. All these factors, especially when coupled with the fact that much of the Company's product prices are determined on a month to month basis, can, and at times do, lead to wide fluctuations in the prices received by the Company. Based upon the results of operations for the year ended December 31, 1995, the Company estimates that a change of $0.10/Mcf in the average price of natural gas and a change of $1.00/Bbl in the price of crude oil throughout such period would have resulted in approximate changes in net income of $1,100,000 and $535,000, respectively. During 1995, 95% of the natural gas volume of the Company and substantially all the crude oil volume of the Company were sold at market responsive prices. CUSTOMER DEMAND Demand for the Company's drilling services is dependent almost entirely on the needs of third parties. Based on past history, such parties' requirements are subject to a number of factors, independent of any subjective factors, that directly impact the demand for the Company's drilling rigs. These include the funds available by such companies to carry out their drilling operations during any given time period which, in turn, are often subject to downward revision based on decreases in t he then current prices of oil and natural gas. Many of the Company's customers are small to mid-size oil and natural gas companies whose drilling budgets tend to be more susceptible to the influences of current price fluctuations. Other factors that can affect the Company's ability to work its drilling rigs are the weather, which can, under adverse circumstances, delay or even cause a project to be abandoned by an operator, the competition faced by the Company in securing the award of a 15 drilling contract in a given area, the experience and recognition of the Company in a new market area, and the availability of labor to run the Company's drilling rigs. UNCERTAINTY OF OIL AND NATURAL GAS RESERVES AND WELL PERFORMANCE There are numerous uncertainties inherent in estimating quantities of proved reserves, including many factors beyond the control of the Company. Estimating quantities of proved reserves is imprecise. Such estimates are based upon certain assumptions pertaining to future production levels, future natural gas and crude oil prices, timing and amount of development expenditures and future operating costs made using currently available geologic, engineering and economic data, some or all of which may prove to be incorrect over time. As a result of changes in these assumptions that will occur in the future, and based upon further production history, results of future exploration and development activities, future natural gas and crude oil prices and other factors, the reported quantity of reserves may be subject to upward or downward revision. In addition to the foregoing, projections regarding the potential production and reserve capabilities of newly drilled and/ or completed wells are subject to additional uncertainties that may significantly influence such projections. Such wells have a very limited production history, if any, on which to base future forecasts of their capabilities. Since an established rate of production is a primary factor used by reservoir engineers to forecast oil and natural gas reserves as well as a well's production rate, the lack of this information decreases the Company's ability to accurately project such information. In addition, there are inherent risks in both the drilling and completion phases of a new well which could cause a well bore to be prematurely abandoned due either to the loss of the well bore in the physical sense or due to the costs associated with operational problems which could render further operations uneconomical. BANK BORROWING The amount of the Company's bank debt as well as its projected borrowing is, to a large extent, a function of the costs associated with the projects undertaken by the Company at any given time and the cash flow received by the Company for its oil and natural gas production. Generally, the costs incurred by the Company in its normal operations are those associated with the drilling of oil and natural gas wells, the acquisition of producing properties, and the costs associated with the maintenance of its drilling rig fleet. To some extent, these costs, particularly the first two items, are discretionary and the Company maintains a degree of control regarding the timing and/ or the need to incur the same. However, in some cases, unforeseen circumstances may arise, such as in the case of an unanticipated opportunity to acquire a large producing property package or the need to replace a costly rig component due to an unexpected loss, which could force the Company to incur increased bank debt above that which it had expected or forecast. Likewise, for many of the reasons mentioned above, the Company's cash flow may not be sufficient to cover its current cash requirements which would then require the Company to increase its bank borrowing. 16 Item 3. Legal Proceeding - ------------------------- 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. 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, 1995. 17 PART II Item 5. Market for the Registrant's Common Equity and Related Stockholder - -------------------------------------------------------------------------- Matters - ------- As of February 21, 1996, the Company had 3,225 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: 1995 1994 QUARTER High Low High Low ------- ------ ------ ------ ------ First $3 1/4 $2 1/2 $3 1/2 $2 5/8 Second $3 7/8 $2 7/8 $3 1/4 $2 3/4 Third $4 1/4 $3 1/4 $3 1/2 $2 5/8 Fourth $4 3/4 $3 1/2 $3 7/8 $2 5/8 18 Item 6. Selected Financial Data - -------------------------------- Year Ended December 31, 1995 1994 1993 1992 1991 ------- ------- ------- ------- ------- (In thousands except per share amounts) Revenues $53,074 $43,895 $38,682 $33,744 $40,232 ======= ======= ======= ======= ======= Income From Continuing Operations $ 3,751 $ 4,628 $ 3,937 $ 1,631 $ 4,164 ======= ======= ======= ======= ======= Net Income $ 3,999 (1) $ 4,794 (2) $ 3,871 $ 1,087 (3) $ 4,341 ======= ======= ======= ======= ======= Net Income Per Common Share: Continued $.18 $.22 $.19 $.08 $.20 ==== ==== ==== ==== ==== Net Income $.19 (1) $.23 (2) $.19 $.05 (3) $.21 ==== ==== ==== ==== ==== Total Assets $110,922 $103,933 $ 88,816 $ 83,960 $ 84,972 ======== ======== ======== ======== ======== Long-Term Debt $ 41,100 $ 37,824 $ 25,919 $ 22,298 $ 23,153 ======== ======== ======== ======== ======== Long-Term Portion of Natural Gas Purchaser Prepayments $ 2,109 $ 2,149 $ 4,417 $ 5,924 $ 7,626 ======== ======== ======== ======== ======== Cash Dividends Per Common Share $ - $ - $ - $ - $ - ======== ======== ======== ======== ======== ___________ (1) Includes a $635,000 gain on compressor sale, a $850,000 gain from settlement of litigation and a net $530,000 deferred tax benefit. (2) Includes a $742,000 gain on sale of a natural gas gathering system. (3) Includes a $1.5 million provision for litigation. 19 See Management's Discussion of Financial Condition and Results of Operations for a review of 1995, 1994 and 1993 activity. Item 7. Management's Discussion and Analysis of Financial Condition and - ------------------------------------------------------------------------ Results of Operations - --------------------- Financial Condition and Liquidity - --------------------------------- The Company currently has a loan agreement ("Loan Agreement"), which provides for a total commitment of $75 million, consisting of a revolving credit facility through August 31, 1997 and a term loan thereafter, maturing on August 31, 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 $50 million of the commitment is available to the Company. The Loan Agreement contains certain covenants which require the Company to maintain consolidated net worth of at least $48 million, a modified current ratio of not less than 1 to 1, a ratio of long-term debt, as defined in the Loan Agreement, to consolidated tangible net worth not greater than 1 to 1 and a ratio of total liabilities, as defined in the Loan Agreement, to consolidated tangible net worth not greater than 1.25 to 1. In addition, working capital provided by operations, as defined in the Loan Agreement, cannot be less than $12 million in any year. At December 31, 1995, borrowings under the Loan Agreement totaled $41.1 million. At February 21, 1996, borrowings under the Loan Agreement totaled $40.9 million with $7.9 million available for future borrowings. The average interest rate on the bank debt was 8.2 and 7.6 percent at December 31, 1995 and February 21, 1996, respectively. At the Company's election, any portion of the debt outstanding may be fixed at the London Interbank Offered Rate ("Libor Rate") for 30, 60, 90 or 180 days with the remainder of the outstanding debt subject to the Chase Manhattan Bank, N. A. prime rate ("Prime Rate"). During any Libor Rate funding period the Company may not pay in part or in whole the outstanding principal balance of the note to which such Libor Rate option applies. At both December 31, 1995 and February 21, 1996, $38.0 million of borrowings were subject to the Libor Rate. A commitment fee of 1/2 of 1 percent is charged for any unused portion of the borrowing base. Shareholders' equity at December 31, 1995 was $56.6 million, making the Company's ratio of long-term debt-to-equity .73 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 Loan Agreement. Net cash provided by continuing operating activities in 1995 was $11.2 million as compared to $12.6 million in 1994. The Company's capital expenditures during 1995 were $22.0 million. The majority of the capital expenditures, $19.3 million, were made in the Company's oil and natural gas operations with $8.8 million and $9.2 20 million used for exploration and development drilling and producing property acquisitions, respectively. Capital expenditures made by the Company's contract drilling operations were approximately $1.6 million in 1995 and principally consisted of drill pipe and drill collar expenditures along with 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 of approximately $2 million will be required in 1996 for drill pipe as certain grades of the Company's drill pipe are reaching the end of their useful life. During 1996, the Company's oil and natural gas segment plans to focus on its developmental drilling program as early 1996 natural gas prices have improved lessening the availability of economical producing property acquisitions. 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 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 $20 million on its capital expenditure program in 1996. 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, 1995 prepayment balance of $2.1 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 $180,000 or a minimum of $90,000 per month for the year 1996. 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 21 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 1996. 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 payments over a five year period with the first payment due June 1, 1998. The Company anticipates the maximum balance of $3 million will be unrecouped at December 31, 1997. 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 1994 and the first nine months of 1995 natural gas delivered was approximately 75 percent of the deliverability of the wells subject to the Settlement Agreement. Pursuant to the terms of the Settlement Agreement, the purchaser notified the Company that effective October 1, 1995, the purchaser plans to make seasonal takes of natural gas by requesting the maximum deliverability subject to the Settlement Agreement in certain months and no deliverability in other months. For the majority of the fourth quarter of 1995 and continuing into the first quarter of 1996 the purchaser has requested the maximum deliverability subject to the Settlement Agreement. 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 approximately $1.6, $1.8 and $1.9 million in 1995, 1994 and 1993, respectively. Oil prices received by the Company in 1995 ranged from an average of $15.33 in July to $18.14 in December. The Company's average price for oil received in 1995 was $16.65. Natural gas prices received by the Company in 1995 ranged from an average of $1.35 in March to $2.01 in December. Average natural gas prices received by the Company remained volatile throughout 1995 and averaged $1.61 f or the year as a whole. 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, an d by world wide oil price levels. Any large drop in spot market natural gas prices will have a significant adverse effect on the value of the Company's reserves and could cause the Company to reduce the carrying value of its oil and natural gas properties. Likewise, declines in natural gas or oil prices could adversely effect the semi-annual borrowing base determination under the Company's Loan Agreement since this determination is calculated on the value of the Company's oil and natural gas reserves. 22 The Company's ability to utilize its full complement of drilling rigs, should economic conditions improve in the future, will be limited 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 1996. 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. Since that time, 115,100 shares have been repurchased at prices ranging from $2 1/2 to $3 3/8 per share. During the first quarter of 1995, 46,659 of the purchased shares were reissued as the Company's matching contribution to its 401(k) Employee Thrift Plan. At December 31, 1995, 68,441 treasury shares were held by the Company. The Company's wholly owned natural gas marketing subsidiary, Mountain Front Pipeline Company, achieved substantial growth in revenues during previous years, but did not achieve the size necessary to reach desired levels of profitability. Consequently, on April 1, 1995 the Company completed a business combination between the Company's natural gas marketing operations and a third party also involved in natural gas marketing activities forming a new company called GED Gas Services, L.L.C. ("GED"). The Company owns a 34 percent interest in GED. Effective November 1, 1995 GED sold its natural gas marketing operations to a third party. T his sale removed the Company from the third party natural gas marketing business. The creation of GED and its subsequent sale of its marketing operations did not adversely affect the Company's drilling and oil and natural gas exploration operations or the profitability of the Company as a whole. The discontinuation of the Company's natural gas marketing segment has been accounted for as a discontinued operation and accordingly, the 1995 and prior year financial information has been restated to reflect this treatment. 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. 23 Results of Operations 1995 versus 1994 - ---------------- Net income for 1995 was $3,999,000, compared with $4,794,000 in 1994. While the Company continued to increase natural gas production through producing property acquisitions and developmental drilling, lower 1995 natural gas prices limited corresponding increases in net income. Net income in the fourth quarter of 1995 w as also further reduced by a $254,000 write down of certain rig components as the Company elected to take 3 of its drilling rigs out of service since current economic conditions do not warrant the capital investment necessary to keep them in service. The impact of lower natural gas prices on net income was partially offset by a $635,000 gain from the sale of 44 natural gas compressors and certain related support equipment which were sold for $2.7 million in the first quarter and by the receipt of $850,000 in the third quarter from a settlement reached by two of the Company's subsidiaries in certain litigation brought against the Federal Deposit Insurance Corporation and other parties. In the fourth quarter, the Company also recognized a $360,000 net gain from the Company's interest in the sale of GED's gas marketing operations and a $530,000 net income tax benefit. The disposition of the Company's involvement in third party natural gas marketing does not adversely affect the operation of the Company's drilling and oil and natural gas exploration operations or the profitability of the Company as a whole. Total revenues from continuing operations increased to $53,074,000 in 1995 as compared to $43,895,000 in 1994. The Company's 1994 net income included a net gain of $742,000 recognized in conjunction with the sale of one of the Company's natural gas gathering systems. Oil and natural gas revenues increased 20 percent due to a 25 percent increase in natural gas production and a 42 percent increase in oil production between 1995 and 1994. Average oil prices received by the Company increased 10 percent while average natural gas prices received by the Company decreased 13 percent. The average natural gas price declined due to a 11 percent reduction in average spot market prices received by the Company coupled with a 18 percent reduction in volumes produced from certain wells included under the Settlement Agreement which contains provisions for prices which are higher than current spot market prices. The impact of higher prices received under the Settlement Agreement increased pre-tax income by approximately $1.6 and $1.8 million in 1995 and 1994, respectively. In 1995, revenues from contract drilling operations increased by 19 percent as average rig utilization increased from 9.5 rigs operating in 1994 to 10.9 rigs operating in 1995. Daywork revenues represented 57 percent of total drilling revenues in 1995 and 58 percent in 1994. 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 1994, the Company moved two of its rigs under multi-well contracts to the South Texas Basin creating a new operating region for the Company's drilling 24 services and helping to further improve its rig utilization. In the fourth quarter of 1995, the contract drilling operations opened an office in Houston, Texas with plans to further develop this new market area. At December 31, 19 95, four of the Company's 22 rigs were located in the South Texas Basin. Operating margins (revenues less operating costs) for the Company's oil and natural gas operations were 62 percent in 1995 compared to 66 percent in 1994. The reduction was primarily due to the decrease in prices received for the Company's natural gas production which offset increases in production between the two years. Margins were also reduced by the shutting in of production on certain natural gas properties in the months of February and March due to low spot market natural gas prices. Total operating costs increased 36 percent due to the additional costs associated with oil and natural gas production from new wells acquired and drilled in 1995 and 1994. Operating margins for contract drilling decreased from 12 percent in 1994 to 11 percent in 1995. Margins in 1995 were limited by initial start up costs incurred in the first quarter of 1995 to establish rigs in the South Texas Basin and by unusually wet weather conditions during the second quarter of 1995 which delay ed rig moves and depressed rig utilization. Total operating costs for contract drilling were up 21 percent in 1995 versus 1994 due to increased rig utilization and start up costs. Contract drilling depreciation increased 28 percent in response to increased rig utilization. Depreciation, depletion and amortization ("DD&A") of oil and natural gas properties increased 23 percent as the Company increased its equivalent barrels of production by 28 percent. The Company's average DD&A rate per equivalent barrel declined from $4.08 in 1994 to $3.93 in 1995. General and administrative expense increased 9 percent as certain employee costs, contract services and rental costs increased between the comparative years due to the continued growth of the Company's operations. This increase is expected to continue in 1996 as the Company expands its operations. Interest expense increased 96 percent as the average interest rate on the Company's outstanding bank debt increased from 7.15 percent in 1994 to 8.52 percent in 1995. Average bank debt outstanding in 1995 was $20.3 million higher than average bank debt outstanding in 1994 primarily due to the financing of producing property acquisition and developmental drilling as previously discussed. The Company's effective income tax rate in recent years has been significantly impacted by its net operating loss carryforwards. As of December 31, 1995, the Company's net operating loss and statutory depletion carryforwards have been fully recognized for financial reporting purposes, resulting in a net deferred tax asset of $530,000. Realization is dependent on generating sufficient taxable income prior to expiration of net operating loss carryforwards. Although realization is not assured, management believes it is more likely than not that all of the deferred tax asset will be realized. The amount of the deferred tax asset considered realizable, however, could be reduced in the near-term if estimates of future taxable income during the carryforward period are reduced. 25 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 segment 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 from continuing operations were $43,895,000 in 1994 and $38,682,000 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 partially offsetting the increases in production. Average natural gas prices received by the Company declined due to a 14 percent reduction in average spot market prices coupled with a 14 percent reduction in volumes produced from certain wells included under the Settlement Agreement which contains provisions for prices which are 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 and $1.9 million in 1994 and 1993, respectively. 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. 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 oil and 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 i n 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. 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 declined from $4.13 in 1993 to $4.08 in 1994. 26 General and administrative expense increased 8 percent as certain employee and reporting costs increased between the comparative years. 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. IMPACT OF FINANCIAL ACCOUNTING PRONOUNCEMENTS - --------------------------------------------- In March 1995, Statement of Financial Accounting Standards No. 121, "Accounting for the Impairment of Long-Lived Assets and Long-Lived Assets to be Disposed of" was issued. The statement establishes accounting standards for the impairment of long-lived assets, such as the Company's drilling, transportation and other equipment and will be effective for the Company beginning with the year ending December 31, 1996. The Company does not believe the new standard will have a material effect on the Company's financial position or results of operations. In October 1995, Statement of Financial Accounting Standards No. 123, "Accounting for Stock-Based Compensation" was issued. The statement requires the computation of compensation for grants of stock, stock options and other equity instrument s issued to employees based on fair value. The compensation calculated is to be either recorded as an expense in the financial statements or, alternatively, disclosed. The Company anticipates it will elect the disclosure method of complying with the new standard. Under existing accounting rules, the Company's stock option grants have not resulted in compensation expense. Accordingly, under the provisions of the new statement, pro forma net income to be disclosed will be lower than net income reported in the financial statements. 27 Item 8. Financial Statements and Supplementary Data - ----------------------------------------------------- UNIT CORPORATION AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS As of December 31, ASSETS 1995 1994 ---------- ---------- (In thousands) Current Assets: Cash and cash equivalents $ 534 $ 2,641 Accounts receivable (less allowance for doubtful accounts of $116 and $289) 10,398 8,173 Materials and supplies 2,048 1,498 Prepaid expenses and other 1,046 952 --------- --------- Total current assets 14,026 13,264 --------- --------- Net Assets of Discontinued Operations - 124 --------- --------- Property and Equipment: Drilling equipment 75,751 75,746 Oil and natural gas properties, on the full cost method 175,225 157,393 Transportation equipment 3,695 3,341 Other 6,100 7,858 --------- --------- 260,771 244,338 Less accumulated depreciation, depletion, amortization and impairment 164,752 153,833 --------- --------- Net property and equipment 96,019 90,505 --------- --------- Other Assets 877 40 --------- --------- Total Assets $110,922 $103,933 ========= ========= The accompanying notes are an integral part of the consolidated financial statements 28 UNIT CORPORATION AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS - CONTINUED As of December 31, LIABILITIES AND SHAREHOLDERS' EQUITY 1995 1994 ---------- ---------- (In thousands) Current Liabilities: Current portion of long-term debt $ 20 $ 496 Current portion of natural gas purchaser prepayments (Note 4) - 1,580 Accounts payable 6,701 6,068 Accrued liabilities 3,976 3,051 Contract advances 410 158 ---------- ---------- Total current liabilities 11,107 11,353 ---------- ---------- Natural Gas Purchaser Prepayments (Note 4) 2,109 2,149 ---------- ---------- Long-Term Debt 41,100 37,824 ---------- ---------- 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, 20,976,090 and 20,910,190 shares issued, respectively 4,195 4,182 Capital in excess of par value 50,181 50,086 Retained earnings (deficit) 2,418 (1,581) Treasury stock, at cost (68,441 and 25,100 shares, respectively) (188) (80) ---------- ---------- Total shareholders' equity 56,606 52,607 ---------- ---------- Total Liabilities and Shareholders' Equity $ 110,922 $ 103,933 ========== ========== The accompanying notes are an integral part of the consolidated financial statements 29 UNIT CORPORATION AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF OPERATIONS Year Ended December 31, 1995 1994 1993 -------- -------- -------- Revenues: (In thousands except per share amounts) Contract drilling $20,211 $16,952 $14,676 Oil and natural gas 31,187 26,001 24,073 Other 1,676 942 (67) -------- -------- -------- Total revenues 53,074 43,895 38,682 Expenses: -------- -------- -------- Contract drilling: Operating costs 18,041 14,909 13,269 Depreciation and impairment 2,596 2,030 1,713 Oil and natural gas: Operating costs 12,003 8,799 8,098 Depreciation, depletion and amortization 10,223 8,281 7,018 General and administrative 3,893 3,574 3,302 Interest 3,235 1,654 1,324 -------- -------- -------- Total expenses 49,991 39,247 34,724 -------- -------- -------- Income From Continuing Operations Before Income Taxes 3,083 4,648 3,958 Income Tax Expense (Benefit) (668) 20 21 -------- -------- -------- Income From Continuing Operations 3,751 4,628 3,937 -------- -------- -------- Discontinued Operations: Income (loss) from operations of discontinued operations (net of income taxes of $69 in 1995) (112) 166 (66) Gain from sale of discontinued operations (net of income taxes of $221 in 1995) 360 - - -------- -------- -------- Income(loss) from discontinued operations 248 166 (66) -------- -------- -------- Net Income $ 3,999 $ 4,794 $ 3,871 ======== ======== ======== Net Earnings Per Common Share: Continuing operations $ .18 $ .22 $ .19 ======== ======== ======== Net income $ .19 $ .23 $ .19 ======== ======== ======== Weighted Average Shares Outstanding 21,210 20,900 20,860 (Both Primary and Fully Diluted) ======== ======== ======== The accompanying notes are an integral part of the consolidated financial statements 30 UNIT CORPORATION AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDERS' EQUITY Year Ended December 31, 1993, 1994 and 1995 Capital In Excess Retained Common Of Par Earnings Treasury Stock Value (Deficit) Stock Total -------- -------- --------- -------- -------- (In thousands) Balances, January 1, 1993 $ 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 Net income - - 3,999 - 3,999 Activity in employee compensation plans (112,559 shares) 13 95 - 122 230 Purchase of treasury stock (90,000 shares) - - - (230) (230) -------- -------- --------- -------- -------- Balances, December 31, 1995 $ 4,195 $50,181 $ 2,418 $ (188) $56,606 ======== ======== ========= ======== ======== The accompanying notes are an integral part of the consolidated financial statements 31 UNIT CORPORATION AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF CASH FLOWS Year Ended December 31, 1995 1994 1993 -------- -------- -------- (In thousands) Cash Flows From Operating Activities: Income from continuing operations $ 3,751 $ 4,628 $ 3,937 Adjustments to reconcile income from continuing operations to net cash provided (used) by continuing operating activities: Depreciation, depletion, amortization and impairment 13,120 10,760 9,243 Gain on disposition of assets (723) (813) (49) Employee stock compensation plans 231 119 151 Bad debt expense 55 - - Deferred tax benefit (682) - - Changes in operating assets and liabilities increasing (decreasing) cash: Accounts receivable (2,280) 94 428 Materials and supplies (550) (74) (99) Prepaid expenses and other (94) (396) 318 Accounts payable (1,151) (871) (1,632) Accrued liabilities 925 824 (877) Contract advances 252 148 8 Natural gas purchaser prepayments (1,620) (1,858) (1,743) -------- -------- -------- Net cash provided by continuing operating activities 11,234 12,561 9,685 -------- -------- -------- Net cash flows provided by discontinued operations including changes in working capital (259) 532 182 -------- -------- -------- Net cash provided by operating activities 10,975 13,093 9,867 -------- -------- -------- The accompanying notes are an integral part of the consolidated financial statements 32 UNIT CORPORATION AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF CASH FLOWS - CONTINUED Year Ended December 31, 1995 1994 1993 --------- --------- --------- (In thousands) Cash Flows From Investing Activities: Capital expenditures (including producing property acquisitions) $(20,634) $(28,227) $(11,946) Proceeds from disposition of assets 4,613 2,038 709 Decrease in short-term investments - 41 664 (Acquisition) disposition of other assets - 141 (45) Proceeds of sale of discontinued operations 369 - - --------- --------- --------- Net cash used in investing activities (15,652) (26,007) (10,618) --------- --------- --------- Cash Flows From Financing Activities: Borrowings under line of credit 39,700 63,700 43,400 Payments under line of credit (35,900) (51,300) (40,600) Proceeds from notes payable and other long-term debt - - 911 Payments on notes payable and other long-term debt (1,000) (480) (367) Acquisition of treasury stock (230) (80) - --------- --------- --------- Net cash provided by financing activities 2,570 11,840 3,344 --------- --------- --------- Net Increase (Decrease) in Cash and Cash Equivalents (2,107) (1,074) 2,593 Cash and Cash Equivalents, Beginning of Year 2,641 3,715 1,122 --------- --------- --------- Cash and Cash Equivalents, End of Year $ 534 $ 2,641 $ 3,715 ========= ========= ========= Supplemental Disclosure of Cash Flow Information: Cash paid during the year for: Interest $ 3,214 $ 1,548 $ 1,326 Income taxes $ - $ 2 $ 2 The accompanying notes are an integral part of the consolidated financial statements 33 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. Nature of Business The Company is engaged in the development, acquisition and production of oil and natural gas properties and the land contract drilling of oil and natural gas wells primarily in the Anadarko, Arkoma and South Texas Basins. These basins are located in Oklahoma, Texas, Kansas and Arkansas. Additional producing properties are located in Canada and other states, including New Mexico, Louisiana, North Dakota, Colorado, Wyoming, Montana, Alabama and Mississippi. The Company has an interest in 2,635 wells and serves as operator of 482 of those wells. Land contract drilling of oil and natural gas wells is performed for a wide range of customers with the 22 drilling rigs owned and operated by the Company. 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 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 34 lives, including a minimum provision of 20 percent of the active rate when the equipment is idle. At December 31, 1995, the Company elected to take three rigs out of service, which rigs and certain other components of the rig fleet were written down by $254,000 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 computed using the straight-line method over the estimated useful lives of the assets ranging from 3 to 15 years. Realization of the carrying value of the Company's drilling rigs is evaluated utilizing estimated future net cash flows from utilization of the Company rigs. Changes in these estimates could cause the Company to reduce the carrying value of its rigs. 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 dispositions of drill pipe and d rill 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 productive 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 $3.93, $4.08 and $4.13 per equivalent barrel in 1995, 1994 and 1993, 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. The full cost ceiling is based principally on the estimated future discounted net cash flows from the Company's oil and natural gas properties. As discussed in Note 12, such estimates are imprecise. Changes in these estimates or declines in oil and natural gas prices could cause the Company in the near-term to reduce the carrying value of its oil and natural gas properties. 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 35 current operations for services performed on oil and natural gas properties in which the Company has an interest or on properties in which a partnership, of which the Comp any 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 1995 and 1993. Limited Partnerships The Company, through its wholly owned subsidiary, Unit Petroleum Company, is a general partner in eleven oil and natural gas limited partnerships 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. 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 partner ships. Income Taxes Measurement of current and deferred income 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. 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 1995 average spot market natural gas price of $1.47 per Mcf, the Company estimates its balancing position to be approximately $4.5 million on under-produced properties and approximately $2.7 million on over-produced properties. The Company's policy is to expense its pro-rata share of lease operating 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 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 36 credit risk is considered by management to be limited due to the large number of customers comprising the Company's customer base. In addition, at December 31, 1995 and 1994, the Company had a concentration of cash of $1.2 and $2.3 million, respectively, with one bank. Accounting Estimates The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. Impact of Financial Accounting Pronouncements In March 1995, Statement of Financial Accounting Standards No. 121, "Accounting for the Impairment of Long-Lived Assets and Long-Lived Assets to be Disposed of" was issued. The statement establishes accounting standards for the impairment of long-lived assets, such as the Company's drilling, transportation and other equipment and will be effective for the Company beginning with the year ending December 31, 1996. The Company does not believe the new standard will have a material effect on the Company's financial position or results of operations. In October 1995, Statement of Financial Accounting Standards No. 123, "Accounting for Stock-Based Compensation" was issued. The statement requires the computation of compensation for grants of stock, stock options and other equity instrument s issued to employees based on fair value. The compensation calculated is to be either recorded as an expense in the financial statements or, alternatively, disclosed. The Company anticipates it will elect the disclosure method of complying with the new standard. Under existing accounting rules, the Company's stock option grants have not resulted in compensation expense. Accordingly, under the provisions of the new statement, pro forma net income to be disclosed will be lower than net income reported in the financial statements. Reclassifications Certain reclassifications have been made in the 1993 and 1994 consolidated financial statements to conform them to classifications used in 1995. NOTE 2 - DISCONTINUED OPERATIONS - -------------------------------- On April 1, 1995, the Company's natural gas marketing operations were combined with a third party also involved in natural gas marketing activities into a business combination forming GED Gas Services L.L.C. ("GED"). The combination was made to attain the increased volumes deemed necessary to 37 profitably market third party natural gas. The Company owns a 34 percent interest in GED. On November 1, 1995 GED sold its natural gas marketing operation. This sale removed the Company from the third party natural gas marketing business. The gain on the sale was $360,000 net of income tax of $221,000. Prior years have been restated to present the Company's former natural gas marketing activity as a discontinued operation. Summary results of operations and financial position data of the discontinued operations were as follows: For the Year Ended December 31, 1995 1994 1993 ------- ------- ------- (In Thousands) Results of Operations: Revenues attributable to discontinued operations $13,548 $43,725 $31,636 Expenses attributable to discontinued operations 13,729 43,559 31,702 ------- ------- ------- Income (loss) attributable to discontinued operations before income taxes (181) 166 (66) Income tax benefit 69 - - ------- ------- ------- Income (loss) attributable to discontinued operations $ (112) $ 166 $ (66) ======= ======= ======= December 31, 1995 1994 ------- ------- (In Thousands) Financial Position: Current assets $ - $ 8,574 Net property plant and equipment - 38 Current liabilities - (8,488) ------- ------- Net assets of discontinued operations $ - $ 124 ======= ======= 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 38 common stock a t 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, 1995 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 ("Settlement Agreement"), the Company has a prepayment balance of $2.1 million at December 31, 1995 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, 1995 p repayment 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 $180,000 or a minimum of $90,000 per month for the year 1996. Both t he 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 annual payments over a five year period with the first payment due June 1, 1998. The prepayment amounts subject to recoupment from future production by the purchaser are being recorded as liabilities a nd are reflected in revenues as recoupment occurs. The portion of the prepayments that are estimated to be recouped in the next twelve months has been included in current liabilities. The Company anticipates the maximum balance of $3 million will b e unrecouped at December 31, 1997. 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. 39 NOTE 5 - LONG-TERM DEBT - ------------------------ Long-term debt consisted of the following as of December 31, 1995 and 1994: 1995 1994 --------- --------- Revolving credit and term loan, (In thousands) with interest at December 31, 1995 and 1994 of 8.2 percent and 8.5 percent, respectively $ 41,100 $ 37,300 Other 20 1,020 --------- --------- 41,120 38,320 Less current portion 20 496 --------- --------- Total long-term debt $ 41,100 $ 37,824 ========= ========= At December 31, 1995, the Company's loan agreement ("Loan Agreement") provided for a total loan commitment of $75 million consisting of a revolving credit facility through August 31, 1997 and a term loan thereafter, maturing on August 31, 200 1. Borrowings under the Loan Agreement are limited to a semi- annual borrowing base computation which as of December 31, 1995 is $50 million. Borrowings under the revolving credit facility bear interest at the Chase Manhattan Bank, N.A. prime rate ("Prime Rate") or the London Interbank Offered Rates ("Libor Rate") plus 1.75 to 2.25 percent depending on the level of debt as a percentage of the total borrowing base. Subsequent to August 1, 1997, borrowings under the Loan Agreement bear interest at the Prime Rate plus .25 percent or the Libor rate plus 2.00 to 2.50 percent depending on the level of debt as a percentage of the total borrowing base. At the Company's election, any portion of the debt outstanding may be fixed at the Libor Rate for 30, 60, 90 or 180 days. During any Libor Rate funding period the Company may not pay in part or in whole the outstanding principal balance of t he note to which such Libor Rate option applies. Borrowings under the Prime Rate option may be paid anytime in part or in whole without premium or penalty. A 1/2 of 1 percent facility fee is charged for any 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 Loan Agreement includes prohibitions against (i) the payment of dividends (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 and only if working capital provided from operations during said year is equal to or greater than 175 percent of current maturities of long-term 40 debt at the end of such 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 Loan Agreement also requires that the Company maintain consolidated net worth of at least $48 million, a modified current ratio of not less than 1 to 1, a ratio of long-term debt, as defined in the Loan Agreement, to consolidated tangible net worth not greater than 1 to 1 and a ratio of total liabilities, as defined in the Loan Agreement, to consolidated tangible net worth not greater than 1.25 to 1. In addition, working capital provided by operations, as defined in the Loan Agreement, cannot be less than $12 million in any year. Estimated annual principal payments under the terms of all long-term debt from 1996 through 2000 are $20,000, $3,425,000, $10,275,000, $10,275,000 and $10,275,000. Based on the borrowing rates currently available to the Company for debt with similar terms and maturities, long-term debt at December 31, 1995 approximates its fair value. NOTE 6 - INCOME TAXES - --------------------- A reconciliation of the income tax expense, computed by applying the federal statutory rate to pre-tax income from continuing operations, to the Company's effective income tax expense is as follows: 1995 1994 1993 -------- -------- -------- (In thousands) Income tax expense computed by applying the statutory rate $ 1,048 $ 1,580 $ 1,346 Tax benefit of net operating loss carryforward (1,730) (1,595) (1,331) State income tax - 6 1 Other 14 29 5 -------- -------- -------- Income tax expense (benefit) $ (668) $ 20 $ 21 ======== ======== ======== 41 Deferred tax assets and liabilities are comprised of the following at December 31, 1995 and 1994: 1995 1994 --------- --------- Deferred tax assets: (In thousands) Allowance for losses $ 670 $ 521 Net operating loss carryforwards 17,058 18,190 Statutory depletion carryforward 2,260 2,500 Investment tax credit carryforward 3,530 3,530 --------- --------- Gross deferred tax assets 23,518 24,741 Valuation allowance (3,530) (6,423) Deferred tax liability- Depreciation, depletion and amortization (19,458) (18,318) --------- --------- Net deferred tax asset $ 530 $ - ========= ========= The deferred tax asset valuation allowance reflects that the investment tax credit 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. Realization of the deferred tax asset is dependent on generating sufficient taxable income prior to expiration of loss carryforwards. Although realization is not assured, management believes it is more likely than not that the deferred tax asset will be realized. The amount of the deferred tax asset considered realizable, however, could be reduced in the near-term if estimates of future taxable income during the carryforward period are reduced. Due to the full utilization of such carryforwards, the Company's effective tax rate in future years will approximate the statutory tax rate (both federal and state). At December 31, 1995, the Company has net operating loss carryforwards for regular tax purposes of approximately $44,891,000 and net operating loss carryforwards for alternative minimum tax purposes of approximately $37,109,000 which expire i n various amounts from 1999 to 2007. The Company has investment tax credit carryforwards of approximately $3,530,000 which expire from 1996 to 2000. In addition, a statutory depletion carryforward of approximately $5,948,000, which may be carried forward indefinitely, is available to reduce future taxable income, subject to statutory limitations. Based on revised calculations, the estimated statutory depletion carryforward was reduced and the estimated deferred tax liability relating to DD&A was increased in the current year. 42 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. On May 3, 1995, the Company's shareholders amended the Plan to increase by 250,000 shares the aggregate number of shares of common stock that could be issued 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 installments subject to certain restrictions. The Company issued 38,354 shares under the Plan in 1993. No shares were issued under the Plan in 1995 or 1994. At December 31, 1995, the Company also has a Stock Option Plan which provides for the granting of options for up to 1,500,000 shares of common stock to officers and employees. The plan permits the issuance of qualified or nonqualified stock options. Options granted become exercisable at the rate of 20 percent per year one year after being granted and expire after ten years from the original grant. The exercise price for options granted is based on market value on the date of the grant . Activity pertaining to the Stock Option Plan is as follows: NUMBER OF OPTION PRICE SHARES ------------------------------ --------- PER SHARE AGGREGATE --------------- ----------- Outstanding at January 1, 1993 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 Granted 26,000 2.75 to 4.00 83,750 Exercised (65,900) 1.50 to 2.75 (108,900) Canceled (10,000) 1.875 (18,750) --------- ---------------- ----------- Outstanding at December 31, 1995 865,600 $ 1.50 to 4.00 $1,933,260 ========= ================ =========== Options for 675,000, 676,400 and 610,500 shares were exercisable at prices ranging from $1.50 to $3.375 at December 31, 1995, 1994 and 1993, respectively. 43 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 ma y be issued 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 m ay 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 -------------- ----------- Outstanding at January 1, 1993 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 1.75 to 3.75 83,750 Granted 12,500 3.375 42,188 --------- -------------- ----------- Outstanding at December 31, 1995 42,500(1) $1.75 to 3.75 $ 125,938 ========= ============== =========== - ------------- (1) All 42,500 options were exercisable at December 31, 1995. 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 46,659, 32,685 and 28,352 shares of common stock and recognized expense of $174,000, $130,000 and $162,000 in 199 5, 1994 and 1993, 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 44 defined unforeseeable emergency hardships. Funds set aside in a trust to satisfy the Company's obligation under the Deferral Plan at December 31, 1995, 1994 and 1993 totaled $271,000, $108,000 and $41, 000, respectively. The Company recognizes payroll expense and records a 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 1995, with a subsidiary of the Company serving as General Partner. The Partnerships were formed f or 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: 1995 1994 1993 -------- -------- -------- (In thousands) Contract drilling $ 34 $ 53 $ 60 Well supervision and other fees $ 119 $ 226 $ 278 General and administrative expense reimbursement $ 235 $ 209 $ 231 A subsidiary of the Company paid the Partnerships, for which the Company or a subsidiary is the general partner, $18,000, $38,000 and $65,000 during the years ended December 31, 1995, 1994 and 1993, respectively, for purchases of natural gas production. During 1995 and 1994, a bank owned by one of the Company's Directors was a participant in the Company's Loan Agreement. The bank's total pro rata share of the Company's line of credit is currently limited to not exceed $1.5 million. 45 NOTE 9 - COMMITMENTS AND CONTINGENCIES - -------------------------------------- The Company leases office space under the terms of operating leases expiring through January 31, 2000. Future minimum rental payments under the terms of the leases are approximately $264,000, $244,000, $246,000, $246,000 and $21,000 in 1996, 1997, 1998, 1999 and 2000, respectively. Total rent expense incurred by the Company was $307,000, $210,000 and $208,000 in 1995, 1994 and 1993, respectively. The Company had letters of credit supported by its Loan Agreement totaling $935,000 at December 31, 1995. 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 $34,000, $38,000 and $56,000 in 1995, 1994 and 1 993, respectively, for such limited partners' interests. 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, will result in judgements which would have a material adverse effect on the Company. 46 NOTE 10 - INDUSTRY SEGMENT INFORMATION - -------------------------------------- The Company operates in the United States in two industry segments which are contract drilling and oil and natural gas exploration. The Company also has natural gas production in Canada which is not significant. Selected financial information by industry segment is as follows: Depreciation, Depletion, Operating Amortization Operating Profit Total Capital and Impairment Revenues (Loss)(1) Assets(2) Expenditures Expense ---------- -------- -------- --------- ---------- (In thousands) Year ended December 31, 1995: Drilling $ 20,211 $ (426) $ 15,449 $ 1,556 $ 2,596 Oil and natural gas 31,187 8,961 92,033 19,308 10,223 ---------- -------- -------- --------- ---------- 51,398 $ 8,535 107,482 20,864 12,819 ======== Other 1,676 3,440 1,089 301 ---------- -------- --------- ---------- Total $ 53,074 $110,922 $ 21,953 $ 13,120 ========== ======== ========= ========== Year ended December 31, 1994: Drilling $ 16,952 $ 13 $ 14,771 $ 1,115 $ 2,030 Oil and natural gas 26,001 8,921 83,082 25,110 8,281 ---------- -------- -------- --------- ---------- 42,953 $ 8,934 97,853 26,225 10,311 ======== Other 942 5,956 764 449 Discontinued operations - 124 - - ---------- -------- --------- ---------- Total $ 43,895 $103,933 $ 26,989 $ 10,760 ========== ======== ========= ========== Year ended December 31, 1993: Drilling $ 14,676 $ (306) $ 15,738 $ 936 $ 1,713 Oil and natural gas 24,073 8,957 64,845 11,422 7,018 ---------- -------- -------- --------- ---------- $ 38,749 $ 8,651 80,583 12,358 8,731 ======== Other (67) 7,743 1,372 512 Discontinued operations - 490 - - ---------- -------- --------- ---------- Total $ 38,682 $ 88,816 $ 13,730 $ 9,243 ========== ======== ========= ========== (1) Operating profit is total operating revenues less operating expenses, depreciation, depletion, amortization and impairment and does not include non- 47 operating revenues, general corporate expenses, interest expense, income taxes, provision for litigation or gain from litigation settlement. (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, furniture and equipment. NOTE 11 - SELECTED QUARTERLY FINANCIAL INFORMATION (UNAUDITED) - -------------------------------------------------------------- Summarized quarterly financial information for 1995 and 1994 is as follows: Three Months Ended ------------------------------------------------- March 31 June 30 September 30 December 31 --------- --------- --------- ---------- (In thousands except per share amounts) Year ended December 31, 1995: Revenues $ 12,388 $ 11,505 $ 14,117 $ 15,064 ========= ========= ========= ========= Gross profit(1) $ 1,875 $ 1,819 $ 1,721 $ 3,120 ========= ========= ========= ========= Income from continuing operations $ 857 $ 102 $ 916 $ 1,876 Income (loss) from discontinued operations 99 (81) (35) (95) Gain from sale of discontinued operations - - - 360 --------- --------- --------- --------- Net Income $ 956 (2) $ 21 $ 881 (3) $ 2,141 (4) ========= ========= ========= ========= Earnings Per Common Share: Continuing operations $ .05 $ - $ .04 $ .09 Discontinued operations - - - (.01) Gain on sale of discontinued operations - - - .02 --------- --------- --------- --------- Net income $ .05 (2) $ - $ .04 (3) $ .10 (4) ========= ========= ========= ========= 48 Three Months Ended ------------------------------------------------ March 31 June 30 September 30 December 31 --------- --------- --------- --------- (In thousands except per share amounts) Year ended December 31, 1994: Revenues $ 10,587 $ 11,064 $ 11,939 $ 10,305 ========= ========= ========= ========= Gross profit(1) $ 2,361 $ 2,754 $ 1,895 $ 1,924 ========= ========= ========= ========= Income from continuing operations $ 1,135 $ 1,407 $ 1,542 $ 544 Income from discontinued operations 76 18 48 24 --------- --------- --------- --------- Net income $ 1,211 $ 1,425 $ 1,590 (5) $ 568 ========= ========= ========= ========= Earnings Per Common Share: Continuing operations $ .06 $ .07 $ .07 $ .03 Discontinued operations - - - - --------- --------- --------- --------- Net income $ .06 $ .07 $ .07 (5) $ .03 ========= ========= ========= ========= (1) Gross Profit excludes other revenues, general and administrative expense and interest expense. (2) Includes $635,000 gain on sale of natural gas compressors. (3) Includes $850,000 gain from the settlement of litigation. (4) Includes a net income tax benefit of $530,000. (5) Includes $742,000 net gain on sale of natural gas gathering system. 49 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) 1995: Capitalized costs: Proved properties $ 171,259 $ 465 $ 171,724 Unproved properties 3,501 - 3,501 --------- -------- --------- 174,760 465 175,225 Less accumulated depreciation, depletion, amortization and impairment 91,739 379 92,118 --------- -------- --------- Net capitalized costs $ 83,021 $ 86 $ 83,107 ========= ======== ========= Cost incurred: Unproved properties $ 1,338 $ - $ 1,338 Producing properties 9,183 - 9,183 Exploration 1,291 - 1,291 Development 7,486 10 7,496 --------- -------- --------- Total costs incurred $ 19,298 $ 10 $ 19,308 ========= ======== ========= 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 $ 75,442 ========= ======== ========= 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 ========= ======== ========= 50 USA Canada Total --------- -------- --------- (In thousands) 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 ========= ======== ========= 51 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) 1995: Revenues $ 28,928 $ 53 $ 28,981 Production costs 9,914 16 9,930 Depreciation, depletion and amortization 10,156 11 10,167 -------- -------- -------- Results of operations for producing activities before income taxes (excluding corporate overhead and financing costs) $ 8,858 $ 26 $ 8,884 ======== ======== ======== 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 ======== ======== ======== 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 ======== ======== ======== 52 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 ------- -------- ----- ----- ------- -------- (In thousands) 1995: Proved developed and undeveloped reserves: Beginning of year 4,308 92,566 - 794 4,308 93,360 Revision of previous estimates 910 9,525 - (10) 910 9,515 Extensions, discoveries and other additions 305 7,910 - 48 305 7,958 Purchases of minerals in place 500 10,892 - - 500 10,892 Sales of minerals in place (18) (938) - - (18) (938) Production (577) (12,005) - (54) (577) (12,059) ------- -------- ----- ----- ------- -------- End of Year 5,428 107,950 - 778 5,428 108,728 ======= ======== ===== ===== ======= ======== Proved developed reserves: Beginning of year 3,521 80,110 - 359 3,521 80,469 End of year 4,697 94,975 - 350 4,697 95,325 1994: 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 3,187 65,395 - 426 3,187 65,821 End of year 3,521 80,110 - 359 3,521 80,469 53 USA Canada Total ---------------- ----------- ---------------- Natural Natural Natural Oil Gas Oil Gas Oil Gas Bbls Mcf Bbls Mcf Bbls Mcf ------- -------- ----- ----- ------- -------- (In thousands) 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 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 geological and engineering data, appear with reasonable certainty to be recoverable in the future from known oil and natural gas reservoirs under existing 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 expenditure 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 estimate s. 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 54 oil and natural gas producers. In addition, since prices and costs do not remain static and no price or cost escalations or de-escalations have been considered, the results are not necessarily indicative of the estimated fair market value of estimated proved reserves nor of estimated future cash flows. 55 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 --------- -------- --------- (In thousands) 1995: Future cash flows $320,916 $ 1,462 $322,378 Future production and development costs 107,830 304 108,134 Future income tax expenses 49,437 660 50,097 --------- -------- --------- Future net cash flows 163,649 498 164,147 10% annual discount for estimated timing of cash flows 60,826 183 61,009 --------- -------- --------- Standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves $102,823 $ 315 $103,138 ========= ======== ========= 1994: 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 ========= ======== ========= 56 The principal sources of changes in the standardized measure of discounted future net cash flows were as follows: USA Canada Total --------- -------- --------- (In thousands) 1995: Sales and transfers of oil and natural gas produced, net of production costs $(19,015) $ (36) $(19,051) Net changes in prices and production costs 28,857 112 28,969 Revisions in quantity estimates and changes in production timing (6,620) (10) (6,630) Extensions, discoveries and improved recovery, less related costs 11,320 49 11,369 Purchases of minerals in place 11,897 - 11,897 Sales of minerals in place (968) - (968) Accretion of discount 8,447 54 8,501 Net change in income taxes (11,727) (105) (11,832) Other - net 2,614 1 2,615 --------- -------- --------- Net change 24,805 65 24,870 Beginning of year 78,018 250 78,268 --------- -------- --------- End of year $102,823 $ 315 $103,138 ========= ======== ========= 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 ========= ======== ========= 57 USA Canada Total --------- -------- --------- 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 ========= ======== ========= The Company's SMOG and changes therein were determined in accordance with Statement of Financial Accounting Standards No. 69. Certain information 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. 58 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. 59 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, 1995 and 1994 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, 1995. 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, 1995 and 1994, and the consolidated results of their operations and their cash flows for each of the three years in the period ended December 31, 1995 in conformity with generally accepted accounting principles. In addition, in our opinion, the financial statement schedule referred to above, when consider ed 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 20, 1996 60 Item 9. Changes in and Disagreements with Accountants on Accounting and - ------------------------------------------------------------------------ Financial Disclosure. - -------------------- None. PART III Item 10. Directors and Executive Officers of the Registrant - ------------------------------------------------------------ The table below and accompanying footnotes set forth certain information 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 a re elected for a term of one year. There are no family relationships between any of the persons named. NAME AGE POSITION - ---------------- --- ---------------------------------------- King P. Kirchner 68 Chairman of the Board, Chief Executive Officer and Director John G. Nikkel 61 President, Chief Operating Officer and Director Earle Lamborn 61 Senior Vice President, Drilling and Director Philip M. Keeley 54 Senior Vice President, Exploration and Production Larry D. Pinkston 41 Vice President, Treasurer and Chief Financial Officer Mark E. Schell 38 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. 61 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 receive d 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 incorporated by reference from the Company's Proxy Statement to be filed with the Securities and Exchange Commission in connection with the Company's 1996 annual meeting of stockholders. Item 11. Executive Compensation - --------------------------------- Information required by this item is incorporated by reference from the Company's Proxy Statement to be filed with the Securities and Exchange Commission in connection with the Company's 1996 annual meeting of stockholders. 62 Item 12. Security Ownership of Certain Beneficial Owners and Management - ------------------------------------------------------------------------ Information required by this item is incorporated by reference from the Company's Proxy Statement to be filed with the Securities and Exchange Commission in connection with the Company's 1996 annual meeting of stockholders. Item 13. Certain Relationships and Related Transactions - -------------------------------------------------------- Information required by this item is incorporated by reference from the Company's Proxy Statement to be filed with the Securities and Exchange Commission in connection with the Company's 1996 annual meeting of stockholders. PART IV 63 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, 1995 and 1994 Consolidated Statements of Operations for the years ended December 31, 1995, 1994 and 1993 Consolidated Statements of Changes in Shareholders' Equity for the years ended December 31, 1995, 1994 and 1993 Consolidated Statements of Cash Flows for the years ended December 31, 1995, 1994 and 1993 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, 1995, 1994 and 1993: Schedule II - 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). 64 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). 4.2.6 Rights Agreement dated as of May 19, 1995 between the Company and Chemical Bank, as Rights Agent (filed as Exhibit 1 to the Company's Form 8-A filed May 23, 1995, File No. 1-92601 and 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). 65 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 Comp any 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 Comp any of Shawnee (filed as an Exhibit in Form 8-K dated December 15, 1994, which is incorporated herein by reference). 10.1.20 Loan Agreement dated August 3, 1995 (filed as an Exhibit to the Company's Quarterly Report under cover of Form 10-Q for the quarter ended June 30, 1995, 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). 66 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). 67 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 as an Exhibit to the Company's Annual Report, under cover of Form 10-K for the year ended December 31, 1994, which is incorporated herein by reference) . 10.2.29 Unit 1996 Employee Oil and Gas Limited Partnership Agreement of Limited Partnership (filed herewith). 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). 68 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: No reports under Form 8-K were filed during the quarter ended December 31, 1995. 69 Schedule II 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, 1995 $ 289 $ 55 $ 228 $ 116 ======== ======== ======== ======== Year ended December 31, 1994 $ 411 $ - $ 122 $ 289 ======== ======== ======== ======== Year ended December 31, 1993 $ 376 $ - $ (35 ) $ 411 ======== ======== ======== ======== Deferred Tax Asset Valuation Allowance: Balance at Balance at beginning end of Description of period Additions Deductions period ----------- -------- -------- -------- -------- (In thousands) Year ended December 31, 1995 $ 6,423 $ - $ 2,893 $ 3,530 ======== ======== ======== ======== Year ended December 31, 1994 $ 8,218 $ - $ 1,795 $ 6,423 ======== ======== ======== ======== Year ended December 31, 1993 $ 12,245 $ - $ 4,027 $ 8,218 ======== ======== ======== ======== 70 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 19, 1996 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 19th day of March, 1996. 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 71 EXHIBIT INDEX ----------------- Exhibit No. Description Page - ------- --------------------------------------------- ---- 10.2.29 Unit 1996 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. 72 EX-10 2 EXHIBIT 10.2.29 CONFIDENTIAL For Private Placement Purposes Only Copy No. ____ UNIT 1996 EMPLOYEE OIL AND GAS LIMITED PARTNERSHIP 1000 Kensington Tower I 7130 South Lewis Tulsa, Oklahoma 74136 (918) 493-7700 A PRIVATE OFFERING OF UNITS OF LIMITED PARTNERSHIP INTEREST _____________________________________ THESE SECURITIES HAVE NOT BEEN REGISTERED UNDER THE SECURI- TIES ACT OF 1933, AS AMENDED, OR UNDER APPLICABLE STATE SECURITIES ACTS IN RELIANCE ON EXEMPTIONS PROVIDED BY SUCH ACTS. THESE SECURITIES MAY NOT BE SOLD OR TRANSFERRED IN THE ABSENCE OF AN EFFECTIVE REGISTRATION UNDER SUCH ACTS OR AN OPINION OF COUNSEL ACCEPTABLE TO THE GENERAL PARTNER THAT SUCH REGISTRATION IS NOT REQUIRED. FURTHER, THE RESALE OF A UNIT MAY RESULT IN SUBSTANTIAL TAX LIABILITY TO THE INVESTOR. SEE "FEDERAL INCOME TAX ASPECTS." ACCORDINGLY, THESE UNITS SHOULD BE CONSIDERED ONLY FOR LONG-TERM INVESTMENT. SEE "PLAN OF DISTRIBUTION -- SUITABILITY OF INVESTORS." _____________________________________ THE INFORMATION CONTAINED IN THIS PRIVATE OFFERING MEMORANDUM IS PROVIDED BY THE GENERAL PARTNER SOLELY FOR THE PERSONS RECEIVING IT FROM THE GENERAL PARTNER AND ANY REPRODUCTION OR DISTRIBUTION OF THIS PRIVATE OFFERING MEMORANDUM, IN WHOLE OR IN PART, OR THE DIVULGENCE OF ANY OF ITS CONTENTS IS PROHIBITED AND MAY CONSTITUTE A VIOLATION OF CERTAIN STATE SECURITIES LAWS. THE OFFEREE, BY ACCEPTING DELIVERY OF THIS PRIVATE OFFERING MEMORANDUM, AGREES TO RETURN IT AND ALL ENCLOSED DOCUMENTS TO THE GENERAL PARTNER IF THE OFFEREE DOES NOT UNDERTAKE TO PURCHASE ANY OF THE UNITS OFFERED HEREBY. _____________________________________ Private Offering Memorandum Date January 3, 1996 (i) 500 Preformation Units of Limited Partnership Interest in the UNIT 1996 EMPLOYEE OIL AND GAS LIMITED PARTNERSHIP _____________________________________ $1,000 Per Unit Plus Possible Additional Assessments of $100 Per Unit (Minimum Investment - 2 Units) Minimum Aggregate Subscriptions Necessary to Form Partnership - 50 Units _____________________________________ A maximum of 500 (minimum of 50) units of limited partnership interest ("Units") in the UNIT 1996 EMPLOYEE OIL AND GAS LIMITED PARTNERSHIP, a proposed Oklahoma limited partnership (the "Partner- ship"), are being offered privately only to certain employees of Unit Corporation ("UNIT") and its subsidiaries and the directors of UNIT at a price of $1,000 per Unit. Subscriptions shall be for not less than 2 Units ($2,000). The Partnership is being formed for the purpose of conducting oil and gas drilling and development operations. Purchasers of the Units will become Limited Partners in the Partnership. Unit Petroleum Company ("UPC" or the "General Partner") will serve as General Partner of the Partnership. UPC's address is 1000 Kensington Tower I, 7130 South Lewis Avenue, Tulsa, Oklahoma 74136, telephone (918) 493-7700. THE RIGHTS AND OBLIGATIONS OF THE GENERAL PARTNER AND THE LIMITED PARTNERS ARE GOVERNED BY THE AGREEMENT OF LIMITED PARTNERSHIP (THE "AGREEMENT"), A COPY OF WHICH ACCOMPANIES THIS MEMORANDUM AND IS INCORPORATED HEREIN BY REFERENCE AN INVESTMENT IN THE UNITS IS SPECULATIVE AND INVOLVES A HIGH DEGREE OF RISK. SEE "RISK FACTORS". CERTAIN SIGNIFICANT RISKS INCLUDE: . Drilling to establish productive oil and natural gas properties is inherently speculative. . Participants will rely solely on the management capability and expertise of the General Partner. . Limited Partners must assume the risks of an illiquid investment. . Investment in the Units is suitable only for investors having sufficient financial resources and who desire a long term investment. (continued on next page) _____________________________________ (ii) . Conflicts of interest exist and additional conflicts of interest may arise between the General Partner and the Limited Partners, and there are no pre-determined procedures for resolving any such conflicts. . Significant tax considerations to be considered by an investor include: . possible audit of income tax returns of the Partnership and/or the Limited Partners and resulting reduction or elimination of tax benefits; and . Limited Partners will not benefit from Partnership losses unless they have passive income from other activities. . There can be no assurance that the Partnership will have adequate funds to provide cash distributions to the Limited Partners. The amount and timing of any such distributions will be within the complete discretion of the General Partner. . The amount of any cash distribution which a Limited Partner may receive from the Partnership could be insufficient to pay the tax liability incurred by such Limited Partner with respect to income or gain allocated to such Limited Partner by the Partnership. . Certain provisions in the Agreement modify what would otherwise be the applicable Oklahoma law as to the fiduciary standards for general partners in limited partnerships. Those standards in the Agreement could be less advantageous to the Limited Partners than the corresponding fiduciary standards otherwise applicable under Oklahoma law. The purchase of Units may be deemed as consent to the fiduciary standards set forth in the Agreement. _____________________________________ EXCEPT AS STATED HEREIN UNDER "ADDITIONAL INFORMATION," NO PERSON HAS BEEN AUTHORIZED TO GIVE ANY INFORMATION OR TO MAKE ANY REPRESENTATIONS OTHER THAN THOSE CONTAINED IN THIS PRIVATE OFFERING MEMORANDUM IN CONNECTION WITH THIS OFFERING AND SUCH REPRESENTATIONS, IF ANY, MAY NOT BE RELIED UPON. THE INFORMATION CONTAINED IN THIS PRIVATE OFFERING MEMORANDUM IS AS OF THE DATE HEREOF UNLESS ANOTHER DATE IS SPECIFIED. _____________________________________ PROSPECTIVE INVESTORS ARE NOT TO CONSTRUE THE CONTENTS OF THIS PRIVATE OFFERING MEMORANDUM AS LEGAL, BUSINESS, OR TAX ADVICE. EACH INVESTOR SHOULD CONSULT HIS OR HER OWN ATTORNEY, BUSINESS ADVISOR AND TAX ADVISOR AS TO LEGAL, BUSINESS, TAX AND RELATED MATTERS CONCERNING HIS OR HER INVESTMENT. PROSPECTIVE INVESTORS ARE URGED TO REQUEST ANY ADDITIONAL INFORMATION THEY MAY CONSIDER NECESSARY TO MAKE AN INFORMED INVESTMENT DECISION. (iii) _____________________________________ THE SECURITIES OFFERED HEREBY HAVE NOT BEEN APPROVED OR DISAPPROVED BY THE UNITED STATES SECURITIES AND EXCHANGE COMMISSION, THE OKLAHOMA SECURITIES COMMISSION OR BY THE SECURITIES REGULATORY AUTHORITY OF ANY OTHER STATE, NOR HAS ANY COMMISSION OR AUTHORITY PASSED UPON OR ENDORSED THE MERITS OF THIS OFFERING OR THE ACCURACY OR ADEQUACY OF THIS PRIVATE OFFERING MEMORANDUM. ANY REPRESENTATION CONTRARY TO THE FOREGOING IS UNLAWFUL. _____________________________________ THESE UNITS ARE BEING OFFERED SUBJECT TO PRIOR SALE, TO WITHDRAWAL, CANCELLATION OR MODIFICATION OF THE OFFER WITHOUT NOTICE AND TO THE FURTHER CONDITIONS SET FORTH HEREIN. _____________________________________ IN CONNECTION WITH THE REGISTRATION OF THE PARTNERSHIP AS A "TAX SHELTER" PURSUANT TO SECTION 6111 OF THE INTERNAL REVENUE CODE OF 1986, AS AMENDED, PLEASE NOTE THAT ISSUANCE OF A REGISTRATION NUMBER DOES NOT INDICATE THAT AN INVESTMENT IN THE PARTNERSHIP OR THE CLAIMED TAX BENEFITS THEREFROM HAVE BEEN REVIEWED, EXAMINED OR APPROVED BY THE INTERNAL REVENUE SERVICE. _____________________________________ ADDITIONAL INFORMATION Each prospective investor, or his or her qualified representative named in writing, is hereby offered the opportunity (1) to obtain additional information necessary to verify the accuracy of the information supplied herewith or hereafter, and (2) to ask questions and receive answers concerning the terms and conditions of the offering. If you desire to avail yourself of the opportunity, please contact: Mark E. Schell, Esq. 1000 Kensington Tower I 7130 South Lewis Tulsa, Oklahoma 74136 (918) 493-7700 (iv) The following documents and instruments are available to qualified offerees upon written request: 1. Amended and Restated Certificate of Incorporation and By-Laws of UNIT. 2. Certificate of Incorporation and By-Laws of Unit Petroleum Company. 3. UNIT's Employees' Thrift Plan. 4. UNIT's Stock Option Plan and related prospectuses covering shares of Common Stock issuable upon exercise of outstanding options. 5. UNIT'S Non Employee Directors' Stock Option Plan. 6. The Credit Agreement and the notes payable of UNIT. 7. All periodic reports on Forms 10-K, 10-Q and 8-K and all proxy materials filed by or on behalf of UNIT with the Securities and Exchange Commission pursuant to the Securities Exchange Act of 1934, as amended, during calendar year 1995, the annual report to shareholders and all quarterly reports to shareholders submitted by UNIT to its shareholders during calendar year 1995. 8. The agreements of limited partnership for the prior oil and gas drilling programs and prior employee programs of Unit Petroleum Company, UNIT and Unit Drilling and Exploration Company ("UDEC"). 9. All periodic reports filed with the Securities and Exchange Commission and all reports and information provided to limited partners in all limited partnerships of which Unit Petroleum Company, UNIT or UDEC now serves or has served in the past as a general partner. 10. Form of nominee agreement to be entered into by the Partnership with any party holding record title to Partnership Properties as nominee of the Partnership. 11. The agreement of limited partnership for the Unit 1986 Energy Income Limited Partnership. (v) SUMMARY OF CONTENTS Page SUMMARY OF PROGRAM........................................ 1 Terms of the Offering................................ 1 Risk Factors......................................... 2 Additional Financing................................. 5 Proposed Activities.................................. 5 Application of Proceeds.............................. 6 Participation in Costs and Revenues.................. 7 Compensation......................................... 8 Federal Income Tax Aspects........................... 8 RISK FACTORS.............................................. 8 Investment Risks..................................... 8 Tax Related Risks.................................... 16 Operational Risks................................... 18 TERMS OF THE OFFERING..................................... 21 General.............................................. 21 Limited Partnership Interests........................ 21 Subscription Rights.................................. 22 Payment for Units; Delinquent Installment............ 23 Right of Presentment................................. 24 Rollup or Consolidation of Partnership............... 26 ADDITIONAL FINANCING...................................... 27 Additional Assessments............................... 27 Prior Programs....................................... 28 Partnership Borrowings............................... 28 PLAN OF DISTRIBUTION...................................... 29 Suitability of Investors............................. 30 RELATIONSHIP OF THE PARTNERSHIP, THE GENERAL PARTNER AND AFFILIATES............................................ 30 PROPOSED ACTIVITIES....................................... 31 General.............................................. 31 Partnership Objectives............................... 35 Areas of Interest.................................... 35 Transfer of Properties............................... 35 Record Title to Partnership Properties............... 36 Marketing of Reserves................................ 36 Conduct of Operations................................ 36 APPLICATION OF PROCEEDS................................... 37 (vi) PARTICIPATION IN COSTS AND REVENUES....................... 38 COMPENSATION.............................................. 40 Supervision of Operations............................ 40 Purchase of Equipment and Provision of Services...... 41 Prior Programs....................................... 42 MANAGEMENT................................................ 44 The General Partner.................................. 44 Officers, Directors and Key Employees................ 44 Prior Employee Programs.............................. 47 Ownership of Common Stock............................ 49 Interest of Management in Certain Transactions....... 52 CONFLICTS OF INTEREST..................................... 52 Acquisition of Properties and Drilling Operations.... 52 Participation in UNIT's Drilling or Income Programs.. 54 Transfer of Properties............................... 55 Partnership Assets................................... 56 Transactions with the General Partner or Affiliates.. 56 Right of Presentment Price Determination............. 57 Receipt of Compensation Regardless of Profitability.. 57 Legal Counsel........................................ 57 FIDUCIARY RESPONSIBILITY.................................. 57 General.............................................. 57 Liability and Indemnification........................ 58 PRIOR ACTIVITIES.......................................... 59 Prior Employee Programs.............................. 61 Results of the Prior Oil and Gas Programs............ 63 FEDERAL INCOME TAX ASPECTS................................ 70 General.............................................. 70 Summary of Certain Matters........................... 71 Partnership Classification........................... 71 Taxation of Limited Partners......................... 72 IRS Tax Shelter Registration......................... 80 Partnership Tax Returns and Tax Information.......... 80 Laws Subject to Change............................... 81 State and Local Taxes................................ 82 COMPETITION, MARKETS AND REGULATION....................... 82 Marketing of Production.............................. 82 Regulation of Partnership Operations................. 83 Natural Gas Price Regulation......................... 84 State Regulation of Oil and Gas Production........... 89 Legislative and Regulatory Production and Pricing Proposals.......................................... 89 Production and Environmental Regulation.............. 91 (vii) SUMMARY OF THE LIMITED PARTNERSHIP AGREEMENT.............. 92 Partnership Distributions............................ 92 Deposit and Use of Funds............................. 93 Power and Authority.................................. 93 Rollup or Consolidation of the Partnership........... 94 Limited Liability.................................... 95 Records, Reports and Returns......................... 96 Transferability of Interests......................... 96 Amendments........................................... 99 Voting Rights........................................ 99 Exculpation and Indemnification of the General Partner.................................... 100 Termination.......................................... 100 Insurance............................................ 101 COUNSEL................................................... 101 GLOSSARY.................................................. 102 FINANCIAL STATEMENTS...................................... 107 EXHIBIT A - AGREEMENT OF LIMITED PARTNERSHIP EXHIBIT B - LEGAL OPINION (viii) SUMMARY OF PROGRAM This summary does not purport to be a complete description of the terms and consequences of an investment in the Partnership and is qualified in its entirety by the more detailed information appearing throughout this Private Offering Memorandum (this "Memorandum"). For definitions of certain terms used in this Memorandum, see "GLOSSARY". Terms of the Offering Limited Partnership Interests. Unit 1996 Employee Oil and Gas Limited Partnership, a proposed Oklahoma limited partnership (the "Partnership"), hereby offers 500 preformation units of limited partnership interest ("Units") in the Partnership. The offer is made only to certain employees of Unit Corporation ("UNIT") and its subsidiaries and directors of UNIT (see "TERMS OF THE OFFERING - Subscription Rights"). Unless the context otherwise requires, all references in this Memorandum to UNIT shall include all or any of its subsidiaries. Unit Petroleum Company ("UPC" or the "General Partner"), a wholly owned subsidiary of UNIT, will serve as General Partner of the Partnership. To invest in the Units, the Limited Partner Subscription Agreement and Suitability Statement (the "Subscription Agreement") (see Attachment I to Exhibit A hereto) must be executed and forwarded to the offices of the General Partner at its address listed on the cover of this Memorandum. The Subscription Agreement must be received by the General Partner not later than 5:00 P.M. Central Standard Time on January 31, 1996 (extendable by the General Partner for up to 30 days). Subscription Agreements may be delivered to the office of the General Partner. No payment is required upon delivery of the Subscription Agreement. Payment for the Units will be made either (i) in four equal Installments, the first of such Installments being due on March 15, 1996 and the remaining three of such Installments being due on June 15, 1996, September 15, 1996 and December 15, 1996, respectively, or (ii) through equal deductions from 1996 salary commencing immediately after formation of the Partnership. The purchase price of each Unit is $1,000, and the minimum permis- sible purchase is two Units ($2,000) for each subscriber. Additional Assessments of up to $100 per Unit may be required (see "ADDITIONAL FINANCING - Additional Assessments"). Maximum purchases by employees (other than directors) will be for an amount equal to one-half of their base salaries for calendar year 1996. Each member of the Board of Directors of UNIT may subscribe for up to 150 Units ($150,000). The Partnership must sell at least 50 Units ($50,000) before the Partner- ship will be formed. No Units will be offered for sale after the Effective Date (see "GLOSSARY") except upon compliance with the provisions of Article XIII of the Agreement. The General Partner may, at its option, purchase Units as a Limited Partner, including any amount that may be necessary to meet the minimum number of Units 1 required for formation of the Partnership. The Partnership will terminate on December 31, 2026, unless it is terminated earlier pursuant to the provisions of the Agreement or by operation of law. See "TERMS OF THE OFFERING - Limited Partnership Interests"; "TERMS OF THE OFFERING - Subscription Rights"; and "SUMMARY OF THE LIMITED PARTNERSHIP AGREEMENT - Termination." Units will be offered only to those qualified employees of UNIT or any of its subsidiaries at the date of formation of the Partnership whose annual base salaries for 1996 have been set at $22,680 or more and Directors of UNIT who meet certain financial requirements which will enable them to bear the economic risks of an investment in the Partnership and who can demonstrate that they have sufficient investment experience and expertise to evaluate the risks and merits of such an investment. The offering will be made privately by the officers and directors of UPC or UNIT, except that in states which require participation by a registered broker-dealer in the offer and sale of securities, the Units will be offered through such broker-dealer as may be selected by the General Partner. Any participating broker-dealer may be reimbursed for actual out-of-pocket expenses. Such reimbursements will be borne by the General Partner. Subscription Rights. Only salaried employees of UNIT or any of its subsidiaries who are exempt under the Fair Labor Standards Act and whose annual base salaries for 1996 have been set at $22,680 or more and directors of UNIT are eligible to subscribe for Units. Employees may not purchase Units for an amount in excess of one-half of their base salaries for calendar year 1996. Directors' subscriptions may not be for more than 150 Units ($150,000). Only employees and directors who are U.S. citizens are eligible to participate in the offering. In addition, employees and directors must be able to bear the economic risks of an investment in the Partnership and must have sufficient investment experience and expertise to evaluate the risks and merits of such an investment. See "TERMS OF THE OFFERING - Subscription Rights." Right of Presentment. After December 31, 1997 and annually thereafter, the Limited Partners will have the right to present their Units to the General Partner for purchase. The General Partner will not be obligated to purchase more than 20% of the then outstanding Units in any one calendar year. The purchase price to be paid for the Units will be determined by a specific valuation formula. See "TERMS OF THE OFFERING - Right of Presentment" for a description of the valuation formula and a discussion of the manner in which the right of presentment may be exercised by the Limited Partners. Risk Factors An investment in the Partnership has many risks. The "RISK FACTORS" section of this Memorandum contains a detailed discussion of 2 the most important risks, organized into Investment Risks (the risks related to the Partnership's investment in oil and gas properties and drilling activities, to an investment in the Partnership and to the provisions of the Agreement); Tax Risks (the risks arising from the tax laws as they apply to the Partnership and its investment in oil and gas properties and drilling activities); and Operational Risks (the risks involved in conducting oil and gas operations). The following are certain of the risks which are more fully described under "RISK FACTORS". Each prospective investor should review the "RISK FACTORS" section carefully before deciding to subscribe for Units. Investment Risks: Future oil and natural gas prices are unpredictable. If oil and natural gas prices go down, the Partnership's distributions, if any, to the Limited Partners will be adversely affected. The General Partner is authorized under the Agreement to cause, in its sole discretion, the sale or transfer of the Partnership's assets to, or the merger or consolidation of the Partnership with, another partnership, corporation or other business entity. Such action could have a material impact on the nature of the investment of all Limited Partners. Except for certain transfers to the General Partner and other restricted transfers, the Agreement prohibits a Limited Partner from transferring Units. Thus, except for the limited right of the Limited Partners after December 31, 1997 to present their Units to the General Partner for purchase, Limited Partners will not be able to liquidate their investments. The Partnership could be formed with as little as $50,000 in Capital Contributions (excluding the Capital Contributions of the General Partner). As the total amount of Capital Contributions to the Partnership will determine the number and diversification of Partnership Properties, the ability of the Partnership to pursue its investment objectives may be restricted in the event that the Partnership receives only the minimum amount of Capital Contributions. The drilling and completion operations to be undertaken by the Partnership for the development of oil and natural gas reserves involve the possibility of a total loss of an investment in the Partnership. 3 The General Partner will have the exclusive management and control of all aspects of the business of the Partnership. The Limited Partners will have no opportunity to participate in the management and control of any aspect of the Partnership's activities. Accordingly, the Limited Partners will be entirely dependent upon the management skills and expertise of the General Partner. Conflicts of interest exist and additional conflicts of interest may arise between the General Partner and the Limited Partners, and there are no pre-determined procedures for resolving any such conflicts. Accordingly the General Partner could cause the Partnership to take actions to the benefit of the General Partner but not to the benefit of the Limited Partners. Certain provisions in the Agreement modify what would otherwise be the applicable Oklahoma law as to the fiduciary standards for a general partner in a limited partnership. The fiduciary standards in the Agreement could be less advantageous to the Limited Partners and more advantageous to the General Partner than corresponding fiduciary standards otherwise applicable under Oklahoma law. The purchase of Units may be deemed as consent to the fiduciary standards set forth in the Agreement. There can be no assurances that the Partnership will have adequate funds to provide cash distributions to the Limited Partners. The amount and timing of any such distributions will be within the complete discretion of the General Partner. The amount of any cash distributions which Limited Partners may receive from the Partnership could be insufficient to pay the tax liability incurred by such Limited Partners with respect to income or gain allocated to such Limited Partners by the Partnership. Tax Risks: Tax laws and regulations applicable to partnership investments may change at any time and these changes may be applicable retroactively. The Partnership may not qualify or may fail to continue to qualify as a partnership for federal income tax purposes. 4 Certain allocations of income, gain, loss and deduction of the Partnership among the Partners may be challenged by the Internal Revenue Service (the "Service") resulting in a Limited Partner having to report additional taxable income or being denied a deduction. Operational Risks: The search for oil and gas is highly speculative and the drilling activities conducted by the Partnership may result in a well that may be dry or productive wells that do not produce sufficient oil and gas to produce a profit or result in a return of the Limited Partners' investment. Certain hazards may be encountered in drilling wells which could lead to substantial liabilities to third parties or governmental entities. In addition, governmental regulations or new laws relating to environmental matters could increase Partnership costs, delay or prevent drilling a well, require the Partnership to cease operations in certain areas or expose the Partnership to significant liabilities for violations of such laws and regulations. Additional Financing Additional Assessments. After the Aggregate Subscription received from the Limited Partners has been fully expended or committed and the General Partner's Minimum Capital Contribution has been fully expended, the General Partner may make one or more calls for Additional Assessments from the Limited Partners if additional funds are required to pay the Limited Partners' share of Drilling Costs, Special Production and Marketing Costs or Leasehold Acquisition Costs. The maximum amount of total Additional Assessments which may be called for by the General Partner is $100 per Unit. See "ADDITIONAL FINANCING -- Additional Assessments". Partnership Borrowings. After the General Partner's Minimum Capital Contribution has been expended, the General Partner may cause the Partnership to borrow funds required to pay Drilling Costs, Special Production and Marketing Costs or Leasehold Acquisition Costs of Productive properties. Additionally, the General Partner may, but is not required to, advance funds to the Partnership to pay such costs. See "ADDITIONAL FINANCING -- Partnership Borrowings". Proposed Activities General. The Partnership is being formed for the purposes of acquiring producing oil and gas properties and conducting oil and gas drilling and development operations. The Partnership will, with certain limited exceptions, participate on a proportionate basis with 5 UPC in each producing oil and gas lease acquired and in each oil and gas well commenced by UPC for its own account or by UNIT during the period from January 1, 1996, if the Partnership is formed prior to such date or from the date of the formation of the Partnership if subsequent to January 1, 1996, until December 31, 1996, and will, with certain limited exceptions, serve as a co-general partner with UNIT in any drilling or income programs which may be formed by the General Partner or UNIT in 1996. See "PROPOSED ACTIVITIES". Partnership Objectives. The Partnership is being formed to provide eligible employees and directors the opportunity to participate in the oil and gas exploration and producing property acquisition activities of UNIT during 1996. UNIT hopes that participation in the Partnership will provide the participants with greater proprietary interests in UNIT's operations and the potential for realizing a more direct benefit in the event these operations prove to be profitable. The Partnership has been structured to achieve the objective of providing the Limited Partners with essentially the same economic returns that UNIT realizes from the wells drilled or acquired during 1996. Application of Proceeds The offering proceeds will be used to pay the Leasehold Acquisi- tion Costs incurred by the Partnership to acquire those producing oil and gas leases in which the Partnership participates and the Leasehold Acquisition Costs, exploration, drilling and development costs incurred by the Partnership pursuant to drilling activities in which the Partnership participates. The General Partner estimates (based on historical operating experience) that such costs may be expended as shown below based on the assumption of a maximum number of subscriptions in the first column and a minimum number of subscriptions in the second column: $500,000 $50,000 Program Program -------- ------- Leasehold Acquisition Costs of Properties to Be Drilled.... $ 25,000 $ 2,500 Drilling Costs of Exploratory Wells(1)....................... 25,000 2,500 Drilling Costs of Development Wells(1)....................... 350,000 35,000 Leasehold Acquisition Costs of Productive Properties.......... 100,000 10,000 Reimbursement of General Partner's Overhead Costs(2).... ---------- --------- Total...................... $ 500,000 $ 50,000 6 (1) See "GLOSSARY." (2) The Agreement provides that the General Partner shall be reimbursed by the Partnership for that portion of its general and administrative overhead expense attributable to its conduct of Partnership business and affairs but such reimbursement will be made only out of Partnership Revenue. See "COMPENSATION." Participation in Costs and Revenues Partnership costs, expenses and revenues will be allocated among the Partners in the following percentages: General Limited COSTS AND EXPENSES Partner Partners Organizational and offering costs of the Partnership and any drilling or income programs in which the Partnership participates as a co-general partner 100% 0% All other Partnership costs and expenses Prior to time Limited Partner Capital Contributions are entirely expended 1% 99% After expenditure of Limited Partner Capital Contributions and until expenditure of General Partner's Minimum Capital Contribution 100% 0% After expenditure of General General Part- Limited Partners' Partner's Minimum Capital ner's Per- Percentage(1) Contribution centage(1) REVENUES General Part- Limited Partners' ner's Per- Percentage(1) centage(1) ____________________ 1) See "GLOSSARY." 7 Compensation The General Partner will not receive any management fees in connection with the operation of the Partnership. The Partnership will reimburse the General Partner for that portion of its general and administrative overhead expense attributable to its conduct of Partnership business and affairs. See "COMPENSATION." Federal Income Tax Aspects The General Partner has received an opinion from the law firm of Conner & Winters, A Professional Corporation, to the effect that, for federal income tax purposes, the Partnership will be classified as a partnership and not as an association taxable as a corporation. Such opinion is based on certain premises as stated therein and is not binding on the Service or the courts. The General Partner will not apply for a ruling from the Service with respect to such matter and the Partnership may not meet all the conditions which must be met before a ruling will be issued. See "FEDERAL INCOME TAX ASPECTS - Partnership Classification." THIS MEMORANDUM CONTAINS AN EXPLANATION OF THE MORE SIGNIFICANT TERMS AND PROVISIONS OF THE AGREEMENT OF LIMITED PARTNERSHIP WHICH IS ATTACHED AS EXHIBIT A. THE SUMMARY OF THE AGREEMENT CONTAINED IN THIS MEMORANDUM IS QUALIFIED IN ITS ENTIRETY BY SUCH REFERENCE AND ACCORDINGLY THE AGREEMENT SHOULD BE CAREFULLY REVIEWED AND CONSIDERED. RISK FACTORS Prospective purchasers of Units should carefully study the information contained in this Memorandum and should make their own evaluations of the probability for the discovery of oil and natural gas through exploration. INVESTMENT RISKS Financial Risks of Drilling Operations The Partnership will participate with the General Partner (including, with certain limited exceptions, other drilling programs sponsored by it, or UNIT) and, in some cases, other parties ("joint interest parties") in connection with drilling operations conducted on properties in which the Partnership has an interest. It is not anticipated that all such drilling operations will be conducted under turnkey drilling contracts and, thus, all of the parties participating in the drilling operations on a particular property, including the Partnership, may be fully liable for their proportionate share of all costs of such operations even if the actual costs significantly exceed the original cost estimates. Further, if any joint interest party defaults in its obligation to pay its share of the costs, the other joint interest parties may be required to fund the deficiency until, if ever, it can be collected from the defaulting party. As a result of forced pooling or similar proceedings (see "COMPETITION, 8 MARKETS AND REGULATION"), the Partnership may acquire larger fractional interests in Partnership Properties than originally anticipated and, thus, be required to bear a greater share of the costs of operations. As a result of the foregoing, the Partnership could become liable for amounts significantly in excess of the amounts originally anticipated to be expended in connection with the operations and, in such event, would have only limited means for providing needed additional funds (see "ADDITIONAL FINANCING"). Also, if a well is operated by a company which does not or cannot pay the costs and expenses of drilling or operating a Partnership Well, the Partnership's interest in such well may become subject to liens and claims of creditors who supplied services or materials in connection with such operations even though the Partnership may have previously paid its share of such costs and expenses to the operator. If the operator is unable or unwilling to pay the amount due, the Partnership might have to pay its share of the amounts owing to such creditors in order to preserve its interest in the well which would mean that it would, in effect, be paying for certain of such costs and expenses twice. Dependence Upon General Partner The Limited Partners will acquire interests in the Partnership, not in the General Partner or UNIT. They will not participate in either increases or decreases in the General Partner's or UNIT's net worth or the value of its common stock. Nevertheless, because the General Partner is primarily responsible for the proper conduct of the Partnership's business and affairs and is obligated to provide certain funds that will be required in connection with its operations, a significant financial reversal for the General Partner or UNIT could have an adverse effect on the Partnership and the Limited Partners' interests therein. Under the Partnership Agreement, UPC is designated as the General Partner of the Partnership and is given the exclusive authority to manage and operate the Partnership's business. See "SUMMARY OF THE LIMITED PARTNERSHIP AGREEMENT -- Power and Authority". Accordingly, Limited Partners must rely solely on the General Partner to make all decisions on behalf of the Partnership, as the Limited Partners will have no role in the management of the business of the Partnership. The Partnership's success will depend, in part, upon the management provided by the General Partner, the ability of the General Partner to select and acquire oil and gas properties on which Partnership Wells capable of producing oil and natural gas in commercial quantities may be drilled, to fund the acquisition of revenue producing properties, and to market oil and natural gas produced from Partnership Wells. Conflicts of Interest UNIT and its subsidiaries have engaged in oil and gas exploration and development and in the acquisition of producing properties for their own account and as the sponsors of drilling and income programs formed with 9 third party investors. It is anticipated that UNIT and its subsidiaries will continue to engage in such activities. However, with certain exceptions, it is likely that the Partnership will participate as a working interest owner in all producing oil and gas leases acquired and in all oil and gas wells commenced by the General Partner or UNIT for its own account during the period from January 1, 1996, if the Partnership is formed prior to such date, or from the date of the formation of the Partnership, if subsequent to January 1, 1996, through December 31, 1996 and, with certain limited exceptions, will be a co-general partner of any drilling or income programs, or both, formed by the General Partner or UNIT in 1996. The General Partner will determine which prospects will be acquired or drilled. With respect to prospects to be drilled, certain of the wells which are drilled for the separate account of the Partnership and the General Partner may be drilled on prospects on which initial drilling operations were conducted by UNIT or the General Partner prior to the formation of the Partnership. Further, certain of the Partnership Wells will be drilled on prospects on which the General Partner and possibly future employee programs may conduct additional drilling operations in years subsequent to 1996. Except with respect to its participation as a co-general partner of any drilling or income program sponsored by the General Partner or UNIT, the Partnership will have an interest only in those wells begun in 1996 and will have no rights in production from wells commenced in years other than 1996. Likewise, if additional interests are acquired in wells participated in by the Partnership after 1996, the Partnership will generally not be entitled to participate in the acquisition of such additional interests. See "CONFLICTS OF INTEREST - Acquisition of Properties and Drilling Operations." The Partnership may enter into contracts for the drilling of some or all of the Partnership Wells with affiliates of the General Partner. Likewise the Partnership may sell or market some or all of its natural gas production to an affiliate of the General Partner. These contracts may not necessarily be negotiated on an arm's - length basis. The General Partner is subject to a conflict of interest in selecting an affiliate of the General Partner to drill the Partnership Wells and/or market the natural gas therefrom. The compensation under these contracts will be determined at the time of entering into each such contract, and the costs to be paid thereunder or the sale price to be received will be one which is competitive with the costs charged or the prices paid by unaffiliated parties in the same geographic region. The General Partner will make the determination of what are competitive rates or prices in the area. No provision has been made for an independent review of the fairness and reasonableness of such compensation. See "CONFLICTS OF INTERESTS - Transactions with the General Partner or Affiliates". Prohibition on Transferability; Lack of Liquidity Except for certain transfers (i) to the General Partner, (ii) to or for the benefit of the transferor Limited Partner or members of his or her immediate family sharing the same residence, and (iii) by reason of death 10 or operation of law, a Limited Partner may not transfer or assign Units. The General Partner has agreed, however, that it will, if requested at any time after December 31, 1997, buy Units for prices determined either by an independent petroleum engineering firm or the General Partner pursuant to a formula described under "TERMS OF THE OFFERING - Right of Presentment." This obligation of the General Partner to purchase Units when requested is limited and does not assure the liquidity of a Limited Partner's investment, and the price received may be less than if the Limited Partner continued to hold his or her Units. In addition similar commitments have been made and may hereafter be made to investors in other oil and gas drilling, income and employee programs sponsored by the General Partner or UNIT. There can be no assurance that the General Partner will have the financial resources to honor its repurchase commitments. See "TERMS OF THE OFFERING - Right of Presentment." Delay of Cash Distributions For income tax purposes, a Limited Partner must report his or her distributive share of the income, gains, losses and deductions of the Partnership whether or not cash distributions are made. No cash distributions are expected to be made earlier than the first quarter of 1997. In addition, to the extent that the Partnership utilizes its revenues to repay outside borrowings or otherwise uses its own revenues to finance its activities (see "ADDITIONAL FINANCING"), the funds available for cash distributions by the Partnership may be reduced or unavailable. It is possible that the amount of tax payable by a Limited Partner on his or her distributive share of the income of a Partnership will exceed cash distributions from the Partnership. See "FEDERAL INCOME TAX ASPECTS." The date any distributions commence and their subsequent timing or amount cannot be accurately predicted. The decision as to whether or not the Partnership will make a cash distribution at any particular time will be made solely by the General Partner. Limitations on Voting and Other Rights of Limited Partners The Agreement, as permitted under the Oklahoma Revised Uniform Limited Partnership Act (the "Act"), eliminates or limits the rights of the Limited Partners to take certain actions, such as: withdrawing from the Partnership, transferring Units without restrictions, or consenting to or voting upon certain matters such as: (i) admitting a new General Partner, (ii) admitting Substituted Limited Partners, and 11 (iii) dissolving the Partnership. Furthermore, the Agreement imposes restrictions on the exercise of voting rights granted to Limited Partners. See "SUMMARY OF THE LIMITED PARTNERSHIP AGREEMENT -- Voting Rights." Without the provisions to the contrary which are contained in the Agreement, the Act provides that certain actions can be taken only with the consent of all Limited Partners. Those provisions of the Agreement which provide for or require the vote of the Limited Partners, generally permit the approval of a proposal by the vote of Limited Partners holding a majority of the outstanding Units. See "SUMMARY OF THE LIMITED PARTNERSHIP AGREEMENT -- Voting Rights." Thus, Limited Partners who do not agree with or do not wish to be subject to the proposed action may nevertheless become subject to the action if the required majority approval is obtained. Notwithstanding the rights granted to Limited Partners under the Agreement and the Act, the General Partner retains substantial discretion as to the operation of the Partnership. Rollup or Consolidation of Partnership Under the terms of the Agreement, at any time two years or more after the Partnership has completed substantially all of its property acquisition, drilling and development operations, the General Partner is authorized to cause the Partnership to transfer its assets to, or to merge or consolidate with, another partnership or a corporation or other entity for the purpose of combining the oil and gas properties and other assets of the Partnership with those of other partnerships formed for investment or participation by the employees, directors and/or consultants of UNIT or any of its subsidiaries. Such transfer or combination may be effected without the vote, approval or consent of the Limited Partners. In such event, the Limited Partners will receive interests in the transferee or resulting entity which will mean that they will most likely participate in the results of a larger number of properties but will have proportionately smaller allocable interests therein. Any such transaction is required to be effected in a manner which UNIT and the General Partner believe is fair and equitable to the Limited Partners but there can be no assurance that such transaction will in fact be in the best interests of the Limited Partners. Limited Partners have no dissenters' or appraisal rights under the terms of the Agreement or the Act. Such a transaction will result in the termination and dissolution of the Partnership. While there can be no assurance that the Partnership will participate in such a transaction, the General Partner currently anticipates that the Partnership will, at the appropriate time, be involved in such a transaction. See "TERMS OF OFFERING", and "SUMMARY OF THE LIMITED PARTNERSHIP AGREEMENT." Partnership Borrowings The General Partner has the authority to cause the Partnership to borrow additional funds in the future to pay certain costs of the Partnership. While the use of additional financing to preserve the Partnership's equity in oil and gas properties is intended to increase the 12 Partnership's profits, such financing could have the effect of increasing the Partnership's losses if the Partnership is unsuccessful. In addition, the Partnership may have to mortgage its oil and gas properties and other assets in order to obtain additional financing. If the Partnership defaults on such indebtedness, the lender may foreclose and the Partnership could lose its investment in such oil and gas properties and other assets. See "ADDITIONAL FINANCING -- Partnership Borrowings." Limited Liability Under the Act a Limited Partner's liability for the obligations of the Partnership is limited to such Limited Partner's Capital Contribution and such Limited Partner's share of Partnership assets. In addition, if a Limited Partner receives a return of any part of his or her Capital Contribution, such Limited Partner is generally liable to the Partnership for a period of one year thereafter (or six years in the event such return is in violation of the Agreement) for the amount of the returned contribution. A Limited Partner will not otherwise be liable for the obligations of the Partnership unless, in addition to the exercise of his or her rights and powers as a Limited Partner, such Limited Partner participates in the control of the business of the Partnership. The Agreement provides that by a vote of a majority in interest, the Limited Partners may effect certain changes in the Partnership such as termination and dissolution of the Partnership and amendment of the Agreement. The exercise of any of these and certain other rights is conditioned upon receipt of an opinion by counsel for the Limited Partners or an order or judgment of a court of competent jurisdiction to the effect that the exercise of such rights will not result in the loss of the limited liability of the Limited Partners or cause the Partnership to be classified as an association taxable as a corporation (see "SUMMARY OF THE LIMITED PARTNERSHIP AGREEMENT - Amendments" and "SUMMARY OF THE LIMITED PARTNERSHIP AGREEMENT - Termination"). As a result of certain judicial opinions it is not clear that these rights will ever be available to the Limited Partners. Nevertheless, in spite of the receipt of any such opinion or judicial order, it is still possible that the exercise of any such rights by the Limited Partners may result in the loss of the Limited Partners' limited liability. The Partnership will be governed by the Act. The Act expressly permits limited partners to vote on certain specified partnership matters without being deemed to be participating in the control of the Partner- ship's business and, thus, should result in greater certainty and more easily obtainable opinions of counsel regarding the exercise of most of the Limited Partners' rights. If the Partnership is dissolved and its business is not to be continued, the Partnership will be wound up. In connection with the winding up of the Partnership, all of its properties may be sold and the proceeds thereof credited to the accounts of the Partners. Properties not sold will, upon termination of the Partnership, be distributed to the Partners. The distribution of Partnership Properties to the Limited 13 Partners would result in their having unlimited liability with respect to such properties. See "SUMMARY OF THE LIMITED PARTNERSHIP AGREEMENT - Limited Liability." Partnership Acting as Co-General Partner It is currently anticipated that the Partnership will serve as a co-general partner in any drilling or income programs formed by the General Partner or UNIT during 1996. See "PROPOSED ACTIVITIES." Accordingly, the Partnership generally will be liable for the obligation and recourse liabilities of any such drilling or income program formed. While a Limited Partner's liability for such claims will be limited to such Limited Partners Capital Contribution and share of Partnership assets, such claims if satisfied from the Partnership's assets could adversely affect the operations of the Partnership. Past-Due Installments; Acceleration; Additional Assessments Installments and Additional Assessments (see "ADDITIONAL FINANCING") are legally binding obligations and past-due amounts will bear interest at the rate set forth in the Agreement; provided, however, that if the General Partner determines that the total Aggregate Subscription is not required to fund the Partnership's business and operations, then the General Partner may, at its sole option, elect to release the Limited Partners from their obligation to pay one or more Installments and amend any relevant Partnership documents accordingly. It is currently anticipated that the total Aggregate Subscription will be required to fund the Partnership's business and operations. In the event an Installment is not paid when due and the General Partner has not released the Limited Partners from their obligation to pay such Installment, then the General Partner may, at its sole option, purchase all Units of the director or employee who fails to pay such Installment, at a price equal to the amount of the prior Installments paid by such person. The General Partner may also bring legal proceedings to collect any unpaid Installments not waived by it or Additional Assessments. In addition, as indicated under "TERMS OF THE OFFERING - Payment for Units; Delinquent Installment," if an employee's employment with or position as a director of the General Partner, UNIT or any affiliate thereof is terminated other than by reason of Normal Retire- ment (see "GLOSSARY"), death or disability prior to the time the full amount of the subscription price for his or her Units has been paid, all unpaid Installments not waived by the General Partner as described above will become due and payable upon such termination. Partnership Funds Except for Capital Contributions, Partnership funds are expected to be commingled with funds of the General Partner or UNIT. Thus, Partnership funds could become subject to the claims of creditors of the General Partner or UNIT. The General Partner believes that its assets and net worth are such that the risk of loss to the Partnership by virtue of such 14 fact is minimal but there can be no assurance that the Partnership will not suffer losses of its funds to creditors of the General Partner or UNIT. Compliance With Federal and State Securities Laws This offering has not been registered under the Securities Act of 1933, as amended, in reliance upon exemptive provisions of said act. Further, these interests are being sold pursuant to exemptions from registration in the various states in which they are being offered and may be subject to additional restrictions in such jurisdictions on transfer. There is no assurance that the offering presently qualifies or will continue to qualify under such exemptive provisions due to, among other things, the adequacy of disclosure and the manner of distribution of the offering, the existence of similar offerings conducted by the General Partner or UNIT or its affiliates in the past or in the future, a failure or delay in providing notices or other required filings, the conduct of other oil and gas activities by the General Partner or UNIT and its affiliates or the change of any securities laws or regulations. If and to the extent suits for rescission are brought and successfully concluded for failure to register this offering or other offerings under the Securities Act of 1933, as amended, or state securities acts, or for acts or omissions constituting certain prohibited practices under any of said acts, both the capital and assets of the General Partner and the Partnership could be adversely affected, thus jeopardizing the ability of the Partnership to operate successfully. Further, the time and capital of the General Partner could be expended in defending an action by investors or by state or federal authorities even where the Partnership and the General Partner are ultimately exonerated. Nominee Agreements The Partnership Agreement empowers the General Partner, UNIT or any of their affiliates, to hold title to the Partnership Properties as nominee for the benefit of the Partnership. If title to the Partnership Properties is held in the name of a nominee, the nominee will act as nominee for the Partnership pursuant to a form of Nominee Agreement to be entered into between the nominee and the Partnership. In some jurisdictions, such interests could be subject to the claims of creditors of such nominee. The General Partner is of the opinion that the likelihood of the occurrence of such claims is remote, due to the fact that executed nominee agreements will appear in the files of the General Partner and the nominee (if other than the General Partner). It is possible that the nominee agreement would be disregarded, however, in which case Partnership Property could be subject to claims and litigation in the event that the nominee failed to pay its debts or became subject to the claims of creditors. The General Partner may elect to hold title to Partnership Properties permanently in the name of a nominee for the Partnership provided such arrangement is evidenced by a nominee agreement and the nominee conducts no 15 business or operations other than holding record title to interests in properties. See "PROPOSED ACTIVITIES -- Record Title To Partnership Properties." Based on certain representations discussed under "FEDERAL INCOME TAX ASPECTS -- Taxation of Limited Partners -- Nominee Ownership of Partnership Properties," Counsel is of the opinion that the Partnership will be treated, for federal income tax purposes, as the owner of the Partnership Properties held by the nominee for the account of the Partnership. Use of Partnership Funds to Exculpate and Indemnify the General Partner The Agreement contains certain provisions which are intended to limit the liability of the General Partner and its affiliates for certain acts or omissions within the scope of the authority conferred upon them by the Agreement. In addition, under the Agreement, the General Partner will be indemnified by the Partnership against losses, judgments, liabilities, expenses and amounts paid in settlement sustained by it in connection with the Partnership so long as the losses, judgments, liabilities, expenses or amounts were not the result of gross negligence or willful misconduct on the part of the General Partner. See "SUMMARY OF THE LIMITED PARTNERSHIP AGREEMENT -- Exculpation and Indemnification of the General Partner." The Partnership Agreement May Limit the Fiduciary Obligation of the General Partner to the Partnership and the Limited Partners The Agreement contains certain provisions which modify what would otherwise be the applicable Oklahoma law relating to the fiduciary standards of the General Partner to the Limited Partners. The fiduciary standards in the Agreement could be less advantageous to the Limited Partners and more advantageous to the General Partner than the corresponding fiduciary standards otherwise applicable under Oklahoma law (although there are very few legal precedents clarifying exactly what fiduciary standards would otherwise be applicable under Oklahoma law). The purchase of Units may be deemed as consent to the fiduciary standards set forth in the Agreement. See "FIDUCIARY RESPONSIBILITY." As a result of these provisions in the Agreement, the Limited Partners may find it more difficult to hold the General Partner responsible for acting in the best interest of the Partnership and the Limited Partners than if the fiduciary standards of the otherwise applicable Oklahoma law governed the situation. TAX RELATED RISKS Changes in Tax Laws The Internal Revenue Code of 1986, as amended (the "Code"), and regulations and interpretations thereof are subject to change by Congress, the courts and administrative agencies. Regulations have not been issued or proposed under many of the provisions of recent legislation. For these reasons, no assurance can be given that the interpretations of the federal income tax laws included herein will not be challenged or if challenged, will be sustained. Notwithstanding enactment of additional legislation 16 further modifying, reducing or eliminating any or all tax benefits, or new interpretations of law which might require treatment different from that described under "FEDERAL INCOME TAX ASPECTS," the Partnership is authorized to expend the Capital Contributions of the Limited Partners and to conduct the Partnership's business, affairs and operations as described in the Agreement, and each item of Partnership Revenue, gain, loss, cost or expense will be shared or borne in the manner specified therein. Partnership Audits; Interest on Tax Deficiencies If the Service audits a Partnership tax return, no assurance can be given that tax adjustments will not be made. Any such adjustments could increase the likelihood of audits of the personal returns of the Limited Partners which could result in adjustments of any items of income, gain, loss, deduction or credit included in those personal returns regardless of whether those items relate to the Partnership. Any deficiency assessed against a taxpayer will bear interest at an annual rate equal to the 3-month Treasury bill rate plus three percentage points. This interest rate will be adjusted quarterly, with the new rate becoming effective two months after the date of each adjustment. The annual rate which commenced October 1, 1995 is 9% (compounded daily), but, as stated, such rate may change every three months. In addition, audits of Partnership taxable years will be conducted at the Partnership level rather than at the Partner level. The Code also gives certain authority to the "Tax Matters Partner" to deal with any Service audit, assessment and administrative and judicial proceedings. The General Partner will be the "Tax Matters Partner" for the Partnership. See "FEDERAL INCOME TAX ASPECTS - Partnership Tax Returns and Tax Information." Status as a Partnership The tax benefits of oil and gas investments will be unavailable to the Limited Partners if the Partnership is not held to be a partnership for federal income tax purposes. The General Partner has not obtained a ruling from the Service that the Partnership will be treated, for federal income tax purposes, as a partnership rather than as an association taxable as a corporation and the Partnership probably will not meet all of the requirements set forth by the Service necessary to obtain such ruling (see "FEDERAL INCOME TAX ASPECTS - Partnership Classification"). Although the General Partner has received an opinion of Conner & Winters, a Professional Corporation, based on certain premises and representations of the General Partner as stated therein, that the Partnership will be classified as a partnership for federal income tax purposes, such opinion is not binding upon the Service and there is no assurance that partnership status will not be challenged. Should the Partnership be held to be an association taxable as a corporation, only the Partnership, and not the Partners, would be entitled to the principal tax benefits, including the deduction for intangible drilling and development costs, and the Partners' after-tax investment return, if any, would be reduced. In such event the Partnership 17 would be taxed on the income and the Partners would be taxed on distributions from the Partnership as dividends to the extent of current or accumulated earnings and profits of the Partnership. Excess distributions would be treated first as a reduction of basis and the balance as capital gain. Tax Treatment of Partnership Allocations There are various provisions in the Agreement pertaining to the allocation among Partners of items of income, gain, loss, deduction and credit. There can be no assurance that the allocation provisions of the Agreement will not be challenged by the Service or that such a challenge, if made, would not be sustained by the courts. Also, under the passive activity loss rules, allocations of losses from the Partnership to Limited Partners may not be deductible currently. See "FEDERAL INCOME TAX ASPECTS - - Partnership Allocations, Partnership Losses and Limitations on Losses and Credits from Passive Activities." Disproportionate Tax Liability upon Transfer Under the terms of the Agreement, distributions of Partnership Revenue will be made to those persons who were the record holders of Units on the day the distribution is made even if that person did not own his or her Units during all of the calendar year with respect to which the distribution is being made. See "SUMMARY OF THE LIMITED PARTNERSHIP AGREEMENT - Partnership Distributions and Transferability of Interests." However, in allocating Partnership Revenue for federal income tax purposes between a transferor and a transferee of Units, generally each will be allocated that portion of the income realized during the year that is equal to the portion of the year that he or she owned the Units. Because of these different allocation procedures, it is possible that a party to a transfer of Units could be allocated a greater or lesser amount of Partnership Revenue for federal income tax purposes than the amount of distributions he or she actually receives. OPERATIONAL RISKS Risks Inherent in Oil and Gas Operations The Partnership will be participating with the General Partner in acquiring producing oil and gas leases and in the drilling of those oil and gas wells commenced by the General Partner from the later of January 1, 1996 or the time the Partnership is formed through December 31, 1996 and, with certain limited exceptions, serving as a co-general partner of any oil and gas drilling or income programs, or both, formed by the General Partner or UNIT during 1996. All drilling to establish productive oil and natural gas properties is inherently speculative. The techniques presently available to identify the existence and location of pools of oil and natural gas are indirect, and, therefore, a considerable amount of personal judgment is involved in the 18 selection of any prospect for drilling. The economics of oil and natural gas drilling and production are affected or may be affected in the future by a number of factors which are beyond the control of the General Partner, including (i) the general demand in the economy for energy fuels, (ii) the worldwide supply of oil and natural gas, (iii) the price of, as well as governmental policies with respect to, oil imports, (iv) potential competition from competing alternative fuels, (v) governmental regulation of prices for oil and natural gas, (vi) state regulations affecting allowable rates of production, well spacing and other factors, and (vii) availability of drilling rigs, casing and other necessary goods and services. See "COMPETITION, MARKETS AND REGULATION." The revenues, if any, generated from Partnership operations will be highly dependent upon the future prices and demand for oil and natural gas. The factors enumerated above affect, and will continue to affect, oil and natural gas prices. Recently, prices for oil and natural gas have fluctuated over a wide range. Operating and Environmental Hazards Operating hazards such as fires, explosions, blowouts, unusual formations, formations with abnormal pressures and other unforeseen conditions are sometimes encountered in drilling wells. On occasion, substantial liabilities to third parties or governmental entities may be incurred, the payment of which could reduce the funds available for exploration and development or result in loss of Partnership Properties. The Partnership will attempt to maintain customary insurance coverage, but the Partnership may be subject to liability for pollution and other damages or may lose substantial portions of its properties due to hazards against which it cannot insure or against which it may elect not to insure due to unreasonably high or prohibitive premium costs or for other reasons. The activities of the Partnership may expose it to potential liability for pollution or other damages under laws and regulations relating to environmental matters (see "Government Regulation and Environmental Risks" below). Competition The oil and gas industry is highly competitive. The Partnership will be involved in intense competition for the acquisition of quality undeveloped leases and producing oil and gas properties. There can be no assurance that a sufficient number of suitable oil and gas properties will be available for acquisition or development by the Partnership. The Partnership will be competing with numerous major and independent companies which possess financial resources and staffs larger than those available to it. The Partnership, therefore, may be unable in certain instances to acquire desirable leases or supplies or may encounter delays in commencing or completing Partnership operations. 19 Markets for Oil and Natural Gas Production There is currently a worldwide surplus of oil production capacity. Historically (prior to the early 1980s), world oil prices were established and maintained largely as a result of the actions of members of OPEC to limit, and maintain a base price for, their oil production. In more recent years, however, members of OPEC have been unable to agree to and maintain price and production controls, which has resulted in significant downward pressure on oil prices. Although future levels of production by the members of OPEC or the degree to which oil prices will be affected thereby cannot be predicted, it is possible that prices for oil produced in the future will be higher or lower than those currently available. There can be no assurance that the Partnership will be able to market any oil that it produces or, if such oil can be marketed, that favorable price and other contractual terms can be negotiated. See "COMPETITION, MARKETS AND REGULATION - Marketing of Production." The natural gas market is also currently unsettled due to a number of factors. In the past, production from natural gas wells in some geographic areas of the United States has been curtailed for considerable periods of time due to a lack of market demand. In addition, there may be an excess supply of natural gas in areas where Partnership Wells are located. In that event, it is possible that such Partnership Wells will be shut-in or that natural gas in these areas will be sold on terms less favorable than might otherwise be obtained. Competition for available markets has been vigorous and there remains great uncertainty about prices that purchasers will pay. In recent years, significant court decisions and regulatory changes have affected the natural gas markets. As a result of such court decisions, regulatory changes and unsettled market conditions, natural gas regulations may be modified in the future and may be subject to further judicial review or invalidation. The combination of these factors, among others, makes it particularly difficult to estimate accurately future prices of natural gas, and any assumptions concerning future prices may prove incorrect. Natural gas surpluses could result in the Partnership's inability to market natural gas profitably, causing Partnership Wells to curtail production and/or receive lower prices for its natural gas, situations which would adversely affect the Partnership's ability to make cash distributions to its participants. See "COMPETITION, MARKETS AND REGULATION." In the event that the Partnership discovers or acquires natural gas reserves, there may be delays in commencing or continuing production due to the need for gathering and pipeline facilities, contract negotiation with the available market, pipeline capacities, seasonal takes by the gas purchaser or a surplus of available gas reserves in a particular area. Government Regulation and Environmental Risks The oil and gas business is subject to pervasive government regulation under which, among other things, rates of production from producing 20 properties may be fixed and the prices for gas produced from such producing properties may be impacted. It is possible that these regulations pertaining to rates of production could become more pervasive and stringent in the future. The activities of the Partnership may expose it to potential liability under laws and regulations relating to environmental matters which could adversely affect the Partnership. Compliance with these laws and regulations may increase Partnership costs, delay or prevent the drilling of wells, delay or prevent the acquisition of otherwise desirable producing oil and gas properties, require the Partnership to cease operations in certain areas, and cause delays in the production of oil and gas. See "COMPETITION, MARKETING AND REGULATION." Leasehold Defects In certain instances, the Partnership may not be able to obtain a title opinion or report with respect to a producing property that is acquired. Consequently, the Partnership's title to any such property may be uncertain. Furthermore, even if certain technical defects do appear in title opinions or reports with respect to a particular property, the General Partner, in its sole discretion, may determine that it is in the best interest of the Partnership to acquire such property without taking any curative action. TERMS OF THE OFFERING General 500 Maximum Units; 50 Minimum Units $1,000 Units; Minimum subscription: $2,000 Minimum Partnership: $50,000 in subscriptions Maximum Partnership: $500,000 in subscriptions Limited Partnership Interests The Partnership hereby offers to certain employees (described under "Subscription Rights" below) and directors of UNIT and its subsidiaries an aggregate of 500 Units. The purchase price of each Unit is $1,000, and the minimum permissible purchase by any eligible subscriber is two Units ($2,000). See "Subscription Rights" below for the maximum number of Units that may be acquired by subscribers. The Partnership will be formed as an Oklahoma limited partnership upon the closing of the offering of Units made by this Memorandum. The General Partner will be Unit Petroleum Company (the "General Partner", or "UPC"), an Oklahoma corporation. Partnership operations will be conducted from the General Partner's offices, the address of which is 1000 Kensington Tower I, 7130 South Lewis Avenue, Tulsa, Oklahoma 74136, telephone (918) 493-7700. 21 The offering of Units will be closed on January 31, 1996 unless extended by the General Partner for up to 30 days, and all Units subscribed will be issued on the Effective Date. The offering may be withdrawn by the General Partner at any time prior to such date if it believes it to be in the best interests of the eligible employees and Directors or the General Partner not to proceed with the offering. If at least 50 Units ($50,000) are not subscribed prior to the termination of the offering, the Partnership will not commence business. The General Partner may, on its own accord, purchase Units and, in such capacity, will enjoy the same rights and obligations as other Limited Partners, except the General Partner will have unlimited liability. The General Partner may, in its discretion, purchase Units sufficient to reach the minimum Aggregate Subscription ($50,000). Because the General Partner or its affiliates might benefit from the successful completion of this offering (see "PARTICIPATION IN COSTS, AND REVENUES" and "COMPENSATION"), investors should not expect that sales of the minimum Aggregate Subscription indicate that such sales have been made to investors that have no financial or other interest in the offering or that have otherwise exercised independent investment discretion. Further, the sale of the minimum Aggregate Subscription is not designed as a protection to investors to indicate that their interest is shared by other unaffiliated investors and no investor should place any reliance on the sale of the minimum Aggregate Subscription as an indication of the merits of this offering. Units acquired by the General Partner will be for investment purposes only without a present intent for resale and there is no limit on the number of Units that may be acquired by it. Subscription Rights Units are offered only to persons who are salaried employees of UNIT or its subsidiaries at the date of formation of the Partnership and who are exempt under the Fair Labor Standards Act and whose annual base salaries for 1996 (excluding bonuses) have been set at $22,680 or more and to Directors of UNIT. Only employees and Directors who are U.S. citizens are eligible to participate in the offering. In addition, employees and Directors must be able to bear the economic risks of an investment in the Partnership and must have sufficient investment experience and expertise to evaluate the risks and merits of such an investment. See "PLAN OF DISTRIBUTION - Suitability of Investors." Eligible employees and Directors are restricted as to the number of Units they may purchase in the offering. The maximum number of Units which can be acquired by any employee is that number of whole Units which can be purchased with an amount which does not exceed one-half of the employee's base salary for 1996. Each Director of UNIT may subscribe for a maximum of 150 Units (maximum investment of $150,000). At December 13, 1995 there were approximately 112 Directors and employees eligible to purchase Units. 22 Eligible employees and Directors may acquire Units through a corporation or other entity in which all of the beneficial interests are owned by them or permitted assignees (see "SUMMARY OF THE LIMITED PARTNERSHIP AGREEMENT - Transferability of Interests"); provided that such employees or Directors will be jointly and severally liable with such entity for payment of the Capital Subscription. If all eligible employees and Directors subscribed for the maximum number of Units, the Units would be oversubscribed. In that event, Units would be allocated among the respective subscribers in the proportion that each subscription amount bears to total subscriptions obtained. No employee is obligated to purchase Units in order to remain in the employ of UNIT, and the purchase of Units by any employee will not obligate UNIT to continue the employment of such employee. Units may be subscribed for by the spouse or a trust for the minor children of eligible employees and Directors. Payment for Units; Delinquent Installment The Capital Subscriptions of the Limited Partners will be payable either (i) in four equal Installments, the first of such Installments being due on March 15, 1996 and the remaining three of such Installments being due on June 15, 1996, September 15, 1996 and December 15, 1996, respectively, or (ii) by employees so electing in the space provided on the Subscription Agreement, through equal deductions from 1996 salary paid to the employee by the General Partner, UNIT or its subsidiaries commencing immediately after formation of the Partnership. If an employee or Director who has subscribed for Units (either directly or through a corporation or other entity) ceases to be employed by or serve as a Director of the General Partner, UNIT or any of its subsidiaries for any reason other than death, disability or Normal Retirement prior to the time the full amount of all Installments not waived by the General Partner as described below are due, then the due date for any such unpaid Installments shall be accelerated so that the full amount of his or her unpaid Capital Subscription will be due and payable on the effective date of such termination. Each Installment will be a legally binding obligation of the Limited Partner and any past due amounts will bear interest at an annual rate equal to two percentage points in excess of the prime rate of interest of Bank of Oklahoma, N.A., Tulsa, Oklahoma; provided, however, that if the General Partner determines that the total Aggregate Subscription is not required to fund the Partnership's business and operations, then the General Partner may, at its sole option, elect to release the Limited Partners from their obligation to pay one or more Installments. If the General Partner elects to waive the payment of an Installment, it will notify all Limited Partners promptly in writing of its decision and will, to the extent required, amend the certificate of limited partnership and any other relevant Partnership documents accordingly. It is currently anticipated that the total 23 Aggregate Subscription will be required, however, to fund the Partnership's business and operations. In the event a Limited Partner fails to pay any Installment when due and the General Partner has not released the Limited Partners from their obligation to pay such Installment, then the General Partner, at its sole option and discretion, may elect to purchase the Units of such defaulting Limited Partner at a price equal to the total amount of the Capital Contributions actually paid into the Partnership by such defaulting Limited Partner, less the amount of any Partnership distributions that may have been received by him or her. Such option may be exercised by the General Partner by written notice to the Limited Partner at any time after the date that the unpaid Installment was due and will be deemed exercised when the amount of the purchase price is first tendered to the defaulting Limited Partner. The General Partner may, in its discretion, accept payments of delinquent Installments not waived by it but will not be required to do so. In the event that the General Partner elects to purchase the Units of a defaulting Limited Partner, it must pay into the Partnership the amount of the delinquent Installment (excluding any interest that may have accrued thereon) and pay each additional Installment, if any, payable with respect to such Units as it becomes due. By virtue of such purchase, the General Partner will be allocated all Partnership Revenues, be charged with all Partnership costs and expenses attributable to such Units and will enjoy the same rights and obligations as other Limited Partners, except the General Partner will have unlimited liability. Right of Presentment After December 31, 1997, and annually thereafter, Limited Partners will have the right to present their Units to the General Partner for purchase. The General Partner will not be obligated to purchase more than 20% of the then outstanding Units in any one calendar year. The purchase price to be paid for the Units of any Limited Partner presenting them for purchase will be based on the net asset value of the Partnership which shall be equal to: (1) The value of the proved reserves attributable to the Partnership Properties, determined as set forth below; plus (2) The estimated salvage value of tangible equipment installed on Partnership Wells less the costs of plugging and abandoning the wells, both discounted at the rate utilized to determine the value of the Partnership's reserves as set forth below; plus (3) The lower of cost or fair market value of all Partnership Properties to which proved reserves have not been attributed but which have not been condemned, as determined by an independent petroleum engineering firm or the General Partner, as the case may be; plus 24 (4) Cash on hand; plus (5) Prepaid expenses and accounts receivable (less a reasonable reserve for doubtful accounts); plus (6) The estimated market value of all other Partnership assets not included in (1) through (5) above, determined by the General Partner; MINUS (7) An amount equal to all debts, obligations and other liabilities of the Partnership. The price to be paid for each Limited Partner's interest of the net asset value will be his or her proportionate share of such net asset value less 75% of the amount of any distributions received by him or her which are attributable to the sales of the Partnership production since the date as of which the Partnership's proved reserves are estimated. The value of the proved reserves attributable to Partnership Properties will be determined as follows: (i) First, the future net revenues from the production and sale of the proved reserves will be estimated as of the end of the calendar year in which presentment is made based on an independent engineering firm's report and its estimates of price and cost escalations or, if no report was made, as determined by the General Partner; (ii) Next, the future net revenues from the production and sale of proved reserves as determined above will be discounted at an annual rate which is one percentage point higher than the prime rate of interest being charged by the Bank of Oklahoma, N.A., Tulsa, Oklahoma, or any successor bank, as of the date such reserves are estimated; and (iii) Finally, the total discounted value of the future net revenues from the production and sale of proved reserves will be reduced by an additional 25% to take into account the risks and uncertainties associated with the production and sale of the reserves and other unforeseen uncertainties. A Limited Partner who elects to have his Units purchased by the General Partner should be aware that estimates of future net recoverable reserves of oil and gas and estimates of future net revenues to be received therefrom are based on a great many factors, some of which, particularly future prices of production, are usually variable and uncertain and are always determined by predictions of future events. Accordingly, it is common for the actual production and revenues received to vary from earlier estimates. Estimates made in the first few years of production from a property will be based on relatively little production history and will not 25 be as reliable as later estimates based on longer production history. As a result of all the foregoing, reserve estimates and estimates of future net revenues from production may vary from year to year. This right of presentment may be exercised by written notice from a Limited Partner to the General Partner. The sale will be effective as of the close of business on the last day of the calendar year in which such notice is given or, at the General Partner's election, at 7:00 A.M. on the following day. Within 120 days after the end of the calendar year, the General Partner will furnish each Limited Partner who gave such notice during the calendar year a statement showing the cash purchase price which would be paid for the Limited Partner's interest as of December 31 of the preceding year, which statement will include a summary of estimated reserves and future net revenues and sufficient material to reveal how the purchase price was determined. The Limited Partner must, within 30 days after receipt of such statement, reaffirm his or her election to sell to the General Partner. As noted above, the General Partner will not be obligated to purchase in any one calendar year more than 20% of the Units in the Partnership then outstanding. Moreover, the General Partner will not be obligated to purchase any Units pursuant to such right if such purchase, when added to the total of all other sales, exchanges, transfers or assignments of Units within the preceding 12 months, would result in the Partnership being considered to have terminated within the meaning of Section 708 of the Code or would cause the Partnership to lose its status as a partnership for federal income tax purposes. If more than the number of Units which may be purchased are tendered in any one year, the Limited Partners from whom the Units are to be purchased will be determined by lot. Any Units presented but not purchased with respect to one year will have priority for such purchase the following year. The General Partner does not intend to establish a cash reserve to fund its obligation to purchase Units, but will use funds provided by its operations or borrowed funds (if available), using its assets (including such Units purchased or to be purchased from Limited Partners) as collateral to fund such obligations. However, there is no assurance that the General Partner will have sufficient financial resources to discharge its obligations. Rollup or Consolidation of Partnership The Agreement provides that two years or more after the Partnership has completed substantially all of its property acquisition, drilling and development operations, the General Partner may, without the vote, consent or approval of the Limited Partners, cause all or substantially all of the oil and gas properties and other assets of the Partnership to be sold, assigned or transferred to, or the Partnership merged or consolidated with, another partnership or a corporation, trust or other entity for the purpose of combining the assets of two or more of the oil and gas partnerships 26 formed for investment or participation by employees, directors and/or consultants of UNIT or any of its subsidiaries; provided, however, that the valuation of the oil and gas properties and other assets of all such participating partnerships for purposes of such transfer or combination shall be made on a consistent basis and in a manner which the General Partner and UNIT believe is fair and equitable to the Limited Partners. As a consequence of any such transfer or combination, the Partnership shall be dissolved and terminated and the Limited Partners shall receive partnership interests, stock or other equity interests in the transferee or resulting entity. Any such action will cause the Limited Partners' attributable interest in the Partnership Properties to be diluted but it will also provide them with attributable interests in the properties and other assets of the other partnerships participating in the consolidation. It also may reduce somewhat the amount of their attributable shares of the direct and indirect costs of administering the Partnership. However, there may be certain adverse tax consequences resulting from such a transaction. See "RISK FACTORS - Investment Risks - Roll-Up or Consolidation of Partnership." ADDITIONAL FINANCING The General Partner will use its best efforts, consistent with Partnership objectives, to acquire Productive properties and complete the Partnership's drilling and development operations before the Aggregate Subscription has been fully expended or committed. However, funds in addition to the Aggregate Subscription may be required to pay costs and expenses which are chargeable to the Limited Partners. In those instances described below, the General Partner may call for Additional Assessments or may apply Partnership Revenue allocable to the Limited Partners in payment and satisfaction of such costs or the General Partner may, but shall not be required to, fund the deficiency with Partnership borrowings to be repaid with Partnership Revenue. Additional Assessments When the Aggregate Subscription has been fully expended or committed, the General Partner may make one or more calls for any portion or all of the maximum Additional Assessments of $100 per Unit. However, no Additional Assessments may be required before the General Partner's Minimum Capital Contribution has been fully expended. Such assessments may be used to pay the Limited Partners' share of the Drilling Costs, Special Production and Marketing Costs or Leasehold Acquisition Costs of Productive properties which are chargeable to the Limited Partners. The amount of the Additional Assessment so called shall be due and payable on or before such date as the General Partner may set in such call, which in no event will be earlier than thirty (30) days after the date of mailing of the call. The notice of the call for Additional Assessments will specify the amount of the assessment being required, the intended use of such funds, the date on which the contributions are payable and describe the consequences of 27 nonpayment. Although the Limited Partners who do not respond will participate in production, if any, obtained from operations conducted with the proceeds from the aggregate Additional Assessments paid into the Partnership, the amount of the unpaid Additional Assessment shall bear interest at the annual rate equal to two (2) percentage points in excess of the prime rate of interest of Bank of Oklahoma, N.A., Tulsa, Oklahoma, or successor bank, as announced and in effect from time to time, until paid. The Partnership will have a lien on the defaulting Limited Partner's interest in the Partnership and the General Partner may retain Partnership Revenue otherwise available for distribution to the defaulting Limited Partner until an amount equal to the unpaid Additional Assessment and interest is received. Furthermore, the General Partner may satisfy such lien by proceeding with legal action to enforce the lien and the defaulting Limited Partner shall pay all expenses of collection, including interest, court costs and a reasonable attorney's fee. Prior Programs In the prior employee programs conducted by UNIT or the General Partner in each of the years 1984 through 1995, Additional Assessments could be called for as provided herein. At September 30, 1995, there had been no calls for Additional Assessments in such programs. There can be no assurance, however, that Additional Assessments will not be required to pay Partnership costs. Partnership Borrowings At any time after the General Partner's Minimum Capital Contribution has been fully expended, the General Partner may cause the Partnership to borrow funds for the purpose of paying Drilling Costs, Special Production and Marketing Costs or Leasehold Acquisition Costs of Productive properties, which borrowings may be secured by interests in the Partnership Properties and will be repaid, including interest accruing thereon, out of Partnership Revenue. The General Partner may, but is not required to, advance funds to the Partnership for the same purposes for which Partnership borrowings are authorized. With respect to any such advances, the General Partner will receive interest in an amount equal to the lesser of the interest which would be charged to the Partnership by unrelated banks on comparable loans for the same purpose or the General Partner's interest cost with respect to such loan, where it borrows the same. No financing charges will be levied by the General Partner in connection with any such loan. If Partnership borrowings secured by interests in the Partnership Wells and repayable out of Partnership Revenue cannot be arranged on a basis which, in the opinion of the General Partner, is fair and reasonable, and the entire sum required to pay such costs is not available from Partnership Revenue, the General Partner may dispose of some or all of the Partnership Properties upon which such operations were to be conducted by sale, farm-out or abandonment. 28 If the Partnership requires funds to conduct Partnership operations during the period between any of the Installments due from the Limited Partners, then, notwithstanding the foregoing, the General Partner shall advance funds to the Partnership in an amount equal to the funds then required to conduct such operations but in no event more than the total amount of the Aggregate Subscription remaining unpaid. With respect to any such advances, the General Partner shall receive no interest thereon and no financing charges will be levied by the General Partner in connection therewith. The General Partner shall be repaid out of the Installments thereafter paid into the capital of the Partnership when due. The Partnership may attempt to finance any expenses in excess of the Partners' Capital Subscriptions by the foregoing means and any other means which the General Partner deems in the best interests of the Partnership, but the Partnership's inability to meet such costs could result in the deferral of drilling operations or in the inability to participate in future drilling or in non-consent penalties pursuant to which co-owners of particular working interests recover several times the amount which would have been funded by the Partnership in accordance with its ownership interest before the Partnership would participate in revenues. The use of Partnership Revenue allocable to the Limited Partners to pay Partnership costs and expenses and to repay any Partnership borrowings will mean that such revenue will not be available for distribution to the Limited Partners. Nonetheless, the Limited Partners may incur income tax liability by virtue of that revenue and, thus, may not receive distributions from the Partnership in amounts necessary to pay such income tax. However, the use of such revenue to pay Partnership costs and expenses may generate additional deductions for the Limited Partners. PLAN OF DISTRIBUTION Units will be offered privately only to select persons who can demonstrate to the General Partner that they have both the economic means and investment expertise to qualify as suitable investors. It is anticipated that the Units will be offered and sold by the officers and directors of UPC or UNIT, except that in states which require participation by a registered broker-dealer in the offer and sale of securities the Units will be offered through such broker-dealer as may be selected by the General Partner. Such broker-dealer's activities in connection with the offering of interests in the Partnership will be limited solely to such activities as are technically required by state laws with respect to the offer of securities by brokers or dealers. Such broker-dealer will not receive any fees or sales commission but will be reimbursed for actual out-of- pocket expenses. Such expenses will be part of the organizational costs to be paid by the General Partner. 29 Suitability of Investors Subscriptions should be made only by appropriate persons who can reasonably benefit from an investment in the Partnership. In this regard, a subscription will generally be accepted only from a person who can represent that such person has (or in the case of a husband and wife, acting as joint tenants, tenants in common or tenants in the entirety, that they have) a net worth, including home, furnishings and automobiles, of at least five times the amount of his or her Capital Subscription, and estimates that such person will have during the current year adjusted gross income in an amount which will enable him or her to bear the economic risks of his or her investment in the Partnership. Such person must also demonstrate that he or she has sufficient investment experience and expertise to evaluate the risks and merits of an investment in the Partnership. Participation in the Partnership is intended only for those persons willing to assume the risk of a speculative, illiquid, long-term investment. Entitlement to and maintenance of the exemptions from registration provided by Sections 3(b) and/or 4(2) of the Securities Act of 1933, as amended, require the imposition of certain limitations on the persons to whom offers may be made, and from whom subscriptions may be accepted. Therefore, this offering is limited to persons who, by virtue of investment acumen or financial resources, satisfy the General Partner that they meet suitability standards consistent with the maintenance and preservation of the exemptions provided by Sections 3(b) and/or 4(2) and by the applicable rules and regulations of the Securities and Exchange Commission, as well as those contained herein and in the Subscription Agreement. Persons offering interests shall sufficiently inquire of a prospective investor to be reasonably assured that such investor meets such acceptable standards. Suitability standards may also be imposed by the regulatory authorities of the various states in which interests may be offered. RELATIONSHIP OF THE PARTNERSHIP, THE GENERAL PARTNER AND AFFILIATES The following diagram depicts the primary relationships among the Partnership, the General Partner and certain of its affiliates. 30 UNIT CORPORATION ---------------- ( ----------------------(-------------------( ( ( ( ( Unit Petroleum Company Unit Drilling Company ---------------------- --------------------- ( General Partner ( ( ( ( Unit 1996 Employee Oil & Gas Limited Partnership ----------------------- ( Limited Partners ( ( ( ( Eligible Employees and Directors ------------------------ PROPOSED ACTIVITIES General The Partnership will, with certain limited exceptions, participate in all of UNIT's or UPC's oil and gas activities commenced during 1996. The Partnership will acquire 5% of essentially all of UNIT's interest in such activities. The activities will include (i) participating as a joint working interest owner with UNIT or UPC in any producing leases acquired and in any wells commenced by UNIT or UPC other than as a general partner in a drilling or income program during 1996 and (ii) serving as a co-general partner in any drilling or income programs, or both, formed by the General Partner or UNIT during 1996. Acquisition of Properties and Drilling Operations. The Partnership will participate, to the extent of 5% of UPC or UNIT's final interest in each well, as a fractional working interest holder in any producing leases acquired and in any drilling operations conducted by UPC or UNIT for its own account which are acquired or commenced, respectively, from January 1, 1996, or the time of the formation of the Partnership if subsequent to January 1, 1996, until December 31, 1996, except for wells, if any: (i) drilled outside the 48 contiguous United States; (ii) drilled as part of secondary or tertiary recovery operations which were in existence prior to formation of the Partnership; 31 (iii) drilled by third parties under farm-out or similar arrangements with UNIT or the General Partner or whereby UNIT or the General Partner may be entitled to an overriding royalty, reversionary or other similar interest in the production from such wells but is not obligated to pay any of the Drilling Costs thereof; (iv) acquired by UNIT or the General Partner through the acquisition by UNIT or the General Partner of, or merger of UNIT or the General Partner with, other companies (However, this exception may, at the discretion of Unit or the General Partner, be waived); or (v) with respect to which the General Partner does not believe that the potential economic return therefrom justifies the costs of participation by the Partnership. Instances referred to in (v) could occur when UNIT or one of its subsidiaries agrees to participate in the ownership of a prospect for its own account in order to obtain the contract to drill the well thereon. There may be situations where the potential economic return of the well alone would not be sufficient to warrant participation by UNIT but when considered in light of the revenues expected to be realized as a result of the drilling contract, such participation is desirable from UNIT's stand- point. However, in such a situation, the Partnership would not be entitled to any of the revenues generated by the drilling contract so its participation in the well would not be desirable. For these purposes, the drilling of a well will be deemed to have commenced on the "spud date," i.e., the date that the drilling rig is set up and actual drilling operations are commenced. Any clearing or other site preparation operations will not be considered part of the drilling operations for these purposes. Participation in Drilling or Income Programs. Except for certain limited exceptions it is anticipated that the Partnership will participate with UPC or UNIT as a co-general partner of any drilling or income programs, or both, formed by UPC or UNIT and its affiliates during 1996. The Partnership will be charged with 5% of the total costs and expenses charged to the general partners and allocated 5% of the revenues allocable to the general partners in any such program and UPC or UNIT will be charged with the remaining 95% of the general partners' share of costs and expenses and allocated the remaining 95% of the general partners' share of program revenues. UNIT or its affiliates formed drilling programs for outside investors from 1979 through 1984. In 1987, the Unit 1986 Energy Income Limited Partnership (the "1986 Energy Program") was formed primarily to acquire interests in producing oil and gas properties. See "PRIOR ACTIVITIES". All of the programs were formed as limited partnerships and interests in 32 all of the programs other than the Unit 1979 Oil and Gas Program and the 1986 Energy Program were offered in registered public offerings. The 1979 Program and 1986 Energy Program were offered privately to a limited number of sophisticated investors. No drilling or income programs for third party investors were formed in 1995. Although it does not currently contemplate doing so, UNIT may form such drilling or income programs during 1996. If such a program is formed, there would be only one or two such programs and they probably would be privately offered. The precise revenue and cost sharing format of any such programs has not been determined. The cost and revenue sharing provisions of virtually all drilling programs offered to third parties generally require the limited partners or investors to bear a somewhat higher percentage of the program's drilling and development costs than the percentage of program revenues to which they are entitled. Likewise, the general partners will normally receive a higher percentage of revenues than the percentage of drilling and development costs which they are required to pay. The difference in these percentages is often referred to as the general partners' "promote". Any drilling program which UNIT or UPC may form in 1996 for outside investors would likely have some amount of "promote" for the general partner(s). Any income program may use the same or a similar format as that used for the 1986 Partnership. In the 1986 Partnership, virtually all partnership costs and expenses other than property acquisition costs are allocated to the partners in the same percentages that partnership revenue is being shared at the time such expenses are incurred, with property acquisition costs and certain other expenses being charged 85% to the accounts of the limited partners and 15% to the accounts of the general partners. Partnership revenue in the 1986 Partnership is allocated 85% to the limited partners' accounts and 15% to the general partners' accounts until program payout (as defined in the agreement of limited partnership for the 1986 Partnership). After program payout, the percentages of partnership revenue allocable to the respective accounts of the partners depend upon the length of the period during which program payout occurs and range from 60% to the limited partners' accounts and 40% to the general partners' accounts to 85% to the limited partners' accounts and 15% to the general partners' accounts. As co-general partners of any drilling or income programs that may be formed by UNIT and/or UPC during 1996 and participated in by the Partnership, UNIT and/or UPC and the Partnership will share the costs, expenses and revenues allocable to the general partners on a proportionate basis, 95% for the account of UNIT and/or UPC and 5% for the account of the Partnership. The Partnership will not receive any portion of any management fees payable to the general partners nor any fees or payments for supervisory services which UNIT or UPC may render to such programs as operator of program wells or other fees and payments which UNIT or UPC may be entitled to receive from such programs for services rendered to them or goods, materials, equipment or other property sold to them. 33 Extent and Nature of Operations. Although the General Partner maintains a general inventory of prospects, it cannot predict with certainty on which of those prospects wells will be started during 1996 nor can it predict what producing properties, if any, will be acquired by it during 1996. Further, since the General Partner anticipates that the Partnership will acquire a small interest (either directly or through any drilling or income programs of which it or UNIT serves as a general partner) in approximately 30 to 70 wells (however, the exact number of wells may vary greatly depending on the actual activity undertaken), it would be impractical to describe in any detail all of the properties in which the Partnership can be expected to acquire some interest. The Partnership's drilling and development operations are expected to include both Exploratory Wells and comparatively lower-risk Development Wells. Exploratory Wells include both the high-risk "wildcat" wells which are located in areas substantially removed from existing production and "controlled" Exploratory Wells which are located in areas where production has been established and where objective horizons have produced from similar geological features in the vicinity. Based on UNIT's historical profile of its drilling operations, it is presently anticipated that the portion of the Aggregate Subscription expended for Partnership drilling operations (see "APPLICATION OF PROCEEDS") will be spent approximately 6% on Exploratory Wells and 94% on Development Wells. However, these percentages may vary significantly. Certain of the Partnership's Development Wells may be drilled on prospects on which initial drilling operations were conducted by the General Partner or UNIT prior to the formation of the Partnership. Further, certain of the Partnership Wells will be drilled on prospects on which the General Partner, UNIT or possibly future employee programs may conduct additional drilling operations in years subsequent to 1996. In either instance, the Partnership will have an interest only in those wells begun in 1996 and will have no rights in production from wells commenced in years other than 1996 even though such other wells may be located on prospects or spacing units on which Partnership Wells have been drilled. Furthermore, it is possible that in years subsequent to 1996, UNIT, UPC or possibly future employee programs will acquire additional interests in wells participated in by the Partnership. In such event the Partnership will generally not be entitled to share in the acquisition of such additional interests. With respect to the acquisition of producing properties, UNIT will endeavor to diversify its investments by acquiring properties located in differing geographic locations and by balancing its investments between properties having high rates of production in early years and properties with more consistent production over a longer term. See "CONFLICTS OF INTERESTS - Acquisition of Properties and Drilling Operations." 34 Partnership Objectives The Partnership is being formed to provide eligible employees and directors the opportunity to participate in the oil and gas exploration and producing property acquisition activities of UNIT during 1996. UNIT hopes that participation in the Partnership will provide the participants with greater proprietary interests in its operations and the potential for realizing a more direct benefit in the event these operations prove to be profitable. The Partnership has been structured to achieve the objective of providing the Limited Partners with essentially the same economic returns that UNIT realizes from the wells drilled or acquired during 1996. Areas of Interest The Agreement authorizes the Partnership to engage in oil and gas exploration, drilling and development operations and to acquire producing oil and gas properties anywhere in the United States, but the areas presently under consideration are located in the states of Oklahoma, Texas, Louisiana, Kansas, Arkansas, Colorado, Montana, North Dakota and Wyoming. It is possible that the Partnership may drill in inland waterways, riverbeds, bayous or marshes but no drilling in the open seas will be attempted. Plans to conduct drilling and development operations or to acquire producing properties in certain of these states may be abandoned if attractive prospects cannot be obtained upon satisfactory terms or if the Partnership is not fully subscribed. Transfer of Properties In the case of wells drilled or producing properties acquired by the Partnership and UPC or UNIT for their own accounts and not through another drilling or income program, the Partnership will acquire from UPC or UNIT a portion of the fractional undivided working interest in the properties or portions thereof comprising the spacing unit on which a proposed Partnership Well is to be drilled or on which a producing Partnership Well is located, and UPC or UNIT will retain for its own account all or a portion of the remainder of such working interest. Such working interests will be sold to the Partnership for an amount equal to the Leasehold Acquisition Costs attributable to the interest being acquired. Neither UNIT nor its affiliates will retain any overrides or other burdens on the working interests conveyed to the Partnership, and the respective working interests of UPC or UNIT and the Partnership in a property will bear their proportionate shares of costs and revenues. The Partnership's direct interest in a property will only encompass the area included within the spacing unit on which a Partnership Well is to be drilled or on which a producing Partnership Well is located, and, in the case of a Partnership Well to be drilled, it will acquire that interest only when the drilling of the well is ready to commence. If the size of a spacing unit is ever reduced, or any subsequent well in which the Partnership has no interest is drilled thereon, the Partnership will have no interest in any additional wells drilled on properties which were part 35 of the original spacing unit unless such additional wells are commenced during 1996. If additional interests in Partnership Wells are acquired in years subsequent to 1996 the Partnership will generally not be entitled to participate or share in the acquisition of such additional interests. In addition, if the Partnership Well drilled on a spacing unit is dry or abandoned, the Partnership will not have an interest in any subsequent or additional well drilled on the spacing unit unless it is commenced during 1996. The Partnership will never own any significant amounts of undeveloped properties or have an occasion to sell or farm out any undeveloped Partnership Properties. Transfers of properties to any drilling or income programs of which the Partnership serves as a general partner will be governed by the provisions of the agreement of limited partnership in effect with respect thereto. If any such program is to be offered publicly, those provisions will have to be consistent with the provisions contained in the Guidelines for the Registration of Oil and Gas Programs adopted by the North American Securities Administrators Association, Inc. Record Title to Partnership Properties Record title to the Partnership Properties will be held by the Partnership or held in the name of a nominee for the Partnership under a form of nominee agreement to be entered into between the nominee and the Partnership. Under the form of nominee agreement, the nominee will disclaim any beneficial interest in the Partnership Properties held as nominee for the Partnership. Marketing of Reserves The General Partner has the authority to market the oil and gas production of the Partnership. In this connection, it may execute on behalf of the Partnership division orders, contracts for the marketing or sale of oil, gas or other hydrocarbons or other marketing agreements. Sales of the oil and gas production of the Partnership will be to independent third parties or to the General Partner or its affiliates (see "CONFLICTS OF INTEREST"). Conduct of Operations The General Partner will have full, exclusive and complete discretion and control over the management, business and affairs of the Partnership and will make all decisions affecting the Partnership Properties. To the extent that Partnership funds are reasonably available, the General Partner will cause the Partnership to (1) test and investigate the Partnership Properties by appropriate geological and geophysical means, (2) conduct drilling and development operations on such Partnership Properties as it deems appropriate in view of such testing and investigation, (3) attempt completion of wells so drilled if in its opinion conditions warrant the attempt and (4) properly equip and complete productive Partnership Wells. The General Partner will also cause the Partnership's productive wells to 36 be operated in accordance with sound and economical oil and gas recovery practices. The General Partner will operate certain drilling and productive wells on behalf of the Partnership in accordance with the terms of the Agreement (see "COMPENSATION"). In those cases, execution of separate operating agreements will not be necessary unless third party owners are involved, e.g., fractional undivided interest Partnership Properties and Partnership Properties that are pooled or unitized with other properties owned by third parties. In such cases, and in all cases where Partnership Properties are operated by third parties, the General Partner will, where appropriate, make or cause to be made and enter into operating agreements, pooling agreements, unitization agreements, etc., in the form in general use in the area where the affected property is located. The General Partner is also authorized to execute production sales contracts on behalf of the Partnership. APPLICATION OF PROCEEDS The Aggregate Subscription will be used to pay costs and expenses incurred in the operations of the Partnership which are chargeable to the Limited Partners. The organizational costs of the Partnership and the offering costs of the Units will be paid by the General Partner. If all 500 Units offered hereby are sold, the proceeds to the Partnership would be $500,000. If the minimum 50 Units are sold, the proceeds to the Partnership would be $50,000. The General Partner estimates that the gross proceeds will be expended as follows: $500,000 Program $50,000 Program ---------------- --------------- Percent Amount Percent Amount ------- ------ ------- ------ Leasehold Acquisition Costs of Properties to Be Drilled.. 5% $ 25,000 5% $ 2,500 Drilling Costs of Exploratory Wells........................ 5% 25,000 5% 2,500 Drilling Costs of Develop- ment Wells................... 70% 350,000 70% 35,000 Leasehold Acquisition Costs of Productive Properties..... 20% 100,000 20% 10,000 Total..................... 100% $ 500,000 100% $50,000 The foregoing allocation between Drilling Costs and Leasehold Acquisition Costs is solely an estimate and the actual percentages may vary materially from this estimate. Funds otherwise available for drilling Exploratory Wells will be reduced to the extent that such funds are used in conducting development operations in which the Partnership participates. 37 Until Capital Contributions are invested in the Partnership's operations, they will be temporarily deposited, with or without inter- est, in one or more bank accounts of the Partnership or invested in short-term United States government securities, money market funds, bank certificates of deposit or commercial paper rated as "A1" or "P1" as the General Partner deems advisable. Partnership funds other than Capital Contributions may be commingled with the funds of the General Partner or UNIT. PARTICIPATION IN COSTS AND REVENUES All costs of organizing the Partnership and offering Units therein will be paid by the General Partner. All costs incurred in the offer- ing and syndication of any drilling or income program formed by UPC or UNIT and its affiliates during 1996 in which the Partnership participates as a co-general partner will also be paid by the General Partner. All other Partnership costs and expenses will be charged 99% to the Limited Partners and 1% to the General Partner until such time as the Aggregate Subscription has been fully expended. Thereafter and until the General Partner's Minimum Capital Contribution has been fully expended, all of such costs and expenses will be charged to the General Partner. After the General Partner's Minimum Capital Contribution has been fully expended, such costs and expenses will be charged to the respective accounts of the General Partner and the Limited Partners on the basis of their respective Percentages (see "GLOSSARY"). All Partnership Revenues will be allocated between the General Partner and the Limited Partners on the basis of their respective Percentages. The General Partner's Minimum Capital Contribution will be deter- mined as of December 31, 1996 and will be an amount equal to: (a) all costs and expenses previously charged to the General Partner as of that date, plus (b) the General Partner's good faith estimate of the additional amounts that it will have to contribute in order to fund the Leasehold Acquisition Costs and Drilling Costs expected to be incurred by the Partnership after that date. The respective Percentages of the General Partner and the Limited Partners will then be determined as of December 31, 1996 based on the relative contributions of the Partners previously made and expected to be made in the future during the remainder of the Partnership's property acquisition and drilling phases. See "GLOSSARY - General Partner's Minimum Capital Contribution", "General Partner's Percentage" and " Limited Partners' Percentage." If the General Partner's estimate of future Leasehold Acquisition Costs and Drilling Costs proves to be 38 lower than the actual amount of such costs and expenses, the excess amounts will be charged to the Partners on the basis of their respective Percentages and the Limited Partners' share will be paid out of their share of Partnership Revenues, Additional Assessments required of them or the proceeds of Partnership borrowings. See "ADDITIONAL FINANCING." If the General Partner's estimate of such costs and expenses proves to be higher than the actual costs and expenses, the General Partner will continue to bear Partnership costs and expenses that would otherwise have been chargeable to the Limited Partners until the total Partnership costs and expenses charged to it (including, without limitation, offering and organizational costs, Operating Expenses, general and administrative overhead costs and reimbursements and Special Production and Marketing Costs as well as Leasehold Acquisition Costs and Drilling Costs) since the formation of the Partnership equals the General Partner's Minimum Capital Contribution. In addition to actual contributions of cash or properties, any Partner will be deemed to have contributed amounts of Partnership Revenues allocated to it which are used to pay its share of Partnership costs and expenses. The following table presents a summary of the allocation of Partnership costs, expenses and revenues between the General Partner and the Limited Partners: 39 General Limited COSTS AND EXPENSES Partner Partners ------- -------- Organizational and offering costs of the Partnership and any drilling or income programs in which the Partnership participates as a co-general partner 100% 0% All other Partnership Costs and Expenses: Prior to time Limited Partner Capital Contributions are entirely expended 1% 99% After expenditure of Limited Partner Capital Contributions and until expenditure of General Partner's Minimum Capital Contribution 100% 0% After expenditure of General General Part Limited Part Partner's Minimum Capital ner's Per- ners' Per- Contribution centage centage REVENUES General Part Limited Part ner's Per- ners' Per- centage centage COMPENSATION Supervision of Operations It is anticipated that the General Partner will operate most, if not all, Partnership Properties during the drilling of Partnership Wells and most, if not all, productive Partnership Wells. For the General Partner's services performed as operator, the Partnership will compensate the General Partner its pro rata portion of the compensation due to the General Partner under the operating agreements, if any, in effect with respect to such wells or, if none is in effect for such wells, at rates no higher than those normally charged in the same or a comparable geographic area by non-affiliated persons or companies dealing at arm's length. That portion of the General Partner's general and administrative overhead expense that is attributable to its conduct of the actual and necessary business, affairs and operations of the Partnership will be 40 reimbursed by the Partnership out of Partnership Revenue. The General Partner's general and administrative overhead expenses are determined in accordance with industry practices. The costs and expenses to be allocated include all customary and routine legal, accounting, geologi- cal, engineering, travel, office rent, telephone, secretarial, sala- ries, data processing, word processing and other incidental reasonable expenses necessary to the conduct of the Partnership's business and generated by the General Partner or allocated to it by UNIT, but will not include filing fees, commissions, professional fees, printing costs and other expenses incurred in forming the Partnership or offering interests therein. The amount of such costs and expenses to be reim- bursed with respect to any particular period will be determined by allocating to the Partnership that portion of the General Partner's total general and administrative overhead expense incurred during such period which is equal to the ratio of the Partnership's total expendi- tures compared to the total expenditures by the General Partner for its own account. The portion of such general and administrative overhead expense reimbursement which is charged to the Limited Partners may not exceed an amount equal to 3% of the Aggregate Subscription during the first 12 months of the Partnership's operations, and in each succeeding twelve- month period, the lesser of (a) 2% of the Aggregate Subscription and (b) 10% of the total Partnership Revenue realized in such twelve-month period. Administrative expenses incurred directly by the Partnership, or incurred by the General Partner on behalf of the Partnership and reimbursable to the General Partner, such as legal, accounting, auditing, reporting, engineering, mailing and other such fees, costs and expenses are not considered a part of the general and administrative expense reimbursed to the General Partner and the amounts thereof will not be subject to the limitations described in the preceding sentence. Purchase of Equipment and Provision of Services UNIT, through its subsidiary Unit Drilling Company, will probably perform significant drilling services for the Partnership. In addition, UNIT owns a 34% interest in GED Gas Services L.L.C., an Oklahoma Limited Liability Company, which may purchase a portion of the Partnership's gas production. These persons are in the business of supplying such equipment and services to non-affiliated parties in the industry and any such equip- ment and such services will be acquired or provided at prices or rates no higher than those normally charged in the same or comparable geo- graphic area by non-affiliated persons or companies dealing at arms' length. Production purchased by any affiliate of UNIT will be for prices which are not less than the highest posted price (in the case of crude oil) or prevailing price (in the case of natural gas) in the same field or area. UNIT or one of its affiliates may provide other goods or services to the Partnership in which event the compensation received therefor 41 will be subject to the same restrictions and conditions described above and under "CONFLICTS OF INTEREST" below. Prior Programs UNIT was formed in 1986 in connection with a major reorganization and recapitalization whereby UNIT acquired all of the assets and liabilities of all of the limited partnerships formed by UNIT's prede- cessor, Unit Drilling and Exploration Company ("UDEC"), during the period of 1980 through 1983 in exchange for shares of UNIT's common stock and UDEC was merged with a wholly owned subsidiary of UNIT whereby UDEC was the surviving corporation and thereby became a wholly owned subsidiary of UNIT. UNIT has conducted one oil and gas program since the date of its formation, the 1986 Energy Program. The 1986 Energy Program was formed on June 12, 1987 with total subscriptions of one million dollars. The Unit 1986 Employee Oil and Gas Limited Partnership is a co-general partner with Unit Petroleum Company of the 1986 Energy Program. Direct compensation charged to or paid by the partnerships and earned by the General Partners for their services in connection with these programs through September 30, 1995, is set forth below. 42 Compensation for Supervision and Reimbursement Operation of of General Fees Productive and Administrative Received as Management Drilling and Overhead a Drilling Program Fee(1) Wells(2)(3) Expense(2)(3)(4) Contractor(2) - -------------- ----------- --------------- --------------- ---------------- 1979.......... $ 150,000 $1,550,807 $2,184,910 $1,835,726 1980.......... 200,000 261,456 1,345,158 1,810,310 1981.......... 1,250,000 (5) 329,695 1,892,568 4,047,260 1981-II....... 450,000 158,406 1,607,706 1,629,201 1982-A........ 634,200 521,910 1,688,024 4,110,107 1982-B........ 316,650 331,594 1,224,023 4,945,437 1983-A........ 50,600 151,289 698,597 695,255 1984.......... -- 191,323 658,831 829,503 1984 Employee(*) -- 3,924 5,000 13,452 1985 Employee(*) -- 10,316 -- 54,892 1986 Employee(*) -- 23,505 -- 59,446 1986 Energy Income Fund(**) -- 120,297 619,779 64,943 1987 Employee(*) -- 50,688 -- 97,079 1988 Employee(*) -- 93,854 -- 112,861 1989 Employee(*) -- 54,536 -- 165,436 1990 Employee(*) -- 28,884 -- 102,977 1991 Employee. -- 167,323 -- 144,722 1992 Employee. -- 36,604 -- 14,861 1993 Employee. -- 19,453 -- 68,504 Consolidated Program(*) -- 26,511 -- -- 1994 Employee. -- 13,123 -- 40,507 1995 Employee. -- 1,054 -- 10,039 _____________ (*) Effective December 31, 1993, pursuant to an Agreement and Plan of Merger, this employee partnership was merged with and into the Unit Consolidated Employee Oil and Gas Limited Partnership (the "Consolidated Program"), with the latter being the surviving limited partnership. See Prior Activities. (**) Formed primarily for purposes of acquiring producing oil and gas properties. (1) Paid to both UDEC and a prior Key Employee Exploration Fund as general partners. No management fee was payable to UDEC or any of its affiliates by any of the 1984 - 1995 Employee Programs and no management fee is payable by the Partnership to UNIT or any of its affiliates. (2) Paid only to UDEC. 43 (3) In the case of compensation for supervision and operation of productive wells and reimbursement of UNIT's general and administrative overhead expense, the general partners generally were charged with and paid a percentage of such amounts equal to the percentage of partner- ship revenues being allocated to them. (4) Although the partnership agreement for each of the 1985-1995 Employee Programs provides that the General Partner is entitled to reimbursement for the general administrative and overhead expenses attributable to each of such programs, the General Partner has to date elected not to seek such reimbursement. However, there can be no assurance that the General Partner will continue to forego such reimbursement in the future. (5) Includes a special allocation of gross revenues totaling $500,000. MANAGEMENT The General Partner UNIT was formed in 1986 in connection with a major reorganization and recapitalization whereby UNIT acquired all of the assets and liabilities of all of the limited partnerships formed by UNIT's prede- cessor, UDEC, during the period of 1980 through 1983 in exchange for shares of UNIT's common stock and UDEC was merged with a wholly owned subsidiary of UNIT whereby UDEC was the surviving corporation and thereby became a wholly owned subsidiary of UNIT. UPC was incorporated in the State of Oklahoma on February 9, 1984 as Sunshine Development Corporation ("SDC"). On October 8, 1985 pursuant to the terms of a Stock Purchase Agreement," UDEC purchased all of the issued and outstanding stock of SDC whereby SDC became a wholly owned subsidiary of UDEC. On February 1, 1988, pursuant to the terms of an "Amended and Restated Certificate of Incorporation", SDC was renamed Unit Petroleum Company. UPC's as well as UNIT's, principal office is at 1000 Kensington Tower I, 7130 South Lewis Avenue, Tulsa, Oklahoma 74136 and its telephone number is (918) 493-7700. UNIT through its various subsidiaries is engaged in the onshore contract drilling of oil and gas wells and in the exploration for and production of oil and gas. Unless the context otherwise requires, references in this Memorandum to UNIT include its predecessor as well as all or any of its subsidiaries. Officers, Directors and Key Employees The Partnership will have no directors or officers. The directors of the General Partner are elected annually and serve until their successors are elected and qualified. Directors of UNIT are elected at the Annual Meeting of Shareholders for a staggered term of three years each, or until their successors are duly elected and qualified. The 44 executive officers of the General Partner are elected by and serve at the pleasure of its Board of Directors. The names, ages and respective positions of the directors and executive officers of UNIT are as follows: Name Age Position ---- --- -------- King P. Kirchner 68 Chairman of the Board and Chief Executive Officer John G. Nikkel 60 President, Chief Operating Officer and Director O. Earle Lamborn 60 Senior Vice President, Drilling and Director Philip M. Keeley 54 Senior Vice President, Exploration and Production Larry D. Pinkston 41 Vice President, Treasurer and Chief Financial Officer Mark E. Schell 38 Secretary and General Counsel William B. Morgan 51 Director Don Cook 70 Director John S. Zink 67 Director John H. Williams 77 Director Don Bodard 75 Director The names, ages and respective positions of the directors and executive officers of UPC are as follows: Name Age Position ---- --- -------- John G. Nikkel 60 Chairman of the Board and President Philip M. Keeley 54 Vice President and Director Mark E. Schell 38 Secretary, General Counsel and Director Larry D. Pinkston 41 Treasurer 45 Mr. Kirchner, a co-founder of UNIT, 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 UNIT 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 industry for over 40 years, joining UNIT's predecessor in 1952 when it was a privately-held corporation. He was elected Vice President-Drilling in 1973 and as Senior Vice President and Director in 1979. Mr. Keeley joined UNIT in November, 1983 as 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 UNIT in December, 1981. He served as Corporate Budget Director and Assistant Controller prior to being appointed 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 UNIT in January of 1987 as its Secretary and General Counsel. From 1979 until joining UNIT, 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. 46 Mr. Morgan was elected a Director of UNIT in February, 1988. Mr. Morgan has been Executive Vice President and General Counsel of St. John Medical Center, Inc., Tulsa, Oklahoma, since March 1, 1995. Prior thereto, he was a Partner in the law firm of Doerner, Saunders, Daniel and Anderson, Tulsa, Oklahoma. Mr. Cook has served as a Director of UNIT since UNIT's inception in 1963. He is a Certified Public Accountant and is a retired partner in the accounting firm of Finley & Cook, Shawnee, Oklahoma. Mr. Zink was elected a Director of UNIT in May, 1982. He is founder of ZEECO, a privately held company engaged in the business of designing and manufacturing combustion and pollution control equipment used in the petroleum industry. He holds a Bachelor of Science degree in Mechanical Engineering from Oklahoma State University. He is also a director of Liberty Bancorp, Tulsa and Oklahoma City, Oklahoma, Matrix Service Company, Tulsa, Oklahoma, and Chairman of the John Zink Foundation. Mr. Williams was elected a Director of UNIT in December of 1988. Prior to retiring on December 31, 1978, he was Chairman of the Board and Chief Executive Officer of The Williams Companies, Inc. Mr. Bodard, a co-founder of UNIT, served as a Director from 1963 until February, 1988 when he resigned. From February, 1988 until August 23, 1994, when Mr. Bodard was again elected to be a Director of Unit, he served as a Consultant to the Board of Directors. He is Secretary- Treasurer of Bodard & Hale Drilling Company, an Oklahoma based drilling company and President of Bodard Drilling Company, Inc. He is also Chairman of the Board of Ameribank, Shawnee, Oklahoma. Prior Employee Programs Since 1984, UNIT has formed limited partnerships for investment by certain of its key employees and directors that participate with UNIT in its exploration and production operations. The name, month of formation and amount of limited partner capital subscriptions of each of these limited partnerships (the "Employee Programs") are set forth below. Limited Partners' Name Formed Capital Subscriptions ---- ------ --------------------- Unit 1984 Employee Oil and Gas Program April 1984 $348,000 Unit 1985 Employee Oil and Gas Limited Partnership January 1985 $378,000 Unit 1986 Employee Oil and Gas Limited Partnership January 1986 $307,000 Unit 1987 Employee Oil and Gas Limited Partnership March 1987 $209,000 47 Unit 1988 Employee Oil and Gas Limited Partnership April 29, 1988 $177,000 Unit 1989 Employee Oil and Gas Limited Partnership December 30, 1988 $157,000 Unit 1990 Employee Oil and Gas Limited Partnership January 19, 1990 $253,000 Unit 1991 Employee Oil and Gas Limited Partnership January 7, 1991 $263,000 Unit 1992 Employee Oil and Gas Limited Partnership January 23, 1992 $240,000 Unit 1993 Employee Oil and Gas Limited Partnership January 21, 1993 $245,000 Unit 1994 Employee Oil and Gas Limited partnership January 19, 1994 $284,000 Unit 1995 Employee Oil and Gas Limited Partnership March 7, 1995 $454,000 One-half of the capital subscriptions from all limited partners were required to be paid in the 1984 Employee Program, three-fourths of the capital subscriptions from all limited partners were required to be paid in the 1985 Employee Program and the 1986 Employee Program. All of the capital subscriptions from all limited partners, including those shown below, were required to be paid in the 1987 through 1995 Employee Programs. The capital subscriptions of the following limited partners to the 1993, 1994 and 1995 Employee Programs were as shown below: Amount of Capital Position with Subscription Subscriber UNIT 1993 1994 1995 ---------- ------------- ---- ---- ---- King P. Kirchner Chairman of the Board $50,000(1) $50,000(1) $50,000(1) and Chief Executive Officer John G. Nikkel President, Chief $72,130(2) $98,000(2) $93,270(2) Operating Officer and Director Philip M. Keeley Senior Vice President, $18,870(2) $22,000(2) $25,730(2) Exploration and Production Don Bodard Director $50,000 $50,000 $200,000 __________________ 48 (1) Mr. Kirchner invested $50,000 indirectly in each of the 1993 Employee Program, the 1994 Employee Program, and the 1995 Employee Program, through the King P. Kirchner Revocable Trust as permitted by the limited partnership agreement of those Employee Programs. (2) Messrs. Nikkel and Keeley have invested in the 1993, 1994 and 1995 Employee Programs both directly and through Nike Exploration Company which is owned 71.4% by Mr. Nikkel and 28.6% by Mr. Keeley. The amounts invested directly and indirectly through Nike Exploration Company in the 1993, 1994 and 1995 Employee Programs by Messrs. Nikkel and Keeley are set forth below: Nike Employee Mr. Nikkel Mr. Keeley Exploration Program Directly Directly Company -------- ---------- ---------- ----------- 1993 $40,000 $ 6,000 $45,000 1994 $50,000 $10,000 $60,000 1995 $54,000 $10,000 $55,000 Ownership of Common Stock UNIT's Common Stock is listed on the New York Stock Exchange as reported on the Composite Tape. On November 21, 1995, there were 20,976,090 shares outstanding. As of November 21, 1995, the only shareholders who owned of record or who were known by UNIT to own beneficially more than 5 % of its total outstanding shares of Common Stock were: Name and Address % of of Beneficial Owner Shares(1) Outstanding(1) ------------------- --------- -------------- King P. Kirchner 1000 Kensington Center 1,320,393(2) 6.30% 7130 South Lewis Avenue Tulsa, Oklahoma 74136 Don Bodard 313 Masonic Building 1,682,928(3) 8.02% Shawnee, Oklahoma 74801 Scottish Amicable Life Assurance Society 7 Hanover Square 1,755,000(4) 8.36% New York, New York 10004 Dimensional Fund Advisors Inc. 1299 Ocean Avenue, 11th Floor 1,273,600(5) 6.07% Santa Monica, California 90401 49 (1) The number of shares includes the shares presently issued and outstanding plus the number of shares which any owner has the right to acquire within 60 days after November 21, 1995, pursuant to the exercise of currently exercisable warrants or stock options. For purposes of calculating the percent of the shares outstanding held by each owner, the total number of shares excludes the shares which all other persons have the right to acquire within 60 days after November 21, 1995, pursuant to the exercise of currently exercisable warrants or stock options. (2) The number of shares includes 4,567 shares held under Unit's 401(k) Thrift Plan as of December 31, 1994. (3) Includes options to purchase 2,500 shares of common stock granted under Unit's Non-Employee Director's Stock Option Plan. (4) This information is based on the most recent amendment, dated February 13, 1989, to the Schedule 13D filed with the Securities and Exchange Commission by Scottish Amicable Life Assurance Society ("Life Assurance"), Scottish Amicable Pensions Investments Limited ("Pensions") and Scottish Amicable International Exempt Unit Trust ("Unit Trust"). Life Assurance holds sole voting and sole dispositive power over 395,000 shares of common stock and 55,000 warrants and shared voting power over 1,060,000 shares of common stock and 245,000 warrants. Unit Trust holds shared voting power over 470,000 shares of common stock and 120,000 warrants. Pensions holds shared voting power with respect to 590,000 shares of common stock and 125,000 warrants. (5) This information is based on Amendment No. 1 to Schedule 13G, dated February 10, 1993, filed with the Securities and Exchange Commission by Dimensional Fund Advisors Inc. ("Dimensional"). Dimensional, a registered investment advisor, is deemed to have beneficial ownership of 1,273,600 shares of common stock as of December 31, 1992, all of which shares are held in portfolios of DFA Investment Dimensions Group Inc., a registered open-end investment company, or the DFA Group Trust and DFA Participation Group Trust, investment vehicles for qualified employee benefit plans, all of which Dimensional serves as investment manager. Dimensional disclaims beneficial ownership of all such shares. As of November 21, 1995, the directors and officers of UNIT (except Mr. Kirchner and Mr. Bodard whose holdings are given above) owned of record or beneficially owned shares of UNIT Common Stock as follows: 50 Amount of Beneficial % of Name Ownership (1) Outstanding(1) ---- ------------- -------------- John Williams................ 11,000 (2) * Don Cook..................... 16,138 (2) * Philip M. Keeley............. 255,157 (3)(4) 1.21 O. Earle Lamborn............. 333,141 (4) 1.58 John G. Nikkel............... 333,300 (4) 1.58 Larry D. Pinkston............ 119,003 (4) * Mark E. Schell............... 49,898 (4) * John S. Zink................. 30,000 (2) * William B. Morgan............ 20,000 (2) * All Officers and Directors as a Group (consisting of 11 persons including Mr. Kirchner).............. 4,170,958 (4)(5) 19.38 _______________ *Less than 1% (1) The number of shares includes the shares presently issued and outstanding plus the number of shares which any owner has the right to acquire within 60 days after November 21, 1995, pursuant to the exercise of currently exercisable warrants or stock options. For purposes of calculating the percent of the shares outstanding held by each owner, the total number of shares excludes the shares which all other persons have the right to acquire within 60 days after November 21, 1995 pursuant to the exercise of currently exercisable warrants or stock options. (2) Includes unexercised stock options granted under UNIT's non-Employee Directors' Stock Option Plan to each of the following, all of which are currently exercisable at the discretion of the holder: Don Cook, 10,000; William B. Morgan, 10,000; John H. Williams, 10,000; John S. Zink, 10,000; Don Bodard, 2,500; and all non-Employee Directors as a group, 42,500. (3) Includes warrants to purchase 2,100 shares of common stock. (4) Includes shares of common stock held under UNIT's 401(k) thrift plan as of December 31, 1994 for the account of: Earle Lamborn, 6,681; John G. Nikkel, 24,886; Philip M. Keeley, 30,408; Larry D. Pinkston, 9,538; and Mark E. Schell, 5,883. (5) Includes options to purchase 541,900 shares of common stock and warrants to purchase 2,100 shares of common stock. 51 Interest of Management in Certain Transactions Reference is made to "COMPENSATION" for a discussion of the compensation for supervision and operation of productive wells and the reimbursement of overhead expenses attributable to the Partnership's operations to which UNIT is entitled under the terms of the Partnership Agreement. CONFLICTS OF INTEREST There will be situations in which the individual interests of the General Partner and the Limited Partners will conflict. Although the General Partner is obligated to deal fairly and in good faith with the Limited Partners and conduct Partnership operations using the standards of a prudent operator in the oil and gas industry, such conflicts may not in every instance be resolved to the maximum advantage of the Limited Partners. Certain circumstances which will or may involve potential conflicts of interest are as follows: The General Partner currently manages and in the future will sponsor and manage oil and natural gas drilling programs similar to the Partnership. The General Partner will decide which prospects the Partnership will acquire. The General Partner will act as operator for Partnership Wells and will, through its affiliates, furnish drilling and/or marketing services with respect to Partnership Wells, the terms of which have not been negotiated by non-affiliated persons. The General Partner is a general partner of numerous other partnerships, and owes duties of good faith dealing to such other partnerships. The General Partner and its affiliates engage in drilling, operating and producing activities for other partnerships. Acquisition of Properties and Drilling Operations With certain limited exceptions it is anticipated that the Partnership will participate in each producing property, if any, acquired by the General Partner and in the drilling of each of the wells, if any, commenced by the General Partner for its own account during the period commencing January 1, 1996, or from the formation of the Partnership if subsequent to January 1, 1996, through December 31, 1996 except for wells: (i) drilled outside the 48 contiguous United States; 52 (ii) drilled as part of secondary or tertiary recovery operations which were in existence prior to formation of the Partnership; (iii) drilled by third parties under farm-out or similar arrangements with UNIT or the General Partner or whereby UNIT or the General Partner may be entitled to an overriding royalty, reversionary or other similar interest in the production from such wells but is not obligated to pay any of the Drilling Costs thereof; (iv) acquired by UNIT or the General Partner through the acquisition by UNIT or the General Partner of, or merger of UNIT or the General Partner with, other companies; or (v) with respect to which the General Partner does not believe that the potential economic return therefrom justifies the costs and participation by the Partnership. As a result, the Partnership may have an interest in wells located on prospects on which producing wells have been drilled by UNIT or the General Partner in prior years. Likewise, it is possible that the Partnership will participate in the drilling of initial wells on prospects on which some or all of the development or offset wells will be drilled in years subsequent to 1996. In the latter case, the Partnership would have no right to participate in the drilling of such development or offset wells. Sometimes UNIT will agree to participate in drilling operations on a prospect which it may not believe are fully warranted from an econom- ic standpoint if it believes that such participation is necessary for, or will significantly increase its chances of, obtaining a contract to drill the well with one of its drilling rigs and the revenues from the contract make the economics of the entire arrangement desirable from UNIT's standpoint. In such an instance, the Partnership would not be entitled to any of the drilling contract revenues so the General Partner will not cause the Partnership to participate in such a well. However, an analysis of the economic potential of any proposed well is a very inexact science and wells which have a very high potential commonly prove to be dry or only marginally profitable and occasionally a well with apparently very little promise may prove to be very profit- able. Thus, there can be no assurance that the General Partner will always make the most profitable decision from the Partnership's stand- point in determining in which of such potential wells the Partnership should or should not participate. Because the Partnership will acquire an interest only in those properties comprising the spacing unit on which each Partnership Well is located, it will not be entitled to participate in other wells drilled by the General Partner, UNIT or any of its affiliates in the 53 same prospect area unless the drilling of those wells commences during the period from January 1, 1996, or from the formation of the Partnership if subsequent to January 1, 1996, through December 31, 1996. If the size of a spacing unit in which the Partnership has an interest is reduced, the Partnership will have no interest in any additional well drilled on the property comprising the original spacing unit unless it is commenced during the period from January 1, 1996, or from the formation of the Partnership if subsequent to January 1, 1996, through December 31, 1996. Likewise the Partnership would have no interest in any increased density wells drilled on the original spacing unit unless such wells were drilled during 1996. In addition, if additional interests are acquired in wells participated in by the Partnership after 1996, the Partnership will generally not be entitled to participate in the acquisition of such additional interests. Management believes that the apparent conflicts of interest arising from these situations are mitigated by the fact that the Partnership is expected to participate in all of UNIT's drilling operations (with the exceptions noted above) conducted during the period. Thus, there is little opportunity for the General Partner to selectively choose Partnership drilling locations for the purpose of proving up other properties of UNIT or its affiliates in which the Partnership has no interest. Further, the Partnership will benefit in many instances by its participation in the drilling of wells located on prospects previously proved up by drilling operations conducted by UNIT prior to formation of the Partnership. Participation in UNIT's Drilling or Income Programs If UNIT forms any drilling or income programs in 1996, it is anticipated that the Partnership will serve as a co-general partner with UNIT in any such drilling or income programs, or both. As the other co-general partner of any such drilling or income program, UNIT would have exclusive management and control over the business, operations and affairs of the drilling or income program. Conflicts of interest may arise between the limited partners and the general partners of such drilling or income program and it is possible that UNIT may elect to resolve those conflicts in favor of the limited partners. Further, if any such drilling or income program is offered publicly, the program agreement will be required to contain a number of provisions concerning the conduct of program operations and handling conflicts of interests required by the Guidelines for the Registration of Oil and Gas Programs adopted by the North American Securities Administrators Association, Inc. Such provisions may significantly reduce the flexibility of UNIT in managing such programs or may affect the profitability of the program operations or the transactions between the general partners and the program. 54 Transfer of Properties The General Partner or its affiliates are authorized to transfer interests in oil and gas properties to the Partnership, in which case the General Partner or its affiliate will receive an amount equal to the Leasehold Acquisition Costs attributable to the interests being acquired by the Partnership in the spacing unit on which the Partner- ship Well is located or is to be drilled. The amount of the Leasehold Acquisition Costs attributable to the fractional undivided interest in a property transferred to the Partnership by the General Partner or any affiliate shall not be reduced or offset by the amount of any gain or profit the General Partner or its affiliate might have realized by any prior sale or transfer of a fractional undivided interest in the property to an unaffiliated third party for a price in excess of the portion of the Leasehold Acquisition Costs of the property that is attributable to the transferred interest. The Partnership will not be reimbursed for or refunded any Leasehold Acquisition Costs if the size of a spacing unit on which a Partnership Well is located or drilled is reduced even though the Partnership will have no interest in any subsequent wells drilled on the area encompassed by the original spacing unit unless they are commenced during 1996. A sale, transfer or conveyance to the Partnership of less than all of the ownership of the General Partner or its affiliates in any interest or property is prohibited unless: (1) the interest retained by the General Partner or its affiliates is a proportionate working interest; (2) the obligations of the Partnership with respect to the properties will be substantially the same proportionately as those of the General Partner or its affiliates at the time it acquired the properties; and (3) the Partnership's interest in revenues will not be less than the proportionate interest therein of the General Partner or its affiliates when it acquired the properties. With respect to the General Partner or its affiliates' remaining interest, it may retain such interest for its own account or it may sell, transfer, farm-out or otherwise convey all or a portion of such remaining interest to non-affiliated industry members, which may occur either before or after the transfer of the interests in the same properties to the Partnership. The General Partner or its affiliates may realize a profit on the interests or may be carried to some extent with respect to its cost obligations in connection with any drilling on such properties and any such profit or interests will be strictly for the account of the General Partner or its affiliates and the Partnership will have no claim with respect thereto. The General Partner or its affiliates may not retain any overrides or other burdens 55 on the property conveyed to the Partnership (other than overriding royalty interests granted to geologists and other persons employed or retained by the General Partner or its affiliates) and may not enter into any farm-out arrangements with respect to its retained interest except to non-affiliated third parties or other programs managed by the General Partner or its affiliates. Partnership Assets The General Partner will not take any action with respect to assets or property of the Partnership which does not benefit primarily the Partnership as a whole. The General Partner will not utilize the funds of the Partnership as compensating balances for the benefit of the General Partner or its affiliates. All benefits from marketing arrangements or other relationships affecting property of the Partner- ship will be fairly and equitably apportioned according to the respec- tive interests of the Partnership and the General Partner. The Partnership Agreement provides that when the Partnership is terminated, there will be an accounting with respect to its assets, liabilities and accounts. The Partnership's physical property and its oil and gas properties may be sold for cash. Except in the case of an election by the General Partner to terminate the Partnership before the tenth anniversary of the Effective Date, Partnership Properties may be sold to the General Partner or any of its affiliates for their fair market value as determined in good faith by the General Partner. Transactions with the General Partner or Affiliates UNIT provides through its subsidiary Unit Drilling Company contract drilling services in the ordinary course of its business. UNIT also owns a 34% of GED Gas Services L.L.C. which is engaged in the business of marketing natural gas. It is anticipated that the Partnership will obtain services, equipment and supplies from some or all of such persons. In addition, UNIT may supply other goods or services to the Partnership. The terms of any contracts or agreements between the Partnership and UNIT or any affiliate will be no less favorable to the Partnership than those of comparable contracts or agreements entered into, and will be at prices not in excess of (or in the case of purchases of production, less than) those charged in the same geographical area, by non-affiliated persons or companies dealing at arm's length. For its services as a drilling contractor, Unit Drilling Company will charge the Partnership on either a daywork (a specified per day rate for each day a drilling rig is on the drill site), a footage (a specified rate per foot drilled) or a turnkey (specified amount for drilling the well) basis. The rate charged by Unit Drilling Company for such services will be the same as those offered to unaffiliated third parties in the same or similar geographic areas. 56 Right of Presentment Price Determination Under the terms of the Partnership Agreement, a Limited Partner can, subject to certain conditions, require the General Partner to purchase his or her Units at a price determined by the application of a stated formula to the estimated future net revenues attributable to the Partnership's estimated proved reserves. See "TERMS OF THE OFFERING - Right of Presentment." It is anticipated that if an independent engineering firm makes an evaluation of the proved reserves of the Partnership, the result of that evaluation will be used in determining the price to be paid to a Limited Partner exercising his or her right of presentment. However, if no such independent evaluation is made, the right of presentment purchase price will be determined by using the proved reserves and future net revenue estimates of the technical staff of the General Partner. Receipt of Compensation Regardless of Profitability The General Partner is entitled to receive its fees and other compensation and reimbursements from the Partnership regardless of whether the Partnership operates at a profit or loss. See "PARTICIPA-TION IN COSTS AND REVENUES" and "COMPENSATION." Such fees, compensa- tion and reimbursements will decrease the Limited Partners' share of any profits generated by operations of the Partnership or increase losses if such operations should prove unprofitable. Legal Counsel Conner & Winters, A Professional Corporation, serves as special legal counsel for the General Partner. Such firm has performed legal services for the General Partner and UNIT and is expected to render legal services to the Partnership. Although such firm has indicated its intention to withdraw from representation of the Partnership if conflicts of interest do in fact arise, there can be no assurance that representation of both the General Partner or UNIT and the Partnership by such firm will not be disadvantageous to the Partnership. FIDUCIARY RESPONSIBILITY General Under Oklahoma law, the General Partner will have a fiduciary duty to the Limited Partners and consequently must exercise good faith, fairness and loyalty in the handling of the Partnership's affairs. The General Partner must provide Limited Partners (or their representatives) with timely and full information concerning matters affecting the business of the Partnership. Each Limited Partner may inspect the Partnership's books and records upon reasonable prior notice. The nature of the fiduciary duties of general partners is an evolving area of law and prospective investors who have questions 57 concerning the duties of the General Partner should consult with their counsel. Regardless of the fiduciary obligations of the General Partner, the General Partner, UNIT or its affiliates, subject to any restrictions or requirements set forth in the Agreement, may: engage independently of the Partnership in all aspects of the oil and gas business, either for their own accounts or for the accounts of others; sell interests in oil and gas properties held by them to, purchase oil and gas production from, and engage in other transactions with, the Partnership; serve as general partner of other oil and gas drilling or income partnerships, including those which may be in competition with the Partnership; and engage in other activities that may involve conflicts of interest. See "CONFLICTS OF INTEREST." Thus, unlike the strict duty of a fiduciary who must act solely in the best interests of his beneficiary, the Agreement permits the General Partner to consider, among other things, the interests of other partnerships sponsored by the General Partner, UNIT or its affiliates in resolving investment and other conflicts of interest. The foregoing provisions permit the General Partner to conduct its own operations and to act as the general partner of more than one similar partnership or investment program and for the Partnership to benefit from its experience resulting therefrom, but relieves the General Partner of the strict fiduciary duty of a general partner acting as such for only one investment program at a time. These provisions are primarily intended to reconcile the applicable duties under Oklahoma law with the fact that the General Partner will manage and administer its own oil and gas operations and a number of other oil and gas investment programs with which possible conflicts of interests may arise and resolve such conflicts in a manner consistent with the expectation of the investors in all such programs, the General Partner's fiduciary duties and customary business practices and statutes applicable thereto. Liability and Indemnification The Agreement provides that the General Partner will perform its duties in an efficient and businesslike manner with due caution and in accordance with established practices of the oil and gas industry. The Agreement further provides that the General Partner and its affiliates will not be liable to the Partnership or the Partners, and will be indemnified by the Partnership, for any expense (including attorney 58 fees), loss or damage incurred by reason of any act or omission performed or omitted in good faith in a manner reasonably believed by the General Partner or its affiliates to be within the scope of authority and in the best interest of the Partnership or the Partners unless the General Partner or its affiliates is guilty of gross negligence or willful misconduct. While not totally certain under Oklahoma law, absent specific provisions in the partnership agreement to the contrary, a general partner of a limited partnership may be liable to its limited partners if it fails to conduct the partnership affairs with the same amount of care which ordinarily prudent persons would use in similar circumstances. Consequently, the Agreement may be viewed as requiring a lesser standard of duty and care than what Oklahoma law might otherwise require of the General Partner. Any claim against the Partnership for indemnification must be satisfied only out of Partnership assets including insurance proceeds, if any, and none of the Limited Partners will have personal liability therefor. The Limited Partners may have more limited rights of action than they would have absent the liability and indemnification provisions above. Moreover, indemnification enforced by the General Partner under such provisions will reduce the assets of the Partnership. It should be noted, however, that it is the position of the Securities and Exchange Commission ("Commission") that any attempt to limit the liability of a general partner or to indemnify a general partner under the federal securities laws is contrary to public policy and, therefore, unenforceable. The General Partner has been advised of the position of the Commission. Generally, the Limited Partners' remedy for the General Partner's breach of a fiduciary duty will be to bring a legal action against the General Partner to recover any damages, generally measured by the benefits earned by the General Partner as a result of the fiduciary breach. Additionally, Limited Partners may also be able to obtain other forms of relief, including injunctive relief. The Act provides that a limited partner may bring an action in the name of a limited partnership (a partnership derivative action) to recover a judgment in its favor if general partners with authority to do so have refused to bring the action or if an effort to cause such general partners to bring the action is not likely to succeed. PRIOR ACTIVITIES UNIT has been engaged in oil and gas exploration and development operations since late 1974 and has conducted oil and gas drilling programs using the limited partnership format since 1979. The follow- ing table depicts the drilling results achieved as of September 30, 1995 by UNIT during each year since 1975. Because of the unpredictability of oil and gas exploration in general, such results 59 should not be considered indicative of the results that may be achieved by the Partnership. Gross Wells(2) Net Wells(3) Year Ended ---------------------- ------------------------- July 31(1) Total Oil Gas Dry Total Oil Gas Dry ----- --- --- --- ----- --- --- --- 1975 Exploratory........ 2 0 2 0 .01 0 .01 0 Development........ 4 0 2 2 .07 0 .03 .04 ----- --- --- --- ----- --- --- --- 6 0 4 2 .08 0 .04 .04 ----- --- --- --- ----- --- --- --- 1976 Exploratory........ 1 0 0 1 .01 0 0 .01 Development........ 8 0 6 2 .29 0 .28 .01 ----- --- --- --- ----- --- --- --- 9 0 6 3 .30 0 .28 .02 ----- --- --- --- ----- --- --- --- 1977 Exploratory........ 9 0 3 6 1.50 0 .45 1.05 Development........ 16 0 9 7 2.00 0 .70 1.30 ----- --- --- --- ----- --- --- --- 25 0 12 13 3.50 0 1.15 2.35 ----- --- --- --- ----- --- --- --- 1978 Exploratory........ 8 1 1 6 1.17 .34 .15 .68 Development........ 26 0 13 13 2.64 0 .76 1.88 ----- --- --- --- ----- --- --- --- 34 1 14 19 3.81 .34 .91 2.56 ----- --- --- --- ----- --- --- --- 1979 Exploratory........ 10 0 5 5 1.40 0 .76 .64 Development........ 16 1 8 7 1.99 .06 .95 .98 ----- --- --- --- ----- --- --- --- 26 1 13 12 3.39 .06 1.71 1.62 ----- --- --- --- ----- --- --- --- 1980 Exploratory........ 1 0 1 0 1.28 0 .23 1.05 Development........ 10 0 8 2 3.13 0 .85 2.28 ----- --- --- --- ----- --- --- --- 11 0 9 2 4.41 0 1.08 3.33 ----- --- --- --- ----- --- --- --- Year Ended December 31(1) 1981 Exploratory........ 14 1 4 9 1.12 .02 .16 .94 Development........ 66 18 29 19 7.38 2.96 1.77 2.65 ----- --- --- --- ----- --- --- --- Total 80 19 33 28 8.50 2.98 1.93 3.59 ----- --- --- --- ----- --- --- --- 1982 Exploratory........ 40 5 9 26 3.39 .60 .32 2.47 Development........ 100 22 51 27 11.70 4.70 2.71 4.29 ----- --- --- --- ----- --- --- --- Total 140 27 60 53 15.09 5.30 3.03 6.76 ----- --- --- --- ----- --- --- --- 1983 Exploratory........ 6 2 0 4 1.31 .72 0 .59 Development........ 72 18 26 28 8.01 3.45 1.17 3.39 ----- --- --- --- ----- --- --- --- Total 78 20 26 32 9.32 4.17 1.17 3.98 ----- --- --- --- ----- --- --- --- 1984 Exploratory........ 2 1 1 0 .52 .49 .03 0 Development........ 50 15 22 13 6.81 3.42 2.74 .65 ----- --- --- --- ----- --- --- --- Total 52 16 23 13 7.33 3.91 2.77 .65 ----- --- --- --- ----- --- --- --- 1985 Exploratory........ 0 0 0 0 0 0 0 0 Development........ 38 11 16 11 8.32 2.89 2.39 3.04 ----- --- --- --- ----- --- --- --- Total 38 11 16 11 8.32 2.89 2.39 3.04 ----- --- --- --- ----- --- --- --- 1986 Exploratory........ 0 0 0 0 0 0 0 0 Development........ 21 4 6 11 3.85 .81 1.01 2.03 ----- --- --- --- ----- --- --- --- Total 21 4 6 11 3.85 .81 1.01 2.03 ----- --- --- --- ----- --- --- --- 1987 Exploratory........ 0 0 0 0 0 0 0 0 Development........ 46 23 10 13 11.91 7.95 1.76 2.34 ----- --- --- --- ----- --- --- --- Total 46 23 10 13 11.91 7.95 1.76 2.34 ----- --- --- --- ----- --- --- --- 60 1988 Exploratory........ 0 0 0 0 0 0 0 0 Development........ 39 20 10 9 22.56 14.77 4.05 3.74 ----- --- --- --- ----- --- --- --- Total 39 20 10 9 22.56 14.77 4.05 3.74 ----- --- --- --- ----- --- --- --- 1989 Exploratory........ 3 0 1 2 1.97 0 .47 1.50 Development........ 40 12 15 13 18.83 8.81 4.13 5.89 ----- --- --- --- ----- --- --- --- Total 43 12 16 15 20.80 8.81 4.60 7.39 ----- --- --- --- ----- --- --- --- 1990 Exploratory........ 5 0 2 3 1.22 0 .12 1.10 Development........ 35 11 14 10 16.53 8.38 3.52 4.63 ----- --- --- --- ----- --- --- --- Total 40 11 16 13 17.75 8.38 3.64 5.73 ----- --- --- --- ----- --- --- --- 1991 Exploratory........ 4 0 0 4 .82 0 0 .82 Development........ 28 10 9 9 15.88 8.61 3.91 3.36 ----- --- --- --- ----- --- --- --- Total 32 10 9 13 16.70 8.61 3.91 4.18 ----- --- --- --- ----- --- --- --- 1992 Exploratory........ 0 0 0 0 0 0 0 0 Development........ 18 1 11 6 5.81 1.00 3.33 1.48 ----- --- --- --- ----- --- --- --- Total 18 1 11 6 5.81 1.00 3.33 1.48 ----- --- --- --- ----- --- --- --- 1993 Exploratory........ 1 0 0 1 .10 0 0 .10 Development........ 16 9 6 1 12.48 8.98 3.32 .18 ----- --- --- --- ----- --- --- --- Total 17 9 6 2 12.58 8.98 3.32 .28 ----- --- --- --- ----- --- --- --- 1994 Exploratory........ 3 0 1 2 1.71 0 .95 .76 Development........ 57 5 40 12 25.79 4.75 14.14 6.90 ----- --- --- --- ----- --- --- --- Total 60 5 41 14 27.50 4.75 15.09 7.66 ----- --- --- --- ----- --- --- --- Period of January 1, 1995 to September 30, 1995 Exploratory........ 0 0 0 0 0 0 0 0 Development........ 28 10 16 2 9.28 3.91 4.69 .68 ----- --- --- --- ----- --- --- --- Total 28 10 16 2 9.28 3.91 4.69 .68 ----- --- --- --- ----- --- --- --- ________________ (1) Except as indicated, the figures used in this table relate to wells drilled and completed during each of the 12 month periods ended July 31 or December 31, as the case may be. Oil wells and gas wells shown include both producing wells and wells capable of production. (2) "Gross Wells" refers to the total number of wells in which there was participation by UNIT. (3) "Net Wells" refers to the aggregate leasehold working inter- est of UNIT in such wells. For example, a 50% leasehold working interest in a well drilled represents 1.0 Gross Well, but a .50 Net Well. Prior Employee Programs During the period of 1979 to 1983, persons who were designated key employees of UNIT by its board of directors participated in the Unit Key Employee Exploration Funds (the "Funds"). These Funds were formed as general partnerships for the purpose of participating in 10% of all 61 of the exploration and development operations conducted by UNIT during a specified period. Except for the Fund formed in 1983, each of the prior Funds served as one of the general partners in at least one of the prior drilling programs sponsored by UNIT and was allocated 10% of the expenses and revenues allocable to the general partners as a group. In each of these Funds the costs charged to it in connection with its operations were financed with the proceeds of bank borrowings and out of the Funds' share of revenues. The 1983 Fund served as the sole capital limited partner in the Unit 1983-A Oil and Gas Program and as such made no contribution to the capital of that program and shared in 10% of the costs and revenues otherwise allocable to the General Partner after the distributions to the General Partner from the program equaled the amount of its contri- butions thereto plus UNIT's interest costs with respect to the unrecov- ered amount of its contributions. Because of the differences in structure, format and plan of operations between the prior Funds and the Partnership and because of the uncertainties which are inherent in oil and gas operations general- ly, the results achieved by the prior Funds should not be considered indicative of the results the Partnership may achieve. For each year from 1984 through 1995, a separate Employee Program was formed as an Oklahoma limited partnership with UNIT or UPC as its sole general partner (UPC now serves as the sole general partner of each of these Employee Programs) and with eligible employees and directors of UNIT and its subsidiaries who subscribed for units therein as the limited partners. Each Employee Program participated on a proportionate basis (to the extent of 10% of the General Partner's interest in each case except for the 1986 and 1987 Employee Programs, in which case the percentage participation was 15% and the 1992-1995 Employee Programs, in which case the percentage was 5%) in all of UNIT's oil and gas exploration and development operations conducted during the calendar year for which the program was formed beginning with its date of formation if it was formed after January 1. Although the terms and provisions of these Employee Programs are virtually identical to those of the Partnership, because of the unpredictability of oil and gas exploration and development in general, the results for the Employee Programs shown below should not be considered indicative of the results that may be achieved by the Partnership. The Funds and the Employee Programs have participated in either 10% or 5% (15% in the case of the 1986 and 1987 Employee Programs) of virtually all of UNIT's or the General Partner's exploration and development operations conducted since the latter half of 1979. Thus, the drilling results of these partnerships would be proportionate to those drilling results of UNIT for the periods beginning after the fiscal year ended July 31, 1979 shown above. 62 Results of the Prior Oil and Gas Programs In each of the General Partner's prior oil and gas programs other than the Unit 1983-A Oil and Gas Program and the Unit 1984 Oil and Gas Limited Partnership, one of the prior Funds also served as a general partner. The 1983 Fund served as the sole capital limited partner of the Unit 1983-A Oil and Gas Program and the 1984 Employee Program serves as a general partner of the Unit 1984 Oil and Gas Limited Partnership. The Unit 1979 Oil and Gas Program was the first limited partnership drilling program of which UNIT was a sponsor. The revenue sharing terms of the 1979 Program are generally 70% to the limited partners and 30% to the general partners until 150% program payout at which time the revenues are to be shared 55% to the limited partners and 45% to the general partners. The revenue sharing terms of the Unit 1980 Oil and Gas Program were generally 60% to the limited partners and 40% to the general partners. The revenue sharing terms of the Unit 1981 Oil and Gas Program were generally 70% to the limited partners and 30% to the general partners until program payout and 50% to the limited partners and 50% to the general partners thereafter. The revenue sharing terms of the Unit 1981-II Oil and Gas Program, the Unit 1982-A Oil and Gas Program and the Unit 1982-B Oil and Gas Program (60% to the limited partners and 40% to the general partners) were substantially the same as those of the Unit 1983-A Oil and Gas Program and the Unit 1984 Oil and Gas Limited Partnership (65% to the limited partners and 35% to the general partner) except that the general partners' cost percentage and the general partners' revenue share in each of those prior programs could not be less than 25%. The following tables depict the drilling results at September 30, 1995, and the economic results at September 30, 1995 of prior oil and gas programs and the 1984-1995 Employee Programs. On September 12, 1986, in connection with a major restructuring and recapitalization, UNIT acquired all of the assets and liabilities of the programs formed during 1980 through 1983 and these programs have now been dissolved. Effective December 31, 1993, pursuant to an Agreement and Plan of Merger, dated as of December 28, 1993, all of the assets and all of the liabilities of the 1984, 1985, 1986, 1987, 1988, 1989 and 1990 Employee Programs were merged with and consolidated into a new Employee Program called the Unit Consolidated Employee Oil and Gas Limited Partnership, an Oklahoma Limited Partnership which was formed November 30, 1993 (the "Consolidated Program"). The Consolidated Program holds no assets other than those acquired in the merger with the 1984 through 1990 Employee Programs. The Unit 1979 Oil and Gas Program continues in existence as do the 1991, 1992, 1993, 1994 and 1995 Employee Programs. Certain of these programs have not completed all of their drilling and development operations. Moreover, because of the unpredictability of oil and gas exploration and development in general, the results shown below should not be considered indicative of the results that may be achieved by the Partnership. 63 DRILLING RESULTS ---------------- As of September 30, 1995 Gross Wells Net Wells -------------------- ---------------------- Program Total Oil Gas Dry Total Oil Gas Dry - ------- -------------------- ---------------------- 1979 Exploratory Wells 6 0 2 4 2.43 0.00 0.65 1.78 Development Wells 21 16 1 4 17.28 14.14 0.03 3.11 ---- ---- ---- ---- ----- ----- ---- ---- Total.......... 27 16 3 8 19.71 14.14 0.68 4.89 ---- ---- ---- ---- ----- ----- ---- ---- 1980(1) Exploratory Wells 15 2 5 8 5.65 0.50 2.14 3.01 Development Wells 32 5 15 12 12.77 1.17 5.75 5.85 ---- ---- ---- ---- ----- ----- ---- ---- Total.......... 47 7 20 20 18.42 1.67 7.89 8.86 ---- ---- ---- ---- ----- ----- ---- ---- 1981(1) Exploratory Wells 11 1 4 6 4.61 0.33 0.88 3.40 Development Wells 67 14 34 19 21.77 5.03 6.61 10.13 ---- ---- ---- ---- ----- ----- ---- ---- Total.......... 78 15 38 25 26.38 5.36 7.49 13.53 ---- ---- ---- ---- ----- ----- ---- ---- 1981-II(1)Exploratory Wells 13 1 5 7 5.21 0.25 1.12 3.84 Development Wells 45 3 29 13 9.07 0.69 4.78 3.60 ---- ---- ---- ---- ----- ----- ---- ---- Total.......... 58 4 34 20 14.28 0.94 5.90 7.44 ---- ---- ---- ---- ----- ----- ---- ---- 1982-A(1) Exploratory Wells 11 3 1 7 3.55 0.78 0.00 2.77 Development Wells 69 23 22 24 25.22 13.09 3.59 8.54 ---- ---- ---- ---- ----- ----- ---- ---- Total.......... 80 26 23 31 28.77 13.87 3.59 11.31 ---- ---- ---- ---- ----- ----- ---- ---- 1982-B(1) Exploratory Wells 4 1 1 2 2.28 0.80 0.08 1.40 Development Wells 41 16 9 16 18.60 9.47 1.01 8.12 ---- ---- ---- ---- ----- ----- ---- ---- Total.......... 45 17 10 18 20.88 10.27 1.09 9.52 ---- ---- ---- ---- ----- ----- ---- ---- 1983-A(1) Exploratory Wells 1 1 0 0 1.00 1.00 0.00 0.00 Development Wells 26 14 10 2 6.60 4.39 1.27 0.94 ---- ---- ---- ---- ----- ----- ---- ---- Total.......... 27 15 10 2 7.60 5.39 1.27 0.94 ---- ---- ---- ---- ----- ----- ---- ---- 1984 Exploratory Wells 0 0 0 0 0.00 0.00 0.00 0.00 Development Wells 21 1 10 10 5.89 .38 3.08 2.43 ---- ---- ---- ---- ----- ----- ---- ---- Total.......... 21 1 10 10 5.89 .38 3.08 2.43 ---- ---- ---- ---- ----- ----- ---- ---- (1) On September 12, 1986, Unit acquired all of the assets and liabilities of this Program and the Program has been dissolved. EMPLOYEE PROGRAMS As of September 30, 1995 Gross Wells Net Wells -------------------- ---------------------- Program Total Oil Gas Dry Total Oil Gas Dry - ------- ----- ---- ---- ---- ----- ----- ---- ---- 1984(1) Exploratory Wells 0 0 0 0 0.00 0.00 0.00 0.00 Empl. Development Wells 25 4 12 9 .14 .02 .06 .06 ----- ---- ---- ---- ----- ----- ---- ---- Total.......... 25 4 12 9 .14 .02 .06 .06 ----- ---- ---- ---- ----- ----- ---- ---- 1985(1) Exploratory Wells 0 0 0 0 0.00 0.00 0.00 0.00 Empl. Development Wells 30 8 10 12 .38 .12 .08 .18 ----- ---- ---- ---- ----- ----- ---- ---- Total.......... 30 8 10 12 .38 .12 .08 .18 ----- ---- ---- ---- ----- ----- ---- ---- 64 1986(1) Exploratory Wells 0 0 0 0 0.00 0.00 0.00 0.00 Empl. Development Wells 18 6 8 4 .48 .12 .30 .06 ----- ---- ---- ---- ----- ----- ---- ---- Total.......... 18 6 8 4 .48 .12 .30 .06 ----- ---- ---- ---- ----- ----- ---- ---- 1987(1) Exploratory Wells 0 0 0 0 0.00 0.00 0.00 0.00 Empl. Development Wells 21 12 5 4 1.17 .74 .25 .18 ----- ---- ---- ---- ----- ----- ---- ---- Total.......... 21 12 5 4 1.17 .74 .25 .18 ----- ---- ---- ---- ----- ----- ---- ---- 1988(1) Exploratory Wells 0 0 0 0 0 0 0 0 Empl. Development Wells 29 15 9 5 1.55 1.03 .28 .24 ----- ---- ---- ---- ----- ----- ---- ---- Total.......... 29 15 9 5 1.55 1.03 .28 .24 ----- ---- ---- ---- ----- ----- ---- ---- 1989(1) Exploratory Wells Empl. Development Wells 32 7 14 11 1.48 .59 .36 .53 ----- ---- ---- ---- ----- ----- ---- ---- Total.......... 32 7 14 11 1.48 .59 .36 .53 ----- ---- ---- ---- ----- ----- ---- ---- 1990(1) Exploratory Wells 5 0 2 3 .122 0 .01 .11 Empl. Development Wells 34 11 14 9 1.65 .83 .35 .46 ----- ---- ---- ---- ----- ----- ---- ---- Total.......... 39 11 16 12 1.78 .83 .36 .57 ----- ---- ---- ---- ----- ----- ---- ---- 1991 Exploratory Wells 4 0 0 4 .08 0 0 .08 Empl. Development Wells 28 10 9 9 1.59 .86 .39 .34 ----- ---- ---- ---- ----- ----- ---- ---- Total.......... 32 10 9 13 1.67 .86 .39 .42 ----- ---- ---- ---- ----- ----- ---- ---- 1992 Exploratory Wells 0 0 0 0 0 0 0 0 Empl. Development Wells 18 1 11 6 .29 .05 .17 .07 ----- ---- ---- ---- ----- ----- ---- ---- Total.......... 18 1 11 6 .29 .05 .17 .07 ----- ---- ---- ---- ----- ----- ---- ---- 1993 Exploratory Wells 0 0 0 0 0 0 0 0 Empl. Development Wells 16 9 6 1 .63 .45 .17 .01 ----- ---- ---- ---- ----- ----- ---- ---- Total.......... 16 9 6 1 .63 .45 .17 .01 ----- ---- ---- ---- ----- ----- ---- ---- 1994 Exploratory Wells 3 0 1 2 .09 0 .05 .04 Empl. Development Wells 57 5 40 12 1.29 .24 .70 .35 ----- ---- ---- ---- ----- ----- ---- ---- Total.......... 60 5 41 14 1.38 .24 .75 .39 ----- ---- ---- ---- ----- ----- ---- ---- 1995(2) Exploratory Wells 0 0 0 0 0 0 0 0 Empl. Development Wells 28 10 16 2 .46 .20 .23 .03 ----- ---- ---- ---- ----- ----- ---- ---- Total......... 28 10 16 2 .46 .20 .23 .03 ----- ---- ---- ---- ----- ----- ---- ---- _______________ (1) Effective December 31, 1993 this Program was merged with and into the Consolidated Program. (2) It is anticipated that this program may participate in approximately 17 additional wells. 65 GENERAL PARTNERS' PAYOUT TABLE(1) As of September 30, 1995 Total Total Revenues Total Revenues Expenditures Before Before Deducting Including Deducting Operating Costs Operating Operating for 3 Months Ended Program Costs(2) Costs September 30, 1995 - --------------------------- ---------- ---------- ------------------ 1979....................... $7,518,410 $9,217,733 $48,817 1980....................... 4,043,599 4,044,424 - 1981....................... 8,325,594 6,338,173 - 1981-II.................... 6,642,875 3,995,616 - 1982-A..................... 9,190,842 6,782,893 - 1982-B..................... 4,213,710 3,126,326 - 1983-A..................... 2,277,514 1,312,531 - 1984....................... 2,103,902 1,433,619 13,438 1984 Employee(*)........... 1,542 1,745 - 1985 Employee(*)........... 2,820 1,808 - 1986 Energy Income Fund(**) 1,114,154 1,148,459 16,985 1986 Employee(*)........... 4,403 6,813 - 1987 Employee(*)........... 624,354 815,358 - 1988 Employee(*)........... 1,196,564 1,588,132 - 1989 Employee(*)........... 1,424,525 1,171,961 - 1990 Employee(*)........... 653,563 525,572 - 1991 Employee.............. 1,563,776 1,278,890 59,720 1992 Employee.............. 153,259 146,733 7,084 1993 Employee.............. 350,873 267,466 24,150 Consolidated Program....... 1,349 3,387 390 1994 Employee.............. 848,610 298,486 95,225 1995 Employee.............. 108,386 5,769 3,217 __________ (*) Effective December 31, 1993, this program was merged with and into the Consolidated Program. (**) Formed primarily for purposes of acquiring producing oil and gas properties. 66 LIMITED PARTNERS' PAYOUT TABLE(1) As of September 30, 1995 Total Total Revenues Total Revenues Expenditures Before Before Deducting Including Deducting Operating Costs Operating Operating for 3 Months Ended Program Costs(2) Costs September 30, 1995 - --------------------------- ----------- ----------- ------------------ 1979....................... $13,131,350 $16,846,061 $ 59,901 1980....................... 17,688,367 6,949,008 - 1981....................... 37,073,946 15,768,826 - 1981-II.................... 18,638,600 7,028,946 - 1982-A..................... 24,866,078 12,708,949 - 1982-B..................... 12,069,566 5,367,312 - 1983-A..................... 3,770,856 1,922,177 - 1984....................... 2,683,124 1,495,249 13,520 1984 Employee(*)........... 120,942 171,540 - 1985 Employee(*)........... 277,901 178,984 - 1986 Energy Income Fund(**) 2,300,313 2,841,218 25,609 1986 Employee(*)........... 435,858 676,972 - 1987 Employee(*)........... 341,846 469,830 - 1988 Employee(*)........... 333,898 446,044 - 1989 Employee(*)........... 179,593 175,331 - 1990 Employee(*)........... 300,852 188,848 - 1991 Employee.............. 410,152 341,562 15,948 1992 Employee.............. 394,905 380,177 18,312 1993 Employee.............. 324,336 248,022 22,447 Consolidated Program....... 136,913 335,644 38,631 1994 Employee.............. 341,816 122,819 38,998 1995 Employee.............. 149,675 10,343 5,953 __________ (*) Effective December 31, 1993, this program was merged with and into the Consolidated Program. (**) Formed primarily for purposes of acquiring producing oil and gas properties. 67 GENERAL PARTNERS' NET CASH TABLE(1) As of September 30, 1995 Total Revenues Less Total Operating Revenues Total Total Costs for Distributed Expenditures Revenues 3 Months for 3 Months Less Less Ended Total Ended Operating Operating Sept.30, Revenues Sept. 30, Program Costs(2) Costs 1995 Distributed 1995 - ---------------------- ----------- ---------- -------- ------------ ----------- 1979.................. $2,833,478 $4,532,801 $7,509 3,622,294 7,000 1980.................. 2,628,978 2,629,803 - 2,635,751 - 1981.................. 6,546,160 4,558,739 - 5,368,272 - 1981-II............... 4,817,145 2,169,886 - 2,609,000 - 1982-A................ 6,297,972 3,890,023 - 3,755,000 - 1982-B................ 2,565,504 1,478,120 - 1,158,000 - 1983-A................ 1,380,331 415,348 - 819,000 - 1984.................. 922,964 252,681 (10,637) 552,741 - 1984 Employee(*)...... 874 1,077 - 1,000 - 1985 Employee(*)...... 2,300 1,288 - 1,035 - 1986 Energy Income Fund(**).............. 223,419 257,724 (154) 296,203 2,000 1986 Employee(*)...... 2,698 5,108 17,845 4,486 - 1987 Employee(*)...... 357,368 548,372 - 465,800 - 1988 Employee(*)...... 770,272 1,161,840 - 942,800 - 1989 Employee(*)...... 1,010,133 752,569 - 607,900 - 1990 Employee(*)...... 466,272 338,281 - 266,600 - 1991 Employee......... 1,050,303 765,417 28,922 639,600 32,000 1992 Employee......... 98,317 91,791 3,302 65,500 4,000 1993 Employee......... 288,975 205,568 16,382 134,700 23,000 Consolidated Program.. 14 2,052 208 2,325 895 1994 Employee......... 766,036 215,912 66,774 88,000 80,000 1995 Employee......... 104,273 1,656 875 - - (*) Effective December 31, 1993, this program was merged with and into the Consolidated Program. (**) Formed primarily for purposes of acquiring producing oil and gas properties. 68 LIMITED PARTNERS' NET CASH TABLE(1) As of September 30, 1995 Total Revenues Total Less Revenues Operating Distributed Total Total Costs for for 3 Expenditures Revenues 3 Months Months Less Less Ended Total Ended Capital Operating Operating Sept.30, Revenues Sept. 30, Program Contributed Costs(2) Costs 1995 Distributed 1995 - ------------- ---------- ---------- ----------- ------- ---------- -------- 1979......... $3,000,000 $6,197,490 $ 9,912,201 $ 9,412 $5,896,401 $ - 1980......... 12,000,000(3) 14,469,265 3,729,906 - 760,000 - 1981......... 29,255,000(4) 32,700,741 11,395,621 - 5,335,065 - 1981-II...... 15,000,000 16,603,760 4,994,106 - 1,710,001 - 1982-A....... 21,140,000 21,591,442 9,434,313 - 6,342,000 - 1982-B....... 10,555,000 9,935,850 3,233,596 - 2,828,740 - 1983-A....... 2,530,000 2,993,705 1,145,026 - 227,700 - 1984......... 1,575,000 2,034,041 846,166 8,826 510,341 13,230 (5) 1984 Employee(*) 174,000 86,664 137,262 - 125,280 - 1985 Employee(*) 283,500 227,670 128,753 - 182,644 - 1986 Energy Income Fund(**) 1,000,000 1,088,143 1,629,050 456 1,452,100 - 1986 Employee(*) 229,750 267,008 508,122 - 460,007 - 1987 Employee(*) 209,000 207,060 335,044 - 324,845 - 1988 Employee(*) 177,000 214,712 326,858 - 281,630 - 1989 Employee(*) 157,000 157,306 153,044 - 147,737 - 1990 Employee(*) 253,000 254,483 142,479 - 180,895 - 1991 Employee.. 253,000 273,842 205,252 7,760 177,525 8,679 (6) 1992 Employee.. 240,000 253,628 238,900 8,590 197,760 8,400 (7) 1993 Employee.. 245,000 267,336 191,022 15,275 141,120 20,825 (8) Consolidated Program........ - 1,564 200,295 20,529 197,012 28,343 (9) 1994 Employee.. 284,000 308,089 89,092 27,377 37,772 28,968(10) 1995 Employee.. 346,550 143,995 4,664 2,719 - - __________ (*) Effective December 31, 1993, this program was merged with and into the Consolidated Program. (**) Formed primarily for purposes of acquiring producing oil and gas properties. (1) Amounts reflect the accrual method of accounting. 69 (2) Does not include expenditures of $237,600, $920,453, $2,252,900, $1,480,248, $2,079,268, $985,371 and $241,076 which were obtained from bank borrowings and used to pay the limited partners' share of sales commissions of $237,600, $722,453, $1,940,400, $1,183,248, $1,656,468, $827,046 and $190,476 and organization costs of $--0--, $198,000, $312,500, $297,000, $422,800, $158,325 and $50,600 for the 1979, 1980, 1981, 1981-II, 1982-A, 1982-B and 1983-A Programs, respectively. (3) Includes original subscriptions of limited partners totaling $10,000,000 and additional assessments totaling $2,000,000. (4) Includes original subscriptions of limited partners totaling $25,000,000 and additional assessments totaling $4,255,000. (5) In November 1995, the 1984 Program made a distribution of $6,930 to that program's limited partners. (6) In November 1995, the 1991 Employee Program made a distribution of $6,049 to that program's limited partners. (7) In November 1995, the 1992 Employee Program made a distribution of $10,320 to that program's limited partners. (8) In November 1995, the 1993 Employee Program made a distribution of $17,150 to that program's limited partners. (9) In November 1995, the Consolidated Program made a distribution of $17,464 to that program's limited partners. (10) In November 1995, the 1994 Employee Program made a distribution of $11,076 to that program's limited partners. FEDERAL INCOME TAX ASPECTS General The following discussion of federal income tax considerations is based on existing provisions of the Internal Revenue Code of 1986, as amended ("Code"), existing and proposed Treasury Regulations, existing administrative interpretations, and existing court decisions. No assurance can be given that legislation, Treasury Regulations, administrative interpretations, or court decisions will not significantly change existing law, or that any of such changes will not be applied retroactively. Conner & Winters, A Professional Corporation, tax counsel to the Partnership ("Counsel"), is of the opinion that to the extent the summary of federal income tax consequences to the Limited Partners set forth in this "FEDERAL INCOME TAX ASPECTS" section and under the 70 heading "RISK FACTORS--Tax Related Risks" involves matters of law, these statements are accurate in all material respects under the Code, Treasury Regulations, and existing interpretations thereof and address the material federal income tax considerations relating to an investment in the Partnership. An opinion of counsel is not binding on the Service or the courts. Accordingly, it is possible that the Service will successfully challenge the tax treatment of certain matters discussed herein. BECAUSE EACH INDIVIDUAL'S TAX SITUATION WILL BE DIFFERENT, EACH PROSPECTIVE INVESTOR SHOULD CONSULT HIS OR HER OWN TAX ADVISOR CONCERNING FEDERAL, STATE, AND LOCAL INCOME AND OTHER TAX LAWS THAT MAY APPLY TO HIS OR HER PARTICIPATION. THE TAX ASPECTS DESCRIBED BELOW DO NOT CONSTITUTE, AND SHOULD NOT BE CONSIDERED AS, LEGAL OR TAX ADVICE. Summary of Certain Matters Assuming the accuracy of certain factual matters identified below, the Partnership will be classified, for federal income tax purposes, as a partnership and not as a corporation and the income of the Partnership will not be subject to federal income tax. Instead each Limited Partner will include in computing his or her income tax his or her distributive share of the items of income, gain, loss, deduction (including an allowance for depletion with respect to income from the Partnership's oil and gas properties), and credit of the Partnership. Except as noted below, the distributive share for federal income tax purposes of each Limited Partner will be determined as provided in the Agreement. Moreover, distributions from the Partnership will not, in general, be subject to income tax. It is expected the income of the Partnership will be passive income which may be used to offset a Limited Partner's losses from other passive activities. Partnership Classification The federal income tax consequences summarized herein depend on the classification of the Partnership as a partnership and not as an association taxable as a corporation for federal income tax purposes. In Counsel's opinion, the Partnership will be treated as a partnership for federal income tax purposes assuming the satisfaction at all times of the following conditions: (i) A duly executed Certificate of Limited Partnership for the Partnership will be filed with the Oklahoma Secretary of State in compliance with the Act and the organization and operation of the Partnership will be in accordance with the Agreement and the Act; (ii) The General Partner will continue to serve as such and is neither controlled by nor is it acting as agent for the Limited Partners or any Persons affiliated with the Limited Partners; 71 (iii) The General Partner has and will maintain substantial assets which can be reached by a creditor of the Partnership, exclusive of its interests in the Partnership and notes and accounts receivable from and payable to the Partnership. At the time of admission of Limited Partners to the Partnership, the General Partner will have a net worth equal to at least 10% of the total Capital Contributions made to the Partnership, excluding any net worth attributable to any interest of the General Partner in the Partnership. For purposes of satisfying this net worth requirement, assets will be valued based upon their current fair market value. The General Partner will use its best efforts to ensure that the net worth of the General Partner continues to meet these requirements throughout the term of the Partnership; (iv) The General Partner will, in the aggregate, at all times during the existence of the Partnership, receive at least 1% of each material item of the Partnership's income, gain, loss, deduction, or credit; (v) In excess of 90% of the gross income of the Partnership will be interest income, (excluding interest identified in Section 7704(d)(2) of the Code) dividends, and gains derived from the exploration, development, mining, or production, processing, refining, transportation, or the marketing of minerals or natural resources, or gain from the sale or disposition of interests in oil and gas properties or other items described in Section 7704(d) of the Code; and (vi) There are no other documents or agreements which alter, modify, or change in any way the validity and accuracy of the above assumptions and information. If the Partnership were classified as a corporation for federal income tax purposes, then (a) the taxable income of the Partnership would be subject to the corporate federal income tax, (b) the income, gains, losses, deductions and credits of the Partnership (including deductions for depletion with respect to income from oil and gas properties) would not be taken into account by the Limited Partners in computing federal income tax, and (c) distributions by the Partnership would be treated as ordinary income (not subject to depletion) to the extent of the current and accumulated earnings and profits of the Partnership. As a result, the after-tax investment return of a Limited Partner by reason of an investment in the Partnership would likely be significantly reduced. The following discussion assumes that the Partnership will be classified as a partnership and not as a corporation for federal income tax purposes. Taxation of Limited Partners A Limited Partner must report for a taxable year his or her share of the Partnership's items of income, gain, loss, deduction, and credit for the Partnership's taxable year that ends during or with the Limited 72 Partner's taxable year, whether or not any cash is actually distributed to the Limited Partner. Revenues from the Partnership's sale of oil and gas production are taxable to Limited Partners as ordinary income subject to depletion and other deductions discussed below. Partnership Allocations. The allocations of items of income, gain, loss, deduction, and credit of the Partnership are discussed under "PARTICIPATION IN COSTS AND REVENUES" in this Memorandum. Counsel is of the opinion that, except as discussed in the following paragraph, the allocations provided in the Agreement will be respected for federal income tax purposes because they have "substantial economic effect," as that term is defined in Treasury Regulations Section 1.704-1(b)(the "704(b) Regulations"), to the extent the allocations do not result in any Limited Partner having a deficit in his or her capital account (after taking into account the adjustments required by Section 1.704- 1(b)(2)(ii)(d) of the 704(b) Regulations). It is possible the Service could adopt an interpretation of the 704(b) Regulations different than that relied upon by Counsel. Code Section 613A(c)(7)(D) requires the depletable basis of oil and gas properties owned by a partnership be allocated to the partners in accordance with their interest in the capital or income of the partnership. The Partnership will allocate the basis in each Partnership Property to the Partners in accordance with their interest in the capital of the Partnership on December 31, 1996. Due to a lack of authority relating to the allocation of basis in oil or gas properties consistent with the policy underlying the applicable Code Section, Counsel is unable to opine that the manner in which the Partnership will allocate the basis of each Partnership Property (and therefore any associated cost depletion deductions) to the Limited Partners will comply with the relevant Code and Treasury Regulation requirements. Notwithstanding this uncertainty, Counsel does not believe that any reallocation of the basis of Partnership Properties in response to a Service challenge of the proposed method of allocation would differ significantly from the proposed method which is set out in the Agreement. Partnership Losses. Subject to the "passive loss" limitation rules described under "Limitations on Losses and Credits from Passive Activities" below and the limitations on miscellaneous itemized deductions, each Limited Partner may deduct his or her share of the Partnership's taxable loss, if any, on his or her own federal income tax return only to the extent of the lesser of the Limited Partner's tax basis in his or her Units at the end of the Partnership's fiscal year in which the loss occurs or the amount that the Limited Partner is "at risk" with respect to an activity of the Partnership. Partnership losses which exceed the Limited Partner's tax basis or "at risk" amount may be deducted in any subsequent year to the extent the Limited Partner's tax basis and "at risk" amounts are increased above zero. A Limited Partner's adjusted tax basis in the Partnership will initially be equal to his or her Capital Contribution. This basis will be 73 increased by (i) the Limited Partner's additional cash contributions, if any, (ii) the Limited Partner's distributive share of income and gain, (iii) the Limited Partner's share of any nonrecourse borrowing of the Partnership, and (iv) the excess of the Limited Partner's deductions for depletion over the basis of the Limited Partner's share of Partnership Properties subject to depletion. The basis will be decreased (but not below zero) by (i) distributions to the Limited Partner from the Partnership, (ii) the Limited Partner's distributive share of the Partnership deductions and losses, (iii) the Limited Partner's depletion deduction on the Limited Partner's share of Partnership Revenues, (iv) and decreases in the Limited Partner's share of nonrecourse borrowings of the Partnership, and (v) the Limited Partner's share of nondeductible expenses of the Partnership which are not properly chargeable to the Partnership capital accounts for federal income tax purposes. A Limited Partner's aggregate "at risk" amount for all Partnership activities will generally be equal to the amount he or she pays for his or her Units plus, in certain cases, his or her share of Partnership Revenues less prior deductions, losses, and cash distributions. Limitations on Losses and Credits from Passive Activities. Code Section 469 imposes limits on the ability of individuals and certain closely held corporations to use losses and credits from so-called "passive activities" to offset taxable income and tax liability arising from nonpassive sources. With the exception of that portion of Partnership Revenues that is portfolio income, as defined below, and any gain or loss from the disposition of a Partnership property that the Treasury Regulations described below classify as not arising from a passive activity, based on the anticipated activities of the Partnership (and assuming the business of the Partnership is conducted as described in this Memorandum), Counsel is of the opinion that the Limited Partners' distributive shares of items of income, gain, loss, deduction, and credit of the Partnership derived from the Partnership's oil and gas operations (other than oil and gas production payments owned by the Partnership) and the sale of oil and gas properties will be treated as derived from a passive activity. Generally, a taxpayer's deductions and credits from passive activities may be used to reduce his or her tax liability in a given taxable year only to the extent his or her liability arises from passive activities. In determining the amount of income from passive activities in any taxable year, a taxpayer must exclude "portfolio income." Portfolio income includes interest, dividends, annuities or royalties, unless such income is derived in the ordinary course of certain types of trades or businesses, less (a) expenses (other than interest) directly and clearly allocable to such income and (b) interest expenses properly allocable to such income. For this purpose, portfolio income also includes any gain or loss from the disposition of property that produces portfolio income or that is held for investment, as well as income derived from oil and gas production payments. Any income, gain, or loss attributable to an investment of working capital (such as unexpended Capital Contributions) will also be treated as 74 portfolio income. Prospective investors should note that the portfolio income of the Partnership must be reported as taxable income of the Partnership, without reduction for any of the expenses of the Partnership (other than those described in clauses (a) and (b) of the second sentence of this paragraph), and that each Limited Partner will be required to pay federal income tax on his or her share of such portfolio income, even if no corresponding distribution is made by the Partnership to the Limited Partners. Based on representations of the General Partner, Counsel believes that the activities of the Partnership which involve the exploration, development and production of oil and gas will constitute the conduct of a trade or business. Consequently, the portfolio income of the Partnership will primarily consist of interest, if any, earned on its invested cash reserves pending their investment in oil and gas properties and/or drilling activities. Prospective investors should be aware, however, that the Department of Treasury has reserved the right to recharacterize other types of income from passive activities as portfolio income. To the extent a taxpayer's aggregate losses from all passive activities exceed his or her aggregate income from all passive activities in a given taxable year, the taxpayer has a "passive activity loss" for the year. Similarly, a "passive activity credit" arises in any year to the extent taxpayer's tax credits (with certain limited exceptions) arising from all passive activities exceed his or her tax liabilities allocable to all passive activities. A passive loss or credit may be carried forward to successive taxable years until fully utilized against income from passive activities in such years; however, passive losses and credits may not be carried back to prior years. In addition, where a taxpayer disposes of his or her entire interest in a passive activity in a transaction in which all of the gain or loss realized on the disposition is recognized, any loss from that activity that was suspended by the passive loss rules will cease to be treated as a passive loss and any loss on the disposition will not be treated as arising from a passive activity. Such losses will be allowed as deductions against income in the following order: (i) gain recognized on the disposition; (ii) net income or gain for the taxable year from all passive activities; and (iii) any other income or gain. Under Section 469(k) of the Code, the limitations on losses and credits from passive activities will be applied separately to a partnership which is considered "publicly traded" under Code Section 7704. For this purpose, a publicly traded partnership is one the interests in which are (a) traded on an established securities market or (b) readily tradeable on a secondary market (or the substantial equivalent thereof). Under the Agreement, the Limited Partners are prohibited from transferring their Units except under very limited circumstances. Based on the representation of the General Partner that it and the Partnership will adhere to the transferability restrictions in the Agreement, Counsel is of the opinion that the Partnership will not be considered publicly traded under Code Section 7704. 75 Intangible Drilling and Development Costs. The Partnership will participate in the drilling of wells on the oil and gas properties in which it acquires an interest. Currently, federal tax laws permit immediate write-offs of certain intangible drilling and development costs against a taxpayer's income. Assuming an appropriate election by the Partnership under Section 263(c) of the Code, intangible drilling and development costs may be deducted as an expense for income tax purposes (subject to the limitations described above under "Partnership Losses"). These costs include expenditures for services and materials having no salvage value which are provided or utilized in preparing a drill site and drilling, testing and completing a well. Generally, a taxpayer may not deduct a greater portion of the intangible drilling and development costs incurred with respect to a particular well than the portion of the well owned by it when the costs are incurred. In the event the Partnership acquires interests in certain oil and gas properties with respect to which drilling activities have already commenced prior to the Partnership's investment, that portion of the Partnership's acquisition cost for such properties which represents its share of the drilling costs previously incurred will not be deductible by the Limited Partners as intangible drilling and development costs. Instead such amounts will be capitalized as part of the depletable basis of such properties. Also, it is possible that because the General Partner's and the Limited Partners' ultimate revenue interests in the Partnership will not be finally determined until after December 31, 1996 (see "PARTICIPATION IN COSTS AND REVENUES"), the Service may attempt to disallow deductions claimed by the Limited Partners for all or a portion of the intangible drilling and development costs specially allocated to them pursuant to the Agreement. The law provides for a recapture of intangible drilling and development costs, requiring the taxpayer to treat as ordinary income any gain on the disposition of oil and gas properties (or any interest in any oil and gas partnership) to the extent of intangible drilling and development costs deducted with respect to such properties. In some cases, the agreements under which the Partnership acquires an interest in a property may require the Partnership to pay a share of the costs attributable thereto which is disproportionately greater than the working interest acquired. In such cases, generally, the excess portion of intangible drilling and development costs must be capitalized as additional leasehold costs. However, full deductibility is obtainable under certain arrangements and in certain circumstances. The General Partner will seek to structure the agreements for the acquisition of properties in a manner which will permit the deduction of the full amount of the intangible drilling and development costs paid but there can be no assurance that it will be able to do so or that the arrangements will be recognized for federal income tax purposes. Since all of the facts and terms of such arrangements are not currently known, it is not practicable to predict the outcome of a challenge to the full deductibility of such costs. 76 Depletion. The Partnership will be the owner of economic interests in its oil and gas properties (except for certain production payments). The Limited Partners are entitled to a deduction for depletion with respect to a Partnership's production and sale of oil and gas from these properties. With respect to each oil and gas property, a Limited Partner's deduction for each year is the greater of cost depletion or percentage depletion. Percentage depletion with respect to a property is equal to 15% of the gross income attributable to the production from such property, subject to certain limitations. Percentage depletion is allowable even if the taxpayer has no basis in the property and continues to be allowable after the taxpayer has fully depleted his or her basis in the property. Cost depletion allows the leasehold cost of each producing Partnership Property to be recovered over its productive life based on units of production. To determine the per unit (i.e., barrels of oil or cubic feet of gas) allowance, the adjusted tax basis for the property is divided by the estimated total units recoverable therefrom. The cost depletion deduction is the per unit allowance multiplied by the number of units sold during the year. Depletion computed under this method cannot exceed the cost or other basis of the producing property. In the case of the Partnership, the cost or percentage depletion allowance is computed separately by the Partners, and not by the Partnership. Nominee Ownership of Partnership Properties. In the event the Partnership Properties are not held in the name of the Partnership, it is anticipated that all of the Partnership Properties will be held in the record name of Unit Texas Company ("UNIT Nominee"), an affiliate of UNIT and a wholly-owned subsidiary of Unit Petroleum Company. In Counsel's opinion the Partnership will be treated, for federal income tax purposes, as the owner of the Partnership Properties held by UNIT Nominee for its benefit assuming the accuracy at the time of formation of the Partnership, and the continuing accuracy thereafter, of the following representations of the General Partner: (i) A nominee/agent agreement ("Nominee Agreement") in substantially the form of the Nominee Agreement attached as Exhibit I to Counsel's opinion included as Exhibit B to this Memorandum will be executed by and between UNIT Nominee, as agent, and the Partnership before any interests in oil and gas properties are acquired by UNIT Nominee as agent for the Partnership; (ii) The terms and provisions of the Nominee Agreement entered into as provided above will be adhered to by each party thereto and, in particular, UNIT Nominee will be held out as the agent and not the principal in all dealings with third parties 77 relating to the oil and gas properties which UNIT Nominee holds as agent for the Partnership; and (iii) The beneficial ownership of any oil and gas property interests to be assigned to the Partnership will be assigned to the Partnership by delivery to UNIT Nominee, as agent for the Partnership, of an enforceable written assignment, in substantially the form of Exhibit II to Counsel's opinion included as Exhibit B to this Memorandum, properly executed by the assignor. If the Service were to argue successfully that UNIT Nominee should be treated as the tax owner of the Partnership's oil and gas properties, there would be significant adverse federal income tax consequences to the Limited Partners, such as the unavailability of depletion deductions in respect of income from oil and gas properties. Reimbursement of Expenses. The Agreement provides that the General Partner shall be reimbursed by the Partnership, subject to limitations based on a percentage of the Aggregate Subscription, for that portion of its general and administrative overhead expenses attributable to its conduct of the Partnership's business and affairs. Such reimbursement will be charged to the accounts of the Partners in the same proportions that Partnership Revenue is being shared at the time such expenses are incurred and will be paid from Partnership Revenue. Generally, the reimbursements paid to the General Partner will be currently deductible to the extent they represent ordinary and necessary business expenses incurred by the Partnership in the course of its business for services rendered by the General Partner. As all of the facts regarding the nature of the services to be rendered are not known and may vary according to the circumstances presented, it is not practical to predict whether all or a substantial portion of such reimbursement will be deductible, if challenged, and there can be no assurance that any such challenge would not ultimately be upheld. Sales and Distributions. The Partnership's gain on a sale of an interest in an oil and gas property will be measured by the difference between the sale proceeds (including the amount of any indebtedness to which the property is subject) and the adjusted basis of the property. Consequently, the amount of tax payable by a Limited Partner on his or her share of the Partnership's allocable share of such gain may in some cases exceed his or her share of cash proceeds therefrom. Gain realized by the Partnership (and, thus, the Limited Partners) on a sale of an oil and gas property will be ordinary income to the extent of the recapture of depreciation, depletion and intangible drilling and development costs. In that regard, the Partnership's cost of acquiring and improving equipment such as pipe, casing, tubing, storage tanks and pumps will be capitalized and depreciated. Cash distributions to a Limited Partner will not be taxable except that amounts distributed in excess of the Limited Partner's tax basis 78 will be taxable. Generally, any amounts distributed to a Limited Partner in excess of his or her tax basis will be capital gain except to the extent of ordinary income attributable to the Limited Partner's share of recapture items (discussed in the preceding paragraph). When a Limited Partner's share of Partnership nonrecourse debt is reduced for any reason, the amount of the reduction is deemed to be a cash distribution. Like an actual cash distribution, the deemed distribution reduces a Limited Partner's adjusted tax basis of his or her Units. Generally, a Limited Partner will realize a gain or loss on the disposition of his or her Units measured by the difference between the amount realized on the disposition and the Limited Partner's adjusted basis for such Units. Since a Limited Partner's share of Partnership nonrecourse indebtedness must be included in the amount realized upon the disposition of the Units, any gain realized on the disposition may result in a tax liability greater than the cash proceeds, if any, from the disposition. The Code requires each person who transfers an interest in a limited partnership possessing "unrealized receivables" or "substantially appreciated inventory items" to report the transfer to the limited partnership. It is expected that the Partnership will be deemed to possess these items. A transferring Limited Partner will be required to report to the General Partner the name, address, and taxpayer identification number of the person acquiring Units and the date on which the Units are transferred. This report to the General Partner must be submitted at the time of sale, or no later than seven days after receipt by the transferor of the purchaser's taxpayer identification number. When the General Partner is notified of any transfers of Units, the identity of the transferor and transferee will be provided to the Service together with any other information required by Treasury Regulations. Failure by a Limited Partner to report a transfer covered by this provision may result in a penalty of $50 per occurrence. The Code permits a partnership to elect, pursuant to Sections 734, 743, and 754, to adjust a partner's share of the tax basis of partnership property following redemption of an interest, death of a partner, or a purchase of a partnership interest by such partner. Because of the tax accounting complexities inherent in, and the substantial expense incident to, making such an election to adjust the tax basis, the General Partner does not presently intend to make such elections on behalf of the Partnership, although it is empowered to do so by the Agreement. The absence of any such election may, in some circumstances, result in a reduction in the value of Units to any potential purchaser. Once a Section 754 election is made on behalf of the Partnership, the tax basis of its property must be adjusted upon all future transfers of interests in the Partnership to any transferee. 79 IRS Tax Shelter Registration Section 6111 of the Code requires an organizer of a "tax shelter" to register the tax shelter with the Secretary of the Treasury and to obtain an identification number which must be included on the tax returns of investors in that tax shelter. Under Temporary Treasury Regulations interpreting Section 6111, the Partnership would constitute a "tax shelter" required to register. While not necessarily agreeing with the expansive interpretation of the registration requirements in the Temporary Treasury Regulations, the General Partner will take all necessary steps to comply with the registration requirements because there are onerous penalties for failing to register as a "tax shelter." After the General Partner has caused the Partnership to be registered in compliance with the requirements, the Service will assign a registration number to the Partnership. The General Partner will furnish this registration number to the Limited Partners. ISSUANCE OF A REGISTRATION NUMBER DOES NOT INDICATE THAT AN INVESTMENT IN THE PARTNERSHIP OR THE CLAIMED TAX BENEFITS THEREFROM HAVE BEEN REVIEWED, EXAMINED OR APPROVED BY THE INTERNAL REVENUE SERVICE. Each Partner must (i) report the Partnership's registration number on Treasury Form 8271 and attach this form to his or her federal income tax return for each taxable year in which he or she is a Partner, and (ii) furnish the Partnership's registration number to each person to whom he or she transfers Units. Partnership Tax Returns and Tax Information Information returns filed by the Partnership are subject to audit by the Service. Prospective investors should note that a federal income tax audit of the Partnership's tax information returns may result in an audit of the returns of the Limited Partners, and that an examination could result in adjustments both to items related to the Partnership and to unrelated items. Interest paid by individuals in respect of an underpayment of tax is nondeductible. The interest rate for an underpayment of tax is set quarterly at the federal short-term rate plus 3 percentage points. The underpayment rate which commenced October 1, 1995 is 9%, compounded daily. The tax treatment of Partnership items will be determined at the Partnership level, rather than in separate proceedings with the Partners. Thus, the availability and amount of the tax deductions taken by the Limited Partners will depend not only on the general legal principles discussed herein, but also upon various determinations of the General Partner. These determinations are subject to challenge by the Service on factual or other grounds. Generally, each Partner is required to treat Partnership items on his or her return consistently with the treatment on the Partnership return. Where this treatment is 80 inconsistent, a statement must be filed by the Partner identifying the inconsistency. If the consistency requirement is not satisfied and the identifying statement is not filed, the Service may assess a deficiency against the Partner before audit proceedings are completed at the Partnership level. Additionally, if a taxpayer fails to show properly on a return any amount that is shown on an information return, the taxpayer's failure may be treated as negligence and subject to a penalty equal to 20% of the underpayment of tax attributable to the negligence. The General Partner is to be designated pursuant to Treasury Regulations as the tax matters partner ("TMP"). The TMP is responsible for protecting the interests of the Partners in the audit process. In the Agreement, the General Partner is designated as the TMP and, as such, is given the right, on behalf of the Partnership, to determine whether to challenge a final Partnership administrative adjustment proposed by the Service. If the TMP determines not to challenge an administrative adjustment, any Partner with at least a 1% interest in the Partnership and any requesting group of Partners that together have at least a 5% interest in the Partnership may challenge it. Generally, the period for assessment with respect to Partnership items for any Partnership taxable year will not expire before three years from (a) the date of filing the Partnership return or, if later, (b) the last date prescribed for filing such return determined without extensions. The period may be extended for all Partners by agreement with the TMP (or other person authorized in writing by the Partnership). The procedures regarding the audit of partnerships and the authority of the TMP are complex and cannot be described completely herein. Each prospective investor is urged to seek the advise of his or her individual tax advisor with respect to those audit provisions. Laws Subject to Change The tax aspects described above are based upon interpretations of the Code as it has been amended to the date of this Memorandum and as Counsel understand it. Federal income tax laws and regulations and interpretations thereof are subject to change by Congress, and the courts and administrative agencies. Regulations have not been issued or proposed under most of the provisions of recent legislation. For these reasons, no assurance can be given that the foregoing interpretations will not be challenged or if challenged, will be sustained or that the favorable tax aspects described above will be available in future years. 81 State and Local Taxes In addition to the federal income tax aspects described above, prospective investors should consider with their advisors the state tax consequences of an investment in Units. COMPETITION, MARKETS AND REGULATION The oil and gas industry is highly competitive in all its phases. The Partnership will encounter strong competition from both major independent oil companies and individuals, many of which possess substantial financial resources, in acquiring economically desirable prospects and equipment and labor to operate and maintain Partnership Properties. There are likewise numerous companies and individuals engaged in the organization and conduct of oil and gas drilling pro- grams and there is a high degree of competition among such companies and individuals in the offering of their programs. Marketing of Production The availability of a ready market for any oil and gas produced from Partnership Wells will depend upon numerous factors beyond the control of the Partnership, including the extent of domestic production and importation of oil and gas, the proximity of Partnership Wells to gas pipelines and the capacity of such gas pipelines, the marketing of other competitive fuels, fluctuation in demand, governmental regulation of production, refining and transportation, general national and worldwide economic conditions, and the pricing, use and allocation of oil and gas and their substitute fuels. The demand for gas decreased significantly in the 1980s due to economic conditions, conservation and other factors. As a result of such reduced demand and other factors, including the Power Plant and Industrial Fuel Use Act (the "Fuel Use Act") which related to the use of oil and gas in the United States in certain fuel burning installations, many pipeline companies began purchasing gas on terms which were not as favorable to sellers as terms governing purchases of gas prior thereto. Spot market gas prices declined generally during that period. While the Fuel Use Act has been repealed and the General Partner expects that the markets for gas will improve, there can be no assurance that such improvement will occur. As a result, it is possible that there may be significant delays in selling any gas from Partnership Properties. In addition, production of gas, if any, from Partnership Wells may be dedicated to long-term gas purchase contracts with gas purchasers. In such event, the price received upon the sale of such gas might be higher or lower than if such gas had not been so dedicated. 82 In the event the Partnership acquires an interest in a gas well or completes a productive gas well, or a well that produces both oil and gas, the well may be shut in for a substantial period of time for lack of a market if the well is in an area distant from existing gas pipelines. The well may remain shut in until such time as a gas pipeline, with available capacity, is extended to such an area or until such time as sufficient wells are drilled to establish adequate reserves which would justify the construction of a gas pipeline, processing facilities, if necessary, and a transmission system. The worldwide supply of oil has been largely dependent upon rates of production of foreign reserves. Although in recent years the demand for oil has slightly increased in this country, imports of foreign oil continue to increase. Consequently, the prices for domestic oil production have remained low. Future domestic oil prices will depend largely upon the actions of foreign producers with respect to rates of production and it is virtually impossible to predict what actions those producers will take in the future. Prices may also be affected by political and other factors relating to the Middle East. As a result, it is possible that prices for oil, if any, produced from a Partnership Well will be lower than those currently available or projected at the time the interest therein is acquired. In view of the many uncertainties affecting the supply and demand for crude oil and natural gas, and the change in the makeup of the Congress of the United States and the resulting potential for a different focus for the United States energy policy, the General Partner is unable to predict what future gas and oil prices will be. Regulation of Partnership Operations Production of any oil and gas found by the Partnership will be affected by state and federal regulations. All states in which the Partnership intends to conduct activities have statutory provisions regulating the production and sale of oil and gas. Such statutes, and the regulations promulgated in connection therewith, generally are intended to prevent waste of oil and gas and to protect correlative rights and the opportunities to produce oil and gas as between owners of a common reservoir. Certain state regulatory authorities also regulate the amount of oil and gas produced by assigning allowable rates of production to each well or proration unit. Pertinent state and federal statutes and regulations also extend to the prevention and clean-up of pollution. These laws and regulations are subject to change and no predictions can be made as to what changes may be made or the effect of such changes on the Partnership's operations. Under the laws and administrative regulations of the State of Oklahoma regarding forced pooling, owners of oil and gas leases or unleased mineral interests may be required to elect to participate in the drilling of a well with other fractional undivided interest owners within an established spacing unit or to sell or farm out their inter- 83 est therein. The terms of any such sale or farm-out are generally those determined by the Oklahoma Corporation Commission to be equal to the most favorable terms then available in the area in arm's length transactions although there can be no assurance that this will be the case. In addition, if properties become the subject of a forced pooling order, drilling operations may have to be undertaken at a time or with other parties which the General Partner feels may not be in the best interest of the Partnership. In such event, the Partnership may have to farm out or assign its interest in such properties. In addi- tion, if a property which might otherwise be acquired by the Partner- ship becomes subject to such an order, it may become unavailable to the Partnership. Finally, as a result of forced pooling proceedings involving a Partnership Property, the Partnership may acquire a larger than anticipated interest in such property, thereby increasing its share of the costs of operations to be conducted. Natural Gas Price Regulation Partnership Revenues are likely to be dependent on the sale and transportation of natural gas that may be subject to regulation by the Federal Energy Regulatory Commission ("FERC"). Historically the sale of natural gas has been regulated by the FERC under the Natural Gas Act of 1938 ("NGA") and/or the Natural Gas Policy Act of 1978 ("NGPA"). Under the NGPA, natural gas is divided into numerous, complex categories based on, among other things, when, where and how deep the gas well was drilled and whether the gas was committed to interstate or intrastate commerce on the day before the date of enactment of the statute. These categories determine whether the natural gas remains subject to non-price regulation under the NGA and/or to maximum price restrictions under the NGPA. In addition to setting ceiling prices for natural gas, FERC approval is required for both the commencement and abandonment of sales of certain categories of gas in interstate commerce for resale and for the transportation of natural gas in interstate commerce. FERC has general investigatory and other powers, including limited authority to set aside or modify terms of gas purchase contracts subject to its jurisdiction. Price and non-price regulation of natural gas produced from most wells drilled after 1978 has terminated. That gas may be sold without prior regulatory approval and at whatever price the market will bear. On July 26, 1989, the Natural Gas Wellhead Decontrol Act of 1989 (the "Wellhead Decontrol Act") became effective. Consequently, due to this statutory deregulation and FERC's issuance of Order No. 547 discussed below, as of January 7, 1993 the price of virtually all gas produced by producers not affiliated with interstate pipelines has been deregulated by FERC. Market determined prices for deregulated categories of natural gas fluctuate in response to market pressures which currently favor purchasers and disfavor producers. As a result of the deregulation of 84 a greater proportion of the domestic United States gas market and an increased availability of natural gas transportation, a competitive trading market for gas has developed. For several reasons the supply of gas has exceeded demand. The General Partner cannot reliably predict at this time whether such supply/demand imbalance will improve or worsen from a producer's viewpoint. During the past several years, FERC has adopted several regulations designed to create a more competitive, less regulated market for natural gas. These regulations have materially affected the market for natural gas. FERC's initial major initiative was adoption of its "open-access transportation program," through Order No.s 436 and 500. Regulation of Natural Gas Pipelines After Partial Wellhead Decontrol, Order No. 436, 50 Fed. Reg. 42,408 (October 18, 1985), vacated and remanded, Associated Gas Distributors v. FERC, 824 F.2d 981 (D.C. Cir. 1987), cert. denied, 485 U.S. 1006 (1988), readopted on an interim basis, Order No. 500, 52 Fed. Reg. 30,344 (Aug. 14, 1987), remanded, American Gas Association v. FERC, 888 F.2d 136 (D.C. Cir. 1989), readopted, Order No. 500-H, 54 Fed. Reg. 52,344 (Dec. 21, 1989), reh'g granted in part and denied in part, Order No. 500-I, 55 Red. Reg. 6605 (Feb. 26, 1990), aff'd in part and remanded in part, American Gas Association v. FERC, 912 F.2d 1496 (D.C. Cir. 1990), cert. denied, 111 S. Ct. 957 (1991). Order 436 implemented three key requirements: (1) jurisdictional pipelines were required to permit their firm sales customers to convert their firm sales entitlements to a volumetrically equivalent amount of firm transportation service over a five-year period; (2) jurisdictional pipelines were required to offer their open-access transportation services without discrimination or preference; and (3) jurisdictional pipelines were required to design maximum rates to ration capacity during peak periods and to maximize throughput for firm service during off-peak periods and for interruptible service during all periods. The availability of transportation under Order 500 greatly expanded the free trading market for natural gas, including the establishment of an active and viable spot market. Subsequently, in Order 636 the FERC focused on whether the resulting regulatory structure provided all gas sellers with the same regulatory opportunity to compete for gas purchasers. It decided that the form of bundled pipeline services (gas sales and transportation) was unduly discriminatory and anticompetitive. The FERC concluded that "the pipelines' bundled, city-gate firm sales service gives pipelines an undue advantage over other gas sellers because of the superior quality of the 'no-notice' aspect of the transportation embedded within the bundled, city-gate, firm sales service compared to the firm and interruptible transportation available for the gas of nonpipeline gas sellers." Pipeline Service Obligations and Revisions to Regulations Governing Self-Implementing Transportation; and Regulation of Natural Gas Pipelines After Wellhead Decontrol, Order No. 636, 57 Fed. Reg. 85 13,267 (Apr. 16, 1992), III FERC Stats. & Regs. Preambles Paragraph 30,939, at 30,406. Order 636 was clarified in August 1992 and finalized in November 1992. Regulations of Natural Gas Pipelines After Partial Wellhead Decontrol, and Order Denying Rehearing in Part, Granting Rehearing in Part, and Clarifying Order No. 636, Order No. 636-A, 57 Fed. Reg. 36,128 (Aug. 12, 1992), III FERC Stats. & Regs. Preambles Paragraph 30,950; Regulation of Natural Gas Pipelines After Partial Wellhead Decontrol; Order Denying Rehearing and Clarifying Order Nos. 636 and 636-A, Order No. 636-B, 57 Fed. Reg. 57,911 (Dec. 8, 1992). Order 636, a complex regulation, is expected to have a major impact on gas pipeline operations, services and rates. Among other things, Order 636 requires each interstate pipeline company to "unbundle" its traditional wholesale services and create and make available on an open and nondiscriminatory basis numerous constituent services (such as gathering services, storage services, firm and interruptible transportation services, and stand-by sales services) and to adopt a new rate making methodology (Straight Fixed Variable) to determine appropriate rates for those services. To the extent the pipeline company or its sales affiliate makes gas sales as a merchant in the future, it will do so in direct competition with all other sellers pursuant to private contracts; however, pipeline companies have or will become "transporters only." Order 636 also allows pipeline companies to act as agents for their customers in arranging the transportation of gas purchased from any supplier, including the pipeline itself, and to charge a negotiated fee for such agency services. The FERC required each pipeline company to develop the specific terms of service in individual proceedings and to submit for approval by FERC a compliance filing which set forth the pipeline company's new, detailed procedures. The new rules are subject to pending court challenges by numerous parties. In addition, many of the individual pipeline restructurings are the subject of pending appeals, either before the FERC or in the courts. On November 8, 1992, FERC published Order 636-B. Regulation of Natural Gas Pipelines After Partial Wellhead Decontrol; Order Denying Rehearing and Clarifying Order Nos. 636 and 636-A, Order No. 636-B, 57 Fed. Reg. 57,911 (Dec. 8, 1992). Order 636-B essentially upholds without significant change Order Nos. 636 and 636-A. FERC also stated that it will accept no further petitions for rehearing. Thus, Order 636 constitutes final agency action. In essence, the goal of Order 636 is to make a pipeline's position as gas merchant indistinguishable from that of a non-pipeline supplier. It, therefore, pushes the point of sale of gas by pipelines upstream, perhaps all the way to the wellhead. Order 636 also requires pipelines to give firm transportation customers flexibility with respect to receipt and delivery points (except that a firm shipper's choice of delivery point cannot be downstream of the existing primary delivery 86 point) and to allow "no-notice" service (which means that gas is available not only simultaneously but also without prior nomination, with the only limitation being the customer's daily contract demand) if the pipeline offered no-notice city-gate sales service on May 18, 1992. Thus, this separation of pipelines' sales and transportation allows non-pipeline sellers to acquire firm downstream transportation rights and thus to offer buyers what is effectively a bundled city-gate sales service and it permits each customer to assemble a package of services that serves its individual requirements. But it also makes more difficult the coordination of gas supply and transportation. The results of these changes could increase the marketability of natural gas and place the burden of obtaining supplies of natural gas for local distribution systems directly on distributors who would no longer be able to rely on the aggregation of supplies by the interstate pipelines. Such distributors may return to longer term contracts with suppliers who can assure a secure supply of natural gas. A return to longer term contracts and the attendant decrease in gas available for the spot market could improve gas prices. The primary beneficiaries of these changes should be gas marketers and the producers who are able to demonstrate the availability of an assured long-term supply of natural gas to local distribution purchasers and to large end users. However, due to the still evolutionary nature of Order 636 and its implementation, it is not possible at this time to project the impact Order 636 will have on the Partnership's ability to sell gas directly into gas markets previously served by the gas pipelines. As a corollary to Order 636, FERC issued Order 547, which is a blanket certificate of public convenience and necessity pursuant to Section 7 of the NGA that authorizes any person who is not an interstate pipeline or an affiliate thereof to make sales for resale at negotiated rates in interstate commerce of any category of gas that is subject to the Commission's NGA jurisdiction. (There are certain requirements which must be met before an affiliated marketer of an interstate pipeline can avail itself of this certification.) Regulations Governing Blanket Marketer Sales Certificates, Order No. 547, 57 Fed. Reg. 57,952 (Dec. 8, 1992) (to be codified at 18 C.F.R. Sections 284.401 - .402). The blanket certificates are effective January 7, 1993, and do not require any further application by a person. The goal of Order 457, in conjunction with Orders 636, 636-A and 636-B, is to provide all merchants of natural gas a "level playing field" so that gas merchants who are not interstate pipelines are on an equal footing with interstate pipeline merchants who are afforded blanket sales certificates pursuant to Order 636. The FERC is also modifying its traditional use of cost-of-service rate regulation in order to prevent pipelines from exercising market power. However, the FERC has begun to allow individual companies to depart from cost-of-service regulation and set market-based rates if they can show they lack significant market power or have mitigated 87 market power. See, e.g., Richmond Gas Storage Systems, 59 FERC Paragraph 61,316 (1992); El Paso Natural Gas Company, 54 FERC Paragraph 61,316, reh'g granted and denied in part, 56 FERC Paragraph 61,290 (1990); Transcontinental Gas Pipe Line Corp., 53 FERC Paragraph 61,446, reh'g granted and denied in part, 57 FERC Paragraph 61,345 (1991). Since the FERC has stated that "[w]here companies have market power, market- based rates are not appropriate," in order to "enhance productive efficiency in non-competitive markets," the FERC recently issued a rule allowing pipelines (and electric utilities) "to propose incentive rate mechanisms as alternatives to traditional cost-of-service regulations." Incentive Ratemaking for Interstate Natural Gas Pipelines, Oil Pipelines, and Electric Utilities; Policy Statement on Incentive Regulation, 57 Fed. Reg. 55,231 (Nov. 24, 1992). The FERC has established five specific regulatory standards for implementing specific incentive mechanisms: they should (1) be prospective, (2) be voluntary, (3) be understandable, (4) result in quantifiable benefits to consumers including an upper limit on the risk to consumers that the incentive rates would be higher than rates they would have paid under traditional regulation, and (5) demonstrate how they maintain or enhance incentives to improve the quality of service. Other regulatory actions have included elimination of minimum take and minimum bill provisions of pipeline sales tariffs (Order 380) and authorization of automatic abandonment authority upon expiration or termination of the underlying contracts (Order 490). The latter order is currently before the United States Court of Appeals for the Sixth Circuit. FERC has also provided several forms of "blanket" certificates authorizing sales of gas with pregranted abandonment. In addition, in Order 451, FERC established an alternative maximum lawful price for certain NGPA Section 104 and 106 gas produced from wells drilled prior to 1975 (so-called "old gas") which otherwise would be subject to lower ceiling prices. FERC provided, however, that the higher price could be collected only where the parties amended the contract or pursuant to complicated "good faith negotiation" rules which permit purchasers facing requests for increased prices to seek reduction of certain higher prices and authorize abandonment of both the higher cost and lower cost supplies if agreement cannot be reached. After the Fifth Circuit vacated Order 451 as an invalid exercise of FERC's authority, the United States Supreme Court reversed that decision and upheld the entirety of Order 451. The issuance of Order 636 and its future interpretation, as well as the future interpretation and application by FERC of all of the above rules and its broad authority, or of the state and local regulations by the relevant agencies, could affect the terms and availability of transportation services for transportation of natural gas to customers and the prices at which gas can be sold on behalf of the Partnership. For instance, as a result of Order 636, more interstate pipeline companies have begun divesting their gathering 88 systems, either to unregulated affiliates or to third persons, a practice which could result in separate, and higher, rates for gathering a producer's natural gas. In proceedings during mid and late 1994 allowing various interstate natural gas companies' spindowns or spinoffs of gathering facilities, the FERC held that, except in limited circumstances of abuse, it generally lacks jurisdiction over a pipeline's gathering affiliates, which neither transport natural gas in interstate commerce nor sell gas in interstate commerce for resale. However, pipelines spinning down gathering systems have to include two Order No. 497 standards of conduct in their tariffs: nondiscriminatory access to transportation for all sources of supply and no tying of pipeline transportation service to any service by the pipeline's gathering affiliate. In addition, if unable to reach a mutually acceptable gathering contract with a present user of the gathering facilities, the pipeline must offer a two-year "default contract" to existing users of the gathering facilities. Consequently, the General Partner cannot reliably predict at this time how regulation will ultimately impact Partnership Revenue. State Regulation of Oil and Gas Production Most states in which the Partnership may conduct oil and gas activities regulate the production and sale of oil and natural gas. Those states generally impose requirements or restrictions for obtaining drilling permits, the method of developing new fields, the spacing and operation of wells and the prevention of waste of oil and gas resources. In addition, most states regulate the rate of production and may establish maximum daily production allowable from both oil and gas wells on a market demand or conservation basis. Until recently there has been no limit on allowable daily production on the basis of market demand, although at some locations production continues to be regulated for conservation or market purposes. In 1987 the Oklahoma Corporation Commission (the "OCC") promulgated production allowable reductions with respect to relatively high capability gas wells (i.e., those capable of open flowing more than 2,000,000 cubic feet per day) and the law enacted by the Oklahoma legislature during March 1992 gives the OCC power to set statewide (versus only field-by-field) production limits for all natural gas wells producing in the State to prevent waste and to protect the interests of the public against production of natural gas reserves in amounts in excess of the reasonable market demand therefor. The General Partner cannot predict whether the OCC, or any other state regulatory agency, may issue additional allowable reductions which may adversely affect the Partnership's ability to produce its gas reserves. Legislative and Regulatory Production and Pricing Proposals A number of legislative and regulatory proposals continually are advanced which, if put into effect, could have an impact on the petroleum industry. The various proposals involve, among other things, 89 an oil import fee, restructuring how oil pipeline rates are determined and implemented, providing purchasers with "market-out" options in existing and future gas purchase contracts, eliminating or limiting the operation of take-or-pay clauses and eliminating or limiting the operation of "indefinite price escalator clauses" (e.g., pricing provisions which allow prices to escalate by means of reference to prices being paid by other purchasers of natural gas or prices for competing fuels). Proposals concerning these and other matters have been and will be made by members of the President's office, Congress, regulatory agencies and special interest groups. The General Partner cannot predict what legislation or regulatory changes, if any, may result from such proposals or any effect therefrom on the Partnership. Several states have either proposed or enacted regulations that could significantly revise current systems of regulating gas production. On April 27, 1992, the Texas Railroad Commission ("TRC") unanimously approved a new proration system that limits gas production so that it more closely tracks market demand. These rules eliminate monthly purchaser nominations as the starting point for determining reservoir market demand and instead the TRC makes an initial determination of reservoir market demand for prorated fields each month using production in the same month from the previous year and the operator's forecast for demand for that month. This initial determination is subject to four adjustments: (1) capability adjustment (downward revisions to the extent necessary to reflect the capability of wells); (2) reservoir forecast correction adjustment (a correction factor that tracts discrepancies between reservoir production and the adjusted reservoir forecast during the most recently reported production month); (3) supplemental change adjustment (adjustment to account for new wells and changes in well capability or well test status including upward revisions of allowables to cover overproduction from a non-prorated well); and (4) commission adjustment by reservoir (any other adjustments that the TRC determines are necessary to fix the reservoir allowable equal to the lawful market demand, including the correction of any inaccuracies in the initial market demand determination). Individual well allowable determinations are determined by an enhanced capability determination routine. A well capacity is determined as the lesser of the latest TRC well deliverability test on file or the highest monthly production during the last six months. Alternatively, an operator may submit a substitute capability determination that has been determined by a registered professional engineer. During March 1992, the Oklahoma legislature enacted a law which places statewide limits on gas production, as well as a new mechanism for capping gas output, during times of slow demand. This law limits Oklahoma's largest gas wells during summertime production (March through October) to no more than the greater of 750,000 cubic feet per day or 25% of their total capacity and, during the high-demand winter heating season (November through February), those wells will be 90 restricted to no more than the greater of 1,000,000 cubic feet per day or 40% of their total capacity, unless and until the OCC promulgates other production limitations. Other states, including Louisiana, New Mexico and Wyoming, are also reported to be contemplating whether to institute new rules governing gas production in those States. The effect of these regulations could be to decrease allowable production on Partnership Properties and thereby to decrease Partnership Revenues. However, by decreasing the amount of natural gas available in the market, such regulations could also have the effect of increasing prices of natural gas, although there can be no assurance that any such increase will occur. There can also be no assurance that the proposed regulations described above will be adopted or that they will be adopted upon the terms set forth above. Additionally, such proposals, if adopted, are likely to be challenged in the courts and there can be no assurance as to the outcome of any such challenge. Production and Environmental Regulation Certain states in which the Partnership may drill and own produc- tive properties control production from wells through regulations establishing the spacing of wells, limiting the number of days in a given month during which a well can produce and otherwise limiting the rate of allowable production. In addition, the federal government and various state governments have adopted laws and regulations regarding protection of the environment. These laws and regulations may require the acquisition of a permit before or after drilling commences, impose requirements that increase the cost of operations, prohibit drilling activities on certain lands lying within wilderness areas or other environmentally sensitive areas and impose substantial liabilities for pollution resulting from drilling operations, particularly operations in offshore waters or on submerged lands. A past, present, or future release or threatened release of a hazardous substance into the air, water, or ground by the Partnership or as a result of disposal practices may subject the Partnership to liability under the Comprehensive Environmental Response, Compensation and Liability Act, as amended ("CERCLA"), the Resource Conservation Recovery Act ("RCRA"), the Clean Water Act, and/or similar state laws, and any regulations promulgated pursuant thereto. Under CERCLA and similar laws, the Partnership may be fully liable for the cleanup costs of a release of hazardous substances even though it contributed to only part of the release. While liability under CERCLA and similar laws may be limited under certain circumstances, typically the limits are so high that the maximum liability would likely have a significant adverse effect on the Partnership. In certain circumstances, the Partnership may have liability for releases of hazardous substances by previous owners of Partnership Properties. Additionally, the discharge or 91 substantial threat of a discharge of oil by the Partnership into United States waters or onto an adjoining shoreline may subject the Partnership to liability under the Oil Pollution Act of 1990 and similar state laws. While liability under the Oil Pollution Act of 1990 is limited under certain circumstances, the maximum liability under those limits would still likely have a significant adverse effect on the Partnership. The Partnership's operations generally will be covered by the insurance carried by the General Partner or UNIT, if any. However, there can be no assurance that such insurance coverage will always be in force or that, if in force, it will adequately cover any losses or liability the Partnership may incur. Violation of environmental legislation and regulations may result in the imposition of fines or civil or criminal penalties and, in certain circumstances, the entry of an order for the removal, remediation and abatement of the conditions, or suspension of the activities, giving rise to the violation. The General Partner believes that the Partnership will comply with all orders and regulations applicable to its operations. However, in view of the many uncertain- ties with respect to the current controls, including their duration and possible modification, the General Partner cannot predict the overall effect of such controls on such operations. Similarly, the General Partner cannot predict what future environmental laws may be enacted or regulations may be promulgated and what, if any, impact they would have on operations or Partnership Revenue. SUMMARY OF THE LIMITED PARTNERSHIP AGREEMENT The business and affairs of the Partnership and the respective rights and obligations of the Partners will be governed by the Agree- ment. The following is a summary of certain pertinent provisions of the Agreement which have not been as fully discussed elsewhere in this Memorandum but does not purport to be a complete description of all relevant terms and provisions of the Agreement and is qualified in its entirety by express reference to the Agreement. Each prospective subscriber should carefully review the entire Agreement. Partnership Distributions The General Partner will make quarterly determinations of the Partnership's cash position. If it determines that excess cash is available for distribution, it will be distributed to the Partners in the same proportions that Partnership Revenue has been allocated to them after giving effect to previous distributions and to portions of such revenues theretofore used or expected to be thereafter used to pay costs incurred in conducting Partnership operations or to repay Part- nership borrowings. It is expected that no cash distributions will be made earlier than the first quarter of 1997. Distributions of cash determined by the General Partner to be available therefor will be made 92 to the Limited Partners quarterly and to the General Partner at any time. All Partnership funds distributed to the Limited Partners shall be distributed to the persons who were record holders of Units on the day on which the distribution is made. Thus, regardless of when an assignment of Units is made, any distribution with respect to the Units which are assigned will be made entirely to the assignee without regard to the period of time prior to the date of such assignment that the assignee holds the Units. The Partnership will terminate automatically on December 31, 2026 unless prior thereto the General Partner or Limited Partners holding a majority of the outstanding Units elect to terminate the Partnership as of an earlier date. Upon termination of the Partnership, the debts, liabilities and obligations of the Partnership will be paid and the Partnership's oil and gas properties and any tangible equipment, materials or other personal property may be sold for cash. The cash received will be used to make certain adjusting payments to the Partners (see "SUMMARY OF THE LIMITED PARTNERSHIP AGREEMENT - Termination"). Any remaining cash and properties will then be distributed to the Partners in proportion to and to the extent of any remaining balances in the Partners' capital accounts and then in undivided percentage interests to the Partners in the same proportions that Partnership Revenues are being shared at the time of such termination (see "SUMMARY OF THE LIMITED PARTNERSHIP AGREEMENT - Termination"). Deposit and Use of Funds Until required in the conduct of the Partnership's business, Partnership funds, including, but not limited to, the Capital Contribu- tions, Partnership Revenue and proceeds of borrowings by the Partner- ship, will be deposited, with or without interest, in one or more bank accounts of the Partnership in a bank or banks to be selected by the General Partner or invested in short-term United States government securities, money market funds, bank certificates of deposit or commer- cial paper rated as "A1" or "P1" as the General Partner, in its sole discretion, deems advisable. Any interest or other income generated by such deposits or investments will be for the Partnership's account. Except for Capital Contributions, Partnership funds from any of the various sources mentioned above may be commingled with funds of the General Partner and may be used, expended and distributed as authorized by the terms and provisions of the Agreement. The General Partner will be entitled to prompt reimbursement of expenses it incurs on behalf of the Partnership. Power and Authority In managing the business and affairs of the Partnership, the General Partner is authorized to take such action as it considers appropriate and in the best interests of the Partnership (see Section 93 10.1 of the Agreement). The General Partner is authorized to engage legal counsel and otherwise to act with respect to Service audits, assessments and administrative and judicial proceedings as it deems in the best interests of the Partnership and pursuant to the provisions of the Code. The General Partner is granted a broad power of attorney authoriz- ing it to execute certain documents required in connection with the organization, qualification, continuance, modification and termination of the Partnership on behalf of the Limited Partners (see Sections 1.5 and 1.6 of the Agreement). Certain actions, such as an assignment for the benefit of its creditors or a sale of substantially all of the Partnership Properties, except in connection with the termination, roll-up or consolidation of the Partnership, cannot be taken by the General Partner without the consent of a majority in interest of the Limited Partners and the receipt of an opinion of counsel as described under "Assignments by the General Partner" below (see Sections 10.15 and 12.1 of the Agreement). The Agreement provides that the General Partner will either conduct the Partnership's drilling and production operations and operate each Partnership Well or arrange for a third party operator to conduct such operations. The General Partner will, on behalf of the Partnership, enter into an appropriate operating agreement with the other owners of properties to be developed by the Partnership authoriz- ing either the General Partner or a third party operator to conduct such operations. The Partnership Agreement further provides that the Partnership will take such action in connection with operations pursu- ant to such operating agreements as the General Partner, in its sole discretion, deems appropriate and in the best interests of the Partner- ship, and the decision of the General Partner with respect thereto will be binding upon the Partnership. Rollup or Consolidation of the Partnership Two years or more after the Partnership has completed substan- tially all of its property acquisition, drilling and development operations, the General Partner may, without the vote, consent or approval of the Limited Partners, cause all or substantially all of the oil and gas properties and other assets of the Partnership to be sold, assigned or transferred to, or the Partnership merged or consolidated with, another partnership or a corporation, trust or other entity for the purpose of combining the assets of two or more of the oil and gas partnerships formed for investment or participation by employees, directors and/or consultants of UNIT or any of its subsidiaries; provided, however, that the valuation of the oil and gas properties and other assets of all such participating partnerships for purposes of such transfer or combination shall be made on a consistent basis and in a manner which the General Partner and UNIT believe is fair and equita- ble to the Limited Partners. As a consequence of any such transfer or 94 combination, the Partnership will be dissolved and terminated and the Limited Partners shall receive partnership interests, stock or other equity interests in the transferee or resulting entity. See "RISK FACTORS - Investment Risks - Roll-Up or Consolidation of the Partnership." Limited Liability Under the Act, a limited partner is not generally liable for partnership obligations unless he takes part in the control of the business. The Agreement provides that the Limited Partners cannot bind or commit the Partnership or take part in the control of its business or management of its affairs, and that the Limited Partners will not be personally liable for any debts or losses of the Partnership. However, the amounts contributed to the Partnership by the Limited Partners and the Limited Partners' interests in Partnership assets, including amounts of undistributed Partnership Revenue allocable to the Limited Partners, will be subject to the claims of creditors of the Partner- ship. A Limited Partner (or his or her estate) will be obligated to contribute cash to the Partnership, even if the Limited Partner is unable to do so because of death, disability or any other reason, for: (1) any unpaid contribution which the Limited Partner agreed to make to the Partnership; and (2) any return, in whole or in part, of the Limited Part- ner's contribution to the extent necessary to discharge Partner- ship liabilities to all creditors who extended credit or whose claims arose before such return. Liability of a Limited Partner is limited by the Act to one year for any return of his or her contribution not in violation of the Partnership Agreement or such Act and six years on any return of his or her contribution in violation of the Partnership Agreement or such Act. A partner is deemed to have received a return of his or her contribution to the extent that a distribution to him or her reduces his or her share of the fair value of the net assets of the Partnership below the value of his or her contribution which has not been distributed to him or her. How this provision applies to a partnership whose primary assets are producing oil and gas properties or other depleting assets is not entirely clear. The Agreement provides that for the purposes of this provision, the value of a Limited Partner's contribution which has not been distributed to him or her at any point in time will be the Limited Partner's Percentage of the stated capital of the Partnership allocated to the Limited Partners as reflected in its financial statements as of such point in time. Maintenance of limited liability of the Limited Partners in other jurisdictions in which the Partnership may operate may require compli- ance with certain legal requirements of those jurisdictions. In such 95 jurisdictions, the General Partner shall cause the Partnership to operate in such a manner as it, on the advice of responsible counsel, deems appropriate to avoid unlimited liability for the Limited Partners (see Sections 1.5, 12.1 and 12.2 of the Agreement). After the termina- tion of the Partnership, any distribution of Partnership Properties to the Limited Partners would result in their having unlimited liability with respect to such properties. Although the Partnership will, with certain limited exceptions, serve as a co-general partner of any drilling or income programs formed by UNIT or UPC in 1996 (see "PROPOSED ACTIVITIES"), the general liability of the Partnership will not flow through to the Limited Partners. Records, Reports and Returns The General Partner will maintain adequate books, records, ac- counts and files for the Partnership and keep the Limited Partners informed by means of written interim reports rendered within 60 days after each quarter of the Partnership's fiscal year. The reports will set forth the source and disposition of Partnership Revenues during the quarter. Engineering reports on the Partnership Properties will be prepared by the General Partner for each year for which the General Partner prepares such a report in connection with its own activities. Such report will include an estimate of the total oil and gas proven re- serves of the Partnership, the dollar value thereof and the value of the Limited Partners' interest in such reserve value. The report shall also contain an estimate of the life of the Partnership Properties and the present worth of the reserves. Each Limited Partner will receive a summary statement of such report which will reflect the value of the Limited Partners' interest in such reserves. The General Partner will timely file the Partnership's income tax returns and by March 15 of each year or as soon thereafter as practica- ble, furnish each person who was a Limited Partner during the prior year all available information necessary for inclusion in his or her federal income tax return. (See Section 8.1 of the Agreement). Transferability of Interests Restrictions. A Limited Partner may not transfer or assign Units except for certain transfers: to the General Partner; to or for the benefit of himself or herself, his or her spouse, or other members of the transferor Limited Partner's immediate family sharing the same residence; 96 to any corporation or other entity whose beneficial owners are all Limited Partners or permitted assignees; by the General Partner to any person who at the time of such transfer is an employee of the General Partner, UNIT or its subsidiaries; and by reason of death or operation of law. Further, no sale or exchange of any Units may be made if the sale of such interest would, in the opinion of counsel for the Partnership, result in a termination of the Partnership for purposes of Section 708 of the Code, violate any applicable securities laws or cause the Partnership to be treated as an association taxable as a corporation for federal income tax purposes; provided, however, that this condition may be waived by the General Partner, in its sole discretion. More- over, in no event shall all or any portion of a Limited Partner's Units be assigned to a minor or an incompetent, except by will, intestate succession, in trust, or pursuant to the Uniform Gifts to Minors Act. As the offer and sale of the Units are not being registered under the Securities Act of 1933, as amended, they may be sold, transferred, assigned or otherwise disposed of by a Limited Partner only if, in the opinion of counsel for the Partnership, such transfer or assignment would not violate, or cause the offering of the Units to be violative of, such act or applicable state securities laws, including investor suitability standards thereunder. Because of the structure and antici- pated operation of the Partnership, Rule 144 under the Securities Act of 1933 will not be available to Limited Partners in connection with any such sales. Assignees. An assignee of a Limited Partner does not automatical- ly become a Substituted Limited Partner, but has the right to receive the same share of Partnership Revenue and distributions thereof to which the assignor Limited Partner would have been entitled. A Limited Partner who assigns his or her Partnership interest ceases to be a Limited Partner, except that until a Substituted Limited Partner is admitted in his or her place, the assignor retains the statutory rights of an assignor of a Limited Partner's interest under the partnership laws of the State of Oklahoma. The assignee of a Partnership interest who does not become a Substituted Limited Partner and desires to make a further assignment of such interest is subject to all of the restrictions on transferability of Partnership interests described herein and in the Partnership Agreement. In the event of the death, incapacity or bankruptcy of a Limited Partner, his or her legal representatives will have all the rights of a Limited Partner only for the purpose of settling or liquidating his or her estate and such power as the decedent, incompetent or bankrupt Limited Partner possessed to assign all or any part of his or her 97 interest in the Partnership and to join with such assignee in satisfying conditions precedent to such assignee's becoming a Substituted Limited Partner. A purported sale, assignment or transfer of a Limited Partner's interest will be recognized by the Partnership when it has received written notice of such sale or assignment in form satisfactory to the General Partner, signed by both parties, containing the purchaser's or assignee's acceptance of the terms of the Agreement and a representa- tion by the parties that the sale or assignment was lawful. Such sale or assignment will be recognized as of the date of such notice, except that if such date is more than 30 days prior to the time of filing, such sale or assignment will be recognized as of the time the notice was filed with the Partnership. Distributions of Partnership Revenue will be made only to those persons who were record owners of Units on the day any such distribution is made (see "RISK FACTORS - Tax Related Risks - Disproportionate Tax Liability upon Transfer"). Substituted Limited Partners. No Limited Partner has the right to substitute an assignee as a Limited Partner in his or her place. The General Partner, however, has the right in its sole discretion to permit such assignee to become a Substituted Limited Partner and any such permission by the General Partner is binding and conclusive without the consent or approval of any Limited Partner. Any Substituted Limited Partner must, as a condition to receiving any interest of the Limited Partner, agree in writing to be bound by the terms and conditions of the Partnership Agreement, pay or agree to pay the costs and expenses incurred by the Partnership in taking the actions necessary in connection with his or her substitution as a Limited Partner and satisfy the other conditions specified in Article XIII of the Partnership Agreement. Assignments by the General Partner. The General Partner may not sell, assign, transfer or otherwise dispose of its interest in the Partnership except with the prior consent of a majority in interest of the Limited Partners, provided that no such consent is required if the sale, assignment or transfer is pursuant to a bona fide merger, other corporate reorganization or complete liquidation, sale of substantially all of the General Partner's assets (provided the purchasers agree to assume the duties and obligations of the General Partner) or any sale or transfer to UNIT or any affiliate of UNIT. Any consent of the Limited Partners will not be effective without an opinion of counsel to the Partnership or an order or judgment of a court of competent juris- diction to the effect that the exercise of such right will not be deemed to evidence that the Limited Partners are taking part in the management of the Partnership's business and affairs and will not result in a loss of any Limited Partner's limited liability or cause the Partnership to be classified as an association taxable as a corpo- ration for federal income tax purposes (see Section 12.1 of the Agree- ment). Any transferee of the General Partner's interest may become a 98 substitute General Partner by assuming and agreeing to perform all of the duties and obligations of a General Partner under the Agreement. In such event, the transferring General Partner, upon making a proper accounting to the substitute General Partner, will be relieved of any further duties or obligations with respect to any future Partnership operations. Amendments The Agreement may be amended upon the approval by a majority in interest of the Limited Partners, except that amendments changing the Partners' participation in costs and revenues, increasing or decreasing the General Partner's compensation or otherwise materially and adversely affecting the interests of either the Limited Partners or the General Partner must be approved by all Limited Partners if their interests would be adversely affected thereby or by the General Partner if its interest would be adversely affected thereby. The Limited Partners have no right to propose amendments to the Agreement. Voting Rights Under the Agreement, the Limited Partners will have very limited rights to vote on any Partnership matters. Except for certain special amendments referred to under "Amendments" above, matters submitted to the Limited Partners for determination will be determined by the affirmative vote of Limited Partners holding a majority of the outstanding Units. Units held by the General Partner may be voted by it. Generally, Limited Partners owning more than 50% of the outstanding Units of the Partnership may, without the necessity of concurrence by the General Partner, vote to: Approve the execution or delivery of any assignment for the benefit of the Partnership's creditors; Approve the sale or disposal of all or substantially all of the Partnership's assets, except pursuant to (i) a rollup or consolidation of the Partnership (see "Rollup or Consolidation of the Partnership" above) or (ii) termination (see "Termination" below); Approve the General Partner's sale, assignment, transfer or disposal of its interest in the Partnership, unless such sale, assignment or transfer is pursuant to (i) a merger or other corporate reorganization, or liquidation or sale of substantially all of its assets, and the purchaser agrees to assume the duties and obligations of the General Partner, or (ii) any sale to UNIT or its affiliates; 99 Terminate and dissolve the Partnership; or Approve any amendments to the Agreement which may be proposed by the General Partner; provided, however, any approvals, consents or elections of the Limited Partners will not become effective unless prior to the exercise thereof the General Partner is furnished with an opinion of counsel for the Partnership, or an order or judgment of any court of competent jurisdiction, that the exercise of such rights: Will not be deemed to evidence that the Limited Partners are taking part in the control or management of the Partnership's business affairs; Will not result in the loss of any Limited Partner's limited liability under the Act; and Will not result in the Partnership being classified as an association taxable as a corporation for federal income tax purposes. Exculpation and Indemnification of the General Partner Pursuant to the Agreement, neither the General Partner or any affiliate thereof will have any liability to the Partnership or to any Partners therein for any loss suffered by the Partnership or such Partner that arises out of any action or inaction of the General Partner or any affiliate thereof if the General Partner or affiliate thereof in good faith determined that such course of conduct was in the best interest of the Partnership, the General Partner or affiliate was acting on behalf of or performing services for the Partnership, such liability or loss was not the result of gross negligence or wilful misconduct by the General Partner or affiliates thereof, and payments arising from such indemnification or agreement to hold harmless are receivable only out of the tangible net assets of the Partnership. Termination The Partnership will terminate automatically on December 31, 2026. In addition, upon the dissolution (other than pursuant to a merger, or other corporate reorganization or sale), bankruptcy, legal disability or withdrawal of the General Partner, the Partnership shall immediately be dissolved and terminated. The Act provides, however, that the Limited Partners may elect to reform and reconstitute themselves as a limited partnership within 90 days after such dissolution under the provisions in the Partnership Agreement or under any other terms. The Partnership may terminate sooner if a majority in interest of the Limited Partners or the General Partner elects to dissolve and termi- nate the Partnership as of an earlier date. Such right to accelerate 100 termination of the Partnership by the Limited Partners will not be available unless prior to any exercise thereof the Limited Partners proposing such termination obtain and furnish to the General Partner an opinion, order or judgment in the form referred to above under "Trans- ferability of Interests - Assignments by the General Partner." The withdrawal, expulsion, dissolution, death, legal disability, bankruptcy or insolvency of any Limited Partner will not effect a dissolution or termination of the Partnership. In the event of an election to termi- nate the Partnership prior to expiration of its stated terms, 90 days' prior written notice must be given to all Partners specifying the termination date which must be the last day of a calendar month follow- ing such 90 day period unless an earlier date is approved by Limited Partners holding a majority of the outstanding Units. When the Partnership is terminated, there will be an accounting with respect to its assets, liabilities and accounts. The Partner- ship's physical property and its oil and gas properties may be sold for cash. Except in the case of an election by the General Partner to terminate the Partnership before the tenth anniversary of the Effective Date, Partnership Properties may be sold to the General Partner or any of its affiliates for their fair market value as determined in good faith by the General Partner. Upon termination, all of the Partnership's debts, liabilities and obligations, including expenses incurred in connection with the termi- nation and the sale or distribution of Partnership assets, will be paid. All Partnership borrowings will be paid in full. When the specified payments have all been made, the remaining cash and proper- ties of the Partnership, if any, will be distributed to the Partners as set forth under "Partnership Distributions" above (see Section 16.4 of the Agreement). Such distribution will result in the Limited Partners' having unlimited liability with respect to any Partnership Properties distributed to them. Insurance The General Partner will use its best efforts to obtain such insurance as it deems prudent to serve as protection against liability for loss and damage. Such insurance may include, but is not limited to, public liability, automotive liability, workers' compensation and employer's liability insurance and blowout and control of well insurance. COUNSEL Conner & Winters, A Professional Corporation, 2400 First National Tower, Tulsa, Oklahoma, has acted as special counsel ("Counsel") to the General Partner in connection with certain aspects of this offering. Counsel has assisted in the preparation of the Agreement and this Memorandum. In connection with the preparation of this Memorandum, 101 Counsel has relied entirely upon information submitted to it by the General Partner. Certain of this information has been verified by Counsel in the course of its representation, but no systematic effort has been made to verify all of the material information contained herein, and much of such information is not subject to independent verification. In addition, Counsel has made no independent investigation of the financial information concerning the General Partner. Further, while passing on certain legal matters, Counsel has not passed on the investment merits nor is it qualified to do so. Because substantial portions of the information contained in this Memorandum have not been independently verified, each investor must make whatever independent inquiries the investor or his or her advisors deem necessary or desirable to verify or confirm the statements made herein. GLOSSARY As used herein and in the Agreement, the following terms and phrases will have the meanings indicated. (a) "Additional Assessments" are amounts required to be contributed by the Limited Partners to the Partnership upon a call therefor by the General Partner in the manner described under "ADDITIONAL FINANCING - Additional Assessments." (b) An "affiliate" of another person is (1) any person directly or indirectly owning, controlling or holding with power to vote 10% or more of the outstanding voting securities of such other person; (2) any person 10% or more of whose outstanding voting securities are directly or indirectly owned, controlled, or held with power to vote, by such other person; (3) any person directly or indirectly controlling, controlled by, or under common control with such other person; (4) any officer, director, trustee or partner of such other person; and (5) if such other person is an officer, director, trustee or partner, any company for which such person acts in any such capacity. (c) The "Aggregate Subscription" is the sum of the Capital Subscriptions of all Limited Partners. (d) "Agreement" and "Partnership Agreement" refers to the Agreement of Limited Partnership attached as Exhibit A to this Private Offering Memorandum. (e) The "Capital Contribution" of a Limited Partner is the amount of the Capital Subscription actually paid in by him or her, or by any predecessor in interest, to the capital of the Partnership including any payments made by deductions from salary. The "Capital Contribution" of the General Partner includes the 102 amounts contributed to the Partnership or paid by the General Partner or by any Limited Partner whose Units are purchased by the General Partner pursuant to Section 4.2 of the Agreement because of a default by such Limited Partner in the payment of an Installment or pursuant to Article XV of the Agreement, including payments made by deductions from the salary of such Limited Partner. (f) The "Capital Subscription" of a Limited Partner or his or her assignee (including the General Partner where Units are transferred pursuant to Section 4.2 of the Agreement) is the amount specified in the Subscription Agreement executed by such Limited Partner for payment by him or her to the capital of the Partnership in accordance with the provisions of the Agreement, reduced by the amounts thereof from which the Limited Partners have been released by the General Partner of their obligation to pay. (g) A "Development Well" means a well intended to be drilled within the proved areas of a known oil or gas reservoir to the depth of a stratigraphic horizon known to be productive. (h) "Director" refers to the duly elected directors of UNIT as well as all honorary directors and consultants to the Board of Directors of UNIT. (i) "Drilling Costs" are those costs incurred in drilling, testing, completing and equipping a well to the point that it proves to be dry and is abandoned or is ready to commence commer- cial production of oil or gas therefrom. (j) "Effective Date" refers to the date on which the certif- icate evidencing formation of the Partnership is filed with the Secretary of State of the State of Oklahoma as required by the Act (54 Okla. Stat. 1991, Section 309). (k) An "Exploratory Well" means a well drilled to find production in an unproven area, to find a new reservoir in a field previously found to be productive or to extend greatly the limits of a known reservoir. (l) A "farm-out" is an agreement whereby the owner of an oil and gas property agrees to assign such property, usually retaining some interest therein such as an overriding royalty, a production payment, a net profits interest or a carried working interest, subject in most cases, however, to the drilling of one or more wells or other performance by the prospective assignee as a condition of the assignment. 103 (m) The "General Partner's Minimum Capital Contribution" is that amount equal to the total of (i) all Partnership costs and expenses charged to its account from the time of the formation of the Partnership through December 31, 1996, plus (ii) the General Partner's estimate of the total Leasehold Acquisition Costs and Drilling Costs expected to be incurred by the Partnership subse- quent to December 31, 1996, if any, minus (iii) the amount, if any, of the unexpended Aggregate Subscription at December 31, 1996. (n) The "General Partner's Percentage" is that percentage determined by dividing the amount of the General Partner's Minimum Capital Contribution by the total of (i) the General Partner's Minimum Capital Contribution plus (ii) the Aggregate Subscription. (o) "Installments" refer to the periodic payments of the Capital Subscription, which are payable either (i) in four equal installments due on March 15, 1996, June 15, 1996, September 15, 1996 and December 15, 1996, respectively, or (ii) if an employee so elects, through equal deductions from 1996 salary commencing immediately after formation of the Partnership. (p) "Leasehold Acquisition Costs" with respect to proper- ties, if any, acquired by the Partnership from non-affiliated parties mean the actual costs to the Partnership of and in acquiring the properties, and, with respect to properties acquired by the Partnership from the General Partner, UNIT or its affiliates are, without duplication, the sum of: (1) the prices paid by the General Partner, UNIT or its affiliates in acquiring an oil and gas property, including purchase option fees and charges, bonuses and penalties, if any; (2) title insurance or examination costs, broker's commissions, filing fees, recording costs, transfer taxes, if any, and like charges incurred in connection with the acquisition of such property; (3) a pro rata portion of the actual, necessary and reasonable expenses of the General Partner, UNIT or its affiliates for seismic and geophysical services; (4) rentals, shut-in royalties and ad valorem taxes paid by the General Partner, UNIT or its affiliates with respect to such property to the date of its transfer to the Partnership; 104 (5) interest and points actually incurred on funds used by the General Partner, UNIT or its affiliates to acquire or maintain such property; and (6) such portion of the General Partner's, UNIT or its affiliates' reasonable, necessary and actual expenses for geological, engineering, drafting, accounting, legal and other like services allocated to the acquisition, operations and maintenance of the property in accordance with generally accepted industry practices, except for expenses in connection with the past drilling of wells which are not producers of sufficient quantities of oil or gas to make commercially reasonable their continued operations, and provided that the costs and expenses enumerated in (4), (5) and (6) above with respect to any particular property shall have been incurred not more than thirty-six (36) months prior to the acquisition of such property by the Partnership. In the event a fractional undivided interest in a property is sold or transferred by the General Partner, UNIT or any affiliate to an unaffiliated third party for an amount in excess of that portion of the original cost of the property attributable to the transferred interest, the amount of such excess shall not reduce or be offset against the amount of the Leasehold Acquisition Costs attributable to any interest in the same property which is transferred to the Partnership. (q) "Limited Partners" are those persons who acquire Units in the Partnership upon its formation and those transferees of Units who are accepted as Substituted Limited Partners. The General Partner may also be a Limited Partner if it subscribes for Units or if it subsequently acquires Units by (i) the exercise by a Limited Partner of his or her right of presentment; (ii) a purchase by the General Partner of the Units of a Limited Partner who defaults in the payment of an Installment; or (iii) any other assignment or transfer. (r) The "Limited Partners' Percentage" is that percentage determined by dividing the amount of the Aggregate Subscription by the total of (i) the General Partner's Minimum Capital Contribu- tion plus (ii) the Aggregate Subscription. (s) "Normal Retirement" means retirement under the terms of a pension or similar retirement plan adopted by the General Partner, UNIT or any subsidiary with whom a Limited Partner is employed as in effect at the time of retirement. (t) "Oil and gas properties" are oil and gas leasehold working interests, fee interests, mineral interests, royalty 105 interests, overriding royalty interests, production payments, options or rights to lease or acquire such interests, geophysical exploration permits and any tangible or intangible properties or other rights incident thereto, whether real, personal or mixed. (u) "Operating Expenses" are expenditures made and costs incurred in producing and marketing oil or gas from completed wells, including, in addition to labor, fuel, repairs, hauling, material, supplies, utility charges and other costs incident to or necessary for the maintenance or operation of such wells or the marketing of production therefrom, ad valorem, severance and other such taxes (other than windfall profit taxes), insurance and casualty loss expense and compensation to well operators or others for services rendered in conducting such operations. (v) The General Partner and the Limited Partners are some- times collectively referred to as the "Partners." (w) "Partnership Agreement" and "Agreement" refer to the Agreement of Limited Partnership attached as Exhibit A to this Private Offering Memorandum. (x) The "Partnership Properties" are oil and gas properties or interests therein acquired by the Partnership or properties acquired by any partnership or joint venture in which the Partner- ship is a partner or joint venturer, whether acquired by purchase, option exercise or otherwise. (y) "Partnership Revenue" refers to the Partnership's gross revenues from all sources, including interest income, proceeds from sales of production, the Partnership's share of revenues from partnerships or joint ventures of which it is a member, sales or other dispositions of Partnership Properties or other Partnership assets, provided that contributions to Partnership capital by the Partners and the proceeds of any Partnership borrowings are specifically excluded and dry-hole and bottom-hole contributions shall be treated as reductions of the costs giving rise to the right to receive such contributions. (z) "Partnership Wells" are any and all of the oil and gas wells in which the Partnership has an interest, either directly or indirectly through any other partnership or joint venture. (aa) "Productive properties" are oil and gas properties that have been tested by drilling and determined to be capable of producing oil or gas in commercial quantities. (bb) A "spacing unit" is a drilling and spacing, production or similar unit established by any regulatory body with jurisdic- tion, or in the absence of such a regulatory body or action 106 thereby, the acreage attributable to wells drilled under the normal spacing pattern in such area or if no such spacing unit is designated, in keeping with generally accepted industry practices, or the largest of such units in the event of multiple objective formations. (cc) "Special Production and Marketing Costs" are costs and expenses that are not normally and customarily incurred in connec- tion with drilling, producing and marketing operations, including without limitation, costs incurred in constructing compressor plants, gasoline plants, gas gathering systems, natural gas processing plants, pipeline systems and salt water disposal systems and costs incurred in installing pressure maintenance and secondary or tertiary production projects. (dd) "Subscription Agreement" refers to the form of Limited Partner Subscription Agreement and Suitability Statement attached as Attachment I to the Partnership Agreement. (ee) A "Substituted Limited Partner" is a transferee, donee, heir, legatee or other recipient of all or any portion of a Limited Partner's interest in the Partnership with respect to whom all conditions and consents required to become a Substituted Limited Partner under Article XIII of the Partnership Agreement have been satisfied and given. (ff) A "Unit" is a preformation unit of limited partnership interest of a Limited Partner in the Partnership representing a Capital Subscription of One Thousand Dollars ($1,000). FINANCIAL STATEMENTS On January 1, 1988 all of the oil and natural gas properties previously owned by Unit Drilling and Exploration Company ("UDEC") and UNIT were transferred into Sunshine Development Company through a contribution of capital. Included in the transfer were all interests previously owned by UDEC in numerous General and Limited Partnerships sponsored by UDEC. Effective February 1, 1988, Sunshine Development Company, a wholly owned subsidiary of UDEC, pursuant to an "Amended and Restated Certificate of Incorporation" was renamed Unit Petroleum Company and became a wholly owned subsidiary of UNIT. Unit Petroleum Company functions as the operating entity for all oil and natural gas exploration and production activities including operating any partnerships for UNIT. The consolidated balance sheet of Unit Petroleum Company at October 31, 1995 is unaudited and includes all adjustments which UNIT 107 considers necessary for a fair presentation of the financial position of Unit Petroleum Company at October 31, 1995. 108 Unit Petroleum Company and Subsidiary Consolidated Balance Sheet (In Thousands) October 31, 1995 ----------- (Unaudited) Assets ------ Current Assets: Cash and cash equivalents $ 133 Accounts receivable 5,463 Materials and supplies, at lower of cost or market 1,793 Other 121 ---------- 7,510 ---------- Property and Equipment: Oil and natural gas properties, on the full cost method 171,079 Other 323 ---------- 171,402 Less accumulated depreciation, depletion, amortization and impairment (90,533) ---------- Net property and equipment 80,869 ---------- Other Assets 1 ---------- Total Assets $ 88,380 ========== Liabilities and Shareholder Equity ---------------------------------- Current Liabilities: Accounts payable $ 3,267 Amount Payable to Parent 8,317 Contract advances 99 Accrued liabilities 1,072 ---------- Total current liabilities 12,755 ---------- Long-Term Portion of Natural Gas Purchaser Prepayment 2,309 ---------- Shareholder Equity: Common stock, $1.00 per value, 500 shares authorized and outstanding 1 Capital in excess of par value 31,486 Retained earnings 41,829 ---------- Total Shareholder Equity 73,316 ---------- Total Liabilities and Shareholder Equity $ 88,380 ========== 109 EXHIBIT A EXHIBIT A UNIT 1996 EMPLOYEE OIL AND GAS LIMITED PARTNERSHIP AGREEMENT OF LIMITED PARTNERSHIP A-1 INDEX Page ---- ARTICLE I Formation of Limited Partnership........ A-4 ARTICLE II Definitions............................. A-6 ARTICLE III Purposes and Powers of the Partnership.. A-10 ARTICLE IV Partner Capital Contributions........... A-13 ARTICLE V Deposit and Use of Capital Contributions and Other Partnership Funds.......... A-15 ARTICLE VI Sharing of Costs, Capital Accounts and Allocation of Charges and Income..... A-17 ARTICLE VII Fiscal Year, Accountings and Reports.............................. A-23 ARTICLE VIII Tax Returns and Elections............... A-23 ARTICLE IX Distributions........................... A-24 ARTICLE X Rights, Duties and Obligations of the General Partner...................... A-24 ARTICLE XI Compensation and Reimbursements......... A-31 ARTICLE XII Rights and Obligations of Limited Partners............................. A-32 ARTICLE XIII Transferability of Limited Partner's Interest............................. A-33 ARTICLE XIV Assignments by the General Partner...... A-36 ARTICLE XV Limited Partners' Right of Presentment.. A-37 ARTICLE XVI Termination and Dissolution of Partnership.......................... A-39 ARTICLE XVII Notices................................ A-41 ARTICLE XVIII Amendments............................. A-42 ARTICLE XIX General Provisions..................... A-42 A-2 ATTACHMENT I Limited Partner Subscription Agreement and Suitability Statement.... I-1 A-3 UNIT 1996 EMPLOYEE OIL AND GAS LIMITED PARTNERSHIP AGREEMENT OF LIMITED PARTNERSHIP THIS AGREEMENT OF LIMITED PARTNERSHIP (this "Agreement") is made and entered into by and among Unit Petroleum Company, an Oklahoma corporation, hereinafter referred to as the "General Partner" or "UPC" (which term shall include any successors or assigns of UPC), and each of those persons who have executed a counterpart of the Limited Partner Subscription Agreement and Suitability Statement attached as Attachment I to this Agreement that have been accepted by the General Partner, said persons being hereinafter collectively referred to as the "Limited Partners". WITNESSETH THAT: ARTICLE I Formation of Limited Partnership 1.1 The parties to this Agreement hereby form a Limited Partnership (the "Partnership") pursuant to the Revised Uniform Limited Partnership Act of the State of Oklahoma (the "Act"). The terms and provisions hereof will be construed and interpreted in accordance with the terms and provisions of the Act and if any of the terms and provisions of this Agreement should be deemed inconsistent with those terms and provisions of the Act which under the Act may not be altered by agreement of the parties, the Act will be controlling, but otherwise this Agreement will be controlling. 1.2 The Partnership will be conducted under the name of "Unit 1996 Employee Oil and Gas Limited Partnership" in Oklahoma, and under such name or variations of such name as the General Partner deems appropriate to comply with the laws of the other jurisdictions in which the Partnership does business. 1.3 The principal office of the Partnership will be 1000 Kensington Tower I, 7130 South Lewis Avenue, P.O. Box 702500, Tulsa, Oklahoma 74136, or at such other location as may from time to time be designated by the General Partner, and the Partnership's agent for service of process shall be Unit Corporation ("UNIT", which term shall include all or any of its subsidiaries or affiliates unless the context otherwise requires) at the same address. 1.4 The Partnership will be effective on the date on which the certificate evidencing formation of the Partnership is filed with the Secretary of State of the State of Oklahoma. Its business and operations A-4 will not be commenced prior to such date. The Partnership will continue in existence until December 31, 2026, unless sooner terminated pursuant to any provisions of this Agreement. 1.5 The parties hereto will execute such certificates and other documents, and the General Partner will file, record and publish such certificates and documents, as may be necessary or appropriate to comply with the requirements for the formation and operation of a limited partnership under the Act and as the General Partner, upon advice of counsel, deems necessary or appropriate to comply with requirements of applicable laws governing the formation and operations of a limited partnership (or a partnership in which special partners have a limited liability) in all other jurisdictions where the Partnership desires to conduct business, including, but not limited to, filings under the Fictitious Name Act, Assumed Name Act or similar law in effect in the counties, parishes and other governmental jurisdictions in which the Partnership conducts business. The General Partner shall not be required to deliver or mail a copy of the certificate of limited partnership or any amendments thereto filed pursuant to the Act to the Limited Partners. 1.6 Each Limited Partner by his or her execution of a counterpart of the Subscription Agreement irrevocably constitutes and appoints the General Partner such Limited Partner's true and lawful attorney and agent, with full power and authority in such Limited Partner's name, place and stead, to execute, sign, acknowledge, swear to, deliver, file and record in the appropriate public offices (i) all certificates or other instruments (including, without limitation, counterparts of this Agreement) and amendments thereto which the General Partner deems appropriate to qualify or continue the Partnership as a limited part- nership (or a partnership in which special partners have limited liability) in the jurisdictions in which the Partnership conducts business; (ii) all instruments and amendments thereto which the General Partner deems appropriate to reflect any change or modification of this Agreement, the admission of additional or substitute Partners in accordance with the terms of this Agreement, the release or waiver of the Limited Partners from the obligation to pay in one or more of the installments of their Capital Subscriptions pursuant to Section 4.2 below and the termination of the Partnership and the cancellation of the certificate of limited partnership; (iii) all conveyances and other instruments which the General Partner deems appropriate to evidence and reflect any sales or transfers, including sales or transfers upon or in connection with the dissolution and termination of the Partnership; and (iv) all consents to transfers of Partnership interests, to the admission of substitute or additional Partners or to the withdrawal or reduction of any Partner's invested capital, to the extent that such actions are authorized by the terms of this Agreement. The Power of Attorney granted herein is irrevocable and is a power coupled with an interest and will A-5 survive the death, disability, dissolution, bankruptcy, insolvency or incapacity of a Limited Partner. ARTICLE II Definitions 2.1 Whenever used in this Agreement the following terms will have the meanings described below: (a) The "Additional Assessments" of the Limited Partners are those amounts, if any, which they are required to pay into the capital of the Partnership pursuant to Section 5.3 of this Agreement. (b) An "affiliate" of another person is (1) any person directly or indirectly owning, controlling or holding with power to vote 10% or more of the outstanding voting securities of such other person; (2) any person 10% or more of whose outstanding voting securities are directly or indirectly owned, controlled, or held with power to vote, by such other person; (3) any person directly or indirectly controlling, controlled by, or under common control with such other person; (4) any officer, director, trustee or partner of such other person; and (5) if such other person is an officer, director, trustee or partner, any company for which such person acts in any such capacity. (c) The "Aggregate Subscription" is the sum of the Capital Subscriptions of all Limited Partners. (d) The "Capital Contribution" of a Limited Partner is the amount of the Capital Subscription actually paid in by him or her, or by any predecessor in interest, to the capital of the Partnership, including any payments made by deductions from salary. The "Capital Contribution" of the General Partner includes the amounts contributed to the Partnership or paid by the General Partner or by any Limited Partner whose Units are purchased by the General Partner including purchases pursuant to Section 4.2 of this Agreement because of a default by such Limited Partner in the payment of a subscription installment or pursuant to Article XV of this Agreement, including payments made by deductions from the salary of such Limited Partner. (e) The "Capital Subscription" of a Limited Partner or his or her assignee (including the General Partner where Units are trans- ferred pursuant to Section 4.2 of this Agreement) is the amount A-6 specified in the Subscription Agreement executed by such Limited Partner for payment by him or her to the capital of the Partnership in accordance with the provisions of this Agreement, reduced by the amount thereof from which the Limited Partner has been released by the General Partner of his or her obligation to pay pursuant to Section 4.2 hereof. (f) "Drilling Costs" are those costs incurred in drilling, testing, completing and equipping a Partnership Well to the point that it proves to be dry and is abandoned or is ready to commence commercial production of oil or gas therefrom. (g) "Effective Date" refers to the date on which the certif- icate evidencing formation of the Partnership is filed with the Secretary of State of the State of Oklahoma as required by the Act (54 Okla. Stat. 1991, Section 309). (h) A "farm-out" is an agreement whereby the owner of an oil and gas property agrees to assign such property, usually retaining some interest therein such as an overriding royalty, a production payment, a net profits interest or a carried working interest, subject in most cases, however, to the drilling of one or more wells or other performance by the prospective assignee as a condition of the assignment. (i) The "General Partner's Minimum Capital Contribution" is that amount equal to the total of (i) all Partnership costs and expenses charged to its account from the time of the formation of the Partnership through December 31, 1996, plus (ii) the General Partner's estimate of the total Leasehold Acquisition Costs and Drilling Costs expected to be incurred by the Partnership subsequent to December 31, 1996, minus (iii) the amount, if any, of the unexpended Aggregate Subscription at December 31, 1996. (j) The "General Partner's Percentage" is that percentage determined by dividing the amount of the General Partner's Minimum Capital Contribution by the total of (i) the General Partner's Minimum Capital Contribution plus (ii) the Aggregate Subscription. (k) "Leasehold Acquisition Costs" with respect to properties, if any, acquired by the Partnership from non-affiliated parties mean the actual costs to the Partnership of and in acquiring the properties, and, with respect to properties acquired by the Partnership from the General Partner, UNIT or its affiliates, are, without duplication, the sum of: (1) the prices paid by the General Partner, UNIT or its affiliates in acquiring an oil and gas property, including purchase option fees and charges, bonuses and A-7 penalties, if any; (2) title insurance or examination costs, broker's commissions, filing fees, recording costs, transfer taxes, if any, and like charges incurred in connection with the acquisition of such property; (3) a pro rata portion of the actual, necessary and reasonable expenses of the General Partner, UNIT or its affiliates for seismic and geophysical services; (4) rentals, shut-in royalties and ad valorem taxes paid by the General Partner, UNIT or its affiliates with respect to such property to the date of its transfer to the Partnership; (5) interest and points actually incurred on funds used by the General Partner, UNIT or its affiliates to acquire or maintain such property; and (6) such portion of the General Partner's, UNIT's or its affiliates' reasonable, necessary and actual expenses for geological, engineering, drafting, accounting, legal and other like services allocated to the acquisition, operations and maintenance of the property in accordance with generally accepted industry practices, except for expenses in connection with the past drilling of wells which are not producers of sufficient quantities of oil or gas to make commercially reasonable their continued operations, and provided that the costs and expenses enumerated in (4), (5) and (6) above with respect to any particular property shall have been incurred not more than thirty-six (36) months prior to the acquisition of such property by the Partnership. In the event a fractional undivided interest in a property is sold or transferred by the General Partner, UNIT or any affiliate to an unaffiliated third party for an amount in excess of that portion of the original cost of the property attributable to the transferred interest, the amount of such excess shall not reduce or be offset against the amount of the Leasehold Acquisition Costs attributable to any interest in the same property which is transferred to the Partnership. (l) "Limited Partners" are those persons who acquire Units in the Partnership upon its formation and those transferees of Units who are accepted as Substituted Limited Partners. The General Partner may also be a Limited Partner if it subscribes for Units or if it subsequently acquires Units by (i) the exercise by a Limited Partner of his or her right of presentment; (ii) a purchase by the General Partner of the Units of a Limited Partner who defaults in the payment of any subscription installment; or (iii) any other assignment or transfer. (m) The "Limited Partners' Percentage" is that percentage determined by dividing the amount of the Aggregate Subscription by the total of (i) the General Partner's Minimum Capital Contribution plus (ii) the Aggregate Subscription. A-8 (n) "Normal Retirement" means retirement under the provision of a pension or similar retirement plan adopted by the General Partner, UNIT or any subsidiary with whom a Limited Partner is employed as in effect at the time of the employee's retirement. (o) "Oil and gas properties" are oil and gas leasehold working interests, fee interests, mineral interests, royalty interests, overriding royalty interests, production payments, options or rights to lease or acquire such interests, geophysical exploration permits and any tangible or intangible properties or other rights incident thereto, whether real, personal or mixed. (p) "Operating Expenses" are expenditures made and costs incurred in producing and marketing oil or gas from completed wells, including, in addition to labor, fuel, repairs, hauling, material, supplies, utility charges and other costs incident to or necessary for the maintenance or operation of such wells or the marketing of production therefrom, ad valorem, severance and other such taxes (other than windfall profit taxes), insurance and casualty loss expense and compensation to well operators or others for services rendered in conducting such operations. (q) The General Partner and the Limited Partners are sometimes collectively referred to as the "Partners". A-7 (r) The "Partnership Properties" are oil and gas properties or interests therein acquired by the Partnership or properties acquired by any partnership or joint venture in which the Partnership is a partner or joint venturer, whether acquired by purchase, option exercise or otherwise. (s) "Partnership Revenue" refers to the Partnership's gross revenues from all sources, including interest income, proceeds from sales of production, the Partnership's share of revenues from partnerships or joint ventures of which it is a member, sales or other dispositions of Partnership Properties or other Partnership assets, provided that contributions to Partnership capital by the Partners and the proceeds of any Partnership borrowings are specifically excluded and dry-hole and bottom-hole contributions shall be treated as reductions of the costs giving rise to the right to receive such contributions. (t) "Partnership Wells" are any and all of the oil and gas wells in which the Partnership has an interest, either directly or indirectly through any other partnership or joint venture. A-9 (u) "Productive properties" are oil and gas properties that have been tested by drilling and determined to be capable of producing oil or gas in commercial quantities. (v) "Special Production and Marketing Costs" are costs and expenses that are not normally and customarily incurred in connec- tion with drilling, producing and marketing operations, including without limitation, costs incurred in constructing compressor plants, gasoline plants, gas gathering systems, natural gas processing plants, pipeline systems and salt water disposal systems and costs incurred in installing pressure maintenance and secondary or tertiary production projects. (w) "Subscription Agreement" refers to the form of Limited Partner Subscription Agreement and Suitability Statement attached as Attachment I to this Agreement. (x) A "Substituted Limited Partner" is a transferee, donee, heir, legatee or other recipient of all or any portion of a Limited Partner's interest in the Partnership with respect to whom all conditions and consents required to become a Substituted Limited Partner under Article XIII have been satisfied and given. (y) A "Unit" is a preformation unit of limited partnership interest of a Limited Partner in the Partnership representing a Capital Subscription of One Thousand Dollars ($1,000). ARTICLE III Purposes and Powers of the Partnership 3.1 The purposes of the Partnership will be to acquire productive oil and gas properties and to explore for, produce, treat, transport and market oil, gas or both, or products derived therefrom, anywhere in the United States. It is contemplated that all or most of the Partnership's operations will be conducted as part of the operations of the General Partner and its affiliates, but the Partnership may engage in operations on its own or in conjunction with unaffiliated third parties. In accomplishing such purposes the Partnership may: (a) acquire oil and gas properties, either alone or in conjunction with other parties; (b) conduct geological and geophysical investigations, including, without limitation, seismic exploration, core drilling and other means and methods of exploration; A-10 (c) drill, equip, complete, rework, reequip, recomplete, plug back, deepen, plug and abandon Partnership Wells as the General Partner deems advisable; (d) acquire and dispose of tangible lease and well equipment for use or used in connection with Partnership Wells; (e) employ or retain such personnel and obtain such legal, accounting, geological, geophysical, engineering and other profes- sional services and advice as the General Partner may deem advisable in the course of the Partnership's operations under this Agreement; (f) either pay or elect not to pay delay rentals or shut-in royalties on Partnership Properties as appropriate in the judgment of the General Partner, it being understood that the General Partner will not be liable for failure to make correct or timely payments of delay rentals or shut-in royalties if such failure was due to any reason other than gross negligence or lack of good faith; (g) make or give dry-hole or bottom-hole or other contribu- tions of oil and gas properties, money or both, to encourage drilling by others in the vicinity of or on Partnership Properties; (h) negotiate for and accept dry-hole, bottom-hole or other contributions of oil and gas properties, cash or both, as consid- eration for the drilling of a Partnership Well, with oil and gas properties so acquired, if any, to become Partnership Properties; (i) pay all ad valorem taxes levied or assessed against the Partnership Properties, all taxes upon or measured by the production of oil or gas or other hydrocarbons therefrom, and all other taxes (other than income taxes) directly relating to operations conducted under this Agreement; (j) enter into and operate pursuant to operating agreements with respect to Partnership Properties naming either the General Partner, any of its affiliates or a third party as operator, or enter into partnership agreements with third parties whereby the Partnership may be either a general or a limited partner (including any partnerships formed or sponsored by the General Partner or in which the General Partner may also be a partner), which operating or partnership agreements shall contain such terms, provisions and conditions as the General Partner deems appropriate; (k) execute all documents or instruments of any kind which the General Partner deems appropriate for carrying out the purposes of the Partnership, including, without limitation, unitization agreements, gasoline plant contracts, recycling agreements and agreements relating to pressure maintenance and secondary or tertiary production projects; A-11 (l) purchase and establish inventories of equipment and material required or expected to be required in connection with its operations; (m) contract or enter into agreements with unaffiliated third parties, the General Partner or its affiliates for the performance of services and the purchase and sale of material, equipment, supplies and property, both real and personal, provided, however, that any such contracts or agreements with the General Partner or any of its affiliates shall, except as otherwise provided herein, provide for prices, fees, rates, charges or other compensation which are not greater than those available from, being paid to or charged by unaffiliated third parties dealing at arm's length in the same or a similar geographic area for the same or comparable services, material, equipment, supplies or property; (n) conduct operations either alone or as a joint venturer, co-tenant, partner or in any other manner of participation with third persons and to enter into agreements and contracts setting forth the terms and provisions of such participation; (o) borrow money from banks and other lending institutions for Partnership purposes and pledge Partnership Properties (including production therefrom) for the repayment of such loans, it being understood that no bank or other lending institution to which the General Partner makes application for a loan will be required to inquire as to the purposes for which such loan is sought, and as between the Partnership and such bank or lending institution it will be conclusively presumed that the proceeds of such loan are to be and will be used for purposes authorized under the terms of this Agreement; (p) hold Partnership Properties in its own name or in the name of the General Partner, UNIT or any affiliate or any other party as nominee for the Partnership; (q) sell, relinquish, release, farm-out, abandon or otherwise dispose of Partnership Properties, including undeveloped, productive and condemned properties; (r) produce, treat, transport and market oil and gas and execute division orders, contracts for the marketing or sale of oil, gas or other hydrocarbons and other marketing agreements; A-12 (s) purchase, sell or pledge payments out of production from Partnership Properties; and (t) perform any and all other acts or activities customary or incident to exploration for or development, production and marketing of oil and gas. ARTICLE IV Partner Capital Contributions 4.1 The General Partner will have the unrestricted right to admit such parties as Limited Partners as it deems advisable. By their execution of the Subscription Agreement, the Limited Partners severally agree, subject to the acceptance of their subscription by the General Partner, to be bound by the terms hereof as Limited Partners. 4.2 The Capital Subscriptions of the Limited Partners will be payable either (i) in four equal installments on March 15, 1996, June 15, 1996, September 15, 1996, and December 15, 1996, respectively, or (ii) by employees so electing, through equal deductions from 1996 salary paid to the employee by the General Partner, UNIT or its subsidiaries commencing immediately after the Effective Date. Notwithstanding the foregoing, if in the judgment of the General Partner, the entire amount of the Aggregate Subscription is not required for purposes of conducting the business, operations and affairs of the Partnership, the General Partner may, at its sole option, elect to release the Limited Partners from the obligation to pay in one or more of the installments of their Capital Subscriptions. If Units are acquired by a corporation or other entity, the beneficial owners of the interests therein shall be jointly and severally liable for the payment of the Capital Subscription. If an employee or director who has subscribed for Units (either directly or through a corporation or other entity) ceases to be employed by or a director of the General Partner, UNIT or any of its subsidiaries for any reason other than death, disability or Normal Retirement prior to the time the full amount of his or her Capital Subscription is paid, then the due date for any unpaid amount shall be accelerated so that the full amount of his or her unpaid Capital Subscription shall be due and payable on the effective date of such termination. The Capital Subscriptions shall be legally binding obligations of the Limited Partners and any past due amounts shall bear interest at the annual rate equal to two (2) percentage points in excess of the prime rate of interest of Bank of Oklahoma, N.A., Tulsa, Oklahoma, or successor bank, as announced and in effect from time to time, until paid. Further, in the event a Limited Partner fails to pay any installment when due, the General Partner, at its sole option and discretion, may elect to purchase the Units of such defaulting Limited Partner at a price equal to the total amount of the Capital Contributions actually paid into the Partnership by such defaulting Limited Partner, less the amount of any Partnership A-13 distributions that may have been received by him or her. Such option may be exercised by the General Partner by written notice to the Limited Partner at any time after the date that the unpaid installment was due and shall be deemed exercised when the amount of the purchase price is first tendered to the defaulting Limited Partner. The General Partner may, in its discretion, accept payments of delinquent installments but shall not be required to do so. In the event that the General Partner elects to purchase the Units of a defaulting Limited Partner, it shall pay into the Partnership the amount of the delinquent installment (excluding any interest that may have accrued thereon) and shall pay each additional installment, if any, payable with respect to such Units as it becomes due. By virtue of such purchase, the General Partner shall be allocated all Partnership Revenues and be charged with all Partnership costs and expenses attributable to such Units otherwise allocable or chargeable to the defaulting Limited Partner to the extent provided in Section 13.9. 4.3 If the Partnership requires funds to conduct Partnership operations during the period between any of the installments due as set forth in Section 4.2 above, then, notwithstanding the provisions of Section 5.4 below, the General Partner shall advance funds to the Partnership in an amount equal to the funds then required to conduct such operations but in no event more than the total amount of the Aggregate Subscription remaining unpaid. With respect to any such advances, the General Partner shall receive no interest thereon and no financing charges will be levied by the General Partner in connection therewith. The General Partner shall be repaid out of the Capital Subscription installments thereafter paid into the capital of the Partnership when due. 4.4 Additional Assessments required by the General Partner pursuant to Section 5.3 of this Agreement will be payable in cash on such date as the General Partner may set in its written notice, but in no event will such assessments be due earlier than thirty (30) days after the date of mailing of the notice. Notice of the General Partner's call for Additional Assessments shall specify the amount required, the manner in which the additional funds will be expended, the date on which such amounts are payable, and the consequences of non-payment. The General Partner will not be required to accept late payments of such amounts, but it may in its discretion do so. 4.5 The General Partner will contribute to the capital of the Partnership amounts equal to the total of all costs paid by the Part- nership that are charged to the General Partner's account as such costs are incurred. A-14 ARTICLE V Deposit and Use of Capital Contributions and Other Partnership Funds 5.1 Until required in the conduct of the Partnership's business, Partnership funds, including, but not limited to, Capital Contributions, Partnership Revenue and proceeds of borrowings by the Partnership, will be deposited, with or without interest, in one or more bank accounts of the Partnership in a bank or banks selected by the General Partner or invested in short-term United States government securities, money market funds, bank certificates of deposit or commercial paper rated as "A1" or "P1" as the General Partner, in its sole discretion, deems advisable. Any interest or other income generated by such deposits or investments will be for the Partnership's account. Except for Capital Contributions, Partnership funds from any of the various sources mentioned above may be commingled with other Partnership funds and with the funds of the General Partner and may be withdrawn, expended and distributed as authorized by the terms and provisions of this Agreement. 5.2 The Capital Contributions of the Limited Partners will be expended for costs incurred by the Partnership that, in accordance with the terms of this Agreement, are properly chargeable to the Limited Partners' accounts. 5.3 After the General Partner's Minimum Capital Contribution has been fully expended, if the Aggregate Subscription has all been fully expended or committed and additional funds are required in order to pay Drilling Costs, Special Production and Marketing Costs or Leasehold Acquisition Costs of productive properties which are chargeable to the Limited Partners, the General Partner may, but shall not be required to, make one or more calls for Additional Assessments from Limited Partners pursuant to Section 4.4; provided, however, that the aggregate amount of Additional Assessments called of the Limited Partners may not exceed $100 per Unit. The Limited Partners who do not respond will participate in production, if any, obtained from the aggregate Additional Assessments paid into the Partnership. However, the amount of the unpaid Additional Assessment shall bear interest at the annual rate equal to two (2) percentage points in excess of the prime rate of interest of Bank of Oklahoma, N.A., Tulsa, Oklahoma, or successor bank, as announced and in effect from time to time, until paid. The Partnership will have a lien on the defaulting Limited Partner's interest in the Partnership and the General Partner may apply Partnership Revenue otherwise available for distribution to the defaulting Limited Partner until an amount equal to the unpaid Additional Assessment and interest is received. Furthermore, the General Partner may satisfy such lien by proceeding with legal action to enforce the lien and the defaulting Limited Partner shall pay all A-15 expenses of collection, including interest, court costs and a reasonable attorney's fee. 5.4 After the General Partner's Minimum Capital Contribution has been fully expended, the General Partner may cause the Partnership to borrow funds for the purpose of paying Drilling Costs, Special Production and Marketing Costs or Leasehold Acquisition Costs of productive properties, which borrowings may be secured by interests in the Part- nership Properties and will be repaid, including interest accruing thereon, out of Partnership Revenue allocable to the accounts of the Partners on whose behalf the proceeds of such borrowings are expended. The General Partner may, but is not required to, advance funds to the Partnership for the same purposes for which Partnership borrowings are authorized by this Section 5.4. With respect to any such advances, the General Partner shall receive interest in an amount equal to the lesser of the interest which would be charged to the Partnership by unrelated banks on comparable loans for the same purpose or the General Partner's interest cost with respect to such loan, where it borrows the same. No financing charges will be levied by the General Partner in connection with any such loan. If Partnership borrowings secured by interests in the Partnership Properties and repayable out of Partnership Revenue cannot be arranged on a basis which, in the opinion of the General Partner, is fair and reasonable, and the entire sum required to pay costs of the type referred to above is not available from Partnership Revenue, the Partnership may elect not to drill or participate in the drilling of a well or the General Partner may dispose of the Partnership Properties upon which such operations were to be conducted by sale (subject to any other applicable provisions of this Agreement), farm-out or abandonment. 5.5 The General Partner may utilize Partnership Revenue allocable to the respective accounts of the Partners to pay any Partnership costs and expenses properly chargeable to the accounts of such Partners. 5.6 With respect to any Partnership activity and subject to the restrictions set forth in Sections 5.3 and 5.4 above, it shall be in the sole discretion of the General Partner whether to call for Additional Assessments, arrange for borrowings on behalf of the Partners, utilize Partnership Revenue or sell (subject to any other applicable provisions of this Agreement), farm-out or abandon Partnership Properties. 5.7 The Partnership Properties and production therefrom may be pledged, mortgaged or otherwise encumbered as security for borrowings by the Partnership authorized by Section 5.4 above, provided that the holder of indebtedness arising by virtue of such borrowings may not have or acquire, at any time as a result of making any such loans, any direct or indirect interest in the profits, capital or property of the Partnership other than as a secured creditor. A-16 ARTICLE VI Sharing of Costs, Capital Accounts and Allocation of Charges and Income 6.1 All costs of organizing the Partnership and offering Units therein will be paid by the General Partner. All costs incurred in the offering and syndication of any drilling or income program formed by UPC or UNIT and its affiliates during 1996 in which the Partnership participates as a co-general partner will also be paid by the General Partner. 6.2 All other Partnership costs and expenses will be charged 99% to the accounts of the Limited Partners and 1% to the account of the General Partner until such time as the Aggregate Subscription has been fully expended. Thereafter and until the General Partner's Minimum Capital Contribution has been fully expended, all of such costs and expenses will be charged to the General Partner. After the General Partner's Minimum Capital Contribution has been fully expended, such costs and expenses will be charged to the respective accounts of the General Partner and the Limited Partners on the basis of their respective Percentages. 6.3 All Partnership Revenues will be allocated between the General Partner and the Limited Partners on the basis of their respective Percentages. 6.4 Partnership costs, expenses and Revenues which are charged and allocated to the Limited Partners shall be charged and allocated to their respective accounts in the proportion the Units of each Limited Partner bear to the total number of outstanding Units. 6.5 Capital accounts shall be established and maintained for each Partner in accordance with tax accounting principles and with valid regulations issued by the U.S. Treasury Department under subsection 704(b) (the "704 Regulations") of the Internal Revenue Code of 1986, as amended (the "Code"). To the extent that tax accounting principles and the 704 Regulations may conflict, the latter shall control. In connec- tion with the establishment and maintenance of such capital accounts, the following provisions shall apply: (a) Each Partner's capital account shall be (i) increased by the amount of money contributed by him or her to the Partnership, the fair market value of property contributed by him or her to the Partnership (net of liabilities securing such contributed property that the Partnership is considered to assume or take subject to under section 752 of the Code) and allocations to him or her of Partnership income and gain (except to the extent such income or gain has previously been reflected in his or her capital account by A-17 adjustments thereto) and (ii) decreased by the amount of money distributed to him or her by the Partnership, the fair market value of property distributed to him or her by the Partnership (net of liabilities securing such distributed property that such Partner is considered to assume or take subject to under section 752 of the Code) and allocations to him or her of Partnership loss, deduction (except to the extent such loss or deduction has previously been reflected in his or her capital account by adjustments thereto) and expenditures described in section 705(a)(2)(B) of the Code. (b) In the event Partnership Property is distributed to a Partner, then, before the capital account of such Partner is adjusted as required by subsection (a) of this Section 6.5, the capital accounts of the Partners shall be adjusted to reflect the manner in which the unrealized income, gain, loss and deduction inherent in such property (that has not been reflected in such capital accounts previously) would be allocated among the Partners if there were a taxable disposition of such property for its fair market value on the date of distribution. (c) If, pursuant to this Agreement, Partnership Property is reflected on the books of the Partnership at a book value that differs from the adjusted tax basis of such property, then the Partners' capital accounts shall be adjusted in accordance with the 704 Regulations for allocations to the Partners of depreciation, depletion, amortization, and gain or loss, as computed for book purposes, with respect to such property. (d) The Partners' capital accounts shall be adjusted for depletion and gain or loss with respect to the Partnership's oil or gas properties in whichever of the following manners the General Partner determines is in the best interests of the Partners: (i) the Partners' capital accounts shall be reduced by a simulated depletion allowance computed on each oil or gas property using either the cost depletion method or the percentage depletion method (without regard to the limitations under the Code which could apply to less than all Partners); provided, however, that the choice between the cost depletion method and the simulated depletion method shall be made on a property-by-property basis in the first taxable year of the Partnership for which such choice is relevant for an oil or gas property, and such choice shall be binding for all Partnership taxable years during which such oil or gas property is held by the Partnership. Such reductions for depletion shall not exceed the aggregate adjusted basis allocated to the Partners with respect to such oil or gas property. Such reductions for depletion shall be allocated among the Partners' capital A-18 accounts in the same proportions as the adjusted basis in the particular property is allocated to each Partner. Upon the taxable disposition of an oil or gas property by the Partnership, the Partnership's simulated gain or loss shall be determined by subtracting its simulated adjusted basis (aggregate adjusted tax basis of the Partners less simulated depletion allowances) in such property from the amount realized on such disposition and the Partners' capital accounts shall be increased or reduced, as the case may be, by the amount of the simulated gain or loss on such disposition in proportion to the Partners' allocable shares of the total amount realized on such disposition, or (ii) the Partnership shall reduce the capital account of each Partner in an amount equal to such Partner's depletion allowance with respect to each oil or gas property of the Partnership (for the Partner's taxable year that ends within the Partnership's taxable year), but such reductions for depletion shall not exceed the adjusted basis allocated to such Partner with respect to such property. Upon the taxable disposition of an oil or gas property by the Partnership, the capital account of each Partner shall be reduced or increased, as the case may be, by the amount of the difference between such Partner's allocable share of the total amount realized on such disposition and such Partner's remaining adjusted tax basis in such property. (e) For purposes of determining the capital account balance of any Partner as of the end of any Partnership taxable year for purposes of Subsection 6.6(f) hereof, such Partner's capital account shall be reduced by: (i) adjustments that, as of the end of such year, reasonably are expected to be made to such Partner's capital account pursuant to paragraph (b)(2)(iv)(k) of the 704 Regulations for depletion allowances with respect to oil and gas properties of the Partnership, (ii) allocations of loss and deduction that, as of the end of such year, reasonably are expected to be made to such Partner pursuant to Code section 704(e)(2), Code section 706(d), and paragraph (b)(2)(ii) of section 1.751-1 of regulations promulgated under the Code, and (iii) distributions that, as of the end of such year, reasonably are expected to be made to such Partner to the extent they exceed offsetting increases to such Partner's capital account that reasonably are expected to occur during A-19 (or prior to) the Partnership taxable years in which such distributions reasonably are expected to be made. 6.6 With respect to the various allocations of Partnership income, gain, loss, deduction and credit for federal income tax purposes, it is hereby agreed as follows: (a) To the extent permitted by law, all charges, deductions and losses shall be allocated for federal income tax purposes in the same manner as the costs in respect of which such charges, deductions and losses are charged to the respective accounts of the Partners. The Partners bearing the costs shall be entitled to the deductions (including, without limitation, cost recovery allowances, depreciation and cost depletion) and credits that are attributable to such costs. (b) The Partnership shall allocate to each Partner his or her portion of the adjusted basis in each depletable Partnership Property as required by Section 613A(c)(7)(D) of the Code based upon the interest of said Partner in the capital of the Partnership as of the time of the acquisition of such Partnership Property. To the extent permitted by the Code, such allocation shall be based upon said Partner's interest (i) in the Partnership capital used to acquire the property, or (ii) in the adjusted basis of the property if it is contributed to the Partnership. If such allocation of basis is not permitted under the Code, then basis will be allocated in the permissible manner which the General Partner deems will most closely achieve the result intended above. (c) Partnership Revenue shall be allocated for federal income tax purposes in the same manner as it is allocated to the respective accounts of the Partners pursuant to Sections 6.3 and 6.4 above. (d) Depreciation or cost recovery allowance recapture and recapture of intangible drilling and development costs, if any, due as a result of sales or dispositions of assets shall be allocated in the same proportion that the depreciation, cost recovery allowances or intangible drilling and development costs being recaptured were allocated. (e) Notwithstanding anything to the contrary stated herein, (i) there shall be allocated first to other Limited Partners and then to the General Partner any item of loss, deduction, credit or allowance that, but for this Subsection 6.6(e), would have been allocated to any Limited Partner that is not obligated to restore any deficit balance in such Limited Partner's capital account and would have thereupon caused or A-20 increased a deficit balance in such Limited Partner's capital account as of the end of the Partnership's taxable year to which such allocation related (after taking into consideration the numbered items specified in Subsection 6.5(e) hereof); (ii) any Limited Partner that is not obligated to restore any deficit balance in such Limited Partner's capital account who unexpectedly receives an adjustment, allocation or distribution specified in Subsection 6.5(e) hereof shall be allocated items of income and gain in an amount and manner sufficient to eliminate such deficit balance as quickly as possible; and (iii) in the event any allocations of loss, deduc- tion, credit or allowance are made to a Limited Partner or the General Partner pursuant to clause (i) of this Subsection 6.6(e), then such Limited Partner and/or the General Partner shall be subsequently allocated all items of income and gain pro rata as they were allocated the item(s) of loss, deduction, credit or allowance under such clause (i) until the aggregate amount of such allocations of income and gain is equal to the aggregate amount of any such allocations of loss, deduction, credit or allowance allocated to such Partner(s) pursuant to clause (i) of this Subsection 6.6(e). (f) Notwithstanding any other provision of this Agreement, if, under any provision of this Agreement, the capital account of any Partner is adjusted to reflect the difference between the basis to the Partnership of Partnership Property and such property's fair market value, then all items of income, gain, loss and deduction with respect to such property shall be allocated among the Partners so as to take account of the variation between the basis of such property and its fair market value at the time of the adjustment to such Partner's capital account in accordance with the requirements of subsection 704(c) of the Code, or in the same manner as provided under subsection 704(c) of the Code. 6.7 Notwithstanding anything to the contrary that may be expressed or implied in this Agreement, the interest of the General Partner in each material item of Partnership income, gain, loss, deduction or credit shall be equal to at least one percent of each such item at all times during the existence of the Partnership. In determining the General Partner's interest in such items, Units owned by the General Partner shall not be taken into account. 6.8 Except as provided in subsections (a) through (d) of this Section 6.8, in the case of a change in a Partner's interest in the Partnership during a taxable year of the Partnership, all Partnership A-21 income, gain, loss, deduction or credit allocable to the Partners shall be allocated to the persons who were Partners during the period to which such item is attributable in accordance with the Partners' interests in the Partnership during such period regardless of when such item is paid or received by the Partnership. (a) With respect to certain "allocable cash basis items" (as such term is defined in the Code) of Partnership Revenue, gain, loss, deduction or credit, if, during any taxable year of the Partnership there is change in any Partner's interest in the Partnership, then, except to the extent provided in regulations prescribed under Section 706 of the Code, each Partner's allocable share of any "allocable cash basis item" shall be determined by (i) assigning the appropriate portion of each such item to each day in the period to which it is attributable, and (ii) allocating the portion assigned to any such day among the Partners in proportion to their interests in the Partnership at the close of such day. (b) If, by adhering to the method of allocation described in the immediately preceding subsection of this Section 6.8, a portion of any "allocable cash basis item" is attributable to any period before the beginning of the Partnership taxable year in which such item is received or paid, such portion shall be (i) assigned to the first day of the taxable year in which it is received or paid, and (ii) allocated among the persons who were Partners in the Partnership during the period to which such portion is attributable in accordance with their interests in the Partnership during such period. (c) If any portion of any "allocable cash basis item" paid or received by the Partnership in a taxable year is attributable to a period after the close of that taxable year, such portion shall be (i) assigned to the last day of the taxable year in which it is paid or received, and (ii) allocated among the persons who are Partners in proportion to their interests in the Partnership at the close of such day. (d) If any deduction is allocated to a person with respect to an "allocable cash basis item" attributable to a period before the beginning of the Partnership taxable year and such person is not a Partner of the Partnership on the first day of the Partnership taxable year, such deduction shall be capitalized by the Partnership and treated in the manner provided for in Section 755 of the Code. A-22 ARTICLE VII Fiscal Year, Accountings and Reports 7.1 Unless the Code requires otherwise, the fiscal year of the Partnership will be the calendar year and the books of the Partnership will be kept in accordance with usual and customary accounting practices on the accrual method. 7.2 Within sixty (60) days after the end of each quarter of each Partnership fiscal year, each person who was a Limited Partner during such period will be furnished a report setting forth the source and disposition of Partnership funds during the quarter. 7.3 Not later than the end of the fiscal year in which all Partnership Wells are drilled and completed, and sufficient production history has been obtained on Partnership Wells to evaluate properly the reserves attributable thereto, the General Partner will make an evalua- tion of Partnership Properties as of the last day of such fiscal year. The report shall include an estimate of the total oil and gas proven reserves of the Partnership and the dollar value thereof and the value of the Limited Partner's interest in such reserve value. It shall also contain an estimate of the present worth of the reserves. Each Limited Partner will receive a summary statement of such report reflecting the Limited Partners' interest in such reserve value. ARTICLE VIII Tax Returns and Elections 8.1 Unless the Code requires otherwise, the General Partner will cause the Partnership to elect the calendar year as its taxable year and will timely file all Partnership income tax returns required to be filed by the jurisdictions in which the Partnership conducts business or derives income. By March 15 of each year or as soon thereafter as practicable, the General Partner will furnish all available information necessary for inclusion in the income tax returns of each person who was a Limited Partner during the prior fiscal year. The General Partner shall be the "Tax Matters Partner" for the Partnership pursuant to the provisions of Section 6231 of the Code subject to the provisions of Section 10.22 below. 8.2 The Partnership will elect to deduct intangible drilling and development costs currently as an expense for income tax purposes and will elect to use the available depreciation method which, in the General Partner's judgment, is in the best interest of the Partners. A-23 8.3 The General Partner shall have the right in its sole discretion at any time to make or not to make such other elections as are authorized or permitted by any law or regulation for income tax purposes (including any election under Section 754 of the Code). ARTICLE IX Distributions 9.1 The Partnership's available cash will be distributed to the Limited Partners and the General Partner in the same proportions that Partnership Revenue has been allocated to them after giving effect to previous distributions and to portions of such revenue theretofore used or retained to pay costs incurred or expected to be incurred in con- ducting Partnership operations or to repay borrowings theretofore or expected to be thereafter obtained by the Partnership. Within forty-five (45) days after the end of each calendar quarter, the General Partner will determine the amount of cash available for distribution to the Limited Partners and will distribute such amount, if any, as promptly thereafter as reasonably possible. Distributions of cash to the General Partner may be at any time the General Partner determines there is cash available therefor. The General Partner's determination of the cash available for distribution will be conclusive and binding upon all Partners. All Partnership funds distributed to the Limited Partners shall be distributed to the persons who were record holders of Units on the day on which the distribution is made. ARTICLE X Rights, Duties and Obligations of the General Partner 10.1 Subject to the limitations of this Agreement, the General Partner will have full, exclusive and complete discretion in the management and control of the business of the Partnership and will make all decisions affecting its business and affairs or the Partnership Properties. The General Partner will have, subject to the provisions of this Article X, full power and authority to take any action described in Article III above and execute and deliver in the name of and on behalf of the Partnership such documents or instruments as the General Partner deems appropriate for the conduct of Partnership business. No person, firm or corporation dealing with the Partnership will be required to inquire into the authority of the General Partner to take any action or make any decision. 10.2 The General Partner will perform the duties imposed upon it under this Agreement in an efficient and businesslike manner with due A-24 caution and in accordance with established practices of the oil and gas industry, but the General Partner shall not be liable, responsible or accountable in damages or otherwise to the Partnership or any of the Partners for, and the Partnership shall indemnify, defend against and save harmless the General Partner, from any expense (including attorneys' fees), loss or damage incurred by reason of any act or omission performed or omitted in good faith on behalf of the Partnership or the Partners, and in a manner reasonably believed by the General Partner to be within the scope of the authority granted by this Agreement and in the best interests of the Partnership or the Partners, provided that the General Partner is not guilty of gross negligence or willful misconduct with respect to such acts or omissions, and further provided that the satisfaction of any indemnification and any saving harmless shall be from and limited to Partnership assets including insurance proceeds, if any, and no Partner shall have any personal liability on account thereof. For purposes of this Section 10.2 only, the term General Partner includes the General Partner, affiliates of the General Partner and any officer, director or employee of the General Partner or any of its affiliates such that all of such parties are covered by the indemnities provided herein. 10.3 The General Partner will utilize its organization and employees and will hire outside consultants for the Partnership as necessary in order to provide experienced, qualified and competent personnel to conduct the Partnership's business. With certain limited exceptions it is the intent of the Partners that the Partnership participate as a co-general partner of any oil and gas drilling or income programs, or both, formed by the General Partner or UNIT for third party investors during 1996 and to participate on a proportionate working interest basis in each producing oil and gas lease acquired and in the drilling of each oil and gas well commenced by the General Partner or UNIT for its own account during the period from the later of January 1, 1996 or the Effective Date through December 31, 1996 (except for wells, if any, (i) drilled outside of the 48 contiguous United States; (ii) drilled as part of secondary or tertiary recovery operations which were in existence prior to the formation of the Partnership; (iii) drilled by third parties under farm-out or similar arrangements with the General Partner or UNIT or whereby the General Partner or UNIT may be entitled to an overriding royalty, reversionary or other similar interest in the production from such wells but is not obligated to pay any of the Drilling Costs thereof; (iv) acquired by UNIT or the General Partner through the acquisition by UNIT or the General Partner of, or merger of UNIT or the General Partner with, other companies; or (v) with respect to which the General Partner does not believe that the potential economic return therefrom justifies the costs of participation by the Partnership). 10.4 The General Partner, UNIT or any affiliate thereof will transfer to the Partnership interests in oil and gas properties com- prising the spacing unit on which a Partnership Well is located or is to A-25 be drilled for the separate account of the Partnership, provided that no broker's commissions or fees of a similar nature will be paid in connection with any such transfer and the consideration paid by the Partnership will be equal to the Leasehold Acquisition Costs of the property so transferred. If the size of a spacing unit on which a Partnership Well is located is ever reduced or increased well density is permitted thereon, the Partnership will not be entitled to any reimbursement or recoupment of any portion of the Leasehold Acquisition Costs paid with respect thereto notwithstanding the provisions of Section 10.7 below. 10.5 With respect to certain transactions involving Partnership Properties, it is hereby agreed as follows: (a) A sale, transfer or conveyance by the General Partner or any affiliate of less than its entire interest in such property is prohibited unless (i) the interest retained by the General Partner or its affiliate is a proportionate working interest, (ii) the respective obligations of the General Partner or its affiliate and the Partnership are substantially the same proportionately as those of the General Partner or its affiliate at the time it acquired the property and (iii) the Partnership's interest in revenues will not be less than the proportionate interest therein of the General Partner or its affiliate when it acquired the property. The General Partner or its affiliate may retain the remaining interest for its own account or it may sell, transfer, farm-out or otherwise convey all or a portion of such remaining interest to non-affiliated industry members. In connection with any such sale, transfer, farm-out or other conveyance of such interest to non-affiliated industry members, which may occur either before or after the transfer of the interests in the same properties to the Partnership, the General Partner or its affiliate may realize a profit on the interests or may be carried to some extent with respect to its cost obligations in connection with any drilling on such properties and any such profit or interest will be strictly for the account of the General Partner and the Partnership will have no claim with respect thereto. (b) The General Partner or its affiliates may not retain any overrides or other burdens on property conveyed to the Partnership (other than overriding royalty interests granted to geologists and other persons employed or retained by the General Partner or its affiliates). 10.6 The General Partner will cause the Partnership Properties to be acquired in accordance with the customs of the oil and gas industry in the area. The Partnership will be required to do only such title work with respect to its oil and gas properties as the General Partner in its A-26 sole judgment deems appropriate in light of the area, any applicable drilling or expiration dates and any other material factors. 10.7 Partnership Properties shall be transferred to the Partnership after the decision to acquire a productive property or the commitment to drill a Partnership Well thereon has been made. The Partnership shall acquire interests in only those properties of the General Partner or UNIT which comprise the spacing unit on which the Partnership Well is drilled or on which a producing Partnership Well is located. If a spacing unit on which a Partnership Well is drilled or located is ever reduced, or any subsequent well in which the Partnership has no interest is drilled thereon, the Partnership will have no interest in any such subsequent or additional wells drilled on properties which were a part of the original spacing unit unless any such additional well is commenced during 1996 or is drilled by a drilling or income program of which the Partnership is a partner. Likewise if UNIT, UPC or any affiliate, including any oil and gas partnership subsequently formed for investment or participation by employees, directors and/or consultants of UNIT or any of its subsidiaries, acquires additional interests in Partnership Wells after 1996 the Partnership generally will not be entitled to participate in the acquisition of such additional interests. In addition, if a Partnership Well drilled on a spacing unit is dry or abandoned, the Partnership will not have an interest in any subsequent or additional well drilled on the spacing unit unless it is commenced during 1996 or is drilled by a drilling or income program of which the Partnership is a partner. 10.8 The General Partner, UNIT or its affiliates will either conduct the Partnership's drilling and production operations and operate each Partnership Well or arrange for a third party operator to conduct such operations. The General Partner will, on behalf of the Partnership, enter into appropriate operating agreements with other owners of Partnership Wells authorizing the General Partner, its affiliates or a third party operator to conduct such operations. The Partnership will take such action in connection with operations pursuant to said operating agreements as the General Partner, in its sole discretion, deems appropriate and in the best interests of the Partnership, and the decision of the General Partner with respect thereto will be binding upon the Partnership. 10.9 The General Partner will cause the Partnership to plug and abandon its dry holes and abandoned wells in accordance with rules and regulations of the governmental regulatory body having jurisdiction. 10.10 The General Partner may pool or unitize Partnership Proper- ties with other oil and gas properties when such pooling or unitization is required by a governmental regulatory body, when well spacing as determined by any such body requires such pooling or unitization, or A-27 when, in the General Partner's opinion, such pooling or unitization is in the best interests of the Partnership. 10.11 The General Partner will have authority to make and enter into contracts for the sale of the Partnership's share of oil or gas production from Partnership Wells, including contracts for the sale of such production to the General Partner, UNIT or its affiliates; provided, however, that the production purchased by the General Partner, UNIT or any of its affiliates will be for prices which are not less than the highest posted price (in the case of crude oil production) or prevailing price (in the case of natural gas production) in the same field or area. 10.12 The General Partner will use its best efforts to procure and maintain for the Partnership, and at its expense, such insurance coverage with responsible companies as may be reasonably available for such premium costs as would not be considered to be unreasonably high or prohibitive with respect to each item of coverage and as the General Partner considers necessary for the protection of the Partnership and the Partners. The coverage will be in such amounts and will cover such risks as the General Partner believes warranted by the operations conducted hereunder. Such risks may include but will not necessarily be limited to public liability and automobile liability, each covering bodily injury, death and property damage, workmen's compensation and employer's liability insurance and blowout and control of well insurance. 10.13 In order to conduct properly the business of the Partnership, and in order to keep the Partners properly informed, the General Partner will: (a) maintain adequate records and files identifying the Partnership Properties and containing all pertinent information in regard thereto that is obtained or developed pursuant to this Agreement; (b) maintain a complete and accurate record of the acquisition and disposition of each Partnership Property; (c) maintain appropriate books and records reflecting the Partnership's revenue and expense and each Partner's participation therein; (d) maintain a capital account for each Partner with appro- priate records as necessary in order to reflect each Partner's interest in the Partnership and furnish required tax information; and (e) keep the Limited Partners informed by means of written reports on the acquisition of Partnership Properties and the A-28 progress of the business and operations of the Partnership, which reports will be rendered semi-annually and at such more frequent intervals during the progress of Partnership operations as the General Partner deems appropriate. 10.14 The General Partner, UNIT and the officers, directors, employees and affiliates thereof may own, purchase or otherwise acquire and deal in oil and gas properties, drill wells, conduct operations and otherwise engage in any aspect of the oil and gas business, either for their own accounts or for the accounts of others. Each Limited Partner hereby agrees that engaging in any activity permitted by this Section 10.14 will not be considered a breach of any duty that the General Partner, UNIT or the officers, directors, employees and affiliates thereof may have to the Partnership or the Limited Partners, and that the Partnership and the Limited Partners will not have any interest in any properties acquired or profits which may be realized with respect to any such activity. 10.15 Subject to Section 12.1, without the prior consent of Limited Partners holding a majority of the outstanding Units, the General Partner will not (i) make, execute or deliver any assignment for the benefit of the Partnership's creditors; or (ii) contract to sell all or substantially all of the Partnership Properties (except as permitted by Sections 10.23 and 16.4(b)). 10.16 In contracting for services to and insurance coverage for the Partnership and its activities and operations, and in acquiring material, equipment and personal property on behalf of the Partnership, the General Partner will use its best efforts to obtain such services, insurance, material, equipment and personal property at prices no less favorable than those normally charged in the same or in comparable geographic areas by non-affiliated persons or companies dealing at arm's length. No rebates, concessions or compensation of a similar nature will be paid to the General Partner by the person or company supplying such services, insurance, material, equipment and personal property. 10.17 The General Partner, UNIT or its affiliates are authorized to provide equipment, materials and services to the Partnership in connection with the conduct of its operations, provided, that the terms of any contracts between the Partnership and the General Partner, UNIT or any affiliates, or the officers, directors, employees and affiliates thereof must be no less favorable to the Partnership than those of comparable contracts entered into, and will be at prices not in excess of those charged in the same geographical area by non-affiliated persons or companies dealing at arm's length. Any such contracts for services must be in writing precisely describing the services to be rendered and all compensation to be paid. A-29 10.18 The General Partner may cause the Partnership to hold Partnership Properties in the Partnership's name, or in the name of the General Partner, UNIT, any affiliates thereof or some third party as nominee for the Partnership. If record title to a Partnership Property is to be held permanently in the name of a nominee, such nominee arrangement will be evidenced and documented by a nominee agreement identifying the Partnership Properties so held and disclaiming any beneficial interest therein by the nominee. 10.19 The General Partner will be generally liable for the debts and obligations of the Partnership, provided that any claims against the Partnership shall be satisfied first out of the assets of the Partnership and only thereafter out of the separate assets of the General Partner. 10.20 The Partnership may not make any loans to the General Partner, UNIT or any of its affiliates. 10.21 The General Partner will use its best efforts at all times to maintain its net worth at a level that is sufficient to insure that the Partnership will be classified for federal income tax purposes as a partnership, rather than as an association taxable as a corporation, on account of the net worth of the General Partner. 10.22 The Tax Matters Partner designated in Section 8.1 above is authorized to engage legal counsel and accountants and to incur expense on behalf of the Partnership in contesting, challenging and defending against any audits, assessments and administrative or judicial proceed- ings conducted or participated in by the Internal Revenue Service with respect to the Partnership's operations and affairs. 10.23 At any time two years or more after the Partnership has completed substantially all of its property acquisition, drilling and development operations, the General Partner may, without the vote, consent or approval of the Limited Partners, cause all or substantially all of the oil and gas properties and other assets of the Partnership to be sold, assigned or transferred to, or the Partnership merged or consolidated with, another partnership or a corporation, trust or other entity for the purpose of combining the assets of two or more of the oil and gas partnerships formed for investment or participation by employees, directors and/or consultants of UNIT or any of its subsidiaries; provided, however, that the valuation of the oil and gas properties and other assets of all such participating partnerships for purposes of such transfer or combination shall be made on a consistent basis and in a manner which the General Partner and UNIT believe is fair and equitable to the Limited Partners. As a consequence of any such transfer or combination, the Partnership shall be dissolved and terminated pursuant to Article XVI hereof and the Limited Partners shall receive partnership A-30 interests, stock or other equity interests in the transferee or resulting entity. ARTICLE XI Compensation and Reimbursements 11.1 For the General Partner's services performed as operator of productive Partnership Wells located on Partnership Properties and as operator during the drilling of Partnership Wells, the Partnership will compensate the General Partner at rates no higher than those normally charged in the same or a comparable geographic area by non-affiliated persons or companies dealing at arm's length. The General Partner will not receive compensation for such services performed in connection with the operation of Partnership Wells operated by third party operators, but such third party operators will be compensated as provided in the operating agreements in effect with respect to such wells and the Partnership will pay its proportionate share of such compensation. 11.2 The General Partner will be reimbursed by the Partnership out of Partnership Revenues for that portion of its general and administra- tive overhead expense that is attributable to its conduct of the actual and necessary business, affairs and operations of the Partnership. The General Partner's general and administrative overhead expenses will be determined in accordance with industry practices. The allocable costs and expenses will include all customary and routine legal, accounting, geological, engineering, travel, office rent, telephone, secretarial, salaries, data processing, word processing and other incidental reason- able expenses necessary to the conduct of the Partnership's business and generated by the General Partner or allocated to it by UNIT, but will not include filing fees, commissions, professional fees, printing costs and other expenses incurred in forming the Partnership or offering interests therein. Also excluded will be any general and administrative overhead expense of the General Partner or UNIT which may be attributable to its services as an operator of Partnership Wells for which it receives compensation pursuant to Section 11.1 above. The portion of the General Partner's general and administrative overhead expense to be reimbursed by the Partnership with respect to any particular period will be determined by allocating to the Partnership that portion of the General Partner's total general and administrative overhead expense incurred during such period which is equal to the ratio of the Partnership's total expenditures compared to the total expenditures by the General Partner for its own account. The portion of such general and administrative overhead expense reimbursement which is charged to the Limited Partners may not exceed an amount equal to 3% of the Aggregate Subscription during the first 12 months of the Partnership's operations, and in each succeeding twelve-month period, the lesser of (a) 2% of the Aggregate A-31 Subscription and (b) 10% of the total Partnership Revenue realized in such twelve-month period. Administrative expenses incurred directly by the Partnership, or incurred by the General Partner on behalf of the Partnership and reimbursable to the General Partner, such as legal, accounting, auditing, reporting, engineering, mailing and other such fees, costs and expenses are not to be deemed a part of the general and administrative expense of the General Partner which is to be reimbursed pursuant to this Section 11.2 and the amounts thereof will not be subject to the limitations described in the preceding sentence. ARTICLE XII Rights and Obligations of Limited Partners 12.1 The Limited Partners, in their capacity as such, cannot transact any business for the Partnership or take part in the control of its business or management of its affairs. Limited Partners will have no power to execute any agreements on behalf of, or otherwise bind or commit, the Partnership. They may give consents and approvals as herein provided and exercise the rights and powers granted to them in this Agreement, it being understood that the exercise of such rights and powers will be deemed to be matters affecting the basic structure of the Partnership and not the exercise of control over its business; provided, however, that exercise of any of the rights and powers granted to the Limited Partners in Sections 10.15, 12.3, 14.1, 16.1 and 18.1 will not be authorized or effective unless prior to the exercise thereof the General Partner is furnished an opinion of counsel for the Partnership or an order or judgment of any court of competent jurisdiction to the effect that the exercise of such rights or powers (i) will not be deemed to evidence that the Limited Partners are taking part in the control of or management of the Partnership's business and affairs, (ii) will not result in the loss of any Limited Partner's limited liability and (iii) will not result in the Partnership being classified as an association taxable as a corporation for federal income tax purposes. 12.2 The Limited Partners will not be personally liable for any debts or losses of the Partnership. Except as otherwise specifically provided herein, no Partner will be responsible for losses of any other Partners. 12.3 Except as otherwise provided in this Agreement, no Limited Partner will be entitled to the return of his contribution. Distribu- tions of Partnership assets pursuant to this Agreement may be considered and treated as returns of contributions if so designated by law or, subject to Section 12.1, by agreement of the General Partner and Limited Partners holding a majority of the outstanding Units. The value of a Limited Partner's undistributed contribution determined for the purposes A-32 of Section 39 of the Act at any point in time shall be his or her percentage of the amount of the Partnership's stated capital allocated to the Limited Partners as reflected in the financial statements of the Partnership as of such point in time. No Partner will receive any interest on his or her contributions and no Partner will have any priority over any other Partner as to the return of contributions. ARTICLE XIII Transferability of Limited Partner's Interest 13.1 Notwithstanding the provisions of Section 13.3, no sale, exchange, transfer or assignment of a Limited Partner's interest in the Partnership may be made unless in the opinion of counsel for the Partnership, (a) such sale, exchange, transfer or assignment, when added to the total of all other sales, exchanges, transfers or assignments of interests in the Partnership within the preceding 12 months, would not result in the Partnership being considered to have terminated within the meaning of Section 708 of the Code (provided, however, that this condition may be waived by the General Partner in its discretion); (b) such sale, exchange, transfer or assignment would not violate, or cause the offering of the Units to be violative of, the Securities Act of 1933, as amended, or any state securities or "blue sky" laws (including any investor suitability standards) applicable to the Partnership or the interest to be sold, exchanged, transferred or assigned; and (c) such sale, exchange, transfer or assignment would not cause the Partnership to lose its status as a partnership for federal income tax purposes, and said opinion of counsel is delivered in writing to the Partnership prior to the date of the sale, exchange, transfer or assignment. 13.2 In no event shall all or any part of an interest in the Partnership be assigned or transferred to a minor (except in trust or pursuant to the Uniform Gifts to Minors Act) or an incompetent (except in trust), except by will or intestate succession. 13.3 Except for transfers or assignments (in trust or otherwise) by a Limited Partner of all or any part of his or her interest in the Partnership A-33 (a) to the General Partner, (b) to or for the benefit of himself or herself, his or her spouse, or other members of his or her immediate family sharing the same household, (c) to a corporation or other entity in which all of the beneficial owners are Limited Partners or assigns permitted in (a) and (b) above, or (d) by the General Partner to any person who at the time of such transfer is an employee of the General Partner, UNIT or its subsidiaries, no Limited Partner's Units or any portion thereof may be sold, assigned or transferred except by reason of death or operation of law. 13.4 If a Limited Partner dies, his or her executor, administrator or trustee, or, if he or she is adjudicated incompetent, his or her committee, guardian or conservator, or, if he or she becomes bankrupt, the trustee or receiver of his or her estate, shall have all the rights of a Limited Partner for the purpose of settling or managing his or her estate and such power as the deceased, incapacitated or bankrupt Limited Partner possessed to assign all or any part of his or her interest and to join with such assignee in satisfying conditions precedent to such assignee's becoming a Substituted Limited Partner. 13.5 The Partnership shall not recognize for any purpose any purported sale, assignment or transfer of all or any fraction of the interest of a Limited Partner in the Partnership, unless the provisions of Section 13.1 shall have been complied with and there shall have been filed with the Partnership a written and dated notification of such sale, assignment or transfer in form satisfactory to the General Partner, executed and acknowledged by both the seller, assignor or transferor and the purchaser, assignee or transferee and such notification (i) contains the acceptance by the purchaser, assignee or transferee of all of the terms and provisions of this Agreement and (ii) represents that such sale, assignment or transfer was made in accordance with all applicable laws and regulations. Any sale, assignment or transfer shall be recognized by the Partnership as effective on the date of such notification if the date of such notification is within thirty (30) days of the date on which such notification is filed with the Partnership, and otherwise shall be recognized as effective on the date such notification is filed with the Partnership. 13.6 Any Limited Partner who shall assign all of his or her interest in the Partnership shall cease to be a Limited Partner, except that, unless and until a Substituted Limited Partner is admitted in his or her A-34 stead, such assigning Limited Partner shall retain the statutory rights of the assignor of a Limited Partner's interest under the Act. 13.7 A person who is the assignee of all or any fraction of the interest of a Limited Partner, but does not become a Substituted Limited Partner and desires to make a further assignment of such interest, shall be subject to all the provisions of this Article XIII to the same extent and in the same manner as any Limited Partner desiring to make an assignment of his or her interest. 13.8 No Limited Partner shall have the right to substitute a purchaser, assignee, transferee, donee, heir, legatee, distributee or other recipient of all or any portion of such Limited Partner's interest in the Partnership as a Limited Partner in his or her place. Any such purchaser, assignee, transferee, donee, legatee, distributee or other recipient of an interest in the Partnership shall be admitted to the Partnership as a Substituted Limited Partner only with the consent of the General Partner, which consent shall be granted or withheld in the sole and absolute discretion of the General Partner and may be arbitrarily withheld, and only by an amendment to this Agreement or the certificate of limited partnership duly executed and recorded in the proper records of each jurisdiction in which the Partnership owns mineral interests and filed in the proper records of the State of Oklahoma. Any such consent by the General Partner shall be binding and conclusive without the consent of any Limited Partners and may be evidenced by the execution of the General Partner of an amendment to this Agreement or the certificate of limited partnership, evidencing the admission of such person as a Substituted Limited Partner. 13.9 No person shall become a Substituted Limited Partner until such person shall have: (a) become a party to, and adopted all of the terms and conditions of, this Agreement; (b) if such person is a corporation, partnership or trust, provided the General Partner with evidence satisfactory to counsel for the Partnership of such person's authority to become a Limited Partner under the terms and provisions of this Agreement; and (c) paid or agreed to pay the costs and expenses incurred by the Partnership in connection with such person's becoming a Limited Partner. Provided, however, that for the purpose of allocating Partnership Revenue, costs and expenses, a person shall be treated as having become, and as appearing in the records of the Partnership as, a Substituted A-35 Limited Partner on such date as the sale, assignment or transfer was recognized by the Partnership pursuant to Section 13.5. 13.10 By his or her execution of his or her Subscription Agreement, each Limited Partner represents and warrants to the General Partner and to the Partnership that his or her acquisition of his or her interest in the Partnership is made as principal for his or her own account for investment purposes only and not with a view to the resale or distribution of such interest. Each Limited Partner agrees that he or she will not sell, assign or otherwise transfer his or her interest in the Partnership or any fraction thereof unless such interest has been registered under the Securities Act of 1933, as amended, or such sale, assignment or transfer is exempt from such registration and, in any event, he or she will not so sell, assign or otherwise transfer his or her interest or any fraction thereof to any person who does not similarly represent, warrant and agree. ARTICLE XIV Assignments by the General Partner 14.1 The General Partner may not sell, assign, transfer or otherwise dispose of its interest in the Partnership except with the prior consent, subject to Section 12.1, of Limited Partners holding a majority of the outstanding Units; provided that a sale, assignment or transfer may be effective without such consent if pursuant to a bona fide merger, any other corporate reorganization or a complete liquidation, pursuant to a sale of all or substantially all of the General Partner's assets (provided the purchasers of such assets agree to assume the duties and obligations of the General Partner) or a sale or transfer to UNIT or any affiliates of UNIT. If the Limited Partners' consent to a proposed transfer is required, the General Partner will, concurrently with the request for such consent, give the Limited Partners written notice identifying the interest to be transferred, the date on which the transfer is to be effective, the proposed transferee and the substitute General Partner, if any. 14.2 Sales, assignments and transfers of the interests in the Partnership owned by the General Partner will be subject to, and the assignee will acquire the assigned interest subject to, all of the terms and provisions of this Agreement. 14.3 If the Limited Partners' consent to a transfer of the General Partner's interest in the Partnership is obtained as above provided, or is not required, the transferee may become a substitute General Partner hereunder. The substitute General Partner will assume and agree to perform all of the General Partner's duties and obligations hereunder and A-36 the transferring General Partner will, upon making a proper accounting to the substitute General Partner, be relieved of any further duties or obligations hereunder with respect to Partnership operations thereafter occurring. ARTICLE XV Limited Partners' Right of Presentment 15.1 After December 31, 1997, each Limited Partner will have the option, subject to the terms and conditions set forth in this Article XV, to require the General Partner to purchase all (but not less than all) of his or her Units, provided that the option may not be exercised after the date of any notice that will effect a dissolution and termination of the Partnership pursuant to Article XVI below. Any such exercise shall be effected by written notice thereof delivered to the General Partner. 15.2 Sales of Limited Partners' Units pursuant to this Article XV will be effective, and the purchase price for such interests will be determined, as of the close of business on the last day of the calendar year in which the Limited Partner's notice exercising his or her option is given, or, at the General Partner's election, as of 7:00 o'clock A.M. on the following day. 15.3 The purchase price to be paid for the Units of any Limited Partner who exercises the option granted in this Article XV will be determined in the following manner. First, future gross revenues expected to be derived from the production and sale of the proved reserves attributable to Partnership Properties will be estimated, as of the end of the calendar year in which presentment is made, by the independent engineering firm preparing a report on the reserves of the Partnership, or if no such firm is preparing a report as of the end of the calendar year in which the option is exercised, then by the General Partner. Next, future net revenues will be calculated by deducting anticipated expenses (including Operating Expenses and other costs that will be incurred in producing and marketing such reserves and any gross production, excise, or other taxes, other than federal income taxes, based on the oil and gas production of the Partnership or sales thereof) from estimated future gross revenues. The estimates of price and cost escalations to be used in such calculations will be those of such independent engineering firm or the General Partner, whichever is making the determination. Then the present worth of the future net revenues will be calculated by discounting the estimated future net revenues at that rate per annum which is one (1) percentage point higher than the prime rate of interest being charged by Bank of Oklahoma, N.A., Tulsa, Oklahoma, or any successor bank, as such prime rate of interest is announced by said bank as of the date such reserves are estimated. This A-37 amount will be reduced by an additional 25% to take into account the uncertainties attendant to the production and sale of oil and gas reserves and other unforeseen contingencies. Estimated salvage value of tangible equipment installed on the Partnership Wells and costs of plugging and abandoning the productive Partnership Wells, both discounted at the aforementioned rate from the expected date of abandonment, will be considered, and Partnership Properties, if any, which do not have proved reserves attributable to them but which have not been condemned will be valued at the lower of cost or their then current market value as determined by the aforementioned independent petroleum engineering firm or General Partner, as the case may be. The Partnership's cash on hand, prepaid expenses, accounts receivable (less a reasonable reserve for doubtful accounts) and the market value of its other assets as determined by the General Partner will be added to the value of the Partnership Properties thus determined, and the Partnership's debts, obligations and other liabilities will be deducted, to arrive at the Partnership's net asset value for purposes of this Section 15.3. The price to be paid for the Limited Partner's interest will be his or her proportionate share of such net asset value less 75% of the amount of any Partnership distributions received by him or her which are attributable to sales of Partnership production since the date as of which the Partnership's proved reserves are estimated. 15.4 Within one hundred twenty (120) days after the end of any calendar year in which a Limited Partner exercises his or her option to require purchase of his or her Units as provided in this Article XV, the General Partner will furnish to such Limited Partner a statement showing the price to be paid for his or her Units and evidencing that such price has been determined in accordance with the provisions of Section 15.3 above. The statement will show which portion of the proposed purchase price is represented by the value of the proved reserves and by each of the other classes of Partnership assets and liabilities attributable to the account of the Limited Partner. The Limited Partner will then have thirty (30) days to confirm, by further notice to the General Partner, his or her intention to sell his or her Units to the General Partner. If the Limited Partner timely confirms his or her intention to sell, the sale will be consummated and the price paid in cash within ten (10) days after such confirmation. The General Partner will not be obligated to purchase (i) any Units pursuant to such right if such purchase, when added to the total of all other sales, exchanges, transfers or assignments of the Units within the preceding 12 months, would result in the Partnership being considered to have terminated within the meaning of Section 708 of the Code or would cause the Partnership to lose its status as a partnership for federal income tax purposes, or (ii) in any one calendar year more than 20% of the Units in the Partnership then outstanding. If less than all of the Units tendered are purchased, the interests purchased will be selected by lot. The Limited Partners whose tendered Units were rejected by reason of the foregoing limitation shall A-38 be entitled to priority in the following year. Contemporaneously with the closing of any such sale, the Limited Partner will execute such certificates or other documents and perform such acts as the General Partner deems necessary to effect the sale and transfer of the liquidating Limited Partner's Units to the General Partner and to preserve the limited liability status of the Partnership under the laws of the jurisdictions in which it is doing business. 15.5 As used in Sections 15.3 and 15.4 above, the term "proved reserves" shall have the meaning ascribed thereto in Regulation S-X adopted by the Securities and Exchange Commission. ARTICLE XVI Termination and Dissolution of Partnership 16.1 The Partnership will terminate automatically on December 31, 2026, unless prior thereto, subject to Section 12.1 above, the General Partner or Limited Partners holding a majority of the outstanding Units elect to terminate the Partnership as of an earlier date. In the event of such earlier termination, ninety (90) days' written notice will be given to all other Partners. The termination date will be specified in such notice and must be the last day of any calendar month following expiration of the ninety (90) day period unless an earlier date is approved by Limited Partners holding a majority of the outstanding Units. 16.2 Upon the dissolution (other than pursuant to a merger or other corporate reorganization), bankruptcy, legal disability or withdrawal of the General Partner (other than pursuant to Section 14.1 above), the Partnership shall immediately be dissolved and terminated; provided, however, that nothing in this Agreement shall impair, restrict or limit the rights and powers of the Partners under the laws of the State of Oklahoma and any other jurisdiction in which the Partnership is doing business to reform and reconstitute themselves as a limited partnership within ninety (90) days following the dissolution of the Partnership either under provisions identical to those set forth herein or under any other provisions. The withdrawal, expulsion, dissolution, death, legal disability, bankruptcy or insolvency of any Limited Partner will not effect a dissolution or termination of the Partnership. 16.3 Upon termination of the Partnership by action of the Limited Partners pursuant to Section 16.1 hereof or as a result of an event under Section 16.2 hereof, a party designated by the Limited Partners holding a majority of the outstanding Units will act as Liquidating Trustee. In any other case, the General Partner will act as Liquidating Trustee. A-39 16.4 As soon as possible after December 31, 2026, or the date of the notice of or event causing an earlier termination of the Partnership, the Liquidating Trustee will begin to wind up the Partnership's business and affairs. In this regard: (a) The Liquidating Trustee will furnish or obtain an accounting with respect to all Partnership accounts and the account of each Partner and with respect to the Partnership's assets and liabilities and its operations from the date of the last previous audit of the Partnership to the date of such dissolution; (b) The Liquidating Trustee may, in its discretion, sell any or all productive and non-productive properties which, except in the case of an election by the General Partner to terminate the Partnership prior to the tenth anniversary of the Effective Date, may be sold to the General Partner or any of its affiliates for their fair market value as determined in good faith by the General Partner; (c) The Liquidating Trustee shall: (i) pay all of the Partnership's debts, liabilities and obligations to its creditors, including the General Partner; and (ii) pay all expenses incurred in connection with the termination, liquidation and dissolution of the Partnership and distribution of its assets as herein provided; (d) The Liquidating Trustee shall ascertain the fair market value by appraisal or other reasonable means of all assets of the Partnership remaining unsold, and each Partner's capital account shall be charged or credited, as the case may be, as if such property had been sold at such fair market value and the gain or loss realized thereby had been allocated to and among the Partners in accordance with Article VI hereof; and (e) On or as soon as practicable after the effective date of the termination, all remaining cash and any other properties and assets of the Partnership not sold pursuant to the preceding subsections of this Section 16.4 will be distributed to the Partners (i) in proportion to and to the extent of any remaining balances in the Partners' capital accounts and then (ii) in undivided interests to the Partners in the same proportions that Partnership Revenues are being shared at the time of such termination, provided, that: (i) the various interests distributed to the respective Partners will be distributed subject to such liens, encum- A-40 brances, restrictions, contracts, operating agreements, obligations, commitments or undertakings as existed with respect to such interests at the time they were acquired by the Partnership or were subsequently created or entered into by the Partnership; (ii) if interests in the Partnership Wells that are not subject to any operating agreement are to be distributed, the Partners will, concurrently with the distribution, enter into standard form operating agreements covering the subsequent operation of each such well which will, if the termination is effected pursuant to Section 16.1 above, be in a form satis- factory to the General Partner and will name the General Partner or its designee as operator; and (iii) no Partner shall be distributed an interest in any asset if the distribution would result in a deficit balance or increase the deficit balance in its capital account (after making the adjustments referred to in this Section 16.4 relating to distributions in kind). 16.5 If the General Partner has a deficit balance in its capital account following the distribution(s) provided for in Section 16.4(e) above, as determined after taking into account all adjustments to its capital account for the taxable year of the Partnership during which such distribution occurs, it shall restore the amount of such deficit balance to the Partnership within ninety (90) days and such amount shall be distributed to the other Partners in accordance with their positive capital account balances. 16.6 Notwithstanding anything to the contrary in this Agreement, upon the dissolution and termination of the Partnership, the General Partner will contribute to the Partnership the lesser of: (a) the deficit balance in its capital account; or (b) the excess of 1.01 percent of the total Capital Contributions of the Limited Partners over the capital previously contributed by the General Partner. ARTICLE XVII Notices 17.1 All notices, consents, requests, demands, offers, reports and other communications required or permitted shall be deemed to be given or made when personally delivered to the party entitled thereto, or when sent by United States mail in a sealed envelope, with postage prepaid, addressed, if to the General Partner, to 1000 Kensington Tower I, 7130 South Lewis Avenue, P. O. Box 702500, Tulsa, Oklahoma 74136, and, if to A-41 a Limited Partner, to the address set forth below such Limited Partner's signature on the counterpart of the Subscription Agreement that he or she originally executed and delivered to the General Partner. The General Partner may change its address by giving notice to all Limited Partners. Limited Partners may change their address by giving notice to the General Partner. ARTICLE XVIII Amendments 18.1 Limited Partners do not have the right to propose amendments to this Agreement. The General Partner may propose an amendment or amendments to this Agreement by mailing to the Limited Partners a notice describing the proposed amendment and a form to be returned by the Limited Partners indicating whether they oppose or approve of its adoption. Such notice will include the text of the proposed amendment, which will have been approved in advance by counsel for the Partnership. If, within sixty (60) days, or such shorter period as may be designated by the General Partner, after any notice proposing an amendment or amendments to this Agreement has been mailed, Limited Partners holding a majority of the outstanding Units have properly executed and returned the form indicating that they approve of and consent to adoption of the proposed amendment, such amendment will become effective as of the date specified in such notice, provided that no amendment which alters the allocations specified in Article VI above, changes the compensation and reimbursement provisions set forth in Article XI above or is otherwise materially adverse to the interests of the Limited Partners will become effective unless approved by all Limited Partners. If an amendment does become effective, all Partners will promptly evidence such effectiveness by executing such certificates and other instruments as the General Partner may deem necessary or appropriate under the laws of the jurisdictions in which the Partnership is then doing business in order to reflect the amendment. ARTICLE XIX General Provisions 19.1 This Agreement embodies the entire understanding and agreement between the Partners concerning the Partnership, and supersedes any and all prior negotiations, understandings or agreements in regard thereto. 19.2 In those cases where this Agreement requires opinions to be expressed by, or actions to be approved by, counsel for Limited Partners, A-42 such counsel must be qualified and experienced in the fields of federal income taxation and partnership and securities laws. 19.3 This Agreement and the Subscription Agreement may be executed in multiple counterpart copies, each of which will be considered an original and all of which constitute one and the same instrument. 19.4 This Agreement will be deemed to have been executed and delivered in the State of Oklahoma and will be construed and interpreted according to the laws of that State. 19.5 This Agreement and all of the terms and provisions hereof will be binding upon and will inure to the benefit of the Partners and their respective heirs, executors, administrators, trustees, successors and assigns. EXECUTED in the name of and on behalf of the undersigned General Partner this _____ day of ________________, 1996 but effective as of the Effective Date. "General Partner" UNIT PETROLEUM COMPANY Attest: By By Mark E. Schell, Secretary John G. Nikkel, President (CORPORATE SEAL) A-43 LIMITED PARTNER SUBSCRIPTION AGREEMENT AND SUITABILITY STATEMENT (ALL INFORMATION WILL BE TREATED CONFIDENTIALLY) Unit 1996 Employee Oil and Gas Limited Partnership c/o Unit Petroleum Company 1000 Kensington Center 7130 South Lewis Avenue Tulsa, Oklahoma 74136 RE: Unit 1996 Employee Oil and Gas Limited Partnership Gentlemen: In connection with the subscription of the undersigned for units of limited partnership interest ("Units") in Unit 1996 Employee Oil and Gas Limited Partnership (the "Partnership") which the undersigned tenders herewith to Unit Petroleum Company (the "General Partner"), the undersigned is hereby furnishing the Partnership and the General Partner the information set forth herein below and makes the representations and warranties set forth below, to indicate whether the undersigned is a suitable subscriber for Units in the Partnership. As a condition precedent to investing in the Partnership, the undersigned hereby represents, warrants, covenants and agrees as follows: 1. The undersigned acknowledges that he or she has received and reviewed a copy of the Private Offering Memorandum (the "Offering Memorandum") dated January 3, 1996, of Unit 1996 Employee Oil and Gas Limited Partnership, relating to the offering of Units in the Partnership, and all Exhibits thereto, including the Agreement of Limited Partnership (the "Agreement"), and understands that the Units will be offered to others on the terms and in the manner described in the Offering Memorandum. The undersigned hereby subscribes for the number of Units set forth below pursuant to the terms of the Offering Memorandum and tenders his or her Capital Subscription as required and agrees to pay his or her Additional Assessments upon call or calls by the General Partner; and the undersigned acknowledges that he or she shall have the right to withdraw this subscription only up until the time the General Partner executes and accepts the undersigned's subscription and that the General Partner may reject any subscription for any reason without liability to it; and, further, the undersigned I-1 agrees to comply with the terms of the Agreement and to execute any and all further documents necessary in connection with his or her admission to the Partnership. 2. The undersigned has reviewed and acknowledges execution of the Power of Attorney set forth in the Agreement and elsewhere in this instrument. 3. The undersigned is aware that no federal or state regulatory agency has made any findings or determination as to the fairness for public or private investment, nor any recommendation or endorsement, of the purchase of Units as an investment. 4. The undersigned recognizes the speculative nature and risks of loss associated with oil and gas investments and that he or she may suffer a complete loss of his or her investment. The Units subscribed for hereby constitute an investment which is suitable and consistent with his or her investment program and that his or her financial situation enables him or her to bear the risks of this investment. The undersigned represents that he or she has adequate means of providing for his or her current needs and possible personal contingencies, and that he or she has no need for liquidity of this investment. 5. The undersigned confirms that he or she understands, and has fully considered for purposes of this investment, the RISK FACTORS set forth in the Offering Memorandum and that (i) the Units are speculative investments which involve a high degree of risk of loss by the undersigned of his or her investment therein, (ii) there is a risk that the anticipated tax benefits under the Agreement could be challenged by the Internal Revenue Service or could be affected by changes in the Internal Revenue Code of 1986, as amended, the regulations thereunder or administrative or judicial interpretations thereof thereby depriving Limited Partners of anticipated tax benefits, (iii) the General Partner and its affiliates will engage in transactions with the Partnership which may result in a profit and, in the future, may be engaged in businesses which are competitive with that of the Partnership, and the undersigned agrees and consents to such activities, even though there are conflicts of interest inherent therein, and (iv) there are substantial restrictions on the transferability of, and there will be no public market for, the Units and, accordingly, it may be difficult for him or her to liquidate his or her investment in the Units in case of emergency, if possible at all. 6. The undersigned confirms that in making his or her decision to purchase the Units subscribed for he or she has relied upon independent investigations made by him or her (or by his or I-2 her own professional tax and other advisors) and that he or she has been given the opportunity to examine all documents and to ask questions of, and to receive answers from the General Partner or any person(s) acting on its behalf concerning the terms and conditions of the offering or any other matter set forth in the Offering Memorandum, and to obtain any additional information, to the extent the General Partner possesses such information or can acquire it without unreasonable effort or expense, necessary to verify the accuracy of the information set forth in the Offering Memorandum, and that no representations have been made to him or her and no offering materials have been furnished to him or her concerning the Units, the Partnership, its business or prospects or other matters, except as set forth in the Offering Memorandum and the other materials described in the Offering Memorandum. 7. The undersigned understands that the Units are being offered and sold under an exemption from registration provided by Sections 3(b) and/or 4(2) of the Securities Act of 1933, as amended (the "Act"), and warrants and represents that any Units subscribed for are being acquired by the undersigned solely for his or her own account, for investment purposes only, and are not being purchased with a view to or for the resale, distribution, subdivision or fractionalization thereof; the undersigned has no agreement or other arrangement, formal or informal, with any person to sell, transfer or pledge any part of any Units subscribed for or which would guarantee the undersigned any rights to such Units; the undersigned has no plans to enter into any such agreement or arrangement, and, consequently, he or she must bear the economic risk of the investment for an indefinite period of time because the Units cannot be resold or otherwise transferred unless subsequently registered under the Act (which neither the General Partner nor the Partnership is obligated to do), or an exemption from such registration is available and, in any event, unless transferred in compliance with the Agreement. 8. The undersigned further understands that the exemption under Rule 144 of the Act will not be generally available because of the conditions and limitations of such rule; that, in the absence of the availability of such rule, any disposition by him or her of any portion of his or her investment will require compliance under the Act; and that the Partnership and the General Partner are under no obligation to take any action in furtherance of making such exemption available. 9. The undersigned is aware that the General Partner will have full and complete control of Partnership operations and that he or she must depend on the General Partner to manage the Partnership profitably; and that a Limited Partner does not have I-3 the same rights as a stockholder in a corporation or the protection which stockholders might have, since limited partners have limited rights in determining policy. 10. The undersigned is aware that the General Partner will receive compensation for its services irrespective of the economic success of the Partnership. 11. The undersigned represents and warrants as follows (please mark and complete all applicable categories): (a) If an individual, the undersigned is the sole party in interest, and the undersigned is at least 21 years of age and a bona fide resident and domiciliary (not a temporary or transient resident) of the state set forth opposite his or her signature hereto; ____ YES ____ NO (b) If a partnership or corporation, the undersigned meets the following: (1) the entity has not been formed for the purposes of making this investment; (2) the entity was formed on ____________; and (3) the entity has a history of investments similar to the type described in the Offering Memorandum; ____ YES ____ NO (c) The undersigned meets all suitability standards and acknowledges being aware of all legend conditions applicable to his or her state of residence as set forth herein; ____ YES ____ NO (d) (i) The undersigned has a net worth (including home, furnishings and automobiles) of at least five times the amount of his or her Capital Subscription, and anticipates that he or she will have adjusted gross income during the current year in an amount which will enable him or her to bear the economic risks of the investment in the Partnership; ____ YES ____ NO and --- I-4 (ii) The undersigned is a salaried employee of Unit Corporation ("UNIT") or any of its subsidiaries at the date of formation of the Partnership whose annual base salary for 1996 has been set at $22,680 or more, or the undersigned is a director of UNIT; ____ YES ____ NO and (e) The undersigned _____ is or _____ is not a citizen of the United States. 12. The undersigned represents and agrees that he or she has had sufficient opportunity to make inquiries of the General Partner in order to supplement information contained in the Offering Memorandum respecting the offering, and that any information so requested has been made available to his or her satisfaction, and he or she has had the opportunity to verify such information. The undersigned further agrees and represents that he or she has knowledge and experience in business and financial matters, and with respect to investments generally, and in particular, investments generally comparable to the offering, so as to enable him or her to utilize such information to evaluate the risks of this investment and to make an informed investment decision. The following is a brief description of the undersigned's experience in the evaluation of other investments generally comparable to the offering: ________________________________________________________________ ________________________________________________________________ ________________________________________________________________ ________________________________________________________________ 13. The undersigned is aware that the Partnership and the General Partner have been and are relying upon the representations and warranties set forth in this Limited Partner Subscription Agreement and Suitability Statement, in part, in determining whether the offering meets the conditions specified in Rules of the Securities and Exchange Commission and the exemption from registration provided by Sections 3(b) and/or 4(2) of the Act. 14. All of the information which the undersigned has furnished the General Partner herein or previously with respect to the undersigned's financial position and business experience is correct and complete as of the date of this Agreement, and, if there should be any material change in such information prior to the closing of the offering period of the Units, the undersigned I-5 will immediately furnish such revised or corrected information to the General Partner. The undersigned agrees that the foregoing representations and warranties shall survive his or her admission to the Partnership, as well as any acceptance or rejection of a subscription for the Units. LIMITED PARTNER SIGNATURE PAGES If the subscription tendered hereby of the undersigned is accepted by the General Partner, the undersigned hereby executes and swears to the Agreement of Limited Partnership of Unit 1996 Employee Oil and Gas Limited Partnership as a Limited Partner, thereby agreeing to all the terms thereof and duly appoints the General Partner, with full power of substitution, his or her true and lawful attorney to execute, file, swear to and record any Certificate of Limited Partnership or amendments thereto or cancellation thereof and any other instruments which may be required by law in any jurisdiction to permit qualification of the Partnership as a limited partnership or for any other purposes necessary to implement the Partnership's purposes. THE SECURITIES REPRESENTED BY THIS CERTIFICATE HAVE NOT BEEN REGISTERED UNDER THE SECURITIES ACT OF 1933, AS AMENDED, THE OKLAHOMA SECURITIES ACT OR OTHER APPLICABLE STATE SECURITIES ACTS. THE SECURITIES HAVE BEEN ACQUIRED FOR INVESTMENT AND MAY NOT BE SOLD OR TRANSFERRED FOR VALUE IN THE ABSENCE OF AN EFFECTIVE REGISTRATION OF THEM UNDER THE SECURITIES ACT OF 1933, AS AMENDED, AND/OR THE OKLAHOMA SECURITIES ACT, OR ANY OTHER APPLICABLE ACT, OR AN OPINION OF COUNSEL TO UNIT 1996 EMPLOYEE OIL AND GAS LIMITED PARTNERSHIP THAT SUCH REGISTRATION IS NOT REQUIRED UNDER SUCH ACT. The undersigned hereby subscribes for _____ Units (minimum subscription: 2 Units) at a price of $1,000 per Unit for a total Capital Subscription (as defined in Article II of the Agreement) of $________________, which shall be due and payable either: (Check One) _______ (a) in four equal installments on March 15, 1996, June 15, 1996, September 15, 1996 and December 15, 1996, respectively; or _______ (b) through equal deductions from 1996 salary of the undersigned commencing immediately after the Effective Date (as defined in Article II of the Agreement). I-6 RESIDENT LIMITED PARTNER ADDRESS (If placing Units in the name of spouse ________________ _________________ or trustee for minor child or children, ________________ _________________ please provide name, Signature address of such spouse or trustee and Social ________________ Mailing Address Security or Tax Please Print Name if different: Identification Number) TAX I.D. OR _________________ SOCIAL SECURITY NO. Date: ___________ _________________ ___________________ ACCEPTED THIS _____ DAY OF ________, 1996. UNIT 1996 EMPLOYEE OIL AND GAS LIMITED PARTNERSHIP By ____________________________________ Authorized Officer of Unit Petroleum Company, General Partner Upon completion, an executed copy of this Limited Partner Subscription Agreement and Suitability Statement should be returned to Unit 1996 Employee Oil and Gas Limited Partnership, Attention Mark E. Schell, 1000 Kensington Tower I, 7130 South Lewis Avenue, Tulsa, Oklahoma, 74136. The General Partner, after acceptance, will return a copy of the accepted Subscription Agreement to the Limited Partner. I-7 EXHIBIT B "CONNER & WINTERS" Letter Head A Professional Corporation Lawyers 2400 First National Tower 15 East Fifth Street Tulsa, Oklahoma 74103-4391 (981) 586-5711 FAX (918) 586-8982 January 3, 1996 Unit Petroleum Company 1000 Galleria Tower I 7130 South Lewis Tulsa, Oklahoma 74136 Re: Unit 1996 Employee Oil and Gas Limited Partnership Gentlemen: We have acted as counsel for Unit Petroleum Company, an Oklahoma corporation (the "General Partner"), which will be the General Partner in the Unit 1996 Employee Oil and Gas Limited Partnership, A proposed Oklahoma limited partnership (the "Partnership"). You have requested our opinions regarding (i) the legality of the interests to be issued in the Partnership and (ii) certain federal income tax matters concerning the Partnership. We have reviewed and relied upon the accuracy of the facts and information set forth in the Private Offering Memorandum dated January 3, 1996 (the "Memorandum"), covering the offer and sale of units of limited partnership interest ("Units") in the Partnership, the Agreement of Limited Partnership included as Exhibit A to the Memorandum (the "Partnership Agreement"), the consolidated balance sheet of the General Partner dated November 30, 1995, and such other documents and matters as we have considered necessary in order to render this opinion. Capitalized terms used herein have the meaning assigned to them in the Memorandum, except as otherwise specifically indicated. In rendering our opinions we have assumed the accuracy of and relied upon certain representations made by you. Our opinions are conditioned upon the initial and continuing accuracy of such representations and of the following representations provided us: Unit Petroleum Company January 3, 1996 Page 2 1. As of the date of the Memorandum, the Memorandum did not contain any untrue statement of a material fact or omit to state a material fact required to be stated therein or necessary to make the statements therein not misleading. 2. The balance sheet of the General Partner included in the Memorandum presents fairly its financial position as of the date indicated; said balance sheet has been prepared in conformity with generally accepted accounting principles applied on a consistent basis; and since the date of the most recent balance sheet of the General Partner included in the Memorandum through the date hereof, there has not been any material adverse change in its financial position. 3. There is not now pending nor, to the knowledge of the General Partner of UNIT, threatened any action, suit or proceeding by the Internal Revenue Service under Sections 6700 or 7408 of the Internal Revenue Code relating to the promoter penalty referred to in Section 6700 of the Code with respect to any partnerships sponsored by the General Partner or UNIT. Neither the General Partner, UNIT, nor, to the knowledge of any of them, any participant in such partnerships has received any pre-filing notifications referred to in Revenue Procedure 83-73 with respect to such partnerships or the Partnership from the Internal Revenue Service. 4. A duly executed certificate of limited partnership for the Partnership will be filed with the Oklahoma Secretary of State in compliance with the Act and the organization and operation of the Partnership will be in accordance with the Act, the Agreement and the representations made in the Memorandum. 5. General Partner has and will maintain substantial assets which can be reached by a creditor of the Partnership, exclusive of all interests in the Partnership and notes and accounts receivable from and payable to the Partnership. At the time of admission of Limited Partners to the Partnership, the General Partner will have a minimum net worth equal to at least 10% of the Capital Contributions made to the Partnership, excluding any net worth attributable to any interest of the General Partner in the Partnership. For purposes of this net worth determination, assets will be valued based upon their current fair market value. The General Partner will use its best efforts to ensure that the net worth of the General Partner continues to meet or exceed an amount equal to 10% of the total Capital Contributions of the Limited Partners in the Partnership. 6. The General Partner will, in the aggregate, at all times during the existence of the Partnership, receive at least one percent (1%) of each material item of the Partnership's income, gain, loss, deduction or credit (other than by reason of the ownership of Units by the General Partner). 7. A nominee/agent agreement ("Nominee Agreement") in substantially the form of the Nominee Agreement attached hereto as Exhibit I will be executed by Unit Petroleum Company January 3, 1996 Page 3 and between Unit Texas Company, an Oklahoma corporation, as agent, and the Partnership before any interests in oil and gas properties are acquired in the name of Unit Texas Company as agent for the Partnership. 8. The terms and provisions of the Nominee Agreement entered into as provided above will be adhered to by each party thereto and, in particular, Unit Texas Company will be held out as agent and not the principal in all dealings with third parties relating to the oil and gas properties which Unit Texas Company holds as agent for the Partnership. 9. The beneficial ownership of any oil and gas property interests to be assigned to the Partnership will be assigned to the Partnership by delivery to Unit Texas Company, as agent for the Partnership, of an enforceable written assignment, in substantially the form of Exhibit II hereto, properly executed by the assignor. 10. The General Partner will accept subscriptions for at least 50 Units in the Partnership by the termination of the offering period. 11. The Partnership Agreement will be duly executed by the General Partner and the Subscription Agreement will be executed and delivered by those persons who purchase Units as Limited Partners of the Partnership. 12. In excess of 90 percent of the gross income of the Partnership will be interest income (excluding interest identified in section 7704(d)(2) of the Internal Revenue Code), dividends, and gain derived from the exploration, develpment, mining, or prodution, processing, refining, transportation, or the marketing of minerals or natural resources, or gain from the sale or disposition of interests in oil and gas properties or other items described in section 7704 (d) of the Internal Revenue Code. 13. The truth and accuracy of the representations in each of the Subscription Agreements. 14. There are no other documents or agreements which alter, modify, or change in any way the validity and accuracy of the above assumption and information. Based on the foregoing: 1. Legality of Interests. It is our opinion that the Partnership will be duly organized and validly existing; the Units will be legally issued, fully paid and non-assessable except as disclosed in the Memorandum; the Partnership will be a limited partnership under the Act and the liability of each Limited Partner will be limited as provided by the Act assuming the Limited Partners exercise only such rights as are provided in the Partnership Agreement. Unit Petroleum Company January 3, 1996 Page 4 2. Federal Income Tax Aspects. We have provided, as our opinion, the discussion of various tax matters set forth in the Memorandum under the headings "Summary of Program -- Federal Income Tax Aspects," "Risk Factors -- Tax Related Risks," and "Federal Income Tax Aspects." We hereby confirm that the statements under those headings in the Memorandum which attribute certain opinions to us are correct. In addition, we are of the opinion that such discussions in the Memorandum address all material tax issues involved in connection with the offer and sale of Units in the Partnership and that such discussions fairly summarize federal income tax laws and consequences relating to the matters set forth therein. In addition to and not in limitation of the foregoing and taking into account Circular 230, it is our opinion that (except where there manner or treatment is stated to be uncertain) the tax treatment set forth in the Memorandum is more likely than not the proper treatment. The discussions and conclusions set forth in the Memorandum are based upon our interpretation of the Internal Revenue Code as amended to date and existing Treasury Regulations, rules and case law. We can give no assurance that changes in such statutes or Regulations or in the interpretation thereof will not affect the opinions herein expressed or the conclusions set forth in the Memorandum. In view of the changes made by the tax legislation in recent years and the fact that a number of regulations and interpretations thereof have not been adopted or issued and by reason of the fact that the recent legislation, as well as existing regulations and rules, will be subject to new and ongoing judicial and administrative interpretations, there can be no assurance that the discussions of tax matters set forth in the Memorandum will not be subject to different interpretations. We hereby consent to the inclusion of this opinion as an exhibit to the Memorandum and to the reference in the Memorandum to our having rendered such opinion. Very truly yours, CONNER & WINTERS, A Professional Corporation EX-22 3 EXHIBIT 22.1 EXHIBIT 22.1 SUBSIDIARIES OF THE REGISTRANT State or Province Percentage Subsidiary of Incorporation Owned - ------------------------------------- ---------------- ---------- Unit Drilling and Exploration Company Delaware 100% Mountain Front Pipeline Company, Inc. Oklahoma 100% Unit Drilling Company Oklahoma 100% Unit Petroleum Company (1) Oklahoma 100% Petroleum Supply Company Oklahoma 100% Unit Energy Canada, Inc. Alberta 100% - ------------- (1) Unit Petroleum Company owns 100% of one subsidiary corporation, namely: Unit Texas Company Oklahoma EX-24 4 EXHIBIT 24.1 EXHIBIT 24.1 CONSENT OF INDEPENDENT ACCOUNTANTS We consent to the incorporation by reference in the registration statements of Unit Corporation on Form S-8 (File No.'s 33-19652, 33-44103,33-49724, 33-64323 and 33-53542) and Form S-3 (File No. 33-16116) of our report dated February 20, 1996, on our audits of the consolidated financial statements and financial statement schedule of Unit Corporation as of December 31, 1995 and 1994, and for the years ended December 31, 1995, 1994 and 1993, which report is included in this Annual Report on Form 1 0-K. COOPERS & LYBRAND L.L.P. Tulsa, Oklahoma March 19, 1996 EX-27 5
5 The schedule contains summary financial information extracted from the Consolidated Financial Statements of Unit Corporation and Subsidiaries under cover of Form 10-K for December 31, 1995 and is qualified in its entirety by reference to such financial statements. 0000798949 UNIT CORPORATION 1,000 YEAR DEC-31-1995 DEC-31-1995 534 0 10,514 116 2,048 14,026 260,771 164,752 110,922 11,107 0 0 0 4,195 52,411 110,922 0 53,074 0 42,863 3,893 0 3,235 3,083 (688) 3,751 248 0 0 3,999 .19 .19 Total revenues and total costs were reduced in 1995 as compared to prior quarters by a business combination in the Company's natural gas marketing segment which left the Company with a 34 percent equity interest in the new resulting entity of GED Gas Services, L.L.C.. GED Gas Services, L.L.C. sold its natual gas marketing operation to a third party in the fourth quarter of 1995 removing the Company from third party natural gas marketing operations. Prior year financial information was restated to present the Company's former natural gas marketing activity as a discontinued operation.
-----END PRIVACY-ENHANCED MESSAGE-----